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Cover and table of contents
10-K 1 d859923d10k.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, 2014
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 of 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. (Check one):
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 Exchange Act). Yes ¨ No x
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2014, was approximately $32.3 billion, based upon the closing price of $79.40 per share as reported by the New York Stock Exchange on such date. On February 11, 2015, 411.1 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2015 annual meeting of stockholders – Part III
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DEVON ENERGY CORPORATION
FORM 10-K
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the United States Securities and Exchange Commission (“SEC”). Such statements are those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2014 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, such as changes in the supply of and demand for oil, natural gas and natural gas liquids (“NGLs”) and related products and services; exploration or drilling programs; our ability to successfully complete mergers, acquisitions and divestitures; political or regulatory events; general economic and financial market conditions; and other risks and factors discussed in this report.
All subsequent written and oral forward-looking statements attributable to Devon Energy Corporation, 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 Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and natural gas liquids (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 200,000 barrels per day and have a deep inventory of development opportunities. Devon also produces over 1.6 billion cubic feet of natural gas a day and more than 130,000 barrels of natural gas liquids per day.
Additionally, in 2014, we combined substantially all of our U.S. midstream assets with Crosstex Energy, Inc. and Crosstex Energy, LP (together “Crosstex”) to form a leading integrated midstream business with enhanced size and scale in key operating regions in the U.S. This midstream business 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 New York Stock Exchange. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2014, Devon and its consolidated subsidiaries had approximately 6,600 employees. Approximately 1,100 of such employees are employed by EnLink Midstream Partners, LP (“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 share. In pursuit of this objective, we focus on growing cash flow per share, adjusted for debt, which we believe has the greatest long-term correlation to share price appreciation in our industry. We also focus on growth in earnings, production and reserves, all on a per debt-adjusted share basis. We do this by:
| • | growing and sustaining a premier portfolio of assets focused on high rate-of-return projects; |
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| • | achieving superior execution through operational and technical excellence, effective project management and exceptional safety results; |
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| • | optimizing cash flow through disciplined capital allocation and cost management; and |
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| • | maintaining financial flexibility and a strong balance sheet. |
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In pursuit of our goal to build value per share, we executed three strategic initiatives in 2014:
| • | Eagle Ford Acquisition – On February 28, 2014, we completed our $6 billion acquisition of interests in certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford from GeoSouthern Energy Corporation (“GeoSouthern”). We funded the acquisition price with cash on hand and debt financing. In connection with the GeoSouthern transaction, we acquired approximately 82,000 net acres located in DeWitt and Lavaca counties in south Texas. |
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| • | MLP Formation – On March 7, 2014, Devon and Crosstex completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business consists of EnLink and EnLink Midstream, LLC (the “General Partner”), a master limited partnership (“MLP”) and a general partner entity, respectively, which are both publicly traded. Devon controls this consolidated entity through its ownership interest in the General Partner. |
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In exchange for a controlling interest in both EnLink and the General Partner, we contributed our equity interest in EnLink Midstream Holdings, LP, a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings owns midstream assets in the Barnett Shale in north Texas and the Cana- and Arkoma-Woodford Shales in Oklahoma, as well as an economic interest in Gulf Coast Fractionators in Mont Belvieu, Texas. As of December 31, 2014, the General Partner and EnLink each held 50% of EnLink Holdings.
| • | Asset Divestitures – In 2014, we completed the divestitures of certain U.S. and Canadian assets for total cash consideration in excess of $5 billion. Proceeds were primarily used to repay debt resulting from the Eagle Ford acquisition noted above. |
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The initiatives above resulted in a more focused asset base, allowing us to better allocate capital and employee resources to the highest-value properties and prospects in our portfolio.
