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10-K 1 d656849d10k.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, 2013
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 ¨
(Do not check if a 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 28, 2013, was approximately $20.9 billion, based upon the closing price of $51.88 per share as reported by the New York Stock Exchange on such date. On February 12, 2014, 407.4 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2014 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, 2013 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 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 nearly doubled our onshore North American oil production since 2008 and have a deep inventory of development opportunities to deliver future oil growth. We produce about 2.4 billion cubic feet of natural gas a day – more than 3 percent of all the gas consumed in North America. We also own natural gas pipelines, plants and treatment facilities in many of our producing areas, making us one of North America’s larger processors of natural gas.
Devon pioneered the commercial development of natural gas from shale and coalbed formations, and we are a proven leader in using steam to produce bitumen from the Canadian oil sands. 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, 2013, we had approximately 5,900 employees.
Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K as well as any amendments to these reports with the SEC. Through our website, 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 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:
| • | 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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We hold 14 million net acres, of which roughly 60 percent are undeveloped, providing us with a platform for future growth. An important factor in determining the direction of our growth strategy, particularly our capital allocation, is the current and forecasted pricing applicable to our production. Our industry had been operating in an environment that had involved depressed North American gas prices contrasted with more robust prices for oil
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and NGLs. Consequently, we have focused our recent capital programs on higher-margin oil and liquids-based resource capture and development. With recent changes in market conditions that have led to challenged prices for NGLs and Canadian heavy oil, we are refining our capital allocations as needed and evaluating other investment opportunities to maximize and accelerate growth in cash flow per debt-adjusted share.
In pursuit of our goal to build value per share, we entered into two significant agreements near the end of 2013. On November 20, 2013, we entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014, and we have the necessary financing in place to fund the acquisition.
On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), respectively, a master limited partnership and a general partner entity, which will both be publicly traded entities.
In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.
Upon closing of the transactions, the pro forma ownership of EnLink will be approximately:
| • | 70% – Devon Energy Corporation |
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| • | 30% – Current Crosstex Energy, Inc. public stockholders |
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Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:
| • | 53% – Devon Energy Corporation |
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| • | 40% – Current Crosstex Energy, L.P. public unitholders |
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| • | 7% – the General Partner |
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In conjunction with the announcement of the GeoSouthern acquisition, we also announced plans to divest certain non-core properties located throughout Canada and the U. S. On February 19, 2014, we announced our first transaction as a part of this divestiture program, in which we agreed to sell the majority of our Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.8 billion ($3.125 billion in Canadian dollars). We expect this non-core divestiture program will generate organizational and operational efficiencies and will allow us to allocate capital and employee resources to higher-value properties and prospects. We expect to complete the majority of the divestitures by the end of 2014. Once the GeoSouthern acquisition and non-core divestitures are complete, we expect oil production will represent more than 30% of our production profile.
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Oil and Gas Properties
Property Profiles
The locations of our key properties are presented on the following map. These properties include those that currently have significant proved reserves and production, as well as properties that do not currently have significant levels of proved reserves or production but are expected to be the source of significant future growth in proved reserves and production.
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The following table outlines a summary of key data in each of our operating areas for 2013. 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 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 | Gross Wells Drilled | ||||||||||||||||||||||||||
| MMBoe | % of Total | % Liquids | MBoe/d | % of Total | % Liquids | |||||||||||||||||||||||
| Anadarko Basin | 406 | 14 | % | 41 | % | 81.7 | 12 | % | 42 | % | 184 | |||||||||||||||||
| Barnett Shale | 1,093 | 37 | % | 23 | % | 227.7 | 33 | % | 25 | % | 172 | |||||||||||||||||
| Mississippian-Woodford Trend | 32 | 1 | % | 66 | % | 7.9 | 1 | % | 75 | % | 232 | |||||||||||||||||
| Permian Basin | 269 | 9 | % | 79 | % | 78.0 | 11 | % | 78 | % | 348 | |||||||||||||||||
| Rockies | 37 | 1 | % | 47 | % | 21.5 | 3 | % | 40 | % | 37 | |||||||||||||||||
| Other | 161 | 5 | % | 35 | % | 39.6 | 6 | % | 35 | % | 5 | |||||||||||||||||
| U.S. core and emerging properties | 1,998 | 67 | % | 36 | % | 456.4 | 66 | % | 39 | % | 978 | |||||||||||||||||
| Canadian heavy oil | 584 | 20 | % | 99 | % | 83.1 | 12 | % | 96 | % | 186 | |||||||||||||||||
| Total core and emerging properties | 2,582 | 87 | % | 51 | % | 539.5 | 78 | % | 48 | % | 1,164 | |||||||||||||||||
| Non-core properties | 381 | 13 | % | 28 | % | 153.4 | 22 | % | 23 | % | 111 | |||||||||||||||||
| Total | 2,963 | 100 | % | 48 | % | 692.9 | 100 | % | 42 | % | 1,275 | |||||||||||||||||
Core and Emerging Properties
Anadarko Basin – Our acreage is located primarily in Oklahoma’s Canadian, Blaine, Caddo and Dewey counties. The Anadarko Basin is a non-conventional reservoir and produces natural gas, NGLs and condensate.
