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, 20162019
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.) |
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333 West Sheridan Avenue, Oklahoma City, Oklahoma |
| 73102-5015 |
(Address of principal executive offices) |
| (Zip code) |
Registrant’s telephone number, including area code:
(405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol |
| Name of each exchange on which registered |
| |
| Common stock, par value $0.10 per share |
| DVN | The New York Stock Exchange |
|
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
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 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, 201628, 2019 was approximately $18.9$11.6 billion, based upon the closing price of $36.25$28.52 per share as reported by the New York Stock Exchange on such date. On February 8, 2017, 524.65, 2020, 382.9 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s definitive Proxy statement for the 2017Statement relating to Registrant’s 2020 annual meeting of stockholders –have been incorporated by reference in Part III
of this Annual Report on Form 10-K.
FORM 10-K
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk |
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
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Item 10. Directors, Executive Officers and Corporate Governance |
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Item 13. Certain Relationships and Related Transactions, and Director Independence |
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2
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon”“Devon,” the “Company” and the “Company”“Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:
“2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.
“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.
“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.
“ASC” means Accounting Standards Codification.
“ASR” means an accelerated share-repurchase transaction with a financial institution to repurchase Devon’s common stock.
“ASU” means Accounting Standards Update.
“Bbl” or “Bbls” means barrel or barrels.
“Bcf” means billion cubic feet.
“BKV” means Banpu Kalnin Ventures.
“BLM” means the United States Bureau of Land Management.
“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.
“Btu” means British thermal units, a measure of heating value.
“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.
“Canadian Plan”CDM” means Devon Canada Corporation Incentive Savings Plan.
“Coronado” means CoronadoCotton Draw Midstream, Holdings LLC.
“Crosstex” means Crosstex Energy, Inc. together with Crosstex Energy L.P.L.L.C.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Financing” means Devon Financing Company, L.L.C.
“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.
“E2” means E2 Energy Services, LLC together with E2 Appalachian Compression, LLC.
“EMH” means EnLink Midstream Holdings, LP.
“EnLink” means EnLink Midstream Partners, L.P.,LP, a master limited partnership.
“EPA” means the United States Environmental Protection Agency.
“FASB” means Financial Accounting Standards Board.
“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.
“G&A” means general and administrative expenses.
“GAAP” means U.S. generally accepted accounting principles.
“General Partner” means EnLink Midstream, LLC, the indirect general partner entity of EnLink.
“GeoSouthern” means GeoSouthern Energy Corporation.EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“LPC” means LPC Crude Oil Marketing LLC.
“Matador” means MRC Energy Company.
3
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
“MLP” means master limited partnership.
“MMBbls” means million barrels.
3
“MMBoe” means million Boe.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“N/M” means not meaningful.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“NYSE” means New York Stock Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“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.
“S&P 500 Index” means Standard and Poor’s 500 index.
“Tall Oak”Tax Reform Legislation” means Tall Oak Midstream, LLC.Tax Cuts and Jobs Act.
“TSR” means total shareholder return.
“U.S.” means United States of America.
“VEX”VIE” means Victoria Express Pipeline and related truck terminal and storage assets.variable interest entity.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/d” means per day.
“/gal”MMBtu” means per gallon.MMBtu.
4
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. 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, 2016 reserve reports and other data in our possession or available from third parties.future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to:
the volatility of oil, gas and NGL prices;
• | the volatility of oil, gas and NGL prices; |
uncertainties inherent in estimating oil, gas and NGL reserves;
• | uncertainties inherent in estimating oil, gas and NGL reserves; |
the extent to which we are successful in acquiring and discovering additional reserves;
• | the extent to which we are successful in acquiring and discovering additional reserves; |
the uncertainties, costs and risks involved in exploration and development activities;
• | the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct; |
risks related to our hedging activities;
• | regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; |
counterparty credit risks;
• | risks related to regulatory, social and market efforts to address climate change; |
regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;
• | risks related to our hedging activities; |
risks relating to our indebtedness;
• | counterparty credit risks; |
our ability to successfully complete mergers, acquisitions and divestitures;
• | risks relating to our indebtedness; |
the extent to which insurance covers any losses we may experience;
• | risks related to environmental regulations; |
our limited control over third parties who operate some of our oil and gas properties;
• | cyberattack risks; |
midstream capacity constraints and potential interruptions in production;
• | our limited control over third parties who operate some of our oil and gas properties; |
competition for leases, materials, people and capital;
• | midstream capacity constraints and potential interruptions in production; |
cyberattacks targeting our systems and infrastructure; and
• | the extent to which insurance covers any losses we may experience; |
• | competition for assets, materials, people and capital; |
any of the other risks and uncertainties discussed in this report.
• | risks related to investors attempting to effect change; |
• | our ability to successfully complete mergers, acquisitions and divestitures; and |
• | any of the other risks and uncertainties discussed in this report. |
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
5
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. In June 2019, we completed the sale of substantially all of our oil and gas assets and operations in Canada. Additionally,In December 2019, we control EnLink, a publicly–traded MLP with an integrated midstream business with significant size and scale in key operating regions inannounced the U.S. For additional information regardingsale of our control of, and ownership interest in, EnLink and its indirect general partner, the General Partner, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.Barnett Shale assets.
Devon has been publicly held since 1988, and our common stock is listed on the NYSE under the ticker symbol DVN. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2016,2019, Devon and its consolidated subsidiaries had approximately 5,000 employees, of which approximately 1,500 employees are employed by EnLink (through its subsidiaries).1,800 employees.
Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports, with the SEC. Through our website, www.devonenergy.com, we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees of our Board of Directors and other documents related to our corporate governance. The corporate governance documents available on our website include our Code of Ethics for Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, and any amendments to and waivers from any provision of that Code will also be posted on our website. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.
In addition, the public may read and copy any materials Devon files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.
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 tenant 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 reflected in the company’s investment grade credit ratings.with four fundamental principles.
Proven and responsible operator – We focusoperate our business on building value per share by:
managingwith the interests of our stakeholders and our environmental, social and governance progress in mind. With our vision to be a premier asset portfolio;
delivering top-tier results within the areas that we operate;
continuing disciplined capital allocation; and
maintaining significant financial strength.
Our formidable portfolio of exploration and production assets and operations provides stable, environmentally responsible production and a platform for future growth. For Devon, 2016 was a transformational year as we executed our strategy. We successfully reshaped our asset portfolio with non-core divestitures and the continued development of our world-class operations in the STACK and Delaware Basin. These assets provide us with a sustainable, multi-decade growth platform that continues to improve in response to our successful drilling programs. During 2016, we delivered the best well productivity in Devon’s 45-year history and continued a four-year streak of increasing Devon’s initial 90-day production rates. Devon has more than doubled its onshore North American oil
6
production since 2011 and has a deep inventory of development opportunities to deliver future oil growth. Adding to these operational highlights, we had several key actions in 2016 as discussed below.
Raised net proceeds of $1.5 billion in an offering of our common stock
Reduced exploratory and development capital investment by $2.8 billion, or 65%
Reduced G&A and field operating costs by $845 million, or 25%
Reduced our dividend $175 million, or 44%
Successfully divested certain non-core upstream assets in the U.S. and our 50% interest in the Access Pipeline in Canada for approximately $3.1 billion
Reduced Devon’s debt by $3.1 billion, or 31%, and have no significant long term maturities until July 2021
Completed a strategic bolt-on acquisition in the STACK for $1.5 billion
Exited 2016 with approximately $5 billion in liquidity
As we enter 2017 and continue to look toward the future, we will approach the current environment in a manner that drives efficiencies across our portfolio. We will manage activity levels within our cash flow by achieving additional operating cost savings and increasing capital productivity, while remaining committed to allocating capital in a disciplined manner that is driven by both value and return. We believe we capture the full value of our assets and improve returns through maximizing our base production and optimizing our capital program. The activities that support this strategy include minimizing controllable downtime, enhancing well productivity, ensuring disciplined project execution, performing premier technical work, focusing on developmental drilling and reducing our operating and capital costs.
EnLink Strategy
EnLink focuses on providing gathering, transmission, processing, storage, fractionation and marketing to upstreamindependent oil and natural gas producers, including Devon. exploration and production company, the work our employees do every day contributes to the local, national and global economies. We produce a valuable commodity that is fundamental to society, and we endeavor to do so in a safe, environmentally responsible and ethical way, while striving to deliver strong returns to our shareholders. We have an ongoing commitment to transparency in reporting our environmental, social and governance performance. See our Sustainability Report published on our company website for performance highlights and additional information. Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
EnLink connectsA premier, sustainable portfolio of assets – As discussed in the wellsnext section of this Annual Report, we own a portfolio of assets located in the United States. We strive to own premier assets capable of generating cash flows in excess of our capital and operating requirements, as well as competitive rates of return. We also desire to own a portfolio of assets that can provide a production growth platform extending many years into the future. Due to the strength of oil prices relative to natural gas, producerswe have been positioning our portfolio to be more heavily weighted to U.S. oil assets in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gasrecent years.
During 2019, we completed our transition to a varietyU.S. oil company. We sold our Canadian business, generating $2.6 billion in proceeds, and announced the sale of markets. Furthermore, EnLink purchases natural gasour Barnett Shale assets for approximately $770 million, before purchase price adjustments. As a result of these divestitures, we expect our oil production growth, price realizations and field-level margins will all improve, as we sharpen our focus on four U.S. oil plays located in the Delaware Basin, STACK, Powder River Basin and Eagle Ford.
Superior execution – As we pursue cash flow growth, we continually work to optimize the efficiency of our capital programs and production operations, with an underlying objective of reducing absolute and per unit costs and enhancing our returns. We also strive to leverage our culture of health, safety and environmental stewardship in all aspects of our business.
Throughout 2019, we continued to achieve efficiency gains in various aspects of our business. Our initial production rates from natural gasnew wells continued to improve in our four U.S. oil plays and have exceeded the average of the top 40 U.S. producers since 2015 by more than 40%. We continued to improve cycle times, incorporate production optimization strategies and other supply sourcescost reduction initiatives, driving down breakeven costs across our portfolio of assets.
As we focus on a more streamlined portfolio of U.S. oil assets, we are aggressively pursuing an improved cost structure to further expand margins. We have realized annualized cost savings by reducing well costs, production expense, financing costs and sells that natural gas to utilities, industrial consumers, other marketers and pipelines.G&A costs.
EnLink’s primary business objective is to provide cash flow stability, while growing through prudent and profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintaining a strong financial position through a conservative and balanced capital structure highlighted by its investment grade status. EnLink has consistently demonstrated expertise within the MLP space and continues to employ a proven business model that includes growing, expanding and executing on its strategy within top basins where Devon and other successful upstream producers operate.
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Financial strength and flexibility – Commodity prices are uncertain and volatile, so we strive to maintain a strong balance sheet, as well as adequate liquidity and financial flexibility, in order to operate competitively in all commodity price cycles. Our capital allocation decisions are made with attention to these financial stewardship principles, as well as the priorities of funding our core operations, protecting our investment-grade credit ratings, and paying and growing our shareholder dividend.
During 2019, we reduced our consolidated debt by $1.7 billion, primarily from proceeds from our divestitures. We also raised our quarterly dividend 12.5% and repurchased 69 million shares of common stock under our share repurchase program.
Oil and Gas Properties
Canadian Business and Barnett Shale Assets – Discontinued Operations
As a result of our divestment of substantially all of our oil and gas assets and operations in Canada, as well as the recently announced divestiture of our Barnett Shale assets, amounts associated with these assets are presented as discontinued operations. Therefore, financial and operational data, such as reserves, production, wells and acreage, provided in this document exclude amounts related to our Canadian and Barnett Shale assets unless otherwise noted. Included within the amounts presented as discontinued operations associated with the Barnett Shale are properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas. For additional information, please see Note 2in “Item 8. Financial Statements and Supplementary Data” of this report.
Property Profiles
8
The following table outlines aKey summary of key data infrom each of our operating areas of operation as of and for the year ended December 31, 2016. Notes 21 and 22 to2019 are detailed in the financial statements included in “Item 8. Financial Statements and Supplementary Data”map below.
7
Table of this report contain additional information on our segments and geographical areas.Contents
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| Proved Reserves |
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| Production |
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| MMBoe |
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| % of Total |
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| % Liquids |
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| MBoe/d |
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| % of Total |
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| % Liquids |
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| Gross Wells Drilled |
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Barnett Shale |
| 895 |
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| 44 | % |
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| 25 | % |
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| 169 |
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| 28 | % |
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| 27 | % |
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| — |
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Delaware Basin |
| 108 |
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| 5 | % |
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| 75 | % |
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| 60 |
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| 10 | % |
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| 74 | % |
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| 58 |
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Eagle Ford |
| 75 |
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| 4 | % |
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| 76 | % |
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| 76 |
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| 12 | % |
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| 76 | % |
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| 63 |
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Heavy Oil |
| 504 |
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| 24 | % |
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| 99 | % |
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| 134 |
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| 22 | % |
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| 98 | % |
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| 25 |
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Rockies Oil |
| 24 |
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| 1 | % |
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| 64 | % |
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| 19 |
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| 3 | % |
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| 79 | % |
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| 19 |
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STACK |
| 393 |
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| 19 | % |
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| 47 | % |
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| 93 |
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| 15 | % |
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| 48 | % |
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| 133 |
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Other |
| 59 |
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| 3 | % |
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| 90 | % |
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| 17 |
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| 3 | % |
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| 81 | % |
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| 28 |
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Retained assets |
| 2,058 |
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| 100 | % |
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| 54 | % |
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| 568 |
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| 93 | % |
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| 62 | % |
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| 326 |
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Divested assets (1) |
| — |
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| — |
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| — |
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| 43 |
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| 7 | % |
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| 51 | % |
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| 14 |
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Total |
| 2,058 |
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| 100 | % |
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| 54 | % |
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| 611 |
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| 100 | % |
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| 61 | % |
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| 340 |
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Led by results from the STACK, Delaware Basin and Eagle Ford, Devon achieved the best drilling results in our 45-year history. Our initial 90-day production rates in 2016 increased for the fourth consecutive year, advancing more than 300% from 2012 levels. These productivity improvements were driven by activity focused in top resource plays, improved subsurface reservoir characterization, leading-edge completion designs and improvements in lateral placement. Excluding the effects of divestitures, our drilling results increased our proved reserves in 2016 on a retained asset basis by 3%. The most significant reserves growth came from our U.S. operations, where we replaced approximately 175% of our 2016 production.
Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this asset into one of the top producing gas fields in North America. Given the sustained low gas price environment, we continue to focus on enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2017, we plan on minimal development activity, with planned capital investment of up to $50 million to optimize base production and further de-risk future development activity.
Delaware Basin – The Delaware Basin is one of Devon’s top-two franchise assets and continues to offermost active program in the portfolio. Through capital-efficient growth, it offers exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, Delaware, Wolfcamp and Leonard formations. TheseWith a significant inventory of oil and liquids-rich drilling opportunities across our acreage in the Delaware Basin will offerthat have multi-zone development potential, Devon has a robust platform to deliver high-margin growth for many years to come. At December 31, 2016,2019, we had threeeight operated rigs.rigs developing this asset. In 2017,2020, we plan to invest approximately $700 million$1.0 billion of capital in the Delaware Basin, and steadily ramp up activity with as many as 10 operated rigs running bymaking it the end of the year, primarily focused on the Bone Spring, Leonard and Wolfcamp formations.
Eagle Ford – We acquired our positiontop-funded asset in the Eagle Ford in 2014 from GeoSouthern and have approximately 66,000 net acres located in DeWitt and Lavaca counties in south Texas. Since acquiring these assets, we have delivered tremendous results by producing 94 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. With the highest margins in our portfolio, our Eagle Ford assets generated approximately $550 million of direct cash margin in 2016. In 2017, we plan approximately $175 million of capital investment.
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Heavy Oil – Our operations in Canada are focused on our heavy oil assets in Alberta, Canada. Our most significant Canadian operation is our Jackfish complex, an industry-leading thermal heavy oil operation in the non-conventional oil sands of east central Alberta. We employ a recovery method known as steam-assisted gravity drainage at Jackfish. The Jackfish operation consists of three facilities. In 2014, we brought the third phase of Jackfish into operation, which ramped up to facility capacity bythe third quarter of 2015. At $55/Bbl WTI, direct cash margin from our Heavy Oil assets has the potential to approach $800 million in 2017. We expect Jackfish to maintain a reasonably flat production profile for greater than 20 years requiring only approximately $200 million of annual maintenance capital based on current economic conditions.
Our Pike oil sands acreage is situated directly to the southeast of our Jackfish acreage in east central Alberta and has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2016. With our 50% partner, we continue to evaluate our development timeline for Pike.
In addition to Jackfish and Pike, we hold acreage and own producing assets in the Bonnyville region, located to the south and east of Jackfish in eastern Alberta. Bonnyville is a low-risk, high margin oil development play that produces heavy oil by conventional means, without the need for steam injection.
In 2017, we plan approximately $300 million of capital investment in our Canadian Heavy Oil business.
Rockies Oil – Our acreage in the Rockies includes approximately 470,000 net surface acres, focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. Recent drilling success in these formations has expanded our drilling inventory, and we expect further growth as we continue to de-risk this emerging light-oil opportunity. As of December 31, 2016, we had one operated rig targeting the Parkman, Teapot and Turner formations within the Cretaceous oil objectives of the Powder River Basin. In 2017, we plan approximately $175 million of capital investment.portfolio.
STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top-two franchise assets. Devon has two primary fields in the area: the Woodford Shale and the Meramec. In 2016, we increased our acreage in these positions by acquiring 80,000 net acres in the STACK. Our acreage in the play now includes approximately 430,000 net acres.provides long-term optionality through its significant inventory. Our STACK position is the largest and one of the bestlargest in the industry, providing visible long-term growth. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Earlyproduction. In December 2019, we announced an agreement with Dow to jointly develop a portion of our STACK acreage. Dow will fund approximately 65% of the partnership capital requirements through a drilling activitycarry of $100 million over the next four years. In 2020, we plan approximately $75 million of capital investment.
Powder River Basin – This asset is focused on emerging oil opportunities in the Meramec playPowder River Basin. Recent drilling success in this basin has produced record setting results acrossexpanded our coredrilling inventory, and we expect further growth as we accelerate activity and continue to de-risk this emerging light-oil opportunity. As of December 31, 2019, we had three operated rigs targeting the Turner, Parkman, Teapot and Niobrara formations in northern Converse County, Wyoming of the Powder River Basin. In 2020, we plan approximately $350 million of capital investment.
Eagle Ford – We acquired our position in the Eagle Ford in 2014. Since acquiring these assets, we have delivered tremendous results driven by our development in DeWitt County, Texas located in the economic core of the play. Our Eagle Ford production is leveraged to oil and liquids window. At December 31, 2016, we had six operated rigs with drilling focusedhas low-cost access to premium Gulf Coast pricing, providing for solid operating margins. Our Eagle Ford assets generated substantial cash flow in the Meramec formation.2019. In 2017,2020, we plan approximately $750$300 million of capital investment and expect to continue to increase drilling activity throughout 2017 and run up to 10 operated rigs by the end of the year.investment.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 22 in “Item 8. Financial Statements and Supplementary Data” of this report.
Proved oil and gas reserves are those quantities of oil, gas and NGLs which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report.
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with theapplicable SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group
10
(the (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards.
The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates. The Group reports 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 Director of the Group has approximatelyover 30 years of industry experience, with positions of increasing responsibility for the estimation and evaluation of reserves. He has been employed by Devon for the past 16 years, including the past nine in his current position. His further professional qualifications include a degree in petroleum engineering and is a registered professional engineer, member of the Society of Petroleum Engineers and experience in reserves estimation for projects in the U.S. (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America.
Throughout the year, the Group performs internal reserves audits of each operating division’s reserves.engineer. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2016,2019, we engaged two such firms to audit 89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited 86%to audit approximately 85% of our 2016 U.S. reserves, and Deloitte LLP audited 96% of our Canadianproved reserves.
In addition to conducting these internal and external reserves audits, Additionally, we also have a Reserves Committee that provides additional oversight of our reserves process. The committee consists of threefive independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The members of our Reserves Committee also have educationalDirectors with education or business backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process. The Reserves Committee meets a minimum
8
The following tables present production, price and cost information for each significant field, country and continent.field.
|
| Production |
| |||||||||||||||||
Year Ended December 31, |
| Oil (MMBbls) |
|
| Bitumen (MMBbls) |
|
| Gas (Bcf) |
|
| NGLs (MMBbls) |
|
| Total (MMBoe) |
| |||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 265 |
|
|
| 15 |
|
|
| 60 |
|
Jackfish |
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
U.S. |
|
| 47 |
|
|
| — |
|
|
| 510 |
|
|
| 42 |
|
|
| 174 |
|
Canada |
|
| 8 |
|
|
| 40 |
|
|
| 7 |
|
|
| — |
|
|
| 49 |
|
Total North America |
|
| 55 |
|
|
| 40 |
|
|
| 517 |
|
|
| 42 |
|
|
| 223 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 291 |
|
|
| 17 |
|
|
| 66 |
|
Jackfish |
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| — |
|
|
| 31 |
|
U.S. |
|
| 60 |
|
|
| — |
|
|
| 579 |
|
|
| 50 |
|
|
| 206 |
|
Canada |
|
| 10 |
|
|
| 31 |
|
|
| 8 |
|
|
| — |
|
|
| 42 |
|
Total North America |
|
| 70 |
|
|
| 31 |
|
|
| 587 |
|
|
| 50 |
|
|
| 248 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 1 |
|
|
| — |
|
|
| 332 |
|
|
| 20 |
|
|
| 76 |
|
Jackfish |
|
| — |
|
|
| 20 |
|
|
| — |
|
|
| — |
|
|
| 20 |
|
U.S. |
|
| 48 |
|
|
| — |
|
|
| 660 |
|
|
| 50 |
|
|
| 207 |
|
Canada |
|
| 10 |
|
|
| 20 |
|
|
| 41 |
|
|
| 1 |
|
|
| 39 |
|
Total North America |
|
| 58 |
|
|
| 20 |
|
|
| 701 |
|
|
| 51 |
|
|
| 246 |
|
|
| Production |
| |||||||||||||
Year Ended December 31, |
| Oil (MMBbls) |
|
| Gas (Bcf) |
|
| NGLs (MMBbls) |
|
| Total (MMBoe) |
| ||||
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
|
| 11 |
|
|
| 114 |
|
|
| 13 |
|
|
| 43 |
|
Delaware Basin |
|
| 26 |
|
|
| 65 |
|
|
| 10 |
|
|
| 46 |
|
U.S. |
|
| 55 |
|
|
| 219 |
|
|
| 28 |
|
|
| 119 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
|
| 12 |
|
|
| 121 |
|
|
| 14 |
|
|
| 45 |
|
Delaware Basin |
|
| 16 |
|
|
| 42 |
|
|
| 6 |
|
|
| 30 |
|
U.S. |
|
| 47 |
|
|
| 206 |
|
|
| 26 |
|
|
| 108 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
|
| 9 |
|
|
| 107 |
|
|
| 11 |
|
|
| 38 |
|
Delaware Basin |
|
| 12 |
|
|
| 37 |
|
|
| 4 |
|
|
| 23 |
|
U.S. |
|
| 42 |
|
|
| 189 |
|
|
| 21 |
|
|
| 95 |
|
11
|
| Average Sales Price |
|
|
|
|
| |||||||||||||
Year Ended December 31, |
| Oil (Per Bbl) |
|
| Bitumen (Per Bbl) |
|
| Gas (Per Mcf) |
|
| NGLs (Per Bbl) |
|
| Production Cost (Per Boe) (1) |
| |||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 41.03 |
|
| $ | — |
|
| $ | 1.76 |
|
| $ | 10.31 |
|
| $ | 6.16 |
|
Jackfish |
| $ | — |
|
| $ | 19.82 |
|
| $ | — |
|
| $ | — |
|
| $ | 8.70 |
|
U.S. |
| $ | 38.92 |
|
| $ | — |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 6.44 |
|
Canada |
| $ | 23.96 |
|
| $ | 19.82 |
|
|
| N/M |
|
| $ | — |
|
| $ | 9.36 |
|
Total North America |
| $ | 36.72 |
|
| $ | 19.82 |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 7.08 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 46.47 |
|
| $ | — |
|
| $ | 2.00 |
|
| $ | 9.62 |
|
| $ | 6.02 |
|
Jackfish |
| $ | — |
|
| $ | 23.41 |
|
| $ | — |
|
| $ | — |
|
| $ | 12.43 |
|
U.S. |
| $ | 44.01 |
|
| $ | — |
|
| $ | 2.17 |
|
| $ | 9.32 |
|
| $ | 7.52 |
|
Canada |
| $ | 30.58 |
|
| $ | 23.41 |
|
|
| N/M |
|
| $ | — |
|
| $ | 13.18 |
|
Total North America |
| $ | 42.12 |
|
| $ | 23.41 |
|
| $ | 2.14 |
|
| $ | 9.32 |
|
| $ | 8.48 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 95.51 |
|
| $ | — |
|
| $ | 3.78 |
|
| $ | 21.98 |
|
| $ | 5.25 |
|
Jackfish |
| $ | — |
|
| $ | 55.88 |
|
| $ | — |
|
| $ | — |
|
| $ | 20.59 |
|
U.S. |
| $ | 85.64 |
|
| $ | — |
|
| $ | 3.92 |
|
| $ | 24.46 |
|
| $ | 7.52 |
|
Canada |
| $ | 68.14 |
|
| $ | 55.88 |
|
| $ | 3.64 |
|
| $ | 50.52 |
|
| $ | 20.10 |
|
Total North America |
| $ | 82.47 |
|
| $ | 55.88 |
|
| $ | 3.90 |
|
| $ | 24.89 |
|
| $ | 9.49 |
|
|
| Average Sales Price (1) |
|
|
|
|
| |||||||||
Year Ended December 31, |
| Oil (Per Bbl) |
|
| Gas (Per Mcf) |
|
| NGLs (Per Bbl) |
|
| Production Cost (Per Boe) (1)(2) |
| ||||
2019 (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
| $ | 55.13 |
|
| $ | 1.97 |
|
| $ | 15.90 |
|
| $ | 7.36 |
|
Delaware Basin |
| $ | 54.01 |
|
| $ | 0.99 |
|
| $ | 13.54 |
|
| $ | 6.43 |
|
U.S. |
| $ | 54.73 |
|
| $ | 1.79 |
|
| $ | 15.21 |
|
| $ | 7.75 |
|
2018 (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
| $ | 63.81 |
|
| $ | 2.29 |
|
| $ | 25.53 |
|
| $ | 7.16 |
|
Delaware Basin |
| $ | 57.24 |
|
| $ | 1.80 |
|
| $ | 24.05 |
|
| $ | 8.15 |
|
U.S. |
| $ | 61.96 |
|
| $ | 2.34 |
|
| $ | 25.47 |
|
| $ | 8.22 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
| $ | 48.43 |
|
| $ | 2.40 |
|
| $ | 17.78 |
|
| $ | 4.72 |
|
Delaware Basin |
| $ | 48.38 |
|
| $ | 2.43 |
|
| $ | 16.44 |
|
| $ | 8.19 |
|
U.S. |
| $ | 49.41 |
|
| $ | 2.57 |
|
| $ | 16.74 |
|
| $ | 6.49 |
|
(1) | As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, starting in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation, which resulted in an increase to our upstream revenues and production expenses with no impact to net earnings. These changes primarily related to our STACK properties. |
(2) | Represents |
Drilling Statistics
The following table summarizes our development and exploratory drilling results.results in the U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Development Wells (1) |
|
| Exploratory Wells (1) |
|
| Total Wells (1) |
| |||||||||||||||||||
Year Ended December 31, |
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Total |
| |||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 88.5 |
|
|
| — |
|
|
| 36.4 |
|
|
| 2.0 |
|
|
| 124.9 |
|
|
| 2.0 |
|
|
| 126.9 |
|
Canada |
|
| 21.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 21.5 |
|
|
| — |
|
|
| 21.5 |
|
Total North America |
|
| 110.0 |
|
|
| — |
|
|
| 36.4 |
|
|
| 2.0 |
|
|
| 146.4 |
|
|
| 2.0 |
|
|
| 148.4 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 298.6 |
|
|
| 1.8 |
|
|
| 40.7 |
|
|
| — |
|
|
| 339.3 |
|
|
| 1.8 |
|
|
| 341.1 |
|
Canada |
|
| 79.0 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 79.0 |
|
|
| — |
|
|
| 79.0 |
|
Total North America |
|
| 377.6 |
|
|
| 1.8 |
|
|
| 40.7 |
|
|
| — |
|
|
| 418.3 |
|
|
| 1.8 |
|
|
| 420.1 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 474.4 |
|
|
| 0.4 |
|
|
| 5.0 |
|
|
| 1.2 |
|
|
| 479.4 |
|
|
| 1.6 |
|
|
| 481.0 |
|
Canada |
|
| 190.8 |
|
|
| 1.0 |
|
|
| — |
|
|
| 0.5 |
|
|
| 190.8 |
|
|
| 1.5 |
|
|
| 192.3 |
|
Total North America |
|
| 665.2 |
|
|
| 1.4 |
|
|
| 5.0 |
|
|
| 1.7 |
|
|
| 670.2 |
|
|
| 3.1 |
|
|
| 673.3 |
|
|
| Development Wells (1) |
|
| Exploratory Wells (1) |
|
| Total Wells (1) |
| |||||||||||||||||||
Year Ended December 31, |
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Total |
| |||||||
2019 |
|
| 161.7 |
|
|
| — |
|
|
| 27.2 |
|
|
| — |
|
|
| 188.9 |
|
|
| — |
|
|
| 188.9 |
|
2018 |
|
| 154.9 |
|
|
| 3.1 |
|
|
| 69.4 |
|
|
| — |
|
|
| 224.3 |
|
|
| 3.1 |
|
|
| 227.4 |
|
2017 |
|
| 145.8 |
|
|
| — |
|
|
| 44.0 |
|
|
| — |
|
|
| 189.8 |
|
|
| — |
|
|
| 189.8 |
|
(1) |
|
129
The following table presents theAs of December 31, 2019, there were 132 gross and 95.3 net wells that werehave been spud and are in progressthe process of drilling, completing or waiting on December 31, 2016. Ascompletion. Gross wells are the sum of February 1, 2017, theseall wells were still in progress.which we own a working interest. Net wells are gross wells multiplied by our fractional working interests in each well.
|
| Gross (1) |
|
| Net (2) |
| ||
U.S. |
|
| 42.0 |
|
|
| 14.5 |
|
Canada |
|
| 10.0 |
|
|
| 10.0 |
|
Total North America |
|
| 52.0 |
|
|
| 24.5 |
|
|
|
|
|
Productive Wells
The following table sets forth our producing wells as of December 31, 2016.
2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil Wells (1) |
|
| Natural Gas Wells |
|
| Total Wells (1) |
| |||||||||||||||
|
| Gross (2)(4) |
|
| Net (3) |
|
| Gross (2)(4) |
|
| Net (3) |
|
| Gross (2)(4) |
|
| Net (3) |
| ||||||
U.S. |
|
| 9,710 |
|
|
| 3,499 |
|
|
| 10,061 |
|
|
| 7,577 |
|
|
| 19,771 |
|
|
| 11,076 |
|
Canada |
|
| 3,239 |
|
|
| 3,138 |
|
|
| 644 |
|
|
| 456 |
|
|
| 3,883 |
|
|
| 3,594 |
|
Total North America |
|
| 12,949 |
|
|
| 6,637 |
|
|
| 10,705 |
|
|
| 8,033 |
|
|
| 23,654 |
|
|
| 14,670 |
|
|
| Oil Wells |
|
| Natural Gas Wells |
|
| Total Wells |
| |||||||||||||||
|
| Gross (1)(3) |
|
| Net (2) |
|
| Gross (1)(3) |
|
| Net (2) |
|
| Gross (1)(3) |
|
| Net (2) |
| ||||||
U.S. |
|
| 7,739 |
|
|
| 2,376 |
|
|
| 3,138 |
|
|
| 1,281 |
|
|
| 10,877 |
|
|
| 3,657 |
|
(1) |
|
| Gross wells are the sum of all wells in which we own a working interest. |
| Net wells are gross wells multiplied by our fractional working interests in each well. |
| Includes |
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. We are the operator of approximately 15,2003,955 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and drillingconstruction 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.
13
The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2016.2019. Of our 4.61.8 million net acres, approximately 2.41.1 million acres are held by production.production and approximately 20% are located on federal lands. The acreage in the table includes 0.3 million, 0.2 million andapproximately 0.1 million net acres subject to leases that are scheduled to expire during 2017, 20182020, 2021 and 2019, respectively.2022. As of December 31, 2016,2019, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.60.1 million net acres set to expire by December 31, 2019,2022, we will performanticipate performing operational and administrative actions to continue the lease terms for portions of the acreage that we intend to further assess. However, we do expect to allow a portion of the acreage to expire in the normal course of business. In 2016,2019, we allowed approximately 0.30.1 million acres to expire, which is consistent with expirations in prior years.
expire.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Developed |
|
| Undeveloped |
|
| Total |
| |||||||||||||||
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
| ||||||
|
| (Thousands) |
| |||||||||||||||||||||
U.S. |
|
| 1,800 |
|
|
| 1,218 |
|
|
| 4,138 |
|
|
| 1,917 |
|
|
| 5,938 |
|
|
| 3,135 |
|
Canada |
|
| 695 |
|
|
| 512 |
|
|
| 2,075 |
|
|
| 953 |
|
|
| 2,770 |
|
|
| 1,465 |
|
Total North America |
|
| 2,495 |
|
|
| 1,730 |
|
|
| 6,213 |
|
|
| 2,870 |
|
|
| 8,708 |
|
|
| 4,600 |
|
|
| Developed |
|
| Undeveloped |
|
| Total |
| |||||||||||||||
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
| ||||||
|
| (Thousands) |
| |||||||||||||||||||||
U.S. |
|
| 1,055 |
|
|
| 576 |
|
|
| 2,956 |
|
|
| 1,272 |
|
|
| 4,011 |
|
|
| 1,848 |
|
(1) | Gross acres are the sum of all acres in which we own a working interest. |
(2) | Net acres are gross acres multiplied by our fractional working interests in the acreage. |
Title to Properties
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry, other than a preliminary title investigation, typically consisting of a review of local title records, little investigation of record title is made at the time of acquisitions of undeveloped properties. TitleMore thorough title investigations, which generally include a review of title records and the preparation of title opinions ofby outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
EnLink 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 transmission pipelines with a capacity of approximately 920 MMcf/d, processing facilities with a total processing capacity of approximately 1.6 Bcf/d and gathering systems with total capacity of approximately 2.3 Bcf/d.
Oklahoma – The Oklahoma assets consist of processing facilities with a total processing capacity of approximately 795 MMcf/d and gathering systems with total capacity of approximately 810 MMcf/d.
Louisiana – The Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.9 Bcf/d, gathering systems with total capacity of approximately 510 MMcf/d, 720 miles of liquids transport lines and four fractionation assets with total fractionation capacity of 175 MBbls/d.
Crude and Condensate – The Crude and Condensate assets consist of approximately 540 miles of crude oil and condensate pipelines with total capacity of approximately 116 MBbls/d, 900 MBbls of above ground storage and eight condensate stabilization and natural gas compression stations with combined capacities of approximately 36 MBbls/d of condensate stabilization and 780 MMcf/d of natural gas compression.
1410
Oil, Gas and NGL Marketing
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.
Additionally, we may enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2017,2020, our production was sold under the following contract terms.
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| Short-Term |
|
| Long-Term |
|
| Short-Term |
|
| Long-Term |
| ||||||||||||||||||||
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
| ||||||||
Oil and bitumen |
|
| 65 | % |
|
| — |
|
|
| 35 | % |
|
| — |
| ||||||||||||||||
Oil |
|
| 64 | % |
|
| — |
|
|
| 36 | % |
|
| — |
| ||||||||||||||||
Natural gas |
|
| 54 | % |
|
| 4 | % |
|
| 42 | % |
|
| — |
|
|
| 64 | % |
|
| 3 | % |
|
| 33 | % |
|
| — |
|
NGLs |
|
| 53 | % |
|
| 17 | % |
|
| 30 | % |
|
| — |
|
|
| 38 | % |
|
| 28 | % |
|
| 34 | % |
|
| — |
|
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, 2016,2019, we were committed to deliver the following fixed quantities of production.
|
| Total |
|
| Less Than 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
|
| Total |
|
| Less Than 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
|
| More Than 5 Years |
| |||||||||
Oil and bitumen (MMBbls) |
|
| 112 |
|
|
| 36 |
|
|
| 48 |
|
|
| 28 |
| ||||||||||||||||||||
Natural gas (Bcf) |
|
| 487 |
|
|
| 338 |
|
|
| 149 |
|
|
| — |
|
|
| 273 |
|
|
| 128 |
|
|
| 94 |
|
|
| 37 |
|
|
| 14 |
|
NGLs (MMBbls) |
|
| 9 |
|
|
| 9 |
|
|
| — |
|
|
| — |
|
|
| 8 |
|
|
| 8 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total (MMBoe) |
|
| 202 |
|
|
| 101 |
|
|
| 73 |
|
|
| 28 |
|
|
| 53 |
|
|
| 29 |
|
|
| 16 |
|
|
| 6 |
|
|
| 2 |
|
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.
Customers
During 2016, 20152019 and 2014,2017, no purchaser accounted for over 10% of our consolidated sales revenue.
During 2018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.
Competition
See “Item 1A. Risk Factors.”
11
Public Policy and Government Regulation
Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting our industry have been pervasive and are under constant review for amendment or
15
expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. The following are significant areas of government control and regulation affecting our operations.
Exploration and Production Regulation
Our operations are subject to federal, tribal, state provincial and local laws and regulations. These laws and regulations relate to matters that include:
acquisition of seismic data;
• | acquisition of seismic data; |
location, drilling and casing of wells;
• | location, drilling and casing of wells; |
well design;
• | well design; |
hydraulic fracturing;
• | hydraulic fracturing; |
well production;
• | well production; |
spill prevention plans;
• | spill prevention plans; |
emissions and discharge permitting;
• | emissions and discharge permitting; |
use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
• | 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;
• | surface usage and the restoration of properties upon which wells have been drilled; |
calculation and disbursement of royalty payments and production taxes;
• | calculation and disbursement of royalty payments and production taxes; |
plugging and abandoning of wells;
• | plugging and abandoning of wells; |
transportation of production; and
• | transportation of production; and |
endangered species and habitat.
• | 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., some states allow the forced pooling or integrationunitization of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the BLM or Bureau of Indian Affairs of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has, been particularly active in recent years in 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 arecan sometimes be subject to frequent delays.
1612
Royalties 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 for wells drilled after January 1, 2017 in the Modernized Royalty Framework, the calculation is based on a percentage of production net of allowed deductions.
Marketing in Canada
Any oil or gas export requires an exporter to obtain export authorizations from Canada’s National Energy Board.
Environmental, Pipeline Safety and Occupational Regulations
We strive to conduct our operations in a socially and environmentally responsible manner, which includes compliance with applicable law. We are subject to many federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment.environment and natural resources. Environmental laws and regulations relate to:
the discharge of pollutants into federal, provincial and state waters;
• | the discharge of pollutants into federal and state waters; |
assessing the environmental impact of seismic acquisition, drilling or construction activities;
• | assessing the environmental impact of seismic acquisition, drilling or construction activities; |
the generation, storage, transportation and disposal of waste materials, including hazardous substances;
• | the generation, storage, transportation and disposal of waste materials, including hazardous substances; |
the emission of certain gases into the atmosphere;
• | the emission of certain gases into the atmosphere; |
the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;
• | the 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 development of emergency response and spill contingency plans; |
the monitoring, repair and design of pipelines used for the transportation of oil and natural gas; and
• | 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.
• | 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 ofBLM, for allegedly failing to comply with environmental laws, which can result in delays in obtaining permits or other necessary authorizations. Environmental protection and health and safety and health compliance are necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
Our business and operations, and our industry in general, are subject to a variety of risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business, financial condition, results of operations and liquidity could be materially and adversely impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
17
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, duringover the period from January 1, 2014 to December 31, 2016,last five years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from a highhighs of $107.26over $75 per Bbl to a low of $26.21 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15and $4.80 per MMBtu, respectively, to a lowlows of $1.64under $27 per Bbl and $1.70 per MMBtu, during the same period.respectively. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:
• | the domestic and worldwide supply of and demand for oil, gas and NGLs; |
• | volatility and trading patterns in the commodity-futures markets; |
• | conservation and environmental protection efforts; |
• | production levels of members of OPEC, Russia, the U.S. or other producing countries; |
• | geopolitical risks, including political and civil unrest in the Middle East, Africa and South America; |
supply13
• | adverse weather conditions, natural disasters, public health crises and other catastrophic events, such as tornadoes, earthquakes, hurricanes and epidemics of infectious diseases; |
volatility and trading patterns in the commodity-futures markets;
• | regional pricing differentials, including in the Delaware Basin and other areas of our operations; |
conservation and environmental protection efforts;
• | differing quality of production, including NGL content of gas produced; |
production levels of members of OPEC, Russia or other producing countries;
• | the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories; |
geopolitical risks, including political and civil unrest in the Middle East and Africa;
• | the price and availability of alternative energy sources; |
adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes;
• | technological advances affecting energy consumption and production, including with respect to electric vehicles; |
regional pricing differentials;
• | stockholder activism or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas in order to reduce greenhouse gas emissions; |
differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);
• | the overall economic environment; |
differing quality and NGL content of gas produced;
• | changes in trade relations and policies, including the imposition of tariffs by the U.S. or China; and |
the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories;
the price and availability of alternative fuels;
technological advances affecting energy consumption;
the overall economic environment; and
governmental regulations and taxes.
In the second half of 2014, global energy commodity prices began a rapid and significant decline, which continued through 2015 and into 2016. This commodity price decline adversely affected our business and results of operations and led to substantial impairments to our oil and gas properties during 2015 and 2016. A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:
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; and
reducing the carrying value of our properties, resulting in additional noncash write-downs.
• | other governmental regulations and taxes. |
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
18
given reservoir may change substantially over time as a result of several factors, including additional development and appraisal activity, the viability of production under varying economic conditions, including commodity price declines, and variations in production levels and associated costs. Consequently, material revisions to existing reservereserves estimates may occur as a result of changes in any of these 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.
Discoveries or Acquisitions of Reserves Are Needed to Avoid a Material Decline in Reserves and Production
The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Moreover, our current development activity is focused on unconventional oil and gas assets, which generally have significantly higher decline rates as compared to conventional assets. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities, such as identifying additional producing zones in existing wells, utilizing secondary or tertiary recovery techniques or acquiring additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
Future Exploration and Drilling Results14
Our Operations Are Uncertain and Involve Substantial Costs and Risks
Our exploration and developmentoperating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can become damaged, our drilling operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
• | unexpected drilling conditions, pressure conditions or irregularities in reservoir formations; |
equipment failures or accidents;
• | equipment failures or accidents; |
fires, explosions, blowouts and surface cratering;
• | fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals; |
adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes;
• | adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures; |
issues with title or in receiving governmental permits or approvals;
• | issues with title or in receiving governmental permits or approvals; |
lack of access to pipelines or other transportation methods;
• | restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets; |
environmental hazards or liabilities;
• | environmental hazards or liabilities; |
restrictions in access to, or disposal of, water used or produced in drilling and completion operations; and
• | 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.
• | shortages or delays in the availability of services or delivery of equipment. |
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, andas well as significant liabilities. Moreover, certain of these events particularly equipment failures or accidents, could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property damage.and natural resources. For example, we have from time to time experienced well-control events that have resulted in various remediation and clean-up costs and certain of the other impacts described above.
19
TableIn addition, we rely on our employees, consultants and sub-contractors to conduct our operations in compliance with applicable laws and standards. Any violation of Contentssuch laws or standards by these individuals, whether through negligence, harassment, discrimination or other misconduct, could result in significant liability for us and adversely affect our business. For example, negligent operations by employees could result in serious injury, death or property damage, and sexual harassment or racial and gender discrimination could result in legal claims and reputational harm.
We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact Our Business
Our operations are subject to extensive federal, state, provincial, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations.operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, whichincluding corporate successors of former operators. These requirements may result in significant costs associated with the removal of tangible equipment and other restorative actions at the end of operations.actions.
In addition, changes in public policy have affected, and at times in the future could further affect, our operations. Regulatory and public policy developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements and increase taxes, royalties and other amounts payable to governments or governmental agencies. Our operating and
15
other compliance costs could increase further if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. In addition, changes in public policy may indirectly impact our operations by, among other things, increasing the cost of supplies and equipment and fostering general economic uncertainty. For example, changes in U.S. trade relations, particularly the imposition of tariffs by the U.S. and China, may increase the cost of materials we or our vendors use, thereby increasing our operating expense. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, pipeline safety,environmental matters more generally, seismic activity and income taxes, and climate change, as discussed below.
Hydraulic Fracturing – The EPA and otherIn recent years, various federal agencies includinghave asserted regulatory authority over certain aspects of the BLM, have made proposals that would subject hydraulic fracturing to further regulation and could restrict the practice of hydraulic fracturing.process. For example, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and it finalized in June 2016 regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a studyreport in December 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The BLM andpreviously finalized regulations to regulate hydraulic fracturing on federal lands but subsequently issued a repeal of those regulations in 2017. Moreover, several states in which we operate have already adopted, and more states are considering 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.operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition some states and municipalities have significantly limitedto state laws, local land use restrictions, such as city ordinances, may restrict drilling activities and/in general or hydraulic fracturing or are considering doing so.in particular.
Beyond these regulatory efforts, various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed implementing even further restrictions on hydraulic fracturing, including prohibiting the technology outright. For example, certain candidates running to be elected President of the United States in 2020 have pledged to impose a ban on hydraulic fracturing. It is possible that any such restrictions may particularly target industry activity on federal lands, which could adversely impact our operations in the Delaware and Powder River Basins, as well as other areas where we operate under federal leases. As of December 31, 2019, approximately 20% of our total leasehold resides on federal lands, and approximately 40% and 60% of our leasehold in the Delaware and Powder River Basins, respectively, resides on federal lands. Although it is not possible at this time to predict the final outcome of these or other proposals, any new federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays or cessation in development or other restrictions on our operations.
Pipeline SafetyEnvironmental Laws Generally – The pipeline assets in whichIn addition to regulatory efforts focused on hydraulic fracturing, we own interests, through EnLink or otherwise, are subject to stringentvarious other federal, state and complexlocal laws and regulations relatedrelating to pipeline safetydischarge of materials into, and integrity management. The PHMSA has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For example, in March 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high consequence areas to newly proposed “moderate consequence areas” and would also impose more rigorous testing and reporting requirements on such pipelines. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardlessprotection of, the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirementsenvironment. These laws and regulations may, among other things, impose liability on us for certain unregulated pipelines, including all hazardous liquid gathering lines. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safetyremediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. Any such changes could have a significant penalties.impact on our operations and profitability.
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Seismic Activity – Recent earthquakesEarthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energyoil and gas industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims, seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
Potential Changes to Tax Laws – We are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions, and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. In past years, legislation has been proposed that would, if enacted into law, make significant changes
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Concerns About Climate Change and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oilRelated Regulatory, Social and gas properties, (ii) the elimination of current deductions for intangible drillingMarket Actions May Adversely Affect Our Business
Continuing and development costs, (iii) the elimination of the deduction for certain domestic production activitiesincreasing political and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules andsocial attention to the deductibilityissue of interest expense, may be developed that also wouldclimate change the taxation of oilhas resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Climate Change – Policy makers in the U.S. and Canada are increasingly focusing on whether the emissions, of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes.methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions.gases. For example, both the EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry. LegislativeFollowing the change in presidential administrations, however, the agencies have attempted to revise or rescind their previously issued methane standards. Litigation concerning these methane regulations and state initiativessubsequent attempts to daterevise or rescind them is ongoing. Nevertheless, several states where we operate, including Wyoming and New Mexico, have generally focused onalready imposed, or stated intentions to impose, laws or regulations designed to reduce methane emissions from oil and gas exploration and production activities. With respect to more comprehensive regulation, policy makers and political candidates have made, or expressed support for, a variety of proposals, such as the development of cap-and-trade and/or carbon tax programs. Aprograms, as well as the more sweeping “green new deal” resolutions introduced in Congress in early 2019. As generally proposed, a cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Carbonallowances, while a carbon tax could impose taxes could likewise affect us by being based on emissions from our equipment and/oroperations and downstream uses of our products. The “green new deal” resolutions call for a 10-year national mobilization effort to, among other things, transition 100% of power demand in the U.S. to zero-emission sources and overhaul transportation systems in the U.S. to remove greenhouse gas emissions as much as is technologically feasible.
In addition to regulatory risk, other market and social initiatives resulting from the changing perception of climate change present risks for our business. For example, in an effort to promote a lower-carbon economy, there are various public and private initiatives subsidizing the development and adoption of alternative energy sources and technologies, including by mandating the use of our products by our customers. Although it is not possible at this timespecific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, certain financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impacttheir concern regarding climate change. Such restrictions in capital could decrease the value of our business any such future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require usmake it more difficult to incur costs to reduce emissions of greenhouse gases associated withfund our operations. Limitations on greenhouse gas emissions could also adversely affect demand forFinally, governmental entities and other plaintiffs have brought, and may continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged effects of climate change. These and the other regulatory, social and market risks relating to climate change described above could result in unexpected costs, increase our operating expense and reduce the demand for our products, which in turn could lower the value of our reserves and have a materialan adverse effect on our profitability, financial condition and liquidity.
In 2015, Alberta released a new Climate Leadership Plan. This plan includes implementing an economy-wide carbon price effective in 2017. The plan also includes a legislated limit for oil sands emissions and a methane emission reduction plan which are under development. Regulations are expected to be finalized by 2018. It is expected that these initiatives will create additional costs for the Alberta oil and gas industry. Presently, it is not possible to accurately estimate the costs we could incur to comply with any law or regulations developed.
Our Hedging Activities Limit Participation in Commodity Price Increases and Involve Other Risks
We enter into hedging activitiesfinancial 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
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commodity price declines, we maywill be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts. Moreover, as a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and other legislation and regulation, hedging transactions and many of our contract counterparties have come under increasingbecome subject to increased governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost and availability of our hedging arrangements, including by causing our contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.arrangements.
The Credit Risk of Our Counterparties Could Adversely Affect Us
We enter into a variety of transactions that expose us to counterparty credit risk. For example, we have exposure to financial institutions and insurance companies through our hedging arrangements, our syndicated revolving credit facility and our insurance policies. Disruptions in the financial markets or otherwise may impact these counterparties and affect their ability to fulfill their existing obligations and their willingness to enter into future transactions with us.
