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, 20162018
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 |
| Name of each exchange on which registered |
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| Common stock, par value $0.10 per share |
| The New York Stock Exchange |
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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, 201629, 2018 was approximately $18.9$22.5 billion, based upon the closing price of $36.25$43.96 per share as reported by the New York Stock Exchange on such date. On February 8, 2017, 524.66, 2019, 438.3 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 2019 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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117 |
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.
“2012 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 24, 2012.
“2018 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 5, 2018.
“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.
“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” means Devon Canada Corporation Incentive Savings Plan.
“Coronado” means Coronado Midstream Holdings LLC.
“Crosstex” means Crosstex Energy, Inc. together with Crosstex Energy L.P.
“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.
3
“Mcf” means thousand cubic feet.
“MLP” means master limited partnership.
“MMBbls” means million barrels.
“MMBoe” means million Boe.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“N/M” means not meaningful.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“NYSE” means New York Stock Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“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.
“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.
“Upstream operations” means upstream revenues minus production expenses.
“U.S.” means United States of America.
“VEX” means Victoria Express Pipeline and related truck terminal and storage assets.
“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;
• | cyberattack risks; |
our limited control over third parties who operate some of our oil and gas properties;
• | our limited control over third parties who operate some of our oil and gas properties; |
midstream capacity constraints and potential interruptions in production;
• | midstream capacity constraints and potential interruptions in production; |
competition for leases, materials, people and capital;
• | the extent to which insurance covers any losses we may experience; |
cyberattacks targeting our systems and infrastructure; and
• | competition for assets, materials, people and capital; |
• | our ability to successfully complete mergers, acquisitions and divestitures; and |
any of the other risks and uncertainties discussed in this report.
• | 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. and Canada. Additionally,In July 2018, we control EnLink, a publicly–traded MLP with an integratedexited the midstream business with significant size and scale in key operating regions in the U.S. For additional information regardingby divesting our control of, andaggregate ownership interestinterests in EnLink and its indirect general partner, the General Partner, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.Partner.
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, 2016,2018, Devon and its consolidated subsidiaries had approximately 5,000 employees, of which approximately 1,500 employees are employed by EnLink (through its subsidiaries).2,900 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 reflectedwith three fundamental principles.
A premier, sustainable portfolio of assets – As discussed in the company’s investment grade credit ratings. We focus our business on building value per share by:
managingnext section of this Annual Report, we own 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 explorationassets located in the United States and productionAlberta, Canada. We strive to own premier 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 developmentcapable of generating cash flows in excess of our world-class operations in the STACKcapital and Delaware Basin. Theseoperating requirements, as well as competitive rates of return. We also desire to own a portfolio of assets that can provide us with a sustainable, multi-decadeproduction growth platform that continuesextending many years into the future. Because of the strength of oil prices relative to improvenatural gas, we have been positioning our portfolio to be more heavily weighted to U.S. oil assets in responserecent years.
During 2018, we made significant progress in our transition to a U.S. oil company. We sold our successful drilling programs. During 2016, we delivered the best well productivity in Devon’s 45-year historymidstream business 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 approximatelygenerating nearly $5 billion in liquidity proceeds. In February 2019, we announced our intent to separate our Canadian business and our Barnett Shale assets from the Company. After these separations, we expect our oil production growth, price realizations and field-level margins will all improve, as we sharpen our focus on four core U.S. oil plays located in the Delaware Basin, STACK, Eagle Ford and Rockies.
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 2018, we continued to achieve efficiency gains in various aspects of our business. Our initial production rates from new wells continued to improve in our four core 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 cost reduction initiatives, driving down breakeven costs across our portfolio of assets.
As we enter 2017focus on a more streamlined portfolio of U.S. oil assets, we are aggressively pursuing an improved cost structure with $780 million of annual costs savings expected by 2021. We expect to realize about 70% of the annualized savings by the end of 2019. Our retained U.S. oil business is expected to realize $300 million of annual well cost savings by 2021, as we increase our focus on development drilling, reduce our facility costs and continue to look towardoptimize well spacing in the future,STACK. Additionally, we will approach the current environmentstreamline and align our workforce with our go-forward business, which should result in a manner that drives efficiencies across our portfolio. We will manage activity levels within our cash flow by achieving additional operating$300 million of annual cost savings by the end of the three-year period. As we continue deleveraging, we expect to reduce annual interest costs by $130 million. Finally, we have plans to reduce our annual production expenses by $50 million over the next three years.
Financial strength and increasing capital productivity, while remaining committedflexibility – Commodity prices are uncertain and volatile, so we strive 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 upstream oil and natural gas producers, including Devon.
EnLink connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. Furthermore, EnLink purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines.
EnLink’s primary business objective is to provide cash flow stability, while growing through prudent and profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintainingmaintain a strong balance sheet, as well as adequate liquidity and financial position through a conservativeflexibility, 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 balanced capital structure highlighted by its investment grade status. EnLink has consistently demonstrated expertise within the MLP spacepaying 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. our shareholder dividend.
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During 2018, we reduced our consolidated debt by 40%, primarily from our divestitures. We also raised our quarterly dividend 33% and began a $4 billion share repurchase program. As we dispose of our Canadian and Barnett Shale assets in 2019, we expect to use the proceeds to reduce debt further and repurchase additional common shares. As a result of our planned dispositions, our Board of Directors has increased our share repurchase program to $5 billion in February 2019 and raised our quarterly dividend 12.5% to $0.09 per share.
Oil and Gas Properties
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. 2018 are detailed in the map below. Notes 2122 and 2223 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain additional information on our segments and geographical areas.
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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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7
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Led by results from the STACK, Index to Financial Statements
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 franchisetop assets and continues to offer exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, Delaware, Wolfcamp and Leonard formations. TheseWe expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin will offerto deliver high-margin growth for many years to come. During 2018, our continued appraisal and development work enabled us to increase our proved reserves in this area by approximately 24%. At December 31, 2016,2018, we had three10 operated rigs.rigs developing this asset. In 2017,2019, we plan to invest approximately $700$900 million of capital in the Delaware Basin, making it the top-funded asset in the portfolio.
STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and steadily ramp up activity with as many as 10Blaine counties, is one of Devon’s top assets. Our STACK position is one of the largest in the industry, providing visible long-term stable production. At December 31, 2018, we had five operated rigs running bywith drilling focused in the endMeramec formation. In 2019, we plan approximately $400 million of capital investment. The STACK is Devon’s second highest funded asset in the year, primarily focused on the Bone Spring, Leonard and Wolfcamp formations.portfolio for 2019.
Eagle Ford – We acquired our position in the Eagle Ford in 2014 from GeoSouthern and have approximately 66,000 net acres located in DeWitt and Lavaca counties in south Texas.2014. Since acquiring these assets, we have delivered tremendous results by producing 94173 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, ourOur Eagle Ford assets generated approximately $550 million of directsignificant cash marginflow in 2016.2018. In 2017,2019, we plan approximately $175$300 million of capital investment.
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TableRockies Oil – Our acreage in the Rockies is focused on emerging oil opportunities in the Powder River Basin. Recent drilling success in this basin has expanded our drilling inventory, and we expect further growth as we accelerate activity and continue to de-risk this emerging light-oil opportunity. As of ContentsDecember 31, 2018, we had two operated rigs targeting the Turner, Parkman, Teapot and Niobrara formations in northern Converse County of the Powder River Basin. In 2019, we plan approximately $300 million of capital investment and adding two additional operated rigs.
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 2015 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. With2018. Currently, we have minimal planned capital outlays for Pike in the near future. The majority of our 50% partner, we continue to evaluate our development timeline for Pike.Pike leasehold does not expire until 2025 and 2026.
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 2017,2019, we plan approximately $300 millionto separate our operations in Canada.
Barnett Shale – This is our largest property in terms of capital investmentproved reserves. Our leases are located primarily in our Canadian Heavy Oil business.
Rockies Oil – Our acreageDenton, Parker, Tarrant and Wise counties in the Rockies includes approximately 470,000 net surface acres, focused on emerging oil opportunitiesnorth Texas. Since acquiring a substantial position in the Powder River Basin and the Wind River Basin. Recent drilling successthis field in these formations has expanded our drilling inventory, and we expect further growth as2002, we continue to de-riskintroduce technology and new innovations to optimize production operations and have transformed 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.
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. Our STACK position is the largest andasset into one of the besttop producing gas fields in the industry, providing visible long-term growth. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Early drilling activity in the Meramec play has produced record setting results across our core position in the oil and liquids window. At December 31, 2016, we had six operated rigs with drilling focused in the Meramec formation.North America. In 2017,2019, we plan approximately $750 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.separate our Barnett Shale assets.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 2223 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.
8
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the 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 to and is managed through our finance department. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.
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 1618 years, including the past nine11 in his current position. His further professional qualifications include a degree in petroleum engineering, 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 auditsreviews of each operating division’scountry’s reserves. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2016,2018, we engaged two such firms to audit approximately 89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited 86%approximately 87% of our 2016 U.S. reserves, and Deloitte LLP audited 96%approximately 97% of our Canadian reserves.
In addition to conducting these internal reviews and external reserves audits, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process. The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies and meets at least once a year separately with our senior reserves engineering personnel and separately with our third-party petroleum consultants.
The following tables present production, price and cost information for each significant field, country and continent.
|
| Production |
|
| Production |
| ||||||||||||||||||||||||||||||||||
Year Ended December 31, |
| Oil (MMBbls) |
|
| Bitumen (MMBbls) |
|
| Gas (Bcf) |
|
| NGLs (MMBbls) |
|
| Total (MMBoe) |
|
| Oil (MMBbls) |
|
| Bitumen (MMBbls) |
|
| Gas (Bcf) |
|
| NGLs (MMBbls) |
|
| Total (MMBoe) |
| ||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 265 |
|
|
| 15 |
|
|
| 60 |
|
|
| — |
|
|
| — |
|
|
| 186 |
|
|
| 12 |
|
|
| 43 |
|
STACK |
|
| 12 |
|
|
| — |
|
|
| 121 |
|
|
| 14 |
|
|
| 45 |
| ||||||||||||||||||||
Jackfish |
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| 35 |
|
|
| — |
|
|
| — |
|
|
| 35 |
|
U.S. |
|
| 47 |
|
|
| — |
|
|
| 510 |
|
|
| 42 |
|
|
| 174 |
|
|
| 47 |
|
|
| — |
|
|
| 397 |
|
|
| 39 |
|
|
| 153 |
|
Canada |
|
| 8 |
|
|
| 40 |
|
|
| 7 |
|
|
| — |
|
|
| 49 |
|
|
| 7 |
|
|
| 35 |
|
|
| 4 |
|
|
| — |
|
|
| 42 |
|
Total North America |
|
| 55 |
|
|
| 40 |
|
|
| 517 |
|
|
| 42 |
|
|
| 223 |
|
|
| 54 |
|
|
| 35 |
|
|
| 401 |
|
|
| 39 |
|
|
| 195 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 291 |
|
|
| 17 |
|
|
| 66 |
|
|
| — |
|
|
| — |
|
|
| 237 |
|
|
| 14 |
|
|
| 54 |
|
STACK |
|
| 9 |
|
|
| — |
|
|
| 107 |
|
|
| 11 |
|
|
| 38 |
| ||||||||||||||||||||
Jackfish |
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
U.S. |
|
| 60 |
|
|
| — |
|
|
| 579 |
|
|
| 50 |
|
|
| 206 |
|
|
| 42 |
|
|
| — |
|
|
| 433 |
|
|
| 36 |
|
|
| 150 |
|
Canada |
|
| 10 |
|
|
| 31 |
|
|
| 8 |
|
|
| — |
|
|
| 42 |
|
|
| 7 |
|
|
| 40 |
|
|
| 6 |
|
|
| — |
|
|
| 48 |
|
Total North America |
|
| 70 |
|
|
| 31 |
|
|
| 587 |
|
|
| 50 |
|
|
| 248 |
|
|
| 49 |
|
|
| 40 |
|
|
| 439 |
|
|
| 36 |
|
|
| 198 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
|
| 1 |
|
|
| — |
|
|
| 332 |
|
|
| 20 |
|
|
| 76 |
|
|
| — |
|
|
| — |
|
|
| 265 |
|
|
| 15 |
|
|
| 60 |
|
STACK |
|
| 7 |
|
|
| — |
|
|
| 103 |
|
|
| 9 |
|
|
| 33 |
| ||||||||||||||||||||
Jackfish |
|
| — |
|
|
| 20 |
|
|
| — |
|
|
| — |
|
|
| 20 |
|
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
U.S. |
|
| 48 |
|
|
| — |
|
|
| 660 |
|
|
| 50 |
|
|
| 207 |
|
|
| 47 |
|
|
| — |
|
|
| 510 |
|
|
| 42 |
|
|
| 174 |
|
Canada |
|
| 10 |
|
|
| 20 |
|
|
| 41 |
|
|
| 1 |
|
|
| 39 |
|
|
| 8 |
|
|
| 40 |
|
|
| 7 |
|
|
| — |
|
|
| 49 |
|
Total North America |
|
| 58 |
|
|
| 20 |
|
|
| 701 |
|
|
| 51 |
|
|
| 246 |
|
|
| 55 |
|
|
| 40 |
|
|
| 517 |
|
|
| 42 |
|
|
| 223 |
|
119
|
| Average Sales Price |
|
|
|
|
|
| Average Sales Price (1) |
|
|
|
|
| ||||||||||||||||||||||||||
Year Ended December 31, |
| Oil (Per Bbl) |
|
| Bitumen (Per Bbl) |
|
| Gas (Per Mcf) |
|
| NGLs (Per Bbl) |
|
| Production Cost (Per Boe) (1) |
|
| Oil (Per Bbl) |
|
| Bitumen (Per Bbl) |
|
| Gas (Per Mcf) |
|
| NGLs (Per Bbl) |
|
| Production Cost (Per Boe) (1)(2) |
| ||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
2018 (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
| $ | 41.03 |
|
| $ | — |
|
| $ | 1.76 |
|
| $ | 10.31 |
|
| $ | 6.16 |
|
| $ | 62.89 |
|
| $ | — |
|
| $ | 2.45 |
|
| $ | 22.72 |
|
| $ | 9.42 |
|
STACK |
| $ | 63.81 |
|
| $ | — |
|
| $ | 2.29 |
|
| $ | 25.53 |
|
| $ | 7.16 |
| ||||||||||||||||||||
Jackfish |
| $ | — |
|
| $ | 19.82 |
|
| $ | — |
|
| $ | — |
|
| $ | 8.70 |
|
| $ | — |
|
| $ | 17.88 |
|
| $ | — |
|
| $ | — |
|
| $ | 12.85 |
|
U.S. |
| $ | 38.92 |
|
| $ | — |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 6.44 |
|
| $ | 61.97 |
|
| $ | — |
|
| $ | 2.37 |
|
| $ | 24.74 |
|
| $ | 8.61 |
|
Canada |
| $ | 23.96 |
|
| $ | 19.82 |
|
|
| N/M |
|
| $ | — |
|
| $ | 9.36 |
|
| $ | 27.36 |
|
| $ | 17.88 |
|
| N/M |
|
| $ | — |
|
| $ | 13.43 |
| |
Total North America |
| $ | 36.72 |
|
| $ | 19.82 |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 7.08 |
|
| $ | 57.76 |
|
| $ | 17.88 |
|
| $ | 2.37 |
|
| $ | 24.74 |
|
| $ | 9.66 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
| $ | 46.47 |
|
| $ | — |
|
| $ | 2.00 |
|
| $ | 9.62 |
|
| $ | 6.02 |
|
| $ | 49.72 |
|
| $ | — |
|
| $ | 2.47 |
|
| $ | 13.67 |
|
| $ | 6.86 |
|
STACK |
| $ | 48.43 |
|
| $ | — |
|
| $ | 2.40 |
|
| $ | 17.78 |
|
| $ | 4.72 |
| ||||||||||||||||||||
Jackfish |
| $ | — |
|
| $ | 23.41 |
|
| $ | — |
|
| $ | — |
|
| $ | 12.43 |
|
| $ | — |
|
| $ | 29.38 |
|
| $ | — |
|
| $ | — |
|
| $ | 11.02 |
|
U.S. |
| $ | 44.01 |
|
| $ | — |
|
| $ | 2.17 |
|
| $ | 9.32 |
|
| $ | 7.52 |
|
| $ | 49.41 |
|
| $ | — |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 6.74 |
|
Canada |
| $ | 30.58 |
|
| $ | 23.41 |
|
|
| N/M |
|
| $ | — |
|
| $ | 13.18 |
|
| $ | 33.73 |
|
| $ | 29.38 |
|
| N/M |
|
| $ | — |
|
| $ | 11.70 |
| |
Total North America |
| $ | 42.12 |
|
| $ | 23.41 |
|
| $ | 2.14 |
|
| $ | 9.32 |
|
| $ | 8.48 |
|
| $ | 47.31 |
|
| $ | 29.38 |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 7.94 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
| $ | 95.51 |
|
| $ | — |
|
| $ | 3.78 |
|
| $ | 21.98 |
|
| $ | 5.25 |
|
| $ | 41.03 |
|
| $ | — |
|
| $ | 1.76 |
|
| $ | 10.31 |
|
| $ | 5.75 |
|
STACK |
| $ | 39.81 |
|
| $ | — |
|
| $ | 1.91 |
|
| $ | 10.86 |
|
| $ | 4.34 |
| ||||||||||||||||||||
Jackfish |
| $ | — |
|
| $ | 55.88 |
|
| $ | — |
|
| $ | — |
|
| $ | 20.59 |
|
| $ | — |
|
| $ | 19.82 |
|
| $ | — |
|
| $ | — |
|
| $ | 8.70 |
|
U.S. |
| $ | 85.64 |
|
| $ | — |
|
| $ | 3.92 |
|
| $ | 24.46 |
|
| $ | 7.52 |
|
| $ | 38.92 |
|
| $ | — |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 6.44 |
|
Canada |
| $ | 68.14 |
|
| $ | 55.88 |
|
| $ | 3.64 |
|
| $ | 50.52 |
|
| $ | 20.10 |
|
| $ | 23.96 |
|
| $ | 19.82 |
|
| N/M |
|
| $ | — |
|
| $ | 9.36 |
| |
Total North America |
| $ | 82.47 |
|
| $ | 55.88 |
|
| $ | 3.90 |
|
| $ | 24.89 |
|
| $ | 9.49 |
|
| $ | 36.72 |
|
| $ | 19.82 |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 7.08 |
|
(1) | As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $254 million during 2018 with no impact to net earnings. These changes primarily related to our Barnett Shale and STACK properties. |
(2) | Represents |
Drilling Statistics
The following table summarizes our development and exploratory drilling results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Development Wells (1) |
|
| Exploratory Wells (1) |
|
| Total Wells (1) |
|
| Development Wells (1) |
|
| Exploratory Wells (1) |
|
| Total Wells (1) |
| ||||||||||||||||||||||||||||||||||||||
Year Ended December 31, |
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Total |
|
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Productive |
|
| Dry |
|
| Total |
| ||||||||||||||
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
U.S. |
|
| 165.6 |
|
|
| 3.1 |
|
|
| 69.4 |
|
|
| — |
|
|
| 235.0 |
|
|
| 3.1 |
|
|
| 238.1 |
| ||||||||||||||||||||||||||||
Canada |
|
| 70.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 70.5 |
|
|
| — |
|
|
| 70.5 |
| ||||||||||||||||||||||||||||
Total North America |
|
| 236.1 |
|
|
| 3.1 |
|
|
| 69.4 |
|
|
| — |
|
|
| 305.5 |
|
|
| 3.1 |
|
|
| 308.6 |
| ||||||||||||||||||||||||||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
U.S. |
|
| 149.8 |
|
|
| — |
|
|
| 44.0 |
|
|
| — |
|
|
| 193.8 |
|
|
| — |
|
|
| 193.8 |
| ||||||||||||||||||||||||||||
Canada |
|
| 100.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 100.5 |
|
|
| — |
|
|
| 100.5 |
| ||||||||||||||||||||||||||||
Total North America |
|
| 250.3 |
|
|
| — |
|
|
| 44.0 |
|
|
| — |
|
|
| 294.3 |
|
|
| — |
|
|
| 294.3 |
| ||||||||||||||||||||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 88.5 |
|
|
| — |
|
|
| 36.4 |
|
|
| 2.0 |
|
|
| 124.9 |
|
|
| 2.0 |
|
|
| 126.9 |
|
|
| 88.5 |
|
|
| — |
|
|
| 36.4 |
|
|
| 2.0 |
|
|
| 124.9 |
|
|
| 2.0 |
|
|
| 126.9 |
|
Canada |
|
| 21.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 21.5 |
|
|
| — |
|
|
| 21.5 |
|
|
| 21.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 21.5 |
|
|
| — |
|
|
| 21.5 |
|
Total North America |
|
| 110.0 |
|
|
| — |
|
|
| 36.4 |
|
|
| 2.0 |
|
|
| 146.4 |
|
|
| 2.0 |
|
|
| 148.4 |
|
|
| 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 |
| ||||||||||||||||||||||||||||
(1) |
|
1210
The following table presents the wells that were in progress on December 31, 2016.2018. As of February 1, 2017,2019, these wells were still in progress.
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
| ||||
U.S. |
|
| 42.0 |
|
|
| 14.5 |
|
|
| 184.0 |
|
|
| 105.2 |
|
Canada |
|
| 10.0 |
|
|
| 10.0 |
|
|
| 1.0 |
|
|
| 1.0 |
|
Total North America |
|
| 52.0 |
|
|
| 24.5 |
|
|
| 185.0 |
|
|
| 106.2 |
|
(1) | Gross wells are the sum of all wells in which we own a working interest. |
(2) | Net wells are gross wells multiplied by our fractional working interests in each well. |
Productive Wells
The following table sets forth our producing wells as of December 31, 2016.2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil Wells (1) |
|
| Natural Gas Wells |
|
| Total Wells (1) |
|
| Oil Wells (1) |
|
| Natural Gas Wells |
|
| Total Wells (1) |
| ||||||||||||||||||||||||||||||
|
| Gross (2)(4) |
|
| Net (3) |
|
| Gross (2)(4) |
|
| Net (3) |
|
| Gross (2)(4) |
|
| Net (3) |
|
| 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 |
|
|
| 9,284 |
|
|
| 3,445 |
|
|
| 8,235 |
|
|
| 5,703 |
|
|
| 17,519 |
|
|
| 9,148 |
|
Canada |
|
| 3,239 |
|
|
| 3,138 |
|
|
| 644 |
|
|
| 456 |
|
|
| 3,883 |
|
|
| 3,594 |
|
|
| 3,183 |
|
|
| 3,071 |
|
|
| 544 |
|
|
| 380 |
|
|
| 3,727 |
|
|
| 3,451 |
|
Total North America |
|
| 12,949 |
|
|
| 6,637 |
|
|
| 10,705 |
|
|
| 8,033 |
|
|
| 23,654 |
|
|
| 14,670 |
|
|
| 12,467 |
|
|
| 6,516 |
|
|
| 8,779 |
|
|
| 6,083 |
|
|
| 21,246 |
|
|
| 12,599 |
|
(1) | Includes bitumen wells. |
(2) | Gross wells are the sum of all wells in which we own a working interest. |
(3) | Net wells are gross wells multiplied by our fractional working interests in each well. |
(4) | 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 15,20012,900 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, 2016.2018. Of our 4.63.8 million net acres, approximately 2.41.9 million acres are held by production. The acreage in the table includes 0.30.2 million, 0.20.1 million and 0.1 million net acres subject to leases that are scheduled to expire during 2017, 20182019, 2020 and 2019,2021, respectively. As of December 31, 2016,2018, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.60.3 million net acres set to expire by December 31, 2019,2021, 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 2016,2018, we allowed approximately 0.30.1 million acres to expire, which is consistent with expirations in prior years.expire.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Developed |
|
| Undeveloped |
|
| Total |
|
| Developed |
|
| Undeveloped |
|
| Total |
| ||||||||||||||||||||||||||||||
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
| ||||||||||||
|
| (Thousands) |
|
| (Thousands) |
| ||||||||||||||||||||||||||||||||||||||||||
U.S. |
|
| 1,800 |
|
|
| 1,218 |
|
|
| 4,138 |
|
|
| 1,917 |
|
|
| 5,938 |
|
|
| 3,135 |
|
|
| 1,449 |
|
|
| 909 |
|
|
| 3,373 |
|
|
| 1,463 |
|
|
| 4,822 |
|
|
| 2,372 |
|
Canada |
|
| 695 |
|
|
| 512 |
|
|
| 2,075 |
|
|
| 953 |
|
|
| 2,770 |
|
|
| 1,465 |
|
|
| 674 |
|
|
| 495 |
|
|
| 2,086 |
|
|
| 967 |
|
|
| 2,760 |
|
|
| 1,462 |
|
Total North America |
|
| 2,495 |
|
|
| 1,730 |
|
|
| 6,213 |
|
|
| 2,870 |
|
|
| 8,708 |
|
|
| 4,600 |
|
|
| 2,123 |
|
|
| 1,404 |
|
|
| 5,459 |
|
|
| 2,430 |
|
|
| 7,582 |
|
|
| 3,834 |
|
(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. |
11
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.
14
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 2017,2019, our production was sold under the following contract terms.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Short-Term |
|
| Long-Term |
|
| Short-Term |
|
| Long-Term |
| ||||||||||||||||||||
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
|
| Variable |
|
| Fixed |
| ||||||||
Oil and bitumen |
|
| 65 | % |
|
| — |
|
|
| 35 | % |
|
| — |
|
|
| 75 | % |
|
| — |
|
|
| 25 | % |
|
| — |
|
Natural gas |
|
| 54 | % |
|
| 4 | % |
|
| 42 | % |
|
| — |
|
|
| 67 | % |
|
| 4 | % |
|
| 29 | % |
|
| — |
|
NGLs |
|
| 53 | % |
|
| 17 | % |
|
| 30 | % |
|
| — |
|
|
| 41 | % |
|
| 20 | % |
|
| 39 | % |
|
| — |
|
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, 2016,2018, 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 |
| ||||||||
Oil and bitumen (MMBbls) |
|
| 112 |
|
|
| 36 |
|
|
| 48 |
|
|
| 28 |
|
|
| 53 |
|
|
| 25 |
|
|
| 28 |
|
|
| — |
|
Natural gas (Bcf) |
|
| 487 |
|
|
| 338 |
|
|
| 149 |
|
|
| — |
|
|
| 360 |
|
|
| 220 |
|
|
| 125 |
|
|
| 15 |
|
NGLs (MMBbls) |
|
| 9 |
|
|
| 9 |
|
|
| — |
|
|
| — |
|
|
| 10 |
|
|
| 10 |
|
|
| — |
|
|
| — |
|
Total (MMBoe) |
|
| 202 |
|
|
| 101 |
|
|
| 73 |
|
|
| 28 |
|
|
| 123 |
|
|
| 72 |
|
|
| 49 |
|
|
| 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, 20152018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.
During 2017 and 2014,2016, no purchaser accounted for over 10% of our consolidated sales revenue.
Competition
See “Item 1A. Risk Factors.”
12
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.
16
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
13
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 inwould use the Modernized Royalty Framework the(MRF) which prescribes a lower royalty rate until allowable costs have been recovered. The calculation for wells post payout is based on a percentage of production net of allowed deductions.deductions and varies with commodity price.
Marketing in Canada
Any oil or gas export requires an exporter to obtain export authorizations from Canada’s National Energy Board.
In December 2018, Alberta enacted the Curtailment Rules (Rules) in an effort to reduce Alberta’s oversupply of oil which resulted from pipeline and rail constraints. Pursuant to the Rules, operators that produce either or both crude oil or crude bitumen in amounts in excess of 10 MBbls/d are required to curtail their production. As of January 1, 2019, the production curtailment amount was set at 325 MBbls/d. The curtailment amounts are expected to reduce over 2019 to an average of approximately 95 MBbls/d as storage levels ease and price differential improve, and the Rules terminate on December 31, 2019. Devon’s curtailments in the first quarter of 2019 as a result of the Rules are anticipated to total approximately 10 MBbls/d of bitumen, or approximately 2% of our total production.
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, provincial 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 allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmentalEnvironmental 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.
1714
Volatile Oil, Gas and NGL Prices Significantly Impact our Business
Our financial condition, results of operations and the value of our properties are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. Historically, market prices and our realized prices have been volatile. For example, 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 high of $107.26over $100 per Bbl and $6 per MMBtu, respectively, to a low of $26.21under $27 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15Bbl and $1.70 per MMBtu, to a low of $1.64 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 or other producing countries; |
• | geopolitical risks, including political and civil unrest in the Middle East, Africa and South America; |
• | adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes; |
• | regional pricing differentials, including in Canada, the Delaware Basin and other areas of our operations; |
• | differing quality of production, including NGL content of gas produced; |
• | the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories; |
• | the price and availability of alternative fuels; |
• | technological advances affecting energy consumption and production; |
• | the overall economic environment; |
• | changes in trade relations and policies, including the imposition of tariffs by the U.S. or China; and |
• | other governmental regulations and taxes. |
The differential between WTI and demandWestern Canadian Select, a benchmark for the Canadian oil gas and NGLs, including consumer demandmarket, recently expanded, widening to nearly $46 per barrel in emerging markets, such as China;
volatility and trading patterns inNovember 2018. As a result, our Canadian heavy oil unhedged realized price for the commodity-futures markets;
conservation and environmental protection efforts;
production levels of members of OPEC, Russia or other producing countries;
geopolitical risks, including political and civil unrest in the Middle East and Africa;
adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes;
regional pricing differentials;
differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);
differing quality and NGL content of gas produced;
the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories;
the price and availability of alternative 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.fourth quarter was near zero. This commodity price decline adverselynegatively affected our business and results of operations in 2018, and led to substantial impairments to our oil and gas properties during 2015 and 2016. Aa sustained weakness or further deterioration in differentials or 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;
• | reducing the amount of oil, bitumen, gas and NGLs that we can produce economically; |
limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;
• | limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt; |
reducing our revenues, operating cash flows and profitability;
• | 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
• | 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.
• | reducing the carrying value of our properties, resulting in noncash write-downs. |
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
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given reservoir may change substantially over time as a result of several factors, including additional development and appraisal activity, the viability of production under varying economic conditions, including commodity price declines, and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material 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.
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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. 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 ResultsOur 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.
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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
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regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations.operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, which may result in significant costs associated with the removal of tangible equipment and other restorative actions at the end of operations.
In addition, changes in public policy have affected, and at times in the future could further affect, our operations. Regulatory and public policy developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements and increase taxes, royalties and other amounts payable to governments or governmental agencies. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. In addition, changes in public policy may indirectly impact our operations by, among other things, increasing the cost of supplies and equipment and fostering general economic uncertainty. For example, changes in U.S. trade relations, particularly the imposition of tariffs by the U.S. and China, may increase the cost of materials we or our vendors use, thereby increasing our operating expense. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, pipeline safety, seismic activity and income taxes, and climate change, as discussed below.
Hydraulic Fracturing – TheIn recent years, the EPA and other federal agencies, including the BLM, havehas made proposals that would subject hydraulic fracturing to further regulation and that could potentially restrict the practice of hydraulic fracturing. 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 finalized in June 2016 regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a study in December 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The BLM and severalpreviously finalized regulations to regulate hydraulic fracturing on federal lands, but subsequently issued a repeal of those regulations in 2017. Several states in which we operate have already adopted and more states are considering adopting laws and/or regulations that require disclosure of chemicals used in hydraulic fracturing and impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. In addition, some states and municipalities have significantly limited drilling activities and/or hydraulic fracturing or are considering doing so.so or banning the practice altogether. Although it is not possible at this time to predict the final outcome of these 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 in development or restrictions on our operations.
Pipeline Safety – The pipeline assets in which we own interests, through EnLink or otherwise, are subject to stringent and complex regulations related to pipeline safety and integrity management. The PHMSA has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For example, in 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. To date, no further action has been taken. PHMSA has announced its intent to address the 2016 proposed rules for gas pipelines through three separate final rulemakings in 2019. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Following the change in presidential administrations, implementation of this rule was delayed, but the final rule is expected to be published in the Federal Register and become effective during the first half of 2019. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
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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 energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims, seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
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Potential Index to Financial Statements
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 to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil
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 subsequent attempts to revise or rescind them is ongoing. Nevertheless, several states where we operate, including Wyoming, have already imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. With respect to more comprehensive regulation, federal and state initiatives to date have generally focused on the development of cap-and-trade and/or carbon tax programs. AAs 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/or emissions resulting from the useoperations and downstream uses of our products by our customers. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to addressproducts.
In Canada, greenhouse gas emissions would impact our business, any such futureare also being addressed at both the federal and provincial level. Devon will continue to be subject to Alberta’s climate change laws and regulations imposing reporting obligations on, or limitinguntil at least 2021. Those laws and regulations include a legislated oil sands emission limit, with forthcoming regulations involving methane emissions reduction targets. Beginning January 2019, the Greenhouse Gas Pollution Pricing Act subjects all of greenhouse gases from, our equipment and operations could require usCanada to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitationsa federal price on greenhouse gas emissions unless a province or territory has implemented a compliant carbon pricing regime. Litigation concerning the act is ongoing, and it is unclear how the act will ultimately treat provincial plans. In Alberta, large industrial emitters are subject to the Carbon Competitiveness Incentive Regulation (CCIR). The CCIR prices carbon, but provides cost protection to emission-intensive / trade-exposed industries, including Devon’s oil sands operations. The impact to our operations from these laws and regulations is expected to be minimal in the near term. Oil and gas facilities that are not subject to the CCIR are exempt from its economy-wide carbon levy until 2023.
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 of alternative energy sources, including by mandating the use of specific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, certain financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to their concern regarding climate change. Such restrictions in capital could also adversely affect demand formake it more difficult to secure funding to operate our business. Finally, governmental entities and other plaintiffs have brought, and may continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged effects of climate change. These and the other regulatory, social and market risks relating to climate change described above could result in unexpected costs, increase our operating expense and reduce the demand for our products, which in turn could lower the value of our reserves and have a material 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, 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
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and availability of our hedging arrangements, including by causing our contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.