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Oil and Gas Properties
Property Profiles
The locations of our 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 for 2014. Notes 21 and 22 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. In the following table and throughout this report, we convert our proved reserves and production to Boe. Gas proved reserves and production are converted, at the pressure base standard of each respective state in which the gas is produced, to Boe 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.
| Proved Reserves | Production | |||||||||||||||||||||||||||
| MMBoe | % of Total | % Liquids | MBoe/d | % of Total | % Liquids | Gross Wells Drilled | ||||||||||||||||||||||
| Anadarko Basin | 419 | 15 | % | 42 | % | 94 | 14 | % | 45 | % | 130 | |||||||||||||||||
| Barnett Shale | 1,037 | 38 | % | 25 | % | 208 | 31 | % | 27 | % | 84 | |||||||||||||||||
| Eagle Ford | 247 | 9 | % | 74 | % | 65 | 10 | % | 78 | % | 242 | |||||||||||||||||
| Mississippian-Woodford Trend | 22 | 1 | % | 73 | % | 20 | 3 | % | 79 | % | 236 | |||||||||||||||||
| Permian Basin | 279 | 10 | % | 79 | % | 96 | 14 | % | 77 | % | 324 | |||||||||||||||||
| Rockies | 42 | 2 | % | 48 | % | 20 | 3 | % | 50 | % | 40 | |||||||||||||||||
| U.S. – other | 159 | 5 | % | 35 | % | 33 | 5 | % | 32 | % | 5 | |||||||||||||||||
| Total U.S. | 2,205 | 80 | % | 42 | % | 536 | 80 | % | 48 | % | 1,061 | |||||||||||||||||
| Canadian heavy oil | 549 | 20 | % | 99 | % | 86 | 12 | % | 95 | % | 205 | |||||||||||||||||
| Total retained properties | 2,754 | 100 | % | 53 | % | 622 | 92 | % | 55 | % | 1,266 | |||||||||||||||||
| Divested properties | — | N/A | N/A | 51 | 8 | % | 24 | % | — | |||||||||||||||||||
| Total | 2,754 | 100 | % | 53 | % | 673 | 100 | % | 52 | % | 1,266 | |||||||||||||||||
Anadarko Basin – Our acreage is located primarily in Oklahoma’s Canadian, Blaine and Caddo counties. The Anadarko Basin is a non-conventional reservoir and produces natural gas, NGLs and condensate.
The Cana-Woodford play in the Anadarko Basin has emerged as one of the most economic shale plays in North America. We are the largest leaseholder and the largest producer in this play. During 2014, we increased our production by 21 percent. We have several thousand remaining drilling locations. In 2015, we plan to drill approximately 95 gross wells in the Anadarko Basin.
Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. The Barnett Shale is a non-conventional reservoir, producing natural gas, NGLs and condensate.
Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to enhance production and have transformed this into one of the top producing gas fields in North America. In 2015, we plan to drill approximately 10 gross wells.
Eagle Ford – We have approximately 82,000 net acres located in the DeWitt and Lavaca counties in south Texas. The Eagle Ford is an industry-leading, light-oil play and is delivering some of the highest rate-of-return drilling opportunities in North America.
We acquired our position in the Eagle Ford on February 28, 2014 from GeoSouthern and subsequently have produced approximately 24 MMBoe with oil accounting for 61 percent of production from the play. Our acreage in DeWitt County is derisked with at least one well drilled in each of the drilling units, providing us with a significant development drilling inventory. Our development in Lavaca County is less mature, but we have had encouraging results from recently drilled wells. In 2015, we plan to drill approximately 225 gross wells.
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In addition, we have a 100 percent interest in the Victoria Express Pipeline (“VEX”) in south Texas. The VEX pipeline is a 56 mile crude oil pipeline from the Eagle Ford to the Port of Victoria terminal that has a current capacity of 50 MBOPD.
Mississippian-Woodford Trend – Our leases are located in north central Oklahoma targeting oil in the Mississippian Lime and Woodford Shale. These areas are being explored and developed under an arrangement with our joint venture partner and independently by us on the acreage outside of our area of mutual interest with our joint venture partner. In 2015, we plan to drill approximately 50 gross wells.
Permian Basin – The Permian 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, Wolfcamp Shale, Delaware and various conventional formations. These and other emerging oil and liquids-rich opportunities across our acreage in the Permian Basin will deliver high-margin growth for many years to come. In 2015, we plan to drill approximately 240 gross wells.
Rockies – 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 2015, we plan to drill approximately 40 gross wells in the Powder River Basin.
