10-K 1 d109858d10k.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, 2015

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 or other jurisdiction of incorporation or organization)   (I.R.S. Employer identification No.)
333 West Sheridan Avenue, Oklahoma City, Oklahoma   73102-5015
(Address of principal executive offices)   (Zip code)

Registrant’s telephone number, including area code:

(405) 235-3611

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

  

Name of each exchange on which registered

Common stock, par value $0.10 per share

   The New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x            Accelerated filer ¨            Non-accelerated filer ¨            Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2015 was approximately $24.3 billion, based upon the closing price of $59.49 per share as reported by the New York Stock Exchange on such date. On February 10, 2016, 441.3 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statement for the 2016 annual meeting of stockholders – Part III

 

 

 


Table of Contents

DEVON ENERGY CORPORATION

FORM 10-K

TABLE OF CONTENTS

 

PART I   

Items 1 and 2. Business and Properties

     6   

Item 1A.  Risk Factors

     20   

Item 1B.  Unresolved Staff Comments

     26   

Item 3.     Legal Proceedings

     26   

Item 4.     Mine Safety Disclosures

     26   
PART II   

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

     27   

Item 6.     Selected Financial Data

     29   

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

     30   

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

     55   

Item 8.     Financial Statements and Supplementary Data

     56   

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

     120   

Item 9A.  Controls and Procedures

     120   

Item 9B.  Other Information

     120   
PART III   

Item 10.   Directors, Executive Officers and Corporate Governance

     121   

Item 11.   Executive Compensation

     121   

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

     121   

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

     121   

Item 14.   Principal Accountant Fees and Services

     121   
PART IV   

Item 15.   Exhibits and Financial Statement Schedules

     122   

Signatures

     129   

 

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DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” refer to Devon Energy Corporation and its consolidated subsidiaries. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:

“2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.

“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.

“ASU” means Accounting Standards Update.

“Bbl” or “Bbls” means barrel or barrels.

“Bcf” means billion cubic feet.

“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.

“Btu” means British thermal units, a measure of heating value.

“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars.

“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.

“Coronado” means Coronado Midstream Holdings LLC.

“Crosstex” means Crosstex Energy, Inc. together with Crosstex Energy L.P.

“DD&A” means depreciation, depletion and amortization expenses.

“Devon Financing” means Devon Financing Company, L.L.C.

“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.

“DOE” means Department of Energy.

“E2” means E2 Energy Services, LLC together with E2 Appalachian Compression, LLC.

“EMH” means EnLink Midstream Holdings, LP.

“EnLink” means EnLink Midstream Partners, L.P., a master limited partnership.

“FASB” means Financial Accounting Standards Board.

“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.

“G&A” means general and administrative expenses.

“General Partner” means EnLink Midstream, LLC, the general partner entity of EnLink.

“GeoSouthern” means GeoSouthern Energy Corporation.

“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

“LIBOR” means London Interbank Offered Rate.

“LOE” means lease operating expenses.

“LPC” means LPC Crude Oil Marketing LLC.

“Matador” means MRC Energy Company.

“MBbls” means thousand barrels.

 

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“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet.

“MLP” means master limited partnership.

“MMBbls” means million barrels.

“MMBoe” means million Boe.

“MMBtu” means million Btu.

“MMcf” means million cubic feet.

“NGL” or “NGLs” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“NYSE” means New York Stock Exchange.

“OPEC” means Organization of the Petroleum Exporting Countries.

“Pre-tax 10% present value” means the present value of Devon’s pre-tax future net revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges.

“SEC” means United States Securities and Exchange Commission.

“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.

“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.

“S&P 500 Index” means Standard and Poor’s 500 index.

“Tall Oak” means Tall Oak Midstream, LLC.

“TSR” means total shareholder return.

“U.S.” means United States of America.

“VEX” means Victoria Express Pipeline and related truck terminal and storage assets.

“WTI” means West Texas Intermediate.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the SEC. Such statements are those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2015 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to:

 

   

the volatility of oil, gas and NGL prices, including the currently depressed commodity price environment;

 

   

uncertainties inherent in estimating oil, gas and NGL reserves;

 

   

the extent to which we are successful in acquiring and discovering additional reserves;

 

   

the uncertainties, costs and risks involved in exploration and development activities;

 

   

risks related to our hedging activities;

 

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counterparty credit risks;

 

   

regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;

 

   

risks relating to our indebtedness;

 

   

our ability to successfully complete mergers, acquisitions and divestitures;

 

   

the extent to which insurance covers any losses we may experience;

 

   

our limited control over third parties who operate our oil and gas properties;

 

   

midstream capacity constraints and potential interruptions in production;

 

   

competition for leases, materials, people and capital;

 

   

cyberattacks targeting our systems and infrastructure; and

 

   

any of the other risks and uncertainties discussed in this report.

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

 

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PART I

Items 1 and 2. Business and Properties

General

Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Our operations are concentrated in various North American onshore areas in the U.S. and Canada. Our portfolio of oil and gas properties provides stable, environmentally responsible production and a platform for future growth. We have doubled our onshore North American oil production since 2010 to more than 275 MBbls per day and have a deep inventory of development opportunities. Devon also produces over 1.6 Bcf of natural gas a day and more than 136 MBbls of NGLs per day.

Additionally, we control EnLink, a leading integrated midstream business with significant size and scale in key operating regions in the U.S. This MLP focuses on providing gathering, transmission, processing, fractionation and marketing to producers of natural gas, NGLs, crude oil and condensate.

A Delaware corporation formed in 1971, we have been publicly held since 1988, and our common stock is listed on the NYSE. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2015, Devon and its consolidated subsidiaries had approximately 6,600 employees. Approximately 1,400 of such employees are employed by EnLink (through its subsidiaries).

Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K as well as any amendments to these reports with the SEC. Through our website, http://www.devonenergy.com, we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees of our Board of Directors and other documents related to our corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer). Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.

In addition, the public may read and copy any materials Devon files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

Strategy

Our primary goal is to build value per debt-adjusted share by:

 

   

exploring for undiscovered oil and natural gas reserves;

 

   

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.

During 2015, we continued to execute on this strategy and experienced a number of key achievements that are outlined in this report. However, we, and the entire upstream energy sector, have faced both operational and financial challenges as oil and natural gas prices weakened significantly throughout 2015 and continued into 2016. To navigate these turbulent times, we are using our focused strategy, flexible portfolio of assets and leadership experience to execute on a number of initiatives that will ensure our long-term financial strength.

 

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Specifically, after completing the STACK acquisition discussed in this report, we had approximately $3.9 billion of liquidity.

While we will continue to operate and develop our premier portfolio of assets, we are committed to protecting our balance sheet and managing our capital programs to be within our cash inflows, including Access Pipeline proceeds. As a result, we are significantly reducing our capital investment in response to lower commodity prices. We plan to invest $900 million to $1.1 billion in our upstream programs, a decrease of roughly 75% compared to our 2015 capital. We are also committed to reducing our G&A and field-level operating costs commensurate with our reduced, but focused, activity level. Following a number of cost-reduction initiatives culminating with our February 2016 workforce reduction, we are expecting a $700 million to $900 million reduction in operating and G&A costs on an annualized basis.

Also, in February 2016, we reduced our quarterly common stock dividend 75% to $0.06 per share.

 

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Oil and Gas Properties

Property Profiles

The locations of our core oil and gas properties are presented on the following map. Additional information related to these properties follows this map, as well as information describing EnLink’s assets.

 

 

LOGO

 

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The following table outlines a summary of key data in each of our operating areas as of and for the year ended December 31, 2015. Notes 20 and 21 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain additional information on our segments and geographical areas.

 

     Proved Reserves     Production        
     MMBoe      % of
Total
    % Liquids         MBoe/d          % of
Total
    %
Liquids
    Gross
Wells
Drilled
 

Delaware Basin

     123         6     78     61         9     79     167   

STACK

     264         12     42     64         9     42     130   

Eagle Ford

     103         4     76     115         17     79     275   

Rockies Oil

     28         1     66     23         3     70     65   

Heavy Oil

     544         25     100     115         17     97     79   

Barnett Shale

     841         39     25     182         27     27     5   
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Core assets

     1,903         87     55     560         82     61     721   

Other

     279         13     57     120         18     58     129   
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total

     2,182         100     56     680         100     60     850   
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Delaware Basin – The Delaware Basin has been a legacy asset for Devon and continues to offer exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, Delaware, Wolfcamp and Leonard formations. These oil and liquids-rich opportunities across our acreage in the Delaware Basin will offer high-margin growth potential for many years to come. In 2016, we plan to invest approximately $200 million of capital in the Delaware Basin, primarily focused on the second Bone Spring opportunity in the basin of southeast New Mexico.

STACK – In early January 2016, we increased our acreage in the Woodford Shale and Meramec plays by acquiring 80,000 net acres in the STACK. The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is named for the stacked pay in the area. Our Woodford Shale position is the largest and one of the best in the industry. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Early drilling activity in the Meramec play has been encouraging across our core position in the oil and liquids window. In 2016, we plan approximately $325 million of capital investment.

Eagle Ford – We acquired our position in the Eagle Ford in early 2014 from GeoSouthern and have approximately 66,000 net acres located in the DeWitt and Lavaca counties in south Texas. Since acquiring these assets, we have delivered tremendous results, increasing production by 125%. Our excellent results are driven by our development in DeWitt County which is located in the economic core of the play. In 2016, we expect our Eagle Ford assets to once again deliver the highest operating margin of any asset in the portfolio and plan approximately $200 million of capital investment.

Rockies Oil – Our operations are focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. In the Powder River, we are currently targeting several Cretaceous oil objectives, including the Turner, Parkman and Frontier formations. Recent drilling success in these formations has expanded our drilling inventory, and we expect further growth as we continue to de-risk this emerging light-oil opportunity. In December 2015, we acquired 253,000 net acres in the “core” of the oil fairway in the Powder River. This acquisition delivers some of the best returns in our portfolio and is a significant resource opportunity. In 2016, we plan approximately $75 million of capital investment.

Heavy Oil – Our operations in Canada are focused on our heavy oil assets in Alberta, Canada. Our most significant Canadian operation is our Jackfish complex, a thermal heavy oil operation in the non-conventional oil sands of east central Alberta. We employ a recovery method known as steam-assisted gravity drainage at Jackfish. In 2014, we brought the third phase of Jackfish into operation, which ramped up to facility capacity by

 

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the third quarter of 2015. We expect each phase to maintain a reasonably flat production profile for greater than 20 years at an average gross production rate of approximately 35 MBbls per day at each facility.

Our Pike oil sands acreage is situated directly to the southeast of our Jackfish acreage in east central Alberta and has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2015. With our 50% partner, we are evaluating our development timeline for Pike.

To facilitate the delivery of our heavy oil production, we have a 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale. The Access Pipeline system has the capacity to transport approximately 170 MBbls of bitumen blend per day, net to our 50% interest. As discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, we have plans to monetize our interest in Access Pipeline in 2016. With any buyer of Access Pipeline, we will also enter into a contractual arrangement to continue transporting our heavy oil volumes on Access Pipeline.

