10-K 1 d656849d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

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

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

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

 

 

 


Table of Contents

DEVON ENERGY CORPORATION

FORM 10-K

TABLE OF CONTENTS

 

PART I   

Items 1 and 2. Business and Properties

     3   

Item 1A.  Risk Factors

     17   

Item 1B.  Unresolved Staff Comments

     21   

Item 3.     Legal Proceedings

     21   

Item 4.     Mine Safety Disclosures

     21   
PART II   

Item 5.      Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     22   

Item 6.     Selected Financial Data

     24   

Item 7.      Management’s Discussion and Analysis of Financial Condition and Results of Operations

     25   

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

     47   

Item 8.     Financial Statements and Supplementary Data

     49   

Item 9.      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     104   

Item 9A.  Controls and Procedures

     104   

Item 9B.  Other Information

     104   
PART III   

Item 10.   Directors, Executive Officers and Corporate Governance

     105   

Item 11.   Executive Compensation

     105   

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     105   

Item 13.   Certain Relationships and Related Transactions, and Director Independence

     105   

Item 14.   Principal Accountant Fees and Services

     105   
PART IV   

Item 15.        Exhibits and Financial Statement Schedules

     106   

Signatures

     113   

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,

 

   

purchasing and developing oil and natural gas properties,

 

   

enhancing the value of production through marketing and midstream activities,

 

   

optimizing production operations to control costs, and

 

   

maintaining a strong balance sheet.

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

 

   

30% – Current Crosstex Energy, Inc. public stockholders

Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:

 

   

53% – Devon Energy Corporation

 

   

40% – Current Crosstex Energy, L.P. public unitholders

 

   

7% – the General Partner

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.

 

LOGO

 

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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;

 

   

a petroleum engineering license, or similar certification;

 

   

memberships in oil and gas industry or trade groups; and

 

   

relevant experience estimating reserves.

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),

 

   

Sho-Vel-Tum CO2 Flood (Oklahoma),

 

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West Loco Hills Unit Waterflood and CO2 Flood (New Mexico),

 

   

Dagger Draw Oil Field (New Mexico),

 

   

Clarke Lake Gas Field (Alberta, Canada),

 

   

Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea), and

 

   

ACG Unit (Caspian Sea).

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;

 

   

oversee the integrity of our reserves evaluation and reporting system;

 

   

oversee and evaluate our compliance with legal and regulatory requirements related to our reserves;

 

   

review the qualifications and independence of our independent engineering consultants; and

 

   

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.

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.

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.
(2) Net wells are gross wells multiplied by our fractional working interests on the well.

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.
(2) Gross wells are the sum of all wells in which we own an interest.
(3) Net wells are gross wells multiplied by our fractional working interests on the well.

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.
(2) Net acres are gross acres multiplied by our fractional working interests on the acreage.

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;

 

   

location, drilling and casing of wells;

 

   

well design;

 

   

hydraulic fracturing;

 

   

well production;

 

   

spill prevention plans;

 

   

emissions and discharge permitting;

 

   

use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

 

   

surface usage and the restoration of properties upon which wells have been drilled;

 

   

calculation and disbursement of royalty payments and production taxes;

 

   

plugging and abandoning of wells;

 

   

transportation of production; and

 

   

endangered species and habitat.

Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the forced pooling or 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;

 

   

the generation, storage, transportation and disposal of waste materials;

 

   

the emission of certain gases into the atmosphere;

 

   

the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and

 

   

the development of emergency response and spill contingency plans.

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.

 

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Item 1A. Risk Factors

Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

Oil, Gas and NGL Prices are Volatile

Our financial results are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. A significant downward movement of the prices for these commodities could have a material adverse effect on our revenues, operating cash flows and profitability. Such a downward price movement could also have a material adverse effect on our estimated proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Historically, market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:

 

   

supply of and consumer demand for oil, gas and NGLs;

 

   

conservation efforts;

 

   

OPEC production levels;

 

   

weather;

 

   

regional pricing differentials;

 

   

differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);

 

   

differing quality and NGL content of gas produced;

 

   

the level of imports and exports of oil, gas and NGLs;

 

   

the price and availability of alternative fuels;

 

   

the overall economic environment; and

 

   

governmental regulations and taxes.

Estimates of Oil, Gas and NGL Reserves are Uncertain

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Our policies and internal controls related to estimating and recording reserves are included in “Items 1 and 2. Business and Properties” of this report.

Discoveries or Acquisitions of Reserves are Needed to Avoid a Material Decline in Reserves and Production

The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase, due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies,

 

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identify additional producing zones in existing wells, secondary or tertiary recovery techniques, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.

Future Exploration and Drilling Results are Uncertain and Involve Substantial Costs

Substantial costs are often required to locate and acquire properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling and completing wells are often uncertain. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:

 

   

unexpected drilling conditions;

 

   

pressure or irregularities in reservoir formations;

 

   

equipment failures or accidents;

 

   

fires, explosions, blowouts and surface cratering;

 

   

adverse weather conditions;

 

   

lack of access to pipelines or other transportation methods;

 

   

environmental hazards or liabilities; and

 

   

shortages or delays in the availability of services or delivery of equipment.

A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on our future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

Competition for Leases, Materials, People and Capital Can Be Significant

Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the cost to acquire properties. Certain of our competitors have financial and other resources substantially larger than ours. They also may have established strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels, and the application of government regulations.

Midstream Capacity Constraints and Interruptions Impact Commodity Sales

We rely on midstream facilities and systems to process our natural gas production and to transport our production to downstream markets. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including,

 

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but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third-parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.

Hedging Limits Participation in Commodity Price Increases and Increases Counterparty Credit Risk Exposure

We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.

Public Policy, Which Includes Laws, Rules and Regulations, Can Change

Our operations are generally subject to federal laws, rules and regulations in the United States and Canada. In addition, we are also subject to the laws and regulations of various states, provinces, tribal and local governments. Pursuant to public policy changes, numerous government departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which require substantial compliance costs and carry substantial penalties for failure to comply. Changes in such public policy have affected, and at times in the future could affect, our operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Existing laws and regulations can also require us to incur substantial costs to maintain regulatory compliance. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, income taxes and climate change as discussed below.

Hydraulic Fracturing – The Bureau of Land Management is considering the possibility of additional regulation of hydraulic fracturing on federal and Indian lands. Currently, regulation of hydraulic fracturing is conducted primarily at the state level through permitting and other compliance requirements. We lease federal and Indian lands and would be affected by the Interior Department proposal if it were to become law.

Income Taxes – We are subject to federal, state, provincial and local income taxes and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. Recently, the United States President and other policy makers have proposed provisions that would, if enacted, make significant changes to United States tax laws applicable to us. The most significant change to our business would eliminate the immediate deduction for intangible drilling and development costs. Such a change could have a material adverse effect on our profitability, financial condition and liquidity.

Climate Change – Policymakers in the United States and Canada are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policymakers at both the United States federal and state levels have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. Legislative initiatives and discussions to date have focused

 

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on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs could be relevant to us and our operations in several ways. First, the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. We could therefore be subject to caps, and penalties if emissions exceeded the caps. Second, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases. Therefore, demand for our products could be reduced by imposition of caps and penalties on our customers. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from use of our products by our customers. Of overriding significance would be the point of regulation or taxation. Application of caps or taxes on companies such as Devon, based on carbon content of produced oil and gas volumes rather than on consumer emissions, could lead to penalties, fees or tax assessments for which there are no mechanisms to pass them through the distribution and consumption chain where fuel use or conservation choices are made. Moreover, because oil and natural gas are used as chemical feedstocks and not solely as fossil fuel, applying a carbon tax to oil and gas at the production stage would be excessive with respect to actual carbon emissions from petroleum fuels.

Environmental Matters and Costs Can Be Significant

As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

Insurance Does Not Cover All Risks

Our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development, production, processing and transportation of oil, natural gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to people or loss of life. Additionally, for our non-operated properties, we generally depend on the operator for operational safety and regulatory compliance.

To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain worker’s compensation and employer’s liability insurance. However, our insurance coverage does not provide 100 percent reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance does not cover penalties or fines assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our profitability, financial condition and liquidity.