In addition, we are exposed to the risk of financial loss from trade, joint interest billing and other receivables. We sell our oil, gas and NGLs to a variety of purchasers, and, as an operator, we pay expenses and bill our non-operating partners for their respective sharesshare of costs. We also frequently look to buyers of oil and gas properties from us or our predecessors to perform certain obligations associated with the disposed assets, including the removal of production facilities and plugging and abandonment of wells. Certain of these counterparties or their successors may experience insolvency, liquidity problems or other issues and may not be able to meet their financial obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or volatile commodity price environment. Any such default by these counterpartiesmay result in us being forced to cover the costs of those obligations and liabilities, which could adversely impact our financial results.results and condition.
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Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us
As of December 31, 2016,2019, we had total consolidated indebtedness of $10.2$4.3 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:
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;
• | requiring us to dedicate a portion of our cash flows from operations to debt service payments, thereby limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other general corporate purposes; |
increasing our vulnerability to general adverse economic and industry conditions, including low commodity price environments; and
• | 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.
• | limiting our ability to obtain additional financing due to higher costs and more restrictive covenants. |
In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that may impact our credit ratings include, among others, debt levels, planned assetsasset sales and purchases, liquidity, forecasted production growth and commodity prices. During 2016, Standard & Poor’s Financial Services and Moody’s Investor Service downgraded our senior unsecured debt ratings. Due to our current credit ratings, weWe are currently required to provide letters of credit or other assurances under certain of our contractual arrangements. FurtherAny 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 Significant
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment.
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These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. Changes in or additions to public policy regarding the protection of the environment could have a significant impact on our operations and profitability.
Cyber Attacks Targeting Our Systems and Infrastructure May Adversely Impact Our Operations
Our industrybusiness has become increasingly dependent on digital technologies, and we anticipate expanding the use of technology in our operations, including through artificial intelligence, process automation and data analytics. Concurrent with this growing dependence on technology is greater sensitivity to conduct daily operations. Concurrently, the industry has become the subject of increased levels of cyber-attack activity.cyber attack related activities, which have frequently targeted our industry. Cyber attacksattackers often attempt to gain unauthorized access to digital systems for purposes of misappropriating assetssensitive information, intellectual property or sensitive information,financial assets, corrupting data or causing operational disruptiondisruptions as well as to prevent users from accessing systems or information and demand payment in order to regain access. These attacks may be carried outperpetrated by third parties or insiders. The techniques utilizedTechniques used in these attacks often range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be carried outperformed in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, our vendors, midstream providers and other business partners may separately suffer disruptions or breaches from cyber attacks, which, in turn, could adversely impact our operations and compromise our information. Although we have not suffered material losses related to cyber attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences.consequences, including litigation risks. Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.
We Have Limited Control onOver Properties Operated by Others
Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, including compliance with environmental, health and safety regulations or the amount and timing of required future capital expenditures. These limitations and our dependence on the operator and other working interest owners for these properties could result in unexpected future costs and delays, curtailments or cancellations of operations or future development, which could adversely affect our financial condition and results of operations.
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Midstream Capacity Constraints and Interruptions Impact Commodity Sales
We rely on midstream facilities and systems owned and operated by others to process our gas production and to transport our oil, gas and NGL production to downstream markets. Such midstream systems include EnLink’s systems, as well as other systems operated by usAll or third parties. Regardless of who operates the midstream systems we rely upon, a portion of our production in any regionone or more regions may be interrupted or shut in from time to time due to losing access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions and natural disasters, accidents, field labor issues or strikes. Additionally, we and third partiesthe midstream operators may be subject to constraints that limit our or their ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.
Insurance Does Not Cover All Risks
OurAs discussed above, our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development production, processing and transportationproduction of oil, gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to people or loss of life.
To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well
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control, business interruption and pollution events that are considered sudden and accidental. We also maintain workers’ compensation and employer’s liability insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for 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, People and Capital Can Be Significant
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield services, which could adversely affect our ability to execute our development plans on a timely basis and within budget. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our competitors have financial and other resources substantially greater than ours. They alsoours and may have established superior strategic long-term positions and relationships, in areas in which we may seek new entry.including with respect to midstream take-away capacity. As a consequence, we may be at a competitive disadvantage in bidding for assets or services and accessing capital.capital and downstream markets. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuelsenergy sources and the application of government regulations.
Our Business Could Be Adversely Impacted by Investors Attempting to Effect Change
Stockholder activism has been increasing in our industry, and investors may from time to time attempt to effect changes to our business or governance, whether by stockholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our board of directors and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of our business. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in significant fluctuation in the market price of our common stock.
Our Acquisition and Divestiture Activities Involve Substantial Risks
Our business depends, in part, on making acquisitions that complement or expand our current business and successfully integrating any acquired assets or businesses. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
• | mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt; |
• | difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and |
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difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
unknown and unforeseen liabilities or other issues relatedIndex to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.Financial Statements
• | 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.
Item 1B.Unresolved Staff Comments
Not applicable.
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We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.
Certain Environmental Matters
On April 4, 2019, Devon Gas Services,Energy Production Company, L.P., a wholly-owned subsidiary of the Company is currently in(“DEPCO”), agreed to settle its previously disclosed negotiations with the EPA with respectrelating to certain alleged noncompliance with the leak detection and repair requirements of EPA regulations promulgated under the Clean Air Act violations at its Beaver Creek Gas Plant located near Riverton, Wyoming. Although management cannot predictWyoming by executing an agreed order with the outcomeEPA. The order included a penalty of settlement negotiations,$150,000 and was approved by the regional EPA judicial officer on June 12, 2019. Moreover, in connection with the resolution of this matter may result in a fine or penalty in excess of $100,000.
In addition, in August 2016, we received an information request fromwith the EPA, under the Clean Air Act relating to our compliance with certain air emission requirements under Clean Air Act regulationsDEPCO entered into a consent decree on May 9, 2019 with respect to various locations in our Eagle Ford operations in south Texas. We responded to this information request in November 2016. Given its early stage and the general uncertainty in matters such as these, we are unable to predictsame matter with the ultimate outcomeWyoming Department of this information request, but it may result in the impositionEnvironmental Quality, which also included a separate penalty of a fine or penalty, through settlement negotiations or otherwise, in excess of $100,000.$150,000.
Item 4.Mine Safety Disclosures
Not applicable.
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Item 5.Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the NYSE.NYSE under the “DVN” ticker symbol. On February 8, 2017,5, 2020, there were 7,8566,771 holders of record of our common stock. We began paying regular quarterly cash dividends on our common stock in the second quarter of 1993. The following table sets forth the quarterly highdeclaration of future dividends is a business decision made by our Board of Directors, and low sales prices forwill depend on Devon’s financial condition and other relevant factors. Additional information on our common stock as reported by the NYSE during 2016dividends can be found in Note 17 in “Item 8. Financial Statements and 2015, as well as the quarterly dividends per share paid during 2016 and 2015.Supplementary Data” of this report.
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| Price Range of Common Stock |
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| Dividends |
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| High |
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| Low |
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| Per Share |
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Quarter Ended 2016: |
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December 31, 2016 |
| $ | 50.66 |
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| $ | 36.64 |
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| $ | 0.06 |
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September 30, 2016 |
| $ | 45.62 |
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| $ | 35.01 |
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| $ | 0.06 |
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June 30, 2016 |
| $ | 39.47 |
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| $ | 25.55 |
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| $ | 0.06 |
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March 31, 2016 |
| $ | 32.93 |
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| $ | 18.07 |
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| $ | 0.24 |
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Quarter Ended 2015: |
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December 31, 2015 |
| $ | 48.68 |
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| $ | 28.00 |
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| $ | 0.24 |
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September 30, 2015 |
| $ | 59.80 |
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| $ | 36.01 |
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| $ | 0.24 |
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June 30, 2015 |
| $ | 70.48 |
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| $ | 58.77 |
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| $ | 0.24 |
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March 31, 2015 |
| $ | 67.08 |
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| $ | 56.35 |
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| $ | 0.24 |
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The following graph compares the cumulative TSR over a five-year period on Devon’s common stock with the cumulative total returns of the S&P 500 Index and a peer group of companies to which we compare our performance. The peer group includes Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, Concho Resources, Inc., ConocoPhillips, Continental Resources, Inc., Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Noble Energy, Inc., Occidental Petroleum Corporation and Pioneer Natural Resources Company. Anadarko Petroleum Corporation was a part of this peer group prior to being acquired by Occidental Petroleum Corporation in 2019. The graph was prepared assuming $100 was invested on December 31, 20112014 in Devon’s common stock, the peer group and the S&P 500 Index, and the peer group, and dividends have been reinvested subsequent to the initial investment. Commencing in 2020, Devon will use a recalibrated peer group for performance and compensation purposes. This new peer group was selected to better align with Devon’s go-forward size and operations in light of our strategic transformation in 2019.
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 is included for historical comparative purposes only and should not be considered indicative of future stock performance.
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Issuer Purchases of Equity Securities
The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2016.
2019 (shares in thousands).
Period |
| Total Number of Shares Purchased (1) |
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| Average Price Paid per Share |
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| Total Number of Shares Purchased (1) |
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| Average Price Paid per Share |
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| Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (2) |
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| Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
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October 1 - October 31 |
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| 25,638 |
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| $ | 43.29 |
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| 4,285 |
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| $ | 21.27 |
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| 4,244 |
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| $ | 199 |
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November 1 - November 30 |
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| 96,822 |
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| $ | 42.15 |
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| 218 |
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| $ | 22.33 |
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| 192 |
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| $ | 195 |
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December 1 - December 31 |
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| 3,778 |
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| $ | 47.30 |
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| 9 |
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| $ | 22.58 |
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| — |
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| $ | 1,000 |
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Total |
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| 126,238 |
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| $ | 42.54 |
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| 4,512 |
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| $ | 21.32 |
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| 4,436 |
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| In addition to shares purchased under the share repurchase program described below, these amounts also included approximately 76,000 shares received by us from employees for the payment of personal income tax withholding on |
(2) | On March 7, 2018, we announced a $1.0 billion share repurchase program. On June 6, 2018, we announced the expansion of this program to $4.0 billion. On February 19, 2019, we announced a further expansion to $5.0 billion with a December 31, 2019 expiration date. Of the $5.0 billion authorized amount, $4.8 billion was repurchased when the program expired on December 31, 2019. On December 17, 2019, we announced a new $1.0 billion share repurchase program with a December 31, 2020 expiration date. Under the new program, $800 million of the $1.0 billion authorization is conditioned upon the closing of the pending Barnett Shale divestiture. During 2019, we repurchased 68.6 million shares of common stock |
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Under the Devon Plan, eligible employees maypreviously had the option to purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 80,60027,000 shares of our common stock in 2016,2019, at then-prevailing stock prices, that they held through their ownership in the Devon Stock Fund. We acquired the shares of our common stock sold under the Devon Planthis plan through open-market purchases.
Similarly, eligible Canadian employees may purchase shares22
Item 6.Selected Financial Data
The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this report.
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| Year Ended December 31, |
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| 2016 |
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| 2015 |
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| 2014 |
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| 2013 |
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| 2012 |
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| (Millions, except per share amounts) |
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Oil, gas and NGL sales |
| $ | 4,182 |
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| $ | 5,382 |
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| $ | 9,910 |
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| $ | 8,522 |
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| $ | 7,153 |
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Total revenues and other (1) |
| $ | 12,197 |
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| $ | 13,145 |
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| $ | 20,638 |
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| $ | 10,388 |
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| $ | 9,514 |
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Earnings (loss) from continuing operations (1) |
| $ | (3,704 | ) |
| $ | (15,203 | ) |
| $ | 1,691 |
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| $ | (20 | ) |
| $ | (185 | ) |
Earnings (loss) from continuing operations attributable to Devon (1) |
| $ | (3,302 | ) |
| $ | (14,454 | ) |
| $ | 1,607 |
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| $ | (20 | ) |
| $ | (185 | ) |
Earnings (loss) from continuing operations per share attributable to Devon – Basic (1) |
| $ | (6.52 | ) |
| $ | (35.55 | ) |
| $ | 3.93 |
|
| $ | (0.06 | ) |
| $ | (0.47 | ) |
Earnings (loss) from continuing operations per share attributable to Devon – Diluted (1) |
| $ | (6.52 | ) |
| $ | (35.55 | ) |
| $ | 3.91 |
|
| $ | (0.06 | ) |
| $ | (0.47 | ) |
Cash dividends per common share |
| $ | 0.42 |
|
| $ | 0.96 |
|
| $ | 0.94 |
|
| $ | 0.86 |
|
| $ | 0.80 |
|
Weighted average common shares outstanding - Basic |
|
| 513 |
|
|
| 412 |
|
|
| 409 |
|
|
| 406 |
|
|
| 404 |
|
Weighted average common shares outstanding - Diluted |
|
| 513 |
|
|
| 412 |
|
|
| 411 |
|
|
| 406 |
|
|
| 404 |
|
Total assets (1) |
| $ | 25,913 |
|
| $ | 29,451 |
|
| $ | 50,568 |
|
| $ | 42,809 |
|
| $ | 43,266 |
|
Long-term debt (2) |
| $ | 10,154 |
|
| $ | 12,056 |
|
| $ | 9,761 |
|
| $ | 7,888 |
|
| $ | 8,395 |
|
Stockholders' equity |
| $ | 10,375 |
|
| $ | 10,989 |
|
| $ | 26,341 |
|
| $ | 20,499 |
|
| $ | 21,278 |
|
|
| 2019 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||||
Statement of Earnings data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream revenues (1) |
| $ | 3,355 |
|
| $ | 4,542 |
|
| $ | 2,988 |
|
| $ | 2,325 |
|
| $ | 4,082 |
|
Total revenues (1) |
| $ | 6,220 |
|
| $ | 8,896 |
|
| $ | 6,501 |
|
| $ | 5,054 |
|
| $ | 7,547 |
|
Net earnings (loss) from continuing operations (2) |
| $ | (79 | ) |
| $ | 714 |
|
| $ | 33 |
|
| $ | (871 | ) |
| $ | (7,989 | ) |
Net earnings (loss) from continuing operations per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic (2) |
| $ | (0.21 | ) |
| $ | 1.43 |
|
| $ | 0.06 |
|
| $ | (1.72 | ) |
| $ | (19.66 | ) |
Diluted (2) |
| $ | (0.21 | ) |
| $ | 1.42 |
|
| $ | 0.06 |
|
| $ | (1.72 | ) |
| $ | (19.66 | ) |
Cash dividends per common share |
| $ | 0.35 |
|
| $ | 0.30 |
|
| $ | 0.24 |
|
| $ | 0.42 |
|
| $ | 0.96 |
|
Balance Sheet data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (3) |
| $ | 13,717 |
|
| $ | 19,566 |
|
| $ | 30,241 |
|
| $ | 28,675 |
|
| $ | 29,673 |
|
Long-term debt (4) |
| $ | 4,294 |
|
| $ | 4,292 |
|
| $ | 5,258 |
|
| $ | 5,359 |
|
| $ | 7,488 |
|
Stockholders' equity |
| $ | 5,920 |
|
| $ | 9,186 |
|
| $ | 14,104 |
|
| $ | 12,722 |
|
| $ | 11,111 |
|
Common shares outstanding |
|
| 382 |
|
|
| 450 |
|
|
| 525 |
|
|
| 523 |
|
|
| 418 |
|
(1) | In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers using the modified retrospective method and has applied the standard to all existing contracts. The impact of adoption is further discussed in Note 1 of “Item 8. Financial Statements and Supplementary Data” of this report. Prior periods have not been restated. |
(2) | Material asset impairments and acquisition and divestiture activity |
|
| Amounts include assets related to our divested Canadian business and |
(4) | Long-term debt balance excludes amounts that were classified as liabilities associated with discontinued operations in the respective periods related to the sale of Devon’s Canadian business and ownership interests in EnLink |
2823
Item 7.Management’s Discussion and AnalysisAnalysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.
Overview of 20162019 Results
By executingDuring 2019, we completed our transformation to a U.S. oil growth company with our exit from Canada and pending sale of the Barnett Shale. These transactions accelerate efforts to focus exclusively on our resource-rich U.S. oil portfolio, which provides us with a strong foundation to grow returns, margin and profitability. By operating under a disciplined returns-driven strategy outlined in “Items 1focused on delivering strong operational results, financial strength and 2. Business and Properties” of this report, we strivevalue to optimize value for our shareholders by growing cash flow, earnings, production and reserves, all on a per debt-adjusted share basis. Despite the challengescontinuing our companycommitment to environmental, social and the entire upstream energy sector have faced from the sustained low commodity price environment,governance excellence, we have continuedcompleted our transformation to execute“New Devon” and made significant progress toward our strategy and position our company for long-term success. Although we have seen moderate improvements in oil and natural gas prices over the course of 2016, prices for oil and natural gas were still significantly lower than 2015 and 2014 and remain under pressure due to excess supply concerns. In response to this environment, we remained committed to an approach centered on:
Maintaining a balanced portfolio of high-class assets with a focus on value and returns,
Accelerating our activity in the STACK and Delaware Basin, and preserving continuity in our other U.S. resource plays,
Driving efficiencies across our portfolio of assets by achieving operating efficiencies and cost savings and increasing capital productivity, and
Protecting and strengthening our investment-grade balance sheet by investing directionally within cash flow and through use of divestiture proceeds.
To that end, in 2016 we:
Expanded our position in the STACK by acquiring approximately 80,000 net acres and assets for $1.5 billion, and increased production in this key resource play by 37% compared to 2015;
Continued the shift to higher-margin products, with oil and bitumen production representing 44% of our retained asset production mix for 2016;
Successfully divested certain non-core upstream assets in the U.S. and our 50% interest in the Access Pipeline in Canada for $3.1 billion;
Reduced exploratory and developmental capital investment by approximately 65% compared to 2015;
Replaced approximately 175% of our retained-asset production through significant reserve additions;
Reduced G&A and field operating costs by $845 million, or 25%, primarily through cost reduction initiatives, including a workforce reduction in early 2016;
Reduced Devon debtobjectives as evidenced by $3.1 billion, or 31%, and have no significant long term maturities until 2021;
Raised net proceeds of $1.5 billion in an offering of our common stock; and
Exited 2016 with approximately $5 billion in cash and Senior Credit Facility capacity.
In 2017 and beyond, we have the financial capacity to further accelerate investment across our best-in-class U.S. resource plays. We are increasing drilling activity and will continue to rapidly shift our production mix to high-margin products. We will continue our premier technical work to drive capital allocation and efficiency and industry-leading well productivity results. We will continue to maximize the value of our base production by sustaining the operational efficiencies we have achieved. Finally, we will continue to manage activity levels within our cash flows. We expect this disciplined approach will position us to deliver substantial cash flow expansion over the next two years.
29
In addition, we recognized $267 million of restructuring and transaction costs during 2016 related to the workforce reduction and incurred $5.0 billion of noncash asset impairments as a result of the continued depressed prices for commodities but recognized $1.9 billion in gains on our divestiture transactions. While the gain on divestitures and impairments significantly impacted our earnings, they had no effect on our operating cash flow or debt covenants.
Key measures of our financial performance in 2016 are summarized in the following table:
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions, except per share and per Boe amounts) |
| |||||||||||||||||
Net earnings (loss) attributable to Devon |
| $ | (3,302 | ) |
|
| + 77 | % |
| $ | (14,454 | ) |
| N/M |
|
| $ | 1,607 |
| |
Net earnings (loss) per share attributable to Devon |
| $ | (6.52 | ) |
|
| + 82 | % |
| $ | (35.55 | ) |
| N/M |
|
| $ | 3.91 |
| |
Core earnings (loss) attributable to Devon (1) |
| $ | (38 | ) |
|
| - 104 | % |
| $ | 1,044 |
|
|
| - 48 | % |
| $ | 2,017 |
|
Core earnings (loss) per share attributable to Devon (1) |
| $ | (0.08 | ) |
|
| - 103 | % |
| $ | 2.52 |
|
|
| - 49 | % |
| $ | 4.91 |
|
Retained production (MBoe/d) |
|
| 568 |
|
|
| - 4 | % |
|
| 589 |
|
|
| +13 | % |
|
| 521 |
|
Total production (MBoe/d) |
|
| 611 |
|
|
| - 10 | % |
|
| 680 |
|
|
| +1 | % |
|
| 673 |
|
Realized price per Boe (2) |
| $ | 18.72 |
|
|
| - 14 | % |
| $ | 21.68 |
|
|
| - 46 | % |
| $ | 40.33 |
|
Operating cash flow |
| $ | 1,746 |
|
|
| - 68 | % |
| $ | 5,373 |
|
|
| - 11 | % |
| $ | 6,021 |
|
Capitalized costs, including acquisitions |
| $ | 4,191 |
|
|
| - 33 | % |
| $ | 6,233 |
|
|
| - 54 | % |
| $ | 13,559 |
|
Shareholder and noncontrolling interests distributions |
| $ | 525 |
|
|
| - 19 | % |
| $ | 650 |
|
|
| +5 | % |
| $ | 621 |
|
Cash and cash equivalents |
| $ | 1,959 |
|
|
| - 15 | % |
| $ | 2,310 |
|
|
| +56 | % |
| $ | 1,480 |
|
Total debt |
| $ | 10,154 |
|
|
| - 22 | % |
| $ | 13,032 |
|
|
| +16 | % |
| $ | 11,193 |
|
Reserves (MMBoe) |
|
| 2,058 |
|
|
| - 6 | % |
|
| 2,182 |
|
|
| - 21 | % |
|
| 2,754 |
|
these 2019 highlights:
|
| Closed on the sale of our Canadian business for $2.6 billion ($3.4 billion Canadian dollars) in |
|
| Announced the sale of our Barnett Shale assets for $770 million (expected closing in the second quarter of 2020). |
• | Completed workforce reduction and other cost reduction initiatives, reaching approximately $240 million of annualized G&A savings. |
• | Improved capital efficiency by reducing capital expenditures approximately 10% and increasing oil |
• | Retired $1.7 billion of senior notes, reducing annualized financing costs by $60 million. |
• | Repurchased $4.8 billion of our total $5.8 billion share repurchase authorizations, representing an outstanding share count reduction of nearly 30% since the program’s inception. |
• | Increased our quarterly common stock dividend 12.5% to $0.09 per share beginning in the second quarter of 2019. |
• | Increased Delaware Basin and |
• | Reduced methane emissions by nearly 20% over the last three years and established a target to further reduce methane intensity rates by 2025. |
• | Exited 2019 with $1.8 billion of cash, inclusive of $380 million restricted for discontinued operations, $3.0 billion of available credit under our Senior Credit Facility and have no debt maturities until 2025. |
As presented in the graph at the left, our operating achievements are subject to the volatility of commodity prices. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from average highs of $64.79 per Bbl and $3.11 per MMBtu, respectively, to average lows of $43.36 per Bbl and $2.46 per MMBtu, respectively. | ||
24
Trends of our annual earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The annual earnings chart presents amounts pertaining to both Devon’s continuing and discontinued operations. The annual cash flow chart presents amounts pertaining to Devon’s continuing operations. “Core earnings” and “EBITDAX” are financial measures not prepared in accordance with GAAP. For a description of these measures, including reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.
Our 2016 net earnings in recent years have been significantly impacted by divestiture transactions and temporary, noncash adjustments to the value of our commodity hedges. Net earnings in 2017 included a $0.1 billion gain on asset dispositions from continuing operations and a $0.2 billion hedge valuation gain, both net of taxes. Net earnings in 2018 included a $2.2 billion gain on our EnLink disposition, a $0.5 billion hedge valuation gain and a $0.2 billion gain on asset dispositions from continuing operations, all net of taxes. Net earnings in 2019 included a $0.4 billion hedge valuation loss, $0.2 billion net gains and charges related to our Canadian disposition and a $0.6 billion asset impairment related to our Barnett Shale disposition, all net loss per share improved comparedof taxes. Excluding these amounts, our core earnings have been more stable over recent years but continue to 2015 primarily duebe heavily influenced by commodity prices.
Like earnings, our operating cash flow is sensitive to more significant noncash asset impairments recognized in 2015volatile commodity prices. EBITDAX, which excludes financial amounts related to discontinued operations, has been increasing over the past three years as a result of the large commodity price declines. Core loss, core loss per shareour New Devon production growth and cost reductions. Regardless of cash flow fluctuations, we remain focused on managing our capital investment to generate free cash flow. As operating cash flow for 2016 decreased significantly comparedhas declined, we have adjusted our capital development plans accordingly.
25
Business and Industry Outlook
Devon marked its 45th48th anniversary in the oil and gas business and its 28th31st year as a public company during 2016.2019. As an established company with a strong leadership team, we have experience operating inthrough periods of challengedvolatile commodity prices. With our focused strategy and portfolio of quality assets, we are preparedcommitted to successfully navigatenavigating the current environment while ensuringsafeguarding our long-term financial strength.
Market prices for crude oil and natural gas are inherently volatile. Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. During 2016,In 2019, WTI oil prices ranged from $26.21/averaged approximately $57.02/Bbl to $54.06/Bbl. As a result of the ongoing worldwide oversupply issue, OPEC agreed to its first oil production cutversus $64.79/Bbl in eight years in November 2016. Following the agreements by both OPEC and non-OPEC producers to reduce output by nearly 1.8 million barrels per day2018. Despite price support in the first half of 2017,2019 driven by supply tightness and geopolitical tensions, 2019 WTI oil prices jumped approximately 10% inoverall were negatively impacted by trade concerns and economic slowdown fears, even with strong supply and demand fundamentals. Looking ahead, crude oil has experienced near term downward pressure as a result of softer demand from the fourth quartergrowing impact of 2016, averaging $49.21/Bbl. Current market fundamentals indicate improved pricesthe coronavirus related crisis. Positive factors that could reduce these recent negative factors and create more demand for crude oil are the extension of OPEC cuts through 2020, as well as the International Maritime Organization 2020 regulations.
Henry Hub gas prices averaged approximately $2.63/MMBtu in 2019 versus $3.09/MMBtu in 2018. Mt. Belvieu Blended Index NGL prices averaged approximately $19.22/Bbl in 2019 versus $28.31/Bbl in 2018. Natural gas and NGL prices faced strong headwinds in 2019 due to U.S. supply growth far outpacing demand for both commodities domestically and internationally. These factors continue to weigh on current natural gas and naturalNGL prices.
As discussed in our Critical Accounting Estimates, our STACK assets are susceptible to a material asset impairment should prices decrease from current levels. While such an impairment would materially impact our reported net earnings, it would not impact our operating cash flow or our current near-term drilling plans.
To mitigate our exposure to commodity price volatility and ensure our financial strength, we continue to execute a disciplined, risk-management hedging program. Our hedging program incorporates both systematic hedges added on a regular basis and discretionary hedges layered in on an opportunistic basis to take advantage of favorable market conditions. We are adding 2020 positions at desirable prices, and we currently have approximately 40% of our anticipated oil volumes and 25% of our anticipated gas liquidsvolumes hedged. Additionally, we are actively adding attractive hedges for 2021. Further insulating our cash flow, we continue to examine and, when appropriate, execute attractive regional basis swap hedges in 2017; however, changes in OPEC production strategies,an effort to protect price realizations across our portfolio.
Throughout 2019, our operational efficiencies continued to accelerate. Our improved cost structure expanded margins, and we ended the macro-economic environment, geopolitical risks, winteryear ahead of our multi-year cost savings initiative plan. As we carry our 2019 momentum into 2020, we will maintain our capital-efficiency focus and summer temperature ranges or other factors could impact current forecasts.intensify our steadfast commitment to capital discipline. Our returns-driven strategy will be underpinned by our continued efforts to improve our cost structure and grow higher-margin oil production. As such, we anticipate continued volatility into 2017. our 2020 capital program has been optimized for strong returns, high single-digit oil growth, free cash flow and enhanced per-share cash flow growth.
30
While we expect thatthe 2020 spend will be focused in on our industry will remain challenged by relatively low prices forhighest margin U.S. oil play, the near-term, we have strategically positioned our company for continued growth and investmentDelaware Basin. As the most active program in ourDevon’s portfolio, of assets. Leveraging the success of our 2016 divestiture program and other key achievements noted above, we are in a position of significant strength and anticipate expanding our exploration and development capital spend by approximately 80% in 2017. Our 2017 outlook is marked by accelerated activity across our key basins, focusing an expanded rig count in the STACK and Delaware Basin and achieving 15% growth inwill be diversified across five core areas. Also accretive to our 2020 returns-focused capital program is our 2020 Rockies activity, where spend will be prioritized to our top-tier Powder River Basin development activity. In total, our 2020 operating plan is expected to deliver U.S. oil production through some of our best-in-class positions. Additionally, we ramped up our hedging program in 2016, with approximately 50% of our oil and 45% of our gas production hedged entering into 2017.
Finally, EnLink continues to be a strategic advantage for us, allowing for improved midstream growth potential. Annual distributions of approximately $270 million provide7.5% to 9.0% on a visible cash flow stream to be further invested in our upstream capital programs discussed above.retained asset basis.
31
26
Oil, Gas and NGL Production
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 1 |
|
|
| - 28 | % |
|
| 1 |
|
|
| - 35 | % |
|
| 2 |
|
Delaware Basin |
|
| 33 |
|
|
| - 15 | % |
|
| 39 |
|
|
| +48 | % |
|
| 26 |
|
Eagle Ford |
|
| 42 |
|
|
| - 37 | % |
|
| 66 |
|
|
| +65 | % |
|
| 40 |
|
Heavy Oil |
|
| 22 |
|
|
| - 17 | % |
|
| 27 |
|
|
| +3 | % |
|
| 26 |
|
Rockies Oil |
|
| 14 |
|
|
| - 9 | % |
|
| 15 |
|
|
| +68 | % |
|
| 9 |
|
STACK |
|
| 19 |
|
|
| +152 | % |
|
| 7 |
|
|
| +14 | % |
|
| 6 |
|
Other |
|
| 10 |
|
|
| - 19 | % |
|
| 14 |
|
|
| - 11 | % |
|
| 14 |
|
Retained assets |
|
| 141 |
|
|
| - 16 | % |
|
| 169 |
|
|
| +37 | % |
|
| 123 |
|
Divested assets |
|
| 10 |
|
|
| - 58 | % |
|
| 22 |
|
|
| - 34 | % |
|
| 35 |
|
Total |
|
| 151 |
|
|
| - 21 | % |
|
| 191 |
|
|
| +20 | % |
|
| 158 |
|
Bitumen (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil |
|
| 109 |
|
|
| +29 | % |
|
| 84 |
|
|
| +51 | % |
|
| 56 |
|
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 741 |
|
|
| - 9 | % |
|
| 815 |
|
|
| - 13 | % |
|
| 932 |
|
Delaware Basin |
|
| 91 |
|
|
| +25 | % |
|
| 73 |
|
|
| +9 | % |
|
| 67 |
|
Eagle Ford |
|
| 106 |
|
|
| - 29 | % |
|
| 149 |
|
|
| +66 | % |
|
| 90 |
|
Heavy Oil |
|
| 20 |
|
|
| - 11 | % |
|
| 22 |
|
|
| - 5 | % |
|
| 23 |
|
Rockies Oil |
|
| 25 |
|
|
| - 37 | % |
|
| 40 |
|
|
| - 23 | % |
|
| 52 |
|
STACK |
|
| 293 |
|
|
| +23 | % |
|
| 239 |
|
|
| - 1 | % |
|
| 242 |
|
Other |
|
| 14 |
|
|
| - 16 | % |
|
| 17 |
|
|
| - 10 | % |
|
| 19 |
|
Retained assets |
|
| 1,290 |
|
|
| - 5 | % |
|
| 1,355 |
|
|
| - 5 | % |
|
| 1,425 |
|
Divested assets |
|
| 123 |
|
|
| - 52 | % |
|
| 255 |
|
|
| - 49 | % |
|
| 495 |
|
Total |
|
| 1,413 |
|
|
| - 12 | % |
|
| 1,610 |
|
|
| - 16 | % |
|
| 1,920 |
|
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 45 |
|
|
| - 12 | % |
|
| 51 |
|
|
| - 12 | % |
|
| 58 |
|
Delaware Basin |
|
| 12 |
|
|
| +27 | % |
|
| 9 |
|
|
| +24 | % |
|
| 7 |
|
Eagle Ford |
|
| 16 |
|
|
| - 33 | % |
|
| 25 |
|
|
| +113 | % |
|
| 12 |
|
Rockies Oil |
|
| 1 |
|
|
| - 9 | % |
|
| 1 |
|
|
| +16 | % |
|
| 1 |
|
STACK |
|
| 26 |
|
|
| +22 | % |
|
| 21 |
|
|
| - 7 | % |
|
| 23 |
|
Other |
|
| 3 |
|
|
| - 17 | % |
|
| 3 |
|
|
| - 5 | % |
|
| 3 |
|
Retained assets |
|
| 103 |
|
|
| - 6 | % |
|
| 110 |
|
|
| +5 | % |
|
| 104 |
|
Divested assets |
|
| 13 |
|
|
| - 50 | % |
|
| 26 |
|
|
| - 26 | % |
|
| 35 |
|
Total |
|
| 116 |
|
|
| - 15 | % |
|
| 136 |
|
|
| - 2 | % |
|
| 139 |
|
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 169 |
|
|
| - 10 | % |
|
| 188 |
|
|
| - 13 | % |
|
| 215 |
|
Delaware Basin |
|
| 60 |
|
|
| - 1 | % |
|
| 61 |
|
|
| +35 | % |
|
| 45 |
|
Eagle Ford |
|
| 76 |
|
|
| - 34 | % |
|
| 115 |
|
|
| +74 | % |
|
| 66 |
|
Heavy Oil |
|
| 134 |
|
|
| +17 | % |
|
| 115 |
|
|
| +34 | % |
|
| 86 |
|
Rockies Oil |
|
| 19 |
|
|
| - 17 | % |
|
| 23 |
|
|
| +23 | % |
|
| 19 |
|
STACK |
|
| 93 |
|
|
| +37 | % |
|
| 68 |
|
|
| - 2 | % |
|
| 70 |
|
Other |
|
| 17 |
|
|
| - 13 | % |
|
| 19 |
|
|
| - 5 | % |
|
| 20 |
|
Retained assets |
|
| 568 |
|
|
| - 4 | % |
|
| 589 |
|
|
| +13 | % |
|
| 521 |
|
Divested assets |
|
| 43 |
|
|
| - 53 | % |
|
| 91 |
|
|
| - 40 | % |
|
| 152 |
|
Total |
|
| 611 |
|
|
| - 10 | % |
|
| 680 |
|
|
| +1 | % |
|
| 673 |
|
32
IndexThe following graphs, discussion and analysis are intended to Financial Statements
Oil, Gasprovide an understanding of our results of operations and NGL Pricingcurrent financial condition. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Analysis of the change in net earnings from continuing operations is shown below and analysis of the change in net earnings from discontinued operations is shown on page 33.
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 (1) |
|
| Change |
|
| 2015 (1) |
|
| Change |
|
| 2014 (1) |
| |||||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 38.92 |
|
|
| - 12 | % |
| $ | 44.01 |
|
|
| - 49 | % |
| $ | 85.64 |
|
Canada |
| $ | 23.96 |
|
|
| - 22 | % |
| $ | 30.58 |
|
|
| - 55 | % |
| $ | 68.14 |
|
Total |
| $ | 36.72 |
|
|
| - 13 | % |
| $ | 42.12 |
|
|
| - 49 | % |
| $ | 82.47 |
|
Bitumen (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
| $ | 19.82 |
|
|
| - 15 | % |
| $ | 23.41 |
|
|
| - 58 | % |
| $ | 55.88 |
|
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 1.84 |
|
|
| - 15 | % |
| $ | 2.17 |
|
|
| - 45 | % |
| $ | 3.92 |
|
Canada (2) |
| N/M |
|
| N/M |
|
| N/M |
|
| N/M |
|
| $ | 3.64 |
| ||||
Total |
| $ | 1.84 |
|
|
| - 14 | % |
| $ | 2.14 |
|
|
| - 45 | % |
| $ | 3.90 |
|
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 9.81 |
|
|
| +5 | % |
| $ | 9.32 |
|
|
| - 62 | % |
| $ | 24.46 |
|
Canada |
| $ | — |
|
| N/M |
|
| $ | — |
|
| N/M |
|
| $ | 50.52 |
| ||
Total |
| $ | 9.81 |
|
|
| +5 | % |
| $ | 9.32 |
|
|
| - 63 | % |
| $ | 24.89 |
|
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 18.34 |
|
|
| - 13 | % |
| $ | 21.12 |
|
|
| - 44 | % |
| $ | 37.96 |
|
Canada |
| $ | 20.07 |
|
|
| - 18 | % |
| $ | 24.46 |
|
|
| - 54 | % |
| $ | 53.11 |
|
Total |
| $ | 18.72 |
|
|
| - 14 | % |
| $ | 21.68 |
|
|
| - 46 | % |
| $ | 40.33 |
|
|
|
|
|
Commodity Sales
2019 vs. 2018
Our 2019 net loss from continuing operations was $79 million and decreased $793 million compared to 2018. The volume and pricegraph below shows the change in net earnings from 2018 to 2019. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
27
Production Volumes
|
| 2019 |
|
| % of Total |
|
| 2018 |
|
| Change |
| ||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 70 |
|
|
| 47 | % |
|
| 42 |
|
|
| +67 | % |
STACK |
|
| 31 |
|
|
| 20 | % |
|
| 32 |
|
|
| - 4 | % |
Powder River Basin |
|
| 17 |
|
|
| 11 | % |
|
| 14 |
|
|
| +26 | % |
Eagle Ford |
|
| 23 |
|
|
| 16 | % |
|
| 28 |
|
|
| - 17 | % |
Other |
|
| 6 |
|
|
| 4 | % |
|
| 5 |
|
|
| +4 | % |
New Devon |
|
| 147 |
|
|
| 98 | % |
|
| 121 |
|
|
| +21 | % |
U.S. divest assets |
|
| 3 |
|
|
| 2 | % |
|
| 9 |
|
|
| - 70 | % |
Total |
|
| 150 |
|
|
| 100 | % |
|
| 130 |
|
|
| +15 | % |
|
| 2019 |
|
| % of Total |
|
| 2018 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 177 |
|
|
| 29 | % |
|
| 105 |
|
|
| +68 | % |
STACK |
|
| 314 |
|
|
| 53 | % |
|
| 334 |
|
|
| - 6 | % |
Powder River Basin |
|
| 24 |
|
|
| 4 | % |
|
| 16 |
|
|
| +55 | % |
Eagle Ford |
|
| 79 |
|
|
| 13 | % |
|
| 79 |
|
|
| - 0 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| - 18 | % |
New Devon |
|
| 595 |
|
|
| 99 | % |
|
| 535 |
|
|
| +11 | % |
U.S. divest assets |
|
| 4 |
|
|
| 1 | % |
|
| 31 |
|
|
| - 87 | % |
Total |
|
| 599 |
|
|
| 100 | % |
|
| 566 |
|
|
| +6 | % |
|
| 2019 |
|
| % of Total |
|
| 2018 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 27 |
|
|
| 36 | % |
|
| 16 |
|
|
| +74 | % |
STACK |
|
| 36 |
|
|
| 46 | % |
|
| 37 |
|
|
| - 5 | % |
Powder River Basin |
|
| 2 |
|
|
| 3 | % |
|
| 1 |
|
|
| +53 | % |
Eagle Ford |
|
| 11 |
|
|
| 14 | % |
|
| 13 |
|
|
| - 15 | % |
Other |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| +12 | % |
New Devon |
|
| 77 |
|
|
| 100 | % |
|
| 68 |
|
|
| +13 | % |
U.S. divest assets |
|
| — |
|
|
| 0 | % |
|
| 3 |
|
|
| N/M |
|
Total |
|
| 77 |
|
|
| 100 | % |
|
| 71 |
|
|
| +9 | % |
|
| 2019 |
|
| % of Total |
|
| 2018 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 127 |
|
|
| 39 | % |
|
| 75 |
|
|
| +69 | % |
STACK |
|
| 119 |
|
|
| 36 | % |
|
| 125 |
|
|
| - 5 | % |
Powder River Basin |
|
| 23 |
|
|
| 7 | % |
|
| 17 |
|
|
| +34 | % |
Eagle Ford |
|
| 47 |
|
|
| 15 | % |
|
| 54 |
|
|
| - 12 | % |
Other |
|
| 7 |
|
|
| 2 | % |
|
| 7 |
|
|
| +5 | % |
New Devon |
|
| 323 |
|
|
| 99 | % |
|
| 278 |
|
|
| +16 | % |
U.S. divest assets |
|
| 4 |
|
|
| 1 | % |
|
| 18 |
|
|
| - 80 | % |
Total |
|
| 327 |
|
|
| 100 | % |
|
| 296 |
|
|
| +11 | % |
From 2018 to 2019, an 11% increase in production volumes contributed to a $410 million increase in earnings. Continued development in the tables above caused the following changesDelaware Basin and Powder River Basin drove a 16% production increase for New Devon which was slightly offset by decreased production associated with divested assets.
Field Prices
|
| 2019 |
|
| Realization |
|
| 2018 |
|
| Change |
| ||||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 57.02 |
|
|
|
|
|
| $ | 64.79 |
|
|
| - 12 | % |
Realized price, unhedged |
| $ | 54.73 |
|
|
| 96% |
|
| $ | 61.96 |
|
|
| - 12 | % |
Cash settlements |
| $ | 1.71 |
|
|
|
|
|
| $ | (8.01 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 56.44 |
|
|
| 99% |
|
| $ | 53.95 |
|
|
| +5 | % |
|
| 2019 |
|
| Realization |
|
| 2018 |
|
| Change |
| ||||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 2.63 |
|
|
|
|
|
| $ | 3.09 |
|
|
| - 15 | % |
Realized price, unhedged |
| $ | 1.79 |
|
|
| 68% |
|
| $ | 2.34 |
|
|
| - 23 | % |
Cash settlements |
| $ | 0.14 |
|
|
|
|
|
| $ | 0.02 |
|
|
|
|
|
Realized price, with hedges |
| $ | 1.93 |
|
|
| 73% |
|
| $ | 2.36 |
|
|
| - 18 | % |
|
| 2019 |
|
| Realization |
|
| 2018 |
|
| Change |
| ||||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 19.22 |
|
|
|
|
|
| $ | 28.31 |
|
|
| - 32 | % |
Realized price, unhedged |
| $ | 15.21 |
|
|
| 79% |
|
| $ | 25.47 |
|
|
| - 40 | % |
Cash settlements |
| $ | 1.61 |
|
|
|
|
|
| $ | (1.75 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 16.82 |
|
|
| 88% |
|
| $ | 23.72 |
|
|
| - 29 | % |
(1) | Based upon composition of our NGL barrel. |
|
| 2019 |
|
| 2018 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
| $ | 31.93 |
|
| $ | 37.87 |
|
|
| - 16 | % |
Cash settlements |
| $ | 1.43 |
|
| $ | (3.89 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 33.36 |
|
| $ | 33.98 |
|
|
| - 2 | % |
From 2018 to our2019, field prices contributed to a $686 million decrease in earnings. Unhedged realized oil, gas and NGL sales.
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Total |
| |||||
|
| (Millions) |
| |||||||||||||||||
2014 sales |
| $ | 4,773 |
|
| $ | 1,138 |
|
| $ | 2,737 |
|
| $ | 1,262 |
|
| $ | 9,910 |
|
Change due to volumes |
|
| 976 |
|
|
| 584 |
|
|
| (443 | ) |
|
| (23 | ) |
|
| 1,094 |
|
Change due to prices |
|
| (2,813 | ) |
|
| (1,000 | ) |
|
| (1,034 | ) |
|
| (775 | ) |
|
| (5,622 | ) |
2015 sales |
| $ | 2,936 |
|
| $ | 722 |
|
| $ | 1,260 |
|
| $ | 464 |
|
| $ | 5,382 |
|
Change due to volumes |
|
| (608 | ) |
|
| 209 |
|
|
| (151 | ) |
|
| (70 | ) |
|
| (620 | ) |
Change due to prices |
|
| (299 | ) |
|
| (143 | ) |
|
| (159 | ) |
|
| 21 |
|
|
| (580 | ) |
2016 sales |
| $ | 2,029 |
|
| $ | 788 |
|
| $ | 950 |
|
| $ | 415 |
|
| $ | 4,182 |
|
Volumes 2016 vs. 2015 Commodity salesprices decreased due to our 67% reduction in exploration and development capital related to our retained assets during 2016. While expanded drilling in the STACK and the performance of our Jackfish assets drove production increases, these production increases were more than offset by reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale and Rockies Oil. Delaware Basin production was relatively flat as natural declines offset the increases from new wells. Additionally, our production decreased as a result of our U.S. non-core divestiture program.
Volumes 2015 vs. 2014 Commodity sales increased due to volumes in 2015 because of strong production growth from our U.S. oil properties. The growth was primarily driven by the continued development of our Eagle
33
Ford, Delaware Basin and Rockies Oil properties. Additionally, our bitumen production increased primarily due to Jackfish 3 coming on-line late in the third quarter of 2014lower WTI, Henry Hub and reaching nameplate capacity in the third quarter of 2015. Lower royalties resulting from the significant price decrease also increased our heavy oil production. The increases were partially offset by a decrease in our gas production, which resulted primarily from asset divestitures in 2014 and natural reservoir declines.
Prices 2016 vs. 2015 Commodity sales decreased in 2016 as a result of lower prices for oil, bitumen and gas. The decrease in oil and bitumen sales primarily resulted from lower average WTI crude oilMont Belvieu index prices, which were approximately 11% lower in 2016 as compared to 2015. The decreases in gas were driven by lower North American regional index prices upon which our gas sales are based.prices. These decreases were partially offset by slightly higher NGL prices at the Mont Belvieu, Texas hub.
Prices 2015 vs. 2014 Commodity sales decreased in 2015 as a result of significantly lower prices for all commodities. The decrease in oil and bitumen sales primarily resulted from significantly lower average WTI crude oil index prices, which were approximately 50% lower in 2015 as compared to 2014. The decreases in gas and NGL sales were driven by lower North American regional index prices upon which our gas sales are based and lower NGL prices at the Mont Belvieu, Texas hub.
Oil, Gas and NGL Derivatives
The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents thefavorable hedge cash settlements and fair value gains and losses recognized as componentsacross each of our revenues. The subsequent tables present our oil, gas and NGL prices with and without the effects of the cash settlements. The prices do not include the effects of fair value gains and losses. products.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivatives |
| $ | (41 | ) |
| $ | 2,083 |
|
| $ | 90 |
|
Gas derivatives |
|
| 35 |
|
|
| 333 |
|
|
| (36 | ) |
NGL derivatives |
|
| (5 | ) |
|
| — |
|
|
| 1 |
|
Total cash settlements |
|
| (11 | ) |
|
| 2,416 |
|
|
| 55 |
|
Gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivatives |
|
| (103 | ) |
|
| (1,687 | ) |
|
| 1,721 |
|
Gas derivatives |
|
| (86 | ) |
|
| (226 | ) |
|
| 213 |
|
NGL derivatives |
|
| (1 | ) |
|
| — |
|
|
| — |
|
Total gains (losses) on fair value changes |
|
| (190 | ) |
|
| (1,913 | ) |
|
| 1,934 |
|
Oil, gas and NGL derivatives |
| $ | (201 | ) |
| $ | 503 |
|
| $ | 1,989 |
|
34
28
|
| Year Ended December 31, 2016 |
| |||||||||||||||||
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Boe |
| |||||
|
| (Per Bbl) |
|
| (Per Bbl) |
|
| (Per Mcf) |
|
| (Per Bbl) |
|
| (Per Boe) |
| |||||
Realized price without hedges |
| $ | 36.72 |
|
| $ | 19.82 |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 18.72 |
|
Cash settlements of hedges |
|
| (0.74 | ) |
|
| — |
|
|
| 0.07 |
|
|
| (0.11 | ) |
|
| (0.05 | ) |
Realized price, including cash settlements |
| $ | 35.98 |
|
| $ | 19.82 |
|
| $ | 1.91 |
|
| $ | 9.70 |
|
| $ | 18.67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2015 |
| |||||||||||||||||
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Boe |
| |||||
|
| (Per Bbl) |
|
| (Per Bbl) |
|
| (Per Mcf) |
|
| (Per Bbl) |
|
| (Per Boe) |
| |||||
Realized price without hedges |
| $ | 42.12 |
|
| $ | 23.41 |
|
| $ | 2.14 |
|
| $ | 9.32 |
|
| $ | 21.68 |
|
Cash settlements of hedges |
|
| 29.88 |
|
|
| — |
|
|
| 0.57 |
|
|
| — |
|
|
| 9.74 |
|
Realized price, including cash settlements |
| $ | 72.00 |
|
| $ | 23.41 |
|
| $ | 2.71 |
|
| $ | 9.32 |
|
| $ | 31.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2014 |
| |||||||||||||||||
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Boe |
| |||||
|
| (Per Bbl) |
|
| (Per Bbl) |
|
| (Per Mcf) |
|
| (Per Bbl) |
|
| (Per Boe) |
| |||||
Realized price without hedges |
| $ | 82.47 |
|
| $ | 55.88 |
|
| $ | 3.90 |
|
| $ | 24.89 |
|
| $ | 40.33 |
|
Cash settlements of hedges |
|
| 1.56 |
|
|
| — |
|
|
| (0.05 | ) |
|
| 0.02 |
|
|
| 0.22 |
|
Realized price, including cash settlements |
| $ | 84.03 |
|
| $ | 55.88 |
|
| $ | 3.85 |
|
| $ | 24.91 |
|
| $ | 40.55 |
|
Hedge Settlements
|
| 2019 |
|
| 2018 |
|
| Change |
| |||
|
| Q |
|
|
|
|
|
|
|
|
| |
Oil |
| $ | 93 |
|
| $ | (380 | ) |
|
| N/M |
|
Natural gas |
|
| 31 |
|
|
| 5 |
|
|
| N/M |
|
NGL |
|
| 46 |
|
|
| (45 | ) |
|
| N/M |
|
Total cash settlements |
| $ | 170 |
|
| $ | (420 | ) |
|
| N/M |
|
Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments. A summary of our open commodity derivative positions is includedthe instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. Our
Production Expenses
|
| 2019 |
|
| 2018 |
|
| Change |
| |||
LOE |
| $ | 462 |
|
| $ | 480 |
|
|
| - 4 | % |
Gathering, processing & transportation |
|
| 463 |
|
|
| 407 |
|
|
| +14 | % |
Production taxes |
|
| 251 |
|
|
| 248 |
|
|
| +1 | % |
Property taxes |
|
| 21 |
|
|
| 18 |
|
|
| +17 | % |
Total |
| $ | 1,197 |
|
| $ | 1,153 |
|
|
| +4 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 3.87 |
|
| $ | 4.45 |
|
|
| - 13 | % |
Gathering, processing & transportation |
| $ | 3.88 |
|
| $ | 3.77 |
|
|
| +3 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 6.6 | % |
|
| 6.1 | % |
|
| +8 | % |
LOE per Boe decreased in 2019 compared to 2018 due to the impact of our cost reduction initiatives. Gathering, processing and transportation increased primarily due to increased activity in the Delaware Basin.
Field-Level Cash Margin
The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL derivatives include price swaps, costless collarsrevenues less production expenses and basis swaps.is not prepared in accordance with GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 7. The changes in production volumes, field prices and production expenses, shown above, had the following impacts on our field-level cash margins by asset.