In addition to Jackfish and Pike, we hold acreage and own producing assets in the Bonnyville region, located to the south and east of Jackfish in eastern Alberta. Bonnyville is a low-risk, high margin oil development play that produces heavy oil by conventional means, without the need for steam injection.

In 2016, we plan approximately $175 million of capital investment in our Canadian Heavy Oil business.

Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this into one of the top producing gas fields in North America. Given the commodity price environment in 2015, we shifted focus to enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2015, we accelerated our horizontal refrac program to test the re-stimulation of 25 wells and also had an active vertical refrac program, re-stimulating 140 vertical wells. In 2016, we plan on minimal refrac activity in the Barnett.

Other – Other assets are located primarily in the Midland Basin, east Texas, Granite Wash and Mississippian-Lime areas. Substantially all of these properties have been identified for divestiture in 2016.

Proved Reserves

For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each key property, see Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report.

Since the beginning of 2015, no estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency except in filings with the SEC and the DOE. Reserve estimates filed with the SEC correspond with the estimates of our reserves contained in this report. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included in this report. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.

Proved oil and gas reserves are those quantities of oil, gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

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The process of estimating oil, gas and NGL reserves is complex and requires significant judgment as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators (“Qualified Estimators”), as defined by the Society of Petroleum Engineers’ standards.

The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Group’s Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates, including any or all of the following:

 

   

an undergraduate degree in petroleum engineering from an accredited university, or equivalent;

 

   

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 fifteen years, including the past eight in his current position. During his career, he has been responsible for reserves estimation as the primary reservoir engineer for projects including, but not limited to:

 

   

Hugoton Gas Field (Kansas);

 

   

Sho-Vel-Tum CO2 Flood (Oklahoma);

 

   

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 and currently is in our Chief Financial Officer’s organization. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.

Throughout the year, the Group performs internal reserves audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below. The Group also ensures our Qualified Estimators obtain continuing education related to the fundamentals of SEC proved reserves assignments.

The Group also oversees audits and reserves estimates performed by third-party petroleum consulting firms. During 2015, we engaged two such firms to audit 95% of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited 94% of our 2015 U.S. reserves, and Deloitte LLP audited 96% of our Canadian reserves.

 

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“Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.

In addition to conducting these internal and external audits, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The Reserves Committee assists the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.

The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies and meets at least once a year separately with our senior reserves engineering personnel and separately with our third-party petroleum consultants. The responsibilities of the Reserves Committee include the following:

 

   

approve the scope of and oversee an annual review and evaluation of our oil, gas and NGL reserves;

 

   

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 third-party petroleum consultants; and

 

   

monitor the performance of our third-party petroleum consultants.

The following table presents our estimated pre-tax cash flow information related to our proved reserves. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 21 to our consolidated financial statements included in this report.

 

     Year Ended December 31, 2015  
     U.S.      Canada      Total  
     (Millions)  

Pre-Tax Future Net Revenue (Non-GAAP) (1)

        

Proved Developed Reserves

   $ 6,382       $ 1,874       $ 8,256   

Proved Undeveloped Reserves

     459         1,523         1,982   
  

 

 

    

 

 

    

 

 

 

Total Proved Reserves

   $ 6,841       $ 3,397       $ 10,238   
  

 

 

    

 

 

    

 

 

 

Pre-Tax 10% Present Value (Non-GAAP) (1)

        

Proved Developed Reserves

   $ 4,609       $ 1,657       $ 6,266   

Proved Undeveloped Reserves

     259         458         717   
  

 

 

    

 

 

    

 

 

 

Total Proved Reserves

   $ 4,868       $ 2,115       $ 6,983   
  

 

 

    

 

 

    

 

 

 

 

(1) Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to DD&A, asset impairments or non-property related expenses such as debt service and income tax expense.

Pre-tax future net revenue and pre-tax 10% present value are non-GAAP measures. The standardized measure was $6.7 billion at the end of 2015. Included as part of the standardized measure were discounted future income taxes of $0.3 billion. Excluding these taxes, the pre-tax 10% present value was $7.0 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized

 

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measure. The pre-tax 10% present value assists in both the estimation of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors, which are more consistent from company to company.

Production, Production Prices and Production Costs

The following table presents production, price and cost information for each significant field, country and continent.

 

     Production  

Year Ended December 31,

   Oil (MMBbls)      Bitumen (MMBbls)      Gas (Bcf)      NGLs (MMBbls)      Total (MMBoe)  

2015

              

Barnett Shale

     —           —           291         17         66   

Jackfish

     —           31         —           —           31   

U.S.

     60         —           579         50         206   

Canada

     10         31         8         —           42   

Total North America

     70         31         587         50         248   

2014

              

Barnett Shale

     1         —           332         20         76   

Jackfish

     —           20         —           —           20   

U.S.

     47         —           660         50         207   

Canada

     10         20         41         1         39   

Total North America

     57         20         701         51         246   

2013

              

Barnett Shale

     1         —           374         20         83   

Jackfish

     —           19         —           —           19   

U.S.

     28         —           709         41         189   

Canada

     15         19         165         4         64   

Total North America

     43         19         874         45         253   

 

     Average Sales Price         

Year Ended December 31,

   Oil (Per Bbl)      Bitumen (Per Bbl)      Gas (Per Mcf)      NGLs (Per Bbl)      Production Cost
(Per Boe) (1)
 

2015

              

Barnett Shale

   $ 46.47       $ —         $ 2.00       $ 9.62       $ 6.02   

Jackfish

   $ —         $ 23.41       $ —         $ —         $ 12.43   

U.S.

   $ 44.01       $ —         $ 2.17       $ 9.32       $ 7.52   

Canada

   $ 30.58       $ 23.41       $ 0.67       $ —         $ 13.18   

Total North America

   $ 42.12       $ 23.41       $ 2.14       $ 9.32       $ 8.48   

2014

              

Barnett Shale

   $ 95.51       $ —         $ 3.78       $ 21.98       $ 5.25   

Jackfish

   $ —         $ 55.88       $ —         $ —         $ 20.59   

U.S.

   $ 85.64       $ —         $ 3.92       $ 24.46       $ 7.52   

Canada

   $ 68.14       $ 55.88       $ 3.64       $ 50.52       $ 20.10   

Total North America

   $ 82.47       $ 55.88       $ 3.90       $ 24.89       $ 9.49   

2013

              

Barnett Shale

   $ 97.74       $ —         $ 2.90       $ 22.45       $ 4.12   

Jackfish

   $ —         $ 48.04       $ —         $ —         $ 17.98   

U.S.

   $ 94.52       $ —         $ 3.10       $ 25.75       $ 6.65   

Canada

   $ 69.18       $ 48.04       $ 3.05       $ 46.17       $ 15.78   

Total North America

   $ 86.02       $ 48.04       $ 3.09       $ 27.33       $ 8.97   

 

(1) Represents LOE per Boe and excludes severance and property taxes.

 

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Drilling Statistics

The following table summarizes our development and exploratory drilling results.

 

     Development Wells  (1)      Exploratory Wells  (1)      Total Wells (1)  

Year Ended December 31,

   Productive      Dry      Productive      Dry      Productive      Dry      Total  

2015

                    

U.S.

     298.6         1.8         40.7         —           339.3         1.8         341.1   

Canada

     79.0         —           —           —           79.0         —           79.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total North America

     377.6         1.8         40.7         —           418.3         1.8         420.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2014

                    

U.S.

     474.4         0.4         5.0         1.2         479.4         1.6         481.0   

Canada

     190.8         1.0         —           0.5         190.8         1.5         192.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total North America

     665.2         1.4         5.0         1.7         670.2         3.1         673.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2013

                    

U.S.

     555.3         —           56.1         7.0         611.4         7.0         618.4   

Canada

     211.9         1.0         7.4         —           219.3         1.0         220.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total North America

     767.2         1.0         63.5         7.0         830.7         8.0         838.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) These well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests in each well.

The following table presents the wells that were in progress on December 31, 2015. As of February 1, 2016, these wells were still in progress.

 

     Gross (1)      Net (2)  

U.S.

     17.0         8.6   

Canada

     —           —     
  

 

 

    

 

 

 

Total North America

     17.0         8.6   
  

 

 

    

 

 

 

 

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

Productive Wells

The following table sets forth our producing wells as of December 31, 2015.

 

     Oil Wells (1)      Natural Gas Wells      Total Wells (1)  
     Gross  (2)(4)      Net (3)      Gross  (2)(4)      Net (3)      Gross  (2)(4)      Net (3)  

U.S.

     10,895         4,352         15,130         10,313         26,025         14,665   

Canada

     3,264         3,166         698         498         3,962         3,664   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total North America

     14,159         7,518         15,828         10,811         29,987         18,329   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes bitumen wells.
(2) Gross wells are the sum of all wells in which we own a working interest.
(3) Net wells are gross wells multiplied by our fractional working interests in each well.
(4) Includes 809 and 1,565 oil and gas wells, respectively, which had multiple completions and were operated by Devon.

 

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The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. We are the operator of approximately 19,000 wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the respective areas. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of G&A, which is a common industry practice.

Acreage Statistics

The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2015. Of our 5.5 million net acres, approximately 3.0 million acres are held by production. The acreage in the table includes 0.2 million, 0.4 million and 0.1 million net acres subject to leases that are scheduled to expire during 2016, 2017 and 2018, respectively. As of December 31, 2015, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.7 million net acres set to expire by December 31, 2018, we will perform operational and administrative actions to continue the lease terms for portions of the acreage that we intend to further assess. However, we do expect to allow a portion of the acreage to expire in the normal course of business. In 2015, we allowed approximately 0.8 million acres to expire.

 

     Developed      Undeveloped      Total  
     Gross (1)      Net (2)      Gross (1)      Net (2)      Gross (1)      Net (2)  
     (Thousands)  

U.S.

     2,598         1,732         4,654         2,207         7,252         3,939   

Canada

     705         520         2,147         1,026         2,852         1,546   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total North America

     3,303         2,252         6,801         3,233         10,104         5,485   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Gross acres are the sum of all acres in which we own a working interest.
(2) Net acres are gross acres multiplied by our fractional working interests in 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.

EnLink Properties

EnLink’s assets are comprised of systems and other assets located in four primary regions:

 

   

Texas – The Texas assets consist of transmission pipelines with a capacity of approximately 1.3 Bcf/d, processing facilities with a total processing capacity of approximately 1.4 Bcf/d and gathering systems with total capacity of approximately 2.9 Bcf/d.

 

   

Oklahoma – The Oklahoma assets consist of processing facilities with a total processing capacity of approximately 550 MMcf/d and gathering systems with total capacity of approximately 605 MMcf/d.

