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, 20172018
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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer |
| ☑ | Accelerated filer |
| ☐ | Non-accelerated filer |
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Smaller reporting company |
| ☐ | Emerging growth company |
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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, 201729, 2018 was approximately $16.7$22.5 billion, based upon the closing price of $31.97$43.96 per share as reported by the New York Stock Exchange on such date. On February 7, 2018, 526.16, 2019, 438.3 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s definitive Proxy Statement relating to Registrant’s 20182019 annual meeting of stockholders have been incorporated by reference in Part III of this Annual Report on Form 10-K.
FORM 10-K
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk |
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
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Item 10. Directors, Executive Officers and Corporate Governance |
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Item 13. Certain Relationships and Related Transactions, and Director Independence |
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2
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon,” the “Company” and “Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:
“2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.
“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan, as amended and restated.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.
“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.
“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.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
3
“Mcf” means thousand cubic feet.
3
“MLP” means master limited partnership.
“MMBbls” means million barrels.
“MMBoe” means million Boe.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“M&M operations” means marketing and midstream revenues minus marketing and midstream expenses.
“N/M” means not meaningful.
“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.
“Tax Reform Legislation” means Tax Cuts and Jobs Act.
“TSR” means total shareholder return.
“Upstream operations” means upstream revenues minus production expenses.
“U.S.” means United States of America.
“VEX” 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, 2017 reserve reports and other data in our possession or available from third parties.future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially 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 oil and gas operations;
• | the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct; |
regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;
• | regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; |
risks related to our hedging activities;
• | risks related to regulatory, social and market efforts to address climate change; |
counterparty credit risks;
• | risks related to our hedging activities; |
risks relating to our indebtedness;
• | counterparty credit risks; |
cyberattack risks;
• | risks relating to our indebtedness; |
our limited control over third parties who operate some of our oil and gas properties;
• | cyberattack risks; |
midstream capacity constraints and potential interruptions in production;
• | our limited control over third parties who operate some of our oil and gas properties; |
the extent to which insurance covers any losses we may experience;
• | 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; |
our ability to successfully complete mergers, acquisitions and divestitures; 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 20 in “Item 8. Financial Statements and Supplementary Data” of this report.Partner.
Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2017,2018, Devon and its consolidated subsidiaries had approximately 4,900 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. 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.next section of this Annual Report, we own a portfolio of assets located in the United States and Alberta, Canada. We strive to own premier assets capable of generating cash flows in excess of our capital and operating requirements, as well as competitive rates of return. We also desire to own a portfolio of assets that can provide a production growth platform extending many years into the future. Because of the strength of oil prices relative to natural gas, we have been positioning our portfolio to be more heavily weighted to U.S. oil assets in recent years.
Devon’s “2020 Vision”During 2018, we made significant progress in our transition to a U.S. oil company. We sold our midstream business and certain non-core upstream assets, generating nearly $5 billion in 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 focus 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 plan throughfocus on development drilling, reduce our facility costs and optimize well spacing in the STACK. Additionally, we will streamline and align our workforce with our go-forward business, which should result in $300 million of annual cost savings by the end of the decade intended to optimize returns and deliver top-tier capital-efficient, cash-flow growth. Our 2020 Vision is focused on the following strategic priorities:
Maximize cash flow by optimizing base production and reducing per-unit cash costs;
Improve capital efficiency with a concentration of investment on highest-returning development projects in the Delaware Basin and STACK;
Simplify our portfolio by monetizing non-core assets;
Improve financial strength by reducing debt; and
Return cash to shareholders.
Our portfolio of exploration and production assets and operations provides stable, environmentally responsible production and a platform for future growth. In 2017, we continued the development of our world-class operations in the STACK and Delaware Basin. These assets provide us with a sustainable, multi-decade growth platform that continues to improve with our successful drilling programs. During 2017, we delivered the best well productivity in Devon’s 46-year history and continued a five-year streak of increasing Devon’s initial 90-day production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity and improving the performance of our established wells. Devon has more than doubled its onshore North American oil production since 2012 and has a deep inventory of development opportunities to deliver future oil growth.
three-year period. As we enter 2018 and look toward the future,continue deleveraging, we expect to achieve additional efficiencies acrossreduce annual interest costs by $130 million. Finally, we have plans to reduce our portfolio. We expectannual production expenses by $50 million over the next three years.
Financial strength and flexibility – Commodity prices are uncertain and volatile, so we strive to fund activity withinmaintain a strong balance sheet, as well as adequate liquidity and financial flexibility, in order to operate competitively in all commodity price cycles. Our capital allocation decisions are made with attention to these financial stewardship principles, as well as the priorities of funding our cash flow,core operations, protecting our investment-grade credit ratings, and remain committed to allocating capital in a disciplined manner to maximize valuepaying and return.growing our shareholder dividend.
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During 2018, we reduced our consolidated debt by 40%, primarily from our divestitures. We believealso raised our quarterly dividend 33% and began a $4 billion share repurchase program. As we capture the full valuedispose of our Canadian and Barnett Shale assets in 2019, we expect to use the proceeds to reduce debt further and improve returns through maximizingrepurchase additional common shares. As a result of our base productionplanned dispositions, our Board of Directors has increased our share repurchase program to $5 billion in February 2019 and optimizingraised 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.quarterly dividend 12.5% to $0.09 per share.
We also continue to implement new shareholder-friendly initiatives, which include new returns-based metrics aligned to employee compensation and the conversion to successful efforts accounting which provides greater transparency into our financial performance.
EnLink Strategy
EnLink focuses on providing gathering, transmission, processing, storage, fractionation and marketing to upstream oil and natural gas producers, including Devon.
EnLink connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. Furthermore, EnLink purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines.
EnLink’s primary business objective is to provide stable cash flow, while growing through prudent and profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintaining a strong financial position through a conservative and balanced capital structure highlighted by its investment grade status. EnLink has consistently demonstrated expertise within the MLP space and continues to employ a proven business model that includes growing, expanding and executing on its strategy within top basins where Devon and other successful upstream producers operate.
7
Property Profiles
Key summary data from each of our areas of operation as of and for the year ended December 31, 20172018 are detailed in the map below. Notes 2322 and 2423 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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Led by results from our franchise assets, STACK and Index to Financial Statements
Delaware Basin Devon achieved the best drilling results in our 46-year history. Our initial 90-day production rates in 2017 increased more than 400% from 2012 levels. These productivity improvements were driven by activity focused in top resource plays, improved subsurface reservoir characterization, leading-edge completion designs and improvements in lateral placement. The most significant reserves growth came from our U.S. operations, where we replaced approximately 150% of our 2017 production with proved reserves additions from the drill bit.
Delaware Basin – The Delaware Basin is one of Devon’s top-two 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. We expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin to
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deliver high-margin growth for many years to come. During 2017,2018, our continued appraisal and development work enabled us to increase our proved reserves in this area by approximately 60%24%. At December 31, 2017,2018, we had eight10 operated rigs developing this asset. In 2018,2019, we plan to invest approximately $725$900 million of capital in the Delaware Basin, as we shift to expanded development operations, primarily focused onmaking it the Bone Spring formation.top-funded asset in the portfolio.
STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top-two franchisetop assets. Devon is currently targeting the Woodford Shale and the Meramec zones. Our STACK position is one of the largest and best in the industry, providing visible long-term growth. Completion design enhancements have resulted in greater productivity and improved economics. Drilling activity in the Meramec has produced record setting initial production across our core position in the oil and liquids window.stable production. At December 31, 2017,2018, we had ninefive operated rigs with drilling focused in the Meramec formation. In 2018,2019, we plan approximately $700$400 million of capital investment. The STACK is Devon’s second highest funded asset in the portfolio for 2019.
Eagle Ford – We acquired our position in the Eagle Ford in 2014. Since acquiring these assets, we have delivered tremendous results by producing 173 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. Our Eagle Ford assets generated significant cash flow in 2018. In 2019, we plan approximately $300 million of capital investment.
Rockies 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 December 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 expect to accelerate full-field development activity.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. We expect Jackfish to maintain a reasonably flat production profile for greater than 2015 years requiring 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, 2017. With our 50% partner,2018. Currently, we continue to evaluate our development timelinehave minimal planned capital outlays for Pike.Pike in the near future. The majority of our 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 2018,2019, we plan approximately $275 million of capital investmentto separate our operations in our Canadian Heavy Oil business.
Eagle Ford – We acquired our position in the Eagle Ford in 2014, with acres located in DeWitt and Lavaca counties in south Texas. In 2017, we closed on the sale of our Lavaca assets for approximately $200 million. Since acquiring these assets, we have delivered tremendous results by producing 119 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. With the highest margins in our portfolio, our Eagle Ford assets generated significant cash flow in 2017. In 2018, we plan approximately $250 million of capital investment.
Rockies Oil – Our acreage in the Rockies is focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. Recent drilling success in these formations has expanded our drilling inventory, and we expect further growth as we continue to de-risk this emerging light-oil opportunity. As of December 31, 2017, we had one operated rig targeting the Turner formation in northern Converse County of the Powder River Basin. In 2018, we plan approximately $150 million of capital investment.Canada.
Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. The Johnson County assets are currently being marketed as part of our non-core divestiture program. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this asset into one of the top producing gas fields in North America. Given the sustained low gas price environment, we continue to focus on enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2018,2019, we plan on minimal development activity, with planned capital investment of up to $50 million to optimize base production and further de-risk future development resources.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 2423 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,
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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.
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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 (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 1718 years, including the past 1011 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 reviews of each operating country’s reserves. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2017,2018, we engaged two such firms to audit approximately 88%89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited approximately 85%87% of our 2017 U.S. reserves, and Deloitte LLP audited approximately 99%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 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.
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The following tables present production, price and cost information for each significant field, country and continent.
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Year Ended December 31, |
| Oil (MMBbls) |
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| Bitumen (MMBbls) |
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| Gas (Bcf) |
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| NGLs (MMBbls) |
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| Total (MMBoe) |
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| Oil (MMBbls) |
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| Bitumen (MMBbls) |
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| Gas (Bcf) |
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| NGLs (MMBbls) |
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| Total (MMBoe) |
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2018 |
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Barnett Shale |
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| — |
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| — |
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| 186 |
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| 12 |
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| 43 |
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STACK |
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| 12 |
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| — |
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| 121 |
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| 14 |
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| 45 |
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Jackfish |
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| — |
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| 35 |
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| — |
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| — |
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|
| 35 |
| ||||||||||||||||||||
U.S. |
|
| 47 |
|
|
| — |
|
|
| 397 |
|
|
| 39 |
|
|
| 153 |
| ||||||||||||||||||||
Canada |
|
| 7 |
|
|
| 35 |
|
|
| 4 |
|
|
| — |
|
|
| 42 |
| ||||||||||||||||||||
Total North America |
|
| 54 |
|
|
| 35 |
|
|
| 401 |
|
|
| 39 |
|
|
| 195 |
| ||||||||||||||||||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 237 |
|
|
| 14 |
|
|
| 54 |
|
|
| — |
|
|
| — |
|
|
| 237 |
|
|
| 14 |
|
|
| 54 |
|
STACK |
|
| 9 |
|
|
| — |
|
|
| 107 |
|
|
| 11 |
|
|
| 38 |
|
|
| 9 |
|
|
| — |
|
|
| 107 |
|
|
| 11 |
|
|
| 38 |
|
Jackfish |
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
U.S. |
|
| 42 |
|
|
| — |
|
|
| 433 |
|
|
| 36 |
|
|
| 150 |
|
|
| 42 |
|
|
| — |
|
|
| 433 |
|
|
| 36 |
|
|
| 150 |
|
Canada |
|
| 7 |
|
|
| 40 |
|
|
| 6 |
|
|
| — |
|
|
| 48 |
|
|
| 7 |
|
|
| 40 |
|
|
| 6 |
|
|
| — |
|
|
| 48 |
|
Total North America |
|
| 49 |
|
|
| 40 |
|
|
| 439 |
|
|
| 36 |
|
|
| 198 |
|
|
| 49 |
|
|
| 40 |
|
|
| 439 |
|
|
| 36 |
|
|
| 198 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 265 |
|
|
| 15 |
|
|
| 60 |
|
|
| — |
|
|
| — |
|
|
| 265 |
|
|
| 15 |
|
|
| 60 |
|
STACK |
|
| 7 |
|
|
| — |
|
|
| 103 |
|
|
| 9 |
|
|
| 33 |
|
|
| 7 |
|
|
| — |
|
|
| 103 |
|
|
| 9 |
|
|
| 33 |
|
Jackfish |
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| 40 |
|
|
| — |
|
|
| — |
|
|
| 40 |
|
U.S. |
|
| 47 |
|
|
| — |
|
|
| 510 |
|
|
| 42 |
|
|
| 174 |
|
|
| 47 |
|
|
| — |
|
|
| 510 |
|
|
| 42 |
|
|
| 174 |
|
Canada |
|
| 8 |
|
|
| 40 |
|
|
| 7 |
|
|
| — |
|
|
| 49 |
|
|
| 8 |
|
|
| 40 |
|
|
| 7 |
|
|
| — |
|
|
| 49 |
|
Total North America |
|
| 55 |
|
|
| 40 |
|
|
| 517 |
|
|
| 42 |
|
|
| 223 |
|
|
| 55 |
|
|
| 40 |
|
|
| 517 |
|
|
| 42 |
|
|
| 223 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
|
| — |
|
|
| — |
|
|
| 291 |
|
|
| 17 |
|
|
| 66 |
| ||||||||||||||||||||
STACK |
|
| 3 |
|
|
| — |
|
|
| 86 |
|
|
| 8 |
|
|
| 25 |
| ||||||||||||||||||||
Jackfish |
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| — |
|
|
| 31 |
| ||||||||||||||||||||
U.S. |
|
| 60 |
|
|
| — |
|
|
| 579 |
|
|
| 50 |
|
|
| 206 |
| ||||||||||||||||||||
Canada |
|
| 10 |
|
|
| 31 |
|
|
| 8 |
|
|
| — |
|
|
| 42 |
| ||||||||||||||||||||
Total North America |
|
| 70 |
|
|
| 31 |
|
|
| 587 |
|
|
| 50 |
|
|
| 248 |
| ||||||||||||||||||||
9
|
| 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) |
| ||||||||||
2018 (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
| $ | 62.89 |
|
| $ | — |
|
| $ | 2.45 |
|
| $ | 22.72 |
|
| $ | 9.42 |
| ||||||||||||||||||||
STACK |
| $ | 63.81 |
|
| $ | — |
|
| $ | 2.29 |
|
| $ | 25.53 |
|
| $ | 7.16 |
| ||||||||||||||||||||
Jackfish |
| $ | — |
|
| $ | 17.88 |
|
| $ | — |
|
| $ | — |
|
| $ | 12.85 |
| ||||||||||||||||||||
U.S. |
| $ | 61.97 |
|
| $ | — |
|
| $ | 2.37 |
|
| $ | 24.74 |
|
| $ | 8.61 |
| ||||||||||||||||||||
Canada |
| $ | 27.36 |
|
| $ | 17.88 |
|
| N/M |
|
| $ | — |
|
| $ | 13.43 |
| |||||||||||||||||||||
Total North America |
| $ | 57.76 |
|
| $ | 17.88 |
|
| $ | 2.37 |
|
| $ | 24.74 |
|
| $ | 9.66 |
| ||||||||||||||||||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 49.72 |
|
| $ | — |
|
| $ | 2.47 |
|
| $ | 13.67 |
|
| $ | 6.86 |
|
| $ | 49.72 |
|
| $ | — |
|
| $ | 2.47 |
|
| $ | 13.67 |
|
| $ | 6.86 |
|
STACK |
| $ | 48.43 |
|
| $ | — |
|
| $ | 2.40 |
|
| $ | 17.78 |
|
| $ | 4.72 |
|
| $ | 48.43 |
|
| $ | — |
|
| $ | 2.40 |
|
| $ | 17.78 |
|
| $ | 4.72 |
|
Jackfish |
| $ | — |
|
| $ | 29.38 |
|
| $ | — |
|
| $ | — |
|
| $ | 11.02 |
|
| $ | — |
|
| $ | 29.38 |
|
| $ | — |
|
| $ | — |
|
| $ | 11.02 |
|
U.S. |
| $ | 49.41 |
|
| $ | — |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 6.74 |
|
| $ | 49.41 |
|
| $ | — |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 6.74 |
|
Canada |
| $ | 33.73 |
|
| $ | 29.38 |
|
| N/M |
|
| $ | — |
|
| $ | 11.70 |
|
| $ | 33.73 |
|
| $ | 29.38 |
|
| N/M |
|
| $ | — |
|
| $ | 11.70 |
| ||
Total North America |
| $ | 47.31 |
|
| $ | 29.38 |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 7.94 |
|
| $ | 47.31 |
|
| $ | 29.38 |
|
| $ | 2.48 |
|
| $ | 15.66 |
|
| $ | 7.94 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
| $ | 41.03 |
|
| $ | — |
|
| $ | 1.76 |
|
| $ | 10.31 |
|
| $ | 5.75 |
|
| $ | 41.03 |
|
| $ | — |
|
| $ | 1.76 |
|
| $ | 10.31 |
|
| $ | 5.75 |
|
STACK |
| $ | 39.81 |
|
| $ | — |
|
| $ | 1.91 |
|
| $ | 10.86 |
|
| $ | 4.34 |
|
| $ | 39.81 |
|
| $ | — |
|
| $ | 1.91 |
|
| $ | 10.86 |
|
| $ | 4.34 |
|
Jackfish |
| $ | — |
|
| $ | 19.82 |
|
| $ | — |
|
| $ | — |
|
| $ | 8.70 |
|
| $ | — |
|
| $ | 19.82 |
|
| $ | — |
|
| $ | — |
|
| $ | 8.70 |
|
U.S. |
| $ | 38.92 |
|
| $ | — |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 6.44 |
|
| $ | 38.92 |
|
| $ | — |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 6.44 |
|
Canada |
| $ | 23.96 |
|
| $ | 19.82 |
|
| N/M |
|
| $ | — |
|
| $ | 9.36 |
|
| $ | 23.96 |
|
| $ | 19.82 |
|
| N/M |
|
| $ | — |
|
| $ | 9.36 |
| ||
Total North America |
| $ | 36.72 |
|
| $ | 19.82 |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 7.08 |
|
| $ | 36.72 |
|
| $ | 19.82 |
|
| $ | 1.84 |
|
| $ | 9.81 |
|
| $ | 7.08 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Barnett Shale |
| $ | 46.47 |
|
| $ | — |
|
| $ | 2.00 |
|
| $ | 9.62 |
|
| $ | 5.96 |
| ||||||||||||||||||||
STACK |
| $ | 43.73 |
|
| $ | — |
|
| $ | 2.22 |
|
| $ | 8.97 |
|
| $ | 5.39 |
| ||||||||||||||||||||
Jackfish |
| $ | — |
|
| $ | 23.41 |
|
| $ | — |
|
| $ | — |
|
| $ | 12.43 |
| ||||||||||||||||||||
U.S. |
| $ | 44.01 |
|
| $ | — |
|
| $ | 2.14 |
|
| $ | 9.32 |
|
| $ | 7.52 |
| ||||||||||||||||||||
Canada |
| $ | 30.58 |
|
| $ | 23.41 |
|
| N/M |
|
| $ | — |
|
| $ | 13.18 |
| |||||||||||||||||||||
Total North America |
| $ | 42.12 |
|
| $ | 23.41 |
|
| $ | 2.14 |
|
| $ | 9.32 |
|
| $ | 8.48 |
| ||||||||||||||||||||
(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 production expense per BOE excluding production and property taxes. Jackfish and Canada include purchases of natural gas used to heat the heavy oil reservoirs. The gas is purchased at prevailing market prices, which vary from year to year. |
11
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 |
|
|
| 149.8 |
|
|
| — |
|
|
| 44.0 |
|
|
| — |
|
|
| 193.8 |
|
|
| — |
|
|
| 193.8 |
|
Canada |
|
| 100.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 100.5 |
|
|
| — |
|
|
| 100.5 |
|
|
| 100.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 100.5 |
|
|
| — |
|
|
| 100.5 |
|
Total North America |
|
| 250.3 |
|
|
| — |
|
|
| 44.0 |
|
|
| — |
|
|
| 294.3 |
|
|
| — |
|
|
| 294.3 |
|
|
| 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 |
| ||||||||||||||||||||||||||||
(1) | Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests. |
10
The following table presents the wells that were in progress on December 31, 2017.2018. As of February 1, 2018,2019, these wells were still in progress.
|
| Gross (1) |
|
| Net (2) |
|
| Gross (1) |
|
| Net (2) |
| ||||
U.S. |
|
| 26.0 |
|
|
| 10.1 |
|
|
| 184.0 |
|
|
| 105.2 |
|
Canada |
|
| 5.0 |
|
|
| 5.0 |
|
|
| 1.0 |
|
|
| 1.0 |
|
Total North America |
|
| 31.0 |
|
|
| 15.1 |
|
|
| 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, 2017.2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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. |
|
| 9,165 |
|
|
| 3,379 |
|
|
| 10,103 |
|
|
| 7,245 |
|
|
| 19,268 |
|
|
| 10,624 |
|
|
| 9,284 |
|
|
| 3,445 |
|
|
| 8,235 |
|
|
| 5,703 |
|
|
| 17,519 |
|
|
| 9,148 |
|
Canada |
|
| 3,195 |
|
|
| 3,085 |
|
|
| 590 |
|
|
| 413 |
|
|
| 3,785 |
|
|
| 3,498 |
|
|
| 3,183 |
|
|
| 3,071 |
|
|
| 544 |
|
|
| 380 |
|
|
| 3,727 |
|
|
| 3,451 |
|
Total North America |
|
| 12,360 |
|
|
| 6,464 |
|
|
| 10,693 |
|
|
| 7,658 |
|
|
| 23,053 |
|
|
| 14,122 |
|
|
| 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 |
12
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. We are the operator of approximately 14,60012,900 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and construction overhead reimbursement at rates customarily charged in the respective areas. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of G&A, which is a common industry practice.
Acreage Statistics
The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2017.2018. Of our 4.33.8 million net acres, approximately 2.31.9 million acres are held by production. The acreage in the table includes 0.10.2 million, 0.20.1 million and 0.1 million net acres subject to leases that are scheduled to expire during 2018, 2019, 2020 and 2020,2021, respectively. As of December 31, 2017,2018, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.40.3 million net acres set to expire by December 31, 2020,2021, we anticipate performing operational and administrative actions to continue the lease terms for portions of the acreage that we intend to further assess. However, we do expect to allow a portion of the acreage to expire in the normal course of business. In 2017,2018, we allowed approximately 0.20.1 million acres to 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. |
|
| 1,808 |
|
|
| 1,203 |
|
|
| 3,587 |
|
|
| 1,598 |
|
|
| 5,395 |
|
|
| 2,801 |
|
|
| 1,449 |
|
|
| 909 |
|
|
| 3,373 |
|
|
| 1,463 |
|
|
| 4,822 |
|
|
| 2,372 |
|
Canada |
|
| 685 |
|
|
| 504 |
| �� |
| 2,091 |
|
|
| 968 |
|
|
| 2,776 |
|
|
| 1,472 |
|
|
| 674 |
|
|
| 495 |
|
|
| 2,086 |
|
|
| 967 |
|
|
| 2,760 |
|
|
| 1,462 |
|
Total North America |
|
| 2,493 |
|
|
| 1,707 |
|
|
| 5,678 |
|
|
| 2,566 |
|
|
| 8,171 |
|
|
| 4,273 |
|
|
| 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, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
EnLink Midstream Properties
EnLink represents the primary component of our midstream operations. EnLink’s assets are comprised of systems and other assets located in four primary regions:
Texas – The Texas assets consist of natural gas gathering, processing and transmission operations in north Texas and the Midland and Delaware Basins in west Texas.
Oklahoma – The Oklahoma assets consist of natural gas gathering, processing and transmission activities in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK and Central Northern Oklahoma Woodford shale areas.
Louisiana – The Louisiana assets consist of natural gas pipelines, natural gas processing plants, gas and NGL storage facilities, fractionation facilities and NGL pipelines located in Louisiana.
Crude and Condensate – The Crude and Condensate assets consist of Ohio River Valley crude oil, condensate, condensate stabilization, natural gas compression and brine disposal activities in the Utica and Marcellus Shales, crude oil operations in the Permian Basin and central Oklahoma, and crude oil activities associated with VEX located in the Eagle Ford Shale.
13
Oil, Gas and NGL Marketing
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.
Additionally, we may enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Note 43 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2018,2019, 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 |
|
| 80 | % |
|
| — |
|
|
| 20 | % |
|
| — |
|
|
| 75 | % |
|
| — |
|
|
| 25 | % |
|
| — |
|
Natural gas |
|
| 52 | % |
|
| 4 | % |
|
| 44 | % |
|
| — |
|
|
| 67 | % |
|
| 4 | % |
|
| 29 | % |
|
| — |
|
NGLs |
|
| 33 | % |
|
| 20 | % |
|
| 47 | % |
|
| — |
|
|
| 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, 2017,2018, 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) |
|
| 86 |
|
|
| 31 |
|
|
| 49 |
|
|
| 6 |
|
|
| 53 |
|
|
| 25 |
|
|
| 28 |
|
|
| — |
|
Natural gas (Bcf) |
|
| 293 |
|
|
| 265 |
|
|
| 28 |
|
|
| — |
|
|
| 360 |
|
|
| 220 |
|
|
| 125 |
|
|
| 15 |
|
NGLs (MMBbls) |
|
| 11 |
|
|
| 11 |
|
|
| — |
|
|
| — |
|
|
| 10 |
|
|
| 10 |
|
|
| — |
|
|
| — |
|
Total (MMBoe) |
|
| 146 |
|
|
| 86 |
|
|
| 54 |
|
|
| 6 |
|
|
| 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 2018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.
During 2017 2016 and 2015,2016, 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 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.
14
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.
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, wells drilled after January 1, 2017 would use the Modernized Royalty Framework (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 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.
15
TableIn December 2018, Alberta enacted the Curtailment Rules (Rules) in an effort to reduce Alberta’s oversupply of Contentsoil 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 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;
• | the monitoring, repair and design of pipelines used for the transportation of oil and natural gas; |
the protection of threatened and endangered species; and
• | 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.
14
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, in recentover the last five years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from a high of over $100 per Bbl and $6 per MMBtu, respectively, to a low of under $27 per Bbl and $1.70 per MMBtu, respectively. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:
supply of and demand for oil, gas and NGLs, including consumer demand in emerging markets, such as China and India;
• | 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;
16
• | 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 Western Canadian Select, a benchmark for the level of imports and exports ofCanadian oil gas and NGLs andmarket, recently expanded, widening to nearly $46 per barrel in November 2018. As a result, our Canadian heavy oil unhedged realized price for 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; and
governmental regulations and taxes.
Commodity prices began to decline in the second half of 2014 and, despite a moderate recovery, have generally been pressured since then.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. 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 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.
15
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.
17
Oil and GasOur Operations Are Uncertain and Involve Substantial Costs and Risks
Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
• | unexpected drilling conditions, pressure conditions or irregularities in reservoir formations; |
equipment failures or accidents;
• | equipment failures or accidents; |
fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;
• | 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, hurricanes and extreme temperatures;
• | 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; |
restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
• | 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, as well as significant liabilities. Moreover, certain of these events could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.
In addition, we rely on our employees, consultants and sub-contractors to conduct our operations in compliance with applicable laws and standards. Any violation of such laws or standards by these individuals, whether through negligence, harassment, discrimination or other misconduct, could result in significant liability for us and adversely affect our business. For example, negligent operations by employees could result in serious injury, death or property damage, and sexual harassment or racial and gender discrimination could result in legal claims and reputational harm.
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 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.
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Hydraulic Fracturing – In recent years, the EPA has made proposals that 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 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 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The BLM previously finalized regulations to regulate hydraulic fracturing on federal lands, but subsequently issued a repeal of those regulations in 2017. Several 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 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 quarterhalf of 2018.2019. 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.
Seismic Activity – Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims, seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
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Changes to Tax Laws – We are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions, and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. Recently enacted legislation commonly referred to as the Tax Cuts
Concerns About Climate Change and Jobs Act (the “Tax Reform Legislation”) significantly affects U.S. tax law by changing how the U.S. imposes income tax on multinational corporations. These changes include, among others, a permanent reduction to the corporate income tax offset by other items intended to broaden the tax base (for example, by imposing significant additional limitations on the deductibility of interest expenseRelated Regulatory, Social and limiting the ability to deduct net operating losses).Market Actions May Adversely Affect Our Business
The U.S. Department of Treasury has broad authority to issue regulationsContinuing and interpretative guidance that may significantly impact how we will apply the law and impact our results of operations in the period issued. Further, compliance with the Tax Reform Legislation and the accounting for such provisions require complex computations and accumulation of information not previously required or regularly produced. As a result, we have provided a provisional estimate in our financial statements of the effect of the Tax Reform Legislation. As additional regulatory guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which will be recorded in the period completed, may be different from our current provisional amounts, which could materially affect our tax obligations and effective tax rate.
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Climate Change – Continuingincreasing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers 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; however, followingindustry. Following the change in presidential administrations, bothhowever, the agencies have published proposed rules that seekattempted to delay implementation ofrevise or rescind their previously issued methane standards while the agencies reviewstandards. Litigation concerning these methane regulations and reconsider both rules.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. LegislativeWith 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.products.
In Canada, greenhouse gas emissions are also being addressed at both the federal and provincial level. RecentDevon will continue to be subject to Alberta’s climate policieschange laws and regulations until at least 2021. Those laws and regulations include a legislated oil sands emission limit, andwith forthcoming policies includeregulations involving methane emissions reduction targets. Beginning January 1, 2018,2019, the Greenhouse Gas Pollution Pricing Act subjects all of Canada to a 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). This regulationThe 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 theits economy-wide carbon levy until 2023.
In addition activists concerned aboutto regulatory risk, other market and social initiatives resulting from the potential effectschanging perception of climate change have directed their attention atpresent 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 funding for fossil-fuel energy companies, which has resulted inspecific 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. Ultimately, thisactivities due to their concern regarding climate change. Such restrictions in capital could make it more difficult to secure funding for exploration and production activities. These various legislative, regulatoryto operate our business. Finally, governmental entities and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipmentplaintiffs have brought, and operations, which could requiremay continue to bring, claims against us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand forand 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.
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 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 become subject to increased governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost
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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 share of costs. We also frequently look to buyers of oil and gas properties from us to perform certain obligations associated with the disposed assets, including the removal of production facilities and plugging and abandonment of wells. Certain of these counterparties may experience insolvency, liquidity problems or other issues and may not be able to meet their obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or volatile commodity price environment. Any such default by these counterparties may result in us being forced to cover the costs of those obligations and liabilities, which could adversely impact our financial results and condition.
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Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us
As of December 31, 2017,2018, we had total consolidated indebtedness of $10.4$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 asset sales and purchases, liquidity, forecasted production growth and commodity prices. We are currently required to provide letters of credit or other assurances under certain of our contractual arrangements. Any credit downgrades could adversely impact our ability to access financing and trade credit, require us to provide additional letters of credit or other assurances under contractual arrangements and increase our interest rate under any credit facility borrowing as well as the cost of any other future debt.
Environmental Matters and Related Costs Can Be 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. 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 May Adversely Impact Our Operations
Our business 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 cyberattack activities, which have been increasing against our industry. Cyber attackers often attempt to gain unauthorized access to digital systems for purposes of misappropriating sensitive information, intellectual property or otherfinancial assets,
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corrupting data or causing operational disruptions. These attacks may be perpetrated by third parties or insiders. Techniques 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, 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.
21
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
As discussed above, our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development production, processing and transportationproduction of oil, gas and NGLs.
To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain workers’ compensation and employer’s liability insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting from these operational hazards. Additionally, 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.
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Item 1B.UnresolvedUnresolved Staff Comments
Not applicable.
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.
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.
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 7, 2018,6, 2019, there were 7,4667,094 holders of record of our common stock. We began paying regular quarterly cash dividends in the second quarter of 1993. The declaration of future dividends is a business decision made by our Board of Directors, from time to time, and will depend on Devon’s financial condition and other relevant factors. The following table sets forth the quarterly highAdditional information on our dividends can be found in Note 18 in “Item 8. Financial Statements and low prices for our common stock during 2017 and 2016, as well as the quarterly dividends per share.Supplementary Data” of this report.
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| Price Range of Common Stock |
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| Dividends |
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| Per Share |
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Quarter Ended 2017: |
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December 31, 2017 |
| $ | 42.60 |
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| $ | 33.98 |
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| $ | 0.06 |
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September 30, 2017 |
| $ | 37.44 |
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| $ | 28.80 |
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| $ | 0.06 |
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June 30, 2017 |
| $ | 43.50 |
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| $ | 29.89 |
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| $ | 0.06 |
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March 31, 2017 |
| $ | 49.45 |
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| $ | 38.02 |
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| $ | 0.06 |
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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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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, 20122013 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.
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Issuer Purchases of Equity Securities
The following table detailsprovides information regarding purchases of our common stock that were made by us during the fourth quarter of 2017. During 2017, we did not repurchase any shares that were a part of a publicly announced program.
2018 (shares in thousands).
Period |
| Total Number of Shares Purchased (1) |
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| Average Price Paid per Share |
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| Average Price Paid per Share |
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October 1 - October 31 |
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| 9,768 |
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| $ | 35.27 |
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| 10,532 |
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| $ | 36.01 |
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| 10,529 |
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| $ | 2,388 |
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November 1 - November 30 |
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| 29,160 |
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| $ | 38.68 |
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| 7,079 |
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| $ | 31.55 |
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| 7,068 |
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| $ | 2,165 |
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December 1 - December 31 |
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| 2,321 |
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| $ | 39.06 |
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| 6,020 |
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| $ | 23.82 |
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| 6,015 |
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| $ | 2,022 |
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Total |
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| 41,249 |
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| $ | 37.89 |
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| 23,631 |
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| $ | 31.57 |
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| 23,612 |
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| 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 for $3.0 billion, or $38.11 per share. Future purchases under the program will be made in the open market, private transactions or through the use of ASR programs. |
Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 46,00039,000 shares of our common
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stock in 2017,2018, 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 this plan through open-market purchases.
Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee. Eligible employees purchased approximately 6,200 shares of our common stock in 2017. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In 2018, there were no shares purchased by Canadian employees under the plan.
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Item 6.Selected Financial Data
The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this report.