In addition
|
| 2019 |
|
| $ per BOE |
|
| 2018 |
|
| $ per BOE |
| ||||
Field-level cash margin (non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
| $ | 1,157 |
|
| $ | 25.00 |
|
| $ | 786 |
|
| $ | 28.65 |
|
STACK |
|
| 685 |
|
| $ | 15.81 |
|
|
| 992 |
|
| $ | 21.75 |
|
Powder River Basin |
|
| 246 |
|
| $ | 28.64 |
|
|
| 249 |
|
| $ | 38.50 |
|
Eagle Ford |
|
| 446 |
|
| $ | 25.80 |
|
|
| 717 |
|
| $ | 36.30 |
|
Other |
|
| 65 |
|
| $ | 25.37 |
|
|
| 72 |
|
| $ | 28.59 |
|
New Devon |
|
| 2,599 |
|
| $ | 22.02 |
|
|
| 2,816 |
|
| $ | 27.67 |
|
U.S. divest assets |
|
| 13 |
|
| $ | 11.01 |
|
|
| 116 |
|
| $ | 19.15 |
|
Total |
| $ | 2,612 |
|
| $ | 21.90 |
|
| $ | 2,932 |
|
| $ | 27.19 |
|
Depreciation, Depletion and Amortization
|
| 2019 |
|
| 2018 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 11.72 |
|
| $ | 10.51 |
|
|
| +11 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas |
| $ | 1,398 |
|
| $ | 1,134 |
|
|
| +23 | % |
Other property and equipment |
|
| 99 |
|
|
| 94 |
|
|
| +5 | % |
Total |
| $ | 1,497 |
|
|
| 1,228 |
|
|
| +22 | % |
Our oil and gas DD&A increased due to cash settlements, we alsocontinued development in the Delaware Basin and Powder River Basin.
General and Administrative Expense
|
| 2019 |
|
| 2018 |
|
| Change |
| |||
Labor and benefits (net of reimbursements) |
| $ | 307 |
|
| $ | 365 |
|
|
| - 16 | % |
Non-labor |
|
| 168 |
|
|
| 209 |
|
|
| - 20 | % |
Total Devon |
| $ | 475 |
|
| $ | 574 |
|
|
| - 17 | % |
From 2018 to 2019, G&A decreased $99 million primarily as a result of the workforce reduction and other cost-saving initiatives that occurred during 2019 as discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
Other Items
|
| 2019 |
|
| 2018 |
|
| Change in earnings |
| |||
Commodity hedge valuation changes (1) |
| $ | (624 | ) |
| $ | 877 |
|
| $ | (1,501 | ) |
Marketing operations |
|
| 53 |
|
|
| 33 |
|
|
| 20 |
|
Exploration expenses |
|
| 58 |
|
|
| 128 |
|
|
| 70 |
|
Asset impairments |
|
| — |
|
|
| 156 |
|
|
| 156 |
|
Asset dispositions |
|
| (48 | ) |
|
| (278 | ) |
|
| (230 | ) |
Net financing costs |
|
| 250 |
|
|
| 580 |
|
|
| 330 |
|
Restructuring and transaction costs |
|
| 84 |
|
|
| 97 |
|
|
| 13 |
|
Other expenses |
|
| 4 |
|
|
| (7 | ) |
|
| (11 | ) |
|
|
|
|
|
|
|
|
|
| $ | (1,153 | ) |
(1) | Included as a component of upstream revenues on the consolidated statements of comprehensive earnings. |
We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationshipsrelationship between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred a net loss in 2016 and generated net gains in 2015 and 2014.
Marketing and Midstream Revenues and Operating Expenses
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions) |
| |||||||||||||||||
Operating revenues |
| $ | 6,323 |
|
|
| - 13 | % |
| $ | 7,260 |
|
|
| - 5 | % |
| $ | 7,667 |
|
Product purchases |
|
| (5,133 | ) |
|
| - 15 | % |
|
| (6,028 | ) |
|
| - 8 | % |
|
| (6,540 | ) |
Operations and maintenance expenses |
|
| (359 | ) |
|
| - 8 | % |
|
| (392 | ) |
|
| +43 | % |
|
| (275 | ) |
Operating profit |
| $ | 831 |
|
|
| - 1 | % |
| $ | 840 |
|
|
| - 1 | % |
| $ | 852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon profit (loss) |
| $ | (48 | ) |
|
| - 443 | % |
| $ | 14 |
|
|
| - 84 | % |
| $ | 88 |
|
EnLink profit |
|
| 879 |
|
|
| +6 | % |
|
| 826 |
|
|
| +8 | % |
|
| 764 |
|
Total profit |
| $ | 831 |
|
|
| - 1 | % |
| $ | 840 |
|
|
| - 1 | % |
| $ | 852 |
|
2016 vs. 2015 The overall decrease in marketing and midstream margin during 2016 wasExploration expense decreased primarily due to lower margins on Devon’s downstream marketing commitments, offset by EnLink’s margin growth largelyrecognizing $95 million in unprovedimpairments related to its acquisition activitycertain non-core acreage in late 2015the U.S during 2018 compared to $18 million in 2019.
Asset impairments decreased due to recognizing $109 million of proved asset impairments and the first quarter$47 million of 2016. We anticipate the margins on Devon’s downstream marketing commitments to continue to negatively impact our marketingnon-oil and midstream margins into 2017.gas asset impairments during 2018 as discussed in Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.
3529
2015 vs. 2014 Marketing and midstream operating profit changes were largely driven by a decrease in Devon’s marketing activitiesAsset dispositions decreased primarily due to a decrease in commodity prices. These declines were partially offset by a full year of EnLink’s legacy asset operations compared to prior year and facility expansions coming online in late 2014, along with assets acquired during 2015.
Asset Dispositions and Other
During 2016, wegains recognized gains of $1.9 billion in conjunction with the non-core U.S. upstream asset divestitures and the divestiturecertain of our 50% interestU.S. asset dispositions in the Access Pipeline in Canada. During 2014, in conjunction with the divestiture of certain Canadian properties, we recognized gains of $1.1 billion.2018. For further discussion, additional information see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
Lease Operating Expenses
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions, except per Boe amounts) |
| |||||||||||||||||
LOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 1,123 |
|
|
| - 28 | % |
| $ | 1,551 |
|
|
| - 0 | % |
| $ | 1,559 |
|
Canada |
|
| 459 |
|
|
| - 17 | % |
|
| 553 |
|
|
| - 28 | % |
|
| 773 |
|
Total |
| $ | 1,582 |
|
|
| - 25 | % |
| $ | 2,104 |
|
|
| - 10 | % |
| $ | 2,332 |
|
LOE per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 6.44 |
|
|
| - 14 | % |
| $ | 7.52 |
|
|
| +0 | % |
| $ | 7.52 |
|
Canada |
| $ | 9.36 |
|
|
| - 29 | % |
| $ | 13.18 |
|
|
| - 34 | % |
| $ | 20.10 |
|
Total |
| $ | 7.08 |
|
|
| - 17 | % |
| $ | 8.48 |
|
|
| - 11 | % |
| $ | 9.49 |
|
2016 vs. 2015 LOE and LOE per BoeNetfinancing costs decreased during 2016 primarily due to $312 million of early retirement charges associated with our well optimizationdebt retirement in 2018 as discussed in Note 13 in “Item 8. Financial Statements and cost reduction initiatives, as well asSupplementary Data” of this report.
Income Taxes
|
| 2019 |
|
| 2018 |
| ||
Current benefit |
| $ | (5) |
|
| $ | (17) |
|
Deferred expense (benefit) |
|
| (25) |
|
|
| 247 |
|
Total expense (benefit) |
| $ | (30) |
|
| $ | 230 |
|
Effective income tax rate |
|
| 28 | % |
|
| 24 | % |
For discussion on income taxes, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
Results of Operations – 2018 vs. 2017
Our 2018 net earnings from continuing operations were $714 million and increased $681 million compared to 2017. The graph below shows the change in net earnings from 2017 to 2018. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
(1) | As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, the presentation of certain processing arrangements changed from a net to a gross presentation in 2018. The change resulted in an increase to our upstream revenues and production expenses by $191 million during 2018 with no impact to net earnings. |
30
Production Volumes
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 42 |
|
|
| 32 | % |
|
| 29 |
|
|
| +42 | % |
STACK |
|
| 32 |
|
|
| 25 | % |
|
| 25 |
|
|
| +28 | % |
Powder River Basin |
|
| 14 |
|
|
| 10 | % |
|
| 10 |
|
|
| +37 | % |
Eagle Ford |
|
| 28 |
|
|
| 22 | % |
|
| 34 |
|
|
| - 17 | % |
Other |
|
| 5 |
|
|
| 4 | % |
|
| 6 |
|
|
| - 6 | % |
New Devon |
|
| 121 |
|
|
| 93 | % |
|
| 104 |
|
|
| +17 | % |
U.S. divest assets |
|
| 9 |
|
|
| 7 | % |
|
| 11 |
|
|
| - 24 | % |
Total |
|
| 130 |
|
|
| 100 | % |
|
| 115 |
|
|
| +13 | % |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 105 |
|
|
| 19 | % |
|
| 86 |
|
|
| +22 | % |
STACK |
|
| 334 |
|
|
| 59 | % |
|
| 294 |
|
|
| +13 | % |
Powder River Basin |
|
| 16 |
|
|
| 3 | % |
|
| 8 |
|
|
| +85 | % |
Eagle Ford |
|
| 79 |
|
|
| 14 | % |
|
| 95 |
|
|
| - 17 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| +6 | % |
New Devon |
|
| 535 |
|
|
| 95 | % |
|
| 484 |
|
|
| +10 | % |
U.S. divest assets |
|
| 31 |
|
|
| 5 | % |
|
| 35 |
|
|
| - 10 | % |
Total |
|
| 566 |
|
|
| 100 | % |
|
| 519 |
|
|
| +9 | % |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 16 |
|
|
| 22 | % |
|
| 10 |
|
|
| +53 | % |
STACK |
|
| 37 |
|
|
| 53 | % |
|
| 30 |
|
|
| +24 | % |
Powder River Basin |
|
| 1 |
|
|
| 2 | % |
|
| 1 |
|
|
| +75 | % |
Eagle Ford |
|
| 13 |
|
|
| 18 | % |
|
| 13 |
|
|
| +2 | % |
Other |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 4 | % |
New Devon |
|
| 68 |
|
|
| 96 | % |
|
| 55 |
|
|
| +25 | % |
U.S. divest assets |
|
| 3 |
|
|
| 4 | % |
|
| 3 |
|
|
| - 10 | % |
Total |
|
| 71 |
|
|
| 100 | % |
|
| 58 |
|
|
| +23 | % |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 75 |
|
|
| 26 | % |
|
| 54 |
|
|
| +39 | % |
STACK |
|
| 125 |
|
|
| 42 | % |
|
| 104 |
|
|
| +20 | % |
Powder River Basin |
|
| 17 |
|
|
| 6 | % |
|
| 12 |
|
|
| +43 | % |
Eagle Ford |
|
| 54 |
|
|
| 18 | % |
|
| 62 |
|
|
| - 13 | % |
Other |
|
| 7 |
|
|
| 2 | % |
|
| 7 |
|
|
| - 3 | % |
New Devon |
|
| 278 |
|
|
| 94 | % |
|
| 239 |
|
|
| +16 | % |
U.S. divest assets |
|
| 18 |
|
|
| 6 | % |
|
| 21 |
|
|
| - 14 | % |
Total |
|
| 296 |
|
|
| 100 | % |
|
| 260 |
|
|
| +14 | % |
From 2017 to 2018, an increase in production volumes contributed to a $246 million increase in earnings. Focused development activities in the Delaware Basin, STACK and Powder River Basin drove production increases for New Devon and were partially offset by decreased activity in the Eagle Ford and lower production volumes associated with our non-core oilU.S. divested assets.
Oil, Gas and gas property divestitures. On an absolute dollar basis, LOE decreased approximately $200NGL Prices
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 64.79 |
|
|
|
|
|
| $ | 50.99 |
|
|
| +27 | % |
Realized price, unhedged |
| $ | 61.96 |
|
|
| 96% |
|
| $ | 49.41 |
|
|
| +25 | % |
Cash settlements |
| $ | (8.01 | ) |
|
|
|
|
| $ | 1.98 |
|
|
|
|
|
Realized price, with hedges |
| $ | 53.95 |
|
|
| 83% |
|
| $ | 51.39 |
|
|
| +5 | % |
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 3.09 |
|
|
|
|
|
| $ | 3.11 |
|
|
| - 1 | % |
Realized price, unhedged |
| $ | 2.34 |
|
|
| 76% |
|
| $ | 2.57 |
|
|
| - 9 | % |
Cash settlements |
| $ | 0.02 |
|
|
|
|
|
| $ | 0.18 |
|
|
|
|
|
Realized price, with hedges |
| $ | 2.36 |
|
|
| 76% |
|
| $ | 2.75 |
|
|
| - 14 | % |
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 28.31 |
|
|
|
|
|
| $ | 24.77 |
|
|
| +14 | % |
Realized price, unhedged |
| $ | 25.47 |
|
|
| 90% |
|
| $ | 16.74 |
|
|
| +52 | % |
Cash settlements |
| $ | (1.75 | ) |
|
|
|
|
| $ | (0.16 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 23.72 |
|
|
| 84% |
|
| $ | 16.58 |
|
|
| +43 | % |
(1) | Based upon composition of average Devon NGL barrel. |
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
| $ | 37.87 |
|
| $ | 30.80 |
|
|
| +23 | % |
Cash settlements |
| $ | (3.89 | ) |
| $ | 1.21 |
|
|
|
|
|
Realized price, with hedges |
| $ | 33.98 |
|
| $ | 32.01 |
|
|
| +6 | % |
Upstream revenues increased $918 million as a result of our U.S. upstream divestitures,higher unhedged, realized prices for oil and we anticipate realizingNGLs. The increase in oil sales primarily resulted from higher average WTI crude index prices, which were 27% higher in 2018, resulting in an increase of approximately $100$600 million.
NGL sales increased $282 million in additional LOE savings in 2017 as a result of these divestitures. Our cost reduction initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers. 14% higher NGL prices at the Mont Belvieu, Texas hub, as well as improved realizations in our NGL price.These cost savingsincreases were partially offset by $28unfavorable hedge cash settlements for our oil and NGL hedges.
In 2018, the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by approximately $191 million with no impact to net earnings.
Hedge Settlements
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
|
| Q |
|
|
|
|
|
|
|
|
| |
Oil |
| $ | (380 | ) |
| $ | 83 |
|
|
| N/M |
|
Natural gas |
|
| 5 |
|
|
| 35 |
|
|
| N/M |
|
NGL |
|
| (45 | ) |
|
| (3 | ) |
|
| N/M |
|
Total cash settlements |
| $ | (420 | ) |
| $ | 115 |
|
|
| N/M |
|
31
Table of Access Pipeline transportation tolls which commencedContents
Production Expenses
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
LOE |
| $ | 480 |
|
| $ | 411 |
|
|
| +17 | % |
Gathering, processing & transportation |
|
| 407 |
|
|
| 205 |
|
|
| +99 | % |
Production taxes |
|
| 248 |
|
|
| 161 |
|
|
| +54 | % |
Property taxes |
|
| 18 |
|
|
| 14 |
|
|
| +29 | % |
Total |
| $ | 1,153 |
|
| $ | 791 |
|
|
| +46 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 4.45 |
|
| $ | 4.33 |
|
|
| +3 | % |
Gathering, processing & transportation |
| $ | 3.77 |
|
| $ | 2.16 |
|
|
| +74 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 6.1 | % |
|
| 5.5 | % |
|
| +10 | % |
LOE increased $69 million primarily due to continued focus on growing our liquids-rich assets within the STACK and Delaware Basin, partially offset by our U.S. non-core divestitures.
In 2018, the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by approximately $191 million with no impact to net earnings.
Production taxes increased on an absolute dollar basis primarily due to the increase in our upstream revenues. Additionally, the increase in Oklahoma severance tax rates that became effective during the third quarter of 2018 also contributed to the increase on an absolute dollar basis and as a percentage of oil, gas and NGL sales.
Field-Level Cash Margin
The changes in production volumes, field prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
|
| 2018 |
|
| $ per BOE |
|
| 2017 |
|
| $ per BOE |
| ||||
Field-level cash margin (non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
| $ | 786 |
|
| $ | 28.65 |
|
| $ | 455 |
|
| $ | 23.04 |
|
STACK |
|
| 992 |
|
| $ | 21.75 |
|
|
| 683 |
|
| $ | 17.99 |
|
Powder River Basin |
|
| 249 |
|
| $ | 38.50 |
|
|
| 128 |
|
| $ | 28.67 |
|
Eagle Ford |
|
| 717 |
|
| $ | 36.30 |
|
|
| 667 |
|
| $ | 29.41 |
|
Other |
|
| 72 |
|
| $ | 28.59 |
|
|
| 68 |
|
| $ | 26.21 |
|
New Devon |
|
| 2,816 |
|
| $ | 27.67 |
|
|
| 2,001 |
|
| $ | 22.88 |
|
U.S. divest assets |
|
| 116 |
|
| $ | 19.15 |
|
|
| 129 |
|
| $ | 17.47 |
|
Total |
| $ | 2,932 |
|
| $ | 27.19 |
|
| $ | 2,130 |
|
| $ | 22.46 |
|
Depreciation, Depletion and Amortization
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 10.51 |
|
| $ | 9.58 |
|
|
| +10 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas |
| $ | 1,134 |
|
| $ | 908 |
|
|
| +25 | % |
Other property and equipment |
|
| 94 |
|
|
| 100 |
|
|
| - 5 | % |
Total |
| $ | 1,228 |
|
| $ | 1,008 |
|
|
| +22 | % |
Our oil and gas DD&A increased primarily due to continued development in the fourth quarter of 2016 subsequentSTACK, Delaware Basin and Powder River Basin properties.
General and Administrative Expense
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Labor and benefits (net of reimbursements) |
| $ | 365 |
|
| $ | 445 |
|
|
| - 18 | % |
Non-labor |
|
| 209 |
|
|
| 200 |
|
|
| + 5 | % |
Total Devon |
| $ | 574 |
|
| $ | 645 |
|
|
| - 11 | % |
From 2017 to the sale of our interest in Access. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $1102018, G&A decreased $71 million annually.
2015 vs. 2014 LOE per Boe decreased during 2015 primarily as a result of higher Jackfish 3 volumes,the workforce reductions that occurred during 2018 as discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
Other Items
|
| 2018 |
|
| 2017 |
|
| Change in earnings |
| |||
Commodity hedge valuation changes (1) |
| $ | 877 |
|
| $ | (48 | ) |
| $ | 925 |
|
Marketing operations |
|
| 33 |
|
|
| (46 | ) |
|
| 79 |
|
Exploration expenses |
|
| 128 |
|
|
| 346 |
|
|
| 218 |
|
Asset impairments |
|
| 156 |
|
|
| — |
|
|
| (156 | ) |
Asset dispositions |
|
| (278 | ) |
|
| (219 | ) |
|
| 59 |
|
Net financing costs |
|
| 580 |
|
|
| 321 |
|
|
| (259 | ) |
Restructuring and transaction costs |
|
| 97 |
|
|
| — |
|
|
| (97 | ) |
Other expenses |
|
| (7 | ) |
|
| 10 |
|
|
| 17 |
|
|
|
|
|
|
|
|
|
|
| $ | 786 |
|
(1) | Included as a component of upstream revenues on the consolidated statements of comprehensive earnings. |
Marketing operations increased primarily due to improved commodity prices, which were partially offset by the impact of our well optimization and cost reduction initiatives, lower royalties and changesdownstream marketing commitments.
Exploration expense decreased due torecognizing $95 million in unprovedimpairments related to certain non-core acreage in the CanadianU.S during 2018 compared to U.S. foreign exchange rate. As Canadian royalties decrease, our net production volumes increase, causing improvements$217 million in 2017. Additionally, geological and geophysical costs decreased $86 million primarily in the STACK and Delaware Basin.
Asset impairments increased due to our per-unit operating costs. The flat U.S. rate is primarily related to our 2014 non-core naturalrecognizing $109 million of proved asset impairments and $47 million of non-oil and gas asset divestituresimpairments during 2018. For additional information, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.
Asset dispositions increased primarily due to gains recognized in conjunction with certain of our oil production growth, where projects generate higher margins but generally require a higher costU.S. asset dispositions in 2018. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
Netfinancing costs increased primarily due to produce per unit than$312 million of early retirement charges associated with our retaineddebt retirement in 2018 as discussed in Note 13 in “Item 8. Financial Statements and divested gas projects.Supplementary Data” of this report.
36
32
General and Administrative Expenses
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions) |
| |||||||||||||||||
Gross G&A |
| $ | 853 |
|
|
| - 30 | % |
| $ | 1,210 |
|
|
| - 5 | % |
| $ | 1,272 |
|
Capitalized G&A |
|
| (244 | ) |
|
| - 34 | % |
|
| (372 | ) |
|
| - 1 | % |
|
| (376 | ) |
Reimbursed G&A |
|
| (82 | ) |
|
| - 32 | % |
|
| (120 | ) |
|
| - 18 | % |
|
| (146 | ) |
Devon Net G&A |
|
| 527 |
|
|
| - 27 | % |
|
| 718 |
|
|
| - 4 | % |
|
| 750 |
|
EnLink Net G&A |
|
| 118 |
|
|
| - 14 | % |
|
| 137 |
|
|
| +41 | % |
|
| 97 |
|
Net G&A |
| $ | 645 |
|
|
| - 25 | % |
| $ | 855 |
|
|
| +1 | % |
| $ | 847 |
|
2016 vs. 2015 Gross G&ARestructuring and capitalized G&A decreased during 2016 largely due to lower Devon employeetransaction costs resulting fromincreased primarily as a result of our workforce reductions as discussed in 2018. See Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report and other cost reduction initiatives. Reimbursed G&A decreased primarily due to a reduction in drilling activity in response to the decline in commodity prices as well as the divestiture of operated properties. EnLink net G&A decreased primarily due to lower employee compensation expense and other cost reductions initiatives during 2016.for additional information.
2015 vs. 2014 Gross G&A decreased during 2015 largely because of a lower employee performance bonus pool and our cost reduction initiatives. Furthermore, $22 million in one-time costs related to the EnLink and GeoSouthern transactions contributed to higher costs in the first quarter of 2014. Reimbursed G&A decreased subsequent to our 2014 asset divestitures. EnLink G&A increased primarily due to a workforce increase associated with EnLink’s 2015 acquisitions.
Production and PropertyIncome Taxes
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions) |
| |||||||||||||||||
Production taxes |
| $ | 141 |
|
|
| - 29 | % |
| $ | 198 |
|
|
| - 45 | % |
| $ | 360 |
|
Property and other taxes |
|
| 95 |
|
|
| - 37 | % |
|
| 151 |
|
|
| +3 | % |
|
| 147 |
|
Devon production and property taxes |
|
| 236 |
|
|
| - 32 | % |
|
| 349 |
|
|
| - 31 | % |
|
| 507 |
|
EnLink property taxes |
|
| 39 |
|
|
| - 1 | % |
|
| 39 |
|
|
| +39 | % |
|
| 28 |
|
Production and property taxes |
| $ | 275 |
|
|
| - 29 | % |
| $ | 388 |
|
|
| - 28 | % |
| $ | 535 |
|
Percentage of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 3.4 | % |
|
| - 8 | % |
|
| 3.7 | % |
|
| +1 | % |
|
| 3.6 | % |
Property and other taxes |
|
| 3.2 | % |
|
| - 9 | % |
|
| 3.5 | % |
|
| +100 | % |
|
| 1.8 | % |
Total |
|
| 6.6 | % |
|
| - 9 | % |
|
| 7.2 | % |
|
| +33 | % |
|
| 5.4 | % |
2016 vs. 2015 Production taxes decreased on an absolute dollar basis primarily due to the decrease in our U.S. revenues, on which the majority of our production taxes are assessed. Furthermore, property and other taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. non-core divestitures. Property taxes do not change in direct correlation with the decline in oil, gas and NGL sales and are generally determined based on the valuation of the underlying assets.
2015 vs. 2014 Production taxes decreased during 2015 primarily because of a decrease in our U.S. revenues, on which the majority of our production taxes are assessed.
37
Depreciation, Depletion and Amortization
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions, except per Boe amounts) |
| |||||||||||||||||
DD&A: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties |
| $ | 1,143 |
|
|
| - 56 | % |
| $ | 2,580 |
|
|
| - 11 | % |
| $ | 2,896 |
|
Other assets |
|
| 145 |
|
|
| - 10 | % |
|
| 162 |
|
|
| +16 | % |
|
| 139 |
|
Devon DD&A |
|
| 1,288 |
|
|
| - 53 | % |
|
| 2,742 |
|
|
| - 10 | % |
|
| 3,035 |
|
EnLink DD&A |
|
| 504 |
|
|
| +30 | % |
|
| 387 |
|
|
| +36 | % |
|
| 284 |
|
Total DD&A |
| $ | 1,792 |
|
|
| - 43 | % |
| $ | 3,129 |
|
|
| - 6 | % |
| $ | 3,319 |
|
DD&A per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties |
| $ | 5.11 |
|
|
| - 51 | % |
| $ | 10.40 |
|
|
| - 12 | % |
| $ | 11.79 |
|
|
| 2018 |
|
| 2017 |
| ||
Current expense (benefit) |
| $ | (17 | ) |
| $ | 9 |
|
Deferred expense (benefit) |
|
| 247 |
|
|
| (2 | ) |
Total expense |
| $ | 230 |
|
| $ | 7 |
|
Effective income tax rate |
|
| 24 | % |
|
| 18 | % |
A description of how DD&A of our oil and gas properties is calculated is included in For discussion on income taxes, see Note 17 in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down,
Discontinued Operations |
The table below presents key components from discontinued operations for the DD&A rate per unittime periods presented. Discontinued operations include our aggregate ownership interests in EnLink and the General Partner that Devon divested in July 2018 and the Canadian business that Devon sold in June 2019. Discontinued operations also include the Barnett Shale assets that Devon has contracted to sell and which is expected to close during the second quarter of production will change inversely. However, when2020, as well as previously divested Barnett Shale properties located primarily in Johnson and Wise counties, Texas. For additional information on discontinued operations, see Note 18in “Part I. Financial Information – Item 1. Financial Statements” of this report.
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Upstream revenues |
| $ | 1,114 |
|
| $ | 1,742 |
|
| $ | 2,319 |
|
Production expenses |
| $ | 599 |
|
| $ | 1,072 |
|
| $ | 1,031 |
|
Marketing margin |
| $ | 20 |
|
| $ | 708 |
|
| $ | 958 |
|
Gain on sale of Canadian operations |
| $ | (223 | ) |
| $ | — |
|
| $ | — |
|
Gain on sale of EnLink and General Partner interests |
| $ | — |
|
| $ | (2,607 | ) |
| $ | — |
|
Asset impairments |
| $ | 785 |
|
| $ | — |
|
| $ | 17 |
|
Financing costs, net |
| $ | 87 |
|
| $ | 112 |
|
| $ | 177 |
|
Restructuring and transaction costs |
| $ | 248 |
|
| $ | 17 |
|
| $ | — |
|
Earnings (loss) from discontinued operations before income taxes |
| $ | (632 | ) |
| $ | 2,839 |
|
| $ | 856 |
|
Income tax expense (benefit) |
| $ | (358 | ) |
| $ | 329 |
|
| $ | (189 | ) |
Net earnings (loss) from discontinued operations, net of tax |
| $ | (274 | ) |
| $ | 2,510 |
|
| $ | 1,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMBoe): |
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 37 |
|
|
| 45 |
|
|
| 56 |
|
Canada |
|
| 19 |
|
|
| 42 |
|
|
| 48 |
|
Total production |
|
| 56 |
|
|
| 87 |
|
|
| 104 |
|
Realized price, unhedged (per Boe) - Barnett Shale |
| $ | 13.30 |
|
| $ | 17.36 |
|
| $ | 14.79 |
|
Realized price, unhedged (per Boe) - Canada |
| $ | 38.98 |
|
| $ | 19.12 |
|
| $ | 29.39 |
|
2019 vs 2018
Net earnings from discontinued operations, net of tax decreased $2.8 billion as we recognized a $2.6 billion ($2.2 billion after-tax) gain on the depletable base changes,sale of our aggregate ownership interests in EnLink and the DD&A rate movesGeneral Partner during 2018. Net earnings from discontinued operations also decreased due to a $748 million asset impairment to our Barnett Shale assets in the same direction.fourth quarter of 2019.
2018 vs 2017
Net earnings from discontinued operations, net of tax increased $1.5 billion as we recognized a $2.6 billion ($2.2 billion after-tax) gain on the sale of our aggregate ownership interests in EnLink and the General Partner during 2018. The per unit DD&A rate is not affectedgain was partially offset by production volumes. Absolute or total DD&A, as opposeda decrease in upstream revenues, which was primarily driven by widening differentials for bitumen sales in Canada to the rate per unitWTI index during the fourth quarter of 2018. Market forces widened Canadian heavy oil differentials beyond historical norms and negatively impacted the price we realized on our Canadian production. We had basis swaps for approximately half of our fourth quarter production generally moves into mitigate the same direction as production volumes.
2016 vs. 2015 DD&A from our oil and gas properties decreased largely becauseeffect of the significant asset impairments recognized throughout 2015 and 2016. lower market price. To further mitigate the effects of the lower price, we reduced our Jackfish production in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d. For discussion of asset impairments,on discontinued operations, see Note 518 in “Item 8. Financial Statements and Supplementary Data” of this report. EnLink’s DD&A increased primarily due to EnLink acquisitions in 2016 and 2015.
2015 vs. 2014 DD&A from our oil and gas properties decreased in 2015 compared to 2014 largely because of the 2014 divestitures of certain U.S. and Canadian assets and the oil and gas asset impairments recognized in 2015. EnLink’s DD&A increased primarily due to EnLink’s acquisitions in 2014 and 2015.
Asset Impairments
During 2016, 2015 and 2014, we recognized asset impairments of $5.0 billion, $20.8 billion and $2.0 billion, respectively. For discussion of asset impairments, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.
Restructuring and Transaction Costs
During 2016, 2015 and 2014, we recognized restructuring and transaction costs of $267 million, $78 million and $46 million, respectively. For discussion of our reorganization programs and the associated restructuring costs, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
3833
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions) |
| |||||||||||||||||
Devon net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
| $ | 488 |
|
|
| +9 | % |
| $ | 450 |
|
|
| - 4 | % |
| $ | 468 |
|
Early retirement of debt |
|
| 269 |
|
| N/M |
|
|
| — |
|
| N/M |
|
|
| 48 |
| ||
Capitalized interest |
|
| (64 | ) |
|
| +18 | % |
|
| (54 | ) |
|
| -7 | % |
|
| (58 | ) |
Other |
|
| 21 |
|
|
| +50 | % |
|
| 14 |
|
|
| - 7 | % |
|
| 15 |
|
Total Devon net financing costs |
|
| 714 |
|
|
| +74 | % |
|
| 410 |
|
|
| - 13 | % |
|
| 473 |
|
EnLink net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
|
| 144 |
|
|
| +26 | % |
|
| 115 |
|
|
| +80 | % |
|
| 64 |
|
Interest accretion on deferred installment payment |
|
| 52 |
|
| N/M |
|
|
| — |
|
| N/M |
|
|
| — |
| ||
Other |
|
| (6 | ) |
|
| - 25 | % |
|
| (8 | ) |
|
| - 27 | % |
|
| (11 | ) |
Total EnLink net financing costs |
|
| 190 |
|
|
| +77 | % |
|
| 107 |
|
|
| +102 | % |
|
| 53 |
|
Total net financing costs |
| $ | 904 |
|
|
| +75 | % |
| $ | 517 |
|
|
| - 2 | % |
| $ | 526 |
|
2016 vs. 2015 Net financing costs increased during 2016 primarily as a result of the retirement premiums and costs related to early redemptions of senior notes in 2016, which is further discussed in Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report. Furthermore, net financing costs increased due to EnLink’s fixed rate borrowings and accretion of its future installment payments related to 2016 acquisition activity discussed in Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
2015 vs. 2014 Net financing costs decreased primarily because of the 2014 early retirement premium and costs and a decrease in average fixed-rate borrowings.
Income Taxes
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
Current income tax expense (benefit) |
| $ | 100 |
|
| $ | (237 | ) |
| $ | 477 |
|
Deferred income tax expense (benefit) |
|
| (273 | ) |
|
| (5,828 | ) |
|
| 1,891 |
|
Total income tax expense (benefit) |
| $ | (173 | ) |
| $ | (6,065 | ) |
| $ | 2,368 |
|
Effective income tax rate |
|
| 4 | % |
|
| 29 | % |
|
| 58 | % |
For discussion on income taxes, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
39
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major source and use categories of ourchanges in cash and cash equivalents.equivalents for the time periods presented below.
|
| Devon |
|
| EnLink |
|
| Consolidated |
| |||||||||||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||||||||
|
| (Millions) |
| |||||||||||||||||||||||||||||||||
Operating cash flow |
| $ | 1,080 |
|
| $ | 4,746 |
|
| $ | 5,507 |
|
| $ | 666 |
|
| $ | 627 |
|
| $ | 514 |
|
| $ | 1,746 |
|
| $ | 5,373 |
|
| $ | 6,021 |
|
Issuance of common stock |
|
| 1,469 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,469 |
|
|
| — |
|
|
| — |
|
Divestitures of property and equipment |
|
| 3,025 |
|
|
| 106 |
|
|
| 5,120 |
|
|
| 93 |
|
|
| 1 |
|
|
| — |
|
|
| 3,118 |
|
|
| 107 |
|
|
| 5,120 |
|
Capital expenditures |
|
| (1,667 | ) |
|
| (4,735 | ) |
|
| (6,192 | ) |
|
| (663 | ) |
|
| (573 | ) |
|
| (796 | ) |
|
| (2,330 | ) |
|
| (5,308 | ) |
|
| (6,988 | ) |
Acquisitions of property, equipment and businesses |
|
| (849 | ) |
|
| (583 | ) |
|
| (6,104 | ) |
|
| (792 | ) |
|
| (524 | ) |
|
| (358 | ) |
|
| (1,641 | ) |
|
| (1,107 | ) |
|
| (6,462 | ) |
Debt activity, net |
|
| (3,383 | ) |
|
| 770 |
|
|
| (2,829 | ) |
|
| 228 |
|
|
| 1,061 |
|
|
| 555 |
|
|
| (3,155 | ) |
|
| 1,831 |
|
|
| (2,274 | ) |
Shareholder and noncontrolling interests distributions |
|
| (221 | ) |
|
| (396 | ) |
|
| (486 | ) |
|
| (304 | ) |
|
| (254 | ) |
|
| (135 | ) |
|
| (525 | ) |
|
| (650 | ) |
|
| (621 | ) |
EnLink and General Partner distributions |
|
| 265 |
|
|
| 268 |
|
|
| 158 |
|
|
| (265 | ) |
|
| (268 | ) |
|
| (158 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
EnLink dropdowns |
|
| — |
|
|
| 167 |
|
|
| — |
|
|
| — |
|
|
| (167 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Issuance of subsidiary units |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 892 |
|
|
| 25 |
|
|
| 410 |
|
|
| 892 |
|
|
| 25 |
|
|
| 410 |
|
Sale of subsidiary units |
|
| — |
|
|
| 654 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 654 |
|
|
| — |
|
Effect of exchange rate and other |
|
| (64 | ) |
|
| (117 | ) |
|
| 172 |
|
|
| 139 |
|
|
| 22 |
|
|
| 36 |
|
|
| 75 |
|
|
| (95 | ) |
|
| 208 |
|
Net change in cash and cash equivalents |
| $ | (345 | ) |
| $ | 880 |
|
| $ | (4,654 | ) |
| $ | (6 | ) |
| $ | (50 | ) |
| $ | 68 |
|
| $ | (351 | ) |
| $ | 830 |
|
| $ | (4,586 | ) |
Cash and cash equivalents at end of period |
| $ | 1,947 |
|
| $ | 2,292 |
|
| $ | 1,412 |
|
| $ | 12 |
|
| $ | 18 |
|
| $ | 68 |
|
| $ | 1,959 |
|
| $ | 2,310 |
|
| $ | 1,480 |
|
|
| Year ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Operating cash flow from continuing operations |
| $ | 2,043 |
|
| $ | 1,583 |
|
| $ | 1,243 |
|
Divestitures of property and equipment |
|
| 390 |
|
|
| 500 |
|
|
| 425 |
|
Capital expenditures |
|
| (1,910 | ) |
|
| (2,116 | ) |
|
| (1,614 | ) |
Acquisitions of property and equipment |
|
| (31 | ) |
|
| (55 | ) |
|
| (44 | ) |
Debt activity, net |
|
| (162 | ) |
|
| (1,226 | ) |
|
| — |
|
Repurchases of common stock |
|
| (1,849 | ) |
|
| (2,956 | ) |
|
| — |
|
Common stock dividends |
|
| (140 | ) |
|
| (149 | ) |
|
| (127 | ) |
Contributions from noncontrolling interests |
|
| 116 |
|
|
| — |
|
|
| — |
|
Other |
|
| (26 | ) |
|
| (46 | ) |
|
| (46 | ) |
Net change in cash, cash equivalents and restricted cash from discontinued operations |
|
| 967 |
|
|
| 4,227 |
|
|
| 888 |
|
Net change in cash, cash equivalents and restricted cash |
| $ | (602 | ) |
| $ | (238 | ) |
| $ | 725 |
|
Cash, cash equivalents and restricted cash at end of period |
| $ | 1,844 |
|
| $ | 2,446 |
|
| $ | 2,684 |
|
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2016.2019. Our operating cash flow decreased $3.6increased $460 million, or 29%, to $2.0 billion or 68%, during 2016. Throughout 2015,year over year. In 2019, our commodity hedges provided us with $2.4 billion of additional operating cash flow. The majority of these hedges expired in 2015 and were the primary driver of our decrease in operating cash flow in 2016. The remaindernearly funded the entirety of the decrease is primarily relatedour capital expenditures program and dividends, allowing us to the continued decrease in commodity prices, partially offset by our focused cost initiatives. use available cash balances and net divestiture proceeds to fund other capital uses.
Our operating cash flow decreased 10% during 2015 primarily dueincreased $340 million, or 27%, from 2017 to lower commodity prices. The effects of lower commodity prices were partially offset by the collection of $425 million of income taxes receivable in the first quarter of 2015 and $2.4 billion of cash settlements associated with our commodity derivatives during 2015.
Excluding payments made for acquisitions, our consolidated2018. Our operating cash flow funded 75%, 100% and 86%approximately 70% of our capital expenditures during 2016, 2015program and 2014,dividends in 2018 and 2017, respectively. In 2016, 2015 and 2014, leveraging our liquidity and other capital resources,As a result, we also usedutilized available cash balances short-term debt, proceeds from EnLink transactions and divestiture proceeds to fundsupplement our acquisitions, dividends and capital requirements.operating cash flows.
Issuance of Common Stock
In February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.
40
Divestitures of Property and EquipmentInvestments – Continuing Operations
During 2016,2019, 2018 and 2017, as part of our announced divestiture programs, we divested certainsold non-core U.S. upstream assets in the U.S.for $390 million, $500 million and our 50% interest in the Access Pipeline in Canada for approximately $3.0 billion, net of purchase price adjustments. Proceeds from these divestitures were used primarily for debt repayment and to support capital investment in Devon’s core resource plays. We did not have significant current cash income taxes resulting from these divestitures.$425 million, respectively. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2014, we divested certain non-core upstream assets in the U.S. and Canada for approximately $5.1 billion. These proceeds were used primarily for debt repayment relating to the GeoSouthern transaction. For additional discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
Capital Expenditures
The following table summarizes our capital expenditures and property acquisitions.
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
Oil and gas |
| $ | 1,624 |
|
| $ | 4,577 |
|
| $ | 5,735 |
|
Corporate and other |
|
| 43 |
|
|
| 158 |
|
|
| 457 |
|
Devon capital expenditures |
|
| 1,667 |
|
|
| 4,735 |
|
|
| 6,192 |
|
EnLink capital expenditures |
|
| 663 |
|
|
| 573 |
|
|
| 796 |
|
Total capital expenditures |
| $ | 2,330 |
|
| $ | 5,308 |
|
| $ | 6,988 |
|
Devon acquisitions |
| $ | 849 |
|
| $ | 583 |
|
| $ | 6,104 |
|
EnLink acquisitions |
|
| 792 |
|
|
| 524 |
|
|
| 358 |
|
Total acquisitions |
| $ | 1,641 |
|
| $ | 1,107 |
|
| $ | 6,462 |
|
|
| Year ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Delaware Basin |
| $ | 912 |
|
| $ | 768 |
|
| $ | 394 |
|
STACK |
|
| 396 |
|
|
| 827 |
|
|
| 742 |
|
Powder River Basin |
|
| 308 |
|
|
| 157 |
|
|
| 121 |
|
Eagle Ford |
|
| 194 |
|
|
| 215 |
|
|
| 115 |
|
Other |
|
| 36 |
|
|
| 110 |
|
|
| 155 |
|
Total oil and gas |
|
| 1,846 |
|
|
| 2,077 |
|
|
| 1,527 |
|
Midstream |
|
| 42 |
|
|
| 16 |
|
|
| 50 |
|
Other |
|
| 22 |
|
|
| 23 |
|
|
| 37 |
|
Total capital expenditures |
| $ | 1,910 |
|
| $ | 2,116 |
|
| $ | 1,614 |
|
Acquisitions |
| $ | 31 |
|
| $ | 55 |
|
| $ | 44 |
|
34
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations our midstream operations,and other corporate activities and EnLink growth and maintenance activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. In responseOur capital program is designed to our loweroperate within or near operating cash flow Devon’s 2016 capital program was designedand may fluctuate with changes to be lower than 2015.commodity prices and other factors impacting cash flow. This change is evidenced by a 56% decrease in totalour operating cash flow fully funding capital expenditures from 2015 to 2016, excluding acquisitions. Since 2014, we have reduced ourin 2019 and funding approximately 75% and 77% of capital expenditures by approximately 70%.
Capital expenditures for Devon’sin 2018 and EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. Midstream2017, respectively. Our capital expenditures are largely impactedlower in 2019 primarily due to our decreased spending in the STACK, partially offset by oil and gas drilling and development activities.
Acquisitionincreased capital investment in 2016 primarily consisted of Devon’s bolt-on acquisition ofhigher margin assets in the STACK play for $1.5 billionDelaware and EnLink’s acquisitionPowder River Basins.
Debt Activity, Net
During 2019, our debt decreased $162 million due to the repayment of Anadarko Basin gathering and processing midstream assets for $1.5 billion. Approximately $849our 6.30% senior notes at maturity.
During 2018, our debt decreased $922 million and $792 million, respectively, was paid in cash atdue to completed tender offers of certain long-term debt as well as the closingsmaturity of certain senior notes. In conjunction with the remaindertender offers, we recognized a $312 million loss on the early retirement of the purchase prices funded with equity considerationdebt, including $304 million of cash retirement costs and debt. In 2015 our acquisition activity primarily consisted of the Powder River Basin asset acquisition in the fourth quarter. The majority of the acquisition capital in 2014 related to the GeoSouthern acquisition in the Eagle Ford. EnLink’s acquisitions in 2015 and 2014 consisted offees. For additional oil and gas pipeline assets, including gathering, transportation and processing facilities. For further discussion on acquisition activity,information, see Note 213 in “Item 8. Financial Statements and Supplementary Data” of this report.
Debt Activity, Net
During 2016, our consolidated net debt decreased $2.9 billion. The decrease was primarily due to completed tender offers to purchase and redeem $2.1 billion of debt securities prior to their maturity and a $1 billion reduction in short-term borrowings during 2016. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt, including $265 million of cash retirement costs and fees. The decrease was partially
41
Index to Financial StatementsRepurchases of Common Stock and Shareholder Distributions
offsetWe repurchased 68.6 million shares of common stock for $1.8 billion in 2019 and 78.1 million shares of common stock for $3.0 billion in 2018 under a share repurchase program authorized by $229 millionour Board of net borrowings from EnLink.Directors. For additional information, see Note 1417 in “Item 8. Financial Statements and Supplementary Data” in this report.
During 2015, our consolidated net debt increased $1.8 billion. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter. EnLink’s net debt borrowings increased $1.1 billion primarily from borrowings made to fund acquisitions and dropdowns.
During 2014, we decreased our net debt by $2.2 billion. The decrease was primarily related to the repayment of debt used to fund the GeoSouthern transaction. This was partially offset by $555 million of net borrowings from EnLink to fund its operations.
Shareholder and Noncontrolling Interests Distributions
The following table summarizes ourDevon paid common stock dividends.
| Amounts |
|
| Rate |
| ||
| (Millions) |
|
| (Per Share) |
| ||
Year Ended 2016: |
|
|
|
|
|
|
|
First quarter 2016 | $ | 125 |
|
| $ | 0.24 |
|
Second quarter 2016 |
| 33 |
|
| $ | 0.06 |
|
Third quarter 2016 |
| 32 |
|
| $ | 0.06 |
|
Fourth quarter 2016 | 31 |
|
| $ | 0.06 |
| |
Total year-to-date | $ | 221 |
|
|
|
|
|
Year Ended 2015: |
|
|
|
|
|
|
|
First quarter 2015 | $ | 99 |
|
| $ | 0.24 |
|
Second quarter 2015 |
| 98 |
|
| $ | 0.24 |
|
Third quarter 2015 |
| 99 |
|
| $ | 0.24 |
|
Fourth quarter 2015 |
| 100 |
|
| $ | 0.24 |
|
Total year-to-date | $ | 396 |
|
|
|
|
|
Year Ended 2014: |
|
|
|
|
|
|
|
First quarter 2014 | $ | 90 |
|
| $ | 0.22 |
|
Second quarter 2014 |
| 99 |
|
| $ | 0.24 |
|
Third quarter 2014 |
| 98 |
|
| $ | 0.24 |
|
Fourth quarter 2014 |
| 99 |
|
| $ | 0.24 |
|
Total year-to-date | $ | 386 |
|
|
|
|
|
In response todividends of $140 million, $149 million and $127 million during 2019, 2018 and 2017, respectively. During the depressed commodity price environment,second quarter of 2018, we reducedincreased our quarterly dividend 33% from $0.06 to $0.06$0.08 per share as part of our focus on returning cash to shareholders. In February 2019, we further increased our quarterly dividend 12.5% to $0.09 per share, beginning in the second quarter of 2016.
In conjunction with the formation of EnLink in the first quarter of 2014, we made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $304 million, $254 million and $135 million to non-Devon unitholders during 2016, 2015 and 2014, respectively.
EnLink and General Partner Distributions
Devon received $265 million, $268 million and $158 million in distributions from EnLink and the General Partner during 2016, 2015 and 2014, respectively.
42
In the second quarter of 2015, Devon received $167 million in cash from EnLink in exchange for VEX.2019. For further discussion,additional information, see Note 217 in “Item 8. Financial Statements and Supplementary Data” of this report.
Issuance
Contributions from Noncontrolling Interests
During 2019, we received approximately $116 million in cash contributions from our partner in CDM.
35
Table of Subsidiary UnitsContents
Cash Flows from Discontinued Operations
All cash flows in the following table relate to activities from discontinued operations for the time periods presented. Discontinued operations include our aggregate ownership interests in EnLink and the General Partner that Devon divested in July 2018 and the Canadian business that Devon sold in June 2019. Discontinued operations also include the Barnett Shale assets that Devon has contracted to sell and which is expected to close during the second quarter of 2020, as well as previously divested Barnett Shale properties located primarily in Johnson and Wise counties, Texas.
|
| Year ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Settlements of intercompany foreign denominated assets/liabilities |
| $ | (32 | ) |
| $ | (241 | ) |
| $ | 9 |
|
Other |
|
| 60 |
|
|
| 1,362 |
|
|
| 1,657 |
|
Operating activities |
|
| 28 |
|
|
| 1,121 |
|
|
| 1,666 |
|
Divestitures of property and equipment - Canadian operations |
|
| 2,608 |
|
|
| — |
|
|
| — |
|
Divestitures of investments - EnLink and General Partner |
|
| — |
|
|
| 3,104 |
|
|
| 190 |
|
Divestitures of property and equipment - Barnett Shale assets |
|
| — |
|
|
| 513 |
|
|
| — |
|
Capital expenditures and other |
|
| (136 | ) |
|
| (891 | ) |
|
| (1,156 | ) |
Investing activities |
|
| 2,472 |
|
|
| 2,726 |
|
|
| (966 | ) |
Debt activity, net |
|
| (1,552 | ) |
|
| 347 |
|
|
| 2 |
|
Issuance of subsidiary units |
|
| — |
|
|
| 1 |
|
|
| 501 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| (217 | ) |
|
| (354 | ) |
Other |
|
| (26 | ) |
|
| 43 |
|
|
| 33 |
|
Financing activities |
|
| (1,578 | ) |
|
| 174 |
|
|
| 182 |
|
Settlements of intercompany foreign denominated assets/liabilities |
|
| 32 |
|
|
| 241 |
|
|
| (9 | ) |
Other |
|
| 13 |
|
|
| (35 | ) |
|
| 15 |
|
Effect of exchange rate changes on cash |
|
| 45 |
|
|
| 206 |
|
|
| 6 |
|
Net change in cash, cash equivalents and restricted cash of discontinued operations |
| $ | 967 |
|
| $ | 4,227 |
|
| $ | 888 |
|
Operating cash flow in 2019 decreased $1.1 billion and $1.6 billion from 2018 and 2017, respectively, as a result of the divestitures referenced above. Additionally, operating cash flow was negatively affected in the first quarter of 2019 primarily due to realization impacts associated with the widening Canadian differentials in the fourth quarter of 2018. Foreign currency denominated intercompany loan activity resulted in a realized loss of $32 million and $241 million in 2019 and 2018, respectively, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. Foreign currency denominated intercompany loan activity resulted in a realized gain of $9 million in 2017, as a result of the weakening of the U.S. dollar in relation to the Canadian dollar. There was an offset in the effect of exchange rate changes on cash line in the above table, resulting in no impact to the net change in cash, cash equivalents and restricted cash.
On June 27, 2019, Devon completed the sale of substantially all its oil and gas assets and operations in Canada for proceeds of $2.6 billion. In January 2016, to fundthe second and fourth quarter of 2018, Devon completed the sale of a portion of its Barnett Shale assets, located primarily in Johnson and Wise counties, Texas for approximately $500 million in combined proceeds. On July 18, 2018, Devon completed the cash considerationsale of its acquisition of Anadarko Basin gatheringaggregate ownership interests in EnLink and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million.the General Partner for $3.125 billion. During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.
Cash flows from financing activities includes the $1.5 billion of senior notes retired prior to maturity in July 2019 and common units were also issued as consideration in the transaction.