The Credit Risk of Our Counterparties Could Adversely Affect 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 to perform certain obligations associated with the disposed assets, including the removal of production facilities and plugging and abandonment of wells. Certain of these counterparties may experience insolvency, liquidity problems or other issues and may not be able to meet their financial obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or volatile commodity price environment. Any such default by these counterparties may result in us being forced to cover the costs of those obligations and liabilities, which could adversely impact our financial results.results and condition.
Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us
As of December 31, 2016,2018, we had total consolidated indebtedness of $10.2$5.9 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 our use of technology in our operations, including through 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.cyberattack activities, which have been increasing against our industry. Cyber attacksattackers often attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, intellectual property or financial assets,
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corrupting data or causing operational disruption anddisruptions. These attacks may be carried outperpetrated by third parties or insiders. The techniques utilizedTechniques used in these attacks range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be carried out 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.
Limited Control on Properties Operated by Others
Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, including compliance with environmental, health and safety regulations or the amount and timing of required future capital expenditures. These limitations and our dependence on the operator and other working interest owners for these properties could result in unexpected future costs and delays, curtailments or cancellations of operations or future development, which could adversely affect our financial condition and results of operations.
Midstream Capacity Constraints and Interruptions Impact Commodity Sales
We rely on midstream facilities and systems 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 material 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 fuels and the application of government regulations.
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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;
• | 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
• | difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and |
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
• | 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
Devon Gas Services,Energy Production Company, L.P., a wholly-owned subsidiary of the Company, is currently in negotiations with the EPA with respect to alleged noncompliance with the leak detection and repair requirements of EPA regulations promulgated under the Clean Air Act at its Beaver Creek Gas Plant located near Riverton, Wyoming. Although management cannot predict the outcome of settlement negotiations, 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 from the EPA under the Clean Air Act relating to our compliance with certain air emission requirements under Clean Air Act regulations 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 predict the ultimate outcome of this information request, but it may result in the imposition of a fine or penalty, through settlement negotiations or otherwise, in excess of $100,000.
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, 2017,6, 2019, there were 7,8567,094 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 18 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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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 |
|
| $ | 36.01 |
|
| $ | 0.24 |
|
June 30, 2015 |
| $ | 70.48 |
|
| $ | 58.77 |
|
| $ | 0.24 |
|
March 31, 2015 |
| $ | 67.08 |
|
| $ | 56.35 |
|
| $ | 0.24 |
|
26
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. The graph was prepared assuming $100 was invested on December 31, 20112013 in Devon’s common stock, the S&P 500 Index and the peer group, and dividends have been reinvested subsequent to the initial investment.
The graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
22
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.
2018 (shares in thousands).
Period |
| Total Number of Shares Purchased (1) |
|
| Average Price Paid per Share |
|
| Total Number of Shares Purchased (1) |
|
| Average Price Paid per Share |
|
| Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (2) |
|
| Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
| ||||||
October 1 - October 31 |
|
| 25,638 |
|
| $ | 43.29 |
|
|
| 10,532 |
|
| $ | 36.01 |
|
|
| 10,529 |
|
| $ | 2,388 |
|
November 1 - November 30 |
|
| 96,822 |
|
| $ | 42.15 |
|
|
| 7,079 |
|
| $ | 31.55 |
|
|
| 7,068 |
|
| $ | 2,165 |
|
December 1 - December 31 |
|
| 3,778 |
|
| $ | 47.30 |
|
|
| 6,020 |
|
| $ | 23.82 |
|
|
| 6,015 |
|
| $ | 2,022 |
|
Total |
|
| 126,238 |
|
| $ | 42.54 |
|
|
| 23,631 |
|
| $ | 31.57 |
|
|
| 23,612 |
|
|
|
|
|
|
| In addition to shares purchased under the share repurchase program described below, these amounts also included approximately 19,000 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. During 2018, we repurchased 78.1 million shares of common stock |
27
Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 80,60039,000 shares of our common stock in 2016,2018, 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 shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada.trustee. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In 2016,2018, there were no shares purchased by Canadian employees.employees under the plan.
23
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.
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2013 |
|
| 2012 |
| |||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||
Oil, gas and NGL sales |
| $ | 4,182 |
|
| $ | 5,382 |
|
| $ | 9,910 |
|
| $ | 8,522 |
|
| $ | 7,153 |
|
Total revenues and other (1) |
| $ | 12,197 |
|
| $ | 13,145 |
|
| $ | 20,638 |
|
| $ | 10,388 |
|
| $ | 9,514 |
|
Earnings (loss) from continuing operations (1) |
| $ | (3,704 | ) |
| $ | (15,203 | ) |
| $ | 1,691 |
|
| $ | (20 | ) |
| $ | (185 | ) |
Earnings (loss) from continuing operations attributable to Devon (1) |
| $ | (3,302 | ) |
| $ | (14,454 | ) |
| $ | 1,607 |
|
| $ | (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 |
|
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||||
Statement of Earnings data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream revenues (1) |
| $ | 6,285 |
|
| $ | 5,307 |
|
| $ | 3,981 |
|
| $ | 5,885 |
|
| $ | 11,619 |
|
Total revenues (1) |
| $ | 10,734 |
|
| $ | 8,878 |
|
| $ | 6,753 |
|
| $ | 9,372 |
|
| $ | 16,636 |
|
Net earnings (loss) from continuing operations (2) |
| $ | 764 |
|
| $ | 758 |
|
| $ | (574 | ) |
| $ | (12,231 | ) |
| $ | (1,004 | ) |
Net earnings (loss) from continuing operations per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic (2) |
| $ | 1.53 |
|
| $ | 1.44 |
|
| $ | (1.14 | ) |
| $ | (30.09 | ) |
| $ | (2.49 | ) |
Diluted (2) |
| $ | 1.52 |
|
| $ | 1.43 |
|
| $ | (1.14 | ) |
| $ | (30.09 | ) |
| $ | (2.49 | ) |
Cash dividends per common share |
| $ | 0.30 |
|
| $ | 0.24 |
|
| $ | 0.42 |
|
| $ | 0.96 |
|
| $ | 0.94 |
|
Balance Sheet data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (2)(3) |
| $ | 19,566 |
|
| $ | 30,241 |
|
| $ | 28,675 |
|
| $ | 29,673 |
|
| $ | 49,253 |
|
Long-term debt |
| $ | 5,785 |
|
| $ | 6,749 |
|
| $ | 6,859 |
|
| $ | 8,990 |
|
| $ | 7,738 |
|
Stockholders' equity |
| $ | 9,186 |
|
| $ | 14,104 |
|
| $ | 12,722 |
|
| $ | 11,111 |
|
| $ | 24,789 |
|
Common shares outstanding |
|
| 450 |
|
|
| 525 |
|
|
| 523 |
|
|
| 418 |
|
|
| 409 |
|
(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 for 2018 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 in 2014 through 2017 include assets related to our aggregate ownership interest in EnLink and |
2824
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 20162018 Results
By executing on2018 was a pivotal year for Devon as we took several significant steps toward achieving our strategy outlinedlong-term strategic goals. Operationally, we successfully transitioned our U.S. oil business into full-field development, which resulted in “Items 1 and 2. Business and Properties” of this report, we strive to optimize value for our shareholders by growing cash flow, earnings,high-return, light-oil production and reserves, all on a per debt-adjusted share basis. Despite the challenges our company and the entire upstream energy sector have faced from the sustained low commodity price environment, we have continued to execute our strategy and position our company for long-term success. Although we have seen moderate improvementsadvancing 14 percent 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.2018. In responseaddition to this environment,strong operating performance, we remained committed to an approach centered on:
Maintaining a balancedmade substantial progress high-grading our asset portfolio, of high-class assets with a focus onbuilding per-share value through our share-repurchase program 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 debt 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 ofreducing our financial performance in 2016 are summarized in the following table:
leverage by more than 40 percent.
|
| 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 |
|
• | Increased STACK and Delaware Basin production 27% in 2018 compared to 2017. |
• | Maintained our 2018 capital expenditure forecast. |
• | Substantially achieved $5.0 billion in asset sales, including the monetization of EnLink and the General Partner. |
• | Repurchased $3.0 billion of common stock, representing a 14% share count reduction since December 31, 2017. |
• | Reduced long-term debt by $922 million, which is expected to reduce annualized financing costs by $66 million. |
• | Completed workforce reduction and cost reduction initiatives expected to generate $150 million of annualized savings. |
• | Increased our quarterly common stock dividend 33% to $0.08 per share beginning in the second quarter of 2018. |
• | Exited 2018 with $2.4 billion of cash and $2.9 billion of available credit under our Senior Credit Facility and have no significant debt maturities until 2021. |
| 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 an average high of $64.79 per Bbl and $3.11 per MMBtu, respectively, to an average low of $43.36 per Bbl and $2.46 per MMBtu, respectively. Widening Western Canadian Select differentials negatively impacted the prices we realized on our heavy oil production in the fourth quarter of 2018. In the first two months of 2019, Western Canadian Select differentials have improved significantly. | |
Key measures of our financial performance in 2018 are summarized in the following table. Increased oil and natural gas liquids prices as well as continued focus cost management improved our 2018 financial performance as compared to 2017, as seen in the table below. Additionally, we recognized a gain of approximately $2.6 billion ($2.2 billion after-tax) related to the sale of EnLink and the General Partner during 2018. More details for these metrics are found within the “Results of Operations – 2018 vs. 2017” below. |
25
|
| 2018 |
|
| Change |
|
| 2017 |
|
| Change |
|
| 2016 |
| |||||
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) attributable to Devon |
| $ | 3,064 |
|
|
| +241 | % |
| $ | 898 |
|
|
| +185 | % |
| $ | (1,056 | ) |
Net earnings (loss) per diluted share attributable to Devon |
| $ | 6.10 |
|
|
| +259 | % |
| $ | 1.70 |
|
|
| +181 | % |
| $ | (2.09 | ) |
Core earnings (loss) attributable to Devon (1) |
| $ | 655 |
|
|
| +53 | % |
| $ | 427 |
|
|
| +216 | % |
| $ | (367 | ) |
Core earnings (loss) attributable to Devon per diluted share (1) |
| $ | 1.30 |
|
|
| +60 | % |
| $ | 0.81 |
|
|
| +212 | % |
| $ | (0.73 | ) |
Continuing Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 764 |
|
|
| +1 | % |
| $ | 758 |
|
|
| +232 | % |
| $ | (574 | ) |
Net earnings (loss) per diluted share |
| $ | 1.52 |
|
|
| +6 | % |
| $ | 1.43 |
|
|
| +225 | % |
| $ | (1.14 | ) |
Core earnings (loss) (1) |
| $ | 587 |
|
|
| +48 | % |
| $ | 397 |
|
|
| +207 | % |
| $ | (371 | ) |
Core earnings (loss) per diluted share (1) |
| $ | 1.17 |
|
|
| +57 | % |
| $ | 0.75 |
|
|
| +202 | % |
| $ | (0.73 | ) |
Discontinued Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) attributable to Devon |
| $ | 2,300 |
|
|
| +1543 | % |
| $ | 140 |
|
|
| +129 | % |
| $ | (481 | ) |
Net earnings (loss) per diluted share attributable to Devon |
| $ | 4.58 |
|
|
| +1596 | % |
| $ | 0.27 |
|
|
| +128 | % |
| $ | (0.95 | ) |
Core earnings attributable to Devon (1) |
| $ | 68 |
|
|
| +127 | % |
| $ | 30 |
|
|
| +580 | % |
| $ | 4 |
|
Core earnings attributable to Devon per diluted share (1) |
| $ | 0.13 |
|
|
| +120 | % |
| $ | 0.06 |
|
|
| +1628 | % |
| $ | 0.00 |
|
Other Metrics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained production (MBoe/d) |
|
| 500 |
|
|
| +4 | % |
|
| 481 |
|
|
| - 3 | % |
|
| 497 |
|
Total production (MBoe/d) |
|
| 535 |
|
|
| - 2 | % |
|
| 543 |
|
|
| - 11 | % |
|
| 611 |
|
Realized price per Boe (2) |
| $ | 29.08 |
|
|
| +12 | % |
| $ | 25.96 |
|
|
| +39 | % |
| $ | 18.72 |
|
Operating cash flow from continuing operations |
| $ | 2,228 |
|
|
| +1 | % |
| $ | 2,209 |
|
|
| +165 | % |
| $ | 834 |
|
Capitalized expenditures, including acquisitions |
| $ | 2,576 |
|
|
| +19 | % |
| $ | 2,169 |
|
|
| - 23 | % |
| $ | 2,826 |
|
Cash and cash equivalents |
| $ | 2,414 |
|
|
| - 9 | % |
| $ | 2,642 |
|
|
| +36 | % |
| $ | 1,947 |
|
Total debt |
| $ | 5,947 |
|
|
| - 13 | % |
| $ | 6,864 |
|
|
| +0 | % |
| $ | 6,859 |
|
Reserves (MMBoe) |
|
| 1,927 |
|
|
| - 10 | % |
|
| 2,152 |
|
|
| +5 | % |
|
| 2,058 |
|
(1) | Core earnings and core earnings per share attributable to Devon are financial measures not prepared in accordance with GAAP. For a description of core earnings and core earnings per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7. |
(2) | Excludes any impact of oil, gas and NGL derivatives. |
Our 2016 net loss and net loss per share improved compared to 2015 primarily due to more significant noncash asset impairments recognized in 2015 as a result of the large commodity price declines. Core loss, core loss per share and operating cash flow for 2016 decreased significantly compared to 2015 as a result of the continued decline in commodity prices and the expiration of certain favorable commodity hedging positions.
Business and Industry Outlook
Devon marked its 45th anniversary in the oil and gas business and its 28th year as a public company during 2016. As an established company with a strong leadership team, we have experience operating in periods of challenged commodity prices. With our focused strategy and portfolio of quality assets, we are prepared to successfully navigate the current environment while ensuring 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 2018, WTI oil prices ranged from $26.21/averaged approximately $67/Bbl to $54.06/Bbl. As a result of the ongoing worldwide oversupply issue, OPEC agreed to its firstthrough October, supported by stronger-than-expected oil production cut in eight years in November 2016. Following the agreementsdemand, market management by both OPEC and non-OPEC producers to reduce output by nearly 1.8 million barrels per day in the first half of 2017,partners and unplanned supply outages. However, oil prices jumpedmarkedly declined in November and December, averaging approximately 10%$53/Bbl and reaching as low as $42.53/Bbl in December. The deterioration of WTI was driven by OPEC and non-OPEC partners unwinding their production cut agreement, compounded by rising supply and concerns over slowing global economic growth. Western Canadian Select basis differentials were challenged in the fourth quarter of 2016, averaging $49.21/Bbl. Current2018 due to robust production outpacing local demand, pipeline capacity and rail capacity out of the region. Looking ahead, current market fundamentals indicate improved prices forthat 2019 crude oil, natural gas and natural gas liquidspricing is expected to improve from its fourth quarter 2018 levels. Additionally, Western Canadian Select differentials are also projected to improve, driven by provincially mandated production cuts combined with takeaway capacity additions expected in 2017; however, changeslate 2019. Changes in OPEC production strategies, the macro-economic environment, geopolitical risks winter and summer temperature ranges or other factors could impact our current forecasts. As such, we anticipate continued volatility into 2017.
In 2018, Devon marked its 30
While we expect that our industry will remain challenged by relatively low prices forth year as a public company and 47th anniversary in the near-term, we have strategically positioned our company for continued growthoil and investment in our portfolio of assets. Leveraging the success of our 2016 divestiture program and other key achievements noted above,gas business, so we are experienced in dealing with the volatile nature of commodity prices. To mitigate our exposure to commodity market volatility and ensure our financial strength, we use a position of significant strength and anticipate expanding our exploration and development capital spend by approximately 80% in 2017.disciplined, risk-management hedging program. Our 2017 outlook is marked by accelerated activity across our key basins, focusing an expanded rig count in the STACK and Delaware Basin and achieving 15% growth in U.S. oil production through some of our best-in-class positions. Additionally, we ramped up our hedging program incorporates both systematic hedges added on a regular basis and discretionary hedges layered in 2016, withon an opportunistic basis to take advantage of favorable market conditions. We have approximately 50% of our anticipated 2019 oil and 45%gas volumes hedged, and we are currently adding hedges for 2020 as well. Further insulating our cash flow, we are proactively locking in hedges on the Western Canadian Select basis differential to WTI and currently have approximately 50% of our 2019 Canadian heavy oil production hedged.
26
Despite the uncertainties pertaining to commodity prices, we remain focused on our strategic priorities of having a premier portfolio of assets, delivering superior execution as we drill and operate oil and natural gas wells, and maintaining our financial strength and flexibility. 2019 will be an important year for Devon as we plan to separate our Canadian and Barnett Shale assets and complete our multi-year transition to a U.S. oil company with operations focused on four core areas in the Delaware Basin, STACK, Eagle Ford and Rockies. With a focused portfolio of U.S. oil assets, we also intend to optimize our cost structure by reducing our annual capital costs, G&A costs, interest expense and production hedged entering into 2017.expenses by $780 million in the aggregate by 2021. We expect to deliver 70% of these annualized cost savings in 2019, as the Canadian and Barnett Shale assets are separated, and we align our workforce with the retained business and reduce outstanding debt.
Finally, EnLink continuesImportantly, the portfolio changes and optimized cost performance are expected to be a strategic advantageenhance our competitive positioning as oil production growth, price realizations, field-level margins and corporate rates-of-return should all improve. With these improved expected outcomes, we remained focused on our 2019 capital allocation priorities of funding our core operations, protecting our investment-grade credit ratings and paying our shareholder dividend. Further, when considering the current commodity price environment and our current hedge position, we can achieve all our capital allocation priorities at $46/Bbl WTI and $3.00/Mcf Henry Hub. Should WTI drop closer to $40/Bbl for us, allowing for improved midstream growth potential. Annual distributions of approximately $270 million provide a visiblean extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI rises above $46/Bbl, our free cash flow streamwill accelerate, providing additional capital allocation opportunities.
Results of Operations – 2018 vs. 2017
The following graphs, discussion and analysis are intended to beprovide an understanding of our results of operations and current financial condition. Specifically, the graph below shows the change in net earnings from 2017 to 2018. The material changes are further invested in ourdiscussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
(1) | Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses. |
27
The graph below presents the drivers of the upstream capital programs discussed above.operations change presented above, with additional details and discussion of the drivers following the graph.
(2) | As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” in this report, 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 $254 million during 2018 with no impact to net earnings. |
28
31
Upstream Operations |
Oil, Gas and NGL Production
|
| Year Ended December 31, |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| |||||||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||||||||||||||||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Oil and bitumen (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Delaware Basin |
|
| 42 |
|
|
| 17 | % |
|
| 29 |
|
|
| +42 | % | ||||||||||||||||||||
STACK |
|
| 32 |
|
|
| 13 | % |
|
| 25 |
|
|
| +28 | % | ||||||||||||||||||||
Rockies Oil |
|
| 14 |
|
|
| 6 | % |
|
| 10 |
|
|
| +37 | % | ||||||||||||||||||||
Heavy Oil |
|
| 18 |
|
|
| 7 | % |
|
| 18 |
|
|
| +1 | % | ||||||||||||||||||||
Eagle Ford |
|
| 28 |
|
|
| 12 | % |
|
| 34 |
|
|
| - 17 | % | ||||||||||||||||||||
Barnett Shale |
|
| 1 |
|
|
| - 28 | % |
|
| 1 |
|
|
| - 35 | % |
|
| 2 |
|
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| - 7 | % |
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 |
|
|
| 5 |
|
|
| 2 | % |
|
| 5 |
|
|
| - 3 | % |
Retained assets |
|
| 141 |
|
|
| - 16 | % |
|
| 169 |
|
|
| +37 | % |
|
| 123 |
|
|
| 140 |
|
|
| 57 | % |
|
| 122 |
|
|
| +14 | % |
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 |
| ||||||||||||||||
U.S. divested assets |
|
| 9 |
|
|
| 4 | % |
|
| 12 |
|
|
| - 23 | % | ||||||||||||||||||||
Total Oil |
|
| 149 |
|
|
| 61 | % |
|
| 134 |
|
|
| +11 | % | ||||||||||||||||||||
Bitumen |
|
| 97 |
|
|
| 39 | % |
|
| 110 |
|
|
| - 12 | % | ||||||||||||||||||||
Total Oil and bitumen |
|
| 246 |
|
|
| 100 | % |
|
| 244 |
|
|
| +1 | % | ||||||||||||||||||||
32
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 105 |
|
|
| 10 | % |
|
| 86 |
|
|
| +22 | % |
STACK |
|
| 334 |
|
|
| 30 | % |
|
| 294 |
|
|
| +13 | % |
Rockies Oil |
|
| 16 |
|
|
| 1 | % |
|
| 8 |
|
|
| +85 | % |
Heavy Oil |
|
| 10 |
|
|
| 1 | % |
|
| 17 |
|
|
| - 39 | % |
Eagle Ford |
|
| 79 |
|
|
| 7 | % |
|
| 95 |
|
|
| - 17 | % |
Barnett Shale |
|
| 447 |
|
|
| 41 | % |
|
| 475 |
|
|
| - 6 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| +6 | % |
Retained assets |
|
| 992 |
|
|
| 90 | % |
|
| 976 |
|
|
| +2 | % |
U.S. divested assets |
|
| 108 |
|
|
| 10 | % |
|
| 227 |
|
|
| - 52 | % |
Total |
|
| 1,100 |
|
|
| 100 | % |
|
| 1,203 |
|
|
| - 9 | % |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 16 |
|
|
| 15 | % |
|
| 10 |
|
|
| +53 | % |
STACK |
|
| 37 |
|
|
| 35 | % |
|
| 30 |
|
|
| +24 | % |
Rockies Oil |
|
| 1 |
|
|
| 2 | % |
|
| 1 |
|
|
| +75 | % |
Eagle Ford |
|
| 13 |
|
|
| 12 | % |
|
| 13 |
|
|
| +2 | % |
Barnett Shale |
|
| 30 |
|
|
| 28 | % |
|
| 31 |
|
|
| - 4 | % |
Other |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 5 | % |
Retained assets |
|
| 98 |
|
|
| 93 | % |
|
| 86 |
|
|
| +14 | % |
U.S. divested assets |
|
| 8 |
|
|
| 7 | % |
|
| 13 |
|
|
| - 40 | % |
Total |
|
| 106 |
|
|
| 100 | % |
|
| 99 |
|
|
| +7 | % |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 75 |
|
|
| 14 | % |
|
| 54 |
|
|
| +39 | % |
STACK |
|
| 125 |
|
|
| 24 | % |
|
| 104 |
|
|
| +20 | % |
Rockies Oil |
|
| 17 |
|
|
| 3 | % |
|
| 12 |
|
|
| +43 | % |
Heavy Oil |
|
| 117 |
|
|
| 22 | % |
|
| 131 |
|
|
| - 11 | % |
Eagle Ford |
|
| 54 |
|
|
| 10 | % |
|
| 62 |
|
|
| - 13 | % |
Barnett Shale |
|
| 105 |
|
|
| 20 | % |
|
| 111 |
|
|
| - 5 | % |
Other |
|
| 7 |
|
|
| 1 | % |
|
| 7 |
|
|
| - 3 | % |
Retained assets |
|
| 500 |
|
|
| 94 | % |
|
| 481 |
|
|
| +4 | % |
U.S. divested assets |
|
| 35 |
|
|
| 6 | % |
|
| 62 |
|
|
| - 44 | % |
Total |
|
| 535 |
|
|
| 100 | % |
|
| 543 |
|
|
| - 2 | % |
Focused development activities in the Delaware Basin, STACK and Rockies resulted in an approximate 28% increase in production from those areas compared to 2017. These increases also drove a 17% increase in our U.S. retained oil production. This strong performance led to the overall growth in our retained assets during 2018. Production increases from our capital focused assets were partially offset by the effects of Contentsfacility repairs and other maintenance work at the Jackfish facilities, as well as by lower production resulting from our U.S. non-core divestitures.
Oil, Gas and NGL PricingPrices
|
| 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 |
|
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||
Oil and bitumen (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 64.79 |
|
|
|
|
|
| $ | 50.99 |
|
|
| +27 | % |
Access Western Blend index |
| $ | 34.75 |
|
|
|
|
|
| $ | 36.90 |
|
|
| - 6 | % |
U.S. |
| $ | 61.97 |
|
|
| 96% |
|
| $ | 49.41 |
|
|
| +25 | % |
Canada |
| $ | 19.37 |
|
|
| 30% |
|
| $ | 29.99 |
|
|
| - 35 | % |
Realized price, unhedged |
| $ | 42.04 |
|
|
| 65% |
|
| $ | 39.23 |
|
|
| +7 | % |
Cash settlements |
| $ | (0.49 | ) |
|
|
|
|
| $ | 0.23 |
|
|
|
|
|
Realized price, with hedges |
| $ | 41.55 |
|
|
| 64% |
|
| $ | 39.46 |
|
|
| +5 | % |
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 3.09 |
|
|
|
|
|
| $ | 3.11 |
|
|
| - 1 | % |
Realized price, unhedged |
| $ | 2.37 |
|
|
| 77% |
|
| $ | 2.48 |
|
|
| - 5 | % |
Cash settlements |
| $ | 0.01 |
|
|
|
|
|
| $ | 0.08 |
|
|
|
|
|
Realized price, with hedges |
| $ | 2.38 |
|
|
| 77% |
|
| $ | 2.56 |
|
|
| - 7 | % |
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 28.31 |
|
|
|
|
|
| $ | 24.77 |
|
|
| +14 | % |
Realized price, unhedged |
| $ | 24.74 |
|
|
| 87% |
|
| $ | 15.66 |
|
|
| +58 | % |
Cash settlements |
| $ | (1.17 | ) |
|
|
|
|
| $ | (0.10 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 23.57 |
|
|
| 83% |
|
| $ | 15.56 |
|
|
| +51 | % |
(1) |
|
|
|
Commodity Sales
The volume and price changes in the tables above caused the following changes
29
Index to our oil, gas and NGL sales.Financial Statements
|
| 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 |
|
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 31.86 |
|
| $ | 24.88 |
|
|
| +28 | % |
Canada |
| $ | 19.12 |
|
| $ | 29.39 |
|
|
| - 35 | % |
Realized price, unhedged |
| $ | 29.08 |
|
| $ | 25.96 |
|
|
| +12 | % |
Cash settlements |
| $ | (0.43 | ) |
| $ | 0.27 |
|
|
|
|
|
Realized price, with hedges |
| $ | 28.65 |
|
| $ | 26.23 |
|
|
| +9 | % |
Volumes 2016 vs. 2015 Commodity sales 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 decreasedUpstream revenues increased 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 fromhigher unhedged, realized prices for our U.S. oil properties. and NGLs.
The growth wasincrease in oil sales primarily driven by the continued developmentresulted from higher average WTI crude index prices, which were 27% higher in 2018, resulting in an increase of our Eagleapproximately $568 million.
33
Ford, Delaware Basin and Rockies Oil properties. Additionally, our bitumen productionNGL sales increased primarily due to Jackfish 3 coming on-line late in the third quarter of 2014 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$351 million as a result of lower prices for oil, bitumen and gas. The decrease in oil and bitumen sales primarily resulted from lower average WTI crude oil 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. These decreases were partially offset by slightly14% higher NGL prices at the Mont Belvieu, Texas hub.hub, as well as improved realizations in our NGL price.
Prices 2015 vs. 2014 Commodity sales decreased in 2015 as a result of significantly lower pricesThese increases were partially offset by widening differentials to the WTI index for all commodities. The decrease in oil and bitumen sales, primarily resulted from significantly lower average WTI crudewhich negatively impacted our upstream revenues by $406 million. In the fourth quarter of 2018, market forces widened Canadian heavy oil index prices, which weredifferentials beyond historical norms and negatively impacted the price we realized on our Canadian production. We had basis swaps for approximately 50% lower in 2015 as compared to 2014. The decreases in gas and NGL sales were driven by lower North American regional index prices upon which our gas sales are based and lower NGL prices at the Mont Belvieu, Texas hub.
Oil, Gas and NGL Derivatives
The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as componentshalf of our revenues. The subsequent tables present our oil, gas and NGL prices with and withoutfourth quarter production to mitigate the effect of the lower market price. To further mitigate the effects of the cash settlements.lower price, we reduced our Jackfish production in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d. Our Canadian heavy oil unhedged realized price for the fourth quarter was near zero. To date in 2019, heavy oil differentials have significantly improved driven by provincially mandated production cuts combined with takeaway capacity additions expected in 2019.
As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The prices do not include the effects of fair value gainschange resulted in an increase to our upstream revenues and losses. production expenses by approximately $254 million with no impact to net earnings.
Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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
|
| 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 |
|
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
|
| Q |
|
|
|
|
|
|
|
|
| |
Oil |
| $ | (44 | ) |
| $ | 21 |
|
|
| - 310 | % |
Natural gas |
|
| 5 |
|
|
| 35 |
|
|
| - 86 | % |
NGL |
|
| (45 | ) |
|
| (3 | ) |
|
| - 1400 | % |
Total cash settlements |
|
| (84 | ) |
|
| 53 |
|
|
| - 258 | % |
Valuation changes |
|
| 692 |
|
|
| 104 |
|
|
| +565 | % |
Total |
| $ | 608 |
|
| $ | 157 |
|
|
| +287 | % |
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 oil, gas and NGL derivatives include price swaps, costless collars and basis swaps.
In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationshipsrelationship between contract prices and the associated forward curves. Including
Production Expenses
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
LOE |
| $ | 995 |
|
| $ | 927 |
|
|
| +7 | % |
Gathering, processing & transportation |
|
| 891 |
|
|
| 647 |
|
|
| +38 | % |
Production taxes |
|
| 278 |
|
|
| 194 |
|
|
| +43 | % |
Property taxes |
|
| 61 |
|
|
| 55 |
|
|
| +11 | % |
Total |
| $ | 2,225 |
|
| $ | 1,823 |
|
|
| +22 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 5.10 |
|
| $ | 4.67 |
|
|
| +9 | % |
Gathering, processing & transportation |
| $ | 4.56 |
|
| $ | 3.26 |
|
|
| +40 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 4.9 | % |
|
| 3.8 | % |
|
| +27 | % |
LOE increased $68 million primarily due to continued focus on growing our liquids-rich assets within the cash settlementsSTACK and Delaware Basin and higher maintenance costs at our Jackfish facilities, partially offset by our U.S. non-core divestitures.
As further discussed above,in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, 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 $254 million with no impact to net earnings.
Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed. 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 derivatives incurredsales.
Property taxes increased as a net loss in 2016 and generated net gains in 2015 and 2014.
Marketing and Midstream Revenues and Operating Expensesresult of higher property value assessments, primarily on our Texas properties, partially offset by our U.S. non-core divestitures.
|
| 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 |
|
Marketing Operations |
2016 vs. 2015
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Marketing revenues |
| $ | 4,449 |
|
| $ | 3,571 |
|
|
| +25 | % |
Marketing expenses |
|
| (4,363 | ) |
|
| (3,619 | ) |
|
| - 21 | % |
Margin |
| $ | 86 |
|
| $ | (48 | ) |
|
| +279 | % |
30
The overall decreaseincrease in marketing and midstreamoperating margin during 2016 was primarily due to lower margins on Devon’s downstream marketing commitments, offset by EnLink’s margin growth largely related to its acquisition activity in late 2015 and the first quarter of 2016. We anticipate the margins on Devon’s downstream marketing commitments to continue to negatively impact our marketing and midstream margins into 2017.
35
2015 vs. 2014 Marketing and midstream operating profit changes were largely driven by a decrease in Devon’s marketing activities due to a decrease inimproved commodity prices. These declinesprices, which were partially offset by a full year of EnLink’s legacy asset operations compared to prior year and facility expansions coming online in late 2014, along with assets acquired during 2015.
Asset Dispositions and Other
During 2016, we recognized gains of $1.9 billion in conjunction with the non-core U.S. upstream asset divestitures and the divestitureimpact of our 50% interestdownstream marketing commitments.
Exploration Expenses |
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Unproved impairments |
| $ | 95 |
|
| $ | 217 |
|
|
| - 56 | % |
Geological and geophysical |
|
| 21 |
|
|
| 110 |
|
|
| - 81 | % |
Exploration overhead and other |
|
| 61 |
|
|
| 53 |
|
|
| +15 | % |
Total |
| $ | 177 |
|
| $ | 380 |
|
|
| - 53 | % |
Unproved impairments in both periods primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs decreased primarily in the Access PipelineSTACK and Delaware Basin.
Depreciation, Depletion and Amortization |
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 7.98 |
|
| $ | 7.15 |
|
|
| +12 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas |
| $ | 1,559 |
|
| $ | 1,419 |
|
|
| +10 | % |
Other property and equipment |
|
| 99 |
|
|
| 110 |
|
|
| - 10 | % |
Total |
| $ | 1,658 |
|
| $ | 1,529 |
|
|
| +8 | % |
Our oil and gas DD&A increased primarily due to continued development in Canada. During 2014,the STACK, Delaware Basin and Rockies properties. The increases were slightly offset by reduced production volumes at the Jackfish facilities and from our 2018 U.S. non-core asset divestitures.
General and Administrative Expenses |
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Labor and benefits |
| $ | 494 |
|
| $ | 582 |
|
|
| - 15 | % |
Non-labor |
|
| 236 |
|
|
| 228 |
|
|
| +4 | % |
Reimbursed G&A |
|
| (80 | ) |
|
| (73 | ) |
|
| - 10 | % |
Total Devon |
| $ | 650 |
|
| $ | 737 |
|
|
| - 12 | % |
Labor and benefits decreased primarily as a result of the workforce reduction that occurred during 2018 as discussed in conjunction with the divestitureNote 6 in “Item 8. Financial Statements and Supplementary Data” of certain Canadian properties, we recognized gainsthis report. Non-labor costs were higher due to an increase in costs related to automation and process improvements.
Financing Costs, net |
Financing costs, net increased $277 million as a result of $1.1 billion.a $312 million loss on early retirement of debt. For further discussion of early retirement premiums and reduced interest expense resulting from our lower debt balances, see Note 215 in
“Item 8. Financial Statements and Supplementary Data” of this report.