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Statement of Earnings data: |
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Upstream revenues |
| $ | 5,307 |
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| $ | 3,981 |
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| $ | 5,885 |
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| $ | 11,619 |
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| $ | 7,296 |
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| $ | 6,285 |
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| $ | 5,307 |
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| $ | 3,981 |
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| $ | 5,885 |
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| $ | 11,619 |
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Total revenues |
| $ | 13,949 |
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| $ | 10,304 |
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| $ | 13,145 |
|
| $ | 19,285 |
|
| $ | 9,362 |
|
| $ | 10,734 |
|
| $ | 8,878 |
|
| $ | 6,753 |
|
| $ | 9,372 |
|
| $ | 16,636 |
|
Earnings (loss) from continuing operations (1) |
| $ | 1,078 |
|
| $ | (1,458 | ) |
| $ | (13,645 | ) |
| $ | (753 | ) |
| $ | (938 | ) | ||||||||||||||||||||
Earnings (loss) from continuing operations attributable to Devon (1) |
| $ | 898 |
|
| $ | (1,056 | ) |
| $ | (12,896 | ) |
| $ | (837 | ) |
| $ | (938 | ) | ||||||||||||||||||||
Earnings (loss) from continuing operations per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Basic (1) |
| $ | 1.71 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
| $ | (2.08 | ) |
| $ | (2.34 | ) | ||||||||||||||||||||
Diluted (1) |
| $ | 1.70 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
| $ | (2.08 | ) |
| $ | (2.34 | ) | ||||||||||||||||||||
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 |
| $ | 0.24 |
|
| $ | 0.42 |
|
| $ | 0.96 |
|
| $ | 0.94 |
|
| $ | 0.86 |
|
| $ | 0.30 |
|
| $ | 0.24 |
|
| $ | 0.42 |
|
| $ | 0.96 |
|
| $ | 0.94 |
|
Balance Sheet data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 30,241 |
|
| $ | 28,675 |
|
| $ | 29,673 |
|
| $ | 49,253 |
|
| $ | 44,390 |
| ||||||||||||||||||||
Long-term debt (2) |
| $ | 10,291 |
|
| $ | 10,154 |
|
| $ | 12,056 |
|
| $ | 9,761 |
|
| $ | 7,888 |
| ||||||||||||||||||||
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 |
| $ | 14,104 |
|
| $ | 12,722 |
|
| $ | 11,111 |
|
| $ | 24,789 |
|
| $ | 20,729 |
|
| $ | 9,186 |
|
| $ | 14,104 |
|
| $ | 12,722 |
|
| $ | 11,111 |
|
| $ | 24,789 |
|
Common shares outstanding |
|
| 525 |
|
|
| 523 |
|
|
| 418 |
|
|
| 409 |
|
|
| 406 |
|
|
| 450 |
|
|
| 525 |
|
|
| 523 |
|
|
| 418 |
|
|
| 409 |
|
|
| In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers using the modified retrospective method and has applied the standard to |
| (2) | Material asset impairments and acquisition and divestiture activity |
|
| Amounts in 2014 through 2017 |
2624
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 20172018 Results
During 2017,2018 was a pivotal year for Devon as we generated solidtook several significant steps toward achieving our long-term strategic goals. Operationally, we successfully transitioned our U.S. oil business into full-field development, which resulted in high-return, light-oil production advancing 14 percent in 2018. In addition to this strong operating results withperformance, we made substantial progress high-grading our strategy of operating in North America’s best resource plays, delivering superior execution, continuing disciplined capital allocationasset portfolio, building per-share value through our share-repurchase program and maintaining a high degree of financial strength. Led by our development in the STACK and Delaware Basin, we continued to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells.
Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in Devon’s earnings and cash flow during 2017. We exited 2017 with liquidity comprised of $2.7 billion of cash and $2.9 billion of available credit under our Senior Credit Facility. We have no significant debt maturities until 2021.
We further enhancedreducing our financial strengthleverage by completing approximately $415 million of our announced $1 billion asset divestiture program in 2017. We anticipate closing the remaining divestitures in 2018.
In 2018 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 shift our production mix to high-margin products. We will continue our premier technical work to drive capital allocation and efficiency and industry-leading well productivity results. We will continue to maximize the value of our base production by sustaining the operational efficiencies we have achieved. Finally, we will continue to manage activity levels within our cash flows. We expect this disciplined approach will position us to deliver capital-efficient, cash-flow expansion over the next two years.
Key measures of our financial performance in 2017 are summarized in the following table. Increased commodity prices as well as continued focus on our production expenses improved our 2017 financial performance as compared to 2016, as seen in the table below. More details for these metrics are found within the “Results of Operations – 2017 vs. 2016”, below.
|
| 2017 |
|
| Change |
|
| 2016* |
|
| Change |
|
| 2015* |
| |||||
Net earnings (loss) attributable to Devon |
| $ | 898 |
|
|
| +185 | % |
| $ | (1,056 | ) |
|
| +92 | % |
| $ | (12,896 | ) |
Net earnings (loss) per diluted share attributable to Devon |
| $ | 1.70 |
|
|
| +181 | % |
| $ | (2.09 | ) |
|
| +93 | % |
| $ | (31.72 | ) |
Core earnings (loss) attributable to Devon (1) |
| $ | 427 |
|
|
| +217 | % |
| $ | (367 | ) |
|
| - 430 | % |
| $ | 111 |
|
Core earnings (loss) per diluted share attributable to Devon (1) |
| $ | 0.81 |
|
|
| +210 | % |
| $ | (0.73 | ) |
|
| - 382 | % |
| $ | 0.26 |
|
Retained production (MBoe/d) |
|
| 541 |
|
|
| - 4 | % |
|
| 563 |
|
|
| - 3 | % |
|
| 580 |
|
Total production (MBoe/d) |
|
| 543 |
|
|
| - 11 | % |
|
| 611 |
|
|
| - 10 | % |
|
| 680 |
|
Realized price per Boe (2) |
| $ | 25.96 |
|
|
| +39 | % |
| $ | 18.72 |
|
|
| - 14 | % |
| $ | 21.68 |
|
Operating cash flow |
| $ | 2,909 |
|
|
| +94 | % |
| $ | 1,500 |
|
|
| - 69 | % |
| $ | 4,898 |
|
Capitalized expenditures, including acquisitions |
| $ | 2,937 |
|
|
| - 25 | % |
| $ | 3,908 |
|
|
| - 32 | % |
| $ | 5,712 |
|
Shareholder and noncontrolling interests distributions |
| $ | 481 |
|
|
| - 8 | % |
| $ | 525 |
|
|
| - 19 | % |
| $ | 650 |
|
Cash and cash equivalents |
| $ | 2,673 |
|
|
| +36 | % |
| $ | 1,959 |
|
|
| - 15 | % |
| $ | 2,310 |
|
Total debt |
| $ | 10,406 |
|
|
| +2 | % |
| $ | 10,154 |
|
|
| - 22 | % |
| $ | 13,032 |
|
Reserves (MMBoe) |
|
| 2,152 |
|
|
| +5 | % |
|
| 2,058 |
|
|
| - 6 | % |
|
| 2,182 |
|
27
more than 40 percent.
|
| Increased STACK and Delaware Basin production 27% in 2018 compared to |
| • | 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. |
Business and Industry Outlook
Devon marked its 46th anniversary in the oil and gas business and its 29th year as a public company during 2017. 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 focused on navigating 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 2017,In 2018, WTI oil prices ranged fromaveraged approximately $42.00/$67/Bbl to $60.00/Bbl,through October, supported by increasing globalstronger-than-expected oil demand, and historically high OPEC compliance with its oil production cuts that were put in place in 2016 for the first half of 2017. Following the decisionmarket management by both OPEC and non-OPEC producers to extend the agreement to reduce output by nearly 1.8 million barrels per day through the end of 2018,partners and unplanned supply outages. However, oil prices increasedmarkedly declined in November and December, averaging approximately 15%$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 2017, averaging $55.49/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 oilpricing 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 2018; however, changeslate 2019. Changes in OPEC production strategies, the macro-economic environment, geopolitical risks orand other factors could impact our current forecasts. As such, we anticipate continued volatility into
In 2018, Devon marked its 30th year as a public company and we continue to execute on our hedging strategy to mitigate such volatility.
Leveraging47th anniversary in the success of our 2017 results, we have a solid financial condition and anticipate expanding our oil and gas investment bybusiness, 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 disciplined, risk-management hedging program. Our hedging program incorporates both systematic hedges added on a regular basis and discretionary hedges layered in on an opportunistic basis to take advantage of favorable market conditions. We have approximately 10%50% of our anticipated 2019 oil and gas volumes hedged, and we are currently adding hedges for 2020 as well. Further insulating our cash flow, we are proactively locking in 2018, while drillinghedges on the Western Canadian Select basis differential to WTI and completingcurrently have approximately 25% more wells. Our 2018 outlook is50% of our 2019 Canadian heavy oil production hedged.
26
Despite the uncertainties pertaining to commodity prices, we remain focused on our high returningstrategic 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 STACK and Delaware Basin, STACK, Eagle Ford and achieving top-line oil-equivalentRockies. 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 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.
Importantly, the portfolio changes and optimized cost performance are expected to enhance 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 6%-9%, on a retained asset basis, through some offunding our best-in-class positions. Additionally,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 continuedcan achieve all our capital allocation priorities at $46/Bbl WTI and $3.00/Mcf Henry Hub. Should WTI drop closer to execute$40/Bbl for an extended period, we would shift our hedging program in 2017focus to preserving our financial strength and now have approximately 40% ofoperational continuity. However, as WTI rises above $46/Bbl, our oil and 50% of our gas production hedged for 2018. With our anticipated results and hedging program, we intend to fully fund our increased activity with our operating cash flow. Additionally, we are targeting reducing our debt by approximately $1 billion.
Finally, EnLink continues to be a strategic advantage for us. With annual distributions to us of approximately $270 million, EnLink provides a visiblefree cash flow stream to be further invested in our upstreamwill accelerate, providing additional capital programs.allocation opportunities.
28
Results of Operations – 20172018 vs. 20162017
The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Specifically, the graph below shows the change in net earnings from 20162017 to 2017.2018. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Additional information regarding noncontrolling interests is discussed in Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
(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 operations change presented above, with additional details and discussion of the drivers following the graph.
|
| As further discussed in |
29
28
Upstream Operations |
Oil, Gas and NGL Production
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||||||
Oil and bitumen (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 42 |
|
|
| 17 | % |
|
| 29 |
|
|
| +42 | % | ||||||||||||||||
STACK |
|
| 26 |
|
|
| 11 | % |
|
| 19 |
|
|
| +38 | % |
|
| 32 |
|
|
| 13 | % |
|
| 25 |
|
|
| +28 | % |
Delaware Basin |
|
| 31 |
|
|
| 13 | % |
|
| 33 |
|
|
| - 7 | % | ||||||||||||||||
Rockies Oil |
|
| 14 |
|
|
| 6 | % |
|
| 14 |
|
|
| +1 | % |
|
| 14 |
|
|
| 6 | % |
|
| 10 |
|
|
| +37 | % |
Heavy Oil |
|
| 18 |
|
|
| 7 | % |
|
| 22 |
|
|
| - 19 | % |
|
| 18 |
|
|
| 7 | % |
|
| 18 |
|
|
| +1 | % |
Eagle Ford |
|
| 34 |
|
|
| 14 | % |
|
| 39 |
|
|
| - 14 | % |
|
| 28 |
|
|
| 12 | % |
|
| 34 |
|
|
| - 17 | % |
Barnett Shale |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 25 | % |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| - 7 | % |
Other |
|
| 8 |
|
|
| 2 | % |
|
| 11 |
|
|
| - 28 | % |
|
| 5 |
|
|
| 2 | % |
|
| 5 |
|
|
| - 3 | % |
Retained assets |
|
| 132 |
|
|
| 54 | % |
|
| 139 |
|
|
| - 4 | % |
|
| 140 |
|
|
| 57 | % |
|
| 122 |
|
|
| +14 | % |
Divested assets |
|
| 2 |
|
|
| 1 | % |
|
| 12 |
|
|
| - 87 | % | ||||||||||||||||
U.S. divested assets |
|
| 9 |
|
|
| 4 | % |
|
| 12 |
|
|
| - 23 | % | ||||||||||||||||
Total Oil |
|
| 134 |
|
|
| 55 | % |
|
| 151 |
|
|
| - 11 | % |
|
| 149 |
|
|
| 61 | % |
|
| 134 |
|
|
| +11 | % |
Bitumen |
|
| 110 |
|
|
| 45 | % |
|
| 109 |
|
|
| +1 | % |
|
| 97 |
|
|
| 39 | % |
|
| 110 |
|
|
| - 12 | % |
Total Oil and bitumen |
|
| 244 |
|
|
|
|
|
|
| 260 |
|
|
| - 6 | % |
|
| 246 |
|
|
| 100 | % |
|
| 244 |
|
|
| +1 | % |
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 105 |
|
|
| 10 | % |
|
| 86 |
|
|
| +22 | % | ||||||||||||||||
STACK |
|
| 304 |
|
|
| 25 | % |
|
| 293 |
|
|
| +4 | % |
|
| 334 |
|
|
| 30 | % |
|
| 294 |
|
|
| +13 | % |
Delaware Basin |
|
| 90 |
|
|
| 7 | % |
|
| 90 |
|
|
| +1 | % | ||||||||||||||||
Rockies Oil |
|
| 15 |
|
|
| 1 | % |
|
| 25 |
|
|
| - 39 | % |
|
| 16 |
|
|
| 1 | % |
|
| 8 |
|
|
| +85 | % |
Heavy Oil |
|
| 17 |
|
|
| 2 | % |
|
| 20 |
|
|
| - 14 | % |
|
| 10 |
|
|
| 1 | % |
|
| 17 |
|
|
| - 39 | % |
Eagle Ford |
|
| 95 |
|
|
| 8 | % |
|
| 101 |
|
|
| - 6 | % |
|
| 79 |
|
|
| 7 | % |
|
| 95 |
|
|
| - 17 | % |
Barnett Shale |
|
| 667 |
|
|
| 55 | % |
|
| 741 |
|
|
| - 10 | % |
|
| 447 |
|
|
| 41 | % |
|
| 475 |
|
|
| - 6 | % |
Other |
|
| 11 |
|
|
| 1 | % |
|
| 13 |
|
|
| - 16 | % |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| +6 | % |
Retained assets |
|
| 1,199 |
|
|
| 99 | % |
|
| 1,283 |
|
|
| - 7 | % |
|
| 992 |
|
|
| 90 | % |
|
| 976 |
|
|
| +2 | % |
Divested assets |
|
| 4 |
|
|
| 1 | % |
|
| 130 |
|
|
| - 97 | % | ||||||||||||||||
U.S. divested assets |
|
| 108 |
|
|
| 10 | % |
|
| 227 |
|
|
| - 52 | % | ||||||||||||||||
Total |
|
| 1,203 |
|
|
|
|
|
|
| 1,413 |
|
|
| - 15 | % |
|
| 1,100 |
|
|
| 100 | % |
|
| 1,203 |
|
|
| - 9 | % |
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 16 |
|
|
| 15 | % |
|
| 10 |
|
|
| +53 | % | ||||||||||||||||
STACK |
|
| 31 |
|
|
| 31 | % |
|
| 26 |
|
|
| +18 | % |
|
| 37 |
|
|
| 35 | % |
|
| 30 |
|
|
| +24 | % |
Delaware Basin |
|
| 11 |
|
|
| 11 | % |
|
| 12 |
|
|
| - 9 | % | ||||||||||||||||
Rockies Oil |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| +2 | % |
|
| 1 |
|
|
| 2 | % |
|
| 1 |
|
|
| +75 | % |
Eagle Ford |
|
| 13 |
|
|
| 13 | % |
|
| 16 |
|
|
| - 19 | % |
|
| 13 |
|
|
| 12 | % |
|
| 13 |
|
|
| +2 | % |
Barnett Shale |
|
| 41 |
|
|
| 42 | % |
|
| 45 |
|
|
| - 8 | % |
|
| 30 |
|
|
| 28 | % |
|
| 31 |
|
|
| - 4 | % |
Other |
|
| 2 |
|
|
| 2 | % |
|
| 2 |
|
|
| +39 | % |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 5 | % |
Retained assets |
|
| 99 |
|
|
| 100 | % |
|
| 102 |
|
|
| - 2 | % |
|
| 98 |
|
|
| 93 | % |
|
| 86 |
|
|
| +14 | % |
Divested assets |
|
| — |
|
|
| — |
|
|
| 14 |
|
|
| - 100 | % | ||||||||||||||||
U.S. divested assets |
|
| 8 |
|
|
| 7 | % |
|
| 13 |
|
|
| - 40 | % | ||||||||||||||||
Total |
|
| 99 |
|
|
|
|
|
|
| 116 |
|
|
| - 15 | % |
|
| 106 |
|
|
| 100 | % |
|
| 99 |
|
|
| +7 | % |
|
| 2017 |
|
| % of Total |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| % of Total |
|
| 2017 |
|
| Change |
| ||||||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 75 |
|
|
| 14 | % |
|
| 54 |
|
|
| +39 | % | ||||||||||||||||
STACK |
|
| 107 |
|
|
| 20 | % |
|
| 93 |
|
|
| +15 | % |
|
| 125 |
|
|
| 24 | % |
|
| 104 |
|
|
| +20 | % |
Delaware Basin |
|
| 56 |
|
|
| 10 | % |
|
| 60 |
|
|
| - 6 | % | ||||||||||||||||
Rockies Oil |
|
| 17 |
|
|
| 3 | % |
|
| 19 |
|
|
| - 8 | % |
|
| 17 |
|
|
| 3 | % |
|
| 12 |
|
|
| +43 | % |
Heavy Oil |
|
| 131 |
|
|
| 24 | % |
|
| 134 |
|
|
| - 2 | % |
|
| 117 |
|
|
| 22 | % |
|
| 131 |
|
|
| - 11 | % |
Eagle Ford |
|
| 62 |
|
|
| 11 | % |
|
| 72 |
|
|
| - 13 | % |
|
| 54 |
|
|
| 10 | % |
|
| 62 |
|
|
| - 13 | % |
Barnett Shale |
|
| 153 |
|
|
| 28 | % |
|
| 169 |
|
|
| - 10 | % |
|
| 105 |
|
|
| 20 | % |
|
| 111 |
|
|
| - 5 | % |
Other |
|
| 15 |
|
|
| 3 | % |
|
| 16 |
|
|
| - 5 | % |
|
| 7 |
|
|
| 1 | % |
|
| 7 |
|
|
| - 3 | % |
Retained assets |
|
| 541 |
|
|
| 99 | % |
|
| 563 |
|
|
| - 4 | % |
|
| 500 |
|
|
| 94 | % |
|
| 481 |
|
|
| +4 | % |
Divested assets |
|
| 2 |
|
|
| 1 | % |
|
| 48 |
|
|
| - 96 | % | ||||||||||||||||
U.S. divested assets |
|
| 35 |
|
|
| 6 | % |
|
| 62 |
|
|
| - 44 | % | ||||||||||||||||
Total |
|
| 543 |
|
|
|
|
|
|
| 611 |
|
|
| - 11 | % |
|
| 535 |
|
|
| 100 | % |
|
| 543 |
|
|
| - 2 | % |
Production declines reduced our upstream revenues by $427 million primarily asFocused 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 result of17% increase in our U.S. non-core divestitures that occurred throughout 2016 and 2017. Retained production volumes decreased dueretained oil production. This strong performance led to reduced completion activitythe overall growth in the Eagle Ford and natural production declines in the Barnett Shale. These decreasesour retained assets during 2018. Production increases from our capital focused assets were partially offset by expanded drillingthe effects of facility repairs and performance inother maintenance work at the STACK.Jackfish facilities, as well as by lower production resulting from our U.S. non-core divestitures.
Oil, Gas and NGL Prices
|
| 2017 |
|
| Realization |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||||||
Oil and bitumen (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 50.99 |
|
|
|
|
|
| $ | 43.36 |
|
|
| +18 | % |
| $ | 64.79 |
|
|
|
|
|
| $ | 50.99 |
|
|
| +27 | % |
Access Western Blend index |
| $ | 36.90 |
|
|
|
|
|
| $ | 26.96 |
|
|
| +37 | % |
| $ | 34.75 |
|
|
|
|
|
| $ | 36.90 |
|
|
| - 6 | % |
U.S. |
| $ | 49.41 |
|
|
| 97% |
|
| $ | 38.92 |
|
|
| +27 | % |
| $ | 61.97 |
|
|
| 96% |
|
| $ | 49.41 |
|
|
| +25 | % |
Canada |
| $ | 29.99 |
|
|
| 59% |
|
| $ | 20.53 |
|
|
| +46 | % |
| $ | 19.37 |
|
|
| 30% |
|
| $ | 29.99 |
|
|
| - 35 | % |
Realized price, unhedged |
| $ | 39.23 |
|
|
| 77% |
|
| $ | 29.65 |
|
|
| +32 | % |
| $ | 42.04 |
|
|
| 65% |
|
| $ | 39.23 |
|
|
| +7 | % |
Cash settlements |
| $ | 0.23 |
|
|
|
|
|
| $ | (0.43 | ) |
|
|
|
|
| $ | (0.49 | ) |
|
|
|
|
| $ | 0.23 |
|
|
|
|
|
Realized price, with hedges |
| $ | 39.46 |
|
|
| 77% |
|
| $ | 29.22 |
|
|
| +35 | % |
| $ | 41.55 |
|
|
| 64% |
|
| $ | 39.46 |
|
|
| +5 | % |
|
| 2017 |
|
| Realization |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||||||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 3.11 |
|
|
|
|
|
| $ | 2.46 |
|
|
| +26 | % |
| $ | 3.09 |
|
|
|
|
|
| $ | 3.11 |
|
|
| - 1 | % |
Realized price, unhedged |
| $ | 2.48 |
|
|
| 80% |
|
| $ | 1.84 |
|
|
| +35 | % |
| $ | 2.37 |
|
|
| 77% |
|
| $ | 2.48 |
|
|
| - 5 | % |
Cash settlements |
| $ | 0.08 |
|
|
|
|
|
| $ | 0.07 |
|
|
|
|
|
| $ | 0.01 |
|
|
|
|
|
| $ | 0.08 |
|
|
|
|
|
Realized price, with hedges |
| $ | 2.56 |
|
|
| 82% |
|
| $ | 1.91 |
|
|
| +34 | % |
| $ | 2.38 |
|
|
| 77% |
|
| $ | 2.56 |
|
|
| - 7 | % |
|
| 2017 |
|
| Realization |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| Realization |
|
| 2017 |
|
| Change |
| ||||||||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 24.77 |
|
|
|
|
|
| $ | 17.20 |
|
|
| +44 | % |
| $ | 28.31 |
|
|
|
|
|
| $ | 24.77 |
|
|
| +14 | % |
Realized price, unhedged |
| $ | 15.66 |
|
|
| 63% |
|
| $ | 9.81 |
|
|
| +60 | % |
| $ | 24.74 |
|
|
| 87% |
|
| $ | 15.66 |
|
|
| +58 | % |
Cash settlements |
| $ | (0.10 | ) |
|
|
|
|
| $ | (0.11 | ) |
|
|
|
|
| $ | (1.17 | ) |
|
|
|
|
| $ | (0.10 | ) |
|
|
|
|
Realized price, with hedges |
| $ | 15.56 |
|
|
| 63% |
|
| $ | 9.70 |
|
|
| +60 | % |
| $ | 23.57 |
|
|
| 83% |
|
| $ | 15.56 |
|
|
| +51 | % |
(1) | Based upon composition of our NGL barrel. |
3029
|
| 2017 |
|
| 2016 |
|
| Change |
|
| 2018 |
|
| 2017 |
|
| Change |
| ||||||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 24.88 |
|
| $ | 18.34 |
|
|
| +36 | % |
| $ | 31.86 |
|
| $ | 24.88 |
|
|
| +28 | % |
Canada |
| $ | 29.39 |
|
| $ | 20.07 |
|
|
| +46 | % |
| $ | 19.12 |
|
| $ | 29.39 |
|
|
| - 35 | % |
Realized price, unhedged |
| $ | 25.96 |
|
| $ | 18.72 |
|
|
| +39 | % |
| $ | 29.08 |
|
| $ | 25.96 |
|
|
| +12 | % |
Cash settlements |
| $ | 0.27 |
|
| $ | (0.05 | ) |
|
|
|
|
| $ | (0.43 | ) |
| $ | 0.27 |
|
|
|
|
|
Realized price, with hedges |
| $ | 26.23 |
|
| $ | 18.67 |
|
|
| +40 | % |
| $ | 28.65 |
|
| $ | 26.23 |
|
|
| +9 | % |
Upstream revenues increased $1.4 billion as a result of higher unhedged, realized prices acrossfor our entire portfolio. U.S. oil and NGLs.
The increase in oil and bitumen sales primarily resulted from higher average WTI crude index prices, which were 18%27% higher in 2017. Additionally, our oil and bitumen2018, resulting in an increase of approximately $568 million.
NGL sales benefited from tighter differentials to the WTI index. The increase in gas sales were driven by higher North American regional index prices upon which our gas sales are based andincreased $351 million as a result of 14% higher NGL prices at the Mont Belvieu, Texas hub.hub, as well as improved realizations in our NGL price.
These increases were partially offset by widening differentials to the WTI index for bitumen sales, which negatively impacted our upstream revenues by $406 million. In the fourth quarter of 2018, market forces widened Canadian heavy oil differentials beyond historical norms and negatively impacted the price we realized on our Canadian production. We had basis swaps for approximately half of our fourth quarter production to mitigate the effect of the lower market price. To further mitigate the effects of the lower price, we reduced our Jackfish production in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d. 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 will changechanged from a net to a gross presentation. We estimate theThe change resulted in an increase to increase our upstream revenues and production expenses by approximately $250$254 million annually with no impact to net earnings.
Commodity Derivatives
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
| $ | 21 |
|
| $ | (41 | ) |
|
| +151 | % |
Natural gas |
|
| 35 |
|
|
| 35 |
|
|
| +0 | % |
NGL |
|
| (3 | ) |
|
| (5 | ) |
|
| +40 | % |
Total cash settlements |
|
| 53 |
|
|
| (11 | ) |
| N/M |
| |
Valuation changes |
|
| 104 |
|
|
| (190 | ) |
|
| +155 | % |
Total |
| $ | 157 |
|
| $ | (201 | ) |
|
| +178 | % |
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 4 in “Item 8. Financial Statements and Supplementary Data” of this report.
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 relationship between contract prices and the associated forward curves.
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
LOE |
| $ | 927 |
|
| $ | 1,027 |
|
|
| - 10 | % |
Gathering & transportation |
|
| 647 |
|
|
| 555 |
|
|
| +17 | % |
Production taxes |
|
| 194 |
|
|
| 147 |
|
|
| +32 | % |
Property taxes |
|
| 55 |
|
|
| 74 |
|
|
| - 26 | % |
Total |
| $ | 1,823 |
|
| $ | 1,803 |
|
|
| +1 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 4.67 |
|
| $ | 4.59 |
|
|
| +2 | % |
Gathering & transportation |
| $ | 3.26 |
|
| $ | 2.48 |
|
|
| +31 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 3.8 | % |
|
| 3.5 | % |
|
| +7 | % |
LOE decreased $100 million primarily due to our non-core U.S. property divestitures in 2016. Continued well optimization and cost reduction initiatives across our portfolio have offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers.
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 the pipeline. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $110 million annually.
Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed.
Property taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. non-core divestitures.
|
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
Operating revenues |
| $ | 5,740 |
|
| $ | 4,252 |
|
|
| +35 | % |
Product purchases |
|
| (4,362 | ) |
|
| (3,015 | ) |
|
| +45 | % |
Operations and maintenance expenses |
|
| (418 | ) |
|
| (398 | ) |
|
| +5 | % |
EnLink margin |
|
| 960 |
|
|
| 839 |
|
|
| +14 | % |
Devon margin |
|
| (48 | ) |
|
| (49 | ) |
|
| - 2 | % |
Total |
| $ | 912 |
|
| $ | 790 |
|
|
| +15 | % |
The overall increase in marketing and midstream operating margin was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities. Devon’s margins continue to be negatively impacted by downstream marketing commitments. We are actively engaged in optimization activities to reduce the costs of downstream commitments; however, we expect such commitments will continue to negatively impact our margin in 2018. As further discussed in Note 1 in “Item 8. Financials Statements and Supplementary Data” of this report, in 2018 EnLink’s marketing and midstream revenues are estimated to decrease by 6-10% with a corresponding decrease to marketing and midstream expenses as a result of complying with the new revenue recognition accounting standard.
31
|
|
| 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 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 increased primarily in the STACK and Delaware Basin.
|
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 7.15 |
|
| $ | 6.47 |
|
|
| +11 | % |
Oil and gas |
| $ | 1,419 |
|
| $ | 1,446 |
|
|
| - 2 | % |
Midstream and other assets |
|
| 110 |
|
|
| 146 |
|
|
| - 25 | % |
Devon |
|
| 1,529 |
|
|
| 1,592 |
|
|
| - 4 | % |
EnLink |
|
| 545 |
|
|
| 504 |
|
|
| +8 | % |
Total |
| $ | 2,074 |
|
| $ | 2,096 |
|
|
| - 1 | % |
Our oil and gas DD&A remained relatively flat as compared to the prior year. Increases in oil and gas DD&A rates due to continued development in the STACK and Delaware Basin were offset by reduced production volumes resulting from the 2016 U.S. asset divestitures. DD&A from our midstream and other assets decreased due to the divestiture of the Access Pipeline in the fourth quarter of 2016.
|
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
Labor and benefits |
| $ | 589 |
|
| $ | 614 |
|
|
| - 4 | % |
Non-labor |
|
| 228 |
|
|
| 215 |
|
|
| +6 | % |
Reimbursed G&A |
|
| (73 | ) |
|
| (82 | ) |
|
| - 11 | % |
Total Devon |
|
| 744 |
|
|
| 747 |
|
|
| - 0 | % |
EnLink |
|
| 128 |
|
|
| 118 |
|
|
| +8 | % |
Total |
| $ | 872 |
|
| $ | 865 |
|
|
| +1 | % |
Labor and benefits decreased primarily as a result of the workforce reduction that occurred in February 2016 as discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report. Non-labor costs were higher due to an increase in costs related to automation and process improvements. Reimbursed G&A decreased primarily due the divestitures of operated properties in 2016. EnLink G&A increased primarily due to higher compensation costs.
Financing costs, net decreased $409 million primarily as a result of our $2.1 billion early debt retirement in 2016. For further discussion of early retirement premiums and reduced interest expense resulting from our lower debt balances, see Note 16 in “Item 8. Financial Statements and Supplementary Data” of this report.
|
|
| 2017 |
|
| 2016 |
|
| Change |
| |||
Asset impairments |
| $ | 17 |
|
| $ | 1,310 |
|
|
| - 99 | % |
Asset dispositions |
|
| (217 | ) |
|
| (1,483 | ) |
|
| - 85 | % |
Restructuring |
|
| — |
|
|
| 267 |
|
| N/M |
| |
Other |
|
| (124 | ) |
|
| 108 |
|
|
| - 215 | % |
Total |
| $ | (324 | ) |
| $ | 202 |
|
|
| - 260 | % |
Asset impairments in 2016 primarily related to goodwill and other intangible asset impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
We recognized gains in conjunction with our non-core U.S. upstream asset dispositions in both 2016 and 2017 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, we recognized restructuring and transaction costs of $267 million primarily as a result of our workforce reduction. For discussion of our reorganization programs and the associated restructuring costs, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
The remaining change in other expense was driven primarily by changes on foreign currency exchange instruments as further discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
|
|
| 2017 |
|
| 2016 |
| ||
Current expense |
| $ | 112 |
|
| $ | 100 |
|
Deferred expense (benefit) |
|
| (294 | ) |
|
| 41 |
|
Total expense (benefit) |
| $ | (182 | ) |
| $ | 141 |
|
Effective income tax rate |
|
| (20 | %) |
|
| (11 | %) |
For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.
