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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20152018

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

Delaware73-1567067

(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

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 or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filerx            Accelerated filer¨            Non-accelerated filer¨

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

If an emerging growth company,¨ indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

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, 201529, 2018 was approximately $24.3$22.5 billion, based upon the closing price of $59.49$43.96 per share as reported by the New York Stock Exchange on such date. On February 10, 2016, 441.36, 2019, 438.3 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s definitive Proxy statement for the 2016Statement relating to Registrant’s 2019 annual meeting of stockholders have been incorporated by reference in Part III of this Annual Report on Form 10-K.


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DEVON ENERGY CORPORATION

FORM 10-K

TABLE OF CONTENTS

 

PART I

6

Items 1 and 2. Business and Properties

6

Item 1A.  Risk Factors

20

14

Item 1B.  Unresolved Staff Comments

26

21

Item 3.     Legal Proceedings

26

21

Item 4.     Mine Safety Disclosures

26
PART II

21

PART II

22

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

27

22

Item 6.     Selected Financial Data

29

24

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

30

25

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

55

49

Item 8.     Financial Statements and Supplementary Data

56

50

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

120

109

Item 9A.  Controls and Procedures

120

109

Item 9B.  Other Information

120
PART III

109

PART III

110

Item 10.   Directors, Executive Officers and Corporate Governance

121

110

Item 11.   Executive Compensation

121

110

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

121

110

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

121

110

Item 14.   Principal Accountant Fees and Services

121
PART IV

110

PART IV

111

Item 15.   Exhibits and Financial Statement Schedules

122

111

SignaturesItem 16.   Form 10-K Summary

116

Signatures

129

117

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DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon”“Devon,” the “Company” and the “Company”“Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. 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.

2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.

“2012 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 24, 2012.

“2018 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 5, 2018.

“ASC” means Accounting Standards Codification.

“ASR” means an accelerated share-repurchase transaction with a financial institution to repurchase Devon’s common stock.

ASU” means Accounting Standards Update.

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

“Bcf” means billion cubic feet.

“BLM” means the United States Bureau of Land Management.

“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.dollars, unless stated otherwise.

“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.,LP, a master limited partnership.

“EPA” means the United States Environmental Protection Agency.

“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.

GAAP” means U.S. generally accepted accounting principles.

General Partner” means EnLink Midstream, LLC, the indirect general partner entity of EnLink.EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.

“GeoSouthern” means GeoSouthern Energy Corporation.

“Inside FERC” refers to the publicationInside 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.

“MBoe” means thousand Boe.

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“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.

“N/M” means not meaningful.

“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”OPIS” means the present valueOil Price Information Service.

“PHMSA” means United States Department of Devon’s pre-tax future net revenue to be generated from the production of proved reserves, net of estimated productionTransportation Pipeline and development costs and site restoration and abandonment charges.Hazardous Materials Safety Administration.

“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”Tax Reform Legislation” means Tall Oak Midstream, LLC.Tax Cuts and Jobs Act.

“TSR” means total shareholder return.

“Upstream operations” means upstream revenues minus production expenses.

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

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

WTI” means West Texas Intermediate.

“/Bbl” means per barrel.

“/d” means per day.

“/MMBtu” means per MMBtu.


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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the SEC. Such statements areinclude 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 and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-lookingAll statements, are based on our examinationother than statements of historical operating trends,facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the information used to prepare our December 31, 2015 reserve reports and other data in our possession or available from third parties.future are forward-looking statements. 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;

the volatility of oil, gas and NGL prices;

uncertainties inherent in estimating oil, gas and NGL reserves;

uncertainties inherent in estimating oil, gas and NGL reserves;

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

the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct;

risks related to our hedging activities;

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

counterparty credit risks;

risks related to regulatory, social and market efforts to address climate change;

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

risks related to our hedging activities;

risks relating to our indebtedness;

counterparty credit risks;

our ability to successfully complete mergers, acquisitions and divestitures;

risks relating to our indebtedness;

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

cyberattack risks;

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

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

midstream capacity constraints and potential interruptions in production;

midstream capacity constraints and potential interruptions in production;

competition for leases, materials, people and capital;

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

cyberattacks targeting our systems and infrastructure; and

competition for assets, materials, people and capital;

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

our ability to successfully complete mergers, acquisitions and divestitures; 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

A Delaware corporation formed in 1971 and publicly held since 1988, Devon (NYSE: DVN) is a leadingan 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,In July 2018, we control EnLink, a leading integratedexited the midstream business with significant sizeby divesting our aggregate ownership interests in EnLink 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.General Partner.

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, 2015,2018, Devon and its consolidated subsidiaries had approximately 6,6002,900 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. The corporate governance (includingdocuments available on our website include our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer).Officer, and any amendments to and waivers from any provision of that Code will also be posted on our website. 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.

Strategywww.sec.gov.

Our primary goalStrategy

Our business strategy is to build value per debt-adjusted share by:

focused on delivering a consistently competitive shareholder return among our peer group. Because the business of exploring for, undiscovereddeveloping and producing oil and natural gas reserves;

purchasingis capital intensive, delivering sustainable capital efficient cash flow growth is a key tenant to our success. While our cash flow is highly dependent on volatile and developinguncertain commodity prices, we pursue our strategy throughout all commodity price cycles with three fundamental principles.

A premier, sustainable portfolio of assets – As discussed in the next section of this Annual Report, we own a portfolio of assets located in the United States and Alberta, Canada. We strive to own premier assets capable of generating cash flows in excess of our capital and operating requirements, as well as competitive rates of return. We also desire to own a portfolio of assets that can provide a production growth platform extending many years into the future. Because of the strength of oil andprices relative to natural gas, properties;we have been positioning our portfolio to be more heavily weighted to U.S. oil assets in recent years.

enhancingDuring 2018, we made significant progress in our transition to a U.S. oil company. We sold our midstream business and certain non-core upstream assets, generating nearly $5 billion in proceeds. In February 2019, we announced our intent to separate our Canadian business and our Barnett Shale assets from the valueCompany. After these separations, we expect our oil production growth, price realizations and field-level margins will all improve, as we sharpen our focus on four core U.S. oil plays located in the Delaware Basin, STACK, Eagle Ford and Rockies.