 

   

Louisiana – The Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.7 Bcf/d, gathering

 

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systems with total capacity of approximately 510 MMcf/d, 660 miles of liquids transport lines and four fractionation assets with total fractionation capacity of 198 MBbls/d.

 

   

Crude and Condensate – The Crude and Condensate assets consist of approximately 350 miles of crude oil and condensate pipelines with total capacity of approximately 101 MBbls/d, 900 MBbls of above ground storage and eight condensate stabilization and natural gas compression stations with combined capacities of approximately 36 MBbls/d of condensate stabilization and 780 MMcf/d of natural gas compression.

Marketing and Midstream Activities

Midstream Operations

Comprising approximately 98% of our 2015 midstream operating profit, EnLink is the primary component of our midstream operations. EnLink’s operations primarily focus on providing midstream energy services, which consist of gathering, transmission, processing, fractionation and marketing, to producers of natural gas, NGLs, crude oil and condensate, including Devon. EnLink connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. Furthermore, EnLink purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines.

Oil, Gas and NGL Marketing

The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.

Additionally, we may periodically enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.

As of January 2016, our production was sold under the following contract terms.

 

     Short-Term     Long-Term  
     Variable     Fixed     Variable     Fixed  

Oil and bitumen

     72     —          28     —     

Natural gas

     36     4     60     —     

NGLs

     52     10     38     —     

Delivery Commitments

A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. As of December 31, 2015, we were committed to deliver the following fixed quantities of production.

 

     Total      Less Than 1 Year      1-3 Years      3-5 Years      More Than 5 Years  

Oil and bitumen (MMBbls)

     145         38         56         46         5   

Natural gas (Bcf)

           736                 439                 287                 10                 —     

NGLs (MMBbls)

     12         12         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMBoe)

     280         123         104         48         5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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We expect to fulfill our delivery commitments primarily with production from our proved developed reserves. In certain regions, such as in our Heavy Oil operation in Canada, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves.

Generally, our proved reserves have been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to be the primary means of fulfilling our future commitments. However, where our proved reserves are not sufficient to satisfy our delivery commitments, we may be subject to deficiency payments. In such instances, we can and may use spot market purchases to satisfy the commitments.

Customers

During 2015, 2014 and 2013, no purchaser accounted for over 10% of our consolidated operating revenues.

Competition

See “Item 1A. Risk Factors.”

Public Policy and Government Regulation

Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting our industry have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. The following are significant areas of government control and regulation affecting our operations.

Exploration and Production Regulation

Our operations are subject to federal, tribal, state, provincial and local laws and regulations. These laws and regulations relate to matters that include:

 

   

acquisition of seismic data;

 

   

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;

 

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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, venting and flaring and royalty payment obligations for production from federal lands.

Royalties and Incentives in Canada

The royalty system in Canada is a significant factor in the profitability of Canadian oil and gas production. Crown royalties are determined by government regulations and are generally calculated as a percentage of the value of the gross production, net of allowed deductions. The royalty percentage is determined on a sliding-scale based on crown posted prices. The regulations prescribe lower royalty rates for oil sands projects until allowable capital costs have been recovered. Recently, the province of Alberta released the findings of the Royalty Review Advisory Panel, which concluded that the royalties for oil sands were appropriate and should be maintained in the new royalty system to be implemented in 2017.

Marketing in Canada

Any oil or gas export that exceeds a certain duration or a certain quantity requires an exporter to obtain export authorizations from Canada’s National Energy Board. The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere.

Environmental and Occupational Regulations

We are subject to many federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to:

 

   

the discharge of pollutants into federal and state waters;

 

   

assessing the environmental impact of seismic acquisition, drilling or construction activities;

 

   

the generation, storage, transportation and disposal of waste materials, including hazardous substances;

 

   

the emission of certain gases into the atmosphere;

 

   

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

 

   

the development of emergency response and spill contingency plans; and

 

   

worker protection.

 

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Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. We consider the costs of environmental protection and safety and health compliance necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and will likely continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

 

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Item 1A. Risk Factors

Our business and operations, and our industry in general, are subject to a variety of risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business, financial condition, results of operations and liquidity could be materially and adversely 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 and the value of our properties 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. Since the second half of 2014, there has been a significant decline in oil, gas and NGL prices, which has adversely affected our 2015 operating results and contributed to a reduction in our anticipated future capital expenditures. In addition, this decline in commodity prices has adversely impacted our estimated proved reserves and resulted in substantial impairments to our oil and gas properties during 2015. A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:

 

   

reducing the amount of oil, gas and NGLs that we can produce economically;

 

   

limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;

 

   

reducing our revenues, operating cash flows and profitability;

 

   

causing us to further decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production of oil, gas and NGLs; and

 

   

reducing the carrying value of our properties, resulting in additional noncash write-downs.

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 demand for oil, gas and NGLs, including consumer demand in emerging markets, such as China;

 

   

conservation and environmental protection efforts;

 

   

OPEC production levels;

 

   

geopolitical risks;

 

   

adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes;

 

   

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, and the level of global oil, gas and NGL inventories;

 

   

the price and availability of alternative fuels;

 

   

the overall economic environment; and

 

   

governmental regulations and taxes.

 

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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, including commodity price declines, 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, such as identifying additional producing zones in existing wells, utilizing secondary or tertiary recovery techniques or acquiring 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

Our exploration and development activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. 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. In addition, our oil and gas properties can become damaged, our drilling operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:

 

   

unexpected drilling conditions;

 

   

unexpected pressure conditions or irregularities in reservoir formations;

 

   

equipment failures or accidents;

 

   

fires, explosions, blowouts and surface cratering;

 

   

adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes;

 

   

issues with title or in receiving governmental permits or approvals;

 

   

lack of access to pipelines or other transportation methods;

 

   

environmental hazards or liabilities;

 

   

restrictions in access to, or disposal of, water resources used in drilling and completion operations; and

 

   

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

 

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A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property, and certain of these events, particularly equipment failures or accidents, could impact third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant property damage.

Hedging Limits Participation in Commodity Price Increases

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.

The Credit Risk of Our Counterparties Could Adversely Affect Us

We enter into a variety of transactions that expose us to counterparty credit risk. For example, we have exposure to financial institutions and insurance companies through our hedging arrangements, our syndicated revolving credit facility and our insurance policies. Disruptions in the financial markets or otherwise may impact these counterparties and affect their ability to fulfill their existing obligations and their willingness to enter into future transactions with us.

In addition, we are exposed to the risk of financial loss from trade, joint interest billing and other receivables. We sell our oil, gas and NGLs to a variety of purchasers, and, as an operator, we pay expenses and bill our non-operating partners for their respective shares of costs. We also frequently look to buyers of oil and gas properties from us to perform certain obligations associated with the disposed assets, including the removal of production facilities and plugging and abandonment of wells. Certain of these counterparties may experience liquidity problems and may not be able to meet their financial obligations to us, particularly if commodity prices remain depressed or decline further. Any such default by these counterparties could adversely impact our financial results.

We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact Our Business

Our operations are subject to extensive federal, state, provincial, tribal, local and other laws, rules and regulations, including with respect to environmental, health and safety, wildlife conservation, gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with applicable governmental rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, which may result in significant costs associated with the removal of tangible equipment and other restorative actions at the end of operations.

In addition, changes in public policy have affected, and at times in the future could affect, our operations. Regulatory developments could, among other things, restrict production levels, enact price controls, change environmental protection requirements and increase taxes, royalties and other amounts payable to governments or governmental agencies. 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, seismic activity, income taxes and climate change as discussed below.

 

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Hydraulic Fracturing – The U.S. Environmental Protection Agency (“EPA”) and other federal agencies, including the Bureau of Land Management (“BLM”) have made proposals that, if implemented, could either restrict the practice of hydraulic fracturing or subject the process to further regulation. For example, the EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing and proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The BLM and many states have already adopted and more states are considering adopting laws and/or regulations that require disclosure of chemicals used in hydraulic fracturing and impose stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. In addition, some states and municipalities have significantly limited drilling activities and/or hydraulic fracturing, or are considering doing so. Although it is not possible at this time to predict the final outcome of these proposals, any new federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays in development or restrictions on our operations.

Pipeline Safety – The pipeline assets in which we own interests are subject to stringent and complex regulations related to pipeline safety and integrity management. The Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.

Seismic Activity – Recent earthquakes in north-central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry, specifically disposal wells used to inject, into the subsurface, water that is produced along with oil and natural gas. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation that could limit or eliminate our ability to inject produced water into certain disposal wells. Restrictions on such disposal wells could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we could be subject to third-party lawsuits seeking alleged property damages as a result of induced seismic activity in our areas of operation.

Income Taxes – We are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions, 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. The U.S. President and other policy makers have proposed provisions that would, if enacted, make significant changes to U.S. tax laws applicable to us. One significant proposal that has recently been considered at the federal level would eliminate the immediate deduction for intangible drilling and development costs. The adoption of this proposal or other tax changes could have a material adverse effect on our profitability, financial condition and liquidity.

Climate Change – Policy makers in the U.S. and Canada are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policy makers at both the U.S. 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. For example, both the EPA and the BLM have proposed regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry. Legislative and state initiatives to date have generally focused 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

 

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economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. 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. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Severe limitations on greenhouse gas emissions could also adversely affect demand for oil and natural gas, which could have a material adverse effect our profitability, financial condition and liquidity.

Currently, the Alberta Government is developing a new strategy on climate change based on recommendations put forward by the Climate Change Advisory Panel. It is expected that these recommendations will create additional costs for the Canadian oil and gas industry. Presently, it is not possible to accurately estimate the costs we could incur to comply with any law or regulations developed.

Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us

As of December 31, 2015, we had total consolidated indebtedness of $13.1 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:

 

   

requiring us to dedicate a significant portion of our cash flows from operations to debt service payments, thereby limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other general corporate purposes;

 

   

increasing our vulnerability to general adverse economic and industry conditions, including low commodity price environments; and

 

   

limiting our ability to obtain additional financing due to higher costs and more restrictive covenants.

In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that may impact our credit ratings include, among others, debt levels, planned assets sales and purchases, liquidity, forecasted production growth and commodity prices. A ratings downgrade could adversely impact our ability to access financing and trade credit and increase our interest rate under any credit facility borrowing as well as the cost of any other future debt. A ratings downgrade to a rating below investment-grade made by one or more rating agencies could potentially require us to post collateral under certain contractual arrangements.

Environmental Matters and Related 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 remediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil, or criminal fines and penalties, as well as injunctions limiting 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. Changes in or additions to public policy regarding the protection of the environment could have a significant impact on our operations and profitability.

Our Acquisition and Divestiture Activities Involve Substantial Risks

Our business depends, in part, on making acquisitions that complement or expand our current business and successfully integrating any acquired assets or businesses. If we are unable to make attractive acquisitions, then our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an

 

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increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:

 

   

mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;

 

   

difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and

 

   

unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.

