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Cover and table of contents
10-K 1 d109858d10k.htm FORM 10-K
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
| x | 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, 2015
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 x 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 x
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 x 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 x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2015 was approximately $24.3 billion, based upon the closing price of $59.49 per share as reported by the New York Stock Exchange on such date. On February 10, 2016, 441.3 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2016 annual meeting of stockholders – Part III
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DEVON ENERGY CORPORATION
FORM 10-K
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DEFINITIONS
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” refer to Devon Energy Corporation and its consolidated subsidiaries. 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.
“ASU” means Accounting Standards Update.
“Bbl” or “Bbls” means barrel or barrels.
“Bcf” means billion cubic feet.
“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.
“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.
“Coronado” means Coronado Midstream Holdings LLC.
“Crosstex” means Crosstex Energy, Inc. together with Crosstex Energy L.P.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Financing” means Devon Financing Company, L.L.C.
“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.
“DOE” means Department of Energy.
“E2” means E2 Energy Services, LLC together with E2 Appalachian Compression, LLC.
“EMH” means EnLink Midstream Holdings, LP.
“EnLink” means EnLink Midstream Partners, L.P., a master limited partnership.
“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.
“General Partner” means EnLink Midstream, LLC, the general partner entity of EnLink.
“GeoSouthern” means GeoSouthern Energy Corporation.
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“LPC” means LPC Crude Oil Marketing LLC.
“Matador” means MRC Energy Company.
“MBbls” means thousand barrels.
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“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
“MLP” means master limited partnership.
“MMBbls” means million barrels.
“MMBoe” means million Boe.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“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.
“Pre-tax 10% present value” means the present value of Devon’s pre-tax future net revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges.
“SEC” means United States Securities and Exchange Commission.
“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.
“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.
“S&P 500 Index” means Standard and Poor’s 500 index.
“Tall Oak” means Tall Oak Midstream, LLC.
“TSR” means total shareholder return.
“U.S.” means United States of America.
“VEX” means Victoria Express Pipeline and related truck terminal and storage assets.
“WTI” means West Texas Intermediate.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the SEC. Such statements are 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 “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2015 reserve reports and other data in our possession or available from third parties. 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, including the currently depressed commodity price environment; |
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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 exploration and development activities; |
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| • | risks related to our hedging activities; |
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| • | counterparty credit risks; |
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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 relating to our indebtedness; |
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| • | our ability to successfully complete mergers, acquisitions and divestitures; |
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| • | the extent to which insurance covers any losses we may experience; |
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| • | our limited control over third parties who operate our oil and gas properties; |
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| • | midstream capacity constraints and potential interruptions in production; |
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| • | competition for leases, materials, people and capital; |
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| • | cyberattacks targeting our systems and infrastructure; 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.
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PART I
Items 1 and 2. Business and Properties
General
Devon is a leading 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. Our portfolio of oil and gas properties provides stable, environmentally responsible production and a platform for future growth. We have doubled our onshore North American oil production since 2010 to more than 275 MBbls per day and have a deep inventory of development opportunities. Devon also produces over 1.6 Bcf of natural gas a day and more than 136 MBbls of NGLs per day.
Additionally, we control EnLink, a leading integrated midstream business with significant size and scale in key operating regions in the U.S. This MLP focuses on providing gathering, transmission, processing, fractionation and marketing to producers of natural gas, NGLs, crude oil and condensate.
A Delaware corporation formed in 1971, we have been publicly held since 1988, and our common stock is listed on the NYSE. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2015, Devon and its consolidated subsidiaries had approximately 6,600 employees. Approximately 1,400 of such employees are employed by EnLink (through its subsidiaries).
Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K as well as any amendments to these reports with the SEC. Through our website, http://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 (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer). Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.
In addition, the public may read and copy any materials Devon files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.
Strategy
Our primary goal is to build value per debt-adjusted share by:
| • | exploring for undiscovered oil and natural gas reserves; |
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| • | purchasing and developing oil and natural gas properties; |
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| • | enhancing the value of production through marketing and midstream activities; |
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| • | optimizing production operations to control costs; and |
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| • | maintaining a strong balance sheet. |
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During 2015, we continued to execute on this strategy and experienced a number of key achievements that are outlined in this report. However, we, and the entire upstream energy sector, have faced both operational and financial challenges as oil and natural gas prices weakened significantly throughout 2015 and continued into 2016. To navigate these turbulent times, we are using our focused strategy, flexible portfolio of assets and leadership experience to execute on a number of initiatives that will ensure our long-term financial strength.