Superior execution – As we pursue cash flow growth, we continually work to optimize the efficiency of production through marketingour capital programs and midstream activities;

optimizing production operations, with an underlying objective of reducing absolute and per unit costs and enhancing our returns. We also strive to control costs;leverage our culture of health, safety and environmental stewardship in all aspects of our business.

Throughout 2018, we continued to achieve efficiency gains in various aspects of our business. Our initial production rates from new wells continued to improve in our four core U.S. oil plays and have exceeded the average of the top 40 U.S. producers since 2015 by more than 40%. We continued to improve cycle times, incorporate production optimization strategies and other cost reduction initiatives, driving down breakeven costs across our portfolio of assets.

maintainingAs we focus on a more streamlined portfolio of U.S. oil assets, we are aggressively pursuing an improved cost structure with $780 million of annual costs savings expected by 2021. We expect to realize about 70% of the annualized savings by the end of 2019. Our retained U.S. oil business is expected to realize $300 million of annual well cost savings by 2021, as we increase our focus on development drilling, reduce our facility costs and optimize well spacing in the STACK. Additionally, we will streamline and align our workforce with our go-forward business, which should result in $300 million of annual cost savings by the end of the three-year period. As we continue deleveraging, we expect to reduce annual interest costs by $130 million. Finally, we have plans to reduce our annual production expenses by $50 million over the next three years.

Financial strength and flexibility – Commodity prices are uncertain and volatile, so we strive to maintain 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 operationalsheet, as well as adequate liquidity 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.

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

While we will continueorder to operate and developcompetitively in all commodity price cycles. Our capital allocation decisions are made with attention to these financial stewardship principles, as well as the priorities of funding our premier portfolio of assets, we are committed tocore operations, protecting our balance sheetinvestment-grade credit ratings, and managingpaying and growing our capital programsshareholder dividend.

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During 2018, we reduced our cash inflows, including Access Pipeline proceeds.consolidated debt by 40%, primarily from our divestitures. We also raised our quarterly dividend 33% and began a $4 billion share repurchase program. As we dispose of our Canadian and Barnett Shale assets in 2019, we expect to use the proceeds to reduce debt further and repurchase additional common shares. As a result we are significantly reducingof our capital investment in responseplanned dispositions, our Board of Directors has increased our share repurchase program to lower commodity prices. We plan to invest $900 million to $1.1$5 billion in our upstream programs, a decrease of roughly 75% compared to our 2015 capital. We are also committed to reducing our G&AFebruary 2019 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 reducedraised our quarterly common stock dividend 75%12.5% to $0.06$0.09 per share.

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.

The following table outlines aKey summary of key data infrom each of our operating areas of operation as of and for the year ended December 31, 2015. 2018 are detailed in the map below. Notes 2022 and 2123 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  
  

 

 

   

 

 

  

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

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Delaware Basin – The Delaware Basin has been a legacy asset for Devonis one of Devon’s top assets 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. TheseWe expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin will offerto deliver high-margin growth potential for many years to come. During 2018, our continued appraisal and development work enabled us to increase our proved reserves in this area by approximately 24%. At December 31, 2018, we had 10 operated rigs developing this asset. In 2016,2019, we plan to invest approximately $200$900 million of capital in the Delaware Basin, primarily focused onmaking it the second Bone Spring opportunitytop-funded asset in the basin of southeast New Mexico.portfolio.

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.one of Devon’s top assets. Our Woodford ShaleSTACK position is the largest and one of the bestlargest in the industry. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Earlyindustry, providing visible long-term stable production. At December 31, 2018, we had five operated rigs with drilling activityfocused in the Meramec play has been encouraging across our core position in the oil and liquids window.formation. In 2016,2019, we plan approximately $325$400 million of capital investment. The STACK is Devon’s second highest funded asset in the portfolio for 2019.

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.2014. Since acquiring these assets, we have delivered tremendous results increasing production by 125%.producing 173 million oil-equivalent barrels. Our excellent results are driven byourby our development in DeWitt County, which is located in the economic core of the play. In 2016, we expect ourOur Eagle Ford assets to once again deliver the highest operating margin of any assetgenerated significant cash flow in the portfolio and2018. In 2019, we plan approximately $200$300 million of capital investment.

Rockies Oil– Our operations areacreage in the Rockies is 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 formationsthis basin has expanded our drilling inventory, and we expect further growth as we accelerate activity and continue to de-risk this emerging light-oil opportunity. InAs of December 2015,31, 2018, we acquired 253,000 net acreshad two operated rigs targeting the Turner, Parkman, Teapot and Niobrara formations in the “core”northern Converse County 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.River Basin. In 2016,2019, we plan approximately $75$300 million of capital investment.investment and adding two additional operated rigs.

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, aan industry-leading 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 phaseThe Jackfish operation consists of Jackfish into operation, which ramped up to facility capacity by

the third quarter of 2015.three facilities. We expect each phaseJackfish to maintain a reasonably flat production profile for greater than 2015 years at an average gross production raterequiring approximately $200 million of approximately 35 MBbls per day at each facility.annual maintenance capital based on current economic conditions.

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,2018. Currently, we are evaluating our development timelinehave minimal planned capital outlays for Pike.

To facilitatePike in the deliverynear future. The majority 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-stockPike leasehold does not expire until 2025 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.2026.

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 2016,2019, we plan approximately $175 million of capital investmentto separate our operations in our Canadian Heavy Oil business.Canada.

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 asset 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 2016,2019, we plan on minimal refrac activity in the Barnett.to separate our Barnett Shale assets.

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 2123 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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Table of Contents

Index to Financial Statements

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 allestimates. The Group reports to and is managed through our finance department. No portion of the following:Group’s compensation is directly dependent on the quantity of reserves booked.