32
Results of Operations – 2016 vs. 2015
The graph below shows the change in net earnings from 2015 to 2016. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Additional information regarding noncontrolling interests is discussed in Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
The graph below presents the drivers of the upstream operations changed presented above, with additional details and discussion of the drivers following the graph.
|
|
33
|
Oil, Gas and NGL Production
|
| 2016 |
|
| % of Total |
|
| 2015 |
|
| Change |
| ||||
Oil and bitumen (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
|
| 19 |
|
|
| 7 | % |
|
| 7 |
|
|
| +152 | % |
Delaware Basin |
|
| 33 |
|
|
| 13 | % |
|
| 39 |
|
|
| - 16 | % |
Rockies Oil |
|
| 14 |
|
|
| 5 | % |
|
| 15 |
|
|
| - 9 | % |
Heavy Oil |
|
| 22 |
|
|
| 9 | % |
|
| 27 |
|
|
| - 17 | % |
Eagle Ford |
|
| 39 |
|
|
| 15 | % |
|
| 61 |
|
|
| - 35 | % |
Barnett Shale |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| - 28 | % |
Other |
|
| 11 |
|
|
| 4 | % |
|
| 13 |
|
|
| - 11 | % |
Retained assets |
|
| 139 |
|
|
| 53 | % |
|
| 163 |
|
|
| - 15 | % |
Divested assets |
|
| 12 |
|
|
| 5 | % |
|
| 28 |
|
|
| - 56 | % |
Total Oil |
|
| 151 |
|
|
| 58 | % |
|
| 191 |
|
|
| - 21 | % |
Bitumen |
|
| 109 |
|
|
| 42 | % |
|
| 84 |
|
|
| +29 | % |
Total Oil and bitumen |
|
| 260 |
|
|
|
|
|
|
| 275 |
|
|
| - 6 | % |
|
| 2016 |
|
| % of Total |
|
| 2015 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
|
| 293 |
|
|
| 21 | % |
|
| 239 |
|
|
| +23 | % |
Delaware Basin |
|
| 90 |
|
|
| 6 | % |
|
| 71 |
|
|
| +27 | % |
Rockies Oil |
|
| 25 |
|
|
| 2 | % |
|
| 40 |
|
|
| - 37 | % |
Heavy Oil |
|
| 20 |
|
|
| 1 | % |
|
| 22 |
|
|
| - 11 | % |
Eagle Ford |
|
| 101 |
|
|
| 7 | % |
|
| 141 |
|
|
| - 28 | % |
Barnett Shale |
|
| 741 |
|
|
| 53 | % |
|
| 815 |
|
|
| - 9 | % |
Other |
|
| 13 |
|
|
| 1 | % |
|
| 17 |
|
|
| - 22 | % |
Retained assets |
|
| 1,283 |
|
|
| 91 | % |
|
| 1,345 |
|
|
| - 5 | % |
Divested assets |
|
| 130 |
|
|
| 9 | % |
|
| 265 |
|
|
| - 51 | % |
Total |
|
| 1,413 |
|
|
|
|
|
|
| 1,610 |
|
|
| - 12 | % |
|
| 2016 |
|
| % of Total |
|
| 2015 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
|
| 26 |
|
|
| 23 | % |
|
| 21 |
|
|
| +22 | % |
Delaware Basin |
|
| 12 |
|
|
| 10 | % |
|
| 9 |
|
|
| +28 | % |
Rockies Oil |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 9 | % |
Eagle Ford |
|
| 16 |
|
|
| 14 | % |
|
| 23 |
|
|
| - 33 | % |
Barnett Shale |
|
| 45 |
|
|
| 39 | % |
|
| 51 |
|
|
| - 12 | % |
Other |
|
| 2 |
|
|
| 1 | % |
|
| 4 |
|
|
| - 59 | % |
Retained assets |
|
| 102 |
|
|
| 88 | % |
|
| 109 |
|
|
| - 7 | % |
Divested assets |
|
| 14 |
|
|
| 12 | % |
|
| 27 |
|
|
| - 50 | % |
Total |
|
| 116 |
|
|
|
|
|
|
| 136 |
|
|
| - 15 | % |
|
| 2016 |
|
| % of Total |
|
| 2015 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STACK |
|
| 93 |
|
|
| 15 | % |
|
| 68 |
|
|
| +37 | % |
Delaware Basin |
|
| 60 |
|
|
| 10 | % |
|
| 60 |
|
|
| - 1 | % |
Rockies Oil |
|
| 19 |
|
|
| 3 | % |
|
| 23 |
|
|
| - 17 | % |
Heavy Oil |
|
| 134 |
|
|
| 22 | % |
|
| 115 |
|
|
| +17 | % |
Eagle Ford |
|
| 72 |
|
|
| 12 | % |
|
| 107 |
|
|
| - 33 | % |
Barnett Shale |
|
| 169 |
|
|
| 28 | % |
|
| 188 |
|
|
| - 10 | % |
Other |
|
| 16 |
|
|
| 2 | % |
|
| 19 |
|
|
| - 13 | % |
Retained assets |
|
| 563 |
|
|
| 92 | % |
|
| 580 |
|
|
| - 3 | % |
Divested assets |
|
| 48 |
|
|
| 8 | % |
|
| 100 |
|
|
| - 52 | % |
Total |
|
| 611 |
|
|
|
|
|
|
| 680 |
|
|
| - 10 | % |
Production declines reduced our upstream revenues by $620 million. Production volumes decreased due to our reduction in exploration and development activity related to our retained assets during 2016. While expanded drilling in the STACK and the performance of our Jackfish assets drove production increases, these production increases were more than offset by reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale and Rockies Oil. Additionally, our production decreased as a result of our U.S. non-core divestitures that occurred throughout 2016.
Oil, Gas and NGL Prices
|
| 2016 |
|
| Realization |
|
| 2015 |
|
| Change |
| ||||
Oil and bitumen (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 43.36 |
|
|
|
|
|
| $ | 48.87 |
|
|
| - 11 | % |
Access Western Blend index |
| $ | 26.96 |
|
|
|
|
|
| $ | 32.18 |
|
|
| - 16 | % |
U.S. |
| $ | 38.92 |
|
|
| 90% |
|
| $ | 44.01 |
|
|
| - 12 | % |
Canada |
| $ | 20.53 |
|
|
| 47% |
|
| $ | 25.14 |
|
|
| - 18 | % |
Realized price, unhedged |
| $ | 29.65 |
|
|
| 68% |
|
| $ | 36.39 |
|
|
| - 19 | % |
Cash settlements |
| $ | (0.43 | ) |
|
|
|
|
| $ | 20.72 |
|
|
|
|
|
Realized price, with hedges |
| $ | 29.22 |
|
|
| 67% |
|
| $ | 57.11 |
|
|
| - 49 | % |
|
| 2016 |
|
| Realization |
|
| 2015 |
|
| Change |
| ||||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 2.46 |
|
|
|
|
|
| $ | 2.67 |
|
|
| - 8 | % |
Realized price, unhedged |
| $ | 1.84 |
|
|
| 75% |
|
| $ | 2.14 |
|
|
| - 14 | % |
Cash settlements |
| $ | 0.07 |
|
|
|
|
|
| $ | 0.57 |
|
|
|
|
|
Realized price, with hedges |
| $ | 1.91 |
|
|
| 77% |
|
| $ | 2.71 |
|
|
| - 30 | % |
|
| 2016 |
|
| Realization |
|
| 2015 |
|
| Change |
| ||||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 17.20 |
|
|
|
|
|
| $ | 16.93 |
|
|
| +2 | % |
Realized price, unhedged |
| $ | 9.81 |
|
|
| 57% |
|
| $ | 9.32 |
|
|
| +5 | % |
Cash settlements |
| $ | (0.11 | ) |
|
|
|
|
| $ | — |
|
|
|
|
|
Realized price, with hedges |
| $ | 9.70 |
|
|
| 56% |
|
| $ | 9.32 |
|
|
| +4 | % |
|
|
34
|
| 2016 |
|
| 2015 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 18.34 |
|
| $ | 21.12 |
|
|
| - 13 | % |
Canada |
| $ | 20.07 |
|
| $ | 24.46 |
|
|
| - 18 | % |
Realized price, unhedged |
| $ | 18.72 |
|
| $ | 21.68 |
|
|
| - 14 | % |
Cash settlements |
| $ | (0.05 | ) |
| $ | 9.74 |
|
|
|
|
|
Realized price, with hedges |
| $ | 18.67 |
|
| $ | 31.42 |
|
|
| - 41 | % |
Upstream revenues decreased $580 million as a result of lower unhedged, realized prices for oil, bitumen and gas. The decrease in oil and bitumen sales primarily resulted from lower average WTI crude index prices, which were 11% lower in 2016 as compared to 2015. The decrease in gas sales was driven by lower North American regional index prices upon which our gas sales are based. These decreases were partially offset by slightly higher NGL prices at the Mont Belvieu, Texas hub.
Commodity Derivatives
|
| 2016 |
|
| 2015 |
|
| Change |
|
| 2018 |
|
| 2017 |
|
| Change |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| Q |
|
|
|
|
|
|
|
|
| |
Oil |
| $ | (41 | ) |
| $ | 2,083 |
|
|
| - 102 | % |
| $ | (44 | ) |
| $ | 21 |
|
|
| - 310 | % |
Natural gas |
|
| 35 |
|
|
| 333 |
|
|
| - 89 | % |
|
| 5 |
|
|
| 35 |
|
|
| - 86 | % |
NGL |
|
| (5 | ) |
|
| — |
|
| N/M |
|
|
| (45 | ) |
|
| (3 | ) |
|
| - 1400 | % | |
Total cash settlements |
|
| (11 | ) |
|
| 2,416 |
|
|
| - 100 | % |
|
| (84 | ) |
|
| 53 |
|
|
| - 258 | % |
Valuation changes |
|
| (190 | ) |
|
| (1,913 | ) |
|
| +90 | % |
|
| 692 |
|
|
| 104 |
|
|
| +565 | % |
Total |
| $ | (201 | ) |
| $ | 503 |
|
|
| - 140 | % |
| $ | 608 |
|
| $ | 157 |
|
|
| +287 | % |
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
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 relationship between contract prices and the associated forward curves.
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 STACK and Delaware Basin and higher maintenance costs at our Jackfish facilities, partially offset by our U.S. non-core divestitures.
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 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 sales.
Property taxes increased as a result of higher property value assessments, primarily on our Texas properties, partially offset by our U.S. non-core divestitures.
Marketing Operations |
|
| 2018 |
|
| 2017 |
|
| Change |
| |||
Marketing revenues |
| $ | 4,449 |
|
| $ | 3,571 |
|
|
| +25 | % |
Marketing expenses |
|
| (4,363 | ) |
|
| (3,619 | ) |
|
| - 21 | % |
Margin |
| $ | 86 |
|
| $ | (48 | ) |
|
| +279 | % |
30
The overall increase in marketing operating margin was primarily due to improved commodity prices, which were partially offset by the impact of our downstream 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 STACK 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 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 Note 6 in “Item 8. Financial Statements and Supplementary Data” of this 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 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 15 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.
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.
Income Taxes |
|
| 2018 |
|
| 2017 |
| ||
Current expense (benefit) |
| $ | (70 | ) |
| $ | 112 |
|
Deferred expense (benefit) |
|
| 226 |
|
|
| (97 | ) |
Total expense |
| $ | 156 |
|
| $ | 15 |
|
Effective income tax rate |
|
| 17 | % |
|
| 2 | % |
For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.
Discontinued Operations |
Discontinued operations net earnings increased primarily due to the gain on the sale of our aggregate ownership interests in EnLink and the 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 upstream revenues by $427 million primarily as a result of our U.S. divested assets. Retained production volumes decreased due to reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale. These decreases were partially offset by expanded drilling and performance in the 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 higher 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
|
| 2016 |
|
| 2015 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||||
LOE |
| $ | 1,027 |
|
| $ | 1,509 |
|
|
| - 32 | % |
| $ | 927 |
|
| $ | 1,027 |
|
|
| - 10 | % |
Gathering & transportation |
|
| 555 |
|
|
| 595 |
|
|
| - 7 | % | ||||||||||||
Gathering, processing & transportation |
|
| 647 |
|
|
| 555 |
|
|
| +17 | % | ||||||||||||
Production taxes |
|
| 147 |
|
|
| 207 |
|
|
| - 29 | % |
|
| 194 |
|
|
| 149 |
|
|
| +30 | % |
Property taxes |
|
| 74 |
|
|
| 128 |
|
|
| - 42 | % |
|
| 55 |
|
|
| 74 |
|
|
| - 26 | % |
Total |
| $ | 1,803 |
|
| $ | 2,439 |
|
|
| - 26 | % |
| $ | 1,823 |
|
| $ | 1,805 |
|
|
| +1 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 4.59 |
|
| $ | 6.08 |
|
|
| - 24 | % |
| $ | 4.67 |
|
| $ | 4.59 |
|
|
| +2 | % |
Gathering & transportation |
| $ | 2.48 |
|
| $ | 2.40 |
|
|
| +4 | % | ||||||||||||
Gathering, processing & transportation |
| $ | 3.26 |
|
| $ | 2.48 |
|
|
| +31 | % | ||||||||||||
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 3.5 | % |
|
| 3.8 | % |
|
| - 8 | % |
|
| 3.8 | % |
|
| 3.5 | % |
|
| +7 | % |
LOE decreased $100 million primarily due to our U.S. property divestitures in 2016. Well optimization and LOE per BOE decreased as a result of our cost reduction initiatives well optimizationacross our portfolio offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and our non-core oilfuel, compression and gas property divestitures. On an absolute dollar basis, LOE decreased approximately $200 million as a result of our U.S. upstream divestitures.workovers.
Gathering and transportation decreasedexpense increased $92 million primarily asdue to a resultfull year of U.S. upstream asset divestitures partially offset by $28 million ofthe Access Pipeline transportation tolls, which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $110 million annually.
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.
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.
|
|
| 2016 |
|
| 2015 |
|
| Change |
| |||
Operating revenues |
| $ | 4,252 |
|
| $ | 4,451 |
|
|
| - 4 | % |
Product purchases |
|
| (3,015 | ) |
|
| (3,245 | ) |
|
| - 7 | % |
Operations and maintenance expenses |
|
| (398 | ) |
|
| (419 | ) |
|
| - 5 | % |
EnLink margin |
|
| 839 |
|
|
| 787 |
|
|
| +7 | % |
Devon margin |
|
| (49 | ) |
|
| 12 |
|
| N/M |
| |
Total |
| $ | 790 |
|
| $ | 799 |
|
|
| - 1 | % |
The overall decrease was primarily due to lower margins on Devon’s downstream marketing commitments, offset by EnLink’s margin growth largely related to its acquisition activity in late 2015 and the first quarter of 2016.
Exploration Expenses |
|
| 2016 |
|
| 2015 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||||
Unproved impairments |
| $ | 77 |
|
| $ | 260 |
|
|
| - 70 | % |
| $ | 217 |
|
| $ | 77 |
|
|
| +182 | % |
Geological and geophysical |
|
| 65 |
|
|
| 108 |
|
|
| - 40 | % |
|
| 110 |
|
|
| 65 |
|
|
| +70 | % |
Exploration overhead and other |
|
| 73 |
|
|
| 83 |
|
|
| - 13 | % |
|
| 53 |
|
|
| 73 |
|
|
| - 27 | % |
Total |
| $ | 215 |
|
| $ | 451 |
|
|
| - 52 | % |
| $ | 380 |
|
| $ | 215 |
|
|
| +77 | % |
Unproved impairments primarily relate to a portion of acreage in our U.S. non-core U.S. operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs were lower due to a reduced exploration capital programincreased primarily in 2016.the STACK and Delaware Basin.
Depreciation, Depletion and Amortization |
|
| 2016 |
|
| 2015 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| |||||||
Oil and gas per Boe |
| $ | 6.47 |
|
| $ | 13.99 |
|
|
| - 54 | % |
| $ | 7.15 |
|
| $ | 6.47 |
|
|
| +11 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Oil and gas |
| $ | 1,446 |
|
| $ | 3,474 |
|
|
| - 58 | % |
| $ | 1,419 |
|
| $ | 1,446 |
|
|
| - 2 | % | |
Midstream and other assets |
|
| 146 |
|
|
| 161 |
|
|
| - 10 | % | |||||||||||||
Devon |
|
| 1,592 |
|
|
| 3,635 |
|
|
| - 56 | % | |||||||||||||
EnLink |
|
| 504 |
|
|
| 387 |
|
|
| +30 | % | |||||||||||||
Other property and equipment |
|
| 110 |
|
|
| 146 |
|
|
| - 25 | % | |||||||||||||
Total |
| $ | 2,096 |
|
| $ | 4,022 |
|
|
| - 48 | % |
| $ | 1,529 |
|
| $ | 1,592 |
|
|
| - 4 | % | |
Our oil and gas DD&A remained relatively flat as compared to the prior year. Increases in oil and gas DD&A rates due to continued development in the STACK and Delaware Basin were offset by reduced production volumes resulting from the 2016 U.S. asset divestitures. DD&A from our oilother property and gas properties decreased largely because of our significant asset impairments recognized in 2015. For discussion on asset impairments, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report. EnLink’s DD&A increased primarily due to acquisitions in 2015 and 2016.
35
|
|
| 2016 |
|
| 2015 |
|
| Change |
| |||
Labor and benefits |
| $ | 614 |
|
| $ | 866 |
|
|
| - 29 | % |
Non-labor |
|
| 215 |
|
|
| 310 |
|
|
| - 31 | % |
Reimbursed G&A |
|
| (82 | ) |
|
| (120 | ) |
|
| - 31 | % |
Total Devon |
|
| 747 |
|
|
| 1,056 |
|
|
| - 29 | % |
EnLink |
|
| 118 |
|
|
| 137 |
|
|
| - 14 | % |
Total |
| $ | 865 |
|
| $ | 1,193 |
|
|
| - 27 | % |
G&Aequipment decreased due to workforce reductions, as discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report, and other cost reduction initiatives in response to the decline in commodity prices. Reimbursed G&A decreased primarily due to a reduction in drilling activity, as well as the divestiture of operated properties. EnLink G&A decreased primarily due to lower employee compensation expense and other cost reduction initiatives duringthe Access Pipeline in the fourth quarter of 2016.
Financing Costs, net |
Financing costs, net increased $388decreased $400 million primarily as a result of our $2.1 billion early debt retirement.retirement in 2016. For further discussion of early retirement premiums and reduced interest expense resulting from our lower debt balances, see Note 1615 in “Item 8. Financial Statements and Supplementary Data” of this report.
Other |
|
| 2016 |
|
| 2015 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||||
Asset impairments |
| $ | 1,310 |
|
| $ | 17,647 |
|
|
| - 93 | % |
| $ | — |
|
| $ | 437 |
|
|
| - 100 | % |
Asset dispositions |
|
| (1,483 | ) |
|
| 7 |
|
| N/M |
|
|
| (217 | ) |
|
| (1,496 | ) |
|
| +85 | % | |
Restructuring |
|
| 267 |
|
|
| 78 |
|
|
| +242 | % |
|
| — |
|
|
| 261 |
|
|
| - 100 | % |
Other |
|
| 108 |
|
|
| 186 |
|
|
| - 42 | % |
|
| (83 | ) |
|
| 101 |
|
|
| - 183 | % |
Total |
| $ | 202 |
|
| $ | 17,918 |
|
|
| - 99 | % |
| $ | (300 | ) |
| $ | (697 | ) |
|
| +57 | % |
Asset impairments largely related to our oil and gas assets and resulted from a significant decline in forecasted commodity prices during 2015 and 2016. Asset impairments forIn 2016, and 2015 also related to goodwill and other intangiblewe recognized proved asset impairments related to EnLink’s business. Additional information regarding the impairments is discussed inon a portion of our U.S. assets. See Note 65 in “Item 8. Financial Statements and Supplementary Data” of this report.report for additional information.
34
We recognized gains in conjunction with certain of our non-core U.S. upstream asset dispositions in both 2016 and 2017 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 32 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.
During 2016, we recognized restructuring and transactions costs of $267 million primarily as a result of our workforce reduction.
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 of our restructuring programs and the associated restructuring costs,on income taxes, see Note 78 in “Item 8. Financial Statements and Supplementary Data” of this report.
|
|
| 2016 |
|
| 2015 |
| ||
Current expense |
| $ | 100 |
|
| $ | (237 | ) |
Deferred expense (benefit) |
|
| 41 |
|
|
| (5,976 | ) |
Total expense (benefit) |
| $ | 141 |
|
| $ | (6,213 | ) |
Effective income tax rate |
|
| (11 | %) |
|
| 31 | % |
For discussion on income taxes,discontinued operations, see Note 819 in “Item 8. Financial Statements and Supplementary Data” of this report.
36
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major source and use categories of Devon and EnLink’schanges in cash and cash equivalents.equivalents for the time periods presented below.
|
| Devon |
|
| EnLink |
|
| Consolidated |
| |||||||||||||||||||||||||||
|
| 2017 |
|
| 2016* |
|
| 2015* |
|
| 2017 |
|
| 2016* |
|
| 2015* |
|
| 2017 |
|
| 2016* |
|
| 2015* |
| |||||||||
Operating cash flow |
| $ | 2,209 |
|
| $ | 834 |
|
| $ | 4,271 |
|
| $ | 700 |
|
| $ | 666 |
|
| $ | 627 |
|
| $ | 2,909 |
|
| $ | 1,500 |
|
| $ | 4,898 |
|
Issuance of common stock |
|
| — |
|
|
| 1,469 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,469 |
|
|
| — |
|
Divestitures of property and investments |
|
| 415 |
|
|
| 3,020 |
|
|
| 106 |
|
|
| 192 |
|
|
| 93 |
|
|
| 1 |
|
|
| 607 |
|
|
| 3,113 |
|
|
| 107 |
|
Capital expenditures |
|
| (1,968 | ) |
|
| (1,384 | ) |
|
| (4,214 | ) |
|
| (791 | ) |
|
| (663 | ) |
|
| (573 | ) |
|
| (2,759 | ) |
|
| (2,047 | ) |
|
| (4,787 | ) |
Acquisitions of property, equipment and businesses |
|
| (46 | ) |
|
| (849 | ) |
|
| (583 | ) |
|
| — |
|
|
| (792 | ) |
|
| (524 | ) |
|
| (46 | ) |
|
| (1,641 | ) |
|
| (1,107 | ) |
Debt activity, net |
|
| — |
|
|
| (3,383 | ) |
|
| 770 |
|
|
| 2 |
|
|
| 228 |
|
|
| 1,061 |
|
|
| 2 |
|
|
| (3,155 | ) |
|
| 1,831 |
|
Shareholder and noncontrolling interests distributions |
|
| (127 | ) |
|
| (221 | ) |
|
| (396 | ) |
|
| (354 | ) |
|
| (304 | ) |
|
| (254 | ) |
|
| (481 | ) |
|
| (525 | ) |
|
| (650 | ) |
EnLink and General Partner distributions |
|
| 265 |
|
|
| 265 |
|
|
| 268 |
|
|
| (265 | ) |
|
| (265 | ) |
|
| (268 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Subsidiary unit transactions |
|
| — |
|
|
| — |
|
|
| 654 |
|
|
| 501 |
|
|
| 892 |
|
|
| 25 |
|
|
| 501 |
|
|
| 892 |
|
|
| 679 |
|
Effect of exchange rate and other |
|
| (53 | ) |
|
| (96 | ) |
|
| 4 |
|
|
| 34 |
|
|
| 139 |
|
|
| (145 | ) |
|
| (19 | ) |
|
| 43 |
|
|
| (141 | ) |
Net change in cash and cash equivalents |
| $ | 695 |
|
| $ | (345 | ) |
| $ | 880 |
|
| $ | 19 |
|
| $ | (6 | ) |
| $ | (50 | ) |
| $ | 714 |
|
| $ | (351 | ) |
| $ | 830 |
|
Cash and cash equivalents at end of period |
| $ | 2,642 |
|
| $ | 1,947 |
|
| $ | 2,292 |
|
| $ | 31 |
|
| $ | 12 |
|
| $ | 18 |
|
| $ | 2,673 |
|
| $ | 1,959 |
|
| $ | 2,310 |
|
|
| Year ended December 31, |
| |||||||||
|
| 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 |
|
|
|
Devon Sources and Uses of Cash
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2018. Our operating cash flow was relatively flat compared to 2017. In 2018, our 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 Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report. There was an offset in the effect of exchange rate and other line in the above table, resulting in no impact to the net change in cash, cash equivalents and restricted cash.
Our operating cash flow increased $1.4 billion, or 165%, as comparedfrom 2016 to 2016 due to significantly higher commodity prices.2017. In 2017, our operating cash flow fully funded our capital expenditureexpenditures program as well as our dividends.
Our operating cash flow decreased $3.4 billion, or 80% from 2015 to 2016. While commodity prices decreased from 2015 to 2016, the primary driver of the decrease was due to the expiration of certain favorable hedge positions that provided us with an additional $2.4 billion of additional operating cash flow in 2015. In 2016, and 2015, our operating cash flow did not fully fund our capital requirements and dividends; as a result, we utilized available cash balances and divestiture proceeds to supplement our operating cash flows.
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 are for the acquisition, drilling and development of oil and gas properties. Our capital program is designed to operate within or near operating cash flow and may fluctuate with changes to commodity prices and other factors impacting cash flow. This is evidenced by our operating cash flow funding approximately 91% of capital 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 recognized a $312 million loss on the early retirement of debt, including $304 million of cash 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, including $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 $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 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.
DivestituresCash Flows from Discontinued Operations
All cash flows in the following table relate to activities of PropertyEnLink and Investmentsthe General Partner.
During
|
| 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 |
|
Operating cash flow in 2018 decreased $224 million and $190 million from 2017 and 2016, respectively, as parta result of the divestiture of our announced divestiture program, we sold non-core U.S. assets for $415 million. For further discussion, see Note 3aggregate ownership interests 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
37
repayment and to support capital investment in Devon’s core resource plays. For further discussion, see Note 3 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 2017 and 2016.
Capital Expenditures
The following table summarizes our capital expenditures and property acquisitions.
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016* |
|
| 2015* |
| |||
Oil and gas |
| $ | 1,879 |
|
| $ | 1,341 |
|
| $ | 4,056 |
|
Corporate and other |
|
| 89 |
|
|
| 43 |
|
|
| 158 |
|
Total capital expenditures |
| $ | 1,968 |
|
| $ | 1,384 |
|
| $ | 4,214 |
|
Acquisitions |
| $ | 46 |
|
| $ | 849 |
|
| $ | 583 |
|
|
|
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 are for the acquisition, drilling and development of oil and gas properties. Our capital program is designed to operate within operating cash flow and may fluctuate with changes to commodity prices and other factors impacting cash flow. This is evidenced by our operating cash flow fully funding capital expenditures in 2017. In response to the lower commodity prices, our total capital expenditures have been reduced by approximately 50% since 2015.
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. In 2015 our acquisition activity primarily consisted of the Powder River Basin asset acquisition in the fourth quarter. For further discussion on acquisition activity, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
Debt Activity, Net
During 2016, our debt decreased $3.1 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. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt, including $265 million of cash retirement costs and fees.
During 2015, our net debt increased $770 million. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter.
Shareholder Distributions
Devon paid common stock dividends of $127 million, $221 million and $396 million during 2017, 2016 and 2015, respectively. In response to the depressed commodity price environment, we reduced our quarterly dividend from $0.24 to $0.06 per share in the second quarter of 2016.
EnLink and General Partner Distributions
Devon received $265 million, $265 million and $268 million in distributions from EnLink and the General Partner during 2017, 2016 and 2015, respectively.in July 2018.
38
In 2015, we conducted an underwritten secondary public offering of 26.2 million common units representing limited partnerour aggregate ownership interests in EnLink raising proceeds of $654 million, net of underwriting discount. See Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
EnLink Sourcesthe General Partner, partially offset by capital expenditures and Uses of Cash
EnLink’s operating cash flow has increased each year since 2015 as a result of the growth experienced from its acquisition activity and continued development activities.
other items. Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. During 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets for $1.5 billion. Approximately $792 million was paid in cash at closing with the remainder of the purchase price funded with equity consideration and debt. For additional information on this acquisition, see Note 3 in “Item 8. Financial Statements
Cash flows from financing activities includes common and Supplementary Data” of this report. EnLink’s acquisitions in 2015 consisted of additional oil and gas pipeline assets, including gathering, transportation and processing facilities.
During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. Proceeds were primarily used to pay a portion of the first $250 million installment payment related to EnLink’s 2016 acquisition noted above.
During 2017, EnLink’s debt increased $247 million. In May 2017,preferred units EnLink issued $500and sold during 2017 and 2016 generating net proceeds of approximately $501 million of 5.45% senior notes dueand $892 million, respectively. Distributions to noncontrolling interests in 2047 to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. In June 2017, EnLink redeemed its 7.125% senior unsecured notes due in 2022 for aggregate cash consideration of $174 million. Additionally, EnLink reduced its credit facility borrowings to $74 million during 2017. As notedthe table above EnLink madeexclude the first installment payment in 2017 related to its 2016 acquisition.
distributions EnLink and the General Partner distributed $354paid to Devon, which have been eliminated in consolidation. Distributions Enlink and the General Partner paid to Devon were $134 million, $304$265 million and $254$265 million to non-Devon unitholders during 2017, 2016 and 2015, respectively.
During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3 million common units through general public offerings and its “at the market” equity program, generating net proceeds of approximately $107 million, $167 million and $25 million, respectively.
In 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.
In 2016, to fund a portion of the cash consideration of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction.
In2018, 2017 and 2016, EnLink received contributionsrespectively.
Liquidity
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from noncontrolling interests. For further discussion see 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
Note 3Table of Contents in “Item 8.
Index to Financial Statements and Supplementary Data” of this report.
Devon 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 liquidityIf needed, we can also include, among other things, 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 2017 has come from our operating cash flow supplemented with approximately $415 million 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, dividends and other contractual commitmentsrequirements as discussed in this section.
39
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 increased 165% in 2017 largely due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as we adjust our capital program to invest within our operating cash flow. Furthermore, proceeds from our non-core asset divestitures will provide additional liquidity as needed.
Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other 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. For 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 significant 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 utilize 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. As a result, entering into 2018 weWe currently have hedged approximately 40% of our anticipated oil and 50% of our anticipated 2019 oil and gas production.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 2019 Canadian heavy oil production hedged. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 20172018 are presented in Note 43 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.
Divestitures of Property and Equipment – In 2017, we announced a program to divest approximately $1 billion of upstream assets. These non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through December 31, 2017, Devon completed divestiture transactions totaling approximately $415 million. The most significant asset remaining in this program is select Barnett Shale properties whichFor 2019, we expect to closeaggressively optimize our cost structure in 2018.
Interest Rates – Ourconjunction 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, 2017, we had total debt of $6.9 billion that bears fixed interest rates averaging 5.7%.
As of December 31, 2017, we had open interest rate swap positions that are presented in Note 4 in “Item 8. Financial Statementsexpense 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.
At38
Divestitures of Property and Equipment
In the endfirst quarter of 2017,2019, we heldsold non-core assets for approximately $2.6 billion of cash. Included$300 million. We also anticipate separating our Canadian and Barnett Shale businesses from our Company in this total was $732 million of cash held by our foreign subsidiaries.2019.
Credit Availability
We have a $3.0 billion Senior Credit Facility. The maturity date for $164 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, 2018. The5, 2023, with the option to extend the maturity date for the remaining $2.8 billion is October 24, 2019. This credit facilityby two additional one-year periods subject to lender consent. The 2018 Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2017,2018, there were no borrowings under our commercial paper program. See Note 1615 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
40
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 oil and gas property impairments and goodwill impairments. As of December 31, 2017,2018, we were in compliance with this covenant. Ourcovenant with a 21.0% debt-to-capitalization ratio at December 31, 2017, as calculated pursuant to the terms of the agreement, was 27.2%.ratio.
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. We are currently targeting up to $1.5 billion
In January 2019, we repaid the $162 million of debt reduction in 2018.6.30% 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. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. In March 2017,Our credit rating from Fitch Ratings affirmed ouris BBB+ with a stable outlook. Our credit rating and revised our outlook to stable from negative. In April 2017, Moody’s Investor Service upgraded our credit rating from Ba2 tois Ba1 with a stablepositive outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.
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
Our 20182019 exploration and development budget is expected to be approximately $2.2$2.0 billion to $2.4$2.25 billion, and funded within operating cash flow. Although negative movements in any of the variables discussed above would impact our operating cash flow, we likely would not change our 2018 planned capital investment. Should our operating cash flow decrease from our forecasts, we could divest non-core assets to balance capital sources and uses.
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, 2017, there were $10 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility and $74 million outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
As of December 31, 2017, EnLink had total debt of $3.5 billion. Of this amount, $3.4 billion bears fixed interest rates averaging 4.6% and $74 million is comprised of floating rate debt with interest rates averaging 3.2%.
EnLink’s 2018 capital budget includes approximately $600 million to $800 million of identified growth projects. EnLink’s primary capital projects for 2018 include the construction of the Thunderbird processing plant in Central Oklahoma, the Lobo III processing plant in the Delaware Basin and the development of additional gathering and compression assets in Central Oklahoma and the Permian Basin.
41
EnLink expects to fund the growth capital expenditures with borrowings under its bank credit facility and proceeds from other debt and equity sources, including capital contributions by joint venture partners. EnLink expects to fund its 2018 maintenance capital expenditures from operating cash flows. EnLink employs a strategy that includes maintaining stable operating cash flows that are supported by long-term, fixed-fee contracts. Approximately 94% of EnLink’s cash flows were generated from fee-based services in 2017. It is possible that not all of the planned projects for 2018 will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expendituresassociated with our Canadian 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. Barnett Shale upstream assets.
Contractual Obligations
The following table presents a summary of our contractual obligations as of December 31, 2017.2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Payments Due by Period |
| |||||||||||||||||
|
| Total |
|
| Less Than 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
|
| More Than 5 Years |
| |||||
Devon obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt (1) |
| $ | 6,933 |
|
| $ | 115 |
|
| $ | 162 |
|
| $ | 1,500 |
|
| $ | 5,156 |
|
Interest expense (2) |
|
| 6,188 |
|
|
| 390 |
|
|
| 756 |
|
|
| 715 |
|
|
| 4,327 |
|
Purchase obligations (3) |
|
| 1,880 |
|
|
| 613 |
|
|
| 1,133 |
|
|
| 134 |
|
|
| — |
|
Operational agreements (4) |
|
| 5,259 |
|
|
| 522 |
|
|
| 756 |
|
|
| 739 |
|
|
| 3,242 |
|
Operational agreements with EnLink (5) |
|
| 909 |
|
|
| 637 |
|
|
| 272 |
|
|
| — |
|
|
| — |
|
Asset retirement obligations (6) |
|
| 1,152 |
|
|
| 39 |
|
|
| 134 |
|
|
| 171 |
|
|
| 808 |
|
Drilling and facility obligations (7) |
|
| 629 |
|
|
| 216 |
|
|
| 218 |
|
|
| 89 |
|
|
| 106 |
|
Lease obligations (8) |
|
| 381 |
|
|
| 88 |
|
|
| 157 |
|
|
| 117 |
|
|
| 19 |
|
Other (9) |
|
| 115 |
|
|
| 115 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total Devon obligations |
|
| 23,446 |
|
|
| 2,735 |
|
|
| 3,588 |
|
|
| 3,465 |
|
|
| 13,658 |
|
EnLink obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt (1) |
|
| 3,574 |
|
|
| — |
|
|
| 474 |
|
|
| — |
|
|
| 3,100 |
|
Interest expense (2) |
|
| 2,573 |
|
|
| 160 |
|
|
| 304 |
|
|
| 298 |
|
|
| 1,811 |
|
Other (9) |
|
| 496 |
|
|
| 306 |
|
|
| 55 |
|
|
| 45 |
|
|
| 90 |
|
Total EnLink obligations |
|
| 6,643 |
|
|
| 466 |
|
|
| 833 |
|
|
| 343 |
|
|
| 5,001 |
|
Total obligations |
| $ | 30,089 |
|
| $ | 3,201 |
|
| $ | 4,421 |
|
| $ | 3,808 |
|
| $ | 18,659 |
|
|
| 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 debt (including current portion of long term debt). |
(3) | Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices. |
(4) | Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets. 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 and Supplementary Data” of this report. |
(5) |
|
| 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 equipment. |
| Other |
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Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 2120 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.
Oil and Gas Assets Accounting, Classification, Reserves Classification & Valuation
Change in Accounting Principle
In the fourth quarter of 2017, we changed our method of accounting for our oil and gas exploration and development activities from the full cost method to the successful efforts method. In accordance with FASB ASC 250 “Accounting Changes and Error Corrections,” financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive Activities—Oil and Gas.” As required by ASC 250, we have presented the accumulated effect of the change in accounting principle from Devon’s inception to December 31, 2014 as a change in the beginning balance of our 2015 consolidated statements of equity.
To recast our financial statements, we made certain critical estimates, judgments and assumptions to apply successful efforts accounting to our historical operations. These critical items are similar to those pertaining to our ongoing successful efforts accounting, which are described below. For additional information regarding the effects of the change to the successful efforts method, including our underlying successful efforts accounting policies, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
To illustrate the effect of the change to successful efforts accounting, the following table summarizes the $1.9 billion increase to our historical equity as of September 30, 2017, the date of our conversion. The increase was primarily driven by lower impairments, offset by higher DD&A and less capitalized expenses.
