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, 20172022
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
(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes☒☑ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
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, 20172022 was approximately $16.7$35.9 billion, based upon the closing price of $31.97$55.11 per share as reported by the New York Stock Exchange on such date. On February 7, 2018, 526.11, 2023, 654.0 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s definitive Proxy Statement relating to Registrant’s 20182023 annual meeting of stockholders have been incorporated by reference in Part III of this Annual Report on Form 10-K.
Auditor Name: KPMG LLP | Auditor Location: Oklahoma City, Oklahoma | Audit Firm ID: 185 |
DEVON ENERGY CORPORATION
FORM 10-K
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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:
“2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.
“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan, as amended and restated.
“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.
“ASC”2022 Plan” means Accounting Standards Codification.the Devon Energy Corporation 2022 Long-Term Incentive Plan.
“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”Catalyst” 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.Catalyst Midstream Partners, LLC.
“Canadian Plan”CDM” means Devon Canada Corporation Incentive Savings Plan.Cotton Draw Midstream, L.L.C.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Financing”EHS” means Devon Financing Company, L.L.C.environmental, health and safety.
“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.
“EMH” means EnLink Midstream Holdings, LP.
“EnLink” means EnLink Midstream Partners, L.P., a master limited partnership.
“EPA” means the United States Environmental Protection Agency.
“FASB”ESG” means Financial Accounting Standards Board.environmental, social and governance.
“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”GHG” means EnLink Midstream, LLC,greenhouse gas.
"IRA" refers to the indirect general partner entityInflation Reduction Act of EnLink.2022.
“GeoSouthern” means GeoSouthern Energy Corporation.
“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.
"Matterhorn" refers to Matterhorn Express Pipeline, LLC.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
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Table“Merger” means the merger of ContentsMerger 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.
“Merger Agreement” means that certain Agreement and Plan of Merger, dated September 26, 2020, by and among the Company, Merger Sub and WPX.
Index to Financial Statements“Merger Sub” means East Merger Sub, Inc., a wholly-owned subsidiary of the Company.
“MLP” means master limited partnership.
“MMBbls” means million barrels.
“MMBoe” means million Boe.
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“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“M&M operations” means marketing and midstream revenues minus marketing and midstream expenses.
“N/M” means not meaningful.
"NCI" means noncontrolling interests.
“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.
“OPIS” means Oil Price Information Service.
“PHMSA” means United States Department of Transportation Pipeline and Hazardous Materials Safety Administration.
“SEC” means United States Securities and Exchange Commission.
“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.credit, effective as of October 5, 2018.
“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.
“STEM” means science, technology, engineering and mathematics.
“S&P 500 Index” means Standard and Poor’s 500 index.
“Tax Reform Legislation” means Tax Cuts and Jobs Act.
“TSR” means total shareholder return.
“Upstream operations” means upstream revenues minus production expenses.
“U.S.” means United States of America.
“VEX”VIE” means Victoria Express Pipeline and related truck terminal and storage assets.variable interest entity.
“WPX” means WPX Energy, Inc.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/d” means per day.
“/gal”MMBtu” means per gallon.MMBtu.
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined bywithin the SEC.meaning of the federal securities laws. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-lookingAll statements, are based on our examinationother than statements of historical operating trends,facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the information used to prepare our December 31, 2017 reserve reports and other data in our possession or available from third parties.future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially and adversely from our expectations due to a number of factors, including, but not limited to:
the volatility of oil, gas and NGL prices;
uncertainties inherent in estimating oil, gas and NGL reserves;
the extent to which we are successful in acquiring and discovering additional reserves;
the uncertainties, costs and risks involved in our operations;
midstream capacity constraints and potential interruptions in production, including from limits to the build out of midstream infrastructure;
risks related to our hedging activities;
governmental interventions in energy markets;
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 leases, materials, people and capital;
our ability to successfully complete mergers, acquisitions and divestitures; and
our ability to pay dividends and make share repurchases; and
The forward-looking statements included in this filing speak only as of the date of this report, represent management’s current reasonable 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 assume nodo not undertake, and expressly disclaim, any duty to update or revise our forward-looking statements based on new information, future events or otherwise.
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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 North American onshore areas in the U.S.
On January 7, 2021, Devon and Canada. Additionally, we control EnLink, a publicly traded MLPWPX completed an all-stock merger of equals. WPX was an oil and gas exploration and production company with an integrated midstream business with significant size and scale in key operating regionsassets in the U.S. For additional information regardingDelaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. This merger enhanced the scale of our controloperations, built a leading position in the Delaware Basin and accelerated our cash-return business model that prioritizes free cash flow generation and the return of and ownership interest in, EnLink and its indirect general partner,capital to shareholders. In accordance with the General Partner, see Note 20 in “Item 8. Financial Statements and Supplementary Data”Merger Agreement, WPX shareholders received a fixed exchange of this report.
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). As of December 31, 2017, Devon and its consolidated subsidiaries had approximately 4,900 employees, of which approximately 1,500 employees are employed by EnLink (through its subsidiaries).
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.
DevonOur Strategy
DevonOur business strategy is committed tofocused on delivering consistent top-quartilea consistently competitive shareholder return among itsour peer group throughgroup. 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 tenet to our success. While our cash flow is highly engaged culture focuseddependent on innovation, safety, operational excellence, environmental stewardshipvolatile and social responsibility. We also maintain a strong commitment to financial strength and flexibility throughuncertain commodity prices, we pursue our strategy throughout all commodity price cycles as reflectedwith four fundamental principles.
Proven and responsible operator – We operate our business with the interests of our stakeholders and our ESG 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 ESG performance. We continue to establish new environmental performance targets for our Company and further incorporate ESG initiatives into our compensation structure.
Premier, sustainable portfolio of assets – As discussed in more detail later in this section, we own a portfolio of assets located in the company’s investment gradeUnited 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 deliver sustainable production extending many years into the future and provide reliable and affordable energy needed to support the world's growing population and energy demands. As a result of our recent Merger and acquisition and divestiture activity, our oil production, price realizations and field-level margins have continued to improve as we continue to sharpen our focus on five U.S. oil and liquids plays located in the Delaware Basin, Anadarko Basin, Williston Basin, Eagle Ford and Powder River Basin.
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.
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
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operations, protecting our investment-grade credit ratings.ratings, and paying and growing our shareholder dividend. While maintaining financial strength is a top priority, we remain committed to maximizing shareholder value which is evidenced by instituting our fixed plus variable dividend strategy and making opportunistic share repurchases.
Environmental, Social and Governance
Devon is focused on producing reliable, affordable and accessible energy the world needs, while continuing to find ways to produce and deliver it more responsibly. We consider the potential impacts of our operations when planning activities and making decisions. We strive to comply with all applicable environmental laws and regulations, often going above and beyond what is required. In the process, Devon incorporates technology, tools and techniques that enable us to minimize or avoid effects on air, water, land and wildlife. We are also evaluating and selectively investing in opportunities to create value in the transition to ever-cleaner forms of energy.
We have a strong organization in place to manage environmental performance, from our Board of Directors to our EHS/ESG leadership team and field-level EHS and operations teams. In recent years, we have updated our governance practices to elevate EHS and ESG oversight and discussion, including those related to climate change and energy transition opportunities. Our Board's Governance, Environmental, and Public Policy Committee frequently reviews our environmental initiatives and is keenly interested in the operational measures, technological advancements, and other actions that the Company takes in advancing our status in this important area. We recently established our standalone ESG team of subject matter experts on sustainability and ESG. The team provides advisory support across Devon to continue making progress in ESG and sustainability.
As a result of our organizational efforts, environmental objectives and targets are considered in capital allocation decisions, corporate and business unit planning and team strategies to integrate sustainability into our business activities. To support our commitment to improve our environmental footprint, we spent approximately $100 million in 2022 on capital projects that will directly or indirectly result in emissions reduction and anticipate similar spending in 2023.
Devon has established environmental performance targets that reflect our dedication and commitment to providing affordable energy while achieving meaningful emissions reductions and pursuing our ultimate goal of net zero GHG emissions for Scope 1 and 2. Our GHG and methane targets shown below are calculated from a 2019 baseline. Devon’s “2020 Vision”emission reduction strategy includes a range of potential actions including expanding our leak detection and repair program; deploying advanced leak detection technologies; reducing the volume of natural gas that is flared; electrifying facilities to reduce the use of natural gas and diesel consumed onsite; and optimizing facility design to minimize leaks and eliminate common equipment failures.
Devon is also focused on conserving and reusing water and interacting with our value chain on our overall environmental goals. We have set a target to advance our recycled water rate by using 90% or more non-freshwater for completions activities in our most active operating areas within the Delaware Basin. Devon is also actively engaged with our stakeholders upstream and downstream of our operations to improve ESG performance across our value chain. We are confident we can deliver strong operational and financial results in a manner that reduces our environmental impact while safeguarding our workforce and the communities in which we operate.
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 people who share and demonstrate our core values of integrity, relationships, courage and results. To develop our workforce, we focus on training, safety, wellness, inclusion, diversity and equity. As of December 31, 2022, Devon and its consolidated subsidiaries had approximately 1,800 employees, all located in the U.S.
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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 for 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.
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 well-being, including an Employee Assistance Program (“EAP”) that provides counseling services for employees and their family members free of charge. Access to experienced counselors, financial experts, staff attorneys, elder-care consultants and other services are included in EAP services available 365 days a year, 24 hours a day. In 2022, Devon implemented additional virtual mental health counseling resources available through talk and text, as well as a digital mental health platform providing mental health assessment and education. Devon encourages employees to take advantage of our wellness programs and activities by getting an annual physical exam, attending preventive health screenings and completing a financial wellness series, all at no cost to our workforce.
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 contribution up to 14% of the employee’s earnings; stock awards for all employees; 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; and telecommuting support; among other benefits. During 2022, Devon revised its paid time off practices and launched an additional four-week Paid Family and Medical Leave Policy for all employees to take care of themselves and their families. In response to the increase in global inflation affecting employees throughout 2022, Devon suspended collection of employee health care premiums through the end of 2023.
Devon also looks to our core values to build the decade intendedworkforce we need. We develop our employees’ knowledge and creativity and advance continual learning and career development through ongoing performance, training and development conversations.
Diversity, Equity and Inclusion
Devon’s success depends on employees who demonstrate integrity, accountability, perseverance and a passion for building our business and delivering results. Our efforts to optimize returnscreate a workforce with these qualities start with offering equal opportunity in all aspects of employment. We do this with company policies and deliver top-tier capital-efficient, cash-flow growth. Our 2020 Visionleadership commitment, and by providing employees opportunities to help shape Devon’s diversity, equity and inclusion direction and actions.
We strive to demonstrate inclusion, equity and diversity throughout the Company to bring a range of thoughts, experiences and points of view to our problem-solving and decision-making. Along with senior leadership efforts, Devon’s Diversity, Equity and Inclusion (“DEI”) Team works to proactively increase diversity and inclusion awareness, identify challenges and find innovative ways to achieve Devon’s inclusion and diversity vision and priorities. In 2022, our workforce was comprised of 23% females and 22% minorities. Along with our workforce efforts, we invest in DEI through community partnerships. One way we are achieving this is focusedby creating STEM centers in elementary schools in the areas in which we operate. Devon has helped open 120 STEM centers that orient children of all backgrounds to skills that will be essential for the future workforce. In 2022, Devon awarded 14 DEI grants to diverse community organizations throughout Oklahoma and New Mexico, totaling $125,000. The DEI grant program plans to expand in 2023 to provide DEI grants across all operating areas of the Company.
Compliance Culture
We reinforce the high expectations we have for ethical conduct by our employees through our Code of Business Conduct and Ethics (“Code”). The Code sets out basic principles for all employees to follow and incorporates specific guidance on critical areas such as our prohibition of harassment and discrimination, our protocols for avoiding conflicts of interest and our policies related to anti-corruption laws, privacy, cybersecurity and confidential information. On an annual basis, Devon employees, as well as our directors and officers, are required to acknowledge and agree to abide by our Code and complete a training course on the following strategic priorities:
Maximize cash flow by optimizing base productionCode and reducing per-unit cash costs;
Improve capital efficiency with a concentration of investment on highest-returning development projects in the Delaware Basin and STACK;
Simplify our portfolio by monetizing non-core assets;
Improve financial strength by reducing debt; and
Return cash to shareholders.
Our portfolio of exploration and production assets and operations provides stable, environmentally responsible production and a platform for future growth. In 2017, we continued the development of our world-class operations in the STACK and Delaware Basin. These assets provide us with a sustainable, multi-decade growth platform that continues to improve with our successful drilling programs. During 2017, we delivered the best well productivity in Devon’s 46-year history and continued a five-year streak of increasing Devon’s initial 90-day production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity and improving the performance of our established wells. Devon has more than doubled its onshore North American oil production since 2012 and has a deep inventory of development opportunities to deliver future oil growth.
As we enter 2018 and look toward the future, we expect to achieve additional efficiencies across our portfolio. We expect to fund activity within our cash flow, and remain committed to allocating capital in a disciplined manner to maximize value and return.
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related policies. We believeencourage our employees to help enforce the Code, and we capture the full value of our assets and improve returns through maximizing our base production and optimizing our capital program. The activitiesmaintain reporting systems that support this strategy include minimizing controllable downtime, enhancing well productivity, ensuring disciplined project execution, performing premier technical work, focusing on developmental drilling and reducing our operating and capital costs.are designed to minimize concerns that reports will result in retaliation.
We also continue to implement new shareholder-friendly initiatives, which include new returns-based metrics aligned to employee compensation and the conversion to successful efforts accounting which provides greater transparency into our financial performance.
EnLink Strategy
EnLink focuses on providing gathering, transmission, processing, storage, fractionation and marketing to upstream oil and natural gas producers, including Devon.
EnLink connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. Furthermore, EnLink purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines.
EnLink’s primary business objective is to provide stable cash flow, while growing through prudent and profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintaining a strong financial position through a conservative and balanced capital structure highlighted by its investment grade status. EnLink has consistently demonstrated expertise within the MLP space and continues to employ a proven business model that includes growing, expanding and executing on its strategy within top basins where Devon and other successful upstream producers operate.
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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, 20172022 are detailed in the map below.Notes 23 and 24 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain additional information on our segments and geographical areas.
Led by results from our franchise assets, STACK and Delaware Basin Devon achieved the best drilling results in our 46-year history. Our initial 90-day production rates in 2017 increased more than 400% from 2012 levels. These productivity improvements were driven by activity focused in top resource plays, improved subsurface reservoir characterization, leading-edge completion designs and improvements in lateral placement. The most significant reserves growth came from our U.S. operations, where we replaced approximately 150% of our 2017 production with proved reserves additions from the drill bit.
Delaware Basin – The Delaware Basin is one of Devon’s top-two franchise assetsour largest and continues to offermost active program in the portfolio with operations in southeast New Mexico and across the state line into west Texas. We acquired additional acreage in the Delaware Basin through the Merger, creating an industry leading position in this basin. 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, Avalon and Delaware Wolfcamp and Leonard formations. We expect theseWith a significant inventory of oil and liquids-rich drilling opportunities across our acreage in the Delaware Basinthat have multi-zone development potential, Devon has a robust platform to
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deliver high-margin growthdrilling programs for many years to come. During 2017, our continued appraisal and development work enabled us to increase our proved reserves by approximately 60%. At December 31, 2017,2022, we had eight16 operated rigs developing this asset. In 2018, we plan to invest approximately $725 million of capitalasset in the Wolfcamp and Bone Spring formations. The Delaware Basin as we shiftis our top funded asset and is expected to expanded development operations, primarily focused on the Bone Spring formation.receive approximately 60% of our capital allocation in 2023.
STACKAnadarko Basin – The STACKOur Anadarko Basin development, located primarily in western Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top-two franchise assets. Devon is currently targeting the Woodford Shale and the Meramec zones.provides long-term optionality through its significant inventory. Our STACKAnadarko Basin position is one of the largest and best in the industry, providing visible long-term growth. Completion design enhancementsproduction. We have resulted in greater productivity and improved economics. Drilling activity in the Meramec has produced record setting initial production across our core position in the oil and liquids window. At December 31, 2017, we had nine operated rigsan agreement with drilling focused in the Meramec formation. In 2018, we plan approximately $700 million of capital investment and expectDow to accelerate full-field development activity.
Heavy Oil – Our operations in Canada are focused on our heavy oil assets in Alberta, Canada. Our most significant Canadian operation is our Jackfish complex, an industry-leading thermal heavy oil operation in the non-conventional oil sands of east central Alberta. We employjointly develop a recovery method known as steam-assisted gravity drainage at Jackfish. The Jackfish operation consists of three facilities. We expect Jackfish to maintain a reasonably flat production profile for greater than 20 years requiring approximately $200 million of annual maintenance capital based on current economic conditions.
Our Pike oil sands acreage is situated directly to the southeastportion of our JackfishAnadarko Basin acreage in east central Alberta and, has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2017. With our 50% partner,2022 we continuehad a four operated rig program associated with this joint venture.
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In addition to Jackfish and Pike, we hold acreage and own producing assets in the Bonnyville region, located to the south and east of Jackfish in eastern Alberta. Bonnyville is a low-risk, high margin oil development play that produces heavy oil by conventional means, without the need for steam injection.
In 2018, we plan approximately $275 million of capital investment in our Canadian Heavy Oil business.
Eagle FordWilliston Basin – We acquired our position in the Williston Basin through the Merger in 2021. It is located entirely on the Fort Berthold Indian Reservation in North Dakota, and its operations are focused in the oil-prone Bakken and Three Forks formations. Our Williston Basin asset is a high-margin oil resource located in the core of the play and generated substantial cash flow in 2022. In July 2022, we acquired additional producing properties and leasehold interests in the Williston Basin that are complementary to our existing acreage, offer operational synergies and added high-quality inventory to our asset portfolio. At December 31, 2022, we had two operated rigs developing this asset.
Eagle Ford – Our Eagle Ford in 2014, with acresoperations are located in Texas' DeWitt and LavacaKarnes counties, in south Texas. In 2017, we closed on the sale of our Lavaca assets for approximately $200 million. Since acquiring these assets, we have delivered tremendous results by producing 119 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, locatedsituated in the economic core of thethis south Texas play. WithIts production is leveraged to oil and has low-cost access to premium Gulf Coast pricing, providing for strong operating margins. In September 2022, we acquired additional producing properties and leasehold interests in the highest margins in our portfolio, our Eagle Ford assets generated significant cash flow in 2017. In 2018,that are complementary to our existing acreage, offer operational synergies and added high-quality inventory to our asset portfolio. At December 31, 2022, we plan approximately $250 million of capital investment.had two operated rigs developing this asset.
Rockies OilPowder River Basin – Our acreage in the RockiesThis asset is focused on emerging oil opportunities in theWyoming's Powder River BasinBasin. We are currently targeting several Cretaceous oil objectives, including the Turner, Parkman, Teapot and the Wind River Basin.Niobrara formations. Recent drilling success in these formationsthis 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. As ofAt December 31, 2017,2022, we had one operated rig targeting the Turner, formationParkman, Teapot and Niobrara formations in northern Converse County of the Powder River Basin. In 2018, we plan approximately $150 million of capital investment.County.
Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. The Johnson County assets are currently being marketed as part of our non-core divestiture program. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this asset into one of the top producing gas fields in North America. Given the sustained low gas price environment, we continue to focus on enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2018, we plan on minimal development activity, with planned capital investment of up to $50 million to optimize base production and further de-risk future development resources.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 24 in “Item 8. Financial Statements and Supplementary Data” of this report.
Proved oil and gas reserves are those quantities of oil, gas and NGLs which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions,
9
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. Such policies require proved reserves to be in compliance with theapplicable SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards.
The Group, which is led by Devon’s DirectorManager of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the DirectorManager and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates. The Group reports toestimates and is managed through our finance department. No portionare independent of the Group’s compensation is directly dependent on the quantity of reserves booked.
operating groups. The DirectorManager of the Group has approximately 30over 15 years of industry experience, with positions of increasing responsibility for the estimation and evaluation of reserves. He has been employed by Devon for the past 17 years, including the past 10 in his current position. His further professional qualifications include a degree in petroleum engineering and is a registered professional engineer, member of the Society of Petroleum Engineers and experience in reserves estimation for projects in the U.S. (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America.
Throughout the year, the Group performs internal reserves reviews of each operating country’s reserves.engineer. The Group also oversees audits and reserves estimates performed by a qualified third-party petroleum consulting firms.firm. During 2017,2022, we engaged two such firmsDeGolyer and MacNaughton to audit approximately 88%89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited approximately 85%reserves. Additionally, our Board of our 2017 U.S. reserves, and Deloitte LLP audited approximately 99% of our Canadian reserves.
In addition to conducting these internal reviews and external reserves audits, we also haveDirectors has a Reserves Committee that provides additional oversight of our reserves process. The committee consists of threesix independent members of our Board of Directors. This committee provides additional oversight of our reserves estimationDirectors who collectively have skills and certification process. The members of our Reserves Committee have educational backgrounds in geology or petroleum engineering, as well as experiencethat are relevant to the reserves estimation process. The Reserves Committee meets a minimum of twice a year to discuss reserves issuesprocesses, reporting systems and policies and meets at least once a year separately with our senior reserves engineering personnel and separately with our third-party petroleum consultants.disclosure requirements.
10
The following tables present production, price and cost information for each significant field countryin our asset portfolio and continent.the total company.
|
| Production |
| |||||||||||||
Year Ended December 31, |
| Oil (MMBbls) |
|
| Gas (Bcf) |
|
| NGLs (MMBbls) |
|
| Total (MMBoe) |
| ||||
2022 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 77 |
|
|
| 222 |
|
|
| 38 |
|
|
| 151 |
|
Anadarko Basin |
|
| 5 |
|
|
| 81 |
|
|
| 9 |
|
|
| 28 |
|
Total |
|
| 109 |
|
|
| 356 |
|
|
| 54 |
|
|
| 223 |
|
2021 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 72 |
|
|
| 195 |
|
|
| 32 |
|
|
| 136 |
|
Anadarko Basin |
|
| 5 |
|
|
| 79 |
|
|
| 9 |
|
|
| 27 |
|
Total |
|
| 106 |
|
|
| 325 |
|
|
| 48 |
|
|
| 209 |
|
2020 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 31 |
|
|
| 91 |
|
|
| 13 |
|
|
| 60 |
|
Anadarko Basin |
|
| 7 |
|
|
| 92 |
|
|
| 10 |
|
|
| 33 |
|
Total |
|
| 57 |
|
|
| 221 |
|
|
| 29 |
|
|
| 122 |
|
|
| Average Sales Price |
|
|
|
| ||||||||||
Year Ended December 31, |
| Oil (Per Bbl) |
|
| Gas (Per Mcf) |
|
| NGLs (Per Bbl) |
|
| Production Cost (Per Boe) (1) |
| ||||
2022 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
| $ | 94.87 |
|
| $ | 5.44 |
|
| $ | 34.33 |
|
| $ | 6.58 |
|
Anadarko Basin |
| $ | 93.41 |
|
| $ | 6.36 |
|
| $ | 36.40 |
|
| $ | 10.10 |
|
Total |
| $ | 94.11 |
|
| $ | 5.47 |
|
| $ | 34.18 |
|
| $ | 7.92 |
|
2021 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
| $ | 66.67 |
|
| $ | 3.47 |
|
| $ | 30.02 |
|
| $ | 5.97 |
|
Anadarko Basin |
| $ | 66.29 |
|
| $ | 3.80 |
|
| $ | 29.73 |
|
| $ | 9.26 |
|
Total |
| $ | 65.98 |
|
| $ | 3.40 |
|
| $ | 29.52 |
|
| $ | 7.02 |
|
2020 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
| $ | 37.25 |
|
| $ | 1.08 |
|
| $ | 10.64 |
|
| $ | 5.76 |
|
Anadarko Basin |
| $ | 35.80 |
|
| $ | 1.66 |
|
| $ | 12.11 |
|
| $ | 9.61 |
|
Total |
| $ | 35.95 |
|
| $ | 1.48 |
|
| $ | 11.72 |
|
| $ | 7.66 |
|
|
| Production |
| |||||||||||||||||
Year Ended December 31, |
| Oil (MMBbls) |
|
| Bitumen (MMBbls) |
|
| Gas (Bcf) |
|
| NGLs (MMBbls) |
|
| Total (MMBoe) |
| |||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 237 |
|
|
| 14 |
|
|
| 54 |
|
STACK |
|
| 9 |
|
|
| — |
|
|
| 107 |
|
|
| 11 |
|
|
| 38 |
|
Jackfish |
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
U.S. |
|
| 42 |
|
|
| — |
|
|
| 433 |
|
|
| 36 |
|
|
| 150 |
|
Canada |
|
| 7 |
|
|
| 40 |
|
|
| 6 |
|
|
| — |
|
|
| 48 |
|
Total North America |
|
| 49 |
|
|
| 40 |
|
|
| 439 |
|
|
| 36 |
|
|
| 198 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 265 |
|
|
| 15 |
|
|
| 60 |
|
STACK |
|
| 7 |
|
|
| — |
|
|
| 103 |
|
|
| 9 |
|
|
| 33 |
|
Jackfish |
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
U.S. |
|
| 47 |
|
|
| — |
|
|
| 510 |
|
|
| 42 |
|
|
| 174 |
|
Canada |
|
| 8 |
|
|
| 40 |
|
|
| 7 |
|
|
| — |
|
|
| 49 |
|
Total North America |
|
| 55 |
|
|
| 40 |
|
|
| 517 |
|
|
| 42 |
|
|
| 223 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 291 |
|
|
| 17 |
|
|
| 66 |
|
STACK |
|
| 3 |
|
|
| — |
|
|
| 86 |
|
|
| 8 |
|
|
| 25 |
|
Jackfish |
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| — |
|
|
| 31 |
|
U.S. |
|
| 60 |
|
|
| — |
|
|
| 579 |
|
|
| 50 |
|
|
| 206 |
|
Canada |
|
| 10 |
|
|
| 31 |
|
|
| 8 |
|
|
| — |
|
|
| 42 |
|
Total North America |
|
| 70 |
|
|
| 31 |
|
|
| 587 |
|
|
| 50 |
|
|
| 248 |
|
|
| Average Sales Price |
|
|
|
|
| |||||||||||||
Year Ended December 31, |
| Oil (Per Bbl) |
|
| Bitumen (Per Bbl) |
|
| Gas (Per Mcf) |
|
| NGLs (Per Bbl) |
|
| Production Cost (Per Boe) (1) |
| |||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 49.72 |
|
| $ | — |
|
| $ | 2.47 |
|
| $ | 13.67 |
|
| $ | 6.86 |
|
STACK |
| $ | 48.43 |
|
| $ | — |
|
| $ | 2.40 |
|
| $ | 17.78 |
|
| $ | 4.72 |
|
Jackfish |
| $ | — |
|
| $ | 29.38 |
|
| $ | — |
|
| $ | — |
|
| $ | 11.02 |
|
U.S. |
| $ | 49.41 |
|
| $ | — |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 6.74 |
|
Canada |
| $ | 33.73 |
|
| $ | 29.38 |
|
| N/M |
|
| $ | — |
|
| $ | 11.70 |
| |
Total North America |
| $ | 47.31 |
|
| $ | 29.38 |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 7.94 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 41.03 |
|
| $ | — |
|
| $ | 1.76 |
|
| $ | 10.31 |
|
| $ | 5.75 |
|
STACK |
| $ | 39.81 |
|
| $ | — |
|
| $ | 1.91 |
|
| $ | 10.86 |
|
| $ | 4.34 |
|
Jackfish |
| $ | — |
|
| $ | 19.82 |
|
| $ | — |
|
| $ | — |
|
| $ | 8.70 |
|
U.S. |
| $ | 38.92 |
|
| $ | — |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 6.44 |
|
Canada |
| $ | 23.96 |
|
| $ | 19.82 |
|
| N/M |
|
| $ | — |
|
| $ | 9.36 |
| |
Total North America |
| $ | 36.72 |
|
| $ | 19.82 |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 7.08 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 46.47 |
|
| $ | — |
|
| $ | 2.00 |
|
| $ | 9.62 |
|
| $ | 5.96 |
|
STACK |
| $ | 43.73 |
|
| $ | — |
|
| $ | 2.22 |
|
| $ | 8.97 |
|
| $ | 5.39 |
|
Jackfish |
| $ | — |
|
| $ | 23.41 |
|
| $ | — |
|
| $ | — |
|
| $ | 12.43 |
|
U.S. |
| $ | 44.01 |
|
| $ | — |
|
| $ | 2.14 |
|
| $ | 9.32 |
|
| $ | 7.52 |
|
Canada |
| $ | 30.58 |
|
| $ | 23.41 |
|
| N/M |
|
| $ | — |
|
| $ | 13.18 |
| |
Total North America |
| $ | 42.12 |
|
| $ | 23.41 |
|
| $ | 2.14 |
|
| $ | 9.32 |
|
| $ | 8.48 |
|
|
|
11
The following table summarizes our development and exploratory drilling results. We did not have any dry development or exploratory wells drilled for the years 2022, 2021 or 2020.
|
| Development Wells (1) |
|
| Exploratory Wells (1) |
|
| Total Wells (1) |
| |||
Year Ended December 31, |
| Productive |
|
| Productive |
|
| Total |
| |||
2022 (2) |
|
| 263.8 |
|
|
| 47.3 |
|
|
| 311.1 |
|
2021 |
|
| 236.3 |
|
|
| 18.8 |
|
|
| 255.1 |
|
2020 |
|
| 106.5 |
|
|
| 26.6 |
|
|
| 133.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Development Wells (1) |
|
| Exploratory Wells (1) |
|
| Total Wells (1) |
| |||||||||||||||||||
Year Ended December 31, |
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Total |
| |||||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 149.8 |
|
|
| — |
|
|
| 44.0 |
|
|
| — |
|
|
| 193.8 |
|
|
| — |
|
|
| 193.8 |
|
Canada |
|
| 100.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 100.5 |
|
|
| — |
|
|
| 100.5 |
|
Total North America |
|
| 250.3 |
|
|
| — |
|
|
| 44.0 |
|
|
| — |
|
|
| 294.3 |
|
|
| — |
|
|
| 294.3 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 88.5 |
|
|
| — |
|
|
| 36.4 |
|
|
| 2.0 |
|
|
| 124.9 |
|
|
| 2.0 |
|
|
| 126.9 |
|
Canada |
|
| 21.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 21.5 |
|
|
| — |
|
|
| 21.5 |
|
Total North America |
|
| 110.0 |
|
|
| — |
|
|
| 36.4 |
|
|
| 2.0 |
|
|
| 146.4 |
|
|
| 2.0 |
|
|
| 148.4 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 298.6 |
|
|
| 1.8 |
|
|
| 40.7 |
|
|
| — |
|
|
| 339.3 |
|
|
| 1.8 |
|
|
| 341.1 |
|
Canada |
|
| 79.0 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 79.0 |
|
|
| — |
|
|
| 79.0 |
|
Total North America |
|
| 377.6 |
|
|
| 1.8 |
|
|
| 40.7 |
|
|
| — |
|
|
| 418.3 |
|
|
| 1.8 |
|
|
| 420.1 |
|
|
As of December 31, 2022, there were 281 gross and 163 net |
The following table presents the wells that werehave been spud and are in progressthe process of drilling, completing or waiting on December 31, 2017. Ascompletion.
11
Table of February 1, 2018, these wells were still in progress.Contents
|
| Gross (1) |
|
| Net (2) |
| ||
U.S. |
|
| 26.0 |
|
|
| 10.1 |
|
Canada |
|
| 5.0 |
|
|
| 5.0 |
|
Total North America |
|
| 31.0 |
|
|
| 15.1 |
|
|
|
|
|
Productive Wells
The following table sets forth our producing wells as of December 31, 2017.2022.
|
| Oil Wells |
|
| Natural Gas Wells |
|
| Total Wells |
| |||||||||||||||
|
| Gross (1)(3) |
|
| Net (2) |
|
| Gross (1)(3) |
|
| Net (2) |
|
| Gross (1)(3) |
|
| Net (2) |
| ||||||
Total |
|
| 10,638 |
|
|
| 4,039 |
|
|
| 3,664 |
|
|
| 1,628 |
|
|
| 14,302 |
|
|
| 5,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil Wells (1) |
|
| Natural Gas Wells |
|
| Total Wells (1) |
| |||||||||||||||
|
| Gross (2)(4) |
|
| Net (3) |
|
| Gross (2)(4) |
|
| Net (3) |
|
| Gross (2)(4) |
|
| Net (3) |
| ||||||
U.S. |
|
| 9,165 |
|
|
| 3,379 |
|
|
| 10,103 |
|
|
| 7,245 |
|
|
| 19,268 |
|
|
| 10,624 |
|
Canada |
|
| 3,195 |
|
|
| 3,085 |
|
|
| 590 |
|
|
| 413 |
|
|
| 3,785 |
|
|
| 3,498 |
|
Total North America |
|
| 12,360 |
|
|
| 6,464 |
|
|
| 10,693 |
|
|
| 7,658 |
|
|
| 23,053 |
|
|
| 14,122 |
|
|
|
|
|
|
|
|
|
12
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 14,6006,169 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.
Acreage Statistics
The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2017.2022. Of our 4.32.0 million net acres, approximately 2.31.3 million acres are held by production. The acreage in the table includes 0.1 million, 0.2 million and 0.1 millionbelow does not include any material net acres subject to leases that are scheduled to expire during 2018, 20192023, 2024 and 2020, respectively. As of December 31, 2017, there were no proved undeveloped reserves associated with our expiring acreage. Of2025. For the 0.4 million net acres that are set to expire by December 31, 2020,2025, 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. In 2017,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 |
|
| 1,234 |
|
|
| 730 |
|
|
| 3,086 |
|
|
| 1,282 |
|
|
| 4,320 |
|
|
| 2,012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Developed |
|
| Undeveloped |
|
| Total |
| |||||||||||||||
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
| ||||||
|
| (Thousands) |
| |||||||||||||||||||||
U.S. |
|
| 1,808 |
|
|
| 1,203 |
|
|
| 3,587 |
|
|
| 1,598 |
|
|
| 5,395 |
|
|
| 2,801 |
|
Canada |
|
| 685 |
|
|
| 504 |
| �� |
| 2,091 |
|
|
| 968 |
|
|
| 2,776 |
|
|
| 1,472 |
|
Total North America |
|
| 2,493 |
|
|
| 1,707 |
|
|
| 5,678 |
|
|
| 2,566 |
|
|
| 8,171 |
|
|
| 4,273 |
|
|
|
|
|
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.
EnLink Midstream Properties
EnLink represents the primary component of our midstream operations. EnLink’s assets are comprised of systems and other assets located in four primary regions:
Texas – The Texas assets consist of natural gas gathering, processing and transmission operations in north Texas and the Midland and Delaware Basins in west Texas.
Oklahoma – The Oklahoma assets consist of natural gas gathering, processing and transmission activities in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK and Central Northern Oklahoma Woodford shale areas.
Louisiana – The Louisiana assets consist of natural gas pipelines, natural gas processing plants, gas and NGL storage facilities, fractionation facilities and NGL pipelines located in Louisiana.
Crude and Condensate – The Crude and Condensate assets consist of Ohio River Valley crude oil, condensate, condensate stabilization, natural gas compression and brine disposal activities in the Utica and Marcellus Shales, crude oil operations in the Permian Basin and central Oklahoma, and crude oil activities associated with VEX located in the Eagle Ford Shale.
1312
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 43 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2018,2023, our production was sold under the following contract terms.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
|
| Short-Term |
|
| Long-Term |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
|
| Short-Term |
|
| Long-Term |
| ||||||||||||||
Oil and bitumen |
|
| 80 | % |
|
| — |
|
|
| 20 | % |
|
| — |
| ||||||||||||||||
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
| ||||||||||||||||||||
Oil |
|
| 33 | % |
|
| — |
|
|
| 67 | % |
|
| — |
| ||||||||||||||||
Natural gas |
|
| 52 | % |
|
| 4 | % |
|
| 44 | % |
|
| — |
|
|
| 64 | % |
|
| 4 | % |
|
| 32 | % |
|
| — |
|
NGLs |
|
| 33 | % |
|
| 20 | % |
|
| 47 | % |
|
| — |
|
|
| 83 | % |
|
| 7 | % |
|
| 10 | % |
|
| — |
|
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, 2017,2022, we were committed to deliver the following fixed quantities of production.
|
| Total |
|
| Less Than 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
| ||||||||||||||||||||||||
Oil and bitumen (MMBbls) |
|
| 86 |
|
|
| 31 |
|
|
| 49 |
|
|
| 6 |
| ||||||||||||||||||||
|
| Total |
|
| Less Than 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
|
| More Than 5 Years |
| |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||
Oil (MMBbls) |
|
| 39 |
|
|
| 27 |
|
|
| 7 |
|
|
| 5 |
|
|
| — |
| ||||||||||||||||
Natural gas (Bcf) |
|
| 293 |
|
|
| 265 |
|
|
| 28 |
|
|
| — |
|
|
| 495 |
|
|
| 148 |
|
|
| 146 |
|
|
| 73 |
|
|
| 128 |
|
NGLs (MMBbls) |
|
| 11 |
|
|
| 11 |
|
|
| — |
|
|
| — |
|
|
| 15 |
|
|
| 15 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total (MMBoe) |
|
| 146 |
|
|
| 86 |
|
|
| 54 |
|
|
| 6 |
|
|
| 136 |
|
|
| 66 |
|
|
| 32 |
|
|
| 17 |
|
|
| 21 |
|
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.
CustomersCompetition
During 2017, 2016 and 2015, no purchaser accounted for over 10% of our consolidated sales revenue.
Competition
See “Item 1A. Risk Factors.”
Public Policy and Government Regulation
Our industry is subject to a wide range of regulations.governmental regulation and oversight. 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 publicPublic policy changes are commonplace, and changes to existing laws and regulations are frequently amended,proposed or implemented. Moreover, it is often difficult to quantify all associated compliance costs as such amounts may be indistinguishable components of our general capital expenditures and operating expenses. Accordingly, we are unable to predict the future cost or impact of compliance. However,regulatory compliance, though we do not expect that any of these laws and regulations willsuch compliance costs or impacts to affect our operations materially differently than they would affect other companies with similar operations, sizesimilarly situated companies. However, based on regulatory trends and financial strength. increasingly stringent laws and permitting requirements, our capital expenditures and operating expenses related to environmental and other regulations have
13
increased over the years and will likely continue to increase. For more information on our environmental capital expenditures specifically, see the environmental, social and governance discussion earlier in this Annual Report.
The following are significant areas of government control and regulation affecting our operations. For additional information on the Company’s regulatory risks, see “Item 1A. Risk Factors—Legal, Regulatory and Environmental Risks” of this report.
14
Exploration and Production Regulation
Our operations are subject to various federal, tribal, state, provincialtribal and local laws and regulations. These lawsregulations relating to exploration and regulations relate to matters that include:production activities, including with respect to:
acquisition of seismic data;
design, 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;
andtransportation of production; and
endangered species and habitat.
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., someSome states allow the forced pooling or integrationunitization of tracts to facilitate exploration and development, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oilleases. Such rules often impact the ultimate timing of our exploration and gas properties.development plans. 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 and Indian lands can sometimes be subject to delay, including as a result of challenges to permits or other regulatory decisions brought by non-governmental organizations or other parties, which can hinder development activities or otherwise adversely impact operations. The federal government has, been particularly active in recent years in evaluatingfrom time to time, evaluated and, in some cases, promulgatingpromulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject
Environmental, Health and Safety Regulations
We strive to frequent delays.
Royaltiesconduct our operations in a socially and Incentives in Canada
The royalty calculation in Canada is a significant factor in the profitability of Canadian oil and gas production. Oil sands crown royalties are determined by government regulations and are generally calculated as a percentage of the value of the gross production, net of allowed deductions. The royalty percentage is determined on a sliding-scale based on crown posted prices. For pre-payout oil sands projects, the regulations prescribe lower royalty rates for oil sands projects until allowable capital costs have been recovered. In early 2016, the Alberta government adopted the recommendation of its Royalty Review Panel. The new royalty framework preserves the existing royalty structure and rates for oil sands. For conventional oil and gas royalty calculations, wells drilled after January 1, 2017 would use the Modernized Royalty Framework (MRF)environmentally responsible manner, which prescribes a lower royalty rate until allowable costs have been recovered. The calculation for wells post payout is based on a percentage of production net of allowed deductions and variesincludes compliance with commodity price.
Marketing in Canada
Any oil or gas export requires an exporter to obtain export authorizations from Canada’s National Energy Board.
15
Environmental, Pipeline Safety and Occupational Regulations
applicable law. We are subject to many federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment and natural resources. Environmental, health and safety laws and regulations relate to:to, among other things:
the discharge of pollutants into federal provincial and state waters;
assessing the environmental impact of seismic acquisition, drilling or construction activities;
14
the generation, storage, transportation and disposal of waste materials, including hazardous substances;
the emission of methane and certain other 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 act in the place of the government and sue operators for alleged violations of environmental law. We considerEnvironmental organizations also can assert legal and administrative challenges to certain actions of oil and gas regulators, such as the costs of environmental protection and safety and health compliance necessary, manageable parts of our business. We have been ableBLM, for allegedly failing to plan for and comply with environmental safetylaws, which can result in delays in obtaining permits or other necessary authorizations. In recent years, federal and health initiatives without materially altering our operating strategystate policy makers and regulators have increasingly implemented or incurring significant unreimbursed expenditures. However, basedproposed new laws and regulations designed to reduce methane emissions and other GHG, which have included mandates for new leak detection and retrofitting requirements, stricter emission standards and a fee on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related tomethane emissions. For example, in November 2022, the protectionBLM proposed a rule that would limit flaring as well as allow the delay or denial of the environment and safety and health compliance have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.permits upon a finding that an operator’s methane waste minimization plan is insufficient.