Limited Control on Properties Operated by Others

Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, including compliance with environmental, health and safety regulations or the amount of

 

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required future capital expenditures. These limitations and our dependence on the operator and other working interest owners for these properties could result in unexpected future costs and adversely affect our financial condition and results of operations.

Cyber Attacks Targeting Our Systems and Infrastructure May Adversely Impact Our Operations

The oil and gas industry has become increasingly dependent on digital technologies to conduct daily operations. Concurrently, the industry has become the subject of increased levels of cyber attack activity. Cyber attacks often attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption and may be carried out by third parties or insiders. The techniques utilized range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be carried out in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. Although we have not suffered material losses related to cyber attacks, if we were successfully attacked we may incur substantial remediation and other costs or suffer other negative consequences. Finally, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.

Item 1B. Unresolved Staff Comments

We have no unresolved SEC Staff comments that have been outstanding greater than 180 days from December 31, 2013.

Item 3. Legal Proceedings

We are involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.

Item 4. Mine Safety Disclosures

Not applicable.

 

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PART II

Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is traded on the New York Stock Exchange (the “NYSE”). On February 5, 2014, there were 10,893 holders of record of our common stock. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE during 2013 and 2012, as well as the quarterly dividends per share paid during 2013 and 2012. We began paying regular quarterly cash dividends on our common stock in the second quarter of 1993. We anticipate continuing to pay regular quarterly dividends in the foreseeable future.

 

     Price Range of Common Stock      Dividends  
             High                      Low                  Per Share      

2013:

        

Quarter Ended December 31, 2013

   $ 66.92       $ 57.58       $ 0.22   

Quarter Ended September 30, 2013

   $ 60.38       $ 52.00       $ 0.22   

Quarter Ended June 30, 2013

   $ 61.10       $ 50.81       $ 0.22   

Quarter Ended March 31, 2013

   $ 61.80       $ 51.63       $ 0.20   

2012:

        

Quarter Ended December 31, 2012

   $ 63.00       $ 50.89       $ 0.20   

Quarter Ended September 30, 2012

   $ 63.95       $ 54.56       $ 0.20   

Quarter Ended June 30, 2012

   $ 73.14       $ 54.01       $ 0.20   

Quarter Ended March 31, 2012

   $ 76.34       $ 62.13       $ 0.20   

 

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Performance Graph

The following performance graph compares the yearly percentage change in the cumulative total shareholder return on Devon’s common stock with the cumulative total returns of the Standard & Poor’s 500 index (“the S&P 500 Index”), the group of companies included in the Crude Petroleum and Natural Gas Standard Industrial Classification code (“the SIC Code”) and a peer group of companies to which we compare our performance. The peer group includes Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, ConocoPhillips, Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Occidental Petroleum Corporation, Pioneer Natural Resources Company and Talisman Energy, Inc. The graph was prepared assuming $100 was invested on December 31, 2008 in Devon’s common stock, the S&P 500 Index, the SIC Code and the peer group and dividends have been reinvested subsequent to the initial investment.

 

LOGO

The graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.

 

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Issuer Purchases of Equity Securities

The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2013. Such purchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises.

 

Period

   Total Number of
Shares Purchased
     Average Price Paid
per Share
 

October 1 – October 31

     1,077       $ 63.22   

November 1 – November 30

     118,940       $ 60.62   

December 1 – December 31

     331,389       $ 60.59   
  

 

 

    

Total

     451,406       $ 60.61   
  

 

 

    

Under the Devon Energy Corporation Incentive Savings Plan (the “Plan”), eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund (the “Stock Fund”), which is administered by an independent trustee. Eligible employees purchased approximately 52,500 shares of our common stock in 2013, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Plan through open-market purchases.

Similarly, under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee. Eligible Canadian employees purchased approximately 10,800 shares of our common stock in 2013, at then-prevailing stock prices, that they held through their ownership in the Canadian Plan. We acquired the shares sold under the Canadian Plan through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S.

Item 6. Selected Financial Data

The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this report.

 

     Year Ended December 31,  
     2013     2012     2011      2010      2009  
     (In millions, except per share amounts)  

Operating revenues

   $ 10,397      $ 9,501      $ 11,445       $ 9,935       $ 8,010   

Earnings (loss) from continuing operations (1)

   $ (20   $ (185   $ 2,134       $ 2,333       $ (2,753

Earnings (loss) per share from continuing operations – Basic

   $ (0.06   $ (0.47   $ 5.12       $ 5.31       $ (6.20

Earnings (loss) per share from continuing operations – Diluted

   $ (0.06   $ (0.47   $ 5.10       $ 5.29       $ (6.20

Cash dividends per common share

   $ 0.86      $ 0.80      $ 0.67       $ 0.64       $ 0.64   

Weighted average common shares outstanding – Basic

     406        404        417         440         444   

Weighted average common shares outstanding – Diluted

     406        404        418         441         444   

Total assets (1)

   $ 42,877      $ 43,326      $ 41,117       $ 32,927       $ 29,686   

Long-term debt

   $ 7,956      $ 8,455      $ 5,969       $ 3,819       $ 5,847   

Stockholders’ equity

   $ 20,499      $ 21,278      $ 21,430       $ 19,253       $ 15,570   

 

(1) During 2013, 2012 and 2009, we recorded noncash asset impairments totaling $2.0 billion ($1.4 billion after income taxes), $2.0 billion ($1.3 billion after income taxes) and $6.4 billion ($4.1 billion after income taxes), respectively.

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.

Overview of 2013 Results

As an enterprise, we strive to optimize value for our shareholders by growing cash flow, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by executing our strategy, which is outlined in “Items 1 and 2. Business and Properties” of this report.

2013 was another year of strong execution and exciting change for Devon. Our oil-focused drilling programs not only accomplished impressive oil production growth, but also expanded margins and improved operating cash flow. Additionally, we took steps to high-grade our portfolio. We did this by announcing an accretive Eagle Ford Shale acquisition, an innovative midstream combination, and the initiation of an asset divestiture program. These actions will provide the platform from which we will deliver outstanding high-margin growth in 2014 and for many years to come.

Key measures of our 2013 performance are summarized below, which exclude amounts from our discontinued operations.

 

     Year Ended December 31,  
     2013     Change     2012     Change     2011  
     ($ in millions, except per share amounts)  

Net earnings (loss)

   $ (20     +89 %   $ (185     -109 %   $ 2,134   

Adjusted earnings (1)

   $ 1,734        +33   $ 1,305        -49 %   $ 2,578   

Earnings (loss) per share

   $ (0.06     +87 %   $ (0.47     -109 %   $ 5.10   

Adjusted earnings per share (1)

   $ 4.26        +32   $ 3.22        -48 %   $ 6.17   

Production (MBoe/d)

     692.9        +2     682.3        +4     657.7   

Realized price per Boe

   $ 33.70        +18   $ 28.65        -17 %   $ 34.64   

Adjusted operating income per Boe (2)

   $ 19.86        +2   $ 19.41        -23 %   $ 25.11   

Operating cash flow

   $ 5,436        +10   $ 4,930        -21 %   $ 6,246   

Capitalized costs

   $ 6,643        -22 %   $ 8,474        +9   $ 7,795   

Shareholder distributions (3)

   $ 348        +8   $ 324        -88 %   $ 2,610   

Reserves (MMBoe)

     2,963        0     2,963        -1 %     3,005   

 

(1) Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are not financial measures prepared in accordance with accounting principles generally accepted in the United States (GAAP). For a description of adjusted earnings, adjusted earnings per share and adjusted operating cash flow as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.
(2) Computed as revenues from commodity sales, commodity derivatives settlements, and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administration, taxes other than income taxes and interest, with the result divided by total production.
(3) Includes common stock dividends and share repurchases.

Our 2013 net loss resulted from noncash asset impairments, which reduced our earnings by $2.0 billion ($1.4 billion after tax). Excluding the asset impairments and other items typically excluded by securities analysts, our adjusted earnings were $1.7 billion, or $4.26 per diluted share. This compares to adjusted earnings of $1.3 billion, or $3.22 per diluted share in 2012.