Category |
|
|
|
|
|
|
|
Total equity as of September 30, 2017 (Full Cost) |
|
|
|
| $ | 11,934 |
|
Adjustments from inception through 2007, net |
|
|
|
|
| (2,147 | ) |
Adjustments after 2007: |
|
|
|
|
|
|
|
Lower asset impairments, net |
|
| 18,317 |
|
|
|
|
Exploration expense |
|
| (5,402 | ) |
|
|
|
Higher DD&A, driven largely by lower impairments |
|
| (5,036 | ) |
|
|
|
G&A expensed rather than capitalized |
|
| (3,075 | ) |
|
|
|
Other (asset dispositions, foreign exchange cumulative translation adjustment, etc.) |
|
| 418 |
|
|
|
|
Deferred income tax on the above items |
|
| (1,152 | ) |
|
|
|
Total adjustments after 2007 |
|
|
|
|
| 4,070 |
|
Equity increase (+16%) |
|
|
|
|
| 1,923 |
|
Total equity as of September 30, 2017 (Successful Efforts) |
|
|
|
| $ | 13,857 |
|
43
Our estimates of proved and proved developed reserves are a major component of DD&A calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by third-party petroleum consulting firms. In 2017, 88% of our reserves were subjected to such audits.
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
Successful Efforts Method of Accounting and Classification
We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management’s assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the previous section.section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.
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, 2017,2018, 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. Based on this assessment, Devon impaired $139 million of undeveloped leasehold in the fourth quarter of 2017. At December 31, 2017,2018, Devon had $1.4$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, 2017, $852018, approximately $10 million is scheduled to expire in 2018.2019. The leasehold expiring in 20182019 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.
Reserves
Our estimates of proved and proved developed reserves are a major component of DD&A calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by third-party petroleum consulting firms. In 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.
Valuation of Long-Lived Assets
Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual
41
assets based on a judgmental assessment of the lowest level (“common operating field”) for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of common operating fields is largely based
44
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 which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Besides the estimates of reserves and future production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we generally utilize the forward strip prices for the first five years and apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost movements to price movements similar to recent history. Changes to any of these assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Due to suppressed commodity prices in 2015 and 2016, we recognized significant asset impairments in each of those years.impairments. With more stabilized andgenerally higher pricing in 2017 and 2018, we did not recognize material asset impairments.
Goodwill and Other Intangibles
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 assess theperform a qualitative and quantitative factorsassessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If our qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. 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 the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue growth rates driven by future commodity prices and volume expectations, operating margins and capital expenditures.
For theBased on our qualitative assessment as of October 31, 2017 impairment tests for Devon’s U.S. reporting unit and each of EnLink’s reporting units,2018, 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 2015 and an update to be performed at December 31, 2015. Using the fair value approaches described above, it was determined that the estimated fair value of EnLink’s Texas, Louisiana and Crude and Condensate reporting units were less than their carrying amounts and a goodwill impairment loss of $492 million, $787 million and $49 million, respectively, was recognized in 2015.
Additionally, another interim impairment test was warranted during 2016 for EnLink’s reporting units. Using the fair value approaches described above, it was determined that the estimated fair value of EnLink’s Texas, General Partner and Crude and Condensate reporting units were less than their carrying amounts and a goodwill impairment loss of $473 million, $307 million and $93 million, respectively, was recognized in 2016.
Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which we would determine that the carrying value exceeds fair value. We would expect that a prolonged or sustained period of lower commodity prices would adversely affect the estimate of
45
future operating results, which could result in future goodwill impairments for our 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 2017, and 2016, we had deferred tax assets that largely resulted from the asset impairments recognized throughout 2016. As a result of our recent cumulative losses and our current realization assessment, we recorded a 100% valuation allowance against our U.S. deferred tax assets. 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, 2017including certain tax credits and December 31, 2016. Further, in 2017, we recognizedstate net operating losses. Devon also has recorded a $660 million partial valuation allowance against certain Canadian deferred tax assets asthat were generated by a result of the2017 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; |
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 |
determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and
further analysis of a variety of other inputs such as the earnings, profits, U.S./foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.
• | 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. |
46
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.
Under the Tax Reform Legislation, the corporate income tax rate was reduced
43
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, we consider the accounting of the transition tax, deferred tax remeasurements, and other items to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. We expect to complete our analysis within the measurement period in accordance with SAB 118.
Absent unexpected events and unexpected effects of the Tax Reform Legislation, Devon expects a positive impact on its future after-tax earnings, primarily due to the lower federal statutory tax rate.
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 20172018 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 two 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 2017 relate to asset dispositions, noncash asset impairments including noncash unproved asset impairments, (included in exploration expenses), U.S. tax reform changes, deferred tax asset valuation allowance, derivatives and financial instrument fair value changes, legal entity restructuring and costs associated with early retirement of debt.
Amounts excluded for 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, restructuring and transaction costs associated with the 2016 workforce reduction, derivatives and financial instrument fair value changes and costs associated with early retirement of debt.
Amounts excluded for 2015 relate to asset dispositions, noncash asset impairments (including an impairment of goodwill) including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig stacking costs, deferred tax asset valuation allowance, restructuring and transaction costs, derivatives and financial instrument fair value changes and repatriation of funds to the U.S.
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.
4744
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
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| ||||||||
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Earnings attributable to Devon (GAAP) | $ | 896 |
|
| $ | 1,078 |
|
| $ | 898 |
|
| $ | 1.70 |
| |||||||||||||||
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Asset dispositions |
| (217 | ) |
|
| (138 | ) |
|
| (138 | ) |
|
| (0.26 | ) | |||||||||||||||
Asset and exploration impairments |
| 234 |
|
|
| 152 |
|
|
| 146 |
|
|
| 0.27 |
| |||||||||||||||
U.S. tax reform |
| — |
|
|
| (211 | ) |
|
| (112 | ) |
|
| (0.21 | ) | |||||||||||||||
Deferred tax asset valuation allowance |
| — |
|
|
| (76 | ) |
|
| (76 | ) |
|
| (0.14 | ) | |||||||||||||||
Fair value changes in financial instruments and foreign currency |
| (218 | ) |
|
| (202 | ) |
|
| (201 | ) |
|
| (0.38 | ) | |||||||||||||||
Legal entity restructuring |
| — |
|
|
| (86 | ) |
|
| (86 | ) |
|
| (0.16 | ) | |||||||||||||||
Early retirement of debt |
| (9 | ) |
|
| (7 | ) |
|
| (4 | ) |
|
| (0.01 | ) | |||||||||||||||
Core earnings attributable to Devon (Non-GAAP) | $ | 686 |
|
| $ | 510 |
|
| $ | 427 |
|
| $ | 0.81 |
| |||||||||||||||
2016* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Loss attributable to Devon (GAAP) | $ | (1,317 | ) |
| $ | (1,458 | ) |
| $ | (1,056 | ) |
| $ | (2.09 | ) | $ | (433 | ) |
| $ | (574 | ) |
| $ | (575 | ) |
| $ | (1.14 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (1,483 | ) |
|
| (989 | ) |
|
| (995 | ) |
|
| (1.95 | ) |
| (1,496 | ) |
|
| (1,001 | ) |
|
| (1,001 | ) |
|
| (1.97 | ) |
Asset and exploration impairments |
| 1,430 |
|
|
| 1,230 |
|
|
| 807 |
|
|
| 1.60 |
|
| 537 |
|
|
| 340 |
|
|
| 340 |
|
|
| 0.69 |
|
Rig stacking costs |
| 10 |
|
|
| 6 |
|
|
| 6 |
|
|
| 0.01 |
|
| 10 |
|
|
| 6 |
|
|
| 6 |
|
|
| 0.01 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| 385 |
|
|
| 385 |
|
|
| 0.76 |
|
| — |
|
|
| 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 loss attributable to Devon (Non-GAAP) | $ | (554 | ) |
| $ | (329 | ) |
| $ | (367 | ) |
| $ | (0.73 | ) | $ | (604 | ) |
| $ | (370 | ) |
| $ | (371 | ) |
| $ | (0.73 | ) |
2015* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Loss attributable to Devon (GAAP) | $ | (19,858 | ) |
| $ | (13,645 | ) |
| $ | (12,896 | ) |
| $ | (31.72 | ) | $ | (884 | ) |
| $ | (884 | ) |
| $ | (481 | ) |
| $ | (0.95 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| 7 |
|
|
| 8 |
|
|
| 8 |
|
|
| 0.02 |
| |||||||||||||||
Asset and exploration impairments |
| 17,914 |
|
|
| 11,955 |
|
|
| 11,131 |
|
|
| 27.37 |
| |||||||||||||||
Rig stacking costs |
| 54 |
|
|
| 34 |
|
|
| 34 |
|
|
| 0.08 |
| |||||||||||||||
Deferred tax asset valuation allowance |
| — |
|
|
| 403 |
|
|
| 403 |
|
|
| 0.99 |
| |||||||||||||||
Restructuring and transaction costs |
| 78 |
|
|
| 52 |
|
|
| 52 |
|
|
| 0.13 |
| |||||||||||||||
Fair value changes in financial instruments and foreign currency |
| 1,967 |
|
|
| 1,349 |
|
|
| 1,346 |
|
|
| 3.31 |
| |||||||||||||||
Repatriations |
| — |
|
|
| 33 |
|
|
| 33 |
|
|
| 0.08 |
| |||||||||||||||
Asset impairments |
| 893 |
|
|
| 890 |
|
|
| 467 |
|
|
| 0.91 |
| |||||||||||||||
Asset dispositions, restructuring and transaction costs and fair value changes |
| 41 |
|
|
| 35 |
|
|
| 18 |
|
|
| 0.04 |
| |||||||||||||||
Core earnings attributable to Devon (Non-GAAP) | $ | 162 |
|
| $ | 189 |
|
| $ | 111 |
|
| $ | 0.26 |
| $ | 50 |
|
| $ | 41 |
|
| $ | 4 |
|
| $ | 0.00 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Loss attributable to Devon (GAAP) | $ | (1,317 | ) |
| $ | (1,458 | ) |
| $ | (1,056 | ) |
| $ | (2.09 | ) | |||||||||||||||
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
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 | ) | |||||||||||||||
46
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 systematically hedge a portion of our production through various financial transactions. The key terms to our oil and gas derivative financial instruments as of December 31, 20172018 are presented in Note 43 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, 2017,2018, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $260$270 million.
Interest Rate Risk
At December 31, 2017,2018, we had total debt of $10.4$5.9 billion. Of this amount, $10.3 billion bearsAll of our debt is based on fixed interest rates averaging 5.3%, and approximately $74 million is comprised of floating rate debt with interest rates averaging 3.2%5.4%.
As of December 31, 2017,2018, we had one open interest rate swap positionsposition that areis presented in Note 43 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, 2017.2018.
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, 20172018 balance sheet.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of these 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 intercompany loans as of December 31, 2017,2018, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.
49
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.
50
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, 20172018 and 2016,2017, the related consolidated statements of comprehensive earnings, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017,2018, and the related notes (collectively, the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2018, 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, 2017,2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Change inAdoption of New Accounting PrincipleStandard
As discussed in Note 1 to the consolidated financial statements, the Company has elected to changechanged its method of accounting for oil and gas exploration and development activitiesrevenue from the full cost method of accountingcontracts with customers in 2018 due to the successful efforts methodadoption of accounting in 2017. Accounting Standards Update 2014-09, Revenue from Contracts with Customers (ASC 606).
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.” Our responsibility is to express an opinion on the Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
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.
/s/ KPMG LLP
We have served as the Company’s auditor since 1980.
Oklahoma City, Oklahoma
February 21, 201820, 2019
52
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016* |
|
| 2015* |
| |||
Upstream revenues |
| $ | 5,307 |
|
| $ | 3,981 |
|
| $ | 5,885 |
|
Marketing and midstream revenues |
|
| 8,642 |
|
|
| 6,323 |
|
|
| 7,260 |
|
Total revenues |
|
| 13,949 |
|
|
| 10,304 |
|
|
| 13,145 |
|
Production expenses |
|
| 1,823 |
|
|
| 1,803 |
|
|
| 2,439 |
|
Exploration expenses |
|
| 380 |
|
|
| 215 |
|
|
| 451 |
|
Marketing and midstream expenses |
|
| 7,730 |
|
|
| 5,533 |
|
|
| 6,461 |
|
Depreciation, depletion and amortization |
|
| 2,074 |
|
|
| 2,096 |
|
|
| 4,022 |
|
Asset impairments |
|
| 17 |
|
|
| 1,310 |
|
|
| 17,647 |
|
Asset dispositions |
|
| (217 | ) |
|
| (1,483 | ) |
|
| 7 |
|
General and administrative expenses |
|
| 872 |
|
|
| 865 |
|
|
| 1,193 |
|
Financing costs, net |
|
| 498 |
|
|
| 907 |
|
|
| 519 |
|
Other expenses |
|
| (124 | ) |
|
| 375 |
|
|
| 264 |
|
Total expenses |
|
| 13,053 |
|
|
| 11,621 |
|
|
| 33,003 |
|
Earnings (loss) before income taxes |
|
| 896 |
|
|
| (1,317 | ) |
|
| (19,858 | ) |
Income tax expense (benefit) |
|
| (182 | ) |
|
| 141 |
|
|
| (6,213 | ) |
Net earnings (loss) |
|
| 1,078 |
|
|
| (1,458 | ) |
|
| (13,645 | ) |
Net earnings (loss) attributable to noncontrolling interests |
|
| 180 |
|
|
| (402 | ) |
|
| (749 | ) |
Net earnings (loss) attributable to Devon |
| $ | 898 |
|
| $ | (1,056 | ) |
| $ | (12,896 | ) |
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | 1.71 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
Diluted |
| $ | 1.70 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
Comprehensive earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 1,078 |
|
| $ | (1,458 | ) |
| $ | (13,645 | ) |
Other comprehensive earnings, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation and other |
|
| 83 |
|
|
| 11 |
|
|
| (443 | ) |
Pension and postretirement plans |
|
| 29 |
|
|
| 22 |
|
|
| 10 |
|
Other comprehensive earnings, net of tax |
|
| 112 |
|
|
| 33 |
|
|
| (433 | ) |
Comprehensive earnings (loss) |
|
| 1,190 |
|
|
| (1,425 | ) |
|
| (14,078 | ) |
Comprehensive earnings (loss) attributable to noncontrolling interests |
|
| 180 |
|
|
| (402 | ) |
|
| (749 | ) |
Comprehensive earnings (loss) attributable to Devon |
| $ | 1,010 |
|
| $ | (1,023 | ) |
| $ | (13,329 | ) |
|
|
|
| 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.
53
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016* |
|
| 2015* |
| |||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 1,078 |
|
| $ | (1,458 | ) |
| $ | (13,645 | ) |
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
| 2,074 |
|
|
| 2,096 |
|
|
| 4,022 |
|
Exploratory dry hole expense and unproved leasehold impairments |
|
| 219 |
|
|
| 113 |
|
|
| 248 |
|
Asset impairments |
|
| 17 |
|
|
| 1,310 |
|
|
| 17,647 |
|
Gains and losses on asset sales |
|
| (217 | ) |
|
| (1,483 | ) |
|
| 7 |
|
Deferred income tax expense (benefit) |
|
| (294 | ) |
|
| 41 |
|
|
| (5,976 | ) |
Commodity derivatives |
|
| (157 | ) |
|
| 201 |
|
|
| (503 | ) |
Cash settlements on commodity derivatives |
|
| 53 |
|
|
| 1 |
|
|
| 2,416 |
|
Other derivatives and financial instruments |
|
| 23 |
|
|
| 185 |
|
|
| (235 | ) |
Cash settlements on other derivatives and financial instruments |
|
| (6 | ) |
|
| (143 | ) |
|
| 272 |
|
Asset retirement obligation accretion |
|
| 62 |
|
|
| 75 |
|
|
| 75 |
|
Share-based compensation |
|
| 198 |
|
|
| 233 |
|
|
| 244 |
|
Other |
|
| (122 | ) |
|
| 270 |
|
|
| 312 |
|
Net change in working capital |
|
| 21 |
|
|
| 24 |
|
|
| (265 | ) |
Change in long-term other assets |
|
| (46 | ) |
|
| 36 |
|
|
| 285 |
|
Change in long-term other liabilities |
|
| 6 |
|
|
| (1 | ) |
|
| (6 | ) |
Net cash from operating activities |
|
| 2,909 |
|
|
| 1,500 |
|
|
| 4,898 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (2,759 | ) |
|
| (2,047 | ) |
|
| (4,787 | ) |
Acquisitions of property, equipment and businesses |
|
| (46 | ) |
|
| (1,641 | ) |
|
| (1,107 | ) |
Divestitures of property and equipment |
|
| 417 |
|
|
| 3,113 |
|
|
| 107 |
|
Proceeds from sale of investment |
|
| 190 |
|
|
| — |
|
|
| — |
|
Other |
|
| (12 | ) |
|
| (19 | ) |
|
| (16 | ) |
Net cash from investing activities |
|
| (2,210 | ) |
|
| (594 | ) |
|
| (5,803 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt, net of issuance costs |
|
| 2,376 |
|
|
| 2,145 |
|
|
| 4,772 |
|
Repayments of long-term debt |
|
| (2,118 | ) |
|
| (4,409 | ) |
|
| (2,634 | ) |
Payment of installment payable |
|
| (250 | ) |
|
| — |
|
|
| — |
|
Net short-term debt repayments |
|
| — |
|
|
| (626 | ) |
|
| (307 | ) |
Early retirement of debt |
|
| (6 | ) |
|
| (265 | ) |
|
| — |
|
Issuance of common stock |
|
| — |
|
|
| 1,469 |
|
|
| — |
|
Sale of subsidiary units |
|
| — |
|
|
| — |
|
|
| 654 |
|
Issuance of subsidiary units |
|
| 501 |
|
|
| 892 |
|
|
| 25 |
|
Dividends paid on common stock |
|
| (127 | ) |
|
| (221 | ) |
|
| (396 | ) |
Contributions from noncontrolling interests |
|
| 57 |
|
|
| 168 |
|
|
| 16 |
|
Distributions to noncontrolling interests |
|
| (354 | ) |
|
| (304 | ) |
|
| (254 | ) |
Shares exchanged for tax withholdings |
|
| (68 | ) |
|
| (35 | ) |
|
| (51 | ) |
Other |
|
| (2 | ) |
|
| (10 | ) |
|
| (13 | ) |
Net cash from financing activities |
|
| 9 |
|
|
| (1,196 | ) |
|
| 1,812 |
|
Effect of exchange rate changes on cash |
|
| 6 |
|
|
| (61 | ) |
|
| (77 | ) |
Net change in cash and cash equivalents |
|
| 714 |
|
|
| (351 | ) |
|
| 830 |
|
Cash and cash equivalents at beginning of period |
|
| 1,959 |
|
|
| 2,310 |
|
|
| 1,480 |
|
Cash and cash equivalents at end of period |
| $ | 2,673 |
|
| $ | 1,959 |
|
| $ | 2,310 |
|
|
|
|
| Year Ended December 31, |
| |||||||||
|
| 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
|
| December 31, 2017 |
|
| December 31, 2016* |
| ||
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 2,673 |
|
| $ | 1,959 |
|
Accounts receivable |
|
| 1,670 |
|
|
| 1,356 |
|
Assets held for sale |
|
| — |
|
|
| 193 |
|
Other current assets |
|
| 448 |
|
|
| 264 |
|
Total current assets |
|
| 4,791 |
|
|
| 3,772 |
|
Oil and gas property and equipment, based on successful efforts accounting, net |
|
| 13,318 |
|
|
| 12,998 |
|
Midstream and other property and equipment, net |
|
| 7,853 |
|
|
| 7,535 |
|
Total property and equipment, net |
|
| 21,171 |
|
|
| 20,533 |
|
Goodwill |
|
| 2,383 |
|
|
| 2,383 |
|
Other long-term assets |
|
| 1,896 |
|
|
| 1,987 |
|
Total assets |
| $ | 30,241 |
|
| $ | 28,675 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 819 |
|
| $ | 642 |
|
Revenues and royalties payable |
|
| 1,180 |
|
|
| 908 |
|
Short-term debt |
|
| 115 |
|
|
| — |
|
Other current liabilities |
|
| 1,201 |
|
|
| 1,066 |
|
Total current liabilities |
|
| 3,315 |
|
|
| 2,616 |
|
Long-term debt |
|
| 10,291 |
|
|
| 10,154 |
|
Asset retirement obligations |
|
| 1,113 |
|
|
| 1,226 |
|
Other long-term liabilities |
|
| 583 |
|
|
| 894 |
|
Deferred income taxes |
|
| 835 |
|
|
| 1,063 |
|
Equity: |
|
|
|
|
|
|
|
|
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 525 million and 523 million shares in 2017 and 2016, respectively |
|
| 53 |
|
|
| 52 |
|
Additional paid-in capital |
|
| 7,333 |
|
|
| 7,237 |
|
Retained earnings (accumulated deficit) |
|
| 702 |
|
|
| (69 | ) |
Accumulated other comprehensive earnings |
|
| 1,166 |
|
|
| 1,054 |
|
Total stockholders’ equity attributable to Devon |
|
| 9,254 |
|
|
| 8,274 |
|
Noncontrolling interests |
|
| 4,850 |
|
|
| 4,448 |
|
Total equity |
|
| 14,104 |
|
|
| 12,722 |
|
Total liabilities and equity |
| $ | 30,241 |
|
| $ | 28,675 |
|
|
|
|
| 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.
55
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
| Retained |
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
| Additional |
|
| Earnings |
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
| Common Stock |
|
| Paid-In |
|
| (Accumulated |
|
| Comprehensive |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
| |||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| Deficit) |
|
| Earnings |
|
| Stock |
|
| Interests |
|
| Equity |
| ||||||||
Previously reported as of December 31, 2014 |
|
| 409 |
|
| $ | 41 |
|
| $ | 4,088 |
|
| $ | 16,631 |
|
| $ | 779 |
|
| $ | — |
|
| $ | 4,802 |
|
| $ | 26,341 |
|
Effect of change in accounting principle |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2,227 | ) |
|
| 675 |
|
|
| — |
|
|
| — |
|
|
| (1,552 | ) |
Balance as of December 31, 2014 as recast* |
|
| 409 |
|
| $ | 41 |
|
| $ | 4,088 |
|
| $ | 14,404 |
|
| $ | 1,454 |
|
| $ | — |
|
| $ | 4,802 |
|
| $ | 24,789 |
|
Net loss |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (12,896 | ) |
|
| — |
|
|
| — |
|
|
| (749 | ) |
|
| (13,645 | ) |
Other comprehensive loss, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (433 | ) |
|
| — |
|
|
| — |
|
|
| (433 | ) |
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 |
|
| $ | 1,112 |
|
| $ | 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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.
56
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.
Change in Accounting Principle and Presentation Changes
In the fourth quarter of 2017, Devon changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method. In accordance with FASB ASC 250 “Accounting Changes and Error Corrections,” financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive Activities—Oil and Gas.” Although the full cost method of accounting for oil and gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the preferred method and is more widely used in the industry and will improve comparison to Devon’s peer group. Devon believes the successful efforts method provides a more transparent representation of its results of operations. The successful efforts method also provides our investments in oil and gas properties to be assessed for impairment as of the balance sheet date in accordance with FASB ASC 360 “Property, Plant and Equipment” rather than valuations based on 12-month historical prices and costs prescribed under the full cost method. For more detailed information regarding the effects of the change in accounting principle to the successful efforts method, see Note 2.
As Devon recast its financial statements to the successful efforts method, the financial statements and disclosures were examined through the lens of simplicity and transparency. From this assessment, certain changes were made to the financial statement presentation not specifically required by the successful efforts method of accounting. In general, Devon sought to simplify the presentation of its consolidated comprehensive statements of earnings and provide expanded and improved disclosures of key components in its operating results. These presentation judgments improve the clarity and utility of the financial operating results for investors and other stakeholders. As a result, certain prior period amounts have been reclassified to align to this new approach. To ensure financial statement users clearly understand the changes, a description of each enhancement is provided below.
Upstream revenues – On the statement of operations, Devon is combining sales of oil, gas and NGL volumes, as well as oil, gas and NGL derivative activity, into this new line item. With the streamlined presentation of upstream revenues, MD&A and other disclosures of these items were expanded.
Production expenses – Similar to streamlining the presentation of upstream revenues, Devon is simplifying the presentation of cash-based expenses associated with upstream production. Previously these expenses were reported separately as lease operations and production and property taxes in the comprehensive statements of earnings. These items are now combined in this new line item. Devon has expanded the MD&A and other disclosures of expenses for lease operations, gathering and transportation, production taxes and property taxes.
57
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Asset dispositions – This line item will capture gains and losses from dispositions of assets. As a full cost company, Devon rarely had material gains and losses on asset dispositions. However, when it did, such amounts were reported as part of revenues. Devon has more gains and losses under the successful efforts method of accounting. Since recognizing gains and losses on asset dispositions are largely affected by previously recognized DD&A and asset impairments, this item was placed adjacent to those items on the comprehensive statements of earnings.
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.
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 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; |
evaluation of suspended well costs;
• | evaluation of suspended well costs; |
the carrying and fair values of oil and gas properties, midstream assets and product and equipment inventories;
• | the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; |
derivative financial instruments;
• | derivative financial instruments; |
the fair value of reporting units and related assessment of goodwill for impairment;
• | the fair value of reporting units and related assessment of goodwill for impairment; |
the fair value of intangible assets other than goodwill;
• | income taxes; |
• | asset retirement obligations; |
income taxes;
• | obligations related to employee pension and postretirement benefits; |
• | legal and environmental risks and exposures; and |
• | general credit risk associated with receivables and other assets. |
5857
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
obligations related to employee pension and postretirement benefits;
legal and environmental risks and exposures; and
general credit risk associated with receivables and other assets.
Revenue Recognition
Impact of ASC 606 Adoption
In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and 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.
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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 2018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue.
During 2017 2016 and 2015,2016, 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.
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Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of December 31, 2017,2018, 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
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specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2017,2018, 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 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.
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, 2017,2018, Devon held no cash collateral of its counterparties nor posted collateral to its counterparties.
General and Administrative Expenses
G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon.
Share-Based Compensation
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 76, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying 2016 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.
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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 8 for further discussion.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.
Net Earnings (Loss) Per Share Attributable to Devon
Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of unvested performance share units.
Cash 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.
Property and Equipment
Oil and Gas Property and Equipment
Devon follows the successful efforts method of accounting for its oil and gas properties. Under this method explorationExploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful
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successful exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) in accordance with ASC 932 “Extractive Activities – Oil and Gas” for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions.
Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly.
Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are amortized 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 carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review.
Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.
Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major development projects of oil and gas properties.
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Midstream and Other Property and Equipment
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using the straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major 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 the fair value of each reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, then goodwill is written down toan impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value 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 2018, 2017 2016 and 2015.2016. No impairment was required as a result of the annual tests in 2017 or 2016; however, sustained weakness in the overall energy sector driven by lower commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units. See Note 14 for further discussion.these time periods.
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 to 20 years. During 2017, 2016 and 2015, EnLink’s customer relationships were also evaluated for impairment, and in 2015, a portion of these intangible assets was considered impaired. See Note 14 for further discussion.
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Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.
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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 2017,2018, Devon adopted 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, including income taxes when awards vest or are settled, statutory withholding and forfeitures. As the result of adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefits and deficiencies in the consolidated comprehensive statements of
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earnings and as operating cash flows in the consolidated statements of cash flows. Devon also retrospectively applied the new cash flow statement guidance dictating the presentation of shares exchanged for tax-withholding purposes as a financing activity. The adoption of the new guidance did not materially impact the consolidated financial statements for the year ended December 31, 2017 or previously reported financial information but could have a more material future impact.
In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill And Other (Topic 350), Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test. Under ASU 2017-04, an entity should perform its goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, Devon elected to early adopt ASU 2017-04. The adoption had no impact on the consolidated financial statements.
Issued Accounting Standards Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which established ASC Topic 606, Revenue from Contracts with Customers(ASC 606). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (ASU 2016-12), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. Devon will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018.
Devon has aggregated and reviewed its contracts that are within the scope of ASC 606. Based on its evaluation, Devon does not anticipate the adoption of ASC 606 will have a material impact on its balance sheet or related consolidated statements of earnings, equity or cash flows. Accordingly, Devon will continue to recognize revenue at the time commodities are delivered. However, ASC 606 will affect how certain transactions are presented in its financial statements. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Devon will change its presentation of certain processing arrangements from a net presentation to a gross presentation. This change will impact Devon’s upstream revenues and production expenses by approximately $250 million for 2016 and 2017, and will impact 2018 by a similar amount. EnLink will change the presentation of certain marketing and midstream revenues to marketing and midstream operating expenses or from marketing and midstream operating expenses to marketing and midstream revenues. Devon estimates this reclassification will result in a net decrease in EnLink’s marketing and midstream revenues of approximately 6-10%. These estimates are based on historical information and could change based on future volumes and commodity prices. These presentation changes will have no impact on net earnings or cash flows.
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Based on the disclosure requirements of ASC 606, upon adoption, Devon expects to provide expanded disclosures relating to itsmethod. See revenue recognition policies and how these relate to its revenue-generating contractual performance obligations. In addition, Devon expects to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of its revenues.
The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change, exceptsection above for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019. Early adoption is permitted, but Devon does not plan to early adopt. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. However, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842), Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The proposed ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. Devon is in the process of evaluating contracts and gathering the necessary terms and data elements for purposes of determining the impact this ASU will have on its consolidated financial statements and related disclosures. Recently, the FASB issued ASU No. 2018-01, Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842. This ASU would permit an entity not to apply Topic 842 to land easements and rights-of-way that exist or expired before the effective date of Topic 842 and that were not previously assessed under Topic 840. An entity would continue to apply its current accounting policy for accounting for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements and rights-of-way to determine whether the arrangement should be accounted for as a lease. For Devon, these contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.
Based on continuing research, Devon estimates a large number of contracts and data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective. Devon has preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact the adoption will have on its consolidated financial statements. Devon anticipates thefurther discussion regarding Devon’s adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls and is evaluating technology requirements and solutions needed to comply with the requirements of this ASU. While we cannot currently estimate the quantitative effect thatrevenue recognition standard.
In January 2018, Devon adopted ASU 2016-02 will have on our consolidated financial statements, the adoption will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities.
The FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. Cost. This ASU will requirerequires entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. ThisAs a result of the adoption of this ASU, is effective for Devon beginning January 1, 2018, and income statementconsolidated statements of earnings presentation changes will bewere applied retrospectively, while service cost component capitalization will bewas applied prospectively. Upon adoption, of this ASU, Devon will reclassifyreclassified $7 million $14 million and $16$14 million of non-service cost components of net periodic benefit costs for 2017 and 2016, and 2015, respectively, asfrom G&A to other expenses. Such amounts are currently classified in Devon’s G&A. No other changes upon adopting this ASU are expected to be material.
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The FASB issuedIn January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. Cash. This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This reconciliation can be presented either on the faceAs a result of the consolidatedadoption of this ASU, Devon made changes to the statement of cash flows or into include the notes to the financial statements. Thisrequired presentation and reconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU is effective for Devon beginning January 1, 2018, and will be applied retrospectively. Currently, Devon doesdid not expect the adoption to have a material impact on itsDevon’s consolidated statementstatements 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 $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet.
In the fourth quarter of 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 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. Devon is adopting this ASU beginning January 1, 2019.
Devon will apply the guidance using a modified retrospective transition method at the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also 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 legacy 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 remaining 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 exploration, development and production of oil and gas. Additionally, Devon will recognize a $24 million before tax, $19 million net of tax cumulative-effect adjustment to reduce retained earnings.
66
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The FASB issued ASU 2017-01, Business Combinations2018-04, Fair Value Measurement (Topic 805)820): ClarifyingChanges to the Definition of a Business. Disclosure Requirements for Fair Value Measurement. This ASU clarifies the definition of a business to assist entities with evaluating whether a set of transferred assetswill eliminate, add and activities should be accountedmodify certain disclosure requirements for as an acquisition or disposals of assets or as a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business.measurement. The guidance also requires that a set of assets must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for Devonannual and interim periods beginning January 1, 2018,2020, with early adoption permitted for either the entire 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 and will be applied prospectively. Devon does not expectassessing the adoption toimpact it may have a material impact on its disclosures in the notes to the consolidated financial statements; however these amendments could result in the recording of fewer business combinations in future periods.statements.
The FASB issued ASU 2017-12, Derivatives2018-05-15, Intangibles, Goodwill and Hedging (Topic 815)Other Internal-Use Software (Subtopic 350-40): Targeted Improvements toCustomer’s Accounting for Hedging Activities. Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. This ASU will expand hedge accountingrequire 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 or expense as incurred. Capitalized implementation costs related to a hosting arrangement that is a service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company's risk management activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This ASU only applies to entities that elect hedge accounting, which Devon has not for derivative financial instruments during the three year period ended December 31, 2017.its intended use. This ASU is effective for annual and interim periods beginning January 1, 2019,2020, with early adoption permitted in 2018. Thepermitted. Entities have the option to adopt the ASU is requiredusing either a retrospective approach or a prospective approach applied to be adopted using a cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings inall implementation costs incurred after the perioddate of adoption to account for prior period effects rather than restating previously reported results.the adoption. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements if hedge accounting were elected by Devon in the future.
2.Change in Accounting Principle
In the fourth quarter of 2017, Devon changed its method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. In addition, gains or losses, if applicable, are recognized more frequently on the dispositions of oil and gas property and equipment under the successful efforts method. Devon has recast certain historical information for all periods presented, including the Consolidated Comprehensive Statements of Earnings, Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Equity and related information in Notes 1, 2, 3, 5, 6, 7, 8, 9, 10, 11, 13, 14, 16, 22, 23, 24 and 25.
The following tables present the effects of the change to the successful efforts method in the consolidated financial statements.