Canadian Heavy Oil – We currently have two main projects, Jackfish and Pike, located in Alberta, Canada. In addition, our Lloydminster properties are located to the south and east of Jackfish in eastern Alberta. Lloydminster produces heavy oil by conventional means, without the need for steam injection.
Jackfish is our thermal heavy oil project in the non-conventional oil sands of east central Alberta. We are employing steam-assisted gravity drainage at Jackfish. In 2014, we brought the third phase of Jackfish into operation. Each phase has a gross facility capacity of 35 MBbls per day at each facility. With three phases of Jackfish operating, production increased 8 percent in 2014. 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.
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, 2014. The regulatory application we filed in 2012 for the first phase of this project was approved in 2014 for initial gross capacity of 105 MBbls per day. We operate and hold a 50 percent interest in the Pike project. Our planned activity at Pike in 2015 consists of front-end engineering and design work, as well as further understanding reservoir characteristics.
To facilitate the delivery of our heavy oil production, we have a 50 percent 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. In 2014, we completed a capacity expansion on the Access Pipeline system, increasing the capacity to transport approximately 170,000 barrels of bitumen blend per day, net to our 50% interest. This expansion is expected to create adequate capacity to transport our growing heavy oil production to the Edmonton market hub. Additionally, it will increase the transport capacity of condensate diluent available at our thermal oil facilities.
In addition to our Jackfish and Pike projects, we hold acreage and own producing assets in the Lloydminster region. Our Lloydminster region is well-developed with significant infrastructure and is primarily accessible year-round for drilling. Lloydminster is a low-risk, high margin oil development play.
In 2015, we plan to drill approximately 130 gross wells in Canada.
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Divested Properties – During 2014, we monetized certain assets through an asset divestiture program. See Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each key property, see Note 22 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.
No estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of 2014 except in filings with the SEC and the Department of Energy (“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.
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 fourteen years, including the past seven 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. The Group’s Director reports to our Vice President of Budget and Reserves, who reports to our Senior Vice President of Business Development, who reports to our Chief Financial Officer. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.
Throughout the year, the Group performs internal 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 consulting firms. During 2014, we engaged two such firms to audit 91 percent of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited 90 percent of our 2014 U.S. reserves, and Deloitte LLP audited 95 percent of our Canadian reserves.
“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 reviews, 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 independent 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 independent engineering consultants; and |
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| • | monitor the performance of our independent engineering consultants. |
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The following table presents our estimated pre-tax cash flow information related to proved reserves. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 22 to our consolidated financial statements included in this report.
| Year Ended December 31, 2014 | ||||||||||||
| U.S. | Canada | Total | ||||||||||
| (In millions) | ||||||||||||
| Pre-Tax Future Net Revenue (Non-GAAP) (1) | ||||||||||||
| Proved Developed Reserves | $ | 32,560 | $ | 4,295 | $ | 36,855 | ||||||
| Proved Undeveloped Reserves | 6,379 | 9,225 | 15,604 | |||||||||
| Total Proved Reserves | $ | 38,939 | $ | 13,520 | $ | 52,459 | ||||||
| Pre-Tax 10% Present Value (Non-GAAP) (1) | ||||||||||||
| Proved Developed Reserves | $ | 17,907 | $ | 3,735 | $ | 21,642 | ||||||
| Proved Undeveloped Reserves | 3,134 | 3,189 | 6,323 | |||||||||
| Total Proved Reserves | $ | 21,041 | $ | 6,924 | $ | 27,965 | ||||||
| (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 depreciation, depletion and amortization, 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 percent present value are non-GAAP measures. The present value of after-tax future net revenues discounted at 10 percent per annum (“standardized measure”) was $20.5 billion at the end of 2014. Included as part of standardized measure were discounted future income taxes of $7.5 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10 percent present value”) was $28 billion. We believe the pre-tax 10 percent present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10 percent present value assists in both the determination 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 percent present value is based on prices and discount factors, which are more consistent from company to company.