 

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Our 2013 adjusted earnings, adjusted earnings per share and adjusted operating income per Boe all increased compared to 2012. The improved 2013 results were driven primarily by increases in gas prices, oil volumes and oil realizations. These factors also contributed to higher adjusted operating cash flow, which combined with a reduction in capitalized costs, caused our cash flow deficit to narrow considerably in 2013.

Business and Industry Outlook

North American crude oil and natural gas prices have historically been volatile based on supply and demand dynamics and we expect this volatility to continue into 2014. Although natural gas prices improved in 2013 compared to 2012, natural gas continues to be challenged due to an imbalance between supply and demand across North America. However, arctic air movements across North America during the early weeks of 2014 have caused natural gas demand to surge. As storage inventories have significantly declined in response to the recent weather conditions, natural gas prices have surpassed $5 per Mcf for the first time since the summer of 2010. Further helping demand, new uses of natural gas in industrial, power and other sectors will continue to help support price dynamics. Nevertheless, we still expect natural gas prices to be range-bound as natural gas supply continues to grow, particularly in the U.S. Looking to 2014, we expect natural gas prices will remain relatively consistent or possibly increase moderately from 2013 levels.

Similar to natural gas in recent years, a surge in the supply of natural gas liquids has kept prices challenged. The majority of our natural gas is comprised of ethane, one of the most price-challenged liquids processed from the natural gas stream. We expect 2014 natural gas liquids prices will be range-bound and remain relatively flat compared to 2013.

Crude oil prices remained relatively stable throughout 2013, and oil continues to be more valuable than natural gas on a relative energy-equivalent basis. As a result, we and other producers have been focused on growing oil production. North American crude oil supply continues to increase due to the continued use of horizontal drilling technology throughout the U.S. and expansions of heavy oil production operations primarily in Canada. Global crude oil demand is expected to grow with supply in 2014. As crude oil supply grows, transportation capacity to downstream markets will be increasingly important. Bottlenecks and other transportation limitations may continue to add volatility among U.S. and Canadian grades of oil. However, we expect 2014 oil prices will remain relatively consistent with 2013.

We exited 2013 with a production profile comprised of roughly 55 percent natural gas, 25 percent oil, and 20 percent natural gas liquids. Recognizing the relative value of crude oil, we are devoting the vast majority of our 2014 capital investment toward growing our oil production, particularly the sweet grades of oil found in the U.S. To make a significant shift in our production profile, we expect to complete a $6 billion acquisition of Eagle Ford Shale assets in the first quarter of 2014 and divest non-core, dry natural gas assets throughout 2014. Once these transactions are complete, we expect oil will represent more than 30 percent of our production profile.

Further enhancing the value of our assets, we are combining substantially all of our U.S. midstream assets with Crosstex Energy, Inc.’s and Crosstex Energy, L.P.’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”), a master limited partnership and a general partner entity, which will both be publicly traded entities. The new midstream business 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. Devon will own a 70 percent controlling interest in EnLink and an approximate 53 percent controlling interest in the Partnership.

Results of Operations

All amounts in this document related to our International operations are presented as discontinued. Therefore, the production, revenue and expense amounts presented in this “Results of Operations” section exclude amounts related to our International assets unless otherwise noted.

 

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Oil, Gas and NGL Production

 

     Year Ended December 31,  
     2013      Change     2012      Change     2011  

Oil (MBbls/d)

            

Anadarko Basin

     9.1         +38     6.6         +52     4.4   

Barnett Shale

     2.0         +22     1.6         -12 %     1.8   

Mississippian-Woodford Trend

     4.7         +625     0.7         N/M        —     

Permian Basin

     46.4         +28     36.3         +30     27.8   

Rockies

     7.8         +30     6.0         +38     4.3   

Other

     3.0         +5     2.8         +12     2.6   
  

 

 

      

 

 

      

 

 

 

U.S. core and emerging properties

     73.0         +35     54.0         +32     40.9   

Canadian heavy oil

     27.9         -3 %     28.8         -8 %     31.2   
  

 

 

      

 

 

      

 

 

 

Total core and emerging properties

     100.9         +22     82.8         +15     72.1   

Non-core properties

     15.9         +2     15.7         +1     15.6   
  

 

 

      

 

 

      

 

 

 

Total

     116.8         +19     98.5         +12     87.7   
  

 

 

      

 

 

      

 

 

 

Bitumen (MBbls/d)

            

Canadian heavy oil

     51.5         +8     47.6         +37     34.8   

Gas (MMcf/d)

            

Anadarko Basin

     285.8         0 %     286.3         +25     229.1   

Barnett Shale

     1,024.9         -5 %     1,074.6         +7     1,006.0   

Mississippian-Woodford Trend

     11.6         +701     1.5         N/M        —     

Permian Basin

     104.8         +24     84.8         +13     75.1   

Rockies

     78.0         -28 %     108.6         -23 %     140.3   

Other

     153.8         -12 %     175.0         -16 %     208.3   
  

 

 

      

 

 

      

 

 

 

U.S. core and emerging properties

     1,658.9         -4 %     1,730.8         +4     1,658.8   

Canadian heavy oil

     22.3         -18 %     27.2         -16 %     32.3   
  

 

 

      

 

 

      

 

 

 

Total core and emerging properties

     1,681.2         -4 %     1,758.0         +3     1,691.1   

Non-core properties

     712.2         -12 %     804.8         -12 %     918.6   
  

 

 

      

 

 

      

 

 

 

Total

     2,393.4         -7 %     2,562.8         -2 %     2,609.7   
  

 

 

      

 

 

      

 

 

 

NGLs (MBbls/d)

            

Anadarko Basin

     24.9         +43     17.3         +43     12.2   

Barnett Shale

     54.9         +17     46.8         +7     43.7   

Mississippian-Woodford Trend

     1.2         +770     0.1         N/M        —     

Permian Basin

     14.1         +26     11.2         +29     8.7   

Rockies

     0.8         +5     0.8         -5     0.8   

Other

     11.1         +1     11.0         -11 %     12.3   
  

 

 

      

 

 

      

 

 

 

U.S. core and emerging properties

     107.0         +23     87.2         +12     77.7   

Non-core properties

     18.7         -14 %     21.9         -3 %     22.6   
  

 

 

      

 

 

      

 

 

 

Total

     125.7         +15     109.1         +9     100.3   
  

 

 

      

 

 

      

 

 

 

Combined (MBoe/d)

            

Anadarko Basin

     81.7         +14     71.7         +31     54.7   

Barnett Shale

     227.7         0     227.5         +7     213.1   

Mississippian-Woodford Trend

     7.9         +662     1.0         N/M        —     

Permian Basin

     78.0         +27     61.6         +26     49.0   

Rockies

     21.5         -13 %     24.9         -13 %     28.5   

Other

     39.6         -8 %     43.0         -13 %     49.7   
  

 

 

      

 

 

      

 

 

 

U.S. core and emerging properties

     456.4         +6     429.7         +9     395.0   

Canadian heavy oil

     83.1         +3     80.9         +13     71.4   
  

 

 

      

 

 

      

 

 

 

Total core and emerging properties

     539.5         +6     510.6         +9     466.4   

Non-core properties

     153.4         -11 %     171.7         -10 %     191.3   
  

 

 

      

 

 

      

 

 

 

Total

     692.9         +2     682.3         +4     657.7   
  

 

 

      

 

 

      

 

 

 

 

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Oil, Gas and NGL Pricing

 

     Year Ended December 31,  
     2013 (1)      Change     2012 (1)      Change     2011 (1)  

Oil (per Bbl)

            

U.S.

   $ 94.52         +7   $ 88.68         -3 %   $ 91.19   

Canada

   $ 69.18         +1   $ 68.29         -8 %   $ 74.32   

Total

   $ 86.02         +7   $ 80.43         -3 %   $ 83.16   

Bitumen (per Bbl)

            

Canada

   $ 48.04         +1   $ 47.57         -18 %   $ 58.16   

Gas (per Mcf)

            

U.S.