In addition, from time to time, we may sell or otherwise dispose of certain of our properties as a result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets and potential post-closing claims for indemnification. Moreover, the current commodity price environment may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing. In addition, we may not realize any expected cost savings from asset dispositions, in part because of revenue losses from the divested properties.

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 workers’ compensation and employer’s liability insurance. However, our insurance coverage does not provide 100% 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 and timing of 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.

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 oil, natural gas and NGL production to downstream markets. Such midstream systems include EnLink’s systems, as

 

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well as other systems operated by us or third parties. 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 from losing access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions and natural disasters, accidents, field labor issues or strikes. Additionally, we and third parties may be subject to constraints that limit our or their 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.

Competition for Assets, 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. Certain of our competitors have financial and other resources substantially greater 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 assets or services. 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.

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

Our 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 to date, if we were successfully attacked, we might incur substantial remediation and other costs or suffer other negative consequences. Moreover, 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

Not applicable.

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 NYSE. On February 10, 2016, there were 8,307 holders of record of our common stock. We began paying regular quarterly cash dividends on our common stock in the second quarter of 1993. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE during 2015 and 2014, as well as the quarterly dividends per share paid during 2015 and 2014.

 

     Price Range of Common Stock      Dividends  
             High                      Low                  Per Share      

Quarter Ended 2015:

        

December 31, 2015

   $ 48.68       $ 28.00       $ 0.24   

September 30, 2015

   $ 59.80       $ 36.01       $ 0.24   

June 30, 2015

   $ 70.48       $ 58.77       $ 0.24   

March 31, 2015

   $ 67.08       $ 56.35       $ 0.24   

Quarter Ended 2014:

        

December 31, 2014

   $ 68.80       $ 51.76       $ 0.24   

September 30, 2014

   $ 80.01       $ 67.58       $ 0.24   

June 30, 2014

   $ 80.63       $ 66.75       $ 0.24   

March 31, 2014

   $ 66.95       $ 57.67       $ 0.22   

In February 2016, we reduced our quarterly common stock dividend 75% to $0.06 per share.

 

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Performance Graph

The following graph compares the cumulative TSR over a five-year period on Devon’s common stock with the cumulative total returns of the S&P 500 Index, our new peer group and our old peer group of companies. Our new peer group includes Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, Concho Resources, Inc., Continental Resources, Inc., ConocoPhillips, Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Noble Energy, Inc., Occidental Petroleum Corporation and Pioneer Natural Resources Company. Concho Resources, Inc. and Continental Resources, Inc. replaced Newfield Exploration Company and Talisman Energy, Inc. from our old peer group. The graph was prepared assuming $100 was invested on December 31, 2010 in Devon’s common stock, the S&P 500 Index and the peer groups, and dividends have been reinvested subsequent to the initial investment.

LOGO

The graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should 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 2015.

 

Period

   Total Number of
Shares Purchased (1)
     Average Price Paid
per Share
 

October 1 – October 31

     5,404       $ 41.78   

November 1 – November 30

     128,025       $ 45.99   

December 1 – December 31

     113,085       $ 44.94   
  

 

 

    

Total

     246,514       $ 45.41   
  

 

 

    

 

(1) Share repurchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting.

Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 71,500 shares of our common stock in 2015, at then-prevailing stock prices, that they held through their ownership in the Devon Stock Fund. We acquired the shares of our common stock sold under the Devon Plan through open-market purchases.

Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Shares sold under the Canadian Plan were acquired 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. In 2015, there were no shares purchased by Canadian employees.

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,  
    2015     2014     2013     2012     2011  
    (Millions, except per share amounts)  

Operating revenues

  $ 13,145      $ 19,566      $ 10,397      $ 9,501      $ 11,445   

Earnings (loss) from continuing operations (1)

  $ (15,203   $ 1,691      $ (20   $ (185   $ 2,134   

Earnings (loss) from continuing operations attributable to Devon

  $ (14,454   $ 1,607      $ (20   $ (185   $ 2,134   

Earnings (loss) from continuing operations per share attributable to Devon – Basic

  $ (35.55   $ 3.93      $ (0.06   $ (0.47   $ 5.12   

Earnings (loss) from continuing operations per share attributable to Devon – Diluted

  $ (35.55   $ 3.91      $ (0.06   $ (0.47   $ 5.10   

Cash dividends per common share

  $ 0.96      $ 0.94      $ 0.86      $ 0.80      $ 0.67   

Weighted average common shares outstanding – Basic

    412        409        406        404        417   

Weighted average common shares outstanding – Diluted

    412        411        406        404        418   

Total assets (1)

  $ 29,532      $ 50,637      $ 42,877      $ 43,326      $ 41,117   

Long-term debt (2)

  $ 12,137      $ 9,830      $ 7,956      $ 8,455      $ 5,969   

Stockholders’ equity

  $ 10,989      $ 26,341      $ 20,499      $ 21,278      $ 21,430   

 

(1) During 2015, we recorded noncash asset impairments totaling $20.8 billion. During 2014, 2013 and 2012, we recorded noncash asset impairments totaling $2.0 billion in each year.
(2) Debt balances at December 31, 2015 and 2014 include $3.1 billion and $2.0 billion, respectively, of EnLink debt that is non-recourse to Devon.

 

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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 2015 Results

By executing on our strategy outlined in “Items 1 and 2. Business and Properties” of this report, we strive to optimize value for our shareholders by growing cash flow, earnings, production and reserves, all on a per debt-adjusted share basis. During 2015, we had several key operating and financial achievements:

 

   

Delivered record crude oil and bitumen production, representing 41% of our total production

 

   

Grew U.S. oil production 28% compared to 2014

 

   

Achieved top-quartile well results in the Delaware Basin of southeast New Mexico

 

   

Exceeded 35 MBbls per day nameplate capacity at Jackfish 3

 

   

Expanded and improved our positions in the STACK and Powder River Basin areas with two separate acquisitions completed for approximately $2 billion of cash and common equity in late 2015 and early 2016

 

   

Sold EnLink units and dropped our interest in VEX to EnLink, generating $821 million in total cash inflows to Devon

 

   

Realized $2.4 billion in cash settlements on our commodity hedge positions

 

   

Reduced LOE $228 million, or 10%, primarily through cost reduction initiatives

 

   

Exited 2015 with $4.7 billion of liquidity consisting of $2.3 billion of cash and $2.4 billion of capacity on our Senior Credit Facility. We have managed our debt maturity schedule to provide maximum flexibility with near-term liquidity; we have no major long-term debt maturities until December 2018.

 

LOGO

  

In spite of these and other operating achievements, weak commodity prices made 2015 a challenging year for the upstream energy sector, including us. As presented in the graph at left, the significant decline in crude oil prices that began in the third quarter of 2014 continued throughout 2015 and weakened further during the first two months of 2016. The 2015 WTI crude oil index was approximately 50% lower than the 2014 average. The downward pressure on oil prices has largely resulted from increased global supply, from both OPEC and non-OPEC countries, and a global economic slowdown that has decreased demand for oil. Similarly, the Henry Hub natural gas and OPIS Mont Belvieu, Texas indices decreased significantly since the end of 2014 as a result of an imbalance between supply and demand across North America.

 

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As a result of these large commodity price declines and in spite of our operating achievements, we recognized $21 billion of noncash asset impairments throughout 2015 that have negatively impacted our financial earnings and retained earnings. Additionally, our core earnings, core earnings per share and operating cash flow for 2015 decreased significantly compared to 2014. Key measures of our financial performance in 2015 are summarized in the following table:

 

     Year Ended December 31,  
     2015     Change     2014      Change     2013  
     (Millions, except per share and per Boe amounts)  

Net earnings (loss) attributable to Devon

   $ (14,454     N/M      $ 1,607         N/M      $ (20

Core earnings attributable to Devon (1)

   $ 1,044        -48   $ 2,017         +16   $ 1,734   

Earnings (loss) per share attributable to Devon

   $ (35.55     N/M      $ 3.91         N/M      $ (0.06

Core earnings per share attributable to Devon (1)

   $ 2.52        -49   $ 4.91         +15   $ 4.26   

Core production (MBoe/d) (2)

     560        +15     489         +16     423   

Total production (MBoe/d)

     680        +1     673         -3     693   

Realized price per Boe (3)

   $ 21.68        -46   $ 40.33         +20   $ 33.70   

Operating cash flow

   $ 5,383        -10   $ 5,981         +10   $ 5,436   

Capitalized costs, including acquisitions

   $ 6,233        -54   $ 13,559         +104   $ 6,643   

Shareholder and noncontrolling interests distributions

   $ 650        +5   $ 621         +78   $ 348   

Reserves (MMBoe)

     2,182        -21     2,754         -7     2,963   

 

(1) Core earnings and core earnings per share attributable to Devon are financial measures not prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”). For a description of core earnings and core earnings per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.
(2) Core production is comprised of production in our key operating areas as outlined and discussed in “Items 1 and 2. Business and Properties” of this report.
(3) Excludes any impact of oil, gas and NGL derivatives.

Business and Industry Outlook

Market prices for crude oil and natural gas are inherently volatile. Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. However, current market fundamentals indicate prices for crude oil and natural gas will continue to be depressed for much of 2016. Although changes in OPEC production strategies, macro-economic forecasts, geopolitical risks or other factors could impact current forecasts, we anticipate weak oil and natural gas prices throughout the majority of 2016.

In 2015, Devon marked its 44th anniversary in the oil and gas business and its 27th year as a public company. As an established company with a strong leadership team, we have experience operating in periods of weak commodity prices. With our focused strategy and portfolio of quality assets, we are prepared to successfully navigate the current pricing challenges and ensure our long-term financial strength.

Specifically, after completing the STACK acquisition, we began 2016 with approximately $3.9 billion of liquidity, consisting of cash and borrowing capacity under our credit facility. We expect to bolster this liquidity in 2016 by monetizing our interest in Access Pipeline and other non-core upstream assets for targeted total proceeds of $2 billion to $3 billion.

While we will continue to operate and develop our premier portfolio of assets, we are committed to protecting our balance sheet and managing our capital programs to be within our cash inflows, including Access Pipeline proceeds. As a result, we are significantly reducing our capital investment in response to lower commodity prices. We plan to invest $900 million to $1.1 billion in our upstream programs, a decrease of roughly 75% compared to our 2015 capital.

We are also committed to reducing our G&A and field-level operating costs commensurate with our reduced, but focused, activity level. In the first quarter of 2016, we announced plans to significantly reduce our

 

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workforce and other G&A costs to better align with the activity level of our core business in the current commodity price environment. The reductions are expected to decrease gross G&A costs by approximately $400 million to $500 million on an annualized basis, excluding associated employee severance and other restructuring costs. Following a number of cost-reduction initiatives culminating with our February 2016 workforce reduction, we are expecting a $700 million to $900 million reduction in operating and G&A costs on an annualized basis.