67
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Changes to the Consolidated Comprehensive |
| ||||||||||
|
| Statement of Earnings |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2017 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Exploration expenses |
| $ | — |
|
| $ | 380 |
|
| $ | 380 |
|
Depreciation, depletion and amortization |
|
| 1,579 |
|
|
| 495 |
|
|
| 2,074 |
|
Asset dispositions |
|
| (5 | ) |
|
| (212 | ) |
|
| (217 | ) |
General and administrative expenses |
|
| 682 |
|
|
| 190 |
|
|
| 872 |
|
Financing costs, net |
|
| 494 |
|
|
| 4 |
|
|
| 498 |
|
Other expenses |
|
| (102 | ) |
|
| (22 | ) |
|
| (124 | ) |
Earnings before income taxes |
|
| 1,731 |
|
|
| (835 | ) |
|
| 896 |
|
Income tax benefit |
|
| (140 | ) |
|
| (42 | ) |
|
| (182 | ) |
Net earnings |
|
| 1,871 |
|
|
| (793 | ) |
|
| 1,078 |
|
Net earnings attributable to Devon |
|
| 1,691 |
|
|
| (793 | ) |
|
| 898 |
|
Net earnings per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| 3.22 |
|
|
| (1.51 | ) |
|
| 1.71 |
|
Diluted |
|
| 3.20 |
|
|
| (1.50 | ) |
|
| 1.70 |
|
Comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
| 1,871 |
|
|
| (793 | ) |
|
| 1,078 |
|
Foreign currency translation and other |
|
| 4 |
|
|
| 79 |
|
|
| 83 |
|
Comprehensive earnings |
|
| 1,904 |
|
|
| (714 | ) |
|
| 1,190 |
|
Comprehensive earnings attributable to Devon |
|
| 1,724 |
|
|
| (714 | ) |
|
| 1,010 |
|
|
| Changes to the Consolidated Comprehensive |
| |||||||||
|
| Statement of Earnings |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2016 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Exploration expenses |
| $ | — |
|
| $ | 215 |
|
| $ | 215 |
|
Depreciation, depletion and amortization |
|
| 1,792 |
|
|
| 304 |
|
|
| 2,096 |
|
Asset impairments |
|
| 4,975 |
|
|
| (3,665 | ) |
|
| 1,310 |
|
Asset dispositions |
|
| (1,887 | ) |
|
| 404 |
|
|
| (1,483 | ) |
General and administrative expenses |
|
| 658 |
|
|
| 207 |
|
|
| 865 |
|
Financing costs, net |
|
| 904 |
|
|
| 3 |
|
|
| 907 |
|
Other expenses |
|
| 403 |
|
|
| (28 | ) |
|
| 375 |
|
Loss before income taxes |
|
| (3,877 | ) |
|
| 2,560 |
|
|
| (1,317 | ) |
Income tax expense (benefit) |
|
| (173 | ) |
|
| 314 |
|
|
| 141 |
|
Net loss |
|
| (3,704 | ) |
|
| 2,246 |
|
|
| (1,458 | ) |
Net loss attributable to Devon |
|
| (3,302 | ) |
|
| 2,246 |
|
|
| (1,056 | ) |
Net loss per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| (6.52 | ) |
|
| 4.43 |
|
|
| (2.09 | ) |
Diluted |
|
| (6.52 | ) |
|
| 4.43 |
|
|
| (2.09 | ) |
Comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
| (3,704 | ) |
|
| 2,246 |
|
|
| (1,458 | ) |
Foreign currency translation and other |
|
| 32 |
|
|
| (21 | ) |
|
| 11 |
|
Comprehensive loss |
|
| (3,650 | ) |
|
| 2,225 |
|
|
| (1,425 | ) |
Comprehensive loss attributable to Devon |
|
| (3,248 | ) |
|
| 2,225 |
|
|
| (1,023 | ) |
68
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Changes to the Consolidated Comprehensive |
| ||||||||||
|
| Statement of Earnings |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2015 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Exploration expenses |
| $ | — |
|
| $ | 451 |
|
| $ | 451 |
|
Depreciation, depletion and amortization |
|
| 3,129 |
|
|
| 893 |
|
|
| 4,022 |
|
Asset impairments |
|
| 20,820 |
|
|
| (3,173 | ) |
|
| 17,647 |
|
Asset dispositions |
|
| — |
|
|
| 7 |
|
|
| 7 |
|
General and administrative expenses |
|
| 868 |
|
|
| 325 |
|
|
| 1,193 |
|
Financing costs, net |
|
| 517 |
|
|
| 2 |
|
|
| 519 |
|
Other expenses |
|
| 179 |
|
|
| 85 |
|
|
| 264 |
|
Loss before income taxes |
|
| (21,268 | ) |
|
| 1,410 |
|
|
| (19,858 | ) |
Income tax benefit |
|
| (6,065 | ) |
|
| (148 | ) |
|
| (6,213 | ) |
Net loss |
|
| (15,203 | ) |
|
| 1,558 |
|
|
| (13,645 | ) |
Net loss attributable to Devon |
|
| (14,454 | ) |
|
| 1,558 |
|
|
| (12,896 | ) |
Net loss per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| (35.55 | ) |
|
| 3.83 |
|
|
| (31.72 | ) |
Diluted |
|
| (35.55 | ) |
|
| 3.83 |
|
|
| (31.72 | ) |
Comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
| (15,203 | ) |
|
| 1,558 |
|
|
| (13,645 | ) |
Foreign currency translation and other |
|
| (559 | ) |
|
| 116 |
|
|
| (443 | ) |
Comprehensive loss |
|
| (15,752 | ) |
|
| 1,674 |
|
|
| (14,078 | ) |
Comprehensive loss attributable to Devon |
|
| (15,003 | ) |
|
| 1,674 |
|
|
| (13,329 | ) |
|
| Changes to the Consolidated |
| |||||||||
|
| Statement of Cash Flows |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2017 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Net earnings |
| $ | 1,871 |
|
| $ | (793 | ) |
| $ | 1,078 |
|
Depreciation, depletion and amortization |
|
| 1,579 |
|
|
| 495 |
|
|
| 2,074 |
|
Exploratory dry hole expense and unproved leasehold impairments |
|
| — |
|
|
| 219 |
|
|
| 219 |
|
Gains and losses on asset sales |
|
| (5 | ) |
|
| (212 | ) |
|
| (217 | ) |
Deferred income tax benefit |
|
| (252 | ) |
|
| (42 | ) |
|
| (294 | ) |
Share-based compensation |
|
| 158 |
|
|
| 40 |
|
|
| 198 |
|
Other |
|
| (108 | ) |
|
| (14 | ) |
|
| (122 | ) |
Net cash from operating activities |
|
| 3,216 |
|
|
| (307 | ) |
|
| 2,909 |
|
Capital expenditures |
|
| (3,074 | ) |
|
| 315 |
|
|
| (2,759 | ) |
Divestitures of property and equipment |
|
| 425 |
|
|
| (8 | ) |
|
| 417 |
|
Net cash from investing activities |
|
| (2,517 | ) |
|
| 307 |
|
|
| (2,210 | ) |
69
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Changes to the Consolidated |
| ||||||||||
|
| Statement of Cash Flows |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2016 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Net loss |
| $ | (3,704 | ) |
| $ | 2,246 |
|
| $ | (1,458 | ) |
Depreciation, depletion and amortization |
|
| 1,792 |
|
|
| 304 |
|
|
| 2,096 |
|
Exploratory dry hole expense and unproved leasehold impairments |
|
| — |
|
|
| 113 |
|
|
| 113 |
|
Asset impairments |
|
| 4,975 |
|
|
| (3,665 | ) |
|
| 1,310 |
|
Gains and losses on asset sales |
|
| (1,887 | ) |
|
| 404 |
|
|
| (1,483 | ) |
Deferred income tax expense (benefit) |
|
| (273 | ) |
|
| 314 |
|
|
| 41 |
|
Share-based compensation |
|
| 194 |
|
|
| 39 |
|
|
| 233 |
|
Other |
|
| 303 |
|
|
| (33 | ) |
|
| 270 |
|
Net cash from operating activities |
|
| 1,778 |
|
|
| (278 | ) |
|
| 1,500 |
|
Capital expenditures |
|
| (2,330 | ) |
|
| 283 |
|
|
| (2,047 | ) |
Divestitures of property and equipment |
|
| 3,118 |
|
|
| (5 | ) |
|
| 3,113 |
|
Net cash from investing activities |
|
| (872 | ) |
|
| 278 |
|
|
| (594 | ) |
|
| Changes to the Consolidated |
| |||||||||
|
| Statement of Cash Flows |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2015 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Net loss |
| $ | (15,203 | ) |
| $ | 1,558 |
|
| $ | (13,645 | ) |
Depreciation, depletion and amortization |
|
| 3,129 |
|
|
| 893 |
|
|
| 4,022 |
|
Exploratory dry hole expense and unproved leasehold impairments |
|
| — |
|
|
| 248 |
|
|
| 248 |
|
Asset impairments |
|
| 20,820 |
|
|
| (3,173 | ) |
|
| 17,647 |
|
Gains and losses on asset sales |
|
| — |
|
|
| 7 |
|
|
| 7 |
|
Deferred income tax benefit |
|
| (5,828 | ) |
|
| (148 | ) |
|
| (5,976 | ) |
Share-based compensation |
|
| 181 |
|
|
| 63 |
|
|
| 244 |
|
Other |
|
| 281 |
|
|
| 31 |
|
|
| 312 |
|
Net cash from operating activities |
|
| 5,419 |
|
|
| (521 | ) |
|
| 4,898 |
|
Capital expenditures |
|
| (5,308 | ) |
|
| 521 |
|
|
| (4,787 | ) |
Net cash from investing activities |
|
| (6,324 | ) |
|
| 521 |
|
|
| (5,803 | ) |
|
| Changes to the Consolidated Balance Sheet |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2017 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Oil and gas property and equipment, net |
| $ | 9,702 |
|
|
| 3,616 |
|
| $ | 13,318 |
|
Total property and equipment, net |
|
| 17,555 |
|
|
| 3,616 |
|
|
| 21,171 |
|
Goodwill |
|
| 3,964 |
|
|
| (1,581 | ) |
|
| 2,383 |
|
Total assets |
|
| 28,206 |
|
|
| 2,035 |
|
|
| 30,241 |
|
Deferred income taxes |
|
| 434 |
|
|
| 401 |
|
|
| 835 |
|
Additional paid-in capital |
|
| 7,206 |
|
|
| 127 |
|
|
| 7,333 |
|
Retained earnings |
|
| 44 |
|
|
| 658 |
|
|
| 702 |
|
Accumulated other comprehensive earnings |
|
| 317 |
|
|
| 849 |
|
|
| 1,166 |
|
Total stockholders’ equity attributable to Devon |
|
| 7,620 |
|
|
| 1,634 |
|
|
| 9,254 |
|
Total equity |
|
| 12,470 |
|
|
| 1,634 |
|
|
| 14,104 |
|
Total liabilities and equity |
|
| 28,206 |
|
|
| 2,035 |
|
|
| 30,241 |
|
70
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| Changes to the Consolidated Balance Sheet |
| ||||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Year Ended December 31, 2016 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Oil and gas property and equipment, net |
| $ | 8,655 |
|
| $ | 4,343 |
|
| $ | 12,998 |
|
Total property and equipment, net |
|
| 16,190 |
|
|
| 4,343 |
|
|
| 20,533 |
|
Goodwill |
|
| 3,964 |
|
|
| (1,581 | ) |
|
| 2,383 |
|
Total assets |
|
| 25,913 |
|
|
| 2,762 |
|
|
| 28,675 |
|
Deferred income taxes |
|
| 648 |
|
|
| 415 |
|
|
| 1,063 |
|
Accumulated deficit |
|
| (1,646 | ) |
|
| 1,577 |
|
|
| (69 | ) |
Accumulated other comprehensive earnings |
|
| 284 |
|
|
| 770 |
|
|
| 1,054 |
|
Total stockholders’ equity attributable to Devon |
|
| 5,927 |
|
|
| 2,347 |
|
|
| 8,274 |
|
Total equity |
|
| 10,375 |
|
|
| 2,347 |
|
|
| 12,722 |
|
Total liabilities and equity |
|
| 25,913 |
|
|
| 2,762 |
|
|
| 28,675 |
|
Devon Acquisitions
In January 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of equity. The allocation of the purchase price was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.
In December 2015,Divestitures
EnLink and General Partner
During the third quarter of 2018, Devon acquiredcompleted the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately 253,000 net acres (unaudited) and assets$2.6 billion ($2.2 billion after-tax). The proceeds from the sale were utilized to increase Devon’s share repurchase program to $4.0 billion, which is discussed further 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.Note 18. Additional information on these discontinued operations can be found in Note 19.
Devon Asset Divestitures
Upstream Assets
In May 2017,During 2018, Devon announcedreceived proceeds of approximately $1.0 billion and recognized a program to divestnet gain on asset dispositions of approximately $1 billion$260 million, primarily from sales of upstream assets. The non-core assets identified for monetization include select portions ofin the Barnett Shale focused primarilyand Delaware Basin. As part of the transactions, approximately $84 million of asset retirement obligations were assumed by the purchasers. In conjunction with the divestitures, 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 earnings. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 267 MMBoe, or 18%, of total U.S. proved reserves.
67
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Additionally, in the first quarter of 2019, 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 around Johnson County and other properties located principally within Devon’s U.S. resource base. ThroughDevon 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 divested assets were approximately 25 MMBoe, or less than 2%, of total U.S. proved reserves.
During 2017, Devon completed divestiture transactions withreceived proceeds totaling approximately $415$420 million, before purchase price adjustments, 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. Devon’s remaining divestiture of Johnson County assets is expected to close in 2018.
During 2016, in several separate transactions with different purchasers, Devon divestedreceived proceeds totaling approximately $1.9 billion and recognized a net gain on asset dispositions of $809 million, primarily from sales of non-core assets located in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. The following table presents a summaryEstimated proved reserves associated with these assets were approximately 157 MMBoe, or 10%, of Devon’s divestiture activity for 2016.
Date |
| Proceeds Received |
|
| Gains on Sale |
|
| Proved Reserves (MMBoe) |
|
| Percentage of U.S. Proved Reserves |
| ||||
Second quarter 2016 |
| $ | 200 |
|
| $ | 83 |
|
|
| 11 |
|
|
| 1 | % |
Third quarter 2016 |
|
| 1,653 |
|
|
| 726 |
|
|
| 146 |
|
|
| 9 | % |
Total |
| $ | 1,853 |
|
| $ | 809 |
|
|
| 157 |
|
|
| 10 | % |
71
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
These divestitures in 2017 and 2016 primarily related to sales of entire common operating fields. Therefore, Devon recognized a gain on the transactions.total U.S. proved reserves. As part of the gain computations,transactions, approximately $290 million of asset retirement obligations were assumed by purchasers and approximately $80 million of goodwill was allocated to these divested assets.
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.
EnLink AcquisitionsCanada and Barnett Shale (Subsequent Event)
In January 2016, EnLink acquired Anadarko Basin gatheringFebruary 2019, Devon announced its intent to separate its Canadian business and processing midstreamBarnett Shale assets along with dedicated acreage service rights and service contracts,from the Company, based on authorizations provided by its Board of Directors subsequent to December 31, 2018. Devon will evaluate multiple methods of separation for approximately $1.4 billion. The purchase price was $1.0 billion to intangiblethese assets, including potential sales or spin-offs. Devon is in the early stages of marketing these assets and approximately $400 million to propertydoes not currently have any indications that it would recognize an impairment upon separating its Canadian business or its Barnett Shale assets.
Devon anticipates reporting all financial information for its Canadian business and equipment. EnLink fundedBarnett Shale assets as discontinued operations in 2019 when all the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily financed with the issuance of EnLink preferred units. The remaining $500 million of the purchase price was to be paid within one year with the option to defer $250 million of the final payment 24 months from the close date. The first installment payment of $250 million was paid in January 2017 using divestiture proceeds, proceeds from equity issuances and borrowings under EnLink’s credit facility. The remaining $250 million payment is reported in other current liabilities in the accompanying consolidated balance sheets and was made in January 2018 using proceeds from equity issuances and borrowings under EnLink’s credit facility. requisite criteria are met for such financial statement presentation.
In August 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $251 million of existing non-monetary assets and cash to the joint venture and had committed an additional $285 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including cash contributions of approximately $144 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.
In November 2016, EnLink entered into a gathering and compression joint venture with a commitment of approximately $40 million to expand its midstream assets in the STACK. The joint venture is initially owned 30% by EnLink and 70% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $29 million in cash for new infrastructure build. After the initial capital commitment, EnLink and the joint venture partner will be responsible for their proportionate share of capital costs.
7268
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents a summary of EnLink’s acquisition activity for 2015.
|
|
|
| Purchase Price |
|
| Allocation |
| ||||||||||||||||||
Date |
| Midstream assets |
| Cash |
|
| EnLink Units |
|
| PP&E |
|
| Goodwill |
|
| Intangibles |
|
| Other |
| ||||||
January 2015 |
| Permian Basin |
| $ | 108 |
|
|
| — |
|
| $ | 30 |
|
| $ | 30 |
|
| $ | 43 |
|
| $ | 5 |
|
March 2015 |
| Permian Basin |
| $ | 240 |
|
| $ | 360 |
|
| $ | 302 |
|
| $ | 18 |
|
| $ | 281 |
|
| $ | (1 | ) |
October 2015 |
| Delaware Basin |
| $ | 141 |
|
|
| — |
|
| $ | 36 |
|
| $ | 11 |
|
| $ | 99 |
|
| $ | (5 | )) |
EnLink Asset Divestitures and Dropdowns
In December 2016, EnLink entered into definitive agreements to divest approximately $278 million of certain non-core midstream assets. As of December 31, 2016, these assets were classified as held for sale. During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.
In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.
In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.
Commodity Derivatives
As of December 31, 2017,2018, Devon had the following open oil derivative positions. The first table presentstwo tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The secondthird table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
|
| Price Swaps |
|
| Price Collars |
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||||||||||||||||
Period |
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
| ||||||||||
Q1-Q4 2018 |
|
| 49,625 |
|
| $ | 52.13 |
|
|
| 51,860 |
|
| $ | 46.06 |
|
| $ | 56.06 |
| ||||||||||||||||||||
Q1-Q4 2019 |
|
| 7,307 |
|
| $ | 52.22 |
|
|
| 6,559 |
|
| $ | 45.82 |
|
| $ | 55.82 |
|
|
| 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 |
|
| Oil Basis Collars |
| ||||||||||||||||
Period |
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Differential to WTI ($/Bbl) |
|
| Weighted Average Ceiling Differential to WTI ($/Bbl) |
| |||||
Q1-Q4 2018 |
| Midland Sweet |
|
| 23,000 |
|
| $ | (1.02 | ) |
|
| — |
|
| $ | — |
|
| $ | — |
|
Q1-Q4 2018 |
| Argus LLS |
|
| 12,000 |
|
| $ | 3.95 |
|
|
| — |
|
| $ | — |
|
| $ | — |
|
Q1-Q4 2018 |
| Western Canadian Select |
|
| 75,490 |
|
| $ | (14.84 | ) |
|
| 1,830 |
|
| $ | (15.50 | ) |
| $ | (13.93 | ) |
Q1-Q4 2019 |
| Midland Sweet |
|
| 27,000 |
|
| $ | (0.47 | ) |
|
| — |
|
| $ | — |
|
| $ | — |
|
|
| Three-Way Price Collars |
| |||||||||||||
Period |
| Volume (Bbls/d) |
|
| Weighted Average Floor Sold Price ($/Bbl) |
|
| Weighted Average Floor Purchased Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
| ||||
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 | ) |
73
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of December 31, 2017,2018, 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 |
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||||||||||||||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average Ceiling Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average Ceiling Price ($/MMBtu) |
| ||||||||||
Q1-Q4 2018 |
|
| 371,956 |
|
| $ | 3.06 |
|
|
| 197,516 |
|
| $ | 2.94 |
|
| $ | 3.26 |
| ||||||||||||||||||||
Q1-Q4 2019 |
|
| 28,466 |
|
| $ | 2.98 |
|
|
| 28,466 |
|
| $ | 2.84 |
|
| $ | 3.14 |
|
|
| 266,293 |
|
| $ | 2.86 |
|
|
| 231,474 |
|
| $ | 2.69 |
|
| $ | 3.06 |
|
Q1-Q4 2020 |
|
| 26,480 |
|
| $ | 2.92 |
|
|
| 24,490 |
|
| $ | 2.74 |
|
| $ | 3.04 |
| ||||||||||||||||||||
69
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Natural Gas Basis Swaps |
|
| Natural Gas Basis Swaps |
| ||||||||||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
|
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||||
Q1-Q4 2018 |
| Panhandle Eastern Pipe Line |
|
| 50,000 |
|
| $ | (0.29 | ) | ||||||||||
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, 2017,2018, 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 2018 |
| Ethane |
|
| 6,747 |
|
| $ | 11.89 |
|
Q1-Q4 2018 |
| Natural Gasoline |
|
| 5,500 |
|
| $ | 54.24 |
|
Q1-Q4 2018 |
| Normal Butane |
|
| 6,750 |
|
| $ | 38.46 |
|
Q1-Q4 2018 |
| Propane |
|
| 9,500 |
|
| $ | 33.19 |
|
|
|
|
| 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 |
|
As of December 31, 2017, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.
|
|
|
|
| |||||||
|
|
|
|
|
| ||||||
|
|
|
|
|
| ||||||
Interest Rate Derivatives
As of December 31, 2017,2018, Devon had the following open interest rate derivative positions:
Notional |
|
| Rate Received |
|
| Rate Paid |
|
| Expiration | |
$ | 750 |
|
| Three Month LIBOR |
|
| 2.98% |
|
| December 2048 (1) |
$ | 100 |
|
| 1.76% |
|
| Three Month LIBOR |
|
| January 2019 |
|
|
Notional |
|
| Rate Received |
|
| Rate Paid |
| Expiration | |
$ | 100 |
|
| 1.76% |
|
| Three Month LIBOR |
| January 2019 |
74
Table of ContentsIn January 2019, this interest rate derivative position settled.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| �� |
|
|
|
|
|
|
Upstream revenues |
| $ | 157 |
|
| $ | (201 | ) |
| $ | 503 |
|
| $ | 608 |
|
| $ | 157 |
|
| $ | (201 | ) |
Marketing and midstream revenues |
|
| (1 | ) |
|
| (13 | ) |
|
| 9 |
| ||||||||||||
Marketing revenues |
|
| (1 | ) |
|
| 3 |
|
|
| (2 | ) | ||||||||||||
Interest rate derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expenses |
|
| (22 | ) |
|
| (19 | ) |
|
| (20 | ) |
|
| 65 |
|
|
| (22 | ) |
|
| (19 | ) |
Foreign currency derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expenses |
|
| — |
|
|
| (153 | ) |
|
| 246 |
|
|
| — |
|
|
| — |
|
|
| (153 | ) |
Net gains (losses) recognized |
| $ | 134 |
|
| $ | (386 | ) |
| $ | 738 |
|
| $ | 672 |
|
| $ | 138 |
|
| $ | (375 | ) |
70
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, 2017 |
|
| December 31, 2016 |
|
| December 31, 2018 |
|
| December 31, 2017 |
| ||||
Commodity derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
| $ | 209 |
|
| $ | 9 |
|
| $ | 637 |
|
| $ | 203 |
|
Other long-term assets |
|
| 2 |
|
|
| 1 |
|
|
| 40 |
|
|
| 2 |
|
Interest rate derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Total derivative assets |
| $ | 212 |
|
| $ | 11 |
|
| $ | 677 |
|
| $ | 206 |
|
Commodity derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
| $ | 267 |
|
| $ | 187 |
|
| $ | 67 |
|
| $ | 259 |
|
Other long-term liabilities |
|
| 27 |
|
|
| 16 |
|
|
| 1 |
|
|
| 27 |
|
Interest rate derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
|
| 64 |
|
|
| — |
|
|
| — |
|
|
| 64 |
|
Other long-term liabilities |
|
| — |
|
|
| 41 |
| ||||||||
Total derivative liabilities |
| $ | 358 |
|
| $ | 244 |
|
| $ | 68 |
|
| $ | 350 |
|
|
In the second quarter of 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards that were transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.
75
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The vesting for certain share-based awards was accelerated in 2018 and 2016 in conjunction with the reduction of workforce activities described in Note 76. Approximately $60 million of associated expense for these accelerated awards and is included in other expensesrestructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.
The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings.
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
G&A |
| $ | 141 |
|
| $ | 124 |
|
| $ | 185 |
|
| $ | 122 |
|
| $ | 141 |
|
| $ | 124 |
|
Exploration expenses |
|
| 7 |
|
|
| 6 |
|
|
| 9 |
|
|
| 4 |
|
|
| 7 |
|
|
| 6 |
|
Total Devon |
|
| 148 |
|
|
| 130 |
|
|
| 194 |
| ||||||||||||
G&A |
|
| 37 |
|
|
| 24 |
|
|
| 31 |
| ||||||||||||
Marketing and midstream expenses |
|
| 11 |
|
|
| 7 |
|
|
| 5 |
| ||||||||||||
Total EnLink |
|
| 48 |
|
|
| 31 |
|
|
| 36 |
| ||||||||||||
Restructuring and transaction costs |
|
| 31 |
|
|
| — |
|
|
| 60 |
| ||||||||||||
Total |
| $ | 196 |
|
| $ | 161 |
|
| $ | 230 |
|
| $ | 157 |
|
| $ | 148 |
|
| $ | 190 |
|
Related income tax benefit |
| $ | 6 |
|
| $ | 6 |
|
| $ | 67 |
|
| $ | 22 |
|
| $ | 6 |
|
| $ | 6 |
|
71
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents a summary of Devon’s unvested restricted stock awards and units, 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 12/31/16 |
|
| 6,407 |
|
| $ | 34.40 |
|
|
| 585 |
|
| $ | 37.60 |
|
|
| 2,604 |
|
|
| $ | 46.66 |
| |||||||||||||||||||||||||||||
Unvested at 12/31/17 |
|
| 6,328 |
|
| $ | 36.81 |
|
|
| 575 |
|
| $ | 38.92 |
|
|
| 2,758 |
|
|
| $ | 41.21 |
| |||||||||||||||||||||||||||||
Granted |
|
| 2,691 |
|
| $ | 44.87 |
|
|
| 223 |
|
| $ | 44.85 |
|
|
| 1,010 |
|
|
| $ | 52.58 |
|
|
| 3,592 |
|
| $ | 35.98 |
|
|
| — |
|
| $ | — |
|
|
| 845 |
|
|
| $ | 37.40 |
| ||||
Vested |
|
| (2,431 | ) |
| $ | 39.51 |
|
|
| (233 | ) |
| $ | 41.27 |
|
|
| (832 | ) |
|
| $ | 78.19 |
|
|
| (3,114 | ) |
| $ | 38.75 |
|
|
| (273 | ) |
| $ | 42.22 |
|
|
| (571 | ) |
|
| $ | 84.22 |
| ||||
Forfeited |
|
| (339 | ) |
| $ | 35.92 |
|
|
| — |
|
| $ | — |
|
|
| (24 | ) |
|
| $ | 40.70 |
|
|
| (843 | ) |
| $ | 35.58 |
|
|
| — |
|
| $ | — |
|
|
| (164 | ) |
|
| $ | 33.92 |
| ||||
Unvested at 12/31/17 |
|
| 6,328 |
|
| $ | 36.81 |
|
|
| 575 |
|
| $ | 38.92 |
|
|
| 2,758 |
|
| (1 | ) |
| $ | 41.21 |
| |||||||||||||||||||||||||||
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.
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Restricted Stock Awards and Units |
| $ | 105 |
|
| $ | 73 |
|
| $ | 101 |
|
Performance-Based Restricted Stock Awards |
| $ | 10 |
|
| $ | 5 |
|
| $ | 8 |
|
Performance Share Units |
| $ | 38 |
|
| $ | 13 |
|
| $ | 22 |
|
76
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, 2017.
|
|
|
|
|
| Performance-Based |
|
|
|
|
| |
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
| |||
|
| Awards and Units |
|
| Awards |
|
| Share Units |
| |||
Unrecognized compensation cost |
| $ | 135 |
|
| $ | 5 |
|
| $ | 28 |
|
Weighted average period for recognition (years) |
|
| 2.4 |
|
|
| 1.6 |
|
|
| 1.9 |
|
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.
|
| 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.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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.
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||||||||||||||||||||
Grant-date fair value |
| $ | 51.05 |
|
| — |
| $ | 53.12 |
|
| $ | 9.24 |
|
| — |
| $ | 10.61 |
|
| $ | 81.99 |
|
| — |
| $ | 85.05 |
|
Risk-free interest rate |
| 1.50% |
|
| 0.94% |
|
| 1.06% |
| |||||||||||||||||||||
Volatility factor |
| 45.8% |
|
| 37.7% |
|
| 26.2% |
| |||||||||||||||||||||
Contractual term (years) |
| 2.89 |
|
| 2.83 |
|
| 2.89 |
| |||||||||||||||||||||
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) |
|
|
|
|
| ||
Outstanding at December 31, 2016 |
|
| 2,532 |
|
| $ | 68.06 |
|
|
|
|
|
|
|
|
|
Expired |
|
| (786 | ) |
| $ | 63.67 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2017 |
|
| 1,746 |
|
| $ | 70.04 |
|
|
| 1.33 |
|
| $ | — |
|
Exercisable at December 31, 2017 |
|
| 1,746 |
|
| $ | 70.04 |
|
|
| 1.33 |
|
| $ | — |
|
6. |
Restructuring and Transaction Costs | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 |
|
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 impairment charges for leasehold improvements and furniture associated with the office space it ceased using.
|
| Other |
|
| Other |
|
|
|
|
| ||
|
| Current |
|
| Long-term |
|
|
|
|
| ||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
Balance as of December 31, 2015 |
| $ | 13 |
|
| $ | 63 |
|
| $ | 76 |
|
Changes related to prior years' restructurings |
|
| 35 |
|
|
| (1 | ) |
|
| 34 |
|
Balance as of December 31, 2016 |
| $ | 48 |
|
| $ | 62 |
|
| $ | 110 |
|
Changes related to prior years' restructurings |
|
| (29 | ) |
|
| (31 | ) |
|
| (60 | ) |
Balance as of December 31, 2017 |
| $ | 19 |
|
| $ | 31 |
|
| $ | 50 |
|
Prior Years’ Restructurings
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 impairment charges for leasehold improvements and furniture associated with the office space it ceased using.
In 2015, Devon recognized $24 million of employee-related and other costs associated with the reduction in workforce made subsequent to the completion of the Jackfish development projects and a decrease in planned Canadian capital investment resulting from the drop in commodity prices.
80
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As part of the U.S. corporate headquarters office consolidation, Devon recognized an additional $54 million expense in 2015, due to the inability to fully sublease remaining office space.
Transaction Costs
In 2016, Devon and EnLink recognized $17$11 million in transaction costs primarily associated with the closing of the acquisitionsSTACK acquisition discussed in Note 32.
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 |
|
Foreign 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 foreign currency denominated monetary assets and liabilities, including intercompany loans between subsidiaries with different functional currencies. Unrealized gains and losses arise from the remeasurement of these foreign currency denominated monetary assets and liabilities and intercompany loans. Realized gains and losses arise when there are settlements of these foreign currency denominated monetary assets and liabilities and intercompany loans.
75
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.
8. | Income Taxes |
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Current income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
| $ | 10 |
|
| $ | 5 |
|
| $ | (243 | ) |
| $ | (14 | ) |
| $ | 9 |
|
| $ | 3 |
|
Various states |
|
| — |
|
|
| (11 | ) |
|
| (8 | ) |
|
| (3 | ) |
|
| — |
|
|
| (11 | ) |
Canada and various provinces |
|
| 102 |
|
|
| 106 |
|
|
| 14 |
|
|
| (53 | ) |
|
| 103 |
|
|
| 106 |
|
Total current tax expense (benefit) |
|
| 112 |
|
|
| 100 |
|
|
| (237 | ) |
|
| (70 | ) |
|
| 112 |
|
|
| 98 |
|
Deferred income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
| (192 | ) |
|
| (3 | ) |
|
| (5,487 | ) |
|
| 248 |
|
|
| — |
|
|
| — |
|
Various states |
|
| (5 | ) |
|
| — |
|
|
| (332 | ) |
|
| 63 |
|
|
| — |
|
|
| — |
|
Canada and various provinces |
|
| (97 | ) |
|
| 44 |
|
|
| (157 | ) |
|
| (85 | ) |
|
| (97 | ) |
|
| 43 |
|
Total deferred tax expense (benefit) |
|
| (294 | ) |
|
| 41 |
|
|
| (5,976 | ) |
|
| 226 |
|
|
| (97 | ) |
|
| 43 |
|
Total income tax expense (benefit) |
| $ | (182 | ) |
| $ | 141 |
|
| $ | (6,213 | ) | ||||||||||||
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, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Total income tax expense (benefit) |
| $ | (182 | ) |
| $ | 141 |
|
| $ | (6,213 | ) | ||||||||||||
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 | % |
Non-deductible goodwill and intangible impairment |
|
| 0 | % |
|
| (23 | %) |
|
| (3 | %) | ||||||||||||
U.S. Tax Reform |
|
| 8 | % |
|
| 0 | % |
|
| 0 | % |
|
| 0 | % |
|
| 36 | % |
|
| 0 | % |
Legal entity restructuring |
|
| (81 | %) |
|
| 6 | % |
|
| 0 | % |
|
| 2 | % |
|
| (94 | %) |
|
| 19 | % |
State income taxes |
|
| 5 | % |
|
| 0 | % |
|
| 10 | % | ||||||||||||
Change in unrecognized tax benefits |
|
| (5 | %) |
|
| 2 | % |
|
| (16 | %) | ||||||||||||
Other |
|
| (13 | %) |
|
| 0 | % |
|
| 1 | % |
|
| (0 | %) |
|
| (13 | %) |
|
| 8 | % |
Deferred tax asset valuation allowance |
|
| 31 | % |
|
| (29 | %) |
|
| (2 | %) |
|
| (6 | %) |
|
| 36 | % |
|
| (89 | %) |
Effective income tax rate |
|
| (20 | %) |
|
| (11 | %) |
|
| 31 | % |
|
| 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.
81
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance. Numerous judgementsjudgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.
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
OnThe Tax Reform Legislation, enacted on December 22, 2017, the Tax Reform Legislation was enacted into law and containscontained several key tax provisions that affectaffected 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, among others.2018. Devon iswas 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.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, Devon considers the accounting of the transition tax, deferred tax remeasurements, and other items to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. Devon expects to complete its analysis within the measurement period in accordance with SAB 118. Provisional amounts recorded this quarter are as follows:
(a) Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings.
(b) Devon’s U.S. segment recognizedearnings, and $108 million in deferred tax expense and EnLink recognized $211 million in deferred tax benefit related to the reduction of the U.S. corporate income tax rate to 21%.
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.allowance.