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 allover 30 years of industry experience with positions of increasing responsibility for the estimation and evaluation of reserves. He has been employed by Devon for the past 18 years, including the past 11 in his current position. His further professional qualifications include a degree in petroleum engineering, registered professional engineer, member of the qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitionsSociety of Petroleum Engineers 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 auditsreviews of each operating division’scountry’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 qualified third-party petroleum consulting firms. During 2015,2018, we engaged two such firms to audit 95%approximately 89% 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.

“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 conformityaccordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited approximately 87% of our U.S. reserves, and Deloitte LLP audited approximately 97% of our Canadian reserves.

In addition to conducting these internal reviews and external reserves 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

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 presentstables present production, price and cost information for each significant field, country and continent.

 

  Production 

 

Production

 

Year Ended December 31,

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

 

Oil (MMBbls)

 

 

Bitumen (MMBbls)

 

 

Gas (Bcf)

 

 

NGLs (MMBbls)

 

 

Total (MMBoe)

 

2015

          

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

   —       —       291     17     66  

 

 

 

 

 

 

 

 

186

 

 

 

12

 

 

 

43

 

STACK

 

 

12

 

 

 

 

 

 

121

 

 

 

14

 

 

 

45

 

Jackfish

   —       31     —       —       31  

 

 

 

 

 

35

 

 

 

 

 

 

 

 

 

35

 

U.S.

   60     —       579     50     206  

 

 

47

 

 

 

 

 

 

397

 

 

 

39

 

 

 

153

 

Canada

   10     31     8     —       42  

 

 

7

 

 

 

35

 

 

 

4

 

 

 

 

 

 

42

 

Total North America

   70     31     587     50     248  

 

 

54

 

 

 

35

 

 

 

401

 

 

 

39

 

 

 

195

 

2014

          

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

   1     —       332     20     76  

 

 

 

 

 

 

 

 

237

 

 

 

14

 

 

 

54

 

STACK

 

 

9

 

 

 

 

 

 

107

 

 

 

11

 

 

 

38

 

Jackfish

   —       20     —       —       20  

 

 

 

 

 

40

 

 

 

 

 

 

 

 

 

40

 

U.S.

   47     —       660     50     207  

 

 

42

 

 

 

 

 

 

433

 

 

 

36

 

 

 

150

 

Canada

   10     20     41     1     39  

 

 

7

 

 

 

40

 

 

 

6

 

 

 

 

 

 

48

 

Total North America

   57     20     701     51     246  

 

 

49

 

 

 

40

 

 

 

439

 

 

 

36

 

 

 

198

 

2013

          

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

   1     —       374     20     83  

 

 

 

 

 

 

 

 

265

 

 

 

15

 

 

 

60

 

STACK

 

 

7

 

 

 

 

 

 

103

 

 

 

9

 

 

 

33

 

Jackfish

   —       19     —       —       19  

 

 

 

 

 

40

 

 

 

 

 

 

 

 

 

40

 

U.S.

   28     —       709     41     189  

 

 

47

 

 

 

 

 

 

510

 

 

 

42

 

 

 

174

 

Canada

   15     19     165     4     64  

 

 

8

 

 

 

40

 

 

 

7

 

 

 

 

 

 

49

 

Total North America

   43     19     874     45     253  

 

 

55

 

 

 

40

 

 

 

517

 

 

 

42

 

 

 

223

 

9


Table of Contents

 

   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  

Index to Financial Statements

 

 

Average Sales Price (1)

 

 

 

 

 

Year Ended December 31,

 

Oil (Per Bbl)

 

 

Bitumen (Per Bbl)

 

 

Gas (Per Mcf)

 

 

NGLs (Per Bbl)

 

 

Production Cost (Per Boe) (1)(2)

 

2018 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

62.89

 

 

$

 

 

$

2.45

 

 

$

22.72

 

 

$

9.42

 

STACK

 

$

63.81

 

 

$

 

 

$

2.29

 

 

$

25.53

 

 

$

7.16

 

Jackfish

 

$

 

 

$

17.88

 

 

$

 

 

$

 

 

$

12.85

 

U.S.

 

$

61.97

 

 

$

 

 

$

2.37

 

 

$

24.74

 

 

$

8.61

 

Canada

 

$

27.36

 

 

$

17.88

 

 

N/M

 

 

$

 

 

$

13.43

 

Total North America

 

$

57.76

 

 

$

17.88

 

 

$

2.37

 

 

$

24.74

 

 

$

9.66

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

49.72

 

 

$

 

 

$

2.47

 

 

$

13.67

 

 

$

6.86

 

STACK

 

$

48.43

 

 

$

 

 

$

2.40

 

 

$

17.78

 

 

$

4.72

 

Jackfish

 

$

 

 

$

29.38

 

 

$

 

 

$

 

 

$

11.02

 

U.S.

 

$

49.41

 

 

$

 

 

$

2.48

 

 

$

15.66

 

 

$

6.74

 

Canada

 

$

33.73

 

 

$

29.38

 

 

N/M

 

 

$

 

 

$

11.70

 

Total North America

 

$

47.31

 

 

$

29.38

 

 

$

2.48

 

 

$

15.66

 

 

$

7.94

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

41.03

 

 

$

 

 

$

1.76

 

 

$

10.31

 

 

$

5.75

 

STACK

 

$

39.81

 

 

$

 

 

$

1.91

 

 

$

10.86

 

 

$

4.34

 

Jackfish

 

$

 

 

$

19.82

 

 

$

 

 

$

 

 

$

8.70

 

U.S.

 

$

38.92

 

 

$

 

 

$

1.84

 

 

$

9.81

 

 

$

6.44

 

Canada

 

$

23.96

 

 

$

19.82

 

 

N/M

 

 

$

 

 

$

9.36

 

Total North America

 

$

36.72

 

 

$

19.82

 

 

$

1.84

 

 

$

9.81

 

 

$

7.08

 

 

(1)

(1)

As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $254 million during 2018 with no impact to net earnings. These changes primarily related to our Barnett Shale and STACK properties.

(2)

Represents LOEproduction expense per Boe and excludes severanceBOE excluding production and property taxes. Jackfish and Canada include purchases of natural gas used to heat the heavy oil reservoirs. The gas is purchased at prevailing market prices, which vary from year to year.