During 2016, 2015 and 2014,preferred units EnLink issued and sold approximately 10.0 million, 1.3 million and 14.8 million common units through general public offerings and its “at the market” equity program,during 2017 generating net proceeds of approximately $167 million, $25$501 million. Distributions to noncontrolling interests in the table above exclude the distributions EnLink and the General Partner paid to Devon, which have been eliminated in consolidation. Distributions EnLink and the General Partner paid to Devon were $134 million and $410$265 million during 2018 and 2017, respectively.
SaleLiquidity
The business of Subsidiary Unitsexploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production
In early 2015, we conducted an underwritten secondary public offering36
from existing wells. At opportunistic times, we also acquire operations and Supplementary Data”properties from other operators or land owners to enhance our existing portfolio of this report.
Effect of Exchange Rate and Other
In 2016, EnLink received contributions from noncontrolling interests. For further discussion see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
Liquidityassets.
Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds and cash on hand.proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidity include, among other things, If needed, we can also issue debt and equity securities, that can be issued pursuant 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 2016 has come from approximately $3.0 billion 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 and other contractual commitmentsrequirements as discussed in this section.
Operating Cash Flow
Key inputs into determining our planned capital investment is the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of 2019, we held approximately $1.8 billion of cash, inclusive of $380 million of cash restricted for discontinued operations. Our operating cash flow isforecasts are sensitive to many variables theand include a measure of uncertainty as these variables differ from our expectations.
Commodity Prices – The most uncertain and volatile 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 decreased 68% in 2016 as a result of the expiration of certain favorable commodity hedging positions and the continued decrease in commodity prices. In spite of this decline, we expect operating cash flow to continue to be a primary source of liquidity as we adjust our capital program in response to lower commodity prices. Additionally, we anticipate utilizing our credit availability to provide additional liquidity as needed.
Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. As
To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a result, entering into 2017 we have hedged approximately 50%portion of our oil and 45%production against downside price risk. We hedge our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of our gas production.favorable market conditions. The key
43
terms to our oil, gas and NGL derivative financial instruments as of December 31, 20162019 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Should WTI drop closer to $45/Bbl for an extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI/Bbl rises above $50, our free cash flow will accelerate, providing additional capital allocation opportunities.
Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.
Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2016,In 2019, we had total debt of $10.2 billion. Of this amount, $10.0 billion bears fixed interest rates averaging 5.3%,aggressively optimized our cost structure in conjunction with our Canadian and approximately $150 million is comprised of floating rate debtBarnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with interest rates averaging 2.5%.
As of December 31, 2016, we had open interest rate swap positions that are presented in Note 3 in “Item 8. Financial Statementsthe retained business and Supplementary Data” in this report.reduce outstanding debt. These optimizations include cost reductions and efficiencies related to our capital programs, G&A, financing costs and production expenses.
Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint-interestjoint interest partners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.
As recent years indicate,37
Divestitures of Property and Equipment
In December 2019, we have a history of investing more than 100%announced the sale of our operating cash flow into capital development activitiesBarnett Shale assets for approximately $770 million. We expect this transaction to grow our company and maximize value for our shareholders. Therefore, negative movementsclose in anythe second quarter of the variables discussed above would not only impact our operating cash flow but also would likely impact the amount of capital investment we could or would make. In the current environment, assuming current pricing expectations, our 2017 exploration and development capital budget is expected to be approximately $2.0 billion to $2.3 billion.
At the end of 2016, we held approximately $2.0 billion of cash. Included in this total was $644 million of cash held by our foreign subsidiaries. If we were to repatriate a portion or all of the cash held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U.S. tax law. The payment of such additional income tax would decrease the amount of cash ultimately available to fund our business.2020.
Credit Availability
We have a $3.0 billion of available borrowing capacity under our Senior Credit Facility. TheFacility at December 31, 2019. On December 13, 2019, we entered into an amendment and extension agreement to, among other things, (i) effect the extension of the maturity date for $30 million of the Senior Credit Facility isfrom October 24, 2017. The5, 2023 to October 5, 2024 with respect to the consenting lenders and (ii) modify the maximum number of maturity date for $164 millionextension requests during the term of the Senior Credit Facility isfrom two to three. As a result of this amendment, the Senior Credit Facility matures on October 24, 2018. 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, 2016,2019, there were no borrowings under our commercial paper program. See Note 1413 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.
The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as full cost ceiling and goodwill impairments. As of December 31, 2016,2019, we were in compliance with this covenant. Ourcovenant with a 19.1% debt-to-capitalization ratio at December 31, 2016, as calculated pursuant to the terms of the agreement, was 18.7%.ratio.
44
Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the creditagreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.
As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and near-term and long-term production growth opportunities. In February 2016, ourOur credit rating was revised byfrom Standard &and Poor’s Financial Services from BBB+is BBB- with a negative outlook tostable outlook. Our credit rating from Fitch is BBB with a stable outlook, andoutlook. Our credit rating from Moody’s Investor Service revised our senior unsecured rating from Baa1is Ba1 with a stable outlook to Ba2 with negativepositive outlook. In March 2016, Fitch Ratings affirmed our BBB+ rating but revised our outlook from stable to negative. Further, in July 2016, Moody’s revised the outlook to stable. The downgrade in ratings required us to post letters of credit and cash collateral as financial assurance of performance under certain contractual arrangements. Any further rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, these downgradesa downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.
Share Repurchase Program
In December 2019, our Board of Directors approved a $1.0 billion share repurchase program that expires on December 31, 2020. This repurchase program was approved in conjunction with the announced divestiture of Devon’s assets in the Barnett Shale. Under this new program, $800 million of the $1.0 billion authorization is conditioned upon the closing of the pending Barnett Shale divestiture.
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Capital Expenditures
Excluding EnLink,Our 2020 exploration and development budget is expected to be approximately $1.7 billion to $1.85 billion.
In December 2019, we announced a partnership under which we will monetize half our 2017 capital expendituresworking interest across 133 undrilled locations in the STACK for an approximate $100 million drilling carry spread over the next four years. Drilling operations under this agreement are expected to range from $2.3 billion to $2.7 billion, including $2.0 billion to $2.3 billion for our exploration and development capital program. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2017 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2017 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2017, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2017 capital expenditures.
EnLink Liquidity
EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2016, there were $12 millioncommence in outstanding letters of credit and $120 million borrowed under the $1.5 billion credit facility and $28 million outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.mid-2020.
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EnLink’s 2017 capital budget includes approximately $610 million to $770 million of identified growth projects. EnLink’s primary capital projects for 2017 include construction of the Lobo II plant and gathering system in the Delaware Basin, completing construction of an NGL pipeline in Louisiana and development of its Tall Oak assets.
EnLink expects to fund the growth capital expenditures from the proceeds of borrowings under its bank credit facility and proceeds from other debt and equity sources. EnLink expects to fund its 2017 maintenance capital expenditures from operating cash flows. EnLink employs a strategy that includes maintaining stable operating cash flows that are supported by long-term, fixed-fee contracts. Approximately 97% of EnLink’s cash flows were generated from fee-based services in 2016. In 2017, it is possible that not all of the planned projects will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.
Contractual Obligations
The following table presents a summary of our contractual obligations as of December 31, 2016.2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Payments Due by Period |
| |||||||||||||||||
|
| Total |
|
| Less Than 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
|
| More Than 5 Years |
| |||||
|
| (Millions) |
| |||||||||||||||||
Devon obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt (1) |
| $ | 6,933 |
|
| $ | — |
|
| $ | 277 |
|
| $ | 500 |
|
| $ | 6,156 |
|
Interest expense (2) |
|
| 6,579 |
|
|
| 390 |
|
|
| 771 |
|
|
| 752 |
|
|
| 4,666 |
|
Purchase obligations (3) |
|
| 2,949 |
|
|
| 609 |
|
|
| 1,411 |
|
|
| 929 |
|
|
| — |
|
Operational agreements (4) |
|
| 4,726 |
|
|
| 545 |
|
|
| 914 |
|
|
| 600 |
|
|
| 2,667 |
|
Operational agreements with EnLink (5) |
|
| 1,589 |
|
|
| 600 |
|
|
| 847 |
|
|
| 142 |
|
|
| — |
|
Asset retirement obligations (6) |
|
| 1,258 |
|
|
| 46 |
|
|
| 143 |
|
|
| 163 |
|
|
| 906 |
|
Drilling and facility obligations (7) |
|
| 388 |
|
|
| 76 |
|
|
| 133 |
|
|
| 94 |
|
|
| 85 |
|
Lease obligations (8) |
|
| 371 |
|
|
| 50 |
|
|
| 168 |
|
|
| 98 |
|
|
| 55 |
|
Other (9) |
|
| 202 |
|
|
| 202 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total Devon obligations |
|
| 24,995 |
|
|
| 2,518 |
|
|
| 4,664 |
|
|
| 3,278 |
|
|
| 14,535 |
|
EnLink obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt (1) |
|
| 3,311 |
|
|
| — |
|
|
| 428 |
|
|
| 120 |
|
|
| 2,763 |
|
Interest expense (2) |
|
| 1,966 |
|
|
| 144 |
|
|
| 283 |
|
|
| 267 |
|
|
| 1,272 |
|
Other (9) |
|
| 794 |
|
|
| 313 |
|
|
| 334 |
|
|
| 35 |
|
|
| 112 |
|
Total EnLink obligations |
|
| 6,071 |
|
|
| 457 |
|
|
| 1,045 |
|
|
| 422 |
|
|
| 4,147 |
|
Total obligations |
| $ | 31,066 |
|
| $ | 2,975 |
|
| $ | 5,709 |
|
| $ | 3,700 |
|
| $ | 18,682 |
|
|
| Payments Due by Period |
| |||||||||||||||||
|
| Total |
|
| Less Than 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
|
| More Than 5 Years |
| |||||
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt (1) |
| $ | 4,349 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 4,349 |
|
Interest expense (2) |
|
| 4,513 |
|
|
| 259 |
|
|
| 518 |
|
|
| 518 |
|
|
| 3,218 |
|
Operational agreements (3) |
|
| 1,468 |
|
|
| 320 |
|
|
| 431 |
|
|
| 301 |
|
|
| 416 |
|
Asset retirement obligations (4) |
|
| 398 |
|
|
| 18 |
|
|
| 13 |
|
|
| 25 |
|
|
| 342 |
|
Drilling and facility obligations (5) |
|
| 262 |
|
|
| 131 |
|
|
| 61 |
|
|
| 38 |
|
|
| 32 |
|
Lease obligations (6) |
|
| 426 |
|
|
| 51 |
|
|
| 53 |
|
|
| 24 |
|
|
| 298 |
|
Other (7) |
|
| 223 |
|
|
| 11 |
|
|
| 75 |
|
|
| 32 |
|
|
| 105 |
|
Total |
|
| 11,639 |
|
|
| 790 |
|
|
| 1,151 |
|
|
| 938 |
|
|
| 8,760 |
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale obligations (8) |
|
| 271 |
|
|
| 35 |
|
|
| 63 |
|
|
| 46 |
|
|
| 127 |
|
Canadian obligations (9) |
|
| 347 |
|
|
| 55 |
|
|
| 69 |
|
|
| 55 |
|
|
| 168 |
|
Total |
|
| 618 |
|
|
| 90 |
|
|
| 132 |
|
|
| 101 |
|
|
| 295 |
|
Total obligations |
| $ | 12,257 |
|
| $ | 880 |
|
| $ | 1,283 |
|
| $ | 1,039 |
|
| $ | 9,055 |
|
(1) | Debt amounts represent scheduled maturities of debt obligations at December 31, |
(2) | Interest expense represents the scheduled cash payments on long-term fixed-rate debt. |
(3) |
|
| 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. |
46
| Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, |
| 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. |
| Lease obligations consist primarily of non-cancelable leases for office space and |
|
|
(7) | Other |
(8) | Barnett Shale obligations primarily represent approximately $240 million of |
(9) | Canadian obligations are related to a firm transportation agreement and office lease abandonments that were retained after Devon’s sale of substantially all of its oil and gas assets and operations in Canada. For additional information, see Note 18in “Item 8. Financial Statements and Supplementary Data” of this report. |
Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 19 in “Item 8. Financial Statements and Supplementary Data” of this report.
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Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.
Full Cost
Oil and Gas Assets Accounting, Classification, Reserves & Valuation
Successful Efforts Method of Accounting and Proved Classification
We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management’s assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.
Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, management considers current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of comprehensive earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2019, all suspended well costs have been suspended for less than one year.
Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2019, Devon had approximately $250 million of undeveloped leasehold. Of the remaining undeveloped leasehold costs at December 31, 2019, approximately $6 million is scheduled to expire in 2020. The leasehold expiring in 2020 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.
Reserves
Our estimates of proved and proved developed reserves are a major component of the depletion and full cost ceilingDD&A calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by a third-party petroleum consulting firms.firm. In 2016, 89%2019, 85% of our reserves were subjected to such audits.
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such
47
40
rules also dictate that a 10% discount factor be used. Therefore, the discounted future net revenues associated with the estimatedValuation of Long-Lived Assets
Long-lived assets used in operations, including proved reserves are not based on our assessment of future prices or costs or our enterprise risk.
Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Because of the volatile nature of oil and gas prices, it generally is not possible to predict the timing or magnitude of full cost write-downs. In addition, because of the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.
Based on prices from the last nine months of 2016 and the short-term pricing outlook for the first quarter of 2017, we do not expect to recognize U.S. and Canadian full cost impairments in the first quarter of 2017.
Derivative Financial Instruments
We enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge future prices received. Additionally, EnLink periodically enters into derivative financial instruments with respect to its oil, gas and NGL marketing activity. These commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.
The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX WTI forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using U.S. Treasury bill rates. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.
We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest rate yields. The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rates. These yield and discounting variables are sensitive to the period of the contract and market volatility.
We periodically enter into foreign exchange forward contracts to manage our exposure to fluctuations in exchange rates. Under the terms of our foreign exchange forward contracts, we generally receive U.S. dollars and pay Canadian dollars based on a total notional amount. We estimate the fair values of our foreign exchange forward contracts primarily by using internal discounted cash flow calculations based upon forward exchange rates. The most significant variable to our cash flow calculations is our observation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are discounted using Treasury rates. These discounting variables are sensitive to the period of the contract and market volatility.
48
We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties.
Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our oil, gas and NGL commodity derivative contracts are held with thirteen separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels.
Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.
Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding the effects that changes in market prices can have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.
Business Combinations
Accounting for the acquisition of a business requires the assets and liabilities of the acquired business to be recorded at fair value. Deferred taxes are recorded for any differences between the fair value and the tax basis of the acquired assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill.
There are various assumptions we make in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of theunproved oil and gas properties, acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gasare depreciated and NGL reserves. These estimates areassessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual assets based on work performed by our engineers and thata judgmental assessment of outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.
However,lowest level (“common operating field”) for which there are factors involvedidentifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of common operating fields is largely based on geological structural features or stratigraphic condition, which requires judgment. Management also considers the nature of production, common infrastructure, common sales points, common processing plants, common regulation and management oversight to make common operating field determinations. These determinations impact the amount of DD&A recognized each period and could impact the determination and measurement of a potential asset impairment.
Management evaluates assets for impairment through an established process in estimatingwhich 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 valuesvalue. Because there usually is a lack of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies a historical 12-month average price to the reserves to arrive at the ceiling amount. By contrast,quoted market prices for long-lived assets, the fair value of reserves acquired in a business combination must beimpaired assets is typically determined based on our estimatesthe present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future oil, natural gasproduction volumes, commodity prices, operating costs and NGL prices. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.
We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriatecapital investment plans, considering all available information at the timedate of the business combination based upon our cost of capital.
We also apply these same general principles to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value ofreview. The expected future cash flows used for impairment reviews include future production volumes associated with proved producing and risk-adjusted proved undeveloped, probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate forBesides the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we consider to be an appropriate risk-weighting factor in each particular instance.
49
In addition, our acquisitions have involved other entities whose operations included substantial midstream activities. In these transactions, the purchase price is allocated to the fair value of midstream facilities and equipment, generally consisting of processing facilities and pipeline systems. Estimating the fair value of these assets requires certain assumptions to be made regarding future quantities of commodities estimated to be processed and transported through these facilities and pipelines, as well as estimates of reserves and future expected prices and operating and capital costs.
Goodwill
We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. While we use data as of October 31 for our test, we typically complete the test in late December or early January as the October 31 market data used in our test becomes available. We first assess the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we determine that it is more likely than not that its fair value is less than its carrying amount, then the two-step goodwill impairment test is performed.
In the first step of the impairment test, the fair value of a reporting unit is compared to its carrying value. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed for purposes of measuring the impairment. In the second step, the fair value of the reporting unit is allocated to all of the assets and liabilities of the reporting unit to determine an implied goodwill value. This allocation is similar to a purchase price allocation. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue growth rates driven byproduction volumes, future commodity prices and volume expectations, operating margins and capital expenditures.
Forare the October 31, 2016 impairment tests for Devon’s U.S. reporting unit and each of EnLink’s reporting units, step one of the impairment analyses showed that the fair value of each reporting unit exceeded its carrying value.
Sustained weaknesslargest driver in the overall energy sector drivenvariability of undiscounted pre-tax cash flows. For our impairment determinations, we utilize the forward strip prices for the first five years and apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future capital and operating costs by lowusing a method that correlates cost movements to price movements similar to recent history. Changes to any of these assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Should management materially reduce planned capital investment and commodity prices together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment testremain depressed, recognition of material asset impairments could become more likely for EnLink’s reporting units in the first quartercertain of 2016. Using the fair value approaches described above, in the first quarter of 2016 it was determined that the estimated fair value of EnLink’s Texas, General Partner and Crude and Condensate reporting units were less than their carrying amounts, primarily due to changes in assumptions related toour assets.
As commodity prices decreased throughout 2019 and discount rates. Throughat year-end approximated the analysis,prices Devon used to determine and compute material asset impairments in 2019, management conducted a goodwillrobust review of its assets for impairment loss of $473 million, $307 million and $93 million for EnLink’s Texas, General Partner and Crude and Condensate reporting units, respectively, was recognized in the first quarter of 2016.
As of March 31, 2016, the goodwill allocated to the Crude and Condensate reporting unit was fully impaired. Other than those mentioned above, no other goodwill impairment was identified or recorded for the remaining reporting units as a result of the interim goodwill assessment, as their estimated fair values were in excess of carrying values. However, the fair value of EnLink’s Texas and General Partner reporting units are not substantially in excess of their carrying value. The fair value of the Texas and General Partner reporting units approximates their carrying values after considering the impairment loss above, and as of December 31, 2016, $233 million and $1.1 billion2019. Based on our recent impairment evaluations, our STACK asset’s sum of goodwill remains allocated to the reporting units, respectively.
Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be
50
recognized in the period in which we would determine thatundiscounted pre-tax cash flows exceeds the carrying value exceeds fair value. We would expect that a prolonged or sustained periodby less than 10%. This cushion has narrowed significantly since the end of lower2018 due primarily to approximately 30% and 5% declines in forward NGL and natural gas pricing, respectively, and negative non-price reserve revisions of approximately 40 MMBoe as discussed in Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report.As of December 31, 2019, the difference between the STACK’s undiscounted pre-tax cash flows, which is used to determine whether an impairment exists, and the discounted pre-tax cash flows, which is used to measure an impairment, is approximately $2.0 billion. Therefore, if commodity prices would adversely affectdeteriorate or we materially reduce future development plans, causing the estimate of future operating results, which could result in future goodwill impairments for other reporting units duecapitalized costs to exceed the potential impact on theundiscounted pre-tax cash flows, of our operations.
TheSTACK asset would be subject to a material impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.
Other Intangible Assets
In 2015, the assessment of customer relationships was updated due to the factors described in the aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment.
The other intangible assets impairment has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.capitalized costs.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. At the endWithin continuing operations, Devon maintains only a valuation allowance against a portion of 2016 and 2015, we hadits deferred tax assets, that largely resulted from the full cost impairments recognized throughout 2015including certain tax credits and 2016. As a result of our recent cumulative losses and our current realization assessment, westate net operating losses. Devon also has recorded a 100% valuation allowance against our U.S. deferred tax assets as of December 31, 2016 and December 31, 2015. Further, in 2016, we recorded a $69 million valuation allowancediscontinued operations against certain Canadian deferred tax assets as a result of continued financial losses. assets.
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.
We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S. and existing U.S. income tax laws, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.
For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:
separate analysis of a diverse chain of foreign entities;
relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;
5141
further analysis of a variety of other inputs such as the earnings, profits, U.S./foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.
Because of the administrative burden required to perform these additional activities, it is impractical to calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of companies.
Non-GAAP Measures
Core Earnings
We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 20162019 Results” in this Item 7.7 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as alternatives to GAAP measures.a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash or non-recurringand other items that are typically excluded by securities analysts in their published estimates of our financial results. For more information on the results of discontinued operations for our Barnett Shale assets, Canadian operations and for EnLink and the General Partner, see Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring when comparing on an annual basis. In the table below, restructuring and transaction costs were incurred in each of the three year periods; however, these costs relate to different restructuring programs. Amounts excluded for 20162019 relate to derivatives and financial instrument fair value changes,asset dispositions, the gain on the sale of Canadian operations, noncash asset impairments (including an impairment of goodwill)noncash Barnett Shale and unproved asset impairments), deferred tax asset valuation allowance, gains and losses on asset sales, costs associated with early retirement of debt, fair value changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with the workforce reductions in 2019 and restructuring and transaction costs associated with the 2016 workforce reduction.divestment of our Canadian operations in 2019.
Amounts excluded for 20152018 relate to asset dispositions, the gain on the sale of Devon’s aggregate ownership interests in EnLink and the General Partner, noncash asset impairments (including noncash unproved asset impairments), deferred tax asset valuation allowance, costs associated with early retirement of debt, fair value changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with the workforce reductions in 2018.
Amounts excluded for 2017 relate to asset dispositions, noncash asset impairments (including noncash unproved asset impairments), U.S. tax reform changes, deferred tax asset valuation allowance, derivatives and financial instrument fair value changes, asset impairments (including an impairment of goodwill), deferred tax asset valuation allowance,legal entity restructuring and transaction costs and repatriation of funds to the U.S.
Amounts excluded for 2014 relate to derivatives and financial instrument fair value changes, asset impairments (including an impairment of goodwill), gains and losses on asset sales, costs associated with early retirement of debt, restructuring and transaction costs associated with our 2014 divestiture program, repatriation of proceeds to the U.S. and deferred income tax on the formation of the General Partner. For more information on our restructuring programs, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.debt.
We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts, which typically make similar adjustments in their estimates of our financial results.analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.
52
Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.
42
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| ||||
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to Devon (GAAP) | $ | (109 | ) |
| $ | (79 | ) |
| $ | (81 | ) |
| $ | (0.21 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (48 | ) |
|
| (37 | ) |
|
| (37 | ) |
|
| (0.09 | ) |
Asset and exploration impairments |
| 20 |
|
|
| 15 |
|
|
| 15 |
|
|
| 0.04 |
|
Fair value changes in financial instruments |
| 623 |
|
|
| 480 |
|
|
| 480 |
|
|
| 1.19 |
|
Restructuring and transaction costs |
| 84 |
|
|
| 64 |
|
|
| 64 |
|
|
| 0.15 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 570 |
|
| $ | 443 |
|
| $ | 441 |
|
| $ | 1.08 |
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to Devon (GAAP) | $ | (632 | ) |
| $ | (274 | ) |
| $ | (274 | ) |
| $ | (0.68 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of Canadian operations |
| (223 | ) |
|
| (425 | ) |
|
| (425 | ) |
|
| (1.05 | ) |
Asset and exploration impairments |
| 785 |
|
|
| 613 |
|
|
| 613 |
|
|
| 1.52 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| 24 |
|
|
| 24 |
|
|
| 0.06 |
|
Early retirement of debt |
| 58 |
|
|
| 45 |
|
|
| 45 |
|
|
| 0.11 |
|
Fair value changes in financial instruments and foreign currency and other |
| (33 | ) |
|
| (37 | ) |
|
| (37 | ) |
|
| (0.10 | ) |
Restructuring and transaction costs |
| 248 |
|
|
| 183 |
|
|
| 183 |
|
|
| 0.45 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 203 |
|
| $ | 129 |
|
| $ | 129 |
|
| $ | 0.31 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to Devon (GAAP) | $ | (741 | ) |
| $ | (353 | ) |
| $ | (355 | ) |
| $ | (0.89 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
| 679 |
|
|
| 522 |
|
|
| 522 |
|
|
| 1.29 |
|
Discontinued Operations |
| 835 |
|
|
| 403 |
|
|
| 403 |
|
|
| 0.99 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 773 |
|
| $ | 572 |
|
| $ | 570 |
|
| $ | 1.39 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 944 |
|
| $ | 714 |
|
| $ | 714 |
|
| $ | 1.42 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (278 | ) |
|
| (214 | ) |
|
| (214 | ) |
|
| (0.42 | ) |
Asset and exploration impairments |
| 257 |
|
|
| 198 |
|
|
| 198 |
|
|
| 0.40 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| (4 | ) |
|
| (4 | ) |
|
| (0.01 | ) |
Early retirement of debt |
| 312 |
|
|
| 240 |
|
|
| 240 |
|
|
| 0.48 |
|
Fair value changes in financial instruments |
| (938 | ) |
|
| (723 | ) |
|
| (723 | ) |
|
| (1.45 | ) |
Restructuring and transaction costs |
| 97 |
|
|
| 76 |
|
|
| 76 |
|
|
| 0.15 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 394 |
|
| $ | 287 |
|
| $ | 287 |
|
| $ | 0.57 |
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 2,839 |
|
| $ | 2,510 |
|
| $ | 2,350 |
|
| $ | 4.68 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (2,593 | ) |
|
| (2,250 | ) |
|
| (2,250 | ) |
|
| (4.49 | ) |
Fair value changes in financial instruments and foreign currency |
| 339 |
|
|
| 277 |
|
|
| 270 |
|
|
| 0.54 |
|
Minimum volume commitment and restructuring and transaction costs |
| (31 | ) |
|
| (27 | ) |
|
| (2 | ) |
|
| (0.00 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 554 |
|
| $ | 510 |
|
| $ | 368 |
|
| $ | 0.73 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 3,783 |
|
| $ | 3,224 |
|
| $ | 3,064 |
|
| $ | 6.10 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
| (550 | ) |
|
| (427 | ) |
|
| (427 | ) |
|
| (0.85 | ) |
Discontinued Operations |
| (2,285 | ) |
|
| (2,000 | ) |
|
| (1,982 | ) |
|
| (3.95 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 948 |
|
| $ | 797 |
|
| $ | 655 |
|
| $ | 1.30 |
|
43
| Year Ended December 31, |
| |||||||||||||
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Share |
| ||||
|
|
| |||||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to Devon (GAAP) | $ | (3,877 | ) |
| $ | (3,704 | ) |
| $ | (3,302 | ) |
| $ | (6.52 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains and losses on asset sales |
| (1,890 | ) |
|
| (1,243 | ) |
|
| (1,249 | ) |
|
| (2.44 | ) |
Asset impairments |
| 4,996 |
|
|
| 3,599 |
|
|
| 3,176 |
|
|
| 6.28 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| 851 |
|
|
| 851 |
|
|
| 1.66 |
|
Restructuring and transaction costs |
| 267 |
|
|
| 173 |
|
|
| 170 |
|
|
| 0.33 |
|
Fair value changes in financial instruments and foreign currency |
| 270 |
|
|
| 153 |
|
|
| 145 |
|
|
| 0.28 |
|
Early retirement of debt |
| 269 |
|
|
| 171 |
|
|
| 171 |
|
|
| 0.33 |
|
Core earnings (loss) attributable to Devon (Non-GAAP) | $ | 35 |
|
| $ | — |
|
| $ | (38 | ) |
| $ | (0.08 | ) |
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to Devon (GAAP) | $ | (21,268 | ) |
| $ | (15,203 | ) |
| $ | (14,454 | ) |
| $ | (35.55 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset impairments |
| 20,820 |
|
|
| 13,923 |
|
|
| 13,100 |
|
|
| 32.18 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| 967 |
|
|
| 967 |
|
|
| 2.37 |
|
Restructuring and transaction costs |
| 78 |
|
|
| 52 |
|
|
| 52 |
|
|
| 0.13 |
|
Fair value changes in financial instruments and foreign currency |
| 1,967 |
|
|
| 1,349 |
|
|
| 1,346 |
|
|
| 3.31 |
|
Repatriations |
| — |
|
|
| 33 |
|
|
| 33 |
|
|
| 0.08 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 1,597 |
|
| $ | 1,121 |
|
| $ | 1,044 |
|
| $ | 2.52 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 4,059 |
|
| $ | 1,691 |
|
| $ | 1,607 |
|
| $ | 3.91 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains and losses on asset sales |
| (1,072 | ) |
|
| (625 | ) |
|
| (625 | ) |
|
| (1.52 | ) |
Asset impairments |
| 1,953 |
|
|
| 1,948 |
|
|
| 1,948 |
|
|
| 4.74 |
|
Restructuring and transaction costs |
| 46 |
|
|
| 35 |
|
|
| 35 |
|
|
| 0.08 |
|
Fair value changes in financial instruments and foreign currency |
| (1,828 | ) |
|
| (1,139 | ) |
|
| (1,132 | ) |
|
| (2.75 | ) |
Investment in General Partner deferred income tax |
| — |
|
|
| 48 |
|
|
| 48 |
|
|
| 0.12 |
|
Repatriations |
| — |
|
|
| 105 |
|
|
| 105 |
|
|
| 0.26 |
|
Early retirement of debt |
| 48 |
|
|
| 31 |
|
|
| 31 |
|
|
| 0.07 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 3,206 |
|
| $ | 2,094 |
|
| $ | 2,017 |
|
| $ | 4.91 |
|
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| ||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 40 |
|
| $ | 33 |
|
| $ | 33 |
|
| $ | 0.06 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (219 | ) |
|
| (140 | ) |
|
| (140 | ) |
|
| (0.27 | ) |
Asset and exploration impairments |
| 217 |
|
|
| 138 |
|
|
| 138 |
|
|
| 0.26 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| (4 | ) |
|
| (4 | ) |
|
| (0.01 | ) |
Fair value changes in financial instruments |
| 70 |
|
|
| 45 |
|
|
| 45 |
|
|
| 0.09 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 108 |
|
| $ | 72 |
|
| $ | 72 |
|
| $ | 0.13 |
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 856 |
|
| $ | 1,045 |
|
| $ | 865 |
|
| $ | 1.64 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. tax reform |
| — |
|
|
| (211 | ) |
|
| (112 | ) |
|
| (0.21 | ) |
Fair value changes in financial instruments and foreign currency |
| (289 | ) |
|
| (248 | ) |
|
| (248 | ) |
|
| (0.47 | ) |
Asset dispositions, impairments and early retirement of debt |
| 11 |
|
|
| 9 |
|
|
| 7 |
|
|
| 0.01 |
|
Legal entity restructuring and deferred tax asset valuation allowance |
| — |
|
|
| (157 | ) |
|
| (157 | ) |
|
| (0.29 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 578 |
|
| $ | 438 |
|
| $ | 355 |
|
| $ | 0.68 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 896 |
|
| $ | 1,078 |
|
| $ | 898 |
|
| $ | 1.70 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
| 68 |
|
|
| 39 |
|
|
| 39 |
|
|
| 0.07 |
|
Discontinued Operations |
| (278 | ) |
|
| (607 | ) |
|
| (510 | ) |
|
| (0.96 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 686 |
|
| $ | 510 |
|
| $ | 427 |
|
| $ | 0.81 |
|
44
EBITDAX and Field-Level Cash Margin
To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL revenues less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.
We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.
We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Net earnings (loss) (GAAP) | $ | (353 | ) |
| $ | 3,224 |
|
| $ | 1,078 |
|
Net (earnings) loss from discontinued operations, net of tax |
| 274 |
|
|
| (2,510 | ) |
|
| (1,045 | ) |
Financing costs, net |
| 250 |
|
|
| 580 |
|
|
| 321 |
|
Income tax expense (benefit) |
| (30 | ) |
|
| 230 |
|
|
| 7 |
|
Exploration expenses |
| 58 |
|
|
| 128 |
|
|
| 346 |
|
Depreciation, depletion and amortization |
| 1,497 |
|
|
| 1,228 |
|
|
| 1,008 |
|
Asset impairments |
| — |
|
|
| 156 |
|
|
| — |
|
Asset dispositions |
| (48 | ) |
|
| (278 | ) |
|
| (219 | ) |
Share-based compensation |
| 83 |
|
|
| 104 |
|
|
| 121 |
|
Derivative and financial instrument non-cash valuation changes |
| 623 |
|
|
| (938 | ) |
|
| 70 |
|
Restructuring and transaction costs |
| 84 |
|
|
| 97 |
|
|
| — |
|
Accretion on discounted liabilities and other |
| 5 |
|
|
| 54 |
|
|
| (12 | ) |
EBITDAX (non-GAAP) |
| 2,443 |
|
|
| 2,075 |
|
|
| 1,675 |
|
Marketing revenues and expenses, net |
| (53 | ) |
|
| (33 | ) |
|
| 46 |
|
Commodity derivative cash settlements |
| (170 | ) |
|
| 420 |
|
|
| (115 | ) |
General and administration expenses, cash-based |
| 392 |
|
|
| 470 |
|
|
| 524 |
|
Field-level cash margin (non-GAAP) | $ | 2,612 |
|
| $ | 2,932 |
|
| $ | 2,130 |
|
5345
Item 7A.Quantitative and QualitativeQualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S.gas and Canadian gasNGL production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodicallysystematically 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, 20162019 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2016,2019, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net liabilityasset positions by the following amounts:approximately $115 million.
|
| 10% Increase |
|
| 10% Decrease |
| ||
Gain (loss): |
| (Millions) |
| |||||
Gas derivatives |
| $ | (67 | ) |
| $ | 64 |
|
Oil derivatives |
| $ | (234 | ) |
| $ | 220 |
|
NGL derivatives |
| $ | (1 | ) |
| $ | 1 |
|
Processing and fractionation derivatives |
| $ | (3 | ) |
| $ | 3 |
|
Interest Rate Risk
At December 31, 2016,2019, we had total debt of $10.2$4.3 billion. Of this amount, $10.0 billion bearsAll of our debt is based on fixed interest rates averaging 5.3%, and approximately $150 million is comprised of floating rate debt with interest rates averaging 2.5%6.0%.
As of December 31, 2016, we had open interest rate swap positions that are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the three month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet or liquidity at December 31, 2016.
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in theDevon has certain Canadian dollar functional currency. Assets and liabilities ofobligations associated with its divested Canadian operations which are to be paid with the Canadian subsidiariescash restricted for discontinued operations. These balances are translated to U.S. dollarsremeasured 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, 20162019 balance sheet.sheet for these items. See Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report for additional information.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of our subsidiaries hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Based on the amount of the cash and
5446
intercompany loans as of December 31, 2016, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.
55
Index to Item 8.Financial Statements
Item 8.Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
|
| |
|
|
|
Consolidated Financial Statements |
|
|
Consolidated |
|
|
|
| |
|
| |
|
| |
|
| |
|
| |
65 | ||
66 | ||
67 | ||
| 70 | |
Note | 70 | |
71 | ||
Note 8 – Net Earnings (Loss) Per Share From Continuing Operations | 74 | |
| 75 | |
| ||
| ||
| ||
| ||
|
| |
| ||
Note 10 – Supplemental Information to Statements of Cash Flows |
|
|
|
| |
Note 12 – | 76 | |
|
| |
79 | ||
81 | ||
82 | ||
85 | ||
87 | ||
| 91 | |
| ||
| ||
| ||
| ||
| ||
| ||
|
| |
| ||
|
|
|
Note |
|
|
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.
5647
Report of Independent RegisteredRegistered Public Accounting Firm
TheTo the Stockholders and Board of Directors and Stockholders
Devon Energy Corporation:
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries (the Company) as of December 31, 20162019 and 2015, and2018, the related consolidated comprehensive statements of comprehensive earnings, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016.2019, and the related notes (collectively, the consolidated financial statements). We also have audited Devon Energy Corporation’sthe Company’s internal control over financial reporting as of December 31, 2016,2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)Commission.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Changes in Accounting Principles
As discussed in Note 14 to the consolidated financial statements, the Company has changed its method of accounting for leases in 2019 due to the adoption of Accounting Standards Update 2016-02, Leases (Topic 842). Devon Energy Corporation’s
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for revenue in 2018 due to the adoption of Accounting Standards Codification 606, Revenue from Contracts with Customers (ASC 606).
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K.Procedures.” Our responsibility is to express an opinion on thesethe Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
48
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion,
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements referredthat were communicated or required to above present fairly,be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in all material respects,any way our opinion on the consolidated financial positionstatements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Evaluation of Devon Energy Corporationthe estimate of proved and subsidiariesunproved oil and gas reserves used to assess the recoverability of the carrying value of oil and gas properties in the STACK common operating field
As discussed in Notes 1, 5, and 12 to the consolidated financial statements, the Company performs recoverability tests for the carrying value of its proved oil and gas properties subject to amortization. The recoverability tests are performed on an annual basis or more often if events and circumstances indicate that the carrying value of such properties may not be recoverable. The determination of the undiscounted cash flows is driven by the underlying estimate of proved and unproved oil and gas reserves for oil and gas properties as determined by the Company’s internal reservoir engineers. Estimating common operating fields’ future cash flows requires the expertise of reservoir engineers who take into consideration the estimate of future production quantities, future operating and capital cost assumptions, and projected oil and gas prices inclusive of market differentials. The STACK common operating field had a carrying value of $3.7 billion as of December 31, 20162019.
We identified the evaluation of the estimate of proved and 2015,unproved oil and gas reserves used to assess the recoverability of the carrying value of the STACK common operating field’s oil and gas properties as a critical audit matter. Based on current and forecasted commodity prices and costs, production volumes and drilling plans, and the resultsrisk adjustment factors associated with the unproved reserve volumes, the STACK common operating field required more judgment to evaluate the estimate of its operationsboth proved and itsunproved oil and gas reserves used in determining undiscounted future net cash flows for eachthe asset group.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s processes to develop and monitor the estimate of proved and unproved oil and gas reserves used to determine future cash flows. We assessed compliance of the yearsmethodology used by the Company’s internal reservoir engineers and external reservoir engineers to estimate proved and unproved oil and gas reserves with industry and regulatory standards. To assess the Company’s ability to accurately estimate future proved and unproved production quantities, we compared the future production quantity assumptions used by the Company in prior periods to the actual production amounts in the three-yearcurrent year and the year-end forecasted future production quantities. We compared the estimated future proved and unproved production quantities used by the Company in the current period to historical production trends and investigated differences. In addition, we assessed the competence, objectivity, and capabilities of the Company’s internal reservoir engineers and third-party reservoir engineers. We read and considered the report of the Company’s external reservoir engineers in connection with our evaluation of the Company’s reserve estimates. We also tested the processes and methodologies used by internal reservoir engineers to estimate unproved future production quantities. We have compared the risk adjustment factors for unproved reserves selected by the Company by prospect to the guideline risk adjustment factor ranges by reserve class in published industry surveys. We have also evaluated the Company’s selected risk adjustment factors by evaluation of the proximity of the unproved reserves to proved producing reserves. We evaluated the future operating and capital cost assumptions used by the internal reservoir engineers to estimate future cash flows by comparing them to historical costs. We also tested the projected oil and gas prices used by the internal reservoir engineers to estimate future cash flows by comparing those prices to publicly available prices and tested the relevant market differentials based on past results and any contractual changes in marketing and/or transportation and processing agreements that would impact future cash flows to be received.
49
Assessment of the estimate of proved oil and gas reserves used in the depletion of proved oil and gas properties
As discussed in Notes 1 and 12 to the consolidated financial statements, the Company calculates depletion for its proved oil and gas properties subject to amortization using a units-of-production method. The rates used to deplete the balance of oil and gas properties subject to amortization are set using the estimate of proved oil and gas reserves by common operating field. Under the units-of-production method, a rate is set annually using the beginning of year balance of oil and gas properties subject to amortization and estimated proved oil and gas reserves for each common operating field. That rate is then applied to production throughout the year to determine the amount of depletion expense to be recorded by common operating field. The Company’s internal reservoir engineers estimate proved oil and gas reserves, and the Company engages external reservoir engineers to perform an independent evaluation of a portion of the estimates of proved oil and gas reserves. These common operating fields had depletion expense of $1.4 billion for the year ended December 31, 2016,2019.
We identified the assessment of the estimate of proved oil and gas reserves used in conformitythe depletion of proved oil and gas properties as a critical audit matter. There was a high degree of subjectivity in evaluating the Company’s estimate of the proved oil and gas reserves used as an input to determine depletion for each common operating field.
The primary procedures we performed to address this critical audit matter including the following. We tested certain internal controls over the Company’s depletion expense calculation process, including controls related to the determination and monitoring of the estimate of proved oil and gas reserves. We analyzed the grouping of costs and proved oil and gas reserves by common operating field. We analyzed and assessed the determination of depletion expense for compliance with U.S. generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework issuedindustry and regulatory standards. To assess the Company’s ability to accurately estimate proved oil and gas reserves, we compared the estimated future production quantities assumptions used by the Committee of Sponsoring OrganizationsCompany in prior periods to the actual production amounts received and the year-end future production quantities forecasted. We compared the estimated future production quantities used by the Company in the current period to historical production trends and investigated differences. In addition, we assessed the competence, objectivity, and capabilities of the Treadway Commission (COSO).Company’s internal reservoir engineers and the Company’s external reservoir engineers. We read and considered the report of the Company’s third-party reservoir engineers in connection with our evaluation of the Company’s reserve estimates.
/s/ KPMG LLP
We have served as the Company’s auditor since 1980.
Oklahoma City, Oklahoma
February 15, 201719, 2020
5750
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF COMPREHENSIVE EARNINGS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions, except per share amounts) |
| |||||||||
Oil, gas and NGL sales |
| $ | 4,182 |
|
| $ | 5,382 |
|
| $ | 9,910 |
|
Oil, gas and NGL derivatives |
|
| (201 | ) |
|
| 503 |
|
|
| 1,989 |
|
Marketing and midstream revenues |
|
| 6,323 |
|
|
| 7,260 |
|
|
| 7,667 |
|
Asset dispositions and other |
|
| 1,893 |
|
|
| — |
|
|
| 1,072 |
|
Total revenues and other |
|
| 12,197 |
|
|
| 13,145 |
|
|
| 20,638 |
|
Lease operating expenses |
|
| 1,582 |
|
|
| 2,104 |
|
|
| 2,332 |
|
Marketing and midstream operating expenses |
|
| 5,492 |
|
|
| 6,420 |
|
|
| 6,815 |
|
General and administrative expenses |
|
| 645 |
|
|
| 855 |
|
|
| 847 |
|
Production and property taxes |
|
| 275 |
|
|
| 388 |
|
|
| 535 |
|
Depreciation, depletion and amortization |
|
| 1,792 |
|
|
| 3,129 |
|
|
| 3,319 |
|
Asset impairments |
|
| 4,975 |
|
|
| 20,820 |
|
|
| 1,953 |
|
Restructuring and transaction costs |
|
| 267 |
|
|
| 78 |
|
|
| 46 |
|
Other operating items |
|
| 64 |
|
|
| 78 |
|
|
| 93 |
|
Total operating expenses |
|
| 15,092 |
|
|
| 33,872 |
|
|
| 15,940 |
|
Operating income (loss) |
|
| (2,895 | ) |
|
| (20,727 | ) |
|
| 4,698 |
|
Net financing costs |
|
| 904 |
|
|
| 517 |
|
|
| 526 |
|
Other nonoperating items |
|
| 78 |
|
|
| 24 |
|
|
| 113 |
|
Earnings (loss) before income taxes |
|
| (3,877 | ) |
|
| (21,268 | ) |
|
| 4,059 |
|
Income tax expense (benefit) |
|
| (173 | ) |
|
| (6,065 | ) |
|
| 2,368 |
|
Net earnings (loss) |
|
| (3,704 | ) |
|
| (15,203 | ) |
|
| 1,691 |
|
Net earnings (loss) attributable to noncontrolling interests |
|
| (402 | ) |
|
| (749 | ) |
|
| 84 |
|
Net earnings (loss) attributable to Devon |
| $ | (3,302 | ) |
| $ | (14,454 | ) |
| $ | 1,607 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | (6.52 | ) |
| $ | (35.55 | ) |
| $ | 3.93 |
|
Diluted |
| $ | (6.52 | ) |
| $ | (35.55 | ) |
| $ | 3.91 |
|
Comprehensive earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | (3,704 | ) |
| $ | (15,203 | ) |
| $ | 1,691 |
|
Other comprehensive earnings (loss), net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation |
|
| 32 |
|
|
| (559 | ) |
|
| (465 | ) |
Pension and postretirement plans |
|
| 22 |
|
|
| 10 |
|
|
| (24 | ) |
Other comprehensive earnings (loss), net of tax |
|
| 54 |
|
|
| (549 | ) |
|
| (489 | ) |
Comprehensive earnings (loss) |
|
| (3,650 | ) |
|
| (15,752 | ) |
|
| 1,202 |
|
Comprehensive earnings (loss) attributable to noncontrolling interests |
|
| (402 | ) |
|
| (749 | ) |
|
| 84 |
|
Comprehensive earnings (loss) attributable to Devon |
| $ | (3,248 | ) |
| $ | (15,003 | ) |
| $ | 1,118 |
|
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
|
| (Millions, except per share amounts) |
| |||||||||
Upstream revenues |
| $ | 3,355 |
|
| $ | 4,542 |
|
| $ | 2,988 |
|
Marketing and midstream revenues |
|
| 2,865 |
|
|
| 4,354 |
|
|
| 3,513 |
|
Total revenues |
|
| 6,220 |
|
|
| 8,896 |
|
|
| 6,501 |
|
Production expenses |
|
| 1,197 |
|
|
| 1,153 |
|
|
| 791 |
|
Exploration expenses |
|
| 58 |
|
|
| 128 |
|
|
| 346 |
|
Marketing and midstream expenses |
|
| 2,812 |
|
|
| 4,321 |
|
|
| 3,559 |
|
Depreciation, depletion and amortization |
|
| 1,497 |
|
|
| 1,228 |
|
|
| 1,008 |
|
Asset impairments |
|
| — |
|
|
| 156 |
|
|
| — |
|
Asset dispositions |
|
| (48 | ) |
|
| (278 | ) |
|
| (219 | ) |
General and administrative expenses |
|
| 475 |
|
|
| 574 |
|
|
| 645 |
|
Financing costs, net |
|
| 250 |
|
|
| 580 |
|
|
| 321 |
|
Restructuring and transaction costs |
|
| 84 |
|
|
| 97 |
|
|
| — |
|
Other expenses |
|
| 4 |
|
|
| (7 | ) |
|
| 10 |
|
Total expenses |
|
| 6,329 |
|
|
| 7,952 |
|
|
| 6,461 |
|
Earnings (loss) from continuing operations before income taxes |
|
| (109 | ) |
|
| 944 |
|
|
| 40 |
|
Income tax expense (benefit) |
|
| (30 | ) |
|
| 230 |
|
|
| 7 |
|
Net earnings (loss) from continuing operations |
|
| (79 | ) |
|
| 714 |
|
|
| 33 |
|
Net earnings (loss) from discontinued operations, net of income taxes |
|
| (274 | ) |
|
| 2,510 |
|
|
| 1,045 |
|
Net earnings (loss) |
|
| (353 | ) |
|
| 3,224 |
|
|
| 1,078 |
|
Net earnings attributable to noncontrolling interests |
|
| 2 |
|
|
| 160 |
|
|
| 180 |
|
Net earnings (loss) attributable to Devon |
| $ | (355 | ) |
| $ | 3,064 |
|
| $ | 898 |
|
Basic net earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) from continuing operations per share |
| $ | (0.21 | ) |
| $ | 1.43 |
|
| $ | 0.06 |
|
Basic earnings (loss) from discontinued operations per share |
|
| (0.68 | ) |
|
| 4.71 |
|
|
| 1.65 |
|
Basic net earnings (loss) per share |
| $ | (0.89 | ) |
| $ | 6.14 |
|
| $ | 1.71 |
|
Diluted net earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) from continuing operations per share |
| $ | (0.21 | ) |
| $ | 1.42 |
|
| $ | 0.06 |
|
Diluted earnings (loss) from discontinued operations per share |
|
| (0.68 | ) |
|
| 4.68 |
|
|
| 1.64 |
|
Diluted net earnings (loss) per share |
| $ | (0.89 | ) |
| $ | 6.10 |
|
| $ | 1.70 |
|
Comprehensive earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | (353 | ) |
| $ | 3,224 |
|
| $ | 1,078 |
|
Other comprehensive earnings (loss), net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation, discontinued operations |
|
| 78 |
|
|
| (152 | ) |
|
| 83 |
|
Release of Canadian cumulative translation adjustment, discontinued operations |
|
| (1,237 | ) |
|
| — |
|
|
| — |
|
Pension and postretirement plans |
|
| 13 |
|
|
| 44 |
|
|
| 29 |
|
Other comprehensive earnings (loss), net of tax |
|
| (1,146 | ) |
|
| (108 | ) |
|
| 112 |
|
Comprehensive earnings (loss): |
|
| (1,499 | ) |
|
| 3,116 |
|
|
| 1,190 |
|
Comprehensive earnings attributable to noncontrolling interests |
|
| 2 |
|
|
| 160 |
|
|
| 180 |
|
Comprehensive earnings (loss) attributable to Devon |
| $ | (1,501 | ) |
| $ | 2,956 |
|
| $ | 1,010 |
|
See accompanying notes to consolidated financial statements.
