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Cover and table of contents
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 |
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For the fiscal year ended December 31, 2018
or
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 73-1567067 | |
|---|---|---|
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer identification No.) | |
| 333 West Sheridan Avenue, Oklahoma City, Oklahoma | 73102-5015 | |
| (Address of principal executive offices) | (Zip code) |
Registrant’s telephone number, including area code:
(405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered | |||
|---|---|---|---|---|
| Common stock, par value $0.10 per share | The New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☑ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | |||
|---|---|---|---|---|---|---|---|---|
| Smaller reporting company | ☐ | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant 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 29, 2018 was approximately $22.5 billion, based upon the closing price of $43.96 per share as reported by the New York Stock Exchange on such date. On February 6, 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 2019 annual meeting of stockholders have been incorporated by reference in Part III of this Annual Report on Form 10-K.
DEVON ENERGY CORPORATION
FORM 10-K
TABLE OF CONTENTS
DEFINITIONS
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon,” the “Company” and “Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:
“2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.
“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.
“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.
“EnLink” means EnLink Midstream Partners, 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, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
“MMBbls” means million barrels.
“MMBoe” means million Boe.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“N/M” means not meaningful.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“NYSE” means New York Stock Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“OPIS” means Oil Price Information Service.
“PHMSA” means United States Department of Transportation Pipeline and Hazardous Materials Safety Administration.
“SEC” means United States Securities and Exchange Commission.
“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.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/d” means per day.
“/MMBtu” means per MMBtu.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to:
| • | the volatility of oil, gas and NGL prices; |
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| • | uncertainties inherent in estimating oil, gas and NGL reserves; |
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| • | the extent to which we are successful in acquiring and discovering additional reserves; |
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| • | the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct; |
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| • | regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; |
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| • | risks related to regulatory, social and market efforts to address climate change; |
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| • | risks related to our hedging activities; |
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| • | counterparty credit risks; |
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| • | risks relating to our indebtedness; |
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| • | cyberattack risks; |
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| • | our limited control over third parties who operate some of our oil and gas properties; |
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| • | midstream capacity constraints and potential interruptions in production; |
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| • | the extent to which insurance covers any losses we may experience; |
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| • | competition for assets, materials, people and capital; |
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| • | our ability to successfully complete mergers, acquisitions and divestitures; and |
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| • | any of the other risks and uncertainties discussed in this report. |
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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.
PART I
Items 1 and 2. Business and Properties
General
A Delaware corporation formed in 1971 and publicly held since 1988, Devon (NYSE: DVN) is an independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Our operations are concentrated in various North American onshore areas in the U.S. and Canada. In July 2018, we exited the midstream business by divesting our aggregate ownership interests in EnLink and the General 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, 2018, Devon and its consolidated subsidiaries had approximately 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.
Our Strategy
Our business strategy is focused on delivering a consistently competitive shareholder return among our peer group. Because the business of exploring for, developing and producing oil and natural gas is capital intensive, delivering sustainable capital efficient cash flow growth is a key tenant to our success. While our cash flow is highly dependent on volatile and uncertain commodity prices, we pursue our strategy throughout all commodity price cycles with three fundamental principles.
A premier, sustainable portfolio of assets – As discussed in the 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.
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 focus 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 three-year period. As we continue deleveraging, we expect to reduce annual interest costs by $130 million. Finally, we have plans to reduce our annual production expenses by $50 million over the next three years.
Financial strength and flexibility – Commodity prices are uncertain and volatile, so we strive to maintain a strong balance sheet, as well as adequate liquidity and financial flexibility, in order to operate competitively in all commodity price cycles. Our capital allocation decisions are made with attention to these financial stewardship principles, as well as the priorities of funding our core operations, protecting our investment-grade credit ratings, and paying and growing our shareholder dividend.
During 2018, we reduced our consolidated debt by 40%, primarily from our divestitures. We also raised our quarterly dividend 33% and began a $4 billion share repurchase program. As we dispose of our Canadian and Barnett Shale assets in 2019, we expect to use the proceeds to reduce debt further and repurchase additional common shares. As a result of our planned dispositions, our Board of Directors has increased our share repurchase program to $5 billion in February 2019 and raised our quarterly dividend 12.5% to $0.09 per share.