The Anadarko Basin has rapidly emerged as one of the most economic shale plays in North America. We are the largest leaseholder and the largest producer in the Anadarko Basin. During 2013, we increased our production by 14 percent. We have several thousand remaining drilling locations. In 2014, we plan to drill approximately 95 wells.
In addition, we have a significant processing plant and gathering system to service these properties. Our Cana plant currently has 350 MMcf per day of total capacity.
Barnett Shale – This is our largest property both 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.
We are the largest producer in the Barnett Shale. 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. We have drilled in excess of 5,000 wells in the Barnett Shale since 2002, yet we still have several thousand remaining drilling locations. In 2014, we plan to drill approximately 80 wells, focused in the areas with the highest liquids content.
In addition, we have a significant processing plant and gathering system in north Texas to service these properties. Our Bridgeport plant is one of the largest processing plants in the U.S., currently with 790 MMcf per day of total capacity. These midstream assets also include an extensive pipeline system and a 15 MBbls per day NGL fractionator.
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Mississippian-Woodford Trend – These properties represent some of our newest assets, with most of our position acquired since 2011. Located in northern Oklahoma and southern Kansas, these acres target oil in the Mississippian Lime and Woodford Shale. These areas are being explored and developed under our joint venture arrangement with Sinopec and independently by us on the acreage outside of our area of mutual interest with Sinopec. In 2014, we plan to drill approximately 230 wells.
Permian Basin – Our acreage is located in various counties in west Texas and southeast New Mexico. These properties have been a legacy asset for us and continue to offer both exploration and low-risk development opportunities. We entered into a joint venture arrangement with Sumitomo in 2012, covering approximately 650,000 net acres in the Cline Shale and Midland-Wolfcamp Shale, further strengthening the capital efficiency of our exploration programs. In addition to the Cline and Wolfcamp Shale activity, our current drilling activity continues to target conventional and non-conventional oil and liquids-rich gas targets within the Conventional Delaware, Bone Spring, Midland-Wolfcamp, Wolfberry and Avalon Shale plays. In 2014, we plan to drill approximately 350 wells.
Rockies – Our operations are focused in the Powder River basin in Wyoming where we have 150,000 net acres. These acres are principally located in eastern Wyoming in the counties of Campbell, Converse and Johnson. We are currently targeting several Cretaceous oil objectives, including the Turner, Frontier and Parkman formations. To date we have identified roughly 600 risked locations across these three formations. Our activity and associated capital in the Powder River basin is a part of our joint venture agreement with Sinopec Corporation, under which we receive a drilling carry that funds a significant portion of our capital requirements during the carry period. In 2014, we plan to drill roughly 25 wells in the Powder River Basin.
Canadian Heavy Oil – We are the first and only U.S.-based independent energy company to develop and operate a bitumen oil sands project in Canada. 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 and western Saskatchewan. 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. The first phase of Jackfish is fully operational with a gross facility capacity of 35 MBbls per day. Jackfish production increased 8 percent in 2013 as the second phase of Jackfish, which came on-line in the second quarter of 2011, continued to increase production. Construction of a third phase began in 2012 with plant startup expected by year-end 2014. We expect each phase to maintain a flat production profile for greater than 20 years at an average net production rate of approximately 25-30 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, 2013. We filed a regulatory application in 2012 for the first phase of this project, with gross capacity of 105 MBbls per day, in which we hold a 50 percent interest.
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 Jackfish, and eventually our Pike, heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale. The Access Pipeline system is currently undergoing a capacity expansion that we anticipate will be completed in late 2014. This expansion is expected to create adequate capacity to transport our anticipated Jackfish and Pike heavy oil production to the Edmonton market hub. Additionally, it will increase the transport capacity of condensate diluent available at our thermal oil facilities.
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. We have drilled approximately 2,700 wells in the area since 2003. In 2014, we plan to drill approximately 175 wells.
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Non-Core Properties
Our non-core properties are located throughout the U.S. and Canada and primarily consist of reservoirs that produce dry natural gas. We are in the process of monetizing these assets through a divestiture program we expect to complete by the end of 2014.