Our business and operations, and our industry in general, are subject to a variety of risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business, financial condition, results of operations and liquidity could be materially and adversely impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
Risks Related to Our Industry
Volatile Oil, Gas and NGL Prices Significantly Impact ourOur 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, in recentover the last five years, monthly NYMEX WTI oil and NYMEX Henry Hub gas prices ranged from a highhighs of over $100$120 per Bbl and $6$9.50 per MMBtu, respectively, to a lowlows of under $27$30 per Bbl and $1.70$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, including consumer demand in emerging markets, such as China and India;
volatility and trading patterns in the commodity-futures markets;
climate change incentives and conservation and environmental protection efforts;
production levels of members of OPEC, Russia, the U.S. or other producing countries;
geopolitical risks, including the on-going conflict between Russia and Ukraine, as well as other political and civil unrest in the Middle East, Africa, Europe and South America;
adverse weather conditions, and natural disasters, public health crises and other catastrophic events, such as tornadoes, earthquakes, hurricanes and hurricanes;
regional pricing differentials;
16
the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories; 15 the price and availability of alternative technological advances affecting energy consumption and stockholder activism or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas in order to reduce GHG emissions; changes in trade relations and policies, such as restrictions on oil, gas and NGL exports by the U.S. or economic sanctions, including embargoes, on Russia or other producing countries, as well as the imposition of tariffs by the U.S. or China; and 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 and the related impact to spacing assumptions for future drilling locations, the viability of production under varying economic conditions, including commodity price declines, and variations in production levels and associated costs. For example, we recognized asset impairments of $2.7 billion in 2020 due to the significant decrease in commodity prices resulting primarily from the COVID-19 pandemic. Consequently, material revisions to our existing Discoveries or Acquisitions of Reserves Are Needed to Avoid a Material Decline in Reserves and Production, and Such Activities Are Capital Intensive 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 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 16 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; adverse weather conditions, such as tornadoes, hurricanes, severe thunderstorms and extreme temperatures, the severity and frequency of which could potentially increase as a consequence of climate change; 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. Many of the factors described above have negatively impacted our operations in the past and may do so again in the future. 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 historically have, and in the future 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 independent 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, gender or age 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, many of our contract counterparties have become subject to increasing governmental oversight and regulations in recent years, which could adversely affect the cost and availability of our hedging arrangements. We Have Limited Control Over Properties and Investments Operated by Others or through Joint Ventures Certain of the properties and investments in which we have an interest are operated by other companies and may involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties and investments, including compliance with environmental, health and safety regulations or the amount and timing of required future capital expenditures. In addition, we conduct certain of our operations through joint ventures in which we may share control with third parties, and the other joint venture participants may have interests or goals that are inconsistent with those of the joint venture or us. These limitations and our dependence on such third parties could result in unexpected future costs or liabilities and unplanned changes in operations or future development, which could adversely affect our financial condition and results of operations. 17 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 gather and 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, terrorism or sabotage, cyberattacks, accidents, field labor issues or strikes. Additionally, midstream operators have in the past been, and in the future may be, subject to constraints that limit their ability to construct, maintain or repair the facilities needed to gather, process and transport our production. Such interruptions or constraints could adversely impact our operations, including by requiring us to curtail our production or obtain alternative takeaway capacity on less favorable terms. 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, services and personnel required to explore, develop and operate properties, such as drilling rigs and oilfield services. The rising costs and scarcity caused by this competitive pressure will generally increase during periods of higher commodity prices and can be further exacerbated by higher inflation rates and supply chain disruptions in the broader economy. For example, we experienced higher operating costs throughout 2022 due to these factors, and we expect such inflationary pressures to continue in 2023. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our competitors have resources substantially greater than ours and may have established superior strategic long-term positions and relationships. 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. Legal, Regulatory and Environmental Risks We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact Our Business Our operations are subject to extensive federal, state, 18 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. For example, President Biden issued an executive order in January 2021, imposing a near total pause on entering new oil and gas leases on public lands. Although the pause on leasing was subsequently lifted in April 2022, the Department of the Interior issued a report on the federal leasing program in November 2021 that recommended various changes, including, among other things, enhancing bonding requirements and applying a more rigorous land-use planning process prior to leasing. The IRA responded, in part, to the report’s recommendations by increasing onshore royalty rates on all new federal leases. However, certain of the report’s recommendations require further Congressional actions, and we cannot predict to what extent, if any, the Department of the Interior may be able to promulgate rules implementing the remaining recommendations of the November 2021 report. 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 burdens 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. As of December 31, 2022, less than 20% of our total leasehold resides on federal lands, which is primarily located in the Delaware and Powder River Basins. Hydraulic Fracturing – 19 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 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. In addition, the IRA includes various changes to the federal tax laws beginning in 2023, including (i) a new 15% corporate alternative minimum tax on “adjusted financial statement income” and (ii) a new 1% excise tax on stock repurchases. While we are still evaluating the full impact of this legislation, and await further guidance and clarifications from the U.S. Treasury, we expect incremental taxes attributable to these new tax provisions. 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 GHG 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 GHG. For example, the EPA released rule proposals during 2021 and 2022 that if adopted would, among other things, (i) broaden methane and volatile organic compounds emission reduction requirements for certain oil and gas facilities, including a zero-emission standard for pneumatic controllers, and (ii) impose standards to eliminate venting of associated gas, and require capture and sale of gas where sale line is available, at new and existing oil wells. Moreover, the recently enacted IRA imposes a new charge or fee with respect to excess methane emissions from certain petroleum and natural gas facilities starting in 2024 and annually increasing through 2026. In addition to these federal efforts, several states where we operate, including New Mexico, Texas and Wyoming, have already imposed, or stated intentions to impose, laws or regulations designed to reduce methane emissions from oil and gas exploration and production activities, including by mandating new leak detection and retrofitting requirements. Policy makers have also advocated for expanding existing, or creating new, reporting and disclosure requirements regarding GHG emissions and other climate-related matters. For example, the EPA proposed amendments in June 2022 to its Green House Gas Reporting Program, which would, among other things, add well blowouts and other abnormal events as new categories of sources for GHG emissions reporting. In addition, the SEC proposed rules in March 2022 that would require public companies to include extensive climate-related disclosures in their SEC filings. Among other things, the proposed SEC rules, if adopted as written, would mandate disclosures on (i) GHG emissions, including Scope 3 emissions if material or part of a company’s emissions goal, (ii) financial impact and expenditure metrics relating to severe weather and climate change and (iii) a company’s use of scenario analysis and climate targets. Although the SEC has not finalized these rules, we would expect to incur substantial additional compliance costs to the extent these or similar rules are adopted. We further anticipate the costs and other risks associated with any such disclosure requirements to be particularly heightened, given that reporting frameworks on GHG emissions and other climate-related metrics are still maturing and often require the use of numerous assumptions and judgments. Additionally, public statements with respect to emissions reduction goals, environmental targets or, more broadly, ESG-related goals, are becoming increasingly subject to heightened scrutiny from public and governmental authorities with respect to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks which could, in turn, lead to further negative sentiment against us and our industry. 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 continued to highlight 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. President Biden subsequently announced a target of reducing economy-wide net GHG emissions in the U.S. by 50% to 52% below 2005 levels by 2030. At the international level, the United States and the European Union jointly announced the launch of a Global Methane Pledge at the 26th Conference of the Parties in 2021, pursuant to which over 130 participating countries have pledged to a collective goal of reducing global methane emissions by at least 20 30% from 2020 levels by 2030. Although the full impact of these actions 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 relating to 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 or otherwise encouraging 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. In addition, 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. The increasing attention to climate change may result in further claims or investigations against us, and heightened societal or political pressures may increase the possibility that liability could be imposed on us in such matters without regard to our causation of, or contribution to, the asserted damage or violation, or to other mitigating factors. Finally, climate change may also result in various enhanced physical risks, such as an increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that may adversely impact our operations. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we are subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce demand for energy for heating purposes. These and the other risks discussed above could result in additional costs, new restrictions on our operations and reputational harm to us, as well as reduce the actual and forecasted demand for our products. These affects in turn could impair or lower the value of our assets, including by resulting in uneconomic or “stranded” assets, and otherwise adversely impact our profitability, liquidity and financial condition. Price Controls, Export Restrictions and Other Governmental Interventions in Energy Markets May Adversely Impact our Business Domestic and foreign governmental bodies have from time to time intervened in energy markets by imposing price controls, restricting exports, limiting production or otherwise taking actions to impact the availability and price of oil, natural gas and NGLs. For instance, members of the European Union agreed to a price-cap framework in December 2022 for the trading of natural gas in response to rising energy costs in Europe. Similarly, during 2021 and 2022, President Biden authorized several releases from the U.S. Strategic Petroleum Reserve in an effort to lower domestic energy prices. Governments may take similar actions in the future, particularly in the event of disruption in energy markets or national emergency. Any such interventions could adversely impact our business, including by depressing the price of our production and generally introducing greater uncertainty to our operations. General and Other Risks Facing our Business 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 created significant volatility, uncertainty and turmoil in the oil and gas industry and the broader economy. The pandemic and the related responses of governmental authorities and others to limit the spread of the virus significantly reduced global economic activity, which resulted in an unprecedented decline in the demand for oil and other commodities during 2020, along with a corresponding deterioration in commodity prices. Moreover, the COVID-19 pandemic contributed to disruption and volatility in global supply chains that resulted in increased costs and delays for materials, and we and our service providers faced increased potential for business interruption and other operational risks due to changes of business practices and possible constraints in retaining sufficient personnel due to illness, quarantines, government actions or other restrictions in connection with the pandemic. Although commodity prices subsequently recovered after their decline in 2020, COVID-19, its variants or any other future pandemic could lead to similar protracted periods of depressed commodity prices or result in other significant adverse consequences to our business. Further, to the extent COVID-19 or any other pandemic adversely affects our business or the global economic conditions more generally, it may also have the effect of heightening many of the other risks described in this report. 21 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 Senior 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. Our business has been adversely impacted by counterparty defaults in the past, and we may experience similar defaults again in the future. Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us As of December 31, 2022, we had total indebtedness of $6.4 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to: In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that may impact our credit ratings include, among others, debt levels, planned asset sales and purchases, liquidity, size and scale of our production and commodity prices. Certain of our contractual obligations require us to provide letters of credit or other assurances. 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 the Senior Credit Facility as well as the cost of any other future debt. Cyberattacks May Adversely Impact Our Operations Our business has become increasingly dependent on digital technologies, and we anticipate expanding 22 Although we have 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 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, In recent years, proxy contests and Our Acquisition and Divestiture Activities Involve Substantial Risks Our business depends, in part, on making acquisitions, including by merger and other similar transactions, 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. Our Ability to Declare and Pay Dividends and Repurchase Shares Is Subject to Certain Considerations Dividends, whether fixed or variable, and share repurchases are authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including the Company’s financial results, cash requirements and future prospects, as well as such other factors deemed relevant by our Board of Directors. We can provide no assurance that we will continue to pay dividends or execute share repurchases at the current rate or at all. Any elimination of, or downward revision in, our dividend payout or share repurchase program could have an adverse effect on the market price of our common stock. Item 1B. Not applicable. We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report and subject to the matters noted below, there were no material pending legal proceedings to which we are a party or to which any of our property is subject. For more information on our legal contingencies, see Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report. Item 4.Mine Safety Disclosures Not applicable. Item 5.Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our common stock is traded on the Price Range of Common Stock Dividends High Low Per Share Quarter Ended 2017: December 31, 2017 $ 42.60 $ 33.98 $ 0.06 September 30, 2017 $ 37.44 $ 28.80 $ 0.06 June 30, 2017 $ 43.50 $ 29.89 $ 0.06 March 31, 2017 $ 49.45 $ 38.02 $ 0.06 Quarter Ended 2016: December 31, 2016 $ 50.66 $ 36.64 $ 0.06 September 30, 2016 $ 45.62 $ 35.01 $ 0.06 June 30, 2016 $ 39.47 $ 25.55 $ 0.06 March 31, 2016 $ 32.93 $ 18.07 $ 0.24 can be found in 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, the SPDR Oil and Gas Exploration & Production ETF ("XOP U.S. Equity") and a peer group of companies to which we compare our performance. 25 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 Issuer Purchases of Equity Securities The following table Period Total Number of Average Price 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 31 370 $ 72.48 368 $ 723 November 1 - November 30 373 $ 71.46 372 $ 696 December 1 - December 31 62 $ 68.27 62 $ 692 Total 805 $ 71.68 802 Item 6.[Reserved] Period Total Number of Shares Purchased (1) Average Price Paid per Share October 1 - October 31 9,768 $ 35.27 November 1 - November 30 29,160 $ 38.68 December 1 - December 31 2,321 $ 39.06 Total 41,249 $ 37.89 Item 2017 2016* 2015* 2014* 2013* Statement of Earnings data: Upstream revenues $ 5,307 $ 3,981 $ 5,885 $ 11,619 $ 7,296 Total revenues $ 13,949 $ 10,304 $ 13,145 $ 19,285 $ 9,362 Earnings (loss) from continuing operations (1) $ 1,078 $ (1,458 ) $ (13,645 ) $ (753 ) $ (938 ) Earnings (loss) from continuing operations attributable to Devon (1) $ 898 $ (1,056 ) $ (12,896 ) $ (837 ) $ (938 ) Earnings (loss) from continuing operations per share attributable to Devon: Basic (1) $ 1.71 $ (2.09 ) $ (31.72 ) $ (2.08 ) $ (2.34 ) Diluted (1) $ 1.70 $ (2.09 ) $ (31.72 ) $ (2.08 ) $ (2.34 ) Cash dividends per common share $ 0.24 $ 0.42 $ 0.96 $ 0.94 $ 0.86 Balance Sheet data: Total assets (1) $ 30,241 $ 28,675 $ 29,673 $ 49,253 $ 44,390 Long-term debt (2) $ 10,291 $ 10,154 $ 12,056 $ 9,761 $ 7,888 Stockholders' equity $ 14,104 $ 12,722 $ 11,111 $ 24,789 $ 20,729 Common shares outstanding 525 523 418 409 406 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 primarily focus on 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of Executive Overview Looking across our 2021 and 2022 performance, the Merger has helped us become a leading unconventional 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 accelerated our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy. In the third quarter of 2022, we We remain focused on building economic value by executing on our We remain committed to capital discipline and Commodity prices strengthened in 2021 and continued to 27 prices to increase even more throughout most of 2022. However, oil prices did begin to decline in the fourth quarter of 2022 due to economic uncertainty surrounding inflation and increased interest rates as well as certain geopolitical events. As presented in the graph at the left, commodity prices are volatile and heavily influence our financial performance and trends. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub gas prices ranged from average highs of $94.39 per Bbl and $6.65 per MMBtu, respectively, to average lows of $39.59 per Bbl and $2.08 per MMBtu, respectively. Trends of our annual earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The annual earnings chart and cash flow chart present 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 earnings in 2020 were negatively impacted by lower commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic. Earnings improved significantly in 2021 due to commodity prices recovering from the initial COVID-19 pandemic as well as the Merger closing in January 2021. Earnings continued to improve 28 during Our net earnings in recent years have been significantly impacted by asset impairments and temporary, noncash adjustments to the value of our commodity hedges. Net earnings in both 2020 and 2021 included a $0.1 billion hedge valuation loss, net of taxes and 2022 included a $0.5 billion hedge valuation gain, net of taxes. Additionally, net earnings in 2020 included $2.2 billion of asset impairments on our proved and unproved properties, net of taxes, due to reduced demand from the COVID-19 pandemic. Excluding these amounts, our core earnings have been more stable over recent years but continue to be heavily influenced by commodity prices. Like earnings, our operating cash flow is sensitive to volatile commodity prices. We have continued to deliver strong cash flow and EBITDAX results primarily due to improved commodity prices and overall market conditions as well as strong operating performance. We exited As commodity prices and our operating performance strengthen and bolster our financial 2017 Change 2016* Change 2015* Net earnings (loss) attributable to Devon $ 898 +185 % $ (1,056 ) +92 % $ (12,896 ) Net earnings (loss) per diluted share attributable to Devon $ 1.70 +181 % $ (2.09 ) +93 % $ (31.72 ) Core earnings (loss) attributable to Devon (1) $ 427 +217 % $ (367 ) - 430 % $ 111 Core earnings (loss) per diluted share attributable to Devon (1) $ 0.81 +210 % $ (0.73 ) - 382 % $ 0.26 Retained production (MBoe/d) 541 - 4 % 563 - 3 % 580 Total production (MBoe/d) 543 - 11 % 611 - 10 % 680 Realized price per Boe (2) $ 25.96 +39 % $ 18.72 - 14 % $ 21.68 Operating cash flow $ 2,909 +94 % $ 1,500 - 69 % $ 4,898 Capitalized expenditures, including acquisitions $ 2,937 - 25 % $ 3,908 - 32 % $ 5,712 Shareholder and noncontrolling interests distributions $ 481 - 8 % $ 525 - 19 % $ 650 Cash and cash equivalents $ 2,673 +36 % $ 1,959 - 15 % $ 2,310 Total debt $ 10,406 +2 % $ 10,154 - 22 % $ 13,032 Reserves (MMBoe) 2,152 +5 % 2,058 - 6 % 2,182 Business and Industry Outlook In 2022, Devon marked its 29 economic cycles. In line with this strategy, we In 2022, WTI oil prices averaged $94.39 per Bbl versus $67.86 per Bbl in 2021. Crude prices experienced significant improvement from the We expect to continue our capital-efficiency focus and our steadfast commitment to capital discipline with our 2023 capital program which is expected to maintain our oil production at similar levels as 2022, adjusted for acquisitions. To achieve our 2023 capital program objectives that maximize free cash flow, approximately 60% of our 2023 spend is expected to be allocated to 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 2023 capital in our other core areas of Eagle Ford, Anadarko Basin, Powder River Basin and Williston Basin. Our 2023 capital is expected to be higher than last year partly due to a full year of planned capital spend on assets acquired during 2022. Additionally, the estimated impact of inflation has also been accounted for in our Results of Operations The following Our 2022 net earnings were $6.0 billion, compared to net earnings of $2.8 billion for 2021. The graph below 30 Production Volumes 2022 % of Total 2021 Change Oil (MBbls/d) Delaware Basin 210 70 % 197 7 % Anadarko Basin 14 5 % 15 -3 % Williston Basin 33 11 % 41 -20 % Eagle Ford 24 8 % 18 33 % Powder River Basin 14 5 % 15 -10 % Other 4 1 % 4 -5 % Total 299 100 % 290 3 % 2022 % of Total 2021 Change Gas (MMcf/d) Delaware Basin 607 62 % 535 13 % Anadarko Basin 221 23 % 217 2 % Williston Basin 61 6 % 58 4 % Eagle Ford 67 7 % 58 15 % Powder River Basin 19 2 % 20 -6 % Other 1 0 % 2 -50 % Total 976 100 % 890 10 % 2022 % of Total 2021 Change NGLs (MBbls/d) Delaware Basin 103 69 % 87 18 % Anadarko Basin 25 17 % 24 5 % Williston Basin 9 6 % 9 -5 % Eagle Ford 10 6 % 9 11 % Powder River Basin 2 2 % 3 -9 % Other — 0 % 1 N/M Total 149 100 % 133 12 % 2022 % of Total 2021 Change Combined (MBoe/d) Delaware Basin 414 68 % 374 11 % Anadarko Basin 76 13 % 75 1 % Williston Basin 51 8 % 60 -14 % Eagle Ford 45 7 % 37 23 % Powder River Basin 19 3 % 21 -9 % Other 5 1 % 5 -1 % Total 610 100 % 572 7 % 2017 % of Total 2016 Change Oil and bitumen (MBbls/d) STACK 26 11 % 19 +38 % Delaware Basin 31 13 % 33 - 7 % Rockies Oil 14 6 % 14 +1 % Heavy Oil 18 7 % 22 - 19 % Eagle Ford 34 14 % 39 - 14 % Barnett Shale 1 1 % 1 - 25 % Other 8 2 % 11 - 28 % Retained assets 132 54 % 139 - 4 % Divested assets 2 1 % 12 - 87 % Total Oil 134 55 % 151 - 11 % Bitumen 110 45 % 109 +1 % Total Oil and bitumen 244 260 - 6 % 2017 % of Total 2016 Change Gas (MMcf/d) STACK 304 25 % 293 +4 % Delaware Basin 90 7 % 90 +1 % Rockies Oil 15 1 % 25 - 39 % Heavy Oil 17 2 % 20 - 14 % Eagle Ford 95 8 % 101 - 6 % Barnett Shale 667 55 % 741 - 10 % Other 11 1 % 13 - 16 % Retained assets 1,199 99 % 1,283 - 7 % Divested assets 4 1 % 130 - 97 % Total 1,203 1,413 - 15 % 2017 % of Total 2016 Change NGLs (MBbls/d) STACK 31 31 % 26 +18 % Delaware Basin 11 11 % 12 - 9 % Rockies Oil 1 1 % 1 +2 % Eagle Ford 13 13 % 16 - 19 % Barnett Shale 41 42 % 45 - 8 % Other 2 2 % 2 +39 % Retained assets 99 100 % 102 - 2 % Divested assets — — 14 - 100 % Total 99 116 - 15 % 2017 % of Total 2016 Change Combined (MBoe/d) STACK 107 20 % 93 +15 % Delaware Basin 56 10 % 60 - 6 % Rockies Oil 17 3 % 19 - 8 % Heavy Oil 131 24 % 134 - 2 % Eagle Ford 62 11 % 72 - 13 % Barnett Shale 153 28 % 169 - 10 % Other 15 3 % 16 - 5 % Retained assets 541 99 % 563 - 4 % Divested assets 2 1 % 48 - 96 % Total 543 611 - 11 % Realized Prices 2022 Realization 2021 Change Oil (per Bbl) WTI index $ 94.39 $ 67.86 39 % Realized price, unhedged $ 94.11 100% $ 65.98 43 % Cash settlements $ (9.38 ) $ (11.60 ) Realized price, with hedges $ 84.73 90% $ 54.38 56 % 2017 Realization 2016 Change Oil and bitumen (per Bbl) WTI index $ 50.99 $ 43.36 +18 % Access Western Blend index $ 36.90 $ 26.96 +37 % U.S. $ 49.41 97% $ 38.92 +27 % Canada $ 29.99 59% $ 20.53 +46 % Realized price, unhedged $ 39.23 77% $ 29.65 +32 % Cash settlements $ 0.23 $ (0.43 ) Realized price, with hedges $ 39.46 77% $ 29.22 +35 % 2017 Realization 2016 Change Gas (per Mcf) Henry Hub index $ 3.11 $ 2.46 +26 % Realized price, unhedged $ 2.48 80% $ 1.84 +35 % Cash settlements $ 0.08 $ 0.07 Realized price, with hedges $ 2.56 82% $ 1.91 +34 % 2017 Realization 2016 Change NGLs (per Bbl) Mont Belvieu blended index (1) $ 24.77 $ 17.20 +44 % Realized price, unhedged $ 15.66 63% $ 9.81 +60 % Cash settlements $ (0.10 ) $ (0.11 ) Realized price, with hedges $ 15.56 63% $ 9.70 +60 % 2022 Realization 2021 Change Gas (per Mcf) Henry Hub index $ 6.65 $ 3.85 73 % Realized price, unhedged $ 5.47 82% $ 3.40 61 % Cash settlements $ (0.93 ) $ (0.66 ) Realized price, with hedges $ 4.54 68% $ 2.74 66 % 2017 2016 Change Combined (per Boe) U.S. $ 24.88 $ 18.34 +36 % Canada $ 29.39 $ 20.07 +46 % 2022 Realization 2021 Change NGLs (per Bbl) WTI index $ 94.39 $ 67.86 39 % Realized price, unhedged $ 25.96 $ 18.72 +39 % $ 34.18 36% $ 29.52 16 % Cash settlements $ 0.27 $ (0.05 ) $ — $ (0.38 ) Realized price, with hedges $ 26.23 $ 18.67 +40 % $ 34.18 36% $ 29.14 17 % 2022 2021 Change Combined (per Boe) Realized price, unhedged $ 63.20 $ 45.68 38 % Cash settlements $ (6.08 ) $ (7.01 ) Realized price, with hedges $ 57.12 $ 38.67 48 % Hedge Settlements 2022 2021 Change Q Oil $ (1,025 ) $ (1,230 ) 17 % Natural gas (331 ) (213 ) -55 % NGL — (19 ) 100 % Total cash settlements (1) $ (1,356 ) $ (1,462 ) 7 % 2017 2016 Change Oil $ 21 $ (41 ) +151 % Natural gas 35 35 +0 % NGL (3 ) (5 ) +40 % Total cash settlements 53 (11 ) N/M Valuation changes 104 (190 ) +155 % Total $ 157 $ (201 ) +178 % Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note Production Expenses 2022 2021 Change LOE $ 1,071 $ 859 25 % Gathering, processing & transportation 693 606 14 % Production taxes 954 633 51 % Property taxes 79 33 139 % Total $ 2,797 $ 2,131 31 % Per Boe: LOE $ 4.81 $ 4.12 17 % Gathering, processing & transportation $ 3.11 $ 2.91 7 % Percent of oil, gas and NGL sales: Production taxes 6.8 % 6.6 % 2 % LOE and gathering, processing and transportation expenses increased primarily due to inflation and higher volumes resulting from increased activity and acquisitions in the Williston Basin and Eagle Ford. Production and property taxes also increased due to higher commodity prices. 32 Field-Level Cash Margin The table below presents the field-level cash 2022 $ per BOE 2021 $ per BOE Field-level cash margin (Non-GAAP) Delaware Basin $ 8,074 $ 53.39 $ 5,183 $ 37.98 Anadarko Basin 968 $ 35.00 616 $ 22.46 Williston Basin 867 $ 46.28 759 $ 34.79 Eagle Ford 870 $ 52.68 474 $ 35.33 Powder River Basin 401 $ 57.39 290 $ 37.83 Other 105 $ 62.58 78 $ 42.00 Total $ 11,285 $ 50.65 $ 7,400 $ 35.47 DD&A 2022 2021 Change Oil and gas per Boe $ 9.52 $ 9.83 -3 % Oil and gas $ 2,119 $ 2,050 3 % Other property and equipment 104 108 -4 % Total $ 2,223 $ 2,158 3 % DD&A increased in 2022 primarily due to higher volumes which was partially offset by lower DD&A rates. The decrease in DD&A rates was primarily due to an increase in oil, gas and NGL reserve estimates at December 31, 2021, resulting from higher prices. General and Administrative Expense 2022 2021 Change G&A per Boe $ 1.77 $ 1.88 -6 % Labor and benefits $ 229 $ 255 -10 % Non-labor 166 136 22 % Total $ 395 $ 391 1 % Other Items 2022 2021 Change in earnings Commodity hedge valuation changes (1) $ 698 $ (82 ) $ 780 Marketing and midstream operations (35 ) (19 ) (16 ) Exploration expenses 29 14 (15 ) Asset dispositions (44 ) (168 ) (124 ) Net financing costs 309 329 20 Restructuring and transaction costs — 258 258 Other, net (95 ) (43 ) 52 $ 955 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. 33 Table of Contents 2017 2016 Change LOE $ 927 $ 1,027 - 10 % Gathering & transportation 647 555 +17 % Production taxes 194 147 +32 % Property taxes 55 74 - 26 % Total $ 1,823 $ 1,803 +1 % Per Boe: LOE $ 4.67 $ 4.59 +2 % Gathering & transportation $ 3.26 $ 2.48 +31 % Percent of oil, gas and NGL sales: Production taxes 3.8 % 3.5 % +7 % In 2022, asset dispositions include $42 million 2017 2016 Change Operating revenues $ 5,740 $ 4,252 +35 % Product purchases (4,362 ) (3,015 ) +45 % Operations and maintenance expenses (418 ) (398 ) +5 % EnLink margin 960 839 +14 % Devon margin (48 ) (49 ) - 2 % Total $ 912 $ 790 +15 % report. 2017 2016 Change Unproved impairments $ 217 $ 77 +182 % Geological and geophysical 110 65 +70 % Exploration overhead and other 53 73 - 27 % Total $ 380 $ 215 +77 % 2017 2016 Change Oil and gas per Boe $ 7.15 $ 6.47 +11 % Oil and gas $ 1,419 $ 1,446 - 2 % Midstream and other assets 110 146 - 25 % Devon 1,529 1,592 - 4 % EnLink 545 504 +8 % Total $ 2,074 $ 2,096 - 1 % Restructuring and transaction costs in 2021 reflect workforce reductions in conjunction with the 2017 2016 Change Labor and benefits $ 589 $ 614 - 4 % Non-labor 228 215 +6 % Reimbursed G&A (73 ) (82 ) - 11 % Total Devon 744 747 - 0 % EnLink 128 118 +8 % Total $ 872 $ 865 +1 % Income Taxes 2022 2021 Current expense $ 559 $ 16 Deferred expense 1,179 49 Total expense $ 1,738 $ 65 Current tax rate 7 % 0 % Deferred tax rate 15 % 2 % Effective income tax rate 22 % 2 % For discussion on income taxes, see Note 8in “Item 8. Financial Statements and Supplementary Data” of this report. 2017 2016 Change Asset impairments $ 17 $ 1,310 - 99 % Asset dispositions (217 ) (1,483 ) - 85 % Restructuring — 267 N/M Other (124 ) 108 - 215 % Total $ (324 ) $ 202 - 260 % 2017 2016 Current expense $ 112 $ 100 Deferred expense (benefit) (294 ) 41 Total expense (benefit) $ (182 ) $ 141 Effective income tax rate (20 %) (11 %) 2016 % of Total 2015 Change Oil and bitumen (MBbls/d) STACK 19 7 % 7 +152 % Delaware Basin 33 13 % 39 - 16 % Rockies Oil 14 5 % 15 - 9 % Heavy Oil 22 9 % 27 - 17 % Eagle Ford 39 15 % 61 - 35 % Barnett Shale 1 0 % 1 - 28 % Other 11 4 % 13 - 11 % Retained assets 139 53 % 163 - 15 % Divested assets 12 5 % 28 - 56 % Total Oil 151 58 % 191 - 21 % Bitumen 109 42 % 84 +29 % Total Oil and bitumen 260 275 - 6 % 2016 % of Total 2015 Change Gas (MMcf/d) STACK 293 21 % 239 +23 % Delaware Basin 90 6 % 71 +27 % Rockies Oil 25 2 % 40 - 37 % Heavy Oil 20 1 % 22 - 11 % Eagle Ford 101 7 % 141 - 28 % Barnett Shale 741 53 % 815 - 9 % Other 13 1 % 17 - 22 % Retained assets 1,283 91 % 1,345 - 5 % Divested assets 130 9 % 265 - 51 % Total 1,413 1,610 - 12 % 2016 % of Total 2015 Change NGLs (MBbls/d) STACK 26 23 % 21 +22 % Delaware Basin 12 10 % 9 +28 % Rockies Oil 1 1 % 1 - 9 % Eagle Ford 16 14 % 23 - 33 % Barnett Shale 45 39 % 51 - 12 % Other 2 1 % 4 - 59 % Retained assets 102 88 % 109 - 7 % Divested assets 14 12 % 27 - 50 % Total 116 136 - 15 % 2016 % of Total 2015 Change Combined (MBoe/d) STACK 93 15 % 68 +37 % Delaware Basin 60 10 % 60 - 1 % Rockies Oil 19 3 % 23 - 17 % Heavy Oil 134 22 % 115 +17 % Eagle Ford 72 12 % 107 - 33 % Barnett Shale 169 28 % 188 - 10 % Other 16 2 % 19 - 13 % Retained assets 563 92 % 580 - 3 % Divested assets 48 8 % 100 - 52 % Total 611 680 - 10 % 2016 Realization 2015 Change Oil and bitumen (per Bbl) WTI index $ 43.36 $ 48.87 - 11 % Access Western Blend index $ 26.96 $ 32.18 - 16 % U.S. $ 38.92 90% $ 44.01 - 12 % Canada $ 20.53 47% $ 25.14 - 18 % Realized price, unhedged $ 29.65 68% $ 36.39 - 19 % Cash settlements $ (0.43 ) $ 20.72 Realized price, with hedges $ 29.22 67% $ 57.11 - 49 % 2016 Realization 2015 Change Gas (per Mcf) Henry Hub index $ 2.46 $ 2.67 - 8 % Realized price, unhedged $ 1.84 75% $ 2.14 - 14 % Cash settlements $ 0.07 $ 0.57 Realized price, with hedges $ 1.91 77% $ 2.71 - 30 % 2016 Realization 2015 Change NGLs (per Bbl) Mont Belvieu blended index (1) $ 17.20 $ 16.93 +2 % Realized price, unhedged $ 9.81 57% $ 9.32 +5 % Cash settlements $ (0.11 ) $ — Realized price, with hedges $ 9.70 56% $ 9.32 +4 % 2016 2015 Change Combined (per Boe) U.S. $ 18.34 $ 21.12 - 13 % Canada $ 20.07 $ 24.46 - 18 % Realized price, unhedged $ 18.72 $ 21.68 - 14 % Cash settlements $ (0.05 ) $ 9.74 Realized price, with hedges $ 18.67 $ 31.42 - 41 % 2016 2015 Change Oil $ (41 ) $ 2,083 - 102 % Natural gas 35 333 - 89 % NGL (5 ) — N/M Total cash settlements (11 ) 2,416 - 100 % Valuation changes (190 ) (1,913 ) +90 % Total $ (201 ) $ 503 - 140 % 2016 2015 Change LOE $ 1,027 $ 1,509 - 32 % Gathering & transportation 555 595 - 7 % Production taxes 147 207 - 29 % Property taxes 74 128 - 42 % Total $ 1,803 $ 2,439 - 26 % Per Boe: LOE $ 4.59 $ 6.08 - 24 % Gathering & transportation $ 2.48 $ 2.40 +4 % Percent of oil, gas and NGL sales: Production taxes 3.5 % 3.8 % - 8 % 2016 2015 Change Operating revenues $ 4,252 $ 4,451 - 4 % Product purchases (3,015 ) (3,245 ) - 7 % Operations and maintenance expenses (398 ) (419 ) - 5 % EnLink margin 839 787 +7 % Devon margin (49 ) 12 N/M Total $ 790 $ 799 - 1 % 2016 2015 Change Unproved impairments $ 77 $ 260 - 70 % Geological and geophysical 65 108 - 40 % Exploration overhead and other 73 83 - 13 % Total $ 215 $ 451 - 52 % 2016 2015 Change Oil and gas per Boe $ 6.47 $ 13.99 - 54 % Oil and gas $ 1,446 $ 3,474 - 58 % Midstream and other assets 146 161 - 10 % Devon 1,592 3,635 - 56 % EnLink 504 387 +30 % Total $ 2,096 $ 4,022 - 48 % 2016 2015 Change Labor and benefits $ 614 $ 866 - 29 % Non-labor 215 310 - 31 % Reimbursed G&A (82 ) (120 ) - 31 % Total Devon 747 1,056 - 29 % EnLink 118 137 - 14 % Total $ 865 $ 1,193 - 27 % 2016 2015 Change Asset impairments $ 1,310 $ 17,647 - 93 % Asset dispositions (1,483 ) 7 N/M Restructuring 267 78 +242 % Other 108 186 - 42 % Total $ 202 $ 17,918 - 99 % 2016 2015 Current expense $ 100 $ (237 ) Deferred expense (benefit) 41 (5,976 ) Total expense (benefit) $ 141 $ (6,213 ) Effective income tax rate (11 %) 31 % Capital Resources, Uses and Liquidity Sources and Uses of Cash The following table presents the major Devon EnLink Consolidated 2017 2016* 2015* 2017 2016* 2015* 2017 2016* 2015* Operating cash flow $ 2,209 $ 834 $ 4,271 $ 700 $ 666 $ 627 $ 2,909 $ 1,500 $ 4,898 Issuance of common stock — 1,469 — — — — — 1,469 — Divestitures of property and investments 415 3,020 106 192 93 1 607 3,113 107 Capital expenditures (1,968 ) (1,384 ) (4,214 ) (791 ) (663 ) (573 ) (2,759 ) (2,047 ) (4,787 ) Acquisitions of property, equipment and businesses (46 ) (849 ) (583 ) — (792 ) (524 ) (46 ) (1,641 ) (1,107 ) Debt activity, net — (3,383 ) 770 2 228 1,061 2 (3,155 ) 1,831 Shareholder and noncontrolling interests distributions (127 ) (221 ) (396 ) (354 ) (304 ) (254 ) (481 ) (525 ) (650 ) EnLink and General Partner distributions 265 265 268 (265 ) (265 ) (268 ) — — — Subsidiary unit transactions — — 654 501 892 25 501 892 679 Effect of exchange rate and other (53 ) (96 ) 4 34 139 (145 ) (19 ) 43 (141 ) Net change in cash and cash equivalents $ 695 $ (345 ) $ 880 $ 19 $ (6 ) $ (50 ) $ 714 $ (351 ) $ 830 Cash and cash equivalents at end of period $ 2,642 $ 1,947 $ 2,292 $ 31 $ 12 $ 18 $ 2,673 $ 1,959 $ 2,310 Year Ended December 31, 2022 2021 Operating cash flow $ 8,530 $ 4,899 WPX acquired cash — 344 Acquisitions of property and equipment (2,583 ) (18 ) Divestitures of property and equipment 39 79 Capital expenditures (2,542 ) (1,989 ) Investment activity, net (37 ) 10 Debt activity, net — (1,302 ) Repurchases of common stock (718 ) (589 ) Common stock dividends (3,379 ) (1,315 ) Noncontrolling interest activity, net (30 ) (41 ) Other (97 ) (44 ) Net change in cash, cash equivalents and restricted cash $ (817 ) $ 34 Cash, cash equivalents and restricted cash at end of period $ 1,454 $ 2,271 Operating Cash Flow and WPX Acquired Cash During Divestitures of Property and Equipment During 35 Capital Expenditures The Year Ended December 31, 2017 2016* 2015* Oil and gas $ 1,879 $ 1,341 $ 4,056 Corporate and other 89 43 158 Total capital expenditures $ 1,968 $ 1,384 $ 4,214 Acquisitions $ 46 $ 849 $ 583 Year Ended December 31, 2022 2021 Delaware Basin $ 1,678 $ 1,535 Anadarko Basin 157 53 Williston Basin 158 77 Eagle Ford 229 122 Powder River Basin 149 73 Other 9 3 Total oil and gas 2,380 1,863 Midstream 92 64 Other 70 62 Total capital expenditures $ 2,542 $ 1,989 Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Investment Activity During 2022 and 2021, Devon received distributions from our investments of $39 million and $35 million, respectively. Devon contributed $76 million and $25 million to our investments during 2022 and 2021, respectively. The 2022 contributions primarily related to our investment in Debt Activity Subsequent to the Repurchases of Common Stock and Shareholder Distributions We repurchased 11.7 million shares of common stock for $718 million in 2022 and 14 million shares of common stock for $589 million in 2021 under share repurchase programs authorized by our 36 The following table summarizes our common stock dividends in 2022 and 2021. In February 2022, our Board of Directors increased our fixed dividend rate by Fixed Variable Total Rate Per Share 2022: First quarter $ 109 $ 558 $ 667 $ 1.00 Second quarter 105 725 830 $ 1.27 Third quarter 117 890 1,007 $ 1.55 Fourth quarter 117 758 875 $ 1.35 Total year-to-date $ 448 $ 2,931 $ 3,379 2021: First quarter $ 76 $ 127 $ 203 $ 0.30 Second quarter 75 154 229 $ 0.34 Third quarter 74 255 329 $ 0.49 Fourth quarter 73 481 554 $ 0.84 Total year-to-date $ 298 $ 1,017 $ 1,315 Noncontrolling Interest Activity During Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture 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 2022, we held approximately $1.5 billion of cash. Our operating cash flow Commodity Prices – The most uncertain and volatile 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. 37 Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, we remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2023. The currently elevated level of cost inflation could erode our cost efficiencies gained over previous years and pressure our margin in 2023. Despite this, we expect to continue generating material amounts of free cash flow at current commodity price levels due to our strategy of spending within cash flow. 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 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 We have $3.0 billion of 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%. Our access to funds from the Senior Credit Facility is not As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness. Debt Ratings We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, 38 reserve mix, debt levels, cost structure, planned asset sales and There are no “rating triggers” in any of our Fixed Plus Variable Dividend We are committed to a "fixed plus variable" dividend strategy. Our 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. Our Board of Directors increased our quarterly fixed dividend rate by 45% to $0.16 per share in February 2022 and again by 13% to $0.18 per share beginning in August 2022. In addition to the fixed quarterly dividend, we may pay a variable dividend up to 50% of our 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 our financial results, cash requirements, future prospects and other factors deemed relevant by the Board. In February 2023, Devon announced a cash dividend in the amount of $0.89 per share payable in the first quarter of 2023. The dividend consists of a fixed quarterly dividend in the amount of $130 million (or $0.20 per share) and a variable dividend in the amount of approximately $449 million (or $0.69 per share). Share Repurchase Program Our Board of Directors has authorized a $2.0 billion share repurchase program that expires on May 4, 2023. Through February 10, 2023, we had executed $1.3 billion of the authorized program. Capital Expenditures Our Payments Due by Period Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years Devon obligations: Debt (1) $ 6,933 $ 115 $ 162 $ 1,500 $ 5,156 Interest expense (2) 6,188 390 756 715 4,327 Purchase obligations (3) 1,880 613 1,133 134 — Operational agreements (4) 5,259 522 756 739 3,242 Operational agreements with EnLink (5) 909 637 272 — — Asset retirement obligations (6) 1,152 39 134 171 808 Drilling and facility obligations (7) 629 216 218 89 106 Lease obligations (8) 381 88 157 117 19 Other (9) 115 115 — — — Total Devon obligations 23,446 2,735 3,588 3,465 13,658 EnLink obligations: Debt (1) 3,574 — 474 — 3,100 Interest expense (2) 2,573 160 304 298 1,811 Other (9) 496 306 55 45 90 Total EnLink obligations 6,643 466 833 343 5,001 Total obligations $ 30,089 $ 3,201 $ 4,421 $ 3,808 $ 18,659 Contingencies and Legal Matters For a detailed discussion of contingencies and legal matters, see Note 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. 39 Oil and Gas Assets Accounting, Classification, Reserves Category Total equity as of September 30, 2017 (Full Cost) $ 11,934 Adjustments from inception through 2007, net (2,147 ) Adjustments after 2007: Lower asset impairments, net 18,317 Exploration expense (5,402 ) Higher DD&A, driven largely by lower impairments (5,036 ) G&A expensed rather than capitalized (3,075 ) Other (asset dispositions, foreign exchange cumulative translation adjustment, etc.) 418 Deferred income tax on the above items (1,152 ) Total adjustments after 2007 4,070 Equity increase (+16%) 1,923 Total equity as of September 30, 2017 (Successful Efforts) $ 13,857 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 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 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. 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 The passage of time provides additional information which may result in revisions to previous estimates to reflect updated information. In the past five years, annual revisions other than price to our proved reserve estimates, which 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 40 production, common infrastructure, common sales points, common processing plants, common regulation and management oversight to make common operating field determinations. These determinations impact the amount of DD&A recognized each period and could impact the determination and measurement of a potential asset impairment. Management evaluates assets for impairment through an established process in 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 reserves, and when needed, 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 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 Reduced demand from the COVID-19 pandemic and management of production levels from OPEC+ caused WTI pricing to As a Income Taxes The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. 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 41 On August 16, 2022, the IRA was signed into law and included various income tax related provisions with an effective date beginning in 2023. Among the enacted provisions are a 15% corporate alternative minimum tax (“CAMT”) and several new and expanded clean energy credits and incentives. The CAMT will be assessed on applicable corporations with an average annual adjusted financial statement income that exceeds $1 billion for the preceding three consecutive years. The Company continues to assess the potential impact of the CAMT, and material incremental cash tax could be incurred depending on actual operating results as well as future U.S. Treasury guidance. Purchase Accounting Periodically we We made a number of assumptions in estimating the fair value of assets acquired and Estimated fair values ascribed to assets acquired can have a In addition to the 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 Amounts excluded for 42 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 We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures. Before tax After tax After Noncontrolling Interests Per Diluted Share 2017 Year Ended December 31, Before Tax After Tax After NCI Per Diluted Share 2022 Earnings attributable to Devon (GAAP) $ 896 $ 1,078 $ 898 $ 1.70 $ 7,775 $ 6,037 $ 6,015 $ 9.12 Adjustments: Asset dispositions (217 ) (138 ) (138 ) (0.26 ) (44 ) (34 ) (34 ) (0.05 ) Asset and exploration impairments 234 152 146 0.27 13 10 10 0.02 U.S. tax reform — (211 ) (112 ) (0.21 ) Deferred tax asset valuation allowance — (76 ) (76 ) (0.14 ) — 17 17 0.03 Fair value changes in financial instruments and foreign currency (218 ) (202 ) (201 ) (0.38 ) Legal entity restructuring — (86 ) (86 ) (0.16 ) Early retirement of debt (9 ) (7 ) (4 ) (0.01 ) Fair value changes in financial instruments (690 ) (532 ) (532 ) (0.81 ) Core earnings attributable to Devon (Non-GAAP) $ 686 $ 510 $ 427 $ 0.81 $ 7,054 $ 5,498 $ 5,476 $ 8.31 2016* Loss attributable to Devon (GAAP) $ (1,317 ) $ (1,458 ) $ (1,056 ) $ (2.09 ) 2021 Earnings attributable to Devon (GAAP) $ 2,898 $ 2,833 $ 2,813 $ 4.19 Adjustments: Asset dispositions (1,483 ) (989 ) (995 ) (1.95 ) (168 ) (129 ) (129 ) (0.19 ) Asset and exploration impairments 1,430 1,230 807 1.60 6 5 5 0.01 Rig stacking costs 10 6 6 0.01 Deferred tax asset valuation allowance — 385 385 0.76 — (639 ) (639 ) (0.95 ) Change in tax legislation — 60 60 0.09 Fair value changes in financial instruments 82 63 63 0.09 Restructuring and transaction costs 267 173 170 0.33 258 224 224 0.33 Fair value changes in financial instruments and foreign currency 270 153 145 0.28 Early retirement of debt 269 171 171 0.33 (30 ) (23 ) (23 ) (0.04 ) Core loss attributable to Devon (Non-GAAP) $ (554 ) $ (329 ) $ (367 ) $ (0.73 ) 2015* Loss attributable to Devon (GAAP) $ (19,858 ) $ (13,645 ) $ (12,896 ) $ (31.72 ) Adjustments: Asset dispositions 7 8 8 0.02 Asset and exploration impairments 17,914 11,955 11,131 27.37 Rig stacking costs 54 34 34 0.08 Deferred tax asset valuation allowance — 403 403 0.99 Restructuring and transaction costs 78 52 52 0.13 Fair value changes in financial instruments and foreign currency 1,967 1,349 1,346 3.31 Repatriations — 33 33 0.08 Core earnings attributable to Devon (Non-GAAP) $ 162 $ 189 $ 111 $ 0.26 $ 3,046 $ 2,394 $ 2,374 $ 3.53 Year ended December 31, Before Tax After Tax After NCI Per Diluted Share 2020 Continuing Operations Loss attributable to Devon (GAAP) $ (3,090 ) $ (2,543 ) $ (2,552 ) $ (6.78 ) Adjustments: Asset dispositions (1 ) — — — 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 ) 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. 44 Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin. Year Ended December 31, 2022 2021 2020 Net earnings (GAAP) $ 6,037 $ 2,833 $ (2,671 ) Net loss from discontinued operations, net of tax — — 128 Financing costs, net 309 329 270 Income tax expense (benefit) 1,738 65 (547 ) Exploration expenses 29 14 167 Depreciation, depletion and amortization 2,223 2,158 1,300 Asset impairments — — 2,693 Asset dispositions (44 ) (168 ) (1 ) Share-based compensation 87 77 76 Derivative and financial instrument non-cash valuation changes (698 ) 82 161 Restructuring and transaction costs — 258 49 Accretion on discounted liabilities and other (95 ) (43 ) (34 ) EBITDAX (Non-GAAP) 9,586 5,605 1,591 Marketing and midstream revenues and expenses, net 35 19 35 Commodity derivative cash settlements 1,356 1,462 (316 ) General and administrative expenses, cash-based 308 314 262 Field-level cash margin (Non-GAAP) $ 11,285 $ 7,400 $ 1,572 45 Item 7A.Quantitative and 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 The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, Interest Rate Risk At December 31, We had no material foreign currency risk at December 31, 46 Item 8.Financial Statements and Supplementary INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES Consolidated Financial Statements Consolidated Note 2 – Note 3 – Note 4 – Note 6 – Note 9 – Net Earnings (Loss) Per Share Note 11 – Supplemental Information to Statements of Cash Flows 81 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. Report of Independent To the Stockholders and Board of Directors 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 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, Basis for 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 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. 48 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 Matter The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 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 $2.1 billion for the year ended December 31, 2022. 