Drilling Statistics

The following table summarizes our development and exploratory drilling results.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

Development Wells (1)

 

 

Exploratory Wells (1)

 

 

Total Wells (1)

 

Year Ended December 31,

  Productive   Dry   Productive   Dry   Productive   Dry   Total 

 

Productive

 

 

Dry

 

 

Productive

 

 

Dry

 

 

Productive

 

 

Dry

 

 

Total

 

2015

              

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

   298.6     1.8     40.7     —       339.3     1.8     341.1  

 

 

165.6

 

 

 

3.1

 

 

 

69.4

 

 

 

 

 

 

235.0

 

 

 

3.1

 

 

 

238.1

 

Canada

   79.0     —       —       —       79.0     —       79.0  

 

 

70.5

 

 

 

 

 

 

 

 

 

 

 

 

70.5

 

 

 

 

 

 

70.5

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Total North America

   377.6     1.8     40.7     —       418.3     1.8     420.1  

 

 

236.1

 

 

 

3.1

 

 

 

69.4

 

 

 

 

 

 

305.5

 

 

 

3.1

 

 

 

308.6

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

2014

              

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

   474.4     0.4     5.0     1.2     479.4     1.6     481.0  

 

 

149.8

 

 

 

 

 

 

44.0

 

 

 

 

 

 

193.8

 

 

 

 

 

 

193.8

 

Canada

   190.8     1.0     —       0.5     190.8     1.5     192.3  

 

 

100.5

 

 

 

 

 

 

 

 

 

 

 

 

100.5

 

 

 

 

 

 

100.5

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Total North America

   665.2     1.4     5.0     1.7     670.2     3.1     673.3  

 

 

250.3

 

 

 

 

 

 

44.0

 

 

 

 

 

 

294.3

 

 

 

 

 

 

294.3

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

2013

              

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

   555.3     —       56.1     7.0     611.4     7.0     618.4  

 

 

88.5

 

 

 

 

 

 

36.4

 

 

 

2.0

 

 

 

124.9

 

 

 

2.0

 

 

 

126.9

 

Canada

   211.9     1.0     7.4     —       219.3     1.0     220.3  

 

 

21.5

 

 

 

 

 

 

 

 

 

 

 

 

21.5

 

 

 

 

 

 

21.5

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Total North America

   767.2     1.0     63.5     7.0     830.7     8.0     838.7  

 

 

110.0

 

 

 

 

 

 

36.4

 

 

 

2.0

 

 

 

146.4

 

 

 

2.0

 

 

 

148.4

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

 

(1)

These well

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

10


Table of Contents

Index to Financial Statements

The following table presents the wells that were in progress on December 31, 2015.2018. As of February 1, 2016,2019, these wells were still in progress.

 

  Gross (1)   Net (2) 

 

Gross (1)

 

 

Net (2)

 

U.S.

   17.0     8.6  

 

 

184.0

 

 

 

105.2

 

Canada

   —       —    

 

 

1.0

 

 

 

1.0

 

  

 

   

 

 

Total North America

   17.0     8.6  

 

 

185.0

 

 

 

106.2

 

  

 

   

 

 

 

(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, 2015.2018.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Oil Wells (1)   Natural Gas Wells   Total Wells(1) 

 

Oil Wells (1)

 

 

Natural Gas Wells

 

 

Total Wells (1)

 

  Gross  (2)(4)   Net (3)   Gross  (2)(4)   Net (3)   Gross  (2)(4)   Net (3) 

 

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  

 

 

9,284

 

 

 

3,445

 

 

 

8,235

 

 

 

5,703

 

 

 

17,519

 

 

 

9,148

 

Canada

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

 

 

3,183

 

 

 

3,071

 

 

 

544

 

 

 

380

 

 

 

3,727

 

 

 

3,451

 

  

 

   

 

   

 

   

 

   

 

   

 

 

Total North America

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

 

 

12,467

 

 

 

6,516

 

 

 

8,779

 

 

 

6,083

 

 

 

21,246

 

 

 

12,599

 

  

 

   

 

   

 

   

 

   

 

   

 

 

 

(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 809902 and 1,565350 gross oil and gas wells, respectively, which had multiple completions and were operated by Devon.completions.

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 19,00012,900 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and drillingconstruction 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, 2015.2018. Of our 5.53.8 million net acres, approximately 3.01.9 million acres are held by production. The acreage in the table includes 0.2 million, 0.40.1 million and 0.1 million net acres subject to leases that are scheduled to expire during 2016, 20172019, 2020 and 2018,2021, respectively. As of December 31, 2015,2018, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.70.3 million net acres set to expire by December 31, 2018,2021, we will performanticipate performing 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 2015,2018, we allowed approximately 0.80.1 million acres to expire.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Developed   Undeveloped   Total 

 

Developed

 

 

Undeveloped

 

 

Total

 

  Gross (1)   Net (2)   Gross (1)   Net (2)   Gross (1)   Net (2) 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

  (Thousands) 

 

(Thousands)

 

U.S.

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

 

 

1,449

 

 

 

909

 

 

 

3,373

 

 

 

1,463

 

 

 

4,822

 

 

 

2,372

 

Canada

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

 

 

674

 

 

 

495

 

 

 

2,086

 

 

 

967

 

 

 

2,760

 

 

 

1,462

 

  

 

   

 

   

 

   

 

   

 

   

 

 

Total North America

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

 

 

2,123

 

 

 

1,404

 

 

 

5,459

 

 

 

2,430

 

 

 

7,582

 

 

 

3,834

 

  

 

   

 

   

 

   

 

   

 

   

 

 

 

(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.

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Title to Properties

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of the business.