Throughout 2017, Devon continued to maintainmaintained 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. The valuation allowances impacted the effective tax rate and are discussed in the next section.
Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in 2017 due to lower relative earnings during the period. During 2017, “other” is primarily
2016
Devon recorded a tax expense of $63 million related to the taxationunrecognized tax benefits during 2016, primarily as a result of other financing items.Canadian audits and legal proceedings.
2016
During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its deferred tax assets. The allowance resultsresulted from continued financial losses in 2016. As of December 31, 2016, the
82
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
allowance continued 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.
In the first quarter of 2016, EnLink recognized a goodwill impairment of approximately $873 million. Additionally, duringDuring the third quarter of 2016, Devon derecognized $83 million of goodwill related to its U.S. operations in conjunction with the divestiture of certain non-core U.S. upstream oil and gas assets. These items arewere not deductible for purposes of calculating income tax and, therefore, impact the effective tax rate.
2015
In the third and fourth quarters of 2015, EnLink recognized goodwill and intangibles impairments of approximately $1.6 billion, which impacted the effective tax rate.
During 2015, Devon recognized approximately $16 billion78
Table of oil and gas impairments relatedContents
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, |
|
| December 31, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
| ||||
Deferred tax assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
| $ | 313 |
|
| $ | 488 |
|
| $ | 300 |
|
| $ | 313 |
|
Accrued liabilities |
|
| 62 |
|
|
| 130 |
|
|
| 50 |
|
|
| 62 |
|
Net operating loss carryforwards |
|
| 865 |
|
|
| 777 |
|
|
| 287 |
|
|
| 796 |
|
Pension benefit obligations |
|
| 54 |
|
|
| 98 |
|
|
| 44 |
|
|
| 54 |
|
Canadian capital loss carryforwards |
|
| 760 |
|
|
| 17 |
|
|
| 609 |
|
|
| 760 |
|
Other |
|
| 135 |
|
|
| 186 |
|
|
| 87 |
|
|
| 135 |
|
Total deferred tax assets before valuation allowance |
|
| 2,189 |
|
|
| 1,696 |
|
|
| 1,377 |
|
|
| 2,120 |
|
Less: valuation allowance |
|
| (968 | ) |
|
| (645 | ) |
|
| (640 | ) |
|
| (968 | ) |
Net deferred tax assets |
|
| 1,221 |
|
|
| 1,051 |
|
|
| 737 |
|
|
| 1,152 |
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment |
|
| (1,703 | ) |
|
| (1,635 | ) |
|
| (1,473 | ) |
|
| (1,288 | ) |
Long-term debt |
|
| (92 | ) |
|
| (53 | ) |
|
| — |
|
|
| (92 | ) |
Other |
|
| (261 | ) |
|
| (426 | ) |
|
| (141 | ) |
|
| (261 | ) |
Total deferred tax liabilities |
|
| (2,056 | ) |
|
| (2,114 | ) |
|
| (1,614 | ) |
|
| (1,641 | ) |
Net deferred tax liability |
| $ | (835 | ) |
| $ | (1,063 | ) |
| $ | (877 | ) |
| $ | (489 | ) |
83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
At December 31, 2017,2018, Devon has recognized $865$287 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segment has $710$595 million of noncapital loss carryforwards expiring between 2029 and 2037.2038. Devon’s U.S. segment has $2.4 billion of U.S. federal carryforwards expiring between 2036 and 2037 and $1.7 billion of U.S. state carryforwards expiring between 2018 and 2037. EnLink has $259 $389 million of U.S. federal net operating loss carryforwards expiring in 2037 and $784 million of U.S. state net operating loss carryforwards expiring between 20342019 and 2037 and $263 million of state carryforwards expiring between 2028 and 2037.2038. 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 20182019 and beyondand EnLink carryforwards to be utilized in 2020 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..
As a result of Devon’s sale of its aggregate ownership interests in EnLink and the reduction inGeneral Partner during the third quarter of 2018, Devon’s U.S. statutory income tax ratesegment reassessed its position and favorable temporary differences, Devon reducedreleased its full valuation allowance by $337position, maintaining only $31 million of valuation allowance against the U.S.certain deferred tax assets, in 2017including certain tax credits and remains in a full valuation allowance position.state net operating losses. Also during 2017,2018, Devon’s Canadian segment recognizedmaintained a $660 million partial valuation allowance of $609 million against the deferred tax asset related to the Canadian capital loss carryforward due to 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, 2017,2018, 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 $908 million. Alldecision in February 2019 to dispose of this amount was deemed to bethe Canadian 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 werewill be reevaluated in 2019.
79
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.
|
| December 31, |
|
| December 31, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
| ||||
Balance at beginning of year |
| $ | 202 |
|
| $ | 131 |
|
| $ | 115 |
|
| $ | 202 |
|
Tax positions taken in prior periods |
|
| (7 | ) |
|
| 36 |
|
|
| (43 | ) |
|
| (7 | ) |
Tax positions taken in current year |
|
| (3 | ) |
|
| — |
|
|
| (2 | ) |
|
| (3 | ) |
Accrual of interest related to tax positions taken |
|
| 16 |
|
|
| 39 |
|
|
| 3 |
|
|
| 16 |
|
Settlements |
|
| (101 | ) |
|
| — |
|
|
| — |
|
|
| (101 | ) |
Lapse of statute of limitations |
|
| — |
|
|
| (5 | ) | ||||||||
Foreign currency translation |
|
| 8 |
|
|
| 1 |
|
|
| (3 | ) |
|
| 8 |
|
Balance at end of year |
| $ | 115 |
|
| $ | 202 |
|
| $ | 70 |
|
| $ | 115 |
|
Devon’s unrecognized tax benefit balance at December 31, 2018 and 2017 and 2016 included $28$12 million and $68$28 million, respectively, of interest and penalties. If recognized, $115$70 million of Devon’s unrecognized tax benefits as of December 31, 20172018 would affect Devon’s effective income tax rate.During 2017,2018, Devon removed $101$43 million of unrecognized tax benefits, including $50$20 million of interest, as a result of the settlementclosure of certain tax examinations. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
84
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Jurisdiction |
| Tax Years Open |
U.S. 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.
80
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, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Net earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Net earnings (loss) attributable to Devon |
| $ | 898 |
|
| $ | (1,056 | ) |
| $ | (12,896 | ) | ||||||||||||
Net earnings (loss) from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Net earnings (loss) from continuing operations |
| $ | 764 |
|
| $ | 758 |
|
| $ | (574 | ) | ||||||||||||
Attributable to participating securities |
|
| (10 | ) |
|
| (2 | ) |
|
| (5 | ) |
|
| (9 | ) |
|
| (8 | ) |
|
| (2 | ) |
Basic and diluted earnings (loss) |
| $ | 888 |
|
| $ | (1,058 | ) |
| $ | (12,901 | ) | ||||||||||||
Basic and diluted earnings (loss) from continuing operations |
| $ | 755 |
|
| $ | 750 |
|
| $ | (576 | ) | ||||||||||||
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding - total |
|
| 525 |
|
|
| 513 |
|
|
| 412 |
|
|
| 499 |
|
|
| 525 |
|
|
| 513 |
|
Attributable to participating securities |
|
| (5 | ) |
|
| (6 | ) |
|
| (5 | ) |
|
| (5 | ) |
|
| (5 | ) |
|
| (6 | ) |
Common shares outstanding - basic |
|
| 520 |
|
|
| 507 |
|
|
| 407 |
|
|
| 494 |
|
|
| 520 |
|
|
| 507 |
|
Dilutive effect of potential common shares issuable |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| 3 |
|
|
| 3 |
|
|
| — |
|
Common shares outstanding - diluted |
|
| 523 |
|
|
| 507 |
|
|
| 407 |
|
|
| 497 |
|
|
| 523 |
|
|
| 507 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Net earnings (loss) per share from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Basic |
| $ | 1.71 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
| $ | 1.53 |
|
| $ | 1.44 |
|
| $ | (1.14 | ) |
Diluted |
| $ | 1.70 |
|
| $ | (2.09 | ) |
| $ | (31.72 | ) |
| $ | 1.52 |
|
| $ | 1.43 |
|
| $ | (1.14 | ) |
Antidilutive options (1) |
|
| 2 |
|
|
| 3 |
|
|
| 4 |
|
|
| 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. |
85
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components of other comprehensive earnings consist of the following:
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Foreign currency translation and other: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Beginning accumulated foreign currency translation and other |
| $ | 1,226 |
|
| $ | 1,215 |
|
| $ | 1,658 |
| ||||||||||||
Change in cumulative translation adjustment and other |
|
| 113 |
|
|
| 22 |
|
|
| (490 | ) | ||||||||||||
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Beginning accumulated foreign currency translation |
| $ | 1,309 |
|
| $ | 1,226 |
|
| $ | 1,215 |
| ||||||||||||
Change in cumulative translation adjustment |
|
| (166 | ) |
|
| 113 |
|
|
| 22 |
| ||||||||||||
Income tax benefit (expense) |
|
| (30 | ) |
|
| (11 | ) |
|
| 47 |
|
|
| 14 |
|
|
| (30 | ) |
|
| (11 | ) |
Ending accumulated foreign currency translation and other |
|
| 1,309 |
|
|
| 1,226 |
|
|
| 1,215 |
| ||||||||||||
Ending accumulated foreign currency translation |
|
| 1,157 |
|
|
| 1,309 |
|
|
| 1,226 |
| ||||||||||||
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated pension and postretirement benefits |
|
| (172 | ) |
|
| (194 | ) |
|
| (204 | ) |
|
| (143 | ) |
|
| (172 | ) |
|
| (194 | ) |
Net actuarial loss and prior service cost arising in current year |
|
| 10 |
|
|
| (28 | ) |
|
| (5 | ) |
|
| (3 | ) |
|
| 10 |
|
|
| (28 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 19 |
|
|
| 26 |
|
|
| 21 |
|
|
| 12 |
|
|
| 19 |
|
|
| 26 |
|
Curtailment and settlement of pension benefits |
|
| — |
|
|
| 24 |
|
|
| — |
|
|
| 47 |
|
|
| — |
|
|
| 24 |
|
Income tax expense |
|
| — |
|
|
| — |
|
|
| (6 | ) |
|
| (12 | ) |
|
| — |
|
|
| — |
|
Other (2) |
|
| (33 | ) |
|
| — |
|
|
| — |
| ||||||||||||
Ending accumulated pension and postretirement benefits |
|
| (143 | ) |
|
| (172 | ) |
|
| (194 | ) |
|
| (132 | ) |
|
| (143 | ) |
|
| (172 | ) |
Other |
|
| 2 |
|
|
| — |
|
|
| — |
| ||||||||||||
Accumulated other comprehensive earnings, net of tax |
| $ | 1,166 |
|
| $ | 1,054 |
|
| $ | 1,021 |
|
| $ | 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, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Net change in working capital accounts, net of assets and liabilities assumed: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Changes in assets and liabilities, net |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Accounts receivable |
| $ | (284 | ) |
| $ | (176 | ) |
| $ | 942 |
|
| $ | 88 |
|
| $ | (94 | ) |
| $ | (58 | ) |
Income taxes receivable |
|
| 8 |
|
|
| 130 |
|
|
| 384 |
| ||||||||||||
Other current assets |
|
| (12 | ) |
|
| 215 |
|
|
| (57 | ) |
|
| (128 | ) |
|
| 20 |
|
|
| 326 |
|
Other long-term assets |
|
| (28 | ) |
|
| (47 | ) |
|
| 36 |
| ||||||||||||
Accounts payable |
|
| 105 |
|
|
| (167 | ) |
|
| (190 | ) |
|
| — |
|
|
| 113 |
|
|
| (196 | ) |
Revenues and royalties payable |
|
| 257 |
|
|
| 96 |
|
|
| (526 | ) |
|
| 153 |
|
|
| 106 |
|
|
| (26 | ) |
Other current liabilities |
|
| (53 | ) |
|
| (74 | ) |
|
| (818 | ) |
|
| (150 | ) |
|
| (53 | ) |
|
| (74 | ) |
Net change in working capital |
| $ | 21 |
|
| $ | 24 |
|
| $ | (265 | ) | ||||||||||||
Other long-term liabilities |
|
| (78 | ) |
|
| (13 | ) |
|
| 16 |
| ||||||||||||
Total |
| $ | (143 | ) |
| $ | 32 |
|
| $ | 24 |
| ||||||||||||
Supplementary cash flow data - total operations: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Interest paid (net of capitalized interest) |
| $ | 481 |
|
| $ | 569 |
|
| $ | 497 |
|
| $ | 385 |
|
| $ | 481 |
|
| $ | 569 |
|
Income taxes paid (received) |
| $ | 78 |
|
| $ | (159 | ) |
| $ | (279 | ) |
| $ | 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 3 for additional details.
In 2015, Devon’s acquisition of certain Powder River Basin assets included a noncash common stock issuance totaling $199 million. EnLink’s acquisitions in 2015 also included $360 million of noncash equity.
86
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components of accounts receivable include the following:
|
| December 31, 2017 |
|
| December 31, 2016 |
|
| December 31, 2018 |
|
| December 31, 2017 |
| ||||
Oil, gas and NGL sales |
| $ | 559 |
|
| $ | 487 |
|
| $ | 430 |
|
| $ | 559 |
|
Joint interest billings |
|
| 134 |
|
|
| 110 |
|
|
| 155 |
|
|
| 134 |
|
Marketing and midstream revenues |
|
| 959 |
|
|
| 708 |
| ||||||||
Marketing revenues |
|
| 285 |
|
|
| 278 |
| ||||||||
Other |
|
| 29 |
|
|
| 69 |
|
|
| 23 |
|
|
| 29 |
|
Gross accounts receivable |
|
| 1,681 |
|
|
| 1,374 |
|
|
| 893 |
|
|
| 1,000 |
|
Allowance for doubtful accounts |
|
| (11 | ) |
|
| (18 | ) |
|
| (8 | ) |
|
| (11 | ) |
Net accounts receivable |
| $ | 1,670 |
|
| $ | 1,356 |
|
| $ | 885 |
|
| $ | 989 |
|
13.Property, Plant and Equipment
Capitalized Costs
The following tables reflect the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
|
| December 31, 2017 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved |
| $ | 40,491 |
|
| $ | 6,804 |
|
| $ | 47,295 |
|
Unproved and properties under development |
|
| 984 |
|
|
| 1,473 |
|
|
| 2,457 |
|
Total oil and gas |
|
| 41,475 |
|
|
| 8,277 |
|
|
| 49,752 |
|
Accumulated DD&A |
|
| (32,379 | ) |
|
| (4,055 | ) |
|
| (36,434 | ) |
Oil and gas property and equipment, net |
| $ | 9,096 |
|
| $ | 4,222 |
|
| $ | 13,318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Proved |
| $ | 38,842 |
|
| $ | 6,163 |
|
| $ | 45,005 |
|
Unproved and properties under development |
|
| 2,115 |
|
|
| 1,277 |
|
|
| 3,392 |
|
Total oil and gas |
|
| 40,957 |
|
|
| 7,440 |
|
|
| 48,397 |
|
Accumulated DD&A |
|
| (31,979 | ) |
|
| (3,420 | ) |
|
| (35,399 | ) |
Oil and gas property and equipment, net |
| $ | 8,978 |
|
| $ | 4,020 |
|
| $ | 12,998 |
|
|
| December 31, |
| |||||
|
| 2017 |
|
| 2016 |
| ||
EnLink |
| $ | 9,120 |
|
| $ | 8,381 |
|
Devon |
|
| 1,955 |
|
|
| 1,919 |
|
Total midstream and other |
|
| 11,075 |
|
|
| 10,300 |
|
EnLink |
|
| (2,533 | ) |
|
| (2,124 | ) |
Devon |
|
| (689 | ) |
|
| (641 | ) |
Total accumulated DD&A |
|
| (3,222 | ) |
|
| (2,765 | ) |
Midstream and other property and equipment, net |
| $ | 7,853 |
|
| $ | 7,535 |
|
8782
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
13.Property, Plant and Equipment
Capitalized Costs
The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
|
| December 31, 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 |
|
Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2017.2018.
|
| 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
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Beginning balance |
| $ | 261 |
|
| $ | 225 |
|
| $ | 199 |
|
Additions pending determination of proved reserves |
|
| 504 |
|
|
| 247 |
|
|
| 348 |
|
Charges to exploration expense |
|
| — |
|
|
| (29 | ) |
|
| (5 | ) |
Reclassifications to proved properties |
|
| (466 | ) |
|
| (189 | ) |
|
| (285 | ) |
Foreign currency translation adjustment |
|
| 14 |
|
|
| 7 |
|
|
| (32 | ) |
Ending balance |
| $ | 313 |
|
| $ | 261 |
|
| $ | 225 |
|
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table provides 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, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Exploratory well costs capitalized for a period of one year or less |
| $ | 113 |
|
| $ | 88 |
|
| $ | 60 |
|
| $ | 110 |
|
| $ | 113 |
|
| $ | 88 |
|
Exploratory well costs capitalized for a period greater than one year |
|
| 200 |
|
|
| 173 |
|
|
| 165 |
|
|
| 194 |
|
|
| 200 |
|
|
| 173 |
|
Ending balance |
| $ | 313 |
|
| $ | 261 |
|
| $ | 225 |
|
| $ | 304 |
|
| $ | 313 |
|
| $ | 261 |
|
Number of projects with exploratory well costs capitalized for a period greater than one year |
|
| 2 |
|
|
| 2 |
|
|
| 2 |
|
|
| 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 continueshas not planned additional exploratory work in the near future on these assets and will continue to assess theits future development timeline of these long cycle projects.
88
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
14.Goodwill and Other Intangible Assets
Goodwill
The following table presents a summary of Devon’s goodwill. For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.
|
| U.S. |
|
| EnLink |
|
| Total |
| |||
Balance as of December 31, 2015 |
| $ | 923 |
|
| $ | 2,414 |
|
| $ | 3,337 |
|
Acquired during period |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Asset divestitures |
|
| (83 | ) |
|
| — |
|
|
| (83 | ) |
Impairment |
|
| — |
|
|
| (873 | ) |
|
| (873 | ) |
Balance as of December 31, 2016 |
| $ | 840 |
|
| $ | 1,543 |
|
| $ | 2,383 |
|
The following table presents the General Partner’s and EnLink’s goodwill activity by reporting unit. For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.
|
| Texas |
|
| Oklahoma |
|
| Crude and Condensate |
|
| General Partner |
|
| Total |
| |||||
Balance as of December 31, 2015 |
| $ | 704 |
|
| $ | 190 |
|
| $ | 93 |
|
| $ | 1,427 |
|
| $ | 2,414 |
|
Acquired during period |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
Impairment |
|
| (473 | ) |
|
| — |
|
|
| (93 | ) |
|
| (307 | ) |
|
| (873 | ) |
Balance as of December 31, 2016 |
| $ | 233 |
|
| $ | 190 |
|
| $ | — |
|
| $ | 1,120 |
|
| $ | 1,543 |
|
Asset Divestitures
In conjunction with the U.S. non-core upstream asset divestitures in 2016 discussed in Note 3, Devon removed goodwill allocated to these assets.
Impairment
As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units in the first quarter of 2016. Based on that test, EnLink recorded noncash goodwill impairments related to its Texas, Crude and Condensate and General Partner reporting units.
Additionally, during 2015, EnLink recorded noncash goodwill impairments related to its Texas, Louisiana and Crude and Condensate reporting units.
89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.
|
| December 31, 2017 |
|
| December 31, 2016 |
| ||
Customer relationships |
| $ | 1,796 |
|
| $ | 1,796 |
|
Accumulated amortization |
|
| (299 | ) |
|
| (172 | ) |
Net intangibles |
| $ | 1,497 |
|
| $ | 1,624 |
|
The weighted-average amortization period for the customer relationships is 15 years. Amortization expense for intangibles was approximately $127 million, $117 million and $56 million for the years ended 2017, 2016 and 2015, respectively. The remaining aggregate amortization expense is estimated to be approximately $123 million in each of the next five years.
expire until 2025.
Components of other current liabilities include the following:
| December 31, 2017 |
|
| December 31, 2016 |
| December 31, 2018 |
|
| December 31, 2017 |
| ||||
Derivative liabilities | $ | 331 |
|
| $ | 187 |
| $ | 67 |
|
| $ | 323 |
|
Installment payment - see Note 3 |
| 250 |
|
|
| 249 |
| |||||||
Accrued interest payable |
| 80 |
|
|
| 96 |
| |||||||
Income taxes payable |
| 145 |
|
|
| 32 |
|
| 14 |
|
|
| 144 |
|
Accrued interest payable |
| 131 |
|
|
| 130 |
| |||||||
Restructuring liabilities |
| 19 |
|
|
| 48 |
|
| 47 |
|
|
| 19 |
|
Other |
| 325 |
|
|
| 420 |
|
| 227 |
|
|
| 246 |
|
Other current liabilities | $ | 1,201 |
|
| $ | 1,066 |
| $ | 435 |
|
| $ | 828 |
|
9084
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, 2017 |
|
| December 31, 2016 |
| ||
Devon debt: |
|
|
|
|
|
|
|
|
8.25% due July 1, 2018 (1)(2) |
| $ | 20 |
|
| $ | 20 |
|
2.25% due December 15, 2018 (1) |
|
| 95 |
|
|
| 95 |
|
6.30% due January 15, 2019 (1) |
|
| 162 |
|
|
| 162 |
|
4.00% due July 15, 2021 |
|
| 500 |
|
|
| 500 |
|
3.25% due May 15, 2022 |
|
| 1,000 |
|
|
| 1,000 |
|
5.85% due December 15, 2025 (1) |
|
| 485 |
|
|
| 485 |
|
7.50% due September 15, 2027 (1)(2) |
|
| 73 |
|
|
| 73 |
|
7.875% due September 30, 2031 (1)(3) |
|
| 1,059 |
|
|
| 1,059 |
|
7.95% due April 15, 2032 (1) |
|
| 789 |
|
|
| 789 |
|
5.60% due July 15, 2041 |
|
| 1,250 |
|
|
| 1,250 |
|
4.75% due May 15, 2042 |
|
| 750 |
|
|
| 750 |
|
5.00% due June 15, 2045 |
|
| 750 |
|
|
| 750 |
|
Net discount on debentures and notes |
|
| (30 | ) |
|
| (30 | ) |
Debt issuance costs |
|
| (39 | ) |
|
| (44 | ) |
Total Devon debt |
|
| 6,864 |
|
|
| 6,859 |
|
EnLink and General Partner debt: |
|
|
|
|
|
|
|
|
Credit facilities |
|
| 74 |
|
|
| 148 |
|
2.70% due April 1, 2019 |
|
| 400 |
|
|
| 400 |
|
7.125% due June 1, 2022 |
|
| — |
|
|
| 163 |
|
4.40% due April 1, 2024 |
|
| 550 |
|
|
| 550 |
|
4.15% due June 1, 2025 |
|
| 750 |
|
|
| 750 |
|
4.85% due July 15, 2026 |
|
| 500 |
|
|
| 500 |
|
5.60% due April 1, 2044 |
|
| 350 |
|
|
| 350 |
|
5.05% due April 1, 2045 |
|
| 450 |
|
|
| 450 |
|
5.45% due June 1, 2047 |
|
| 500 |
|
|
| — |
|
Net premium (discount) on debentures and notes |
|
| (6 | ) |
|
| 9 |
|
Debt issuance costs |
|
| (26 | ) |
|
| (25 | ) |
Total EnLink and General Partner debt |
|
| 3,542 |
|
|
| 3,295 |
|
Total debt |
|
| 10,406 |
|
|
| 10,154 |
|
Less amount classified as short-term debt (4) |
|
| 115 |
|
|
| — |
|
Total long-term debt |
| $ | 10,291 |
|
| $ | 10,154 |
|
|
| 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%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. |
(2) | These senior notes were included in 2018 tender offer repurchases discussed below. |
(3) | Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned |
(4) |
|
91Debt 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, 2017, excluding debt issuance costs, premiumsavailable credit. On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and discounts, are as follows:
|
| Devon |
|
| EnLink |
|
| Total |
| |||
2018 |
| $ | 115 |
|
| $ | — |
|
| $ | 115 |
|
2019 |
|
| 162 |
|
|
| 474 |
|
|
| 636 |
|
2020 |
|
| — |
|
|
| — |
|
|
| — |
|
2021 |
|
| 500 |
|
|
| — |
|
|
| 500 |
|
2022 |
|
| 1,000 |
|
|
| — |
|
|
| 1,000 |
|
Thereafter |
|
| 5,156 |
|
|
| 3,100 |
|
|
| 8,256 |
|
Total |
| $ | 6,933 |
|
| $ | 3,574 |
|
| $ | 10,507 |
|
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: $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 $7.4$6.1 million. As of December 31, 2017,2018, Devon had $59$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, 2017.2018.
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, 2017,2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 27.2%21.0%. Devon’s change to successful efforts did not materially change this ratio.
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. As of December 31, 2017,2018, 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 32. 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.
9286
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
EnLink has a $1.5 billion unsecured revolving credit facility that will mature on March 6, 2020. As of December 31, 2017, there were $10 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019. As of December 31, 2017, the General Partner had $74 million in outstanding borrowings under the $250 million credit facility at a weighted average borrowing rate of 3.2%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2017.
In the second quarter of 2017, EnLink issued $500 million of 5.45% unsecured senior notes due in 2047. The proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive statement of earnings.
In July 2016, EnLink issued $500 million of 4.85% unsecured senior notes due 2026. EnLink used the net proceeds to repay outstanding borrowings under its revolving credit facility and for general partnership purposes.
Financing Costs, Net
The following schedule includes the components of net financing costs.
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Devon net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Interest based on debt outstanding |
| $ | 390 |
|
| $ | 488 |
|
| $ | 450 |
|
| $ | 339 |
|
| $ | 390 |
|
| $ | 488 |
|
Early retirement of debt |
|
| — |
|
|
| 269 |
|
|
| — |
|
|
| 312 |
|
|
| — |
|
|
| 269 |
|
Capitalized interest |
|
| (69 | ) |
|
| (61 | ) |
|
| (52 | ) |
|
| (41 | ) |
|
| (69 | ) |
|
| (61 | ) |
Other |
|
| (4 | ) |
|
| 21 |
|
|
| 14 |
|
|
| (16 | ) |
|
| (4 | ) |
|
| 21 |
|
Total Devon net financing costs |
|
| 317 |
|
|
| 717 |
|
|
| 412 |
| ||||||||||||
EnLink net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Interest based on debt outstanding |
|
| 167 |
|
|
| 144 |
|
|
| 115 |
| ||||||||||||
Interest accretion on deferred installment payment |
|
| 26 |
|
|
| 52 |
|
|
| — |
| ||||||||||||
Early retirement of debt |
|
| (9 | ) |
|
| — |
|
|
| — |
| ||||||||||||
Other |
|
| (3 | ) |
|
| (6 | ) |
|
| (8 | ) | ||||||||||||
Total EnLink net financing costs |
|
| 181 |
|
|
| 190 |
|
|
| 107 |
| ||||||||||||
Total net financing costs |
| $ | 498 |
|
| $ | 907 |
|
| $ | 519 |
|
| $ | 594 |
|
| $ | 317 |
|
| $ | 717 |
|
93
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the changes in asset retirement obligations.
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
| ||||
Asset retirement obligations as of beginning of period |
| $ | 1,272 |
|
| $ | 1,414 |
|
| $ | 1,138 |
|
| $ | 1,258 |
|
Liabilities incurred and assumed through acquisitions |
|
| 40 |
|
|
| 27 |
| ||||||||
Liabilities incurred |
|
| 39 |
|
|
| 40 |
| ||||||||
Liabilities settled and divested |
|
| (68 | ) |
|
| (324 | ) |
|
| (116 | ) |
|
| (68 | ) |
Revision of estimated obligation |
|
| (184 | ) |
|
| 66 |
|
|
| (25 | ) |
|
| (184 | ) |
Accretion expense on discounted obligation |
|
| 62 |
|
|
| 75 |
|
|
| 59 |
|
|
| 62 |
|
Foreign currency translation adjustment |
|
| 30 |
|
|
| 14 |
|
|
| (38 | ) |
|
| 30 |
|
Asset retirement obligations as of end of period |
|
| 1,152 |
|
|
| 1,272 |
|
|
| 1,057 |
|
|
| 1,138 |
|
Less current portion |
|
| 39 |
|
|
| 46 |
|
|
| 27 |
|
|
| 39 |
|
Asset retirement obligations, long-term |
| $ | 1,113 |
|
| $ | 1,226 |
|
| $ | 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 assumed inflation rate and retirement dates for its oil and gas assets.
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.
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 annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. Devon contributed $60$50 million, $64$53 million and $79$57 million to these plans in 2018, 2017 2016 and 2015,2016, respectively.
87
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Defined Benefit Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans covering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits under the defined benefit plans have been closed to new employees since 2007;employees; however, eligible employees continue to accrue benefits based upon years of service and compensation. Benefits are primarily funded from assets held in the plans’ trusts.
Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 70% fixed income, 20% equity and 10% other. See the following discussion for Devon’s pension assets by asset class.
94
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Fixed-income – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices and were $342$193 million and $311$342 million at December 31, 20172018 and 2016,2017, 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 securities are based upon the net asset values provided by the investment managers and were $401$301 million and $367$401 million at December 31, 2018 and 2017, and 2016, respectively.
Equity – Devon’s equity securities include a commingled global equity fundfunds that investsinvest in large, mid-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 securities are based upon the net asset values provided by the investment managers and were $157$84 million and $171$157 million at December 31, 2018 and 2017, and 2016, respectively.
Other – Devon’s other securities include short-term investmentsinvestment funds an actively traded global mutual fund focusing on alternative investment strategies and a hedge fund that investsinvest both long and short using a variety of investment strategies. The fair value of these securities is based upon the net asset values provided by investment managers and were $135$132 million and $136$135 million at December 31, 2018 and 2017, and 2016, respectively.
Defined Postretirement Plans
Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. The plans provide medical and in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.
95
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Benefit Obligations and Funded Status
The following table summarizes the benefit obligations, assets, funded status and balance sheet impacts associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 20172018 and 2016.2017.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| $ | 1,249 |
|
| $ | 1,308 |
|
| $ | 21 |
|
| $ | 23 |
|
Service cost |
|
| 15 |
|
|
| 15 |
|
|
| — |
|
|
| — |
|
Interest cost |
|
| 42 |
|
|
| 42 |
|
|
| — |
|
|
| 1 |
|
Actuarial loss (gain) |
|
| 59 |
|
|
| 63 |
|
|
| — |
|
|
| (1 | ) |
Plan amendments |
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
Plan curtailments |
|
| — |
|
|
| (31 | ) |
|
| — |
|
|
| — |
|
Plan settlements |
|
| — |
|
|
| (94 | ) |
|
| — |
|
|
| — |
|
Foreign exchange rate changes |
|
| 2 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
Benefits paid |
|
| (88 | ) |
|
| (57 | ) |
|
| (3 | ) |
|
| (2 | ) |
Benefit obligation at end of year |
|
| 1,279 |
|
|
| 1,249 |
|
|
| 19 |
|
|
| 21 |
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
| 985 |
|
|
| 1,059 |
|
|
| — |
|
|
| — |
|
Actual return on plan assets |
|
| 122 |
|
|
| 61 |
|
|
| — |
|
|
| — |
|
Employer contributions |
|
| 14 |
|
|
| 16 |
|
|
| 2 |
|
|
| 2 |
|
Participant contributions |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
Plan settlements |
|
| — |
|
|
| (94 | ) |
|
| — |
|
|
| — |
|
Benefits paid |
|
| (88 | ) |
|
| (57 | ) |
|
| (3 | ) |
|
| (2 | ) |
Foreign exchange rate changes |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Fair value of plan assets at end of year |
|
| 1,035 |
|
|
| 985 |
|
|
| — |
|
|
| — |
|
Funded status at end of year |
| $ | (244 | ) |
| $ | (264 | ) |
| $ | (19 | ) |
| $ | (21 | ) |
Amounts recognized in balance sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term assets |
| $ | 4 |
|
| $ | 3 |
|
| $ | — |
|
| $ | — |
|
Other current liabilities |
|
| (13 | ) |
|
| (13 | ) |
|
| (3 | ) |
|
| (3 | ) |
Other long-term liabilities |
|
| (235 | ) |
|
| (254 | ) |
|
| (16 | ) |
|
| (18 | ) |
Net amount |
| $ | (244 | ) |
| $ | (264 | ) |
| $ | (19 | ) |
| $ | (21 | ) |
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain) |
| $ | 257 |
|
| $ | 285 |
|
| $ | (11 | ) |
| $ | (11 | ) |
Prior service cost (credit) |
|
| 6 |
|
|
| 8 |
|
|
| (3 | ) |
|
| (5 | ) |
Total |
| $ | 263 |
|
| $ | 293 |
|
| $ | (14 | ) |
| $ | (16 | ) |
Certain of Devon’s pension plans are unfunded and have a combined projected benefit obligation and accumulated benefit obligation of $239 million and $225 million, respectively, at December 31, 2017 and $234 million and $211 million, respectively, at December 31, 2016.
9688
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 |
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||||||||
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 15 |
|
| $ | 15 |
|
| $ | 33 |
|
| $ | — |
|
| $ | — |
|
| $ | 1 |
|
| $ | 10 |
|
| $ | 15 |
|
| $ | 15 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Interest cost |
|
| 42 |
|
|
| 42 |
|
|
| 52 |
|
|
| — |
|
|
| 1 |
|
|
| 1 |
|
|
| 39 |
|
|
| 42 |
|
|
| 42 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Expected return on plan assets |
|
| (54 | ) |
|
| (55 | ) |
|
| (58 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (49 | ) |
|
| (54 | ) |
|
| (55 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Recognition of net actuarial loss (gain) (1) |
|
| 19 |
|
|
| 25 |
|
|
| 20 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
|
| 13 |
|
|
| 19 |
|
|
| 25 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Recognition of prior service cost (1) |
|
| 2 |
|
|
| 3 |
|
|
| 4 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (2 | ) |
|
| 1 |
|
|
| 2 |
|
|
| 3 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
Total net periodic benefit cost (2) |
|
| 24 |
|
|
| 30 |
|
|
| 51 |
|
|
| (2 | ) |
|
| (1 | ) |
|
| (1 | ) |
|
| 14 |
|
|
| 24 |
|
|
| 30 |
|
|
| (2 | ) |
|
| (2 | ) |
|
| (1 | ) |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss (gain) arising in current year |
|
| (9 | ) |
|
| 26 |
|
|
| 5 |
|
|
| (1 | ) |
|
| — |
|
|
| (1 | ) |
|
| 4 |
|
|
| (9 | ) |
|
| 26 |
|
|
| (1 | ) |
|
| (1 | ) |
|
| — |
|
Prior service cost (credit) arising in current year |
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
| ||||||||||||||||||||||||
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost (3) |
|
| (19 | ) |
|
| (43 | ) |
|
| (20 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
| ||||||||||||||||||||||||
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 | ) |
|
| (9 | ) |
|
| (4 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
|
| (2 | ) |
|
| (2 | ) |
|
| (9 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Total other comprehensive loss (earnings) |
|
| (30 | ) |
|
| (24 | ) |
|
| (19 | ) |
|
| 1 |
|
|
| 2 |
|
|
| 2 |
|
|
| (58 | ) |
|
| (30 | ) |
|
| (24 | ) |
|
| 1 |
|
|
| 1 |
|
|
| 2 |
|
Total recognized |
| $ | (6 | ) |
| $ | 6 |
|
| $ | 32 |
|
| $ | (1 | ) |
| $ | 1 |
|
| $ | 1 |
|
| $ | (44 | ) |
| $ | (6 | ) |
| $ | 6 |
|
| $ | (1 | ) |
| $ | (1 | ) |
| $ | 1 |
|
(1) | These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. |
(2) |
|
(3) | These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note |
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 2018 are $14 million and $1 million, respectively.