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. /s/ KPMG, LLP We have served as the Company’s auditor since 1980. Oklahoma City, Oklahoma DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED Year Ended December 31, Year Ended December 31, 2017 2016* 2015* 2022 2021 2020 Upstream revenues $ 5,307 $ 3,981 $ 5,885 (Millions, except per share amounts) Oil, gas and NGL sales $ 14,082 $ 9,531 $ 2,695 Oil, gas and NGL derivatives (658 ) (1,544 ) 155 Marketing and midstream revenues 8,642 6,323 7,260 5,745 4,219 1,978 Total revenues 13,949 10,304 13,145 19,169 12,206 4,828 Production expenses 1,823 1,803 2,439 2,797 2,131 1,123 Exploration expenses 380 215 451 29 14 167 Marketing and midstream expenses 7,730 5,533 6,461 5,780 4,238 2,013 Depreciation, depletion and amortization 2,074 2,096 4,022 2,223 2,158 1,300 Asset impairments 17 1,310 17,647 — — 2,693 Asset dispositions (217 ) (1,483 ) 7 (44 ) (168 ) (1 ) General and administrative expenses 872 865 1,193 395 391 338 Financing costs, net 498 907 519 309 329 270 Other expenses (124 ) 375 264 Restructuring and transaction costs — 258 49 Other, net (95 ) (43 ) (34 ) Total expenses 13,053 11,621 33,003 11,394 9,308 7,918 Earnings (loss) before income taxes 896 (1,317 ) (19,858 ) Earnings (loss) from continuing operations before income taxes 7,775 2,898 (3,090 ) Income tax expense (benefit) (182 ) 141 (6,213 ) 1,738 65 (547 ) Net earnings (loss) from continuing operations 6,037 2,833 (2,543 ) Net loss from discontinued operations, net of income taxes — — (128 ) Net earnings (loss) 1,078 (1,458 ) (13,645 ) 6,037 2,833 (2,671 ) Net earnings (loss) attributable to noncontrolling interests 180 (402 ) (749 ) Net earnings attributable to noncontrolling interests 22 20 9 Net earnings (loss) attributable to Devon $ 898 $ (1,056 ) $ (12,896 ) $ 6,015 $ 2,813 $ (2,680 ) Net earnings (loss) per share attributable to Devon: Basic $ 1.71 $ (2.09 ) $ (31.72 ) Diluted $ 1.70 $ (2.09 ) $ (31.72 ) Net earnings (loss) per share: Basic earnings (loss) from continuing operations per share $ 9.15 $ 4.20 $ (6.78 ) Basic loss from discontinued operations per share — — (0.34 ) Basic net earnings (loss) per share $ 9.15 $ 4.20 $ (7.12 ) Diluted earnings (loss) per share: Diluted earnings (loss) from continuing operations per share $ 9.12 $ 4.19 $ (6.78 ) Diluted loss from discontinued operations per share — — (0.34 ) Diluted net earnings (loss) per share $ 9.12 $ 4.19 $ (7.12 ) Comprehensive earnings (loss): Net earnings (loss) $ 1,078 $ (1,458 ) $ (13,645 ) $ 6,037 $ 2,833 $ (2,671 ) Other comprehensive earnings, net of tax: Foreign currency translation and other 83 11 (443 ) Other comprehensive earnings (loss), net of tax: Pension and postretirement plans 29 22 10 16 (5 ) (8 ) Other comprehensive earnings, net of tax 112 33 (433 ) Comprehensive earnings (loss) 1,190 (1,425 ) (14,078 ) Comprehensive earnings (loss) attributable to noncontrolling interests 180 (402 ) (749 ) Other comprehensive earnings (loss), net of tax 16 (5 ) (8 ) Comprehensive earnings (loss): 6,053 2,828 (2,679 ) Comprehensive earnings attributable to noncontrolling interests 22 20 9 Comprehensive earnings (loss) attributable to Devon $ 1,010 $ (1,023 ) $ (13,329 ) $ 6,031 $ 2,808 $ (2,688 ) See accompanying notes to consolidated financial statements. DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2017 2016* 2015* Cash flows from operating activities: Net earnings (loss) $ 1,078 $ (1,458 ) $ (13,645 ) Adjustments to reconcile net earnings (loss) to net cash from operating activities: Depreciation, depletion and amortization 2,074 2,096 4,022 Exploratory dry hole expense and unproved leasehold impairments 219 113 248 Asset impairments 17 1,310 17,647 Gains and losses on asset sales (217 ) (1,483 ) 7 Deferred income tax expense (benefit) (294 ) 41 (5,976 ) Commodity derivatives (157 ) 201 (503 ) Cash settlements on commodity derivatives 53 1 2,416 Other derivatives and financial instruments 23 185 (235 ) Cash settlements on other derivatives and financial instruments (6 ) (143 ) 272 Asset retirement obligation accretion 62 75 75 Share-based compensation 198 233 244 Other (122 ) 270 312 Net change in working capital 21 24 (265 ) Change in long-term other assets (46 ) 36 285 Change in long-term other liabilities 6 (1 ) (6 ) Net cash from operating activities 2,909 1,500 4,898 Cash flows from investing activities: Capital expenditures (2,759 ) (2,047 ) (4,787 ) Acquisitions of property, equipment and businesses (46 ) (1,641 ) (1,107 ) Divestitures of property and equipment 417 3,113 107 Proceeds from sale of investment 190 — — Other (12 ) (19 ) (16 ) Net cash from investing activities (2,210 ) (594 ) (5,803 ) Cash flows from financing activities: Borrowings of long-term debt, net of issuance costs 2,376 2,145 4,772 Repayments of long-term debt (2,118 ) (4,409 ) (2,634 ) Payment of installment payable (250 ) — — Net short-term debt repayments — (626 ) (307 ) Early retirement of debt (6 ) (265 ) — Issuance of common stock — 1,469 — Sale of subsidiary units — — 654 Issuance of subsidiary units 501 892 25 Dividends paid on common stock (127 ) (221 ) (396 ) Contributions from noncontrolling interests 57 168 16 Distributions to noncontrolling interests (354 ) (304 ) (254 ) Shares exchanged for tax withholdings (68 ) (35 ) (51 ) Other (2 ) (10 ) (13 ) Net cash from financing activities 9 (1,196 ) 1,812 Effect of exchange rate changes on cash 6 (61 ) (77 ) Net change in cash and cash equivalents 714 (351 ) 830 Cash and cash equivalents at beginning of period 1,959 2,310 1,480 Cash and cash equivalents at end of period $ 2,673 $ 1,959 $ 2,310 Year Ended December 31, 2022 2021 2020 Cash flows from operating activities: Net earnings (loss) $ 6,037 $ 2,833 $ (2,671 ) Adjustments to reconcile net earnings (loss) to net cash from operating activities: Net loss from discontinued operations, net of income taxes — — 128 Depreciation, depletion and amortization 2,223 2,158 1,300 Asset impairments — — 2,693 Leasehold impairments 12 4 152 (Amortization) accretion of liabilities (31 ) (27 ) 32 Total (gains) losses on commodity derivatives 658 1,544 (155 ) Cash settlements on commodity derivatives (1,356 ) (1,462 ) 316 Gains on asset dispositions (44 ) (168 ) (1 ) Deferred income tax expense (benefit) 1,179 49 (328 ) Share-based compensation 88 99 88 Early retirement of debt — (30 ) — Other (10 ) 15 5 Changes in assets and liabilities, net (226 ) (116 ) (95 ) Net cash from operating activities - continuing operations 8,530 4,899 1,464 Cash flows from investing activities: Capital expenditures (2,542 ) (1,989 ) (1,153 ) Acquisitions of property and equipment (2,583 ) (18 ) (8 ) Divestitures of property and equipment 39 79 34 WPX acquired cash — 344 — Distributions from investments 39 35 — Contributions to investments (76 ) (25 ) — Net cash from investing activities - continuing operations (5,123 ) (1,574 ) (1,127 ) Cash flows from financing activities: Repayments of long-term debt — (1,243 ) — Early retirement of debt — (59 ) — Repurchases of common stock (718 ) (589 ) (38 ) Dividends paid on common stock (3,379 ) (1,315 ) (257 ) Contributions from noncontrolling interests — 4 21 Distributions to noncontrolling interests (30 ) (21 ) (14 ) Acquisition of noncontrolling interests — (24 ) — Shares exchanged for tax withholdings and other (86 ) (45 ) (18 ) Net cash from financing activities - continuing operations (4,213 ) (3,292 ) (306 ) Effect of exchange rate changes on cash - continuing operations (11 ) 1 — Net change in cash, cash equivalents and restricted cash - continuing operations (817 ) 34 31 Cash flows from discontinued operations: Operating activities — — (110 ) Investing activities — — 481 Financing activities — — — Effect of exchange rate changes on cash — — (9 ) Net change in cash, cash equivalents and restricted cash of discontinued operations — — 362 Net change in cash, cash equivalents and restricted cash (817 ) 34 393 Cash, cash equivalents and restricted cash at beginning of period 2,271 2,237 1,844 Cash, cash equivalents and restricted cash at end of period $ 1,454 $ 2,271 $ 2,237 Reconciliation of cash, cash equivalents and restricted cash: Cash and cash equivalents $ 1,314 $ 2,099 $ 2,047 Restricted cash 140 172 190 Total cash, cash equivalents and restricted cash $ 1,454 $ 2,271 $ 2,237 See accompanying notes to consolidated financial statements. DEVON ENERGY CORPORATION AND SUBSIDIARIES December 31, 2022 December 31, 2021 December 31, 2017 December 31, 2016* ASSETS Current assets: Cash and cash equivalents $ 2,673 $ 1,959 Cash, cash equivalents and restricted cash $ 1,454 $ 2,271 Accounts receivable 1,670 1,356 1,767 1,543 Assets held for sale — 193 Inventory 201 114 Other current assets 448 264 469 321 Total current assets 4,791 3,772 3,891 4,249 Oil and gas property and equipment, based on successful efforts accounting, net 13,318 12,998 16,567 13,536 Midstream and other property and equipment, net 7,853 7,535 Other property and equipment, net ($109 million and $111 million related to CDM in 2022 and 2021, respectively) 1,539 1,472 Total property and equipment, net 21,171 20,533 18,106 15,008 Goodwill 2,383 2,383 753 753 Right-of-use assets 224 235 Investments 440 402 Other long-term assets 1,896 1,987 307 378 Total assets $ 30,241 $ 28,675 $ 23,721 $ 21,025 LIABILITIES AND EQUITY Current liabilities: Accounts payable $ 819 $ 642 $ 859 $ 500 Revenues and royalties payable 1,180 908 1,506 1,456 Short-term debt 115 — 251 — Other current liabilities 1,201 1,066 489 1,131 Total current liabilities 3,315 2,616 3,105 3,087 Long-term debt 10,291 10,154 6,189 6,482 Lease liabilities 257 252 Asset retirement obligations 1,113 1,226 511 468 Other long-term liabilities 583 894 900 1,050 Deferred income taxes 835 1,063 1,463 287 Equity: Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 525 million and 523 million shares in 2017 and 2016, respectively 53 52 Stockholders' equity: Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 65 66 Additional paid-in capital 7,333 7,237 6,921 7,636 Retained earnings (accumulated deficit) 702 (69 ) Accumulated other comprehensive earnings 1,166 1,054 Retained earnings 4,297 1,692 Accumulated other comprehensive loss (116 ) (132 ) Total stockholders’ equity attributable to Devon 9,254 8,274 11,167 9,262 Noncontrolling interests 4,850 4,448 129 137 Total equity 14,104 12,722 11,296 9,399 Total liabilities and equity $ 30,241 $ 28,675 $ 23,721 $ 21,025 See accompanying notes to consolidated financial statements. DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY Retained Accumulated Additional Earnings Other Other Common Stock Paid-In (Accumulated Comprehensive Treasury Noncontrolling Total Additional Comprehensive Shares Amount Capital Deficit) Earnings Stock Interests Equity Common Stock Paid-In Retained Earnings Treasury Noncontrolling Total Previously reported as of December 31, 2014 409 $ 41 $ 4,088 $ 16,631 $ 779 $ — $ 4,802 $ 26,341 Effect of change in accounting principle — — — (2,227 ) 675 — — (1,552 ) Balance as of December 31, 2014 as recast* 409 $ 41 $ 4,088 $ 14,404 $ 1,454 $ — $ 4,802 $ 24,789 Net loss — — — (12,896 ) — — (749 ) (13,645 ) Shares Amount Capital Earnings (Loss) Stock Interests Equity 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 — — — — (433 ) — — (433 ) — — — — (8 ) — — (8 ) Stock option exercises — — 4 — — — — 4 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 Net earnings — — — 2,813 — — 20 2,833 Other comprehensive loss, net of tax — — — — (5 ) — — (5 ) Restricted stock grants, net of cancellations 2 — — — — — — — 6 — — — — — — — Common stock repurchased — — — — — (35 ) — (35 ) — — — — — (633 ) — (633 ) Common stock retired — — (35 ) — — 35 — — (16 ) (1 ) (632 ) — — 633 — — Common stock dividends — — — (396 ) — — — (396 ) — — — (1,329 ) — — — (1,329 ) Common stock issued 7 1 198 — — — — 199 290 29 5,403 — — — — 5,432 Share-based compensation — — 165 — — — — 165 1 — 99 — — — — 99 Share-based compensation tax expense — — (9 ) — — — — (9 ) Subsidiary equity transactions — — 585 — — — 141 726 Contributions from noncontrolling interests — — — — — — 3 3 Distributions to noncontrolling interests — — — — — — (254 ) (254 ) — — — — — — (20 ) (20 ) Balance as of December 31, 2015* 418 $ 42 $ 4,996 $ 1,112 $ 1,021 $ — $ 3,940 $ 11,111 Net loss — — — (1,056 ) — — (402 ) (1,458 ) Other comprehensive earnings, net of tax — — — — 33 — — 33 Restricted stock grants, net of cancellations 2 — — — — — — — Common stock repurchased — — — — — (28 ) — (28 ) Common stock retired — — (28 ) — — 28 — — Common stock dividends — — (96 ) (125 ) — — — (221 ) Common stock issued 103 10 2,117 — — — — 2,127 Share-based compensation — — 168 — — — — 168 Subsidiary equity transactions — — 80 — — — 1,214 1,294 Distributions to noncontrolling interests — — — — — — (304 ) (304 ) Balance as of December 31, 2016* 523 $ 52 $ 7,237 $ (69 ) $ 1,054 $ — $ 4,448 $ 12,722 Balance as of December 31, 2021 663 $ 66 $ 7,636 $ 1,692 $ (132 ) $ — $ 137 $ 9,399 Net earnings — — — 898 — — 180 1,078 — — — 6,015 — — 22 6,037 Other comprehensive earnings, net of tax — — — — 112 — — 112 — — — — 16 — — 16 Restricted stock grants, net of cancellations 1 1 — — — — — 1 2 1 3 — — — — 4 Common stock repurchased — — — — — (44 ) — (44 ) — — — — — (808 ) — (808 ) Common stock retired — — (44 ) — — 44 — — (13 ) (2 ) (806 ) — — 808 — — Common stock dividends — — — (127 ) — — — (127 ) — — — (3,410 ) — — — (3,410 ) Share-based compensation 1 — 126 — — — — 126 1 — 88 — — — — 88 Subsidiary equity transactions — — 14 — — — 576 590 Distributions to noncontrolling interests — — — — — — (354 ) (354 ) — — — — — — (30 ) (30 ) Balance as of December 31, 2017 525 $ 53 $ 7,333 $ 702 $ 1,166 $ — $ 4,850 $ 14,104 Balance as of December 31, 2022 653 $ 65 $ 6,921 $ 4,297 $ (116 ) $ — $ 129 $ 11,296 See accompanying notes to consolidated financial statements. DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 Devon and 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, Variable Interest Entity Devon and an affiliate of QL Capital Partners, LP (“QLCP”) formed CDM, a joint venture in the 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 2022, 2021 and 2020, QLCP distributions from CDM were approximately $30 million, $20 million and $14 million, respectively. During 2021 and 2020, QLCP contributions to CDM were approximately $3 million and $21 million, respectively. 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, if material, on Devon's consolidated balance sheets. Investments In conjunction with the Merger, Devon acquired an interest in Catalyst, which is a joint venture established among WPX, an affiliate of Howard Energy Partners, LLC (“HEP”) and certain other investors, to develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the arrangement, Devon and a holding company owned by the other joint venture investors each have a 50% voting 54 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) interest in the joint venture legal entity, and HEP serves as the operator. Through 2038, Devon’s production from 50,000 net acres in the Stateline area of the Delaware Basin has been dedicated to Catalyst subject to fixed-fee oil gathering and natural gas processing agreements. The agreements do not include any minimum volume commitments. Devon accounts for the investment in Catalyst as an equity method investment. Devon's share of the earnings are reflected as a component of other, net in the accompanying consolidated statements of comprehensive earnings. During 2022, Devon made an investment in Matterhorn. Matterhorn is a joint venture entity and was formed for the purpose of constructing a natural gas pipeline that will transport natural gas from the Permian Basin to the Katy, Texas area. Devon’s investment in Matterhorn does not give it the ability to exercise significant influence over Matterhorn. Devon has other investments largely focused on midstream, new technologies and energy transition initiatives. Devon does not have the ability to exercise significant influence over these investments. The following table presents Devon's investments that are shown on the consolidated balance sheet. Carrying Amount Investments % Interest December 31, 2022 December 31, 2021 Catalyst 50% $ 339 $ 368 Matterhorn 12.5% 54 — Other Various 47 34 Total $ 440 $ 402 As of December 31, 2022, Devon’s $339 million investment in Catalyst exceeded the underlying equity in net assets by approximately $120 million. The basis difference results primarily from intangible assets associated with Devon’s acreage dedication and is amortized over the remaining 15-year term of the associated oil gathering and natural gas processing agreements. After the closing of the Merger, Catalyst has provided certain gathering, processing and marketing services to Devon in the ordinary course of business. The impact from these services on Devon’s consolidated statement of comprehensive earnings and consolidated balance sheet for the years ended and as of December 31, 2022 and 2021, respectively, are summarized below. Year ended December 31, 2022 2021 Oil, gas and NGL sales $ 405 $ 264 Production expenses $ 55 $ 42 Accounts receivable $ 14 $ 22 Segment Information 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 these operations. 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 55 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 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, derivative financial instruments; the fair value of reporting units and related assessment of goodwill for impairment; obligations related to employee pension and postretirement benefits; purchase accounting estimates used for assets acquired and liabilities assumed; the fair value of contingent earnout payments, and 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, Devon acts as a principal in sales transactions when control of the product is retained prior to delivery to the ultimate third-party customer or acts as an agent when services are rendered on behalf of the principal in the transactions. A control-based assessment is performed to identify whether Devon is a principal or an agent in the transaction, which determines whether revenue and the related expenses are presented on a gross or net basis, respectively. 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 56 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 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 Marketing revenues are Devon’s reported midstream revenue primarily relates to its interest in CDM. CDM provides gathering, compression and 57 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Satisfaction of Performance Obligations and Revenue Recognition 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, 2022. 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, 2022 2021 2020 Oil $ 10,281 $ 6,996 $ 2,034 Gas 1,948 1,104 326 NGL 1,853 1,431 335 Oil, gas and NGL sales 14,082 9,531 2,695 Oil 3,305 2,451 936 Gas 1,163 718 488 NGL 1,277 1,050 554 Marketing and midstream revenues 5,745 4,219 1,978 Total revenues from contracts with customers $ 19,827 $ 13,750 $ 4,673 Customers For the year ended December 31, 2022, sales to one customer accounted for If any one of Devon’s 58 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) resources needed to access alternative customers or markets and avoid or materially mitigate associated sales Derivative Financial Instruments Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon 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, By using derivative financial instruments to hedge exposures to changes in commodity prices 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. 59 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Share-Based Compensation 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 60 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 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, Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. To fund retained long-term obligations related to previously disposed assets, approximately $120 million and $160 million of Devon’s cash balance as of December 31, 2022 and 2021, respectively, is presented as restricted. These obligations primarily relate to abandoned Canadian firm transportation agreements. This cash is not legally restricted and can be used by Devon for other general corporate purposes. Accounts Receivable Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest Devon Property and Equipment Oil and Gas Property and Equipment Devon follows the successful efforts method of accounting for its oil and gas properties. 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”) 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. 61 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 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 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 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 Devon capitalizes interest costs incurred 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 Asset Retirement Obligations Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites 62 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Leases Devon establishes right-of-use assets and lease liabilities on the balance sheet for all leases with a term longer than 12 months. 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 Devon 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: 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. 63 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 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. 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. WPX Merger Purchase Price Allocation The allocation of the total purchase price of WPX to the identifiable assets acquired and the liabilities assumed was finalized at December 31, 2021. The transaction was 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 were recorded at their respective fair values as of the date of completion of the Merger and added to Devon’s. Determining the fair value of the assets and liabilities of WPX required judgment and certain assumptions to be made, the most 64 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Final Purchase Price Allocation Consideration: WPX Common Stock outstanding 561.2 Exchange Ratio 0.5165 Devon common stock issued 289.9 Devon closing price on January 7, 2021 $ 18.57 Total common equity consideration 5,383 Share-based replacement awards 49 Total consideration $ 5,432 Assets acquired: Cash, cash equivalents and restricted cash $ 344 Accounts receivable 425 Other current assets 49 Right-of-use assets 38 Proved oil and gas property and equipment 7,017 Unproved and properties under development 2,362 Other property and equipment 485 Investments 400 Other long-term assets 43 Total assets acquired $ 11,163 Liabilities assumed: Accounts payable $ 346 Revenue and royalties payable 223 Other current liabilities 454 Debt 3,562 Lease liabilities 38 Asset retirement obligations 94 Deferred income taxes 249 Other long-term liabilities 765 Total liabilities assumed 5,731 Net assets acquired $ 5,432 65 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Pro Forma Financial Information The following unaudited pro forma financial Year Ended December 31, Continuing operations: 2020 Total revenues $ 7,261 Net loss $ (3,438 ) Basic net loss per share $ (5.16 ) Acquisitions In September 2022, Devon completed its Divestitures – Continuing Operations In 2021, Devon completed the sale of non-core assets in the Rockies for proceeds of $9 million, net of purchase price adjustments, and recognized a $35 million gain related to the sale. Devon received $4 million in contingent earnout payments related to this transaction in the first quarters of 2023 and 2022. The total estimated proved reserves associated with these divested assets was approximately 3 MMBoe. Divestitures – Discontinued Operations In the fourth quarter of 2020, Devon completed the sale of its DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Commodity Derivatives Changes to the Consolidated Comprehensive Statement of Earnings As Reported Under For the Year Ended December 31, 2017 Under Full Cost Changes Successful Efforts Exploration expenses $ — $ 380 $ 380 Depreciation, depletion and amortization 1,579 495 2,074 Asset dispositions (5 ) (212 ) (217 ) General and administrative expenses 682 190 872 Financing costs, net 494 4 498 Other expenses (102 ) (22 ) (124 ) Earnings before income taxes 1,731 (835 ) 896 Income tax benefit (140 ) (42 ) (182 ) Net earnings 1,871 (793 ) 1,078 Net earnings attributable to Devon 1,691 (793 ) 898 Net earnings per share attributable to Devon: Basic 3.22 (1.51 ) 1.71 Diluted 3.20 (1.50 ) 1.70 Comprehensive earnings: Net earnings 1,871 (793 ) 1,078 Foreign currency translation and other 4 79 83 Comprehensive earnings 1,904 (714 ) 1,190 Comprehensive earnings attributable to Devon 1,724 (714 ) 1,010 Changes to the Consolidated Comprehensive Statement of Earnings As Reported Under For the Year Ended December 31, 2016 Under Full Cost Changes Successful Efforts Exploration expenses $ — $ 215 $ 215 Depreciation, depletion and amortization 1,792 304 2,096 Asset impairments 4,975 (3,665 ) 1,310 Asset dispositions (1,887 ) 404 (1,483 ) General and administrative expenses 658 207 865 Financing costs, net 904 3 907 Other expenses 403 (28 ) 375 Loss before income taxes (3,877 ) 2,560 (1,317 ) Income tax expense (benefit) (173 ) 314 141 Net loss (3,704 ) 2,246 (1,458 ) Net loss attributable to Devon (3,302 ) 2,246 (1,056 ) Net loss per share attributable to Devon: Basic (6.52 ) 4.43 (2.09 ) Diluted (6.52 ) 4.43 (2.09 ) Comprehensive loss: Net loss (3,704 ) 2,246 (1,458 ) Foreign currency translation and other 32 (21 ) 11 Comprehensive loss (3,650 ) 2,225 (1,425 ) Comprehensive loss attributable to Devon (3,248 ) 2,225 (1,023 ) Changes to the Consolidated Comprehensive Statement of Earnings As Reported Under For the Year Ended December 31, 2015 Under Full Cost Changes Successful Efforts Exploration expenses $ — $ 451 $ 451 Depreciation, depletion and amortization 3,129 893 4,022 Asset impairments 20,820 (3,173 ) 17,647 Asset dispositions — 7 7 General and administrative expenses 868 325 1,193 Financing costs, net 517 2 519 Other expenses 179 85 264 Loss before income taxes (21,268 ) 1,410 (19,858 ) Income tax benefit (6,065 ) (148 ) (6,213 ) Net loss (15,203 ) 1,558 (13,645 ) Net loss attributable to Devon (14,454 ) 1,558 (12,896 ) Net loss per share attributable to Devon: Basic (35.55 ) 3.83 (31.72 ) Diluted (35.55 ) 3.83 (31.72 ) Comprehensive loss: Net loss (15,203 ) 1,558 (13,645 ) Foreign currency translation and other (559 ) 116 (443 ) Comprehensive loss (15,752 ) 1,674 (14,078 ) Comprehensive loss attributable to Devon (15,003 ) 1,674 (13,329 ) Changes to the Consolidated Statement of Cash Flows As Reported Under For the Year Ended December 31, 2017 Under Full Cost Changes Successful Efforts Net earnings $ 1,871 $ (793 ) $ 1,078 Depreciation, depletion and amortization 1,579 495 2,074 Exploratory dry hole expense and unproved leasehold impairments — 219 219 Gains and losses on asset sales (5 ) (212 ) (217 ) Deferred income tax benefit (252 ) (42 ) (294 ) Share-based compensation 158 40 198 Other (108 ) (14 ) (122 ) Net cash from operating activities 3,216 (307 ) 2,909 Capital expenditures (3,074 ) 315 (2,759 ) Divestitures of property and equipment 425 (8 ) 417 Net cash from investing activities (2,517 ) 307 (2,210 ) Changes to the Consolidated Statement of Cash Flows As Reported Under For the Year Ended December 31, 2016 Under Full Cost Changes Successful Efforts Net loss $ (3,704 ) $ 2,246 $ (1,458 ) Depreciation, depletion and amortization 1,792 304 2,096 Exploratory dry hole expense and unproved leasehold impairments — 113 113 Asset impairments 4,975 (3,665 ) 1,310 Gains and losses on asset sales (1,887 ) 404 (1,483 ) Deferred income tax expense (benefit) (273 ) 314 41 Share-based compensation 194 39 233 Other 303 (33 ) 270 Net cash from operating activities 1,778 (278 ) 1,500 Capital expenditures (2,330 ) 283 (2,047 ) Divestitures of property and equipment 3,118 (5 ) 3,113 Net cash from investing activities (872 ) 278 (594 ) Changes to the Consolidated Statement of Cash Flows As Reported Under For the Year Ended December 31, 2015 Under Full Cost Changes Successful Efforts Net loss $ (15,203 ) $ 1,558 $ (13,645 ) Depreciation, depletion and amortization 3,129 893 4,022 Exploratory dry hole expense and unproved leasehold impairments — 248 248 Asset impairments 20,820 (3,173 ) 17,647 Gains and losses on asset sales — 7 7 Deferred income tax benefit (5,828 ) (148 ) (5,976 ) Share-based compensation 181 63 244 Other 281 31 312 Net cash from operating activities 5,419 (521 ) 4,898 Capital expenditures (5,308 ) 521 (4,787 ) Net cash from investing activities (6,324 ) 521 (5,803 ) Changes to the Consolidated Balance Sheet As Reported Under For the Year Ended December 31, 2017 Under Full Cost Changes Successful Efforts Oil and gas property and equipment, net $ 9,702 3,616 $ 13,318 Total property and equipment, net 17,555 3,616 21,171 Goodwill 3,964 (1,581 ) 2,383 Total assets 28,206 2,035 30,241 Deferred income taxes 434 401 835 Additional paid-in capital 7,206 127 7,333 Retained earnings 44 658 702 Accumulated other comprehensive earnings 317 849 1,166 Total stockholders’ equity attributable to Devon 7,620 1,634 9,254 Total equity 12,470 1,634 14,104 Total liabilities and equity 28,206 2,035 30,241 Changes to the Consolidated Balance Sheet As Reported Under For the Year Ended December 31, 2016 Under Full Cost Changes Successful Efforts Oil and gas property and equipment, net $ 8,655 $ 4,343 $ 12,998 Total property and equipment, net 16,190 4,343 20,533 Goodwill 3,964 (1,581 ) 2,383 Total assets 25,913 2,762 28,675 Deferred income taxes 648 415 1,063 Accumulated deficit (1,646 ) 1,577 (69 ) Accumulated other comprehensive earnings 284 770 1,054 Total stockholders’ equity attributable to Devon 5,927 2,347 8,274 Total equity 10,375 2,347 12,722 Total liabilities and equity 25,913 2,762 28,675 Date Proceeds Received Gains on Sale Proved Reserves (MMBoe) Percentage of U.S. Proved Reserves Second quarter 2016 $ 200 $ 83 11 1 % Third quarter 2016 1,653 726 146 9 % Total $ 1,853 $ 809 157 10 % Purchase Price Allocation Date Midstream assets Cash EnLink Units PP&E Goodwill Intangibles Other January 2015 Permian Basin $ 108 — $ 30 $ 30 $ 43 $ 5 March 2015 Permian Basin $ 240 $ 360 $ 302 $ 18 $ 281 $ (1 ) October 2015 Delaware Basin $ 141 — $ 36 $ 11 $ 99 $ (5 )) 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 2018 49,625 $ 52.13 51,860 $ 46.06 $ 56.06 Q1-Q4 2019 7,307 $ 52.22 6,559 $ 45.82 $ 55.82 Price Collars Period Volume Weighted Weighted Q1-Q4 2023 86,207 $ 69.03 $ 94.66 Oil Basis Swaps Oil Basis Collars Period Index Volume (Bbls/d) Weighted Average Differential to WTI ($/Bbl) Volume (Bbls/d) Weighted Average Floor Differential to WTI ($/Bbl) Weighted Average Ceiling Differential to WTI ($/Bbl) Q1-Q4 2018 Midland Sweet 23,000 $ (1.02 ) — $ — $ — Q1-Q4 2018 Argus LLS 12,000 $ 3.95 — $ — $ — Q1-Q4 2018 Western Canadian Select 75,490 $ (14.84 ) 1,830 $ (15.50 ) $ (13.93 ) Q1-Q4 2019 Midland Sweet 27,000 $ (0.47 ) — $ — $ — Oil Basis Swaps Period Index Volume Weighted Average Q1-Q4 2023 Midland Sweet 18,647 $ 0.73 Q1-Q4 2024 Midland Sweet 9,000 $ 1.14 As of December 31, 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 2018 371,956 $ 3.06 197,516 $ 2.94 $ 3.26 Q1-Q4 2019 28,466 $ 2.98 28,466 $ 2.84 $ 3.14 Price Swaps Price Collars Period Volume (MMBtu/d) Weighted Average Price ($/MMBtu) Volume (MMBtu/d) Weighted Average Floor Price ($/MMBtu) Weighted Average Q1-Q4 2023 11,123 $ 5.47 199,490 $ 3.78 $ 8.27 Q1-Q4 2024 40,527 $ 3.78 $ 7.05 Natural Gas Basis Swaps Period Index Volume Weighted Average Q1-Q4 2023 El Paso Natural Gas 140,041 $ (1.58 ) Q1-Q4 2023 Houston Ship Channel 110,000 $ (0.16 ) Q1-Q4 2023 WAHA 70,000 $ (0.51 ) Q1-Q4 2024 WAHA 40,000 $ (0.51 ) Natural Gas Basis Swaps Period Index Volume (MMBtu/d) Weighted Average Differential to Henry Hub ($/MMBtu) Q1-Q4 2018 Panhandle Eastern Pipe Line 50,000 $ (0.29 ) As of December 31, Financial Statement Presentation All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the Price Swaps Period Product Volume (Bbls/d) Weighted Average Price ($/Bbl) Q1-Q4 2018 Ethane 6,747 $ 11.89 Q1-Q4 2018 Natural Gasoline 5,500 $ 54.24 Q1-Q4 2018 Normal Butane 6,750 $ 38.46 Q1-Q4 2018 Propane 9,500 $ 33.19 Notional Rate Received Rate Paid Expiration $ 750 Three Month LIBOR 2.98% December 2048 (1) $ 100 1.76% Three Month LIBOR January 2019 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Year Ended December 31, 2017 2016 2015 Commodity derivatives: Upstream revenues $ 157 $ (201 ) $ 503 Marketing and midstream revenues (1 ) (13 ) 9 Interest rate derivatives: Other expenses (22 ) (19 ) (20 ) Foreign currency derivatives: Other expenses — (153 ) 246 Net gains (losses) recognized $ 134 $ (386 ) $ 738 December 31, 2022 December 31, 2021 Gross Fair Value Amounts Netted Net Fair Value Gross Fair Value Amounts Netted Net Fair Value Balance Sheet Classification Commodity derivatives: Short-term derivative asset $ 138 $ (19 ) $ 119 $ 6 $ (4 ) $ 2 Other current assets Long-term derivative asset 12 — 12 6 — 6 Other long-term assets Short-term derivative liability (22 ) 19 (3 ) (579 ) 4 (575 ) Other current liabilities Long-term derivative liability — — — (2 ) — (2 ) Other long-term liabilities Total derivative asset (liability) $ 128 $ — $ 128 $ (569 ) $ — $ (569 ) December 31, 2017 December 31, 2016 Commodity derivative assets: Other current assets $ 209 $ 9 Other long-term assets 2 1 Interest rate derivative assets: Other current assets 1 1 Total derivative assets $ 212 $ 11 Commodity derivative liabilities: Other current liabilities $ 267 $ 187 Other long-term liabilities 27 16 Interest rate derivative liabilities: Other current liabilities 64 — Other long-term liabilities — 41 Total derivative liabilities $ 358 $ 244 In The vesting for certain share-based awards was accelerated in The table below presents the share-based compensation expense included in Devon’s accompanying consolidated Year Ended December 31, 2022 2021 2020 G&A $ 87 $ 77 $ 76 Exploration expenses 1 1 1 Restructuring and transaction costs — 21 11 Total $ 88 $ 99 $ 88 Related income tax benefit $ 34 $ 13 $ — 68 Year Ended December 31, 2017 2016 2015 G&A $ 141 $ 124 $ 185 Exploration expenses 7 6 9 Total Devon 148 130 194 G&A 37 24 31 Marketing and midstream expenses 11 7 5 Total EnLink 48 31 36 Total $ 196 $ 161 $ 230 Related income tax benefit $ 6 $ 6 $ 67 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) The following table presents a summary of Devon’s unvested restricted stock awards and units Restricted Stock Performance-Based Performance Awards and Units Restricted Stock Awards Share Units Awards and Units Weighted Average Grant-Date Fair Value Awards Weighted Average Grant-Date Fair Value Units Weighted Average Grant-Date Fair Value (Thousands, except fair value data) Unvested at 12/31/16 6,407 $ 34.40 585 $ 37.60 2,604 $ 46.66 Granted 2,691 $ 44.87 223 $ 44.85 1,010 $ 52.58 Vested (2,431 ) $ 39.51 (233 ) $ 41.27 (832 ) $ 78.19 Forfeited (339 ) $ 35.92 — $ — (24 ) $ 40.70 Unvested at 12/31/17 6,328 $ 36.81 575 $ 38.92 2,758 (1 ) $ 41.21 Restricted Stock Awards & Units Performance Share Units Awards/Units Weighted Units Weighted (Thousands, except fair value data) Unvested at 12/31/21 7,656 $ 22.15 2,076 $ 24.12 Granted 1,408 $ 53.60 964 $ 44.05 (1) Vested (3,192 ) $ 23.10 (1,194 ) $ 28.91 Forfeited (84 ) $ 34.05 (5 ) $ 68.68 Unvested at 12/31/22 5,788 $ 29.11 1,841 (2) $ 31.33 The following table presents the aggregate fair value of awards and units that vested during the indicated period. 2022 2021 2020 Restricted Stock Awards and Units $ 180 $ 115 $ 44 Performance-Based Restricted Stock Awards $ — $ 1 $ 2 Performance Share Units $ 62 $ 15 $ 10 2017 2016 2015 Restricted Stock Awards and Units $ 105 $ 73 $ 101 Performance-Based Restricted Stock Awards $ 10 $ 5 $ 8 Performance Share Units $ 38 $ 13 $ 22 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, Performance-Based Restricted Stock Restricted Stock Performance Restricted Stock Performance Awards and Units Awards Share Units Awards/Units Share Units Unrecognized compensation cost $ 135 $ 5 $ 28 $ 85 $ 18 Weighted average period for recognition (years) 2.4 1.6 1.9 2.5 1.6 Restricted Stock Awards and Units Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from one to four Performance Share Units Performance share units are granted to certain members of Devon’s management and DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) At 2017 2016 2015 Grant-date fair value $ 51.05 — $ 53.12 $ 9.24 — $ 10.61 $ 81.99 — $ 85.05 Risk-free interest rate 1.50% 0.94% 1.06% Volatility factor 45.8% 37.7% 26.2% Contractual term (years) 2.89 2.83 2.89 2022 2021 2020 Grant-date fair value $ 68.68 $ 18.08 $ 27.89 Risk-free interest rate 1.81 % 0.18 % 1.36 % Volatility factor 70.1 % 67.8 % 38.4 % Contractual term (years) 2.89 2.89 2.89 Weighted Average Options Exercise Price Remaining Term Intrinsic Value (Thousands) (Years) Outstanding at December 31, 2016 2,532 $ 68.06 Expired (786 ) $ 63.67 Outstanding at December 31, 2017 1,746 $ 70.04 1.33 $ — Exercisable at December 31, 2017 1,746 $ 70.04 1.33 $ — General Partner EnLink Restricted Performance Restricted Performance Incentive Units Units Incentive Units Units Unrecognized compensation cost $ 11 $ 5 $ 12 $ 5 Weighted average period for recognition (years) 1.7 1.8 1.7 1.8 The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the consolidated Year Ended December 31, Year Ended December 31, 2017 2016 2015 2022 2021 2020 Proved oil and gas assets $ — $ 435 $ 16,076 $ — $ — $ 2,664 EnLink goodwill — 873 1,328 EnLink other intangible assets — — 223 Other assets 17 2 20 — — 29 Total asset impairments $ 17 $ 1,310 $ 17,647 $ — $ — $ 2,693 Unproved impairments $ 217 $ 77 $ 260 $ 12 $ 4 $ 152 Proved Oil and Gas and Other Asset Impairments Devon recognized approximately $2.7 billion of proved asset impairments during the first quarter of 2020. These impairments related to the Anadarko Basin and 70 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) UnprovedImpairments Due to the downturn in the commodity price environment and reduced near-term investment as discussed above, Devon recognized $152 million of unproved impairments Rockies field. In Year Ended December 31, 2017 2016 2015 Foreign exchange (gain) loss, net $ (132 ) $ 39 $ 25 Asset retirement obligation accretion 62 75 75 Restructuring and transaction costs — 267 78 Other, net (54 ) (6 ) 86 Total $ (124 ) $ 375 $ 264 6. The following table summarizes Devon’s restructuring Year Ended December 31, 2022 2021 2020 Restructuring costs $ — $ 210 $ 41 Transaction costs — 48 8 Total costs $ — $ 258 $ 49 2021 Merger Integration In conjunction with the Merger closing, Devon recognized $210 million of restructuring expense in 2021 related to employee severance and termination benefits, settlements and curtailments from defined retirement benefits and contract terminations. Of these expenses, $66 million related to non-cash charges which primarily consisted of settlements and curtailments of defined retirement benefits of $41 million and the Other Other Current Long-term Liabilities Liabilities Total Balance as of December 31, 2015 $ 13 $ 63 $ 76 Changes related to prior years' restructurings 35 (1 ) 34 Balance as of December 31, 2016 $ 48 $ 62 $ 110 Changes related to prior years' restructurings (29 ) (31 ) (60 ) Balance as of December 31, 2017 $ 19 $ 31 $ 50 Prior Years’ Restructurings Other Other Current Long-term Liabilities Liabilities Total Balance as of December 31, 2020 $ 35 $ 137 $ 172 Changes related to prior years' restructurings 3 (26 ) (23 ) Balance as of December 31, 2021 $ 38 $ 111 $ 149 Changes related to prior years' restructurings (4 ) (30 ) (34 ) Balance as of December 31, 2022 $ 34 $ 81 $ 115 Table•differing quality of Contents••fuels;•production;••the overall economic environment;environment, including inflationary pressures and rising interest rates;••other governmental regulations and taxes.Commodity prices began to decline in the second half of 2014 and, despite a moderate recovery, have generally been pressured since then. This commodity price decline adversely affected our business and results of operations and led to substantial impairments to our oil and gas properties during 2015. A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:reducing the amount of oil, gas and NGLs that we can produce economically;limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;reducing our revenues, operating cash flows and profitability;causing us to decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production of oil, gas and NGLs; andreducing the carrying value of our properties, resulting in additional noncash write-downs.reservereserves estimates may occur as a result of changes in any of these or other factors. Such revisions to proved reserves could have a materialan 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.wells,properties, 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.17TableOur business requires significant capital to find and acquire new reserves. Although we plan to primarily fund these activities from cash generated by our operations, we have also from time to time relied on other sources of Contentscapital, including by accessing the debt and equity capital markets. There can be no assurance that these or other financing sources will be available in the future on acceptable terms, or at all. If we are unable to generate sufficient funds from operations or raise additional capital for any reason, we may be unable to replace our reserves, which would adversely affect our business, financial condition and results of operations.Oil and GasOur Operations Are Uncertain and Involve Substantial Costs and Risks•••••other natural disasters, such as tornadoes, earthquakes, hurricanesfloods and extreme temperatures;wildfires;•••••provincial, tribal and local and other laws rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations.operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. For example,Moreover, certain regulations require the plugging and abandonment of wells, and removal of production facilities and other restorative actions by current and former operators, which mayincluding corporate successors of former operators. We have incurred and will continue to incur substantial capital, operating and remediation costs as a result in significant costs associated with the removal of tangible equipmentthese and other restorative actions at the end of operations.laws, regulations, permits and orders to which we are subject.In addition, changesChanges in public policy have affected, and in the future could further affect, our operations. RegulatoryFor 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. The IRA, for instance, contains hundreds of billions of dollars in incentives for the development of renewable energy, clean fuels and carbon capture and sequestration, among other provisions, potentially further accelerating the transition toward lower-or zero-carbon emissions alternatives to fossil fuels. 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, and increaseimpose restrictions on pipelines or other necessary infrastructure, raise taxes, royalties and other amounts payable to governments or governmental agencies. Ouragencies and otherwise increase our operating costs. In addition, changes in public policy may indirectly impact our operations by, among other things, increasing the cost of supplies and other compliance costs could increase further if existing lawsequipment and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations.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 hydraulic fracturing, pipeline safety, seismic activity, income taxes and climate change, asthe matters discussed in more detail below.In recent years,Various federal agencies have asserted regulatory authority over certain aspects of the EPA has made proposals that subject hydraulic fracturing to further regulation and that could potentially restrict the practice of hydraulic fracturing.process. For example, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and it previously 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 studyMoreover, several state and local governments in 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The BLM previously finalized regulations to regulate hydraulic fracturing on federal lands, but subsequently issued a repeal of those regulations in 2017. Several statesareas in which we operate have already adopted, and more states are considering adoptingor stated intentions to adopt, laws and/or regulations that requiremandate further restrictions on hydraulic fracturing, such as requiring disclosure of chemicals used in hydraulic fracturing, and imposeimposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. In addition, some statesoperations and municipalitiesestablishing standards for the capture of air emissions released during hydraulic fracturing. Beyond these regulatory efforts, various policy makers, regulatory agencies and political leaders at the federal, state and local levels have significantly limited drilling activities and/orproposed implementing even further restrictions on hydraulic fracturing, or are considering doing so.including prohibiting the technology outright. Although it is not possible at this time to predict the final outcome of these or other proposals, any new federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays or cessation in development or other restrictions on our operations.Pipeline SafetyEnvironmental Laws Generally – The pipeline assets in which we own interests, through EnLink or otherwise, are subject to stringent and complex regulations related to pipeline safety and integrity management. The PHMSA has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For example, in 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high consequence areas to newly proposed “moderate consequence areas” and would also impose more rigorous testing and reporting requirements on such pipelines. To date, no further action has been taken. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Following the change in presidential administrations, implementation of this rule was delayed, but the final rule is expected to be published in the Federal Register and become effective during the first quarter of 2018. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.Seismic Activity – Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy 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, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. Recently enacted legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Legislation”) significantly affects U.S. tax law by changing how the U.S. imposes income tax on multinational corporations. These changes include, among others, a permanent reduction to the corporate income tax offset by other items intended to broaden the tax base (for example, by imposing significant additional limitations on the deductibility of interest expense and limiting the ability to deduct net operating losses).The U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may significantly impact how we will apply the law and impact our results of operations in the period issued. Further, compliance with the Tax Reform Legislation and the accounting for such provisions require complex computations and accumulation of information not previously required or regularly produced. As a result, we have provided a provisional estimate in our financial statements of the effect of the Tax Reform Legislation. As additional regulatory guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which will be recorded in the period completed, may be different from our current provisional amounts, which could materially affect our tax obligations and effective tax rate.19Climate Change – Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. 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; however, following the change in presidential administrations, both agencies have published proposed rules that seek to delay implementation of their previously issued methane standards while the agencies review and reconsider both rules. Nevertheless, several states where we operate, including Wyoming, have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generallyefforts focused on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from the use of our products by our customers.In Canada, greenhouse gas emissions are also being addressed at both the federal and provincial level. Recent climate policies include a legislated oil sands emission limit, and forthcoming policies include methane emissions reduction targets. Beginning January 1, 2018, large industrial emitters are subject to the Carbon Competitiveness Incentive Regulation (CCIR). This regulation prices carbon, but provides cost protection to emission-intensive / trade-exposed industries, including Devon’s oil sands operations. The impact to our operations from these regulations is expected to be minimal in the near term. Oil and gas facilities that are not subject to the CCIR are exempt from the economy-wide carbon levy until 2023.In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.Our Hedging Activities Limit Participation in Commodity Price Increases and Involve Other RisksWe enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may 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, 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, including by causing our contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.The Credit Risk of Our Counterparties Could Adversely Affect UsWe 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 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 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 by these counterparties may result in us being forced to cover the costs of those obligations and liabilities, which could adversely impact our financial results and condition.20Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact UsAs of December 31, 2017, we had total consolidated indebtedness of $10.4 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:requiring us to dedicate a significant 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; andlimiting 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.Environmental Matters and Related Costs Can Be SignificantAs an owner, lessee or operator of oil and gas properties,hydraulic fracturing, we are subject to various other federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that results from our operations.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. Changes in or additions to public policy regarding the protection of the environmentAny such changes could have a significant impact on our operations and profitability.Cyber AttacksSeismic Activity – Earthquakes in southeastern New Mexico, western Texas, northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the oil and gas industry, particularly the disposal of wastewater in salt-water disposal wells. 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. For example, New Mexico implemented protocols in November 2021 requiring operators to take various actions with respect to salt-water disposal wells within a specified proximity of certain seismic activity, including a requirement to limit injection rates if the seismic event is of a certain magnitude. Separately, the Railroad Commission of Texas has shown increasing regulatory focus on seismicity and the oil and gas industry in recent years, and has imposed limits on certain salt-water disposal well activities in portions of the Delaware and Midland Basins. These or similar actions directed at our operating areas could limit the takeaway capacity for produced water in the impacted area, which could increase our operating expense, require us to curtail our development plans or otherwise adversely impact our operations.•requiring us to dedicate a portion of our liquidity 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.ourthe use of technologythese technologies in our operations, including through artificial intelligence, process automation and data analytics. Concurrent with thisthe growing dependence on technology is a greater sensitivity to cyberattack related activities, which have been increasing againstincreasingly targeted our industry. Cyber attackersPerpetrators of cyberattacks often attempt to gain unauthorized access to digital systems for purposes of misappropriating sensitiveconfidential and proprietary information, intellectual property or otherfinancial assets, corrupting data or causing operational disruptions. These attacks may be perpetrated by third partiesdisruptions as well as preventing users from accessing systems or insiders. Techniques usedinformation for the purpose of demanding payment in these attacks range from highly sophisticated effortsorder for users to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gainregain access. Cyber attacks may also be carried out in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, our vendors (including third-party cloud and IT service providers), midstream providers and other business partners may separately suffer disruptions or breaches from cyber attacks,cyberattacks, which, in turn, could adversely impact our operations and compromise our information. Moreover, we and other upstream companies rely on extensive oil and gas infrastructure and distribution systems to deliver our production to market, which in turn depend upon digital technologies. Any cyberattack directed at such infrastructure or systems could adversely impact our business and operations, including by limiting our ability to transport and market our production. Geopolitical instability may also increase our cybersecurity risk.not sufferedexperienced cybersecurity incidents from time to time, none have had a material losses relatedeffect on our business, operations or reputation. However, our systems and procedures for protecting against such attacks and mitigating such risks may prove to cyberbe insufficient in the future due to system vulnerabilities, human error or malfeasance or other factors. Any such attacks could have an adverse impact on our business, operations or reputation and lead to date, if we were successfully attacked, we could incur substantial remediation and other costs, litigation or suffer other negative consequences, including litigation risks.regulatory actions. Moreover, as the sophistication and volume of cyber attacks continuescyberattacks continue to evolve,increase, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.vulnerabilities, and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.Limited Control on Properties Operated by OthersCertain 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.21Midstream Capacity Constraints and Interruptions Impact Commodity SalesWe rely on midstream facilities and systems to process our gas production and to transport our oil, gas and NGL production to downstream markets. Such midstream systems include EnLink’s systems, as well as other systems operated by us or third parties. Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time due to losing access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions and natural disasters, accidents, field labor issues or strikes. Additionally, we and third parties may be subject to constraints that limit our or their ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.production, processing and transportationproduction of oil, gas and NGLs.insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certaina variety of other risks, such asincluding pollution events that are considered gradual, war and political riskrisks and war. Our insurance does not coverfines or penalties or fines assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have a materialan adverse effect on our profitability, financial condition and liquidity.Competition for Assets, Materials, PeopleOur Business Could Be Adversely Impacted by Shareholder Activism, Proxy Contests or Similar ActionsCapital Can Be SignificantStrong competition existsother forms of shareholder activism have been directed against numerous public companies. Investors may from time to time seek to involve themselves in all sectorsthe governance, strategic direction and operations of the oil and gas industry. We competeCompany, whether by stockholder proposals, public campaigns, proxy solicitations or otherwise. These actions may be prompted or exacerbated by unfavorable recommendations or ratings from proxy advisory firms or other third parties, including with major integrated and independent oil and gas companies forrespect to our performance (or the acquisitionperception 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, whichour performance) under ESG metrics. Such actions could adversely affectimpact our business by distracting our Board of Directors and employees from our long-term strategy, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on core business operations and strategic transactions or plans and provoking perceived uncertainty about the future direction of our development plans on a timely basisbusiness. Such perceived uncertainty may, in turn, make it more difficult to retain employees and within budget. Competition is also prevalentcould result in significant fluctuation in the marketing of oil, gas and NGLs. Certainmarket price of our competitors have financial and other resources substantially greater than ours. They also may have established strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for assets or services and accessing capital. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels and the application of government regulations.common stock.•••2223UnresolvedUnresolved Staff CommentsDevon Gas Services, L.P.On April 7, 2020, WPX Energy, Inc., a wholly-owned subsidiary of the Company, is currentlyreceived a notice of violation from the EPA relating to specific historical air emission events occurring on the Fort Berthold Indian Reservation in negotiationsNorth Dakota. On July 22, 2022, we received an updated notice of violation from the EPA relating to the same underlying events. On June 4, 2021, we received a separate notice of violation from the EPA relating to alleged air permit violations by WPX Energy Permian, LLC, a wholly-owned subsidiary of the Company, during 2020 in western Texas. The Company has been engaging with the EPA with respect to alleged noncompliance with the leak detectionresolve each of these matters. Although these matters are ongoing and repair requirements of EPA regulations promulgated under the Clean Air Act at its Beaver Creek Gas Plant located near Riverton, Wyoming. Although management cannot predict thetheir ultimate outcome, of settlement negotiations, the resolution of this mattereach of these matters may result in a fine or penalty in excess of $100,000.$300,000.2324NYSE.NYSE under the “DVN” ticker symbol. On February 7, 2018,1, 2023, there were 7,46611,875 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 dividends is a business decision made by ourdividend, whether fixed or variable, will remain at the full discretion of the Board of Directors from time to time, and will depend on Devon’s financial conditionresults, cash requirements, future prospects and other factors deemed relevant factors. The following table sets forthby the Devon Board. In determining the amount of the quarterly highfixed dividend, the Board expects to consider a number of factors, including Devon’s financial condition, the commodity price environment and low prices for our common stock during 2017a 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 2016,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 quarterlycommodity price outlook. Additional information on our dividends per share.24Table of ContentsNote 18Index to in “Item 8. Financial Statements and Supplementary Data” of this report.TheBeginning in 2022, we replaced the peer groups with the XOP U.S. Equity Index due to recent industry consolidation causing consistent year over year changes. In 2021, the peer group includes Anadarko Petroleumincluded APA Corporation, Apache Corporation, ChesapeakeConocoPhillips, Coterra Energy Corporation, Concho Resources, Inc., ConocoPhillips, Continental Resources,Diamondback Energy, Inc., Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Noble Energy,Ovintiv, Inc., Occidental Petroleum Corporation and Pioneer Natural Resources Company. Continental Resources, Inc. was previously included in the 2021 peer group, but has been excluded as a result of going private in 2022. The graph was prepared assuming $100 was invested on December 31, 20122017 in Devon’s common stock, the S&P 500 Index, the XOP U.S. Equity Index and the 2021 peer group, and dividends have been reinvested subsequent to the initial investment.