   $ 3.10         +33   $ 2.32         -34 %   $ 3.50   

Canada

   $ 3.05         +23   $ 2.49         -36 %   $ 3.87   

Total

   $ 3.09         +31   $ 2.36         -34 %   $ 3.58   

NGLs (per Bbl)

            

U.S.

   $ 25.75         -10 %   $ 28.49         -28 %   $ 39.47   

Canada

   $ 46.17         -5 %   $ 48.63         -13 %   $ 55.99   

Total

   $ 27.33         -10 %   $ 30.42         -26 %   $ 41.10   

Combined (per Boe)

            

U.S.

   $ 31.59         +23   $ 25.59         -18 %   $ 31.31   

Canada

   $ 39.91         +8   $ 37.01         -14 %   $ 43.23   

Total

   $ 33.70         +18   $ 28.65         -17 %   $ 34.64   

 

(1) Prices presented exclude any effects due to oil, gas and NGL derivatives.

Commodity Sales

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales.

 

     Oil     Bitumen     Gas     NGLs     Total  
     (In millions)  

2011 sales

   $ 2,660      $ 739      $ 3,411      $ 1,505      $ 8,315   

Change due to volumes

     337        273        (52     137        695   

Change due to prices

     (98     (184     (1,148     (427     (1,857
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2012 sales

   $ 2,899      $ 828      $ 2,211      $ 1,215      $ 7,153   

Change due to volumes

     531        65        (152     181        625   

Change due to prices

     238        9        639        (142     744   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2013 sales

   $ 3,668      $ 902      $ 2,698      $ 1,254      $ 8,522   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Volumes 2013 vs. 2012 – Upstream sales increased $625 million due to a 15 percent increase in our liquids production, partially offset by a 7 percent decline in our gas production. Oil production was the largest driver of the increase, accounting for 85 percent of the higher sales. Largely due to continued development of our properties in the Permian Basin, the Mississippian-Woodford Trend and the Anadarko Basin, our oil sales increased $531 million. Bitumen sales increased $65 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $181 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a 7 percent decrease in our 2013 gas production, resulting in a $152 million decline in sales.

Volumes 2012 vs. 2011 – Upstream sales increased $695 million due to a 4 percent increase in production. Oil and bitumen production were the largest drivers of the increase, accounting for nearly 90 percent of the higher sales. As a result of continued development of our liquids-rich properties in the Permian Basin, our oil

 

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sales increased $337 million. Bitumen sales increased $273 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $137 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a slight decrease in our 2012 gas production, resulting in a $52 million decline in sales.

Prices 2013 vs. 2012 – Upstream sales increased $744 million due to an 18 percent increase in our realized price without hedges. Our gas sales were the most significantly impacted with a $639 million increase in sales. The change in our gas price was largely due to higher North American regional index prices upon which our gas sales are based. Our liquid sales increased $105 million due to higher oil and bitumen sales partially offset by lower NGL sales. The largest contributors to the higher liquids prices were an increase in the average NYMEX West Texas Intermediate index price and a slightly higher bitumen realized price, partially offset by lower NGL prices at the Mont Belvieu, Texas hub.

Prices 2012 vs. 2011 – Upstream sales decreased $1.9 billion due to a 17 percent decrease in our realized price without hedges. Our gas sales were the most significantly impacted with a $1.1 billion decrease in sales. The change in our gas price was largely due to fluctuations of the North American regional index prices upon which our gas sales are based. We also experienced declines in our NGL, bitumen and oil sales due to our realized price. The largest contributors to the lower liquids prices were lower NGL prices at the Mont Belvieu, Texas hub and wider bitumen differentials.

Oil, Gas and NGL Derivatives

The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.

 

     Year Ended December 31,  
     2013     2012     2011  
     (In millions)  

Cash settlements:

      

Oil derivatives

   $ 55      $ 259      $ (26

Gas derivatives

     139        610        416   

NGL derivatives

     1        1        2   
  

 

 

   

 

 

   

 

 

 

Total cash settlements

     195        870        392   
  

 

 

   

 

 

   

 

 

 

Gains (losses) on fair value changes:

      

Oil derivatives

     (243     150        185   

Gas derivatives

     (139     (330     305   

NGL derivatives

     (4     3        (1
  

 

 

   

 

 

   

 

 

 

Total gains (losses) on fair value changes

     (386     (177     489   
  

 

 

   

 

 

   

 

 

 

Oil, gas and NGL derivatives

   $ (191   $ 693      $ 881   
  

 

 

   

 

 

   

 

 

 

 

     Year Ended December 31, 2013  
     Oil
(Per  Bbl)
     Bitumen
(Per Bbl)
     Gas
(Per Mcf)
     NGLs
(Per Bbl)
     Boe
(Per Boe)
 

Realized price without hedges

   $ 86.02       $ 48.04       $ 3.09       $ 27.33       $ 33.70   

Cash settlements of hedges

     1.30         —           0.16         0.01         0.77   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Realized price, including cash settlements

   $ 87.32       $ 48.04       $ 3.25       $ 27.34       $ 34.47   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Table of Contents
     Year Ended December 31, 2012  
     Oil
(Per  Bbl)
    Bitumen
(Per Bbl)
     Gas
(Per  Mcf)
     NGLs
(Per Bbl)
     Boe
(Per  Boe)
 

Realized price without hedges

   $ 80.43      $ 47.57       $ 2.36       $ 30.42       $ 28.65   

Cash settlements of hedges

     7.19        —           0.65         0.04         3.48   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Realized price, including cash settlements

   $ 87.62      $ 47.57       $ 3.01       $ 30.46       $ 32.13   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 
     Year Ended December 31, 2011  
     Oil
(Per Bbl)
    Bitumen
(Per Bbl)
     Gas
(Per Mcf)
     NGLs
(Per Bbl)
     Boe
(Per Boe)
 

Realized price without hedges

   $ 83.16      $ 58.16       $ 3.58       $ 41.10       $ 34.64   

Cash settlements of hedges

     (0.81     —           0.44         0.07         1.63   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Realized price, including cash settlements

   $ 82.35      $ 58.16       $ 4.02       $ 41.17       $ 36.27   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments. A summary of our open commodity derivative positions is included in Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Our oil, gas and NGL derivatives include price swaps, costless collars, basis swaps and call options. To facilitate a portion of our price swaps, we sold gas and oil call options for 2014 through 2016. The call options give counterparties the right to purchase production at a predetermined price.

In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred net losses of $191 million in 2013 and generated net gains of $693 million and $881 million during 2012 and 2011, respectively.

Marketing and Midstream Revenues and Operating Costs and Expenses

 

     Year Ended December 31,  
     2013      Change     2012      Change     2011  
     ($ in millions)  

Revenues

   $ 2,066         +25   $ 1,655         -27 %   $ 2,249   

Operating costs and expenses

     1,553         +25     1,246         -27 %     1,716   
  

 

 

      

 

 

      

 

 

 

Operating profit

   $ 513         +25   $ 409         -23 %   $ 533   
  

 

 

      

 

 

      

 

 

 

2013 vs. 2012 Marketing and midstream operating profit increased $104 million, or 25 percent, from the year ended December 31, 2012 to the year ended December 31, 2013.

Our profit largely increased due to the effects of pricing and marketing activities. Our profit increased nearly $40 million due to our NGL and gas marketing. Additionally, changes in pricing led to an increase in operating profit of approximately $32 million. Higher residue natural gas prices were the primary contributor to the higher profit.

Higher gathering and processing volumes were responsible for an increase in operating profit of $21 million. Higher volumes were primarily the result of NGL production. The increase was largely driven by higher inlet volumes at the Cana processing facility, improved efficiencies at the Cana and Bridgeport processing facilities and downtime impacting our Bridgeport processing facility in 2012.

 

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Operations and maintenance expenses decreased $11 million, or 6 percent primarily due to expenditures for regulatory testing in 2012.

2012 vs. 2011 Marketing and midstream operating profit decreased $124 million, or 23 percent, from the year ended December 31, 2011 to the year ended December 31, 2012.