As is customary in the industry, other than a preliminary title investigation, typically consisting of a review of local title records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations,More thorough title investigations, which generally include a review of title opinionrecords and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

EnLink PropertiesMarketing Activities

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

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 2016,2019, our production was sold under the following contract terms.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Short-Term Long-Term 

 

Short-Term

 

 

Long-Term

 

  Variable Fixed Variable Fixed 

 

Variable

 

 

Fixed

 

 

Variable

 

 

Fixed

 

Oil and bitumen

   72  —      28  —    

 

 

75

%

 

 

 

 

 

25

%

 

 

 

Natural gas

   36  4  60  —    

 

 

67

%

 

 

4

%

 

 

29

%

 

 

 

NGLs

   52  10  38  —    

 

 

41

%

 

 

20

%

 

 

39

%

 

 

 

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, 2015,2018, 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 

 

Total

 

 

Less Than 1 Year

 

 

1-3 Years

 

 

3-5 Years

 

Oil and bitumen (MMBbls)

   145     38     56     46     5  

 

 

53

 

 

 

25

 

 

 

28

 

 

 

 

Natural gas (Bcf)

         736             439             287             10             —    

 

 

360

 

 

 

220

 

 

 

125

 

 

 

15

 

NGLs (MMBbls)

   12     12     —       —       —    

 

 

10

 

 

 

10

 

 

 

 

 

 

 

  

 

   

 

   

 

   

 

   

 

 

Total (MMBoe)

   280     123     104     48     5  

 

 

123

 

 

 

72

 

 

 

49

 

 

 

2

 

  

 

   

 

   

 

   

 

   

 

 

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,Moreover, our proved reserves have generally 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, 20142018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.

During 2017 and 2013,2016, no purchaser accounted for over 10% of our consolidated operating revenues.sales revenue.

Competition

See “Item 1A. Risk Factors.”

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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;

acquisition of seismic data;

location, drilling and casing of wells;

location, drilling and casing of wells;

well design;

well design;

hydraulic fracturing;

hydraulic fracturing;

well production;

well production;

spill prevention plans;

spill prevention plans;

emissions and discharge permitting;

emissions and discharge permitting;

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

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;

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

calculation and disbursement of royalty payments and production taxes;

calculation and disbursement of royalty payments and production taxes;

plugging and abandoning of wells;

plugging and abandoning of wells;

transportation of production; and

transportation of production; and

endangered species and habitat.

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 integrationunitization 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, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws 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 or approved by the federal government and administered by the BLM or Bureau of Land ManagementIndian Affairs 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.government, tribes or tribal members. The federal government has, been particularly active in recent years in evaluatingfrom time to time, evaluated and, in some cases, promulgatingpromulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands can sometimes be subject to delays.

Royalties and Incentives in Canada

The royalty systemcalculation in Canada is a significant factor in the profitability of Canadian oil and gas production. CrownOil sands 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. TheFor pre-payout oil sands projects, the regulations prescribe lower royalty rates for oil sands projects until allowable capital costs have been recovered. Recently,In

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early 2016, the provinceAlberta government adopted the recommendation of Alberta released the findings of theits Royalty Review Advisory Panel, which concluded thatPanel. The new royalty framework preserves the royaltiesexisting royalty structure and rates for oil sands were appropriatesands. For conventional oil and should be maintained ingas royalty calculations, wells drilled after January 1, 2017 would use the newModernized Royalty Framework (MRF) which prescribes a lower royalty system to be implemented in 2017.rate until allowable costs have been recovered. The calculation for wells post payout is based on a percentage of production net of allowed deductions and varies with commodity price. 

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.

In December 2018, Alberta enacted the Curtailment Rules (Rules) in an effort to reduce Alberta’s oversupply of oil which resulted from pipeline and rail constraints. Pursuant to the Rules, operators that produce either or both crude oil or crude bitumen in amounts in excess of 10 MBbls/d are required to curtail their production. As of January 1, 2019, the production curtailment amount was set at 325 MBbls/d. The governmentscurtailment amounts are expected to reduce over 2019 to an average of Alberta, British Columbiaapproximately 95 MBbls/d as storage levels ease and Saskatchewan also regulateprice differential improve, and the volumeRules terminate on December 31, 2019. Devon’s curtailments in the first quarter of natural gas that may be removed from those provinces for consumption elsewhere.2019 as a result of the Rules are anticipated to total approximately 10 MBbls/d of bitumen, or approximately 2% of our total production.

Environmental, Pipeline Safety and Occupational Regulations

We strive to conduct our operations in a socially and environmentally responsible manner, which includes compliance with applicable law. 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.environment and natural resources. Environmental laws and regulations relate to:

the discharge of pollutants into federal and state waters;

the discharge of pollutants into federal, provincial and state waters;

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

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

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

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

the emission of certain gases into the atmosphere;

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 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

the development of emergency response and spill contingency plans;

worker protection.

the monitoring, repair and design of pipelines used for the transportation of oil and natural gas;

the protection of threatened and endangered species; and

worker protection.

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 considerMoreover, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the costsplace of the government and sue operators for alleged violations of environmental law. Environmental protection and health and safety and health compliance are 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 likelymay continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

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.

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Volatile Oil, Gas and NGL Prices Are VolatileSignificantly Impact our Business

Our financial condition, results of operations 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. SinceHistorically, market prices and our realized prices have been volatile. For example, over the second halflast five years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from a high of 2014, there has beenover $100 per Bbl and $6 per MMBtu, respectively, to a significant declinelow of under $27 per Bbl and $1.70 per MMBtu, respectively. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:

the domestic and worldwide supply of and demand for oil, gas and NGLs;

volatility and trading patterns in the commodity-futures markets;

conservation and environmental protection efforts;

production levels of members of OPEC, Russia or other producing countries;

geopolitical risks, including political and civil unrest in the Middle East, Africa and South America;

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

regional pricing differentials, including in Canada, the Delaware Basin and other areas of our operations;

differing quality of production, including 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;

technological advances affecting energy consumption and production;

the overall economic environment;

changes in trade relations and policies, including the imposition of tariffs by the U.S. or China; and

other governmental regulations and taxes.

The differential between WTI and Western Canadian Select, a benchmark for the Canadian oil gas and NGL prices, which has adverselymarket, recently expanded, widening to nearly $46 per barrel in November 2018. As a result, our Canadian heavy oil unhedged realized price for the fourth quarter was near zero. This negatively affected our 2015 operating results of operations in 2018, 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 differentials or 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;

reducing the amount of oil, bitumen, 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 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 noncash write-downs.