isare included for historical comparative purposes only and should not be considered indicative of future stock performance.detailsprovides information regarding purchases of our common stock that were made by us during the fourth quarter of 2017. During 2017,2022 (shares in thousands).
Shares Purchased (1)
Paid per Share(1)In addition to shares purchased under the share repurchase program described below, these amounts also include approximately 3,000 shares received by us from employees for the payment of personal income tax withholding on vesting transactions.(2)On November 2, 2021, we did notannounced a $1.0 billion share repurchase anyprogram that would expire on December 31, 2022. On February 15, 2022, we announced the expansion of this program to $1.6 billion, and in May 2022, authorized a further expansion to $2.0 billion and extended the expiration date to May 4, 2023. In the fourth quarter of 2022, we repurchased 0.8 million common shares that were a partfor $58 million, or $71.69 per share, under this share repurchase program. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of a publicly announced program.this report.(1)Share repurchases represent shares received by us from employees for the payment of personal income tax withholding on share-based compensation vesting.Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 46,000 shares of our common2526stock in 2017, 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.Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee. Eligible employees purchased approximately 6,200 shares of our common stock in 2017. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S.6. Selected Financial DataThe financial information below should be read in conjunction with “Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this report.Operations*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.(1)Material asset impairments and acquisition and divestiture activity have had significant impacts on operating results and the carrying value of our oil and gas assets. More discussion on these items can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 3 and Note 6 of “Item 8. Financial Statements and Supplementary Data” of this report. (2)Debt balances at December 31, 2017, 2016, 2015 and 2014 include $3.5 billion, $3.3 billion, $3.1 billion and $2.0 billion, respectively, of EnLink and the General Partner debt that is non-recourse to Devon.26Item 7.Management’s Discussion and Analysis of Financial Condition and Results of OperationsIntroductionOverview20172020 items and year-to-year comparisons between 2021 and 2020 that are not included in this report can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2021 Annual Report on Form 10-K.During 2017,generated solid operating resultsacquired additional producing properties and leasehold interests in both the Williston Basin and Eagle Ford that are complementary to our existing acreage, offer operational synergies and add high-quality inventory. Additionally, our diverse portfolio balances exposure to oil and natural gas prices with access to premium markets to improve realized pricing.strategystrategic priorities of moderating production growth, emphasizing capital and operational efficiencies, optimizing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our 2022 performance highlights for these priorities include the following items:•Generated $8.5 billion of operating cash flow in North America’s best resource plays, delivering superior execution, continuing disciplined capital allocation2022, which is a 74% increase from the prior year.•2022 oil production averaged 299 MBbls/d, which is a 3% increase from the prior year.•As of December 31, 2022, completed approximately 65% of our authorized $2.0 billion share repurchase program, with 25.7 million of our common shares repurchased for $1.3 billion, or $50.90 per share, since inception of the plan.•Exited 2022 with $4.5 billion of liquidity, including $1.5 billion of cash.•Including variable dividends, paid dividends of approximately $3.4 billion in 2022 and maintaining a high degreehave declared $579 million of financial strength. Led by our developmentdividends to be paid in the STACKfirst quarter of 2023, which is inclusive of an 11% increase to our fixed quarterly dividend to $0.20 per share.•Invested approximately $100 million in emissions reduction capital projects in 2022.Delaware Basin, wedelivering the objectives that underpin our current plan. Those objectives prioritize value creation through moderated capital investment and production growth, particularly with a view of the volatility in commodity prices, supply chain constraints and the economic uncertainty arising from recent geopolitical events.improvestrengthen throughout the majority of 2022, which has significantly improved our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells.Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in Devon’s earnings and cash flow generation. The increase in commodity prices was primarily driven by increased demand resulting from the recovery from the COVID-19 pandemic. The military conflict between Russia and Ukraine and related economic sanctions imposed on Russia, as well as OPEC+ restraining production growth, further exacerbated supply shortages, causing oil
2017. 2022 as commodity prices continued to strengthen and we executed on our strategic priorities as a company. Led by a 73% and 39% increase in Henry Hub and WTI from 2021 to 2022, respectively, our unhedged combined realized price rose 38%. Additionally, volumes increased 7% from 2021 to 2022 primarily due to the continued development of assets in the Delaware Basin and acquisitions in the Williston Basin and Eagle Ford that both closed in the third quarter of 2022.
20172022 with $4.5 billion of liquidity, comprised of $2.7$1.5 billion of cash and $2.9$3.0 billion of available credit under our Senior Credit Facility. We currently have no significant$6.4 billion of debt maturities until 2021.outstanding, of which approximately $250 million is classified as short-term. We currently have approximately 25% and 20% of our oil and gas production hedged, respectively, for 2023. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub natural gas index. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our portfolio.We further enhancedstrength by completing approximately $415 millioncondition, we have authorized opportunistic repurchases of up to $2.0 billion of our announced $1 billion asset divestiture program in 2017.common shares with an expiration date of May 4, 2023. We anticipate closing the remaining divestitures in 2018.In 2018 and beyond,repurchased approximately 11.7 million shares during 2022 for approximately $718 million, or $61.36 per share. As of December 31, 2022, we have repurchased approximately 25.7 million shares for approximately $1.3 billion, or $50.90 per share, since the financial capacity to further accelerate investment acrossinception of the program. Additionally, we continue funding our best-in-class U.S. resource plays.fixed plus variable dividends, which totaled $3.4 billion in 2022. We are increasing drilling activity and will continue to shift our production mix to high-margin products. We will continue our premier technical work to drive capital allocation and efficiency and industry-leading well productivity results. We will continue to maximize the value of our base production by sustaining the operational efficiencies we have achieved. Finally, we will continue to manage activity levels within our cash flows. We expect this disciplined approach will position us to deliver capital-efficient, cash-flow expansion over the next two years.Key measures of our financial performance in 2017 are summarizedrecently declared a dividend payable in the following table. Increased commodity prices as well as continued focus onfirst quarter of 2023 for $579 million, which includes an 11% increase to our production expenses improved our 2017 financial performance as comparedfixed quarterly dividend to 2016, as seen in the table below. More details for these metrics are found within the “Results of Operations – 2017 vs. 2016”, below.$0.20 per share.27*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.(1)Core earnings and core earnings per share attributable to Devon are financial measures not prepared in accordance with GAAP. For a description of core earnings and core earnings per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.(2)Excludes any impact of oil, gas and NGL derivatives.46th51st anniversary in the oil and gas business and its 29th34th year as a public company during 2017. As an established company with a strong leadership team, we have experience operating in periodscompany. The strength of challenged commodity prices. With our focused strategy and portfolio of quality assets, the success of our 2021 transformational merger with WPX and strong commodity prices led us to generate net earnings of $6 billion in 2022, which was more than double that of 2021. Our portfolio was further strengthened in 2022 following the completion of two bolt-on acquisitions in the Williston Basin and Eagle Ford that were highly complementary to our existing positions in each basin. Both acquisitions were funded with cash on hand, and our balance sheet and financial position remains strong following the acquisitions. We remain committed to continuing our track record of industry leading return of capital to our shareholders, underpinned by low capital reinvestment rates and a disciplined, returns-driven strategy which is designed to be successful throughare focused on navigatingreturned over $4 billion of cash to shareholders through fixed and variable cash dividends and share repurchases in 2022.current environment while ensuring our long-term financial strength.Marketprior year, but volatility remained. Current market fundamentals indicate that even though the supply-demand balance for commodities is expected to remain tight due to growing demand and continued discipline by oil producers, market prices for crude oil and natural gas are inherently volatile. Therefore, we cannot predict with certaintyexpected to be lower in 2023 due to ongoing recession fears driven by high inflation levels and rising interest rates. Additionally, commodity prices could remain volatile as uncertainty still exists from the future prices for the commodities we produce and sell. During 2017, WTIimpact of sanctioned Russian oil prices ranged from approximately $42.00/Bbl to $60.00/Bbl, supported by increasing global demand and historically high OPEC compliance with its oil production cuts that were put in place in 2016 for the first half of 2017. Following the decision by both OPEC and non-OPEC producers to extend the agreement to reduce output by nearly 1.8 million barrels per day through the end of 2018, oil prices increased approximately 15% in the fourth quarterglobal market, as well as actions taken by OPEC+ countries in supporting a balanced global crude supply. Henry Hub natural gas prices continued to strengthen in 2022, averaging $6.65 per Mcf compared to $3.85 per Mcf in 2021. Natural gas prices rebounded in 2022 due to increased demand, continued capital discipline by producers, high LNG prices and infrastructure constraints. Looking forward to 2023, natural gas and NGL prices are expected to decline compared to 2022 due to limited LNG export capacity coming online, rising U.S. natural gas production and sufficient storage levels. Our 2023 cash flow is partly protected from commodity price volatility due to our current hedge position that covers approximately 25% of 2017, averaging $55.49/Bbl. Current market fundamentals indicate improved prices for crudeour anticipated oil in 2018; however, changes in OPEC production strategies, the macro-economic environment, geopolitical risks or other factors could impact current forecasts. As such, we anticipate continued volatility into 2018volumes and 20% of our anticipated gas volumes. 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.hedging2023 capital and operating costs forecasts. The currently elevated level of cost inflation could erode our cost efficiencies gained over previous years and pressure our margin in 2023, particularly if commodity prices decline. Despite this, we expect to continue generating material amounts of free cash flow at current commodity price levels due to our strategy of spending within cash flow. We expect to mitigate such volatility.Leveraging the successimpact of cost inflation through efficiencies gained from the scale of our 2017 results, we have a solid financial condition and anticipate expandingoperations as well as by leveraging our oil and gas investment by approximately 10% in 2018, while drilling and completing approximately 25% more wells. Our 2018 outlook is focused on our high returning assets in the STACK and Delaware Basin and achieving top-line oil-equivalent production growth of 6%-9%, on a retained asset basis, through some of our best-in-class positions. Additionally, we continued to execute our hedging program in 2017 and now have approximately 40% of our oil and 50% of our gas production hedged for 2018. With our anticipated results and hedging program, we intend to fully fund our increased activitylong-standing relationships with our operating cash flow. Additionally, we are targeting reducing our debt by approximately $1 billion.suppliers.Finally, EnLink continues to be a strategic advantage for us. With annual distributions to us of approximately $270 million, EnLink provides a visible cash flow stream to be further invested in our upstream capital programs.28 – 2017 vs. 2016graphs,graph, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Specifically, the graph below shows the change in net earnings from 2016 to 2017. 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. Additional information regarding noncontrolling interestsAnalysis of the change in net earnings is discussed in Note 20 in “Item 8. Financial Statements and Supplementary Data”shown below.this report.
presentsshows the drivers ofchange in net earnings from 2021 to 2022. The material changes are further discussed by category on the upstream operations change presented above, with additional details and discussion of the drivers following the graph.pages.
*Prior year amounts, including amounts in the following tables, have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.29Upstream OperationsOil, Gas and NGL ProductionProduction declines reduced our upstream revenues by $427From 2021 to 2022, the change in volumes contributed to a $488 million primarily as a result of our U.S. non-core divestitures that occurred throughout 2016 and 2017. Retained productionincrease in earnings. The increase in volumes decreasedwas primarily due to reduced completion activitycontinued development in the Delaware Basin and acquisitions in the Williston Basin and Eagle Ford and natural production declinesthat both closed in the Barnett Shale.third quarter of 2022. These decreasesincreases were partially offset by expanded drillingnatural declines in legacy Williston Basin assets and performance in the STACK.Power River Basin.Oil, Gas and NGL Prices(1)Based upon composition of our NGL barrel.3031Upstream revenues increased $1.4 billion as a result of higher unhedged,From 2021 to 2022, realized prices across our entire portfolio.contributed to a $4.1 billion increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices. The increase in index prices was partially offset by hedge cash settlements related to oil and bitumen sales primarily resulted from higher average WTI crude index prices, which were 18% higher in 2017. Additionally, ourgas commodities.(1)Included as a component of oil, gas and bitumen sales benefited from tighter differentials toNGL derivatives on the WTI index. The increase in gas sales were driven by higher North American regional index prices upon which our gas sales are based and higher NGL prices at the Mont Belvieu, Texas hub.consolidated statements of comprehensive earnings.As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements will change from a net to a gross presentation. We estimate the change to increase our upstream revenues and production expenses by approximately $250 million annually with no impact to net earnings.Commodity Derivatives43 in “Item 8. Financial Statements and Supplementary Data” of this report.In additionsettlements, we alsomargin 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, realized prices and production expenses, shown above, had the following impacts on our field-level cash margins by asset.(1)Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.Production ExpensesLOE decreased $100Index to Financial Statementsprimarily duerelated to our non-core U.S. property divestitures in 2016. Continued well optimization and cost reduction initiatives across our portfolio have offset industry inflation. These initiatives have been primarily focused on reducing coststhe re-valuation of contingent earnout payments associated with water disposal, power and fuel, compression and workovers.Gathering and transportation expense increased $92divested Barnett Shale assets. 2021 asset dispositions include $110 million primarily duerelated to a full yearthe re-valuation of the Access Pipeline transportation tolls, which commenced in the fourth quarter of 2016 subsequentcontingent earnout payments associated with divested Barnett Shale assets as well as $39 million related to the sale of our interestnon-core assets in the pipeline. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $110 million annually.Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed.Property taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. non-core divestitures.Marketing & Midstream OperationsThe overall increase in marketing and midstream operating margin was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities. Devon’s margins continue to be negatively impacted by downstream marketing commitments. We are actively engaged in optimization activities to reduce the costs of downstream commitments; however, we expect such commitments will continue to negatively impact our margin in 2018. As further discussed in Rockies. For additional information, see Note 12 in “Item 8. FinancialsFinancial Statements and Supplementary Data” of this report, in 2018 EnLink’s marketing and midstream revenues are estimated to decrease by 6-10% with a corresponding decrease to marketing and midstream expenses as a result of complying with the new revenue recognition accounting standard.31Exploration ExpensesUnproved impairments primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysicalNet financing costs increased primarily in the STACK and Delaware Basin.Depreciation, Depletion and AmortizationOur oil and gas DD&A remained relatively flat as compared to the prior year. Increases in oil and gas DD&A rates due to continued development in the STACK and Delaware Basin were offset by reduced production volumes resulting from the 2016 U.S. asset divestitures. DD&A from our midstream and other assets decreased due to debt retirements in 2021 which was partially offset by a $30 million gain associated with those retirements. Additionally, net financing costs also decreased in 2022 due to an increase in interest income resulting from an increase in interest rates. For additional information, see Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report.divestitureMerger, as well as various transaction costs related to the Merger. For additional information, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of the Access Pipeline in the fourth quarter of 2016.this report.General and Administrative ExpensesLabor and benefits decreased primarily as a result of the workforce reduction that occurred in February 2016 as discussed in For discussion on other, net, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.Non-labor costs were higherIn 2023, our total effective income tax rate is expected to remain relatively consistent with that for 2022. However, due to anreduced net operating loss carryforwards and potential effects from the IRA, our current income tax rate could increase noticeably in costs related to automation and process improvements. Reimbursed G&A decreased primarily due2023. While our 2022 current income tax rate was 7%, we expect our 2023 current income tax rate could approach the divestitures of operated properties in 2016. EnLink G&A increased primarily due to higher compensation costs.mid-teens, depending on commodity prices among other factors.Financing costs, net decreased $409 million primarily as a result of our $2.1 billion early debt retirement in 2016. For further discussion of early retirement premiums and reduced interest expense resulting from our lower debt balances, see Note 16 in “Item 8. Financial Statements and Supplementary Data” of this report.OtherAsset impairments in 2016 primarily related to goodwill and other intangible asset impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.We recognized gains in conjunction with our non-core U.S. upstream asset dispositions in both 2016 and 2017 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.During 2016, we recognized restructuring and transaction costs of $267 million primarily as a result of our workforce reduction. For discussion of our reorganization programs and the associated restructuring costs, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.The remaining change in other expense was driven primarily by changes on foreign currency exchange instruments as further discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.Income TaxesFor discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.3234Results of Operations – 2016 vs. 2015The graph below shows the change in net earnings from 2015 to 2016. 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. Additional information regarding noncontrolling interests is discussed in Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
The graph below presents the drivers of the upstream operations changed presented above, with additional details and discussion of the drivers following the graph. 
*Prior year amounts, including amounts in the following tables, have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.33Upstream OperationsOil, Gas and NGL ProductionProduction declines reduced our upstream revenues by $620 million. Production volumes decreased due to our reduction in exploration and development activity related to our retained assets during 2016. While expanded drilling in the STACK and the performance of our Jackfish assets drove production increases, these production increases were more than offset by reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale and Rockies Oil. Additionally, our production decreased as a result of our U.S. non-core divestitures that occurred throughout 2016.Oil, Gas and NGL Prices(1)Based upon composition of average Devon NGL barrel.34Upstream revenues decreased $580 million as a result of lower unhedged, realized prices for oil, bitumen and gas. The decrease in oil and bitumen sales primarily resulted from lower average WTI crude index prices, which were 11% lower in 2016 as compared to 2015. The decrease in gas sales was driven by lower North American regional index prices upon which our gas sales are based. These decreases were partially offset by slightly higher NGL prices at the Mont Belvieu, Texas hub.Commodity DerivativesProduction ExpensesLOE and LOE per BOE decreased as a result of our cost reduction initiatives, well optimization and our non-core oil and gas property divestitures. On an absolute dollar basis, LOE decreased approximately $200 million as a result of our U.S. upstream divestitures.Gathering and transportation decreased primarily as a result of U.S. upstream asset divestitures partially offset by $28 million of Access Pipeline transportation tolls which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline.Production taxes decreased on an absolute dollar basis primarily due to the decrease in our U.S. upstream revenues, on which the majority of our production taxes are assessed.Property taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. non-core divestitures.Marketing & Midstream OperationsThe overall decrease was primarily due to lower margins on Devon’s downstream marketing commitments, offset by EnLink’s margin growth largely related to its acquisition activity in late 2015 and the first quarter of 2016.Exploration ExpensesUnproved impairments primarily relate to a portion of acreage in our non-core U.S. operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs were lower due to a reduced exploration capital program in 2016.Depreciation, Depletion and AmortizationDD&A from our oil and gas properties decreased largely because of our significant asset impairments recognized in 2015. For discussion on asset impairments, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report. EnLink’s DD&A increased primarily due to acquisitions in 2015 and 2016.35General and Administrative ExpensesG&A decreased due to workforce reductions, as discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report, and other cost reduction initiatives in response to the decline in commodity prices. Reimbursed G&A decreased primarily due to a reduction in drilling activity, as well as the divestiture of operated properties. EnLink G&A decreased primarily due to lower employee compensation expense and other cost reduction initiatives during 2016.Financing Costs, netFinancing costs, net increased $388 million primarily as a result of our $2.1 billion early debt retirement. For further discussion, see Note 16 in “Item 8. Financial Statements and Supplementary Data” of this report.OtherAsset impairments largely related to our oil and gas assets and resulted from a significant decline in forecasted commodity prices during 2015 and 2016. Asset impairments for 2016 and 2015 also related to goodwill and other intangible asset impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.We recognized gains in conjunction with our non-core U.S. upstream asset dispositions in 2016 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. During 2016, we recognized restructuring and transactions costs of $267 million primarily as a result of our workforce reduction. For discussion of our restructuring programs and the associated restructuring costs, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.Income TaxesFor discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.36source and use categories of Devon and EnLink’schanges in cash and cash equivalents.equivalents for the time periods presented below.*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.Devon Sources and Uses of CashNetAs presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity in 2017. Our operatingliquidity. Operating cash flow increased $1.4 billion, or 165%, as74% during 2022 compared to 20162021. The increase was primarily due to significantly higherincreased commodity prices. In 2017, our operating cash flow fully funded our capital expenditure programprices as well as our dividends.higher volumes for 2022 compared to 2021.Our operating cash flow decreased $3.4 billion, or 80% from 2015 to 2016. While commodity prices decreased from 2015 to 2016, the primary driver of the decrease was due to the expiration of certain favorable hedge positions that provided us with an additional $2.4 billion of additional operating cash flow in 2015. In 2016 and 2015, our operating cash flow did not fully fund our capital requirements and dividends; as a result, we utilized available cash balances and divestiture proceeds to supplement our operating cash flows.Issuance of Common StockIn February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.DivestituresAcquisitions of Property and InvestmentsEquipment2017, as part2022, we paid $2.6 billion toward acquisitions of our announced divestiture program, we sold non-core U.S. assets for $415 million.producing properties and leasehold interests located in the Eagle Ford and Williston Basin, which were completed in the third quarter of 2022. For further discussion,additional information, please see Note 32 in “Item“Part II. Item 8. Financial Statements and Supplementary Data” ofin this report.2016,2022 we divested certain non-core upstreamreceived contingent earnout payments related to assets previously sold. For additional information, please see Note 2in the U.S. and our 50% interest in the Access Pipeline in Canada for approximately $3.0 billion, net of purchase price adjustments. Proceeds from these divestitures were used primarily for debt37repayment and to support capital investment in Devon’s core resource plays. For further discussion, see Note 3 in “Item“Part II. Item 8. Financial Statements and Supplementary Data” ofin this report.We did not have significant current cash income taxes resulting from the divestitures in 2017 and 2016.During 2021, we sold non-core U.S. upstream assets for approximately $79 million.followingamounts in the table summarizes ourbelow reflect cash payments for capital expenditures, and property acquisitions.including cash paid for capital expenditures incurred in prior periods.*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.The vast majority ofOur capital investment program is driven by a disciplined allocation process focused on moderating our production growth and maximizing our returns. As such, our capital expenditures are for the acquisition, drilling and development2022 represent approximately 30% of oil and gas properties. Our capital program is designed to operate within 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 expendituresflow.2017. In responseMatterhorn.lower commodity prices,Merger closing, we redeemed $1.2 billion of senior notes in 2021. We also paid $59 million of cash retirement costs related to these redemptions.total capital expenditures have been reducedBoard of Directors. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report.approximately 50% since 2015.Acquisition costs in 2016 primarily consisted of Devon’s bolt-on acquisition of assets45% to $0.16 per share and again by 13% to $0.18 per share beginning in the STACK play for $1.5 billion. Approximately $849 million wasthird quarter of 2022. In addition to the fixed quarterly dividend, we paid a variable dividend in cash at closing with the remaindereach quarter of the purchase price funded with equity consideration. In 2015 our acquisition activity primarily consisted of the Powder River Basin asset acquisition in the fourth quarter.2022 and 2021. For further discussion on acquisition activity,additional information, see Note 318 in “Item 8. Financial Statements and Supplementary Data” of this report.Debt Net2016,2021, we received $4 million of contributions from our debt decreased $3.1 billion. The decrease was primarily duenoncontrolling interests (primarily in CDM). During 2022 and 2021, we distributed $30 million and $21 million, respectively, to completed tender offersour noncontrolling interests in CDM. In the first quarter of 2021, we paid $24 million to purchase and redeem $2.1 billionthe noncontrolling interest portion of debt securities priora partnership that WPX had formed to their maturity and a $1 billion reduction in short-term borrowings. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt, including $265 million of cash retirement costs and fees.During 2015, our net debt increased $770 million. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announcedacquire minerals in the fourth quarter.Delaware Basin.Shareholder DistributionsLiquidityDevon paid common stock dividendsThe business of $127 million, $221 millionexploring for, developing and $396 million during 2017, 2016 and 2015, respectively. In response to the depressed commodity price environment, we reduced our quarterly dividend from $0.24 to $0.06 per share in the second quarter of 2016.EnLink and General Partner DistributionsDevon received $265 million, $265 million and $268 million in distributions from EnLink and the General Partner during 2017, 2016 and 2015, respectively.38In 2015, we conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.EnLink Sources and Uses of CashEnLink’s operating cash flow has increased each year since 2015 as a result of the growth experienced from its acquisition activity and continued development activities.Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion ofproducing oil and natural gas gathering facilitiesis capital intensive. Because oil, natural gas and pipelines. During 2016, EnLink acquired Anadarko Basin gatheringNGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and processing midstream assets for $1.5 billion. Approximately $792 million was paid in cash at closing with the remaindereven 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 the purchase price funded with equity consideration and debt. For additional information on this acquisition, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. EnLink’s acquisitions in 2015 consisted of additional oil and gas pipeline assets, including gathering, transportation and processing facilities.assets.During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. Proceeds were primarily used to pay a portion of the first $250 million installment payment related to EnLink’s 2016 acquisition noted above.During 2017, EnLink’s debt increased $247 million. In May 2017, EnLink issued $500 million of 5.45% senior notes due in 2047 to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. In June 2017, EnLink redeemed its 7.125% senior unsecured notes due in 2022 for aggregate cash consideration of $174 million. Additionally, EnLink reduced its credit facility borrowings to $74 million during 2017. As noted above, EnLink made the first installment payment in 2017 related to its 2016 acquisition.EnLink and the General Partner distributed $354 million, $304 million and $254 million to non-Devon unitholders during 2017, 2016 and 2015, respectively.During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3 million common units through general public offerings and its “at the market” equity program, generating net proceeds of approximately $107 million, $167 million and $25 million, respectively.In 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.In 2016, to fund a portion of the cash consideration of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction. In 2017 and 2016, EnLink received contributions from noncontrolling interests. For further discussion see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.Devon Liquidityproceeds and cash on hand.proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidityIf needed, we can also include, among other things,issue debt and equity securities, that can be issued pursuant toincluding through transactions under our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. The most significant source of liquidity in 2017 has come from our operating cash flow supplemented with approximately $415 million of proceeds related to our asset divestitures.SEC. We estimate the combination of theseour sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments, dividends and other contractual commitmentsrequirements, as discussed in this section.section, as well as execute our cash-return business model.39isforecasts are sensitive to many variables theand include a measure of uncertainty as actual results may differ from our expectations.of whichvariables for our operating cash flow are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow increased 165% in 2017 largely due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as we adjust our capital program to invest within our operating cash flow. Furthermore, proceeds from our non-core asset divestitures will provide additional liquidity as needed.Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantiallyhighly variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.We target hedging approximately 50% of our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. As a result, entering into 2018 we have hedged approximately 40% of our anticipated oil and 50% of our anticipated gas production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 20172022 are presented in Note 43 in “Item 8. Financial Statements and Supplementary Data” of this report.prices.Divestitures of Propertyprices, which is what we experienced in 2022 and Equipment – In 2017, we announced a program2021. Furthermore, the COVID-19 pandemic has contributed to divest approximately $1 billion of upstream assets. These non-core assets identifieddisruption and volatility in our supply chain, which has resulted, and may continue to result, in labor shortages, increased costs and delays for monetization include select portions of the Barnett Shale focused primarily in and around Johnson Countypipe and other properties located principally within Devon’s U.S. resource base. Through December 31, 2017, Devon completed divestiture transactions totaling approximately $415 million. The most significant asset remaining in this program is select Barnett Shale properties which wematerials needed for our operations as well as increased costs due to inflation. We expect to close in 2018.mitigate the impact of cost inflation through efficiencies gained from the scale of our operations as well as by leveraging our long-standing relationships with our suppliers.Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2017, we had total debt of $6.9 billion that bears fixed interest rates averaging 5.7%.As of December 31, 2017, we had open interest rate swap positions that are presented in Note 4 in “Item 8. Financial Statements and Supplementary Data” in this report.our joint-interest partnersjoint interest owners 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.At the end of 2017, we held approximately $2.6Credit Availabilitycash. Included in this total was $732 million of cash held byavailable borrowing capacity under our foreign subsidiaries.Credit AvailabilityWe have a $3.0 billion Senior Credit Facility. The maturity date for $164 million of the Senior Credit Facility isat December 31, 2022. The Senior Credit Facility matures on October 24, 2018. The5, 2024, with the option to extend the maturity date forby two additional one-year periods subject to lender consent. Subsequent to October 5, 2023, the remainingborrowing capacity decreases to $2.8 billion is October 24, 2019. This credit facilitybillion. The Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2017,2022, there were no borrowings under our commercial paper program. See Note 1614 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our40outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as oil and gas property impairments and goodwill impairments. As of December 31, 2017,2022, we were in compliance with this covenant. Ourcovenant with a 23% debt-to-capitalization ratio at December 31, 2017, as calculated pursuant to the terms of the agreement, was 27.2%.ratio.restricted under anysubject to a specific funding condition requiring the absence of a “material adverse effect” clauses.. It is not uncommon for credit agreements to include such clauses. These clausesprovisions. In general, these provisions can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the creditagreement. While our credit facilityagreement includes covenantsprovisions qualified by material adverse effect as well as a covenant that requirerequires us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facilitySenior Credit Facility is not conditioned on the absence of a material adverse effect. We are currently targeting up to $1.5 billion of debt reduction in 2018.near-termsize and long-term production growth opportunities.scale of our production. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. In March 2017,Our credit rating from Fitch Ratings affirmed ouris BBB+ with a stable outlook. Our credit rating and revised our outlook to stable from negative. In April 2017, Moody’s Investor Service upgraded our credit rating from Ba2 to Ba1is Baa2 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements. or EnLink’s contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.2018 exploration and development2023 capital expenditure budget is expected to be approximately $2.2$3.6 billion to $2.4$3.8 billion, and funded within operating cash flow. Although negative movementswhich is approximately 35% higher than our 2022 capital expenditures. The anticipated increase in anycapital spending is driven by a full year of the variables discussed above would impact our operating cash flow, we likely would not change our 2018 planned capital investment. Should our operating cash flow decrease from our forecasts, we could divest non-corespend on assets to balance capital sourcesacquired in 2022 and uses.general inflation trends.EnLink LiquidityContractual ObligationsEnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2017, there were $10 million in outstanding letters2022, our material contractual obligations include debt, interest expense, asset retirement obligations, lease obligations, retained obligations related to our divested Canadian business, operational agreements, drilling and facility obligations and various tax obligations. As discussed above, we estimate the combination of credit and no outstanding borrowings under the $1.5 billion credit facility and $74 million outstanding borrowings under the $250 million credit facility. Allour sources of EnLink’s and the General Partner’s debt is non-recoursecapital will continue to Devon.As of December 31, 2017, EnLink had total debt of $3.5 billion. Of this amount, $3.4 billion bears fixed interest rates averaging 4.6% and $74 million is comprised of floating rate debt with interest rates averaging 3.2%.EnLink’s 2018 capital budget includes approximately $600 million to $800 million of identified growth projects. EnLink’s primary capital projects for 2018 include the construction of the Thunderbird processing plant in Central Oklahoma, the Lobo III processing plant in the Delaware Basin and the development of additional gathering and compression assets in Central Oklahoma and the Permian Basin.41EnLink expectsbe adequate to fund the growth capital expenditures with borrowings under its bank credit facilityour short- and proceeds from other debtlong-term contractual obligations. See Notes 6, 8, 14,15, 16 and equity sources, including capital contributions by joint venture partners. EnLink expects to fund its 2018 maintenance capital expenditures from operating cash flows. EnLink employs a strategy that includes maintaining stable operating cash flows that are supported by long-term, fixed-fee contracts. Approximately 94%20 in “Item 8. Financial Statements and Supplementary Data” of EnLink’s cash flows were generated from fee-based services in 2017. It is possible that not all of the planned projectsthis report for 2018 will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control. further discussion.Contractual ObligationsThe following table presents a summary of our contractual obligations as of December 31, 2017.(1)Debt amounts represent scheduled maturities of debt obligations at December 31, 2017, excluding net discounts and debt issue costs included in the carrying value of debt.(2)Interest expense represents the scheduled cash payments on long-term fixed-rate debt (including current portion of long term debt).(3)Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.(4)Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets.(5)Operational agreements between Devon and EnLink represent fixed-fee gathering and processing and transportation agreements. These agreements also include minimum volume commitments that will remain in effect for approximately one more year, as well as annual rate escalators.(6)Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2017 balance sheet.(7)Drilling and facility obligations represent gross contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.(8)Lease obligations consist primarily of non-cancelable leases for office space and equipment.(9)Other Devon obligations primarily relate to uncertain tax positions as discussed in Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report. Other EnLink obligations primarily consist of a $250 million installment payment on the Anadarko Basin assets acquisition as discussed in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.422120 in “Item 8. Financial Statements and Supplementary Data” of this report. Classification & ValuationChange in Accounting PrincipleIn the fourth quarter of 2017, we changed our method of accounting for our oil and gas exploration and development activities from the full cost method to the successful efforts method. In accordance with FASB ASC 250 “Accounting Changes and Error Corrections,” financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive Activities—Oil and Gas.” As required by ASC 250, we have presented the accumulated effect of the change in accounting principle from Devon’s inception to December 31, 2014 as a change in the beginning balance of our 2015 consolidated statements of equity.To recast our financial statements, we made certain critical estimates, judgments and assumptions to apply successful efforts accounting to our historical operations. These critical items are similar to those pertaining to our ongoing successful efforts accounting, which are described below. For additional information regarding the effects of the change to the successful efforts method, including our underlying successful efforts accounting policies, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.To illustrate the effect of the change to successful efforts accounting, the following table summarizes the $1.9 billion increase to our historical equity as of September 30, 2017, the date of our conversion. The increase was primarily driven by lower impairments, offset by higher DD&A and less capitalized expenses.43Our 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 third-party petroleum consulting firms. In 2017, 88% of our reserves were subjected to such audits.The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.previous section.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.Consolidated Comprehensive Statementconsolidated statements of Earnings.comprehensive earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2017, Devon had approximately $200 million of2022, all suspended well costs have been suspended for moreless than one year, which largely pertain to its Pike Heavy Oil project. Stratigraphic testing has demonstrated reserves can be produced economically at Pike. However, this capital intensive, long-duration project remains unsanctioned by Devon and its 50% partner, which is the primary reason reserves have not been designated as proven at Pike. With no lease expiration at Pike in the near future, management continues to keep the Pike exploratory costs capitalized.year.Based on this assessment,At December 31, 2022, Devon impaired $139had approximately $777 million of undeveloped leasehold in the fourth quarter of 2017. At December 31, 2017, Devon had $1.4 billion of undeveloped leasehold and capitalized interest which includes approximately $750 million related to Pike. Consistent with the evaluation above on suspended well costs, the costs for Pike continue to remain capitalized.costs. Of the remaining undeveloped leasehold costs at December 31, 2017, $85 million2022, none is scheduled to expire in 2018.2023.leasehold expiringprocess of estimating oil, gas and NGL reserves requires substantial judgment, resulting in 2018 relatesimprecise 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 areasaudits performed by a third-party petroleum consulting firm. In 2022, 89% of our proved reserves were subjected to such an audit.Devon is actively drilling. If our drilling ishave been both increases and decreases in individual years, have averaged approximately 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not successful, this leasehold could become partiallybe necessary in the future. For example, revisions may be driven broadly by economic factors such as significant changes in operating costs, or entirely impaired.they may be more focused such as in a given area or reservoir. The data for a given reservoir may 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.44generally utilize theNYMEX forward strip prices for the first five years and applyincorporate internally generated price forecasts for subsequent years. along with price forecasts published by reputable investment banks and reservoir engineering firms to estimate our future revenues.thesethe reserves or market-based assumptions could result in lowercan significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact both the recognition and timingamount of impairments. Duesuppressed commodity prices in 2015 and 2016,decrease more than 60% during the first quarter of 2020. As a result, we recognized significant asset impairments in each of those years.reduced our planned 2020 capital investment 45%. With more stabilized and higher pricing in 2017, we did not recognize material asset impairments. Goodwill and Other IntangiblesGoodwillWe test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. While we use data as of October 31 for our test, we typically complete the test in late December or early January as the October 31 market data used in our test becomes available.We assess the qualitative and quantitative factors to determine whether the fair value of a reporting unit is less than its carrying amount. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue growth rates driven by futurematerially lower commodity prices and volume expectations, operating marginsreduced near-term investment, we assessed all our oil and capital expenditures.For the Octobergas fields for impairment as of March 31, 2017 impairment tests for Devon’s U.S. reporting unit2020 and each of EnLink’s reporting units, the fair value of each reporting unit exceeded its carrying value.Sustained weaknessrecognized proved and unproved impairments totaling $2.8 billion. The impairments relate to our Anadarko Basin and Rockies fields in the overall energy sector driven by lowwhich our basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices together withwere much higher than the first quarter of 2020.declineresult of the impairments recognized in 2020 and the EnLink unit price, caused a changesignificant increases in circumstances warranting an interimcommodity prices during 2021 which sustained through 2022, none of our oil and gas assets were at risk of impairment test for EnLink’s reporting units in 2015 and an update to be performed atas of December 31, 2015. Using the fair value approaches described above, it was determined that the estimated fair value of EnLink’s Texas, Louisiana and Crude and Condensate reporting units were less than their carrying amounts and a goodwill impairment loss of $492 million, $787 million and $49 million, respectively, was recognized in 2015.2022.Additionally, another interim impairment test was warranted during 2016 for EnLink’s reporting units. Using the fair value approaches described above, it was determined that the estimated fair value of EnLink’s Texas, General Partner and Crude and Condensate reporting units were less than their carrying amounts and a goodwill impairment loss of $473 million, $307 million and $93 million, respectively, was recognized in 2016.Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which we would determine that the carrying value exceeds fair value. We would expect that a prolonged or sustained period of lower commodity prices would adversely affect the estimate of45future operating results, which could result in future goodwill impairments for our reporting units 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 adversely affects our results of operations in the period recognized.Other Intangible AssetsIn 2015, the assessment of customer relationships was updated due to the factors described in the aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment.The other intangible assets impairment has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.At the endDue to significant increases in commodity pricing and projections of 2017 and 2016, we had deferred tax assets that largely resulted from the asset impairments recognized throughout 2016. As a result of our recent cumulative losses and our current realization assessment, we recorded a 100% valuation allowance against our U.S. deferred tax assets as of December 31, 2017 and December 31, 2016. Further, in 2017, we recognized a $660 million partial valuation allowance against certain Canadian deferred tax assets as a result of the Canadian legal entity restructuring. 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 ourfuture income, tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S. and existing U.S. income tax laws, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested. For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:separate analysis of a diverse chain of foreign entities;relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; andfurther analysis of a variety of other inputs such as the earnings, profits, U.S./foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.46Because of the administrative burden required to perform these additional activities, it is impractical to calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of companies.Under the Tax Reform Legislation, the corporate income tax rate was reduced to 21% effective January 1, 2018. We are required to recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax, remeasuring our U.S. deferred tax assets and liabilities and reassessing the net realizability of our deferred tax assets and liabilities.In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 20172021, Devon reassessed its evaluation of the realizability of deferred tax assets in future years and ongoing guidancedetermined that a U.S. federal valuation allowance was no longer necessary. As such, Devon removed its remaining U.S. federal valuation allowance.accounting interpretation are expectedtax 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% over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change occurred during 2022 for Devon, but the Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next 12 months,year. 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. Devon continues to maintain valuation allowances for certain state and foreign deferred tax assets.consideracquire assets and assume liabilities in transactions accounted for as business combinations, such as the Merger with WPX. In connection with the Merger in 2021, as the accounting acquirer, we allocated the $5.4 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the transition tax, deferred tax remeasurements,date of the Merger.other items to be incomplete dueliabilities assumed in the Merger. The most significant assumptions related to the forthcoming guidanceestimated fair values of proved and our ongoing analysisunproved oil and gas properties. Since sufficient market data was not available regarding the fair values of final year-end dataproved and tax positions. We expect to complete our analysis withinunproved oil and gas properties, we prepared estimates and engaged third-party valuation experts. Significant judgments and assumptions were inherent in these estimates and included, among other things, estimates of reserve quantities, estimates of future commodity prices, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflected the measurement period in accordance with SAB 118.Absent unexpected events and unexpected effectsrisk of the Tax Reform Legislation, Devon expectsunderlying cash flow estimates.positivesignificant impact on its future after-tax earnings, primarily dueresults of operations presented in Devon’s financial statements. A higher fair value ascribed to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserve quantities, development costs and operating costs. In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.lower federal statutory taxfair value of proved and unproved oil and gas properties, other fair value assessments for the assets acquired and liabilities assumed in the Merger related to debt, the equity method investment in Catalyst and out-of-market contract liabilities. The fair value of the assumed WPX publicly traded debt was based on available third-party quoted prices. We prepared estimates and engaged third-party valuation experts to assist in the valuation of the equity method investment in Catalyst. Significant judgments and assumptions inherent in this estimate included projected Catalyst cash flows, comparable companies cash flow multiples and an estimate of an applicable market participant discount rate. The fair value of assumed out-of-market contract assets and liabilities associated with longer-term marketing, gathering, processing and transportation contracts included significant judgments and assumptions related to determining the market rates, estimates of future reserves and production associated with the respective contracts and applying an applicable market participant discount rate.20172022 Results” in this Item 7.7 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as alternatives to GAAP measures.a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings (loss) excluding certain noncash or non-recurringand other items that are typically excluded by securities analysts in their published estimates of our quarterly financial results. For more information on the results of discontinued operations for our Barnett Shale assets, 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. Items may appear to be recurring when comparing on an annual basis. In the table below, restructuring and transaction costs were incurred in two of the three year periods; however, these costs relate to different restructuring programs. Amounts excluded for 2017 relate to asset dispositions, noncash asset impairments including noncash unproved asset impairments (included in exploration expenses), U.S. tax reform changes, deferred tax asset valuation allowance, derivatives and financial instrument fair value changes, legal entity restructuring and costs associated with early retirement of debt.Amounts excluded for 20162022 relate to asset dispositions, noncash asset impairments (including an impairment of goodwill) including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig stacking costs,impairments), deferred tax asset valuation allowance restructuring and transaction costs associated with the 2016 workforce reduction, derivatives and financial instrument fair value changes and costs associated with early retirement of debt.in derivative financial instruments.20152021 relate to asset dispositions, noncash asset impairments (including an impairment of goodwill) including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig stacking costs,impairments), deferred tax asset valuation allowance, changes in tax legislation, fair value changes in derivative financial instruments, restructuring and transaction costs derivativesassociated with the workforce reductions in 2021 and financial instrumentcosts associated with the early retirement of debt.repatriation of funds toforeign currency, change in tax legislation and restructuring and transaction costs associated with the U.S.workforce reductions in 2020.analysts, which typically make similar adjustments in their estimates of our financial results.analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.47*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.4843QualitativeQualitative Disclosures about Market Risk U.S. and Canadian 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, 20172022 are presented in Note 43 in “Item 8. Financial Statements and Supplementary Data” of this report.2017,2022, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $260$150 million.2017,2022, we had total debt of $10.4$6.4 billion. Of this amount, $10.3 billion bearsAll of our debt is based on fixed interest rates averaging 5.3%, and approximately $74 million is comprised of floating rate debt with interest rates averaging 3.2%5.8%.As ofForeign Currency Risk2017, we had open interest rate swap positions that are presented in 2022.Note 4Table of Contents in “ItemData” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the three month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet or liquidity at December 31, 2017.DataForeign Currency RiskOur net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our December 31, 2017 balance sheet.Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of these subsidiaries hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Based on the amount of the cash and intercompany loans as of December 31, 2017, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.49Item 8.Financial Statements and Supplementary Data5148 Comprehensive Statements of Comprehensive Earnings535054515552565357545754Change in Accounting PrincipleAcquisitions and Divestitures6764Acquisitions and DivestituresDerivative Financial Instruments7167Derivative Financial InstrumentsShare-Based Compensation73687570Asset ImpairmentsRestructuring and Transaction Costs797180728172Attributable to DevonFrom Continuing Operations85768676867787778778899091799483948398879888998910191102Note 2422 – Supplemental Information on Oil and Gas Operations (Unaudited)10492Note 25 – Supplemental Quarterly Financial Information (Unaudited)1125047RegisteredRegistered Public Accounting FirmThe and Stockholders