We estimate we will incur approximately $225 million to $275 million of restructuring costs as a result of the workforce reduction. We expect to recognize the majority of these restructuring costs in the first quarter of 2016 and will recognize the remaining costs throughout 2016 until our planned divestiture transactions have closed and further workforce reductions occur.

Also, in February 2016, we reduced our quarterly common stock dividend 75% to $0.06 per share.

 

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Results of Operations

Oil, Gas and NGL Production

 

     Year Ended December 31,  
     2015      Change     2014      Change     2013  

Oil (MBbls/d)

            

Delaware Basin

     39         +48     26         +33     20   

STACK

     6         +6     6         +23     5   

Eagle Ford

     66         +66     39         N/M        —     

Rockies Oil

     15         +39     10         -1     11   

Heavy Oil

     27         +3     26         -7     28   

Barnett Shale

     1         -38     2         -2     2   
  

 

 

      

 

 

      

 

 

 

Core assets

     154         +42     109         +66     66   

Other (1)

     37         -25     49         -5     51   
  

 

 

      

 

 

      

 

 

 

Total

     191         +20     158         +36     117   
  

 

 

      

 

 

      

 

 

 

Bitumen (MBbls/d)

            

Heavy Oil

     84         +51     56         +8     51   

Gas (MMcf/d)

            

Delaware Basin

     73         +9     67         +16     57   

STACK

     226         -3     234         +14     205   

Eagle Ford

     148         +70     87         N/M        —     

Rockies Oil

     40         -17     47         -22     61   

Heavy Oil

     22         -5     23         -19     28   

Barnett Shale

     797         -12     909         -11     1,025   
  

 

 

      

 

 

      

 

 

 

Core assets

     1,306         -4     1,367         -1     1,376   

Other (1)

     304         -45     553         -46     1,017   
  

 

 

      

 

 

      

 

 

 

Total

     1,610         -16     1,920         -20     2,393   
  

 

 

      

 

 

      

 

 

 

NGLs (MBbls/d)

            

Delaware Basin

     9         +24     8         +24     6   

STACK

     21         -8     22         +33     17   

Eagle Ford

     25         +115     11         N/M        —     

Rockies Oil

     1         +33     1         +27     1   

Barnett Shale

     48         -12     55         -1     55   
  

 

 

      

 

 

      

 

 

 

Core assets

     104         +7     97         +23     79   

Other (1)

     32         -25     42         -11     47   
  

 

 

      

 

 

      

 

 

 

Total

     136         -2     139         +10     126   
  

 

 

      

 

 

      

 

 

 

Combined (MBoe/d)

            

Delaware Basin

     61         +35     45         +27     36   

STACK

     64         -4     67         +21     56   

Eagle Ford

     115         +75     65         N/M        —     

Rockies Oil

     23         +29     18         -6     19   

Heavy Oil

     115         +34     86         +2     85   

Barnett Shale

     182         -13     208         -9     228   
  

 

 

      

 

 

      

 

 

 

Core assets

     560         +14     489         +15     424   

Other (1)

     120         -35     184         -32     269   
  

 

 

      

 

 

      

 

 

 

Total

     680         +1     673         -3     693   
  

 

 

      

 

 

      

 

 

 

 

(1) Other assets are located primarily in the Midland Basin, east Texas, Granite Wash and Mississippian-Lime areas. Substantially all of these properties have been identified for divestiture in 2016.

 

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Oil, Gas and NGL Pricing

 

     Year Ended December 31,  
     2015 (1)      Change     2014 (1)      Change     2013 (1)  

Oil (per Bbl)

            

U.S.

   $ 44.01         -49   $ 85.64         -9   $ 94.52   

Canada

   $ 30.58         -55   $ 68.14         -1   $ 69.18   

Total

   $ 42.12         -49   $ 82.47         -4   $ 86.02   

Bitumen (per Bbl)

            

Canada

   $ 23.41         -58   $ 55.88         +16   $ 48.04   

Gas (per Mcf)

            

U.S.

   $ 2.17         -45   $ 3.92         +27   $ 3.10   

Canada (2)

   $ 0.67         -82   $ 3.64         +19   $ 3.05   

Total

   $ 2.14         -45   $ 3.90         +26   $ 3.09   

NGLs (per Bbl)

            

U.S.

   $ 9.32         -62   $ 24.46         -5   $ 25.75   

Canada

   $ —           N/M      $ 50.52         +9   $ 46.17   

Total

   $ 9.32         -63   $ 24.89         -9   $ 27.33   

Combined (per Boe)

            

U.S.

   $ 21.12         -44   $ 37.96         +20   $ 31.59   

Canada

   $ 24.46         -54   $ 53.11         +33   $ 39.91   

Total

   $ 21.68         -46   $ 40.33         +20   $ 33.70   

 

(1) Prices presented exclude any effects of oil, gas and NGL derivatives.
(2) The reported Canadian gas volumes include 12, 21 and 25 MMcf per day for the years ended 2015, 2014 and 2013, respectively, that are produced from certain of our leases and then transported to our Jackfish operations where the gas is used as fuel. However, the revenues and expenses related to this consumed gas are eliminated in our consolidated financial results. With the sale of the vast majority of the Canadian gas business in the second quarter of 2014, the eliminated gas revenues subsequently impacted our gas price more significantly.

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  
     (Millions)  

2013 sales

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

Change due to volumes

     1,311        76        (533     131        985   

Change due to prices

     (206     160        572        (123     403   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2014 sales

   $ 4,773      $ 1,138      $ 2,737      $ 1,262      $ 9,910   

Change due to volumes

     976        584        (443     (23     1,094   

Change due to prices

     (2,813     (1,000     (1,034     (775     (5,622
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2015 sales

   $ 2,936      $ 722      $ 1,260      $ 464      $ 5,382   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Volumes 2015 vs. 2014 Oil, gas and NGL sales increased due to volumes in 2015 because of strong production growth from our U.S. oil properties. The growth was primarily driven by the continued development of our Eagle Ford, Delaware Basin and Rockies Oil properties. Additionally, our bitumen production increased primarily due to Jackfish 3 coming on-line late in the third quarter of 2014 and reaching nameplate capacity in the third quarter of 2015. Lower royalties resulting from the significant price decrease also increased our heavy

 

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oil production. The increases were partially offset by a decrease in our gas production, which resulted primarily from asset divestitures in 2014 and natural reservoir declines.

Volumes 2014 vs. 2013 Oil, gas and NGL sales increased due to volumes primarily because of a 66% increase in our core assets oil production. Such growth resulted from our Eagle Ford properties and the continued development of our properties in the Delaware Basin. In addition, we continued to grow our NGL production from the Delaware Basin and STACK, which resulted in $131 million of additional sales. Bitumen sales increased due to development of our Jackfish thermal heavy oil projects in Canada, including Jackfish 3 which had first sales in 2014. These increases were partially offset by a 20% decrease in our 2014 gas production, which was impacted by our asset divestitures and natural declines.

Prices 2015 vs. 2014 Oil, gas and NGL sales decreased in 2015 as a result of significantly lower prices for all commodities. The decrease in oil and bitumen sales primarily resulted from significantly lower average WTI crude oil index prices, which were approximately 50% lower in 2015 as compared to 2014. The decreases in gas and NGL sales were driven by lower North American regional index prices upon which our gas sales are based and lower NGL prices at the Mont Belvieu, Texas hub.

Prices 2014 vs. 2013 Oil, gas and NGL sales increased primarily because of a 20% increase in our realized prices without hedges. Our gas sales were the most significantly impacted. The change in our realized gas price was largely due to higher North American regional index prices upon which our gas sales are based. Additionally, our bitumen sales increased as a result of a 16% increase in our realized price, as a result of tighter bitumen and heavy oil differentials. These increases were partially offset by lower oil and NGL realized prices resulting from lower WTI crude oil index prices and lower NGL prices at the Mont Belvieu, Texas hub.

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,  
     2015      2014      2013  
     (Millions)  

Cash settlements:

        

Oil derivatives

   $ 2,083       $ 90       $ 55   

Gas derivatives

     333         (36      139   

NGL derivatives

     —           1         1   
  

 

 

    

 

 

    

 

 

 

Total cash settlements

     2,416         55         195   
  

 

 

    

 

 

    

 

 

 

Gains (losses) on fair value changes:

        

Oil derivatives

     (1,687      1,721         (243

Gas derivatives

     (226      213         (139

NGL derivatives

     —           —           (4
  

 

 

    

 

 

    

 

 

 

Total gains (losses) on fair value changes

     (1,913      1,934         (386
  

 

 

    

 

 

    

 

 

 

Oil, gas and NGL derivatives

   $ 503       $ 1,989       $ (191
  

 

 

    

 

 

    

 

 

 

 

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     Year Ended December 31, 2015  
     Oil
(Per Bbl)
     Bitumen
(Per Bbl)
     Gas
(Per Mcf)
     NGLs
(Per Bbl)
     Boe
(Per Boe)
 

Realized price without hedges

   $ 42.12       $ 23.41       $ 2.14       $ 9.32       $ 21.68   

Cash settlements of hedges

     29.88         —           0.57         —           9.74   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Realized price, including cash settlements

   $ 72.00       $ 23.41       $ 2.71       $ 9.32       $ 31.42   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

     Year Ended December 31, 2014  
     Oil
(Per Bbl)
     Bitumen
(Per Bbl)
     Gas
(Per Mcf)
    NGLs
(Per Bbl)
     Boe
(Per Boe)
 

Realized price without hedges

   $ 82.47       $ 55.88       $ 3.90      $ 24.89       $ 40.33   

Cash settlements of hedges

     1.56         —           (0.05     0.02         0.22   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Realized price, including cash settlements

   $ 84.03       $ 55.88       $ 3.85      $ 24.91       $ 40.55   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

     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   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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 3 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 2015 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 generated net gains in 2015 and 2014 and incurred a net loss in 2013.

Marketing and Midstream Revenues and Operating Expenses

 

     Year Ended December 31,  
     2015     Change     2014     Change     2013  
     (Millions)  

Operating revenues

   $ 7,260        -5   $ 7,667        +271   $ 2,066   

Product purchases

     (6,028     -8     (6,540     +382     (1,356

Operations and maintenance expenses

     (392     +43     (275     +40     (197
  

 

 

     

 

 

     

 

 

 

Operating profit

   $ 840        -1   $ 852        +66   $ 513   
  

 

 

     

 

 

     

 

 

 

Devon profit

   $ 14        -84   $ 88        -5   $ 93   

EnLink profit

     826        +8     764        +82     420   
  

 

 

     

 

 

     

 

 

 

Total profit

   $ 840        -1   $ 852        +66   $ 513   
  

 

 

     

 

 

     

 

 

 

 

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2015 vs. 2014 Marketing and midstream operating profit changes were largely driven by a full year of EnLink’s legacy asset operations compared to prior year and facility expansions coming online in late 2014, along with assets acquired during 2015. The change was offset by a decrease in Devon’s marketing activities due to a decrease in commodity prices.