Our profit largely decreased due to the effects of pricing and marketing activities. Changes in pricing led to a decrease in operating profit of approximately $106 million. Lower residue natural gas and NGL prices were the primary contributor to the lower profit. Additionally, our profit decreased $13 million primarily due to lower profits on our NGL marketing.

Higher gathering, processing and transportation volumes were responsible for an increase in operating profit of $11 million. Higher volumes were primarily the result of additional throughput at Bridgeport and Cana gathering.

Operations and maintenance expenses increased $16 million, or 9 percent primarily due to expenditures for regulatory testing in 2012.

Lease Operating Expenses (“LOE”)

 

     Year Ended December 31,  
     2013      Change     2012      Change     2011  

LOE ($ in millions):

            

U.S.

   $ 1,257         +19   $ 1,059         +14   $ 925   

Canada

     1,011         -0 %     1,015         +10     926   
  

 

 

      

 

 

      

 

 

 

Total

   $ 2,268         +9   $ 2,074         +12   $ 1,851   
  

 

 

      

 

 

      

 

 

 

LOE per Boe:

            

U.S.

   $ 6.65         +15   $ 5.79         +8   $ 5.35   

Canada

   $ 15.78         +4   $ 15.18         +10   $ 13.82   

Total

   $ 8.97         +8   $ 8.30         +8   $ 7.71   

2013 vs. 2012 LOE increased $0.67 per Boe largely because of our liquids production growth, particularly in the Permian Basin and the Mississippian-Woodford Trend in the U.S. These projects generally require a higher per unit cost than our gas projects, particularly because they are in the early stages of development. Additionally, we conducted a turnaround at Jackfish 2 in the third quarter of 2013, contributing to higher unit costs in 2013. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.

2012 vs. 2011 LOE increased $0.59 per Boe largely because of our oil production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.

General and Administrative Expenses (“G&A”)

 

     Year Ended December 31,  
     2013     Change     2012     Change     2011  
     ($ in millions)  

Gross G&A

   $ 1,128        -4 %   $ 1,171        +13   $ 1,036   

Capitalized G&A

     (368     +3     (359     +7     (337

Reimbursed G&A

     (143     +19     (120     +5     (114
  

 

 

     

 

 

     

 

 

 

Net G&A

   $ 617        -11 %   $ 692        +18   $ 585   
  

 

 

     

 

 

     

 

 

 

Net G&A per Boe

   $ 2.44        -12 %   $ 2.77        +14   $ 2.44   
  

 

 

     

 

 

     

 

 

 

 

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2013 vs. 2012 Net G&A and net G&A per Boe decreased largely due to lower personnel expenses and office rent as a result of the Houston office consolidation in 2012 and lower costs as a result of the company-wide implementation of SAP in Q2 2012. Higher reimbursements due to increased liquids drilling activity and reimbursement rates also contributed to the decrease in net G&A and net G&A per Boe.

2012 vs. 2011 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits. Employee costs increased primarily from an expansion of our workforce as part of growing production operations at certain of our key areas, including Jackfish, the Permian Basin and the Anadarko Basin.

Production and Property Taxes

 

     Year Ended December 31,  
     2013     Change     2012     Change     2011  
     ($ in millions)  

Production

   $ 275        +23   $ 224        -10 %   $ 248   

Property and other

     186        -2 %     190        +8     176   
  

 

 

     

 

 

     

 

 

 

Production and property taxes

   $ 461        +11   $ 414        -3 %   $ 424   
  

 

 

     

 

 

     

 

 

 

Percentage of oil, gas and NGL revenue:

          

Production

     3.23     +3     3.13     +5     2.98

Property and other

     2.18     -18 %     2.65     +25     2.12
  

 

 

     

 

 

     

 

 

 

Total

     5.41     -6 %     5.78     +13     5.10
  

 

 

     

 

 

     

 

 

 

2013 vs. 2012 Production and property taxes increased primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.

2012 vs. 2011 Production and property taxes decreased primarily due to a decrease in our U.S. revenues, on which the majority of our production taxes are assessed.

Depreciation, Depletion and Amortization (“DD&A”)

 

     Year Ended December 31,  
     2013      Change     2012      Change     2011  
     ($ in millions)  

DD&A:

            

Oil & gas properties

   $ 2,465         -2 %   $ 2,526         +27   $ 1,987   

Other properties

     315         +11     285         +9     261   
  

 

 

      

 

 

      

 

 

 

Total

   $ 2,780         -1 %   $ 2,811         +25   $ 2,248   
  

 

 

      

 

 

      

 

 

 

DD&A per Boe:

            

Oil & gas properties

   $ 9.75         -4 %   $ 10.12         +22   $ 8.28   

Other properties

     1.24         +9     1.14         +5     1.09   
  

 

 

      

 

 

      

 

 

 

Total

   $ 10.99         -2 %   $ 11.26         +20   $ 9.37   
  

 

 

      

 

 

      

 

 

 

A description of how DD&A of our oil and gas properties is calculated is included in Note 1 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, when the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.

 

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2013 vs. 2012 Oil and gas property DD&A decreased $61 million largely as a result of the asset impairment charges recognized in 2012 and 2013. Depreciation and amortization on our other properties increased $30 million largely from the construction of our new headquarters in Oklahoma City and natural gas pipeline development in the Cana-Woodford Shale.

2012 vs. 2011 Oil and gas property DD&A increased $460 million due to a 22 percent increase in the DD&A rate and $79 million due to our 4 percent increase in production. The largest contributors to the higher rate were our 2012 drilling and development activities.

Asset Impairments

 

     Year Ended December 31, 2013      Year Ended December 31, 2012  
         Gross              Net of Taxes              Gross              Net of Taxes      
     (In millions)  

U.S. oil and gas assets

   $ 1,110       $ 707       $ 1,793       $ 1,142   

Canada oil and gas assets

     843         632         163         122   

Midstream assets

     23         14         68         44   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total asset impairments

   $ 1,976       $ 1,353       $ 2,024       $ 1,308   
  

 

 

    

 

 

    

 

 

    

 

 

 

Oil and Gas Impairments

Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1 to the financial statements under “Item 8. Consolidated Financial Statements” of this report.

The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which have reduced proved reserve values.

Midstream Impairments

Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of our midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.

Net Financing Costs

 

     Year Ended December 31,  
     2013     Change     2012     Change     2011  
     ($ in millions)  

Interest based on debt outstanding

   $ 466        +6   $ 440        +6   $ 414   

Capitalized interest

     (56     +15     (48     -33 %     (72

Other fees and expenses

     27        +94     14        +33     10   
  

 

 

     

 

 

     

 

 

 

Interest expense

     437        +8     406        +15     352   

Interest income

     (20     -43 %     (36     +69     (21
  

 

 

     

 

 

     

 

 

 

Net financing costs

   $ 417        +13   $ 370        +12   $ 331   
  

 

 

     

 

 

     

 

 

 

2013 vs. 2012 Net financing costs increased primarily due to additional debt borrowings and associated fees, partially offset by lower weighted average interest rates and higher capitalized interest. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and to provide funding for our planned Eagle Ford Shale acquisition that is expected to close in the first quarter of 2014.

 

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Table of Contents

2012 vs. 2011 Net financing costs increased primarily due to additional debt borrowings and lower capitalized interest, partially offset by lower weighted average interest rates. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and divestiture proceeds.

Restructuring Costs

 

     Year Ended December 31,  
     2013      2012     2011  
     (In millions)  

Office consolidation:

       

Employee severance and retention

   $ 13       $ 77      $ —     

Lease obligations and other

     41         3        —     
  

 

 

    

 

 

   

 

 

 

Total

     54         80        —     
  

 

 

    

 

 

   

 

 

 

Offshore divestitures:

       

Employee severance

   $ —         $ (3   $ 8   

Lease obligations and other

     —           (3     (10
  

 

 

    

 

 

   

 

 

 

Total

     —           (6     (2
  

 

 

    

 

 

   

 

 

 

Restructuring costs (1)

   $ 54       $ 74      $ (2
  

 

 

    

 

 

   

 

 

 

 

(1) Restructuring costs related to our discontinued operations totaled $(2) million in 2011. These costs primarily consist of employee severance and are not included in the table. There were no costs related to discontinued operations in 2013 or 2012.