Devon Energy Corporation:“Company”)Company) as of December 31, 20172022 and 2016,2021, the related consolidated statements of comprehensive earnings, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017,2022, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2017,2022, based on criteria established in Internal Control – Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission.20172022 and 2016,2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2022, 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, 2017,2022 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.Change in Accounting PrincipleAs discussed in Note 1 to the consolidated financial statements, the Company has elected to change its method of accounting for oil and gas exploration and development activities from the full cost method of accounting to the successful efforts method of accounting in 2017. OpinionOpinionsoverOver Financial Reporting contained in “Item"Item 9A. Controls and Procedures.”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”)(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.51
February 15, 2023February 21, 20185249 COMPREHENSIVE STATEMENTS OF COMPREHENSIVE EARNINGS*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.5350*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.5451
653 million and 663 million shares in 2022 and 2021, respectively*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.5552*Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.56531.1.Summary of Significant Accounting PoliciesNorth American onshore areas in the U.S.Canada.WPX completed an all-stock merger of equals on January 7, 2021. 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 also owns natural gas pipelines, plants and treatment facilities through its ownership in EnLink andcommon stock. The transaction has been accounted for using the General Partner.acquisition method of accounting, with Devon being treated as the accounting acquirer. See Note 2 for further discussion.Change in Accounting Principle and Presentation ChangesIn the fourth quarter of 2017, Devon changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method. In accordance with FASB ASC 250 “Accounting Changes and Error Corrections,” financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive Activities—Oil and Gas.” Although the full cost method of accounting for oil and gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the preferred method and is more widely used in the industry and will improve comparison to Devon’s peer group. Devon believes the successful efforts method provides a more transparent representation of its results of operations. The successful efforts method also provides our investments in oil and gas properties to be assessed for impairment as of the balance sheet date in accordance with FASB ASC 360 “Property, Plant and Equipment” rather than valuations based on 12-month historical prices and costs prescribed under the full cost method. For more detailed information regarding the effects of the change in accounting principle to the successful efforts method, see Note 2.As Devon recast its financial statements to the successful efforts method, the financial statements and disclosures were examined through the lens of simplicity and transparency. From this assessment, certain changes were made to the financial statement presentation not specifically required by the successful efforts method of accounting. In general, Devon sought to simplify the presentation of its consolidated comprehensive statements of earnings and provide expanded and improved disclosures of key components in its operating results. These presentation judgments improve the clarity and utility of the financial operating results for investors and other stakeholders. As a result, certain prior period amounts have been reclassified to align to this new approach. To ensure financial statement users clearly understand the changes, a description of each enhancement is provided below.Upstream revenues – On the statement of operations, Devon is combining sales of oil, gas and NGL volumes, as well as oil, gas and NGL derivative activity, into this new line item. With the streamlined presentation of upstream revenues, MD&A and other disclosures of these items were expanded.Production expenses – Similar to streamlining the presentation of upstream revenues, Devon is simplifying the presentation of cash-based expenses associated with upstream production. Previously these expenses were reported separately as lease operations and production and property taxes in the comprehensive statements of earnings. These items are now combined in this new line item. Devon has expanded the MD&A and other disclosures of expenses for lease operations, gathering and transportation, production taxes and property taxes.57DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)Asset dispositions – This line item will capture gains and losses from dispositions of assets. As a full cost company, Devon rarely had material gains and losses on asset dispositions. However, when it did, such amounts were reported as part of revenues. Devon has more gains and losses under the successful efforts method of accounting. Since recognizing gains and losses on asset dispositions are largely affected by previously recognized DD&A and asset impairments, this item was placed adjacent to those items on the comprehensive statements of earnings.and entities in which it holds a controlling interest.interest and VIEs for which Devon is the primary beneficiary. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments accountedin non-controlled entities over which Devon does not have the ability to exercise significant influence are initially recognized at cost and subsequently adjusted for usingcontributions and distributions.equity method and cost method are reported asDelaware Basin. Devon holds a component of other long-term assets.Devon completed a business combinationcontrolling interest in 2014 whereby Devon controls both EnLinkCDM and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’sCDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon.•••midstream assetsother property and equipment and product and equipment inventories;•••the fair value of intangible assets other than goodwill;•income taxes;58DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)••legal and environmental risks and exposures; and••general credit risk associated with receivables and other assets.titlecontrol has transferred and collectability of the revenue is probable. DeliveryDevon’s performance obligations are satisfied at a point in time. This occurs and title typicallywhen control is transferred whento the purchaser upon delivery of contract specified production has been deliveredvolumes at a specified point. The transaction price used to recognize revenue is a pipeline, railcar or truck. Cashfunction of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received relating to futurewithin 30 days of the end of the production is deferred and recognized when all revenue recognition criteria are met.month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of comprehensive earnings.and midstreamRevenuesrecordedgenerated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract-specified products are sold or services are provided to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, titlecontrol has transferred and collectability of the revenue is probable. RevenuesThe transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases transportation and processing contracts are reported on a gross basis when Devon takes title tocontrol of the products and has risks and rewards of ownership.During 2017, 2016Midstream Revenues2015, no purchaserdehydration 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.more than 10%approximately 15% of Devon's sales revenue. For the years ended December 31, 2021 and 2020, sales to two customers accounted for approximately 19% and 12% and 13% and 10%, respectively, of Devon's sales revenue.consolidatedmajor customers were to stop purchasing our production, the Company believes there are a number of other purchasers to whom the company could sell Devon’s production. If multiple significant customers were to discontinue purchasing Devon’s production abruptly, the Company believes it would have therevenue.disruptions.interest rates and Canadian to U.S. dollar exchangeinterest rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.and EnLink periodically enterenters into derivative financial instruments with respect to a portion of theirits oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars and call options.collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes two-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.counterparty.Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of December 31, 2017, Devon did not have any open foreign exchange contracts.59DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)2017,2022, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets.interest rates and foreign currencyinterest 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, 2017,2022, Devon held no cash collateral of its counterparties nornor posted collateral to its counterparties. Given Devon's current credit ratings and the terms of the underlying contracts, Devon is not currently required to post collateral to its counterparties with respect to its open derivative positions, and would not be required to post any such collateral as a result of any change to the amount of Devon's net liability for such positions.Independent of EnLink, Devon grants share-based awards to members of its Board of Directors, management and select employees. EnLink and the General Partner also grant share-based awards to members of its Board of Directors and select employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated comprehensive statements of comprehensive earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 76, certain share-based awards were accelerated and recognized as a component of restructuring and transaction costs in the accompanying 2016 consolidated comprehensive statements of comprehensive earnings.60DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)awards, as well as performance-based restricted stock awards that have met the requisite performance targets.awards. Diluted earnings per share is calculated and Cash Equivalents and Restricted Cashreceivables for whichreceivables. Devon does not require collateral security. security for joint interest receivables.has establishedrecords an allowance for bad debts equal tocredit 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 estimable portions of accounts receivable for which failure to collect is considered probable. When a portionage of the receivable, is deemed uncollectible,current macro-economic conditions, credit rating of the write-off is made against the allowance.counterparty and our historical loss rate.Under this method explorationExploration 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 drilling61DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)in accordance with ASC 932 “Extractive Activities – Oil and Gas” for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. Costs of insignificant unproved properties are amortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms.annually, or more frequently ifwhen 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.consolidated statements of comprehensive 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.andthat are attributable to material unproved oil and gas properties and major development projects of oil and gas properties.62DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)Midstream and Other Property and Equipmentmidstream and corporate construction projects are also capitalized. and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.Goodwillana 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 andassessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative factors.goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of eachthe 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, then goodwill is written down toan impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. The fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units areunit is estimated based upon several valuation analyses, including comparable companies,market capitalization, comparable transactions of similar companies and premiums paid.and EnLink performed annual impairment tests of goodwill in the fourth quarters of 2017, 20162022, 2021 and 2015. 2020. No impairment was required as a result of the annual tests in 2017 or 2016; however, sustained weakness in the overall energy sector driven by lower commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units. See Note 14 for further discussion.Intangible AssetsUnamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10 to 20 years. During 2017, 2016 and 2015, EnLink’s customer relationships were also evaluated for impairment, and in 2015, a portion of these intangible assets was considered impaired. See Note 14 for further discussion.time periods.63DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)•••Foreign Currency Translation AdjustmentsThe U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity.2.Acquisitions and DivestituresRecently Adopted Accounting StandardsIn On January 2017,7, 2021, Devon adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting. Its objective is to simplify several aspectsand WPX completed an all-stock merger of equals. WPX was 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 accountingMerger, 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 Merger was structured as a tax-free reorganization for share-based payments, including income taxes when awards vest or are settled, statutory withholding and forfeitures. As the result of adoption, Devon made certainU.S. federal income tax presentation changes,purposes.notably prospectively presenting excess tax benefitssignificant of these being related to the valuation of WPX's oil and deficienciesgas properties. Significant judgments and assumptions included, among other things, estimates of reserve quantities, estimates of future commodity prices, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflected the risk of the underlying cash flow estimates. The inputs and assumptions related to the oil and gas properties were categorized as level 3 in the consolidated comprehensive statements offair value hierarchy.earnings and as operating cash flows inThe following table represents the consolidated statements of cash flows. Devon also retrospectively applied the new cash flow statement guidance dictating the presentation of shares exchanged for tax-withholding purposes as a financing activity. The adoptionfinal allocation of the new guidance did not materially impacttotal purchase price of WPX to the consolidatedidentifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date.statementsinformation for the year ended December 31, 2017 or previously reported2020 is based on our historical consolidated financial statements adjusted to reflect as if the Merger had occurred on January 1, 2020. The information below reflects pro forma adjustments to conform WPX’s historical financial information but couldto Devon’s financial statement presentation. The unaudited pro forma financial information is not necessarily indicative of what would have a more material future impact.In January 2017,occurred if the FASB issued ASU 2017-04, Intangibles – Goodwill And Other (Topic 350), Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amountMerger had been completed as part of step two of the goodwill impairment test. Under ASU 2017-04, an entity should performbeginning of the periods presented, nor is it indicative of future results.goodwill impairment test by comparingacquisition of producing properties and leasehold interests located in the Eagle Ford for cash consideration of approximately $1.7 billion, net of purchase price adjustments. Additionally, in July 2022, Devon completed its acquisition of producing properties and leasehold interests located in the Williston Basin for cash consideration of approximately $830 million, net of purchase price adjustments. The total estimated proved reserves associated with these Eagle Ford and Williston Basin assets are approximately 87 MMBoe and 66 MMBoe, respectively. Each of these acquisitions were accounted for as asset acquisitions as substantially all of the fair value was concentrated in a group of similar assets. Each of the acquisitions resulted in the purchase of producing properties and leasehold interests in a reporting unitdefined geographical and geological area and substantially all of the assets have similar risk characteristics.carrying amount. An impairment charge should be recognizedBarnett Shale assets to BKV for proceeds, net of purchase price adjustments, of $490 million. The agreement with BKV provides for contingent earnout payments to Devon with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commenced on January 1, 2021 and has a term of four years. Devon received $65 million in contingent earnout payments related to this transaction in the first quarters of 2023 and 2022 and could receive up to an additional $130 million in contingent earnout payments for the amount by whichremaining performance periods depending on future commodity prices. The valuation of the carrying amount exceedsfuture contingent earnout payments included within other current assets and other long-term assets in the reporting unit'sDecember 31, 2022 consolidated balance sheet was $65 million and $88 million, respectively. During 2022 and 2021, Devon recorded a $42 million and $110 million increase to the fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment testsvalue within those annual periods, with early application for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, Devon elected to early adopt ASU 2017-04. The adoption had no impactasset dispositions on the consolidated financial statements.Issued Accounting Standards Not Yet AdoptedIn May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which established ASC Topic 606, Revenue from Contracts with Customers (ASC 606). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (ASU 2016-12), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. Devon will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018. Devon has aggregated and reviewed its contracts that are within the scope of ASC 606. Based on its evaluation, Devon does not anticipate the adoption of ASC 606 will have a material impact on its balance sheet or related consolidated statements of comprehensive earnings equity or cash flows. Accordingly, Devon will continuerelated to recognize revenue at the time commodities are delivered. However, ASC 606 will affect how certain transactions are presentedthese payments. These values were derived utilizing a Monte Carlo valuation model and qualify as a level 3 fair value measurement. Additional information can be found in its financial statements. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Devon will change its presentation of certain processing arrangements from a net presentation to a gross presentation. This change will impact Devon’s upstream revenues and production expenses by approximately $250 million for 2016 and 2017, and will impact 2018 by a similar amountNote 19. EnLink will change the presentation of certain marketing and midstream revenues to marketing and midstream operating expenses or from marketing and midstream operating expenses to marketing and midstream revenues. Devon estimates this reclassification will result in a net decrease in EnLink’s marketing and midstream revenues of approximately 6-10%. These estimates are based on historical information and could change based on future volumes and commodity prices. These presentation changes will have no impact on net earnings or cash flows.65663.Derivative Financial InstrumentsBased on the disclosure requirements of ASC 606, upon adoption, Devon expects to provide expanded disclosures relating to its revenue recognition policies and how these relate to its revenue-generating contractual performance obligations. In addition, Devon expects to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of its revenues. The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019. Early adoption is permitted, but Devon does not plan to early adopt. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. However, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842), Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The proposed ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. Devon is in the process of evaluating contracts and gathering the necessary terms and data elements for purposes of determining the impact this ASU will have on its consolidated financial statements and related disclosures. Recently, the FASB issued ASU No. 2018-01, Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842. This ASU would permit an entity not to apply Topic 842 to land easements and rights-of-way that exist or expired before the effective date of Topic 842 and that were not previously assessed under Topic 840. An entity would continue to apply its current accounting policy for accounting for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements and rights-of-way to determine whether the arrangement should be accounted for as a lease. For Devon, these contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.Based on continuing research, Devon estimates a large number of contracts and data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective. Devon has preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact the adoption will have on its consolidated financial statements. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls and is evaluating technology requirements and solutions needed to comply with the requirements of this ASU. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities.The FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU will require entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. This ASU is effective for Devon beginning January 1, 2018, and income statement presentation changes will be applied retrospectively, while service cost component capitalization will be applied prospectively. Upon adoption of this ASU, Devon will reclassify $7 million, $14 million and $16 million of non-service cost components of net periodic benefit costs for 2017, 2016 and 2015, respectively, as other expenses. Such amounts are currently classified in Devon’s G&A. No other changes upon adopting this ASU are expected to be material.66DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)The FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This reconciliation can be presented either on the face of the consolidated statement of cash flows or in the notes to the financial statements. This ASU is effective for Devon beginning January 1, 2018, and will be applied retrospectively. Currently, Devon does not expect the adoption to have a material impact on its consolidated statement of cash flows.The FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This ASU clarifies the definition of a business to assist entities with evaluating whether a set of transferred assets and activities should be accounted for as an acquisition or disposals of assets or as a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires that a set of assets must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for Devon beginning January 1, 2018, and will be applied prospectively. Devon does not expect the adoption to have a material impact on its consolidated financial statements; however these amendments could result in the recording of fewer business combinations in future periods.The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This ASU will expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company's risk management activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This ASU only applies to entities that elect hedge accounting, which Devon has not for derivative financial instruments during the three year period ended December 31, 2017. This ASU is effective for annual and interim periods beginning January 1, 2019, with early adoption permitted in 2018. The ASU is required to be adopted using a cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements if hedge accounting were elected by Devon in the future.2.Change in Accounting PrincipleIn the fourth quarter of 2017, Devon changed its method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. In addition, gains or losses, if applicable, are recognized more frequently on the dispositions of oil and gas property and equipment under the successful efforts method. Devon has recast certain historical information for all periods presented, including the Consolidated Comprehensive Statements of Earnings, Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Equity and related information in Notes 1, 2, 3, 5, 6, 7, 8, 9, 10, 11, 13, 14, 16, 22, 23, 24 and 25.The following tables present the effects of the change to the successful efforts method in the consolidated financial statements.67DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)68DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)69DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)70DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)Devon AcquisitionsIn January 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of equity. The allocation of the purchase price was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.In December 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. The allocation of the purchase price was $393 million to unproved properties and $106 million to proved properties.Devon Asset DivestituresUpstream AssetsIn May 2017, Devon announced a program to divest approximately $1 billion of upstream assets. The non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through December 31, 2017, Devon completed divestiture transactions with proceeds totaling approximately $415 million, before purchase price adjustments, and a net gain of $212 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves. Devon’s remaining divestiture of Johnson County assets is expected to close in 2018.During 2016, in several separate transactions with different purchasers, Devon divested non-core assets located in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. The following table presents a summary of Devon’s divestiture activity for 2016.71DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)These divestitures in 2017 and 2016 primarily related to sales of entire common operating fields. Therefore, Devon recognized a gain on the transactions. As part of the gain computations, approximately $290 million of asset retirement obligations were assumed by purchasers and $80 million of goodwill was allocated to these divested assets.Access PipelineIn October 2016, Devon divested its 50% interest in Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes.EnLink AcquisitionsIn January 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.4 billion. The purchase price was $1.0 billion to intangible assets and approximately $400 million to property and equipment. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily financed with the issuance of EnLink preferred units. The remaining $500 million of the purchase price was to be paid within one year with the option to defer $250 million of the final payment 24 months from the close date. The first installment payment of $250 million was paid in January 2017 using divestiture proceeds, proceeds from equity issuances and borrowings under EnLink’s credit facility. The remaining $250 million payment is reported in other current liabilities in the accompanying consolidated balance sheets and was made in January 2018 using proceeds from equity issuances and borrowings under EnLink’s credit facility. In August 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $251 million of existing non-monetary assets and cash to the joint venture and had committed an additional $285 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including cash contributions of approximately $144 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.In November 2016, EnLink entered into a gathering and compression joint venture with a commitment of approximately $40 million to expand its midstream assets in the STACK. The joint venture is initially owned 30% by EnLink and 70% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $29 million in cash for new infrastructure build. After the initial capital commitment, EnLink and the joint venture partner will be responsible for their proportionate share of capital costs.72DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)The following table presents a summary of EnLink’s acquisition activity for 2015.EnLink Asset Divestitures and DropdownsIn December 2016, EnLink entered into definitive agreements to divest approximately $278 million of certain non-core midstream assets. As of December 31, 2016, these assets were classified as held for sale. During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.Commodity DerivativesAs of December 31, 2017,2022, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
(Bbls/d)
Average Floor
Price ($/Bbl)
Average
Ceiling Price
($/Bbl)
(Bbls/d)
Differential to WTI
($/Bbl)73DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)2017,2022, 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.
Ceiling Price ($/MMBtu)
(MMBtu/d)
Differential to
Henry Hub
($/MMBtu)2017,2022, Devon had the followingdid not have any open NGL derivative positions. Devon’s NGL positions settle againstaverage of the prompt month OPIS Mont Belvieu, Texas index.consolidated balance sheets. Amounts related to contracts allowed to be netted upon payment subject to a masterAs of December 31, 2017, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.PeriodProductVolume (Total)Weighted Average Price PaidWeighted Average Price ReceivedQ1-Q4 2018Propane681MBblsIndex$0.88/galQ1 2018-Q1 2019Natural Gas122,629MMBtu/dIndex$2.57/MMBtuInterest Rate DerivativesAs of December 31, 2017, Devon had the following open interest rate derivative positions:(1)Mandatory settlement in December 2018.7467Financial Statement PresentationThe following table presentsnetting arrangement with the same counterparty are reported on a net gains and losses by derivative financial instrument type followed bybasis in the corresponding individual consolidated comprehensive statements of earnings caption.The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.sheets. The table below presents a summary of these positions as of December 31, 2022 and 2021.4.the second quarter of 2017, Devon’s2022, Devon's stockholders approved the 20172022 Plan. The 20172022 Plan replaces the 20152017 Plan. From the effective date of the 20172022 Plan, no further awards may be made under the 2015 Plan, and2017 Plan; however, awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards that were transferred to the 2017 Plan in accordance with its terms). The 20172022 Plan authorizes the Compensation Committee, which consistsgrant of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units Canadian restricted stock units, performance units and stock appreciation rights to eligible employees. Restricted stock awards or restricted stock units granted under the 2022 Plan may be subject to performance-based conditions. The 20172022 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 20172022 Plan, options and stock appreciation rights represent one share and other awards represent 2.31.74 shares.75DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)20162021 and 2020 in conjunction with the reduction of workforce activities described in Note 76. Approximately $60 million of associated expense for these accelerated awards and is included in other expensesrestructuring and transaction costs in the accompanying consolidated comprehensive statements of comprehensive earnings.comprehensive statements of comprehensive earnings.performance-based restricted stock awards and performance share units granted under the plans.
Average
Grant-Date
Fair Value
Average
Grant-Date
Fair Value(1)These grants also include the impact of performance share units granted in prior year that vested higher than 100% target due to Devon's TSR performance compared to applicable peers.(2)A maximum of 3.7 million common shares could be awarded based upon Devon’s final TSR ranking.(1)A maximum of 5.5 million common shares could be awarded based upon Devon’s final TSR ranking.76DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)2017.2022.years. During the vesting period, recipients of restricted stock awards made under the 2015 Plan or 2009 Plan receive dividends that are not subject to restrictions or other limitations. However, dividendsyears. Dividends declared during the vesting period with respect to restricted stock awards made under the 2017 Plan and all restricted stock units will not be paid until the underlying award vests. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award, or unit, which is expensed over the applicable vesting period.Performance-Based Restricted Stock AwardsPerformance-based restricted stock awards are 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. senior 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 fourteen peer companies over the specified three-year performance period. TheSubject to certain limits, the vesting of units may be between zero and 200%200% of the units granted depending on Devon’s TSR as compared to the peer group onas of the vesting date.end of the performance period.7769the 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.Stock OptionsIn accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from one to four years. The fair value of stock options on the date of grant is expensed over the applicable vesting period. No stock options were granted in 2017, 2016 and 2015. The following table presents a summary of Devon’s outstanding stock options.5.Asset ImpairmentsThe aggregate intrinsic value of stock options that were exercised during 2015 was $0.2 million. As of December 31, 2017, Devon had no unrecognized compensation cost related to unvested stock options.78DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)In March 2017, the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees. The combined grant date fair value was $10 million, and the total cost was recognized in the first quarter of 2017 due to the awards vesting immediately.The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of December 31, 2017.comprehensive statements of comprehensive earnings.In 2015Reduced 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 2016,reduced near-term investment, Devon impaired a significant portionassessed all of its U.S. oil and gas portfolio duecommon 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 lower forecasted oil, gasthe 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 NGL prices.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.EnLink GoodwillOther Intangible Assets ImpairmentsInRockies fields in which the cost basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher. During 2020, Devon recognized goodwillapproximately $29 million of non-oil and other intangiblegas asset impairments.related to EnLink’s business. Additional information regardingin 2020, primarily in the impairments is discussed in Note 14.Unproved Impairments2017, 20162022 and 2015,2021, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairmentsimpairments.79DEVON ENERGY CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statement of earnings.Certain of Devon’s non-Canadian foreign subsidiaries have a U.S. dollar functional currency, hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. During 2017, Devon recognized foreign exchange gains related to these activities resulting from the weakening of the U.S. dollar in relation to the Canadian dollar.Restructuring and Transaction Costsliabilities presentedand transaction costs.accompanying consolidated balance sheets.accelerated vesting of share-based grants of $21 million. Additionally, in conjunction primarily with the Merger closing, Devon recognized $48 million of transaction costs primarily comprised of bank, legal and accounting fees.In 2016,During 2020, Devon sold assets, reduced its workforce and recognized $227 million in employee-related and other costs associated with a reduction in workforce that was made in response to the depressed commodity price environment.restructuring expenses of $41 million. Of these employee-related costs, approximately $60expenses recognized in 2020, $11 million and $9 million resulted from accelerated vesting of share-based grants which are noncash charges. Additionally, approximately $24 million resulted from estimatedand settlements and curtailments of defined benefit settlements.retirement benefits, respectively.As a resultThe following table summarizes Devon’s restructuring liabilities. The remaining restructuring liability as of the reduction of workforce, Devon ceased using certain office space that was subjectDecember 31, 2022 primarily relates to non-cancellable operating lease arrangements. Devon recognized $23 million in restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using.an abandoned Canadian firm transportation agreement.In 2015, Devon recognized $24 million of employee-related and other costs associated with the reduction in workforce made subsequent to the completion of the Jackfish development projects and a decrease in planned Canadian capital investment resulting from the drop in commodity prices.
8071
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table summarizes Devon’s other expenses (income) presented in the accompanying consolidated comprehensive statements of earnings.
|
| Year Ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Estimated future obligation under a performance guarantee |
| $ | (144 | ) |
| $ | (18 | ) |
| $ | — |
|
Ukraine charitable pledge |
|
| 20 |
|
|
| — |
|
|
| — |
|
Asset retirement obligation accretion |
|
| 25 |
|
|
| 28 |
|
|
| 20 |
|
Severance and other non-income tax refunds |
|
| (5 | ) |
|
| (39 | ) |
|
| (40 | ) |
Other |
|
| 9 |
|
|
| (14 | ) |
|
| (14 | ) |
Total |
| $ | (95 | ) |
| $ | (43 | ) |
| $ | (34 | ) |
Devon has guaranteed performance through 2026 for a minimum volume commitment associated with assets divested in 2018. In 2022, the purchaser of the U.S. corporate headquarters office consolidation, Devon recognized an additional $54 million expense in 2015, due to the inabilityassets was able to fully sublease remaining office space.
Transaction Costs
In 2016,satisfy the $35 million performance obligation due in 2022 and repay Devon $44 million for shortfall payments paid by WPX and EnLink recognized $17Devon in 2021 and 2020. Due to improved commodity prices, market conditions, and performance by the purchaser of the assets, Devon also reduced the estimated liability associated with this performance obligation by $65 million in transaction costs primarily associated with2022. The effect of these cash collections and liability revisions resulted in a $144 million total benefit in 2022.
During 2022, Devon paid approximately $20 million for humanitarian relief for the closingUkrainian people and surrounding countries supporting refugees.
During 2022, 2021 and 2020, Devon received severance and other non-income tax refunds of the acquisitions discussed in Note 3.$5 million, $39 million and $40 million, respectively, related to prior periods.
|
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
|
| Year Ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Current income tax expense (benefit): |
|
|
|
|
|
|
|
|
| |||
U.S. federal |
| $ | 501 |
|
| $ | 10 |
|
| $ | (219 | ) |
Various states |
|
| 65 |
|
|
| 9 |
|
|
| — |
|
Canada |
|
| (7 | ) |
|
| (3 | ) |
|
| — |
|
Total current income tax expense (benefit) |
|
| 559 |
|
|
| 16 |
|
|
| (219 | ) |
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
| |||
U.S. federal |
|
| 1,090 |
|
|
| 18 |
|
|
| (304 | ) |
Various states |
|
| 82 |
|
|
| 22 |
|
|
| (24 | ) |
Canada |
|
| 7 |
|
|
| 9 |
|
|
| — |
|
Total deferred income tax expense (benefit) |
|
| 1,179 |
|
|
| 49 |
|
|
| (328 | ) |
Total income tax expense (benefit) |
| $ | 1,738 |
|
| $ | 65 |
|
| $ | (547 | ) |
72
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Current income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
| $ | 10 |
|
| $ | 5 |
|
| $ | (243 | ) |
Various states |
|
| — |
|
|
| (11 | ) |
|
| (8 | ) |
Canada and various provinces |
|
| 102 |
|
|
| 106 |
|
|
| 14 |
|
Total current tax expense (benefit) |
|
| 112 |
|
|
| 100 |
|
|
| (237 | ) |
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
| (192 | ) |
|
| (3 | ) |
|
| (5,487 | ) |
Various states |
|
| (5 | ) |
|
| — |
|
|
| (332 | ) |
Canada and various provinces |
|
| (97 | ) |
|
| 44 |
|
|
| (157 | ) |
Total deferred tax expense (benefit) |
|
| (294 | ) |
|
| 41 |
|
|
| (5,976 | ) |
Total income tax expense (benefit) |
| $ | (182 | ) |
| $ | 141 |
|
| $ | (6,213 | ) |
Total income tax expense (benefit) 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, |
| |||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| Year Ended December 31, |
| ||||||||||||
Total income tax expense (benefit) |
| $ | (182 | ) |
| $ | 141 |
|
| $ | (6,213 | ) | ||||||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||||||||||||||
Earnings (loss) from continuing operations before income taxes |
| $ | 7,775 |
|
| $ | 2,898 |
|
| $ | (3,090 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
U.S. statutory income tax rate |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
|
| 21 | % |
|
| 21 | % |
|
| 21 | % |
Non-deductible goodwill and intangible impairment |
|
| 0 | % |
|
| (23 | %) |
|
| (3 | %) | ||||||||||||
U.S. Tax Reform |
|
| 8 | % |
|
| 0 | % |
|
| 0 | % | ||||||||||||
Legal entity restructuring |
|
| (81 | %) |
|
| 6 | % |
|
| 0 | % | ||||||||||||
Change in tax legislation |
|
| 0 | % |
|
| 0 | % |
|
| 4 | % | ||||||||||||
State income taxes |
|
| 1 | % |
|
| 1 | % |
|
| 1 | % | ||||||||||||
Other |
|
| (13 | %) |
|
| 0 | % |
|
| 1 | % |
|
| 0 | % |
|
| 2 | % |
|
| (1 | %) |
Deferred tax asset valuation allowance |
|
| 31 | % |
|
| (29 | %) |
|
| (2 | %) |
|
| 0 | % |
|
| (22 | %) |
|
| (7 | %) |
Effective income tax rate |
|
| (20 | %) |
|
| (11 | %) |
|
| 31 | % |
|
| 22 | % |
|
| 2 | % |
|
| 18 | % |
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.
81
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 judgementsjudgments 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.
2017
2022
On December 22, 2017,August 16, 2022, the Tax Reform LegislationIRA was enactedsigned into law and containsincluded various income tax related provisions with effective dates generally beginning in 2023. Among the enacted provisions are a 15% corporate alternative minimum tax (“CAMT”) and several key tax provisionsnew and expanded clean energy credits and incentives. The CAMT will be assessed on applicable corporations with an average annual adjusted financial statement income that affectexceeds $1 billion for the preceding three consecutive years. Devon including a one-time mandatory transition tax on accumulated foreign earnings and a reductionhas made an accounting policy election to not consider the effects of the corporate incomeCAMT on the realizability of its deferred tax rateassets, carryforwards and other tax credits and will instead account for any such effects as a period cost when they arise.
2021
Prior to 21% effective January 1, 2018, among others.2021, Devon is requiredmaintained a valuation allowance against all U.S. federal deferred tax assets. Devon recognized approximately $250 million of deferred tax liabilities to recognizeaccount for the effectMerger. The recognition of thethese deferred tax law changes in the period of enactment, such as determining the transition tax, remeasuring U.S.liabilities caused a decrease to Devon’s net deferred tax assets and liabilitiesa corresponding decrease to the valuation allowance Devon had recognized on its U.S. federal deferred tax assets.
Due to significant increases in commodity pricing and reassessingprojections of future income, in the netfourth quarter of 2021, Devon reassessed its evaluation of the realizability of deferred tax assets in future years and liabilities.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allowsdetermined that a U.S. federal valuation allowance was no longer necessary. As such, Devon to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, Devon considers the accounting of the transition tax, deferred tax remeasurements, and other items to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. Devon expects to completeremoved its analysis within the measurement period in accordance with SAB 118. Provisional amounts recorded this quarter are as follows:
(a) Devon’sremaining $84 million U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings.
(b) Devon’s U.S. segment recognized $108 million in deferred tax expense and EnLink recognized $211 million in deferred tax benefit related to the reduction of the U.S. corporate income tax rate to 21%.
In the fourth quarter of 2017, Devon’s Canadian segment generated nonrecurring capital losses from internal legal entity restructuring. A deferred tax asset of $727 million was recognized related to the capital losses, offset by a $641 million increase in thefederal valuation allowance.
Throughout 2017, Devon continued to maintain a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to asset impairments
2020
The Coronavirus Aid, Relief, and significantEconomic Security Act (“CARES Act”) became law on March 27, 2020. The CARES Act allows net operating losses for U.S. federal and state income tax. Devon reduced its U.S. segment valuation allowance by $323 milliongenerated in 2017 based primarily on the financial income recorded during the period. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets. The valuation allowances impacted the effective tax rate and are discussed in the next section.
Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in 2017 due to lower relative earnings during the period. During 2017, “other” is primarily related to the taxation of other financing items.
2016
During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its deferred tax assets. The allowance results from continued financial losses in 2016. As oftaxable years beginning after December 31, 2016, the2017 and
8273
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
before January 1, 2021 to be carried back five years to offset taxable income and recoup previously paid taxes. As a result, Devon carried 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 continued to represent a 100% valuation against the U.S. netcertain deferred tax assets. Additionally,assets, including certain tax credits and state net operating losses. Reduced demand from the Canadian segment recognizedCOVID-19 pandemic caused an unprecedented downturn in the commodity price environment in 2020. As a $71 million partial valuation allowance resulting from continued financial losses.
Inresult, Devon recorded significant impairments during the first quarter of 2016, EnLink recognized2020. Devon reassessed its position and recorded a goodwill impairment of approximately $873 million. Additionally, during the third quarter of 2016, Devon derecognized $83 million of goodwill related to its100% valuation allowance against all U.S. operations in conjunction with the divestiture of certain non-core U.S. upstream oilfederal and gas assets. These items are not deductible for purposes of calculating income tax and, therefore, impact the effective tax rate.
2015
In the third and fourth quarters of 2015, EnLink recognized goodwill and intangibles impairments of approximately $1.6 billion, which impacted the effective tax rate.