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Specifically, after completing the STACK acquisition discussed in this report, we had approximately $3.9 billion of liquidity.
While we will continue to operate and develop our premier portfolio of assets, we are committed to protecting our balance sheet and managing our capital programs to be within our cash inflows, including Access Pipeline proceeds. As a result, we are significantly reducing our capital investment in response to lower commodity prices. We plan to invest $900 million to $1.1 billion in our upstream programs, a decrease of roughly 75% compared to our 2015 capital. We are also committed to reducing our G&A and field-level operating costs commensurate with our reduced, but focused, activity level. Following a number of cost-reduction initiatives culminating with our February 2016 workforce reduction, we are expecting a $700 million to $900 million reduction in operating and G&A costs on an annualized basis.
Also, in February 2016, we reduced our quarterly common stock dividend 75% to $0.06 per share.
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Oil and Gas Properties
Property Profiles
The locations of our core oil and gas properties are presented on the following map. Additional information related to these properties follows this map, as well as information describing EnLink’s assets.
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The following table outlines a summary of key data in each of our operating areas as of and for the year ended December 31, 2015. Notes 20 and 21 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.
| Proved Reserves | Production | |||||||||||||||||||||||||||
| MMBoe | % of Total | % Liquids | MBoe/d | % of Total | % Liquids | Gross Wells Drilled | ||||||||||||||||||||||
| Delaware Basin | 123 | 6 | % | 78 | % | 61 | 9 | % | 79 | % | 167 | |||||||||||||||||
| STACK | 264 | 12 | % | 42 | % | 64 | 9 | % | 42 | % | 130 | |||||||||||||||||
| Eagle Ford | 103 | 4 | % | 76 | % | 115 | 17 | % | 79 | % | 275 | |||||||||||||||||
| Rockies Oil | 28 | 1 | % | 66 | % | 23 | 3 | % | 70 | % | 65 | |||||||||||||||||
| Heavy Oil | 544 | 25 | % | 100 | % | 115 | 17 | % | 97 | % | 79 | |||||||||||||||||
| Barnett Shale | 841 | 39 | % | 25 | % | 182 | 27 | % | 27 | % | 5 | |||||||||||||||||
| Core assets | 1,903 | 87 | % | 55 | % | 560 | 82 | % | 61 | % | 721 | |||||||||||||||||
| Other | 279 | 13 | % | 57 | % | 120 | 18 | % | 58 | % | 129 | |||||||||||||||||
| Total | 2,182 | 100 | % | 56 | % | 680 | 100 | % | 60 | % | 850 | |||||||||||||||||
Delaware Basin – The Delaware Basin has been a legacy asset for Devon 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. These oil and liquids-rich opportunities across our acreage in the Delaware Basin will offer high-margin growth potential for many years to come. In 2016, we plan to invest approximately $200 million of capital in the Delaware Basin, primarily focused on the second Bone Spring opportunity in the basin of southeast New Mexico.
STACK – In early January 2016, we increased our acreage in the Woodford Shale and Meramec plays by acquiring 80,000 net acres in the STACK. The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is named for the stacked pay in the area. Our Woodford Shale position is the largest and one of the best in the industry. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Early drilling activity in the Meramec play has been encouraging across our core position in the oil and liquids window. In 2016, we plan approximately $325 million of capital investment.
Eagle Ford – We acquired our position in the Eagle Ford in early 2014 from GeoSouthern and have approximately 66,000 net acres located in the DeWitt and Lavaca counties in south Texas. Since acquiring these assets, we have delivered tremendous results, increasing production by 125%. Our excellent results are driven by our development in DeWitt County which is located in the economic core of the play. In 2016, we expect our Eagle Ford assets to once again deliver the highest operating margin of any asset in the portfolio and plan approximately $200 million of capital investment.