Oil and Gas Properties
Property Profiles
Key summary data from each of our areas of operation as of and for the year ended December 31, 2018 are detailed in the map below. Notes 22 and 23 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.
Delaware Basin – The Delaware Basin is one of Devon’s top assets and continues to offer exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, Wolfcamp and Leonard formations. We expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin to deliver high-margin growth for many years to come. During 2018, our continued appraisal and development work enabled us to increase our proved reserves in this area by approximately 24%. At December 31, 2018, we had 10 operated rigs developing this asset. In 2019, we plan to invest approximately $900 million of capital in the Delaware Basin, making it the top-funded asset in the portfolio.
STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top assets. Our STACK position is one of the largest in the industry, providing visible long-term stable production. At December 31, 2018, we had five operated rigs with drilling focused in the Meramec formation. In 2019, we plan approximately $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 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 15 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, 2018. Currently, we have minimal planned capital outlays for 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 oil development play that produces heavy oil by conventional means, without the need for steam injection.
In 2019, we plan to separate our operations in Canada.
Barnett Shale – This is our largest property in terms of proved reserves. Our leases are located primarily in Denton, Parker, Tarrant and Wise counties in north Texas. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this asset into one of the top producing gas fields in North America. In 2019, we plan to 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 23 in “Item 8. Financial Statements and Supplementary Data” of this report.
Proved oil and gas reserves are those quantities of oil, gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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 over 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 18 years, including the past 11 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 2018, we engaged two such firms to audit approximately 89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited approximately 87% of our U.S. reserves, and Deloitte LLP audited approximately 97% of our Canadian reserves.
In addition to conducting these internal reviews and external reserves audits, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The members of our Reserves Committee have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process. The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies and meets at least once a year separately with our senior reserves engineering personnel and separately with our third-party petroleum consultants.
The following tables present production, price and cost information for each significant field, country and continent.
| Production | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Year Ended December 31, | Oil (MMBbls) | Bitumen (MMBbls) | Gas (Bcf) | NGLs (MMBbls) | Total (MMBoe) | |||||||||||||||
| 2018 | ||||||||||||||||||||
| Barnett Shale | — | — | 186 | 12 | 43 | |||||||||||||||
| STACK | 12 | — | 121 | 14 | 45 | |||||||||||||||
| Jackfish | — | 35 | — | — | 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 | |||||||||||||||
| STACK | 9 | — | 107 | 11 | 38 | |||||||||||||||
| Jackfish | — | 40 | — | — | 40 | |||||||||||||||
| U.S. | 42 | — | 433 | 36 | 150 | |||||||||||||||
| Canada | 7 | 40 | 6 | — | 48 | |||||||||||||||
| Total North America | 49 | 40 | 439 | 36 | 198 | |||||||||||||||
| 2016 | ||||||||||||||||||||
| Barnett Shale | — | — | 265 | 15 | 60 | |||||||||||||||
| STACK | 7 | — | 103 | 9 | 33 | |||||||||||||||
| Jackfish | — | 40 | — | — | 40 | |||||||||||||||
| U.S. | 47 | — | 510 | 42 | 174 | |||||||||||||||
| Canada | 8 | 40 | 7 | — | 49 | |||||||||||||||
| Total North America | 55 | 40 | 517 | 42 | 223 |
| 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)(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 | ||||||||||
| STACK | $ | 48.43 | $ | — | $ | 2.40 | $ | 17.78 | $ | 4.72 | ||||||||||
| Jackfish | $ | — | $ | 29.38 | $ | — | $ | — | $ | 11.02 | ||||||||||
| U.S. | $ | 49.41 | $ | — | $ | 2.48 | $ | 15.66 | $ | 6.74 | ||||||||||
| Canada | $ | 33.73 | $ | 29.38 | N/M | $ | — | $ | 11.70 | |||||||||||
| Total North America | $ | 47.31 | $ | 29.38 | $ | 2.48 | $ | 15.66 | $ | 7.94 | ||||||||||
| 2016 | ||||||||||||||||||||
| Barnett Shale | $ | 41.03 | $ | — | $ | 1.76 | $ | 10.31 | $ | 5.75 | ||||||||||
| STACK | $ | 39.81 | $ | — | $ | 1.91 | $ | 10.86 | $ | 4.34 | ||||||||||
| Jackfish | $ | — | $ | 19.82 | $ | — | $ | — | $ | 8.70 | ||||||||||
| U.S. | $ | 38.92 | $ | — | $ | 1.84 | $ | 9.81 | $ | 6.44 | ||||||||||
| Canada | $ | 23.96 | $ | 19.82 | N/M | $ | — | $ | 9.36 | |||||||||||
| Total North America | $ | 36.72 | $ | 19.82 | $ | 1.84 | $ | 9.81 | $ | 7.08 |
| (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. |
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| (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. |
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Drilling Statistics
The following table summarizes our development and exploratory drilling results.