During 2015, Devon recognized approximately $16 billion of oil and gas impairments related to its U.S. operations. These impairments resulted instate net deferred tax assets against which Devon recognizedand maintained a $403 millionfull valuation allowance.allowance position throughout 2020.
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, |
|
| December 31, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2022 |
|
| 2021 |
| ||||
Deferred tax assets: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Asset retirement obligations |
| $ | 313 |
|
| $ | 488 |
| ||||||||
Net operating loss carryforwards |
| $ | 526 |
|
| $ | 1,075 |
| ||||||||
Capital loss carryforwards |
|
| 523 |
|
|
| 559 |
| ||||||||
Accrued liabilities |
|
| 62 |
|
|
| 130 |
|
|
| 209 |
|
|
| 262 |
|
Net operating loss carryforwards |
|
| 865 |
|
|
| 777 |
| ||||||||
Pension benefit obligations |
|
| 54 |
|
|
| 98 |
| ||||||||
Canadian capital loss carryforwards |
|
| 760 |
|
|
| 17 |
| ||||||||
Other |
|
| 135 |
|
|
| 186 |
| ||||||||
Fair value of derivative financial instruments |
|
| — |
|
|
| 129 |
| ||||||||
Asset retirement obligation |
|
| 119 |
|
|
| 109 |
| ||||||||
Other, including tax credits |
|
| 14 |
|
|
| 138 |
| ||||||||
Total deferred tax assets before valuation allowance |
|
| 2,189 |
|
|
| 1,696 |
|
|
| 1,391 |
|
|
| 2,272 |
|
Less: valuation allowance |
|
| (968 | ) |
|
| (645 | ) |
|
| (814 | ) |
|
| (893 | ) |
Net deferred tax assets |
|
| 1,221 |
|
|
| 1,051 |
|
|
| 577 |
|
|
| 1,379 |
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Property and equipment |
|
| (1,703 | ) |
|
| (1,635 | ) |
|
| (1,969 | ) |
|
| (1,630 | ) |
Long-term debt |
|
| (92 | ) |
|
| (53 | ) | ||||||||
Fair value of derivative financial instruments |
|
| (33 | ) |
|
| — |
| ||||||||
Other |
|
| (261 | ) |
|
| (426 | ) |
|
| (38 | ) |
|
| (29 | ) |
Total deferred tax liabilities |
|
| (2,056 | ) |
|
| (2,114 | ) |
|
| (2,040 | ) |
|
| (1,659 | ) |
Net deferred tax liability |
| $ | (835 | ) |
| $ | (1,063 | ) | ||||||||
Net deferred tax asset (liability) |
| $ | (1,463 | ) |
| $ | (280 | ) | ||||||||
83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
At December 31, 2017,2022, Devon has recognized $865$526 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segmenttaxable income. Devon has $710 million of noncapital loss carryforwards expiring between 2029 and 2037. Devon’s U.S. segment has $2.4 billion of U.S. federal carryforwards expiring between 2036 and 2037 and $1.7 billion of U.S. state carryforwards expiring between 2018 and 2037. EnLink has $259221 million of U.S. federal net operating loss carryforwards, expiringof which $199 million expires between 20342030 and 2037, and $263$22 million of state carryforwards expiring between 2028 and 2037. In the current environment, Devon expects tax benefits from the Canadian carryforwards to be utilized in 2018 and beyond and EnLink carryforwards to be utilized in 2020 and beyond. Devon currently does not anticipate utilizing the U.S. federal orexpire. Devon also has $305 million of state net operating loss carryforwards as indicatedprimarily expiring between 2023 and 2041, $268 million of which are covered by the fulla valuation allowance position in the U.S. segment.allowance.
As
Devon’s net operating losses acquired from WPX as a result of the reduction in U.S. statutory income tax rate and favorable temporary differences, Devon reduced its valuation allowance by $337 million againstMerger are subject to limitation pursuant to Section 382 of the U.S.Internal Revenue Code of 1986, which relates to limitations upon the 50% or greater change of ownership of an entity during any three-year period. The Company anticipates utilizing these net operating losses prior to their expiration.
Devon's 2022 capital loss carryforward deferred tax assets, in 2017 and remains in a full valuation allowance position. Also during 2017, Devon’s Canadian segment recognized a $660 million partial valuation allowance against the deferred tax assetprimarily related to the Canadian capital loss carryforward dueCanada, are fully covered by a valuation allowance.
74
As of December 31, 2017, Devon’s unremitted foreign earnings from its international operations totaled approximately $908 million. All of this amount was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.
|
| December 31, |
| |||||||||||||
|
| December 31, |
|
| 2022 |
|
| 2021 |
| |||||||
|
| 2017 |
|
| 2016 |
|
| (Millions) |
| |||||||
Balance at beginning of year |
| $ | 202 |
|
| $ | 131 |
|
| $ | 36 |
|
| $ | 23 |
|
Tax positions taken in prior periods |
|
| (7 | ) |
|
| 36 |
|
|
| 51 |
|
|
| 5 |
|
Tax positions taken in current year |
|
| (3 | ) |
|
| — |
| ||||||||
Accrual of interest related to tax positions taken |
|
| 16 |
|
|
| 39 |
| ||||||||
Assumed WPX tax positions taken in prior periods |
|
| — |
|
|
| 8 |
| ||||||||
Settlements |
|
| (101 | ) |
|
| — |
|
|
| (14 | ) |
|
| — |
|
Lapse of statute of limitations |
|
| — |
|
|
| (5 | ) | ||||||||
Foreign currency translation |
|
| 8 |
|
|
| 1 |
| ||||||||
Balance at end of year |
| $ | 115 |
|
| $ | 202 |
|
| $ | 73 |
|
| $ | 36 |
|
Devon’sDevon's 2022 unrecognized tax benefit balance included no interest. At December 31, 2022 and December 31, 2021, there were $73 million and $36 million, respectively, of current unrecognized tax benefits that if recognized would affect the annual effective tax rate. Deferred unrecognized tax benefits of $42 million at December 31, 2017 and 20162021 are not included $28 million and $68 million, respectively,in the table above but are accounted for in Devon’s deferred tax disclosure above. Due to utilization of interest and penalties. If recognized, $115tax attributes in 2022, $42 million of Devon’s deferred unrecognized tax benefits were reclassified as of December 31, 2017 would affect Devon’s effective income tax rate. During 2017, Devon removed $101 million ofcurrent unrecognized tax benefits, including $50 million of interest, as a result of the settlement of certain tax examinations. benefits.
Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
84
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Jurisdiction | Tax Years Open | |
U.S. |
| |
Various U.S. states |
| |
Canada |
| |
|
|
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.
75
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
The following table reconciles net earnings (loss) attributable to Devonfrom continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.share from continuing operations.
|
| Year Ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Net earnings (loss) from continuing operations: |
|
|
|
|
|
|
|
|
| |||
Net earnings (loss) from continuing operations |
| $ | 6,015 |
|
| $ | 2,813 |
|
| $ | (2,552 | ) |
Attributable to participating securities |
|
| (57 | ) |
|
| (30 | ) |
|
| (4 | ) |
Basic and diluted earnings (loss) from continuing operations |
| $ | 5,958 |
|
| $ | 2,783 |
|
| $ | (2,556 | ) |
Common shares: |
|
|
|
|
|
|
|
|
| |||
Common shares outstanding - total |
|
| 657 |
|
|
| 670 |
|
|
| 383 |
|
Attributable to participating securities |
|
| (6 | ) |
|
| (7 | ) |
|
| (6 | ) |
Common shares outstanding - basic |
|
| 651 |
|
|
| 663 |
|
|
| 377 |
|
Dilutive effect of potential common shares issuable |
|
| 2 |
|
|
| 2 |
|
|
| — |
|
Common shares outstanding - diluted |
|
| 653 |
|
|
| 665 |
|
|
| 377 |
|
Net earnings (loss) per share from continuing operations: |
|
|
|
|
|
|
|
|
| |||
Basic |
| $ | 9.15 |
|
| $ | 4.20 |
|
| $ | (6.78 | ) |
Diluted |
| $ | 9.12 |
|
| $ | 4.19 |
|
| $ | (6.78 | ) |
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Net earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) attributable to Devon |
| $ | 898 |
|
| $ | (1,056 | ) |
| $ | (12,896 | ) |
Attributable to participating securities |
|
| (10 | ) |
|
| (2 | ) |
|
| (5 | ) |
Basic and diluted earnings (loss) |
| $ | 888 |
|
| $ | (1,058 | ) |
| $ | (12,901 | ) |
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding - total |
|
| 525 |
|
|
| 513 |
|
|
| 412 |
|
Attributable to participating securities |
|
| (5 | ) |
|
| (6 | ) |
|
| (5 | ) |
Common shares outstanding - basic |
|
| 520 |
|
|
| 507 |
|
|
| 407 |
|
Dilutive effect of potential common shares issuable |
|
| 3 |
|
|
| — |
|
|
| — |
|
Common shares outstanding - diluted |
|
| 523 |
|
|
| 507 |
|
|
| 407 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | 1.71 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
Diluted |
| $ | 1.70 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
Antidilutive options (1) |
|
| 2 |
|
|
| 3 |
|
|
| 4 |
|
Components of other comprehensive earnings (loss) consist of the following:
|
| Year Ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
| |||
Beginning accumulated pension and postretirement benefits |
| $ | (132 | ) |
| $ | (127 | ) |
| $ | (119 | ) |
Net actuarial gain (loss) and prior service cost arising in current year |
|
| 15 |
|
|
| (35 | ) |
|
| (34 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 6 |
|
|
| 3 |
|
|
| 7 |
|
Curtailment and settlement of pension benefits (2) |
|
| — |
|
|
| 19 |
|
|
| 16 |
|
Other (3) |
|
| — |
|
|
| 7 |
|
|
| — |
|
Income tax benefit (expense) |
|
| (5 | ) |
|
| 1 |
|
|
| 3 |
|
Accumulated other comprehensive loss, net of tax |
| $ | (116 | ) |
| $ | (132 | ) |
| $ | (127 | ) |
|
|
85
76
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Foreign currency translation and other: |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated foreign currency translation and other |
| $ | 1,226 |
|
| $ | 1,215 |
|
| $ | 1,658 |
|
Change in cumulative translation adjustment and other |
|
| 113 |
|
|
| 22 |
|
|
| (490 | ) |
Income tax benefit (expense) |
|
| (30 | ) |
|
| (11 | ) |
|
| 47 |
|
Ending accumulated foreign currency translation and other |
|
| 1,309 |
|
|
| 1,226 |
|
|
| 1,215 |
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated pension and postretirement benefits |
|
| (172 | ) |
|
| (194 | ) |
|
| (204 | ) |
Net actuarial loss and prior service cost arising in current year |
|
| 10 |
|
|
| (28 | ) |
|
| (5 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 19 |
|
|
| 26 |
|
|
| 21 |
|
Curtailment and settlement of pension benefits |
|
| — |
|
|
| 24 |
|
|
| — |
|
Income tax expense |
|
| — |
|
|
| — |
|
|
| (6 | ) |
Ending accumulated pension and postretirement benefits |
|
| (143 | ) |
|
| (172 | ) |
|
| (194 | ) |
Accumulated other comprehensive earnings, net of tax |
| $ | 1,166 |
|
| $ | 1,054 |
|
| $ | 1,021 |
|
|
|
|
| Year Ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Changes in assets and liabilities, net: |
|
|
|
|
|
|
|
|
| |||
Accounts receivable |
| $ | (142 | ) |
| $ | (526 | ) |
| $ | 231 |
|
Other current assets |
|
| (119 | ) |
|
| 30 |
|
|
| (97 | ) |
Other long-term assets |
|
| 90 |
|
|
| 12 |
|
|
| (9 | ) |
Accounts payable and revenues and royalties payable |
|
| 152 |
|
|
| 539 |
|
|
| (109 | ) |
Other current liabilities |
|
| (97 | ) |
|
| (18 | ) |
|
| (68 | ) |
Other long-term liabilities |
|
| (110 | ) |
|
| (153 | ) |
|
| (43 | ) |
Total |
| $ | (226 | ) |
| $ | (116 | ) |
| $ | (95 | ) |
Supplementary cash flow data - total operations: |
|
|
|
|
|
|
|
|
| |||
Interest paid |
| $ | 370 |
|
| $ | 404 |
|
| $ | 259 |
|
Income taxes paid (refunded) |
| $ | 438 |
|
| $ | (116 | ) |
| $ | 171 |
|
As of December 31, 2022 and 2021, Devon had approximately $413 million and $205 million, respectively, of accrued capital expenditures included in total property and equipment, net and accounts payable on the consolidated balance sheets.
|
Components of accounts receivable include the following:
|
| December 31, 2022 |
|
| December 31, 2021 |
| ||
Oil, gas and NGL sales |
| $ | 1,153 |
|
| $ | 984 |
|
Joint interest billings |
|
| 162 |
|
|
| 158 |
|
Marketing and midstream revenues |
|
| 428 |
|
|
| 370 |
|
Other |
|
| 33 |
|
|
| 38 |
|
Gross accounts receivable |
|
| 1,776 |
|
|
| 1,550 |
|
Allowance for doubtful accounts |
|
| (9 | ) |
|
| (7 | ) |
Net accounts receivable |
| $ | 1,767 |
|
| $ | 1,543 |
|
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Net change in working capital accounts, net of assets and liabilities assumed: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
| $ | (284 | ) |
| $ | (176 | ) |
| $ | 942 |
|
Income taxes receivable |
|
| 8 |
|
|
| 130 |
|
|
| 384 |
|
Other current assets |
|
| (12 | ) |
|
| 215 |
|
|
| (57 | ) |
Accounts payable |
|
| 105 |
|
|
| (167 | ) |
|
| (190 | ) |
Revenues and royalties payable |
|
| 257 |
|
|
| 96 |
|
|
| (526 | ) |
Other current liabilities |
|
| (53 | ) |
|
| (74 | ) |
|
| (818 | ) |
Net change in working capital |
| $ | 21 |
|
| $ | 24 |
|
| $ | (265 | ) |
Interest paid (net of capitalized interest) |
| $ | 481 |
|
| $ | 569 |
|
| $ | 497 |
|
Income taxes paid (received) |
| $ | 78 |
|
| $ | (159 | ) |
| $ | (279 | ) |
In 2016, Devon’s acquisition of certain STACK assets included the noncash issuance of Devon common stock. Further, in 2016, EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets included noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions. See Note 3 for additional details.
In 2015, Devon’s acquisition of certain Powder River Basin assets included a noncash common stock issuance totaling $199 million. EnLink’s acquisitions in 2015 also included $360 million of noncash equity.
8677
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components of accounts receivable include the following:
|
| December 31, 2017 |
|
| December 31, 2016 |
| ||
Oil, gas and NGL sales |
| $ | 559 |
|
| $ | 487 |
|
Joint interest billings |
|
| 134 |
|
|
| 110 |
|
Marketing and midstream revenues |
|
| 959 |
|
|
| 708 |
|
Other |
|
| 29 |
|
|
| 69 |
|
Gross accounts receivable |
|
| 1,681 |
|
|
| 1,374 |
|
Allowance for doubtful accounts |
|
| (11 | ) |
|
| (18 | ) |
Net accounts receivable |
| $ | 1,670 |
|
| $ | 1,356 |
|
Capitalized Costs
The following tables reflecttable presents the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
|
| December 31, 2022 |
|
| December 31, 2021 |
| ||
Property and equipment: |
|
|
|
|
|
| ||
Proved |
| $ | 42,734 |
|
| $ | 38,051 |
|
Unproved and properties under development |
|
| 1,548 |
|
|
| 1,081 |
|
Total oil and gas |
|
| 44,282 |
|
|
| 39,132 |
|
Less accumulated DD&A |
|
| (27,715 | ) |
|
| (25,596 | ) |
Oil and gas property and equipment, net |
|
| 16,567 |
|
|
| 13,536 |
|
Other property and equipment |
|
| 2,280 |
|
|
| 2,139 |
|
Less accumulated DD&A |
|
| (741 | ) |
|
| (667 | ) |
Other property and equipment, net (1) |
|
| 1,539 |
|
|
| 1,472 |
|
Property and equipment, net |
| $ | 18,106 |
|
| $ | 15,008 |
|
|
| December 31, 2017 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved |
| $ | 40,491 |
|
| $ | 6,804 |
|
| $ | 47,295 |
|
Unproved and properties under development |
|
| 984 |
|
|
| 1,473 |
|
|
| 2,457 |
|
Total oil and gas |
|
| 41,475 |
|
|
| 8,277 |
|
|
| 49,752 |
|
Accumulated DD&A |
|
| (32,379 | ) |
|
| (4,055 | ) |
|
| (36,434 | ) |
Oil and gas property and equipment, net |
| $ | 9,096 |
|
| $ | 4,222 |
|
| $ | 13,318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved |
| $ | 38,842 |
|
| $ | 6,163 |
|
| $ | 45,005 |
|
Unproved and properties under development |
|
| 2,115 |
|
|
| 1,277 |
|
|
| 3,392 |
|
Total oil and gas |
|
| 40,957 |
|
|
| 7,440 |
|
|
| 48,397 |
|
Accumulated DD&A |
|
| (31,979 | ) |
|
| (3,420 | ) |
|
| (35,399 | ) |
Oil and gas property and equipment, net |
| $ | 8,978 |
|
| $ | 4,020 |
|
| $ | 12,998 |
|
|
| December 31, |
| |||||
|
| 2017 |
|
| 2016 |
| ||
EnLink |
| $ | 9,120 |
|
| $ | 8,381 |
|
Devon |
|
| 1,955 |
|
|
| 1,919 |
|
Total midstream and other |
|
| 11,075 |
|
|
| 10,300 |
|
EnLink |
|
| (2,533 | ) |
|
| (2,124 | ) |
Devon |
|
| (689 | ) |
|
| (641 | ) |
Total accumulated DD&A |
|
| (3,222 | ) |
|
| (2,765 | ) |
Midstream and other property and equipment, net |
| $ | 7,853 |
|
| $ | 7,535 |
|
87
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2017.2022.
|
| Year Ended December 31, |
| |||||||||||||||||||
|
| Year Ended December 31, |
|
| 2022 |
| 2021 |
| 2020 |
| ||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| (Millions) |
| ||||||||||
Beginning balance |
| $ | 261 |
|
| $ | 225 |
|
| $ | 199 |
|
| $ | 66 |
| $ | 18 |
| $ | 82 |
|
Acquired WPX costs |
|
| — |
| 34 |
| — |
| ||||||||||||||
Additions pending determination of proved reserves |
|
| 504 |
|
|
| 247 |
|
|
| 348 |
|
|
| 462 |
| 206 |
| 148 |
| ||
Charges to exploration expense |
|
| — |
|
|
| (29 | ) |
|
| (5 | ) |
|
| (1 | ) |
| (2 | ) |
| (3 | ) |
Reclassifications to proved properties |
|
| (466 | ) |
|
| (189 | ) |
|
| (285 | ) |
|
| (401 | ) |
| (190 | ) |
| (209 | ) |
Foreign currency translation adjustment |
|
| 14 |
|
|
| 7 |
|
|
| (32 | ) | ||||||||||
Ending balance |
| $ | 313 |
|
| $ | 261 |
|
| $ | 225 |
|
| $ | 126 |
| $ | 66 |
| $ | 18 |
|
The following table provides an aging of capitalized well costs and the number ofDevon had no projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Exploratory well costs capitalized for a period of one year or less |
| $ | 113 |
|
| $ | 88 |
|
| $ | 60 |
|
Exploratory well costs capitalized for a period greater than one year |
|
| 200 |
|
|
| 173 |
|
|
| 165 |
|
Ending balance |
| $ | 313 |
|
| $ | 261 |
|
| $ | 225 |
|
Number of projects with exploratory well costs capitalized for a period greater than one year |
|
| 2 |
|
|
| 2 |
|
|
| 2 |
|
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling relate to Devon’s heavy oil operations. Management believes these projects with suspended exploratory well costs exhibit sufficient quantitiesas of hydrocarbons to justify potential development. Devon continues to assess the development timeline of these long cycle projects. December 31, 2022, 2021 and 2020.
8878
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Goodwill
The following table presents a summary of Devon’s goodwill. For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.
|
| U.S. |
|
| EnLink |
|
| Total |
| |||
Balance as of December 31, 2015 |
| $ | 923 |
|
| $ | 2,414 |
|
| $ | 3,337 |
|
Acquired during period |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Asset divestitures |
|
| (83 | ) |
|
| — |
|
|
| (83 | ) |
Impairment |
|
| — |
|
|
| (873 | ) |
|
| (873 | ) |
Balance as of December 31, 2016 |
| $ | 840 |
|
| $ | 1,543 |
|
| $ | 2,383 |
|
The following table presents the General Partner’s and EnLink’s goodwill activity by reporting unit. For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.
|
| Texas |
|
| Oklahoma |
|
| Crude and Condensate |
|
| General Partner |
|
| Total |
| |||||
Balance as of December 31, 2015 |
| $ | 704 |
|
| $ | 190 |
|
| $ | 93 |
|
| $ | 1,427 |
|
| $ | 2,414 |
|
Acquired during period |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
Impairment |
|
| (473 | ) |
|
| — |
|
|
| (93 | ) |
|
| (307 | ) |
|
| (873 | ) |
Balance as of December 31, 2016 |
| $ | 233 |
|
| $ | 190 |
|
| $ | — |
|
| $ | 1,120 |
|
| $ | 1,543 |
|
Asset Divestitures
In conjunction with the U.S. non-core upstream asset divestitures in 2016 discussed in Note 3, Devon removed goodwill allocated to these assets.
Impairment
As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units in the first quarter of 2016. Based on that test, EnLink recorded noncash goodwill impairments related to its Texas, Crude and Condensate and General Partner reporting units.
Additionally, during 2015, EnLink recorded noncash goodwill impairments related to its Texas, Louisiana and Crude and Condensate reporting units.
89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.
|
| December 31, 2017 |
|
| December 31, 2016 |
| ||
Customer relationships |
| $ | 1,796 |
|
| $ | 1,796 |
|
Accumulated amortization |
|
| (299 | ) |
|
| (172 | ) |
Net intangibles |
| $ | 1,497 |
|
| $ | 1,624 |
|
The weighted-average amortization period for the customer relationships is 15 years. Amortization expense for intangibles was approximately $127 million, $117 million and $56 million for the years ended 2017, 2016 and 2015, respectively. The remaining aggregate amortization expense is estimated to be approximately $123 million in each of the next five years.
Components of other current liabilities include the following:
| December 31, 2017 |
|
| December 31, 2016 |
| ||
Derivative liabilities | $ | 331 |
|
| $ | 187 |
|
Installment payment - see Note 3 |
| 250 |
|
|
| 249 |
|
Income taxes payable |
| 145 |
|
|
| 32 |
|
Accrued interest payable |
| 131 |
|
|
| 130 |
|
Restructuring liabilities |
| 19 |
|
|
| 48 |
|
Other |
| 325 |
|
|
| 420 |
|
Other current liabilities | $ | 1,201 |
|
| $ | 1,066 |
|
90
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon. Devon unless otherwise noted in the table below.
|
| December 31, 2022 |
|
| December 31, 2021 |
| ||
8.25% due August 1, 2023 (1) |
| $ | 242 |
|
| $ | 242 |
|
5.25% due September 15, 2024 (1) |
|
| 472 |
|
|
| 472 |
|
5.85% due December 15, 2025 |
|
| 485 |
|
|
| 485 |
|
7.50% due September 15, 2027 (2) |
|
| 73 |
|
|
| 73 |
|
5.25% due October 15, 2027 (1) |
|
| 390 |
|
|
| 390 |
|
5.875% due June 15, 2028 (1) |
|
| 325 |
|
|
| 325 |
|
4.50% due January 15, 2030 (1) |
|
| 585 |
|
|
| 585 |
|
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 premium on debentures and notes |
|
| 103 |
|
|
| 149 |
|
Debt issuance costs |
|
| (26 | ) |
|
| (30 | ) |
Total debt |
| $ | 6,440 |
|
| $ | 6,482 |
|
Less amount classified as short-term debt |
|
| 251 |
|
|
| — |
|
Total long-term debt |
| $ | 6,189 |
|
| $ | 6,482 |
|
|
| December 31, 2017 |
|
| December 31, 2016 |
| ||
Devon debt: |
|
|
|
|
|
|
|
|
8.25% due July 1, 2018 (1)(2) |
| $ | 20 |
|
| $ | 20 |
|
2.25% due December 15, 2018 (1) |
|
| 95 |
|
|
| 95 |
|
6.30% due January 15, 2019 (1) |
|
| 162 |
|
|
| 162 |
|
4.00% due July 15, 2021 |
|
| 500 |
|
|
| 500 |
|
3.25% due May 15, 2022 |
|
| 1,000 |
|
|
| 1,000 |
|
5.85% due December 15, 2025 (1) |
|
| 485 |
|
|
| 485 |
|
7.50% due September 15, 2027 (1)(2) |
|
| 73 |
|
|
| 73 |
|
7.875% due September 30, 2031 (1)(3) |
|
| 1,059 |
|
|
| 1,059 |
|
7.95% due April 15, 2032 (1) |
|
| 789 |
|
|
| 789 |
|
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 |
|
| (30 | ) |
|
| (30 | ) |
Debt issuance costs |
|
| (39 | ) |
|
| (44 | ) |
Total Devon debt |
|
| 6,864 |
|
|
| 6,859 |
|
EnLink and General Partner debt: |
|
|
|
|
|
|
|
|
Credit facilities |
|
| 74 |
|
|
| 148 |
|
2.70% due April 1, 2019 |
|
| 400 |
|
|
| 400 |
|
7.125% due June 1, 2022 |
|
| — |
|
|
| 163 |
|
4.40% due April 1, 2024 |
|
| 550 |
|
|
| 550 |
|
4.15% due June 1, 2025 |
|
| 750 |
|
|
| 750 |
|
4.85% due July 15, 2026 |
|
| 500 |
|
|
| 500 |
|
5.60% due April 1, 2044 |
|
| 350 |
|
|
| 350 |
|
5.05% due April 1, 2045 |
|
| 450 |
|
|
| 450 |
|
5.45% due June 1, 2047 |
|
| 500 |
|
|
| — |
|
Net premium (discount) on debentures and notes |
|
| (6 | ) |
|
| 9 |
|
Debt issuance costs |
|
| (26 | ) |
|
| (25 | ) |
Total EnLink and General Partner debt |
|
| 3,542 |
|
|
| 3,295 |
|
Total debt |
|
| 10,406 |
|
|
| 10,154 |
|
Less amount classified as short-term debt (4) |
|
| 115 |
|
|
| — |
|
Total long-term debt |
| $ | 10,291 |
|
| $ | 10,154 |
|
|
|
|
|
|
|
|
|
91
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Debt maturities as of December 31, 2017,2022, excluding debt issuance costs, premiums and discounts, are as follows:
|
| Total |
| |
2023 |
| $ | 242 |
|
2024 |
|
| 472 |
|
2025 |
|
| 485 |
|
2026 |
|
| — |
|
2027 |
|
| 463 |
|
Thereafter |
|
| 4,701 |
|
Total |
| $ | 6,363 |
|
On or after the dates in the following schedule, Devon has the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture documents, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture documents governing the notes to be redeemed. At any time prior to the dates in the following schedule, Devon has the option to redeem some or all of the notes at a specified "make whole" premium as described in such documents. Other than with respect to the notes identified in
79
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Devon |
|
| EnLink |
|
| Total |
| |||
2018 |
| $ | 115 |
|
| $ | — |
|
| $ | 115 |
|
2019 |
|
| 162 |
|
|
| 474 |
|
|
| 636 |
|
2020 |
|
| — |
|
|
| — |
|
|
| — |
|
2021 |
|
| 500 |
|
|
| — |
|
|
| 500 |
|
2022 |
|
| 1,000 |
|
|
| — |
|
|
| 1,000 |
|
Thereafter |
|
| 5,156 |
|
|
| 3,100 |
|
|
| 8,256 |
|
Total |
| $ | 6,933 |
|
| $ | 3,574 |
|
| $ | 10,507 |
|
the schedule below, Devon's senior notes generally include more limited redemption provisions, such as "par call" rights near the maturity date or "make whole" redemption rights.
Optional Redemption | ||
5.25% due October 15, 2027 | October 15, 2022 | |
5.875% due June 15, 2028 | June 15, 2023 | |
4.50% due January 15, 2030 | January 15, 2025 |
Retirement of Senior Notes
During 2021, Devon redeemed $43 million of the 6.00% senior notes due 2022, $175 million of the 5.875% senior notes due 2028, $315 million of the 4.50% senior notes due 2030, $210 million of the 5.25% senior notes due 2027 and $500 million of the 5.75% senior notes due 2026. In 2021, Devon recognized $30 million of gains on early retirement of debt, consisting of $89 million of non-cash premium accelerations, partially offset by $59 million of cash retirement costs. The gain on early retirement is included in financing costs, net in the consolidated statements of comprehensive earnings.
Credit Lines
Devon has a $3.0$3.0 billion Senior Credit Facility. As of December 31, 2022, 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, 2022. The facilitySenior Credit Facility matures as follows: $164 million on October 24, 2018 and5, 2024, with the remaining $2.8options to extend the maturity date by two additional one-year periods subject to lender consent. The maximum borrowing capacity of the Senior Credit Facility becomes $2.8 billion onafter October 24, 2019.5, 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 $7.4approximately $5 million. As of December 31, 2017, Devon had $59 million in outstanding letters of credit under the Senior Credit Facility. There were no borrowings under the Senior Credit Facility as of December 31, 2017.
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%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. Also,For example, total capitalization is adjusted to add back certain noncash financial write-downs, such as asset impairments. As of December 31, 2017,2022, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 27.2%23%. Devon’s change to successful efforts did not materially change this ratio.
Commercial Paper
Devon’s Senior Credit Facility supports its $3.0$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, 2017,2022, Devon had no outstanding commercial paper borrowings.
Retirement of Senior Notes
During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 3. Devon recognized a loss on early retirement of debt, primarily consisting of $265 million in cash retirement costs and other fees. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.
9280
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
EnLink has a $1.5 billion unsecured revolving credit facility that will mature on March 6, 2020. As of December 31, 2017, there were $10 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019. As of December 31, 2017, the General Partner had $74 million in outstanding borrowings under the $250 million credit facility at a weighted average borrowing rate of 3.2%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2017.
In the second quarter of 2017, EnLink issued $500 million of 5.45% unsecured senior notes due in 2047. The proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive statement of earnings.
In July 2016, EnLink issued $500 million of 4.85% unsecured senior notes due 2026. EnLink used the net proceeds to repay outstanding borrowings under its revolving credit facility and for general partnership purposes.
Net Financing Costs Net
The following schedule includes the components of net financing costs.
|
| Year Ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Interest based on debt outstanding |
| $ | 370 |
|
| $ | 388 |
|
| $ | 259 |
|
Gain on early retirement of debt |
|
| — |
|
|
| (30 | ) |
|
| — |
|
Interest income |
|
| (38 | ) |
|
| (2 | ) |
|
| (12 | ) |
Other |
|
| (23 | ) |
|
| (27 | ) |
|
| 23 |
|
Total net financing costs |
| $ | 309 |
|
| $ | 329 |
|
| $ | 270 |
|
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Devon net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
| $ | 390 |
|
| $ | 488 |
|
| $ | 450 |
|
Early retirement of debt |
|
| — |
|
|
| 269 |
|
|
| — |
|
Capitalized interest |
|
| (69 | ) |
|
| (61 | ) |
|
| (52 | ) |
Other |
|
| (4 | ) |
|
| 21 |
|
|
| 14 |
|
Total Devon net financing costs |
|
| 317 |
|
|
| 717 |
|
|
| 412 |
|
EnLink net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
|
| 167 |
|
|
| 144 |
|
|
| 115 |
|
Interest accretion on deferred installment payment |
|
| 26 |
|
|
| 52 |
|
|
| — |
|
Early retirement of debt |
|
| (9 | ) |
|
| — |
|
|
| — |
|
Other |
|
| (3 | ) |
|
| (6 | ) |
|
| (8 | ) |
Total EnLink net financing costs |
|
| 181 |
|
|
| 190 |
|
|
| 107 |
|
Total net financing costs |
| $ | 498 |
|
| $ | 907 |
|
| $ | 519 |
|
Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate. Certain of Devon’s lease agreements include variable payments based on usage or rental payments adjusted periodically for inflation. Devon’s lease agreements do not contain any material residual value guarantees or restrictive covenants.
The following table presents Devon’s right-of-use assets and lease liabilities.
|
| December 31, 2022 |
|
| December 31, 2021 |
| ||||||||||||||||||
|
| Finance |
|
| Operating |
|
| Total |
|
| Finance |
|
| Operating |
|
| Total |
| ||||||
Right-of-use assets |
| $ | 203 |
|
| $ | 21 |
|
| $ | 224 |
|
| $ | 211 |
|
| $ | 24 |
|
| $ | 235 |
|
Lease liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current lease liabilities (1) |
| $ | 8 |
|
| $ | 13 |
|
| $ | 21 |
|
| $ | 8 |
|
| $ | 18 |
|
| $ | 26 |
|
Long-term lease liabilities |
|
| 249 |
|
|
| 8 |
|
|
| 257 |
|
|
| 247 |
|
|
| 5 |
|
|
| 252 |
|
Total lease liabilities |
| $ | 257 |
|
| $ | 21 |
|
| $ | 278 |
|
| $ | 255 |
|
| $ | 23 |
|
| $ | 278 |
|
The following table presents Devon’s total lease cost.
|
|
| Year Ended December 31, |
| |||||||||
|
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Operating lease cost | Property and equipment; LOE; G&A |
| $ | 22 |
|
| $ | 25 |
|
| $ | 10 |
|
Short-term lease cost (1) | Property and equipment; LOE; G&A |
|
| 141 |
|
|
| 89 |
|
|
| 45 |
|
Financing lease cost: |
|
|
|
|
|
|
|
|
|
| |||
Amortization of right-of-use assets | DD&A |
|
| 8 |
|
|
| 8 |
|
|
| 8 |
|
Interest on lease liabilities | Net financing costs |
|
| 11 |
|
|
| 11 |
|
|
| 11 |
|
Variable lease cost | G&A |
|
| — |
|
|
| (4 | ) |
|
| — |
|
Lease income | G&A |
|
| (8 | ) |
|
| (8 | ) |
|
| (8 | ) |
Net lease cost |
|
| $ | 173 |
|
| $ | 121 |
|
| $ | 66 |
|
9381
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
The following table presents Devon’s additional lease information.
|
| Year Ended December 31, |
| |||||||||||||
|
| 2022 |
|
| 2021 |
| ||||||||||
|
| Finance |
|
| Operating |
|
| Finance |
|
| Operating |
| ||||
Cash outflows for lease liabilities: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating cash flows |
| $ | 8 |
|
| $ | 14 |
|
| $ | 7 |
|
| $ | 15 |
|
Investing cash flows |
| $ | — |
|
| $ | 9 |
|
| $ | — |
|
| $ | 9 |
|
Right-of-use assets obtained in exchange for new |
| $ | — |
|
| $ | 20 |
|
| $ | — |
|
| $ | 7 |
|
Weighted average remaining lease term (years) |
|
| 5.0 |
|
|
| 1.7 |
|
|
| 6.0 |
|
|
| 1.5 |
|
Weighted average discount rate |
|
| 4.2 | % |
|
| 2.8 | % |
|
| 4.2 | % |
|
| 1.3 | % |
The following table presents Devon’s maturity analysis as of December 31, 2022 for leases expiring in each of the next 5 years and thereafter.
|
| Finance |
|
| Operating |
|
| Total |
| |||
2023 |
| $ | 8 |
|
| $ | 13 |
|
| $ | 21 |
|
2024 |
|
| 8 |
|
|
| 7 |
|
|
| 15 |
|
2025 |
|
| 8 |
|
|
| 1 |
|
|
| 9 |
|
2026 |
|
| 8 |
|
|
| — |
|
|
| 8 |
|
2027 |
|
| 8 |
|
|
| — |
|
|
| 8 |
|
Thereafter |
|
| 272 |
|
|
| — |
|
|
| 272 |
|
Total lease payments |
|
| 312 |
|
|
| 21 |
|
|
| 333 |
|
Less: interest |
|
| (55 | ) |
|
| — |
|
|
| (55 | ) |
Present value of lease liabilities |
| $ | 257 |
|
| $ | 21 |
|
| $ | 278 |
|
Devon rents or subleases certain real estate to third parties. The following table presents Devon’s expected lease income as of December 31, 2022 for each of the next 5 years and thereafter.
|
| Operating |
| |
|
| Lease Income |
| |
2023 |
| $ | 10 |
|
2024 |
|
| 10 |
|
2025 |
|
| 13 |
|
2026 |
|
| 13 |
|
2027 |
|
| 13 |
|
Thereafter |
|
| 72 |
|
Total |
| $ | 131 |
|
82
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the changes in asset retirement obligations.
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2022 |
|
| 2021 |
| ||||
Asset retirement obligations as of beginning of period |
| $ | 1,272 |
|
| $ | 1,414 |
|
| $ | 485 |
|
| $ | 369 |
|
Liabilities incurred and assumed through acquisitions |
|
| 40 |
|
|
| 27 |
|
|
| 73 |
|
|
| 134 |
|
Liabilities settled and divested |
|
| (68 | ) |
|
| (324 | ) |
|
| (19 | ) |
|
| (57 | ) |
Revision of estimated obligation |
|
| (184 | ) |
|
| 66 |
|
|
| (35 | ) |
|
| 11 |
|
Accretion expense on discounted obligation |
|
| 62 |
|
|
| 75 |
|
|
| 25 |
|
|
| 28 |
|
Foreign currency translation adjustment |
|
| 30 |
|
|
| 14 |
| ||||||||
Asset retirement obligations as of end of period |
|
| 1,152 |
|
|
| 1,272 |
|
|
| 529 |
|
|
| 485 |
|
Less current portion |
|
| 39 |
|
|
| 46 |
|
|
| 18 |
|
|
| 17 |
|
Asset retirement obligations, long-term |
| $ | 1,113 |
|
| $ | 1,226 |
|
| $ | 511 |
|
| $ | 468 |
|
During 2017,2022, Devon increased its asset retirement obligations by approximately $38 million due to asset acquisitions in the Eagle Ford and Williston Basin. During this same time period, Devon reduced its asset retirement obligations by $184$35 million primarily due to changes in the assumed inflation rate andextended retirement dates for its oil and gas assets.
assets, partially offset by inflation-driven increases to current settlement costs. During 2016,2021, Devon reduced itsassumed $98 million of WPX asset retirement obligation by $287 million for those obligations that were assumed by purchasers of certain upstream U.S. assets.obligations.
|
Defined Contribution Plans
Devon sponsors defined contribution plans covering its employees in the U.S. and Canada.employees. Such plans include its 401(k) plan and enhanced contribution planplan. Devon makes matching contributions and Canadian pension and savings plan. Contributions areadditional retirement contributions, with the matching contributions being primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respectivethe U.S. government. Devon contributed $60$37 million, $64$33 million and $79$33 million to these plans in 2017, 20162022, 2021 and 2015,2020, respectively.
Defined Benefit Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans covering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits under the defined benefit plans have been closed to new employees since 2007; however, eligible employees continue to accrueand effective, as of December 31, 2020, Devon’s benefits based upon yearscommittee approved a freeze of service and compensation. all future benefit accruals under the plans.
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 70%90% fixed income 20% equity and 10% other.10% equity. See the following discussion for Devon’s pension assets by asset class.
94
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 aredo
83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
not consistently trade actively traded securities that can be redeemed upon demand.in an established market. The fair values of these Level 12 securities are estimated based upon quoted market pricesrates available for securities with similar terms and maturity when active trading is not available and were $342$384 million and $311$590 million at December 31, 20172022 and 2016,2021, respectively. Also, included are
Equity – Devon’s equity securities include commingled global equity funds that primarily invest in long-term bondslarge, mid and U.S. Treasurysmall capitalization stocks across the world’s developed and emerging markets and international large cap equity securities. These fixed incomeequity securities can be redeemedsold 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 $401$49 million and $367$67 million at December 31, 20172022 and 2016,2021, respectively.
Equity – Devon’s equity securities include a commingled global equity fund that invests in large, mid- and small capitalization stocks across the world’s developed and emerging markets. These equity 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 $157 million and $171 million at December 31, 2017 and 2016, respectively.
Other – Devon’s other securities include short-term investmentsinvestment funds an actively traded global mutual fund focusing on alternative investment strategies and a hedge fund that investsinvest 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 $135$25 million and $136$14 million at December 31, 20172022 and 2016,2021, respectively.
Defined Postretirement Plans
Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. The plans provide medical and in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. 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.