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 2013 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 herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included herein. 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 and gas, 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 thirteen years, including the past five 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 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 2013, we engaged two such firms to audit 91 percent of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited 92 percent of our 2013 U.S. reserves, and Deloitte audited 90 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 separately with our senior reserves engineering personnel and our independent petroleum consultants at those meetings. 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 pretax cash flow information related to its 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 herein.
| Year Ended December 31, 2013 | ||||||||||||
| U.S. | Canada | Total | ||||||||||
| (In millions) | ||||||||||||
| Pre-Tax Future Net Revenue (Non-GAAP) (1) | ||||||||||||
| Proved Developed Reserves | $ | 26,617 | $ | 4,100 | $ | 30,717 | ||||||
| Proved Undeveloped Reserves | 3,255 | 8,188 | 11,443 | |||||||||
| Total Proved Reserves | $ | 29,872 | $ | 12,288 | $ | 42,160 | ||||||
| Pre-Tax 10% Present Value (Non-GAAP) (1) | ||||||||||||
| Proved Developed Reserves | $ | 13,862 | $ | 3,623 | $ | 17,485 | ||||||
| Proved Undeveloped Reserves | 988 | 2,864 | 3,852 | |||||||||
| Total Proved Reserves | $ | 14,850 | $ | 6,487 | $ | 21,337 | ||||||
| (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 $15.7 billion at the end of 2013. Included as part of standardized measure were discounted future income taxes of $5.6 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10 percent present value”) was $21.3 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) | |||||||||||||||
| 2013 | ||||||||||||||||||||
| Barnett Shale | 2.0 | — | 1,024.9 | 54.9 | 227.7 | |||||||||||||||
| Jackfish | — | 51.5 | — | — | 51.5 | |||||||||||||||
| U.S. | 77.7 | — | 1,941.8 | 116.0 | 517.3 | |||||||||||||||
| Canada | 39.1 | 51.5 | 451.6 | 9.7 | 175.6 | |||||||||||||||
| Total North America | 116.8 | 51.5 | 2,393.4 | 125.7 | 692.9 | |||||||||||||||
| 2012 | ||||||||||||||||||||
| Barnett Shale | 1.6 | — | 1,074.6 | 46.8 | 227.5 | |||||||||||||||
| Jackfish | — | 47.6 | — | — | 47.6 | |||||||||||||||
| U.S. | 58.7 | — | 2,054.5 | 98.6 | 499.7 | |||||||||||||||
| Canada | 39.8 | 47.6 | 508.3 | 10.5 | 182.6 | |||||||||||||||
| Total North America | 98.5 | 47.6 | 2,562.8 | 109.1 | 682.3 | |||||||||||||||
| 2011 | ||||||||||||||||||||
| Barnett Shale | 1.8 | — | 1,006.0 | 43.7 | 213.1 | |||||||||||||||
| Jackfish | — | 34.8 | — | — | 34.8 | |||||||||||||||
| U.S. | 46.0 | — | 2,026.6 | 90.4 | 474.1 | |||||||||||||||
| Canada | 41.7 | 34.8 | 583.1 | 9.9 | 183.6 | |||||||||||||||
| Total North America | 87.7 | 34.8 | 2,609.7 | 100.3 | 657.7 |
| Average Sales Price | Production Cost (Per Boe) | |||||||||||||||||||
| Year Ended December 31, | Oil (Per Bbl) | Bitumen (Per Bbl) | Gas (Per Mcf) | NGLs (Per Bbl) | ||||||||||||||||
| 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 | ||||||||||
| 2011 | ||||||||||||||||||||
| Barnett Shale | $ | 94.23 | $ | — | $ | 3.30 | $ | 39.00 | $ | 3.97 | ||||||||||
| Jackfish | $ | — | $ | 58.16 | $ | — | $ | — | $ | 17.28 | ||||||||||
| U.S. | $ | 91.19 | $ | — | $ | 3.50 | $ | 39.47 | $ | 5.35 | ||||||||||
| Canada | $ | 74.32 | $ | 58.16 | $ | 3.87 | $ | 55.99 | $ | 13.82 | ||||||||||
| Total North America | $ | 83.16 | $ | 58.16 | $ | 3.58 | $ | 41.10 | $ | 7.71 |
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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 | |||||||||||||||||||||
| 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 | |||||||||||||||||||||
| 2011 | ||||||||||||||||||||||||||||
| U.S. | 721.2 | 5.5 | 18.8 | 4.0 | 740.0 | 9.5 | 749.5 | |||||||||||||||||||||
| Canada | 247.6 | 1.5 | 19.1 | 1.0 | 266.7 | 2.5 | 269.2 | |||||||||||||||||||||
| Total North America | 968.8 | 7.0 | 37.9 | 5.0 | 1,006.7 | 12.0 | 1,018.7 | |||||||||||||||||||||
| (1) | These well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests on the well. |
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The following table presents the February 1, 2014, results of our wells that were in progress on December 31, 2013.