Other |
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Asset impairments |
| $ | 156 |
|
| $ | — |
|
| N/M |
| |
Asset dispositions |
|
| (263 | ) |
|
| (217 | ) |
|
| - 21 | % |
Restructuring |
|
| 114 |
|
|
| — |
|
| N/M |
| |
Other |
|
| 140 |
|
|
| (83 | ) |
|
| +269 | % |
Total |
| $ | 147 |
|
| $ | (300 | ) |
|
| +149 | % |
Additional information regarding the impairments is discussed in Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.
Lease Operating Expenses
We recognized gains in conjunction with certain of our U.S. asset dispositions in 2017 and 2018. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2018, we recognized restructuring and transaction costs of $114 million primarily as a result of our workforce reduction. See Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
The remaining change in other expense was driven primarily by changes on foreign currency exchange instruments as further discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
|
| 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 |
|
Income Taxes |
|
| 2018 |
|
| 2017 |
| ||
Current expense (benefit) |
| $ | (70 | ) |
| $ | 112 |
|
Deferred expense (benefit) |
|
| 226 |
|
|
| (97 | ) |
Total expense |
| $ | 156 |
|
| $ | 15 |
|
Effective income tax rate |
|
| 17 | % |
|
| 2 | % |
2016 vs. 2015 LOEFor discussion on income taxes, see Note 8 in “Item 8. Financial Statements and LOE per Boe decreased during 2016Supplementary Data” of this report.
Discontinued Operations |
Discontinued operations net earnings increased primarily due to the gain on the sale of our well optimizationaggregate ownership interests in EnLink and cost reduction initiatives, as well asthe General Partner of $2.6 billion ($2.2 billion after-tax). For discussion on discontinued operations, see Note 19 in “Item 8. Financial Statements and Supplementary Data” of this report” of this report.
31
Results of Operations – 2017 vs. 2016
The graph below shows the change in net earnings from 2016 to 2017. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
(1) | Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses. |
The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.
32
Upstream Operations |
Oil, Gas and NGL Production
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
| ||||
Oil and bitumen (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 29 |
|
|
| 12 | % |
|
| 32 |
|
|
| - 7 | % |
STACK |
|
| 25 |
|
|
| 11 | % |
|
| 18 |
|
|
| +39 | % |
Rockies Oil |
|
| 10 |
|
|
| 4 | % |
|
| 9 |
|
|
| +9 | % |
Heavy Oil |
|
| 18 |
|
|
| 7 | % |
|
| 22 |
|
|
| - 19 | % |
Eagle Ford |
|
| 34 |
|
|
| 14 | % |
|
| 39 |
|
|
| - 14 | % |
Barnett Shale |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| - 25 | % |
Other |
|
| 5 |
|
|
| 2 | % |
|
| 6 |
|
|
| - 13 | % |
Retained assets |
|
| 122 |
|
|
| 50 | % |
|
| 127 |
|
|
| - 4 | % |
U.S. divested assets |
|
| 12 |
|
|
| 5 | % |
|
| 24 |
|
|
| - 51 | % |
Total Oil |
|
| 134 |
|
|
| 55 | % |
|
| 151 |
|
|
| - 11 | % |
Bitumen |
|
| 110 |
|
|
| 45 | % |
|
| 109 |
|
|
| +1 | % |
Total Oil and bitumen |
|
| 244 |
|
|
| 100 | % |
|
| 260 |
|
|
| - 6 | % |
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 86 |
|
|
| 7 | % |
|
| 86 |
|
|
| +1 | % |
STACK |
|
| 294 |
|
|
| 24 | % |
|
| 282 |
|
|
| +4 | % |
Rockies Oil |
|
| 8 |
|
|
| 1 | % |
|
| 16 |
|
|
| - 48 | % |
Heavy Oil |
|
| 17 |
|
|
| 2 | % |
|
| 20 |
|
|
| - 14 | % |
Eagle Ford |
|
| 95 |
|
|
| 8 | % |
|
| 101 |
|
|
| - 6 | % |
Barnett Shale |
|
| 475 |
|
|
| 39 | % |
|
| 530 |
|
|
| - 10 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| - 10 | % |
Retained assets |
|
| 976 |
|
|
| 81 | % |
|
| 1,036 |
|
|
| - 6 | % |
U.S. divested assets |
|
| 227 |
|
|
| 19 | % |
|
| 377 |
|
|
| - 40 | % |
Total |
|
| 1,203 |
|
|
| 100 | % |
|
| 1,413 |
|
|
| - 15 | % |
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 10 |
|
|
| 10 | % |
|
| 11 |
|
|
| - 10 | % |
STACK |
|
| 30 |
|
|
| 30 | % |
|
| 25 |
|
|
| +19 | % |
Rockies Oil |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| +23 | % |
Eagle Ford |
|
| 13 |
|
|
| 13 | % |
|
| 16 |
|
|
| - 19 | % |
Barnett Shale |
|
| 31 |
|
|
| 32 | % |
|
| 34 |
|
|
| - 9 | % |
Other |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 4 | % |
Retained assets |
|
| 86 |
|
|
| 87 | % |
|
| 88 |
|
|
| - 3 | % |
U.S. divested assets |
|
| 13 |
|
|
| 13 | % |
|
| 28 |
|
|
| - 53 | % |
Total |
|
| 99 |
|
|
| 100 | % |
|
| 116 |
|
|
| - 15 | % |
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 54 |
|
|
| 10 | % |
|
| 57 |
|
|
| - 6 | % |
STACK |
|
| 104 |
|
|
| 19 | % |
|
| 90 |
|
|
| +15 | % |
Rockies Oil |
|
| 12 |
|
|
| 2 | % |
|
| 13 |
|
|
| - 3 | % |
Heavy Oil |
|
| 131 |
|
|
| 24 | % |
|
| 134 |
|
|
| - 2 | % |
Eagle Ford |
|
| 62 |
|
|
| 11 | % |
|
| 72 |
|
|
| - 13 | % |
Barnett Shale |
|
| 111 |
|
|
| 21 | % |
|
| 123 |
|
|
| - 10 | % |
Other |
|
| 7 |
|
|
| 1 | % |
|
| 8 |
|
|
| - 6 | % |
Retained assets |
|
| 481 |
|
|
| 88 | % |
|
| 497 |
|
|
| - 3 | % |
U.S. divested assets |
|
| 62 |
|
|
| 12 | % |
|
| 114 |
|
|
| - 45 | % |
Total |
|
| 543 |
|
|
| 100 | % |
|
| 611 |
|
|
| - 11 | % |
Production declines reduced our non-core oil and gas property divestitures. On an absolute dollar basis, LOE decreased approximately $200upstream revenues by $427 million primarily as a result of our U.S. upstream divestitures,divested assets. Retained production volumes decreased due to reduced completion activity in the Eagle Ford and we anticipate realizing approximately $100 millionnatural production declines in additional LOE savingsthe Barnett Shale. These decreases were partially offset by expanded drilling and performance in 2017the STACK.
Oil, Gas and NGL Prices
|
| 2017 |
|
| Realization |
|
| 2016 |
|
| Change |
| ||||
Oil and bitumen (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 50.99 |
|
|
|
|
|
| $ | 43.36 |
|
|
| +18 | % |
Access Western Blend index |
| $ | 36.90 |
|
|
|
|
|
| $ | 26.96 |
|
|
| +37 | % |
U.S. |
| $ | 49.41 |
|
|
| 97% |
|
| $ | 38.92 |
|
|
| +27 | % |
Canada |
| $ | 29.99 |
|
|
| 59% |
|
| $ | 20.53 |
|
|
| +46 | % |
Realized price, unhedged |
| $ | 39.23 |
|
|
| 77% |
|
| $ | 29.65 |
|
|
| +32 | % |
Cash settlements |
| $ | 0.23 |
|
|
|
|
|
| $ | (0.43 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 39.46 |
|
|
| 77% |
|
| $ | 29.22 |
|
|
| +35 | % |
|
| 2017 |
|
| Realization |
|
| 2016 |
|
| Change |
| ||||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 3.11 |
|
|
|
|
|
| $ | 2.46 |
|
|
| +26 | % |
Realized price, unhedged |
| $ | 2.48 |
|
|
| 80% |
|
| $ | 1.84 |
|
|
| +35 | % |
Cash settlements |
| $ | 0.08 |
|
|
|
|
|
| $ | 0.07 |
|
|
|
|
|
Realized price, with hedges |
| $ | 2.56 |
|
|
| 82% |
|
| $ | 1.91 |
|
|
| +34 | % |
|
| 2017 |
|
| Realization |
|
| 2016 |
|
| Change |
| ||||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 24.77 |
|
|
|
|
|
| $ | 17.20 |
|
|
| +44 | % |
Realized price, unhedged |
| $ | 15.66 |
|
|
| 63% |
|
| $ | 9.81 |
|
|
| +60 | % |
Cash settlements |
| $ | (0.10 | ) |
|
|
|
|
| $ | (0.11 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 15.56 |
|
|
| 63% |
|
| $ | 9.70 |
|
|
| +60 | % |
(1) | Based upon composition of average Devon NGL barrel. |
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 24.88 |
|
| $ | 18.34 |
|
|
| +36 | % |
Canada |
| $ | 29.39 |
|
| $ | 20.07 |
|
|
| +46 | % |
Realized price, unhedged |
| $ | 25.96 |
|
| $ | 18.72 |
|
|
| +39 | % |
Cash settlements |
| $ | 0.27 |
|
| $ | (0.05 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 26.23 |
|
| $ | 18.67 |
|
|
| +40 | % |
33
Upstream revenues increased $1.4 billion as a result of these divestitures. Ourhigher unhedged, realized prices across our entire portfolio. The increase in oil and bitumen sales primarily resulted from higher average WTI crude index prices, which were 18% higher in 2017. Additionally, our oil and bitumen sales benefited from tighter differentials to the WTI index. The increase in gas sales was driven by higher North American regional index prices upon which our gas sales are based and higher NGL prices at the Mont Belvieu, Texas hub.
Commodity Derivatives
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
|
| Q |
|
|
|
|
|
|
|
|
| |
Oil |
| $ | 21 |
|
| $ | (41 | ) |
|
| +151 | % |
Natural gas |
|
| 35 |
|
|
| 35 |
|
|
| +0 | % |
NGL |
|
| (3 | ) |
|
| (5 | ) |
|
| +40 | % |
Total cash settlements |
|
| 53 |
|
|
| (11 | ) |
| N/M |
| |
Valuation changes |
|
| 104 |
|
|
| (190 | ) |
|
| +155 | % |
Total |
| $ | 157 |
|
| $ | (201 | ) |
|
| +178 | % |
Production Expenses
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
LOE |
| $ | 927 |
|
| $ | 1,027 |
|
|
| - 10 | % |
Gathering, processing & transportation |
|
| 647 |
|
|
| 555 |
|
|
| +17 | % |
Production taxes |
|
| 194 |
|
|
| 149 |
|
|
| +30 | % |
Property taxes |
|
| 55 |
|
|
| 74 |
|
|
| - 26 | % |
Total |
| $ | 1,823 |
|
| $ | 1,805 |
|
|
| +1 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 4.67 |
|
| $ | 4.59 |
|
|
| +2 | % |
Gathering, processing & transportation |
| $ | 3.26 |
|
| $ | 2.48 |
|
|
| +31 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 3.8 | % |
|
| 3.5 | % |
|
| +7 | % |
LOE decreased $100 million primarily due to our U.S. property divestitures in 2016. Well optimization and cost reduction initiatives across our portfolio offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers. These cost savings were partially offset by $28
Gathering and transportation expense increased $92 million primarily due to a full year of the Access Pipeline transportation tolls, which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in Access.the pipeline. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $110 million annually.
2015 vs. 2014 LOE per Boe decreased during 2015 primarily as a result of higher Jackfish 3 volumes, our well optimization and cost reduction initiatives, lower royalties and changes in the Canadian to U.S. foreign exchange rate. As Canadian royalties decrease, our net production volumes increase, causing improvements to our per-unit operating costs. The flat U.S. rate is primarily related to our 2014 non-core natural gas asset divestitures and our oil production growth, where projects generate higher margins but generally require a higher cost to produce per unit than our retained and divested gas projects.
36
General and Administrative Expenses
|
| Year Ended December 31, |
| |||||||||||||||||
|
| 2016 |
|
| Change |
|
| 2015 |
|
| Change |
|
| 2014 |
| |||||
|
| (Millions) |
| |||||||||||||||||
Gross G&A |
| $ | 853 |
|
|
| - 30 | % |
| $ | 1,210 |
|
|
| - 5 | % |
| $ | 1,272 |
|
Capitalized G&A |
|
| (244 | ) |
|
| - 34 | % |
|
| (372 | ) |
|
| - 1 | % |
|
| (376 | ) |
Reimbursed G&A |
|
| (82 | ) |
|
| - 32 | % |
|
| (120 | ) |
|
| - 18 | % |
|
| (146 | ) |
Devon Net G&A |
|
| 527 |
|
|
| - 27 | % |
|
| 718 |
|
|
| - 4 | % |
|
| 750 |
|
EnLink Net G&A |
|
| 118 |
|
|
| - 14 | % |
|
| 137 |
|
|
| +41 | % |
|
| 97 |
|
Net G&A |
| $ | 645 |
|
|
| - 25 | % |
| $ | 855 |
|
|
| +1 | % |
| $ | 847 |
|
2016 vs. 2015 Gross G&A and capitalized G&A decreased during 2016 largely due to lower Devon employee costs resulting from workforce reductions, as discussed in 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.
2015 vs. 2014 Gross G&A decreased during 2015 largely because of a lower employee performance bonus pool and our cost reduction initiatives. Furthermore, $22 million in one-time costs related to the EnLink and GeoSouthern transactions contributed to higher costs in the first quarter of 2014. Reimbursed G&A decreased subsequent to our 2014 asset divestitures. EnLink G&A increased primarily due to a workforce increase associated with EnLink’s 2015 acquisitions.
Production and Property 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 decreasedincreased on an absolute dollar basis primarily due to the decreaseincrease in our U.S. upstream revenues, on which the majority of our production taxes are assessed. Furthermore, property and other
Property taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. non-coreasset 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.
Exploration Expenses |
2015 vs. 2014 Production taxes decreased during 2015
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
Unproved impairments |
| $ | 217 |
|
| $ | 77 |
|
|
| +182 | % |
Geological and geophysical |
|
| 110 |
|
|
| 65 |
|
|
| +70 | % |
Exploration overhead and other |
|
| 53 |
|
|
| 73 |
|
|
| - 27 | % |
Total |
| $ | 380 |
|
| $ | 215 |
|
|
| +77 | % |
Unproved impairments primarily becauserelate to a portion of a decreaseacreage in our U.S. revenues, onnon-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs increased primarily in the majority of our production taxes are assessed.
37
Depreciation, DepletionSTACK and AmortizationDelaware Basin.
|
| 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 |
|
Depreciation, Depletion and Amortization |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||
Oil and gas per Boe |
| $ | 7.15 |
|
| $ | 6.47 |
|
|
| +11 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and gas |
| $ | 1,419 |
|
| $ | 1,446 |
|
|
| - 2 | % | |
Other property and equipment |
|
| 110 |
|
|
| 146 |
|
|
| - 25 | % | |
Total |
| $ | 1,529 |
|
| $ | 1,592 |
|
|
| - 4 | % | |
A description of how DD&A of ourOur oil and gas properties is calculated is includedDD&A remained relatively flat as compared to the prior year. Increases in Note 1 in “Item 8. Financial Statementsoil and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, thegas DD&A rate per unit of production will change inversely. However, when the depletable base changes, the DD&A rate movesrates due to continued development in the same direction. The per unit DD&A rate is not affectedSTACK and Delaware Basin were offset by reduced production volumes. Absolute or total DD&A, as opposed tovolumes resulting from the rate per unit of production, generally moves in the same direction as production volumes.
2016 vs. 2015U.S. asset divestitures. DD&A from our oilother property and gas propertiesequipment decreased largely becausedue to the divestiture of the significant asset impairments recognized throughout 2015 andAccess Pipeline in the fourth quarter of 2016. For discussion of asset impairments, see Note 5 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.
38
|
| 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 |
|
Financing Costs, net |
2016 vs. 2015 Net financingFinancing costs, increased during 2016net decreased $400 million primarily as a result of theour $2.1 billion early debt retirement in 2016. For further discussion of early retirement premiums and costs related to early redemptions of senior notes in 2016, which is further discussed in reduced interest expense resulting from our lower debt balances, see 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 715 in “Item 8. Financial Statements and Supplementary Data” of this report.
Other |
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
Asset impairments |
| $ | — |
|
| $ | 437 |
|
|
| - 100 | % |
Asset dispositions |
|
| (217 | ) |
|
| (1,496 | ) |
|
| +85 | % |
Restructuring |
|
| — |
|
|
| 261 |
|
|
| - 100 | % |
Other |
|
| (83 | ) |
|
| 101 |
|
|
| - 183 | % |
Total |
| $ | (300 | ) |
| $ | (697 | ) |
|
| +57 | % |
39In 2016, we recognized proved asset impairments on a portion of our U.S. assets. See Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report for additional information.
34
We recognized gains in conjunction with certain of our asset dispositions in both 2016 and 2017 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, we recognized restructuring and transaction costs of $261 million primarily as a result of our workforce reduction. 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.
The remaining change in other expense was driven primarily by changes on foreign currency exchange instruments, as further discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
Income Taxes |
|
| 2017 |
|
| 2016 |
| ||
Current expense |
| $ | 112 |
|
| $ | 98 |
|
Deferred expense (benefit) |
|
| (97 | ) |
|
| 43 |
|
Total expense |
| $ | 15 |
|
| $ | 141 |
|
Effective income tax rate |
|
| 2 | % |
|
| (33 | %) |
For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.
Discontinued Operations |
For discussion on discontinued operations, see Note 19 in “Item 8. Financial Statements and Supplementary Data” of this report.
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, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Operating cash flow from continuing operations |
| $ | 2,228 |
|
| $ | 2,209 |
|
| $ | 834 |
|
Divestitures of property and equipment |
|
| 1,013 |
|
|
| 426 |
|
|
| 3,020 |
|
Capital expenditures |
|
| (2,451 | ) |
|
| (1,968 | ) |
|
| (1,384 | ) |
Acquisitions of property and equipment |
|
| (55 | ) |
|
| (46 | ) |
|
| (849 | ) |
Debt activity, net |
|
| (1,226 | ) |
|
| — |
|
|
| (3,383 | ) |
Repurchases of common stock |
|
| (2,956 | ) |
|
| — |
|
|
| — |
|
Common stock dividends |
|
| (149 | ) |
|
| (127 | ) |
|
| (221 | ) |
Issuance of common stock |
|
| — |
|
|
| — |
|
|
| 1,469 |
|
Effect of exchange rate and other |
|
| 151 |
|
|
| (53 | ) |
|
| (96 | ) |
Net change in cash, cash equivalents and restricted cash from discontinued operations |
|
| 3,207 |
|
|
| 284 |
|
|
| 259 |
|
Net change in cash, cash equivalents and restricted cash |
| $ | (238 | ) |
| $ | 725 |
|
| $ | (351 | ) |
Cash, cash equivalents and restricted cash at end of period |
| $ | 2,446 |
|
| $ | 2,684 |
|
| $ | 1,959 |
|
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2016.2018. Our operating cash flow decreased $3.6 billion, or 68%, during 2016. Throughout 2015,was relatively flat compared to 2017. In 2018, 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 funded approximately 86% of our capital expenditure program and dividends. We utilized available cash balances and divestiture proceeds to supplement our operating cash flows. Operating cash flow for 2018 included a realized foreign exchange loss of $241 million relating to foreign currency denominated intercompany loan activity as described in 2016. The remainderNote 7 in “Item 8. Financial Statements and Supplementary Data” of this report. There was an offset in the decrease is primarily relatedeffect of exchange rate and other line in the above table, resulting in no impact to the continued decreasenet change in commodity prices, partially offset by our focused cost initiatives. cash, cash equivalents and restricted cash.
Our operating cash flow decreased 10% during 2015 primarily dueincreased $1.4 billion, or 165%, from 2016 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 with2017. In 2017, our commodity derivatives during 2015.
Excluding payments made for acquisitions, our consolidated operating cash flow fully funded 75%, 100%our capital expenditures program as well as our dividends. In 2016, our operating cash flow did not fully fund our capital requirements and 86%dividends; as a result, we utilized available cash balances and divestiture proceeds to supplement our operating cash flows.
35
Divestitures of Property and Investments
During 2018, as part of our announced divestiture program, we sold non-core U.S. upstream assets for approximately $1.0 billion. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2017, as part of our announced divestiture program, we sold non-core U.S. upstream assets for approximately $420 million. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, we divested certain non-core upstream assets in the U.S. and our 50% interest in the Access Pipeline in Canada for approximately $3.0 billion, net of purchase price adjustments. Proceeds from these divestitures were used primarily for debt repayment and to support capital investment in our core resource plays. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
We did not have significant current cash income taxes resulting from the divestitures in 2018, 2017 and 2016.
Capital Expenditures
The following table summarizes our capital expenditures and property acquisitions.
|
| Year ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Oil and gas |
| $ | 2,395 |
|
| $ | 1,879 |
|
| $ | 1,341 |
|
Corporate and other |
|
| 56 |
|
|
| 89 |
|
|
| 43 |
|
Total capital expenditures |
| $ | 2,451 |
|
| $ | 1,968 |
|
| $ | 1,384 |
|
Acquisitions |
| $ | 55 |
|
| $ | 46 |
|
| $ | 849 |
|
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations and other corporate activities. The vast majority of our capital expenditures during 2016, 2015are for the acquisition, drilling and 2014, respectively. In 2016, 2015development of oil and 2014, leveraging our liquiditygas properties. Our capital program is designed to operate within or near operating cash flow and may fluctuate with changes to commodity prices and other factors impacting cash flow. This is evidenced by our operating cash flow funding approximately 91% of capital resources,expenditures in 2018 and fully funding capital expenditures in 2017.
Acquisition costs in 2016 primarily consisted of Devon’s bolt-on acquisition of assets in the STACK play for $1.5 billion. Approximately $849 million was paid in cash at closing with the remainder of the purchase price funded with equity consideration. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report for more information.
Debt Activity, Net
During 2018, our debt decreased $922 million due to completed tender offers of certain long-term debt as well as the maturity of certain senior notes. In conjunction with the tender offers, we also usedrecognized a $312 million loss on the early retirement of debt, including $304 million of cash balances,retirement costs and fees. For additional information, see Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, our debt decreased $3.1 billion 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. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt, proceedsincluding $265 million of cash retirement costs and fees. For additional information, see Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report.
Repurchases of Common Stock and Shareholder Distributions
In June 2018, in conjunction with the announcement of the divestiture of our investment in EnLink and the General Partner, our Board of Directors authorized a $4.0 billion share repurchase program of our common stock. The share repurchase program expires December 31, 2019. As discussed further in Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report, we repurchased 78.1 million shares of common stock for $3.0 billion, or $38.11 per share, under the ASR agreement and through open-market share repurchases through December 31, 2018.
36
Devon paid common stock dividends of $149 million, $127 million and $221 million during 2018, 2017 and 2016, respectively. During the second quarter of 2018, we increased our quarterly dividend 33% to $0.08 per share as part of our initiative to return cash to shareholders. Our prior quarterly dividend was $0.06 per share subsequent to a reduction from EnLink transactions$0.24 per share in the second quarter of 2016 due to the depressed commodity price environment. For additional information, see Note 18 in “Item 8. Financial Statements and divestiture proceeds to fund our acquisitions, dividends and capital requirements.Supplementary Data” of this report.
Issuance of Common Stock
In February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.
40
Table of ContentsCash Flows from Discontinued Operations
Divestitures of Property and Equipment
During 2016, we divested certain non-core upstream assetsAll cash flows in the U.S.following table relate to activities of EnLink 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. 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 ExpendituresGeneral Partner.
|
| 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, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Cash flows from discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
| $ | 476 |
|
| $ | 700 |
|
| $ | 666 |
|
Capital expenditures and other |
|
| (556 | ) |
|
| (801 | ) |
|
| (1,381 | ) |
Divestitures of investments |
|
| 3,104 |
|
|
| 190 |
|
|
| — |
|
Investing activities |
|
| 2,548 |
|
|
| (611 | ) |
|
| (1,381 | ) |
Debt activity, net |
|
| 347 |
|
|
| 2 |
|
|
| 228 |
|
Issuance of subsidiary units |
|
| 1 |
|
|
| 501 |
|
|
| 892 |
|
Distributions to noncontrolling interests |
|
| (217 | ) |
|
| (354 | ) |
|
| (304 | ) |
Other |
|
| 52 |
|
|
| 46 |
|
|
| 158 |
|
Financing activities |
|
| 183 |
|
|
| 195 |
|
|
| 974 |
|
Net change in cash, cash equivalents and restricted cash of discontinued operations |
| $ | 3,207 |
|
| $ | 284 |
|
| $ | 259 |
|
Capital expenditures consistOperating cash flow in 2018 decreased $224 million and $190 million from 2017 and 2016, respectively, as a result of amounts related to our oil and gas exploration and development operations, our midstream operations, other corporate activities and EnLink growth and maintenance activities. The vast majoritythe divestiture of our aggregate ownership interests in EnLink and the General Partner in July 2018.
Cash flows from investing activities for 2018 includes $3.125 billion received from the divestiture of our aggregate ownership interests in EnLink and the General Partner, partially offset by capital expenditures are for the acquisition, drilling and development of oil and gas properties. In response to our lower operating cash flow, Devon’s 2016 capital program was designed to be lower than 2015. This change is evidenced by a 56% decrease in total capital expenditures from 2015 to 2016, excluding acquisitions. Since 2014, we have reduced our capital expenditures by approximately 70%.
other items. Capital expenditures for Devon’s and EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. Midstream capital expenditures are largely impacted by oil and gas drilling and development activities.
Acquisition capitalDuring 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. During 2016, primarily consisted of Devon’s bolt-on acquisition of assets in the STACK play for $1.5 billion and EnLink’s acquisition ofEnLink acquired Anadarko Basin gathering and processing midstream assets for $1.5 billion. Approximately $849 million and $792 million respectively, was paid in cash at the closingsclosing with the remainder of the purchase pricesprice funded with equity consideration and debt. In 2015 our acquisition activity primarily consisted
Cash flows from financing activities includes common and preferred units EnLink issued and sold during 2017 and 2016 generating net proceeds of the Powder River Basin asset acquisitionapproximately $501 million and $892 million, respectively. Distributions to noncontrolling interests in the fourth quarter. The majority oftable above exclude the acquisition capital in 2014 related to the GeoSouthern acquisition in the Eagle Ford. EnLink’s acquisitions in 2015 and 2014 consisted of additional oil and gas pipeline assets, including gathering, transportation and processing facilities. For further discussion on acquisition activity, see Note 2 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
offset by $229 million of net borrowings from EnLink. For additional information, see Note 14 in “Item 8. Financial Statements and Supplementary Data” in this report.
During 2015, our consolidated net debt increased $1.8 billion. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter. EnLink’s net debt borrowings increased $1.1 billion primarily from borrowings made to fund acquisitions and dropdowns.
During 2014, we decreased our net debt by $2.2 billion. The decrease was primarily related to the repayment of debt used to fund the GeoSouthern transaction. This was partially offset by $555 million of net borrowings from EnLink to fund its operations.
Shareholder and Noncontrolling Interests Distributions
The following table summarizes our common stock dividends.
| Amounts |
|
| Rate |
| ||
| (Millions) |
|
| (Per Share) |
| ||
Year Ended 2016: |
|
|
|
|
|
|
|
First quarter 2016 | $ | 125 |
|
| $ | 0.24 |
|
Second quarter 2016 |
| 33 |
|
| $ | 0.06 |
|
Third quarter 2016 |
| 32 |
|
| $ | 0.06 |
|
Fourth quarter 2016 | 31 |
|
| $ | 0.06 |
| |
Total year-to-date | $ | 221 |
|
|
|
|
|
Year Ended 2015: |
|
|
|
|
|
|
|
First quarter 2015 | $ | 99 |
|
| $ | 0.24 |
|
Second quarter 2015 |
| 98 |
|
| $ | 0.24 |
|
Third quarter 2015 |
| 99 |
|
| $ | 0.24 |
|
Fourth quarter 2015 |
| 100 |
|
| $ | 0.24 |
|
Total year-to-date | $ | 396 |
|
|
|
|
|
Year Ended 2014: |
|
|
|
|
|
|
|
First quarter 2014 | $ | 90 |
|
| $ | 0.22 |
|
Second quarter 2014 |
| 99 |
|
| $ | 0.24 |
|
Third quarter 2014 |
| 98 |
|
| $ | 0.24 |
|
Fourth quarter 2014 |
| 99 |
|
| $ | 0.24 |
|
Total year-to-date | $ | 386 |
|
|
|
|
|
In response to the depressed commodity price environment, we reduced our quarterly dividend to $0.06 per share 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,distributions EnLink and the General Partner distributed $304 million, $254 million and $135 millionpaid to non-Devon unitholders during 2016, 2015 and 2014, respectively.
EnLink and General PartnerDevon, which have been eliminated in consolidation. Distributions
Devon received $265 million, $268 million and $158 million in distributions from EnLink Enlink and the General Partner paid to Devon were $134 million, $265 million and $265 million during 2016, 20152018, 2017 and 2014,2016, respectively.
42Liquidity
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.
37
In the second quarter of 2015, Devon received $167 million in cash from EnLink in exchange for VEX. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
Issuance of Subsidiary Units
In January 2016, to fund a portion of the cash consideration of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction.
During 2016, 2015 and 2014, 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, generating net proceeds of approximately $167 million, $25 million and $410 million, respectively.
Sale of Subsidiary Units
In early 2015, we conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.
Effect of Exchange Rate and Other
In 2016, EnLink received contributions from noncontrolling interests. For further discussion see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
Liquidity
Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds and cash on hand.proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidity include, among other things, If needed, we can also issue debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well asSEC. In February 2019, we also announced plans to separate our Canadian and Barnett Shale assets and operations. We expect to complete these asset separations in 2019. We plan to use the sale of a portion of ourproceeds from these transactions for debt repayments and 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.share repurchases. 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 2018, we held approximately $2.4 billion of cash. 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. AsFor illustration, our operating cash flow slightly increased in 2018 largely due to 16% growth from our retained U.S. liquids portfolio, as well as 32% higher realized pricing related to these assets. These increases were mostly offset by a result, entering into 2017significant decrease in our realized price for our bitumen production in 2018. Western Canadian Select basis differentials widened significantly above historical norms due to robust production outpacing local demand, pipeline capacity and rail capacity out of the region. The market fundamentals led our fourth quarter unhedged realized price for bitumen to be near $0 per Bbl. In the first two months of 2019, government-mandated production curtailments and current market fundamentals have led to a significant improvement in the Western Canadian Select basis differential.
To mitigate some of the risk inherent in prices, we have hedgedutilize various derivative financial instruments to protect a portion of our production against downside price risk. We target hedging approximately 50% of our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. We currently have approximately 50% of our anticipated 2019 oil and 45%gas volumes hedged, and we are adding hedges for 2020 as well. Further insulating our cash flow, we are proactively locking in hedges on the Western Canada Select basis differential to WTI and currently have approximately 50% of our gas production.2019 Canadian heavy oil production hedged. The key
43
terms to our oil, gas and NGL derivative financial instruments as of December 31, 20162018 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 at $46/Bbl WTI and $3.00/Mcf Henry Hub. Should WTI drop closer to $40/Bbl for an extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI/Bbl rises above $46, 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 – OurFor 2019, we expect to aggressively optimize our cost structure in conjunction with our planned Canadian and Barnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with the retained business and reduce outstanding debt. We anticipate the planned $780 million reduction of annualized costs will occur over three years, with roughly 70% of the savings delivered by the end of 2019. Approximately 40% of the reduced costs relate to our capital programs and the remainder relates to our operating cash flow can also be impacted byexpenses, including G&A, interest rate fluctuations. As of December 31, 2016, we had total debt of $10.2 billion. Of this amount, $10.0 billion bears fixed interest rates averaging 5.3%,expense and approximately $150 million is comprised of floating rate debt with interest rates averaging 2.5%.
As of December 31, 2016, we had open interest rate swap positions that are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” in this report.production expenses.
Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.
As recent years indicate, we have a history38
Table of investing more than 100%Contents
Divestitures of our operating cash flow into capital development activities to grow our companyProperty and maximize value for our shareholders. Therefore, negative movements in any 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. Equipment
In the current environment, assuming current pricing expectations,first quarter of 2019, we sold non-core assets for approximately $300 million. We also anticipate separating our 2017 explorationCanadian 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. IncludedBarnett Shale businesses from our Company 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.2019.
Credit Availability
We have a $3.0 billion Senior Credit Facility. The maturity date for $30 million of theOur 2018 Senior Credit Facility, isunder which we have $2.9 billion of available borrowing capacity at December 31, 2018, matures on October 24, 2017. The5, 2023, with the option to extend the maturity date for $164 million of theby two additional one-year periods subject to lender consent. The 2018 Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2016,2018, there were no borrowings under our commercial paper program. See Note 1415 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.
The 2018 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, 2016,2018, we were in compliance with this covenant. Ourcovenant with a 21.0% 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 2018 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.
In January 2019, we repaid the $162 million of 6.30% senior notes at maturity with cash on hand.
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+ with a negative outlook tois BBB with a stable outlook, andoutlook. Our credit rating from Fitch is BBB+ with a stable outlook. 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 February 2019, our Board of Directors increased our share repurchase program by an additional $1 billion. The $5 billion share repurchase program expires December 31, 2019. Through February 15, 2019, we have executed $3.4 billion of the authorized program.
39
Capital Expenditures
Excluding EnLink, our 2017 capital expenditures areOur 2019 exploration and development budget is expected to range from $2.3 billion to $2.7 billion, includingbe approximately $2.0 billion to $2.3$2.25 billion, forincluding capital associated with our explorationCanadian 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.Barnett Shale upstream assets.
EnLink Liquidity
EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2016, there were $12 million 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.