95
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Benefit Obligations and Funded Status
The following table summarizes the benefit obligations, assets, funded status and balance sheet impacts associated with itsDevon’s defined pension and postretirement plans. Devon’s benefit obligations and plan assets are
84
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 20172022 and 2016.2021.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||
|
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Benefit obligation at beginning of year |
| $ | 880 |
|
| $ | 981 |
|
| $ | 12 |
|
| $ | 13 |
|
Service cost |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Interest cost |
|
| 19 |
|
|
| 18 |
|
|
| — |
|
|
| — |
|
Actuarial gain |
|
| (215 | ) |
|
| (18 | ) |
|
| (4 | ) |
|
| (1 | ) |
Plan amendments |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Plan curtailments |
|
| — |
|
|
| 22 |
|
|
| — |
|
|
| — |
|
Plan settlements |
|
| — |
|
|
| (73 | ) |
|
| — |
|
|
| — |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 2 |
|
Benefits paid |
|
| (55 | ) |
|
| (50 | ) |
|
| (2 | ) |
|
| (3 | ) |
Benefit obligation at end of year |
|
| 629 |
|
|
| 880 |
|
|
| 7 |
|
|
| 12 |
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Fair value of plan assets at beginning of year |
|
| 671 |
|
|
| 745 |
|
|
| — |
|
|
| — |
|
Actual return on plan assets |
|
| (172 | ) |
|
| (11 | ) |
|
| — |
|
|
| — |
|
Employer contributions |
|
| 14 |
|
|
| 60 |
|
|
| 1 |
|
|
| 1 |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 2 |
|
Plan settlements |
|
| — |
|
|
| (73 | ) |
|
| — |
|
|
| — |
|
Benefits paid |
|
| (55 | ) |
|
| (50 | ) |
|
| (2 | ) |
|
| (3 | ) |
Fair value of plan assets at end of year |
|
| 458 |
|
|
| 671 |
|
|
| — |
|
|
| — |
|
Funded status at end of year |
| $ | (171 | ) |
| $ | (209 | ) |
| $ | (7 | ) |
| $ | (12 | ) |
Amounts recognized in balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Other long-term assets |
| $ | — |
|
| $ | 6 |
|
| $ | — |
|
| $ | — |
|
Other current liabilities |
|
| (14 | ) |
|
| (14 | ) |
|
| (1 | ) |
|
| (2 | ) |
Other long-term liabilities |
|
| (157 | ) |
|
| (201 | ) |
|
| (6 | ) |
|
| (9 | ) |
Net amount |
| $ | (171 | ) |
| $ | (209 | ) |
| $ | (7 | ) |
| $ | (11 | ) |
Amounts recognized in accumulated other |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net actuarial loss (gain) |
| $ | 189 |
|
| $ | 206 |
|
| $ | (15 | ) |
| $ | (12 | ) |
Prior service cost |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 1 |
|
Total |
| $ | 189 |
|
| $ | 206 |
|
| $ | (14 | ) |
| $ | (11 | ) |
During 2021, non-qualified plans experienced curtailments due to the Merger and both qualified and non-qualified plans experienced a partial plan settlement due to continued lump sum payments.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| $ | 1,249 |
|
| $ | 1,308 |
|
| $ | 21 |
|
| $ | 23 |
|
Service cost |
|
| 15 |
|
|
| 15 |
|
|
| — |
|
|
| — |
|
Interest cost |
|
| 42 |
|
|
| 42 |
|
|
| — |
|
|
| 1 |
|
Actuarial loss (gain) |
|
| 59 |
|
|
| 63 |
|
|
| — |
|
|
| (1 | ) |
Plan amendments |
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
Plan curtailments |
|
| — |
|
|
| (31 | ) |
|
| — |
|
|
| — |
|
Plan settlements |
|
| — |
|
|
| (94 | ) |
|
| — |
|
|
| — |
|
Foreign exchange rate changes |
|
| 2 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
Benefits paid |
|
| (88 | ) |
|
| (57 | ) |
|
| (3 | ) |
|
| (2 | ) |
Benefit obligation at end of year |
|
| 1,279 |
|
|
| 1,249 |
|
|
| 19 |
|
|
| 21 |
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
| 985 |
|
|
| 1,059 |
|
|
| — |
|
|
| — |
|
Actual return on plan assets |
|
| 122 |
|
|
| 61 |
|
|
| — |
|
|
| — |
|
Employer contributions |
|
| 14 |
|
|
| 16 |
|
|
| 2 |
|
|
| 2 |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
Plan settlements |
|
| — |
|
|
| (94 | ) |
|
| — |
|
|
| — |
|
Benefits paid |
|
| (88 | ) |
|
| (57 | ) |
|
| (3 | ) |
|
| (2 | ) |
Foreign exchange rate changes |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Fair value of plan assets at end of year |
|
| 1,035 |
|
|
| 985 |
|
|
| — |
|
|
| — |
|
Funded status at end of year |
| $ | (244 | ) |
| $ | (264 | ) |
| $ | (19 | ) |
| $ | (21 | ) |
Amounts recognized in balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term assets |
| $ | 4 |
|
| $ | 3 |
|
| $ | — |
|
| $ | — |
|
Other current liabilities |
|
| (13 | ) |
|
| (13 | ) |
|
| (3 | ) |
|
| (3 | ) |
Other long-term liabilities |
|
| (235 | ) |
|
| (254 | ) |
|
| (16 | ) |
|
| (18 | ) |
Net amount |
| $ | (244 | ) |
| $ | (264 | ) |
| $ | (19 | ) |
| $ | (21 | ) |
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain) |
| $ | 257 |
|
| $ | 285 |
|
| $ | (11 | ) |
| $ | (11 | ) |
Prior service cost (credit) |
|
| 6 |
|
|
| 8 |
|
|
| (3 | ) |
|
| (5 | ) |
Total |
| $ | 263 |
|
| $ | 293 |
|
| $ | (14 | ) |
| $ | (16 | ) |
Certain of Devon’s pension plans are unfunded and have a combined projected benefit obligation andor accumulated benefit obligation in excess of $239 million and $225 million, respectively,plan assets at December 31, 20172022, and $234 million and $211 million, respectively, at December 31, 2016.2021, as presented in the table below.
|
| December 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Projected and accumulated benefit obligation |
| $ | 629 |
|
| $ | 215 |
|
Fair value of plan assets |
| $ | 458 |
|
| $ | — |
|
9685
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Service cost |
| $ | — |
|
| $ | — |
|
| $ | 5 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Interest cost |
|
| 19 |
|
|
| 18 |
|
|
| 25 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Expected return on plan assets |
|
| (31 | ) |
|
| (34 | ) |
|
| (41 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial loss (gain) (1) |
|
| 6 |
|
|
| 4 |
|
|
| 5 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| — |
|
Recognition of prior service cost (1) |
|
| — |
|
|
| — |
|
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| (1 | ) |
Total net periodic benefit cost (2) |
|
| (6 | ) |
|
| (12 | ) |
|
| (3 | ) |
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Actuarial loss (gain) arising in current year |
|
| (11 | ) |
|
| 28 |
|
|
| 27 |
|
|
| (4 | ) |
|
| (1 | ) |
|
| (1 | ) |
Prior service cost arising in current year |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
Recognition of net actuarial gain (loss), including |
|
| (6 | ) |
|
| (23 | ) |
|
| (9 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Recognition of prior service cost, including |
|
| — |
|
|
| — |
|
|
| (7 | ) |
|
| — |
|
|
| — |
|
|
| 1 |
|
Total other comprehensive loss (earnings) |
|
| (17 | ) |
|
| 5 |
|
|
| 13 |
|
|
| (3 | ) |
|
| 1 |
|
|
| 1 |
|
Total |
| $ | (23 | ) |
| $ | (7 | ) |
| $ | 10 |
|
| $ | (4 | ) |
| $ | — |
|
| $ | — |
|
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 15 |
|
| $ | 15 |
|
| $ | 33 |
|
| $ | — |
|
| $ | — |
|
| $ | 1 |
|
Interest cost |
|
| 42 |
|
|
| 42 |
|
|
| 52 |
|
|
| — |
|
|
| 1 |
|
|
| 1 |
|
Expected return on plan assets |
|
| (54 | ) |
|
| (55 | ) |
|
| (58 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial loss (gain) (1) |
|
| 19 |
|
|
| 25 |
|
|
| 20 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Recognition of prior service cost (1) |
|
| 2 |
|
|
| 3 |
|
|
| 4 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (2 | ) |
Total net periodic benefit cost (2) |
|
| 24 |
|
|
| 30 |
|
|
| 51 |
|
|
| (2 | ) |
|
| (1 | ) |
|
| (1 | ) |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss (gain) arising in current year |
|
| (9 | ) |
|
| 26 |
|
|
| 5 |
|
|
| (1 | ) |
|
| — |
|
|
| (1 | ) |
Prior service cost (credit) arising in current year |
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost (3) |
|
| (19 | ) |
|
| (43 | ) |
|
| (20 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) |
|
| (2 | ) |
|
| (9 | ) |
|
| (4 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Total other comprehensive loss (earnings) |
|
| (30 | ) |
|
| (24 | ) |
|
| (19 | ) |
|
| 1 |
|
|
| 2 |
|
|
| 2 |
|
Total recognized |
| $ | (6 | ) |
| $ | 6 |
|
| $ | 32 |
|
| $ | (1 | ) |
| $ | 1 |
|
| $ | 1 |
|
| These net periodic benefit costs were reclassified out of |
|
|
|
|
The estimated net actuarial loss and prior service cost for our pension and postretirement benefits that will be amortized from accumulated other comprehensive earnings intoin the current period.
Assumptions
|
| Pension Benefits |
|
| Postretirement Benefits |
|
| Pension Benefits |
| Postretirement Benefits | ||||||||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2022 |
| 2021 |
| 2020 |
| 2022 |
| 2021 |
| 2020 | ||||||
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Discount rate |
| 3.59% |
|
|
| 4.07% |
|
|
| 4.25% |
|
| 3.25% |
|
|
| 3.46% |
|
|
| 3.63% |
|
| 5.78% |
| 2.71% |
| 2.38% |
| 5.71% |
| 2.34% |
| 1.82% | ||
Rate of compensation increase |
| 2.50% |
|
|
| 4.49% |
|
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
|
| N/A |
| N/A |
| 2.50% |
| N/A |
| N/A |
| N/A | ||||
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Discount rate |
| 4.08% |
|
|
| 4.39% |
|
|
| 3.90% |
|
| 3.46% |
|
|
| 3.63% |
|
| 3.25% |
| |||||||||||||||
Discount rate - service cost |
| N/A |
| N/A |
| 3.47% |
| 2.83% |
| 2.51% |
| 3.25% | ||||||||||||||||||||||||
Discount rate - interest cost |
| 2.18% |
| 2.11% |
| 2.75% |
| 1.57% |
| 1.01% |
| 2.31% | ||||||||||||||||||||||||
Rate of compensation increase |
| 4.48% |
|
|
| 4.49% |
|
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
|
| N/A |
| N/A |
| 2.50% |
| N/A |
| N/A |
| N/A | ||||
Expected return on plan assets |
| 5.69% |
|
|
| 5.20% |
| �� |
| 5.22% |
|
| N/A |
|
| N/A |
|
| N/A |
|
| 4.80% |
| 5.00% |
| 6.00% |
| N/A |
| N/A |
| N/A | ||||
86
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Discount Rate -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.
97
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 and an improvement scale derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in Devon’s plans.tables.
Other assumptions – For measurement of the 20172022 benefit obligation for the other postretirement medical plans, a 7.3%6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018.2023. The rate was assumed to decrease annually to an ultimate rate of 5%5% in the year 2029 and remain at that level thereafter. A one percentage point change in assumed health care cost trend rates would not have a material impact on periodic benefit cost or benefit obligations.
Expected Cash Flows
Devon expects benefit plan payments to average approximately $76$53 million a year for the next five years and $406$249 million total for the five years thereafter. Of these payments to be paid in 2018, $32023, $15 million is expected to be funded from Devon’s available cash, cash equivalents and cash equivalents.other assets.
|
The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10$0.10 per share, and 4.5 million shares of preferred stock, par value $1.00$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.
Common Stock IssuedShare Repurchase Program
In January 2016,December 2019, Devon issued approximately 23 million sharesannounced a share repurchase program of $1.0 billion with a December 31, 2020 expiration date. In November 2021, Devon announced a new share repurchase program of $1.0 billion with a December 31, 2022 expiration date. In February 2022, the Board of Directors authorized an expansion of the share repurchase program to $1.6 billion, and in May 2022, authorized a further expansion to $2.0 billion and extended the expiration date to May 4, 2023.
The table below provides information regarding purchases of Devon’s common stock that were made under the respective share repurchase programs (shares in conjunction with the STACK asset acquisition discussed in Note 3thousands). Additionally, in February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.
In December 2015, Devon issued approximately 7 million shares of common stock as part of the Powder River Basin asset acquisition discussed in Note 3.
|
| Total Number of |
|
| Dollar Value of |
|
| Average Price Paid |
| |||
$1.0 Billion Plan (Closed) |
|
|
|
|
|
|
|
|
| |||
2020 |
|
| 2,243 |
|
| $ | 38 |
|
| $ | 16.85 |
|
Total |
|
| 2,243 |
|
| $ | 38 |
|
| $ | 16.85 |
|
|
|
|
|
|
|
|
|
|
| |||
$2.0 Billion Plan |
|
|
|
|
|
|
|
|
| |||
2021 |
|
| 13,983 |
|
| $ | 589 |
|
| $ | 42.15 |
|
2022 |
|
| 11,708 |
|
|
| 718 |
|
|
| 61.36 |
|
Total plan |
|
| 25,691 |
|
| $ | 1,307 |
|
| $ | 50.90 |
|
Dividends
Devon paid common stock dividends of $127 million, $221 million and $396 million during 2017, 2016 and 2015, respectively. In response to the depressed commodity price environment, Devon reduced the quarterly dividend rate from $0.24 to $0.06 per share in the second quarter of 2016.
Subsidiary Equity Transactions
EnLink has the ability to sell common units through its “at the market” equity offering programs. In the third quarter of 2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common
9887
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
units throughDividends
Devon is committed to paying a quarterly dividend at a fixed rate and a variable quarterly dividend, which is dependent on quarterly cash flows, among other factors. The following table summarizes the dividends Devon has paid on its programs. Future common units that EnLink issues will be issued understock in 2022, 2021 and 2020, respectively.
| Fixed |
|
| Variable |
|
| Total |
|
| Rate Per Share |
| ||||
2022: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 109 |
|
| $ | 558 |
|
| $ | 667 |
|
| $ | 1.00 |
|
Second quarter |
| 105 |
|
|
| 725 |
|
|
| 830 |
|
| $ | 1.27 |
|
Third quarter |
| 117 |
|
|
| 890 |
|
|
| 1,007 |
|
| $ | 1.55 |
|
Fourth quarter |
| 117 |
|
|
| 758 |
|
|
| 875 |
|
| $ | 1.35 |
|
Total year-to-date | $ | 448 |
|
| $ | 2,931 |
|
| $ | 3,379 |
|
|
|
| |
2021: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 76 |
|
| $ | 127 |
|
| $ | 203 |
|
| $ | 0.30 |
|
Second quarter |
| 75 |
|
|
| 154 |
|
|
| 229 |
|
| $ | 0.34 |
|
Third quarter |
| 74 |
|
|
| 255 |
|
|
| 329 |
|
| $ | 0.49 |
|
Fourth quarter |
| 73 |
|
|
| 481 |
|
|
| 554 |
|
| $ | 0.84 |
|
Total year-to-date | $ | 298 |
|
| $ | 1,017 |
|
| $ | 1,315 |
|
|
|
| |
2020: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 34 |
|
| $ | — |
|
| $ | 34 |
|
| $ | 0.09 |
|
Second quarter |
| 42 |
|
|
| — |
|
|
| 42 |
|
| $ | 0.11 |
|
Third quarter |
| 43 |
|
|
| — |
|
|
| 43 |
|
| $ | 0.11 |
|
Fourth quarter |
| 41 |
|
|
| 97 |
|
|
| 138 |
|
| $ | 0.37 |
|
Total year-to-date | $ | 160 |
|
| $ | 97 |
|
| $ | 257 |
|
|
|
| |
In February 2023, Devon raised its fixed quarterly dividend by 11%, to $0.20 per share and announced a cash dividend in the new equity distribution agreement. During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3 million common units through its “at the market” program and general public offerings, generating net proceedsamount of $107 million, $167 million and $25 million, respectively. During$0.89 per share payable in the first quarter of 2016,2023. The dividend consists of a fixed quarterly dividend in the General Partner issued common unitsamount of approximately $130 million (or $0.20 per share) and a variable quarterly dividend in the amount of approximately $449 million (or $0.69 per share).
Devon raised its fixed quarterly dividend by 45%, to $0.16 per share, beginning in the first quarter of 2022, and again by 13%, to $0.18 per share, beginning in the third quarter of 2022. Devon also increased its fixed quarterly dividend rate in the second quarter of 2020 from $0.09 to $0.11.
In the fourth quarter of 2020, Devon paid a $97 million (or $0.26 per share) special dividend.
Noncontrolling Interests
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.
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 classified the results of operations and cash flows related to its Barnett Shale assets as discontinued operations on its consolidated financial statements.
88
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In conjunction with the Anadarko Basinamended divestiture agreement in April 2020, Devon recognized a $182 million asset impairment related to the Barnett Shale assets acquisition discussed in Note 3.2020, 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.
In
On October 2015, EnLink issued approximately 2.81, 2020, Devon completed the sale of its Barnett Shale assets to BKV for proceeds, net of purchase price adjustments, of $490 million. Additionally, the agreement provides for contingent earnout payments to Devon of up to $260 million common units inbased upon future commodity prices, with upside participation beginning at a private placement transaction with the General Partner, generating approximately $50$2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commenced on January 1, 2021 and has a term of four years. Devon received $65 million in proceeds. In 2015, Devon conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising net proceeds of $654 million.
In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds of approximately $394 million. As a result of these transactions and EnLink’s acquisition and dropdown activity discussed further in Note 3, the table below shows the ownership interest activitycontingent earnout payments related to this transaction in the General Partnerfirst quarters of 2023 and EnLink2022 and could receive up to an additional $130 million in contingent earnout payments for the last three years.
|
| EnLink |
|
| General Partner |
| ||||||||||||||
Ownership interest as of |
| Devon |
|
| Non-Devon Unitholders |
|
| General Partner |
|
| Devon |
|
| Non-Devon Unitholders |
| |||||
December 31, 2015 |
|
| 28% |
|
|
| 45% |
|
|
| 27% |
|
|
| 70% |
|
|
| 30% |
|
December 31, 2016 |
|
| 24% |
|
|
| 53% |
|
|
| 23% |
|
|
| 64% |
|
|
| 36% |
|
December 31, 2017 |
|
| 23% |
|
|
| 55% |
|
|
| 22% |
|
|
| 64% |
|
|
| 36% |
|
Distributions to Noncontrolling Interests
EnLinkremaining performance periods depending on future commodity prices. The valuation of the future contingent earnout payments included within other current assets and other long-term assets in the General Partner distributed $354 million, $304December 31, 2022 balance sheet was $65 million and $254$88 million, respectively. During 2022 and 2021, Devon recorded a $42 million and a $110 million increase, respectively, to non-Devon unitholders during 2017, 2016the fair value within asset dispositions on the consolidated statements of comprehensive earnings related to these payments. These values were derived utilizing a Monte Carlo valuation model and 2015, respectively.qualify as a level 3 fair value measurement.
The following table presents the amounts reported in the consolidated statements of comprehensive earnings as discontinued operations.
Year ended December 31, 2020 |
| Total |
| |
|
|
|
| |
Oil, gas and NGL sales |
| $ | 263 |
|
Total revenues |
|
| 263 |
|
Production expenses |
|
| 214 |
|
Asset impairments |
|
| 182 |
|
Asset dispositions |
|
| 1 |
|
General and administrative expenses |
|
| 3 |
|
Financing costs, net |
|
| (3 | ) |
Restructuring and transaction costs |
|
| 9 |
|
Other expenses |
|
| 9 |
|
Total expenses |
|
| 415 |
|
Loss from discontinued operations before income taxes |
|
| (152 | ) |
Income tax benefit |
|
| (24 | ) |
Loss from discontinued operations, net of tax |
| $ | (128 | ) |
|
Devon is party to various legal actions arising in the normal course ofconnection 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. TheseDevon 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
89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
allegations typically asserted in these suits typically assert various allegations, includingare claims that the producers and related partiesDevon used below-market prices, made improper deductions, paid royalty proceeds in an untimely manner without including required interest, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in the 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.
Environmental and Climate Change Matters
Devon’s business is subject to numerous federal, state, tribal and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, as well as remediation costs. Although Devon does not currently believebelieves that it is subjectin substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, there can be no assurance that this will continue in the future.
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 material exposureland 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 denies the allegations in these lawsuits and intends to vigorously defend against these claims.
The State of Delaware and various municipalities and other governmental and private parties in California 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 injunctive relief. Although Devon cannot predict the ultimate outcome of these matters, Devon denies the allegations asserted in these lawsuits and intends to vigorously defend against these claims.
Other Indemnifications and Legacy Matters
Pursuant to various sale agreements relating to divested businesses and assets, Devon has indemnified various purchasers against liabilities that they may incur with respect to such royalty matters.the businesses and assets acquired from Devon. Additionally, federal, state and other laws in areas of former operations may require previous operators (including corporate successors of previous operators) to perform or make payments in certain circumstances where the current operator may no longer be able to satisfy the applicable obligation. Such obligations may include plugging and abandoning wells, removing production facilities or performing requirements under surface agreements in existence at the time of disposition.
99
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 and related facilities. 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.
90
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Environmental MattersCommitments
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.
Other Matters
Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no material pending legal proceedings to which Devon is a party or to which any of its property is subject.
Commitments
The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2017.2022.
Year Ending December 31, |
| Purchase Obligations |
|
| Drilling and Facility Obligations |
|
| Operational Agreements |
|
| Office and Equipment Leases |
|
| EnLink Obligations |
| |||||
2018 |
| $ | 613 |
|
| $ | 216 |
|
| $ | 1,159 |
|
| $ | 88 |
|
| $ | 53 |
|
2019 |
|
| 577 |
|
|
| 109 |
|
|
| 562 |
|
|
| 84 |
|
|
| 36 |
|
2020 |
|
| 556 |
|
|
| 109 |
|
|
| 466 |
|
|
| 73 |
|
|
| 19 |
|
2021 |
|
| 134 |
|
|
| 51 |
|
|
| 366 |
|
|
| 61 |
|
|
| 18 |
|
2022 |
|
| — |
|
|
| 38 |
|
|
| 373 |
|
|
| 56 |
|
|
| 17 |
|
Thereafter |
|
| — |
|
|
| 106 |
|
|
| 3,242 |
|
|
| 19 |
|
|
| 90 |
|
Total |
| $ | 1,880 |
|
| $ | 629 |
|
| $ | 6,168 |
|
| $ | 381 |
|
| $ | 233 |
|
Year Ending December 31, |
| Drilling and Facility Obligations |
|
| Operational Agreements |
|
| Office and Equipment Leases and Other |
| |||
2023 |
| $ | 273 |
|
| $ | 470 |
|
| $ | 118 |
|
2024 |
|
| 42 |
|
|
| 491 |
|
|
| 62 |
|
2025 |
|
| 21 |
|
|
| 464 |
|
|
| 47 |
|
2026 |
|
| 12 |
|
|
| 423 |
|
|
| 23 |
|
2027 |
|
| 19 |
|
|
| 294 |
|
|
| 24 |
|
Thereafter |
|
| 15 |
|
|
| 1,072 |
|
|
| 341 |
|
Total |
| $ | 382 |
|
| $ | 3,214 |
|
| $ | 615 |
|
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.
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. Total rental expense recognized for operating leases, net of sublease income, was $67 million, $78 million and $88 million in 2017, 2016 and 2015, respectively.
100
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, restricted cash, accounts receivable, other current receivables, accounts payable, other current payables, and accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at December 31, 20172022 and December 31, 2016,2021, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items and the pension plan assets is provided in Note 6, Note 14 and Note 18, respectively.
|
|
|
|
|
|
|
|
|
| Fair Value |
| |||||
|
|
|
|
|
|
|
|
|
| Measurements Using: |
| |||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
| ||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
| ||||
December 31, 2017 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 1,533 |
|
| $ | 1,533 |
|
| $ | 1,454 |
|
| $ | 79 |
|
Commodity derivatives |
| $ | 211 |
|
| $ | 211 |
|
| $ | — |
|
| $ | 211 |
|
Commodity derivatives |
| $ | (294 | ) |
| $ | (294 | ) |
| $ | — |
|
| $ | (294 | ) |
Interest rate derivatives |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
Interest rate derivatives |
| $ | (64 | ) |
| $ | (64 | ) |
| $ | — |
|
| $ | (64 | ) |
Debt |
| $ | (10,406 | ) |
| $ | (11,782 | ) |
| $ | — |
|
| $ | (11,782 | ) |
Installment payment |
| $ | (250 | ) |
| $ | (250 | ) |
| $ | — |
|
| $ | (250 | ) |
Capital lease obligations |
| $ | (4 | ) |
| $ | (3 | ) |
| $ | — |
|
| $ | (3 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 1,542 |
|
| $ | 1,542 |
|
| $ | 1,298 |
|
| $ | 244 |
|
Commodity derivatives |
| $ | 10 |
|
| $ | 10 |
|
| $ | — |
|
| $ | 10 |
|
Commodity derivatives |
| $ | (203 | ) |
| $ | (203 | ) |
| $ | — |
|
| $ | (203 | ) |
Interest rate derivatives |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
Interest rate derivatives |
| $ | (41 | ) |
| $ | (41 | ) |
| $ | — |
|
| $ | (41 | ) |
Debt |
| $ | (10,154 | ) |
| $ | (10,760 | ) |
| $ | — |
|
| $ | (10,760 | ) |
Installment payment |
| $ | (473 | ) |
| $ | (477 | ) |
| $ | — |
|
| $ | (477 | ) |
Capital lease obligations |
| $ | (7 | ) |
| $ | (6 | ) |
| $ | — |
|
| $ | (6 | ) |
|
|
|
|
|
|
|
| Fair Value Measurements Using: |
| |||||||||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
| |||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
|
| Inputs |
| |||||
December 31, 2022 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash equivalents |
| $ | 708 |
|
| $ | 708 |
|
| $ | 708 |
|
| $ | — |
|
| $ | — |
|
Commodity derivatives |
| $ | 131 |
|
| $ | 131 |
|
| $ | — |
|
| $ | 131 |
|
| $ | — |
|
Commodity derivatives |
| $ | (3 | ) |
| $ | (3 | ) |
| $ | — |
|
| $ | (3 | ) |
| $ | — |
|
Debt |
| $ | (6,440 | ) |
| $ | (6,231 | ) |
| $ | — |
|
| $ | (6,231 | ) |
| $ | — |
|
Contingent earnout payments |
| $ | 157 |
|
| $ | 157 |
|
| $ | — |
|
| $ | — |
|
| $ | 157 |
|
December 31, 2021 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash equivalents |
| $ | 1,421 |
|
| $ | 1,421 |
|
| $ | 1,421 |
|
| $ | — |
|
| $ | — |
|
Commodity derivatives |
| $ | 8 |
|
| $ | 8 |
|
| $ | — |
|
| $ | 8 |
|
| $ | — |
|
Commodity derivatives |
| $ | (577 | ) |
| $ | (577 | ) |
| $ | — |
|
| $ | (577 | ) |
| $ | — |
|
Debt |
| $ | (6,482 | ) |
| $ | (7,644 | ) |
| $ | — |
|
| $ | (7,644 | ) |
| $ | — |
|
Contingent earnout payments |
| $ | 184 |
|
| $ | 184 |
|
| $ | — |
|
| $ | — |
|
| $ | 184 |
|
The following methods and assumptions were used to estimate the fair values in the tablestable above.
Level 1 Fair Value Measurements
Cash equivalents – Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents – Amounts consist primarily of commercial paper and Canadian agency and provincial securities investments. The fair value approximates the carrying value.
10191
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 and interest ratederivatives– The fair valuesvalue of commodity and interest rate derivatives areis 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 trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. The fair values of commercial papermaturity when active trading is not available.
Level 3 Fair Value Measurements
Contingent Earnout Payments – Devon has the right to receive contingent consideration related to the Barnett and credit facility balances are the carrying values.
Installment payment – The fair value of the EnLink installment payment wasnon-core Rockies asset divestiture based on Level 2 inputs from third-party market quotations.
Capital lease obligations – The fair value was calculated using inputs from third-party banks.
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian exploration and production operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged infuture oil and gas explorationprices. These values were derived using a Monte Carlo valuation model and production activities, and certain information regarding such activities for each segment is included in Note 24.
Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presentedqualify as a separate reporting segment.level 3 fair value measurement. For additional information, see Note 2.
102
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| U.S. (1) |
|
| Canada |
|
| EnLink (1) |
|
| Eliminations |
|
| Total |
| |||||
Year Ended December 31, 2017: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 7,326 |
|
| $ | 1,552 |
|
| $ | 5,071 |
|
| $ | — |
|
| $ | 13,949 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 669 |
|
| $ | (669 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 1,149 |
|
| $ | 380 |
|
| $ | 545 |
|
| $ | — |
|
| $ | 2,074 |
|
Asset impairments |
| $ | — |
|
| $ | — |
|
| $ | 17 |
|
| $ | — |
|
| $ | 17 |
|
Asset dispositions |
| $ | (218 | ) |
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | (217 | ) |
Interest expense |
| $ | 324 |
|
| $ | 69 |
|
| $ | 181 |
|
| $ | (57 | ) |
| $ | 517 |
|
Earnings before income taxes |
| $ | 500 |
|
| $ | 273 |
|
| $ | 123 |
|
| $ | — |
|
| $ | 896 |
|
Income tax expense (benefit) |
| $ | 9 |
|
| $ | 6 |
|
| $ | (197 | ) |
| $ | — |
|
| $ | (182 | ) |
Net earnings |
| $ | 491 |
|
| $ | 267 |
|
| $ | 320 |
|
| $ | — |
|
| $ | 1,078 |
|
Net earnings attributable to noncontrolling interests |
| $ | — |
|
| $ | — |
|
| $ | 180 |
|
| $ | — |
|
| $ | 180 |
|
Net earnings attributable to Devon |
| $ | 491 |
|
| $ | 267 |
|
| $ | 140 |
|
| $ | — |
|
| $ | 898 |
|
Property and equipment, net |
| $ | 10,274 |
|
| $ | 4,310 |
|
| $ | 6,587 |
|
| $ | — |
|
| $ | 21,171 |
|
Total assets |
| $ | 14,254 |
|
| $ | 5,498 |
|
| $ | 10,538 |
|
| $ | (49 | ) |
| $ | 30,241 |
|
Capital expenditures, including acquisitions |
| $ | 1,821 |
|
| $ | 348 |
|
| $ | 768 |
|
| $ | — |
|
| $ | 2,937 |
|
Year Ended December 31, 2016: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 5,722 |
|
| $ | 1,031 |
|
| $ | 3,551 |
|
| $ | — |
|
| $ | 10,304 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 701 |
|
| $ | (701 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 1,178 |
|
| $ | 414 |
|
| $ | 504 |
|
| $ | — |
|
| $ | 2,096 |
|
Asset impairments |
| $ | 435 |
|
| $ | 2 |
|
| $ | 873 |
|
| $ | — |
|
| $ | 1,310 |
|
Asset dispositions |
| $ | (955 | ) |
| $ | (541 | ) |
| $ | 13 |
|
| $ | — |
|
| $ | (1,483 | ) |
Restructuring and transaction costs |
| $ | 242 |
|
| $ | 19 |
|
| $ | 6 |
|
| $ | — |
|
| $ | 267 |
|
Interest expense |
| $ | 624 |
|
| $ | 184 |
|
| $ | 190 |
|
| $ | (84 | ) |
| $ | 914 |
|
Earnings (loss) before income taxes |
| $ | (673 | ) |
| $ | 240 |
|
| $ | (884 | ) |
| $ | — |
|
| $ | (1,317 | ) |
Income tax expense (benefit) |
| $ | (8 | ) |
| $ | 149 |
|
| $ | — |
|
| $ | — |
|
| $ | 141 |
|
Net earnings (loss) |
| $ | (665 | ) |
| $ | 91 |
|
| $ | (884 | ) |
| $ | — |
|
| $ | (1,458 | ) |
Net earnings (loss) attributable to noncontrolling interests |
| $ | 1 |
|
| $ | — |
|
| $ | (403 | ) |
| $ | — |
|
| $ | (402 | ) |
Net earnings (loss) attributable to Devon |
| $ | (666 | ) |
| $ | 91 |
|
| $ | (481 | ) |
| $ | — |
|
| $ | (1,056 | ) |
Property and equipment, net |
| $ | 10,166 |
|
| $ | 4,110 |
|
| $ | 6,257 |
|
| $ | — |
|
| $ | 20,533 |
|
Total assets |
| $ | 13,390 |
|
| $ | 5,071 |
|
| $ | 10,276 |
|
| $ | (62 | ) |
| $ | 28,675 |
|
Capital expenditures, including acquisitions |
| $ | 2,640 |
|
| $ | 186 |
|
| $ | 1,082 |
|
| $ | — |
|
| $ | 3,908 |
|
Year Ended December 31, 2015: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 8,360 |
|
| $ | 1,012 |
|
| $ | 3,773 |
|
| $ | — |
|
| $ | 13,145 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 679 |
|
| $ | (679 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 3,164 |
|
| $ | 471 |
|
| $ | 387 |
|
| $ | — |
|
| $ | 4,022 |
|
Asset impairments |
| $ | 16,069 |
|
| $ | 15 |
|
| $ | 1,563 |
|
| $ | — |
|
| $ | 17,647 |
|
Asset dispositions |
| $ | (33 | ) |
| $ | 39 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 7 |
|
Restructuring and transaction costs |
| $ | 54 |
|
| $ | 24 |
|
| $ | — |
|
| $ | — |
|
| $ | 78 |
|
Interest expense |
| $ | 368 |
|
| $ | 97 |
|
| $ | 107 |
|
| $ | (46 | ) |
| $ | 526 |
|
Loss before income taxes |
| $ | (17,898 | ) |
| $ | (576 | ) |
| $ | (1,384 | ) |
| $ | — |
|
| $ | (19,858 | ) |
Income tax expense (benefit) |
| $ | (6,100 | ) |
| $ | (143 | ) |
| $ | 30 |
|
| $ | — |
|
| $ | (6,213 | ) |
Net loss |
| $ | (11,798 | ) |
| $ | (433 | ) |
| $ | (1,414 | ) |
| $ | — |
|
| $ | (13,645 | ) |
Net earnings (loss) attributable to noncontrolling interests |
| $ | 1 |
|
| $ | — |
|
| $ | (750 | ) |
| $ | — |
|
| $ | (749 | ) |
Net loss attributable to Devon |
| $ | (11,799 | ) |
| $ | (433 | ) |
| $ | (664 | ) |
| $ | — |
|
| $ | (12,896 | ) |
Property and equipment, net |
| $ | 10,357 |
|
| $ | 4,962 |
|
| $ | 5,667 |
|
| $ | — |
|
| $ | 20,986 |
|
Total assets |
| $ | 14,399 |
|
| $ | 5,830 |
|
| $ | 9,541 |
|
| $ | (97 | ) |
| $ | 29,673 |
|
Capital expenditures, including acquisitions |
| $ | 4,143 |
|
| $ | 591 |
|
| $ | 978 |
|
| $ | — |
|
| $ | 5,712 |
|
|
|
103
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country.
Included in this note are disclosuresAll of Devon’s results of operations for oil and gas producing activities and standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. In conjunction with Devon’s oil and gas accounting policy change discussed in Note 1, Devon also modified its treatment of certain “production support” costs in these two disclosures. Production support costs consisted of labor, supervision, materials and supplies for oil and gas production monitoring and support activities, includingreserves are located within the U.S.
The supplemental information technology, accounting and certain other administrative support functions. These costs are included in G&A expenses in the accompanying consolidated comprehensive statements of earnings. Devon used a methodtables below excludes amounts for 2020 related to allocateDevon’s discontinued operations. For additional information on these costs to its country-based results ofdiscontinued operations, and standardized measure disclosures. In 2016 and 2015, Devon’s results of operations disclosures included production support costs of $168 million and $224 million, respectively, and its standardized measure disclosures included estimated future production support costs of $2.8 billion and $2.7 billion, respectively.see Note 19.
Devon’s 2016 and 2015 disclosures have been revised to exclude these amounts.
Based on research conducted by Devon, diversity of practice has existed across peer companies regarding the treatment of production support costs in results of operations and standardized measure disclosures. Devon’s research of public filings indicates most companies exclude such costs from results of operations and standardized measure disclosures, but some companies appear to include such costs in their disclosures. Considering the apparent diversity of practice, Devon is making this disclosure change for two primary reasons. First, by converting to the successful efforts method of accounting and making this disclosure change, Devon’s results of operations and standardized measure disclosures will be most comparable to the vast majority of its peers. Second, allocating these costs to more granular common operating fields as opposed to country-based full cost pools is cost prohibitive and not materially important to investors and stakeholders, considering such allocated costs represented approximately 4% of Devon’s 2016 and 2015 oil, gas and NGL sales.
10492
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.
|
| Year Ended December 31, 2017 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Proved properties |
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
| ||||||||||||
Unproved properties |
|
| 50 |
|
|
| 4 |
|
|
| 54 |
| ||||||||||||
Exploration costs |
|
| 590 |
|
|
| 87 |
|
|
| 677 |
| ||||||||||||
Development costs |
|
| 1,036 |
|
|
| 225 |
|
|
| 1,261 |
| ||||||||||||
Costs incurred |
| $ | 1,678 |
|
| $ | 316 |
|
| $ | 1,994 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2016 |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Proved properties |
| $ | 237 |
|
| $ | — |
|
| $ | 237 |
|
| $ | 1,760 |
|
| $ | 7,017 |
|
| $ | — |
|
Unproved properties |
|
| 1,356 |
|
|
| 2 |
|
|
| 1,358 |
|
|
| 803 |
|
|
| 2,381 |
|
|
| 8 |
|
Exploration costs |
|
| 282 |
|
|
| 78 |
|
|
| 360 |
|
|
| 472 |
|
|
| 212 |
|
|
| 159 |
|
Development costs |
|
| 875 |
|
|
| 54 |
|
|
| 929 |
|
|
| 2,132 |
|
|
| 1,643 |
|
|
| 820 |
|
Costs incurred |
| $ | 2,750 |
|
| $ | 134 |
|
| $ | 2,884 |
|
| $ | 5,167 |
|
| $ | 11,253 |
|
| $ | 987 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2015 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Proved properties |
| $ | 193 |
|
| $ | 2 |
|
| $ | 195 |
| ||||||||||||
Unproved properties |
|
| 635 |
|
|
| 81 |
|
|
| 716 |
| ||||||||||||
Exploration costs |
|
| 432 |
|
|
| 120 |
|
|
| 552 |
| ||||||||||||
Development costs |
|
| 2,982 |
|
|
| 351 |
|
|
| 3,333 |
| ||||||||||||
Costs incurred |
| $ | 4,242 |
|
| $ | 554 |
|
| $ | 4,796 |
| ||||||||||||
Acquisition costs for 2022 in the table above pertain primarily to the Eagle Ford and Willison Basin acquisitions which closed in the third quarter of 2022. Acquisition costs for 2021 primarily relate to the Merger. Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations. Additionally, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $69 million, $61 million and $52 million in 2017, 2016 and 2015, respectively.
Results of Operations
The following tables includetable includes revenues and expenses associated with Devon’s oil and gas producing activities. They doIt does 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, | |||||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| |||
Oil, gas and NGL sales |
| $ | 14,082 |
|
| $ | 9,531 |
|
| $ | 2,695 |
|
|
Production expenses |
|
| (2,797 | ) |
|
| (2,131 | ) |
|
| (1,123 | ) |
|
Exploration expenses |
|
| (29 | ) |
|
| (14 | ) |
|
| (167 | ) |
|
Depreciation, depletion and amortization |
|
| (2,119 | ) |
|
| (2,050 | ) |
|
| (1,207 | ) |
|
Asset dispositions |
|
| 43 |
|
|
| 170 |
|
|
| — |
|
|
Asset impairments |
|
| — |
|
|
| — |
|
|
| (2,664 | ) |
|
Accretion of asset retirement obligations |
|
| (25 | ) |
|
| (28 | ) |
|
| (20 | ) |
|
Income tax expense |
|
| (2,041 | ) |
|
| (1,238 | ) |
|
| — |
|
|
Results of operations |
| $ | 7,114 |
|
| $ | 4,240 |
|
| $ | (2,486 | ) |
|
Depreciation, depletion and amortization per Boe |
| $ | 9.52 |
|
| $ | 9.83 |
|
| $ | 9.90 |
|
|
105
93
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| December 31, 2017 |
| ||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 3,746 |
|
| $ | 1,404 |
|
| $ | 5,150 |
|
Production expenses |
|
| (1,232 | ) |
|
| (591 | ) |
|
| (1,823 | ) |
Exploration expenses |
|
| (346 | ) |
|
| (34 | ) |
|
| (380 | ) |
Depreciation, depletion and amortization |
|
| (1,050 | ) |
|
| (369 | ) |
|
| (1,419 | ) |
Asset dispositions |
|
| 211 |
|
|
| 1 |
|
|
| 212 |
|
Accretion of asset retirement obligations |
|
| (38 | ) |
|
| (24 | ) |
|
| (62 | ) |
Income tax expense |
|
| — |
|
|
| (104 | ) |
|
| (104 | ) |
Results of operations |
| $ | 1,291 |
|
| $ | 283 |
|
| $ | 1,574 |
|
Depreciation, depletion and amortization per Boe |
| $ | 6.97 |
|
| $ | 7.73 |
|
| $ | 7.15 |
|
|
| December 31, 2016 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 3,198 |
|
| $ | 984 |
|
| $ | 4,182 |
|
Production expenses |
|
| (1,311 | ) |
|
| (492 | ) |
|
| (1,803 | ) |
Exploration expenses |
|
| (176 | ) |
|
| (39 | ) |
|
| (215 | ) |
Depreciation, depletion and amortization |
|
| (1,066 | ) |
|
| (380 | ) |
|
| (1,446 | ) |
Asset dispositions |
|
| 946 |
|
|
| 1 |
|
|
| 947 |
|
Asset impairments |
|
| (435 | ) |
|
| — |
|
|
| (435 | ) |
Accretion of asset retirement obligations |
|
| (49 | ) |
|
| (26 | ) |
|
| (75 | ) |
Income tax expense |
|
| — |
|
|
| (13 | ) |
|
| (13 | ) |
Results of operations |
| $ | 1,107 |
|
| $ | 35 |
|
| $ | 1,142 |
|
Depreciation, depletion and amortization per Boe |
| $ | 6.11 |
|
| $ | 7.75 |
|
| $ | 6.47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| December 31, 2015 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 4,356 |
|
| $ | 1,026 |
|
| $ | 5,382 |
|
Production expenses |
|
| (1,853 | ) |
|
| (586 | ) |
|
| (2,439 | ) |
Exploration expenses |
|
| (323 | ) |
|
| (128 | ) |
|
| (451 | ) |
Depreciation, depletion and amortization |
|
| (3,051 | ) |
|
| (423 | ) |
|
| (3,474 | ) |
Asset dispositions |
|
| 32 |
|
|
| (39 | ) |
|
| (7 | ) |
Asset impairments |
|
| (16,061 | ) |
|
| (15 | ) |
|
| (16,076 | ) |
Accretion of asset retirement obligations |
|
| (47 | ) |
|
| (28 | ) |
|
| (75 | ) |
Income tax benefit |
|
| 5,783 |
|
|
| 50 |
|
|
| 5,833 |
|
Results of operations |
| $ | (11,164 | ) |
| $ | (143 | ) |
| $ | (11,307 | ) |
Depreciation, depletion and amortization per Boe |
| $ | 14.79 |
|
| $ | 10.08 |
|
| $ | 13.99 |
|
106
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents Devon’s estimated proved reserves by productproduct.