Rockies Oil – Our operations are focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. In the Powder River, we are currently targeting several Cretaceous oil objectives, including the Turner, Parkman and Frontier formations. 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. In December 2015, we acquired 253,000 net acres in the “core” of the oil fairway in the Powder River. This acquisition delivers some of the best returns in our portfolio and is a significant resource opportunity. In 2016, we plan approximately $75 million of capital investment.
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, a 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. In 2014, we brought the third phase of Jackfish into operation, which ramped up to facility capacity by
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the third quarter of 2015. We expect each phase to maintain a reasonably flat production profile for greater than 20 years at an average gross production rate of approximately 35 MBbls per day at each facility.
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, 2015. With our 50% partner, we are evaluating our development timeline for Pike.
To facilitate the delivery of our heavy oil production, we have a 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale. The Access Pipeline system has the capacity to transport approximately 170 MBbls of bitumen blend per day, net to our 50% interest. As discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, we have plans to monetize our interest in Access Pipeline in 2016. With any buyer of Access Pipeline, we will also enter into a contractual arrangement to continue transporting our heavy oil volumes on Access Pipeline.
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 2016, we plan approximately $175 million of capital investment in our Canadian Heavy Oil business.
Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this into one of the top producing gas fields in North America. Given the commodity price environment in 2015, we shifted focus to enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2015, we accelerated our horizontal refrac program to test the re-stimulation of 25 wells and also had an active vertical refrac program, re-stimulating 140 vertical wells. In 2016, we plan on minimal refrac activity in the Barnett.
Other – Other assets are located primarily in the Midland Basin, east Texas, Granite Wash and Mississippian-Lime areas. Substantially all of these properties have been identified for divestiture in 2016.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each key property, see Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report.
Since the beginning of 2015, no estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency except in filings with the SEC and the DOE. Reserve estimates filed with the SEC correspond with the estimates of our reserves contained in this report. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included in this report. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.
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.
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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 (“Qualified 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 Group’s Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates, including any or all of the following:
| • | an undergraduate degree in petroleum engineering from an accredited university, or equivalent; |
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| • | a petroleum engineering license, or similar certification; |
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| • | memberships in oil and gas industry or trade groups; and |
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| • | relevant experience estimating reserves. |
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The current Director of the Group has all of the qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has 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. He has been employed by Devon for the past fifteen years, including the past eight in his current position. During his career, he has been responsible for reserves estimation as the primary reservoir engineer for projects including, but not limited to:
| • | Hugoton Gas Field (Kansas); |
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| • | Sho-Vel-Tum CO2 Flood (Oklahoma); |
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| • | West Loco Hills Unit Waterflood and CO2 Flood (New Mexico); |
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| • | Dagger Draw Oil Field (New Mexico); |
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| • | Clarke Lake Gas Field (Alberta, Canada); |
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| • | Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea); and |
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| • | ACG Unit (Caspian Sea). |
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From 2003 to 2010, he served as the reservoir engineering representative on our internal peer review team. In this role, he reviewed reserves and resource estimates for projects including, but not limited to, the Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf), Cascade Lower Tertiary Development (Gulf of Mexico Deepwater) and Polvo Development (Campos Basin, Brazil).
The Group reports independently of any of our operating divisions and currently is in our Chief Financial Officer’s organization. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.
Throughout the year, the Group performs internal reserves audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below. The Group also ensures our Qualified Estimators obtain continuing education related to the fundamentals of SEC proved reserves assignments.
The Group also oversees audits and reserves estimates performed by third-party petroleum consulting firms. During 2015, we engaged two such firms to audit 95% of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited 94% of our 2015 U.S. reserves, and Deloitte LLP audited 96% of our Canadian reserves.
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“Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.
In addition to conducting these internal and external 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 Reserves Committee assists the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.