45
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, 2016.2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 |
| |||||
Devon obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt (1) |
| $ | 6,011 |
|
| $ | 162 |
|
| $ | 500 |
|
| $ | 1,000 |
|
| $ | 4,349 |
|
Interest expense (2) |
|
| 4,951 |
|
|
| 317 |
|
|
| 623 |
|
|
| 535 |
|
|
| 3,476 |
|
Purchase obligations (3) |
|
| 1,248 |
|
|
| 541 |
|
|
| 707 |
|
|
| — |
|
|
| — |
|
Operational agreements (4) |
|
| 5,626 |
|
|
| 587 |
|
|
| 892 |
|
|
| 773 |
|
|
| 3,374 |
|
Asset retirement obligations (5) |
|
| 1,057 |
|
|
| 27 |
|
|
| 76 |
|
|
| 79 |
|
|
| 875 |
|
Drilling and facility obligations (6) |
|
| 445 |
|
|
| 274 |
|
|
| 133 |
|
|
| 22 |
|
|
| 16 |
|
Lease obligations (7) |
|
| 500 |
|
|
| 64 |
|
|
| 74 |
|
|
| 51 |
|
|
| 311 |
|
Other (8) |
|
| 295 |
|
|
| 32 |
|
|
| 78 |
|
|
| 27 |
|
|
| 158 |
|
Total obligations |
| $ | 20,133 |
|
| $ | 2,004 |
|
| $ | 3,083 |
|
| $ | 2,487 |
|
| $ | 12,559 |
|
(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 |
(3) | Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices. |
(4) | Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets. |
46
Index Approximately $1.9 billion relates to the transportation agreement we entered in 2016 in which we dedicated our thermal-oil acreage to the Access Pipeline for an initial term of 25 years following the divestment of our 50% interest in the Access Pipeline. For additional information, see Note 2 in “Item 8. Financial Statements
| 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 |
| Other |
Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 1920 in “Item 8. Financial Statements and Supplementary Data” of this report.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the
40
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 Comprehensive Statement of Earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2018, Devon had approximately $200 million of well costs suspended for more than one year, which largely pertain to its Pike Heavy Oil project. Stratigraphic testing has demonstrated reserves can be produced economically at Pike. However, this capital intensive, long-duration project remains unsanctioned by Devon and its 50% partner, which is the primary reason reserves have not been designated as proven at Pike. With no lease expiration at Pike in the near future, management continues to keep the Pike exploratory costs capitalized.
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, 2018, Devon had $1.2 billion of undeveloped leasehold and capitalized interest, which includes approximately $750 million related to Pike. Consistent with the evaluation above on suspended well costs, the costs for Pike continue to remain capitalized. Of the remaining undeveloped leasehold costs at December 31, 2018, approximately $10 million is scheduled to expire in 2019. The leasehold expiring in 2019 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 third-party petroleum consulting firms. In 2016,2018, 89% 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 quantitiesValuation of Long-Lived Assets
Long-lived assets used in operations, including 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
rules also dictate that a 10% discount factor be used. Therefore, the discounted future net revenues associated with the estimated 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 valuesare depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual
41
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 ourthe present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Besides the estimates of reserves and future oil, natural gas and NGL prices. Our estimates ofproduction volumes, future commodity prices are based onthe largest driver in the variability of undiscounted pre-tax cash flows. For our own analysis of pricing trends. These estimates are based on current data obtained with regard to regionalimpairment determinations, we generally utilize the forward strip prices for the first five years 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.
apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future prices to apply to the estimated reserve quantities acquired,capital 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 discountedby using a rate determined appropriate at the time of the business combination based upon ourmethod that correlates cost of capital.
We also apply these same general principlesmovements to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we considerprice movements similar to be an appropriate risk-weighting factor in each particular instance.
49
Indexrecent history. Changes to Financial Statements
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 valueany of these assets requires certain assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Due to be made regarding future quantities of commodities estimated to be processedsuppressed commodity prices in 2016, we recognized significant asset impairments. With generally higher pricing in 2017 and transported through these facilities and pipelines, as well as estimates of future expected prices and operating and capital costs.2018, we did not recognize material asset impairments.
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 asAs of OctoberDecember 31, for our test, we typically complete2018, the test in late December or early January as the October 31 market data used in our test becomes available. U.S. reporting unit had goodwill totaling $841 million.
We first assess theperform a qualitative factorsassessment 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.amount. If we determineour qualitative assessment determines 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 less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. As part of our qualitative assessment, we considered the general macroeconomic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers, and stock performance. If the qualitative assessment determines that a quantitative goodwill impairment test is required, then the fair value of each reporting unit is compared to itsthe carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. 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 by future commodity prices and volume expectations, operating margins and capital expenditures.
For theBased on our qualitative assessment as of 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 showed2018, it is not more likely than not that the fair value of eachthe U.S. reporting unit exceededis less than its carrying amount. Since our annual test for goodwill impairment on October 31, 2018 was performed, our stock price decreased 30% from October 31 to December 31. As such, we performed an updated assessment as of December 31, 2018 to determine if it is more likely than not that the fair value of our reporting unit is less than its carrying amount. Based on our qualitative assessment as of December 31, 2018, it is not more likely than not that the fair value of the U.S. reporting unit is less than its carrying value.
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 for EnLink’s reporting units in the first quarter 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 to commodity prices and discount rates. Through the analysis, a goodwill impairment loss of $473 million, $307 million and $93 million for EnLink’s Texas, General Partner and Crude and Condensate reporting units, respectively, was recognized in the first quarter of 2016.
As of March 31, 2016, the goodwill allocated to the Crude and Condensate reporting unit was fully impaired. Other than those mentioned above, no other goodwill impairment was identified or recorded for the remaining reporting units as a result of the interim goodwill assessment, as their estimated fair values were in excess of carrying values. However, the fair value of EnLink’s Texas and General Partner reporting units are not substantially in excess of their carrying value. The fair value of the Texas and General Partner reporting units approximates their carrying values after considering the impairment loss above, and as of December 31, 2016, $233 million and $1.1 billion 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 that the carrying value exceeds fair value. We would expect that a prolonged or sustained period of lower commodity prices would adversely affect the estimate of future operating results, which could result in future goodwill impairments for otherour U.S. reporting unitsunit due to the potential impact on the cash flows of our operations.
42
The impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.
Other Intangible 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.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. At the end of 2016 and 2015, we had deferred tax assets that largely resulted from the full cost impairments recognized throughout 2015 and 2016. As a result of our recent cumulative losses and our current realization assessment,2017, we recorded a 100% valuation allowance against our U.S. deferred tax assets. Upon closing the EnLink divestiture in the third quarter of 2018, Devon reassessed its position and determined that its U.S. segment is no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, as of December 31, 2016including certain tax credits and December 31, 2015. Further, in 2016, westate net operating losses. Devon also has recorded a $69 millionpartial valuation allowance against certain Canadian deferred tax assets asthat were generated by a result of continued financial losses.2017 Canadian legal entity restructuring.
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to 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.laws. 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;
51
| • | relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings; |
• | determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and |
• | further analysis of a variety of other inputs such as the earnings and 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. |
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.
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Non-GAAP Measures
Core Earnings
We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 20162018 Results” in this Item 7.7 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. 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. Additionally, we’ve presented our discontinued operations associated with the sale of our aggregate ownership interests in EnLink and the General Partner separately to show our results on a go-forward basis. For more information on the results of operations for EnLink and the General Partner, see Note 19 in “Item 8. Financial Statements and Supplementary Data” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appearAmounts excluded for 2018 relate to be recurring when comparingasset dispositions, the gain on an annual basis. In the table below,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 were incurred in each ofassociated with the three year periods; however, these costs relate2018 workforce reduction and settlements relating to different restructuring programs. minimum volume contract commitments.
Amounts excluded for 20162017 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, legal entity restructuring and costs associated with early retirement of debt.
Amounts excluded for 2016 relate to asset dispositions, noncash asset impairments (including an impairment of EnLink goodwill), including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig stacking costs, deferred tax asset valuation allowance, gains and losses on asset sales, costs associated with early retirement of debt and restructuring and transaction costs associated with the 2016 workforce reduction.
Amounts excluded for 2015 relate toreduction, derivatives and financial instrument fair value changes asset impairments (including an impairment of goodwill), deferred tax asset valuation allowance, 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. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.
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Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| ||||
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 920 |
|
| $ | 764 |
|
| $ | 764 |
|
| $ | 1.52 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (263 | ) |
|
| (202 | ) |
|
| (202 | ) |
|
| (0.41 | ) |
Asset and exploration impairments |
| 257 |
|
|
| 198 |
|
|
| 198 |
|
|
| 0.40 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| (42 | ) |
|
| (42 | ) |
|
| (0.08 | ) |
Early retirement of debt |
| 312 |
|
|
| 240 |
|
|
| 240 |
|
|
| 0.48 |
|
Fair value changes in financial instruments and foreign currency |
| (614 | ) |
|
| (458 | ) |
|
| (458 | ) |
|
| (0.92 | ) |
Restructuring and transaction costs |
| 114 |
|
|
| 87 |
|
|
| 87 |
|
|
| 0.18 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 726 |
|
| $ | 587 |
|
| $ | 587 |
|
| $ | 1.17 |
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 2,863 |
|
| $ | 2,460 |
|
| $ | 2,300 |
|
| $ | 4.58 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of EnLink and the General Partner |
| (2,607 | ) |
|
| (2,222 | ) |
|
| (2,222 | ) |
|
| (4.43 | ) |
Fair value changes, and minimum volume commitment settlement |
| (34 | ) |
|
| (28 | ) |
|
| (10 | ) |
|
| (0.02 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 222 |
|
| $ | 210 |
|
| $ | 68 |
|
| $ | 0.13 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 3,783 |
|
| $ | 3,224 |
|
| $ | 3,064 |
|
| $ | 6.10 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
| (194 | ) |
|
| (177 | ) |
|
| (177 | ) |
|
| (0.35 | ) |
Discontinued Operations |
| (2,641 | ) |
|
| (2,250 | ) |
|
| (2,232 | ) |
|
| (4.45 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 948 |
|
| $ | 797 |
|
| $ | 655 |
|
| $ | 1.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 773 |
|
| $ | 758 |
|
| $ | 758 |
|
| $ | 1.43 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (217 | ) |
|
| (138 | ) |
|
| (138 | ) |
|
| (0.26 | ) |
Asset and exploration impairments |
| 217 |
|
|
| 138 |
|
|
| 138 |
|
|
| 0.25 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| (76 | ) |
|
| (76 | ) |
|
| (0.14 | ) |
Fair value changes in financial instruments and foreign currency |
| (214 | ) |
|
| (199 | ) |
|
| (199 | ) |
|
| (0.37 | ) |
Legal entity restructuring |
| — |
|
|
| (86 | ) |
|
| (86 | ) |
|
| (0.16 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 559 |
|
| $ | 397 |
|
| $ | 397 |
|
| $ | 0.75 |
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 123 |
|
| $ | 320 |
|
| $ | 140 |
|
| $ | 0.27 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. tax reform |
| — |
|
|
| (211 | ) |
|
| (112 | ) |
|
| (0.21 | ) |
Asset dispositions, impairments, fair value changes and early retirement of debt |
| 4 |
|
|
| 4 |
|
|
| 2 |
|
|
| 0.00 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 127 |
|
| $ | 113 |
|
| $ | 30 |
|
| $ | 0.06 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 896 |
|
| $ | 1,078 |
|
| $ | 898 |
|
| $ | 1.70 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
| (214 | ) |
|
| (361 | ) |
|
| (361 | ) |
|
| (0.68 | ) |
Discontinued Operations |
| 4 |
|
|
| (207 | ) |
|
| (110 | ) |
|
| (0.21 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 686 |
|
| $ | 510 |
|
| $ | 427 |
|
| $ | 0.81 |
|
45
| Year Ended December 31, |
| ||||||||||||||||||||||||||||
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Share |
| |||||||||||||||||||
|
|
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| |||||||||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Loss attributable to Devon (GAAP) | $ | (3,877 | ) |
| $ | (3,704 | ) |
| $ | (3,302 | ) |
| $ | (6.52 | ) | $ | (433 | ) |
| $ | (574 | ) |
| $ | (575 | ) |
| $ | (1.14 | ) |
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 |
| |||||||||||||||
Asset dispositions |
| (1,496 | ) |
|
| (1,001 | ) |
|
| (1,001 | ) |
|
| (1.97 | ) | |||||||||||||||
Asset and exploration impairments |
| 537 |
|
|
| 340 |
|
|
| 340 |
|
|
| 0.69 |
| |||||||||||||||
Rig stacking costs |
| 10 |
|
|
| 6 |
|
|
| 6 |
|
|
| 0.01 |
| |||||||||||||||
Deferred tax asset valuation allowance |
| — |
|
|
| 851 |
|
|
| 851 |
|
|
| 1.66 |
|
| — |
|
|
| 385 |
|
|
| 385 |
|
|
| 0.76 |
|
Restructuring and transaction costs |
| 267 |
|
|
| 173 |
|
|
| 170 |
|
|
| 0.33 |
|
| 261 |
|
|
| 168 |
|
|
| 168 |
|
|
| 0.33 |
|
Fair value changes in financial instruments and foreign currency |
| 270 |
|
|
| 153 |
|
|
| 145 |
|
|
| 0.28 |
|
| 248 |
|
|
| 135 |
|
|
| 135 |
|
|
| 0.26 |
|
Early retirement of debt |
| 269 |
|
|
| 171 |
|
|
| 171 |
|
|
| 0.33 |
|
| 269 |
|
|
| 171 |
|
|
| 171 |
|
|
| 0.33 |
|
Core earnings (loss) attributable to Devon (Non-GAAP) | $ | 35 |
|
| $ | — |
|
| $ | (38 | ) |
| $ | (0.08 | ) | |||||||||||||||
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Core loss attributable to Devon (Non-GAAP) | $ | (604 | ) |
| $ | (370 | ) |
| $ | (371 | ) |
| $ | (0.73 | ) | |||||||||||||||
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Loss attributable to Devon (GAAP) | $ | (21,268 | ) |
| $ | (15,203 | ) |
| $ | (14,454 | ) |
| $ | (35.55 | ) | $ | (884 | ) |
| $ | (884 | ) |
| $ | (481 | ) |
| $ | (0.95 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset impairments |
| 20,820 |
|
|
| 13,923 |
|
|
| 13,100 |
|
|
| 32.18 |
|
| 893 |
|
|
| 890 |
|
|
| 467 |
|
|
| 0.91 |
|
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 |
| |||||||||||||||
Asset dispositions, restructuring and transaction costs and fair value changes |
| 41 |
|
|
| 35 |
|
|
| 18 |
|
|
| 0.04 |
| |||||||||||||||
Core earnings attributable to Devon (Non-GAAP) | $ | 1,597 |
|
| $ | 1,121 |
|
| $ | 1,044 |
|
| $ | 2.52 |
| $ | 50 |
|
| $ | 41 |
|
| $ | 4 |
|
| $ | 0.00 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Earnings attributable to Devon (GAAP) | $ | 4,059 |
|
| $ | 1,691 |
|
| $ | 1,607 |
|
| $ | 3.91 |
| |||||||||||||||
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Loss attributable to Devon (GAAP) | $ | (1,317 | ) |
| $ | (1,458 | ) |
| $ | (1,056 | ) |
| $ | (2.09 | ) | |||||||||||||||
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 |
| |||||||||||||||
Continuing Operations |
| (171 | ) |
|
| 204 |
|
|
| 204 |
|
|
| 0.41 |
| |||||||||||||||
Discontinued Operations |
| 934 |
|
|
| 925 |
|
|
| 485 |
|
|
| 0.95 |
| |||||||||||||||
Core loss attributable to Devon (Non-GAAP) | $ | (554 | ) |
| $ | (329 | ) |
| $ | (367 | ) |
| $ | (0.73 | ) | |||||||||||||||
5346
EBITDAX and Field-Level Cash Margin
To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; depreciation, depletion and amortization; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL revenues less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.
We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.
We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.
Below are reconciliations of net earnings from continuing operations to EBITDAX and a further reconciliation to Field-Level Cash Margin. Because we have sold upstream assets in the periods presented and have plans to dispose our Canadian and Barnett Shale businesses, which represent approximately 40% of our 2018 production volumes, we have also excluded the EBITDAX and Field-Level Cash Margin for our divested assets, Canada and the Barnett Shale to compute Adjusted EBITDAX and Adjusted Field-Level Cash Margin. We use Adjusted EBITDAX and Adjusted Field-Level Cash Margin to assess the performance of our portfolio of upstream assets on a “same-store” basis across periods.
47
| Year Ended December 31, |
| |||||||||
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Net earnings from continuing operations (GAAP) | $ | 764 |
|
| $ | 758 |
|
| $ | (574 | ) |
Financing costs, net |
| 594 |
|
|
| 317 |
|
|
| 717 |
|
Income tax expense |
| 156 |
|
|
| 15 |
|
|
| 141 |
|
Exploration expenses |
| 177 |
|
|
| 380 |
|
|
| 215 |
|
Depreciation, depletion and amortization |
| 1,658 |
|
|
| 1,529 |
|
|
| 1,592 |
|
Asset impairments |
| 156 |
|
|
| — |
|
|
| 437 |
|
Asset disposition gains |
| (263 | ) |
|
| (217 | ) |
|
| (1,496 | ) |
Share-based compensation |
| 122 |
|
|
| 141 |
|
|
| 124 |
|
Derivative and financial instrument non-cash valuation changes |
| (614 | ) |
|
| (214 | ) |
|
| 248 |
|
Restructuring and transaction costs |
| 114 |
|
|
| — |
|
|
| 261 |
|
Accretion on discounted liabilities and other |
| 61 |
|
|
| 29 |
|
|
| 44 |
|
EBITDAX (non-GAAP) |
| 2,925 |
|
|
| 2,738 |
|
|
| 1,709 |
|
Marketing revenues and expenses, net |
| (86 | ) |
|
| 48 |
|
|
| 49 |
|
Commodity derivative cash settlements |
| 84 |
|
|
| (53 | ) |
|
| 11 |
|
General and administration expenses, cash-based |
| 529 |
|
|
| 596 |
|
|
| 609 |
|
Field-level cash margin (non-GAAP) | $ | 3,452 |
|
| $ | 3,329 |
|
| $ | 2,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX (non-GAAP) | $ | 2,925 |
|
| $ | 2,738 |
|
| $ | 1,709 |
|
EBITDAX, Divested assets |
| (184 | ) |
|
| (267 | ) |
|
| (346 | ) |
EBITDAX, Canada |
| (593 | ) |
|
| (748 | ) |
|
| (491 | ) |
EBITDAX, Barnett Shale |
| (248 | ) |
|
| (262 | ) |
|
| (148 | ) |
Adjusted EBITDAX (non-GAAP) | $ | 1,900 |
|
| $ | 1,461 |
|
| $ | 724 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Field-level cash margin (non-GAAP) | $ | 3,452 |
|
| $ | 3,329 |
|
| $ | 2,378 |
|
Field-level cash margin, divested assets |
| (184 | ) |
|
| (267 | ) |
|
| (346 | ) |
Field-level cash margin, Canada |
| (210 | ) |
|
| (812 | ) |
|
| (490 | ) |
Field-level cash margin, Barnett Shale |
| (248 | ) |
|
| (262 | ) |
|
| (148 | ) |
Adjusted field-level cash margin (non-GAAP) | $ | 2,810 |
|
| $ | 1,988 |
|
| $ | 1,394 |
|
48
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, bitumen, 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, bitumen, 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. and Canadian gas and NGL production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we 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, 20162018 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, 2016,2018, 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 $270 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, 2016,2018, we had total debt of $10.2$5.9 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%5.4%.
As of December 31, 2016,2018, we had one open interest rate swap positionsposition that areis presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair valuesvalue of our interest rate swaps areswap is 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, 2016.2018.
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our December 31, 20162018 balance sheet.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of our subsidiaries hold Canadian-dollar cash and engageDevon engages in intercompany loansloan activity between subsidiaries with Canadian subsidiaries that are based in Canadian dollars.different functional currencies. The value of the Canadian-dollar cash andthese foreign currency denominated intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollarsubsidiaries’ functional currency. Based on the amount of the cash and
54
intercompany loans as of December 31, 2016,2018, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.
5549
Item 8.Financial StatementsStatements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND 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.
5650
Report of Independent RegisteredRegistered Public Accounting Firm
The 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, 20162018 and 2015, and2017, 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, 2016.2018, 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, 2016,2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, 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, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Adoption of New Accounting Standard
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for revenue from contracts with customers in 2018 due to the adoption of Accounting Standards Update 2014-09, Revenue from Contracts with Customers (ASC 606). Devon Energy Corporation’s
Basis for Opinion
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 maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
51
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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
/s/ KPMG LLP
We have served as the Company’s auditor since 1980.
Oklahoma City, Oklahoma
February 15, 201720, 2019
5752
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF 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, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Upstream revenues |
| $ | 6,285 |
|
| $ | 5,307 |
|
| $ | 3,981 |
|
Marketing revenues |
|
| 4,449 |
|
|
| 3,571 |
|
|
| 2,772 |
|
Total revenues |
|
| 10,734 |
|
|
| 8,878 |
|
|
| 6,753 |
|
Production expenses |
|
| 2,225 |
|
|
| 1,823 |
|
|
| 1,805 |
|
Exploration expenses |
|
| 177 |
|
|
| 380 |
|
|
| 215 |
|
Marketing expenses |
|
| 4,363 |
|
|
| 3,619 |
|
|
| 2,821 |
|
Depreciation, depletion and amortization |
|
| 1,658 |
|
|
| 1,529 |
|
|
| 1,592 |
|
Asset impairments |
|
| 156 |
|
|
| — |
|
|
| 437 |
|
Asset dispositions |
|
| (263 | ) |
|
| (217 | ) |
|
| (1,496 | ) |
General and administrative expenses |
|
| 650 |
|
|
| 737 |
|
|
| 733 |
|
Financing costs, net |
|
| 594 |
|
|
| 317 |
|
|
| 717 |
|
Restructuring and transaction costs |
|
| 114 |
|
|
| — |
|
|
| 261 |
|
Other expenses |
|
| 140 |
|
|
| (83 | ) |
|
| 101 |
|
Total expenses |
|
| 9,814 |
|
|
| 8,105 |
|
|
| 7,186 |
|
Earnings (loss) from continuing operations before income taxes |
|
| 920 |
|
|
| 773 |
|
|
| (433 | ) |
Income tax expense |
|
| 156 |
|
|
| 15 |
|
|
| 141 |
|
Net earnings (loss) from continuing operations |
|
| 764 |
|
|
| 758 |
|
|
| (574 | ) |
Net earnings (loss) from discontinued operations, net of income tax expense |
|
| 2,460 |
|
|
| 320 |
|
|
| (884 | ) |
Net earnings (loss) |
|
| 3,224 |
|
|
| 1,078 |
|
|
| (1,458 | ) |
Net earnings (loss) attributable to noncontrolling interests |
|
| 160 |
|
|
| 180 |
|
|
| (402 | ) |
Net earnings (loss) attributable to Devon |
| $ | 3,064 |
|
| $ | 898 |
|
| $ | (1,056 | ) |
Basic net earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) from continuing operations per share |
| $ | 1.53 |
|
| $ | 1.44 |
|
| $ | (1.14 | ) |
Basic earnings (loss) from discontinued operations per share |
|
| 4.61 |
|
|
| 0.27 |
|
|
| (0.95 | ) |
Basic net earnings (loss) per share |
| $ | 6.14 |
|
| $ | 1.71 |
|
| $ | (2.09 | ) |
Diluted net earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) from continuing operations per share |
| $ | 1.52 |
|
| $ | 1.43 |
|
| $ | (1.14 | ) |
Diluted earnings (loss) from discontinued operations per share |
|
| 4.58 |
|
|
| 0.27 |
|
|
| (0.95 | ) |
Diluted net earnings (loss) per share |
| $ | 6.10 |
|
| $ | 1.70 |
|
| $ | (2.09 | ) |
Comprehensive earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 3,224 |
|
| $ | 1,078 |
|
| $ | (1,458 | ) |
Other comprehensive earnings (loss), net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation |
|
| (152 | ) |
|
| 83 |
|
|
| 11 |
|
Pension and postretirement plans |
|
| 44 |
|
|
| 29 |
|
|
| 22 |
|
Other comprehensive earnings (loss), net of tax |
|
| (108 | ) |
|
| 112 |
|
|
| 33 |
|
Comprehensive earnings (loss) |
|
| 3,116 |
|
|
| 1,190 |
|
|
| (1,425 | ) |
Comprehensive earnings (loss) attributable to noncontrolling interests |
|
| 160 |
|
|
| 180 |
|
|
| (402 | ) |
Comprehensive earnings (loss) attributable to Devon |
| $ | 2,956 |
|
| $ | 1,010 |
|
| $ | (1,023 | ) |
See accompanying notes to consolidated financial statements.
5853
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 3,224 |
|
| $ | 1,078 |
|
| $ | (1,458 | ) |
Adjustments to reconcile net earnings to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net (earnings) loss from discontinued operations, net of income tax expense |
|
| (2,460 | ) |
|
| (320 | ) |
|
| 884 |
|
Depreciation, depletion and amortization |
|
| 1,658 |
|
|
| 1,529 |
|
|
| 1,592 |
|
Asset impairments |
|
| 156 |
|
|
| — |
|
|
| 437 |
|
Leasehold impairments |
|
| 95 |
|
|
| 219 |
|
|
| 113 |
|
Accretion on discounted liabilities |
|
| 61 |
|
|
| 63 |
|
|
| 75 |
|
Total (gains) losses on commodity derivatives |
|
| (608 | ) |
|
| (157 | ) |
|
| 201 |
|
Cash settlements on commodity derivatives |
|
| (84 | ) |
|
| 53 |
|
|
| 1 |
|
Gains on asset dispositions |
|
| (263 | ) |
|
| (217 | ) |
|
| (1,496 | ) |
Deferred income tax expense (benefit) |
|
| 226 |
|
|
| (97 | ) |
|
| 43 |
|
Share-based compensation |
|
| 161 |
|
|
| 150 |
|
|
| 203 |
|
Early retirement of debt |
|
| 312 |
|
|
| — |
|
|
| 269 |
|
Total (gains) losses on foreign exchange |
|
| 139 |
|
|
| (132 | ) |
|
| (121 | ) |
Settlements of intercompany foreign denominated assets/liabilities |
|
| (241 | ) |
|
| 9 |
|
|
| 63 |
|
Other |
|
| (5 | ) |
|
| (1 | ) |
|
| 4 |
|
Changes in assets and liabilities, net |
|
| (143 | ) |
|
| 32 |
|
|
| 24 |
|
Net cash from operating activities - continuing operations |
|
| 2,228 |
|
|
| 2,209 |
|
|
| 834 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (2,451 | ) |
|
| (1,968 | ) |
|
| (1,384 | ) |
Acquisitions of property and equipment |
|
| (55 | ) |
|
| (46 | ) |
|
| (849 | ) |
Divestitures of property and equipment |
|
| 1,013 |
|
|
| 426 |
|
|
| 3,020 |
|
Net cash from investing activities - continuing operations |
|
| (1,493 | ) |
|
| (1,588 | ) |
|
| 787 |
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Repayments of long-term debt principal |
|
| (922 | ) |
|
| — |
|
|
| (2,492 | ) |
Net short-term debt repayments |
|
| — |
|
|
| — |
|
|
| (626 | ) |
Early retirement of debt |
|
| (304 | ) |
|
| — |
|
|
| (265 | ) |
Issuance of common stock |
|
| — |
|
|
| — |
|
|
| 1,469 |
|
Repurchases of common stock |
|
| (2,956 | ) |
|
| — |
|
|
| — |
|
Dividends paid on common stock |
|
| (149 | ) |
|
| (127 | ) |
|
| (221 | ) |
Shares exchanged for tax withholdings |
|
| (48 | ) |
|
| (59 | ) |
|
| (35 | ) |
Other |
|
| (7 | ) |
|
| — |
|
|
| — |
|
Net cash from financing activities - continuing operations |
|
| (4,386 | ) |
|
| (186 | ) |
|
| (2,170 | ) |
Effect of exchange rate changes on cash: |
|
|
|
|
|
|
|
|
|
|
|
|
Settlements of intercompany foreign denominated assets/liabilities |
|
| 241 |
|
|
| (9 | ) |
|
| (63 | ) |
Other |
|
| (35 | ) |
|
| 15 |
|
|
| 2 |
|
Total effect of exchange rate changes on cash - continuing operations |
|
| 206 |
|
|
| 6 |
|
|
| (61 | ) |
Net change in cash, cash equivalents and restricted cash of continuing operations |
|
| (3,445 | ) |
|
| 441 |
|
|
| (610 | ) |
Cash flows from discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
| 476 |
|
|
| 700 |
|
|
| 666 |
|
Investing activities |
|
| 2,548 |
|
|
| (611 | ) |
|
| (1,381 | ) |
Financing activities |
|
| 183 |
|
|
| 195 |
|
|
| 974 |
|
Net change in cash, cash equivalents and restricted cash of discontinued operations |
|
| 3,207 |
|
|
| 284 |
|
|
| 259 |
|
Net change in cash, cash equivalents and restricted cash |
|
| (238 | ) |
|
| 725 |
|
|
| (351 | ) |
Cash, cash equivalents and restricted cash at beginning of period |
|
| 2,684 |
|
|
| 1,959 |
|
|
| 2,310 |
|
Cash, cash equivalents and restricted cash at end of period |
| $ | 2,446 |
|
| $ | 2,684 |
|
| $ | 1,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of cash, cash equivalents and restricted cash: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 2,414 |
|
| $ | 2,642 |
|
| $ | 1,947 |
|
Restricted cash included in other current assets |
|
| 32 |
|
|
| 11 |
|
|
| — |
|
Cash and cash equivalents included in current assets held for sale |
|
| — |
|
|
| 31 |
|
|
| 12 |
|
Total cash, cash equivalents and restricted cash |
| $ | 2,446 |
|
| $ | 2,684 |
|
| $ | 1,959 |
|
See accompanying notes to consolidated financial statements.
54
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, 2018 |
|
| December 31, 2017 |
| ||
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 2,414 |
|
| $ | 2,642 |
|
Accounts receivable |
|
| 885 |
|
|
| 989 |
|
Current assets held for sale |
|
| 197 |
|
|
| 760 |
|
Other current assets |
|
| 941 |
|
|
| 400 |
|
Total current assets |
|
| 4,437 |
|
|
| 4,791 |
|
Oil and gas property and equipment, based on successful efforts accounting, net |
|
| 12,813 |
|
|
| 13,318 |
|
Other property and equipment, net |
|
| 1,122 |
|
|
| 1,266 |
|
Total property and equipment, net |
|
| 13,935 |
|
|
| 14,584 |
|
Goodwill |
|
| 841 |
|
|
| 841 |
|
Other long-term assets |
|
| 353 |
|
|
| 296 |
|
Long-term assets held for sale |
|
| — |
|
|
| 9,729 |
|
Total assets |
| $ | 19,566 |
|
| $ | 30,241 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 662 |
|
| $ | 633 |
|
Revenues and royalties payable |
|
| 898 |
|
|
| 748 |
|
Short-term debt |
|
| 162 |
|
|
| 115 |
|
Current liabilities held for sale |
|
| 69 |
|
|
| 991 |
|
Other current liabilities |
|
| 435 |
|
|
| 828 |
|
Total current liabilities |
|
| 2,226 |
|
|
| 3,315 |
|
Long-term debt |
|
| 5,785 |
|
|
| 6,749 |
|
Asset retirement obligations |
|
| 1,030 |
|
|
| 1,099 |
|
Other long-term liabilities |
|
| 462 |
|
|
| 549 |
|
Long-term liabilities held for sale |
|
| — |
|
|
| 3,936 |
|
Deferred income taxes |
|
| 877 |
|
|
| 489 |
|
Equity: |
|
|
|
|
|
|
|
|
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 450 million and 525 million shares in 2018 and 2017, respectively |
|
| 45 |
|
|
| 53 |
|
Additional paid-in capital |
|
| 4,486 |
|
|
| 7,333 |
|
Retained earnings |
|
| 3,650 |
|
|
| 702 |
|
Accumulated other comprehensive earnings |
|
| 1,027 |
|
|
| 1,166 |
|
Treasury stock, at cost, 1.0 million shares in 2018 |
|
| (22 | ) |
|
| — |
|
Total stockholders’ equity attributable to Devon |
|
| 9,186 |
|
|
| 9,254 |
|
Noncontrolling interests |
|
| — |
|
|
| 4,850 |
|
Total equity |
|
| 9,186 |
|
|
| 14,104 |
|
Total liabilities and equity |
| $ | 19,566 |
|
| $ | 30,241 |
|
See accompanying notes to consolidated financial statements.
5955
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 |
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
| Additional |
|
| Earnings |
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
| Common Stock |
|
| Paid-In |
|
| (Accumulated |
|
| Comprehensive |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
| |||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| Deficit) |
|
| Earnings |
|
| Stock |
|
| Interests |
|
| Equity |
| ||||||||
Balance as of December 31, 2015 |
|
| 418 |
|
| $ | 42 |
|
| $ | 4,996 |
|
| $ | 1,112 |
|
| $ | 1,021 |
|
| $ | — |
|
| $ | 3,940 |
|
| $ | 11,111 |
|
Net loss |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,056 | ) |
|
| — |
|
|
| — |
|
|
| (402 | ) |
|
| (1,458 | ) |
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 33 |
|
|
| — |
|
|
| — |
|
|
| 33 |
|
Restricted stock grants, net of cancellations |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (28 | ) |
|
| — |
|
|
| (28 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (28 | ) |
|
| — |
|
|
| — |
|
|
| 28 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (96 | ) |
|
| (125 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (221 | ) |
Common stock issued |
|
| 103 |
|
|
| 10 |
|
|
| 2,117 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,127 |
|
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 168 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 168 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 80 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,214 |
|
|
| 1,294 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (304 | ) |
|
| (304 | ) |
Balance as of December 31, 2016 |
|
| 523 |
|
| $ | 52 |
|
| $ | 7,237 |
|
| $ | (69 | ) |
| $ | 1,054 |
|
| $ | — |
|
| $ | 4,448 |
|
| $ | 12,722 |
|
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 |
|
See accompanying notes to consolidated financial statements.
6056
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. and Canada.