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
| Oil (MMBbls) |
|
| Gas (Bcf) (1) |
|
| NGL (MMBbls) |
|
| Combined (MMBoe) |
| ||||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
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 |
|
Revisions due to prices |
|
| 55 |
|
|
| 382 |
|
|
| 36 |
|
|
| 155 |
|
Revisions other than price |
|
| (23 | ) |
|
| 11 |
|
|
| 64 |
|
|
| 43 |
|
Extensions and discoveries |
|
| 112 |
|
|
| 348 |
|
|
| 58 |
|
|
| 228 |
|
Purchase of reserves |
|
| 393 |
|
|
| 961 |
|
|
| 110 |
|
|
| 663 |
|
Production |
|
| (106 | ) |
|
| (325 | ) |
|
| (48 | ) |
|
| (209 | ) |
Sale of reserves |
|
| (4 | ) |
|
| (11 | ) |
|
| (1 | ) |
|
| (7 | ) |
December 31, 2021 |
|
| 709 |
|
|
| 2,878 |
|
|
| 437 |
|
|
| 1,625 |
|
Revisions due to prices |
|
| 15 |
|
|
| 61 |
|
|
| 8 |
|
|
| 34 |
|
Revisions other than price |
|
| (55 | ) |
|
| 13 |
|
|
| 3 |
|
|
| (49 | ) |
Extensions and discoveries |
|
| 127 |
|
|
| 449 |
|
|
| 76 |
|
|
| 278 |
|
Purchase of reserves |
|
| 106 |
|
|
| 137 |
|
|
| 24 |
|
|
| 153 |
|
Production |
|
| (109 | ) |
|
| (356 | ) |
|
| (54 | ) |
|
| (223 | ) |
Sale of reserves |
|
| — |
|
|
| (7 | ) |
|
| (1 | ) |
|
| (3 | ) |
December 31, 2022 |
|
| 793 |
|
|
| 3,175 |
|
|
| 493 |
|
|
| 1,815 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
December 31, 2019 |
|
| 198 |
|
|
| 1,344 |
|
|
| 167 |
|
|
| 589 |
|
December 31, 2020 |
|
| 194 |
|
|
| 1,244 |
|
|
| 173 |
|
|
| 574 |
|
December 31, 2021 |
|
| 544 |
|
|
| 2,361 |
|
|
| 348 |
|
|
| 1,285 |
|
December 31, 2022 |
|
| 596 |
|
|
| 2,595 |
|
|
| 391 |
|
|
| 1,419 |
|
Proved developed-producing reserves: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
December 31, 2019 |
|
| 191 |
|
|
| 1,327 |
|
|
| 165 |
|
|
| 578 |
|
December 31, 2020 |
|
| 190 |
|
|
| 1,223 |
|
|
| 171 |
|
|
| 564 |
|
December 31, 2021 |
|
| 533 |
|
|
| 2,316 |
|
|
| 341 |
|
|
| 1,260 |
|
December 31, 2022 |
|
| 585 |
|
|
| 2,553 |
|
|
| 387 |
|
|
| 1,397 |
|
Proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
December 31, 2019 |
|
| 78 |
|
|
| 277 |
|
|
| 44 |
|
|
| 168 |
|
December 31, 2020 |
|
| 88 |
|
|
| 268 |
|
|
| 45 |
|
|
| 178 |
|
December 31, 2021 |
|
| 165 |
|
|
| 517 |
|
|
| 89 |
|
|
| 340 |
|
December 31, 2022 |
|
| 197 |
|
|
| 580 |
|
|
| 102 |
|
|
| 396 |
|
Price Revisions
Reserves increased 34 MMBoe in 2022 primarily due to price increases in the trailing 12 month averages for oil, gas and NGLs.
|
|
|
|
|
|
|
|
|
|
|
|
|
| Bitumen |
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGL |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
| Oil (MMBbls) |
|
| (MMBbls) |
|
| Gas (Bcf) |
|
| (MMBbls) |
|
| Combined (MMBoe) (1) |
| |||||||||||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Canada |
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
| 351 |
|
|
| 23 |
|
|
| 374 |
|
|
| 521 |
|
|
| 7,651 |
|
|
| 36 |
|
|
| 7,687 |
|
|
| 578 |
|
|
| 2,205 |
|
|
| 549 |
|
|
| 2,754 |
|
Revisions due to prices |
|
| (53 | ) |
|
| 4 |
|
|
| (49 | ) |
|
| 103 |
|
|
| (1,412 | ) |
|
| (9 | ) |
|
| (1,421 | ) |
|
| (119 | ) |
|
| (408 | ) |
|
| 106 |
|
|
| (302 | ) |
Revisions other than price |
|
| (52 | ) |
|
| 2 |
|
|
| (50 | ) |
|
| (84 | ) |
|
| (3 | ) |
|
| (6 | ) |
|
| (9 | ) |
|
| (6 | ) |
|
| (59 | ) |
|
| (83 | ) |
|
| (142 | ) |
Extensions and discoveries |
|
| 51 |
|
|
| 3 |
|
|
| 54 |
|
|
| 11 |
|
|
| 171 |
|
|
| — |
|
|
| 171 |
|
|
| 24 |
|
|
| 104 |
|
|
| 14 |
|
|
| 118 |
|
Purchase of reserves |
|
| 5 |
|
|
| — |
|
|
| 5 |
|
|
| — |
|
|
| 17 |
|
|
| — |
|
|
| 17 |
|
|
| 1 |
|
|
| 9 |
|
|
| — |
|
|
| 9 |
|
Production |
|
| (60 | ) |
|
| (10 | ) |
|
| (70 | ) |
|
| (31 | ) |
|
| (579 | ) |
|
| (8 | ) |
|
| (587 | ) |
|
| (50 | ) |
|
| (206 | ) |
|
| (42 | ) |
|
| (248 | ) |
Sale of reserves |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (37 | ) |
|
| — |
|
|
| (37 | ) |
|
| — |
|
|
| (7 | ) |
|
| — |
|
|
| (7 | ) |
December 31, 2015 |
|
| 242 |
|
|
| 22 |
|
|
| 264 |
|
|
| 520 |
|
|
| 5,808 |
|
|
| 13 |
|
|
| 5,821 |
|
|
| 428 |
|
|
| 1,638 |
|
|
| 544 |
|
|
| 2,182 |
|
Revisions due to prices |
|
| (18 | ) |
|
| (2 | ) |
|
| (20 | ) |
|
| 23 |
|
|
| (103 | ) |
|
| — |
|
|
| (103 | ) |
|
| (13 | ) |
|
| (48 | ) |
|
| 21 |
|
|
| (27 | ) |
Revisions other than price |
|
| (2 | ) |
|
| 3 |
|
|
| 1 |
|
|
| (19 | ) |
|
| 628 |
|
|
| 10 |
|
|
| 638 |
|
|
| 48 |
|
|
| 151 |
|
|
| (14 | ) |
|
| 137 |
|
Extensions and discoveries |
|
| 36 |
|
|
| 2 |
|
|
| 38 |
|
|
| — |
|
|
| 280 |
|
|
| — |
|
|
| 280 |
|
|
| 42 |
|
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
Purchase of reserves |
|
| 8 |
|
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 33 |
|
|
| — |
|
|
| 33 |
|
|
| 7 |
|
|
| 20 |
|
|
| — |
|
|
| 20 |
|
Production |
|
| (47 | ) |
|
| (8 | ) |
|
| (55 | ) |
|
| (40 | ) |
|
| (510 | ) |
|
| (7 | ) |
|
| (517 | ) |
|
| (42 | ) |
|
| (174 | ) |
|
| (49 | ) |
|
| (223 | ) |
Sale of reserves |
|
| (25 | ) |
|
| — |
|
|
| (25 | ) |
|
| — |
|
|
| (521 | ) |
|
| — |
|
|
| (521 | ) |
|
| (45 | ) |
|
| (157 | ) |
|
| — |
|
|
| (157 | ) |
December 31, 2016 |
|
| 194 |
|
|
| 17 |
|
|
| 211 |
|
|
| 484 |
|
|
| 5,615 |
|
|
| 16 |
|
|
| 5,631 |
|
|
| 425 |
|
|
| 1,554 |
|
|
| 504 |
|
|
| 2,058 |
|
Revisions due to prices |
|
| 12 |
|
|
| (1 | ) |
|
| 11 |
|
|
| (37 | ) |
|
| 398 |
|
|
| 1 |
|
|
| 399 |
|
|
| 32 |
|
|
| 111 |
|
|
| (38 | ) |
|
| 73 |
|
Revisions other than price |
|
| 6 |
|
|
| 2 |
|
|
| 8 |
|
|
| (10 | ) |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
|
| (10 | ) |
|
| (5 | ) |
|
| (7 | ) |
|
| (12 | ) |
Extensions and discoveries |
|
| 90 |
|
|
| 4 |
|
|
| 94 |
|
|
| 12 |
|
|
| 403 |
|
|
| — |
|
|
| 403 |
|
|
| 63 |
|
|
| 221 |
|
|
| 16 |
|
|
| 237 |
|
Production |
|
| (42 | ) |
|
| (7 | ) |
|
| (49 | ) |
|
| (40 | ) |
|
| (433 | ) |
|
| (6 | ) |
|
| (439 | ) |
|
| (36 | ) |
|
| (150 | ) |
|
| (48 | ) |
|
| (198 | ) |
Sale of reserves |
|
| (3 | ) |
|
| — |
|
|
| (3 | ) |
|
| — |
|
|
| (9 | ) |
|
| — |
|
|
| (9 | ) |
|
| (1 | ) |
|
| (6 | ) |
|
| — |
|
|
| (6 | ) |
December 31, 2017 |
|
| 257 |
|
|
| 15 |
|
|
| 272 |
|
|
| 409 |
|
|
| 5,974 |
|
|
| 13 |
|
|
| 5,987 |
|
|
| 473 |
|
|
| 1,725 |
|
|
| 427 |
|
|
| 2,152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
| 255 |
|
|
| 23 |
|
|
| 278 |
|
|
| 137 |
|
|
| 6,948 |
|
|
| 36 |
|
|
| 6,984 |
|
|
| 486 |
|
|
| 1,900 |
|
|
| 165 |
|
|
| 2,065 |
|
December 31, 2015 |
|
| 203 |
|
|
| 22 |
|
|
| 225 |
|
|
| 219 |
|
|
| 5,694 |
|
|
| 13 |
|
|
| 5,707 |
|
|
| 411 |
|
|
| 1,563 |
|
|
| 243 |
|
|
| 1,806 |
|
December 31, 2016 |
|
| 160 |
|
|
| 17 |
|
|
| 177 |
|
|
| 190 |
|
|
| 5,361 |
|
|
| 16 |
|
|
| 5,377 |
|
|
| 387 |
|
|
| 1,439 |
|
|
| 210 |
|
|
| 1,649 |
|
December 31, 2017 |
|
| 178 |
|
|
| 15 |
|
|
| 193 |
|
|
| 200 |
|
|
| 5,619 |
|
|
| 13 |
|
|
| 5,632 |
|
|
| 410 |
|
|
| 1,524 |
|
|
| 218 |
|
|
| 1,742 |
|
Proved developed-producing reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
| 224 |
|
|
| 19 |
|
|
| 243 |
|
|
| 137 |
|
|
| 6,746 |
|
|
| 34 |
|
|
| 6,780 |
|
|
| 467 |
|
|
| 1,815 |
|
|
| 162 |
|
|
| 1,977 |
|
December 31, 2015 |
|
| 192 |
|
|
| 19 |
|
|
| 211 |
|
|
| 219 |
|
|
| 5,546 |
|
|
| 13 |
|
|
| 5,559 |
|
|
| 393 |
|
|
| 1,509 |
|
|
| 240 |
|
|
| 1,749 |
|
December 31, 2016 |
|
| 143 |
|
|
| 13 |
|
|
| 156 |
|
|
| 190 |
|
|
| 5,243 |
|
|
| 16 |
|
|
| 5,259 |
|
|
| 370 |
|
|
| 1,386 |
|
|
| 207 |
|
|
| 1,593 |
|
December 31, 2017 |
|
| 165 |
|
|
| 12 |
|
|
| 177 |
|
|
| 197 |
|
|
| 5,512 |
|
|
| 13 |
|
|
| 5,525 |
|
|
| 397 |
|
|
| 1,481 |
|
|
| 212 |
|
|
| 1,693 |
|
Proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
| 96 |
|
|
| — |
|
|
| 96 |
|
|
| 384 |
|
|
| 703 |
|
|
| — |
|
|
| 703 |
|
|
| 92 |
|
|
| 305 |
|
|
| 384 |
|
|
| 689 |
|
December 31, 2015 |
|
| 39 |
|
|
| — |
|
|
| 39 |
|
|
| 301 |
|
|
| 114 |
|
|
| — |
|
|
| 114 |
|
|
| 17 |
|
|
| 75 |
|
|
| 301 |
|
|
| 376 |
|
December 31, 2016 |
|
| 34 |
|
|
| — |
|
|
| 34 |
|
|
| 294 |
|
|
| 254 |
|
|
| — |
|
|
| 254 |
|
|
| 38 |
|
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
December 31, 2017 |
|
| 79 |
|
|
| — |
|
|
| 79 |
|
|
| 209 |
|
|
| 355 |
|
|
| — |
|
|
| 355 |
|
|
| 63 |
|
|
| 201 |
|
|
| 209 |
|
|
| 410 |
|
Reserves increased 155 MMBoe in 2021 primarily due to price increases in the trailing 12 month averages for oil, gas and NGLs.
|
|
10794
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Reserves decreased 78 MMBoe in 2020 primarily due to price decreases in the trailing 12 month averages for oil, gas and NGLs.
Revisions Other Than Price
2022 – Total revisions other than price (-49 MMBoe) were driven by higher operating costs across all areas of operation and the revisions to proved undeveloped reserves noted below. These downward revisions were partially offset by upward revisions due to well performance exceeding previous estimates primarily in the Delaware Basin. In total, after accounting for these compensating factors, we recorded negative revisions across each of our operating areas with the most significant changes being located in the Delaware Basin (-33 MMBoe), followed by the Powder River Basin (-5 MMBoe) and the Anadarko Basin (-4 MMBoe).
2021 – Total revisions other than price (43 MMBoe) were primarily due to well performance exceeding previous estimates modestly across all areas of operation (53 MMBoe) and the removal of proved undeveloped locations as noted below (-10 MMBoe). The upward revisions were driven by the Delaware Basin (23 MMBoe), Williston Basin (12 MMBoe) and Anadarko Basin (12 MMBoe).
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 Anadarko Basin (22 MMBoe).
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.
2022 – Of the 278 MMBoe of additions from extensions and discoveries, 255 MMBoe were in the Delaware Basin, 7 MMBoe were in the Powder River Basin, 6 MMBoe were in Eagle Ford, 5 MMBoe were in the Anadarko Basin and 5 MMBoe were in the Williston Basin.
2021 – Of the 228 MMBoe of additions from extensions and discoveries, 209 MMBoe were in the Delaware Basin, 8 MMBoe were in the Anadarko Basin, 6 MMBoe were in the Williston Basin, 3 MMBoe were in Eagle Ford and 2 MMBoe were in the Powder River Basin.
2020 – Of the 135 MMBoe of additions from extensions and discoveries, 117 MMBoe were in the Delaware Basin, 8 MMBoe were in the Anadarko Basin, 5 MMBoe were in the Powder River Basin and 5 MMBoe were in Eagle Ford.
Purchase of Reserves
During 2022, Devon had reserve additions due to the acquisitions of 66 MMBoe in the Williston Basin and 87 MMBoe in the Eagle Ford. For additional information on these asset additions, see Note 2.
During 2021, Devon had reserve additions due to the Merger of 538 MMBoe in the Delaware Basin and 125 MMBoe in the Williston Basin. For additional information on these asset additions, see Note 2.
95
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Sale of Reserves
During 2022, 2021 and 2020, Devon had U.S. non-core asset divestitures. For additional information on these divestitures, see Note 2.
Proved Undeveloped Reserves
The following table presents the changes in Devon’s total proved undeveloped reserves during 20172022 (MMBoe).
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved undeveloped reserves as of December 31, 2016 |
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
Extensions and discoveries |
|
| 116 |
|
|
| 12 |
|
|
| 128 |
|
Revisions due to prices |
|
| — |
|
|
| (27 | ) |
|
| (27 | ) |
Revisions other than price |
|
| (21 | ) |
|
| (6 | ) |
|
| (27 | ) |
Conversion to proved developed reserves |
|
| (9 | ) |
|
| (64 | ) |
|
| (73 | ) |
Proved undeveloped reserves as of December 31, 2017 |
|
| 201 |
|
|
| 209 |
|
|
| 410 |
|
Total | ||||
Proved undeveloped reserves as of December 31, 2021 | 340 | |||
Extensions and discoveries | 176 | |||
Revisions due to prices | 2 | |||
Revisions other than price | (39 | ) | ||
Purchase of reserves | 44 | |||
Sale of reserves | — | |||
Conversion to proved developed reserves | (127 | ) | ||
Proved undeveloped reserves as of December 31, 2022 | 396 | |||
Total proved undeveloped reserves remained consistentincreased 16% from 20162021 to 20172022 with the year-end 20172022 balance representing 19%22% of total proved reserves. Approximately 97% of the 176 MMBoe in extensions and discoveries were the result of Devon’s focus on drilling and development activities in the STACK andDelaware Basin. This continued development in the Delaware Basin was the primary driveralso accounted for more than 80% of the 128127 MMBoe increase in extensions and discoveries. Continued development primarily at Jackfish led to the conversion of 73 MMBoe, or 18%, of the 2016 proved undeveloped reserves being converted to proved developed reserves.reserves in 2022. Costs incurred in 2022 to develop and convert Devon’s proved undeveloped reserves were approximately $237 million for 2017.
A significant amount$866 million. Of the 44 MMBoe of Devon’s proved undevelopedpurchased reserves, at the end of 2017 related to its Jackfish operations. At December 31, 2017 and 2016, Devon’s Jackfish proved undeveloped reserves were 209 MMBoe and 294 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35 MBbl daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due51% relate to the large up-front capital investmentsWilliston Basin and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than five years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends through 2028. At the end of 2017, approximately 196 MMBoe of proved undeveloped reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of the reserves. Furthermore, approximately 88 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop.
Price Revisions
Reserves increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12 month average for oil, gas and NGLs in 2017. Reserves decreased 38 MMBoe in Canada due to a significant increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing its royalties, which decreases its after-royalty volumes.
Reserves decreased 27 MMBoe and 302 MMBoe during 2016 and 2015, respectively, primarily due to lower commodity prices for oil and gas. The lower bitumen price increased Canadian reserves due49% to the decline in royalties, which increases Devon’s after-royalty volumes.
108
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
TotalEagle Ford. Proved undeveloped reserves revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and NGLs, with the largest revisions being made in the Barnett Shale and STACK (Cana-Woodford Shale).
Revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish(-39 MMBoe) were primarily due to a refined reserves methodology that resultedchanges in a reduced recovery factor.
Extensions and Discoveries
2017 – Over 80% of the additions were through our focused effortspreviously adopted development plans (-22 MMBoe) in the STACK (120 MMBoe) and the Delaware Basin (79(-9 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.
The 2017 extensions and discoveries included 66 MMBoe related to additions from Devon’s infill drilling activities, which was primarily related to the STACK.
2016 – Of the 126 MMBoe of extensions and discoveries, 97 MMBoe related to STACK, 18 MMBoe related to the Delaware Basin and 7 MMBoe related to the Eagle Ford.
The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 73 MMBoe related to STACK.
2015 – Of the 118 MMBoe of extensions and discoveries, 38 MMBoe related to the Delaware Basin, 30 MMBoe related to the, Anadarko Basin 21 MMBoe related to the Eagle Ford(-7 MMBoe) and 11 MMBoe related to Jackfish.
The 2015 extensions and discoveries included 13 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 11 MMBoe at Jackfish.
Purchase of Reserves
2016 – Primarily related to Devon’s acquisition in the STACK play.
2015 – Primarily related to Devon’s acquisition in the Powder River Basin.Basin (-6 MMBoe), combined with additional downward revisions (-17 MMBoe) caused by both continued evaluation of well performance and higher operating costs.
Sale of Reserves
2017 – Related to Devon’s non-core asset divestitures in the U.S. as discussed further in Note 3.
2016 – Related to Devon’s non-core upstream asset divestitures discussed further in Note 3.
109
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.
|
| Year Ended December 31, 2017 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
Future cash inflows |
| $ | 34,701 |
|
| $ | 13,602 |
|
| $ | 48,303 |
| ||||||||||||
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Development |
|
| (3,316 | ) |
|
| (1,853 | ) |
|
| (5,169 | ) | ||||||||||||
Production |
|
| (15,526 | ) |
|
| (5,986 | ) |
|
| (21,512 | ) | ||||||||||||
Future income tax expense |
|
| — |
|
|
| (988 | ) |
|
| (988 | ) | ||||||||||||
Future net cash flow |
|
| 15,859 |
|
|
| 4,775 |
|
|
| 20,634 |
| ||||||||||||
10% discount to reflect timing of cash flows |
|
| (7,541 | ) |
|
| (1,756 | ) |
|
| (9,297 | ) | ||||||||||||
Standardized measure of discounted future net cash flows |
| $ | 8,318 |
|
| $ | 3,019 |
|
| $ | 11,337 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2016 |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
Future cash inflows |
| $ | 22,847 |
|
| $ | 9,672 |
|
| $ | 32,519 |
|
| $ | 108,361 |
|
| $ | 66,321 |
|
| $ | 14,957 |
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Development |
|
| (2,784 | ) |
|
| (2,201 | ) |
|
| (4,985 | ) |
|
| (5,176 | ) |
|
| (3,689 | ) |
|
| (1,747 | ) |
Production |
|
| (11,934 | ) |
|
| (6,049 | ) |
|
| (17,983 | ) |
|
| (35,264 | ) |
|
| (22,975 | ) |
|
| (7,964 | ) |
Future income tax expense |
|
| — |
|
|
| (121 | ) |
|
| (121 | ) |
|
| (13,216 | ) |
|
| (6,423 | ) |
|
| — |
|
Future net cash flow |
|
| 8,129 |
|
|
| 1,301 |
|
|
| 9,430 |
|
|
| 54,705 |
|
|
| 33,234 |
|
|
| 5,246 |
|
10% discount to reflect timing of cash flows |
|
| (3,524 | ) |
|
| (466 | ) |
|
| (3,990 | ) |
|
| (23,391 | ) |
|
| (13,933 | ) |
|
| (1,774 | ) |
Standardized measure of discounted future net cash flows |
| $ | 4,605 |
|
| $ | 835 |
|
| $ | 5,440 |
|
| $ | 31,314 |
|
| $ | 19,301 |
|
| $ | 3,472 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2015 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
Future cash inflows |
| $ | 27,398 |
|
| $ | 13,047 |
|
| $ | 40,445 |
| ||||||||||||
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Development |
|
| (3,306 | ) |
|
| (2,759 | ) |
|
| (6,065 | ) | ||||||||||||
Production |
|
| (14,938 | ) |
|
| (6,501 | ) |
|
| (21,439 | ) | ||||||||||||
Future income tax expense |
|
| — |
|
|
| (580 | ) |
|
| (580 | ) | ||||||||||||
Future net cash flow |
|
| 9,154 |
|
|
| 3,207 |
|
|
| 12,361 |
| ||||||||||||
10% discount to reflect timing of cash flows |
|
| (3,230 | ) |
|
| (1,248 | ) |
|
| (4,478 | ) | ||||||||||||
Standardized measure of discounted future net cash flows |
| $ | 5,924 |
|
| $ | 1,959 |
|
| $ | 7,883 |
| ||||||||||||
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 20172022 estimates, Devon’s future realized prices were assumed to be $47.86$93.53 per Bbl of oil, $31.86 per Bbl of bitumen, $2.43$5.41 per Mcf of gas and $16.25 $34.58
96
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
per Bbl of NGLs. Of the $5.2$5.2 billion of future development costs as of the end of 2017, $0.92022, $1.7 billion, $0.8$1.2 billion and $0.5$0.7 billion are estimated to be spent in 2018, 20192023, 2024 and 2020,2025, respectively.
Future development costs include not only development costs but also future asset retirement costs. Included as part of the $5.2$5.2 billion of future development costs are $1.3$0.8 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.
110
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, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
Beginning balance |
| $ | 5,440 |
|
| $ | 7,883 |
|
| $ | 21,583 |
|
| $ | 19,301 |
|
| $ | 3,472 |
|
| $ | 5,398 |
|
Net changes in prices and production costs |
|
| 5,218 |
|
|
| (2,027 | ) |
|
| (21,330 | ) |
|
| 14,081 |
|
|
| 8,274 |
|
|
| (3,277 | ) |
Oil, bitumen, gas and NGL sales, net of production costs |
|
| (3,327 | ) |
|
| (2,379 | ) |
|
| (2,943 | ) | ||||||||||||
Oil, gas and NGL sales, net of production costs |
|
| (11,285 | ) |
|
| (7,400 | ) |
|
| (1,572 | ) | ||||||||||||
Changes in estimated future development costs |
|
| 789 |
|
|
| 112 |
|
|
| 1,313 |
|
|
| (216 | ) |
|
| (414 | ) |
|
| 402 |
|
Extensions and discoveries, net of future development costs |
|
| 2,497 |
|
|
| 674 |
|
|
| 1,102 |
|
|
| 7,279 |
|
|
| 3,877 |
|
|
| 988 |
|
Purchase of reserves |
|
| 2 |
|
|
| 224 |
|
|
| 93 |
|
|
| 4,185 |
|
|
| 12,460 |
|
|
| 23 |
|
Sales of reserves in place |
|
| (3 | ) |
|
| (577 | ) |
|
| (77 | ) |
|
| (20 | ) |
|
| (12 | ) |
|
| (7 | ) |
Revisions of quantity estimates |
|
| (318 | ) |
|
| (21 | ) |
|
| (1,312 | ) |
|
| (874 | ) |
|
| 838 |
|
|
| 147 |
|
Previously estimated development costs incurred during the period |
|
| 559 |
|
|
| 663 |
|
|
| 2,158 |
|
|
| 956 |
|
|
| 663 |
|
|
| 537 |
|
Accretion of discount |
|
| 1,034 |
|
|
| 537 |
|
|
| 702 |
|
|
| 2,059 |
|
|
| 1,218 |
|
|
| 285 |
|
Foreign exchange and other |
|
| (7 | ) |
|
| 74 |
|
|
| (1,148 | ) | ||||||||||||
Net change in income taxes |
|
| (547 | ) |
|
| 277 |
|
|
| 7,742 |
| ||||||||||||
Net change in income taxes and other |
|
| (4,152 | ) |
|
| (3,675 | ) |
|
| 548 |
| ||||||||||||
Ending balance |
| $ | 11,337 |
|
| $ | 5,440 |
|
| $ | 7,883 |
|
| $ | 31,314 |
|
| $ | 19,301 |
|
| $ | 3,472 |
|
11197
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Net Earnings (Loss) Attributable to Devon
The following tables present a summary of Devon’s unaudited interim results of operations as recast under the successful efforts method of accounting. See Note 2 for additional details. As a result of the conversion to the successful efforts method of accounting in the fourth quarter of 2017, Devon has provided the full consolidated comprehensive statements of earnings for each interim quarter in 2017 to aid investors and facilitate comparative periods to be shown during 2018. Devon has provided the required summary information for each interim quarter in 2016.
|
| 2017, under Successful Efforts |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Upstream revenues |
| $ | 1,541 |
|
| $ | 1,332 |
|
| $ | 1,101 |
|
| $ | 1,333 |
|
| $ | 5,307 |
|
Marketing and midstream revenues |
|
| 2,010 |
|
|
| 1,927 |
|
|
| 2,055 |
|
|
| 2,650 |
|
|
| 8,642 |
|
Total revenues |
|
| 3,551 |
|
|
| 3,259 |
|
|
| 3,156 |
|
|
| 3,983 |
|
|
| 13,949 |
|
Production expenses |
|
| 457 |
|
|
| 455 |
|
|
| 448 |
|
|
| 463 |
|
|
| 1,823 |
|
Exploration expenses |
|
| 95 |
|
|
| 57 |
|
|
| 57 |
|
|
| 171 |
|
|
| 380 |
|
Marketing and midstream expenses |
|
| 1,814 |
|
|
| 1,714 |
|
|
| 1,824 |
|
|
| 2,378 |
|
|
| 7,730 |
|
Depreciation, depletion and amortization |
|
| 528 |
|
|
| 506 |
|
|
| 512 |
|
|
| 528 |
|
|
| 2,074 |
|
Asset impairments |
|
| 7 |
|
|
| — |
|
|
| 2 |
|
|
| 8 |
|
|
| 17 |
|
Asset dispositions |
|
| (3 | ) |
|
| (27 | ) |
|
| (169 | ) |
|
| (18 | ) |
|
| (217 | ) |
General and administrative expenses |
|
| 233 |
|
|
| 214 |
|
|
| 203 |
|
|
| 222 |
|
|
| 872 |
|
Financing costs, net |
|
| 128 |
|
|
| 116 |
|
|
| 128 |
|
|
| 126 |
|
|
| 498 |
|
Other expenses |
|
| (33 | ) |
|
| (20 | ) |
|
| (76 | ) |
|
| 5 |
|
|
| (124 | ) |
Total expenses |
|
| 3,226 |
|
|
| 3,015 |
|
|
| 2,929 |
|
|
| 3,883 |
|
|
| 13,053 |
|
Earnings before income taxes |
|
| 325 |
|
|
| 244 |
|
|
| 227 |
|
|
| 100 |
|
|
| 896 |
|
Income tax expense (benefit) |
|
| 8 |
|
|
| (1 | ) |
|
| 15 |
|
|
| (204 | ) |
|
| (182 | ) |
Net earnings |
|
| 317 |
|
|
| 245 |
|
|
| 212 |
|
|
| 304 |
|
|
| 1,078 |
|
Net earnings attributable to noncontrolling interests |
|
| 14 |
|
|
| 26 |
|
|
| 19 |
|
|
| 121 |
|
|
| 180 |
|
Net earnings attributable to Devon |
| $ | 303 |
|
| $ | 219 |
|
| $ | 193 |
|
| $ | 183 |
|
| $ | 898 |
|
Net earnings per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | 0.58 |
|
| $ | 0.41 |
|
| $ | 0.37 |
|
| $ | 0.35 |
|
| $ | 1.71 |
|
Diluted |
| $ | 0.58 |
|
| $ | 0.41 |
|
| $ | 0.37 |
|
| $ | 0.35 |
|
| $ | 1.70 |
|
Comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
| $ | 317 |
|
| $ | 245 |
|
| $ | 212 |
|
| $ | 304 |
|
| $ | 1,078 |
|
Other comprehensive earnings, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation and other |
|
| 8 |
|
|
| 28 |
|
|
| 42 |
|
|
| 5 |
|
|
| 83 |
|
Pension and postretirement plans |
|
| 5 |
|
|
| 4 |
|
|
| 5 |
|
|
| 15 |
|
|
| 29 |
|
Other comprehensive earnings, net of tax |
|
| 13 |
|
|
| 32 |
|
|
| 47 |
|
|
| 20 |
|
|
| 112 |
|
Comprehensive earnings |
|
| 330 |
|
|
| 277 |
|
|
| 259 |
|
|
| 324 |
|
|
| 1,190 |
|
Comprehensive earnings attributable to noncontrolling interests |
|
| 14 |
|
|
| 26 |
|
|
| 19 |
|
|
| 121 |
|
|
| 180 |
|
Comprehensive earnings attributable to Devon |
| $ | 316 |
|
| $ | 251 |
|
| $ | 240 |
|
| $ | 203 |
|
| $ | 1,010 |
|
112
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| 2016, under Successful Efforts |
| ||||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 2,126 |
|
| $ | 2,488 |
|
| $ | 2,882 |
|
| $ | 2,808 |
|
| $ | 10,304 |
|
Earnings (loss) before income taxes |
| $ | (2,036 | ) |
| $ | (339 | ) |
| $ | 787 |
|
| $ | 271 |
|
| $ | (1,317 | ) |
Net earnings (loss) attributable to Devon |
| $ | (1,550 | ) |
| $ | (326 | ) |
| $ | 613 |
|
| $ | 207 |
|
| $ | (1,056 | ) |
Basic net earnings (loss) per share attributable to Devon |
| $ | (3.27 | ) |
| $ | (0.63 | ) |
| $ | 1.17 |
|
| $ | 0.41 |
|
| $ | (2.09 | ) |
Diluted net earnings (loss) per share attributable to Devon |
| $ | (3.27 | ) |
| $ | (0.63 | ) |
| $ | 1.16 |
|
| $ | 0.41 |
|
| $ | (2.09 | ) |
The 2017 results include gains from asset dispositions of approximately $217 million (or $0.42 per diluted share), as discussed in Note 3.
The 2016 results include asset impairments of $1.2 billion (or $2.59 per diluted share) and $81 million (or $0.15 per diluted share), during the first quarter and the fourth quarter of 2016, respectively, as discussed in Note 6. Additionally, the 2016 quarterly results include gains from asset dispositions of approximately $3 million (or $0.01 per diluted share), $75 million (or $0.14 per diluted share), $830 million (or $1.59 per diluted share) and $575 million (or $1.10 per diluted share) during the first quarter through the fourth quarter of 2016, respectively, as discussed in Note 3.
The following tables present a summary of Devon’s quarterly consolidated comprehensive statements of earnings information for 2017 and 2016 reported under the full cost method.
|
| 2017, under Full Cost |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 3,551 |
|
| $ | 3,259 |
|
| $ | 3,156 |
|
| $ | 3,983 |
|
| $ | 13,949 |
|
Earnings before income taxes |
| $ | 598 |
|
| $ | 458 |
|
| $ | 272 |
|
| $ | 403 |
|
| $ | 1,731 |
|
Net earnings attributable to Devon |
| $ | 565 |
|
| $ | 425 |
|
| $ | 228 |
|
| $ | 473 |
|
| $ | 1,691 |
|
Basic net earnings per share attributable to Devon |
| $ | 1.08 |
|
| $ | 0.81 |
|
| $ | 0.43 |
|
| $ | 0.90 |
|
| $ | 3.22 |
|
Diluted net earnings per share attributable to Devon |
| $ | 1.07 |
|
| $ | 0.80 |
|
| $ | 0.43 |
|
| $ | 0.89 |
|
| $ | 3.20 |
|
|
| 2016, under Full Cost |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 2,126 |
|
| $ | 2,488 |
|
| $ | 2,882 |
|
| $ | 2,808 |
|
| $ | 10,304 |
|
Earnings (loss) before income taxes |
| $ | (3,685 | ) |
| $ | (1,745 | ) |
| $ | 1,178 |
|
| $ | 375 |
|
| $ | (3,877 | ) |
Net earnings (loss) attributable to Devon |
| $ | (3,056 | ) |
| $ | (1,570 | ) |
| $ | 993 |
|
| $ | 331 |
|
| $ | (3,302 | ) |
Basic net earnings (loss) per share attributable to Devon |
| $ | (6.44 | ) |
| $ | (3.04 | ) |
| $ | 1.90 |
|
| $ | 0.63 |
|
| $ | (6.52 | ) |
Diluted net earnings (loss) per share attributable to Devon |
| $ | (6.44 | ) |
| $ | (3.04 | ) |
| $ | 1.89 |
|
| $ | 0.63 |
|
| $ | (6.52 | ) |
113
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents a summary of Devon’s quarterly cash flow information as recast under the successful efforts method of accounting. See Note 2 for additional details. Devon has provided this information for each interim quarter in 2017 to aid investors and facilitate comparative periods to be shown during 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
| 2017 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Net earnings |
| $ | 317 |
|
| $ | 245 |
|
| $ | 212 |
|
| $ | 304 |
|
| $ | 1,078 |
|
Net cash from operating activities |
|
| 746 |
|
|
| 738 |
|
|
| 700 |
|
|
| 725 |
|
|
| 2,909 |
|
Net cash from investing activities |
|
| (454 | ) |
|
| (587 | ) |
|
| (457 | ) |
|
| (712 | ) |
|
| (2,210 | ) |
Net cash from financing activities |
|
| (124 | ) |
|
| 91 |
|
|
| 157 |
|
|
| (115 | ) |
|
| 9 |
|
Effect of exchange rate changes on cash |
|
| (8 | ) |
|
| 8 |
|
|
| 12 |
|
|
| (6 | ) |
|
| 6 |
|
Net change in cash and cash equivalents |
|
| 160 |
|
|
| 250 |
|
|
| 412 |
|
|
| (108 | ) |
|
| 714 |
|
Cash and cash equivalents at beginning of period |
|
| 1,959 |
|
|
| 2,119 |
|
|
| 2,369 |
|
|
| 2,781 |
|
|
| 1,959 |
|
Cash and cash equivalents at end of period |
| $ | 2,119 |
|
| $ | 2,369 |
|
| $ | 2,781 |
|
| $ | 2,673 |
|
| $ | 2,673 |
|
Effects of Accounting Change on Fourth Quarter
As Devon recast the financial statements due to a change in accounting principle during the fourth quarter of 2017, the effects of the accounting change on the fourth quarter consolidated comprehensive statement of earnings and consolidated statement of cash flow are included below. See Note 2 for additional details.
|
| Changes to the Consolidated Comprehensive |
| |||||||||
|
| Statement of Earnings |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Quarter Ended December 31, 2017 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Exploration expenses |
| $ | — |
|
| $ | 171 |
|
| $ | 171 |
|
Depreciation, depletion and amortization |
|
| 417 |
|
|
| 111 |
|
|
| 528 |
|
Asset dispositions |
|
| 1 |
|
|
| (19 | ) |
|
| (18 | ) |
General and administrative expenses |
|
| 174 |
|
|
| 48 |
|
|
| 222 |
|
Financing costs, net |
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
Other expenses |
|
| 15 |
|
|
| (10 | ) |
|
| 5 |
|
Earnings before income taxes |
|
| 403 |
|
|
| (303 | ) |
|
| 100 |
|
Income tax benefit |
|
| (191 | ) |
|
| (13 | ) |
|
| (204 | ) |
Net earnings |
|
| 594 |
|
|
| (290 | ) |
|
| 304 |
|
Net earnings attributable to Devon |
|
| 473 |
|
|
| (290 | ) |
|
| 183 |
|
Net earnings per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| 0.90 |
|
|
| (0.55 | ) |
|
| 0.35 |
|
Diluted |
|
| 0.89 |
|
|
| (0.54 | ) |
|
| 0.35 |
|
Comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
| 594 |
|
|
| (290 | ) |
|
| 304 |
|
Foreign currency translation and other |
|
| 6 |
|
|
| (1 | ) |
|
| 5 |
|
Comprehensive earnings |
|
| 615 |
|
|
| (291 | ) |
|
| 324 |
|
Comprehensive earnings attributable to Devon |
|
| 494 |
|
|
| (291 | ) |
|
| 203 |
|
114
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Changes to the Consolidated |
| |||||||||
|
| Statement of Cash Flows |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Quarter Ended December 31, 2017 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Net earnings |
| $ | 594 |
|
| $ | (290 | ) |
| $ | 304 |
|
Depreciation, depletion and amortization |
|
| 417 |
|
|
| 111 |
|
|
| 528 |
|
Exploratory dry hole expense and unproved leasehold impairments |
|
| — |
|
|
| 139 |
|
|
| 139 |
|
Gains and losses on asset sales |
|
| 1 |
|
|
| (19 | ) |
|
| (18 | ) |
Deferred income tax benefit |
|
| (232 | ) |
|
| (13 | ) |
|
| (245 | ) |
Share-based compensation |
|
| 36 |
|
|
| 11 |
|
|
| 47 |
|
Other |
|
| 26 |
|
|
| (10 | ) |
|
| 16 |
|
Net cash from operating activities |
|
| 796 |
|
|
| (71 | ) |
|
| 725 |
|
Capital expenditures |
|
| (871 | ) |
|
| 72 |
|
|
| (799 | ) |
Divestitures of property and equipment |
|
| 102 |
|
|
| (1 | ) |
|
| 101 |
|
Net cash from investing activities |
|
| (783 | ) |
|
| 71 |
|
|
| (712 | ) |
115
Item 9.Changes in and Disagreements with AccountantsAccountants 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, 20172022 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 21, 2018,15, 2023, management concluded that its internal control over financial reporting was effective as of December 31, 2017.2022.
The effectiveness of our internal control over financial reporting as of December 31, 20172022 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, 2017,2022, 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
In the fourth quarter of 2017, we added and modified certain internal control processes as a result of changing our method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. There werewas no other changeschange in our internal control over financial reporting during the fourth quarter of 20172022 that has materially affected, or areis reasonably likely to materially affect, our internal control over financial reporting.
Not applicable.
Item 9C.Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
116Not applicable.
98
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, 2017.2022.
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, 2017.2022.
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, 2017.2022.
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, 2017.2022.
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, 2017.2022.
11799
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 and Sale Agreement, | |
2.2 |
| |
| 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 | |
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 |
118
|
| |
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 | |
4.4 |
| |
| 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). | |
100
| 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). | |
| Supplemental Indenture No. 6, dated as of June 9, 2021, between Registrant and UMB Bank, National Association, as Trustee, relating to the 8.250% Senior Notes due 2023 and the 5.250% Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to Registrant's Form 8-K filed June 9, 2021; File No. 001-32318). | |
4.7 | Supplemental Indenture No. 7, dated as of June 9, 2021, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.250% Senior Notes due 2027, 5.875% Senior Notes due 2028 and 4.500% Senior Notes due 2030 (incorporated by reference to Exhibit 4.3 to Registrant’s Form 8-K filed June 9, 2021; File No. 001-32318). | |
4.8 | 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). | |
| 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). | |
| Supplemental Indenture No. | |
| 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). | |
| 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 | |
|
| |
|
|
119
|
| |
|
| |
| 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). | |
| 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). | |
| 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 |
101
| 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). | |
| Indenture, dated as of | |
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 | |
|
| |
| Second Supplemental Indenture, dated as of | |
|
| |
| Fourth Supplemental Indenture, dated as of | |
4.21 | Fifth Supplemental Indenture, | |
4.22 | 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, relating 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 June 17, 2020; File No. 001-35322). | |
4.23 | Supplemental Indenture No. 7, dated as of June 9, 2021, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 8.250% Senior Notes due 2023, the 5.250% Senior Notes due 2024, the 5.250% Senior Notes due 2027, the 5.875% Senior Notes due 2028 and the 4.500% Senior Notes due 2030 (incorporated by reference to Exhibit | |
4.24 |
|
120
|
| |
10.1 | Credit Agreement, dated as of October | |
10.2 | First Amendment to Credit Agreement and Extension Agreement, dated as of | |
10.3 |
| |
10.4 |
| |
| 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).** |
102
10.5 | ||
| 2021 Amendment (effective as of January 7, 2021) to the Devon Energy Corporation | |
|
| |
|
| |
|
| |
10.8 | Amendment No. 4 to the WPX Energy, Inc. 2013 Incentive Plan and | |
| Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective as of | |
|
| |
|
|
121
|
| |
| 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).** | |
| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan | |
| Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan | |
| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration Plan | |
| Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Benefit Restoration Plan (incorporated by reference to Exhibit 10.20 to the Company’s Form 10-K filed February 17, 2021; File No. 001-32318).** | |
10.15 | Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective as of January 1, | |
|
| |
|
| |
| Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective as of January 1, | |
|
| |
|
| |
| 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).** | |
| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Executive Retirement Plan | |
103
10.19 | 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).** | |
| ||
10.20 | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.35 to Registrant’s Form 10-K filed February 17, 2021; File No. 001-32318).** | |
10.21 | 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).** | |
| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan | |
| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Retirement Income Plan |
122
|
| |
| Amendment 2019-1, effective September 10, 2019, to the Devon Energy Corporation Supplemental Retirement Income Plan (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed November 6, 2019; File No. 001-32318).** | |
10.25 | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Supplemental Retirement Income Plan (incorporated by reference to Exhibit 10.40 to the Company’s Form 10-K filed February 17, 2021; File No. 001-32318).** | |
10.26 | Devon Energy Corporation Incentive Savings Plan (amended and restated effective as of January 1, | |
|
| |
|
| |
|
| |
| Employment Agreement, dated effective April 19, 2017, by and between Registrant and | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
123104
|
| |
10.33 | ||
|
| |
10.34 | Employment Agreement, dated March 2, 2022, by and between Devon Energy Corporation and Tana K. Cashion (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed March 7, 2022; File No. 001-32318).** | |
10.35 | 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).** | |
10.36 | First Amendment to the WPX Energy Nonqualified Deferred Compensation Plan, executed January 4, 2021 (incorporated by reference to Exhibit 10.37 of Registrant’s Form 10-K filed February 16, 2022; File No. 001-32318).** | |
10.37 | Second Amendment to the WPX Energy Nonqualified Deferred Compensation Plan, executed December 15, 2021 (incorporated by reference to Exhibit 10.38 of Registrant’s Form 10-K filed February 16, 2022; File No. 001-32318).** | |
10.38 | 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).** | |
10.39 | First Amendment to the WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, executed December 9, 2021 (incorporated by reference to Exhibit 10.40 of Registrant’s Form 10-K filed February 16, 2022; File No. 001-32318).** | |
10.40 | WPX Energy Nonqualified Restoration Plan, effective January 1, 2015 (incorporated by reference to Exhibit 10.41 of Registrant’s Form 10-K filed February 16, 2022; File No. 001-32318).** | |
10.41 | First Amendment to the WPX Energy Nonqualified Restoration Plan, executed January 4, 2021 (incorporated by reference to Exhibit 10.42 of Registrant’s Form 10-K filed February 16, 2022; File No. 001-32318).** | |
10.42 | Second Amendment to the WPX Energy Nonqualified Restoration Plan, executed December 15, 2021 (incorporated by reference to Exhibit 10.43 of Registrant’s Form 10-K filed February 16, 2022; File No. 001-32318).** | |
10.43 | 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 | |
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| 2019 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the | |
10.45 | 2020 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the | |
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10.46 | 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).** | |
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10.47 | 2021 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon Energy Corporation and | |
| 2022 Form of | |
10.49 | 2020 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the | |
| 2020 Form of | |
10.51 | 2021 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon Energy Corporation and certain officers for performance based restricted share units awarded (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q filed May 5, 2021; File No. 001-32318).** | |
10.52 | 2022 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon Energy Corporation and certain officers for performance based restricted share units awarded (incorporated by reference to Exhibit 10.2 of Registrant’s Form 10-Q filed May 3, 2022; File No. 001-32318).** | |
10.53 | 2022 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2022 Long-Term Incentive Plan between the Company and all non-management directors for restricted stock awarded (incorporated by reference to Exhibit 10.2 of Registrant’s Form 10-Q filed August 2, 2022; File No. 001-32318).** | |
10.54 | 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).** | |
10.55 | 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).** | |
10.56 | 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).** | |
10.57 | 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).** |
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10.58 | 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, | |
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10.60 | Form of Amended Exhibit B to Amended and Restated Performance-Based Restricted Stock Unit | |
10.61 | Form of Global Amendment to Performance-Based Restricted Stock Unit Agreements between WPX Energy, Inc. and certain executive officers (incorporated by reference to Exhibit | |
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31.2 | ||
32.1 | ||
32.2 | ||
| Report of | |
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101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |
101.LAB | ||
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |
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* 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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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 |
February 21, 201815, 2023
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/ | President, Chief Executive Officer and | February | |
| Director (Principal executive officer) | ||
/s/ JEFFREY L. RITENOUR | Executive Vice President | February | |
Jeffrey L. Ritenour | and Chief Financial Officer (Principal financial officer) | ||
/s/ JEREMY D. HUMPHERS | Senior Vice President | February | |
Jeremy D. Humphers | and Chief Accounting Officer (Principal accounting officer) | ||
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/s/ BARBARA M. BAUMANN | Chair and Director | February | |
Barbara M. Baumann | |||
/s/ JOHN E. BETHANCOURT | Director | February | |
John E. Bethancourt | |||
/s/ | Director | February | |
| |||
/s/ | Director | February | |
| |||
/s/ KELT KINDICK | Director | February 15, 2023 | |
Kelt Kindick | |||
/s/ JOHN KRENICKI JR. | Director | February 15, 2023 | |
John Krenicki Jr. | |||
/s/ KARL F. KURZ | Director | February 15, 2023 | |
Karl F. Kurz | |||
/s/ MICHAEL N. MEARS | Director | February 15, 2023 | |
Michael N. Mears | |||
/s/ ROBERT A. MOSBACHER, JR. | Director | February | |
Robert A. Mosbacher, Jr. | |||
/s/ DUANE C. RADTKE | Director | February | |
Duane C. Radtke | |||
/s/ | Director | February | |
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