2014 vs. 2013 Marketing and midstream operating profit largely increased as a result of higher prices and volumes, partially offset by higher operations and maintenance expenses. Of the $339 million increase, $344 million was attributed to EnLink’s operations. Higher profits from EnLink’s Texas segment, which includes the Bridgeport facility, and Louisiana segment were the largest drivers of the increase. The Louisiana segment operating profit increased because of acquisitions and completions of additional pipelines.

Devon’s marketing activities were the primary driver of the increases in both operating revenues and product purchases. The higher marketing revenues and product purchases are primarily due to commitments we entered into to secure capacity on downstream oil pipelines. Marketing activities of EnLink also contributed to these increases.

Lease Operating Expenses

 

     Year Ended December 31,  
     2015      Change     2014      Change     2013  
     (Millions, except per Boe amounts)  

LOE:

            

U.S.

   $ 1,551         -0   $ 1,559         +24   $ 1,257   

Canada

     553         -28     773         -24     1,011   
  

 

 

      

 

 

      

 

 

 

Total

   $ 2,104         -10   $ 2,332         +3   $ 2,268   
  

 

 

      

 

 

      

 

 

 

LOE per Boe:

            

U.S.

   $ 7.52         +0   $ 7.52         +13   $ 6.65   

Canada

   $ 13.18         -34   $ 20.10         +27   $ 15.78   

Total

   $ 8.48         -11   $ 9.49         +6   $ 8.97   

2015 vs. 2014 LOE per Boe decreased during 2015 primarily as a result of higher Jackfish 3 volumes, our well optimization and cost reduction initiatives, lower royalties and changes in the Canadian to U.S. foreign exchange rate. As Canadian royalties decrease, our net production volumes increase, causing improvements to our per-unit operating costs. The flat U.S. rate is primarily related to our 2014 non-core natural gas asset divestitures and our oil production growth, where projects generate higher margins but generally require a higher cost to produce per unit than our retained and divested gas projects.

2014 vs. 2013 Our absolute LOE changed largely as a result of our portfolio transformation initiatives, including our February 2014 purchase of Eagle Ford assets and our 2014 divestitures of non-core gas properties in the U.S. and Canada. Higher volumes from development of our Eagle Ford assets, as well as our Delaware Basin assets, caused U.S. LOE to increase. This increase was partially offset by the decrease resulting from the U.S. divestitures. The Canadian divestitures were the primary cause of the decrease in Canadian LOE.

Total LOE increased $0.52 per Boe primarily because of higher unit costs related to our Canadian operations. The higher Canadian unit costs largely resulted from the divestiture of the conventional natural gas assets in the second quarter of 2014 which resulted in lower total volumes while retaining the relatively higher-cost thermal heavy oil operations. Additionally, higher Jackfish royalties paid in 2014 also contributed to higher Canadian unit costs. The higher unit cost in the U.S. was primarily related to our liquids production growth, particularly in the Delaware Basin and Mississippian-Woodford Trend, where projects generate higher revenues but generally require a higher cost to produce per unit than our gas projects. Additionally, we experienced inflationary pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.

 

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General and Administrative Expenses

 

     Year Ended December 31,  
     2015      Change     2014      Change     2013  
     (Millions, except per Boe amounts)  

Gross G&A

   $ 1,347         -2   $ 1,369         +21   $ 1,128   

Capitalized G&A

     (372      -1     (376      +2     (368

Reimbursed G&A

     (120      -18     (146      +2     (143
  

 

 

      

 

 

      

 

 

 

Net G&A

   $ 855         +1   $ 847         +37   $ 617   
  

 

 

      

 

 

      

 

 

 

Net G&A per Boe

   $ 3.45         +0   $ 3.45         +41   $ 2.44   
  

 

 

      

 

 

      

 

 

 

2015 vs. 2014 Gross G&A decreased during 2015 largely because of a lower employee performance bonus pool and our cost reduction initiatives. Furthermore, $22 million in one-time costs related to the EnLink and GeoSouthern transactions contributed to higher costs in the first quarter of 2014. These decreases were offset by an increase in EnLink G&A of approximately $40 million primarily resulting from a workforce increase associated with EnLink’s 2015 acquisitions. Reimbursed G&A decreased subsequent to our 2014 asset divestitures.

2014 vs. 2013 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits and $22 million of 2014 costs related to the EnLink and GeoSouthern transactions. The higher employee compensation and benefits costs were primarily related to share-based awards, which cause our G&A to be higher in the period in which our annual share-based grant is made. The grant related to our 2013 compensation cycle was made in the first quarter of 2014. The grant related to our 2012 compensation cycle was made in the fourth quarter of 2012. Additionally, the expansion of our workforce as a part of growing production operations at certain of our key areas also contributed to the increase.

Production and Property Taxes

 

     Year Ended December 31,  
     2015     Change     2014     Change     2013  
     (Millions)  

Production

   $ 198        -45   $ 360        +31   $ 275   

Property and other

     190        +8     175        -6     186   
  

 

 

     

 

 

     

 

 

 

Production and property taxes

   $ 388        -28   $ 535        +16   $ 461   
  

 

 

     

 

 

     

 

 

 

Percentage of oil, gas and NGL sales:

          

Production

     3.7     +1     3.6     +13     3.2

Property and other

     3.5     +100     1.8     -19     2.2
  

 

 

     

 

 

     

 

 

 

Total

     7.2     +33     5.4     -0     5.4
  

 

 

     

 

 

     

 

 

 

2015 vs. 2014 Our absolute production taxes decreased during 2015 primarily because of a decrease in our U.S. revenues, on which the majority of our production taxes are assessed. Property taxes as a percentage of oil, gas and NGL sales increased during 2015 primarily due to ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL sales.

2014 vs. 2013 Production and property taxes increased primarily as a result of an increase in our U.S. revenues.

 

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Depreciation, Depletion and Amortization

 

     Year Ended December 31,  
     2015      Change     2014      Change     2013  
     (Millions, except per Boe amounts)  

DD&A:

            

Oil and gas properties

   $ 2,580         -11   $ 2,896         +18   $ 2,465   

Other assets

     549         +30     423         +34     315   
  

 

 

      

 

 

      

 

 

 

Total

   $ 3,129         -6   $ 3,319         +19   $ 2,780   
  

 

 

      

 

 

      

 

 

 

DD&A per Boe:

            

Oil and gas properties

   $ 10.40         -12   $ 11.79         +21   $ 9.75   

Other assets

     2.21         +28     1.72         +38     1.24   
  

 

 

      

 

 

      

 

 

 

Total

   $ 12.61         -7   $ 13.51         +23   $ 10.99   
  

 

 

      

 

 

      

 

 

 

A description of how DD&A of our oil and gas properties is calculated is included in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, the DD&A rate per unit of production will change inversely. However, when the depletable base changes, 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.

2015 vs. 2014 DD&A from our oil and gas properties decreased in 2015 compared to 2014 largely because of the 2014 divestitures of certain U.S. and Canadian assets and the oil and gas asset impairments recognized in 2015. Other DD&A increased primarily due to EnLink’s acquisitions in 2014 and 2015.

2014 vs. 2013 DD&A from our oil and gas properties increased in 2014 largely because of higher DD&A rates. The higher rates resulted from our oil and gas drilling and development activities and the GeoSouthern acquisition, which were partially offset by the asset impairments recognized in 2013 and the 2014 asset divestitures. Other DD&A increased primarily due to the formation of EnLink in 2014.

Asset Impairments

During 2015, 2014 and 2013, we recognized asset impairments of $20.8 billion, $2.0 billion and $2.0 billion, respectively. For discussion on asset impairments, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

Restructuring Costs

During 2015, 2014 and 2013, we recognized restructuring costs of $78 million, $46 million and $54 million, respectively. For discussion of our reorganization programs and the associated restructuring costs, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

Gains on Asset Sales

In conjunction with the divestiture of certain Canadian properties, we recognized gains of $1.1 billion in 2014. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

 

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Net Financing Costs

 

     Year Ended December 31,  
     2015      Change     2014      Change     2013  
     (Millions)  

Interest based on debt outstanding

   $ 565         +6   $ 532         +14   $ 466   

Early retirement of debt

     —           N/M        48         N/M        —     

Capitalized interest

     (62      -11     (70      +26     (56

Other fees and expenses

     20         -24     26         -1     27   
  

 

 

      

 

 

      

 

 

 

Interest expense

     523         -3     536         +23     437   

Interest income

     (6      -41     (10      -49     (20
  

 

 

      

 

 

      

 

 

 

Net financing costs

   $ 517         -2   $ 526         +26   $ 417   
  

 

 

      

 

 

      

 

 

 

2015 vs. 2014 Net financing costs decreased during 2015 primarily as a result of the retirement premium and costs related to the early redemption of senior notes in 2014, which is further discussed in Note 13 in “Item 8. Financial Statements and Supplementary Data” of this report. Interest on outstanding borrowings increased during 2015 primarily due to an increase of $51 million in EnLink interest expense as a result of an increase in fixed-rate borrowings, partially offset by a $18 million decrease in Devon interest expense as a result of a decrease in its average fixed-rate borrowings.

2014 vs. 2013 Net financing costs increased primarily because of higher average borrowings resulting from the EnLink and GeoSouthern transactions and the 2014 early retirement premium and costs.

Income Taxes

 

     Year Ended December 31,  
     2015     2014     2013  

Total income tax expense (benefit) (millions)

   $ (6,065   $ 2,368      $ 169   
  

 

 

   

 

 

   

 

 

 

Effective income tax rate

     (29 )%      58     113
  

 

 

   

 

 

   

 

 

 

For discussion on income taxes, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.

 

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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.

 

    Devon     EnLink     Consolidated  
    2015     2014     2015     2014     2015     2014     2013 (1)  
    (Millions)  

Operating cash flow

  $ 4,756      $ 5,467      $ 627      $ 514      $ 5,383      $ 5,981      $ 5,436   

Sale of subsidiary units

    654        —          —          —          654        —          —     

Divestitures of property and equipment

    106        5,120        1        —          107        5,120        419   

Capital expenditures

    (4,735     (6,192     (573     (796     (5,308     (6,988     (6,502

Acquisitions of property, equipment and businesses

    (583     (6,104     (524     (358     (1,107     (6,462     (256

Short-term investment activity, net

    —          —          —          —          —          —          2,343   

Debt activity, net

    770        (2,789     1,061        555        1,831        (2,234     361   

Shareholder and noncontrolling interests distributions

    (396     (486     (254     (135     (650     (621     (348

EnLink and General Partner distributions

    268        158        (268     (158     —          —          —     

EnLink dropdowns

    167        —          (167     —          —          —          —     

Stock option proceeds

    4        93        —          —          4        93        3   

Issuance of subsidiary units

    —          —          25        410        25        410        —     

Effect of exchange rate and other

    (131     79        22        36        (109     115        (27
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net change in cash and cash equivalents

  $ 880      $ (4,654   $ (50   $ 68      $ 830      $ (4,586   $ 1,429   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

  $ 2,292      $ 1,412      $ 18      $ 68      $ 2,310      $ 1,480      $ 6,066   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 2013 amounts for EnLink consist of legacy Devon midstream assets.