Office Consolidation

In October 2012, we announced plans to consolidate our U.S. personnel into a single operations group centrally located at our corporate headquarters in Oklahoma City. As a result, we closed our office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation.

Employee severance and retention – As of December 31, 2013, we had incurred $90 million of employee severance and retention costs associated with the office consolidation. This included amounts related to cash severance costs and accelerated vesting of share-based grants.

Lease obligations and other – As of December 31, 2013, we had incurred $28 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that we ceased using as a part of the office consolidation. Our estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that we may receive over the term of the leases, as well as the amount of variable operating costs that we will be required to pay under the leases.

Divestiture of Offshore Assets

In the fourth quarter of 2009, we announced plans to divest our offshore assets. As of December 31, 2012, we had divested all of our U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.

 

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Table of Contents

Income Taxes

The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the United States statutory income tax rate.

 

     Year Ended December 31,  
     2013     2012     2011  

Total income tax expense (benefit) (in millions)

   $ 169      $ (132   $ 2,156   
  

 

 

   

 

 

   

 

 

 

United States statutory income tax rate

     35     (35 %)      35

State income taxes

     23     6     1

Taxation on Canadian operations

     9     (6 %)      (2 %) 

Repatriations

     65     0     17

Other

     (19 %)      (7 %)      (1 %) 
  

 

 

   

 

 

   

 

 

 

Effective income tax rate

     113     (42 %)      50
  

 

 

   

 

 

   

 

 

 

Pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of our foreign earnings had been deemed to no longer be indefinitely reinvested. As of December 31, 2012, we had recognized a $936 million deferred income tax liability related to assumed repatriations of earnings from our foreign subsidiaries, including $725 million of deferred income tax expense recognized in 2011.

In the second and fourth quarters of 2013, we repatriated to the U. S. a total of $4.3 billion of our cash held outside of the U. S. In the fourth quarter of 2013, we announced plans to divest of our Canadian non-core properties. These events resulted in incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.

In 2013, our state income tax rate is higher than 2012 and 2011 primarily due to the relatively small amount of pre-tax income, resulting from pre-tax income for the U.S. partially offset by a pre-tax loss for Canada. Also, in the table above, the “other” effect is primarily comprised of permanent tax differences for which the dollar amounts do not increase or decrease as our pre-tax earnings do. Generally, such items typically have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate for the years ended December 31, 2013 and 2012, respectively, because of the relatively small pre-tax income/loss for those periods. For 2013 “other” was comprised primarily of tax audit adjustments and a favorable tax impact due to acquisition financing.

Earnings (Loss) From Discontinued Operations

 

     Year Ended December 31,  
     2013      2012     2011  
     (In millions)  

Operating earnings

   $ —         $ —        $ 38   

Gain (loss) on sale of oil and gas properties

     —           (16     2,552   
  

 

 

    

 

 

   

 

 

 

Earnings (loss) before income taxes

     —           (16     2,590   

Income tax expense

     —           5        20   
  

 

 

    

 

 

   

 

 

 

Earnings (loss) from discontinued operations

   $ —         $ (21   $ 2,570   
  

 

 

    

 

 

   

 

 

 

 

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Table of Contents

The earnings (loss) in each period were primarily driven by gains (losses) on the sales of our oil and gas assets in each period. In 2012 we incurred a loss of $16 million ($21 million net of taxes) for the sale of our assets in Angola. In 2011 we generated a gain of $2.5 billion ($2.5 billion net of taxes) for the sale of our assets in Brazil.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major source and use categories of our cash and cash equivalents.

 

     Year Ended December 31,  
     2013     2012     2011  
     (In millions)  

Operating cash flow – continuing operations

   $ 5,436      $ 4,930      $ 6,246   

Capital expenditures

     (6,758     (8,225     (7,534

Debt activity, net

     361        1,921        4,187   

Shareholder distributions

     (348     (324     (2,610

Divestitures of property and equipment

     419        1,539        3,380   

Other

     (24     81        (46
  

 

 

   

 

 

   

 

 

 

Net change in cash and short-term investments

   $ (914   $ (78   $ 3,623   
  

 

 

   

 

 

   

 

 

 

Cash and short-term investments at end of period

   $ 6,066      $ 6,980      $ 7,058   
  

 

 

   

 

 

   

 

 

 

Operating Cash Flow – Continuing Operations

Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in 2013. Our operating cash flow increased 10 percent during 2013 primarily due to higher commodity prices and production growth, partially offset by higher expenses. Our operating cash flow decreased 21 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth and higher cash settlements from our commodity derivatives.

During 2013 our operating cash flow funded approximately 80 percent of our cash payments for capital expenditures. Leveraging our liquidity, we used cash balances, short-term debt and divestiture proceeds to fund the remainder of our cash-based capital expenditures.

Capital Expenditures

 

     Year Ended December 31,  
     2013      2012      2011  
     (In millions)  

Development

   $ 4,754       $ 5,183       $ 5,269   

Exploration

     602         541         378   

Acquisition

     256         1,329         901   
  

 

 

    

 

 

    

 

 

 

Subtotal

     5,612         7,053         6,548   

Capitalized G&A and interest

     354         343         332   
  

 

 

    

 

 

    

 

 

 

Total oil and gas

     5,966         7,396         6,880   

Midstream

     699         504         333   

Corporate and other

     93         325         321   
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 6,758       $ 8,225       $ 7,534   
  

 

 

    

 

 

    

 

 

 

 

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Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $6.0 billion, $7.4 billion and $6.9 billion in 2013, 2012 and 2011, respectively. The 20 percent decline in exploration, development and acquisition capital spending in 2013 was primarily due to a decline in new venture acreage acquisitions and utilization of the drilling carries in 2013 from our Sinopec and Sumitomo joint venture arrangements. The higher exploration and development capital spending in 2012 and 2011 was primarily due to new venture acreage acquisitions and increased drilling and development. With rising oil prices and proceeds from our offshore divestitures, we increased our onshore North American acreage positions and associated exploration and development activities to drive near-term growth of our oil production.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil pipelines. Our midstream capital expenditures are largely impacted by oil and gas drilling activities. The higher 2013 midstream expenditures primarily relate to expansions of our plants serving the Barnett Shale and Cana-Woodford Shale and our Access Pipeline transporting heavy oil in Canada.

Capital expenditures related to other activities decreased in 2013. This decrease is largely driven by the construction of our new headquarters in Oklahoma City, which was completed in 2012.

Debt Activity, Net

During 2013, we increased our debt borrowings by $361 million as a result of issuing $2.25 billion of debt related to the planned Eagle Ford Shale acquisition, which is expected to close in the first quarter of 2014, and repaying approximately $1.9 billion of outstanding short-term debt.

In December 2013, to provide funding for our planned Eagle Ford Shale acquisition, we issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately $2.2 billion, net of discounts and issuance costs.

During 2012, we increased our debt borrowings by $1.9 billion as a result of issuing $2.5 billion of long-term debt and repaying approximately $0.6 billion of outstanding short-term debt. The additional borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.

During 2011, we increased our commercial paper borrowings by $3.7 billion and received $0.5 billion from new debt issuances, net of debt maturities. Proceeds were primarily used to fund capital expenditures and common stock repurchases in excess of operating cash flow.

Shareholder Distributions

The following table summarizes our share repurchases and our common stock dividends (amounts and shares in millions).

 

     2013      2012      2011  
     Amount      Shares      Per Share      Amount      Shares      Per Share      Amount      Shares      Per Share  

Repurchases

     N/A         N/A         N/A         N/A         N/A         N/A       $ 2,332         31.3       $ 74.54   

Dividends

   $ 348         N/A       $ 0.86       $ 324         N/A       $ 0.80       $ 278         N/A       $ 0.67   

In connection with our offshore divestitures, we conducted a $3.5 billion share repurchase program that we completed in the fourth quarter of 2011. Under the program, we repurchased 49.2 million shares, representing 11 percent of our outstanding shares, at an average price of $71.18 per share.