5851
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | (353 | ) |
| $ | 3,224 |
|
| $ | 1,078 |
|
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net (earnings) loss from discontinued operations, net of income taxes |
|
| 274 |
|
|
| (2,510 | ) |
|
| (1,045 | ) |
Depreciation, depletion and amortization |
|
| 1,497 |
|
|
| 1,228 |
|
|
| 1,008 |
|
Asset impairments |
|
| — |
|
|
| 156 |
|
|
| — |
|
Leasehold impairments |
|
| 18 |
|
|
| 94 |
|
|
| 219 |
|
Accretion on discounted liabilities |
|
| 33 |
|
|
| 27 |
|
|
| 27 |
|
Total (gains) losses on commodity derivatives |
|
| 454 |
|
|
| (457 | ) |
|
| (66 | ) |
Cash settlements on commodity derivatives |
|
| 166 |
|
|
| (420 | ) |
|
| 115 |
|
Gains on asset dispositions |
|
| (48 | ) |
|
| (278 | ) |
|
| (219 | ) |
Deferred income tax expense (benefit) |
|
| (25 | ) |
|
| 247 |
|
|
| (2 | ) |
Share-based compensation |
|
| 115 |
|
|
| 137 |
|
|
| 126 |
|
Early retirement of debt |
|
| — |
|
|
| 312 |
|
|
| — |
|
Other |
|
| (6 | ) |
|
| (19 | ) |
|
| (8 | ) |
Changes in assets and liabilities, net |
|
| (82 | ) |
|
| (158 | ) |
|
| 10 |
|
Net cash from operating activities - continuing operations |
|
| 2,043 |
|
|
| 1,583 |
|
|
| 1,243 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (1,910 | ) |
|
| (2,116 | ) |
|
| (1,614 | ) |
Acquisitions of property and equipment |
|
| (31 | ) |
|
| (55 | ) |
|
| (44 | ) |
Divestitures of property and equipment |
|
| 390 |
|
|
| 500 |
|
|
| 425 |
|
Net cash from investing activities - continuing operations |
|
| (1,551 | ) |
|
| (1,671 | ) |
|
| (1,233 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Repayments of long-term debt |
|
| (162 | ) |
|
| (922 | ) |
|
| — |
|
Early retirement of debt |
|
| — |
|
|
| (304 | ) |
|
| — |
|
Repurchases of common stock |
|
| (1,849 | ) |
|
| (2,956 | ) |
|
| — |
|
Dividends paid on common stock |
|
| (140 | ) |
|
| (149 | ) |
|
| (127 | ) |
Contributions from noncontrolling interests |
|
| 116 |
|
|
| — |
|
|
| — |
|
Shares exchanged for tax withholdings |
|
| (25 | ) |
|
| (39 | ) |
|
| (46 | ) |
Other |
|
| (1 | ) |
|
| (7 | ) |
|
| — |
|
Net cash from financing activities - continuing operations |
|
| (2,061 | ) |
|
| (4,377 | ) |
|
| (173 | ) |
Net change in cash, cash equivalents and restricted cash of continuing operations |
|
| (1,569 | ) |
|
| (4,465 | ) |
|
| (163 | ) |
Cash flows from discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
| 28 |
|
|
| 1,121 |
|
|
| 1,666 |
|
Investing activities |
|
| 2,472 |
|
|
| 2,726 |
|
|
| (966 | ) |
Financing activities |
|
| (1,578 | ) |
|
| 174 |
|
|
| 182 |
|
Effect of exchange rate changes on cash |
|
| 45 |
|
|
| 206 |
|
|
| 6 |
|
Net change in cash, cash equivalents and restricted cash of discontinued operations |
|
| 967 |
|
|
| 4,227 |
|
|
| 888 |
|
Net change in cash, cash equivalents and restricted cash |
|
| (602 | ) |
|
| (238 | ) |
|
| 725 |
|
Cash, cash equivalents and restricted cash at beginning of period |
|
| 2,446 |
|
|
| 2,684 |
|
|
| 1,959 |
|
Cash, cash equivalents and restricted cash at end of period |
| $ | 1,844 |
|
| $ | 2,446 |
|
| $ | 2,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of cash, cash equivalents and restricted cash: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 1,464 |
|
| $ | 2,414 |
|
| $ | 2,642 |
|
Cash restricted for discontinued operations |
|
| 380 |
|
|
| — |
|
|
| — |
|
Restricted cash included in other current assets |
|
| — |
|
|
| 32 |
|
|
| 11 |
|
Cash and cash equivalents included in current assets associated with discontinued operations |
|
| — |
|
|
| — |
|
|
| 31 |
|
Total cash, cash equivalents and restricted cash |
| $ | 1,844 |
|
| $ | 2,446 |
|
| $ | 2,684 |
|
See accompanying notes to consolidated financial statements.
52
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | (3,704 | ) |
| $ | (15,203 | ) |
| $ | 1,691 |
|
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
| 1,792 |
|
|
| 3,129 |
|
|
| 3,319 |
|
Asset impairments |
|
| 4,975 |
|
|
| 20,820 |
|
|
| 1,953 |
|
Gains and losses on asset sales |
|
| (1,887 | ) |
|
| — |
|
|
| (1,072 | ) |
Deferred income tax expense (benefit) |
|
| (273 | ) |
|
| (5,828 | ) |
|
| 1,891 |
|
Derivatives and other financial instruments |
|
| 386 |
|
|
| (738 | ) |
|
| (2,070 | ) |
Cash settlements on derivatives and financial instruments |
|
| (142 | ) |
|
| 2,688 |
|
|
| 104 |
|
Asset retirement obligation accretion |
|
| 75 |
|
|
| 75 |
|
|
| 89 |
|
Amortization of stock-based compensation |
|
| 194 |
|
|
| 181 |
|
|
| 163 |
|
Other |
|
| 303 |
|
|
| 281 |
|
|
| 245 |
|
Net change in working capital |
|
| (8 | ) |
|
| (311 | ) |
|
| 50 |
|
Change in long-term other assets |
|
| 36 |
|
|
| 285 |
|
|
| (421 | ) |
Change in long-term other liabilities |
|
| (1 | ) |
|
| (6 | ) |
|
| 79 |
|
Net cash from operating activities |
|
| 1,746 |
|
|
| 5,373 |
|
|
| 6,021 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (2,330 | ) |
|
| (5,308 | ) |
|
| (6,988 | ) |
Acquisitions of property, equipment and businesses |
|
| (1,641 | ) |
|
| (1,107 | ) |
|
| (6,462 | ) |
Divestitures of property and equipment |
|
| 3,118 |
|
|
| 107 |
|
|
| 5,120 |
|
Redemptions of long-term investments |
|
| — |
|
|
| — |
|
|
| 57 |
|
Other |
|
| (19 | ) |
|
| (16 | ) |
|
| 89 |
|
Net cash from investing activities |
|
| (872 | ) |
|
| (6,324 | ) |
|
| (8,184 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt, net of issuance costs |
|
| 2,145 |
|
|
| 4,772 |
|
|
| 5,340 |
|
Repayments of long-term debt |
|
| (4,409 | ) |
|
| (2,634 | ) |
|
| (7,178 | ) |
Net short-term debt repayments |
|
| (626 | ) |
|
| (307 | ) |
|
| (385 | ) |
Early retirement of debt |
|
| (265 | ) |
|
| — |
|
|
| (51 | ) |
Issuance of common stock |
|
| 1,469 |
|
|
| — |
|
|
| — |
|
Sale of subsidiary units |
|
| — |
|
|
| 654 |
|
|
| — |
|
Issuance of subsidiary units |
|
| 892 |
|
|
| 25 |
|
|
| 410 |
|
Dividends paid on common stock |
|
| (221 | ) |
|
| (396 | ) |
|
| (386 | ) |
Contributions from noncontrolling interests |
|
| 168 |
|
|
| 16 |
|
|
| 6 |
|
Distributions to noncontrolling interests |
|
| (304 | ) |
|
| (254 | ) |
|
| (235 | ) |
Other |
|
| (13 | ) |
|
| (18 | ) |
|
| 85 |
|
Net cash from financing activities |
|
| (1,164 | ) |
|
| 1,858 |
|
|
| (2,394 | ) |
Effect of exchange rate changes on cash |
|
| (61 | ) |
|
| (77 | ) |
|
| (29 | ) |
Net change in cash and cash equivalents |
|
| (351 | ) |
|
| 830 |
|
|
| (4,586 | ) |
Cash and cash equivalents at beginning of period |
|
| 2,310 |
|
|
| 1,480 |
|
|
| 6,066 |
|
Cash and cash equivalents at end of period |
| $ | 1,959 |
|
| $ | 2,310 |
|
| $ | 1,480 |
|
|
| December 31, 2019 |
|
| December 31, 2018 |
| ||
|
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 1,464 |
|
| $ | 2,414 |
|
Cash restricted for discontinued operations |
|
| 380 |
|
|
| — |
|
Accounts receivable |
|
| 832 |
|
|
| 812 |
|
Current assets associated with discontinued operations |
|
| 896 |
|
|
| 331 |
|
Other current assets |
|
| 279 |
|
|
| 880 |
|
Total current assets |
|
| 3,851 |
|
|
| 4,437 |
|
Oil and gas property and equipment, based on successful efforts accounting, net |
|
| 7,558 |
|
|
| 7,430 |
|
Other property and equipment, net ($80 million related to CDM in 2019) |
|
| 1,035 |
|
|
| 1,032 |
|
Total property and equipment, net |
|
| 8,593 |
|
|
| 8,462 |
|
Goodwill |
|
| 753 |
|
|
| 753 |
|
Right-of-use assets |
|
| 243 |
|
|
| — |
|
Other long-term assets |
|
| 196 |
|
|
| 276 |
|
Long-term assets associated with discontinued operations |
|
| 81 |
|
|
| 5,638 |
|
Total assets |
| $ | 13,717 |
|
| $ | 19,566 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 428 |
|
| $ | 530 |
|
Revenues and royalties payable |
|
| 730 |
|
|
| 722 |
|
Short-term debt |
|
| — |
|
|
| 162 |
|
Current liabilities associated with discontinued operations |
|
| 459 |
|
|
| 492 |
|
Other current liabilities |
|
| 310 |
|
|
| 320 |
|
Total current liabilities |
|
| 1,927 |
|
|
| 2,226 |
|
Long-term debt |
|
| 4,294 |
|
|
| 4,292 |
|
Lease liabilities |
|
| 244 |
|
|
| — |
|
Asset retirement obligations |
|
| 380 |
|
|
| 468 |
|
Other long-term liabilities |
|
| 426 |
|
|
| 411 |
|
Long-term liabilities associated with discontinued operations |
|
| 185 |
|
|
| 2,454 |
|
Deferred income taxes |
|
| 341 |
|
|
| 529 |
|
Stockholders' equity: |
|
|
|
|
|
|
|
|
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 382 million and 450 million shares in 2019 and 2018, respectively |
|
| 38 |
|
|
| 45 |
|
Additional paid-in capital |
|
| 2,735 |
|
|
| 4,486 |
|
Retained earnings |
|
| 3,148 |
|
|
| 3,650 |
|
Accumulated other comprehensive earnings (loss) |
|
| (119 | ) |
|
| 1,027 |
|
Treasury stock, at cost, 1.0 million shares in 2018 |
|
| — |
|
|
| (22 | ) |
Total stockholders’ equity attributable to Devon |
|
| 5,802 |
|
|
| 9,186 |
|
Noncontrolling interests |
|
| 118 |
|
|
| — |
|
Total equity |
|
| 5,920 |
|
|
| 9,186 |
|
Total liabilities and equity |
| $ | 13,717 |
|
| $ | 19,566 |
|
See accompanying notes to consolidated financial statements.
5953
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF EQUITY
|
| December 31, 2016 |
|
| December 31, 2015 |
| ||
|
| (Millions, except share data) |
| |||||
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 1,959 |
|
| $ | 2,310 |
|
Accounts receivable |
|
| 1,356 |
|
|
| 1,105 |
|
Assets held for sale |
|
| 193 |
|
|
| — |
|
Other current assets |
|
| 264 |
|
|
| 606 |
|
Total current assets |
|
| 3,772 |
|
|
| 4,021 |
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
Oil and gas, based on full cost accounting: |
|
|
|
|
|
|
|
|
Subject to amortization |
|
| 75,648 |
|
|
| 78,190 |
|
Not subject to amortization |
|
| 3,437 |
|
|
| 2,584 |
|
Total oil and gas |
|
| 79,085 |
|
|
| 80,774 |
|
Midstream and other |
|
| 10,455 |
|
|
| 10,380 |
|
Total property and equipment, at cost |
|
| 89,540 |
|
|
| 91,154 |
|
Less accumulated depreciation, depletion and amortization |
|
| (73,350 | ) |
|
| (72,086 | ) |
Property and equipment, net |
|
| 16,190 |
|
|
| 19,068 |
|
Goodwill |
|
| 3,964 |
|
|
| 5,032 |
|
Other long-term assets |
|
| 1,987 |
|
|
| 1,330 |
|
Total assets |
| $ | 25,913 |
|
| $ | 29,451 |
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 642 |
|
| $ | 906 |
|
Revenues and royalties payable |
|
| 908 |
|
|
| 763 |
|
Short-term debt |
|
| — |
|
|
| 976 |
|
Other current liabilities |
|
| 1,066 |
|
|
| 650 |
|
Total current liabilities |
|
| 2,616 |
|
|
| 3,295 |
|
Long-term debt |
|
| 10,154 |
|
|
| 12,056 |
|
Asset retirement obligations |
|
| 1,226 |
|
|
| 1,370 |
|
Other long-term liabilities |
|
| 894 |
|
|
| 853 |
|
Deferred income taxes |
|
| 648 |
|
|
| 888 |
|
Stockholders’ equity: |
|
|
|
|
|
|
|
|
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 523 million and 418 million shares in 2016 and 2015, respectively |
|
| 52 |
|
|
| 42 |
|
Additional paid-in capital |
|
| 7,237 |
|
|
| 4,996 |
|
Retained earnings (accumulated deficit) |
|
| (1,646 | ) |
|
| 1,781 |
|
Accumulated other comprehensive earnings |
|
| 284 |
|
|
| 230 |
|
Total stockholders’ equity attributable to Devon |
|
| 5,927 |
|
|
| 7,049 |
|
Noncontrolling interests |
|
| 4,448 |
|
|
| 3,940 |
|
Total stockholders’ equity |
|
| 10,375 |
|
|
| 10,989 |
|
Total liabilities and stockholders’ equity |
| $ | 25,913 |
|
| $ | 29,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Retained |
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
| Additional |
|
| Earnings |
|
| Comprehensive |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
| Common Stock |
|
| Paid-In |
|
| (Accumulated |
|
| Earnings |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
| |||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| Deficit) |
|
| (Loss) |
|
| Stock |
|
| Interests |
|
| Equity |
| ||||||||
Balance as of December 31, 2016 |
|
| 523 |
|
| $ | 52 |
|
| $ | 7,237 |
|
| $ | (69 | ) |
| $ | 1,054 |
|
| $ | — |
|
| $ | 4,448 |
|
| $ | 12,722 |
|
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 898 |
|
|
| — |
|
|
| — |
|
|
| 180 |
|
|
| 1,078 |
|
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 112 |
|
|
| — |
|
|
| — |
|
|
| 112 |
|
Restricted stock grants, net of cancellations |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (44 | ) |
|
| — |
|
|
| (44 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (44 | ) |
|
| — |
|
|
| — |
|
|
| 44 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (127 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (127 | ) |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 126 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 126 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 14 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 576 |
|
|
| 590 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (354 | ) |
|
| (354 | ) |
Balance as of December 31, 2017 |
|
| 525 |
|
| $ | 53 |
|
| $ | 7,333 |
|
| $ | 702 |
|
| $ | 1,166 |
|
| $ | — |
|
| $ | 4,850 |
|
| $ | 14,104 |
|
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3,064 |
|
|
| — |
|
|
| — |
|
|
| 160 |
|
|
| 3,224 |
|
Other comprehensive loss, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (108 | ) |
|
| — |
|
|
| — |
|
|
| (108 | ) |
Restricted stock grants, net of cancellations |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (3,017 | ) |
|
| — |
|
|
| (3,017 | ) |
Common stock retired |
|
| (79 | ) |
|
| (8 | ) |
|
| (2,987 | ) |
|
| — |
|
|
| — |
|
|
| 2,995 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (149 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (149 | ) |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 140 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 140 |
|
Divestment of subsidiary equity investment |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| (4,863 | ) |
|
| (4,861 | ) |
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 72 |
|
|
| 72 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (219 | ) |
|
| (219 | ) |
Other |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 33 |
|
|
| (33 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Balance as of December 31, 2018 |
|
| 450 |
|
| $ | 45 |
|
| $ | 4,486 |
|
| $ | 3,650 |
|
| $ | 1,027 |
|
| $ | (22 | ) |
| $ | — |
|
| $ | 9,186 |
|
Effect of adoption of lease accounting |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (7 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (7 | ) |
Net earnings (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (355 | ) |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| (353 | ) |
Other comprehensive loss, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,146 | ) |
|
| — |
|
|
| — |
|
|
| (1,146 | ) |
Restricted stock grants, net of cancellations |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,852 | ) |
|
| — |
|
|
| (1,852 | ) |
Common stock retired |
|
| (71 | ) |
|
| (7 | ) |
|
| (1,867 | ) |
|
| — |
|
|
| — |
|
|
| 1,874 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (140 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (140 | ) |
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 116 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 116 |
|
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 116 |
|
|
| 116 |
|
Balance as of December 31, 2019 |
|
| 382 |
|
| $ | 38 |
|
| $ | 2,735 |
|
| $ | 3,148 |
|
| $ | (119 | ) |
| $ | — |
|
| $ | 118 |
|
| $ | 5,920 |
|
See accompanying notes to consolidated financial statements.
6054
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| Additional |
|
| Retained |
|
| Other |
|
|
|
|
|
|
|
|
|
| Total |
| ||||
|
| Common Stock |
|
| Paid-In |
|
| Earnings |
|
| Comprehensive |
|
| Treasury |
|
| Noncontrolling |
|
| Stockholders’ |
| |||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| (Accumulated Deficit) |
|
| Earnings |
|
| Stock |
|
| Interests |
|
| Equity |
| ||||||||
|
| (Millions) |
| |||||||||||||||||||||||||||||
Balance as of December 31, 2013 |
|
| 406 |
|
| $ | 41 |
|
| $ | 3,780 |
|
| $ | 15,410 |
|
| $ | 1,268 |
|
| $ | — |
|
| $ | — |
|
| $ | 20,499 |
|
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,607 |
|
|
| — |
|
|
| — |
|
|
| 84 |
|
|
| 1,691 |
|
Other comprehensive loss, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (489 | ) |
|
| — |
|
|
| — |
|
|
| (489 | ) |
Stock option exercises |
|
| 1 |
|
|
| — |
|
|
| 93 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 93 |
|
Restricted stock grants, net of cancellations |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (27 | ) |
|
| — |
|
|
| (27 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (27 | ) |
|
| — |
|
|
| — |
|
|
| 27 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (386 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (386 | ) |
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 151 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 151 |
|
Share-based compensation tax expense |
|
| — |
|
|
| — |
|
|
| (3 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (3 | ) |
Acquisition of noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 4,670 |
|
|
| 4,670 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 93 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 277 |
|
|
| 370 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (235 | ) |
|
| (235 | ) |
Other |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| 7 |
|
Balance as of December 31, 2014 |
|
| 409 |
|
| $ | 41 |
|
| $ | 4,088 |
|
| $ | 16,631 |
|
| $ | 779 |
|
| $ | — |
|
| $ | 4,802 |
|
| $ | 26,341 |
|
Net loss |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (14,454 | ) |
|
| — |
|
|
| — |
|
|
| (749 | ) |
|
| (15,203 | ) |
Other comprehensive loss, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (549 | ) |
|
| — |
|
|
| — |
|
|
| (549 | ) |
Stock option exercises |
|
| — |
|
|
| — |
|
|
| 4 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 4 |
|
Restricted stock grants, net of cancellations |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (35 | ) |
|
| — |
|
|
| (35 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (35 | ) |
|
| — |
|
|
| — |
|
|
| 35 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (396 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (396 | ) |
Common stock issued |
|
| 7 |
|
|
| 1 |
|
|
| 198 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 199 |
|
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 165 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 165 |
|
Share-based compensation tax expense |
|
| — |
|
|
| — |
|
|
| (9 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (9 | ) |
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 585 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 141 |
|
|
| 726 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (254 | ) |
|
| (254 | ) |
Balance as of December 31, 2015 |
|
| 418 |
|
| $ | 42 |
|
| $ | 4,996 |
|
| $ | 1,781 |
|
| $ | 230 |
|
| $ | — |
|
| $ | 3,940 |
|
| $ | 10,989 |
|
Net loss |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (3,302 | ) |
|
| — |
|
|
| — |
|
|
| (402 | ) |
|
| (3,704 | ) |
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 54 |
|
|
| — |
|
|
| — |
|
|
| 54 |
|
Restricted stock grants, net of cancellations |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (28 | ) |
|
| — |
|
|
| (28 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (28 | ) |
|
| — |
|
|
| — |
|
|
| 28 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (96 | ) |
|
| (125 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (221 | ) |
Common stock issued |
|
| 103 |
|
|
| 10 |
|
|
| 2,117 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,127 |
|
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 168 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 168 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 80 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,214 |
|
|
| 1,294 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (304 | ) |
|
| (304 | ) |
Balance as of December 31, 2016 |
|
| 523 |
|
| $ | 52 |
|
| $ | 7,237 |
|
| $ | (1,646 | ) |
| $ | 284 |
|
| $ | — |
|
| $ | 4,448 |
|
| $ | 10,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
61
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 North American onshore areas in the U.S.
As further discussed in Note 18, Devon reached an agreement to sell its Barnett Shale assets in December 2019, sold its Canadian operations on June 27, 2019 and Canada. Devon also owns natural gas pipelines, plants and treatment facilities throughsold its ownership interests in EnLink and the General Partner.Partner on July 18, 2018. Activity relating to Devon’s Barnett Shale assets, inclusive of properties divested as partial sales of the Barnett Shale common operating field in previous reporting periods located primarily in Johnson and Wise counties, Texas, Canadian operations and EnLink and the General Partner are classified as discontinued operations within Devon’s consolidated statements of comprehensive earnings and consolidated statements of cash flows. The associated assets and liabilities of Devon’s Barnett Shale assets and Canadian operations are presented as assets and liabilities associated with discontinued operations on the consolidated balance sheets.
Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U.S. and reflect industry practices. The more significant of such policies are discussed below.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Devon, and entities in which it holds a controlling interest.interest and VIEs for which Devon is the primary beneficiary. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.
Devon entered into an agreement in the fourth quarter of 2019 to form Cotton Draw Midstream, L.L.C. or, “CDM”, a partnership in the Delaware Basin with an affiliate of QL Capital Partners, LP (“QLCP”). As discussed more fullypart of this transaction, Devon contributed gathering system and compression assets in Note 2,the Cotton Draw area to CDM in exchange for a $100 million cash distribution funded by QLCP. Devon completedwill continue to operate the assets pursuant to the management services agreement. QLCP has also committed $40 million of expansion capital to CDM to fund the build out of the assets over the next several years. Devon holds a business 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 stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon.
Devon, through its controlling interest in CDM, has the power to direct the activities that significantly affect the economic performance of CDM and the obligation to absorb losses or the right to receive benefits that could be significant to CDM; therefore, Devon is considered the primary beneficiary and consolidates CDM. CDM maintains its own capital structure that is separate from Devon.
The assets of CDM cannot be used by Devon for general corporate purposes and are included in and disclosed parenthetically on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which the creditors do not have recourse to Devon's assets are also included in and disclosed parenthetically on Devon's consolidated balance sheets, if material.
Segment Information
Subsequent to the sale of Devon’s Canadian business in 2019 discussed in Note 18, Devon’s oil and gas exploration and production activities are solely focused in the U.S. For financial reporting purposes, Devon
55
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
aggregates its U.S. operating segments into one reporting segment due to the similar nature of its business. With the reclassification of Devon’s Canadian operations to discontinued operations and assets and liabilities associated with discontinued operations, Devon now has one reporting segment, which is reflected in the consolidated financial statements.
Use of Estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
• | proved reserves and related present value of future net revenues; |
• | evaluation of suspended well costs; |
• | the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; |
• | derivative financial instruments; |
• | the fair value of reporting units and related assessment of goodwill for impairment; |
• | income taxes; |
• | asset retirement obligations; |
• | obligations related to employee pension and postretirement benefits; |
• | legal and environmental risks and exposures; and |
• | general credit risk associated with receivables and other assets. |
Revenue Recognition
Impact of ASC 606 Adoption
In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and related present valueapplied the standard to all existing contracts at adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of futuregoods or services to customers in an amount that reflects the consideration in exchange for those goods or services.
The changes to upstream revenues and production expenses were due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This was a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net revenues;
price from the carrying valuethird-party end customer. As a result, Devon changed the presentation of oilrevenues and gas properties, midstream assets and product and equipment inventories;
derivative financial instruments;
the fair value of reporting units and related assessment of goodwillexpenses for impairment;
the fair value of intangible assets other than goodwill;
income taxes;
asset retirement obligations;
obligationsthese agreements. Revenues related to employee pensionthese agreements are presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and postretirement benefits;transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are presented as production expenses. During 2018, these changes resulted in a $191 million increase to upstream revenues and production expenses with no impact to net earnings. As a result of
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
general credit risk associated with receivablesthe adoption of ASC 606, Devon’s marketing and other assets.
Revenue Recognitionmidstream revenues and marketing and midstream expenses were not impacted.
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, 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.
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 at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated statements of comprehensive earnings.
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 and midstreamRevenues
Marketing revenues are recordedgenerated 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
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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.
Satisfaction of Performance Obligations and Revenue Recognitions
Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the crude oil, natural gas or NGLs are delivered at a fixed or determinable price.
Transaction Price Allocated to Remaining Performance Obligations
Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
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, 2019. 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, |
| |||||
|
| 2019 |
|
| 2018 |
| ||
Oil |
| $ | 2,988 |
|
| $ | 2,941 |
|
Gas |
|
| 391 |
|
|
| 482 |
|
NGL |
|
| 430 |
|
|
| 662 |
|
Oil, gas and NGL revenues from contracts with customers |
|
| 3,809 |
|
|
| 4,085 |
|
Oil, gas and NGL derivatives |
|
| (454 | ) |
|
| 457 |
|
Upstream revenues |
|
| 3,355 |
|
|
| 4,542 |
|
|
|
|
|
|
|
|
|
|
Oil |
|
| 1,534 |
|
|
| 2,745 |
|
Gas |
|
| 645 |
|
|
| 738 |
|
NGL |
|
| 686 |
|
|
| 871 |
|
Total marketing revenues from contracts with customers |
|
| 2,865 |
|
|
| 4,354 |
|
|
|
|
|
|
|
|
|
|
Total revenues |
| $ | 6,220 |
|
| $ | 8,896 |
|
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Customers
During 2016, 20152019 and 2014, no2017, 0 purchaser accounted for more than 10% of Devon’s consolidated sales revenue.
During 2018, Devon had 1 purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices interest rates and Canadian to U.S. dollar exchangeinterest rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.
Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars and call options.collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes two-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.counterparty.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates.volatility. As of December 31, 2016,2019, Devon did not have any open foreign exchangeinterest rate swap contracts.
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2016,2019, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
instruments are also recorded in earnings. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements.
By using derivative financial instruments to hedge exposures to changes in commodity prices interest rates and foreign 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, 2016,2019, Devon held no collateral from counterparties. As of December 31, 2015, Devon held $75 million of0 cash collateral which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. Theits counterparties 0r posted collateral is reported in other current liabilities in the accompanying consolidated balance sheets. As a result of ratings downgrades for Devon during 2016, we were required to post $17 million of cash collateral under certain of our derivative contracts. The collateral is reported in other current assets in the accompanying December 31, 2016 consolidated balance sheet. In January 2017, this collateral was deemed to be no longer required and was returned to Devon. As of the date of this report, Devon has no cash collateral held by its counterparties.
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 and netDevon.
59
Table of amounts capitalized pursuantContents
Index to the full cost method of accounting.Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Share-Based Compensation
Independent of EnLink, Devon grants share-based awards to members of its Board of Directors, management and select employees. EnLink and the General Partner also grant share-based awards to members of its Board of Directors and select employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated comprehensive statements of comprehensive earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring and transaction costs in the accompanying consolidated comprehensive statements of comprehensive earnings.
Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase.
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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 7 for further discussion.
Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.
Net Earnings (Loss) Per Share Attributable to Devon
Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the
60
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.unvested performance share units.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
Cash Restricted for Discontinued Operations
In conjunction primarily with the sale of its Canadian operations in June 2019, approximately $380 million of Devon’s cash balance is restricted for funding certain tax and other obligations related to the disposed assets. Other obligations primarily relate to abandoned firm transportation and office lease agreements. This cash is not legally restricted and can be used by Devon for other general corporate purposes. However, it has been designated to settle retained obligations associated with discontinued operations.
Accounts Receivable
Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable, including joint interest receivables, for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Oil and Gas Property and Equipment
Devon follows the full costsuccessful efforts method of accounting for its oil and gas properties. Accordingly, allExploration costs, incidental tosuch as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the acquisition, exploration andcosts of drilling development ofwells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties includingwith a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions.
Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly.
Capitalized costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unprovedproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Depletion is calculated using the capitalizedProved 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, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly.annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved
Proved properties are transferred intoassessed for impairment annually, or more frequently if events or changes in circumstances dictate that the depletion calculation over their respective holding periods generally ranging from threecarrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to four years.estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review.
SalesGains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized. However, if a disposition or series of dispositions occurring in a quarterly reporting period significantly alters the relationship between capitalized
Devon capitalizes interest costs and proved reserves in a particular country, a gain or loss is recognized. As discussed more fully in Note 2, the 2014 and 2016 divestitures of certain Canadian and U.S. non-core upstream assets significantly altered such relationship, and Devon recognized gains on these transactions. These gainsincurred that are classified as asset dispositions and other in the accompanying consolidated statements of earnings. Furthermore, upon recognizing the gain on the 2016 divestitures andattributable to be more consistent with industry practice, Devon began presenting gains on asset sales in the total revenues and other section of the accompanying consolidated statements of earnings, and has reclassified the 2014 gain on asset sales of $1.1 billion from operating expenses to total revenues and other to reflect consistent financial statement presentation.
Under the full cost method of accounting, capitalized costs ofmaterial unproved oil and gas properties net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10% per annum, net of related tax effects. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book valuemajor development projects of oil and gas properties.
Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2016 qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Asset Retirement Obligations
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes ana qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative 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 allocating goodwill and all other assets and liabilities to assigned reporting units. Thethe fair value of each reporting unit is estimated andbe compared to the net bookcarrying value of the reporting unit. If the estimated fair value of the reporting unit is less than the net bookcarrying value, including goodwill, thenan impairment charge will be recognized for the goodwill is written down toamount by which the impliedcarrying amount exceeds the fair value of the goodwill through a charge to expense.value. Because quoted market prices are not available for Devon’s reporting units,unit, the fair valuesvalue of the reporting units areunit is estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
Devon and EnLink performed annual impairment tests of goodwill in the fourth quarters of 2016, 20152019, 2018 and 2014.2017. No impairment write-down was required as a result of the annual tests in 2016; however, sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units and in 2014 for Devon’s Canadian reporting unit based on interim and annual impairment tests. See Note 12 for further discussion.
Intangible Assets
Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years. During 2016 and 2015, EnLink’s customer relationships were also evaluated for impairment, and in 2015, a portion of these intangible assets was considered impaired. See Note 12 for further discussion.time periods.
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for
67
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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.
63
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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.
• | Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. |
Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.
• | Level 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.
• | Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model. |
Foreign Currency Translation Adjustments
The U.S. dollar is the functional currency for Devon’s consolidated operations. Devon’s recently divested Canadian operations except its Canadian subsidiaries, which useused the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries areoperations were translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow arewere translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income
The disposition of substantially all of Devon’s Canadian oil and are includedgas assets and operations resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings in stockholders’ equity.to be included within the gain computation.
Noncontrolling Interests
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.
Recently Adopted Accounting Standards
In January 2016,2019, Devon adopted ASU 2015-03, Interest – Imputation of Interest2016-02, Leases (Topic 835): Simplifying842), using the Presentation of Debt Issuance Costs. This ASU requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. As a resultmodified retrospective method. See Note 14for further discussion regarding Devon’s adoption of the adoption, Devon reclassified unamortized debt issuanceleases standard.
The SEC released Final Rule Release No. 33-10618, FAST Act Modernization and Simplification of Regulation S-K, which amends Regulation S-K to modernize and simplify certain disclosure requirements in a manner that reduces costs of $81 million as of December 31, 2015 from other long-term assets to a reduction of long-term debtand burdens on the consolidated balance sheets.
The FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. Its objective is to clarify guidance and eliminate diversity in practice of classification on certain cash receipts and payments in the statement of cash flows. Devon early adopted this ASU as of September
68
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
30, 2016 using a retrospective transition method. As a result of the adoption, Devon has classified $265 million of debt retirement payments as cash flows from financing activities in the accompanying 2016 consolidated statement of cash flows and has reclassified $40 million of debt retirement payments previously classified as cash flows from operating activities to cash flows from financing activities in the accompanying 2014 consolidated statement of cash flows.
The FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern. Its objective isregistrants while continuing to provide guidance about management’s responsibilityall material information to evaluate whether there are conditionsinvestors. The rule became effective May 2, 2019. The rule amended numerous SEC rules, items and forms covering a diverse group of topics, primarily focusing on reducing or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern. Certain disclosures are required should substantial doubt exist. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year after the date that the financial statements are issued. This ASU was effective for Devon beginning December 31, 2016; however, no additional disclosures as contemplated byeliminating disclosures. Other than presentation, this ASU were warranted.
Recently Issued Accounting Standards
The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018, with early adoption permitted in 2017. The ASU is required to be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Devon intends to use the cumulative effect transition method. Based on current evaluations to-date, Devon doesdid not anticipate this ASU will have a material impact on its balance sheet or related consolidated statement of earnings, stockholders’ equity or cash flows. Devon is continuing to evaluate the disclosure requirements of this ASU and has begun transitioning to the implementation phase of the adoption. Devon does not plan on early adopting this ASU.
The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019 and will be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. Early adoption is permitted. Devon is continuing to evaluate the impact this ASU will have on itsDevon’s consolidated financial statements and related disclosures and does not plan on early adopting.statements.
The FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. Its objective is to simplify several aspects of the accounting for share-based payments, and associated income taxes, statutory withholding and forfeitures. Classification of these aspects on the statement of cash flows is also addressed. Devon adopted this ASU as of January 1, 2017. For recording periods following adoption, Devon will make certain income tax presentation changes, most notably prospectively presenting excess tax benefits as income tax expense in the consolidated comprehensive statements of earnings and as operating cash flows in the consolidated statements of cash flows. While Devon does not expect that these
69
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
changes will materially impact its consolidated financial statements and related disclosures, the adoption of this ASU could result in increased volatility in income tax expense and net earnings in Devon’s financial statements.
The FASB issued ASU No. 2016-13, Credit Losses, Measurement of Credit Losses on Financial Instruments. This ASU changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for Devon beginning January 1, 2020, with early adoption permitted. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures.
Devon Acquisitions
On January 7, 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash and $659 million of equity. The allocation of the purchase price at December 31, 2016 was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.
On December 17, 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. The allocation of the purchase price was $393 million to unproved properties and $106 million to proved properties and gathering systems.
On February 28, 2014, Devon acquired approximately 82,000 net acres (unaudited) and assets located in DeWitt and Lavaca counties in south Texas from GeoSouthern for approximately $6.0 billion. Devon funded the acquisition with cash on hand and debt financing. The allocation of the purchase price was approximately $5.0 billion to proved properties and approximately $1.0 billion to unproved properties.
Devon Asset Divestitures
During 2016, Devon divested certain non-core upstream assets in the U.S. and its 50% interest in the Access Pipeline in Canada. Proceeds from the transactions have been utilized primarily for debt repayment and to support future capital investment in Devon’s core resource plays.
Upstream Assets
In the second quarter of 2016, Devon divested its non-core Mississippian assets for approximately $200 million. Estimated proved reserves associated with these assets were approximately 11 MMBoe, or less than 1% of total U.S. proved reserves.
During the third quarter of 2016, in several separate transactions with different purchasers, Devon divested non-core upstream assets located in east Texas, the Anadarko Basin and the Midland Basin for approximately $1.7 billion. Estimated proved reserves associated with these assets were approximately 146 MMBoe, or approximately 9% of total U.S. proved reserves.
Absent gain recognition, the divestiture transactions that closed in the third quarter of 2016 would have significantly altered the costs and reserves relationship of Devon’s U.S cost center. Therefore, Devon recognized a
70
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
$1.4 billion gain in the third quarter of 2016 associated with these divestitures. A summary of the gain computation follows.
|
| Three Months Ended September 30, 2016 |
| |
|
| (Millions) |
| |
Proceeds received, net of purchase price adjustments and selling costs |
| $ | 1,653 |
|
Asset retirement obligation assumed by purchasers |
|
| 250 |
|
Total consideration received |
|
| 1,903 |
|
|
|
|
|
|
Allocated oil and gas property basis sold |
|
| 355 |
|
Allocated goodwill |
|
| 197 |
|
Total assets sold |
|
| 552 |
|
|
|
|
|
|
Gains on asset sales |
| $ | 1,351 |
|
Access Pipeline
In October 2016, Devon divested Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes.
Prior Year Divestitures
During 2014, Devon divested certain upstream properties located throughout Canada and the U.S. as part of its asset portfolio transformation for approximately $5 billion. A gain of $1.1 billion was recognized with the sale of the Canadian conventional assets. This gain is included as a separate item in the accompanying consolidated comprehensive statements of earnings. Devon repatriated the Canadian asset proceeds to the U.S. Between collecting the divestiture proceeds and repatriating the funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign exchange currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings. The proceeds were used to repay debt.
EnLink Acquisitions
On January 7, 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.5 billion, subject to certain adjustments. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily funded with the issuance of EnLink preferred units. The remaining $500 million of the purchase price is to be paid within one year with the option to defer $250 million of the final payment 24 months from the close date. The first $250 million of undiscounted future installment payment is reported in other current liabilities in the accompanying consolidated balance sheets with the remaining $250 million payment reported in other long-term liabilities. The accretion of the discount is reported within net financing costs in
71
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
the accompanying consolidated comprehensive statement of earnings. The first installment payment of $250 million was paid in January 2017 and was funded using divestiture proceeds, proceeds from equity issuances and borrowings under EnLink’s credit facility. The allocation of the purchase price at December 31, 2016 was $1.0 billion to intangible assets and approximately $400 million to property and equipment.
On August 1, 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $251 million of existing non-monetary assets and cash to the joint venture and had committed an additional $285 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including cash contributions of approximately $144 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.
On November 9, 2016, EnLink entered into a gathering and compression joint venture with a commitment of approximately $40 million to expand its midstream assets in the STACK. The joint venture is initially owned 30% by EnLink and 70% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $29 million in cash for new infrastructure build. After the initial capital commitment, EnLink and the joint venture partner will be responsible for their proportionate share of capital expenses.
The following table presents a summary of EnLink’s acquisition activity for 2015.
|
|
|
| Purchase Price (Millions) |
|
| Allocation (Millions) |
| ||||||||||||||||||
Date |
| Acquiree |
| Cash |
|
| EnLink Units |
|
| PP&E |
|
| Goodwill |
|
| Intangibles |
|
| Other |
| ||||||
January 2015 |
| LPC |
| $ | 108 |
|
|
| — |
|
| $ | 30 |
|
| $ | 30 |
|
| $ | 43 |
|
| $ | 5 |
|
March 2015 |
| Coronado |
| $ | 240 |
|
| $ | 360 |
|
| $ | 302 |
|
| $ | 18 |
|
| $ | 281 |
|
| $ | (1 | ) |
October 2015 |
| Matador |
| $ | 141 |
|
|
| — |
|
| $ | 36 |
|
| $ | 11 |
|
| $ | 99 |
|
| $ | (5) |
|
EnLink Asset Divestitures and Dropdowns
In December 2016, EnLink entered into definitive agreements to divest approximately $278 million of certain non-core midstream assets. Certain of these transactions are expected to close during the first quarter of 2017. As of December 31, 2016, these assets were classified as held for sale.
In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.
In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.
Formation of EnLink and the General Partner
On March 7, 2014, Devon and Crosstex completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a midstream business that consists of the General Partner and EnLink, which are both publicly traded.
72
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In exchange for a controlling interest in both EnLink and the General Partner, Devon contributed its equity interest in a newly formed Devon subsidiary, EMH, and $100 million in cash. EMH owned midstream assets in the Barnett Shale in north Texas and the Cana- and Arkoma-Woodford Shales in Oklahoma, as well as an economic interest in Gulf Coast Fractionators in Mont Belvieu, Texas.
This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, EMH was the accounting acquirer because its parent company, Devon, obtained control of EnLink and the General Partner as a result of the business combination. Consequently, EMH’s assets and liabilities retained their carrying values. Additionally, the Crosstex assets acquired and liabilities assumed by the General Partner and EnLink in the business combination, as well as the General Partner’s noncontrolling interest in EnLink, were recorded at their fair values which were measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of Crosstex’s net assets acquired was recorded as goodwill.
The following table summarizes the purchase price (millions, except unit price).
Crosstex Energy, Inc. outstanding common shares: |
|
|
|
|
|
Held by public shareholders |
|
| 48.0 |
|
|
Restricted shares |
|
| 0.4 |
|
|
Total subject to conversion |
|
| 48.4 |
|
|
Exchange ratio |
|
| 1.0 |
| x |
Converted shares |
|
| 48.4 |
|
|
Crosstex Energy, Inc. common share price (1) |
| $ | 37.60 |
|
|
Crosstex Energy, Inc. consideration |
| $ | 1,823 |
|
|
Fair value of noncontrolling interest in E2 (2) |
|
| 18 |
|
|
Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests |
| $ | 1,841 |
|
|
Crosstex Energy, LP outstanding units: |
|
|
|
|
|
Common units held by public unitholders |
|
| 75.1 |
|
|
Preferred units held by third party (3) |
|
| 17.1 |
|
|
Restricted units |
|
| 0.4 |
|
|
Total |
|
| 92.6 |
|
|
Crosstex Energy, LP common unit price (4) |
| $ | 30.51 |
|
|
Crosstex Energy, LP common units value |
| $ | 2,825 |
|
|
Crosstex Energy, LP outstanding unit options value |
|
| 4 |
|
|
Total fair value of noncontrolling interests in the Crosstex Energy, LP (4) |
|
| 2,829 |
|
|
Total consideration and fair value of noncontrolling interests |
| $ | 4,670 |
|
|
|
|
|
|
|
|
|
|
73
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The allocation of the purchase price is as follows (millions):
Assets acquired: |
|
|
|
|
Current assets |
| $ | 437 |
|
Property, plant and equipment |
|
| 2,438 |
|
Intangible assets |
|
| 569 |
|
Equity investment |
|
| 222 |
|
Goodwill (1) |
|
| 3,283 |
|
Other long-term assets |
|
| 1 |
|
Liabilities assumed: |
|
|
|
|
Current liabilities |
|
| (515 | ) |
Long-term debt |
|
| (1,454 | ) |
Deferred income taxes |
|
| (210 | ) |
Other long-term liabilities |
|
| (101 | ) |
Total purchase price |
| $ | 4,670 |
|
|
|
Pro Forma Financial Information
The following unaudited pro forma financial information has been prepared assuming both the EnLink formation and the GeoSouthern acquisition occurred on January 1, 2014. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devon’s results of operations for any future period.
|
| Year Ended December 31, 2014 |
| |
|
| (Millions) |
| |
Total operating revenues |
| $ | 20,213 |
|
Net earnings |
| $ | 1,716 |
|
Noncontrolling interests |
| $ | 97 |
|
Net earnings attributable to Devon |
| $ | 1,619 |
|
Net earnings per common share attributable to Devon |
| $ | 3.94 |
|
7464
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Discontinued Operations – Upstream Assets
In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from the Company, based on authorizations provided by its Board of Directors. On June 27, 2019, Devon completed the sale of substantially all of its oil and gas assets and operations in Canada to Canadian Natural Resources Limited for proceeds, net of purchase price adjustments, of $2.6 billion ($3.4 billion Canadian dollars), and recognized a pre-tax gain of $223 million ($425 million, net of tax, primarily due to a significant deferred tax benefit). As a part of the transaction, $436 million of asset retirement obligations were assumed by Canadian Natural Resources Limited. In aggregate, the total estimated proved reserves associated with these assets were approximately 400 MMBoe, or 21% of total proved reserves. In conjunction with the Canadian divestiture, Devon recognized approximately $285 million of restructuring and asset impairment related charges. These costs relate to personnel, office lease abandonment and a firm transportation agreement abandonment. Additional information on these discontinued operations can be found in Note 18.
In December 2019, Devon announced the sale of its Barnett Shale assets to BKV for approximately $770 million, before purchase price adjustments. Estimated proved reserves associated with Devon’s Barnett Shale assets are approximately 45% of total U.S. proved reserves. In connection with the announced sale of its Barnett Shale assets, Devon recognized a $748 million asset impairment related to these assets, primarily due to the difference between the net carrying value and the purchase price, net of estimated customary purchase price adjustments. This transaction is expected to close in the second quarter of 2020. For additional information see Note 18.
During 2018, Devon received proceeds of approximately $500 million and recognized a $26 million net gain on asset dispositions from the sales of non-core assets in the Barnett Shale, located primarily in Johnson and Wise counties, Texas. In conjunction with these divestitures, Devon settled certain gas processing contracts and recognized $40 million in settlement expense, which is included in asset dispositions within the discontinued operations. For additional information, see Note 18.
Discontinued Operations – EnLink and General Partner
During the third quarter of 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). The proceeds from the sale were utilized to increase Devon’s share repurchase activities, which are discussed further in Note 17. Additional information on these discontinued operations can be found in Note 18.
Continuing Operations
During 2019, Devon received proceeds of approximately $390 million and recognized a $48 million net gain on asset dispositions, primarily from sales of non-core assets in the Permian Basin. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 54 MMBoe. As of December 31, 2018, assets and liabilities associated with the Permian Basin divested assets were classified as held for sale in the accompanying consolidated balance sheet.
During 2018, Devon received proceeds totaling approximately $500 million, primarily from the sales of non-core assets in the Delaware Basin, and recognized a net gain on asset dispositions of $278 million. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 24 MMBoe.
During 2017, Devon received proceeds totaling approximately $425 million, and recognized a net gain on asset dispositions of $219 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves.
65
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
3. | Derivative Financial Instruments |
Commodity Derivatives
As of December 31, 2016,2019, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||
Period |
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
| |||||
Q1-Q4 2017 |
|
| 72,527 |
|
| $ | 54.32 |
|
|
| 53,245 |
|
| $ | 45.16 |
|
| $ | 57.97 |
|
Q1-Q4 2018 |
|
| 2,600 |
|
| $ | 53.38 |
|
|
| 6,189 |
|
| $ | 46.97 |
|
| $ | 56.97 |
|
|
| 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 2020 |
|
| 11,238 |
|
| $ | 57.68 |
|
|
| 44,932 |
|
| $ | 51.30 |
|
| $ | 61.36 |
|
Q1-Q4 2021 |
|
| 989 |
|
| $ | 54.81 |
|
|
| 5,942 |
|
| $ | 49.59 |
|
| $ | 59.59 |
|
|
| Oil Basis Swaps |
|
| Oil Basis Swaps |
| ||||||||||||||
Period |
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
|
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
| ||||
Q1-Q4 2017 |
| Midland Sweet |
|
| 10,000 |
|
| $ | (0.43 | ) | ||||||||||
Q1-Q4 2020 |
| Argus MEH |
|
| 10,000 |
|
| $ | 3.38 |
| ||||||||||
Q1-Q4 2020 |
| NYMEX Roll |
|
| 50,000 |
|
| $ | 0.36 |
|
As of December 31, 2016,2019, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.
|
| 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 2017 |
|
| 189,753 |
|
| $ | 3.13 |
|
|
| 335,274 |
|
| $ | 2.97 |
|
| $ | 3.38 |
|
Q1-Q4 2018 |
|
| 29,705 |
|
| $ | 3.17 |
|
|
| 19,110 |
|
| $ | 3.20 |
|
| $ | 3.50 |
|
|
| 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 2020 |
|
| 81,409 |
|
| $ | 2.77 |
|
|
| 42,557 |
|
| $ | 2.73 |
|
| $ | 3.03 |
|
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||
Q1-Q4 2017 |
| Panhandle Eastern Pipe Line |
|
| 150,000 |
|
| $ | (0.34 | ) |
Q1-Q4 2017 |
| El Paso Natural Gas |
|
| 80,000 |
|
| $ | (0.13 | ) |
Q1-Q4 2017 |
| Houston Ship Channel |
|
| 35,000 |
|
| $ | 0.06 |
|
Q1-Q4 2017 |
| Transco Zone 4 |
|
| 205,000 |
|
| $ | 0.03 |
|
Q1 2018 |
| Panhandle Eastern Pipe Line |
|
| 50,000 |
|
| $ | (0.29 | ) |
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||
Q1-Q4 2020 |
| Panhandle Eastern Pipe Line |
|
| 30,000 |
|
| $ | (0.47 | ) |
Q1-Q4 2020 |
| El Paso Natural Gas |
|
| 45,000 |
|
| $ | (0.70 | ) |
Q1-Q4 2020 |
| Houston Ship Channel |
|
| 10,000 |
|
| $ | 0.02 |
|
As of December 31, 2016, EnLink2019, Devon had the following open NGL derivative positions associated with gas processing and fractionation. EnLink’spositions. Devon’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.
|
|
|
|
| |||||||
|
|
|
|
|
| ||||||
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
| Price Swaps |
| |||||
Period |
| Product |
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
| ||
Q1-Q4 2020 |
| Natural Gasoline |
|
| 1,000 |
|
| $ | 44.84 |
|
Q1-Q4 2020 |
| Normal Butane |
|
| 1,500 |
|
| $ | 23.56 |
|
Q1-Q4 2020 |
| Propane |
|
| 4,500 |
|
| $ | 25.18 |
|
75
66
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Interest Rate Derivatives
As of December 31, 2016, Devon had the following open interest rate derivative positions:
Notional |
|
| Rate Received |
|
| Rate Paid |
|
| Expiration | |||
(Millions) |
|
|
|
|
|
|
|
|
|
|
| |
$ | 750 |
|
| Three Month LIBOR |
|
|
| 2.98% |
|
| December 2048 (1) | |
$ | 100 |
|
|
| 1.76% |
|
| Three Month LIBOR |
|
| January 2019 |
|
|
Financial Statement Presentation
The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of comprehensive earnings caption.