Operating Cash Flow

Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2015. Our operating cash flow decreased 10% during 2015 primarily due to lower commodity prices. The effects of lower commodity prices were partially offset by the collection of $425 million of income taxes receivable in the first quarter of 2015 and $2.4 billion of cash settlements associated with our commodity derivatives during 2015.

Our operating cash flow increased 10% during 2014 primarily because of higher realized prices and liquids production growth, partially offset by higher expenses.

Excluding payments made for acquisitions, our consolidated operating cash flow funded 100% and approximately 86% of our capital expenditures during 2015 and 2014, respectively. In 2015 and 2014, leveraging our liquidity and other capital resources, we also used cash balances, short-term debt, proceeds from EnLink transactions and divestiture proceeds to fund our acquisitions, dividends and capital requirements.

Sale of Subsidiary Units

In early 2015, we conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 17 in “Item 8. Financial Statements and Supplementary Data” of this report.

 

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Divestitures of Property and Equipment

During 2014, we completed our Canadian asset divestiture program and received proceeds of approximately $2.9 billion. Additionally, we completed the divestment of certain of our U.S. assets and received proceeds of approximately $2.2 billion.

During 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.

Capital Expenditures

 

     Year Ended December 31,  
     2015      2014      2013  
     (Millions)  

Oil and gas

   $ 4,577       $ 5,735       $ 5,710   

Midstream

     56         348         455   

Corporate and other

     102         109         93   
  

 

 

    

 

 

    

 

 

 

Devon capital expenditures

     4,735         6,192         6,258   

EnLink capital expenditures

     573         796         244   
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 5,308       $ 6,988       $ 6,502   
  

 

 

    

 

 

    

 

 

 

Devon acquisitions

   $ 583       $ 6,104       $ 256   

EnLink acquisitions

     524         358         —     
  

 

 

    

 

 

    

 

 

 

Total acquisitions

   $ 1,107       $ 6,462       $ 256   
  

 

 

    

 

 

    

 

 

 

Capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations, other corporate activities and EnLink growth and maintenance activities.

The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. In response to lower commodity prices, Devon’s 2015 capital program was designed to be lower than 2014, particularly compared to the second half of 2014 when oil prices began to significantly decline. This change is evidenced by a 48% decrease in exploration and development costs from the fourth quarter of 2014 to the fourth quarter of 2015, as well as a 24% decrease in total capital expenditures from 2014 to 2015, excluding acquisitions. Excluding acquisitions, oil and gas capital spending was flat from 2013 to 2014, primarily due to utilization of the drilling carries in 2014 from our joint venture arrangements.

Capital expenditures for Devon’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines and are largely impacted by Devon’s oil and gas drilling activities. Our 2014 and 2013 midstream capital expenditures largely related to the expansion of our Access Pipeline in Canada. The majority of our midstream capital is incurred by EnLink. EnLink’s 2015 capital expenditures decreased compared to 2014 primarily as a result of pipeline construction and expansion projects that went into service in 2014. EnLink’s 2013 capital expenditures primarily related to expansions of plants serving the Barnett Shale and Cana-Woodford Shale.

Acquisition capital spend in 2015 primarily consisted of the Powder River Basin asset acquisition in the fourth quarter. The majority of the acquisition capital in 2014 related to the GeoSouthern acquisition in the Eagle Ford. EnLink’s acquisitions in 2015 and 2014 consisted of additional oil and gas pipeline assets, including gathering, transportation and processing facilities. For further discussion on EnLink acquisition activity, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

 

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Short-Term Investment Activity, Net

During 2013, we purchased approximately $1.1 billion of short-term investments and redeemed approximately $3.4 billion. We consider securities with original contract maturities in excess of three months but less than one year to be short-term investments.

Debt Activity, Net

During 2015, our consolidated net debt borrowings increased $1.8 billion. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter. EnLink’s net debt borrowings increased $1.1 billion primarily from borrowings made to fund acquisitions and dropdowns.

During 2014, we decreased our net debt borrowings by $2.2 billion. The decrease was primarily related to the repayment of debt used to fund the GeoSouthern transaction. This was partially offset by $555 million of net borrowings from EnLink to fund its operations.

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 acquisition and repaying approximately $1.9 billion of outstanding short-term debt.

Shareholder and Noncontrolling Interests Distributions

The following table summarizes our common stock dividends. The quarterly cash dividend was $0.20 per share in the first quarter of 2013. We increased the dividend rate to $0.22 per share in the second quarter of 2013 and to $0.24 per share in the second quarter of 2014.

 

     2015      2014      2013  
     Amount      Per Share      Amount      Per Share      Amount      Per Share  
     (Millions, except per share amounts)  

Dividends

   $  396       $ 0.96       $ 386       $ 0.94       $ 348       $ 0.86   

In conjunction with the formation of EnLink in the first quarter of 2014, we made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $254 and $135 million to non-Devon unitholders during 2015 and 2014, respectively.

EnLink and General Partner Distributions

Devon received $268 million and $158 million in distributions from EnLink and the General Partner during 2015 and 2014, respectively.

EnLink Dropdowns

In the second quarter of 2015, Devon received $167 million in cash from EnLink in exchange for VEX. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Stock Option Proceeds

We received $4 million, $93 million and $3 million from stock option proceeds in 2015, 2014 and 2013, respectively.

 

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Issuance of Subsidiary Units

During 2015 and 2014, EnLink issued and sold approximately 1.3 million and 14.8 million common units through general public offerings and its “at the market” equity program, generating net proceeds of approximately $25 million and $410 million, respectively. Furthermore, in October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 million in proceeds.

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 a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include, among other things, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. We estimate the combination of these sources of capital will continue to be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed in this section.

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow decreased 10% in 2015 as a result of the significant decrease in commodity prices. In spite of this decline, we expect operating cash flow to continue to be a primary source of liquidity as we adjust our capital program in response to lower commodity prices. Additionally, we anticipate utilizing divestiture proceeds and our credit availability to provide additional liquidity as needed.

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 lower prices to continue throughout 2016, and currently, our production is largely unhedged. If commodity prices remain consistent with 2015 and we are unable to obtain favorable hedge contracts for our 2016 production, our 2016 operating cash flow could materially decline from what it was in 2015.

The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2015 are presented in Note 3 in “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 decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.

Divestitures of Property and Equipment – In the fourth quarter of 2015, we announced our intention to monetize up to 80 MBoe per day of certain non-core upstream assets across our portfolio in 2016. In addition, we also intend to market our Access Pipeline in Canada. We anticipate these divestitures will generate approximately $2 billion to $3 billion of proceeds to further strengthen our financial position in 2016.

Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2015, we had total debt of $13.1 billion with an overall weighted-average borrowing rate of 4.9%. Of the $13.1 billion of total debt, $1.4 billion is comprised of floating rate debt instruments that bear interest rates averaging 1.1%.

 

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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% 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. In the current environment, assuming current pricing expectations, our 2016 exploration and development capital budget is expected to be approximately $900 million to $1.1 billion, or roughly 75% less than our 2015 capital program. With our 2016 capital focused primarily on oil development, we anticipate our oil production will remain relatively flat from 2015 to 2016, but our natural gas and NGL production will decline, resulting in a 6% production decline in our core assets.

At the end of 2015, we held approximately $2.3 billion of cash. Included in this total was $646 million 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 decrease the amount of cash ultimately available to fund our business.

Credit Availability

We have a $3.0 billion Senior Credit Facility. The maturity date for $30 million of the Senior Credit Facility is October 24, 2017. The maturity date for $164 million of the Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019. This credit facility supports our $3.0 billion commercial paper program. 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, 2015, there were no borrowings under the Senior Credit Facility.

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%. 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 and goodwill impairments. As of December 31, 2015, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2015, as calculated pursuant to the terms of the agreement, was 23.7%.

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

 

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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.

Our Senior Credit Facility supports our $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, 2015, we had $626 million of borrowings under our commercial paper program.

EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2015, there were $11 million in outstanding letters of credit and $414 million borrowed under the $1.5 billion credit facility and no outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.

Debt Ratings

Devon and EnLink are rated by the major debt ratings agencies in the U.S. However, the General Partner does not receive debt ratings. In determining those debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term growth opportunities and capital allocation challenges.

There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should debt ratings fall below a specified level. However, a ratings downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Capital Expenditures

In January 2016, Devon acquired Anadarko Basin STACK assets for approximately $1.5 billion in cash and equity, subject to certain adjustments. Including this acquisition but excluding EnLink, our 2016 capital expenditures are expected to range from $1.2 billion to $1.4 billion, including $900 million to $1.1 billion for our oil and gas capital program. 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 2016 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2016 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2016, available cash balances and credit availability and proceeds from our divestiture program, we anticipate having adequate capital resources to fund our 2016 capital expenditures.

In connection with our acquisition of the STACK play and Powder River Basin assets, we issued 23,470,000 shares of our common stock (the “STACK Acquisition Shares”) and 6,857,488 shares of our common stock (the “PRB Acquisition Shares”), respectively. Pursuant to the terms of these acquisitions, we agreed to register for resale with the SEC the STACK Acquisition Shares and the PRB Acquisition Shares. Following such respective registrations, the STACK Acquisition Shares and the PRB Acquisition Shares can generally be freely sold in the public markets at any time on or after February 21, 2016 and March 16, 2016, respectively.

 

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EnLink Capital Resources and Expenditures

In January 2016, EnLink acquired Tall Oak, a gathering and processing midstream company with assets in central Oklahoma, for approximately $1.5 billion in cash and equity, subject to certain adjustments.

Excluding this acquisition, EnLink’s 2016 capital budget includes approximately $445 million to $570 million of identified growth projects. EnLink’s primary capital projects for 2016 include completing the construction of the Riptide plant in Texas, acquired as part of the Coronado transaction, commencing construction on an NGL pipeline in Louisiana and development of its Tall Oak assets.

EnLink expects to fund the growth capital expenditures from the proceeds of borrowings under its bank credit facility and proceeds from other debt and equity sources. EnLink expects to fund its 2016 maintenance capital expenditures from operating cash flows. In 2016, it is possible that not all of the planned projects will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.

Contractual Obligations

The following table presents a summary of our contractual obligations as of December 31, 2015.