Assumptions
|
| Pension Benefits |
|
| Postretirement Benefits |
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||||||||
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 3.59% |
|
|
| 4.07% |
|
|
| 4.25% |
|
| 3.25% |
|
|
| 3.46% |
|
|
| 3.63% |
|
| 4.21% |
|
| 3.59% |
|
| 4.07% |
|
| 4.01% |
|
| 3.25% |
|
| 3.46% |
| ||||||||
Rate of compensation increase |
| 2.50% |
|
|
| 4.49% |
|
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
|
| 2.50% |
|
| 2.50% |
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
| ||||||||||
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 4.08% |
|
|
| 4.39% |
|
|
| 3.90% |
|
| 3.46% |
|
|
| 3.63% |
|
| 3.25% |
| |||||||||||||||||||||||||||
Discount rate - service cost |
| 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 |
| 4.48% |
|
|
| 4.49% |
|
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
|
| 2.50% |
|
| 4.48% |
|
| 4.49% |
|
| N/A |
|
| N/A |
|
| N/A |
| ||||||||||
Expected return on plan assets |
| 5.69% |
|
|
| 5.20% |
| �� |
| 5.22% |
|
| N/A |
|
| N/A |
|
| N/A |
|
| 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.
97
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types.
Mortality rate – Devon utilized the Society of Actuaries produced mortality tables and an improvement scale derived from the updated tables 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 20172018 benefit obligation for the other postretirement medical plans, a 7.3%7.1% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018.2019. 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.
Expected Cash Flows
Devon expects benefit plan payments to average approximately $76$59 million a year for the next five years and $406$153 million total for the five years thereafter. Of these payments to be paid in 2018, $32019, $17 million is expected to be funded from Devon’s available cash, cash equivalents and cash equivalents.
other assets.
The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 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 32. 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 discussedshare repurchase program by an additional $1.0 billion, bringing the total to $5.0 billion. The share repurchase program expires December 31, 2019.
91
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 Note 3thousands).
|
| 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 dividends of $127 million, $221 million and $396 million during 2017, 2016 and 2015, respectively. stock.
| 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 |
|
|
|
|
|
In response to the depressed commodity price environment, Devon reduced the quarterly dividend rate from $0.24 to $0.06 per share in the second quarter of 2016.
Subsidiary Equity Transactions
EnLink has Devon increased the abilityquarterly dividend by 33% to sell common units through its “at$0.08 per share in the market” equity offering programs. In the thirdsecond quarter of 2017, EnLink entered into additional equity distribution agreements2018. In February 2019, Devon announced a 12.5% increase to sell upits quarterly dividend, to $600 million$0.09 per share, beginning in commonthe second quarter of 2019.
9892
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
units through
19. | Discontinued Operations and Assets Held For Sale |
On June 6, 2018, Devon announced that it had entered into an agreement to sell its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3 million common units through its “at the market” program and general public offerings, generating net proceeds of $107 million, $167 million and $25 million, respectively. During the first quarter of 2016, the General Partner issued common units in conjunction with the Anadarko Basin assets acquisition discussed in Note 3.
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 partneraggregate ownership interests in EnLink, raising net proceeds of $654 million.
In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds of approximately $394 million. As a result of these transactions and EnLink’s acquisition and dropdown activity discussed further in Note 3, the table below shows the ownership interest activity in the General Partner and EnLink for the last three years.
|
| EnLink |
|
| General Partner |
| ||||||||||||||
Ownership interest as of |
| Devon |
|
| Non-Devon Unitholders |
|
| General Partner |
|
| Devon |
|
| Non-Devon Unitholders |
| |||||
December 31, 2015 |
|
| 28% |
|
|
| 45% |
|
|
| 27% |
|
|
| 70% |
|
|
| 30% |
|
December 31, 2016 |
|
| 24% |
|
|
| 53% |
|
|
| 23% |
|
|
| 64% |
|
|
| 36% |
|
December 31, 2017 |
|
| 23% |
|
|
| 55% |
|
|
| 22% |
|
|
| 64% |
|
|
| 36% |
|
Distributions to Noncontrolling Interests
EnLink and the General Partner distributed $354for $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 $304 millionwith EnLink, which primarily related to gathering and $254 millionprocessing expenses. These net outflows represent gross cash amounts and not net working interest amounts.
Prior to non-Devon unitholders duringthe divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation.
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 2016are related to the divestiture of EnLink and 2015, respectively.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. TheseDevon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits typically assert various allegations, includingare claims that the producers and related partiesDevon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in the underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
99
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 material pending legal proceedings to which Devon is a party or to which any of its property is subject.
95
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commitments
The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2017.2018.
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 |
| |||||||||
2018 |
| $ | 613 |
|
| $ | 216 |
|
| $ | 1,159 |
|
| $ | 88 |
|
| $ | 53 |
| ||||||||||||||||
2019 |
|
| 577 |
|
|
| 109 |
|
|
| 562 |
|
|
| 84 |
|
|
| 36 |
|
| $ | 541 |
|
| $ | 274 |
|
| $ | 587 |
|
| $ | 64 |
|
2020 |
|
| 556 |
|
|
| 109 |
|
|
| 466 |
|
|
| 73 |
|
|
| 19 |
|
|
| 567 |
|
|
| 85 |
|
|
| 519 |
|
|
| 43 |
|
2021 |
|
| 134 |
|
|
| 51 |
|
|
| 366 |
|
|
| 61 |
|
|
| 18 |
|
|
| 140 |
|
|
| 48 |
|
|
| 373 |
|
|
| 31 |
|
2022 |
|
| — |
|
|
| 38 |
|
|
| 373 |
|
|
| 56 |
|
|
| 17 |
|
|
| — |
|
|
| 14 |
|
|
| 419 |
|
|
| 26 |
|
2023 |
|
| — |
|
|
| 8 |
|
|
| 354 |
|
|
| 25 |
| ||||||||||||||||||||
Thereafter |
|
| — |
|
|
| 106 |
|
|
| 3,242 |
|
|
| 19 |
|
|
| 90 |
|
|
| — |
|
|
| 16 |
|
|
| 3,374 |
|
|
| 311 |
|
Total |
| $ | 1,880 |
|
| $ | 629 |
|
| $ | 6,168 |
|
| $ | 381 |
|
| $ | 233 |
|
| $ | 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 recognized for operating leases, net of sublease income, was $67$11 million, $78$7 million and $88$11 million in 2018, 2017 2016 and 2015,2016, respectively.
10096
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, 20172018 and December 31, 2016,2017, 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 65, Note 14and Note 1817, 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 |
| ||||||||||||||||||||
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 |
| $ | 1,533 |
|
| $ | 1,533 |
|
| $ | 1,454 |
|
| $ | 79 |
|
| $ | 1,533 |
|
| $ | 1,533 |
|
| $ | 1,454 |
|
| $ | 79 |
|
Commodity derivatives |
| $ | 211 |
|
| $ | 211 |
|
| $ | — |
|
| $ | 211 |
|
| $ | 205 |
|
| $ | 205 |
|
| $ | — |
|
| $ | 205 |
|
Commodity derivatives |
| $ | (294 | ) |
| $ | (294 | ) |
| $ | — |
|
| $ | (294 | ) |
| $ | (286 | ) |
| $ | (286 | ) |
| $ | — |
|
| $ | (286 | ) |
Interest rate derivatives |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
Interest rate derivatives |
| $ | (64 | ) |
| $ | (64 | ) |
| $ | — |
|
| $ | (64 | ) |
| $ | (64 | ) |
| $ | (64 | ) |
| $ | — |
|
| $ | (64 | ) |
Debt |
| $ | (10,406 | ) |
| $ | (11,782 | ) |
| $ | — |
|
| $ | (11,782 | ) |
| $ | (6,864 | ) |
| $ | (8,131 | ) |
| $ | — |
|
| $ | (8,131 | ) |
Installment payment |
| $ | (250 | ) |
| $ | (250 | ) |
| $ | — |
|
| $ | (250 | ) | ||||||||||||||||
Capital lease obligations |
| $ | (4 | ) |
| $ | (3 | ) |
| $ | — |
|
| $ | (3 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
December 31, 2016 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Cash equivalents |
| $ | 1,542 |
|
| $ | 1,542 |
|
| $ | 1,298 |
|
| $ | 244 |
| ||||||||||||||||
Commodity derivatives |
| $ | 10 |
|
| $ | 10 |
|
| $ | — |
|
| $ | 10 |
| ||||||||||||||||
Commodity derivatives |
| $ | (203 | ) |
| $ | (203 | ) |
| $ | — |
|
| $ | (203 | ) | ||||||||||||||||
Interest rate derivatives |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
| ||||||||||||||||
Interest rate derivatives |
| $ | (41 | ) |
| $ | (41 | ) |
| $ | — |
|
| $ | (41 | ) | ||||||||||||||||
Debt |
| $ | (10,154 | ) |
| $ | (10,760 | ) |
| $ | — |
|
| $ | (10,760 | ) | ||||||||||||||||
Installment payment |
| $ | (473 | ) |
| $ | (477 | ) |
| $ | — |
|
| $ | (477 | ) | ||||||||||||||||
Capital lease obligations |
| $ | (7 | ) |
| $ | (6 | ) |
| $ | — |
|
| $ | (6 | ) | ||||||||||||||||
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.
101
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commodity and interest ratederivatives– The fair values of commodity and interest rate 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 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 2423.
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.
10298
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| U.S. (1) |
|
| Canada |
|
| EnLink (1) |
|
| Eliminations |
|
| Total |
| |||||
Year Ended December 31, 2017: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 7,326 |
|
| $ | 1,552 |
|
| $ | 5,071 |
|
| $ | — |
|
| $ | 13,949 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 669 |
|
| $ | (669 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 1,149 |
|
| $ | 380 |
|
| $ | 545 |
|
| $ | — |
|
| $ | 2,074 |
|
Asset impairments |
| $ | — |
|
| $ | — |
|
| $ | 17 |
|
| $ | — |
|
| $ | 17 |
|
Asset dispositions |
| $ | (218 | ) |
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | (217 | ) |
Interest expense |
| $ | 324 |
|
| $ | 69 |
|
| $ | 181 |
|
| $ | (57 | ) |
| $ | 517 |
|
Earnings before income taxes |
| $ | 500 |
|
| $ | 273 |
|
| $ | 123 |
|
| $ | — |
|
| $ | 896 |
|
Income tax expense (benefit) |
| $ | 9 |
|
| $ | 6 |
|
| $ | (197 | ) |
| $ | — |
|
| $ | (182 | ) |
Net earnings |
| $ | 491 |
|
| $ | 267 |
|
| $ | 320 |
|
| $ | — |
|
| $ | 1,078 |
|
Net earnings attributable to noncontrolling interests |
| $ | — |
|
| $ | — |
|
| $ | 180 |
|
| $ | — |
|
| $ | 180 |
|
Net earnings attributable to Devon |
| $ | 491 |
|
| $ | 267 |
|
| $ | 140 |
|
| $ | — |
|
| $ | 898 |
|
Property and equipment, net |
| $ | 10,274 |
|
| $ | 4,310 |
|
| $ | 6,587 |
|
| $ | — |
|
| $ | 21,171 |
|
Total assets |
| $ | 14,254 |
|
| $ | 5,498 |
|
| $ | 10,538 |
|
| $ | (49 | ) |
| $ | 30,241 |
|
Capital expenditures, including acquisitions |
| $ | 1,821 |
|
| $ | 348 |
|
| $ | 768 |
|
| $ | — |
|
| $ | 2,937 |
|
Year Ended December 31, 2016: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 5,722 |
|
| $ | 1,031 |
|
| $ | 3,551 |
|
| $ | — |
|
| $ | 10,304 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 701 |
|
| $ | (701 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 1,178 |
|
| $ | 414 |
|
| $ | 504 |
|
| $ | — |
|
| $ | 2,096 |
|
Asset impairments |
| $ | 435 |
|
| $ | 2 |
|
| $ | 873 |
|
| $ | — |
|
| $ | 1,310 |
|
Asset dispositions |
| $ | (955 | ) |
| $ | (541 | ) |
| $ | 13 |
|
| $ | — |
|
| $ | (1,483 | ) |
Restructuring and transaction costs |
| $ | 242 |
|
| $ | 19 |
|
| $ | 6 |
|
| $ | — |
|
| $ | 267 |
|
Interest expense |
| $ | 624 |
|
| $ | 184 |
|
| $ | 190 |
|
| $ | (84 | ) |
| $ | 914 |
|
Earnings (loss) before income taxes |
| $ | (673 | ) |
| $ | 240 |
|
| $ | (884 | ) |
| $ | — |
|
| $ | (1,317 | ) |
Income tax expense (benefit) |
| $ | (8 | ) |
| $ | 149 |
|
| $ | — |
|
| $ | — |
|
| $ | 141 |
|
Net earnings (loss) |
| $ | (665 | ) |
| $ | 91 |
|
| $ | (884 | ) |
| $ | — |
|
| $ | (1,458 | ) |
Net earnings (loss) attributable to noncontrolling interests |
| $ | 1 |
|
| $ | — |
|
| $ | (403 | ) |
| $ | — |
|
| $ | (402 | ) |
Net earnings (loss) attributable to Devon |
| $ | (666 | ) |
| $ | 91 |
|
| $ | (481 | ) |
| $ | — |
|
| $ | (1,056 | ) |
Property and equipment, net |
| $ | 10,166 |
|
| $ | 4,110 |
|
| $ | 6,257 |
|
| $ | — |
|
| $ | 20,533 |
|
Total assets |
| $ | 13,390 |
|
| $ | 5,071 |
|
| $ | 10,276 |
|
| $ | (62 | ) |
| $ | 28,675 |
|
Capital expenditures, including acquisitions |
| $ | 2,640 |
|
| $ | 186 |
|
| $ | 1,082 |
|
| $ | — |
|
| $ | 3,908 |
|
Year Ended December 31, 2015: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 8,360 |
|
| $ | 1,012 |
|
| $ | 3,773 |
|
| $ | — |
|
| $ | 13,145 |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 679 |
|
| $ | (679 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 3,164 |
|
| $ | 471 |
|
| $ | 387 |
|
| $ | — |
|
| $ | 4,022 |
|
Asset impairments |
| $ | 16,069 |
|
| $ | 15 |
|
| $ | 1,563 |
|
| $ | — |
|
| $ | 17,647 |
|
Asset dispositions |
| $ | (33 | ) |
| $ | 39 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 7 |
|
Restructuring and transaction costs |
| $ | 54 |
|
| $ | 24 |
|
| $ | — |
|
| $ | — |
|
| $ | 78 |
|
Interest expense |
| $ | 368 |
|
| $ | 97 |
|
| $ | 107 |
|
| $ | (46 | ) |
| $ | 526 |
|
Loss before income taxes |
| $ | (17,898 | ) |
| $ | (576 | ) |
| $ | (1,384 | ) |
| $ | — |
|
| $ | (19,858 | ) |
Income tax expense (benefit) |
| $ | (6,100 | ) |
| $ | (143 | ) |
| $ | 30 |
|
| $ | — |
|
| $ | (6,213 | ) |
Net loss |
| $ | (11,798 | ) |
| $ | (433 | ) |
| $ | (1,414 | ) |
| $ | — |
|
| $ | (13,645 | ) |
Net earnings (loss) attributable to noncontrolling interests |
| $ | 1 |
|
| $ | — |
|
| $ | (750 | ) |
| $ | — |
|
| $ | (749 | ) |
Net loss attributable to Devon |
| $ | (11,799 | ) |
| $ | (433 | ) |
| $ | (664 | ) |
| $ | — |
|
| $ | (12,896 | ) |
Property and equipment, net |
| $ | 10,357 |
|
| $ | 4,962 |
|
| $ | 5,667 |
|
| $ | — |
|
| $ | 20,986 |
|
Total assets |
| $ | 14,399 |
|
| $ | 5,830 |
|
| $ | 9,541 |
|
| $ | (97 | ) |
| $ | 29,673 |
|
Capital expenditures, including acquisitions |
| $ | 4,143 |
|
| $ | 591 |
|
| $ | 978 |
|
| $ | — |
|
| $ | 5,712 |
|
|
|
|
| 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.
103(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.
Included in this note are disclosures of Devon’s results of operations for oil and gas producing activities and standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. In conjunction with Devon’s oil and gas accounting policy change discussed in Note 1, Devon also modified its treatment of certain “production support” costs in these two disclosures. Production support costs consisted of labor, supervision, materials and supplies for oil and gas production monitoring and support activities, including information technology, accounting and certain other administrative support functions. These costs are included in G&A expenses in the accompanying consolidated comprehensive statements of earnings. Devon used a method to allocate these costs to its country-based results of operations and standardized measure disclosures. In 2016 and 2015, Devon’s results of operations disclosures included production support costs of $168 million and $224 million, respectively, and its standardized measure disclosures included estimated future production support costs of $2.8 billion and $2.7 billion, respectively.
Devon’s 2016 and 2015 disclosures have been revised to exclude these amounts.
Based on research conducted by Devon, diversity of practice has existed across peer companies regarding the treatment of production support costs in results of operations and standardized measure disclosures. Devon’s research of public filings indicates most companies exclude such costs from results of operations and standardized measure disclosures, but some companies appear to include such costs in their disclosures. Considering the apparent diversity of practice, Devon is making this disclosure change for two primary reasons. First, by converting to the successful efforts method of accounting and making this disclosure change, Devon’s results of operations and standardized measure disclosures will be most comparable to the vast majority of its peers. Second, allocating these costs to more granular common operating fields as opposed to country-based full cost pools is cost prohibitive and not materially important to investors and stakeholders, considering such allocated costs represented approximately 4% of Devon’s 2016 and 2015 oil, gas and NGL sales.
104100
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.
|
| Year Ended December 31, 2017 |
|
| Year Ended December 31, 2018 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
|
Unproved properties |
|
| 50 |
|
|
| 4 |
|
|
| 54 |
|
|
| 71 |
|
|
| — |
|
|
| 71 |
|
Exploration costs |
|
| 590 |
|
|
| 87 |
|
|
| 677 |
|
|
| 679 |
|
|
| 85 |
|
|
| 764 |
|
Development costs |
|
| 1,036 |
|
|
| 225 |
|
|
| 1,261 |
|
|
| 1,537 |
|
|
| 249 |
|
|
| 1,786 |
|
Costs incurred |
| $ | 1,678 |
|
| $ | 316 |
|
| $ | 1,994 |
|
| $ | 2,289 |
|
| $ | 334 |
|
| $ | 2,623 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2016 |
|
| Year Ended December 31, 2017 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| 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 |
|
| 282 |
|
|
| 78 |
|
|
| 360 |
|
|
| 590 |
|
|
| 87 |
|
|
| 677 |
|
Development costs |
|
| 875 |
|
|
| 54 |
|
|
| 929 |
|
|
| 1,036 |
|
|
| 225 |
|
|
| 1,261 |
|
Costs incurred |
| $ | 2,750 |
|
| $ | 134 |
|
| $ | 2,884 |
|
| $ | 1,678 |
|
| $ | 316 |
|
| $ | 1,994 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2015 |
|
| Year Ended December 31, 2016 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
| $ | 193 |
|
| $ | 2 |
|
| $ | 195 |
|
| $ | 237 |
|
| $ | — |
|
| $ | 237 |
|
Unproved properties |
|
| 635 |
|
|
| 81 |
|
|
| 716 |
|
|
| 1,356 |
|
|
| 2 |
|
|
| 1,358 |
|
Exploration costs |
|
| 432 |
|
|
| 120 |
|
|
| 552 |
|
|
| 282 |
|
|
| 78 |
|
|
| 360 |
|
Development costs |
|
| 2,982 |
|
|
| 351 |
|
|
| 3,333 |
|
|
| 875 |
|
|
| 54 |
|
|
| 929 |
|
Costs incurred |
| $ | 4,242 |
|
| $ | 554 |
|
| $ | 4,796 |
|
| $ | 2,750 |
|
| $ | 134 |
|
| $ | 2,884 |
|
Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.Additionally, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $41 million, $69 million and $61 million in 2018, 2017 and $52 million in 2017, 2016, and 2015, respectively.
101
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Results of Operations
The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including DD&A and after giving effect to permanent differences.
|
| Year Ended December 31, 2018 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 4,863 |
|
| $ | 814 |
|
| $ | 5,677 |
|
Production expenses |
|
| (1,620 | ) |
|
| (605 | ) |
|
| (2,225 | ) |
Exploration expenses |
|
| (129 | ) |
|
| (48 | ) |
|
| (177 | ) |
Depreciation, depletion and amortization |
|
| (1,234 | ) |
|
| (325 | ) |
|
| (1,559 | ) |
Asset dispositions |
|
| 262 |
|
|
| — |
|
|
| 262 |
|
Asset impairments |
|
| (109 | ) |
|
| — |
|
|
| (109 | ) |
Accretion of asset retirement obligations |
|
| (35 | ) |
|
| (24 | ) |
|
| (59 | ) |
Income tax (expense) benefit |
|
| (460 | ) |
|
| 51 |
|
|
| (409 | ) |
Results of operations |
| $ | 1,538 |
|
| $ | (137 | ) |
| $ | 1,401 |
|
Depreciation, depletion and amortization per Boe |
| $ | 8.08 |
|
| $ | 7.63 |
|
| $ | 7.98 |
|
105
|
| 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 |
|
102
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| December 31, 2017 |
| ||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 3,746 |
|
| $ | 1,404 |
|
| $ | 5,150 |
|
Production expenses |
|
| (1,232 | ) |
|
| (591 | ) |
|
| (1,823 | ) |
Exploration expenses |
|
| (346 | ) |
|
| (34 | ) |
|
| (380 | ) |
Depreciation, depletion and amortization |
|
| (1,050 | ) |
|
| (369 | ) |
|
| (1,419 | ) |
Asset dispositions |
|
| 211 |
|
|
| 1 |
|
|
| 212 |
|
Accretion of asset retirement obligations |
|
| (38 | ) |
|
| (24 | ) |
|
| (62 | ) |
Income tax expense |
|
| — |
|
|
| (104 | ) |
|
| (104 | ) |
Results of operations |
| $ | 1,291 |
|
| $ | 283 |
|
| $ | 1,574 |
|
Depreciation, depletion and amortization per Boe |
| $ | 6.97 |
|
| $ | 7.73 |
|
| $ | 7.15 |
|
|
| December 31, 2016 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 3,198 |
|
| $ | 984 |
|
| $ | 4,182 |
|
Production expenses |
|
| (1,311 | ) |
|
| (492 | ) |
|
| (1,803 | ) |
Exploration expenses |
|
| (176 | ) |
|
| (39 | ) |
|
| (215 | ) |
Depreciation, depletion and amortization |
|
| (1,066 | ) |
|
| (380 | ) |
|
| (1,446 | ) |
Asset dispositions |
|
| 946 |
|
|
| 1 |
|
|
| 947 |
|
Asset impairments |
|
| (435 | ) |
|
| — |
|
|
| (435 | ) |
Accretion of asset retirement obligations |
|
| (49 | ) |
|
| (26 | ) |
|
| (75 | ) |
Income tax expense |
|
| — |
|
|
| (13 | ) |
|
| (13 | ) |
Results of operations |
| $ | 1,107 |
|
| $ | 35 |
|
| $ | 1,142 |
|
Depreciation, depletion and amortization per Boe |
| $ | 6.11 |
|
| $ | 7.75 |
|
| $ | 6.47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| December 31, 2015 |
| |||||||||
|
| U.S. |
|
| Canada |
|
| Total |
| |||
Oil, gas and NGL sales |
| $ | 4,356 |
|
| $ | 1,026 |
|
| $ | 5,382 |
|
Production expenses |
|
| (1,853 | ) |
|
| (586 | ) |
|
| (2,439 | ) |
Exploration expenses |
|
| (323 | ) |
|
| (128 | ) |
|
| (451 | ) |
Depreciation, depletion and amortization |
|
| (3,051 | ) |
|
| (423 | ) |
|
| (3,474 | ) |
Asset dispositions |
|
| 32 |
|
|
| (39 | ) |
|
| (7 | ) |
Asset impairments |
|
| (16,061 | ) |
|
| (15 | ) |
|
| (16,076 | ) |
Accretion of asset retirement obligations |
|
| (47 | ) |
|
| (28 | ) |
|
| (75 | ) |
Income tax benefit |
|
| 5,783 |
|
|
| 50 |
|
|
| 5,833 |
|
Results of operations |
| $ | (11,164 | ) |
| $ | (143 | ) |
| $ | (11,307 | ) |
Depreciation, depletion and amortization per Boe |
| $ | 14.79 |
|
| $ | 10.08 |
|
| $ | 13.99 |
|
106
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents Devon’s estimated proved reserves by product and by country.
|
|
|
|
|
|
|
|
|
|
|
|
|
| Bitumen |
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Bitumen |
|
|
|
|
|
|
|
|
|
|
|
|
|
| NGL |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
| Oil (MMBbls) |
|
| (MMBbls) |
|
| Gas (Bcf) |
|
| (MMBbls) |
|
| Combined (MMBoe) (1) |
|
| Oil (MMBbls) |
|
| (MMBbls) |
|
| Gas (Bcf) |
|
| (MMBbls) |
|
| Combined (MMBoe) (1) |
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| Canada |
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| 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, 2014 |
|
| 351 |
|
|
| 23 |
|
|
| 374 |
|
|
| 521 |
|
|
| 7,651 |
|
|
| 36 |
|
|
| 7,687 |
|
|
| 578 |
|
|
| 2,205 |
|
|
| 549 |
|
|
| 2,754 |
| ||||||||||||||||||||||||||||||||||||||||||||
Revisions due to prices |
|
| (53 | ) |
|
| 4 |
|
|
| (49 | ) |
|
| 103 |
|
|
| (1,412 | ) |
|
| (9 | ) |
|
| (1,421 | ) |
|
| (119 | ) |
|
| (408 | ) |
|
| 106 |
|
|
| (302 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Revisions other than price |
|
| (52 | ) |
|
| 2 |
|
|
| (50 | ) |
|
| (84 | ) |
|
| (3 | ) |
|
| (6 | ) |
|
| (9 | ) |
|
| (6 | ) |
|
| (59 | ) |
|
| (83 | ) |
|
| (142 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Extensions and discoveries |
|
| 51 |
|
|
| 3 |
|
|
| 54 |
|
|
| 11 |
|
|
| 171 |
|
|
| — |
|
|
| 171 |
|
|
| 24 |
|
|
| 104 |
|
|
| 14 |
|
|
| 118 |
| ||||||||||||||||||||||||||||||||||||||||||||
Purchase of reserves |
|
| 5 |
|
|
| — |
|
|
| 5 |
|
|
| — |
|
|
| 17 |
|
|
| — |
|
|
| 17 |
|
|
| 1 |
|
|
| 9 |
|
|
| — |
|
|
| 9 |
| ||||||||||||||||||||||||||||||||||||||||||||
Production |
|
| (60 | ) |
|
| (10 | ) |
|
| (70 | ) |
|
| (31 | ) |
|
| (579 | ) |
|
| (8 | ) |
|
| (587 | ) |
|
| (50 | ) |
|
| (206 | ) |
|
| (42 | ) |
|
| (248 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Sale of reserves |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (37 | ) |
|
| — |
|
|
| (37 | ) |
|
| — |
|
|
| (7 | ) |
|
| — |
|
|
| (7 | ) | ||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 |
|
| 242 |
|
|
| 22 |
|
|
| 264 |
|
|
| 520 |
|
|
| 5,808 |
|
|
| 13 |
|
|
| 5,821 |
|
|
| 428 |
|
|
| 1,638 |
|
|
| 544 |
|
|
| 2,182 |
|
|
| 242 |
|
|
| 22 |
|
|
| 264 |
|
|
| 520 |
|
|
| 5,808 |
|
|
| 13 |
|
|
| 5,821 |
|
|
| 428 |
|
|
| 1,638 |
|
|
| 544 |
|
|
| 2,182 |
|
Revisions due to prices |
|
| (18 | ) |
|
| (2 | ) |
|
| (20 | ) |
|
| 23 |
|
|
| (103 | ) |
|
| — |
|
|
| (103 | ) |
|
| (13 | ) |
|
| (48 | ) |
|
| 21 |
|
|
| (27 | ) |
|
| (18 | ) |
|
| (2 | ) |
|
| (20 | ) |
|
| 23 |
|
|
| (103 | ) |
|
| — |
|
|
| (103 | ) |
|
| (13 | ) |
|
| (48 | ) |
|
| 21 |
|
|
| (27 | ) |
Revisions other than price |
|
| (2 | ) |
|
| 3 |
|
|
| 1 |
|
|
| (19 | ) |
|
| 628 |
|
|
| 10 |
|
|
| 638 |
|
|
| 48 |
|
|
| 151 |
|
|
| (14 | ) |
|
| 137 |
|
|
| (2 | ) |
|
| 3 |
|
|
| 1 |
|
|
| (19 | ) |
|
| 628 |
|
|
| 10 |
|
|
| 638 |
|
|
| 48 |
|
|
| 151 |
|
|
| (14 | ) |
|
| 137 |
|
Extensions and discoveries |
|
| 36 |
|
|
| 2 |
|
|
| 38 |
|
|
| — |
|
|
| 280 |
|
|
| — |
|
|
| 280 |
|
|
| 42 |
|
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
|
| 36 |
|
|
| 2 |
|
|
| 38 |
|
|
| — |
|
|
| 280 |
|
|
| — |
|
|
| 280 |
|
|
| 42 |
|
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
Purchase of reserves |
|
| 8 |
|
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 33 |
|
|
| — |
|
|
| 33 |
|
|
| 7 |
|
|
| 20 |
|
|
| — |
|
|
| 20 |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 33 |
|
|
| — |
|
|
| 33 |
|
|
| 7 |
|
|
| 20 |
|
|
| — |
|
|
| 20 |
|
Production |
|
| (47 | ) |
|
| (8 | ) |
|
| (55 | ) |
|
| (40 | ) |
|
| (510 | ) |
|
| (7 | ) |
|
| (517 | ) |
|
| (42 | ) |
|
| (174 | ) |
|
| (49 | ) |
|
| (223 | ) |
|
| (47 | ) |
|
| (8 | ) |
|
| (55 | ) |
|
| (40 | ) |
|
| (510 | ) |
|
| (7 | ) |
|
| (517 | ) |
|
| (42 | ) |
|
| (174 | ) |
|
| (49 | ) |
|
| (223 | ) |
Sale of reserves |
|
| (25 | ) |
|
| — |
|
|
| (25 | ) |
|
| — |
|
|
| (521 | ) |
|
| — |
|
|
| (521 | ) |
|
| (45 | ) |
|
| (157 | ) |
|
| — |
|
|
| (157 | ) |
|
| (25 | ) |
|
| — |
|
|
| (25 | ) |
|
| — |
|
|
| (521 | ) |
|
| — |
|
|
| (521 | ) |
|
| (45 | ) |
|
| (157 | ) |
|
| — |
|
|
| (157 | ) |
December 31, 2016 |
|
| 194 |
|
|
| 17 |
|
|
| 211 |
|
|
| 484 |
|
|
| 5,615 |
|
|
| 16 |
|
|
| 5,631 |
|
|
| 425 |
|
|
| 1,554 |
|
|
| 504 |
|
|
| 2,058 |
|
|
| 194 |
|
|
| 17 |
|
|
| 211 |
|
|
| 484 |
|
|
| 5,615 |
|
|
| 16 |
|
|
| 5,631 |
|
|
| 425 |
|
|
| 1,554 |
|
|
| 504 |
|
|
| 2,058 |
|
Revisions due to prices |
|
| 12 |
|
|
| (1 | ) |
|
| 11 |
|
|
| (37 | ) |
|
| 398 |
|
|
| 1 |
|
|
| 399 |
|
|
| 32 |
|
|
| 111 |
|
|
| (38 | ) |
|
| 73 |
|
|
| 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 | ) |
|
| 6 |
|
|
| 2 |
|
|
| 8 |
|
|
| (10 | ) |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
|
| (10 | ) |
|
| (5 | ) |
|
| (7 | ) |
|
| (12 | ) |
Extensions and discoveries |
|
| 90 |
|
|
| 4 |
|
|
| 94 |
|
|
| 12 |
|
|
| 403 |
|
|
| — |
|
|
| 403 |
|
|
| 63 |
|
|
| 221 |
|
|
| 16 |
|
|
| 237 |
|
|
| 90 |
|
|
| 4 |
|
|
| 94 |
|
|
| 12 |
|
|
| 403 |
|
|
| — |
|
|
| 403 |
|
|
| 63 |
|
|
| 221 |
|
|
| 16 |
|
|
| 237 |
|
Production |
|
| (42 | ) |
|
| (7 | ) |
|
| (49 | ) |
|
| (40 | ) |
|
| (433 | ) |
|
| (6 | ) |
|
| (439 | ) |
|
| (36 | ) |
|
| (150 | ) |
|
| (48 | ) |
|
| (198 | ) |
|
| (42 | ) |
|
| (7 | ) |
|
| (49 | ) |
|
| (40 | ) |
|
| (433 | ) |
|
| (6 | ) |
|
| (439 | ) |
|
| (36 | ) |
|
| (150 | ) |
|
| (48 | ) |
|
| (198 | ) |
Sale of reserves |
|
| (3 | ) |
|
| — |
|
|
| (3 | ) |
|
| — |
|
|
| (9 | ) |
|
| — |
|
|
| (9 | ) |
|
| (1 | ) |
|
| (6 | ) |
|
| — |
|
|
| (6 | ) |
|
| (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 |
|
|
| 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, 2014 |
|
| 255 |
|
|
| 23 |
|
|
| 278 |
|
|
| 137 |
|
|
| 6,948 |
|
|
| 36 |
|
|
| 6,984 |
|
|
| 486 |
|
|
| 1,900 |
|
|
| 165 |
|
|
| 2,065 |
| ||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 |
|
| 203 |
|
|
| 22 |
|
|
| 225 |
|
|
| 219 |
|
|
| 5,694 |
|
|
| 13 |
|
|
| 5,707 |
|
|
| 411 |
|
|
| 1,563 |
|
|
| 243 |
|
|
| 1,806 |
|
|
| 203 |
|
|
| 22 |
|
|
| 225 |
|
|
| 219 |
|
|
| 5,694 |
|
|
| 13 |
|
|
| 5,707 |
|
|
| 411 |
|
|
| 1,563 |
|
|
| 243 |
|
|
| 1,806 |
|
December 31, 2016 |
|
| 160 |
|
|
| 17 |
|
|
| 177 |
|
|
| 190 |
|
|
| 5,361 |
|
|
| 16 |
|
|
| 5,377 |
|
|
| 387 |
|
|
| 1,439 |
|
|
| 210 |
|
|
| 1,649 |
|
|
| 160 |
|
|
| 17 |
|
|
| 177 |
|
|
| 190 |
|
|
| 5,361 |
|
|
| 16 |
|
|
| 5,377 |
|
|
| 387 |
|
|
| 1,439 |
|
|
| 210 |
|
|
| 1,649 |
|
December 31, 2017 |
|
| 178 |
|
|
| 15 |
|
|
| 193 |
|
|
| 200 |
|
|
| 5,619 |
|
|
| 13 |
|
|
| 5,632 |
|
|
| 410 |
|
|
| 1,524 |
|
|
| 218 |
|
|
| 1,742 |
|
|
| 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, 2014 |
|
| 224 |
|
|
| 19 |
|
|
| 243 |
|
|
| 137 |
|
|
| 6,746 |
|
|
| 34 |
|
|
| 6,780 |
|
|
| 467 |
|
|
| 1,815 |
|
|
| 162 |
|
|
| 1,977 |
| ||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 |
|
| 192 |
|
|
| 19 |
|
|
| 211 |
|
|
| 219 |
|
|
| 5,546 |
|
|
| 13 |
|
|
| 5,559 |
|
|
| 393 |
|
|
| 1,509 |
|
|
| 240 |
|
|
| 1,749 |
|
|
| 192 |
|
|
| 19 |
|
|
| 211 |
|
|
| 219 |
|
|
| 5,546 |
|
|
| 13 |
|
|
| 5,559 |
|
|
| 393 |
|
|
| 1,509 |
|
|
| 240 |
|
|
| 1,749 |
|
December 31, 2016 |
|
| 143 |
|
|
| 13 |
|
|
| 156 |
|
|
| 190 |
|
|
| 5,243 |
|
|
| 16 |
|
|
| 5,259 |
|
|
| 370 |
|
|
| 1,386 |
|
|
| 207 |
|
|
| 1,593 |
|
|
| 143 |
|
|
| 13 |
|
|
| 156 |
|
|
| 190 |
|
|
| 5,243 |
|
|
| 16 |
|
|
| 5,259 |
|
|
| 370 |
|
|
| 1,386 |
|
|
| 207 |
|
|
| 1,593 |
|
December 31, 2017 |
|
| 165 |
|
|
| 12 |
|
|
| 177 |
|
|
| 197 |
|
|
| 5,512 |
|
|
| 13 |
|
|
| 5,525 |
|
|
| 397 |
|
|
| 1,481 |
|
|
| 212 |
|
|
| 1,693 |
|
|
| 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, 2014 |
|
| 96 |
|
|
| — |
|
|
| 96 |
|
|
| 384 |
|
|
| 703 |
|
|
| — |
|
|
| 703 |
|
|
| 92 |
|
|
| 305 |
|
|
| 384 |
|
|
| 689 |
| ||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 |
|
| 39 |
|
|
| — |
|
|
| 39 |
|
|
| 301 |
|
|
| 114 |
|
|
| — |
|
|
| 114 |
|
|
| 17 |
|
|
| 75 |
|
|
| 301 |
|
|
| 376 |
|
|
| 39 |
|
|
| — |
|
|
| 39 |
|
|
| 301 |
|
|
| 114 |
|
|
| — |
|
|
| 114 |
|
|
| 17 |
|
|
| 75 |
|
|
| 301 |
|
|
| 376 |
|
December 31, 2016 |
|
| 34 |
|
|
| — |
|
|
| 34 |
|
|
| 294 |
|
|
| 254 |
|
|
| — |
|
|
| 254 |
|
|
| 38 |
|
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
|
| 34 |
|
|
| — |
|
|
| 34 |
|
|
| 294 |
|
|
| 254 |
|
|
| — |
|
|
| 254 |
|
|
| 38 |
|
|
| 115 |
|
|
| 294 |
|
|
| 409 |
|
December 31, 2017 |
|
| 79 |
|
|
| — |
|
|
| 79 |
|
|
| 209 |
|
|
| 355 |
|
|
| — |
|
|
| 355 |
|
|
| 63 |
|
|
| 201 |
|
|
| 209 |
|
|
| 410 |
|
|
| 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. |
107103
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 20172018 (MMBoe).