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2019 |
|
| 2018 |
|
| 2017 |
| ||||||
Commodity derivatives: |
| (Millions) |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Oil, gas and NGL derivatives |
| $ | (201 | ) |
| $ | 503 |
|
| $ | 1,989 |
| ||||||||||||
Upstream revenues |
| $ | (454 | ) |
| $ | 457 |
|
| $ | 67 |
| ||||||||||||
Marketing and midstream revenues |
|
| (13 | ) |
|
| 9 |
|
|
| 22 |
|
|
| 1 |
|
|
| (1 | ) |
|
| 3 |
|
Interest rate derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other nonoperating items |
|
| (19 | ) |
|
| (20 | ) |
|
| (1 | ) | ||||||||||||
Foreign currency derivatives: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Other nonoperating items |
|
| (153 | ) |
|
| 246 |
|
|
| 60 |
| ||||||||||||
Other expenses |
|
| — |
|
|
| 65 |
|
|
| (22 | ) | ||||||||||||
Net gains (losses) recognized |
| $ | (386 | ) |
| $ | 738 |
|
| $ | 2,070 |
|
| $ | (453 | ) |
| $ | 521 |
|
| $ | 48 |
|
76
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.
|
| December 31, 2016 |
|
| December 31, 2015 |
| ||||||||||
|
| (Millions) |
|
| December 31, 2019 |
|
| December 31, 2018 |
| |||||||
Commodity derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
| $ | 9 |
|
| $ | 34 |
|
| $ | 49 |
|
| $ | 634 |
|
Other long-term assets |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
|
| 40 |
|
Interest rate derivative assets: |
|
|
|
|
|
|
|
| ||||||||
Other current assets |
|
| 1 |
|
|
| 1 |
| ||||||||
Other long-term assets |
|
| — |
|
|
| 1 |
| ||||||||
Foreign currency derivative assets: |
|
|
|
|
|
|
|
| ||||||||
Other current assets |
|
| — |
|
|
| 8 |
| ||||||||
Total derivative assets |
| $ | 11 |
|
| $ | 45 |
|
| $ | 50 |
|
| $ | 674 |
|
|
|
|
|
|
|
|
|
| ||||||||
Commodity derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
| $ | 187 |
|
| $ | 14 |
|
| $ | 30 |
|
| $ | 32 |
|
Other long-term liabilities |
|
| 16 |
|
|
| 4 |
|
|
| 1 |
|
|
| 1 |
|
Interest rate derivative liabilities: |
|
|
|
|
|
|
|
| ||||||||
Other long-term liabilities |
|
| 41 |
|
|
| 22 |
| ||||||||
Foreign currency derivative liabilities: |
|
|
|
|
|
|
|
| ||||||||
Other current liabilities |
|
| — |
|
|
| 8 |
| ||||||||
Total derivative liabilities |
| $ | 244 |
|
| $ | 48 |
|
| $ | 31 |
|
| $ | 33 |
|
4. |
In the second quarter of 2015,2017, Devon’s stockholders approved the 2015 Long-Term Incentive2017 Plan. The 20152017 Plan replaces the 2009 Long-Term Incentive Plan, as amended.2015 Plan. From the effective date of the 20152017 Plan, no further awards may be made under the 20092015 Plan, and awards previously granted will continue to be governed by the terms of the 2009 Plan.respective award documents. Subject to the terms of the 20152017 Plan, awards may be made under the 2015 Plan for a total of 2833.5 million shares of Devon common stock, plus the number of shares available for issuance under the 20092015 Plan (including shares subject to outstanding awards underthat were transferred to the 20092017 Plan that are subsequently forfeited, canceled or expire)in accordance with its terms). The 20152017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance awards or units and stock appreciation rights to eligible employees. The 20152017 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 20152017 Plan, options and stock appreciation rights represent one1 share and other awards represent three2.3 shares.
Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.
7767
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The table below presents the effects of share-based compensation included in Devon’s accompanying consolidated comprehensive statements of earnings. Gross G&A in 2016, 2015 and 2014 includes $24 million, $31 million and $17 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.
The vesting for certain share-based awards was accelerated in 20162019 and 2018 in conjunction with the reduction of workforce activities described in Note 6. Approximately $60 million of associated expense for these accelerated awards6 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of comprehensive earnings. In 2014, vesting of certain
The table below presents the share-based awards was accelerated in conjunction with the divestiture of Devon’s Canadian conventional assets. Approximately $15 million of associatedcompensation expense for these accelerated awards is included in restructuring and transaction costs in theDevon’s accompanying consolidated comprehensive statements of comprehensive earnings.
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
Gross G&A for share-based compensation |
| $ | 154 |
|
| $ | 225 |
|
| $ | 199 |
|
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties |
| $ | 39 |
|
| $ | 63 |
|
| $ | 53 |
|
Related income tax benefit |
| $ | 4 |
|
| $ | 45 |
|
| $ | 42 |
|
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
G&A |
| $ | 83 |
|
| $ | 104 |
|
| $ | 121 |
|
Exploration expenses |
|
| 1 |
|
|
| 2 |
|
|
| 5 |
|
Restructuring and transaction costs |
|
| 31 |
|
|
| 31 |
|
|
| — |
|
Total |
| $ | 115 |
|
| $ | 137 |
|
| $ | 126 |
|
Related income tax benefit |
| $ | 13 |
|
| $ | 17 |
|
| $ | — |
|
The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plans.
|
| Restricted Stock |
|
| Performance-Based |
|
| Performance |
|
| Restricted Stock |
|
| Performance-Based |
|
| Performance |
| |||||||||||||||||||||||||||||||||||
|
| Awards and Units |
|
| Restricted Stock Awards |
|
| Share Units |
|
| Awards and Units |
|
| Restricted Stock Awards |
|
| Share Units |
| |||||||||||||||||||||||||||||||||||
|
| Awards and Units |
|
| Weighted Average Grant-Date Fair Value |
|
| Awards |
|
| Weighted Average Grant-Date Fair Value |
|
| Units |
|
|
|
| Weighted Average Grant-Date Fair Value |
|
| Awards and Units |
|
| Weighted Average Grant-Date Fair Value |
|
| Awards |
|
| Weighted Average Grant-Date Fair Value |
|
| Units |
|
|
|
| Weighted Average Grant-Date Fair Value |
| |||||||||||||
|
| (Thousands, except fair value data) |
|
| (Thousands, except fair value data) |
| |||||||||||||||||||||||||||||||||||||||||||||||
Unvested at 12/31/15 |
|
| 4,738 |
|
| $ | 62.49 |
|
|
| 434 |
|
| $ | 60.48 |
|
|
| 1,859 |
|
| $ | 76.17 |
| |||||||||||||||||||||||||||||
Unvested at 12/31/18 |
|
| 5,963 |
|
| $ | 35.47 |
|
|
| 302 |
|
| $ | 35.93 |
|
|
| 2,868 |
|
|
| $ | 30.14 |
| ||||||||||||||||||||||||||||
Granted |
|
| 4,390 |
|
| $ | 19.91 |
|
|
| 330 |
|
| $ | 19.22 |
|
|
| 1,388 |
|
| $ | 10.41 |
|
|
| 4,430 |
|
| $ | 25.47 |
|
|
| — |
|
| $ | — |
|
|
| 741 |
|
|
| $ | 28.97 |
| ||||
Vested |
|
| (2,473 | ) |
| $ | 61.44 |
|
|
| (179 | ) |
| $ | 59.10 |
|
|
| (602 | ) |
| $ | 63.37 |
|
|
| (4,646 | ) |
| $ | 33.48 |
|
|
| (149 | ) |
| $ | 38.03 |
|
|
| (145 | ) |
|
| $ | 37.23 |
| ||||
Forfeited |
|
| (248 | ) |
| $ | 44.38 |
|
|
| — |
|
| $ | — |
|
|
| (41 | ) |
| $ | 43.88 |
|
|
| (763 | ) |
| $ | 27.50 |
|
|
| — |
|
| $ | — |
|
|
| (1,309 | ) |
|
| $ | 11.91 |
| ||||
Unvested at 12/31/16 |
|
| 6,407 |
|
| $ | 34.40 |
|
|
| 585 |
|
| $ | 37.60 |
|
|
| 2,604 |
|
| (1 | ) | $ | 46.66 |
| |||||||||||||||||||||||||||
Unvested at 12/31/19 |
|
| 4,984 |
|
| $ | 29.65 |
|
|
| 153 |
|
| $ | 33.88 |
|
|
| 2,155 |
|
| (1 | ) |
| $ | 40.35 |
|
(1) | A maximum of |
The following table presents the aggregate fair value of awards and units that vested during the indicated period.
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
Restricted Stock Awards and Units |
| $ | 73 |
|
| $ | 101 |
|
| $ | 112 |
|
Performance-Based Restricted Stock Awards |
| $ | 5 |
|
| $ | 8 |
|
| $ | 10 |
|
Performance Share Units |
| $ | 13 |
|
| $ | 22 |
|
| $ | — |
|
78
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2016.
|
|
|
|
|
| Performance-Based |
|
|
|
|
| |
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
| |||
|
| Awards and Units |
|
| Awards |
|
| Share Units |
| |||
Unrecognized compensation cost (millions) |
| $ | 131 |
|
| $ | 5 |
|
| $ | 21 |
|
Weighted average period for recognition (years) |
|
| 2.3 |
|
|
| 2.2 |
|
|
| 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 years. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period.
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Restricted Stock Awards and Units |
| $ | 127 |
|
| $ | 111 |
|
| $ | 105 |
|
Performance-Based Restricted Stock Awards |
| $ | 4 | $ | 10 | $ | 10 | |||||
Performance Share Units | $ | 4 | $ | 20 | $ | 38 |
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, 2019.
|
|
|
|
|
| Performance-Based |
|
|
|
|
| |
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
| |||
|
| Awards and Units |
|
| Awards |
|
| Share Units |
| |||
Unrecognized compensation cost |
| $ | 80 |
|
| $ | — |
|
| $ | 12 |
|
Weighted average period for recognition (years) |
|
| 2.5 |
|
|
| 1.4 |
|
|
| 1.5 |
|
68
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 years. In order for awards to vest, the performance target must be met in the first year, and if met, recipients are entitled to dividends on the awards over the remaining service requirement for vesting ranges from one to four years. During the vesting period, recipients of restricted stock awards made under the 2015 Plan receive dividends that are not subject to restrictions or other limitations. However, 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 Awards
Performance-based restricted stock awards were granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from one to four years. In order for awards to vest, the performance target must be met in the first year. If the performance target is met, the recipient is entitled to dividends under the same terms described above for nonperformance-based restricted stock. If the performance target and service period requirements are not met, the award does not vest. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. NaN performance-based restricted stock awards were granted in 2019 and 2018.
Performance Share Units
Performance share units are granted to certain members of Devon’s management and employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of 14 peer companies over the specified three-year performance period. The vesting of units may be between 0 and 200% of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.
At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted.
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||||||||||||||||||||
Grant-date fair value |
| $ | 28.43 |
|
| — |
| $ | 29.53 |
|
| $ | 36.23 |
|
| — |
| $ | 37.88 |
|
| $ | 51.05 |
|
| — |
| $ | 53.12 |
|
Risk-free interest rate |
| 2.48% |
|
| 2.28% |
|
| 1.50% |
| |||||||||||||||||||||
Volatility factor |
| 39.1% |
|
| 45.8% |
|
| 45.8% |
| |||||||||||||||||||||
Contractual term (years) |
| 2.89 |
|
| 2.89 |
|
| 2.89 |
|
69
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
5. | Asset Impairments |
The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the consolidated statements of comprehensive earnings.
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Proved oil and gas assets |
| $ | — |
|
| $ | 109 |
|
| $ | — |
|
Other assets |
|
| — |
|
|
| 47 |
|
|
| — |
|
Total asset impairments |
| $ | — |
|
| $ | 156 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved impairments |
| $ | 18 |
|
| $ | 95 |
|
| $ | 217 |
|
Proved Oil and Gas and Other Asset Impairments
In 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and approximately $47 million of non-oil and gas asset impairments.
UnprovedImpairments
In 2019, 2018 and 2017, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments.
6. | Restructuring and Transaction Costs |
2019 Workforce Reductions
During the first quarter of 2019, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure in conjunction with the portfolio transformation announcement further discussed in Note 2. As a result, Devon recognized $84 million of restructuring expenses during 2019. Of these expenses, $31 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, $7 million resulted from settlements of defined retirement benefits.
Prior Years’ Restructurings
During 2018, Devon recognized $97 million in personnel related restructuring expenses related to workforce reductions. Of these expenses, $31 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, $14 million resulted from estimated settlements of defined retirement benefits.
The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets.
70
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Other |
|
| Other |
|
|
|
|
| ||
|
| Current |
|
| Long-term |
|
|
|
|
| ||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
Balance as of December 31, 2017 |
| $ | 17 |
|
| $ | 17 |
|
| $ | 34 |
|
Changes related to prior years' restructurings |
|
| 22 |
|
|
| (14 | ) |
|
| 8 |
|
Balance as of December 31, 2018 |
| $ | 39 |
|
| $ | 3 |
|
| $ | 42 |
|
Changes due to 2019 workforce reductions |
|
| 18 |
|
|
| — |
|
|
| 18 |
|
Changes related to prior years' restructurings |
|
| (37 | ) |
|
| (2 | ) |
|
| (39 | ) |
Balance as of December 31, 2019 |
| $ | 20 |
|
| $ | 1 |
|
| $ | 21 |
|
7. | Income Taxes |
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Current income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
| $ | (3 | ) |
| $ | (14 | ) |
| $ | 8 |
|
Various states |
|
| (2 | ) |
|
| (3 | ) |
|
| 1 |
|
Total current income tax expense (benefit) |
|
| (5 | ) |
|
| (17 | ) |
|
| 9 |
|
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
| 8 |
|
|
| 184 |
|
|
| (2 | ) |
Various states |
|
| (33 | ) |
|
| 63 |
|
|
| — |
|
Total deferred income tax expense (benefit) |
|
| (25 | ) |
|
| 247 |
|
|
| (2 | ) |
Total income tax expense (benefit) |
| $ | (30 | ) |
| $ | 230 |
|
| $ | 7 |
|
Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) from continuing operations before income taxes as a result of the following:
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Earnings (loss) from continuing operations before income taxes |
| $ | (109 | ) |
| $ | 944 |
|
| $ | 40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
| 21 | % |
|
| 21 | % |
|
| 35 | % |
U.S. Tax Reform |
|
| 0 | % |
|
| 0 | % |
|
| 957 | % |
State income taxes |
|
| 24 | % |
|
| 5 | % |
|
| (2 | %) |
Change in unrecognized tax benefits |
|
| (13 | %) |
|
| (2 | %) |
|
| (15 | %) |
Audit settlements |
|
| 15 | % |
|
| (2 | %) |
|
| 0 | % |
Other |
|
| (19 | %) |
|
| 2 | % |
|
| 2 | % |
Deferred tax asset valuation allowance |
|
| 0 | % |
|
| 0 | % |
|
| (959 | %) |
Effective income tax rate |
|
| 28 | % |
|
| 24 | % |
|
| 18 | % |
71
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examinations by the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business.
Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.
2019
In December 2019, Devon announced the sale of its Barnett Shale assets. This transaction is expected to close in the second quarter of 2020. Devon expects no incremental cash taxes associated with the divestiture of these assets.
On June 27, 2019, Devon completed the sale of substantially all of its oil and gas assets and operations in Canada. Devon’s foreign earnings have not been considered indefinitely reinvested since the announcement of the plan to separate the assets in the first quarter of 2019. As the separation took the form of an asset sale and Devon has retained certain non-operating obligations to be settled over time, Devon has not recorded a deferred tax asset or corresponding valuation allowance related to its Canadian investment.
Devon has recorded materially all tax impacts related to the Barnett Shale and Canadian assets in discontinued operations. Additional information on these discontinued operations can be found in Note 18.
During 2019, Devon recorded a tax expense of $14 million related to unrecognized tax benefits, due to a change in tax positions taken in prior periods.
In the fourth quarter of 2019, Devon entered into an audit agreement with the Canada Revenue Agency. The Canadian income tax expense resulting from this agreement is reflected in discontinued operations. However, the agreement also resulted in a $16 million tax benefit to Devon’s U.S. continuing operations.
The “other” effect is composed of permanent differences, including stock compensation, for which the dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, permanent adjustments, as well as the state income tax, have an insignificant impact on Devon’s effective income tax rate. However, these items had a more noticeable impact to the rate in 2019 due to the low relative net loss in the period.
2018
Through the first six months of 2018, Devon maintained a 100% valuation allowance against its deferred tax assets resulting from prior year cumulative financial losses, oil and gas impairments and significant net operating losses for U.S. federal and state income tax. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period projected net operating loss utilization, and projections of future taxable income, Devon reassessed its position and determined that it was no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses. As part of its reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the
72
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
$259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations.
2017
The Tax Reform Legislation, enacted on December 22, 2017, contained several key tax provisions that affected Devon, including a one-time mandatory transition tax on accumulated foreign earnings and a reduction of the corporate income tax rate to 21% effective January 1, 2018. Devon was required to recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax, remeasuring deferred tax assets and liabilities and reassessing the net realizability of deferred tax assets and liabilities. Devon recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings, and $205 million in deferred tax expense related to the reduction of the U.S. corporate income tax rate to 21%.
During 2017, Devon recorded a tax benefit of $6 million related to unrecognized tax benefits, primarily as a result of a change in tax positions taken in prior periods.
Devon maintained a 100% valuation allowance against its deferred tax assets resulting from prior year cumulative financial losses largely due to asset impairments and significant net operating losses for U.S. federal and state income tax. Devon reduced its valuation allowance by $342 million in 2017 based primarily on the financial income recorded during the period.
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, |
| |||||
|
| 2019 |
|
| 2018 |
| ||
Deferred tax assets: |
|
|
|
|
|
|
|
|
Asset retirement obligations |
| $ | 123 |
|
| $ | 146 |
|
Accrued liabilities |
|
| 35 |
|
|
| 45 |
|
Net operating loss carryforwards |
|
| 306 |
|
|
| 126 |
|
Pension benefit obligations |
|
| 39 |
|
|
| 44 |
|
Tax credits and other |
|
| 66 |
|
|
| 77 |
|
Total deferred tax assets before valuation allowance |
|
| 569 |
|
|
| 438 |
|
Less: valuation allowance |
|
| (106 | ) |
|
| (31 | ) |
Net deferred tax assets |
|
| 463 |
|
|
| 407 |
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property and equipment |
|
| (800 | ) |
|
| (786 | ) |
Other |
|
| (4 | ) |
|
| (150 | ) |
Total deferred tax liabilities |
|
| (804 | ) |
|
| (936 | ) |
Net deferred tax liability |
| $ | (341 | ) |
| $ | (529 | ) |
At December 31, 2019, Devon has recognized $306 million of deferred tax assets related to various net operating loss carryforwards available to offset future taxable income. Devon has $871 million of U.S. federal net operating loss carryforwards ($466 million expiring in 2037 with the remainder having an indefinite life) and $2.5 billion of U.S. state net operating loss carryforwards expiring between 2021 and 2039. In the current environment, Devon expects tax benefits from the U.S. federal and $377 million of U.S. state net operating loss carryforwards to be utilized in 2022 and beyond. A valuation allowance is recorded against the remaining $2.1 billion of U.S. state net operating loss carryforwards.
73
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, |
| |||||
|
| 2019 |
|
| 2018 |
| ||
Balance at beginning of year |
| $ | 51 |
|
| $ | 71 |
|
Tax positions taken in prior periods |
|
| 14 |
|
|
| (20 | ) |
Balance at end of year |
| $ | 65 |
|
| $ | 51 |
|
Devon recognized a net interest benefit of $5 million in 2019 and its unrecognized tax benefit balance included 0 interest and penalties at December 31, 2019. Devon recognized no net interest or penalties in 2018 and its unrecognized tax benefit balance included $5 million of interest and penalties at December 31, 2018. At December 31, 2019 and December 31, 2018, there are $65 million and $51 million, respectively, of unrecognized tax benefits that if recognized would affect the annual effective tax rate.Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
Jurisdiction | Tax Years Open | |
U.S. Federal | 2016-2019 | |
Various U.S. states | 2015-2019 |
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.
8. | Net Earnings (Loss) Per Share from Continuing Operations |
The following table reconciles net earnings (loss) from continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share from continuing operations.
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Net earnings (loss) from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) from continuing operations |
| $ | (81 | ) |
| $ | 714 |
|
| $ | 33 |
|
Attributable to participating securities |
|
| (2 | ) |
|
| (8 | ) |
|
| (1 | ) |
Basic and diluted earnings (loss) from continuing operations |
| $ | (83 | ) |
| $ | 706 |
|
| $ | 32 |
|
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding - total |
|
| 407 |
|
|
| 499 |
|
|
| 525 |
|
Attributable to participating securities |
|
| (6 | ) |
|
| (5 | ) |
|
| (5 | ) |
Common shares outstanding - basic |
|
| 401 |
|
|
| 494 |
|
|
| 520 |
|
Dilutive effect of potential common shares issuable |
|
| — |
|
|
| 3 |
|
|
| — |
|
Common shares outstanding - diluted |
|
| 401 |
|
|
| 497 |
|
|
| 520 |
|
Net earnings (loss) per share from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | (0.21 | ) |
| $ | 1.43 |
|
| $ | 0.06 |
|
Diluted |
| $ | (0.21 | ) |
| $ | 1.42 |
|
| $ | 0.06 |
|
Antidilutive options (1) |
|
| 1 |
|
|
| 1 |
|
|
| 2 |
|
(1) | Amounts represent options to purchase shares of Devon’s common stock
|
74
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Other Comprehensive Earnings |
Components of other comprehensive earnings consist of the following:
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated foreign currency translation and other |
| $ | 1,159 |
|
| $ | 1,309 |
|
| $ | 1,226 |
|
Change in cumulative translation adjustment |
|
| 78 |
|
|
| (166 | ) |
|
| 113 |
|
Release of Canadian cumulative translation adjustment (1) |
|
| (1,237 | ) |
|
| — |
|
|
| — |
|
Income tax benefit (expense) |
|
| — |
|
|
| 14 |
|
|
| (30 | ) |
Other |
|
| — |
|
|
| 2 |
|
|
| — |
|
Ending accumulated foreign currency translation and other |
|
| — |
|
|
| 1,159 |
|
|
| 1,309 |
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated pension and postretirement benefits |
|
| (132 | ) |
|
| (143 | ) |
|
| (172 | ) |
Net actuarial loss (gain) and prior service cost arising in current year |
|
| (10 | ) |
|
| (3 | ) |
|
| 10 |
|
Recognition of net actuarial loss and prior service cost in earnings (2) |
|
| 6 |
|
|
| 12 |
|
|
| 19 |
|
Curtailment and settlement of pension benefits |
|
| 21 |
|
|
| 47 |
|
|
| — |
|
Income tax expense |
|
| (4 | ) |
|
| (12 | ) |
|
| — |
|
Other (3) |
|
| — |
|
|
| (33 | ) |
|
| — |
|
Ending accumulated pension and postretirement benefits |
|
| (119 | ) |
|
| (132 | ) |
|
| (143 | ) |
Accumulated other comprehensive earnings (loss), net of tax |
| $ | (119 | ) |
| $ | 1,027 |
|
| $ | 1,166 |
|
(1) | In conjunction with the
|
(2) | These accumulated other comprehensive earnings components are included in the
|
|
| Other |
|
| Other |
|
|
|
|
| ||
|
| Current |
|
| Long-term |
|
|
|
|
| ||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
|
| (Millions) |
| |||||||||
Balance as of December 31, 2014 |
| $ | 13 |
|
| $ | 7 |
|
| $ | 20 |
|
Changes related to prior years' restructurings |
|
| — |
|
|
| 56 |
|
|
| 56 |
|
Balance as of December 31, 2015 |
| $ | 13 |
|
| $ | 63 |
|
| $ | 76 |
|
Changes due to 2016 workforce reductions |
|
| 29 |
|
|
| 6 |
|
|
| 35 |
|
Changes related to prior years' restructurings |
|
| 6 |
|
|
| (7 | ) |
|
| (1 | ) |
Balance as of December 31, 2016 |
| $ | 48 |
|
| $ | 62 |
|
| $ | 110 |
|
10. | Supplemental Information to Statements of Cash Flows |
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Changes in assets and liabilities, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
| $ | (3 | ) |
| $ | (69 | ) |
| $ | (139 | ) |
Other current assets |
|
| (7 | ) |
|
| (152 | ) |
|
| 15 |
|
Other long-term assets |
|
| 17 |
|
|
| (7 | ) |
|
| (36 | ) |
Accounts payable |
|
| (54 | ) |
|
| (3 | ) |
|
| 91 |
|
Revenues and royalties payable |
|
| 8 |
|
|
| 106 |
|
|
| 102 |
|
Other current liabilities |
|
| (66 | ) |
|
| 3 |
|
|
| (15 | ) |
Other long-term liabilities |
|
| 23 |
|
|
| (36 | ) |
|
| (8 | ) |
Total |
| $ | (82 | ) |
| $ | (158 | ) |
| $ | 10 |
|
Supplementary cash flow data - total operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest) |
| $ | 308 |
|
| $ | 385 |
|
| $ | 481 |
|
Income taxes paid |
| $ | 6 |
|
| $ | 40 |
|
| $ | 78 |
|
75
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
11. | Accounts Receivable |
Components of accounts receivable include the following:
|
| December 31, 2019 |
|
| December 31, 2018 |
| ||
Oil, gas and NGL sales |
| $ | 452 |
|
| $ | 375 |
|
Joint interest billings |
|
| 168 |
|
|
| 149 |
|
Marketing and midstream revenues |
|
| 207 |
|
|
| 284 |
|
Other |
|
| 13 |
|
|
| 10 |
|
Gross accounts receivable |
|
| 840 |
|
|
| 818 |
|
Allowance for doubtful accounts |
|
| (8 | ) |
|
| (6 | ) |
Net accounts receivable |
| $ | 832 |
|
| $ | 812 |
|
12.Property, Plant and Equipment
Capitalized Costs
The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
|
| December 31, 2019 |
|
| December 31, 2018 |
| ||
Property and equipment: |
|
|
|
|
|
|
|
|
Proved |
| $ | 27,668 |
|
| $ | 25,901 |
|
Unproved and properties under development |
|
| 583 |
|
|
| 830 |
|
Total oil and gas |
|
| 28,251 |
|
|
| 26,731 |
|
Less accumulated DD&A |
|
| (20,693 | ) |
|
| (19,301 | ) |
Oil and gas property and equipment, net |
|
| 7,558 |
|
|
| 7,430 |
|
Other property and equipment |
|
| 1,725 |
|
|
| 1,680 |
|
Less accumulated DD&A |
|
| (690 | ) |
|
| (648 | ) |
Other property and equipment, net (1) |
|
| 1,035 |
|
|
| 1,032 |
|
Property and equipment, net |
| $ | 8,593 |
|
| $ | 8,462 |
|
(1) | $80 million related to CDM in 2019. |
Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2019.
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Beginning balance |
| $ | 98 |
|
| $ | 100 |
|
| $ | 75 |
|
Additions pending determination of proved reserves |
|
| 278 |
|
|
| 658 |
|
|
| 491 |
|
Reclassifications to proved properties |
|
| (294 | ) |
|
| (660 | ) |
|
| (466 | ) |
Ending balance |
| $ | 82 |
|
| $ | 98 |
|
| $ | 100 |
|
Devon had no projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling as of December 31, 2019, 2018 and 2017, respectively.
76
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
13. | Debt and Related Expenses |
See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.
|
| December 31, 2019 |
|
| December 31, 2018 |
| ||
|
|
|
|
|
|
|
|
|
6.30% due January 15, 2019 |
| $ | — |
|
| $ | 162 |
|
5.85% due December 15, 2025 |
|
| 485 |
|
|
| 485 |
|
7.50% due September 15, 2027 (1) |
|
| 73 |
|
|
| 73 |
|
7.875% due September 30, 2031 (2) (3) |
|
| 675 |
|
|
| 675 |
|
7.95% due April 15, 2032 (2) |
|
| 366 |
|
|
| 366 |
|
5.60% due July 15, 2041 |
|
| 1,250 |
|
|
| 1,250 |
|
4.75% due May 15, 2042 |
|
| 750 |
|
|
| 750 |
|
5.00% due June 15, 2045 |
|
| 750 |
|
|
| 750 |
|
Net discount on debentures and notes |
|
| (20 | ) |
|
| (21 | ) |
Debt issuance costs |
|
| (35 | ) |
|
| (36 | ) |
Total debt |
|
| 4,294 |
|
|
| 4,454 |
|
Less amount classified as short-term debt |
|
| — |
|
|
| 162 |
|
Total long-term debt (4) |
| $ | 4,294 |
|
| $ | 4,292 |
|
(1) | This instrument was assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of this note at the time assumed was $169 million and 6.5%. This instrument is the unsecured and unsubordinated obligation of Devon OEI Operating, L.L.C. and is guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. |
(2) | These senior notes were included in 2018 tender offer repurchases discussed below. |
(3) | These senior notes were originally issued by Devon Financing, a wholly-owned subsidiary of Devon, and guaranteed by Devon. On June 19, 2019, Devon Financing assigned its obligations and rights with respect to these senior notes to Devon pursuant to the terms of the related indenture. As a result of this transfer, Devon Financing was relieved of its obligations under the senior notes and related indenture and Devon assumed all such |
| The balance as of December 31,
|
As noted in the table above, as of December 31, 2019, Devon does not have any outstanding debt maturities due within the next five years.
77
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Credit Lines
Devon has a $3.0 billion Senior Credit Facility. As of December 31, 2019, Devon had $2 million in outstanding letters of credit under the Senior Credit Facility. There were 0 borrowings under the Senior Credit Facility as of December 31, 2019.
In connection with the closing of the sale of its Canadian business, Devon reallocated and terminated all Canadian commitments under the Senior Credit Facility in accordance with the terms of the credit agreement governing the Senior Credit Facility. The termination of the Canadian subfacility was effective as of June 27, 2019, and such termination did not decrease the $3.0 billion in total revolving commitments under, or otherwise modify the terms of, the Senior Credit Facility. Subsequent to Devon’s divestment of substantially all of its oil and gas assets and operations in Canada, Devon entered into an amendment and extension agreement on December 13, 2019 to, among other things, (i) effect the extension of the maturity date of the Senior Credit Facility from October 5, 2023 to October 5, 2024 with respect to the consenting lenders, (ii) modify the maximum number of maturity extension requests during the term of the Senior Credit Facility from two to three and (iii) eliminate various references to the terminated Canadian subfacility. As a result of this amendment, Devon has the option to extend the October 5, 2024 maturity date by two additional one-year periods subject to lender consent, and the maximum borrowing capacity of the Senior Credit Facility becomes $2.8 billion after October 5, 2023. Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $6 million.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. For example, total capitalization is adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2019, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 19.1%.
Commercial Paper
Devon’s Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the commercial paper market. During 2016, Devon reduced commercial paper borrowings by $626 million. As of December 31, 2016,2019, Devon had no0 outstanding commercial paper borrowings.
Retirement of Senior Notes
In January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity.
During 2016,2018, Devon completed tender offers to repurchase $2.1 billion$807 million in aggregate principal amount of debt securities, using proceeds fromcash on hand. This included $384 million of the asset divestitures discussed in Note 2.7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a loss$312 million charge on early retirement of debt, primarily consisting of $265$304 million in cash retirement costs and other fees.$8 million of noncash charges. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of comprehensive earnings.
In November 2014, During 2018, Devon redeemed $1.9 billionrepaid $115 million of senior notes prior to their scheduled maturity, primarily with proceeds received from asset divestitures. Devon recognized a loss on the early retirement of debt, primarilyat maturity.
9378
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
consistingFinancing Costs, Net
The following schedule includes the components of $40net financing costs.
|
| Year Ended December 31, |
| |||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
| |||
Interest based on debt outstanding |
| $ | 260 |
|
| $ | 287 |
|
| $ | 337 |
|
Early retirement of debt |
|
| — |
|
|
| 312 |
|
|
| — |
|
Other |
|
| (10 | ) |
|
| (19 | ) |
|
| (16 | ) |
Total net financing costs |
| $ | 250 |
|
| $ | 580 |
|
| $ | 321 |
|
14. | Leases |
Devon adopted ASU No. 2016-02, Leases (Topic 842), as of January 1, 2019, using the modified retrospective transition approach. ASC 842 supersedes the previous lease accounting requirements in ASC 840 and requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 establishes a right-of-use model that requires a lessee to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term longer than 12 months. At adoption, using the modified retrospective transition approach, Devon recorded right-of-use lease assets of $410 million and lease liabilities of $380 million. Additionally, Devon recorded a $8 million before tax, $7 million net of tax, cumulative-effect adjustment to reduce retained earnings. Comparative periods have been presented in cash retirementaccordance with ASC Topic 840 and do not include any retrospective adjustments to reflect the adoption of Topic 842. Excluding land easements and rights-of-way, all leases that existed at January 1, 2019 or were entered into or modified thereafter, are accounted for under Topic 842. Devon elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases with terms of 12 months or less. Additionally, Devon elected to account for lease components separately from the nonlease components.
Devon made certain significant assumptions and judgments in determining its right-of-use asset and lease liability balances. First is the determination of whether a contract contains a lease. Devon considered the presence of an identified asset that is physically distinct, and for which the supplier does not have substantive substitution rights and whether Devon has the right to control the underlying asset. Second, Devon assessed lease terms and considered whether Devon is reasonably certain to extend leases or exercise purchase options. Certain of Devon’s leases include one or more options to renew, with renewal terms that can extend the lease term for additional years. Certain leases also include options to purchase the leased property. For options to renew or purchase that Devon is reasonably certain to exercise, these costs are recognized as part of the right-of-use assets and lease liabilities. Third, significant judgments have been made in determining discount rates. Devon estimates discount rates using market rates that approximate collateralized borrowings over the remaining term of Devon’s lease payments.
Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other noncash charges. These costsequipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are included in net financing costs in the consolidated comprehensive statementrelated to real estate. Certain of earnings.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.
Issuance of Senior Notes
In December 2015, in conjunction with the announcement of the Powder River Basin and STACK acquisitions, Devon issued $850 million of 5.85% senior notes due 2025 that are unsecured and unsubordinated obligations. Devon used the net proceeds to partially fund the cash portion of these acquisitions.
In June 2015, Devon issued $750 million of 5.0% senior notes due 2045 that are unsecured and unsubordinated obligations. Devon used the net proceeds to repay the floating rate senior notes that matured on December 15, 2015, as well as outstanding commercial paper balances.
EnLink Debt
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
EnLink has a $1.5 billion unsecured revolving credit facility that will mature on March 6, 2020. As of December 31, 2016, there were $12 million in outstanding letters of credit and $120 million outstanding borrowings, with a weighted-average borrowing rate of 2.3%, 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, 2016, the General Partner had $28 million outstanding borrowings under the $250 million credit facility at a weighted average borrowing rate of 3.4%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2016.
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.
In May 2015, EnLink issued $900 million principal amount of unsecured senior notes, consisting of $750 million principal amount of its 4.15% senior notes due 2025 and an additional $150 million principal amount of its 5.05% senior notes due 2045. EnLink used the net proceeds to repay outstanding revolving credit facility borrowings, for capital expenditures and for general operations.
9479
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Net Financing CostsThe following table presents Devon’s right-of-use assets and lease liabilities as of December 31, 2019.
|
| Finance |
|
| Operating |
|
| Total |
| |||
Right-of-use assets |
| $ | 229 |
|
| $ | 14 |
|
| $ | 243 |
|
Lease liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Current lease liabilities (1) |
| $ | 7 |
|
| $ | 10 |
|
| $ | 17 |
|
Long-term lease liabilities |
|
| 240 |
|
|
| 4 |
|
|
| 244 |
|
Total lease liabilities |
| $ | 247 |
|
| $ | 14 |
|
| $ | 261 |
|
(1) | Current lease liabilities are included in other current liabilities on the consolidated balance sheets. |
The following schedule includes the components of net financing costs.table presents Devon’s total lease cost.
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
Devon net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
| $ | 488 |
|
| $ | 450 |
|
| $ | 468 |
|
Early retirement of debt |
|
| 269 |
|
|
| — |
|
|
| 48 |
|
Capitalized interest |
|
| (64 | ) |
|
| (54 | ) |
|
| (58 | ) |
Other |
|
| 21 |
|
|
| 14 |
|
|
| 15 |
|
Total Devon net financing costs |
|
| 714 |
|
|
| 410 |
|
|
| 473 |
|
EnLink net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
|
| 144 |
|
|
| 115 |
|
|
| 64 |
|
Interest accretion on deferred installment payment |
|
| 52 |
|
|
| — |
|
|
| — |
|
Other |
|
| (6 | ) |
|
| (8 | ) |
|
| (11 | ) |
Total EnLink net financing costs |
|
| 190 |
|
|
| 107 |
|
|
| 53 |
|
Total net financing costs |
| $ | 904 |
|
| $ | 517 |
|
| $ | 526 |
|
|
|
| Year Ended |
| |
|
|
| December 31, 2019 |
| |
Operating lease cost | Property, plant and equipment; G&A |
| $ | 40 |
|
Short-term lease cost (1) | Property, plant and equipment; G&A |
|
| 84 |
|
Financing lease cost: |
|
|
|
|
|
Amortization of right-of-use assets | DD&A |
|
| 8 |
|
Interest on lease liabilities | Net financing costs |
|
| 10 |
|
Variable lease cost | G&A |
|
| 2 |
|
Lease income | G&A |
|
| (5 | ) |
Net lease cost |
|
| $ | 139 |
|
|
|
The following table presents Devon’s additional lease information for the changes in asset retirement obligations.year ended December 31, 2019.
|
| Year Ended December 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
|
| (Millions) |
| |||||
Asset retirement obligations as of beginning of period |
| $ | 1,414 |
|
| $ | 1,399 |
|
Liabilities incurred and assumed through acquisitions |
|
| 27 |
|
|
| 63 |
|
Liabilities settled and divested |
|
| (324 | ) |
|
| (89 | ) |
Revision of estimated obligation |
|
| 66 |
|
|
| 62 |
|
Accretion expense on discounted obligation |
|
| 75 |
|
|
| 75 |
|
Foreign currency translation adjustment |
|
| 14 |
|
|
| (96 | ) |
Asset retirement obligations as of end of period |
|
| 1,272 |
|
|
| 1,414 |
|
Less current portion |
|
| 46 |
|
|
| 44 |
|
Asset retirement obligations, long-term |
| $ | 1,226 |
|
| $ | 1,370 |
|
|
| Year Ended December 31, 2019 |
| |||||
|
| Finance |
|
| Operating |
| ||
Cash outflows for lease liabilities: |
|
|
|
|
|
|
|
|
Operating cash flows |
| $ | 7 |
|
| $ | 2 |
|
Investing cash flows |
| $ | — |
|
| $ | 41 |
|
Right-of-use assets obtained in exchange for new lease liabilities |
| $ | — |
|
| $ | 3 |
|
Weighted average remaining lease term (years) |
|
| 8.0 |
|
|
| 2.2 |
|
Weighted average discount rate |
|
| 4.2 | % |
|
| 3.2 | % |
During 2016, Devon reduced its asset retirement obligation by $287 million for those obligations that were assumed by purchasers of certain upstream U.S. assets.
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the qualified plans are based on the employees’ years of service and compensation and are funded from assets held in the plans’ trusts.
9580
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans’ benefits are based on the employees’ yearsfollowing table presents Devon’s maturity analysis as of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans’ benefit obligations. The total value of these trusts was $16 million and $22 million at December 31, 20162019 for leases expiring in each of the next 5 years and 2015, respectivelythereafter.
|
| Finance |
|
| Operating |
|
| Total (1) |
| |||
2020 |
| $ | 7 |
|
| $ | 10 |
|
| $ | 17 |
|
2021 |
|
| 7 |
|
|
| 1 |
|
|
| 8 |
|
2022 |
|
| 8 |
|
|
| 1 |
|
|
| 9 |
|
2023 |
|
| 8 |
|
|
| 1 |
|
|
| 9 |
|
2024 |
|
| 8 |
|
|
| 1 |
|
|
| 9 |
|
Thereafter |
|
| 297 |
|
|
| 1 |
|
|
| 298 |
|
Total lease payments |
|
| 335 |
|
|
| 15 |
|
|
| 350 |
|
Less: interest |
|
| (88 | ) |
|
| (1 | ) |
|
| (89 | ) |
Present value of lease liabilities |
| $ | 247 |
|
| $ | 14 |
|
| $ | 261 |
|
(1) | Under previous lease accounting standard, ASC 840, Devon’s lease obligations as of December 31, 2018 expiring in each of the next 5 years and thereafter were $61 million for 2019, $48 million for 2020, $18 million for 2021, $9 million for 2022, $8 million for 2023 and $33 million thereafter. |
Devon rents or subleases certain real estate to third parties. The following table presents Devon’s expected lease income as of December 31, 2019 for each of the next 5 years and is includedthereafter.
|
| Operating |
| |
|
| Lease Income |
| |
2020 |
| $ | 6 |
|
2021 |
|
| 6 |
|
2022 |
|
| 6 |
|
2023 |
|
| 7 |
|
2024 |
|
| 7 |
|
Thereafter |
|
| 44 |
|
Total |
| $ | 76 |
|
15. | Asset Retirement Obligations |
The following table presents the changes in other long-term assetsasset retirement obligations.
|
| Year Ended December 31, |
| |||||
|
| 2019 |
|
| 2018 |
| ||
Asset retirement obligations as of beginning of period |
| $ | 484 |
|
| $ | 492 |
|
Liabilities incurred |
|
| 20 |
|
|
| 30 |
|
Liabilities settled and divested |
|
| (66 | ) |
|
| (48 | ) |
Revision of estimated obligation |
|
| (61 | ) |
|
| (16 | ) |
Accretion expense on discounted obligation |
|
| 21 |
|
|
| 26 |
|
Asset retirement obligations as of end of period |
|
| 398 |
|
|
| 484 |
|
Less current portion |
|
| 18 |
|
|
| 16 |
|
Asset retirement obligations, long-term |
| $ | 380 |
|
| $ | 468 |
|
During 2019, Devon reduced its asset retirement obligations by $61 million, primarily due to changes in the accompanying consolidated balance sheets. For the remaining nonqualified plansfuture cost estimates and retirement dates for which trusts have not been established, benefits are funded from Devon’s available cashits oil and cash equivalents.
gas assets. During 2019, 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.reduced its asset
9681
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Benefit Obligations and Funded Status
The following table presents the funded statusretirement obligations by $42 million as a result of Devon’s 2019 divestitures. For additional information, see Note 2.
During 2018, Devon reduced its asset retirement obligations by $34 million as a result of Devon’s 2018 divestitures. For additional information, see Note 2.
16. | Retirement Plans |
Defined Contribution Plans
Devon sponsors defined contribution plans covering its employees. Such plans include its 401(k) plan and enhanced contribution plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by the U.S. government. Devon contributed $34 million, $40 million and $42 million to these plans in 2019, 2018 and 2017, respectively.
Defined Benefit Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified pensionplans covering eligible employees and postretirement benefit plans. The benefit obligation for pension plans representsformer employees meeting certain age and service requirements. Benefits under the projected benefit obligation, while the benefit obligation for the postretirementdefined benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differshave been closed to new employees; however, eligible employees continue to accrue benefits based upon years of service and compensation. Benefits are primarily funded from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans was $1.2 billion at December 31, 2016 and 2015. Devon’s benefit obligations and plan assets are measured each year as of December 31.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||
|
| 2016 |
|
| 2015 |
|
| 2016 |
|
| 2015 |
| ||||
|
| (Millions) |
| |||||||||||||
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| $ | 1,308 |
|
| $ | 1,377 |
|
| $ | 23 |
|
| $ | 24 |
|
Service cost |
|
| 15 |
|
|
| 33 |
|
|
| — |
|
|
| 1 |
|
Interest cost |
|
| 42 |
|
|
| 52 |
|
|
| 1 |
|
|
| 1 |
|
Actuarial loss (gain) |
|
| 63 |
|
|
| (68 | ) |
|
| (1 | ) |
|
| (2 | ) |
Plan amendments |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Plan curtailments |
|
| (31 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Plan settlements |
|
| (94 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Foreign exchange rate changes |
|
| 1 |
|
|
| (6 | ) |
|
| — |
|
|
| — |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
Benefits paid |
|
| (57 | ) |
|
| (80 | ) |
|
| (2 | ) |
|
| (4 | ) |
Benefit obligation at end of year |
|
| 1,249 |
|
|
| 1,308 |
|
|
| 21 |
|
|
| 23 |
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
| 1,059 |
|
|
| 1,149 |
|
|
| — |
|
|
| — |
|
Actual return on plan assets |
|
| 61 |
|
|
| (16 | ) |
|
| — |
|
|
| — |
|
Employer contributions |
|
| 16 |
|
|
| 11 |
|
|
| 2 |
|
|
| 2 |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
Plan settlements |
|
| (94 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Benefits paid |
|
| (57 | ) |
|
| (80 | ) |
|
| (2 | ) |
|
| (4 | ) |
Foreign exchange rate changes |
|
| — |
|
|
| (5 | ) |
|
| — |
|
|
| — |
|
Fair value of plan assets at end of year |
|
| 985 |
|
|
| 1,059 |
|
|
| — |
|
|
| — |
|
Funded status at end of year |
| $ | (264 | ) |
| $ | (249 | ) |
| $ | (21 | ) |
| $ | (23 | ) |
Amounts recognized in balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term assets |
| $ | 3 |
|
| $ | 2 |
|
| $ | — |
|
| $ | — |
|
Other current liabilities |
|
| (13 | ) |
|
| (12 | ) |
|
| (3 | ) |
|
| (3 | ) |
Other long-term liabilities |
|
| (254 | ) |
|
| (239 | ) |
|
| (18 | ) |
|
| (20 | ) |
Net amount |
| $ | (264 | ) |
| $ | (249 | ) |
| $ | (21 | ) |
| $ | (23 | ) |
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain) |
| $ | 285 |
|
| $ | 302 |
|
| $ | (11 | ) |
| $ | (11 | ) |
Prior service cost (credit) |
|
| 8 |
|
|
| 14 |
|
|
| (5 | ) |
|
| (6 | ) |
Total |
| $ | 293 |
|
| $ | 316 |
|
| $ | (16 | ) |
| $ | (17 | ) |
97
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $13 million and $11 million for 2016 and 2015, respectively, which were funded from the trusts established for the nonqualified plans.
Certain of Devon’s pension plans are unfunded and have a combined projected benefit obligation and accumulated benefit obligation of $234 million and $211 million, respectively, at December 31, 2016 and $244 million and $199 million, respectively, at December 31, 2015.
Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
| ||||||
|
| (Millions) |
| |||||||||||||||||||||
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 15 |
|
| $ | 33 |
|
| $ | 30 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 1 |
|
Interest cost |
|
| 42 |
|
|
| 52 |
|
|
| 55 |
|
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Expected return on plan assets |
|
| (55 | ) |
|
| (58 | ) |
|
| (54 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Curtailment and settlement expense |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial loss (gain) (1) |
|
| 25 |
|
|
| 20 |
|
|
| 18 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Recognition of prior service cost (1) |
|
| 3 |
|
|
| 4 |
|
|
| 4 |
|
|
| (1 | ) |
|
| (2 | ) |
|
| (2 | ) |
Total net periodic benefit cost (2) |
|
| 30 |
|
|
| 51 |
|
|
| 54 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss (gain) arising in current year |
|
| 26 |
|
|
| 5 |
|
|
| 57 |
|
|
| — |
|
|
| (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) |
|
| (43 | ) |
|
| (20 | ) |
|
| (19 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) |
|
| (9 | ) |
|
| (4 | ) |
|
| (4 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 2 |
|
Total other comprehensive loss (earnings) |
|
| (24 | ) |
|
| (19 | ) |
|
| 34 |
|
|
| 2 |
|
|
| 2 |
|
|
| 3 |
|
Total recognized |
| $ | 6 |
|
| $ | 32 |
|
| $ | 88 |
|
| $ | 1 |
|
| $ | 1 |
|
| $ | 2 |
|
|
|
|
|
|
|
The estimated net actuarial loss and prior service cost for our pension and postretirement benefits that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2017 are $18 million and $1 million, respectively.
98
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the weighted-average actuarial assumptions used to determine obligations and periodic costs.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
| ||||||
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
| 4.07% |
|
|
| 4.25% |
|
|
| 3.90% |
|
|
| 3.46% |
|
|
| 3.63% |
|
|
| 3.25% |
|
Rate of compensation increase |
|
| 4.49% |
|
|
| 4.49% |
|
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
| |||
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
| 4.39% |
|
|
| 3.90% |
|
|
| 4.80% |
|
|
| 3.63% |
|
|
| 3.25% |
|
|
| 3.65% |
|
Rate of compensation increase |
|
| 4.49% |
|
|
| 4.49% |
|
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
| |||
Expected return on plan assets |
|
| 5.20% |
|
|
| 5.22% |
|
|
| 5.42% |
|
| N/A |
|
| N/A |
|
| N/A |
|
Discount rate – Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.
At the end of 2015, Devon changed the approach used to measure service and interest costs for pension and other postretirement benefits. For 2015, Devon measured service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016, Devon elected to measure service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. Devon believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations nor the funded status of the plans. The change in the service and interest costs going forward is not expected to be significant. This change has been accounted for as a change in accounting estimate.
Rate of compensation increase – For measurement of the 2016 benefit obligation for the pension plans, a 4.49% compensation increase was assumed.
Expected return on plan assets – The expected rate of return on plan assets was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types. See the pension plan assets section below for more information on Devon’s target allocations.
Mortality rate assumptions – In 2014, the Society of Actuaries issued updated versions of its mortality tables and mortality improvement scale, reflecting the increasing life expectancies in the U.S. While not required to strictly adhere to this data, Devon utilized actuary-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.
Other assumptions – For measurement of the 2016 benefit obligation for the other postretirement medical plans, a 7.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. The rate was assumed to decrease annually to an ultimate rate of 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.
99
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon’s overall investment objective for its pension plans’ assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. Devon’s target allocations for its pension plan assets are 70% fixed income, 20% equity and 10% other.
The See the following tables present the fair values ofdiscussion for Devon’s pension assets by asset class.
|
| As of December 31, 2016 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
| Fair Value Measurements Using: |
| |||||||||
|
| Actual Allocation |
|
| Total |
|
| Level 1 Inputs |
|
| Level 2 Inputs |
|
| Level 3 Inputs |
| |||||
|
| (Millions) |
| |||||||||||||||||
Fixed-income securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury obligations |
|
| 35 | % |
| $ | 343 |
|
| $ | 68 |
|
| $ | 275 |
|
| $ | — |
|
Corporate bonds |
|
| 30 | % |
|
| 297 |
|
|
| 205 |
|
|
| 92 |
|
|
| — |
|
Other bonds |
|
| 4 | % |
|
| 38 |
|
|
| 38 |
|
|
| — |
|
|
| — |
|
Total fixed-income securities |
|
| 69 | % |
|
| 678 |
|
|
| 311 |
|
|
| 367 |
|
|
| — |
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Global (large, mid, small cap) |
|
| 17 | % |
|
| 171 |
|
|
| — |
|
|
| 171 |
|
|
| — |
|
Other securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedge fund and alternative investments |
|
| 11 | % |
|
| 112 |
|
|
| — |
|
|
| — |
|
|
| 112 |
|
Short-term investments |
|
| 3 | % |
|
| 24 |
|
|
| 8 |
|
|
| 16 |
|
|
| — |
|
Total other securities |
|
| 14 | % |
|
| 136 |
|
|
| 8 |
|
|
| 16 |
|
|
| 112 |
|
Total investments |
|
| 100 | % |
| $ | 985 |
|
| $ | 319 |
|
| $ | 554 |
|
| $ | 112 |
|
|
| As of December 31, 2015 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
| Fair Value Measurements Using: |
| |||||||||
|
| Actual Allocation |
|
| Total |
|
| Level 1 Inputs |
|
| Level 2 Inputs |
|
| Level 3 Inputs |
| |||||
|
| (Millions) |
| |||||||||||||||||
Fixed-income securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury obligations |
|
| 17 | % |
| $ | 179 |
|
| $ | 88 |
|
| $ | 91 |
|
| $ | — |
|
Corporate bonds |
|
| 48 | % |
|
| 507 |
|
|
| 371 |
|
|
| 136 |
|
|
| — |
|
Other bonds |
|
| 3 | % |
|
| 35 |
|
|
| 35 |
|
|
| — |
|
|
| — |
|
Total fixed-income securities |
|
| 68 | % |
|
| 721 |
|
|
| 494 |
|
|
| 227 |
|
|
| — |
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Global (large, mid, small cap) |
|
| 18 | % |
|
| 186 |
|
|
| — |
|
|
| 186 |
|
|
| — |
|
Other securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedge fund and alternative investments |
|
| 11 | % |
|
| 120 |
|
|
| — |
|
|
| — |
|
|
| 120 |
|
Short-term investments |
|
| 3 | % |
|
| 32 |
|
|
| 6 |
|
|
| 26 |
|
|
| — |
|
Total other securities |
|
| 14 | % |
|
| 152 |
|
|
| 6 |
|
|
| 26 |
|
|
| 120 |
|
Total investments |
|
| 100 | % |
| $ | 1,059 |
|
| $ | 500 |
|
| $ | 439 |
|
| $ | 120 |
|
100
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following methods and assumptions were used to estimate the fair values in the tables above.