As further discussed in Note 2, Devon also owns natural gas pipelines, plants and treatment facilities throughsold its ownershipinterests in EnLink and the General Partner.Partner on July 18, 2018. Activity relating to EnLink and the General Partner are classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows. The associated assets and liabilities of EnLink and the General Partner are presented as assets and liabilities held for sale 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. 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.
As discussed more fully in Note 2, Devon completed a business combination in 2014 whereby Devon controls both EnLink and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s 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 earnings and consolidated balance sheets.
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;
• | proved reserves and related present value of future net revenues; |
the carrying value of oil and gas properties, midstream assets and product and equipment inventories;
• | evaluation of suspended well costs; |
derivative financial instruments;
• | the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; |
the fair value of reporting units and related assessment of goodwill for impairment;
• | derivative financial instruments; |
the fair value of intangible assets other than goodwill;
• | the fair value of reporting units and related assessment of goodwill for impairment; |
income taxes;
• | income taxes; |
asset retirement obligations;
• | asset retirement obligations; |
• | obligations related to employee pension and postretirement benefits; |
obligations related to employee pension and postretirement benefits;
• | legal and environmental risks and exposures; and |
• | general credit risk associated with receivables and other assets. |
6257
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.
The impact of adoption in the current period results is as follows:
|
| Year Ended December 31, 2018 |
| |||||||||
|
| Under ASC 606 |
|
| Under ASC 605 |
|
| Increase/ (Decrease) |
| |||
Upstream revenues |
| $ | 6,285 |
|
| $ | 6,031 |
|
| $ | 254 |
|
Marketing revenues |
|
| 4,449 |
|
|
| 4,449 |
|
|
| — |
|
Total impacted revenues |
| $ | 10,734 |
|
| $ | 10,480 |
|
| $ | 254 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses |
| $ | 2,225 |
|
| $ | 1,971 |
|
| $ | 254 |
|
Marketing expenses |
|
| 4,363 |
|
|
| 4,363 |
|
|
| — |
|
Total impacted expenses |
| $ | 6,588 |
|
| $ | 6,334 |
|
| $ | 254 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
| $ | 920 |
|
| $ | 920 |
|
| $ | — |
|
Changes to upstream revenues and production expenses are 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 is 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 price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and 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 now presented as production expenses.
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 earnings.
58
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 comprehensive statements of 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 comprehensive statements of 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 comprehensive statements of 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 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 natural gas, NGLs or crude oil are delivered at a fixed or determinable price.
59
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets.
Disaggregation of Revenue
Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. Disaggregation of revenue disclosures can be found in Note 22.
Customers
During 2016, 20152018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue.
During 2017 and 2014,2016, no purchaser accounted for more than 10% 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 exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.
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 both two-way price collars and three-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 counterpartycounterparty. The three-way price collars consist of a two-way collar with an additional short put option sold by Devon, and cash-settle similarly to the collars. The call options give counterpartiestwo-way collars unless the rightmarket price falls below the additional short put causing the company to purchase production at a predetermined price.receive the market price plus the long put to short put price differential.
60
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of December 31, 2016,2018, Devon did not have any open foreign exchange 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, 2016,2018, 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
63
DEVON ENERGY CORPORATION AND SUBSIDIARIES
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 currency 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, 2016,2018, Devon held no collateral from counterparties. As of December 31, 2015, Devon held $75 million of cash collateral which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. Theits counterparties nor 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 net of amounts capitalized pursuant to the full cost method of accounting.Devon.
Share-Based Compensation
Independent of EnLink, Devon grants share-based awards to members of its Board of Directors 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 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 costs in the accompanying consolidated comprehensive statements of 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.
64
61
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 78 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 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.
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.
65Property and Equipment
Oil and Gas Property and Equipment
Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful
62
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Propertyexploratory wells along with acquisition costs and Equipment
the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon follows the full cost method of accounting forgroups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions.
Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Accordingly,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 incidental to the acquisition, exploration and developmentquarterly.
Capitalized costs of proved oil and gas properties including 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 unproved 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. 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 properties are transferred intoamortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms.
Proved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the depletion calculation over their respective holding periods generally ranging from 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 incurred 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 gains 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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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. Other Property and Equipment
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, the fair values of the reporting units are 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, 20152018, 2017 and 2014.2016. 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
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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.
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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 except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity.
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 2016,2018, Devon adopted ASU 2015-03, Interest2014-09, Revenue from Contracts with Customers (ASC 606), using the modified retrospective method. See revenue recognition section above for further discussion regarding Devon’s adoption of this revenue recognition standard.
In January 2018, Devon adopted ASU 2017-07, Compensation – Imputation of InterestRetirement Benefits (Topic 835): Simplifying715), Improving the Presentation of Debt Issuance Costs.Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU requires debt issuance costs relatedentities to a recognized debt liability to be presented onpresent the balance sheetservice cost component of net periodic benefit cost in the same line item as a direct deduction fromother employee compensation costs. Only the carrying amountservice cost component of that debt liability rather than as an asset.net periodic benefit cost is eligible for capitalization. As a result of the adoption of this ASU, consolidated statements of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively. Upon adoption, Devon reclassified unamortized debt issuance$7 million and $14 million of non-service cost components of net periodic benefit costs of $81 million as of December 31, 2015for 2017 and 2016, respectively, from G&A to other long-term assets to a reduction of long-term debt on the consolidated balance sheets.expenses.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
30, 2016 usingIn January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a retrospective transition method.reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon has classified $265 million of debt retirement payments as cash flows from financing activities inmade changes to the accompanying 2016 consolidated statement of cash flows to include the required presentation and hasreconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows.
In the fourth quarter of 2018, Devon early adopted ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220). This ASU allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. As a result of adopting this ASU, Devon reclassified $40$33 million of debt retirement payments previously classified as cash flows from operating activitiesaccumulated other comprehensive income to cash flows from financing activitiesretained earnings in the accompanying 2014December 31, 2018 consolidated statementbalance sheet.
In the fourth quarter of cash flows.2018, Devon early adopted ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU eliminated and added certain disclosure requirements for employers that sponsors defined benefit plans and/or other postretirement plans. Other than changes to required disclosures, this ASU did not have a material impact on Devon’s consolidated financial statements and related disclosures.
The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification, which amends various SEC disclosure requirements determined to be redundant, duplicative, overlapping, outdated or superseded as part of the SEC’s ongoing disclosure effectiveness initiative. The rule was effective November 5, 2018. The rule amended numerous SEC rules, items and forms covering a diverse group of topics. Devon has implemented these required changes to disclosures which generally reduced or eliminated disclosures. Devon will adopt the requirement of presenting a current and comparative year-to-date change in stockholder’s equity roll forward during the first quarter of 2019.
Issued Accounting Standards Not Yet Adopted
The FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern. Its objective is to provide guidance about management’s responsibility to evaluate whether there are conditions 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 by 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 does 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. Short-term leases can continue being accounted for off balance sheet based on a policy election. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. ThisDevon is adopting this ASU is effective for Devon beginning January 1, 2019 and2019.
Devon will be appliedapply the guidance using a modified retrospective transition method which requires applyingat the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to leases that existbe applied prospectively to all new or are entered into aftermodified land easements and rights-of-way. Devon also has elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases. Devon will be allowed to continue to apply the beginninglegacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented with the 2019 adoption year. Devon has implemented processes, controls, and a technology solution needed to comply with the requirements of this ASU.
To adopt Topic 842, Devon expects to recognize right-of-use assets of approximately $400 million with a corresponding lease liability based on the present value of the earliest period inremaining term minimum lease payments. Devon’s right-of-use assets are for certain leases related to real estate, drilling rigs and other equipment related to the financial statements. Early adoption is permitted. Devon is continuing to evaluate the impact this ASU will have on its consolidated financial statementsexploration, development and related disclosuresproduction of oil and does not plan on early adopting.
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,gas. Additionally, Devon will make certain incomerecognize a $24 million before tax, presentation changes, most notably prospectively presenting excess$19 million net of 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 thesecumulative-effect adjustment to reduce retained earnings.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
changes
The FASB issued ASU 2018-04, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement. This ASU will materially impact its consolidated financial statementseliminate, add and related disclosures,modify certain disclosure requirements for fair value measurement. The ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the adoptionentire standard or only the provisions that eliminate or modify requirements. The ASU requires the additional disclosure requirements to be adopted using a retrospective approach. Devon is currently evaluating the provisions of this ASU could resultand assessing the impact it may have on its disclosures in increased volatility in income tax expense and net earnings in Devon’sthe notes to the consolidated financial statements.
The FASB issued ASU No. 2016-13, Credit Losses, Measurement of Credit Losses on Financial Instruments2018-05-15, Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. This ASU changes how entities will measure credit losses for most financialrequire a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets and certain other instrumentsor expense as incurred. Capitalized implementation costs related to a hosting arrangement that are not measured at fair value through net income. The standardis a service contract will replace today’s incurred loss approach with an expected loss model for instruments measured atbe amortized cost. Entities will applyover the standard’s provisions as a cumulative-effect adjustment to retained earnings asterm of the hosting arrangement, beginning when the module or component of the first reporting period in which the guidancehosting arrangement is effective.ready for its intended use. This ASU is effective for Devonannual and interim periods beginning January 1, 2020, with early adoption permitted. Entities have the option to adopt the ASU using either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of the adoption. Devon is currently evaluating the impactprovisions of this ASU willand assessing the impact it may have on its consolidated financial statements and related disclosures.
statements.
Devon Acquisitions
OnIn 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, after adjustments, 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)Divestitures
EnLink 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.General Partner
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,the third quarter of 2018, Devon divested certain non-core upstream assetscompleted the sale of its aggregate ownership interests in EnLink and the U.S.General Partner for $3.125 billion and its 50% interest in the Access Pipeline in Canada. Proceedsrecognized a gain of approximately $2.6 billion ($2.2 billion after-tax). The proceeds from the transactions have beensale were utilized primarily for debt repayment and to support future capital investmentincrease Devon’s share repurchase program to $4.0 billion, which is discussed further in Devon’s core resource plays.Note 18. Additional information on these discontinued operations can be found in Note 19.
Upstream Assets
During 2018, Devon received proceeds of approximately $1.0 billion and recognized a net gain on asset dispositions of approximately $260 million, primarily from sales of non-core assets in the Barnett Shale and Delaware Basin. As part of the transactions, approximately $84 million of asset retirement obligations were assumed by the purchasers. In conjunction with the second quarterdivestitures, Devon settled certain gas processing contracts and recognized $40 million in settlement expense, which is included in asset dispositions within the 2018 consolidated statements of 2016, Devon divested its non-core Mississippian assets for approximately $200 million. Estimatedearnings. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 11267 MMBoe, or less than 1%18%, 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
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
$1.4 billion gainAdditionally, in the thirdfirst quarter of 20162019, Devon completed two separate divestitures of non-core assets in the Permian Basin totaling $300 million. One of the divestitures related to the sale of an entire common operating field, and Devon expects to recognize a gain of approximately $35 million during the first quarter of 2019. As of December 31, 2018, these associated assets and liabilities were classified as held for sale in the accompanying consolidated balance sheet. See Note 19 for additional information. In aggregate, the total estimated proved reserves associated with these divestitures. A summarydivested assets were approximately 25 MMBoe, or less than 2%, of total U.S. proved reserves.
During 2017, Devon received proceeds totaling approximately $420 million, and recognized a net gain on asset dispositions of $212 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves.
During 2016, Devon received proceeds totaling approximately $1.9 billion and recognized a net gain on asset dispositions of $809 million, primarily from sales of non-core assets in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. Estimated proved reserves associated with these assets were approximately 157 MMBoe, or 10%, of total U.S. proved reserves. As part of the gain computation follows.transactions, approximately $290 million of asset retirement obligations were assumed by purchasers and approximately $80 million of goodwill was allocated to these divested assets.
|
| 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 its 50% interest in Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes.
Prior Year Divestitures
During 2014, Devon divested certain upstream properties located throughout Canada and Barnett Shale (Subsequent Event)
In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from the U.S. as partCompany, based on authorizations provided by its Board of its asset portfolio transformationDirectors subsequent to December 31, 2018. Devon will evaluate multiple methods of separation for approximately $5 billion. A gain of $1.1 billion was recognized with the sale of the Canadian conventional assets. This gainthese assets, including potential sales or spin-offs. Devon is included as a separate item in the accompanying consolidated comprehensive statementsearly stages of earnings. marketing these assets and does not currently have any indications that it would recognize an impairment upon separating its Canadian business or its Barnett Shale assets.
Devon repatriatedanticipates reporting all financial information for its Canadian business and Barnett Shale assets as discontinued operations in 2019 when all 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 lossesrequisite criteria are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings. The proceeds were used to repay debt.met for such financial statement presentation.
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
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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.
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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 |
|
74
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commodity Derivatives
As of December 31, 2016,2018, Devon had the following open oil derivative positions. The first table presentstwo tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The secondthird 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 2019 |
|
| 51,719 |
|
| $ | 59.48 |
|
|
| 87,921 |
|
| $ | 54.48 |
|
| $ | 64.49 |
|
Q1-Q4 2020 |
|
| 1,740 |
|
| $ | 62.88 |
|
|
| 8,951 |
|
| $ | 52.85 |
|
| $ | 63.13 |
|
|
| Oil Basis Swaps |
|
| Three-Way Price Collars |
| ||||||||||||||||||||
Period |
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Sold Price ($/Bbl) |
|
| Weighted Average Floor Purchased Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
| ||||||
Q1-Q4 2017 |
| Midland Sweet |
|
| 10,000 |
|
| $ | (0.43 | ) | ||||||||||||||||
Q1-Q4 2019 |
|
| 5,000 |
|
| $ | 50.00 |
|
| $ | 63.00 |
|
| $ | 74.80 |
| ||||||||||
|
| Oil Basis Swaps |
| |||||||
Period |
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
| ||
Q1-Q4 2019 |
| Midland Sweet |
|
| 28,000 |
|
| $ | (0.46 | ) |
Q1-Q4 2019 |
| Argus LLS |
|
| 17,500 |
|
| $ | 5.00 |
|
Q1-Q4 2019 |
| Argus MEH |
|
| 16,000 |
|
| $ | 2.84 |
|
Q1-Q4 2019 |
| NYMEX Roll |
|
| 38,000 |
|
| $ | 0.45 |
|
Q1-Q4 2019 |
| Western Canadian Select |
|
| 31,505 |
|
| $ | (21.73 | ) |
Q1-Q4 2020 |
| NYMEX Roll |
|
| 38,000 |
|
| $ | 0.31 |
|
Q1-Q4 2020 |
| Western Canadian Select |
|
| 915 |
|
| $ | (20.75 | ) |
As of December 31, 2016,2018, 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 2019 |
|
| 266,293 |
|
| $ | 2.86 |
|
|
| 231,474 |
|
| $ | 2.69 |
|
| $ | 3.06 |
|
Q1-Q4 2020 |
|
| 26,480 |
|
| $ | 2.92 |
|
|
| 24,490 |
|
| $ | 2.74 |
|
| $ | 3.04 |
|
|
| 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 | ) |
As of December 31, 2016, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.
|
|
|
|
| |||||||
|
|
|
|
|
| ||||||
|
|
|
|
|
| ||||||
|
|
|
|
|
| ||||||
7569
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||
Q1-Q4 2019 |
| Panhandle Eastern Pipe Line |
|
| 84,466 |
|
| $ | (0.73 | ) |
Q1-Q4 2019 |
| El Paso Natural Gas |
|
| 130,000 |
|
| $ | (1.46 | ) |
Q1-Q4 2019 |
| Houston Ship Channel |
|
| 142,637 |
|
| $ | 0.01 |
|
Q1-Q4 2019 |
| Transco Zone 4 |
|
| 7,397 |
|
| $ | (0.03 | ) |
As of December 31, 2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.
|
|
|
| Price Swaps |
| |||||
Period |
| Product |
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
| ||
Q1-Q4 2019 |
| Ethane |
|
| 1,000 |
|
| $ | 11.55 |
|
Q1-Q4 2019 |
| Natural Gasoline |
|
| 4,500 |
|
| $ | 55.93 |
|
Q1-Q4 2019 |
| Normal Butane |
|
| 4,000 |
|
| $ | 33.69 |
|
Q1-Q4 2019 |
| Propane |
|
| 8,500 |
|
| $ | 30.01 |
|
Interest Rate Derivatives
As of December 31, 2016,2018, Devon had the following open interest rate derivative positions:
Notional | Notional |
|
| Rate Received |
|
| Rate Paid |
|
| Expiration | Notional |
|
| Rate Received |
|
| Rate Paid |
| Expiration | ||
(Millions) |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
$ | 750 |
|
| Three Month LIBOR |
|
|
| 2.98% |
|
| December 2048 (1) | 100 |
|
| 1.76% |
|
| Three Month LIBOR |
| January 2019 | |
$ | 100 |
|
|
| 1.76% |
|
| Three Month LIBOR |
|
| January 2019 | ||||||||||
In January 2019, this interest rate derivative position settled. |
|
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 earnings caption.
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Commodity derivatives: |
| (Millions) |
|
|
|
|
|
| �� |
|
|
|
|
|
| |||||||||
Oil, gas and NGL derivatives |
| $ | (201 | ) |
| $ | 503 |
|
| $ | 1,989 |
| ||||||||||||
Marketing and midstream revenues |
|
| (13 | ) |
|
| 9 |
|
|
| 22 |
| ||||||||||||
Upstream revenues |
| $ | 608 |
|
| $ | 157 |
|
| $ | (201 | ) | ||||||||||||
Marketing revenues |
|
| (1 | ) |
|
| 3 |
|
|
| (2 | ) | ||||||||||||
Interest rate derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other nonoperating items |
|
| (19 | ) |
|
| (20 | ) |
|
| (1 | ) | ||||||||||||
Other expenses |
|
| 65 |
|
|
| (22 | ) |
|
| (19 | ) | ||||||||||||
Foreign currency derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other nonoperating items |
|
| (153 | ) |
|
| 246 |
|
|
| 60 |
| ||||||||||||
Other expenses |
|
| — |
|
|
| — |
|
|
| (153 | ) | ||||||||||||
Net gains (losses) recognized |
| $ | (386 | ) |
| $ | 738 |
|
| $ | 2,070 |
|
| $ | 672 |
|
| $ | 138 |
|
| $ | (375 | ) |
7670
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, 2018 |
|
| December 31, 2017 |
| |||||||
Commodity derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
| $ | 9 |
|
| $ | 34 |
|
| $ | 637 |
|
| $ | 203 |
|
Other long-term assets |
|
| 1 |
|
|
| 1 |
|
|
| 40 |
|
|
| 2 |
|
Interest rate derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Other long-term assets |
|
| — |
|
|
| 1 |
| ||||||||
Foreign currency derivative assets: |
|
|
|
|
|
|
|
| ||||||||
Other current assets |
|
| — |
|
|
| 8 |
| ||||||||
Total derivative assets |
| $ | 11 |
|
| $ | 45 |
|
| $ | 677 |
|
| $ | 206 |
|
|
|
|
|
|
|
|
|
| ||||||||
Commodity derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
| $ | 187 |
|
| $ | 14 |
|
| $ | 67 |
|
| $ | 259 |
|
Other long-term liabilities |
|
| 16 |
|
|
| 4 |
|
|
| 1 |
|
|
| 27 |
|
Interest rate derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities |
|
| 41 |
|
|
| 22 |
| ||||||||
Foreign currency derivative liabilities: |
|
|
|
|
|
|
|
| ||||||||
Other current liabilities |
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 64 |
|
Total derivative liabilities |
| $ | 244 |
|
| $ | 48 |
|
| $ | 68 |
|
| $ | 350 |
|
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 one share and other awards represent three2.3 shares.
Devon also has a stock option plan thatThe vesting for certain share-based awards was adoptedaccelerated in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by2018 and 2016 in conjunction with the employees owning such options, but no new options or restricted stock awards will be granted under this plan.reduction of workforce activities described in Note 6 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.
77
The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings.
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
G&A |
| $ | 122 |
|
| $ | 141 |
|
| $ | 124 |
|
Exploration expenses |
|
| 4 |
|
|
| 7 |
|
|
| 6 |
|
Restructuring and transaction costs |
|
| 31 |
|
|
| — |
|
|
| 60 |
|
Total |
| $ | 157 |
|
| $ | 148 |
|
| $ | 190 |
|
Related income tax benefit |
| $ | 22 |
|
| $ | 6 |
|
| $ | 6 |
|
71
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 2016 in conjunction with the reduction of workforce described in Note 6. Approximately $60 million of associated expense for these accelerated awards is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings. In 2014, vesting of certain share-based awards was accelerated in conjunction with the divestiture of Devon’s Canadian conventional assets. Approximately $15 million of associated expense for these accelerated awards is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of 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 |
|
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 12/31/17 |
|
| 6,328 |
|
| $ | 36.81 |
|
|
| 575 |
|
| $ | 38.92 |
|
|
| 2,758 |
|
|
| $ | 41.21 |
| ||||||||||||||||||||||||||||
Granted |
|
| 4,390 |
|
| $ | 19.91 |
|
|
| 330 |
|
| $ | 19.22 |
|
|
| 1,388 |
|
| $ | 10.41 |
|
|
| 3,592 |
|
| $ | 35.98 |
|
|
| — |
|
| $ | — |
|
|
| 845 |
|
|
| $ | 37.40 |
| ||||
Vested |
|
| (2,473 | ) |
| $ | 61.44 |
|
|
| (179 | ) |
| $ | 59.10 |
|
|
| (602 | ) |
| $ | 63.37 |
|
|
| (3,114 | ) |
| $ | 38.75 |
|
|
| (273 | ) |
| $ | 42.22 |
|
|
| (571 | ) |
|
| $ | 84.22 |
| ||||
Forfeited |
|
| (248 | ) |
| $ | 44.38 |
|
|
| — |
|
| $ | — |
|
|
| (41 | ) |
| $ | 43.88 |
|
|
| (843 | ) |
| $ | 35.58 |
|
|
| — |
|
| $ | — |
|
|
| (164 | ) |
|
| $ | 33.92 |
| ||||
Unvested at 12/31/16 |
|
| 6,407 |
|
| $ | 34.40 |
|
|
| 585 |
|
| $ | 37.60 |
|
|
| 2,604 |
|
| (1 | ) | $ | 46.66 |
| |||||||||||||||||||||||||||
Unvested at 12/31/18 |
|
| 5,963 |
|
| $ | 35.47 |
|
|
| 302 |
|
| $ | 35.93 |
|
|
| 2,868 |
|
| (1 | ) |
| $ | 30.14 |
| ||||||||||||||||||||||||||
(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.
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Restricted Stock Awards and Units |
| $ | 111 |
|
| $ | 105 |
|
| $ | 73 |
|
Performance-Based Restricted Stock Awards |
| $ | 10 | $ | 10 | $ | 5 | |||||
Performance Share Units | $ | 20 | $ | 38 | $ | 13 | ||||||
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, 2018.
|
|
|
|
|
| Performance-Based |
|
|
|
|
| |
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
| |||
|
| Awards and Units |
|
| Awards |
|
| Share Units |
| |||
Unrecognized compensation cost |
| $ | 117 |
|
| $ | 1 |
|
| $ | 23 |
|
Weighted average period for recognition (years) |
|
| 2.4 |
|
|
| 1.0 |
|
|
| 1.7 |
|
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 made under the 2015 Plan or 2009 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.
72
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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.
Performance Share Units
Performance share units are granted to certain members of Devon’s management and senior employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified three-year performance period. The vesting of units may be between zero and 200% of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.
At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted.
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||||||||||||||||||||
Grant-date fair value |
|
| $36.23 |
|
| — |
| $ | 37.88 |
|
|
| $51.05 |
|
| — |
|
| $53.12 |
|
|
| $9.24 |
|
| — |
|
| $10.61 |
|
Risk-free interest rate |
| 2.28% |
|
| 1.50% |
|
| 0.94% |
| |||||||||||||||||||||
Volatility factor |
| 45.8% |
|
| 45.8% |
|
| 37.7% |
| |||||||||||||||||||||
Contractual term (years) |
| 2.89 |
|
| 2.89 |
|
| 2.83 |
| |||||||||||||||||||||
Stock Options
In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from one to four years. The fair value of stock options on the date of grant is expensed over the applicable vesting period. No stock options were granted in 2018, 2017 and 2016. The following table presents a summary of Devon’s outstanding stock options.
|
|
|
|
|
| Weighted Average |
|
|
|
|
| |||||
|
| Options |
|
| Exercise Price |
|
| Remaining Term |
|
| Intrinsic Value |
| ||||
|
| (Thousands) |
|
|
|
|
|
| (Years) |
|
|
|
|
| ||
Outstanding at December 31, 2017 |
|
| 1,746 |
|
| $ | 70.04 |
|
|
|
|
|
|
|
|
|
Expired |
|
| (1,029 | ) |
| $ | 72.51 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2018 |
|
| 717 |
|
| $ | 66.49 |
|
|
| 0.87 |
|
| $ | — |
|
Exercisable at December 31, 2018 |
|
| 717 |
|
| $ | 66.49 |
|
|
| 0.87 |
|
| $ | — |
|
73
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of December 31, 2018, Devon had no unrecognized compensation cost related to unvested stock options.
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||||||||||||||||||||
Grant-date fair value |
| $ | 9.24 |
|
| — |
| $ | 10.61 |
|
| $ | 81.99 |
|
| — |
| $ | 85.05 |
|
| $ | 70.18 |
|
| — |
| $ | 81.05 |
|
Risk-free interest rate |
| 0.94% |
|
| 1.06% |
|
| 0.54% |
| |||||||||||||||||||||
Volatility factor |
| 37.7% |
|
| 26.2% |
|
| 28.8% |
| |||||||||||||||||||||
Contractual term (years) |
| 2.83 |
|
| 2.89 |
|
| 2.89 |
| |||||||||||||||||||||
5. |
|
The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the consolidated comprehensive statements of earnings.
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Proved oil and gas assets |
| $ | 109 |
|
| $ | — |
|
| $ | 435 |
|
Other assets |
|
| 47 |
|
|
| — |
|
|
| 2 |
|
Total asset impairments |
| $ | 156 |
|
| $ | — |
|
| $ | 437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved impairments |
| $ | 95 |
|
| $ | 217 |
|
| $ | 77 |
|
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.
In 2016, Devon impaired a portion of its U.S. oil and gas portfolio due to lower forecasted oil, gas and NGL prices.
UnprovedImpairments
In 2018, 2017 and 2016, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments.
|
|
|
|
|
| Weighted Average |
|
|
|
|
| |||||
|
| Options |
|
| Exercise Price |
|
| Remaining Term |
|
| Intrinsic Value |
| ||||
|
| (Thousands) |
|
|
|
|
|
| (Years) |
|
| (Millions) |
| |||
Outstanding at December 31, 2015 |
|
| 3,448 |
|
| $ | 67.98 |
|
|
|
|
|
|
|
|
|
Expired |
|
| (916 | ) |
| $ | 67.75 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2016 |
|
| 2,532 |
|
| $ | 68.06 |
|
|
| 1.87 |
|
| $ | — |
|
Vested and expected to vest at December 31, 2016 |
|
| 2,532 |
|
| $ | 68.06 |
|
|
| 1.87 |
|
| $ | — |
|
Exercisable at December 31, 2016 |
|
| 2,532 |
|
| $ | 68.06 |
|
|
| 1.87 |
|
| $ | — |
|
6. |
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets.
Other Other Current Long-term Liabilities Liabilities Total Balance as of December 31, 2016 $ 48 $ 62 $ 110 Changes related to prior years’ restructurings (29 ) (31 ) (60 ) Balance as of December 31, 2017 $ 19 $ 31 $ 50 Changes due to 2018 workforce reductions 30 — 30 Changes related to prior years’ restructurings (2 ) (15 ) (17 ) Balance as of December 31, 2018 $ 47 $ 16 $ 63 The following table presents the asset impairments recognized in 2016, 2015
74
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2018 Workforce Reductions
In 2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized $114 million of restructuring expenses during 2018, primarily consisting of employee-related costs. 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.
Prior Years’ Restructurings
In 2016, Devon recognized $227 million in employee-related and other costs associated with a reduction in workforce that was made in response to the depressed commodity price environment. Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $24 million resulted from estimated defined benefit settlements.
As a result of the reduction of workforce, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Devon recognized $23 million in restructuring costs that represent the present value of its future obligations under the leases and 2014.
|
| Year Ended December 31, |
| |||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||
|
| (Millions) |
| |||||||||
U.S. oil and gas assets |
| $ | 2,809 |
|
| $ | 17,992 |
|
| $ | — |
|
Canada oil and gas assets |
|
| 1,291 |
|
|
| 1,257 |
|
|
| — |
|
Canada goodwill |
|
| — |
|
|
| — |
|
|
| 1,941 |
|
EnLink goodwill |
|
| 873 |
|
|
| 1,328 |
|
|
| — |
|
EnLink other intangible assets |
|
| — |
|
|
| 223 |
|
|
| — |
|
Other assets |
|
| 2 |
|
|
| 20 |
|
|
| 12 |
|
Total asset impairments |
| $ | 4,975 |
|
| $ | 20,820 |
|
| $ | 1,953 |
|
Oil and Gas Impairments
Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.
The oil and gas impairments resulted from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, natural gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves. For further information, see Note 22.
Goodwill and Other Intangible Assets Impairments
In 2016 and 2015, Devon recognized goodwill and other intangible assets impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 12.
In 2014, as a result of its annual impairment test of goodwill, Devon concluded the implied fair value of its Canadian goodwill was zero and wrote off the remaining goodwill.
The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets.
|
| 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 |
|
81
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Reduction in Workforce
In 2016, Devon recognized employee-related and other costs associated with a reduction in workforce that was made in response to the depressed commodity price environment. The following table summarizes restructuring and transaction costs presented in the accompanying consolidated comprehensive statement of earnings.
|
| Year Ended December 31, 2016 |
| |
|
| (Millions) |
| |
2016 reduction in workforce: |
|
|
|
|
Employee related costs |
| $ | 227 |
|
Lease obligations |
|
| 20 |
|
Asset impairments |
|
| 3 |
|
Transaction costs |
|
| 17 |
|
Restructuring and transaction costs |
| $ | 267 |
|
Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $24 million resulted from estimated defined benefit settlements. These cash and noncash charges included estimates for employees released from service during 2016, as well as amounts based on the number of employees impacted by certain of its non-core asset divestitures.
Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, Devon recognized restructuring costs that represent the present value of its future obligations under the leases. Additionally, Devon recognized asset impairment charges for leasehold improvements and furniture associated with the office space it ceased using.
Transaction Costs
In 2016, Devon and EnLink recognized $11 million in transaction costs primarily associated with the closing of the acquisitionsSTACK acquisition discussed in Note 2.2.
Prior Years’ Restructurings
7. | Other Expenses |
The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings.
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Foreign exchange (gain) loss, net |
| $ | 139 |
|
| $ | (132 | ) |
| $ | 39 |
|
Asset retirement obligation accretion |
|
| 59 |
|
|
| 62 |
|
|
| 75 |
|
Other, net |
|
| (58 | ) |
|
| (13 | ) |
|
| (13 | ) |
Total |
| $ | 140 |
|
| $ | (83 | ) |
| $ | 101 |
|
In 2015, Devon recognized $24 millionForeign exchange (gain) loss, net
The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. The amounts in the table above include both unrealized and realized foreign exchange impacts of employee-relatedforeign currency denominated monetary assets and other costs associatedliabilities, including intercompany loans between subsidiaries with the reduction in workforce made subsequent to the completion of the Jackfish development projectsdifferent functional currencies. Unrealized gains and a decrease in planned Canadian capital investment resultinglosses arise from the drop in commodity prices. Devon incurred employee severance, lease obligationremeasurement of these foreign currency denominated monetary assets and other costs related to the vacated office space as partliabilities and intercompany loans. Realized gains and losses arise when there are settlements of the cost reduction plan.
As part of the U.S. corporate headquarters office consolidation, Devon recognized an additional $54 million expense in 2015, due to a lack of demand for vacated office spacethese foreign currency denominated monetary assets and the inability to fully sublease remaining office space.
In 2014, Devon recognized $46 million of employee-relatedliabilities and other costs associated with its divestiture of certain Canadian assets. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are noncash charges.intercompany loans.
8275
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Foreign currency denominated intercompany loan activity during 2018 resulted in a realized loss of $241 million, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. These losses during 2018, were partially offset by reversing $195 million of previously recognized unrealized losses on intercompany loan activity.
Foreign currency denominated intercompany loan activity during 2016 resulted in a realized gain of $63 million, as a result of the weakening of the U.S. dollar in relation to the Canadian dollar. These gains during 2016, were partially offset by reversing $10 million of previously recognized unrealized gains on intercompany loan activity.