The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies and meets at least once a year separately with our senior reserves engineering personnel and separately with our third-party petroleum consultants. The responsibilities of the Reserves Committee include the following:
| • | approve the scope of and oversee an annual review and evaluation of our oil, gas and NGL reserves; |
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| • | oversee the integrity of our reserves evaluation and reporting system; |
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| • | oversee and evaluate our compliance with legal and regulatory requirements related to our reserves; |
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| • | review the qualifications and independence of our third-party petroleum consultants; and |
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| • | monitor the performance of our third-party petroleum consultants. |
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The following table presents our estimated pre-tax cash flow information related to our proved reserves. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 21 to our consolidated financial statements included in this report.
| Year Ended December 31, 2015 | ||||||||||||
| U.S. | Canada | Total | ||||||||||
| (Millions) | ||||||||||||
| Pre-Tax Future Net Revenue (Non-GAAP) (1) | ||||||||||||
| Proved Developed Reserves | $ | 6,382 | $ | 1,874 | $ | 8,256 | ||||||
| Proved Undeveloped Reserves | 459 | 1,523 | 1,982 | |||||||||
| Total Proved Reserves | $ | 6,841 | $ | 3,397 | $ | 10,238 | ||||||
| Pre-Tax 10% Present Value (Non-GAAP) (1) | ||||||||||||
| Proved Developed Reserves | $ | 4,609 | $ | 1,657 | $ | 6,266 | ||||||
| Proved Undeveloped Reserves | 259 | 458 | 717 | |||||||||
| Total Proved Reserves | $ | 4,868 | $ | 2,115 | $ | 6,983 | ||||||
| (1) | Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to DD&A, asset impairments or non-property related expenses such as debt service and income tax expense. |
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Pre-tax future net revenue and pre-tax 10% present value are non-GAAP measures. The standardized measure was $6.7 billion at the end of 2015. Included as part of the standardized measure were discounted future income taxes of $0.3 billion. Excluding these taxes, the pre-tax 10% present value was $7.0 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized
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measure. The pre-tax 10% present value assists in both the estimation of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors, which are more consistent from company to company.
Production, Production Prices and Production Costs
The following table presents 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) | |||||||||||||||
| 2015 | ||||||||||||||||||||
| Barnett Shale | — | — | 291 | 17 | 66 | |||||||||||||||
| Jackfish | — | 31 | — | — | 31 | |||||||||||||||
| U.S. | 60 | — | 579 | 50 | 206 | |||||||||||||||
| Canada | 10 | 31 | 8 | — | 42 | |||||||||||||||
| Total North America | 70 | 31 | 587 | 50 | 248 | |||||||||||||||
| 2014 | ||||||||||||||||||||
| Barnett Shale | 1 | — | 332 | 20 | 76 | |||||||||||||||
| Jackfish | — | 20 | — | — | 20 | |||||||||||||||
| U.S. | 47 | — | 660 | 50 | 207 | |||||||||||||||
| Canada | 10 | 20 | 41 | 1 | 39 | |||||||||||||||
| Total North America | 57 | 20 | 701 | 51 | 246 | |||||||||||||||
| 2013 | ||||||||||||||||||||
| Barnett Shale | 1 | — | 374 | 20 | 83 | |||||||||||||||
| Jackfish | — | 19 | — | — | 19 | |||||||||||||||
| U.S. | 28 | — | 709 | 41 | 189 | |||||||||||||||
| Canada | 15 | 19 | 165 | 4 | 64 | |||||||||||||||
| Total North America | 43 | 19 | 874 | 45 | 253 |
| Average Sales Price | ||||||||||||||||||||
| Year Ended December 31, | Oil (Per Bbl) | Bitumen (Per Bbl) | Gas (Per Mcf) | NGLs (Per Bbl) | Production Cost (Per Boe) (1) | |||||||||||||||
| 2015 | ||||||||||||||||||||