Fixed-income securities – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Devon’s fixed income securities also includeprices and were $240 million and $193 million at December 31, 2019 and 2018, respectively. Also included are commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.managers and were $233 million and $291 million at December 31, 2019 and 2018, respectively.
Equity securities– Devon’s equity securities include a commingled global equity fundfunds that investsinvest in large, mid and small capitalization stocks across the world’s developed and emerging markets.markets and international large cap equity securities. These equity securities can be redeemedsold on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.managers and were $112 million and $77 million at December 31, 2019 and 2018, respectively.
Other securities – Devon’s other securities include cash and commingled, short-term investment funds. The short-termfunds and a hedge fund that invest both long and short term using a variety of investment funds’ securities can be redeemed on demand but are not actively traded.strategies. The fair valuesvalue of these Level 2 securities areis based upon the net asset values provided by investment managers.
Devon’s hedge fundmanagers and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategieswere $109 million and a hedge fund of funds that invests both long$124 million at December 31, 2019 and short using a variety of investment strategies. Devon’s hedge fund of funds is not actively traded, and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.
The following table presents a summary of the changes in Devon’s Level 3 plan assets (millions).2018, respectively.
December 31, 2014 |
| $ | 112 |
|
Purchases |
|
| 5 |
|
Investment returns |
|
| 3 |
|
December 31, 2015 |
|
| 120 |
|
Investments sold |
|
| (12 | ) |
Investment returns |
|
| 4 |
|
December 31, 2016 |
| $ | 112 |
|
10182
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Expected Cash FlowsDefined Postretirement Plans
Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.
Benefit Obligations and Funded Status
The following table below presents contributions expected to be made to Devon’s qualified plans, nonqualified planssummarizes the benefit obligations, assets, funded status and balance sheet impacts associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2019 and 2018.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||
|
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| $ | 916 |
|
| $ | 1,247 |
|
| $ | 17 |
|
| $ | 19 |
|
Service cost |
|
| 7 |
|
|
| 9 |
|
|
| — |
|
|
| — |
|
Interest cost |
|
| 32 |
|
|
| 38 |
|
|
| — |
|
|
| — |
|
Actuarial loss (gain) |
|
| 91 |
|
|
| (81 | ) |
|
| (3 | ) |
|
| (3 | ) |
Plan amendments |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Plan curtailments |
|
| (3 | ) |
|
| 2 |
|
|
| 1 |
|
|
| 2 |
|
Plan settlements |
|
| (75 | ) |
|
| (241 | ) |
|
| — |
|
|
| — |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Benefits paid |
|
| (47 | ) |
|
| (58 | ) |
|
| (3 | ) |
|
| (3 | ) |
Benefit obligation at end of year |
|
| 924 |
|
|
| 916 |
|
|
| 14 |
|
|
| 17 |
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
| 685 |
|
|
| 1,007 |
|
|
| — |
|
|
| — |
|
Actual return on plan assets |
|
| 118 |
|
|
| (36 | ) |
|
| — |
|
|
| — |
|
Employer contributions |
|
| 13 |
|
|
| 13 |
|
|
| 1 |
|
|
| 1 |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Plan settlements |
|
| (75 | ) |
|
| (241 | ) |
|
| — |
|
|
| — |
|
Benefits paid |
|
| (47 | ) |
|
| (58 | ) |
|
| (3 | ) |
|
| (3 | ) |
Fair value of plan assets at end of year |
|
| 694 |
|
|
| 685 |
|
|
| — |
|
|
| — |
|
Funded status at end of year |
| $ | (230 | ) |
| $ | (231 | ) |
| $ | (14 | ) |
| $ | (17 | ) |
Amounts recognized in balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
| $ | (13 | ) |
| $ | (13 | ) |
| $ | (2 | ) |
| $ | (3 | ) |
Other long-term liabilities |
|
| (217 | ) |
|
| (218 | ) |
|
| (12 | ) |
|
| (14 | ) |
Net amount |
| $ | (230 | ) |
| $ | (231 | ) |
| $ | (14 | ) |
| $ | (17 | ) |
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain) |
| $ | 183 |
|
| $ | 198 |
|
| $ | (12 | ) |
| $ | (11 | ) |
Prior service cost (credit) |
|
| 5 |
|
|
| 4 |
|
|
| (1 | ) |
|
| (2 | ) |
Total |
| $ | 188 |
|
| $ | 202 |
|
| $ | (13 | ) |
| $ | (13 | ) |
During the third quarter of 2018, Devon entered into a group annuity contract, under which a third party has permanently assumed certain of Devon’s defined benefit pension obligations. The purchase of this group annuity contract reduced Devon’s pension assets and liabilities and is the primary component of the $241 million of plan
83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
settlements within the preceding table. In connection with the group annuity contract transaction, Devon recorded a settlement expense of approximately $33 million, which was reclassified from other comprehensive earnings to other expense on the consolidated statements of comprehensive earnings in 2018.
Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2019 and December 31, 2018, as presented in the table below.
|
| December 31, |
| |||||
|
| 2019 |
|
| 2018 |
| ||
Projected benefit obligation |
| $ | 924 |
|
| $ | 916 |
|
Accumulated benefit obligation (1) |
| $ | 223 |
|
| $ | 900 |
|
Fair value of plan assets |
| $ | 694 |
|
| $ | 685 |
|
(1) | The accumulated benefit obligation as of December 31, 2019 included a qualified pension plan that contained $690 million of accumulated benefit obligation which was not in excess of plan assets. |
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
|
| 2019 |
|
| 2018 |
|
| 2017 |
| ||||||
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 7 |
|
| $ | 9 |
|
| $ | 15 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Interest cost |
|
| 32 |
|
|
| 38 |
|
|
| 41 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Expected return on plan assets |
|
| (38 | ) |
|
| (48 | ) |
|
| (54 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial loss (gain) (1) |
|
| 7 |
|
|
| 13 |
|
|
| 19 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Recognition of prior service cost (1) |
|
| 1 |
|
|
| 1 |
|
|
| 2 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Total net periodic benefit cost (2) |
|
| 9 |
|
|
| 13 |
|
|
| 23 |
|
|
| (2 | ) |
|
| (2 | ) |
|
| (2 | ) |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss (gain) arising in current year |
|
| 7 |
|
|
| 5 |
|
|
| (8 | ) |
|
| (2 | ) |
|
| (1 | ) |
|
| (1 | ) |
Prior service cost arising in current year |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) |
|
| (22 | ) |
|
| (59 | ) |
|
| (19 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) |
|
| (2 | ) |
|
| (2 | ) |
|
| (2 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Total other comprehensive loss (earnings) |
|
| (14 | ) |
|
| (56 | ) |
|
| (29 | ) |
|
| — |
|
|
| 1 |
|
|
| 1 |
|
Total recognized |
| $ | (5 | ) |
| $ | (43 | ) |
| $ | (6 | ) |
| $ | (2 | ) |
| $ | (1 | ) |
| $ | (1 | ) |
(1) | These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. |
(2) | The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated statements of comprehensive earnings. |
(3) | These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2019 and 2018. See Note 6 for further discussion. |
84
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assumptions
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2019 |
|
| 2018 |
|
| 2017 |
|
| 2019 |
|
| 2018 |
|
| 2017 |
| ||||||
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 3.14% |
|
| 4.09% |
|
| 3.51% |
|
| 2.81% |
|
| 4.01% |
|
| 3.25% |
| ||||||
Rate of compensation increase |
| 2.50% |
|
| 2.50% |
|
| 2.50% |
|
| N/A |
|
| N/A |
|
| N/A |
| ||||||
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate - service cost |
| 3.74% |
|
| 3.77% |
|
| 4.06% |
|
| 3.99% |
|
| 4.13% |
|
| 4.22% |
| ||||||
Discount rate - interest cost |
| 3.36% |
|
| 3.14% |
|
| 2.91% |
|
| 3.21% |
|
| 2.67% |
|
| 2.39% |
| ||||||
Rate of compensation increase |
| 2.50% |
|
| 2.50% |
|
| 4.50% |
|
| N/A |
|
| N/A |
|
| N/A |
| ||||||
Expected return on plan assets |
| 5.75% |
|
| 5.75% |
|
| 5.75% |
|
| N/A |
|
| N/A |
|
| N/A |
|
Discount Rate - Future pension and post-retirement obligations are discounted based on the rate at which obligations could be effectively settled, considering the timing of expected future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.
Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types.
Mortality rate – Devon utilized the Society of Actuaries produced mortality tables.
Other assumptions – For measurement of the 2019 benefit obligation for the other postretirement medical plans, a 7.1% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2020. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter.
Expected Cash Flows
Devon expects benefit plan payments to average approximately $56 million a year for the next five years and $278 million total for the five years thereafter. Of the benefits expectedthese payments to be paid in 2017, $132020, $16 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans, and the $3 million of postretirement benefits is expected to be funded from Devon’s available cash, cash equivalents and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||
|
| (Millions) |
| |||||
2017 |
| $ | 60 |
|
| $ | 3 |
|
2018 |
| $ | 61 |
|
| $ | 3 |
|
2019 |
| $ | 62 |
|
| $ | 3 |
|
2020 |
| $ | 64 |
|
| $ | 2 |
|
2021 |
| $ | 67 |
|
| $ | 2 |
|
2022 to 2026 |
| $ | 374 |
|
| $ | 7 |
|
Defined Contribution Plans
Independent of EnLink, Devon maintains defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. EnLink also maintains a 401(k) plan covering eligible employees. The following table presents expense related to these defined contribution plans.
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
401(k) and enhanced contribution plans |
| $ | 53 |
|
| $ | 63 |
|
| $ | 49 |
|
Canadian pension and savings plans |
|
| 11 |
|
|
| 16 |
|
|
| 20 |
|
Total |
| $ | 64 |
|
| $ | 79 |
|
| $ | 69 |
|
assets.
The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Common Stock IssuedShare Repurchase Program
In January 2016,
On March 7, 2018, Devon issued approximately 23announced a $1.0 billion share repurchase program. On June 6, 2018, Devon announced the expansion of this program to $4.0 billion. On February 19, 2019, Devon announced a further expansion to $5.0 billion with a December 31, 2019 expiration date. Of the $5.0 billion authorized amount, $4.8 billion was repurchased when the program expired on December 31, 2019. On December 17, 2019, Devon announced a new $1.0 billion share repurchase program with a December 31, 2020 expiration date. Under the new program, $800 million shares of common stock in conjunction with the STACK asset acquisition discussed in Note 2. 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$1.0 billion authorization is conditioned upon the offering were $1.5 billion.
In December 2015, Devon issued approximately 7 million shares of common stock as partclosing of the Powder River Basin asset acquisition discussed in Note 2. pending Barnett Shale divestiture.
10285
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The table below provides information regarding purchases of Devon’s common stock that were made during 2018 and 2019 (shares in thousands).
|
| Total Number of Shares Purchased |
|
| Dollar Value of Shares Purchased |
|
| Average Price Paid per Share |
| |||
First quarter 2018: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 2,561 |
|
| $ | 82 |
|
| $ | 32.19 |
|
Second quarter 2018: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 11,154 |
|
|
| 439 |
|
|
| 39.35 |
|
Third quarter 2018: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 16,492 |
|
|
| 712 |
|
|
| 43.13 |
|
ASR |
|
| 24,330 |
|
|
| 1,000 |
|
|
| 41.10 |
|
Total |
|
| 40,822 |
|
|
| 1,712 |
|
|
| 41.92 |
|
Fourth quarter 2018: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 23,612 |
|
|
| 745 |
|
|
| 31.57 |
|
First quarter 2019: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 36,141 |
|
|
| 1,024 |
|
|
| 28.33 |
|
Second quarter 2019: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 5,911 |
|
|
| 159 |
|
|
| 27.01 |
|
Third quarter 2019: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 22,137 |
|
|
| 550 |
|
|
| 24.80 |
|
Fourth quarter 2019: |
|
|
|
|
|
|
|
|
|
|
|
|
Open-Market |
|
| 4,436 |
|
|
| 94 |
|
|
| 21.32 |
|
Total inception-to-date |
|
| 146,774 |
|
| $ | 4,805 |
|
| $ | 32.74 |
|
Dividends
The table below summarizes the dividends Devon paid on its common stock.
| Amounts |
|
| Rate |
| ||
| (Millions) |
|
| (Per Share) |
| ||
Year Ended 2016: |
|
|
|
|
|
|
|
First quarter 2016 | $ | 125 |
|
| $ | 0.24 |
|
Second quarter 2016 |
| 33 |
|
| $ | 0.06 |
|
Third quarter 2016 |
| 32 |
|
| $ | 0.06 |
|
Fourth quarter 2016 |
| 31 |
|
| $ | 0.06 |
|
Total year-to-date | $ | 221 |
|
|
|
|
|
Year Ended 2015: |
|
|
|
|
|
|
|
First quarter 2015 | $ | 99 |
|
| $ | 0.24 |
|
Second quarter 2015 |
| 98 |
|
| $ | 0.24 |
|
Third quarter 2015 |
| 99 |
|
| $ | 0.24 |
|
Fourth quarter 2015 |
| 100 |
|
| $ | 0.24 |
|
Total year-to-date | $ | 396 |
|
|
|
|
|
Year Ended 2014: |
|
|
|
|
|
|
|
First quarter 2014 | $ | 90 |
|
| $ | 0.22 |
|
Second quarter 2014 |
| 99 |
|
| $ | 0.24 |
|
Third quarter 2014 |
| 98 |
|
| $ | 0.24 |
|
Fourth quarter 2014 |
| 99 |
|
| $ | 0.24 |
|
Total year-to-date | $ | 386 |
|
|
|
|
|
| Amounts |
|
| Rate Per Share |
| ||
Year Ended 2019: |
|
|
|
|
|
|
|
First quarter | $ | 34 |
|
| $ | 0.08 |
|
Second quarter |
| 37 |
|
| $ | 0.09 |
|
Third quarter |
| 35 |
|
| $ | 0.09 |
|
Fourth quarter |
| 34 |
|
| $ | 0.09 |
|
Total year-to-date | $ | 140 |
|
|
|
|
|
Year Ended 2018: |
|
|
|
|
|
|
|
First quarter | $ | 32 |
|
| $ | 0.06 |
|
Second quarter |
| 42 |
|
| $ | 0.08 |
|
Third quarter |
| 38 |
|
| $ | 0.08 |
|
Fourth quarter |
| 37 |
|
| $ | 0.08 |
|
Total year-to-date | $ | 149 |
|
|
|
|
|
Year Ended 2017: |
|
|
|
|
|
|
|
First quarter | $ | 32 |
|
| $ | 0.06 |
|
Second quarter |
| 33 |
|
| $ | 0.06 |
|
Third quarter |
| 30 |
|
| $ | 0.06 |
|
Fourth quarter |
| 32 |
|
| $ | 0.06 |
|
Total year-to-date | $ | 127 |
|
|
|
|
|
Subsidiary Equity Transactions
During the first quarter of 2016, EnLink issued common units in conjunction with the Tall Oak acquisition discussed in Note 2. Through its equity distribution agreements, EnLink has the ability to sell common units through an “at the market” equity offering program. During 2016, 2015 and 2014, EnLink issued and sold approximately 10.0 million, 1.3 million and 14.8 million common units through its at the market program and general public offerings, generating net proceeds of $167 million, $25 million and $410 million, respectively. Furthermore, in October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 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. As a result of these transactions and EnLink’s acquisition and dropdown activity discussed further in Note 2, the table below shows the ownership interest activity in the General Partner and EnLink since inception.
|
| EnLink |
|
| General Partner |
| ||||||||||||||
Ownership interest as of |
| Devon |
|
| Non-Devon Unitholders |
|
| General Partner |
|
| Devon |
|
| Non-Devon Unitholders |
| |||||
March 7, 2014 |
|
| 52% |
|
|
| 41% |
|
|
| 7% |
|
|
| 70% |
|
|
| 30% |
|
December 31, 2014 |
|
| 49% |
|
|
| 43% |
|
|
| 8% |
|
|
| 70% |
|
|
| 30% |
|
December 31, 2015 |
|
| 28% |
|
|
| 45% |
|
|
| 27% |
|
|
| 70% |
|
|
| 30% |
|
December 31, 2016 |
|
| 24% |
|
|
| 53% |
|
|
| 23% |
|
|
| 64% |
|
|
| 36% |
|
10386
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
DistributionsDevon raised its quarterly dividend by 12.5%, to $0.09 per share, beginning in the second quarter of 2019. In the second quarter of 2018, Devon increased the quarterly dividend rate by 33% from $0.06 to $0.08 per share. In February 2020, Devon announced a 22% increase to its quarterly dividend, to $0.11 per share, beginning in the second quarter of 2020.
Noncontrolling Interests
In conjunction withAs discussed in Note 1, the formationnoncontrolling interests’ share of CDM’s net earnings and the General Partnercontributions from the noncontrolling interests are presented as components of equity for 2019. The noncontrolling interests’ equity balances and activities for 2017 and 2018 are related to EnLink and the divestment of Devon’s aggregate ownership interests in 2014, Devon made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner, distributed $304 million, $254 million and $135 million to non-Devon unitholders during 2016, 2015 and 2014, respectively.
as further discussed in Note 18.
Barnett Shale
On December 17, 2019, Devon announced that it had entered into an agreement to sell its Barnett Shale assets to BKV for approximately $770 million, before purchase price adjustments. Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations upon the authorization to enter the agreement by Devon’s Board of Directors. As part of its assessment, Devon is effectively exiting its last natural gas focused asset and the transaction resulted in a material reduction to total assets, revenues, net earnings and total proved reserves. Estimated proved reserves associated with Devon’s Barnett Shale assets are approximately 45% of total U.S. proved reserves. As a result, Devon has classified the results of operations and cash flows related to its Barnett Shale assets, inclusive of Barnett properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas, as discontinued operations on its consolidated financial statements.In connection with the abandonment of certain gas processing contracts related to 2018 divestitures, Devon has restricted approximately $25 million to fund these obligations. Cash payments for the abandonment charges total approximately $2 million per quarter.
In connection with the announced sale of its Barnett Shale assets, Devon recognized a $748 million asset impairment related to these assets, primarily due to the difference between the net carrying value and the purchase price, net of estimated customary purchase price adjustments, and qualifies as a level 2 fair value measurement. Approximately $88 million of the U.S. reporting unit goodwill was allocated to the Barnett Shale assets. Additionally, Devon ceased depreciation for all plant, property and equipment classified as assets held for sale on the date the sales agreement was approved by the Board of Directors. This transaction is expected to close in the second quarter of 2020.
Canada
On May 29, 2019, Devon announced it had entered into an agreement to sell substantially all of its oil and gas assets and operations in Canada to Canadian Natural Resources Limited. Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations upon the authorization to enter the agreement by Devon’s Board of Directors. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire heavy oil and Canadian operations; 2) Devon’s Canadian operations is a separate reportable segment and is a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, revenues, net earnings and total proved reserves. As a result, Devon has classified the results of operations and cash flows related to its Canadian operations as discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation for all plant, property and equipment classified as assets held for sale on the date the sales agreement was approved by the Board of Directors.
87
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On June 27, 2019, Devon completed the sale of its Canadian business for $2.6 billion ($3.4 billion Canadian dollars), net of purchase price adjustments, and recognized a pre-tax gain of $223 million ($425 million net of tax, primarily due to a significant deferred tax benefit). Included within this gain is a $55 million adjustment to the gain in the fourth quarter of 2019 related to income taxes. Current (cash) income tax associated with the sale was approximately $150 million and is expected to be paid in early 2020. The disposition of substantially all of Devon’s Canadian oil and gas assets resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings to be included within the gain computation. The historical cumulative foreign currency translation portion of the gain is not taxable. As of December 31, 2019, $355 million of the Canadian cash balance is restricted for funding certain tax and other obligations related to the Canadian business and is classified as cash restricted for discontinued operations on the consolidated balance sheets.
In conjunction with the sale of Devon’s Canadian business, Devon recognized approximately $285 million of restructuring and asset impairment related charges. Canadian Natural Resources Limited has reimbursed Devon for approximately $50 million of these restructuring costs, under the terms of the disposition agreement. Along with certain tax obligations, these costs will be funded with the restricted cash described above. These charges consist of $154 million related to a firm transportation agreement abandonment and $57 million related to office lease abandonment and associated asset impairment charges. Cash payments for the abandonment charges total approximately $6 million per quarter. Additionally, there are $74 million of employee related costs, including approximately $40 million of noncash accelerated vesting of employee stock awards. As mentioned above, Canadian Natural Resources Limited reimbursed the Company for approximately $50 million of these costs pursuant to the disposition agreement and Devon funded the remaining employee related costs.
Prior to the second quarter of 2019, Devon’s Canadian business maintained a valuation allowance against certain capital loss carryforwards and net operating losses. As a result of the sale of substantially all of Devon’s Canadian oil and gas assets and operations and the lack of future forecasted income, all but approximately $22 million of the Canadian deferred tax assets have been offset with a valuation allowance. In the fourth quarter of 2019, Devon entered into an audit agreement with the Canada Revenue Agency. As a result of this agreement, income tax expense of $82 million is reflected in discontinued operations.
In July 2019, Devon utilized a portion of the sales proceeds to early retire $500 million of the 4.00% senior notes due July 15, 2021 and $1.0 billion of the 3.25% senior notes due May 15, 2022. Devon recognized a charge on the early retirement of these notes in the third quarter of 2019 consisting of $52 million in cash retirement costs and $6 million of noncash charges.
EnLink
On June 6, 2018, Devon announced that it had entered into an agreement to sell its aggregate ownership interests in EnLink and the General Partner for $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations. As a result, Devon classified the results of operations and cash flows related to EnLink and the General Partner as discontinued operations on its consolidated financial statements.
On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). Current (cash) income tax associated with the transaction was approximately $12 million. The vast majority of the tax effect relates to deferred tax expense offset by the valuation allowance adjustment.
88
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon has minimum volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant through early 2021.
Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation.
During 2019 and from the period of July 19, 2018 through December 31, 2018, Devon had net outflows of approximately $560 million and $380 million with EnLink, respectively, which primarily related to gathering and processing expenses. These net outflows represent gross cash amounts and not net working interest amounts.
The following table presents the amounts reported in the consolidated statements of comprehensive earnings as discontinued operations.
89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Year ended December 31, |
| Barnett Shale |
|
| Canada |
|
| EnLink |
|
| Total |
| ||||
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream revenues |
| $ | 486 |
|
| $ | 628 |
|
| $ | — |
|
| $ | 1,114 |
|
Marketing and midstream revenues |
|
| — |
|
|
| 38 |
|
|
| — |
|
|
| 38 |
|
Total revenues |
|
| 486 |
|
|
| 666 |
|
|
| — |
|
|
| 1,152 |
|
Production expenses |
|
| 306 |
|
|
| 293 |
|
|
| — |
|
|
| 599 |
|
Exploration expenses |
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| 13 |
|
Marketing and midstream expenses |
|
| — |
|
|
| 18 |
|
|
| — |
|
|
| 18 |
|
Depreciation, depletion and amortization |
|
| 77 |
|
|
| 128 |
|
|
| — |
|
|
| 205 |
|
Asset impairments |
|
| 748 |
|
|
| 37 |
|
|
| — |
|
|
| 785 |
|
Asset dispositions |
|
| 1 |
|
|
| (223 | ) |
|
| — |
|
|
| (222 | ) |
General and administrative expenses |
|
| — |
|
|
| 34 |
|
|
| — |
|
|
| 34 |
|
Financing costs, net |
|
| — |
|
|
| 87 |
|
|
| — |
|
|
| 87 |
|
Restructuring and transaction costs |
|
| — |
|
|
| 248 |
|
|
| — |
|
|
| 248 |
|
Other expenses |
|
| 11 |
|
|
| 6 |
|
|
| — |
|
|
| 17 |
|
Total expenses |
|
| 1,143 |
|
|
| 641 |
|
|
| — |
|
|
| 1,784 |
|
Earnings (loss) from discontinued operations before income taxes |
|
| (657 | ) |
|
| 25 |
|
|
| — |
|
|
| (632 | ) |
Income tax benefit |
|
| (142 | ) |
|
| (216 | ) |
|
| — |
|
|
| (358 | ) |
Net earnings (loss) from discontinued operations, net of tax |
| $ | (515 | ) |
| $ | 241 |
|
| $ | — |
|
| $ | (274 | ) |
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream revenues |
| $ | 777 |
|
| $ | 965 |
|
| $ | — |
|
| $ | 1,742 |
|
Marketing and midstream revenues |
|
| — |
|
|
| 95 |
|
|
| 3,567 |
|
|
| 3,662 |
|
Total revenues |
|
| 777 |
|
|
| 1,060 |
|
|
| 3,567 |
|
|
| 5,404 |
|
Production expenses |
|
| 467 |
|
|
| 605 |
|
|
| — |
|
|
| 1,072 |
|
Exploration expenses |
|
| — |
|
|
| 48 |
|
|
| — |
|
|
| 48 |
|
Marketing and midstream expenses |
|
| — |
|
|
| 42 |
|
|
| 2,912 |
|
|
| 2,954 |
|
Depreciation, depletion and amortization |
|
| 100 |
|
|
| 330 |
|
|
| 244 |
|
|
| 674 |
|
Asset dispositions |
|
| 14 |
|
|
| — |
|
|
| (2,607 | ) |
|
| (2,593 | ) |
General and administrative expenses |
|
| — |
|
|
| 76 |
|
|
| 65 |
|
|
| 141 |
|
Financing costs, net |
|
| — |
|
|
| 14 |
|
|
| 98 |
|
|
| 112 |
|
Restructuring and transaction costs |
|
| — |
|
|
| 17 |
|
|
| — |
|
|
| 17 |
|
Other expenses |
|
| (34 | ) |
|
| 182 |
|
|
| (8 | ) |
|
| 140 |
|
Total expenses |
|
| 547 |
|
|
| 1,314 |
|
|
| 704 |
|
|
| 2,565 |
|
Earnings (loss) from discontinued operations before income taxes |
|
| 230 |
|
|
| (254 | ) |
|
| 2,863 |
|
|
| 2,839 |
|
Income tax expense (benefit) |
|
| 50 |
|
|
| (124 | ) |
|
| 403 |
|
|
| 329 |
|
Net earnings (loss) from discontinued operations, net of tax |
|
| 180 |
|
|
| (130 | ) |
|
| 2,460 |
|
|
| 2,510 |
|
Net earnings attributable to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| 160 |
|
|
| 160 |
|
Net earnings (loss) from discontinued operations, attributable to Devon |
| $ | 180 |
|
| $ | (130 | ) |
| $ | 2,300 |
|
| $ | 2,350 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream revenues |
| $ | 825 |
|
| $ | 1,494 |
|
| $ | — |
|
| $ | 2,319 |
|
Marketing and midstream revenues |
|
| — |
|
|
| 58 |
|
|
| 5,071 |
|
|
| 5,129 |
|
Total revenues |
|
| 825 |
|
|
| 1,552 |
|
|
| 5,071 |
|
|
| 7,448 |
|
Production expenses |
|
| 440 |
|
|
| 591 |
|
|
| — |
|
|
| 1,031 |
|
Exploration expenses |
|
| — |
|
|
| 34 |
|
|
| — |
|
|
| 34 |
|
Marketing and midstream expenses |
|
| — |
|
|
| 60 |
|
|
| 4,111 |
|
|
| 4,171 |
|
Depreciation, depletion and amortization |
|
| 141 |
|
|
| 380 |
|
|
| 545 |
|
|
| 1,066 |
|
Asset impairments |
|
| — |
|
|
| — |
|
|
| 17 |
|
|
| 17 |
|
Asset dispositions |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| 2 |
|
General and administrative expenses |
|
| — |
|
|
| 92 |
|
|
| 128 |
|
|
| 220 |
|
Financing costs, net |
|
| — |
|
|
| (4 | ) |
|
| 181 |
|
|
| 177 |
|
Other expenses |
|
| 12 |
|
|
| (104 | ) |
|
| (34 | ) |
|
| (126 | ) |
Total expenses |
|
| 594 |
|
|
| 1,050 |
|
|
| 4,948 |
|
|
| 6,592 |
|
Earnings from discontinued operations before income taxes |
|
| 231 |
|
|
| 502 |
|
|
| 123 |
|
|
| 856 |
|
Income tax expense (benefit) |
|
| — |
|
|
| 8 |
|
|
| (197 | ) |
|
| (189 | ) |
Net earnings from discontinued operations, net of tax |
|
| 231 |
|
|
| 494 |
|
|
| 320 |
|
|
| 1,045 |
|
Net earnings attributable to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| 180 |
|
|
| 180 |
|
Net earnings from discontinued operations, attributable to Devon |
| $ | 231 |
|
| $ | 494 |
|
| $ | 140 |
|
| $ | 865 |
|
90
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the carrying amounts of the assets and liabilities associated with discontinued operations on the consolidated balance sheets. The U.S. Other amounts in the table below relate to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2.
|
| As of December 31, 2019 |
|
| As of December 31, 2018 |
| ||||||||||||||||||||||
|
| Barnett Shale (1) |
|
| Canada |
|
| Total |
|
| Barnett Shale |
|
| Canada |
|
| U.S. Other |
|
| Total |
| |||||||
Cash restricted for discontinued operations |
| $ | 25 |
|
| $ | 355 |
|
| $ | 380 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
| $ | 38 |
|
| $ | 1 |
|
| $ | 39 |
|
| $ | 44 |
|
| $ | 30 |
|
| $ | 7 |
|
| $ | 81 |
|
Other current assets |
|
| 5 |
|
|
| 2 |
|
|
| 7 |
|
|
| 4 |
|
|
| 56 |
|
|
| — |
|
|
| 60 |
|
Oil and gas property and equipment, based on successful efforts accounting, net |
|
| 751 |
|
|
| — |
|
|
| 751 |
|
|
| 1,552 |
|
|
| 3,829 |
|
|
| 190 |
|
|
| 5,571 |
|
Other property and equipment, net |
|
| 11 |
|
|
| — |
|
|
| 11 |
|
|
| 12 |
|
|
| 78 |
|
|
| — |
|
|
| 90 |
|
Goodwill |
|
| 88 |
|
|
| — |
|
|
| 88 |
|
|
| 88 |
|
|
| — |
|
|
| — |
|
|
| 88 |
|
Other long-term assets |
|
| — |
|
|
| 81 |
|
|
| 81 |
|
|
| — |
|
|
| 79 |
|
|
| — |
|
|
| 79 |
|
Total assets associated with discontinued operations |
| $ | 893 |
|
| $ | 84 |
|
| $ | 977 |
|
| $ | 1,700 |
|
| $ | 4,072 |
|
| $ | 197 |
|
| $ | 5,969 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 15 |
|
| $ | 4 |
|
| $ | 19 |
|
| $ | 32 |
|
| $ | 98 |
|
| $ | 3 |
|
| $ | 133 |
|
Revenues and royalties payable |
|
| 44 |
|
|
| 3 |
|
|
| 47 |
|
|
| 111 |
|
|
| 67 |
|
|
| — |
|
|
| 178 |
|
Other current liabilities |
|
| 19 |
|
|
| 233 |
|
|
| 252 |
|
|
| 11 |
|
|
| 104 |
|
|
| 19 |
|
|
| 134 |
|
Long-term debt (2) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,493 |
|
|
| — |
|
|
| 1,493 |
|
Asset retirement obligations |
|
| 141 |
|
|
| — |
|
|
| 141 |
|
|
| 139 |
|
|
| 424 |
|
|
| 47 |
|
|
| 610 |
|
Deferred income taxes |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 348 |
|
|
| — |
|
|
| 348 |
|
Other long-term liabilities |
|
| 16 |
|
|
| 169 |
|
|
| 185 |
|
|
| 30 |
|
|
| 20 |
|
|
| — |
|
|
| 50 |
|
Total liabilities associated with discontinued operations |
| $ | 235 |
|
| $ | 409 |
|
| $ | 644 |
|
| $ | 323 |
|
| $ | 2,554 |
|
| $ | 69 |
|
| $ | 2,946 |
|
(1) | Certain long-term assets and liabilities for the Barnett Shale were reclassified to respective current assets and liabilities as of December 31, 2019 with the announced sale of the Barnett Shale assets expected to close during the second quarter of 2020. |
(2) | Includes the $500 million 4.00% Senior Notes due July 15, 2021 and $1.0 billion 3.25% Senior Notes due May 15, 2022 that were retired early in July 2019 utilizing a portion of the proceeds from the sale of Devon’s Canadian business. |
19. | Commitments and Contingencies |
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. TheDevon 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
91
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
allegations typically asserted in these suits allegeare claims that the producers and related partiesDevon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
Environmental and Other Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.
Other MattersBeginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs’ 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 any wrongdoing and is vigorously defending against these claims.
Devon is involvedVarious municipalities and other governmental and private parties in other variousCalifornia have filed legal proceedings incidentalagainst certain oil and gas companies, including Devon, seeking relief to its business. However,abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctions against the production of all fossil fuels. Although Devon cannot predict the ultimate outcome of these matters,Devon believes these claims to Devon’s knowledge, there were no other material pending legal proceedingsbe baseless and intends to which Devon is a party or to which any of its property is subject.vigorously defend against the proceedings.
104
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2016.2019.
Year Ending December 31, |
| Purchase Obligations |
|
| Drilling and Facility Obligations |
|
| Operational Agreements |
|
| Office and Equipment Leases |
|
| EnLink Obligations |
|
| Drilling and Facility Obligations |
|
| Operational Agreements |
|
| Office and Equipment Leases |
| ||||||||
|
| (Millions) |
|
|
|
|
| |||||||||||||||||||||||||
2017 |
| $ | 609 |
|
| $ | 76 |
|
| $ | 1,145 |
|
| $ | 50 |
|
| $ | 50 |
| ||||||||||||
2018 |
|
| 649 |
|
|
| 66 |
|
|
| 1,134 |
|
|
| 85 |
|
|
| 51 |
| ||||||||||||
2019 |
|
| 762 |
|
|
| 67 |
|
|
| 627 |
|
|
| 83 |
|
|
| 33 |
| ||||||||||||
2020 |
|
| 748 |
|
|
| 57 |
|
|
| 457 |
|
|
| 59 |
|
|
| 18 |
|
| $ | 131 |
|
| $ | 320 |
|
| $ | 51 |
|
2021 |
|
| 181 |
|
|
| 37 |
|
|
| 285 |
|
|
| 39 |
|
|
| 17 |
|
|
| 31 |
|
|
| 223 |
|
|
| 41 |
|
2022 |
|
| 30 |
|
|
| 208 |
|
|
| 12 |
| ||||||||||||||||||||
2023 |
|
| 22 |
|
|
| 162 |
|
|
| 12 |
| ||||||||||||||||||||
2024 |
|
| 16 |
|
|
| 139 |
|
|
| 12 |
| ||||||||||||||||||||
Thereafter |
|
| — |
|
|
| 85 |
|
|
| 2,667 |
|
|
| 55 |
|
|
| 102 |
|
|
| 32 |
|
|
| 416 |
|
|
| 298 |
|
Total |
| $ | 2,949 |
|
| $ | 388 |
|
| $ | 6,315 |
|
| $ | 371 |
|
| $ | 271 |
|
| $ | 262 |
|
| $ | 1,468 |
|
| $ | 426 |
|
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.
92
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 included in G&A under operating leases, net of sublease income, was $78 million, $88 million and $64 million in 2016, 2015 and 2014, respectively.
105
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, cash restricted for discontinued operations, accounts receivable, other current receivables, accounts payable, other current payables, and accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at December 31, 20162019 and December 31, 2015.2018, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items and the pension plan assets is provided in Note 5, Note 12 and Note 16, respectively.table.
|
|
|
|
|
|
|
|
|
| Fair Value |
| |||||
|
|
|
|
|
|
|
|
|
| Measurements Using: |
| |||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
| ||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
| ||||
|
| (Millions) |
| |||||||||||||
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 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 1,871 |
|
| $ | 1,871 |
|
| $ | 1,471 |
|
| $ | 400 |
|
Commodity derivatives |
| $ | 35 |
|
| $ | 35 |
|
| $ | — |
|
| $ | 35 |
|
Commodity derivatives |
| $ | (18 | ) |
| $ | (18 | ) |
| $ | — |
|
| $ | (18 | ) |
Interest rate derivatives |
| $ | 2 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
|
Interest rate derivatives |
| $ | (22 | ) |
| $ | (22 | ) |
| $ | — |
|
| $ | (22 | ) |
Foreign currency derivatives |
| $ | 8 |
|
| $ | 8 |
|
| $ | — |
|
| $ | 8 |
|
Foreign currency derivatives |
| $ | (8 | ) |
| $ | (8 | ) |
| $ | — |
|
| $ | (8 | ) |
Debt |
| $ | (13,032 | ) |
| $ | (11,927 | ) |
| $ | — |
|
| $ | (11,927 | ) |
Capital lease obligations |
| $ | (17 | ) |
| $ | (16 | ) |
| $ | — |
|
| $ | (16 | ) |
|
|
|
|
|
|
|
|
|
| Fair Value Measurements Using: |
| |||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
| ||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
| ||||
December 31, 2019 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 702 |
|
| $ | 702 |
|
| $ | 702 |
|
| $ | — |
|
Commodity derivatives |
| $ | 50 |
|
| $ | 50 |
|
| $ | — |
|
| $ | 50 |
|
Commodity derivatives |
| $ | (31 | ) |
| $ | (31 | ) |
| $ | — |
|
| $ | (31 | ) |
Debt |
| $ | (4,294 | ) |
| $ | (5,376 | ) |
| $ | — |
|
| $ | (5,376 | ) |
December 31, 2018 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 1,505 |
|
| $ | 1,505 |
|
| $ | 1,405 |
|
| $ | 100 |
|
Commodity derivatives |
| $ | 674 |
|
| $ | 674 |
|
| $ | — |
|
| $ | 674 |
|
Commodity derivatives |
| $ | (33 | ) |
| $ | (33 | ) |
| $ | — |
|
| $ | (33 | ) |
Debt |
| $ | (4,454 | ) |
| $ | (4,494 | ) |
| $ | — |
|
| $ | (4,494 | ) |
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 1 Fair Value Measurements
Cash equivalents – Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. Theinvestments and the fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents – Amounts primarily consist primarily of commercial paper and Canadian agency and provincial securities investments. The fair value approximates the carrying value.
106
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commodity interest rate and foreign currency derivatives – The fair valuesvalue of commodity interest rate and foreign currency 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 actively trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. The fair values of commercial paper and credit facility balances are the carrying values.
Installment payment – The fair value of the EnLink installment payment as of December 31, 2016 was based on Level 2 inputs from third-party market quotations.
Capital lease obligations – The fair value was calculated using inputs from third-party banks.maturity.
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 in oil and gas exploration and production activities, and certain information regarding such activities for each segment is included in Note 22.
10793
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment.
|
| U.S. (1) |
|
| Canada |
|
| EnLink (1) |
|
| Eliminations |
|
| Total |
| |||||
|
| (Millions) |
| |||||||||||||||||
Year Ended December 31, 2016: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 5,722 |
|
| $ | 1,031 |
|
| $ | 3,551 |
|
| $ | — |
|
| $ | 10,304 |
|
Asset dispositions and other |
| $ | 1,367 |
|
| $ | 542 |
|
| $ | (16) |
|
| $ | — |
|
| $ | 1,893 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 701 |
|
| $ | (701 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 928 |
|
| $ | 360 |
|
| $ | 504 |
|
| $ | — |
|
| $ | 1,792 |
|
Asset impairments |
| $ | 2,809 |
|
| $ | 1,293 |
|
| $ | 873 |
|
| $ | — |
|
| $ | 4,975 |
|
Restructuring and transaction costs |
| $ | 242 |
|
| $ | 19 |
|
| $ | 6 |
|
| $ | — |
|
| $ | 267 |
|
Interest expense |
| $ | 624 |
|
| $ | 181 |
|
| $ | 190 |
|
| $ | (84 | ) |
| $ | 911 |
|
Loss before income taxes |
| $ | (2,051 | ) |
| $ | (942 | ) |
| $ | (884 | ) |
| $ | — |
|
| $ | (3,877 | ) |
Income tax benefit |
| $ | (8 | ) |
| $ | (165 | ) |
| $ | — |
|
| $ | — |
|
| $ | (173 | ) |
Net loss |
| $ | (2,043 | ) | �� | $ | (777 | ) |
| $ | (884 | ) |
| $ | — |
|
| $ | (3,704 | ) |
Net earnings (loss) attributable to noncontrolling interests |
| $ | 1 |
|
| $ | — |
|
| $ | (403 | ) |
| $ | — |
|
| $ | (402 | ) |
Net loss attributable to Devon |
| $ | (2,044 | ) |
| $ | (777 | ) |
| $ | (481 | ) |
| $ | — |
|
| $ | (3,302 | ) |
Property and equipment, net |
| $ | 7,358 |
|
| $ | 2,575 |
|
| $ | 6,257 |
|
| $ | — |
|
| $ | 16,190 |
|
Total assets |
| $ | 12,163 |
|
| $ | 3,536 |
|
| $ | 10,276 |
|
| $ | (62 | ) |
| $ | 25,913 |
|
Capital expenditures, including acquisitions |
| $ | 2,880 |
|
| $ | 229 |
|
| $ | 1,082 |
|
| $ | — |
|
| $ | 4,191 |
|
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 |
| $ | 2,220 |
|
| $ | 522 |
|
| $ | 387 |
|
| $ | — |
|
| $ | 3,129 |
|
Asset impairments |
| $ | 18,000 |
|
| $ | 1,257 |
|
| $ | 1,563 |
|
| $ | — |
|
| $ | 20,820 |
|
Restructuring and transaction costs |
| $ | 54 |
|
| $ | 24 |
|
| $ | — |
|
| $ | — |
|
| $ | 78 |
|
Interest expense |
| $ | 368 |
|
| $ | 94 |
|
| $ | 107 |
|
| $ | (46 | ) |
| $ | 523 |
|
Loss before income taxes |
| $ | (18,214 | ) |
| $ | (1,670 | ) |
| $ | (1,384 | ) |
| $ | — |
|
| $ | (21,268 | ) |
Income tax expense (benefit) |
| $ | (5,650 | ) |
| $ | (445 | ) |
| $ | 30 |
|
| $ | — |
|
| $ | (6,065 | ) |
Net loss |
| $ | (12,564 | ) |
| $ | (1,225 | ) |
| $ | (1,414 | ) |
| $ | — |
|
| $ | (15,203 | ) |
Net earnings (loss) attributable to noncontrolling interests |
| $ | 1 |
|
| $ | — |
|
| $ | (750 | ) |
| $ | — |
|
| $ | (749 | ) |
Net loss attributable to Devon |
| $ | (12,565 | ) |
| $ | (1,225 | ) |
| $ | (664 | ) |
| $ | — |
|
| $ | (14,454 | ) |
Property and equipment, net |
| $ | 8,811 |
|
| $ | 4,590 |
|
| $ | 5,667 |
|
| $ | — |
|
| $ | 19,068 |
|
Total assets |
| $ | 14,550 |
|
| $ | 5,457 |
|
| $ | 9,541 |
|
| $ | (97 | ) |
| $ | 29,451 |
|
Capital expenditures, including acquisitions |
| $ | 4,575 |
|
| $ | 680 |
|
| $ | 978 |
|
| $ | — |
|
| $ | 6,233 |
|
Year Ended December 31, 2014: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 14,854 |
|
| $ | 2,063 |
|
| $ | 2,649 |
|
| $ | — |
|
| $ | 19,566 |
|
Asset dispositions and other |
| $ | (5 | ) |
| $ | 1,077 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,072 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 859 |
|
| $ | (859 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 2,475 |
|
| $ | 560 |
|
| $ | 284 |
|
| $ | — |
|
| $ | 3,319 |
|
Asset impairments |
| $ | 12 |
|
| $ | 1,941 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,953 |
|
Restructuring and transaction costs |
| $ | — |
|
| $ | 46 |
|
| $ | — |
|
| $ | — |
|
| $ | 46 |
|
Interest expense |
| $ | 441 |
|
| $ | 85 |
|
| $ | 54 |
|
| $ | (44 | ) |
| $ | 536 |
|
Earnings (loss) before income taxes |
| $ | 4,390 |
|
| $ | (657 | ) |
| $ | 326 |
|
| $ | — |
|
| $ | 4,059 |
|
Income tax expense |
| $ | 1,797 |
|
| $ | 495 |
|
| $ | 76 |
|
| $ | — |
|
| $ | 2,368 |
|
Net earnings (loss) |
| $ | 2,593 |
|
| $ | (1,152 | ) |
| $ | 250 |
|
| $ | — |
|
| $ | 1,691 |
|
Net earnings attributable to noncontrolling interests |
| $ | 1 |
|
| $ | — |
|
| $ | 83 |
|
| $ | — |
|
| $ | 84 |
|
Net earnings (loss) attributable to Devon |
| $ | 2,592 |
|
| $ | (1,152 | ) |
| $ | 167 |
|
| $ | — |
|
| $ | 1,607 |
|
Property and equipment, net |
| $ | 24,463 |
|
| $ | 6,790 |
|
| $ | 5,043 |
|
| $ | — |
|
| $ | 36,296 |
|
Total assets |
| $ | 31,994 |
|
| $ | 8,509 |
|
| $ | 10,189 |
|
| $ | (124 | ) |
| $ | 50,568 |
|
Capital expenditures, including acquisitions |
| $ | 11,214 |
|
| $ | 1,344 |
|
| $ | 1,001 |
|
| $ | — |
|
| $ | 13,559 |
|
108
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. With the sale of substantially all of its Canadian assets and operations, all of Devon’s reserves are located within the U.S.
The supplemental information in the tables below exclude amounts for all periods presented related to Devon’s discontinued operations, which consist of Devon’s Canadian operations that were sold in 2019 and its Barnett Shale assets, inclusive of properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas, which is provided separately by country.expected to close in 2020. 612 MMBoe of estimated proved reserves and $940 million of discounted future net cash flows were excluded for 2019, which all related to Devon’s Barnett Shale assets. Amounts excluded for 2018 and 2017 consisted of 1,104 MMBoe and 1,365 MMBoe, respectively, of estimated proved reserves and $3,042 million and $5,383 million, respectively, of discounted future net cash flows, which related to both Devon’s Canadian operations and its Barnett Shale assets, inclusive of properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas. 410 MMBoe and $1,426 million of discounted future net cash flows related to Devon’s Canadian operations in 2018 were sold in the second quarter of 2019. For additional information on these discontinued operations, see Note 18.
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.
|
| Year Ended December 31, 2016 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Year Ended December 31, |
| ||||||||||||
|
| (Millions) |
|
| 2019 |
|
| 2018 |
|
| 2017 |
| ||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
| $ | 237 |
|
| $ | — |
|
| $ | 237 |
|
| $ | — |
|
| $ | 2 |
|
| $ | 1 |
|
Unproved properties |
|
| 1,356 |
|
|
| 2 |
|
|
| 1,358 |
|
|
| 35 |
|
|
| 70 |
|
|
| 50 |
|
Exploration costs |
|
| 345 |
|
|
| 49 |
|
|
| 394 |
|
|
| 312 |
|
|
| 679 |
|
|
| 591 |
|
Development costs |
|
| 1,034 |
|
|
| 109 |
|
|
| 1,143 |
|
|
| 1,499 |
|
|
| 1,505 |
|
|
| 1,046 |
|
Costs incurred |
| $ | 2,972 |
|
| $ | 160 |
|
| $ | 3,132 |
|
| $ | 1,846 |
|
| $ | 2,256 |
|
| $ | 1,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2015 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
|
| (Millions) |
| |||||||||||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Proved properties |
| $ | 193 |
|
| $ | 2 |
|
| $ | 195 |
| ||||||||||||
Unproved properties |
|
| 634 |
|
|
| 83 |
|
|
| 717 |
| ||||||||||||
Exploration costs |
|
| 478 |
|
|
| 109 |
|
|
| 587 |
| ||||||||||||
Development costs |
|
| 3,269 |
|
|
| 402 |
|
|
| 3,671 |
| ||||||||||||
Costs incurred |
| $ | 4,574 |
|
| $ | 596 |
|
| $ | 5,170 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2014 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
|
| (Millions) |
| |||||||||||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Proved properties |
| $ | 5,210 |
|
| $ | — |
|
| $ | 5,210 |
| ||||||||||||
Unproved properties |
|
| 1,176 |
|
|
| 1 |
|
|
| 1,177 |
| ||||||||||||
Exploration costs |
|
| 270 |
|
|
| 52 |
|
|
| 322 |
| ||||||||||||
Development costs |
|
| 4,400 |
|
|
| 1,063 |
|
|
| 5,463 |
| ||||||||||||
Costs incurred |
| $ | 11,056 |
|
| $ | 1,116 |
|
| $ | 12,172 |
|
Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.
109
94
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Pursuant to the full cost method of accounting, Devon capitalizes certain of its G&A that is related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $244 million, $372 million and $376 million in 2016, 2015 and 2014, respectively. Also, 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 $64 million, $54 million and $45 million in 2016, 2015 and 2014, respectively.