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.

Estimates of Oil, Gas and NGL Reserves Are Uncertain and May Be Subject to Revision

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 and appraisal 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 financial condition and the value of our properties, as well as the estimates of our 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.

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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 ResultsOur Operations Are Uncertain and Involve Substantial Costs and Risks

Our exploration and developmentoperating 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 drilling conditions, pressure conditions or irregularities in reservoir formations;

equipment failures or accidents;

fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;

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

issues with title or in receiving governmental permits or approvals;

restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;

environmental hazards or liabilities;

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

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

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.

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

In addition, we rely on our employees, consultants and sub-contractors to conduct our operations in compliance with applicable laws and standards. Any violation of such laws or standards by these individuals, whether through negligence, harassment, discrimination or other misconduct, could result in significant liability for us and adversely affect our business. For example, negligent operations by employees could result in serious injury, death or property damage, and sexual harassment or racial and gender discrimination could result in legal claims and reputational harm.

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 matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such

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regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion 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 laws, 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 in the future could further affect, our operations. Regulatory and public policy developments could, among other things, restrict production levels, impose 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. In addition, changes in public policy may indirectly impact our operations by, among other things, increasing the cost of supplies and equipment and fostering general economic uncertainty. For example, changes in U.S. trade relations, particularly the imposition of tariffs by the U.S. and China, may increase the cost of materials we or our vendors use, thereby increasing our operating expense. 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, pipeline safety, seismic activity and income taxes, as discussed below.

Hydraulic Fracturing – In recent years, the EPA has made proposals that subject hydraulic fracturing to further regulation and that could potentially restrict the practice of hydraulic fracturing. For example, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and finalized in 2016 regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a study in 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The BLM previously finalized regulations to regulate hydraulic fracturing on federal lands, but subsequently issued a repeal of those regulations in 2017. Several states in which we operate have already adopted and more states are considering adopting laws or regulations that require disclosure of chemicals used in hydraulic fracturing and impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. In addition, some states and municipalities have significantly limited drilling activities or hydraulic fracturing or are considering doing so or banning the practice altogether. 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 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. For example, in 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high consequence areas to newly proposed “moderate consequence areas” and would also impose more rigorous testing and reporting requirements on such pipelines. To date, no further action has been taken. PHMSA has announced its intent to address the 2016 proposed rules for gas pipelines through three separate final rulemakings in 2019. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Following the change in presidential administrations, implementation of this rule was delayed, but the final rule is expected to be published in the Federal Register and become effective during the first half of 2019. 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 – Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims, seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of operation.  

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Index to Financial Statements

Changes to Tax Laws – 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.

Concerns About Climate Change and Related Regulatory, Social and Market Actions May Adversely Affect Our Business

Continuing and increasing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases. For example, both the EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry. Following the change in presidential administrations, however, the agencies have attempted to revise or rescind their previously issued methane standards. Litigation concerning these methane regulations and subsequent attempts to revise or rescind them is ongoing. Nevertheless, several states where we operate, including Wyoming, have already imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. With respect to more comprehensive regulation, federal and state initiatives to date have generally focused on the development of cap-and-trade or carbon tax programs. As generally proposed, a cap-and-trade program would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances, while a carbon tax could impose taxes based on emissions from our operations and downstream uses of our products.  

In Canada, greenhouse gas emissions are also being addressed at both the federal and provincial level. Devon will continue to be subject to Alberta’s climate change laws and regulations until at least 2021. Those laws and regulations include a legislated oil sands emission limit, with forthcoming regulations involving methane emissions reduction targets. Beginning January 2019, the Greenhouse Gas Pollution Pricing Act subjects all of Canada to a federal price on greenhouse gas emissions unless a province or territory has implemented a compliant carbon pricing regime. Litigation concerning the act is ongoing, and it is unclear how the act will ultimately treat provincial plans. In Alberta, large industrial emitters are subject to the Carbon Competitiveness Incentive Regulation (CCIR). The CCIR prices carbon, but provides cost protection to emission-intensive / trade-exposed industries, including Devon’s oil sands operations. The impact to our operations from these laws and regulations is expected to be minimal in the near term. Oil and gas facilities that are not subject to the CCIR are exempt from its economy-wide carbon levy until 2023.

In addition to regulatory risk, other market and social initiatives resulting from the changing perception of climate change present risks for our business. For example, in an effort to promote a lower-carbon economy, there are various public and private initiatives subsidizing the development of alternative energy sources, including by mandating the use of specific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, certain financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to their concern regarding climate change. Such restrictions in capital could make it more difficult to secure funding to operate our business. Finally, governmental entities and other plaintiffs have brought, and may continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged effects of climate change. These and the other regulatory, social and market risks relating to climate change described above could result in unexpected costs, increase our operating expense and reduce the demand for our products, which in turn could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.  

Our Hedging LimitsActivities Limit Participation in Commodity Price Increases and Involve Other Risks

We periodically enter into hedging activitiesfinancial derivative instruments 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 maywill 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. Moreover, as a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and other legislation, hedging transactions and many of our contract counterparties have become subject to increased governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost

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and availability of our hedging arrangements, including by causing our contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.

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 sharesshare 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 insolvency, liquidity problems or other issues and may not be able to meet their financial obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly if commodity prices remainduring a depressed or decline further.volatile commodity price environment. Any such default by these counterparties may result in us being forced to cover the costs of those obligations and liabilities, which could adversely impact our financial results.results and condition.

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.

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

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, 2015,2018, we had total consolidated indebtedness of $13.1$5.9 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;

requiring us to dedicate a 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

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.

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 assetsasset sales and purchases, liquidity, forecasted production growth and commodity prices. A ratings downgradeWe are currently required to provide letters of credit or other assurances under certain of our contractual arrangements. Any credit downgrades could adversely impact our ability to access financing and trade credit, require us to provide additional letters of credit or other assurances under contractual arrangements 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.