| Barnett Shale | $ | 46.47 | $ | — | $ | 2.00 | $ | 9.62 | $ | 6.02 | ||||||||||
| Jackfish | $ | — | $ | 23.41 | $ | — | $ | — | $ | 12.43 | ||||||||||
| U.S. | $ | 44.01 | $ | — | $ | 2.17 | $ | 9.32 | $ | 7.52 | ||||||||||
| Canada | $ | 30.58 | $ | 23.41 | $ | 0.67 | $ | — | $ | 13.18 | ||||||||||
| Total North America | $ | 42.12 | $ | 23.41 | $ | 2.14 | $ | 9.32 | $ | 8.48 | ||||||||||
| 2014 | ||||||||||||||||||||
| Barnett Shale | $ | 95.51 | $ | — | $ | 3.78 | $ | 21.98 | $ | 5.25 | ||||||||||
| Jackfish | $ | — | $ | 55.88 | $ | — | $ | — | $ | 20.59 | ||||||||||
| U.S. | $ | 85.64 | $ | — | $ | 3.92 | $ | 24.46 | $ | 7.52 | ||||||||||
| Canada | $ | 68.14 | $ | 55.88 | $ | 3.64 | $ | 50.52 | $ | 20.10 | ||||||||||
| Total North America | $ | 82.47 | $ | 55.88 | $ | 3.90 | $ | 24.89 | $ | 9.49 | ||||||||||
| 2013 | ||||||||||||||||||||
| Barnett Shale | $ | 97.74 | $ | — | $ | 2.90 | $ | 22.45 | $ | 4.12 | ||||||||||
| Jackfish | $ | — | $ | 48.04 | $ | — | $ | — | $ | 17.98 | ||||||||||
| U.S. | $ | 94.52 | $ | — | $ | 3.10 | $ | 25.75 | $ | 6.65 | ||||||||||
| Canada | $ | 69.18 | $ | 48.04 | $ | 3.05 | $ | 46.17 | $ | 15.78 | ||||||||||
| Total North America | $ | 86.02 | $ | 48.04 | $ | 3.09 | $ | 27.33 | $ | 8.97 |
| (1) | Represents LOE per Boe and excludes severance and property taxes. |
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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 | |||||||||||||||||||||
| 2015 | ||||||||||||||||||||||||||||
| U.S. | 298.6 | 1.8 | 40.7 | — | 339.3 | 1.8 | 341.1 | |||||||||||||||||||||
| Canada | 79.0 | — | — | — | 79.0 | — | 79.0 | |||||||||||||||||||||
| Total North America | 377.6 | 1.8 | 40.7 | — | 418.3 | 1.8 | 420.1 | |||||||||||||||||||||
| 2014 | ||||||||||||||||||||||||||||
| U.S. | 474.4 | 0.4 | 5.0 | 1.2 | 479.4 | 1.6 | 481.0 | |||||||||||||||||||||
| Canada | 190.8 | 1.0 | — | 0.5 | 190.8 | 1.5 | 192.3 | |||||||||||||||||||||
| Total North America | 665.2 | 1.4 | 5.0 | 1.7 | 670.2 | 3.1 | 673.3 | |||||||||||||||||||||
| 2013 | ||||||||||||||||||||||||||||
| U.S. | 555.3 | — | 56.1 | 7.0 | 611.4 | 7.0 | 618.4 | |||||||||||||||||||||
| Canada | 211.9 | 1.0 | 7.4 | — | 219.3 | 1.0 | 220.3 | |||||||||||||||||||||
| Total North America | 767.2 | 1.0 | 63.5 | 7.0 | 830.7 | 8.0 | 838.7 | |||||||||||||||||||||
| (1) | These well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests in each well. |
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The following table presents the wells that were in progress on December 31, 2015. As of February 1, 2016, these wells were still in progress.
| Gross (1) | Net (2) | |||||||
| U.S. | 17.0 | 8.6 | ||||||
| Canada | — | — | ||||||
| Total North America | 17.0 | 8.6 | ||||||
| (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, 2015.
| 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. | 10,895 | 4,352 | 15,130 | 10,313 | 26,025 | 14,665 | ||||||||||||||||||
| Canada | 3,264 | 3,166 | 698 | 498 | 3,962 | 3,664 | ||||||||||||||||||
| Total North America | 14,159 | 7,518 | 15,828 | 10,811 | 29,987 | 18,329 | ||||||||||||||||||
| (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 809 and 1,565 oil and gas wells, respectively, which had multiple completions and were operated by Devon. |
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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 19,000 wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing and drilling 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, 2015. Of our 5.5 million net acres, approximately 3.0 million acres are held by production. The acreage in the table includes 0.2 million, 0.4 million and 0.1 million net acres subject to leases that are scheduled to expire during 2016, 2017 and 2018, respectively. As of December 31, 2015, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.7 million net acres set to expire by December 31, 2018, we will perform 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 2015, we allowed approximately 0.8 million acres to expire.