| Development Wells (1) | Exploratory Wells (1) | Total Wells (1) | ||||||||||||||||||||||||||
| Year Ended December 31, | Productive | Dry | Productive | Dry | Productive | Dry | Total | |||||||||||||||||||||
| 2018 | ||||||||||||||||||||||||||||
| U.S. | 165.6 | 3.1 | 69.4 | — | 235.0 | 3.1 | 238.1 | |||||||||||||||||||||
| Canada | 70.5 | — | — | — | 70.5 | — | 70.5 | |||||||||||||||||||||
| Total North America | 236.1 | 3.1 | 69.4 | — | 305.5 | 3.1 | 308.6 | |||||||||||||||||||||
| 2017 | ||||||||||||||||||||||||||||
| U.S. | 149.8 | — | 44.0 | — | 193.8 | — | 193.8 | |||||||||||||||||||||
| Canada | 100.5 | — | — | — | 100.5 | — | 100.5 | |||||||||||||||||||||
| Total North America | 250.3 | — | 44.0 | — | 294.3 | — | 294.3 | |||||||||||||||||||||
| 2016 | ||||||||||||||||||||||||||||
| U.S. | 88.5 | — | 36.4 | 2.0 | 124.9 | 2.0 | 126.9 | |||||||||||||||||||||
| Canada | 21.5 | — | — | — | 21.5 | — | 21.5 | |||||||||||||||||||||
| Total North America | 110.0 | — | 36.4 | 2.0 | 146.4 | 2.0 | 148.4 |
| (1) | Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests. |
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The following table presents the wells that were in progress on December 31, 2018. As of February 1, 2019, these wells were still in progress.
| Gross (1) | Net (2) | |||||||
|---|---|---|---|---|---|---|---|---|
| U.S. | 184.0 | 105.2 | ||||||
| Canada | 1.0 | 1.0 | ||||||
| Total North America | 185.0 | 106.2 |
| (1) | Gross wells are the sum of all wells in which we own a working interest. |
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| (2) | Net wells are gross wells multiplied by our fractional working interests in each well. |
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Productive Wells
The following table sets forth our producing wells as of December 31, 2018.
| Oil Wells (1) | Natural Gas Wells | Total Wells (1) | ||||||||||||||||||||||
| Gross (2)(4) | Net (3) | Gross (2)(4) | Net (3) | Gross (2)(4) | Net (3) | |||||||||||||||||||
| U.S. | 9,284 | 3,445 | 8,235 | 5,703 | 17,519 | 9,148 | ||||||||||||||||||
| Canada | 3,183 | 3,071 | 544 | 380 | 3,727 | 3,451 | ||||||||||||||||||
| Total North America | 12,467 | 6,516 | 8,779 | 6,083 | 21,246 | 12,599 |
| (1) | Includes bitumen wells. |
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| (2) | Gross wells are the sum of all wells in which we own a working interest. |
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| (3) | Net wells are gross wells multiplied by our fractional working interests in each well. |
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| (4) | Includes 902 and 350 gross oil and gas wells, respectively, which had multiple completions. |
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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 12,900 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, 2018. Of our 3.8 million net acres, approximately 1.9 million acres are held by production. The acreage in the table includes 0.2 million, 0.1 million and 0.1 million net acres subject to leases that are scheduled to expire during 2019, 2020 and 2021, respectively. As of December 31, 2018, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.3 million net acres set to expire by December 31, 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 2018, we allowed approximately 0.1 million acres to expire.