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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 (MBbls/d) | Bitumen (MBbls/d) | Gas (MMcf/d) | NGLs (MBbls/d) | Total (MBoe/d) | |||||||||||||||
| 2014 | ||||||||||||||||||||
| Barnett Shale | 2 | — | 909 | 54 | 208 | |||||||||||||||
| Jackfish | — | 56 | — | — | 56 | |||||||||||||||
| U.S. | 130 | — | 1,809 | 137 | 568 | |||||||||||||||
| Canada | 28 | 56 | 111 | 2 | 105 | |||||||||||||||
| Total North America | 158 | 56 | 1,920 | 139 | 673 | |||||||||||||||
| 2013 | ||||||||||||||||||||
| Barnett Shale | 2 | — | 1,025 | 55 | 228 | |||||||||||||||
| Jackfish | — | 51 | — | — | 51 | |||||||||||||||
| U.S. | 78 | — | 1,942 | 116 | 517 | |||||||||||||||
| Canada | 39 | 51 | 451 | 10 | 176 | |||||||||||||||
| Total North America | 117 | 51 | 2,393 | 126 | 693 | |||||||||||||||
| 2012 | ||||||||||||||||||||
| Barnett Shale | 2 | — | 1,075 | 47 | 228 | |||||||||||||||
| Jackfish | — | 48 | — | — | 48 | |||||||||||||||
| U.S. | 58 | — | 2,055 | 99 | 500 | |||||||||||||||
| Canada | 40 | 48 | 508 | 10 | 182 | |||||||||||||||
| Total North America | 98 | 48 | 2,563 | 109 | 682 |
| Average Sales Price | ||||||||||||||||||||
| Year Ended December 31, | Oil (Per Bbl) | Bitumen (Per Bbl) | Gas (Per Mcf) | NGLs (Per Bbl) | Production Cost (Per Boe) | |||||||||||||||
| 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 | ||||||||||
| 2012 | ||||||||||||||||||||
| Barnett Shale | $ | 91.45 | $ | — | $ | 2.23 | $ | 27.57 | $ | 3.91 | ||||||||||
| Jackfish | $ | — | $ | 47.57 | $ | — | $ | — | $ | 19.51 | ||||||||||
| U.S. | $ | 88.68 | $ | — | $ | 2.32 | $ | 28.49 | $ | 5.79 | ||||||||||
| Canada | $ | 68.29 | $ | 47.57 | $ | 2.49 | $ | 48.63 | $ | 15.18 | ||||||||||
| Total North America | $ | 80.43 | $ | 47.57 | $ | 2.36 | $ | 30.42 | $ | 8.30 |
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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 | |||||||||||||||||||||
| 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 | |||||||||||||||||||||
| 2012 | ||||||||||||||||||||||||||||
| U.S. | 668.2 | 1.0 | 24.6 | 4.9 | 692.8 | 5.9 | 698.7 | |||||||||||||||||||||
| Canada | 209.3 | 4.0 | 27.3 | 1.0 | 236.6 | 5.0 | 241.6 | |||||||||||||||||||||
| Total North America | 877.5 | 5.0 | 51.9 | 5.9 | 929.4 | 10.9 | 940.3 | |||||||||||||||||||||
| (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 February 1, 2015 results of our wells that were in progress on December 31, 2014.
| Productive | Dry | Still in Progress | Total | |||||||||||||||||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||||||||
| U.S. | 26.0 | 13.6 | — | — | 66.0 | 27.8 | 92.0 | 41.4 | ||||||||||||||||||||||||
| Canada | 5.0 | 5.0 | 3.0 | 2.5 | 61.0 | 60.5 | 69.0 | 68.0 | ||||||||||||||||||||||||
| Total North America | 31.0 | 18.6 | 3.0 | 2.5 | 127.0 | 88.3 | 161.0 | 109.4 | ||||||||||||||||||||||||
| (1) | Gross wells are the sum of all wells in which we own an 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, 2014.