Cyber Attacks May Adversely Impact Our Acquisition and Divestiture Activities Involve Substantial RisksOperations

Our business depends,has become increasingly dependent on digital technologies, and we anticipate expanding our use of technology in part,our operations, including through process automation and data analytics. Concurrent with this growing dependence on making acquisitionstechnology is greater sensitivity to cyberattack activities, which have been increasing against our industry. Cyber attackers often attempt to gain unauthorized access to digital systems for purposes of misappropriating sensitive information, intellectual property or financial assets,

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corrupting data or causing operational disruptions. These attacks may be perpetrated by third parties or insiders. Techniques used in these attacks 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 complementdoes not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, our vendors, midstream providers and other business partners may separately suffer disruptions or expandbreaches from cyber attacks, which, in turn, could adversely impact our current businessoperations and successfully integrating any acquired assets or businesses. Ifcompromise our information. Although we are unablehave not suffered material losses related to make attractive acquisitions, then our future growth could be limited. Furthermore, evencyber attacks to date, if we do make acquisitions, they may not result in an

increase in our cash flow from operationswere successfully attacked, we could incur substantial remediation and other costs or otherwise result insuffer other negative consequences, including litigation risks. Moreover, as the benefits anticipated duesophistication of cyber attacks continues 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,evolve, we may sell or otherwise dispose of certain of our properties as a result of an evaluation of our asset portfolio andbe required to helpexpend significant additional resources to further 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 seekdigital security or 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.remediate vulnerabilities.  

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 delays, curtailments or cancellations of operations or future development, which could 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

well as other systems operated by usAll or third parties. Regardless of who operates the midstream systems we rely upon, a portion of our production in any regionone or more regions may be interrupted or shut in from time to time fromdue to 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 partiesthe midstream operators 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.

Insurance Does Not Cover All Risks

As discussed above, our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development and production of oil, gas and NGLs. 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, we have limited or no insurance coverage for a variety of other risks, including pollution events that are considered gradual, war and political risks and fines or penalties 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.  

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. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield services, which could adversely affect our ability to execute our development plans on a timely basis and within budget. 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 alsoours and may have established superior strategic long-term positions and relationships, in areas in which we may seek new entry.including with respect to midstream take-away capacity. As a consequence, we may be at a competitive disadvantage in bidding for assets or services.services and accessing capital and downstream markets. 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.

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Our SystemsBusiness Could Be Adversely Impacted by Investors Attempting to Effect Change

Stockholder activism has been increasing in our industry, and Infrastructure May Adversely Impact Our Operationsinvestors may from time to time attempt to effect changes to our business or governance, whether by stockholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our board of directors and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of our business.  Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in significant fluctuation in the market price of our common stock.

Our industry has become increasingly dependentAcquisition and Divestiture Activities Involve Substantial Risks

Our business depends, in part, 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 misappropriatingmaking acquisitions that complement or expand our current business and successfully integrating any acquired assets or sensitive information, corrupting data or causing operational disruption and maybusinesses. If we are unable to make attractive acquisitions, our future growth could 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,limited. Furthermore, even if we were successfully attacked, we might incur substantial remediation and other costsdo make acquisitions, they may not result in an increase in our cash flow from operations or suffer other negative consequences. Moreover, asotherwise result in the sophistication of cyber attacks continuesbenefits anticipated due to evolve,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 be requiredsell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio and to expend significant additional resources to furtherhelp enhance our digital securityliquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or business and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to remediate vulnerabilities.terminate a transaction prior to closing.

Item 1B.Unresolved Staff Comments

Not applicable.

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.

Devon Energy Production Company, L.P., a wholly-owned subsidiary of the Company, is currently in negotiations with the EPA with respect to alleged noncompliance with the leak detection and repair requirements of EPA regulations promulgated under the Clean Air Act at its Beaver Creek Gas Plant located near Riverton, Wyoming. Although management cannot predict the outcome of settlement negotiations, the resolution of this matter may result in a fine or penalty in excess of $100,000.

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.NYSE under the “DVN” ticker symbol. On February 10, 2016,6, 2019, there were 8,3077,094 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 highdeclaration of future dividends is a business decision made by our Board of Directors, and low sales prices forwill depend on Devon’s financial condition and other relevant factors. Additional information on our common stock as reported by the NYSE during 2015dividends can be found in Note 18 in “Item 8. Financial Statements and 2014, as well as the quarterly dividends per share paid during 2015 and 2014.Supplementary Data” of this report.

   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.

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 olda peer group of companies. Our newcompanies to which we compare our performance. The peer group includes Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, Concho Resources, Inc., ConocoPhillips, 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, 20102013 in Devon’s common stock, the S&P 500 Index and the peer groups,group, and dividends have been reinvested subsequent to the initial investment.

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 2015.2018 (shares in thousands).

Period

 

Total Number of

Shares Purchased (1)

 

 

Average Price

Paid per Share

 

 

Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (2)

 

 

Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2)

 

October 1 - October 31

 

 

10,532

 

 

$

36.01

 

 

 

10,529

 

 

$

2,388

 

November 1 - November 30

 

 

7,079

 

 

$

31.55

 

 

 

7,068

 

 

$

2,165

 

December 1 - December 31

 

 

6,020

 

 

$

23.82

 

 

 

6,015

 

 

$

2,022

 

Total

 

 

23,631

 

 

$

31.57

 

 

 

23,612

 

 

 

 

 

 

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

(1)

In addition to shares purchased under the share repurchase program described below, these amounts also included approximately 19,000 shares received by us from employees and directors for the payment of personal income tax withholding on restrictedvesting transactions.

(2)

On March 7, 2018, we announced a $1.0 billion share repurchase program. On June 6, 2018, we announced the expansion of this program to $4.0 billion. On February 19, 2019, we announced a further expansion to $5.0 billion with a December 31, 2019 expiration date. During 2018, we repurchased 78.1 million shares of common stock vesting.for $3.0 billion, or $38.11 per share. Future purchases under the program will be made in the open market, private transactions or through the use of ASR programs.

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 71,50039,000 shares of our common stock in 2015,2018, 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 Planthis 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.trustee. 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 2015,2018, there were no shares purchased by Canadian employees.employees under the plan.


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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.