 

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

Devon debt (1)

   $ 10,051       $ 976       $ 875       $ 700       $ 7,500   

EnLink debt (2)

     3,077         —           —           814         2,263   

Interest expense (3)

     9,804         630         1,252         1,115         6,807   

Purchase obligations (4)

     3,905         557         1,494         1,648         206   

Operational agreements (5)

     4,601         994         1,908         657         1,042   

Asset retirement obligations (6)

     1,414         44         104         102         1,164   

Drilling and facility obligations (7)

     189         69         85         7         28   

Lease obligations (8)

     443         70         134         110         129   

Other (9)

     140         2         92         39         7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (10)

   $ 33,624       $ 3,342       $ 5,944       $ 5,192       $ 19,146   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Debt amounts represent scheduled maturities of Devon’s debt obligations at December 31, 2015, excluding $28 million of net discounts included in the carrying value of debt. Debt due less than one year includes $626 million of commercial paper, which can be renewed beyond one year.
(2) Debt amounts represent scheduled maturities of EnLink’s debt obligations at December 31, 2015, excluding $13 million of net premiums included in the carrying value of debt. All of EnLink’s debt is non-recourse to Devon.
(3) Interest expense represents the scheduled cash payments on long-term, fixed-rate debt and an estimate of our floating-rate notes. These amounts include $1.8 billion of interest expense related to EnLink.
(4) 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.

 

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(5) 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. Operational agreements include approximately $1.7 billion of minimum volume commitments between Devon and EnLink. The initial terms of the gas volume contracts with EnLink are summarized in the following table. In addition, Devon and EnLink have a 30 MBbls/d minimum transportation volume commitment for the VEX pipeline. All contracts with EnLink expire in 2019.

 

Contract

  Contract
Terms
(Years)
    Minimum
Gathering
Volume
Commitment
(MMcf/d)
    Minimum
Processing
Volume
Commitment
(MMcf/d)
    Minimum
Volume
Commitment
Term
(Years)
    Annual
Rate
Escalators
 

Bridgeport gathering and processing contract

    10        850        650        5        CPI   

East Johnson County gathering contract

    10        125        —          5        CPI   

Cana gathering and processing contract

    10        330        330        5        CPI   

 

(6) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2015 balance sheet.
(7) Drilling and facility obligations represent gross contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.
(8) Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.
(9) These amounts include $133 million related to uncertain tax positions.
(10) This table excludes approximately $1.7 billion of cash payments made on January 7, 2016 upon closing the STACK acquisition and EnLink’s acquisition of Tall Oak. The table also excludes the $500 million of future cash installment payments required to be paid by EnLink within 24 months as part of the Tall Oak acquisition.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 18 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 U.S. 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 third-party petroleum consulting firms. In 2015, 95% of our reserves were subjected to such audits.

 

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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 3% 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% 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% 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 generally is not possible to predict the timing or magnitude of full cost write-downs. In addition, because of 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.

Based on prices for the last nine months of 2015 and the short-term pricing outlook for the first quarter of 2016, we expect to recognize additional U.S. and Canadian full cost impairments in the first quarter of 2016. The estimated U.S. impairment would be material to our net earnings, but we believe it will not be as large as the $3.7 billion impairment we recognized in the fourth quarter of 2015. We also expect to recognize an impairment related to our Canadian oil and gas properties that will approximate the impairment recognized in the fourth quarter of 2015. While difficult to measure, we estimate that the first quarter 2016 impairments will approximate $3 billion in the aggregate. Our full cost impairments have no impact to our cash flow or liquidity.

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. Additionally, EnLink periodically enters into derivative financial instruments with respect to its oil, gas and NGL marketing activity. These commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.

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 WTI forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we

 

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base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using U.S. 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. 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.

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 oil, gas and NGL commodity derivative contracts are held with thirteen separate counterparties, and our foreign exchange forward contracts are held with six 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.

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 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.

Business Combinations

Accounting for the acquisition of a business requires the assets and liabilities of the acquired business to be recorded at fair value. Deferred taxes are recorded for any differences between the fair value and the tax basis of the acquired assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill.

 

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There are various assumptions we make in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by our engineers and that of outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.

However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies a historical 12-month average price to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a business combination must be based on our estimates of future oil, natural gas and NGL prices. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the business combination based upon our cost of capital.

We also apply these same general principles to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we consider to be an appropriate risk-weighting factor in each particular instance.

In addition, our acquisitions have involved other entities whose operations included substantial midstream activities. In these transactions, the purchase price is allocated to the fair value of midstream facilities and equipment, generally consisting of processing facilities and pipeline systems. Estimating the fair value of these assets requires certain assumptions to be made regarding future quantities of commodities estimated to be processed and transported through these facilities and pipelines, as well as estimates of future expected prices and operating and capital costs.

Goodwill

We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. While we use data as of October 31 for our test, we typically complete the test in late December or early January as the October 31 market data used in our test becomes available. We first assess the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we determine that it is more likely than not that its fair value is less than its carrying amount, then the two-step goodwill impairment test is performed.

In the first step of the impairment test, the fair value of a reporting unit is compared to its carrying value. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment

 

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test is performed for purposes of measuring the impairment. In the second step, the fair value of the reporting unit is allocated to all of the assets and liabilities of the reporting unit to determine an implied goodwill value. This allocation is similar to a purchase price allocation. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue growth rates driven by future commodity prices and volume expectations, operating margins and capital expenditures.

For our October 31, 2015 impairment test, step one of our impairment analysis showed that the fair value of our U.S. reporting unit exceeded its carrying value.

Sustained weakness in the overall energy sector beginning in the fourth quarter of 2014 and continuing into 2015 driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test for EnLink’s reporting units, as well as an update performed as of December 31. Based on the results of the impairment analysis, it was determined that the estimated fair value of EnLink’s Crude and Condensate, Louisiana and Texas reporting units were less than their carrying amounts, primarily due to changes in assumptions related to commodity prices and discount rates. Through the analysis, goodwill impairments of $492 million, $787 million and $49 million for EnLink’s Texas, Louisiana and Crude and Condensate reporting units, respectively, were recognized in 2015. Subsequent to the impairments, EnLink had $93 million and $704 million of goodwill allocated to the Crude and Condensate and Texas reporting units, respectively. The Louisiana reporting unit’s goodwill was entirely written off. As of December 31, 2015, the fair value of EnLink’s Texas reporting unit exceeded its carrying value by approximately 7%, and the carrying value of EnLink’s Crude and Condensate reporting unit approximated its fair value.

The impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.

Other Intangible Assets

In 2015, the assessment of customer relationships was updated due to the factors described in the aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment.

The other intangible assets impairment has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.

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. At the end of 2015, we had deferred tax assets that largely resulted from the full cost impairments recognized in the fourth quarter of 2015. As a result of our recent cumulative losses, we recorded a 100% valuation allowance against our U.S. deferred tax assets as of December 31, 2015.

 

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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 U.S. 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, U.S./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 impractical 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 “core earnings attributable to Devon” and “core earnings per share attributable to Devon” in “Overview of 2015 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. Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash 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 when comparing on an annual basis. In the table below, restructuring costs were incurred in each of the three year periods; however, these costs relate to different restructuring programs. Amounts excluded for 2015 relate to derivatives and financial instrument fair value changes, asset impairments (including an impairment of goodwill), deferred tax asset valuation allowance, restructuring costs and repatriation of funds to the U.S. Amounts excluded for 2014 relate to derivatives and financial instrument fair value changes, asset impairments (including an impairment of goodwill), our divestiture programs and related gains on asset sales and restructuring costs, repatriation of proceeds to the U.S., loss on early retirement of debt and deferred income tax on the formation of the General Partner. Amounts excluded for 2013 relate to derivatives and financial instrument fair value changes, asset impairments, our divestiture programs and related repatriation of proceeds to the U.S. and restructuring costs. For more information on our restructuring programs, see Note 6 in “Item 8. Financial

 

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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.

Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.

 

     Year Ended December 31,  
         2015              2014              2013      
     (Millions, except per share amounts)  

Net earnings (loss) attributable to Devon (GAAP)

   $ (14,454    $ 1,607       $ (20

Adjustments (net of taxes and noncontrolling interests):

        

Derivatives and other financial instruments

     (206      (1,262      131   

Cash settlements on derivatives and financial instruments

     1,552         31         139   
  

 

 

    

 

 

    

 

 

 

Noncash effect of derivatives and financial instruments

     1,346         (1,231      270   

Asset impairments

     13,100         1,948         1,353   

Deferred tax asset valuation allowance

     967         —           —     

Gain on asset sales and repatriations

     33         (421      97   

Investment in General Partner deferred income tax

     —           48         —     

Restructuring costs

     52         35         34   

Early retirement of debt

     —           31         —     
  

 

 

    

 

 

    

 

 

 

Core earnings attributable to Devon (non-GAAP)

   $ 1,044       $ 2,017       $ 1,734   
  

 

 

    

 

 

    

 

 

 

Earnings (loss) per share attributable to Devon (GAAP)

   $ (35.55    $ 3.91       $ (0.06

Adjustments (net of taxes and noncontrolling interests):

        

Derivatives and other financial instruments

     (0.49      (3.07      0.31   

Cash settlements on derivatives and financial instruments

     3.80         0.08         0.34   
  

 

 

    

 

 

    

 

 

 

Noncash effect of derivatives and financial instruments

     3.31         (2.99      0.65   

Asset impairments

     32.18         4.74         3.35   

Deferred tax asset valuation allowance

     2.37         —           —     

Gain on asset sales and repatriations

     0.08         (1.02      0.24   

Investment in General Partner deferred income tax

     —           0.12         —     

Restructuring costs

     0.13         0.08         0.08   

Early retirement of debt

     —           0.07         —     
  

 

 

    

 

 

    

 

 

 

Core earnings per share attributable to Devon (non-GAAP)

   $ 2.52       $ 4.91       $ 4.26   
  

 

 

    

 

 

    

 

 

 

 

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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 production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodically hedge a portion of our production through various financial transactions. The key terms to all our oil and gas derivative financial instruments as of December 31, 2015 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2015, a 10% change in the forward curves associated with our commodity derivative instruments would not have materially impacted our balance sheet at December 31, 2015.

Interest Rate Risk

At December 31, 2015, we had total debt of $13.1 billion. Of this amount, $11.7 billion bears fixed interest rates averaging 5.3%, and $1.4 billion is comprised of floating rate debt with interest rates averaging 1.1%. Our commercial paper borrowings typically have maturities between 1 and 90 days.

As of December 31, 2015, we had open interest rate swap positions that are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the 3 month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet at December 31, 2015.

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% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our December 31, 2015 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of our subsidiaries hold Canadian-dollar cash and engage in 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, 2015, 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, 2015, a 10% 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

     57   

Consolidated Financial Statements

  

Consolidated Comprehensive Statements of Earnings

     58   

Consolidated Statements of Cash Flows

     59   

Consolidated Balance Sheets

     60   

Consolidated Statements of Stockholders’ Equity

     61   

Notes to Consolidated Financial Statements

     62   

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, 2015 and 2014, 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, 2015. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) 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, 2015 and 2014, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S 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, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Oklahoma City, Oklahoma

February 17, 2016

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

 

     Year Ended December 31,  
         2015             2014             2013      
     (Millions, except per share amounts)  

Oil, gas and NGL sales

   $ 5,382      $ 9,910      $ 8,522   

Oil, gas and NGL derivatives

     503        1,989        (191

Marketing and midstream revenues

     7,260