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
|
| Year Ended December 31, |
| |||||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| Year Ended December 31, |
| ||||||||||||
|
| (Millions) |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||||||||
Current income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
| $ | 5 |
|
| $ | (243 | ) |
| $ | 152 |
|
| $ | (14 | ) |
| $ | 9 |
|
| $ | 3 |
|
Various states |
|
| (11 | ) |
|
| (8 | ) |
|
| 18 |
|
|
| (3 | ) |
|
| — |
|
|
| (11 | ) |
Canada and various provinces |
|
| 106 |
|
|
| 14 |
|
|
| 307 |
|
|
| (53 | ) |
|
| 103 |
|
|
| 106 |
|
Total current tax expense (benefit) |
|
| 100 |
|
|
| (237 | ) |
|
| 477 |
|
|
| (70 | ) |
|
| 112 |
|
|
| 98 |
|
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
| (3 | ) |
|
| (5,033 | ) |
|
| 1,610 |
|
|
| 248 |
|
|
| — |
|
|
| — |
|
Various states |
|
| — |
|
|
| (336 | ) |
|
| 93 |
|
|
| 63 |
|
|
| — |
|
|
| — |
|
Canada and various provinces |
|
| (270 | ) |
|
| (459 | ) |
|
| 188 |
|
|
| (85 | ) |
|
| (97 | ) |
|
| 43 |
|
Total deferred tax expense (benefit) |
|
| (273 | ) |
|
| (5,828 | ) |
|
| 1,891 |
|
|
| 226 |
|
|
| (97 | ) |
|
| 43 |
|
Total income tax expense (benefit) |
| $ | (173 | ) |
| $ | (6,065 | ) |
| $ | 2,368 |
| ||||||||||||
Total income tax expense |
| $ | 156 |
|
| $ | 15 |
|
| $ | 141 |
| ||||||||||||
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following:
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
|
| (Millions) |
| |||||||||||||||||||||
Total income tax expense (benefit) |
| $ | (173 | ) |
| $ | (6,065 | ) |
| $ | 2,368 |
| ||||||||||||
Current income tax expense (benefit) |
| $ | (70 | ) |
| $ | 112 |
|
| $ | 98 |
| ||||||||||||
Deferred income tax expense (benefit) |
|
| 226 |
|
|
| (97 | ) |
|
| 43 |
| ||||||||||||
Total income tax expense |
| $ | 156 |
|
| $ | 15 |
|
| $ | 141 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
|
| 21 | % |
|
| 35 | % |
|
| 35 | % |
U.S. Tax Reform |
|
| 0 | % |
|
| 36 | % |
|
| 0 | % | ||||||||||||
Legal entity restructuring |
|
| 2 | % |
|
| (94 | %) |
|
| 19 | % | ||||||||||||
State income taxes |
|
| 5 | % |
|
| 0 | % |
|
| 10 | % | ||||||||||||
Change in unrecognized tax benefits |
|
| (5 | %) |
|
| 2 | % |
|
| (16 | %) | ||||||||||||
Other |
|
| (0 | %) |
|
| (13 | %) |
|
| 8 | % | ||||||||||||
Deferred tax asset valuation allowance |
|
| (22 | %) |
|
| (4 | %) |
|
| 0 | % |
|
| (6 | %) |
|
| 36 | % |
|
| (89 | %) |
Non-deductible goodwill and intangible impairment |
|
| (8 | %) |
|
| (2 | %) |
|
| 23 | % | ||||||||||||
Change in unrecognized tax benefits |
|
| (2 | %) |
|
| 0 | % |
|
| 1 | % | ||||||||||||
Taxation on Canadian operations |
|
| (3 | %) |
|
| (1 | %) |
|
| (4 | %) | ||||||||||||
State income taxes |
|
| 1 | % |
|
| 1 | % |
|
| 2 | % | ||||||||||||
Other |
|
| 3 | % |
|
| 0 | % |
|
| 1 | % | ||||||||||||
Effective income tax rate |
|
| 4 | % |
|
| 29 | % |
|
| 58 | % |
|
| 17 | % |
|
| 2 | % |
|
| (33 | %) |
76
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 judgementsjudgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.
83
2018
In the second quarter of 2018, Devon’s Canadian segment utilized a portion of its capital losses as a part of an internal legal entity restructuring. A valuation allowance remains recorded against the remaining balance of the capital losses.
During 2018, Devon recorded a tax benefit of $42 million related to unrecognized tax benefits, primarily as a result of a favorable Canadian court decision and the closure of prior year IRS audits.
Throughout 2017 and through the first two quarters of 2018, Devon’s U.S. segment maintained a 100% valuation allowance against its U.S. deferred tax assets. 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 its U.S. segment is 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’s U.S. segment would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the $259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations. A partial valuation allowance continues to be held against certain Canadian segment deferred tax assets. During 2018, the Canadian segment reduced its valuation allowance by approximately $59 million.
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 U.S. deferred tax assets and liabilities and reassessing the net realizability of deferred tax assets and liabilities. Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings, and $108 million in deferred tax expense related to the reduction of the U.S. corporate income tax rate to 21%.
77
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In the fourth quarter of 2017, Devon’s Canadian segment generated nonrecurring capital losses from internal legal entity restructuring. A deferred tax asset of $727 million was recognized related to the capital losses, offset by a $641 million increase in the valuation allowance.
Devon maintained a 100% valuation allowance against its U.S. 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 U.S. segment valuation allowance by $323 million in 2017 based primarily on the financial income recorded during the period. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.
Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in 2017 due to lower relative earnings during the period.
2016
Devon recorded a tax expense of $63 million related to unrecognized tax benefits during 2016, primarily as a result of Canadian audits and legal proceedings.
During 2016, Devon’s U.S. segment recordedrecognized an additional $774$313 million valuation allowance against its deferred tax assets. The allowance resultsresulted from continued financial losses resulting from additional full cost impairments in 2016. As of December 31, 2016, the allowance continuescontinued to represent a 100% valuation against the U.S. net deferred tax assets. Additionally, the Canadian segment recognized a $71 million partial valuation allowance resulting from continued financial losses. The valuation allowances impacted the effective tax rate and are discussed in the next section.
In the first quarter of 2016, EnLink recorded a goodwill impairment of approximately $873 million. Additionally, duringDuring the third quarter of 2016, Devon derecognized $197$83 million of goodwill related to its U.S. operations in conjunction with the divestiture of certain non-core U.SU.S. upstream oil and gas assets. These impairments areitems were not deductible for purposes of calculating income tax and, therefore, impact the effective tax rate.
2015
In the third and fourth quarters of 2015, EnLink recorded goodwill and intangibles impairments of approximately $1.6 billion, which impacted the effective tax rate.
During 2015, Devon recorded approximately $18 billion of oil and gas impairments related to its U.S. operations. These impairments resulted in deferred tax assets against which Devon recognized a $967 million valuation allowance.
2014
In the second and fourth quarters of 2014, goodwill was removed in conjunction with the Canadian conventional asset divestitures, and Devon recorded a goodwill impairment in the Canadian reporting unit. These non-deductible goodwill reductions impacted the effective tax rate.
Additionally, during 2014, Devon repatriated to the U.S. $2.8 billion of cash relating to the Canadian asset divestiture. In conjunction with the repatriation, Devon recognized approximately $105 million of additional income tax expense for the full year. Prior to the repatriation, Devon had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, Devon retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax. After the use of foreign tax credits, the current income tax on the repatriation was $67 million.
Furthermore, Devon completed its divestiture program of certain assets in the U.S. In conjunction with the divestitures, Devon recognized $294 million of current income tax expense. The current tax expense was entirely offset by the recognition of deferred tax benefits.
Devon also recorded a $46 million deferred tax liability in conjunction with the formation of EnLink in 2014.
8478
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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, |
| |||||||||||||
|
| 2016 |
|
| 2015 |
|
| December 31, |
| |||||||
|
| (Millions) |
|
| 2018 |
|
| 2017 |
| |||||||
Deferred tax assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment |
| $ | 685 |
|
| $ | 490 |
| ||||||||
Asset retirement obligations |
|
| 488 |
|
|
| 485 |
|
| $ | 300 |
|
| $ | 313 |
|
Accrued liabilities |
|
| 130 |
|
|
| 160 |
|
|
| 50 |
|
|
| 62 |
|
Net operating loss carryforwards |
|
| 777 |
|
|
| 175 |
|
|
| 287 |
|
|
| 796 |
|
Pension benefit obligations |
|
| 98 |
|
|
| 106 |
|
|
| 44 |
|
|
| 54 |
|
Canadian capital loss carryforwards |
|
| 609 |
|
|
| 760 |
| ||||||||
Other |
|
| 203 |
|
|
| 162 |
|
|
| 87 |
|
|
| 135 |
|
Total deferred tax assets before valuation allowance |
|
| 2,381 |
|
|
| 1,578 |
|
|
| 1,377 |
|
|
| 2,120 |
|
Less: valuation allowance |
|
| (1,666 | ) |
|
| (967 | ) |
|
| (640 | ) |
|
| (968 | ) |
Net deferred tax assets |
|
| 715 |
|
|
| 611 |
|
|
| 737 |
|
|
| 1,152 |
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment |
|
| (884 | ) |
|
| (1,187 | ) |
|
| (1,473 | ) |
|
| (1,288 | ) |
Long-term debt |
|
| (53 | ) |
|
| (36 | ) |
|
| — |
|
|
| (92 | ) |
Other |
|
| (426 | ) |
|
| (271 | ) |
|
| (141 | ) |
|
| (261 | ) |
Total deferred tax liabilities |
|
| (1,363 | ) |
|
| (1,494 | ) |
|
| (1,614 | ) |
|
| (1,641 | ) |
Net deferred tax liability |
| $ | (648 | ) |
| $ | (883 | ) |
| $ | (877 | ) |
| $ | (489 | ) |
At December 31, 2016,2018, Devon has recognized $777$287 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segment has $595 million of noncapital loss carryforwards expiring between 2029 and 2038. Devon’s U.S. segment has $389 million of U.S. federal net operating loss carryforwards consist of $536 million of Canadian carryforwards that expire between 2029expiring in 2037 and 2037, $1.5 billion of U.S. federal carryforward that expires in 2036, $689784 million of U.S. state net operating loss carryforwards that expireexpiring between 20182019 and 2036 and $293 million of carryforwards related to EnLink’s operations that expire between 2028 and 2036.2038. In the current environment, Devon expects tax benefits from the U.S. federal, majority of U.S. state and Canadian noncapital loss carryforwards to be utilized in 20172019 and beyondand EnLink carryforwards to be utilized in 2018 and beyond. Devon currently does not anticipate utilizing the U.S. federal or state net operating loss carryforwards, as indicated by the full valuation allowance position in the U.S. segment. EnLink also has $1 million of deferred tax assets related to alternative minimum tax credits, which have no expiration date and will be available for use against tax on future taxable income..
As a result of Devon’s continued financial losses incurred largely bysale of its aggregate ownership interests in EnLink and the additionalGeneral Partner during the third quarter of 2018, Devon’s U.S. segment reassessed its position and released its full cost impairments, Devon recorded an additional $630valuation allowance position, maintaining only $31 million of valuation allowance against the U.S.certain deferred tax assets, in 2016including certain tax credits and remains in a full valuation allowance position.state net operating losses. Also during 2016,2018, Devon’s Canadian segment recordedmaintained a $69 million partial valuation allowance of $609 million against the deferred tax asset related to the Canadian capital loss carryforward due to its continued financial losses.projected lack of future capital gain income. In the event Devon were to determine that it would be able to realize the deferred income tax assets in the future, Devon would adjust the valuation allowance, reducing the provision for income taxes in the period of such adjustment.
AsAfter enactment of the Tax Reform Legislation, Devon’s Canadian segment is the sole foreign operation to be considered for the indefinitely reinvested assertion of APB 23. Devon’s Canadian operations are robust and active and requires continuing capital investment. Accordingly, as of December 31, 2016,2018, no income taxes should be accrued by Devon relative to its investment in its Canadian operations. In view of Devon’s unremitted foreign earnings from its international operations totaled approximately $1.0 billion. All but $47 milliondecision in February 2019 to dispose of the $1.0 billion was deemed to beCanadian business, the indefinitely reinvested into the developmentassertion of APB 23 and growthany required accrual of Devon’s Canadian business. Therefore, Devon has not recognized a deferredincome tax liability for U.S. income taxes associated with such earnings. If such earnings were towill be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involvedreevaluated in making such an estimate.2019.
8579
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
For the remaining $47 million of unremitted earnings deemed not to be indefinitely reinvested, Devon has recognized a $13 million deferred tax liability associated with such unremitted earnings as of December 31, 2016.
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.
|
| December 31, |
| |||||||||||||
|
| 2016 |
|
| 2015 |
|
| December 31, |
| |||||||
|
| (Millions) |
|
| 2018 |
|
| 2017 |
| |||||||
Balance at beginning of year |
| $ | 131 |
|
| $ | 241 |
|
| $ | 115 |
|
| $ | 202 |
|
Tax positions taken in prior periods |
|
| 36 |
|
|
| (19 | ) |
|
| (43 | ) |
|
| (7 | ) |
Tax positions taken in current year |
|
| — |
|
|
| 31 |
|
|
| (2 | ) |
|
| (3 | ) |
Accrual of interest related to tax positions taken |
|
| 39 |
|
|
| (5 | ) |
|
| 3 |
|
|
| 16 |
|
Settlements |
|
| — |
|
|
| (108 | ) |
|
| — |
|
|
| (101 | ) |
Lapse of statute of limitations |
|
| (5 | ) |
|
| — |
| ||||||||
Foreign currency translation |
|
| 1 |
|
|
| (9 | ) |
|
| (3 | ) |
|
| 8 |
|
Balance at end of year |
| $ | 202 |
|
| $ | 131 |
|
| $ | 70 |
|
| $ | 115 |
|
Devon’s unrecognized tax benefit balance at December 31, 20162018 and 20152017 included $68$12 million and $29$28 million, respectively, of interest and penalties. If recognized, $202$70 million of Devon’s unrecognized tax benefits as of December 31, 20162018 would affect Devon’s effective income tax rate. Further,During 2018, Devon believes that within the next 12 months, it is reasonably possible that certain tax examinations will be resolved by settlement with the taxing authorities. During 2016, Devon recognized $88removed $43 million of unrecognized tax benefits, including $36$20 million of interest, associated with suchas a result of the closure of certain tax examinations. 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 |
|
|
Various U.S. states |
|
|
Canada Federal |
|
|
Various Canadian provinces |
|
|
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.
8680
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table reconciles net earnings (loss) attributable to Devonfrom continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.share from continuing operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, |
| |||||||||
|
| Year Ended December 31, |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
| |||||||||||||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||||||
Net earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Net earnings (loss) attributable to Devon |
| $ | (3,302 | ) |
| $ | (14,454 | ) |
| $ | 1,607 |
| ||||||||||||
Net earnings (loss) from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Net earnings (loss) from continuing operations |
| $ | 764 |
|
| $ | 758 |
|
| $ | (574 | ) | ||||||||||||
Attributable to participating securities |
|
| (2 | ) |
|
| (5 | ) |
|
| (17 | ) |
|
| (9 | ) |
|
| (8 | ) |
|
| (2 | ) |
Basic and diluted earnings (loss) |
| $ | (3,304 | ) |
| $ | (14,459 | ) |
| $ | 1,590 |
| ||||||||||||
Basic and diluted earnings (loss) from continuing operations |
| $ | 755 |
|
| $ | 750 |
|
| $ | (576 | ) | ||||||||||||
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding - total |
|
| 513 |
|
|
| 412 |
|
|
| 409 |
|
|
| 499 |
|
|
| 525 |
|
|
| 513 |
|
Attributable to participating securities |
|
| (6 | ) |
|
| (5 | ) |
|
| (4 | ) |
|
| (5 | ) |
|
| (5 | ) |
|
| (6 | ) |
Common shares outstanding - basic |
|
| 507 |
|
|
| 407 |
|
|
| 405 |
|
|
| 494 |
|
|
| 520 |
|
|
| 507 |
|
Dilutive effect of potential common shares issuable |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| 3 |
|
|
| 3 |
|
|
| — |
|
Common shares outstanding - diluted |
|
| 507 |
|
|
| 407 |
|
|
| 407 |
|
|
| 497 |
|
|
| 523 |
|
|
| 507 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Net earnings (loss) per share from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Basic |
| $ | (6.52 | ) |
| $ | (35.55 | ) |
| $ | 3.93 |
|
| $ | 1.53 |
|
| $ | 1.44 |
|
| $ | (1.14 | ) |
Diluted |
| $ | (6.52 | ) |
| $ | (35.55 | ) |
| $ | 3.91 |
|
| $ | 1.52 |
|
| $ | 1.43 |
|
| $ | (1.14 | ) |
Antidilutive options (1) |
|
| 3 |
|
|
| 4 |
|
|
| 3 |
|
|
| 1 |
|
|
| 2 |
|
|
| 3 |
|
(1) | Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive. |
87
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components of other comprehensive earnings consist of the following:
|
|
|
| |||||||||||||||||||||||
|
| Year Ended December 31, |
| |||||||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| Year Ended December 31, |
| ||||||||||||||
|
| (Millions) |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||||||||||
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Beginning accumulated foreign currency translation |
| $ | 424 |
|
| $ | 983 |
|
| $ | 1,448 |
|
| $ | 1,309 |
|
| $ | 1,226 |
|
| $ | 1,215 |
| ||
Change in cumulative translation adjustment |
|
| 45 |
|
|
| (621 | ) |
|
| (499 | ) |
|
| (166 | ) |
|
| 113 |
|
|
| 22 |
| ||
Income tax benefit (expense) |
|
| (13 | ) |
|
| 62 |
|
|
| 34 |
|
|
| 14 |
|
|
| (30 | ) |
|
| (11 | ) | ||
Ending accumulated foreign currency translation |
|
| 456 |
|
|
| 424 |
|
|
| 983 |
|
|
| 1,157 |
|
|
| 1,309 |
|
|
| 1,226 |
| ||
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Beginning accumulated pension and postretirement benefits |
|
| (194 | ) |
|
| (204 | ) |
|
| (180 | ) |
|
| (143 | ) |
|
| (172 | ) |
|
| (194 | ) | ||
Net actuarial loss and prior service cost arising in current year |
|
| (28 | ) |
|
| (5 | ) |
|
| (57 | ) |
|
| (3 | ) |
|
| 10 |
|
|
| (28 | ) | ||
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 26 |
|
|
| 21 |
|
|
| 20 |
|
|
| 12 |
|
|
| 19 |
|
|
| 26 |
| ||
Curtailment and settlement of pension benefits |
|
| 24 |
|
|
| — |
|
|
| — |
|
|
| 47 |
|
|
| — |
|
|
| 24 |
| ||
Income tax benefit (expense) |
|
| — |
|
|
| (6 | ) |
|
| 13 |
| ||||||||||||||
Income tax expense |
|
| (12 | ) |
|
| — |
|
|
| — |
| ||||||||||||||
Other (2) |
|
| (33 | ) |
|
| — |
|
|
| — |
| ||||||||||||||
Ending accumulated pension and postretirement benefits |
|
| (172 | ) |
|
| (194 | ) |
|
| (204 | ) |
|
| (132 | ) |
|
| (143 | ) |
|
| (172 | ) | ||
Other |
|
| 2 |
|
|
| — |
|
|
| — |
| ||||||||||||||
Accumulated other comprehensive earnings, net of tax |
| $ | 284 |
|
| $ | 230 |
|
| $ | 779 |
|
| $ | 1,027 |
|
| $ | 1,166 |
|
| $ | 1,054 |
| ||
(1) | These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of |
81
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1 for additional details. |
11. | Supplemental Information to Statements of Cash Flows |
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
|
| (Millions) |
| |||||||||||||||||||||
Net change in working capital accounts, net of assets and liabilities assumed: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Changes in assets and liabilities, net |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Accounts receivable |
| $ | (176 | ) |
| $ | 942 |
|
| $ | 128 |
|
| $ | 88 |
|
| $ | (94 | ) |
| $ | (58 | ) |
Income taxes receivable |
|
| 130 |
|
|
| 384 |
|
|
| (467 | ) | ||||||||||||
Other current assets |
|
| 215 |
|
|
| (57 | ) |
|
| (222 | ) |
|
| (128 | ) |
|
| 20 |
|
|
| 326 |
|
Other long-term assets |
|
| (28 | ) |
|
| (47 | ) |
|
| 36 |
| ||||||||||||
Accounts payable |
|
| (167 | ) |
|
| (190 | ) |
|
| (68 | ) |
|
| — |
|
|
| 113 |
|
|
| (196 | ) |
Revenues and royalties payable |
|
| 96 |
|
|
| (526 | ) |
|
| 133 |
|
|
| 153 |
|
|
| 106 |
|
|
| (26 | ) |
Other current liabilities |
|
| (106 | ) |
|
| (864 | ) |
|
| 546 |
|
|
| (150 | ) |
|
| (53 | ) |
|
| (74 | ) |
Net change in working capital |
| $ | (8 | ) |
| $ | (311 | ) |
| $ | 50 |
| ||||||||||||
Other long-term liabilities |
|
| (78 | ) |
|
| (13 | ) |
|
| 16 |
| ||||||||||||
Total |
| $ | (143 | ) |
| $ | 32 |
|
| $ | 24 |
| ||||||||||||
Supplementary cash flow data - total operations: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Interest paid (net of capitalized interest) |
| $ | 566 |
|
| $ | 494 |
|
| $ | 514 |
|
| $ | 385 |
|
| $ | 481 |
|
| $ | 569 |
|
Income taxes paid (received) |
| $ | (159 | ) |
| $ | (279 | ) |
| $ | 899 |
|
| $ | 40 |
|
| $ | 78 |
|
| $ | (159 | ) |
In 2016, Devon’s acquisition of certain STACK assets included the noncash issuance of Devon common stock. See Note 2 for additional details. Further, in 2016, EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets included noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions. See Note 2 for additional details.
In 2015, Devon’s acquisition
12. | Accounts Receivable |
Components of certain Powder River Basin assets included noncash common stock issuance totaling $199 million. EnLink’s acquisitions in 2015 also included $360 million of noncash equity.accounts receivable include the following:
88
|
| December 31, 2018 |
|
| December 31, 2017 |
| ||
Oil, gas and NGL sales |
| $ | 430 |
|
| $ | 559 |
|
Joint interest billings |
|
| 155 |
|
|
| 134 |
|
Marketing revenues |
|
| 285 |
|
|
| 278 |
|
Other |
|
| 23 |
|
|
| 29 |
|
Gross accounts receivable |
|
| 893 |
|
|
| 1,000 |
|
Allowance for doubtful accounts |
|
| (8 | ) |
|
| (11 | ) |
Net accounts receivable |
| $ | 885 |
|
| $ | 989 |
|
82
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On March 7, 2014, Devon completed a business combination to form EnLink. With the exception of a $100 million cash payment to noncontrolling interests, the business combination was a non-monetary transaction. 13.Property, Plant and Equipment
Capitalized Costs
Components of accounts receivable include the following:
|
| December 31, 2016 |
|
| December 31, 2015 |
| ||
|
| (Millions) |
| |||||
Oil, gas and NGL sales |
| $ | 487 |
|
| $ | 362 |
|
Joint interest billings |
|
| 110 |
|
|
| 211 |
|
Marketing and midstream revenues |
|
| 708 |
|
|
| 520 |
|
Other |
|
| 69 |
|
|
| 30 |
|
Gross accounts receivable |
|
| 1,374 |
|
|
| 1,123 |
|
Allowance for doubtful accounts |
|
| (18 | ) |
|
| (18 | ) |
Net accounts receivable |
| $ | 1,356 |
|
| $ | 1,105 |
|
Goodwill
The following table presents a summary of Devon’s goodwill.
|
| U.S. |
|
| EnLink |
|
| Total |
| |||
|
| (Millions) |
| |||||||||
Balance as of December 31, 2014 |
| $ | 2,618 |
|
| $ | 3,685 |
|
| $ | 6,303 |
|
Acquired during period |
|
| — |
|
|
| 57 |
|
|
| 57 |
|
Impairment |
|
| — |
|
|
| (1,328 | ) |
|
| (1,328 | ) |
Balance as of December 31, 2015 |
| $ | 2,618 |
|
| $ | 2,414 |
|
| $ | 5,032 |
|
Acquired during period |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Asset divestitures |
|
| (197 | ) |
|
| — |
|
|
| (197 | ) |
Impairment |
|
| — |
|
|
| (873 | ) |
|
| (873 | ) |
Balance as of December 31, 2016 |
| $ | 2,421 |
|
| $ | 1,543 |
|
| $ | 3,964 |
|
The following table presentsreflects the General Partner’saggregate capitalized costs related to Devon’s oil and EnLink’s goodwill activity by reporting unit.gas and non-oil and gas activities.
|
| Texas |
|
| Louisiana |
|
| Oklahoma |
|
| Crude and Condensate |
|
| General Partner |
|
| Total |
| ||||||||||||
|
| (Millions) |
| |||||||||||||||||||||||||||
Balance as of December 31, 2014 |
| $ | 1,168 |
|
| $ | 787 |
|
| $ | 190 |
|
| $ | 113 |
|
| $ | 1,427 |
|
| $ | 3,685 |
| ||||||
Acquired during period |
|
| 28 |
|
|
| — |
|
|
| — |
|
|
| 29 |
|
|
| — |
|
|
| 57 |
| ||||||
Impairment |
|
| (492 | ) |
|
| (787 | ) |
|
| — |
|
|
| (49 | ) |
|
| — |
|
|
| (1,328 | ) | ||||||
Balance as of December 31, 2015 |
| $ | 704 |
|
| $ | — |
|
| $ | 190 |
|
| $ | 93 |
|
| $ | 1,427 |
|
| $ | 2,414 |
| ||||||
Acquired during period |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
| ||||||
Impairment |
|
| (473 | ) |
|
| — |
|
|
| — |
|
|
| (93 | ) |
|
| (307 | ) |
|
| (873 | ) | ||||||
Balance as of December 31, 2016 |
| $ | 233 |
|
| $ | — |
|
| $ | 190 |
|
| $ | — |
|
| $ | 1,120 |
|
| $ | 1,543 |
| ||||||
|
| December 31, 2018 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Property and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
| $ | 40,378 |
|
| $ | 6,427 |
|
| $ | 46,805 |
|
Unproved and properties under development |
|
| 833 |
|
|
| 1,434 |
|
|
| 2,267 |
|
Total oil and gas |
|
| 41,211 |
|
|
| 7,861 |
|
|
| 49,072 |
|
Less accumulated DD&A |
|
| (32,229 | ) |
|
| (4,030 | ) |
|
| (36,259 | ) |
Oil and gas property and equipment, net |
| $ | 8,982 |
|
| $ | 3,831 |
|
| $ | 12,813 |
|
Other property and equipment |
|
|
|
|
|
|
|
|
|
| 1,832 |
|
Less accumulated DD&A |
|
|
|
|
|
|
|
|
|
| (710 | ) |
Other property and equipment, net |
|
|
|
|
|
|
|
|
|
| 1,122 |
|
Property and equipment, net |
|
|
|
|
|
|
|
|
| $ | 13,935 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| December 31, 2017 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Property and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
| $ | 40,491 |
|
| $ | 6,804 |
|
| $ | 47,295 |
|
Unproved and properties under development |
|
| 984 |
|
|
| 1,473 |
|
|
| 2,457 |
|
Total oil and gas |
|
| 41,475 |
|
|
| 8,277 |
|
|
| 49,752 |
|
Less accumulated DD&A |
|
| (32,379 | ) |
|
| (4,055 | ) |
|
| (36,434 | ) |
Oil and gas property and equipment, net |
| $ | 9,096 |
|
| $ | 4,222 |
|
| $ | 13,318 |
|
Other property and equipment |
|
|
|
|
|
|
|
|
|
| 1,955 |
|
Less accumulated DD&A |
|
|
|
|
|
|
|
|
|
| (689 | ) |
Other property and equipment, net |
|
|
|
|
|
|
|
|
|
| 1,266 |
|
Property and equipment, net |
|
|
|
|
|
|
|
|
| $ | 14,584 |
|
89Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2018.
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Beginning balance |
| $ | 313 |
|
| $ | 261 |
|
| $ | 225 |
|
Additions pending determination of proved reserves |
|
| 672 |
|
|
| 504 |
|
|
| 247 |
|
Charges to exploration expense |
|
| — |
|
|
| — |
|
|
| (29 | ) |
Reclassifications to proved properties |
|
| (662 | ) |
|
| (466 | ) |
|
| (189 | ) |
Foreign currency translation adjustment |
|
| (19 | ) |
|
| 14 |
|
|
| 7 |
|
Ending balance |
| $ | 304 |
|
| $ | 313 |
|
| $ | 261 |
|
83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In conjunction with the U.S. non-core upstream asset divestitures in 2016 discussed in Note 2, Devon removed $197 million of goodwill, which was allocated to these assets.
Impairment
As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units in the first quarter of 2016. Based on that test, EnLink recorded a noncash goodwill impairment.
During 2015, as a result of interim and annual impairment tests of goodwill, noncash goodwill impairments were recorded related to EnLink’s Texas, Louisiana and Crude and Condensate reporting units.
Other Intangible Assets
In the third quarter of 2015, Devon recorded a $223 million noncash impairment of intangible assets related to EnLink’s Crude and Condensate reporting unit resulting from an assessment of EnLink’s customer relationships. 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 following table presents other intangible assets reported in other long-term assetsprovides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Exploratory well costs capitalized for a period of one year or less |
| $ | 110 |
|
| $ | 113 |
|
| $ | 88 |
|
Exploratory well costs capitalized for a period greater than one year |
|
| 194 |
|
|
| 200 |
|
|
| 173 |
|
Ending balance |
| $ | 304 |
|
| $ | 313 |
|
| $ | 261 |
|
Number of projects with exploratory well costs capitalized for a period greater than one year |
|
| 2 |
|
|
| 2 |
|
|
| 2 |
|
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling relate to Devon’s heavy oil operations. Management believes these projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development. Currently, Devon has not planned additional exploratory work in the accompanying consolidated balance sheets.near future on these assets and will continue to assess its future development timeline of these long cycle projects as it competes for capital allocation within Devon’s portfolio. Devon’s interest in this acreage does not begin to expire until 2025.
|
| December 31, 2016 |
|
| December 31, 2015 |
| ||
|
| (Millions) |
| |||||
Customer relationships |
| $ | 1,796 |
|
| $ | 745 |
|
Accumulated amortization |
|
| (172 | ) |
|
| (55 | ) |
Net intangibles |
| $ | 1,624 |
|
| $ | 690 |
|
14. | Other Current Liabilities |
Components of other current liabilities include the following:
| December 31, 2018 |
|
| December 31, 2017 |
| ||
Derivative liabilities | $ | 67 |
|
| $ | 323 |
|
Accrued interest payable |
| 80 |
|
|
| 96 |
|
Income taxes payable |
| 14 |
|
|
| 144 |
|
Restructuring liabilities |
| 47 |
|
|
| 19 |
|
Other |
| 227 |
|
|
| 246 |
|
Other current liabilities | $ | 435 |
|
| $ | 828 |
|
The weighted-average amortization period for the customer relationships is 14 years. Amortization expense for intangibles was approximately $117 million, $56 million and $36 million for the years ended 2016, 2015 and 2014, respectively. The remaining aggregate amortization expense is estimated to be approximately $118 million in each of the next five years.
9084
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components of other current liabilities include the following:
| December 31, 2016 |
|
| December 31, 2015 |
| ||
| (Millions) |
| |||||
Installment payment - see Note 2 | $ | 249 |
|
| $ | — |
|
Derivative liabilities |
| 187 |
|
|
| 22 |
|
Accrued interest payable |
| 130 |
|
|
| 149 |
|
Restructuring liabilities |
| 48 |
|
|
| 13 |
|
Other |
| 452 |
|
|
| 466 |
|
Other current liabilities | $ | 1,066 |
|
| $ | 650 |
|
91
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.
|
| December 31, 2016 |
|
| December 31, 2015 |
| ||
|
| (Millions) |
| |||||
Devon debt: |
|
|
|
|
|
|
|
|
Commercial paper |
| $ | — |
|
| $ | 626 |
|
Floating rate due December 15, 2016 |
|
| — |
|
|
| 350 |
|
8.25% due July 1, 2018 (1)(2) |
|
| 20 |
|
|
| 125 |
|
2.25% due December 15, 2018 (1) |
|
| 95 |
|
|
| 750 |
|
6.30% due January 15, 2019 (1) |
|
| 162 |
|
|
| 700 |
|
4.00% due July 15, 2021 |
|
| 500 |
|
|
| 500 |
|
3.25% due May 15, 2022 |
|
| 1,000 |
|
|
| 1,000 |
|
5.85% due December 15, 2025 (1) |
|
| 485 |
|
|
| 850 |
|
7.50% due September 15, 2027 (1)(2) |
|
| 73 |
|
|
| 150 |
|
7.875% due September 30, 2031 (1)(3) |
|
| 1,059 |
|
|
| 1,250 |
|
7.95% due April 15, 2032 (1) |
|
| 789 |
|
|
| 1,000 |
|
5.60% due July 15, 2041 |
|
| 1,250 |
|
|
| 1,250 |
|
4.75% due May 15, 2042 |
|
| 750 |
|
|
| 750 |
|
5.00% due June 15, 2045 |
|
| 750 |
|
|
| 750 |
|
Net discount on debentures and notes |
|
| (30 | ) |
|
| (28 | ) |
Debt issuance costs |
|
| (44 | ) |
|
| (57 | ) |
Total Devon debt |
|
| 6,859 |
|
|
| 9,966 |
|
EnLink and General Partner debt: |
|
|
|
|
|
|
|
|
Credit facilities |
|
| 148 |
|
|
| 414 |
|
2.70% due April 1, 2019 |
|
| 400 |
|
|
| 400 |
|
7.125% due June 1, 2022 |
|
| 163 |
|
|
| 163 |
|
4.40% due April 1, 2024 |
|
| 550 |
|
|
| 550 |
|
4.15% due June 1, 2025 |
|
| 750 |
|
|
| 750 |
|
4.85% due July 15, 2026 |
|
| 500 |
|
|
| — |
|
5.60% due April 1, 2044 |
|
| 350 |
|
|
| 350 |
|
5.05% due April 1, 2045 |
|
| 450 |
|
|
| 450 |
|
Net premium on debentures and notes |
|
| 9 |
|
|
| 13 |
|
Debt issuance costs |
|
| (25 | ) |
|
| (24 | ) |
Total EnLink and General Partner debt |
|
| 3,295 |
|
|
| 3,066 |
|
Total debt |
|
| 10,154 |
|
|
| 13,032 |
|
Less amount classified as short-term debt (4) |
|
| — |
|
|
| 976 |
|
Total long-term debt |
| $ | 10,154 |
|
| $ | 12,056 |
|
|
| December 31, 2018 |
|
| December 31, 2017 |
| ||
8.25% due July 1, 2018 (1) |
| $ | — |
|
| $ | 20 |
|
2.25% due December 15, 2018 |
|
| — |
|
|
| 95 |
|
6.30% due January 15, 2019 |
|
| 162 |
|
|
| 162 |
|
4.00% due July 15, 2021 |
|
| 500 |
|
|
| 500 |
|
3.25% due May 15, 2022 |
|
| 1,000 |
|
|
| 1,000 |
|
5.85% due December 15, 2025 |
|
| 485 |
|
|
| 485 |
|
7.50% due September 15, 2027 (1) |
|
| 73 |
|
|
| 73 |
|
7.875% due September 30, 2031 (2) (3) |
|
| 675 |
|
|
| 1,059 |
|
7.95% due April 15, 2032 (2) |
|
| 366 |
|
|
| 789 |
|
5.60% due July 15, 2041 |
|
| 1,250 |
|
|
| 1,250 |
|
4.75% due May 15, 2042 |
|
| 750 |
|
|
| 750 |
|
5.00% due June 15, 2045 |
|
| 750 |
|
|
| 750 |
|
Net discount on debentures and notes |
|
| (24 | ) |
|
| (30 | ) |
Debt issuance costs |
|
| (40 | ) |
|
| (39 | ) |
Total debt |
|
| 5,947 |
|
|
| 6,864 |
|
Less amount classified as short-term debt (4) |
|
| 162 |
|
|
| 115 |
|
Total long-term debt |
| $ | 5,785 |
|
| $ | 6,749 |
|
(1) |
|
| These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, |
(2) | These senior notes were included in 2018 tender offer repurchases discussed below. |
(3) | Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned |
(4) |
|
92Debt maturities as of December 31, 2018, excluding debt issuance costs, premiums and discounts, are as follows:
|
| Total |
| |
2019 |
| $ | 162 |
|
2020 |
|
| — |
|
2021 |
|
| 500 |
|
2022 |
|
| 1,000 |
|
2023 |
|
| — |
|
Thereafter |
|
| 4,349 |
|
Total |
| $ | 6,011 |
|
85
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Debt maturities asCredit Lines
Under its 2012 Senior Credit Facility, Devon had $3.0 billion of December 31, 2016, excluding debt issuance costs, premiumsavailable credit. On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and discounts, are as follows (millions):
2017 |
| $ | — |
|
2018 |
|
| 115 |
|
2019 |
|
| 590 |
|
2020 |
|
| 120 |
|
2021 |
|
| 500 |
|
Thereafter |
|
| 8,919 |
|
Total |
| $ | 10,244 |
|
Credit Lines
Devon has asubsequently entered into its new $3.0 billion revolving 2018 Senior Credit Facility. The facility2018 Senior Credit Facility matures as follows: $30 million on October 24, 2017, $164 million on October 24, 2018 and5, 2023, with the remaining $2.8 billion on October 24, 2019.option to extend the maturity date by two additional one-year periods subject to lender consent. Amounts borrowed under the 2018 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 2018 Senior Credit Facility currently provides for an annual facility fee of $7.6$6.1 million. As of December 31, 2016,2018, Devon had $140 million in outstanding letters of credit, including $57$48 million in outstanding letters of credit under the 2018 Senior Credit Facility. There were no borrowings under the Senior Credit Facility as of December 31, 2016.2018.