 

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Divestitures of Property and Equipment

In 2013, we sold our Thunder Creek operations in Wyoming for approximately $148 million and our Bear Paw Basin assets in Havre, Montana for approximately $73 million. We also sold other minor oil and gas assets.

During 2012, we closed joint venture transactions with Sinopec and Sumitomo. Sinopec paid approximately $900 million in cash and received a 33.3 percent interest in five of our new ventures exploration plays in the U.S. Sinopec is also funding approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays. Sumitomo paid approximately $400 million and received a 30 percent interest in the Cline and Midland-Wolfcamp Shale plays in Texas. Additionally, Sumitomo is funding approximately $1.0 billion of our share of future exploration, development and drilling costs associated with these plays.

Also in 2012, we sold our West Johnson County Plant and gathering system in north Texas for approximately $90 million and divested our Angola operations for approximately $71 million.

In 2011, our divestitures primarily related to the divestitures of our offshore assets.

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed in this section, including our planned $6 billion acquisition of Eagle Ford Shale assets from GeoSouthern.

Operating Cash Flow and Cash Balances

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. Due to higher commodity prices, our operating cash flow from continuing operations increased 10 percent to $5.4 billion in 2013. We expect operating cash flow to continue to be our primary source of liquidity.

Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. We expect this volatility to continue throughout 2014.

To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum prices on our future production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2013 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.

Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also generally true during periods of depressed commodity prices or reduced activity.

Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2013, we had total debt of $12.0 billion with an overall weighted average borrowing rate of 4.1 percent.

 

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Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. Additionally, we are exposed to the credit risk of counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.

As recent years indicate, we have a history of investing more than 100 percent of our operating cash flow into capital development activities to grow our company and maximize value for our shareholders. Therefore, negative movements in any of the variables discussed above would not only impact our operating cash flow, but also would likely impact the amount of capital investment we could or would make.

At the end of 2013, we held approximately $6.1 billion of cash. Included in this total was $1.8 billion of cash held by our foreign subsidiaries. If we were to repatriate a portion or all of the cash held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U. S. tax law. The payment of such additional income tax would materially decrease the amount of cash and short-term investments ultimately available to fund our business.

Credit Availability

We have a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that matures on October 24, 2018. Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2013, we had $2.9 billion of available capacity under our syndicated, unsecured Senior Credit Facility, net of letters of credit outstanding.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65 percent. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as full cost ceiling impairments. As of December 31, 2013, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2013, as calculated pursuant to the terms of the agreement, was 25.7 percent.

Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.

We also have access to $3.0 billion of short-term credit under our commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2013, we had $1.3 billion of borrowings under our commercial paper program.

 

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Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Our current debt ratings are BBB with a stable outlook by Fitch, BBB+ with a negative outlook by Standard & Poor’s, and Baa1 with a review for downgrade by Moody’s.

There are no “rating triggers” in any of our debt contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs from LIBOR plus 112.5 basis points to a new rate of LIBOR plus 125 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future.

Capital Expenditures

Excluding our planned $6 billion Eagle Ford Shale acquisition, our 2014 capital expenditures are expected to range from $6.4 billion to $6.9 billion, including $5.4 billion to $5.8 billion for our oil and gas operations, which include capitalized G&A and interest. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2014 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2014 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2014, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2014 capital expenditures.

Additionally, our financial and operational flexibility has been further enhanced by the joint venture transactions that we entered into in 2012 with Sinopec and Sumitomo. Pursuant to the joint venture agreements, Sinopec and Sumitomo are subject to drilling carries with remaining commitments that totaled $1.4 billion at the end of 2013. These drilling carries will fund 70 percent of our capital requirements related to joint venture properties, which results in our partners paying approximately 80 percent of the overall development costs during the carry period. This is allowing us to accelerate the de-risking and commercialization of the joint venture properties without diverting capital from our core development projects. We expect the remaining carries will be realized by the end of 2015.

Acquisitions and Divestitures

GeoSouthern Acquisition – 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.

To provide funding for the Eagle Ford Shale acquisition, we issued $2.25 billion of senior notes in December 2013. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45%, which rate will be reset quarterly. The floating rate senior notes due in 2016 bear interest at a rate equal to three-month LIBOR plus 0.54%, which rate will be reset quarterly. We also entered into a term loan agreement in December 2013 with a group of major financial institutions pursuant to which we may draw up to $2.0 billion to finance, in part, the Eagle Ford Shale acquisition and to pay transaction costs. Half of any loans under the term loan agreement will have a maturity of three years and the other half will have a maturity of five years (the 5-Year Loans). The 5-Year Loans will provide for the partial amortization of principal during the last

 

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two years that they are outstanding. Loans borrowed under the term loan agreement may, at our election, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate.

In the event that the Eagle Ford Shale acquisition is not completed on or prior to June 30, 2014, we will be required to redeem each series of new senior notes at 101% of the $2.25 billion aggregate principal amount, plus accrued and unpaid interest.

Crosstex Merger – 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”), 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

 

   

30% – Current Crosstex Energy, Inc. public stockholders

Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:

 

   

53% – Devon Energy Corporation

 

   

40% – Current Crosstex Energy, L.P. public unitholders

 

   

7% – the General Partner

Asset Divestitures – In conjunction with the announcement of the Eagle Ford Shale acquisition, we also announced plans to monetize certain non-core assets located throughout Canada and the U. S. The divestitures will likely occur in a number of separate transactions, but we expect to complete the majority of the divestitures by the end of 2014.

 

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Contractual Obligations

A summary of our contractual obligations as of December 31, 2013, is provided in the following table.

 

     Payments Due by Period  
     Total      Less Than
1 Year
       1-3 Years          3-5 Years        More Than 5
Years
 
     (In millions)  

Debt (1)

   $ 12,042       $ 4,067       $ 500       $ 875       $ 6,600   

Interest expense (2)

     7,328         472         914         845         5,097   

Purchase obligations (3)

     6,425         852         1,819         1,756         1,998   

Operational agreements (4)

     3,449         519         876         723         1,331   

Asset retirement obligations (5)

     2,228         88         146         141         1,853   

Drilling and facility obligations (6)

     366         341         25         —           —     

Lease obligations (7)

     285         41         72         61         111   

Other (8)

     446         272         78         44         52   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 32,569       $ 6,652       $ 4,430       $ 4,445       $ 17,042   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Debt amounts represent scheduled maturities of our debt obligations at December 31, 2013, excluding $20 million of net discounts included in the carrying value of debt. Included in current debt is the $2.25 billion senior notes related to the GeoSouthern acquisition that will be reclassified to long-term once the transaction closes in the first quarter of 2014.

 

(2) Interest expense represents the scheduled cash payments on long-term, fixed-rate debt and an estimate of our floating-rate debt.

 

(3) Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.

 

(4) Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets.

 

(5) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2013 balance sheet.

 

(6) Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.

 

(7) Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.

 

(8) These amounts include $243 million related to uncertain tax positions.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 18 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.

Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the

 

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United States of America requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

Full Cost Method of Accounting and Proved Reserves

Our estimates of proved reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by outside petroleum consultants. In 2013, 91 percent of our reserves were subjected to such audits.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than two percent of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such rules also dictate that a 10 percent discount factor be used. Therefore, the discounted future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs or our enterprise risk.

Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10 percent discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Because of the volatile nature of oil and gas prices, it is not possible to predict the timing or magnitude of full cost write-downs. In addition, due to the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.

Derivative Financial Instruments

We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge future prices received. Our commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.

 

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The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using United States Treasury bill rates. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.

We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. Under the terms of our interest rate swaps, we generally receive a fixed rate and pay a variable rate on a total notional amount. As of December 31, 2013 we had no outstanding interest rate swaps.

We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest rate yields. The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rates. These yield and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward interest rate yields.

We periodically enter into foreign exchange forward contracts to manage our exposure to fluctuations in exchange rates. Under the terms of our foreign exchange forward contracts, we generally receive U.S. dollars and pay Canadian dollars based on a total notional amount.