| Productive | Dry | Still in Progress | Total | |||||||||||||||||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||||||||
| U.S. | 11.0 | 5.3 | — | — | 73.0 | 25.8 | 84.0 | 31.1 | ||||||||||||||||||||||||
| Canada | 1.0 | 1.0 | — | — | 5.0 | 3.1 | 6.0 | 4.1 | ||||||||||||||||||||||||
| Total North America | 12.0 | 6.3 | — | — | 78.0 | 28.9 | 90.0 | 35.2 | ||||||||||||||||||||||||
| (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 on the well. |
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Productive Wells
The following table sets forth our producing wells as of December 31, 2013.
| Oil Wells (1) | Natural Gas Wells | Total Wells | ||||||||||||||||||||||
| Gross (2) | Net (3) | Gross (2) | Net (3) | Gross (2) | Net (3) | |||||||||||||||||||
| U.S. | 9,328 | 3,669 | 20,124 | 13,092 | 29,452 | 16,761 | ||||||||||||||||||
| Canada | 5,416 | 4,271 | 5,444 | 3,249 | 10,860 | 7,520 | ||||||||||||||||||
| Total North America | 14,744 | 7,940 | 25,568 | 16,341 | 40,312 | 24,281 | ||||||||||||||||||
| (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 on the 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 24,000 of our 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 area. 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, 2013. The acreage in the table includes 0.7 million, 1.4 million and 0.6 million net acres subject to leases that are scheduled to expire during 2014, 2015 and 2016, respectively. Approximately 18 MMBoe, or 2.5 percent, of our proved undeveloped reserves was attributable to this expiring acreage as of December 31, 2013. Of the 2.7 million net acres set to expire by December 31, 2016, we will perform operational and administrative actions to continue the lease terms for a portion of the acreage, including all the acreage for which we have proved undeveloped reserves at the end of 2013. However, we do expect to allow a portion of the acreage to expire in the normal course of business. In 2013, we allowed approximately 50% of our expiring acreage to expire.
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
| U.S. | 3,312 | 2,107 | 9,281 | 3,698 | 12,593 | 5,805 | ||||||||||||||||||
| Canada | 3,592 | 2,221 | 6,476 | 4,713 | 10,068 | 6,934 | ||||||||||||||||||
| Total North America | 6,904 | 4,328 | 15,757 | 8,411 | 22,661 | 12,739 | ||||||||||||||||||
| (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 on 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.
Marketing and Midstream Activities
Our marketing and midstream operations provide gathering, compression, treating, processing, fractionation and marketing services to us and other third parties. We generate revenues from these operations by collecting service fees and selling processed gas and NGLs. The expenses associated with these operations primarily consist of the costs to operate our gathering systems, plants and related facilities, as well as purchases of gas and NGLs.
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.
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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 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2014, our production was sold under the following contracts.
| Short-Term | Long-Term | |||||||||||||||
| Variable | Fixed | Variable | Fixed | |||||||||||||
| Oil and bitumen | 67 | % | — | 33 | % | — | ||||||||||
| Natural gas | 76 | % | — | 20 | % | 4 | % | |||||||||
| NGLs | 89 | % | 6 | % | 5 | % | — |
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, 2013, 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) | 166 | 24 | 45 | 48 | 49 | |||||||||||||||
| Natural gas (Bcf) | 800 | 481 | 251 | 68 | — | |||||||||||||||
| NGLs (MMBbls) | 61 | 7 | 11 | 12 | 31 | |||||||||||||||
| Total (MMBoe) | 360 | 111 | 98 | 71 | 80 | |||||||||||||||
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 2013, 2012 and 2011, no purchaser accounted for over 10 percent of our operating revenues.
Competition
See “Item 1A. Risk Factors.”
Public Policy and Government Regulation
The oil and natural gas industry is subject to regulation throughout the world. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting the oil and natural gas 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 the oil and natural gas 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
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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 oil and natural gas companies of similar size and financial strength. The following are significant areas of government control and regulation affecting our operations.
Exploration and Production Regulation
Our oil and gas 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 oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, with the royalty rate dependent in part upon prescribed reference prices, well
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productivity, geographical location and the type and quality of the petroleum product produced. Occasionally, the federal and provincial governments of Canada also have established incentive programs, such as royalty rate reductions, royalty holidays, and tax credits, for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally increase our revenues, earnings and cash flow.
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 yet 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.