The 2018 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. Also,For example, total capitalization is adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2016,2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 18.7%21.0%.
Commercial Paper
Devon’s 2018 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, 2016,2018, Devon had no outstanding commercial paper borrowings.
Retirement of Senior Notes
During 2018, Devon completed tender offers to repurchase $807 million in aggregate principal amount of debt using cash on hand. This included $384 million of the 7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million loss on early retirement of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along with other charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings. In December 2018, Devon repaid the $95 million of 2.25% senior notes at maturity. Additionally, in January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity.
During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 2.2. Devon recognized a loss on early retirement of debt, primarily consisting of $265 million in cash retirement costs and other fees. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.
In November 2014, Devon redeemed $1.9 billion 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, primarily
9386
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
consistingFinancing Costs, Net
The following schedule includes the components of $40 million in cash retirement costs and other noncash charges. These costs are included in net financing costscosts.
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Interest based on debt outstanding |
| $ | 339 |
|
| $ | 390 |
|
| $ | 488 |
|
Early retirement of debt |
|
| 312 |
|
|
| — |
|
|
| 269 |
|
Capitalized interest |
|
| (41 | ) |
|
| (69 | ) |
|
| (61 | ) |
Other |
|
| (16 | ) |
|
| (4 | ) |
|
| 21 |
|
Total net financing costs |
| $ | 594 |
|
| $ | 317 |
|
| $ | 717 |
|
16. | Asset Retirement Obligations |
The following table presents the changes in asset retirement obligations.
|
| Year Ended December 31, |
| |||||
|
| 2018 |
|
| 2017 |
| ||
Asset retirement obligations as of beginning of period |
| $ | 1,138 |
|
| $ | 1,258 |
|
Liabilities incurred |
|
| 39 |
|
|
| 40 |
|
Liabilities settled and divested |
|
| (116 | ) |
|
| (68 | ) |
Revision of estimated obligation |
|
| (25 | ) |
|
| (184 | ) |
Accretion expense on discounted obligation |
|
| 59 |
|
|
| 62 |
|
Foreign currency translation adjustment |
|
| (38 | ) |
|
| 30 |
|
Asset retirement obligations as of end of period |
|
| 1,057 |
|
|
| 1,138 |
|
Less current portion |
|
| 27 |
|
|
| 39 |
|
Asset retirement obligations, long-term |
| $ | 1,030 |
|
| $ | 1,099 |
|
During 2018, Devon reduced its asset retirement obligation by $84 million, primarily as a result of Devon’s 2018 divestitures. For additional information, see Note 2.
During 2017, Devon reduced its asset retirement obligations by $184 million, primarily due to changes in the consolidated comprehensive statementassumed inflation rate and retirement dates for its oil and gas assets.
17. | Retirement Plans |
Defined Contribution Plans
Devon sponsors defined contribution plans covering its employees in the U.S. and Canada. Such plans include its 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of earnings.annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. Devon contributed $50 million, $53 million and $57 million to these plans in 2018, 2017 and 2016, respectively.
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.
9487
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Net Financing CostsDefined Benefit Plans
The following schedule includes the components of net financing costs.
|
| 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 |
|
The following table presents the changes in asset retirement obligations.
|
| 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 |
|
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 certaincovering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits forunder the qualifieddefined benefit plans arehave been closed to new employees; however, eligible employees continue to accrue benefits based on the employees’upon years of service and compensation andcompensation. Benefits are primarily funded from assets held in the plans’ trusts.
95
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’ years 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, 2016 and 2015, respectively and is included in other long-term assets in the accompanying consolidated balance sheets. For the remaining nonqualified plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.
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.
96
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Benefit Obligations and Funded Status
The following table presents the funded status of Devon’s qualified and nonqualified pension and postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs 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 $193 million and $342 million at December 31, 2018 and 2017, 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 $301 million and $401 million at December 31, 2018 and 2017, 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 $84 million and $157 million at December 31, 2018 and 2017, respectively.
Other securities – Devon’s other securities include cash and commingled, short-term investment funds. The short-term investment funds’ 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 investment managers.
Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategiesfunds and a hedge fund of funds that investsinvest both long 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 3these securities is based upon the net asset values provided by investment representsmanagers and were $132 million and $135 million at December 31, 2018 and 2017, respectively.
Defined Postretirement Plans
Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the fair valueplans is to fund the benefits as determined by the hedge fund manager.they become payable with available cash and cash equivalents.
Benefit Obligations and Funded Status
The following table presents a summary ofsummarizes the changes inbenefit obligations, assets, funded status and balance sheet impacts associated with its defined pension and postretirement plans. Devon’s Level 3benefit obligations and plan assets (millions).are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2018 and 2017.
December 31, 2014 |
| $ | 112 |
|
Purchases |
|
| 5 |
|
Investment returns |
|
| 3 |
|
December 31, 2015 |
|
| 120 |
|
Investments sold |
|
| (12 | ) |
Investment returns |
|
| 4 |
|
December 31, 2016 |
| $ | 112 |
|
10188
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| $ | 1,279 |
|
| $ | 1,249 |
|
| $ | 19 |
|
| $ | 21 |
|
Service cost |
|
| 10 |
|
|
| 15 |
|
|
| — |
|
|
| — |
|
Interest cost |
|
| 39 |
|
|
| 42 |
|
|
| — |
|
|
| — |
|
Actuarial loss (gain) |
|
| (83 | ) |
|
| 59 |
|
|
| (3 | ) |
|
| — |
|
Plan amendments |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Plan curtailments |
|
| 2 |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
Plan settlements |
|
| (241 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Foreign exchange rate changes |
|
| (3 | ) |
|
| 2 |
|
|
| — |
|
|
| — |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| 1 |
|
Benefits paid |
|
| (60 | ) |
|
| (88 | ) |
|
| (3 | ) |
|
| (3 | ) |
Benefit obligation at end of year |
|
| 943 |
|
|
| 1,279 |
|
|
| 17 |
|
|
| 19 |
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
| 1,035 |
|
|
| 985 |
|
|
| — |
|
|
| — |
|
Actual return on plan assets |
|
| (36 | ) |
|
| 122 |
|
|
| — |
|
|
| — |
|
Employer contributions |
|
| 14 |
|
|
| 14 |
|
|
| 1 |
|
|
| 2 |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| 1 |
|
Plan settlements |
|
| (241 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Benefits paid |
|
| (60 | ) |
|
| (88 | ) |
|
| (3 | ) |
|
| (3 | ) |
Foreign exchange rate changes |
|
| (3 | ) |
|
| 2 |
|
|
| — |
|
|
| — |
|
Fair value of plan assets at end of year |
|
| 709 |
|
|
| 1,035 |
|
|
| — |
|
|
| — |
|
Funded status at end of year |
| $ | (234 | ) |
| $ | (244 | ) |
| $ | (17 | ) |
| $ | (19 | ) |
Amounts recognized in balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term assets |
| $ | 3 |
|
| $ | 4 |
|
| $ | — |
|
| $ | — |
|
Other current liabilities |
|
| (14 | ) |
|
| (13 | ) |
|
| (3 | ) |
|
| (3 | ) |
Other long-term liabilities |
|
| (223 | ) |
|
| (235 | ) |
|
| (14 | ) |
|
| (16 | ) |
Net amount |
| $ | (234 | ) |
| $ | (244 | ) |
| $ | (17 | ) |
| $ | (19 | ) |
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain) |
| $ | 202 |
|
| $ | 257 |
|
| $ | (11 | ) |
| $ | (11 | ) |
Prior service cost (credit) |
|
| 4 |
|
|
| 6 |
|
|
| (2 | ) |
|
| (3 | ) |
Total |
| $ | 206 |
|
| $ | 263 |
|
| $ | (13 | ) |
| $ | (14 | ) |
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 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 comprehensive statements of earnings in 2018.
89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2018 and December 31, 2017, as presented in the table below.
|
| December 31, |
| |||||
|
| 2018 |
|
| 2017 |
| ||
Projected benefit obligation |
| $ | 922 |
|
| $ | 1,255 |
|
Accumulated benefit obligation |
| $ | 906 |
|
| $ | 1,226 |
|
Fair value of plan assets |
| $ | 685 |
|
| $ | 1,007 |
|
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 10 |
|
| $ | 15 |
|
| $ | 15 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Interest cost |
|
| 39 |
|
|
| 42 |
|
|
| 42 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Expected return on plan assets |
|
| (49 | ) |
|
| (54 | ) |
|
| (55 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial loss (gain) (1) |
|
| 13 |
|
|
| 19 |
|
|
| 25 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Recognition of prior service cost (1) |
|
| 1 |
|
|
| 2 |
|
|
| 3 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Total net periodic benefit cost (2) |
|
| 14 |
|
|
| 24 |
|
|
| 30 |
|
|
| (2 | ) |
|
| (2 | ) |
|
| (1 | ) |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss (gain) arising in current year |
|
| 4 |
|
|
| (9 | ) |
|
| 26 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| — |
|
Prior service cost arising in current year |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) |
|
| (60 | ) |
|
| (19 | ) |
|
| (43 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) |
|
| (2 | ) |
|
| (2 | ) |
|
| (9 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Total other comprehensive loss (earnings) |
|
| (58 | ) |
|
| (30 | ) |
|
| (24 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 2 |
|
Total recognized |
| $ | (44 | ) |
| $ | (6 | ) |
| $ | 6 |
|
| $ | (1 | ) |
| $ | (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 comprehensive statements of earnings. |
(3) | These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6 for further discussion. |
Assumptions
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 4.21% |
|
| 3.59% |
|
| 4.07% |
|
| 4.01% |
|
| 3.25% |
|
| 3.46% |
| ||||||
Rate of compensation increase |
| 2.50% |
|
| 2.50% |
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
| ||||||
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate - service cost |
| 3.98% |
|
| 4.29% |
|
| 4.39% |
|
| 4.13% |
|
| 4.22% |
|
| 3.63% |
| ||||||
Discount rate - interest cost |
| 3.22% |
|
| 2.99% |
|
| 4.39% |
|
| 2.67% |
|
| 2.39% |
|
| 3.63% |
| ||||||
Rate of compensation increase |
| 2.50% |
|
| 4.48% |
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
| ||||||
Expected return on plan assets |
| 5.67% |
|
| 5.69% |
|
| 5.20% |
|
| N/A |
|
| N/A |
|
| N/A |
| ||||||
90
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 and an improvement scale derived from the updated tables for 2017 and 2018 and the actuary’s best estimate of mortality for 2016 for the population of participants in Devon’s plans.
Other assumptions – For measurement of the 2018 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 2019. 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
The table below presents contributions expectedDevon expects benefit plan payments to be made to Devon’s qualified plans, nonqualified plansaverage approximately $59 million a year for the next five years and postretirement plans.$153 million total for the five years thereafter. Of the benefits expectedthese payments to be paid in 2017, $132019, $17 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 Issued
In January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition discussed in Note 2.2. 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 the offering were $1.5 billion.
Share Repurchase Program
In December 2015,March 2018, Devon issued approximately 7 millionannounced a share repurchase program to buy up to $1.0 billion of shares of common stock as partstock. In June 2018, in conjunction with the announced divestiture of its investment in EnLink and the General Partner, Devon increased its program by an additional $3.0 billion. In February 2019, Devon’s Board of Directors authorized an expansion of the Powder River Basin asset acquisition discussed in Note 2. share repurchase program by an additional $1.0 billion, bringing the total to $5.0 billion. The share repurchase program expires December 31, 2019.
10291
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
During the third quarter of 2018, Devon entered into and completed an ASR transaction to repurchase $1.0 billion of the $4.0 billion program. The table below provides information regarding purchases of Devon’s common stock that were made during 2018 (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 |
|
Total year-to-date |
|
| 78,149 |
|
| $ | 2,978 |
|
| $ | 38.11 |
|
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 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 |
|
|
|
|
|
Year Ended 2016: |
|
|
|
|
|
|
|
First quarter | $ | 125 |
|
| $ | 0.24 |
|
Second quarter |
| 33 |
|
| $ | 0.06 |
|
Third quarter |
| 32 |
|
| $ | 0.06 |
|
Fourth quarter |
| 31 |
|
| $ | 0.06 |
|
Total year-to-date | $ | 221 |
|
|
|
|
|
Subsidiary Equity Transactions
DuringIn response to the firstdepressed commodity price environment, Devon reduced the quarterly dividend rate from $0.24 to $0.06 per share in the second quarter of 2016, EnLink issued common units in conjunction with2016. Devon increased the Tall Oak acquisition discussed in Note 2. Through its equity distribution agreements, EnLink has the abilityquarterly dividend by 33% 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$0.08 per share in the General Partner and EnLink since inception.second quarter of 2018. In February 2019, Devon announced a 12.5% increase to its quarterly dividend, to $0.09 per share, beginning in the second quarter of 2019.
|
| 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% |
|
10392
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
19. | Discontinued Operations and Assets Held For Sale |
On June 6, 2018, Devon announced that it had entered into an agreement to Noncontrolling Interests
In conjunction with the formation of the General Partnersell its aggregate ownership interests in 2014, Devon made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $304for $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 part of its assessment, Devon considered the following: 1) Devon is exiting its entire midstream business ownership; 2) EnLink and the General Partner are a separate reportable segment and are a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, debt, revenues, net earnings and operating cash flows. 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. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was signed.
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 explained inNote 8.
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.
From the period of July 19, 2018 through December 31, 2018, Devon had net outflows of approximately $380 million $254 millionwith EnLink, which primarily related to gathering and $135 millionprocessing expenses. These net outflows represent gross cash amounts and not net working interest amounts.
Prior to non-Devon unitholders during 2016, 2015the divestment of Devon’s aggregate ownership of EnLink and 2014, respectively.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.
93
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations.
|
| Year Ended December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2016 |
| |||
Marketing and midstream revenues |
| $ | 3,567 |
|
| $ | 5,071 |
|
| $ | 3,551 |
|
Marketing and midstream expenses |
|
| 2,912 |
|
|
| 4,111 |
|
|
| 2,712 |
|
Depreciation, depletion and amortization |
|
| 244 |
|
|
| 545 |
|
|
| 504 |
|
General and administrative expenses |
|
| 65 |
|
|
| 128 |
|
|
| 118 |
|
Financing costs, net |
|
| 98 |
|
|
| 181 |
|
|
| 190 |
|
Asset impairments |
|
| — |
|
|
| 17 |
|
|
| 873 |
|
Asset dispositions |
|
| (2,607 | ) |
|
| — |
|
|
| 13 |
|
Other expenses |
|
| (8 | ) |
|
| (34 | ) |
|
| 25 |
|
Total expenses |
|
| 704 |
|
|
| 4,948 |
|
|
| 4,435 |
|
Earnings (loss) from discontinued operations before income taxes |
|
| 2,863 |
|
|
| 123 |
|
|
| (884 | ) |
Income tax expense (benefit) |
|
| 403 |
|
|
| (197 | ) |
|
| — |
|
Net earnings (loss) from discontinued operations, net of income tax expense |
|
| 2,460 |
|
|
| 320 |
|
|
| (884 | ) |
Net earnings (loss) attributable to noncontrolling interests |
|
| 160 |
|
|
| 180 |
|
|
| (403 | ) |
Net earnings (loss) from discontinued operations attributable to Devon |
| $ | 2,300 |
|
| $ | 140 |
|
| $ | (481 | ) |
The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets. The assets and liabilities classified as held for sale at December 31, 2018 are related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2. The assets and liabilities classified as held for sale at December 31, 2017 are related to the divestiture of EnLink and the General Partner.
|
| December 31, 2018 |
|
| December 31, 2017 |
| ||
Cash and cash equivalents |
| $ | — |
|
| $ | 31 |
|
Accounts receivable |
|
| 7 |
|
|
| 681 |
|
Other current assets |
|
| — |
|
|
| 48 |
|
Oil and gas property and equipment, based on successful efforts accounting, net |
|
| 190 |
|
|
| — |
|
Midstream and other property and equipment, net |
|
| — |
|
|
| 6,587 |
|
Goodwill |
|
| — |
|
|
| 1,542 |
|
Other long-term assets |
|
| — |
|
|
| 1,600 |
|
Total assets held for sale |
| $ | 197 |
|
| $ | 10,489 |
|
|
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 3 |
|
| $ | 186 |
|
Revenues and royalties payable |
|
| — |
|
|
| 432 |
|
Other current liabilities |
|
| 19 |
|
|
| 373 |
|
Long-term debt |
|
| — |
|
|
| 3,542 |
|
Deferred income taxes |
|
| — |
|
|
| 346 |
|
Asset retirement obligations |
|
| 47 |
|
|
| 14 |
|
Other long-term liabilities |
|
| — |
|
|
| 34 |
|
Total liabilities held for sale |
| $ | 69 |
|
| $ | 4,927 |
|
94
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.
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 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 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.
Beginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although we cannot predict the ultimate outcome of these matters, Devon is vigorously defending against these claims.
Other Matters
Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
10495
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, 2016.2018.
Year Ending December 31, |
| Purchase Obligations |
|
| Drilling and Facility Obligations |
|
| Operational Agreements |
|
| Office and Equipment Leases |
|
| EnLink Obligations |
|
| Purchase 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 |
|
| $ | 541 |
|
| $ | 274 |
|
| $ | 587 |
|
| $ | 64 |
|
2020 |
|
| 748 |
|
|
| 57 |
|
|
| 457 |
|
|
| 59 |
|
|
| 18 |
|
|
| 567 |
|
|
| 85 |
|
|
| 519 |
|
|
| 43 |
|
2021 |
|
| 181 |
|
|
| 37 |
|
|
| 285 |
|
|
| 39 |
|
|
| 17 |
|
|
| 140 |
|
|
| 48 |
|
|
| 373 |
|
|
| 31 |
|
2022 |
|
| — |
|
|
| 14 |
|
|
| 419 |
|
|
| 26 |
| ||||||||||||||||||||
2023 |
|
| — |
|
|
| 8 |
|
|
| 354 |
|
|
| 25 |
| ||||||||||||||||||||
Thereafter |
|
| — |
|
|
| 85 |
|
|
| 2,667 |
|
|
| 55 |
|
|
| 102 |
|
|
| — |
|
|
| 16 |
|
|
| 3,374 |
|
|
| 311 |
|
Total |
| $ | 2,949 |
|
| $ | 388 |
|
| $ | 6,315 |
|
| $ | 371 |
|
| $ | 271 |
|
| $ | 1,248 |
|
| $ | 445 |
|
| $ | 5,626 |
|
| $ | 500 |
|
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.
Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. The value of the drilling obligations reported is based on gross contractual value.
Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.
Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in G&A underrecognized for operating leases, net of sublease income, was $78$11 million, $88$7 million and $64$11 million in 2016, 20152018, 2017 and 2014,2016, respectively.
10596
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, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at December 31, 20162018 and December 31, 2015.2017, 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. MoreAdditional information on these itemsasset impairments and the pension plan assets is provided in Note 5, and Note 12 and Note 16,17, respectively.
|
|
|
|
|
|
|
|
|
| Fair Value |
|
|
|
|
|
|
|
|
|
| Fair Value Measurements Using: |
| ||||||||||
|
|
|
|
|
|
|
|
|
| Measurements Using: |
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
| |||||||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
| ||||||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
| ||||||||||||||||||||
|
| (Millions) |
| |||||||||||||||||||||||||||||
December 31, 2016 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
December 31, 2018 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Cash equivalents |
| $ | 1,505 |
|
| $ | 1,505 |
|
| $ | 1,405 |
|
| $ | 100 |
| ||||||||||||||||
Commodity derivatives |
| $ | 677 |
|
| $ | 677 |
|
| $ | — |
|
| $ | 677 |
| ||||||||||||||||
Commodity derivatives |
| $ | (68 | ) |
| $ | (68 | ) |
| $ | — |
|
| $ | (68 | ) | ||||||||||||||||
Debt |
| $ | (5,947 | ) |
| $ | (5,965 | ) |
| $ | — |
|
| $ | (5,965 | ) | ||||||||||||||||
December 31, 2017 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Cash equivalents |
| $ | 1,542 |
|
| $ | 1,542 |
|
| $ | 1,298 |
|
| $ | 244 |
|
| $ | 1,533 |
|
| $ | 1,533 |
|
| $ | 1,454 |
|
| $ | 79 |
|
Commodity derivatives |
| $ | 10 |
|
| $ | 10 |
|
| $ | — |
|
| $ | 10 |
|
| $ | 205 |
|
| $ | 205 |
|
| $ | — |
|
| $ | 205 |
|
Commodity derivatives |
| $ | (203 | ) |
| $ | (203 | ) |
| $ | — |
|
| $ | (203 | ) |
| $ | (286 | ) |
| $ | (286 | ) |
| $ | — |
|
| $ | (286 | ) |
Interest rate derivatives |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
Interest rate derivatives |
| $ | (41 | ) |
| $ | (41 | ) |
| $ | — |
|
| $ | (41 | ) |
| $ | (64 | ) |
| $ | (64 | ) |
| $ | — |
|
| $ | (64 | ) |
Debt |
| $ | (10,154 | ) |
| $ | (10,760 | ) |
| $ | — |
|
| $ | (10,760 | ) |
| $ | (6,864 | ) |
| $ | (8,131 | ) |
| $ | — |
|
| $ | (8,131 | ) |
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 | ) | ||||||||||||||||
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 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 and interest rate and foreign currency derivatives– The fair values of commodity and interest rate and foreign currency derivatives are 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
97
Table of commercial paper and credit facility balances are the carrying values.Contents
Installment payment
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – 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.(Continued)
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 22.23.
107
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon considers EnLink, combined with the General Partner, to be an operatinga segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located acrossin the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore,However, with Devon’s closing of the divestment of EnLink isand the General Partner in July 2018, activity related to EnLink and the General Partner have now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows, and the associated assets and liabilities of EnLink and the General Partner are presented as a separate reporting segment.assets and liabilities held for sale on the consolidated balance sheets. Additional information can be found in Note 19.
|
| 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 |
|
10898
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Year Ended December 31, 2018: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers (1) |
| $ | 9,674 |
|
| $ | 1,060 |
|
| $ | 10,734 |
|
Depreciation, depletion and amortization |
| $ | 1,328 |
|
| $ | 330 |
|
| $ | 1,658 |
|
Interest expense |
| $ | 469 |
|
| $ | 166 |
|
| $ | 635 |
|
Asset impairments |
| $ | 156 |
|
| $ | — |
|
| $ | 156 |
|
Asset dispositions |
| $ | (263 | ) |
| $ | — |
|
| $ | (263 | ) |
Restructuring and transaction costs |
| $ | 97 |
|
| $ | 17 |
|
| $ | 114 |
|
Earnings (loss) from continuing operations before income taxes |
| $ | 1,294 |
|
| $ | (374 | ) |
| $ | 920 |
|
Income tax expense (benefit) |
| $ | 294 |
|
| $ | (138 | ) |
| $ | 156 |
|
Net earnings (loss) from continuing operations |
| $ | 1,000 |
|
| $ | (236 | ) |
| $ | 764 |
|
Property and equipment, net |
| $ | 10,026 |
|
| $ | 3,909 |
|
| $ | 13,935 |
|
Total assets (2) |
| $ | 14,853 |
|
| $ | 4,516 |
|
| $ | 19,369 |
|
Capital expenditures, including acquisitions |
| $ | 2,294 |
|
| $ | 282 |
|
| $ | 2,576 |
|
Year Ended December 31, 2017: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 7,326 |
|
| $ | 1,552 |
|
| $ | 8,878 |
|
Depreciation, depletion and amortization |
| $ | 1,149 |
|
| $ | 380 |
|
| $ | 1,529 |
|
Interest expense |
| $ | 324 |
|
| $ | 12 |
|
| $ | 336 |
|
Asset dispositions |
| $ | (218 | ) |
| $ | 1 |
|
| $ | (217 | ) |
Earnings from continuing operations before income taxes |
| $ | 443 |
|
| $ | 330 |
|
| $ | 773 |
|
Income tax expense |
| $ | 9 |
|
| $ | 6 |
|
| $ | 15 |
|
Net earnings from continuing operations |
| $ | 434 |
|
| $ | 324 |
|
| $ | 758 |
|
Property and equipment, net |
| $ | 10,274 |
|
| $ | 4,310 |
|
| $ | 14,584 |
|
Total assets (3) |
| $ | 14,254 |
|
| $ | 5,498 |
|
| $ | 19,752 |
|
Capital expenditures, including acquisitions |
| $ | 1,821 |
|
| $ | 348 |
|
| $ | 2,169 |
|
Year Ended December 31, 2016: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 5,722 |
|
| $ | 1,031 |
|
| $ | 6,753 |
|
Depreciation, depletion and amortization |
| $ | 1,178 |
|
| $ | 414 |
|
| $ | 1,592 |
|
Interest expense |
| $ | 624 |
|
| $ | 100 |
|
| $ | 724 |
|
Asset impairments |
| $ | 435 |
|
| $ | 2 |
|
| $ | 437 |
|
Asset dispositions |
| $ | (955 | ) |
| $ | (541 | ) |
| $ | (1,496 | ) |
Restructuring and transaction costs |
| $ | 242 |
|
| $ | 19 |
|
| $ | 261 |
|
Earnings (loss) from continuing operations before income taxes |
| $ | (757 | ) |
| $ | 324 |
|
| $ | (433 | ) |
Income tax expense (benefit) |
| $ | (8 | ) |
| $ | 149 |
|
| $ | 141 |
|
Net earnings (loss) from continuing operations |
| $ | (749 | ) |
| $ | 175 |
|
| $ | (574 | ) |
Property and equipment, net |
| $ | 10,166 |
|
| $ | 4,110 |
|
| $ | 14,276 |
|
Total assets (3) |
| $ | 13,390 |
|
| $ | 5,071 |
|
| $ | 18,461 |
|
Capital expenditures, including acquisitions |
| $ | 2,640 |
|
| $ | 186 |
|
| $ | 2,826 |
|
(1) Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers.
(2) Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million.
(3) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively.
99
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents revenue from contracts with customers that are disaggregated based on the type of good.
|
| Year Ended December 31, 2018 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil |
| $ | 2,957 |
|
| $ | 814 |
|
| $ | 3,771 |
|
Gas |
|
| 950 |
|
|
| — |
|
|
| 950 |
|
NGL |
|
| 956 |
|
|
| — |
|
|
| 956 |
|
Oil, gas and NGL revenues from contracts with customers |
|
| 4,863 |
|
|
| 814 |
|
|
| 5,677 |
|
Oil, gas and NGL derivatives |
|
| 457 |
|
|
| 151 |
|
|
| 608 |
|
Upstream revenues |
|
| 5,320 |
|
|
| 965 |
|
|
| 6,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
| 2,745 |
|
|
| 95 |
|
|
| 2,840 |
|
Gas |
|
| 738 |
|
|
| — |
|
|
| 738 |
|
NGL |
|
| 871 |
|
|
| — |
|
|
| 871 |
|
Total marketing revenues from contracts with customers |
|
| 4,354 |
|
|
| 95 |
|
|
| 4,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
| $ | 9,674 |
|
| $ | 1,060 |
|
| $ | 10,734 |
|
Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country.