We estimate the fair values of our foreign exchange forward contracts primarily by using internal discounted cash flow calculations based upon forward exchange rates. The most significant variable to our cash flow calculations is our observation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are discounted using Treasury rates. These discounting variables are sensitive to the period of the contract and market volatility.

We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties.

Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with fourteen separate counterparties, and our foreign exchange forward contracts are held with four separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold for collateral posting decreases as the debt rating falls further below such credit levels.

Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.

Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding

 

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the effects that changes in market prices can have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.

Goodwill

The annual impairment test, which we conduct as of October 31 each year, includes an assessment of qualitative factors and requires us to estimate the fair values of our own assets and liabilities. Because quoted market prices are not available for our reporting units, we must estimate the fair values to conduct the goodwill impairment test. The most significant judgments involved in estimating the fair values of our reporting units relate to the valuation of our property and equipment. We develop estimated fair values of our property and equipment by performing various quantitative analyses using information related to comparable companies, comparable transactions and premiums paid.

In our comparable companies analysis, we review the stock market trading multiples for selected publicly traded independent exploration and production companies with financial and operating characteristics that are comparable to our respective reporting units. Such characteristics are market capitalization, location of proved reserves and the characterization of the operations. In our comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. In our premiums paid analysis, we use a sample of selected transactions of all publicly traded companies announced recently. We then review the premiums paid to the price of the target one day and one month prior to the announcement of the transaction. We use this information to determine the median premiums paid.

We then use the comparable company multiples, comparable transaction multiples, transaction premiums and other data to develop valuation estimates of our property and equipment. We also use market and other data to develop valuation estimates of the other assets and liabilities included in our reporting units. At October 31, 2013, the date of our last impairment test, the fair values of our U.S. and Canadian reporting units exceeded their related carrying values. The fair value of our U.S. reporting unit substantially exceeded its carrying value. However, the fair value of our Canadian reporting is not substantially in excess of its carrying value. As of October 31, 2013, the fair value of our Canadian reporting unit derived by the average of our three valuation methods (comparable company multiples, comparable transaction multiples, and transaction premiums) exceeded its carrying value by approximately 11 percent. As of December 31, 2013, we had $2.8 billion of goodwill allocated to the Canadian reporting unit.

Significant decreases to our stock price, decreases in commodity prices, negative deviations from projected Canadian reporting unit earnings or unfavorable changes in reserves could result in a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates, other than to note the historical average changes in our reserve estimates.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.

 

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The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S., and existing United States income tax laws, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.

For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:

 

   

Separate analysis of a diverse chain of foreign entities;

 

   

Relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;

 

   

Determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings, and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and

 

   

Further analysis of a variety of other inputs such as the earnings, profits, United States/foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.

Because of the administrative burden required to perform these additional activities, it is impracticable to calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of companies.

Non-GAAP Measures

We make reference to “adjusted earnings” and “adjusted earnings per share” in “Overview of 2013 Results” in this Item 7. that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings, as well as the per share amount, represent net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring while comparing on an annual basis. In the below table, restructuring costs were incurred in each of the three year periods, however, these costs relate to different restructuring programs. Amounts excluded for 2013 and a portion of 2012 relate to our office consolidation and amounts excluded for the remaining portion of 2012 and 2011 relate to our offshore divestiture program. For more information on our restructuring programs see Note 6 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

 

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Below are reconciliations of our adjusted earnings and earnings per share to their comparable GAAP measures. The reconciliations exclude amounts related to our discontinued operations.

 

     Year Ended December 31,  
         2013             2012             2011      
     (In millions, except per share amounts)  

Net earnings (loss) (GAAP)

   $ (20   $ (185   $ 2,134   

Adjustments (net of taxes):

      

Asset impairments

     1,353        1,308        —     

Derivatives and other financial instruments

     131        (425     (546

Cash settlements on derivatives and financial instruments

     139        558        308   

U.S. income taxes on foreign earnings

     97        —          744   

Restructuring costs

     34        49        (2

Insurance proceeds

     —          —          (60
  

 

 

   

 

 

   

 

 

 

Adjusted earnings (Non-GAAP)

   $ 1,734      $ 1,305      $ 2,578   
  

 

 

   

 

 

   

 

 

 

Earnings (loss) per share (GAAP)

   $ (0.06   $ (0.47   $ 5.10   

Adjustments (net of taxes):

      

Asset impairments

     3.35        3.23        —     

Derivatives and other financial instruments

     0.31        (1.04     (1.33

Cash settlements on derivatives and financial instruments

     0.34        1.37        0.76   

U.S. income taxes on foreign earnings

     0.24        —          1.78   

Restructuring costs

     0.08        0.13        —     

Insurance proceeds

     —          —          (0.14
  

 

 

   

 

 

   

 

 

 

Adjusted earnings per share (Non-GAAP)

   $ 4.26      $ 3.22      $ 6.17   
  

 

 

   

 

 

   

 

 

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodically enter into financial hedging activities with respect to a portion of our production through various financial transactions that hedge future prices received. The key terms to all our oil, gas and NGL derivative financial instruments as of December 31, 2013 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.

 

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The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2013, a 10 percent increase and 10 percent decrease in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:

 

     10% Increase     10% Decrease  
     (In millions)  

Gain (loss):

    

Gas derivatives

   $ (225   $ 202   

Oil derivatives

   $ (594   $ 545   

NGL derivatives

   $ (1   $ —     

Interest Rate Risk

At December 31, 2013, we had total debt of $12.0 billion. Of this amount, $9.9 billion bears fixed interest rates averaging 4.9 percent. The remaining $2.1 billion of debt is comprised of commercial paper borrowings that bear interest rates averaging 0.30 percent and floating rate debt that at December 31, 2013 had rates averaging 0.73 percent. Our commercial paper borrowings typically have maturities between 1 and 90 days.

Foreign Currency Risk

Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our December 31, 2013 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Additionally, at December 31, 2013, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash and intercompany loans. Based on the amount of the cash and intercompany loans as of December 31, 2013, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.

 

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Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

 

Report of Independent Registered Public Accounting Firm      50   

Consolidated Financial Statements

  

Consolidated Comprehensive Statements of Earnings

     51   

Consolidated Statements of Cash Flows

     52   

Consolidated Balance Sheets

     53   

Consolidated Statements of Stockholders’ Equity

     54   

Notes to Consolidated Financial Statements

     55   

All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Devon Energy Corporation:

We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2013 and 2012, and the related consolidated comprehensive statements of earnings, cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2013. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Devon Energy Corporation’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with United States generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Oklahoma City, Oklahoma

February 28, 2014

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

 

     Year Ended December 31,  
         2013             2012             2011      
     (In millions, except per share amounts)  

Oil, gas and NGL sales

   $ 8,522     $ 7,153     $ 8,315  

Oil, gas and NGL derivatives

     (191     693       881  

Marketing and midstream revenues

     2,066       1,655       2,249  
  

 

 

   

 

 

   

 

 

 

Total operating revenues

     10,397       9,501       11,445  
  

 

 

   

 

 

   

 

 

 

Lease operating expenses

     2,268       2,074       1,851  

Marketing and midstream operating expenses

     1,553       1,246       1,716  

General and administrative expenses

     617       692       585  

Production and property taxes

     461       414       424  

Depreciation, depletion and amortization

     2,780       2,811       2,248  

Asset impairments

     1,976       2,024       —     

Other operating items

     121       92       (11
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     9,776       9,353       6,813  
  

 

 

   

 

 

   

 

 

 

Operating income

     621       148       4,632  

Net financing costs

     417       370       331  

Restructuring costs

     54       74       (2

Other nonoperating items

     1       21       13  
  

 

 

   

 

 

   

 

 

 

Earnings (loss) from continuing operations before income taxes

     149       (317     4,290  

Income tax expense (benefit)

     169       (132     2,156  
  

 

 

   

 

 

   

 

 

 

Earnings (loss) from continuing operations

     (20     (185     2,134  

Earnings (loss) from discontinued operations, net of tax

     —          (21     2,570  
  

 

 

   

 

 

   

 

 

 

Net earnings (loss)

   $ (20   $ (206   $ 4,704