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||
Proved undeveloped reserves as of December 31, 2016 |
|
| 115 |
|
|
| 294 |
|
|
| 409 |
| ||||||||||||
Proved undeveloped reserves as of December 31, 2017 |
|
| 201 |
|
|
| 209 |
|
|
| 410 |
| ||||||||||||
Extensions and discoveries |
|
| 116 |
|
|
| 12 |
|
|
| 128 |
|
|
| 107 |
|
|
| 6 |
|
|
| 113 |
|
Revisions due to prices |
|
| — |
|
|
| (27 | ) |
|
| (27 | ) |
|
| 1 |
|
|
| 6 |
|
|
| 7 |
|
Revisions other than price |
|
| (21 | ) |
|
| (6 | ) |
|
| (27 | ) |
|
| (8 | ) |
|
| (15 | ) |
|
| (23 | ) |
Sale of reserves |
|
| (10 | ) |
|
| — |
|
|
| (10 | ) | ||||||||||||
Conversion to proved developed reserves |
|
| (9 | ) |
|
| (64 | ) |
|
| (73 | ) |
|
| (52 | ) |
|
| — |
|
|
| (52 | ) |
Proved undeveloped reserves as of December 31, 2017 |
|
| 201 |
|
|
| 209 |
|
|
| 410 |
| ||||||||||||
Proved undeveloped reserves as of December 31, 2018 |
|
| 239 |
|
|
| 206 |
|
|
| 445 |
| ||||||||||||
Total proved undeveloped reserves remained consistentincreased 9% from 20162017 to 20172018 with the year-end 20172018 balance representing 19%23% of total proved reserves. Devon’s focus on drilling and development activities in the STACK and Delaware Basin was the primary driver of the 128113 MMBoe increase in extensions and discoveries. Continued development primarily at Jackfishin the STACK and Delaware Basin led to the conversion of 7352 MMBoe, or 18%26%, of the 20162017 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $237$691 million for 2017.2018.
A significant amount of Devon’s proved undeveloped reserves at the end of 20172018 related to its Jackfish operations. At December 31, 20172018 and 2016,2017, Devon’s Jackfish proved undeveloped reserves were 209206 MMBoe and 294209 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 five years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends through 2028.2032. At the end of 2017,2018, approximately 196125 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 8881 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 itsthe royalties, which decreases itsthe after-royalty volumes.
Reserves decreased 27 MMBoe and 302 MMBoe during 2016 and 2015, respectively, primarily due to lower commodity prices for oil and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes.
108
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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 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.
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 which was primarily related to the STACK.
2016 – Of the 126 MMBoe of extensions and discoveries, 97 MMBoe related to STACK, 18 MMBoe related to the Delaware Basin and 7 MMBoe related to the Eagle Ford.
The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling activities primarily consisting of 73 MMBoe related to STACK.
2015 – Of the 118 MMBoe of extensions and discoveries, 38 MMBoe related to the Delaware Basin, 30 MMBoe related to the Anadarko Basin, 21 MMBoe related to the Eagle Ford 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.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.
Sale of Reserves
2017 – Related to Devon’s non-core asset divestitures in the U.S. as discussed further in Note 3.
2016 – Related to Devon’s non-core upstream asset divestitures discussed further in Note 3.
109105
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, 2017 |
|
| Year Ended December 31, 2018 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||
Future cash inflows |
| $ | 34,701 |
|
| $ | 13,602 |
|
| $ | 48,303 |
|
| $ | 40,183 |
|
| $ | 9,146 |
|
| $ | 49,329 |
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
| (3,316 | ) |
|
| (1,853 | ) |
|
| (5,169 | ) |
|
| (3,444 | ) |
|
| (1,558 | ) |
|
| (5,002 | ) |
Production |
|
| (15,526 | ) |
|
| (5,986 | ) |
|
| (21,512 | ) |
|
| (18,107 | ) |
|
| (5,445 | ) |
|
| (23,552 | ) |
Future income tax expense |
|
| — |
|
|
| (988 | ) |
|
| (988 | ) |
|
| (2,969 | ) |
|
| — |
|
|
| (2,969 | ) |
Future net cash flow |
|
| 15,859 |
|
|
| 4,775 |
|
|
| 20,634 |
|
|
| 15,663 |
|
|
| 2,143 |
|
|
| 17,806 |
|
10% discount to reflect timing of cash flows |
|
| (7,541 | ) |
|
| (1,756 | ) |
|
| (9,297 | ) |
|
| (6,897 | ) |
|
| (717 | ) |
|
| (7,614 | ) |
Standardized measure of discounted future net cash flows |
| $ | 8,318 |
|
| $ | 3,019 |
|
| $ | 11,337 |
|
| $ | 8,766 |
|
| $ | 1,426 |
|
| $ | 10,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2016 |
|
| Year Ended December 31, 2017 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| 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 |
|
| (11,934 | ) |
|
| (6,049 | ) |
|
| (17,983 | ) |
|
| (15,526 | ) |
|
| (5,986 | ) |
|
| (21,512 | ) |
Future income tax expense |
|
| — |
|
|
| (121 | ) |
|
| (121 | ) |
|
| — |
|
|
| (988 | ) |
|
| (988 | ) |
Future net cash flow |
|
| 8,129 |
|
|
| 1,301 |
|
|
| 9,430 |
|
|
| 15,859 |
|
|
| 4,775 |
|
|
| 20,634 |
|
10% discount to reflect timing of cash flows |
|
| (3,524 | ) |
|
| (466 | ) |
|
| (3,990 | ) |
|
| (7,541 | ) |
|
| (1,756 | ) |
|
| (9,297 | ) |
Standardized measure of discounted future net cash flows |
| $ | 4,605 |
|
| $ | 835 |
|
| $ | 5,440 |
|
| $ | 8,318 |
|
| $ | 3,019 |
|
| $ | 11,337 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended December 31, 2015 |
|
| Year Ended December 31, 2016 |
| ||||||||||||||||||
|
| U.S. |
|
| Canada |
|
| Total |
|
| U.S. |
|
| Canada |
|
| Total |
| ||||||
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 |
|
| (14,938 | ) |
|
| (6,501 | ) |
|
| (21,439 | ) |
|
| (11,934 | ) |
|
| (6,049 | ) |
|
| (17,983 | ) |
Future income tax expense |
|
| — |
|
|
| (580 | ) |
|
| (580 | ) |
|
| — |
|
|
| (121 | ) |
|
| (121 | ) |
Future net cash flow |
|
| 9,154 |
|
|
| 3,207 |
|
|
| 12,361 |
|
|
| 8,129 |
|
|
| 1,301 |
|
|
| 9,430 |
|
10% discount to reflect timing of cash flows |
|
| (3,230 | ) |
|
| (1,248 | ) |
|
| (4,478 | ) |
|
| (3,524 | ) |
|
| (466 | ) |
|
| (3,990 | ) |
Standardized measure of discounted future net cash flows |
| $ | 5,924 |
|
| $ | 1,959 |
|
| $ | 7,883 |
|
| $ | 4,605 |
|
| $ | 835 |
|
| $ | 5,440 |
|
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 20172018 estimates, Devon’s future realized prices were assumed to be $47.86$58.64 per Bbl of oil, $31.86$22.12 per Bbl of bitumen, $2.43$2.45 per Mcf of gas and $16.25$24.72 per Bbl of NGLs. Of the $5.2$5.0 billion of future development costs as of the end of 2017, $0.92018, $1.2 billion, $0.8$0.6 billion and $0.5$0.3 billion are estimated to be spent in 2018, 2019, 2020 and 2020,2021, respectively.
106
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 $5.2$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.
110
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2018 |
|
| 2017 |
|
| 2016 |
| ||||||
Beginning balance |
| $ | 5,440 |
|
| $ | 7,883 |
|
| $ | 21,583 |
|
| $ | 11,337 |
|
| $ | 5,440 |
|
| $ | 7,883 |
|
Net changes in prices and production costs |
|
| 5,218 |
|
|
| (2,027 | ) |
|
| (21,330 | ) |
|
| (243 | ) |
|
| 5,218 |
|
|
| (2,027 | ) |
Oil, bitumen, gas and NGL sales, net of production costs |
|
| (3,327 | ) |
|
| (2,379 | ) |
|
| (2,943 | ) |
|
| (3,452 | ) |
|
| (3,327 | ) |
|
| (2,377 | ) |
Changes in estimated future development costs |
|
| 789 |
|
|
| 112 |
|
|
| 1,313 |
|
|
| (216 | ) |
|
| 789 |
|
|
| 112 |
|
Extensions and discoveries, net of future development costs |
|
| 2,497 |
|
|
| 674 |
|
|
| 1,102 |
|
|
| 3,139 |
|
|
| 2,497 |
|
|
| 674 |
|
Purchase of reserves |
|
| 2 |
|
|
| 224 |
|
|
| 93 |
|
|
| — |
|
|
| 2 |
|
|
| 224 |
|
Sales of reserves in place |
|
| (3 | ) |
|
| (577 | ) |
|
| (77 | ) |
|
| (588 | ) |
|
| (3 | ) |
|
| (577 | ) |
Revisions of quantity estimates |
|
| (318 | ) |
|
| (21 | ) |
|
| (1,312 | ) |
|
| (414 | ) |
|
| (318 | ) |
|
| (21 | ) |
Previously estimated development costs incurred during the period |
|
| 559 |
|
|
| 663 |
|
|
| 2,158 |
|
|
| 962 |
|
|
| 559 |
|
|
| 663 |
|
Accretion of discount |
|
| 1,034 |
|
|
| 537 |
|
|
| 702 |
|
|
| 960 |
|
|
| 1,034 |
|
|
| 537 |
|
Foreign exchange and other |
|
| (7 | ) |
|
| 74 |
|
|
| (1,148 | ) |
|
| (329 | ) |
|
| (7 | ) |
|
| 72 |
|
Net change in income taxes |
|
| (547 | ) |
|
| 277 |
|
|
| 7,742 |
|
|
| (964 | ) |
|
| (547 | ) |
|
| 277 |
|
Ending balance |
| $ | 11,337 |
|
| $ | 5,440 |
|
| $ | 7,883 |
|
| $ | 10,192 |
|
| $ | 11,337 |
|
| $ | 5,440 |
|
24. | Supplemental Quarterly Financial Information (Unaudited) |
The following tables present a summary of Devon’s unaudited interim results of operations.
|
| 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. |
111107
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| 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 following tables present a summary of Devon’s unaudited interim results of operations as recast under the successful efforts method of accounting. See Note 2 for additional details. As a result of the conversion to the successful efforts method of accounting in the fourth quarter of 2017, Devon has provided the full consolidated comprehensive statements of earnings for each interim quarter in 2017 to aid investors and facilitate comparative periods to be shown during 2018. Devon has provided the required summary information for each interim quarter in 2016.
|
| 2017, under Successful Efforts |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Upstream revenues |
| $ | 1,541 |
|
| $ | 1,332 |
|
| $ | 1,101 |
|
| $ | 1,333 |
|
| $ | 5,307 |
|
Marketing and midstream revenues |
|
| 2,010 |
|
|
| 1,927 |
|
|
| 2,055 |
|
|
| 2,650 |
|
|
| 8,642 |
|
Total revenues |
|
| 3,551 |
|
|
| 3,259 |
|
|
| 3,156 |
|
|
| 3,983 |
|
|
| 13,949 |
|
Production expenses |
|
| 457 |
|
|
| 455 |
|
|
| 448 |
|
|
| 463 |
|
|
| 1,823 |
|
Exploration expenses |
|
| 95 |
|
|
| 57 |
|
|
| 57 |
|
|
| 171 |
|
|
| 380 |
|
Marketing and midstream expenses |
|
| 1,814 |
|
|
| 1,714 |
|
|
| 1,824 |
|
|
| 2,378 |
|
|
| 7,730 |
|
Depreciation, depletion and amortization |
|
| 528 |
|
|
| 506 |
|
|
| 512 |
|
|
| 528 |
|
|
| 2,074 |
|
Asset impairments |
|
| 7 |
|
|
| — |
|
|
| 2 |
|
|
| 8 |
|
|
| 17 |
|
Asset dispositions |
|
| (3 | ) |
|
| (27 | ) |
|
| (169 | ) |
|
| (18 | ) |
|
| (217 | ) |
General and administrative expenses |
|
| 233 |
|
|
| 214 |
|
|
| 203 |
|
|
| 222 |
|
|
| 872 |
|
Financing costs, net |
|
| 128 |
|
|
| 116 |
|
|
| 128 |
|
|
| 126 |
|
|
| 498 |
|
Other expenses |
|
| (33 | ) |
|
| (20 | ) |
|
| (76 | ) |
|
| 5 |
|
|
| (124 | ) |
Total expenses |
|
| 3,226 |
|
|
| 3,015 |
|
|
| 2,929 |
|
|
| 3,883 |
|
|
| 13,053 |
|
Earnings before income taxes |
|
| 325 |
|
|
| 244 |
|
|
| 227 |
|
|
| 100 |
|
|
| 896 |
|
Income tax expense (benefit) |
|
| 8 |
|
|
| (1 | ) |
|
| 15 |
|
|
| (204 | ) |
|
| (182 | ) |
Net earnings |
|
| 317 |
|
|
| 245 |
|
|
| 212 |
|
|
| 304 |
|
|
| 1,078 |
|
Net earnings attributable to noncontrolling interests |
|
| 14 |
|
|
| 26 |
|
|
| 19 |
|
|
| 121 |
|
|
| 180 |
|
Net earnings attributable to Devon |
| $ | 303 |
|
| $ | 219 |
|
| $ | 193 |
|
| $ | 183 |
|
| $ | 898 |
|
Net earnings per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | 0.58 |
|
| $ | 0.41 |
|
| $ | 0.37 |
|
| $ | 0.35 |
|
| $ | 1.71 |
|
Diluted |
| $ | 0.58 |
|
| $ | 0.41 |
|
| $ | 0.37 |
|
| $ | 0.35 |
|
| $ | 1.70 |
|
Comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
| $ | 317 |
|
| $ | 245 |
|
| $ | 212 |
|
| $ | 304 |
|
| $ | 1,078 |
|
Other comprehensive earnings, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation and other |
|
| 8 |
|
|
| 28 |
|
|
| 42 |
|
|
| 5 |
|
|
| 83 |
|
Pension and postretirement plans |
|
| 5 |
|
|
| 4 |
|
|
| 5 |
|
|
| 15 |
|
|
| 29 |
|
Other comprehensive earnings, net of tax |
|
| 13 |
|
|
| 32 |
|
|
| 47 |
|
|
| 20 |
|
|
| 112 |
|
Comprehensive earnings |
|
| 330 |
|
|
| 277 |
|
|
| 259 |
|
|
| 324 |
|
|
| 1,190 |
|
Comprehensive earnings attributable to noncontrolling interests |
|
| 14 |
|
|
| 26 |
|
|
| 19 |
|
|
| 121 |
|
|
| 180 |
|
Comprehensive earnings attributable to Devon |
| $ | 316 |
|
| $ | 251 |
|
| $ | 240 |
|
| $ | 203 |
|
| $ | 1,010 |
|
(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. |
112
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| 2016, under Successful Efforts |
| ||||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 2,126 |
|
| $ | 2,488 |
|
| $ | 2,882 |
|
| $ | 2,808 |
|
| $ | 10,304 |
|
Earnings (loss) before income taxes |
| $ | (2,036 | ) |
| $ | (339 | ) |
| $ | 787 |
|
| $ | 271 |
|
| $ | (1,317 | ) |
Net earnings (loss) attributable to Devon |
| $ | (1,550 | ) |
| $ | (326 | ) |
| $ | 613 |
|
| $ | 207 |
|
| $ | (1,056 | ) |
Basic net earnings (loss) per share attributable to Devon |
| $ | (3.27 | ) |
| $ | (0.63 | ) |
| $ | 1.17 |
|
| $ | 0.41 |
|
| $ | (2.09 | ) |
Diluted net earnings (loss) per share attributable to Devon |
| $ | (3.27 | ) |
| $ | (0.63 | ) |
| $ | 1.16 |
|
| $ | 0.41 |
|
| $ | (2.09 | ) |
The 2017 results include gains from asset dispositions of approximately $217 million (or $0.42 per diluted share), as discussed in Note 3.
The 2016 results include asset impairments of $1.2 billion (or $2.59 per diluted share) and $81 million (or $0.15 per diluted share), during the first quarter and the fourth quarter of 2016, respectively, as discussed in Note 6. Additionally, the 2016 quarterly results include gains from asset dispositions of approximately $3 million (or $0.01 per diluted share), $75 million (or $0.14 per diluted share), $830 million (or $1.59 per diluted share) and $575 million (or $1.10 per diluted share) during the first quarter through the fourth quarter of 2016, respectively, as discussed in Note 3.
The following tables present a summary of Devon’s quarterly consolidated comprehensive statements of earnings information for 2017 and 2016 reported under the full cost method.
|
| 2017, under Full Cost |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 3,551 |
|
| $ | 3,259 |
|
| $ | 3,156 |
|
| $ | 3,983 |
|
| $ | 13,949 |
|
Earnings before income taxes |
| $ | 598 |
|
| $ | 458 |
|
| $ | 272 |
|
| $ | 403 |
|
| $ | 1,731 |
|
Net earnings attributable to Devon |
| $ | 565 |
|
| $ | 425 |
|
| $ | 228 |
|
| $ | 473 |
|
| $ | 1,691 |
|
Basic net earnings per share attributable to Devon |
| $ | 1.08 |
|
| $ | 0.81 |
|
| $ | 0.43 |
|
| $ | 0.90 |
|
| $ | 3.22 |
|
Diluted net earnings per share attributable to Devon |
| $ | 1.07 |
|
| $ | 0.80 |
|
| $ | 0.43 |
|
| $ | 0.89 |
|
| $ | 3.20 |
|
|
| 2016, under Full Cost |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Total revenues |
| $ | 2,126 |
|
| $ | 2,488 |
|
| $ | 2,882 |
|
| $ | 2,808 |
|
| $ | 10,304 |
|
Earnings (loss) before income taxes |
| $ | (3,685 | ) |
| $ | (1,745 | ) |
| $ | 1,178 |
|
| $ | 375 |
|
| $ | (3,877 | ) |
Net earnings (loss) attributable to Devon |
| $ | (3,056 | ) |
| $ | (1,570 | ) |
| $ | 993 |
|
| $ | 331 |
|
| $ | (3,302 | ) |
Basic net earnings (loss) per share attributable to Devon |
| $ | (6.44 | ) |
| $ | (3.04 | ) |
| $ | 1.90 |
|
| $ | 0.63 |
|
| $ | (6.52 | ) |
Diluted net earnings (loss) per share attributable to Devon |
| $ | (6.44 | ) |
| $ | (3.04 | ) |
| $ | 1.89 |
|
| $ | 0.63 |
|
| $ | (6.52 | ) |
113
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents a summary of Devon’s quarterly cash flow information as recast under the successful efforts method of accounting. See Note 2 for additional details. Devon has provided this information for each interim quarter in 2017 to aid investors and facilitate comparative periods to be shown during 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
| 2017 |
| |||||||||||||||||
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
|
| Full Year |
| |||||
Net earnings |
| $ | 317 |
|
| $ | 245 |
|
| $ | 212 |
|
| $ | 304 |
|
| $ | 1,078 |
|
Net cash from operating activities |
|
| 746 |
|
|
| 738 |
|
|
| 700 |
|
|
| 725 |
|
|
| 2,909 |
|
Net cash from investing activities |
|
| (454 | ) |
|
| (587 | ) |
|
| (457 | ) |
|
| (712 | ) |
|
| (2,210 | ) |
Net cash from financing activities |
|
| (124 | ) |
|
| 91 |
|
|
| 157 |
|
|
| (115 | ) |
|
| 9 |
|
Effect of exchange rate changes on cash |
|
| (8 | ) |
|
| 8 |
|
|
| 12 |
|
|
| (6 | ) |
|
| 6 |
|
Net change in cash and cash equivalents |
|
| 160 |
|
|
| 250 |
|
|
| 412 |
|
|
| (108 | ) |
|
| 714 |
|
Cash and cash equivalents at beginning of period |
|
| 1,959 |
|
|
| 2,119 |
|
|
| 2,369 |
|
|
| 2,781 |
|
|
| 1,959 |
|
Cash and cash equivalents at end of period |
| $ | 2,119 |
|
| $ | 2,369 |
|
| $ | 2,781 |
|
| $ | 2,673 |
|
| $ | 2,673 |
|
Effects of Accounting Change on Fourth Quarter
As Devon recast the financial statements due to a change in accounting principle during the fourth quarter of 2017, the effects of the accounting change on the fourth quarter consolidated comprehensive statement of earnings and consolidated statement of cash flow are included below. See Note 2 for additional details.
|
| Changes to the Consolidated Comprehensive |
| |||||||||
|
| Statement of Earnings |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Quarter Ended December 31, 2017 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Exploration expenses |
| $ | — |
|
| $ | 171 |
|
| $ | 171 |
|
Depreciation, depletion and amortization |
|
| 417 |
|
|
| 111 |
|
|
| 528 |
|
Asset dispositions |
|
| 1 |
|
|
| (19 | ) |
|
| (18 | ) |
General and administrative expenses |
|
| 174 |
|
|
| 48 |
|
|
| 222 |
|
Financing costs, net |
|
| 124 |
|
|
| 2 |
|
|
| 126 |
|
Other expenses |
|
| 15 |
|
|
| (10 | ) |
|
| 5 |
|
Earnings before income taxes |
|
| 403 |
|
|
| (303 | ) |
|
| 100 |
|
Income tax benefit |
|
| (191 | ) |
|
| (13 | ) |
|
| (204 | ) |
Net earnings |
|
| 594 |
|
|
| (290 | ) |
|
| 304 |
|
Net earnings attributable to Devon |
|
| 473 |
|
|
| (290 | ) |
|
| 183 |
|
Net earnings per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| 0.90 |
|
|
| (0.55 | ) |
|
| 0.35 |
|
Diluted |
|
| 0.89 |
|
|
| (0.54 | ) |
|
| 0.35 |
|
Comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
| 594 |
|
|
| (290 | ) |
|
| 304 |
|
Foreign currency translation and other |
|
| 6 |
|
|
| (1 | ) |
|
| 5 |
|
Comprehensive earnings |
|
| 615 |
|
|
| (291 | ) |
|
| 324 |
|
Comprehensive earnings attributable to Devon |
|
| 494 |
|
|
| (291 | ) |
|
| 203 |
|
114
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
| Changes to the Consolidated |
| |||||||||
|
| Statement of Cash Flows |
| |||||||||
|
|
|
|
|
|
|
|
|
| As Reported Under |
| |
For the Quarter Ended December 31, 2017 |
| Under Full Cost |
|
| Changes |
|
| Successful Efforts |
| |||
Net earnings |
| $ | 594 |
|
| $ | (290 | ) |
| $ | 304 |
|
Depreciation, depletion and amortization |
|
| 417 |
|
|
| 111 |
|
|
| 528 |
|
Exploratory dry hole expense and unproved leasehold impairments |
|
| — |
|
|
| 139 |
|
|
| 139 |
|
Gains and losses on asset sales |
|
| 1 |
|
|
| (19 | ) |
|
| (18 | ) |
Deferred income tax benefit |
|
| (232 | ) |
|
| (13 | ) |
|
| (245 | ) |
Share-based compensation |
|
| 36 |
|
|
| 11 |
|
|
| 47 |
|
Other |
|
| 26 |
|
|
| (10 | ) |
|
| 16 |
|
Net cash from operating activities |
|
| 796 |
|
|
| (71 | ) |
|
| 725 |
|
Capital expenditures |
|
| (871 | ) |
|
| 72 |
|
|
| (799 | ) |
Divestitures of property and equipment |
|
| 102 |
|
|
| (1 | ) |
|
| 101 |
|
Net cash from investing activities |
|
| (783 | ) |
|
| 71 |
|
|
| (712 | ) |
115108
Item 9.Changes in and Disagreements with AccountantsAccountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 20172018 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, which was completed on February 21, 2018,20, 2019, management concluded that its internal control over financial reporting was effective as of December 31, 2017.2018.
The effectiveness of our internal control over financial reporting as of December 31, 20172018 has been audited by KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as of and for the year ended December 31, 2017,2018, 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
In the fourth quarter of 2017, we added and modified certain internal control processes as a result of changing our method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. There werewas no other changeschange in our internal control over financial reporting during the fourth quarter of 20172018 that has materially affected, or areis reasonably likely to materially affect, our internal control over financial reporting.
Not applicable.
116109
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, 2017.2018.
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, 2017.2018.
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, 2017.2018.
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, 2017.2018.
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, 2017.2018.
117110
Item 15.Exhibits and Financial Statement Schedules
(a) The following documents are included as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto.
3. Exhibits
Exhibit No. |
| Description |
|
|
|
2.1 |
| Purchase Agreement, |
|
| |
|
|
|
3.1 |
| Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318). |
|
|
|
3.2 |
| Registrant’s Bylaws (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed January 27, 2016; File No. 001-32318). |
|
|
|
4.1 |
| Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318). |
|
|
|
4.2 |
| Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318). |
118
|
| |
|
|
|
4.3 |
| Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 3.250% Senior Notes due 2022 and the 4.750% Senior Notes due 2042 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012; File No. 001-32318). |
|
|
|
4.4 |
| |
|
| Supplemental Indenture No. 4, dated as of June 16, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.000% Senior Notes due 2045 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed June 16, 2015; File No. 001-32318). |
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| Supplemental Indenture No. 5, dated as of December 15, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.850% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 15, 2015; File No. 001-32318). |
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| Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176). |
111
Exhibit No. | Description | |
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| Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176). |
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| 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 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed January 9, 2009; File No. 000-32318). |
4.9 | 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). | |
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4.10 |
| Indenture, dated as of October 3, 2001, among Devon Financing Company, L.L.C. (f/k/a Devon Financing Corporation, U.L.C.), as Issuer, Registrant, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 7.875% Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4 filed October 31, 2001; File No. 333-68694). |
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4.11 |
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119
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| Senior Indenture, dated as of September 1, 1997, between Devon OEI Operating, L.L.C. (as successor to Seagull Energy Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee, and related Specimen of 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K filed March 23, 1998; File No. 001-08094). |
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| First Supplemental Indenture, dated as of March 30, 1999, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.10 to Ocean Energy, Inc.’s Form 10-Q filed May 17, 1999; File No. 001-08094). |
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| Second Supplemental Indenture, dated as of May 9, 2001, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444). |
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| Third Supplemental Indenture, dated as of December 31, 2005, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K filed March 3, 2006; File No. 001-32318). |
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120
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10.1 |
| Credit Agreement, dated as of October |
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10.2 |
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| Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed June 8, 2012; File No. 001-32318).* |
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| Devon Energy Corporation 2015 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666).* | |
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) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2013; File No. 001-32318).* |
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| Devon Energy Corporation Annual Incentive Compensation Plan (amended and restated effective as of January 1, 2017) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed June 12, 2017; File No. 001-32318).* |
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| Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective as of April 15, 2014) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 6, 2014; File No. 001-32318).* |
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| Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to Exhibit 10.11 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318).* |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to Exhibit 10.13 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* |
121
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10.11 |
| Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).* |
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| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.6 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).* |
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| Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318).* |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* |
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| Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).* |
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| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).* |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* |
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10.19 |
| Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).* |
113
Exhibit No. | Description | |
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| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).* |
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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).* |
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| Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).* |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.25 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* |
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| Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).* |
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| Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).* |
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| Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* |
122
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10.27 | 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).* | |
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10.28 |
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10.29 |
| Amended and Restated Form of Employment Agreement between Registrant and certain executive officers (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009; File No. 001-32318).* |
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10.30 |
| Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant and certain executive officers (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011; File No. 001-32318).* |
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10.31 |
| Form of Employment Agreement between Registrant and certain executive officers (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).* |
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10.32 |
| 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).* |
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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 executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit |
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10.34 |
| Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the |
114
Exhibit No. | Description | |
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10.35 |
| Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and |
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| 2017 Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 3, 2017; File No. 001-32318).* |
10.37 | 2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 2, 2018; File No. 001-32318).* | |
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10.38 |
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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 (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed May 4, 2016; File No. 001-32318).* |
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| 2017 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 3, 2017; File No. 001-32318).* |
123
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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).* | |
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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 (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318).* |
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10.42 |
| 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 (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318).* |
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10.43 |
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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 John Richels (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318).* |
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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 (incorporated by reference to Exhibit 10.24 to Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318).* |
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115
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| 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 (incorporated by reference to Exhibit 10.44 to Registrant’s Form 10-K filed February 17, 2016; File No. 001-32318).* |
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21 |
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23.1 |
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23.2 |
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23.3 |
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124
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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 |
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101.SCH |
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101.CAL |
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101.DEF |
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101.LAB |
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101.PRE |
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| Indicates management contract or compensatory plan or arrangement. |
Not applicable.
125116
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.
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| DEVON ENERGY CORPORATION |
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| By: | /s/ JEFFREY L. RITENOUR |
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| Jeffrey L. Ritenour |
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| Executive Vice President and |
February 21, 201820, 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/ JEFFREY L. RITENOUR |
| Executive Vice President | February |
Jeffrey L. Ritenour |
| 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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126117