| Oil Wells (1) | Natural Gas Wells | Total Wells (1) | ||||||||||||||||||||||
| Gross (2) | Net (3) | Gross (2) | Net (3) | Gross (2) | Net (3) | |||||||||||||||||||
| U.S. | 9,927 | 3,963 | 15,870 | 10,586 | 25,797 | 14,549 | ||||||||||||||||||
| Canada | 3,321 | 3,202 | 748 | 538 | 4,069 | 3,740 | ||||||||||||||||||
| Total North America | 13,248 | 7,165 | 16,618 | 11,124 | 29,866 | 18,289 | ||||||||||||||||||
| (1) | Includes bitumen wells. |
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| (2) | Gross wells are the sum of all wells in which we own an interest. |
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| (3) | Net wells are gross wells multiplied by our fractional working interests in each well. |
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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
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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 general and administrative expense, 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, 2014. The acreage in the table includes 0.9 million, 0.3 million and 0.5 million net acres subject to leases that are scheduled to expire during 2015, 2016 and 2017, respectively. As of December 31, 2014, there were no proved undeveloped reserves associated with our expiring acreage. Of the 1.7 million net acres set to expire by December 31, 2017, 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 2014, we allowed approximately 0.2 million acres to expire.
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
| U.S. | 2,688 | 1,735 | 5,797 | 2,931 | 8,485 | 4,666 | ||||||||||||||||||
| Canada | 777 | 582 | 2,147 | 995 | 2,924 | 1,577 | ||||||||||||||||||
| Total North America | 3,465 | 2,317 | 7,944 | 3,926 | 11,409 | 6,243 | ||||||||||||||||||
| (1) | Gross acres are the sum of all acres in which we own an 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 – These assets consist of transmission pipelines with a capacity of approximately 1.3 Bcf/d, processing facilities with a total processing capacity of approximately 1.2 Bcf/d and gathering systems with total capacity of approximately 2.8 Bcf/d. |
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| • | Oklahoma – These 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 and gathering systems with total capacity of approximately 510 MMcf/d. |
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| • | Ohio River Valley – The Ohio River Valley (“ORV”) operations are an integrated network of assets comprised of a 5,000-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot operation crude oil and condensate rail loading terminal on the Ohio Central Railroad network and approximately 200 miles of crude oil and condensate pipelines in Ohio and West Virginia. The assets also include 500,000 barrels of above ground storage and a trucking fleet of approximately 100 vehicles comprised of both semi and straight trucks. EnLink has eight existing brine disposal wells with an injection capacity of approximately 5,000 Bbls/d. Additionally, ORV operations include five condensate stabilization and natural gas compression stations, including two stations under construction, with combined capacities of 19,000 Bbls/d of condensate stabilization and 580 MMcf/d of natural gas compression. |
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Marketing and Midstream Activities
Midstream Operations
Comprising approximately 95% of our 2014 midstream operating profit, EnLink is the primary component of our midstream operations. EnLink’s operations primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation and marketing, to producers of natural gas, NGLs, crude oil and condensate, including Devon. EnLink also provides crude oil, condensate and brine services to producers. 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. Further, 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 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2015, our production was sold under the following contracts.
| Short-Term | Long-Term | |||||||||||||||
| Variable | Fixed | Variable | Fixed | |||||||||||||
| Oil and bitumen | 51 | % | — | 49 | % | — | ||||||||||
| Natural gas | 69 | % | 1 | % | 30 | % | — | |||||||||
| NGLs | 63 | % | 13 | % | 24 | % | — |
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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, 2014, 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) | 180 | 51 | 54 | 47 | 28 | |||||||||||||||
| Natural gas (Bcf) | 711 | 382 | 314 | 15 | — | |||||||||||||||
| NGLs (MMBbls) | 4 | 4 | — | — | — | |||||||||||||||
| Total (MMBoe) | 302 | 118 | 107 | 49 | 28 | |||||||||||||||
We expect to fulfill our delivery commitments over the next three years with production from our proved developed reserves. We expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved developed reserves. In certain regions, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves.
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 satisfy our future commitments. However, should our proved reserves not be sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill the commitments.
Customers
During 2014, 2013 and 2012, no purchaser accounted for over 10 percent of our operating revenues.
Competition
See “Item 1A. Risk Factors.”
Public Policy and Government Regulation
Our industry is subject to regulation throughout the world. 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 laws and 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 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, state, provincial, tribal 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 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**.**
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:
| • | assessing the environmental impact of seismic acquisition, drilling or construction activities; |
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| • | the generation, storage, transportation and disposal of waste materials; |
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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; and |
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| • | the development of emergency response and spill contingency plans. |
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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.