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||
| (Thousands) | ||||||||||||||||||||||||
| U.S. | 1,449 | 909 | 3,373 | 1,463 | 4,822 | 2,372 | ||||||||||||||||||
| Canada | 674 | 495 | 2,086 | 967 | 2,760 | 1,462 | ||||||||||||||||||
| Total North America | 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. |
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| (2) | Net acres are gross acres multiplied by our fractional working interests in the acreage. |
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Title to Properties
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
Marketing Activities
Oil, Gas and NGL Marketing
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.
Additionally, we may enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2019, our production was sold under the following contract terms.
| Short-Term | Long-Term | |||||||||||||||
| Variable | Fixed | Variable | Fixed | |||||||||||||
| Oil and bitumen | 75 | % | — | 25 | % | — | ||||||||||
| Natural gas | 67 | % | 4 | % | 29 | % | — | |||||||||
| NGLs | 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, 2018, we were committed to deliver the following fixed quantities of production.
| Total | Less Than 1 Year | 1-3 Years | 3-5 Years | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and bitumen (MMBbls) | 53 | 25 | 28 | — | ||||||||||||
| Natural gas (Bcf) | 360 | 220 | 125 | 15 | ||||||||||||
| NGLs (MMBbls) | 10 | 10 | — | — | ||||||||||||
| Total (MMBoe) | 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 and 2016, no purchaser accounted for over 10% of our consolidated sales revenue.
Competition
See “Item 1A. Risk Factors.”
Public Policy and Government Regulation
Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting our industry have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. The following are significant areas of government control and regulation affecting our operations.
Exploration and Production Regulation
Our operations are subject to federal, tribal, state, provincial and local laws and regulations. These laws and regulations relate to matters that include:
| • | acquisition of seismic data; |
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| • | location, drilling and casing of wells; |
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| • | well design; |
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| • | hydraulic fracturing; |
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| • | well production; |
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| • | spill prevention plans; |
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| • | emissions and discharge permitting; |
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| • | use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; |
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| • | surface usage and the restoration of properties upon which wells have been drilled; |
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| • | calculation and disbursement of royalty payments and production taxes; |
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| • | plugging and abandoning of wells; |
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| • | transportation of production; and |
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| • | endangered species and habitat. |
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Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the forced pooling or unitization of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the BLM or Bureau of Indian Affairs of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has, from time to time, evaluated and, in some cases, promulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands can sometimes be subject to 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
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.
In December 2018, Alberta enacted the Curtailment Rules (Rules) in an effort to reduce Alberta’s oversupply of oil which resulted from pipeline and rail constraints. Pursuant to the Rules, operators that produce either or both crude oil or crude bitumen in amounts in excess of 10 MBbls/d are required to curtail their production. As of January 1, 2019, the production curtailment amount was set at 325 MBbls/d. The curtailment amounts are expected to reduce over 2019 to an average of approximately 95 MBbls/d as storage levels ease and price differential improve, and the Rules terminate on December 31, 2019. Devon’s curtailments in the first quarter of 2019 as a result of the Rules are anticipated to total approximately 10 MBbls/d of bitumen, or approximately 2% of our total production.
Environmental, Pipeline Safety and Occupational Regulations
We strive to conduct our operations in a socially and environmentally responsible manner, which includes compliance with applicable law. We are subject to many federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment and natural resources. Environmental laws and regulations relate to:
| • | the discharge of pollutants into federal, provincial and state waters; |
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| • | assessing the environmental impact of seismic acquisition, drilling or construction activities; |
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| • | the generation, storage, transportation and disposal of waste materials, including hazardous substances; |
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| • | the emission of certain gases into the atmosphere; |
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| • | the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; |
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| • | the development of emergency response and spill contingency plans; |
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| • | the monitoring, repair and design of pipelines used for the transportation of oil and natural gas; |
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| • | the protection of threatened and endangered species; and |
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| • | worker protection. |
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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. Environmental protection and health and safety compliance are necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, 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.