100
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.
|
| Year Ended December 31, 2018 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Proved properties |
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
| ||||||||||||
Unproved properties |
|
| 71 |
|
|
| — |
|
|
| 71 |
| ||||||||||||
Exploration costs |
|
| 679 |
|
|
| 85 |
|
|
| 764 |
| ||||||||||||
Development costs |
|
| 1,537 |
|
|
| 249 |
|
|
| 1,786 |
| ||||||||||||
Costs incurred |
| $ | 2,289 |
|
| $ | 334 |
|
| $ | 2,623 |
| ||||||||||||
|
| Year Ended December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Year Ended December 31, 2017 |
| ||||||||||||
|
| (Millions) |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
| $ | 237 |
|
| $ | — |
|
| $ | 237 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
|
Unproved properties |
|
| 1,356 |
|
|
| 2 |
|
|
| 1,358 |
|
|
| 50 |
|
|
| 4 |
|
|
| 54 |
|
Exploration costs |
|
| 345 |
|
|
| 49 |
|
|
| 394 |
|
|
| 590 |
|
|
| 87 |
|
|
| 677 |
|
Development costs |
|
| 1,034 |
|
|
| 109 |
|
|
| 1,143 |
|
|
| 1,036 |
|
|
| 225 |
|
|
| 1,261 |
|
Costs incurred |
| $ | 2,972 |
|
| $ | 160 |
|
| $ | 3,132 |
|
| $ | 1,678 |
|
| $ | 316 |
|
| $ | 1,994 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2015 |
|
| Year Ended December 31, 2016 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||
|
| (Millions) |
| |||||||||||||||||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
| $ | 193 |
|
| $ | 2 |
|
| $ | 195 |
|
| $ | 237 |
|
| $ | — |
|
| $ | 237 |
|
Unproved properties |
|
| 634 |
|
|
| 83 |
|
|
| 717 |
|
|
| 1,356 |
|
|
| 2 |
|
|
| 1,358 |
|
Exploration costs |
|
| 478 |
|
|
| 109 |
|
|
| 587 |
|
|
| 282 |
|
|
| 78 |
|
|
| 360 |
|
Development costs |
|
| 3,269 |
|
|
| 402 |
|
|
| 3,671 |
|
|
| 875 |
|
|
| 54 |
|
|
| 929 |
|
Costs incurred |
| $ | 4,574 |
|
| $ | 596 |
|
| $ | 5,170 |
|
| $ | 2,750 |
|
| $ | 134 |
|
| $ | 2,884 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| 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
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,Additionally, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $64$41 million, $54$69 million and $45$61 million in 2018, 2017 and 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
110101
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, 2018 |
| ||||||||||||
|
| (Millions) |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||||||||
Oil, gas and NGL sales |
| $ | 3,198 |
|
| $ | 984 |
|
| $ | 4,182 |
|
| $ | 4,863 |
|
| $ | 814 |
|
| $ | 5,677 |
|
Lease operating expenses |
|
| (1,123 | ) |
|
| (459 | ) |
|
| (1,582 | ) | ||||||||||||
General and administrative expenses |
|
| (148 | ) |
|
| (20 | ) |
|
| (168 | ) | ||||||||||||
Production and property taxes |
|
| (200 | ) |
|
| (31 | ) |
|
| (231 | ) | ||||||||||||
Production expenses |
|
| (1,620 | ) |
|
| (605 | ) |
|
| (2,225 | ) | ||||||||||||
Exploration expenses |
|
| (129 | ) |
|
| (48 | ) |
|
| (177 | ) | ||||||||||||
Depreciation, depletion and amortization |
|
| (817 | ) |
|
| (326 | ) |
|
| (1,143 | ) |
|
| (1,234 | ) |
|
| (325 | ) |
|
| (1,559 | ) |
Gains on asset sales |
|
| 1,351 |
|
|
| — |
|
|
| 1,351 |
| ||||||||||||
Asset dispositions |
|
| 262 |
|
|
| — |
|
|
| 262 |
| ||||||||||||
Asset impairments |
|
| (2,809 | ) |
|
| (1,291 | ) |
|
| (4,100 | ) |
|
| (109 | ) |
|
| — |
|
|
| (109 | ) |
Accretion of asset retirement obligations |
|
| (49 | ) |
|
| (25 | ) |
|
| (74 | ) |
|
| (35 | ) |
|
| (24 | ) |
|
| (59 | ) |
Income tax benefit |
|
| — |
|
|
| 245 |
|
|
| 245 |
| ||||||||||||
Income tax (expense) benefit |
|
| (460 | ) |
|
| 51 |
|
|
| (409 | ) | ||||||||||||
Results of operations |
| $ | (597 | ) |
| $ | (923 | ) |
| $ | (1,520 | ) |
| $ | 1,538 |
|
| $ | (137 | ) |
| $ | 1,401 |
|
Depreciation, depletion and amortization per Boe |
| $ | 4.68 |
|
| $ | 6.65 |
|
| $ | 5.11 |
|
| $ | 8.08 |
|
| $ | 7.63 |
|
| $ | 7.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| 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 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| Year Ended December 31, 2017 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 3,746 |
|
| $ | 1,404 |
|
| $ | 5,150 |
|
Production expenses |
|
| (1,232 | ) |
|
| (591 | ) |
|
| (1,823 | ) |
Exploration expenses |
|
| (346 | ) |
|
| (34 | ) |
|
| (380 | ) |
Depreciation, depletion and amortization |
|
| (1,050 | ) |
|
| (369 | ) |
|
| (1,419 | ) |
Asset dispositions |
|
| 211 |
|
|
| 1 |
|
|
| 212 |
|
Accretion of asset retirement obligations |
|
| (38 | ) |
|
| (24 | ) |
|
| (62 | ) |
Income tax expense |
|
| — |
|
|
| (104 | ) |
|
| (104 | ) |
Results of operations |
| $ | 1,291 |
|
| $ | 283 |
|
| $ | 1,574 |
|
Depreciation, depletion and amortization per Boe |
| $ | 6.97 |
|
| $ | 7.73 |
|
| $ | 7.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2016 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 3,198 |
|
| $ | 984 |
|
| $ | 4,182 |
|
Production expenses |
|
| (1,313 | ) |
|
| (492 | ) |
|
| (1,805 | ) |
Exploration expenses |
|
| (176 | ) |
|
| (39 | ) |
|
| (215 | ) |
Depreciation, depletion and amortization |
|
| (1,066 | ) |
|
| (380 | ) |
|
| (1,446 | ) |
Asset dispositions |
|
| 946 |
|
|
| 1 |
|
|
| 947 |
|
Asset impairments |
|
| (435 | ) |
|
| — |
|
|
| (435 | ) |
Accretion of asset retirement obligations |
|
| (49 | ) |
|
| (26 | ) |
|
| (75 | ) |
Income tax expense |
|
| — |
|
|
| (13 | ) |
|
| (13 | ) |
Results of operations |
| $ | 1,105 |
|
| $ | 35 |
|
| $ | 1,140 |
|
Depreciation, depletion and amortization per Boe |
| $ | 6.11 |
|
| $ | 7.75 |
|
| $ | 6.47 |
|
111102
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 and by country.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil (MMBbls) |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
| 229 |
|
|
| 56 |
|
|
| 285 |
|
Revisions due to prices |
|
| (1 | ) |
|
| — |
|
|
| (1 | ) |
Revisions other than price |
|
| (38 | ) |
|
| 1 |
|
|
| (37 | ) |
Extensions and discoveries |
|
| 94 |
|
|
| 5 |
|
|
| 99 |
|
Purchase of reserves |
|
| 132 |
|
|
| — |
|
|
| 132 |
|
Production |
|
| (48 | ) |
|
| (10 | ) |
|
| (58 | ) |
Sale of reserves |
|
| (17 | ) |
|
| (29 | ) |
|
| (46 | ) |
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, 2016 |
|
| 194 |
|
|
| 17 |
|
|
| 211 |
|
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, 2016 |
|
| 160 |
|
|
| 17 |
|
|
| 177 |
|
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, 2016 |
|
| 143 |
|
|
| 13 |
|
|
| 156 |
|
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 |
|
113
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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Bitumen |
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGL |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
| Total (MMBoe) (1) |
|
| Oil (MMBbls) |
|
| (MMBbls) |
|
| Gas (Bcf) |
|
| (MMBbls) |
|
| Combined (MMBoe) (1) |
| ||||||||||||||||||||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
|
| Canada |
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| 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 |
|
|
| 242 |
|
|
| 22 |
|
|
| 264 |
|
|
| 520 |
|
|
| 5,808 |
|
|
| 13 |
|
|
| 5,821 |
|
|
| 428 |
|
|
| 1,638 |
|
|
| 544 |
|
|
| 2,182 |
|
Revisions due to prices |
|
| (48 | ) |
|
| 21 |
|
|
| (27 | ) |
|
| (18 | ) |
|
| (2 | ) |
|
| (20 | ) |
|
| 23 |
|
|
| (103 | ) |
|
| — |
|
|
| (103 | ) |
|
| (13 | ) |
|
| (48 | ) |
|
| 21 |
|
|
| (27 | ) |
Revisions other than price |
|
| 151 |
|
|
| (14 | ) |
|
| 137 |
|
|
| (2 | ) |
|
| 3 |
|
|
| 1 |
|
|
| (19 | ) |
|
| 628 |
|
|
| 10 |
|
|
| 638 |
|
|
| 48 |
|
|
| 151 |
|
|
| (14 | ) |
|
| 137 |
|
Extensions and discoveries |
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
|
| 36 |
|
|
| 2 |
|
|
| 38 |
|
|
| — |
|
|
| 280 |
|
|
| — |
|
|
| 280 |
|
|
| 42 |
|
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
Purchase of reserves |
|
| 20 |
|
|
| — |
|
|
| 20 |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 33 |
|
|
| — |
|
|
| 33 |
|
|
| 7 |
|
|
| 20 |
|
|
| — |
|
|
| 20 |
|
Production |
|
| (174 | ) |
|
| (49 | ) |
|
| (223 | ) |
|
| (47 | ) |
|
| (8 | ) |
|
| (55 | ) |
|
| (40 | ) |
|
| (510 | ) |
|
| (7 | ) |
|
| (517 | ) |
|
| (42 | ) |
|
| (174 | ) |
|
| (49 | ) |
|
| (223 | ) |
Sale of reserves |
|
| (157 | ) |
|
| — |
|
|
| (157 | ) |
|
| (25 | ) |
|
| — |
|
|
| (25 | ) |
|
| — |
|
|
| (521 | ) |
|
| — |
|
|
| (521 | ) |
|
| (45 | ) |
|
| (157 | ) |
|
| — |
|
|
| (157 | ) |
December 31, 2016 |
|
| 1,554 |
|
|
| 504 |
|
|
| 2,058 |
|
|
| 194 |
|
|
| 17 |
|
|
| 211 |
|
|
| 484 |
|
|
| 5,615 |
|
|
| 16 |
|
|
| 5,631 |
|
|
| 425 |
|
|
| 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 |
| ||||||||||||||||||||||||||||||||||||||||||||
Revisions due to prices |
|
| 12 |
|
|
| (1 | ) |
|
| 11 |
|
|
| (37 | ) |
|
| 398 |
|
|
| 1 |
|
|
| 399 |
|
|
| 32 |
|
|
| 111 |
|
|
| (38 | ) |
|
| 73 |
| ||||||||||||
Revisions other than price |
|
| 6 |
|
|
| 2 |
|
|
| 8 |
|
|
| (10 | ) |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
|
| (10 | ) |
|
| (5 | ) |
|
| (7 | ) |
|
| (12 | ) | ||||||||||||
Extensions and discoveries |
|
| 90 |
|
|
| 4 |
|
|
| 94 |
|
|
| 12 |
|
|
| 403 |
|
|
| — |
|
|
| 403 |
|
|
| 63 |
|
|
| 221 |
|
|
| 16 |
|
|
| 237 |
| ||||||||||||
Production |
|
| (42 | ) |
|
| (7 | ) |
|
| (49 | ) |
|
| (40 | ) |
|
| (433 | ) |
|
| (6 | ) |
|
| (439 | ) |
|
| (36 | ) |
|
| (150 | ) |
|
| (48 | ) |
|
| (198 | ) | ||||||||||||
Sale of reserves |
|
| (3 | ) |
|
| — |
|
|
| (3 | ) |
|
| — |
|
|
| (9 | ) |
|
| — |
|
|
| (9 | ) |
|
| (1 | ) |
|
| (6 | ) |
|
| — |
|
|
| (6 | ) | ||||||||||||
December 31, 2017 |
|
| 257 |
|
|
| 15 |
|
|
| 272 |
|
|
| 409 |
|
|
| 5,974 |
|
|
| 13 |
|
|
| 5,987 |
|
|
| 473 |
|
|
| 1,725 |
|
|
| 427 |
|
|
| 2,152 |
| ||||||||||||
Revisions due to prices |
|
| 12 |
|
|
| 1 |
|
|
| 13 |
|
|
| 10 |
|
|
| 94 |
|
|
| (3 | ) |
|
| 91 |
|
|
| 12 |
|
|
| 40 |
|
|
| 11 |
|
|
| 51 |
| ||||||||||||
Revisions other than price |
|
| (10 | ) |
|
| 2 |
|
|
| (8 | ) |
|
| 2 |
|
|
| (163 | ) |
|
| (4 | ) |
|
| (167 | ) |
|
| (23 | ) |
|
| (60 | ) |
|
| 3 |
|
|
| (57 | ) | ||||||||||||
Extensions and discoveries |
|
| 93 |
|
|
| 5 |
|
|
| 98 |
|
|
| 7 |
|
|
| 446 |
|
|
| — |
|
|
| 446 |
|
|
| 64 |
|
|
| 232 |
|
|
| 11 |
|
|
| 243 |
| ||||||||||||
Production |
|
| (47 | ) |
|
| (7 | ) |
|
| (54 | ) |
|
| (35 | ) |
|
| (397 | ) |
|
| (4 | ) |
|
| (401 | ) |
|
| (39 | ) |
|
| (153 | ) |
|
| (42 | ) |
|
| (195 | ) | ||||||||||||
Sale of reserves |
|
| (7 | ) |
|
| — |
|
|
| (7 | ) |
|
| — |
|
|
| (1,195 | ) |
|
| — |
|
|
| (1,195 | ) |
|
| (61 | ) |
|
| (267 | ) |
|
| — |
|
|
| (267 | ) | ||||||||||||
December 31, 2018 |
|
| 298 |
|
|
| 16 |
|
|
| 314 |
|
|
| 393 |
|
|
| 4,759 |
|
|
| 2 |
|
|
| 4,761 |
|
|
| 426 |
|
|
| 1,517 |
|
|
| 410 |
|
|
| 1,927 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
December 31, 2015 |
|
| 1,563 |
|
|
| 243 |
|
|
| 1,806 |
|
|
| 203 |
|
|
| 22 |
|
|
| 225 |
|
|
| 219 |
|
|
| 5,694 |
|
|
| 13 |
|
|
| 5,707 |
|
|
| 411 |
|
|
| 1,563 |
|
|
| 243 |
|
|
| 1,806 |
|
December 31, 2016 |
|
| 1,439 |
|
|
| 210 |
|
|
| 1,649 |
|
|
| 160 |
|
|
| 17 |
|
|
| 177 |
|
|
| 190 |
|
|
| 5,361 |
|
|
| 16 |
|
|
| 5,377 |
|
|
| 387 |
|
|
| 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, 2017 |
|
| 178 |
|
|
| 15 |
|
|
| 193 |
|
|
| 200 |
|
|
| 5,619 |
|
|
| 13 |
|
|
| 5,632 |
|
|
| 410 |
|
|
| 1,524 |
|
|
| 218 |
|
|
| 1,742 |
| ||||||||||||
December 31, 2018 |
|
| 198 |
|
|
| 16 |
|
|
| 214 |
|
|
| 187 |
|
|
| 4,331 |
|
|
| 2 |
|
|
| 4,333 |
|
|
| 359 |
|
|
| 1,278 |
|
|
| 204 |
|
|
| 1,482 |
| ||||||||||||
Proved developed-producing reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
December 31, 2015 |
|
| 1,509 |
|
|
| 240 |
|
|
| 1,749 |
|
|
| 192 |
|
|
| 19 |
|
|
| 211 |
|
|
| 219 |
|
|
| 5,546 |
|
|
| 13 |
|
|
| 5,559 |
|
|
| 393 |
|
|
| 1,509 |
|
|
| 240 |
|
|
| 1,749 |
|
December 31, 2016 |
|
| 1,386 |
|
|
| 207 |
|
|
| 1,593 |
|
|
| 143 |
|
|
| 13 |
|
|
| 156 |
|
|
| 190 |
|
|
| 5,243 |
|
|
| 16 |
|
|
| 5,259 |
|
|
| 370 |
|
|
| 1,386 |
|
|
| 207 |
|
|
| 1,593 |
|
Proved undeveloped reserves as of: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||
December 31, 2013 |
|
| 258 |
|
|
| 443 |
|
|
| 701 |
| ||||||||||||||||||||||||||||||||||||||||||||
December 31, 2014 |
|
| 305 |
|
|
| 384 |
|
|
| 689 |
| ||||||||||||||||||||||||||||||||||||||||||||
December 31, 2017 |
|
| 165 |
|
|
| 12 |
|
|
| 177 |
|
|
| 197 |
|
|
| 5,512 |
|
|
| 13 |
|
|
| 5,525 |
|
|
| 397 |
|
|
| 1,481 |
|
|
| 212 |
|
|
| 1,693 |
| ||||||||||||
December 31, 2018 |
|
| 189 |
|
|
| 12 |
|
|
| 201 |
|
|
| 187 |
|
|
| 4,261 |
|
|
| 2 |
|
|
| 4,263 |
|
|
| 349 |
|
|
| 1,249 |
|
|
| 199 |
|
|
| 1,448 |
| ||||||||||||
Proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
December 31, 2015 |
|
| 75 |
|
|
| 301 |
|
|
| 376 |
|
|
| 39 |
|
|
| — |
|
|
| 39 |
|
|
| 301 |
|
|
| 114 |
|
|
| — |
|
|
| 114 |
|
|
| 17 |
|
|
| 75 |
|
|
| 301 |
|
|
| 376 |
|
December 31, 2016 |
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
|
| 34 |
|
|
| — |
|
|
| 34 |
|
|
| 294 |
|
|
| 254 |
|
|
| — |
|
|
| 254 |
|
|
| 38 |
|
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
December 31, 2017 |
|
| 79 |
|
|
| — |
|
|
| 79 |
|
|
| 209 |
|
|
| 355 |
|
|
| — |
|
|
| 355 |
|
|
| 63 |
|
|
| 201 |
|
|
| 209 |
|
|
| 410 |
| ||||||||||||
December 31, 2018 |
|
| 100 |
|
|
| — |
|
|
| 100 |
|
|
| 206 |
|
|
| 428 |
|
|
| — |
|
|
| 428 |
|
|
| 67 |
|
|
| 239 |
|
|
| 206 |
|
|
| 445 |
| ||||||||||||
(1) | Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. |
117103
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 20162018 (MMBoe).
|
|
|
|
|
|
|
|
|
|
|
|
|
| U.S. |
|
| Canada |
|
| Total |
| |||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
Proved undeveloped reserves as of December 31, 2015 |
|
| 75 |
|
|
| 301 |
|
|
| 376 |
| ||||||||||||
Proved undeveloped reserves as of December 31, 2017 |
|
| 201 |
|
|
| 209 |
|
|
| 410 |
| ||||||||||||
Extensions and discoveries |
|
| 78 |
|
|
| — |
|
|
| 78 |
|
|
| 107 |
|
|
| 6 |
|
|
| 113 |
|
Revisions due to prices |
|
| (8 | ) |
|
| 10 |
|
|
| 2 |
|
|
| 1 |
|
|
| 6 |
|
|
| 7 |
|
Revisions other than price |
|
| (1 | ) |
|
| (4 | ) |
|
| (5 | ) |
|
| (8 | ) |
|
| (15 | ) |
|
| (23 | ) |
Sale of reserves |
|
| (1 | ) |
|
| — |
|
|
| (1 | ) |
|
| (10 | ) |
|
| — |
|
|
| (10 | ) |
Conversion to proved developed reserves |
|
| (28 | ) |
|
| (13 | ) |
|
| (41 | ) |
|
| (52 | ) |
|
| — |
|
|
| (52 | ) |
Proved undeveloped reserves as of December 31, 2016 |
|
| 115 |
|
|
| 294 |
|
|
| 409 |
| ||||||||||||
Proved undeveloped reserves as of December 31, 2018 |
|
| 239 |
|
|
| 206 |
|
|
| 445 |
| ||||||||||||
ProvedTotal proved undeveloped reserves increased 9% from 20152017 to 2016, and2018 with the year-end 20162018 balance represents 20%representing 23% of total proved reserves. DrillingDevon’s focus on drilling and development activities in the STACK and Delaware Basin increased Devon’s proved undeveloped reserves by 78 MMBoe.was the primary driver of the 113 MMBoe in extensions and discoveries. Continued development of Devon’s Eagle Fordprimarily in the STACK and Jackfish propertiesDelaware Basin led to the conversion of 4152 MMBoe, or 11%26%, of the 20152017 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $586$691 million for 2016.2018.
A significant amount of Devon’s proved undeveloped reserves at the end of 20162018 related to its Jackfish operations. At December 31, 20162018 and 2015,2017, Devon’s Jackfish proved undeveloped reserves were 294206 MMBoe and 301209 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 5five 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 2029.2032. At the end of 2016,2018, approximately 199125 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 11981 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop.
104
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Price Revisions
Reserves increased 40 MMBoe in the U.S. primarily due to price increases in the trailing 12 month average for oil, gas and NGLs in 2018. Reserves increased 11 MMBoe in Canada due to a decrease in the trailing 12 month average price for bitumen in 2018. The decreased price has the effect of decreasing the applicable royalties, which increases the after-royalty volumes.
Reserves increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12 month average for oil, gas and NGLs in 2017. Reserves decreased 38 MMBoe in Canada due to a significant increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing the royalties, which decreases the after-royalty volumes.
Reserves decreased 27 MMBoe and 302 MMBoe during 2016 and 2015, respectively, primarily due to lower commodity prices for oil bitumen and gas. The lower bitumen price increased Canadian reserves due to the decline 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.
Revisions Other Than Price
Total revisions other than price in 2018 primarily related to Devon’s evaluation of certain oil and dry gas regions, with the largest revisions being made in the STACK.
Total revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and NGLs, with the largest revisions being made in the Barnett Shale and STACK (Cana-Woodford Shale). Revisions
118
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
2018 – Approximately 72% of the additions were through our focused efforts in the STACK (87 MMBoe) and the Delaware Basin (88 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.
The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling activities, primarily relating to the STACK.
2017 – Over 80% of the additions were through our 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.
The 2017 extensions and discoveries included 66 MMBoe related to additions from Devon’s infill drilling activities primarily related to the STACK.
2016 – Of the 126 MMBoe of extensions and discoveries, 97 MMBoe related to STACK, 18 MMBoe related to the Delaware Basin and 7 MMBoe related to the Eagle Ford.
The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling activities primarily consisting of 73 MMBoe related to STACK.
2015 – Of the 118 MMBoe of extensions and discoveries, 38 MMBoe related to the Delaware Basin, 30 MMBoe related to the Anadarko Basin, 21 MMBoe related to the Eagle Ford 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.STACK.
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.
Sale of Reserves
2016 – The 157 MMBoe of reserves sales related to Devon’s non-core upstream asset divestitures discussed further in Note 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.
119105
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Sale of Reserves
Related to Devon’s 2018, 2017 and 2016 U.S. non-core asset divestitures as discussed further in Note 2.
Standardized Measure
The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.
|
| Year Ended December 31, 2018 |
| |||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||||||||||||||
Future cash inflows |
| $ | 40,183 |
|
| $ | 9,146 |
|
| $ | 49,329 |
| ||||||||||||
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Development |
|
| (3,444 | ) |
|
| (1,558 | ) |
|
| (5,002 | ) | ||||||||||||
Production |
|
| (18,107 | ) |
|
| (5,445 | ) |
|
| (23,552 | ) | ||||||||||||
Future income tax expense |
|
| (2,969 | ) |
|
| — |
|
|
| (2,969 | ) | ||||||||||||
Future net cash flow |
|
| 15,663 |
|
|
| 2,143 |
|
|
| 17,806 |
| ||||||||||||
10% discount to reflect timing of cash flows |
|
| (6,897 | ) |
|
| (717 | ) |
|
| (7,614 | ) | ||||||||||||
Standardized measure of discounted future net cash flows |
| $ | 8,766 |
|
| $ | 1,426 |
|
| $ | 10,192 |
| ||||||||||||
|
| Year Ended December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Year Ended December 31, 2017 |
| ||||||||||||
|
| (Millions) |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||||||||
Future cash inflows |
| $ | 22,847 |
|
| $ | 9,672 |
|
| $ | 32,519 |
|
| $ | 34,701 |
|
| $ | 13,602 |
|
| $ | 48,303 |
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
| (2,784 | ) |
|
| (2,201 | ) |
|
| (4,985 | ) |
|
| (3,316 | ) |
|
| (1,853 | ) |
|
| (5,169 | ) |
Production |
|
| (14,484 | ) |
|
| (6,287 | ) |
|
| (20,771 | ) |
|
| (15,526 | ) |
|
| (5,986 | ) |
|
| (21,512 | ) |
Future income tax expense |
|
| — |
|
|
| (57 | ) |
|
| (57 | ) |
|
| — |
|
|
| (988 | ) |
|
| (988 | ) |
Future net cash flow |
|
| 5,579 |
|
|
| 1,127 |
|
|
| 6,706 |
|
|
| 15,859 |
|
|
| 4,775 |
|
|
| 20,634 |
|
10% discount to reflect timing of cash flows |
|
| (2,128 | ) |
|
| (380 | ) |
|
| (2,508 | ) |
|
| (7,541 | ) |
|
| (1,756 | ) |
|
| (9,297 | ) |
Standardized measure of discounted future net cash flows |
| $ | 3,451 |
|
| $ | 747 |
|
| $ | 4,198 |
|
| $ | 8,318 |
|
| $ | 3,019 |
|
| $ | 11,337 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2015 |
|
| Year Ended December 31, 2016 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||
|
| (Millions) |
| |||||||||||||||||||||
Future cash inflows |
| $ | 27,398 |
|
| $ | 13,047 |
|
| $ | 40,445 |
|
| $ | 22,847 |
|
| $ | 9,672 |
|
| $ | 32,519 |
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
| (3,306 | ) |
|
| (2,759 | ) |
|
| (6,065 | ) |
|
| (2,784 | ) |
|
| (2,201 | ) |
|
| (4,985 | ) |
Production |
|
| (17,251 | ) |
|
| (6,891 | ) |
|
| (24,142 | ) |
|
| (11,934 | ) |
|
| (6,049 | ) |
|
| (17,983 | ) |
Future income tax expense |
|
| — |
|
|
| (475 | ) |
|
| (475 | ) |
|
| — |
|
|
| (121 | ) |
|
| (121 | ) |
Future net cash flow |
|
| 6,841 |
|
|
| 2,922 |
|
|
| 9,763 |
|
|
| 8,129 |
|
|
| 1,301 |
|
|
| 9,430 |
|
10% discount to reflect timing of cash flows |
|
| (1,973 | ) |
|
| (1,102 | ) |
|
| (3,075 | ) |
|
| (3,524 | ) |
|
| (466 | ) |
|
| (3,990 | ) |
Standardized measure of discounted future net cash flows |
| $ | 4,868 |
|
| $ | 1,820 |
|
| $ | 6,688 |
|
| $ | 4,605 |
|
| $ | 835 |
|
| $ | 5,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
| 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 20162018 estimates, Devon’s future realized prices were assumed to be $37.37$58.64 per Bbl of oil, $15.74$22.12 per Bbl of bitumen, $1.98$2.45 per Mcf of gas and $9.91$24.72 per Bbl of NGLs. Of the $5.0 billion of future development costs as of the end of 2016, $0.42018, $1.2 billion, $0.8$0.6 billion and $0.5$0.3 billion are estimated to be spent in 2017, 20182019, 2020 and 2019,2021, respectively.
120106
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 billion of future development costs are $1.3$1.4 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) |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||||||||
Beginning balance |
| $ | 6,688 |
|
| $ | 20,474 |
|
| $ | 15,741 |
|
| $ | 11,337 |
|
| $ | 5,440 |
|
| $ | 7,883 |
|
Net changes in prices and production costs |
|
| (2,128 | ) |
|
| (20,756 | ) |
|
| 2,561 |
|
|
| (243 | ) |
|
| 5,218 |
|
|
| (2,027 | ) |
Oil, bitumen, gas and NGL sales, net of production costs |
|
| (2,163 | ) |
|
| (2,704 | ) |
|
| (6,865 | ) |
|
| (3,452 | ) |
|
| (3,327 | ) |
|
| (2,377 | ) |
Changes in estimated future development costs |
|
| 112 |
|
|
| 1,313 |
|
|
| (768 | ) |
|
| (216 | ) |
|
| 789 |
|
|
| 112 |
|
Extensions and discoveries, net of future development costs |
|
| 660 |
|
|
| 1,129 |
|
|
| 4,836 |
|
|
| 3,139 |
|
|
| 2,497 |
|
|
| 674 |
|
Purchase of reserves |
|
| 222 |
|
|
| 95 |
|
|
| 6,422 |
|
|
| — |
|
|
| 2 |
|
|
| 224 |
|
Sales of reserves in place |
|
| (560 | ) |
|
| (79 | ) |
|
| (2,384 | ) |
|
| (588 | ) |
|
| (3 | ) |
|
| (577 | ) |
Revisions of quantity estimates |
|
| (32 | ) |
|
| (1,451 | ) |
|
| (746 | ) |
|
| (414 | ) |
|
| (318 | ) |
|
| (21 | ) |
Previously estimated development costs incurred during the period |
|
| 663 |
|
|
| 2,158 |
|
|
| 1,933 |
|
|
| 962 |
|
|
| 559 |
|
|
| 663 |
|
Accretion of discount |
|
| 403 |
|
|
| 567 |
|
|
| 1,746 |
|
|
| 960 |
|
|
| 1,034 |
|
|
| 537 |
|
Foreign exchange and other |
|
| 105 |
|
|
| (1,254 | ) |
|
| (107 | ) |
|
| (329 | ) |
|
| (7 | ) |
|
| 72 |
|
Net change in income taxes |
|
| 228 |
|
|
| 7,196 |
|
|
| (1,895 | ) |
|
| (964 | ) |
|
| (547 | ) |
|
| 277 |
|
Ending balance |
| $ | 4,198 |
|
| $ | 6,688 |
|
| $ | 20,474 |
|
| $ | 10,192 |
|
| $ | 11,337 |
|
| $ | 5,440 |
|
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 | ) |
|
| 2018 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 2,198 |
|
| $ | 2,249 |
|
| $ | 2,579 |
|
| $ | 3,708 |
|
| $ | 10,734 |
|
Asset dispositions (1) |
| $ | (12 | ) |
| $ | 23 |
|
| $ | (6 | ) |
| $ | (268 | ) |
| $ | (263 | ) |
Earnings (loss) from continuing operations before income taxes (2) |
| $ | (245 | ) |
| $ | (481 | ) |
| $ | 162 |
|
| $ | 1,484 |
|
| $ | 920 |
|
Net earnings (loss) from continuing operations |
| $ | (211 | ) |
| $ | (474 | ) |
| $ | 300 |
|
| $ | 1,149 |
|
| $ | 764 |
|
Net earnings from discontinued operations, net of income tax expense (3) |
| $ | 58 |
|
| $ | 139 |
|
| $ | 2,263 |
|
| $ | — |
|
| $ | 2,460 |
|
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 |
|
|
| 2017 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 2,400 |
|
| $ | 2,165 |
|
| $ | 1,933 |
|
| $ | 2,380 |
|
| $ | 8,878 |
|
Asset dispositions (1) |
| $ | (8 | ) |
| $ | (22 | ) |
| $ | (170 | ) |
| $ | (17 | ) |
| $ | (217 | ) |
Earnings from continuing operations before income taxes |
| $ | 313 |
|
| $ | 207 |
|
| $ | 207 |
|
| $ | 46 |
|
| $ | 773 |
|
Net earnings from continuing operations |
| $ | 308 |
|
| $ | 212 |
|
| $ | 194 |
|
| $ | 44 |
|
| $ | 758 |
|
Net earnings from discontinued operations, net of income tax expense |
| $ | 9 |
|
| $ | 33 |
|
| $ | 18 |
|
| $ | 260 |
|
| $ | 320 |
|
Net earnings attributable to Devon |
| $ | 303 |
|
| $ | 219 |
|
| $ | 193 |
|
| $ | 183 |
|
| $ | 898 |
|
Basic net earnings per share attributable to Devon |
| $ | 0.58 |
|
| $ | 0.41 |
|
| $ | 0.37 |
|
| $ | 0.35 |
|
| $ | 1.71 |
|
Diluted net earnings per share attributable to Devon |
| $ | 0.58 |
|
| $ | 0.41 |
|
| $ | 0.37 |
|
| $ | 0.35 |
|
| $ | 1.70 |
|
(1) | Additional discussion regarding asset dispositions can be found in Note 2. |
121107
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(2) | Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5. |
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.
(3) | 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, as discussed in Note 19. |
122108
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, 20162018 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, 2017,20, 2019, management concluded that its internal control over financial reporting was effective as of December 31, 2016.2018.
The effectiveness of our internal control over financial reporting as of December 31, 20162018 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, 2016,2018, 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 20162018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Not Applicable.applicable.
123109
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, 2016.2018.
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, 2016.2018.
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, 2016.2018.
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, 2016.2018.
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, 2016.2018.
124
110
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 |
|
| |
|
|
|
2.1 |
| Purchase Agreement, |
|
| |
|
| |
|
| |
|
|
|
3.1 |
| Registrant’s Restated Certificate of Incorporation |
|
|
|
3.2 |
| Registrant’s Bylaws |
|
|
|
4.1 |
|
125
|
| |
|
| |
|
| Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee |
|
|
|
|
| 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 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 |
|
|
|
|
| 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 3.250% Senior Notes due 2022 and the 4.750% Senior Notes due 2042 |
|
|
|
|
| |
|
| 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 |
|
|
|
|
| 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 |
|
|
|
|
| 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 |
111
Exhibit No. | Description | |
|
|
|
|
| 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 |
|
|
|
|
| Supplemental Indenture No. 3, dated as of January 9, 2009, 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 6.30% Senior Notes due 2019 |
|
|
|
| Supplemental Indenture No. 4, dated as of March 22, 2018, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Notes due 2032 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed March 22, 2018; File No. 000-32318). | |
4.10 |
| Indenture, dated as of October 3, 2001, |
|
|
|
|
|
126
|
| |
|
| |
|
| |
|
| |
|
| 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 |
|
|
|
|
| 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 |
|
|
|
|
| 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 |
|
|
|
|
| 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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|
| |
|
| |
|
| |
|
|
127
|
| |
|
| |
10.1 |
| Credit Agreement, dated as of October |
|
|
|
10.2 |
| |
|
| |
|
| |
|
| |
|
| Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) |
|
|
|
| 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).* | |
112
Exhibit No. | Description | |
10.4 | Devon Energy Corporation 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 7, 2017; File No. 333-218561).* | |
10.5 |
| 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) |
|
|
|
|
| Devon Energy Corporation |
|
|
|
|
| |
|
| |
|
| Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective as of April 15, 2014) |
128
|
| |
|
|
|
|
| Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan |
|
|
|
|
| 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).* |
|
|
|
| ||
10.11 |
| Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| 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).* |
|
|
|
|
| Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| 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).* |
|
|
|
| ||
10.19 |
| Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) |
113
Exhibit No. | Description | |
|
|
|
|
| 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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|
|
| 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).* |
|
|
|
|
| Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| 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).* |
|
|
|
|
| Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) |
|
|
|
|
| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) |
129
|
| |
|
| |
|
|
|
|
| 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).* |
10.28 | ||
|
|
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| |
|
| |
|
| |
|
| |
|
| Amended and Restated Form of Employment Agreement between Registrant and certain executive officers |
|
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|
|
| Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant and certain executive officers |
|
|
|
|
| Form of Employment Agreement between Registrant and certain executive officers |
|
|
|
| Employment Agreement, dated April 19, 2017, by and between Registrant and Mr. Jeffrey L. Ritenour (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed on April 20, 2017; File No. 001-32318).* | |
10.33 |
| Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and |
|
| |
|
|
|
|
| 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 |
114
Exhibit No. | Description | |
|
|
|
|
| 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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|
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| 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 |
|
|
|
| 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 (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 3, 2017; File No. 001-32318).* | |
10.40 | 2018 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 2, 2018; File No. 001-32318).* | |
10.41 |
| Form of Notice of Grant of Incentive Stock Options and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for incentive stock options granted |
|
|
|
|
| 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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|
|
| 2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the | |
|
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| |
|
| Form of Letter Agreement amending the restricted stock award agreements and nonqualified stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and |
|
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|
|
| Form of Amendment to Incentive Stock Option Award Agreements between Registrant and post-retirement eligible executives relating to incentive stock options under the 2009 Long-Term Incentive Plan |
|
|
|
115
|
|
|
| ||
|
| Amendment to Performance Restricted Stock Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Restricted Stock Award Agreement dated February 10, 2015 |
|
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| |
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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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99.1 |
| |
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|
99.2 |
| |
|
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|
101.INS |
| XBRL Instance |
|
|
|
101.SCH |
| XBRL Taxonomy Extension Schema Document. |
|
|
|
101.CAL |
| XBRL Taxonomy Extension Calculation Linkbase Document. |
|
|
|
101.DEF |
| XBRL Taxonomy Extension Definition Linkbase Document. |
|
|
|
101.LAB |
| XBRL Taxonomy Extension Labels Linkbase Document. |
|
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|
101.PRE |
| XBRL Taxonomy Extension Presentation Linkbase Document. |
|
|
| Indicates management contract or compensatory plan or arrangement. |
132Item 16.Form 10-K Summary
Not applicable.
116
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 |
|
|
|
| By: | /s/ |
|
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|
|
| Executive Vice President and |
February 15, 201720, 2019
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/ JOHN RICHELS |
| Chairman of the Board | February |
John Richels | |||
/s/ DUANE C. RADTKE | Vice Chairman of the Board | February 20, 2019 | |
Duane C. Radtke |
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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 |
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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 20, 2019 | |
John Krenicki Jr. |
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/s/ ROBERT A. MOSBACHER, JR. |
| Director | February |
Robert A. Mosbacher, Jr. | |||
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/s/ MARY P. RICCIARDELLO |
| Director | February |
Mary P. Ricciardello |
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133
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134
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135
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136
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137
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138
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139
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140
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117
141