Capitalized Costs
The following tables reflect the aggregate capitalized costs related to oil and gas activities.
|
| December 31, 2016 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
|
| (Millions) |
| |||||||||
Proved properties |
| $ | 61,401 |
|
| $ | 14,247 |
|
| $ | 75,648 |
|
Unproved properties |
|
| 2,092 |
|
|
| 1,345 |
|
|
| 3,437 |
|
Total oil and gas properties |
|
| 63,493 |
|
|
| 15,592 |
|
|
| 79,085 |
|
Accumulated DD&A |
|
| (57,323 | ) |
|
| (13,107 | ) |
|
| (70,430 | ) |
Net capitalized costs |
| $ | 6,170 |
|
| $ | 2,485 |
|
| $ | 8,655 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| December 31, 2015 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
|
| (Millions) |
| |||||||||
Proved properties |
| $ | 64,443 |
|
| $ | 13,747 |
|
| $ | 78,190 |
|
Unproved properties |
|
| 1,352 |
|
|
| 1,232 |
|
|
| 2,584 |
|
Total oil and gas properties |
|
| 65,795 |
|
|
| 14,979 |
|
|
| 80,774 |
|
Accumulated DD&A |
|
| (58,312 | ) |
|
| (11,185 | ) |
|
| (69,497 | ) |
Net capitalized costs |
| $ | 7,483 |
|
| $ | 3,794 |
|
| $ | 11,277 |
|
The following table presents a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2016.
|
| Costs Incurred In |
| |||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| Prior to 2014 |
|
| Total |
| |||||
|
| (Millions) |
| |||||||||||||||||
Acquisition costs |
| $ | 1,176 |
|
| $ | 579 |
|
| $ | 246 |
|
| $ | 464 |
|
| $ | 2,465 |
|
Exploration costs |
|
| 107 |
|
|
| 134 |
|
|
| 89 |
|
|
| 206 |
|
|
| 536 |
|
Development costs |
|
| 12 |
|
|
| — |
|
|
| 23 |
|
|
| 150 |
|
|
| 185 |
|
Capitalized interest |
|
| 63 |
|
|
| 52 |
|
|
| 37 |
|
|
| 99 |
|
|
| 251 |
|
Total oil and gas properties not subject to amortization |
| $ | 1,358 |
|
| $ | 765 |
|
| $ | 395 |
|
| $ | 919 |
|
| $ | 3,437 |
|
Included in the $3.4 billion of oil and gas properties not subject to amortization are approximately $2.9 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada, the assets acquired in the STACK play during 2016 and the Powder River Basin assets acquired in 2015. Devon continues to assess its Pike development timeline with its 50% partner. Based on the development plans, Pike costs will begin to be included in the amortization computation when the first phase of this project is fully approved and Devon subsequently begins recognizing the associated proved reserves. Devon is
110
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
evaluating and plans to develop the newly acquired STACK and Powder River Basin properties over the next four to five years.
Results of Operations
The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including DD&A and after giving effect to permanent differences.
|
| December 31, 2016 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Year Ended December 31, |
| ||||||||||||
|
| (Millions) |
|
| 2019 |
|
| 2018 |
|
| 2017 |
| ||||||||||||
Oil, gas and NGL sales |
| $ | 3,198 |
|
| $ | 984 |
|
| $ | 4,182 |
|
| $ | 3,809 |
|
| $ | 4,085 |
|
| $ | 2,921 |
|
Lease operating expenses |
|
| (1,123 | ) |
|
| (459 | ) |
|
| (1,582 | ) | ||||||||||||
General and administrative expenses |
|
| (148 | ) |
|
| (20 | ) |
|
| (168 | ) | ||||||||||||
Production and property taxes |
|
| (200 | ) |
|
| (31 | ) |
|
| (231 | ) | ||||||||||||
Production expenses |
|
| (1,197 | ) |
|
| (1,153 | ) |
|
| (791 | ) | ||||||||||||
Exploration expenses |
|
| (58 | ) |
|
| (128 | ) |
|
| (346 | ) | ||||||||||||
Depreciation, depletion and amortization |
|
| (817 | ) |
|
| (326 | ) |
|
| (1,143 | ) |
|
| (1,398 | ) |
|
| (1,134 | ) |
|
| (908 | ) |
Gains on asset sales |
|
| 1,351 |
|
|
| — |
|
|
| 1,351 |
| ||||||||||||
Asset dispositions |
|
| 37 |
|
|
| 276 |
|
|
| 212 |
| ||||||||||||
Asset impairments |
|
| (2,809 | ) |
|
| (1,291 | ) |
|
| (4,100 | ) |
|
| — |
|
|
| (109 | ) |
|
| — |
|
Accretion of asset retirement obligations |
|
| (49 | ) |
|
| (25 | ) |
|
| (74 | ) |
|
| (21 | ) |
|
| (26 | ) |
|
| (27 | ) |
Income tax benefit |
|
| — |
|
|
| 245 |
|
|
| 245 |
| ||||||||||||
Income tax expense |
|
| (270 | ) |
|
| (416 | ) |
|
| — |
| ||||||||||||
Results of operations |
| $ | (597 | ) |
| $ | (923 | ) |
| $ | (1,520 | ) |
| $ | 902 |
|
| $ | 1,395 |
|
| $ | 1,061 |
|
Depreciation, depletion and amortization per Boe |
| $ | 4.68 |
|
| $ | 6.65 |
|
| $ | 5.11 |
|
| $ | 11.72 |
|
| $ | 10.51 |
|
| $ | 9.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| December 31, 2015 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
|
| (Millions) |
| |||||||||||||||||||||
Oil, gas and NGL sales |
| $ | 4,356 |
|
| $ | 1,026 |
|
| $ | 5,382 |
| ||||||||||||
Lease operating expenses |
|
| (1,551 | ) |
|
| (553 | ) |
|
| (2,104 | ) | ||||||||||||
General and administrative expenses |
|
| (196 | ) |
|
| (28 | ) |
|
| (224 | ) | ||||||||||||
Production and property taxes |
|
| (309 | ) |
|
| (33 | ) |
|
| (342 | ) | ||||||||||||
Depreciation, depletion and amortization |
|
| (2,107 | ) |
|
| (474 | ) |
|
| (2,581 | ) | ||||||||||||
Asset impairments |
|
| (17,992 | ) |
|
| (1,257 | ) |
|
| (19,249 | ) | ||||||||||||
Accretion of asset retirement obligations |
|
| (47 | ) |
|
| (27 | ) |
|
| (74 | ) | ||||||||||||
Income tax benefit |
|
| 5,547 |
|
|
| 314 |
|
|
| 5,861 |
| ||||||||||||
Results of operations |
| $ | (12,299 | ) |
| $ | (1,032 | ) |
| $ | (13,331 | ) | ||||||||||||
Depreciation, depletion and amortization per Boe |
| $ | 10.21 |
|
| $ | 11.30 |
|
| $ | 10.40 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
11195
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| December 31, 2014 |
| ||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
|
| (Millions) |
| |||||||||
Oil, gas and NGL sales |
| $ | 7,867 |
|
| $ | 2,043 |
|
| $ | 9,910 |
|
Lease operating expenses |
|
| (1,559 | ) |
|
| (773 | ) |
|
| (2,332 | ) |
General and administrative expenses |
|
| (153 | ) |
|
| (57 | ) |
|
| (210 | ) |
Production and property taxes |
|
| (466 | ) |
|
| (37 | ) |
|
| (503 | ) |
Depreciation, depletion and amortization |
|
| (2,365 | ) |
|
| (531 | ) |
|
| (2,896 | ) |
Gains on asset sales |
|
| — |
|
|
| 1,077 |
|
|
| 1,077 |
|
Accretion of asset retirement obligations |
|
| (49 | ) |
|
| (39 | ) |
|
| (88 | ) |
Income tax expense |
|
| (1,199 | ) |
|
| (568 | ) |
|
| (1,767 | ) |
Results of operations (1) |
| $ | 2,076 |
|
| $ | 1,115 |
|
| $ | 3,191 |
|
Depreciation, depletion and amortization per Boe |
| $ | 11.41 |
|
| $ | 13.80 |
|
| $ | 11.79 |
|
|
|
112
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following tables presenttable presents Devon’s estimated proved reserves by product by country.product.
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
|
| Oil (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Oil (MMBbls) |
|
| Gas (Bcf) |
|
| NGL (MMBbls) |
|
| Combined (MMBoe) |
| |||||||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 229 |
|
|
| 56 |
|
|
| 285 |
| ||||||||||||||||
December 31, 2016 |
|
| 191 |
|
|
| 1,613 |
|
|
| 200 |
|
|
| 660 |
| ||||||||||||
Revisions due to prices |
|
| 12 |
|
|
| 55 |
|
|
| 5 |
|
|
| 27 |
| ||||||||||||
Revisions other than price |
|
| 6 |
|
|
| (31 | ) |
|
| (15 | ) |
|
| (14 | ) | ||||||||||||
Extensions and discoveries |
|
| 90 |
|
|
| 371 |
|
|
| 63 |
|
|
| 215 |
| ||||||||||||
Production |
|
| (42 | ) |
|
| (189 | ) |
|
| (21 | ) |
|
| (95 | ) | ||||||||||||
Sale of reserves |
|
| (3 | ) |
|
| (9 | ) |
|
| (1 | ) |
|
| (6 | ) | ||||||||||||
December 31, 2017 |
|
| 254 |
|
|
| 1,810 |
|
|
| 231 |
|
|
| 787 |
| ||||||||||||
Revisions due to prices |
|
| 12 |
|
|
| 7 |
|
|
| 2 |
|
|
| 15 |
| ||||||||||||
Revisions other than price |
|
| (10 | ) |
|
| (102 | ) |
|
| (27 | ) |
|
| (53 | ) | ||||||||||||
Extensions and discoveries |
|
| 93 |
|
|
| 358 |
|
|
| 54 |
|
|
| 206 |
| ||||||||||||
Production |
|
| (47 | ) |
|
| (206 | ) |
|
| (26 | ) |
|
| (108 | ) | ||||||||||||
Sale of reserves |
|
| (6 | ) |
|
| (65 | ) |
|
| (7 | ) |
|
| (24 | ) | ||||||||||||
December 31, 2018 |
|
| 296 |
|
|
| 1,802 |
|
|
| 227 |
|
|
| 823 |
| ||||||||||||
Revisions due to prices |
|
| (1 | ) |
|
| — |
|
|
| (1 | ) |
|
| (7 | ) |
|
| (86 | ) |
|
| (6 | ) |
|
| (28 | ) |
Revisions other than price |
|
| (38 | ) |
|
| 1 |
|
|
| (37 | ) |
|
| (13 | ) |
|
| (50 | ) |
|
| (9 | ) |
|
| (31 | ) |
Extensions and discoveries |
|
| 94 |
|
|
| 5 |
|
|
| 99 |
|
|
| 76 |
|
|
| 269 |
|
|
| 39 |
|
|
| 160 |
|
Purchase of reserves |
|
| 132 |
|
|
| — |
|
|
| 132 |
|
|
| 3 |
|
|
| 7 |
|
|
| 1 |
|
|
| 6 |
|
Production |
|
| (48 | ) |
|
| (10 | ) |
|
| (58 | ) |
|
| (55 | ) |
|
| (219 | ) |
|
| (28 | ) |
|
| (119 | ) |
Sale of reserves |
|
| (17 | ) |
|
| (29 | ) |
|
| (46 | ) |
|
| (24 | ) |
|
| (102 | ) |
|
| (13 | ) |
|
| (54 | ) |
December 31, 2014 |
|
| 351 |
|
|
| 23 |
|
|
| 374 |
| ||||||||||||||||
Revisions due to prices |
|
| (53 | ) |
|
| 4 |
|
|
| (49 | ) | ||||||||||||||||
Revisions other than price |
|
| (52 | ) |
|
| 2 |
|
|
| (50 | ) | ||||||||||||||||
Extensions and discoveries |
|
| 51 |
|
|
| 3 |
|
|
| 54 |
| ||||||||||||||||
Purchase of reserves |
|
| 5 |
|
|
| — |
|
|
| 5 |
| ||||||||||||||||
Production |
|
| (60 | ) |
|
| (10 | ) |
|
| (70 | ) | ||||||||||||||||
December 31, 2015 |
|
| 242 |
|
|
| 22 |
|
|
| 264 |
| ||||||||||||||||
Revisions due to prices |
|
| (18 | ) |
|
| (2 | ) |
|
| (20 | ) | ||||||||||||||||
Revisions other than price |
|
| (2 | ) |
|
| 3 |
|
|
| 1 |
| ||||||||||||||||
Extensions and discoveries |
|
| 36 |
|
|
| 2 |
|
|
| 38 |
| ||||||||||||||||
Purchase of reserves |
|
| 8 |
|
|
| — |
|
|
| 8 |
| ||||||||||||||||
Production |
|
| (47 | ) |
|
| (8 | ) |
|
| (55 | ) | ||||||||||||||||
Sale of reserves |
|
| (25 | ) |
|
| — |
|
|
| (25 | ) | ||||||||||||||||
December 31, 2019 |
|
| 276 |
|
|
| 1,621 |
|
|
| 211 |
|
|
| 757 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
December 31, 2016 |
|
| 194 |
|
|
| 17 |
|
|
| 211 |
|
|
| 157 |
|
|
| 1,359 |
|
|
| 161 |
|
|
| 545 |
|
Proved developed reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
December 31, 2013 |
|
| 194 |
|
|
| 56 |
|
|
| 250 |
| ||||||||||||||||
December 31, 2014 |
|
| 255 |
|
|
| 23 |
|
|
| 278 |
| ||||||||||||||||
December 31, 2015 |
|
| 203 |
|
|
| 22 |
|
|
| 225 |
| ||||||||||||||||
December 31, 2017 |
|
| 175 |
|
|
| 1,455 |
|
|
| 168 |
|
|
| 585 |
| ||||||||||||
December 31, 2018 |
|
| 196 |
|
|
| 1,427 |
|
|
| 166 |
|
|
| 600 |
| ||||||||||||
December 31, 2019 |
|
| 198 |
|
|
| 1,344 |
|
|
| 167 |
|
|
| 589 |
| ||||||||||||
Proved developed-producing reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
December 31, 2016 |
|
| 160 |
|
|
| 17 |
|
|
| 177 |
|
|
| 141 |
|
|
| 1,267 |
|
|
| 148 |
|
|
| 500 |
|
Proved developed-producing reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
December 31, 2013 |
|
| 178 |
|
|
| 51 |
|
|
| 229 |
| ||||||||||||||||
December 31, 2014 |
|
| 224 |
|
|
| 19 |
|
|
| 243 |
| ||||||||||||||||
December 31, 2015 |
|
| 192 |
|
|
| 19 |
|
|
| 211 |
| ||||||||||||||||
December 31, 2017 |
|
| 163 |
|
|
| 1,384 |
|
|
| 160 |
|
|
| 554 |
| ||||||||||||
December 31, 2018 |
|
| 188 |
|
|
| 1,394 |
|
|
| 162 |
|
|
| 582 |
| ||||||||||||
December 31, 2019 |
|
| 191 |
|
|
| 1,327 |
|
|
| 165 |
|
|
| 578 |
| ||||||||||||
Proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
December 31, 2016 |
|
| 143 |
|
|
| 13 |
|
|
| 156 |
|
|
| 34 |
|
|
| 254 |
|
|
| 39 |
|
|
| 115 |
|
Proved undeveloped reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
December 31, 2013 |
|
| 35 |
|
|
| — |
|
|
| 35 |
| ||||||||||||||||
December 31, 2014 |
|
| 96 |
|
|
| — |
|
|
| 96 |
| ||||||||||||||||
December 31, 2015 |
|
| 39 |
|
|
| — |
|
|
| 39 |
| ||||||||||||||||
December 31, 2016 |
|
| 34 |
|
|
| — |
|
|
| 34 |
| ||||||||||||||||
December 31, 2017 |
|
| 79 |
|
|
| 355 |
|
|
| 63 |
|
|
| 202 |
| ||||||||||||
December 31, 2018 |
|
| 100 |
|
|
| 375 |
|
|
| 61 |
|
|
| 223 |
| ||||||||||||
December 31, 2019 |
|
| 78 |
|
|
| 277 |
|
|
| 44 |
|
|
| 168 |
|
113
(1) | Gas reserves are converted to Boe at the rate of 6 Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGL reserves are converted to Boe on a one-to-one basis with oil. The conversion rates are not necessarily indicative of the relationship of oil, natural gas and NGL prices. |
96
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Bitumen (MMBbls) |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| — |
|
|
| 552 |
|
|
| 552 |
|
Revisions due to prices |
|
| — |
|
|
| (37 | ) |
|
| (37 | ) |
Revisions other than price |
|
| — |
|
|
| 18 |
|
|
| 18 |
|
Extensions and discoveries |
|
| — |
|
|
| 8 |
|
|
| 8 |
|
Production |
|
| — |
|
|
| (20 | ) |
|
| (20 | ) |
December 31, 2014 |
|
| — |
|
|
| 521 |
|
|
| 521 |
|
Revisions due to prices |
|
| — |
|
|
| 103 |
|
|
| 103 |
|
Revisions other than price |
|
| — |
|
|
| (84 | ) |
|
| (84 | ) |
Extensions and discoveries |
|
| — |
|
|
| 11 |
|
|
| 11 |
|
Production |
|
| — |
|
|
| (31 | ) |
|
| (31 | ) |
December 31, 2015 |
|
| — |
|
|
| 520 |
|
|
| 520 |
|
Revisions due to prices |
|
| — |
|
|
| 23 |
|
|
| 23 |
|
Revisions other than price |
|
| — |
|
|
| (19 | ) |
|
| (19 | ) |
Production |
|
| — |
|
|
| (40 | ) |
|
| (40 | ) |
December 31, 2016 |
|
| — |
|
|
| 484 |
|
|
| 484 |
|
Proved developed reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| — |
|
|
| 111 |
|
|
| 111 |
|
December 31, 2014 |
|
| — |
|
|
| 137 |
|
|
| 137 |
|
December 31, 2015 |
|
| — |
|
|
| 219 |
|
|
| 219 |
|
December 31, 2016 |
|
| — |
|
|
| 190 |
|
|
| 190 |
|
Proved developed-producing reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| — |
|
|
| 111 |
|
|
| 111 |
|
December 31, 2014 |
|
| — |
|
|
| 137 |
|
|
| 137 |
|
December 31, 2015 |
|
| — |
|
|
| 219 |
|
|
| 219 |
|
December 31, 2016 |
|
| — |
|
|
| 190 |
|
|
| 190 |
|
Proved undeveloped reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| — |
|
|
| 441 |
|
|
| 441 |
|
December 31, 2014 |
|
| — |
|
|
| 384 |
|
|
| 384 |
|
December 31, 2015 |
|
| — |
|
|
| 301 |
|
|
| 301 |
|
December 31, 2016 |
|
| — |
|
|
| 294 |
|
|
| 294 |
|
114
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Gas (Bcf) |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 8,550 |
|
|
| 758 |
|
|
| 9,308 |
|
Revisions due to prices |
|
| 191 |
|
|
| 45 |
|
|
| 236 |
|
Revisions other than price |
|
| (299 | ) |
|
| 4 |
|
|
| (295 | ) |
Extensions and discoveries |
|
| 335 |
|
|
| 8 |
|
|
| 343 |
|
Purchase of reserves |
|
| 457 |
|
|
| — |
|
|
| 457 |
|
Production |
|
| (660 | ) |
|
| (41 | ) |
|
| (701 | ) |
Sale of reserves |
|
| (923 | ) |
|
| (738 | ) |
|
| (1,661 | ) |
December 31, 2014 |
|
| 7,651 |
|
|
| 36 |
|
|
| 7,687 |
|
Revisions due to prices |
|
| (1,412 | ) |
|
| (9 | ) |
|
| (1,421 | ) |
Revisions other than price |
|
| (3 | ) |
|
| (6 | ) |
|
| (9 | ) |
Extensions and discoveries |
|
| 171 |
|
|
| — |
|
|
| 171 |
|
Purchase of reserves |
|
| 17 |
|
|
| — |
|
|
| 17 |
|
Production |
|
| (579 | ) |
|
| (8 | ) |
|
| (587 | ) |
Sale of reserves |
|
| (37 | ) |
|
| — |
|
|
| (37 | ) |
December 31, 2015 |
|
| 5,808 |
|
|
| 13 |
|
|
| 5,821 |
|
Revisions due to prices |
|
| (103 | ) |
|
| — |
|
|
| (103 | ) |
Revisions other than price |
|
| 628 |
|
|
| 10 |
|
|
| 638 |
|
Extensions and discoveries |
|
| 280 |
|
|
| — |
|
|
| 280 |
|
Purchase of reserves |
|
| 33 |
|
|
| — |
|
|
| 33 |
|
Production |
|
| (510 | ) |
|
| (7 | ) |
|
| (517 | ) |
Sale of reserves |
|
| (521 | ) |
|
| — |
|
|
| (521 | ) |
December 31, 2016 |
|
| 5,615 |
|
|
| 16 |
|
|
| 5,631 |
|
Proved developed reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 7,707 |
|
|
| 752 |
|
|
| 8,459 |
|
December 31, 2014 |
|
| 6,948 |
|
|
| 36 |
|
|
| 6,984 |
|
December 31, 2015 |
|
| 5,694 |
|
|
| 13 |
|
|
| 5,707 |
|
December 31, 2016 |
|
| 5,361 |
|
|
| 16 |
|
|
| 5,377 |
|
Proved developed-producing reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 7,425 |
|
|
| 680 |
|
|
| 8,105 |
|
December 31, 2014 |
|
| 6,746 |
|
|
| 34 |
|
|
| 6,780 |
|
December 31, 2015 |
|
| 5,546 |
|
|
| 13 |
|
|
| 5,559 |
|
December 31, 2016 |
|
| 5,243 |
|
|
| 16 |
|
|
| 5,259 |
|
Proved undeveloped reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 843 |
|
|
| 6 |
|
|
| 849 |
|
December 31, 2014 |
|
| 703 |
|
|
| — |
|
|
| 703 |
|
December 31, 2015 |
|
| 114 |
|
|
| — |
|
|
| 114 |
|
December 31, 2016 |
|
| 254 |
|
|
| — |
|
|
| 254 |
|
115
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural Gas Liquids (MMBbls) |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 552 |
|
|
| 23 |
|
|
| 575 |
|
Revisions due to prices |
|
| 7 |
|
|
| 1 |
|
|
| 8 |
|
Revisions other than price |
|
| 2 |
|
|
| — |
|
|
| 2 |
|
Extensions and discoveries |
|
| 47 |
|
|
| — |
|
|
| 47 |
|
Purchase of reserves |
|
| 57 |
|
|
| — |
|
|
| 57 |
|
Production |
|
| (50 | ) |
|
| (1 | ) |
|
| (51 | ) |
Sale of reserves |
|
| (37 | ) |
|
| (23 | ) |
|
| (60 | ) |
December 31, 2014 |
|
| 578 |
|
|
| — |
|
|
| 578 |
|
Revisions due to prices |
|
| (119 | ) |
|
| — |
|
|
| (119 | ) |
Revisions other than price |
|
| (6 | ) |
|
| — |
|
|
| (6 | ) |
Extensions and discoveries |
|
| 24 |
|
|
| — |
|
|
| 24 |
|
Purchase of reserves |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Production |
|
| (50 | ) |
|
| — |
|
|
| (50 | ) |
December 31, 2015 |
|
| 428 |
|
|
| — |
|
|
| 428 |
|
Revisions due to prices |
|
| (13 | ) |
|
| — |
|
|
| (13 | ) |
Revisions other than price |
|
| 48 |
|
|
| — |
|
|
| 48 |
|
Extensions and discoveries |
|
| 42 |
|
|
| — |
|
|
| 42 |
|
Purchase of reserves |
|
| 7 |
|
|
| — |
|
|
| 7 |
|
Production |
|
| (42 | ) |
|
| — |
|
|
| (42 | ) |
Sale of reserves |
|
| (45 | ) |
|
| — |
|
|
| (45 | ) |
December 31, 2016 |
|
| 425 |
|
|
| — |
|
|
| 425 |
|
Proved developed reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 468 |
|
|
| 23 |
|
|
| 491 |
|
December 31, 2014 |
|
| 486 |
|
|
| — |
|
|
| 486 |
|
December 31, 2015 |
|
| 411 |
|
|
| — |
|
|
| 411 |
|
December 31, 2016 |
|
| 387 |
|
|
| — |
|
|
| 387 |
|
Proved developed-producing reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 442 |
|
|
| 21 |
|
|
| 463 |
|
December 31, 2014 |
|
| 467 |
|
|
| — |
|
|
| 467 |
|
December 31, 2015 |
|
| 393 |
|
|
| — |
|
|
| 393 |
|
December 31, 2016 |
|
| 370 |
|
|
| — |
|
|
| 370 |
|
Proved undeveloped reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 84 |
|
|
| — |
|
|
| 84 |
|
December 31, 2014 |
|
| 92 |
|
|
| — |
|
|
| 92 |
|
December 31, 2015 |
|
| 17 |
|
|
| — |
|
|
| 17 |
|
December 31, 2016 |
|
| 38 |
|
|
| — |
|
|
| 38 |
|
116
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (MMBoe) (1) |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 2,205 |
|
|
| 758 |
|
|
| 2,963 |
|
Revisions due to prices |
|
| 38 |
|
|
| (29 | ) |
|
| 9 |
|
Revisions other than price |
|
| (86 | ) |
|
| 21 |
|
|
| (65 | ) |
Extensions and discoveries |
|
| 197 |
|
|
| 14 |
|
|
| 211 |
|
Purchase of reserves |
|
| 265 |
|
|
| — |
|
|
| 265 |
|
Production |
|
| (207 | ) |
|
| (39 | ) |
|
| (246 | ) |
Sale of reserves |
|
| (207 | ) |
|
| (176 | ) |
|
| (383 | ) |
December 31, 2014 |
|
| 2,205 |
|
|
| 549 |
|
|
| 2,754 |
|
Revisions due to prices |
|
| (408 | ) |
|
| 106 |
|
|
| (302 | ) |
Revisions other than price |
|
| (59 | ) |
|
| (83 | ) |
|
| (142 | ) |
Extensions and discoveries |
|
| 104 |
|
|
| 14 |
|
|
| 118 |
|
Purchase of reserves |
|
| 9 |
|
|
| — |
|
|
| 9 |
|
Production |
|
| (206 | ) |
|
| (42 | ) |
|
| (248 | ) |
Sale of reserves |
|
| (7 | ) |
|
| — |
|
|
| (7 | ) |
December 31, 2015 |
|
| 1,638 |
|
|
| 544 |
|
|
| 2,182 |
|
Revisions due to prices |
|
| (48 | ) |
|
| 21 |
|
|
| (27 | ) |
Revisions other than price |
|
| 151 |
|
|
| (14 | ) |
|
| 137 |
|
Extensions and discoveries |
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
Purchase of reserves |
|
| 20 |
|
|
| — |
|
|
| 20 |
|
Production |
|
| (174 | ) |
|
| (49 | ) |
|
| (223 | ) |
Sale of reserves |
|
| (157 | ) |
|
| — |
|
|
| (157 | ) |
December 31, 2016 |
|
| 1,554 |
|
|
| 504 |
|
|
| 2,058 |
|
Proved developed reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 1,947 |
|
|
| 315 |
|
|
| 2,262 |
|
December 31, 2014 |
|
| 1,900 |
|
|
| 165 |
|
|
| 2,065 |
|
December 31, 2015 |
|
| 1,563 |
|
|
| 243 |
|
|
| 1,806 |
|
December 31, 2016 |
|
| 1,439 |
|
|
| 210 |
|
|
| 1,649 |
|
Proved developed-producing reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 1,857 |
|
|
| 297 |
|
|
| 2,154 |
|
December 31, 2014 |
|
| 1,815 |
|
|
| 162 |
|
|
| 1,977 |
|
December 31, 2015 |
|
| 1,509 |
|
|
| 240 |
|
|
| 1,749 |
|
December 31, 2016 |
|
| 1,386 |
|
|
| 207 |
|
|
| 1,593 |
|
Proved undeveloped reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 258 |
|
|
| 443 |
|
|
| 701 |
|
December 31, 2014 |
|
| 305 |
|
|
| 384 |
|
|
| 689 |
|
December 31, 2015 |
|
| 75 |
|
|
| 301 |
|
|
| 376 |
|
December 31, 2016 |
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
|
|
117
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the changes in Devon’s total proved undeveloped reserves during 20162019 (MMBoe).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved undeveloped reserves as of December 31, 2015 |
|
| 75 |
|
|
| 301 |
|
|
| 376 |
|
Extensions and discoveries |
|
| 78 |
|
|
| — |
|
|
| 78 |
|
Revisions due to prices |
|
| (8 | ) |
|
| 10 |
|
|
| 2 |
|
Revisions other than price |
|
| (1 | ) |
|
| (4 | ) |
|
| (5 | ) |
Sale of reserves |
|
| (1 | ) |
|
| — |
|
|
| (1 | ) |
Conversion to proved developed reserves |
|
| (28 | ) |
|
| (13 | ) |
|
| (41 | ) |
Proved undeveloped reserves as of December 31, 2016 |
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
U.S. | ||||
Proved undeveloped reserves as of December 31, 2018 | 223 | |||
Extensions and discoveries | 89 | |||
Revisions due to prices | — | |||
Revisions other than price | (20 | ) | ||
Sale of reserves | (17 | ) | ||
Conversion to proved developed reserves | (107 | ) | ||
Proved undeveloped reserves as of December 31, 2019 | 168 |
ProvedTotal proved undeveloped reserves increased 9%decreased 25% from 20152018 to 2016, and2019 with the year-end 20162019 balance represents 20%representing 22% of total proved reserves. DrillingOver 70% of the 89 MMBoe in extensions and discoveries were the result of Devon’s focus on drilling and development activities in the STACK and Delaware Basin. This continued development in the STACK, and Delaware Basin increased Devon’s proved undeveloped reserves by 78 MMBoe. Continued development of Devon’s Eagle Ford and Jackfish propertiesalso led to the conversion of 41107 MMBoe, or 11%,48% of the 20152018 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $586$918 million for 2016. 2019.
A significant amount of Devon’s proved undeveloped reserves at the end of 2016 related to its Jackfish operations. At December 31, 2016 and 2015, Devon’s Jackfish proved undeveloped reserves were 294 MMBoe and 301 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. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than 5 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 2029. At the end of 2016, approximately 199 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 119 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 decreased 2728 MMBoe and 302 MMBoe during 2016 and 2015, respectively,in 2019 primarily due to lower commodity pricesprice decreases in the trailing 12 month averages for oil, bitumengas and gas. The lower bitumen priceNGLs.
Reserves increased Canadian reserves15 MMBoe and 27 MMBoe primarily due to price increases in the declinetrailing 12 month averages for oil, gas and NGLs in royalties, which increases Devon’s after-royalty volumes.
In 2014, price revisions increased Devon’s total proved reserves less than 1% due to higher commodity prices. 2018 and 2017, respectively.
Revisions Other Than Price
Total revisions other than price in 20162019 and 2018 primarily related to Devon’s development programs evaluation of certain oil and dry gas regions, and NGLs, with the largest revisions being made in the Barnett ShaleSTACK.
Extensions and Discoveries
2019 – Of the 160 MMBoe of additions from extensions and discoveries, 77 MMBoe were in the Delaware Basin, 37 MMBoe were in the STACK, (Cana-Woodford Shale)28 MMBoe in the Powder River Basin and 18 MMBoe in Eagle Ford. In 2019, there were no additions related to infill drilling activities.
2018 – Approximately 85% of the additions were through focused efforts in the STACK (87 MMBoe) and the Delaware Basin (88 MMBoe). RevisionsThe remaining extensions were added throughout the remainder of Devon’s portfolio.
118The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling activities, primarily relating to the STACK.
2017 – Over 90% of the additions were through focused efforts in the STACK (120 MMBoe) and the Delaware Basin (79 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.
97
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish were primarily due to a refined reserves methodology that resulted in a reduced recovery factor. Revisions other than price in 2014 primarily related to Devon’s evaluation of certain dry gas regions, with the largest revisions being made in the Cana-Woodford Shale and Barnett Shale.
Extensions and Discoveries
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 20162017 extensions and discoveries included 7461 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 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.
2014 – Of the 211 MMBoe of extensions and discoveries, 70 MMBoe related to the Permian Basin, 54 MMBoe related to the Eagle Ford, 36 MMBoe related to the Barnett Shale, 14 MMBoe related to the Anadarko Basin, 8 MMBoe related to Jackfish and 14 MMBoe related to the Mississippian-Woodford Trend.
The 2014 extensions and discoveries included 5 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 4 MMBoe at the Permian Basin.
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.
2014 – Of the 265 MMBoe of reserves purchases, 246 MMBoe related to Devon’s GeoSouthern acquisition in the Eagle Ford.STACK.
Sale of Reserves
2016 – The 157 MMBoe of reserves sales related to Devon’sDuring 2019, 2018 and 2017, Devon had U.S. non-core upstream asset divestitures. For additional information on these divestitures, discussed further in see Note 2.2.
2015 – The 7 MMBoe of reserves sales related to Devon’s asset divestitures in the San Juan Basin.
2014 – The 383 MMBoe of reserves sales related to Devon’s asset divestitures in the U.S. and Canada.
119
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, 2016 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Year Ended December 31, |
| ||||||||||||
|
| (Millions) |
|
| 2019 |
|
| 2018 |
|
| 2017 |
| ||||||||||||
Future cash inflows |
| $ | 22,847 |
|
| $ | 9,672 |
|
| $ | 32,519 |
|
| $ | 20,750 |
|
| $ | 27,759 |
|
| $ | 20,845 |
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
| (2,784 | ) |
|
| (2,201 | ) |
|
| (4,985 | ) |
|
| (2,093 | ) |
|
| (2,957 | ) |
|
| (2,687 | ) |
Production |
|
| (14,484 | ) |
|
| (6,287 | ) |
|
| (20,771 | ) |
|
| (9,174 | ) |
|
| (10,991 | ) |
|
| (7,782 | ) |
Future income tax expense |
|
| — |
|
|
| (57 | ) |
|
| (57 | ) |
|
| (1,037 | ) |
|
| (2,036 | ) |
|
| — |
|
Future net cash flow |
|
| 5,579 |
|
|
| 1,127 |
|
|
| 6,706 |
|
|
| 8,446 |
|
|
| 11,775 |
|
|
| 10,376 |
|
10% discount to reflect timing of cash flows |
|
| (2,128 | ) |
|
| (380 | ) |
|
| (2,508 | ) |
|
| (3,048 | ) |
|
| (4,625 | ) |
|
| (4,422 | ) |
Standardized measure of discounted future net cash flows |
| $ | 3,451 |
|
| $ | 747 |
|
| $ | 4,198 |
|
| $ | 5,398 |
|
| $ | 7,150 |
|
| $ | 5,954 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2015 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
|
| (Millions) |
| |||||||||||||||||||||
Future cash inflows |
| $ | 27,398 |
|
| $ | 13,047 |
|
| $ | 40,445 |
| ||||||||||||
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Development |
|
| (3,306 | ) |
|
| (2,759 | ) |
|
| (6,065 | ) | ||||||||||||
Production |
|
| (17,251 | ) |
|
| (6,891 | ) |
|
| (24,142 | ) | ||||||||||||
Future income tax expense |
|
| — |
|
|
| (475 | ) |
|
| (475 | ) | ||||||||||||
Future net cash flow |
|
| 6,841 |
|
|
| 2,922 |
|
|
| 9,763 |
| ||||||||||||
10% discount to reflect timing of cash flows |
|
| (1,973 | ) |
|
| (1,102 | ) |
|
| (3,075 | ) | ||||||||||||
Standardized measure of discounted future net cash flows |
| $ | 4,868 |
|
| $ | 1,820 |
|
| $ | 6,688 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2014 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
|
| (Millions) |
| |||||||||||||||||||||
Future cash inflows |
| $ | 75,847 |
|
| $ | 31,371 |
|
| $ | 107,218 |
| ||||||||||||
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Development |
|
| (7,168 | ) |
|
| (3,619 | ) |
|
| (10,787 | ) | ||||||||||||
Production |
|
| (29,740 | ) |
|
| (14,232 | ) |
|
| (43,972 | ) | ||||||||||||
Future income tax expense |
|
| (11,021 | ) |
|
| (3,026 | ) |
|
| (14,047 | ) | ||||||||||||
Future net cash flow |
|
| 27,918 |
|
|
| 10,494 |
|
|
| 38,412 |
| ||||||||||||
10% discount to reflect timing of cash flows |
|
| (12,819 | ) |
|
| (5,119 | ) |
|
| (17,938 | ) | ||||||||||||
Standardized measure of discounted future net cash flows |
| $ | 15,099 |
|
| $ | 5,375 |
|
| $ | 20,474 |
|
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 20162019 estimates, Devon’s future realized prices were assumed to be $37.37$53.58 per Bbl of oil, $15.74 per Bbl of bitumen, $1.98$1.69 per Mcf of gas and $9.91$15.26 per Bbl of NGLs. Of the $5.0$2.1 billion of future development costs as of the end of 2016, $0.4 billion,2019, $0.8 billion, $0.5 billion and $0.5$0.2 billion are estimated to be spent in 2017, 20182020, 2021 and 2019,2022, respectively.
120
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Future development costs include not only development costs but also future asset retirement costs. Included as part of the $5.0$2.1 billion of future development costs are $1.3$0.4 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.
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
|
| Year Ended December 31, |
| |||||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| Year Ended December 31, |
| ||||||||||||
|
| (Millions) |
|
| 2019 |
|
| 2018 |
|
| 2017 |
| ||||||||||||
Beginning balance |
| $ | 6,688 |
|
| $ | 20,474 |
|
| $ | 15,741 |
|
| $ | 7,150 |
|
| $ | 5,954 |
|
| $ | 3,292 |
|
Net changes in prices and production costs |
|
| (2,128 | ) |
|
| (20,756 | ) |
|
| 2,561 |
|
|
| (2,323 | ) |
|
| 1,533 |
|
|
| 1,784 |
|
Oil, bitumen, gas and NGL sales, net of production costs |
|
| (2,163 | ) |
|
| (2,704 | ) |
|
| (6,865 | ) | ||||||||||||
Oil, gas and NGL sales, net of production costs |
|
| (2,612 | ) |
|
| (2,932 | ) |
|
| (2,130 | ) | ||||||||||||
Changes in estimated future development costs |
|
| 112 |
|
|
| 1,313 |
|
|
| (768 | ) |
|
| 303 |
|
|
| (273 | ) |
|
| (73 | ) |
Extensions and discoveries, net of future development costs |
|
| 660 |
|
|
| 1,129 |
|
|
| 4,836 |
|
|
| 1,690 |
|
|
| 2,944 |
|
|
| 2,398 |
|
Purchase of reserves |
|
| 222 |
|
|
| 95 |
|
|
| 6,422 |
|
|
| 43 |
|
|
| — |
|
|
| 2 |
|
Sales of reserves in place |
|
| (560 | ) |
|
| (79 | ) |
|
| (2,384 | ) |
|
| (481 | ) |
|
| (120 | ) |
|
| (3 | ) |
Revisions of quantity estimates |
|
| (32 | ) |
|
| (1,451 | ) |
|
| (746 | ) |
|
| (359 | ) |
|
| (152 | ) |
|
| (51 | ) |
Previously estimated development costs incurred during the period |
|
| 663 |
|
|
| 2,158 |
|
|
| 1,933 |
|
|
| 857 |
|
|
| 787 |
|
|
| 322 |
|
Accretion of discount |
|
| 403 |
|
|
| 567 |
|
|
| 1,746 |
|
|
| 506 |
|
|
| 648 |
|
|
| 445 |
|
Foreign exchange and other |
|
| 105 |
|
|
| (1,254 | ) |
|
| (107 | ) | ||||||||||||
Net change in income taxes |
|
| 228 |
|
|
| 7,196 |
|
|
| (1,895 | ) | ||||||||||||
Net change in income taxes and other |
|
| 624 |
|
|
| (1,239 | ) |
|
| (32 | ) | ||||||||||||
Ending balance |
| $ | 4,198 |
|
| $ | 6,688 |
|
| $ | 20,474 |
|
| $ | 5,398 |
|
| $ | 7,150 |
|
| $ | 5,954 |
|
98
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following tables present a summary of Devon’s unaudited interim results of operations.
|
| 2016 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||
Total revenues and other |
| $ | 2,126 |
|
| $ | 2,488 |
|
| $ | 4,233 |
|
| $ | 3,350 |
|
| $ | 12,197 |
|
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 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||
Total revenues and other |
| $ | 3,265 |
|
| $ | 3,393 |
|
| $ | 3,601 |
|
| $ | 2,886 |
|
| $ | 13,145 |
|
Loss before income taxes |
| $ | (5,624 | ) |
| $ | (4,479 | ) |
| $ | (5,623 | ) |
| $ | (5,542 | ) |
| $ | (21,268 | ) |
Net loss attributable to Devon |
| $ | (3,599 | ) |
| $ | (2,816 | ) |
| $ | (3,507 | ) |
| $ | (4,532 | ) |
| $ | (14,454 | ) |
Basic net loss per share attributable to Devon |
| $ | (8.88 | ) |
| $ | (6.94 | ) |
| $ | (8.64 | ) |
| $ | (11.12 | ) |
| $ | (35.55 | ) |
Diluted net loss per share attributable to Devon |
| $ | (8.88 | ) |
| $ | (6.94 | ) |
| $ | (8.64 | ) |
| $ | (11.12 | ) |
| $ | (35.55 | ) |
|
| 2019 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues (1) |
| $ | 1,079 |
|
| $ | 1,806 |
|
| $ | 1,746 |
|
| $ | 1,589 |
|
| $ | 6,220 |
|
Asset dispositions (2) |
| $ | (45 | ) |
| $ | (2 | ) |
| $ | (1 | ) |
| $ | — |
|
| $ | (48 | ) |
Earnings (loss) from continuing operations before income taxes |
| $ | (497 | ) |
| $ | 219 |
|
| $ | 190 |
|
| $ | (21 | ) |
| $ | (109 | ) |
Net earnings (loss) from continuing operations |
| $ | (378 | ) |
| $ | 151 |
|
| $ | 136 |
|
| $ | 12 |
|
| $ | (79 | ) |
Net earnings (loss) from discontinued operations, net of income tax expense (benefit) (4) |
| $ | 61 |
|
| $ | 344 |
|
| $ | (27 | ) |
| $ | (652 | ) |
| $ | (274 | ) |
Net earnings (loss) attributable to Devon |
| $ | (317 | ) |
| $ | 495 |
|
| $ | 109 |
|
| $ | (642 | ) |
| $ | (355 | ) |
Basic net earnings (loss) per share attributable to Devon |
| $ | (0.74 | ) |
| $ | 1.20 |
|
| $ | 0.27 |
|
| $ | (1.70 | ) |
| $ | (0.89 | ) |
Diluted net earnings (loss) per share attributable to Devon |
| $ | (0.74 | ) |
| $ | 1.19 |
|
| $ | 0.27 |
|
| $ | (1.70 | ) |
| $ | (0.89 | ) |
|
| 2018 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues (1) |
| $ | 1,665 |
|
| $ | 1,727 |
|
| $ | 1,974 |
|
| $ | 3,530 |
|
| $ | 8,896 |
|
Asset dispositions (2) |
| $ | (12 | ) |
| $ | (18 | ) |
| $ | (6 | ) |
| $ | (242 | ) |
| $ | (278 | ) |
Earnings (loss) from continuing operations before income taxes (3) |
| $ | (264 | ) |
| $ | (486 | ) |
| $ | (105 | ) |
| $ | 1,799 |
|
| $ | 944 |
|
Net earnings (loss) from continuing operations |
| $ | (261 | ) |
| $ | (499 | ) |
| $ | 96 |
|
| $ | 1,378 |
|
| $ | 714 |
|
Net earnings (loss) from discontinued operations, net of income tax expense (benefit) (4) |
| $ | 108 |
|
| $ | 163 |
|
| $ | 2,469 |
|
| $ | (230 | ) |
| $ | 2,510 |
|
Net earnings (loss) attributable to Devon |
| $ | (197 | ) |
| $ | (425 | ) |
| $ | 2,537 |
|
| $ | 1,149 |
|
| $ | 3,064 |
|
Basic net earnings (loss) per share attributable to Devon |
| $ | (0.38 | ) |
| $ | (0.83 | ) |
| $ | 5.17 |
|
| $ | 2.50 |
|
| $ | 6.14 |
|
Diluted net earnings (loss) per share attributable to Devon |
| $ | (0.38 | ) |
| $ | (0.83 | ) |
| $ | 5.14 |
|
| $ | 2.48 |
|
| $ | 6.10 |
|
(1) | Includes noncash commodity hedge valuation changes of approximately $600 million loss in the first quarter of 2019 and approximately $1.4 billion gain in the fourth quarter of 2018. |
(2) | Additional discussion regarding asset dispositions can be found in Note 2. |
(3) | Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5. |
(4) | 2019 includes a $748 million asset impairment recognized in connection with the announced sale of Devon’s Barnett Shale assets in the fourth quarter of 2019. In addition, 2019 includes a gain of $425 million (after-tax) on the sale of its Canadian business during 2019, and 2018 includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018. Additional discussion can be found in Note 18. |
121
99
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Net Earnings (Loss) Attributable to Devon
The 2016 quarterly results include asset impairments of $3.0 billion (or $6.40 per diluted share), $1.5 billion (or $2.89 per diluted share), $0.3 billion (or $0.61 per diluted share) and $0.1 billion (or $0.24 per diluted share) for the first quarter through the fourth quarter of 2016, respectively, as discussed in Note 5. Additionally, the 2016 quarterly results include gains from asset dispositions of approximately $1.4 billion (or $2.59 per diluted share) and $540 million (or $1.04 per diluted share) during the third and fourth quarter of 2016, respectively, as discussed in Note 2.
The 2015 quarterly results include asset impairments of $5.5 billion (or $13.46 per diluted share), $4.2 billion (or $10.27 per diluted share), $5.9 billion (or $14.41 per diluted share) and $5.3 billion (or $13.09 per diluted share) for the first quarter through the fourth quarter of 2015, respectively, as discussed in Note 5.
122
Item 9.Changes in and Disagreements with AccountantsAccountants on Accounting and Financial Disclosure
Not Applicable.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, 20162019 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 15, 2017,19, 2020, management concluded that its internal control over financial reporting was effective as of December 31, 2016.2019.
The effectiveness of our internal control over financial reporting as of December 31, 20162019 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, 2016,2019, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” of this report.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting during the fourth quarter of 20162019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Not Applicable.On February 18, 2020, we entered into indemnification agreements with each of our directors. Subject to various terms and conditions, the indemnification agreements provide for, among other things, (i) indemnification rights for the directors with respect to certain claims and liabilities to the fullest extent permitted by Delaware law, (ii) the right to advancement of expenses for the directors with respect to certain claims and liabilities, (iii) clarification for the processes used to determine whether a director is entitled to indemnification and (iv) the maintenance of directors and officers liability insurance coverage for the directors. The foregoing description of the indemnification agreements is not complete and is subject to and qualified in its entirety by reference to a form of the indemnification agreement, a copy of which is attached hereto as Exhibit 10.40 and the terms of which are incorporated herein by reference.
123100
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 Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2016.2019.
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 Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2016.2019.
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 Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2016.2019.
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 Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2016.2019.
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 Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2016.2019.
124
101
PART IV
Item 15.Exhibits and Financial Statement Schedules
(a) The following documents are filedincluded 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 |
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| |
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2.1 |
| Purchase Agreement, |
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2.2 |
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2.3 |
| Purchase and Sale Agreement, dated |
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3.1 |
| Registrant’s Restated Certificate of Incorporation |
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3.2 |
| Registrant’s Bylaws |
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4.1 |
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125
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| Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee |
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| 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 |
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| 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 |
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| |
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| 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 |
102
Exhibit No. | Description | |
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| 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 |
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| 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 |
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| 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 |
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| Supplemental Indenture No. |
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| Indenture, dated as of October 3, 2001, |
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| 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 |
126
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| 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 |
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| 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 |
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| 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 |
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| 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 |
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103
Exhibit No. | Description | |
10.1 | Credit Agreement, dated as of | |
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127
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10.3 |
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| Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) |
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| Devon Energy Corporation 2015 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666).** | |
10.5 | Devon Energy Corporation 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 7, 2017; File No. 333-218561).** | |
10.6 |
| 2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) |
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| Devon Energy Corporation |
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| Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective as of April 15, 2014) |
128
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| Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to Exhibit 10.13 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).** |
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| Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to Exhibit 10.10 to Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).** | |
10.12 |
| Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) |
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| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) |
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| Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).** |
104
Exhibit No. | Description | |
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| Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) |
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| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).** |
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10.19 | Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).** | |
10.20 | Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Defined Contribution Restoration Plan (as amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).** | |
10.21 |
| Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) |
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10.22 |
| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) |
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10.23 |
| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.23 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).** |
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10.24 | Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental Contribution Plan (as amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).** | |
10.25 |
| Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.25 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).** |
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| Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental Executive Retirement Plan (as amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).** | |
10.28 |
| Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) |
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| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).** |
129105
Exhibit No. |
| Description |
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| Amendment 2019-1, effective September 10, 2019, to the Devon Energy Corporation |
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| Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2018) (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 21, 2018; File No. 001-32318).** | |
10.33 |
| Amendment |
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| Amendment |
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10.35 |
| Amended and Restated Form of Employment Agreement between Registrant and certain executive officers |
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10.36 |
| Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant and certain executive officers |
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10.37 |
| Form of Employment Agreement between Registrant and certain executive officers |
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10.38 |
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10.39 |
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10.40 | Form of Indemnity Agreement between Registrant and non-management directors.** | |
10.41 |
| Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and David A. Hager for performance based restricted stock awarded |
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| Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted stock awarded |
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| 2017 Form of Notice of Grant of Performance |
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| 2018 Form of Notice of Grant of |
130
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106
Exhibit No. | Description | |
10.45 | 2019 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for restricted stock awarded | |
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| 2017 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded |
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| 2018 Form of Notice of Grant of |
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| 2019 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 executive officers for performance based restricted share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 1, 2019; File No. 001-32318).** | |
10.49 |
| Form of Notice of Grant of Nonqualified Stock Options and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for nonqualified stock options granted |
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131
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31.1 |
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31.2 |
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32.1 |
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32.2 |
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101.SCH |
| Inline XBRL Taxonomy Extension Schema Document. |
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101.CAL |
| Inline XBRL Taxonomy Extension Calculation Linkbase Document. |
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101.DEF |
| Inline XBRL Taxonomy Extension Definition Linkbase Document. |
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101.LAB |
| Inline XBRL Taxonomy Extension Labels Linkbase Document. |
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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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**Indicates management contract or compensatory plan or arrangement.
132Item 16.Form 10-K Summary
Not applicable.
107
SIGNATURES
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 |
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| By: | /s/ |
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| Executive Vice President and |
February 15, 201719, 2020
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/ DAVID A. HAGER |
| President, Chief Executive Officer and | February |
David A. Hager |
| Director (Principal executive officer) |
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/s/ |
| Executive Vice President | February |
|
| and Chief Financial Officer (Principal financial officer) |
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/s/ JEREMY D. HUMPHERS |
| Senior Vice President | February |
Jeremy D. Humphers |
| and Chief Accounting Officer (Principal accounting officer) |
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/s/ |
| Chairman of the Board | February |
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/s/ BARBARA M. BAUMANN |
| Director | February |
Barbara M. Baumann |
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/s/ JOHN E. BETHANCOURT |
| Director | February |
John E. Bethancourt | |||
/s/ ANN G. FOX | Director | February 19, 2020 | |
Ann G. Fox |
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/s/ ROBERT H. HENRY |
| Director | February |
Robert H. Henry |
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/s/ MICHAEL M. KANOVSKY |
| Director | February |
Michael M. Kanovsky | |||
/s/ JOHN KRENICKI JR. | Director | February 19, 2020 | |
John Krenicki Jr. |
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/s/ ROBERT A. MOSBACHER, JR. |
| Director | February |
Robert A. Mosbacher, Jr. |
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/s/ |
| Director | February |
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/s/ MARY P. RICCIARDELLO |
| Director | February |
Mary P. Ricciardello |
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133
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139
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| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
140
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
141