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||
| (Thousands) | ||||||||||||||||||||||||
| U.S. | 2,598 | 1,732 | 4,654 | 2,207 | 7,252 | 3,939 | ||||||||||||||||||
| Canada | 705 | 520 | 2,147 | 1,026 | 2,852 | 1,546 | ||||||||||||||||||
| Total North America | 3,303 | 2,252 | 6,801 | 3,233 | 10,104 | 5,485 | ||||||||||||||||||
| (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, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, which generally include a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
EnLink Properties
EnLink’s assets are comprised of systems and other assets located in four primary regions:
| • | Texas – The Texas assets consist of transmission pipelines with a capacity of approximately 1.3 Bcf/d, processing facilities with a total processing capacity of approximately 1.4 Bcf/d and gathering systems with total capacity of approximately 2.9 Bcf/d. |
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| • | Oklahoma – The Oklahoma assets consist of processing facilities with a total processing capacity of approximately 550 MMcf/d and gathering systems with total capacity of approximately 605 MMcf/d. |
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| • | Louisiana – The Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.7 Bcf/d, gathering |
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| systems with total capacity of approximately 510 MMcf/d, 660 miles of liquids transport lines and four fractionation assets with total fractionation capacity of 198 MBbls/d. |
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| • | Crude and Condensate – The Crude and Condensate assets consist of approximately 350 miles of crude oil and condensate pipelines with total capacity of approximately 101 MBbls/d, 900 MBbls of above ground storage and eight condensate stabilization and natural gas compression stations with combined capacities of approximately 36 MBbls/d of condensate stabilization and 780 MMcf/d of natural gas compression. |
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Marketing and Midstream Activities
Midstream Operations
Comprising approximately 98% of our 2015 midstream operating profit, EnLink is the primary component of our midstream operations. EnLink’s operations primarily focus on providing midstream energy services, which consist of gathering, transmission, processing, fractionation and marketing, to producers of natural gas, NGLs, crude oil and condensate, 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.
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 periodically 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 2016, our production was sold under the following contract terms.
| Short-Term | Long-Term | |||||||||||||||
| Variable | Fixed | Variable | Fixed | |||||||||||||
| Oil and bitumen | 72 | % | — | 28 | % | — | ||||||||||
| Natural gas | 36 | % | 4 | % | 60 | % | — | |||||||||
| NGLs | 52 | % | 10 | % | 38 | % | — |
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, 2015, we were committed to deliver the following fixed quantities of production.
| Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years | ||||||||||||||||
| Oil and bitumen (MMBbls) | 145 | 38 | 56 | 46 | 5 | |||||||||||||||
| Natural gas (Bcf) | 736 | 439 | 287 | 10 | — | |||||||||||||||
| NGLs (MMBbls) | 12 | 12 | — | — | — | |||||||||||||||
| Total (MMBoe) | 280 | 123 | 104 | 48 | 5 | |||||||||||||||
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We expect to fulfill our delivery commitments primarily with production from our proved developed reserves. In certain regions, such as in our Heavy Oil operation in Canada, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves.
Generally, our proved reserves have 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 may be subject to deficiency payments. In such instances, we can and may use spot market purchases to satisfy the commitments.
Customers
During 2015, 2014 and 2013, no purchaser accounted for over 10% of our consolidated operating revenues.
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 integration 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, state conservation laws generally limit the venting or flaring of natural gas and 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 by the federal government and administered by the Bureau of Land Management 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. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring and royalty payment obligations for production from federal lands.
Royalties and Incentives in Canada
The royalty system in Canada is a significant factor in the profitability of Canadian oil and gas production. 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. The regulations prescribe lower royalty rates for oil sands projects until allowable capital costs have been recovered. Recently, the province of Alberta released the findings of the Royalty Review Advisory Panel, which concluded that the royalties for oil sands were appropriate and should be maintained in the new royalty system to be implemented in 2017.
Marketing in Canada
Any oil or gas export that exceeds a certain duration or a certain quantity requires an exporter to obtain export authorizations from Canada’s National Energy Board. The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere.
Environmental and Occupational Regulations
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. Environmental laws and regulations relate to:
| • | the discharge of pollutants into federal 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; 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. We consider the costs of environmental protection and safety and health compliance 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 will likely continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.