 

 

2018

 

 

2017

 

 

2016

 

 

2015

 

 

2014

 

Statement of Earnings data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Upstream revenues (1)

 

$

6,285

 

 

$

5,307

 

 

$

3,981

 

 

$

5,885

 

 

$

11,619

 

Total revenues (1)

 

$

10,734

 

 

$

8,878

 

 

$

6,753

 

 

$

9,372

 

 

$

16,636

 

Net earnings (loss) from continuing operations (2)

 

$

764

 

 

$

758

 

 

$

(574

)

 

$

(12,231

)

 

$

(1,004

)

Net earnings (loss) from continuing operations per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic (2)

 

$

1.53

 

 

$

1.44

 

 

$

(1.14

)

 

$

(30.09

)

 

$

(2.49

)

Diluted (2)

 

$

1.52

 

 

$

1.43

 

 

$

(1.14

)

 

$

(30.09

)

 

$

(2.49

)

Cash dividends per common share

 

$

0.30

 

 

$

0.24

 

 

$

0.42

 

 

$

0.96

 

 

$

0.94

 

Balance Sheet data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets (2)(3)

 

$

19,566

 

 

$

30,241

 

 

$

28,675

 

 

$

29,673

 

 

$

49,253

 

Long-term debt

 

$

5,785

 

 

$

6,749

 

 

$

6,859

 

 

$

8,990

 

 

$

7,738

 

Stockholders' equity

 

$

9,186

 

 

$

14,104

 

 

$

12,722

 

 

$

11,111

 

 

$

24,789

 

Common shares outstanding

 

 

450

 

 

 

525

 

 

 

523

 

 

 

418

 

 

 

409

 

 

  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)

In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers using the modified retrospective method and has applied the standard to all existing contracts. The impact of adoption for 2018 is further discussed in Note 1 of “Item 8. Financial Statements and Supplementary Data” of this report. Prior periods have not been restated.

(1)

During 2015, we recorded noncash

(2)

Material asset impairments totaling $20.8 billion. During 2014, 2013 and 2012, we recorded noncashacquisition and divestiture activity had significant impacts on operating results and the carrying value of our oil and gas assets. Specifically, there were asset impairments totaling $2.0of $0.4 billion, $16.1 billion and $3.4 billion in each year.

(2)Debt balances at December 31,2016, 2015 and 2014, respectively. More discussion on these items can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 2 and Note 5 of “Item 8. Financial Statements and Supplementary Data” of this report.  

(3)

Amounts in 2014 through 2017 include $3.1 billionassets related to our aggregate ownership interest in EnLink and $2.0 billion, respectively,the General Partner. As discussed further in Note 19 of “Item 8. Financial Statements and Supplementary Data” of this report, the 2018 divestment of our aggregate ownership interests in EnLink and the General Partner resulted in the reclassification of EnLink debt that is non-recourseand the General Partners’ assets to Devon.assets held for sale, which are included within this amount.

24


Table of Contents

Index to Financial Statements

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 20152018 Results

By executing on2018 was a pivotal year for Devon as we took several significant steps toward achieving our strategy outlinedlong-term strategic goals. Operationally, we successfully transitioned our U.S. oil business into full-field development, which resulted in “Items 1high-return, light-oil production advancing 14 percent in 2018. In addition to this strong operating performance, we made substantial progress high-grading our asset portfolio, building per-share value through our share-repurchase program and 2. Business and Properties” of this report, we strive to optimize value forreducing our shareholdersfinancial leverage 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:

more than 40 percent.

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

Increased STACK and Delaware Basin production 27% in 2018 compared to 2017.

Maintained our 2018 capital expenditure forecast.

Substantially achieved $5.0 billion in asset sales, including the monetization of EnLink and the General Partner.

Repurchased $3.0 billion of common stock, representing a 14% share count reduction since December 31, 2017.

Reduced long-term debt by $922 million, which is expected to reduce annualized financing costs by $66 million.

Completed workforce reduction and cost reduction initiatives expected to generate $150 million of annualized savings.

Increased our quarterly common stock dividend 33% to $0.08 per share beginning in the second quarter of 2018.

Exited 2018 with $2.4 billion of cash and $2.9 billion of available credit under our Senior Credit Facility and have no significant debt maturities until 2021.

 

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.

 

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 the left, our operating achievements are subject to the significant decline in crudevolatility of commodity prices. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub prices that beganranged from an average high of $64.79 per Bbl and $3.11 per MMBtu, respectively, to an average low of $43.36 per Bbl and $2.46 per MMBtu, respectively. Widening Western Canadian Select differentials negatively impacted the prices we realized on our heavy oil production in the thirdfourth quarter of 2014 continued throughout 2015 and weakened further during2018. In the first two months of 2016. The 2015 WTI crude2019, Western Canadian Select differentials have improved significantly.  

Key measures of our financial performance in 2018 are summarized in the following table. Increased 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 liquids prices as well as continued focus cost management improved our 2018 financial performance as compared to 2017, as seen in the table below. Additionally, we recognized a gain of approximately $2.6 billion ($2.2 billion after-tax) related to the sale of EnLink and OPIS Mont Belvieu, Texas indices decreased significantly since the endGeneral Partner during 2018. More details for these metrics are found within the “Results of 2014 as a result of an imbalance between supply and demand across North America.Operations – 2018 vs. 2017” below.

25


As a resultTable 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:Contents

 

   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  

Index to Financial Statements

 

 

 

2018

 

 

Change

 

 

2017

 

 

Change

 

 

2016

 

Total:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss) attributable to Devon

 

$

3,064

 

 

 

+241

%

 

$

898

 

 

 

+185

%

 

$

(1,056

)

Net earnings (loss) per diluted share attributable to Devon

 

$

6.10

 

 

 

+259

%

 

$

1.70

 

 

 

+181

%

 

$

(2.09

)

Core earnings (loss) attributable to Devon (1)

 

$

655

 

 

 

+53

%

 

$

427

 

 

 

+216

%

 

$

(367

)

Core earnings (loss) attributable to Devon per diluted share (1)

 

$

1.30

 

 

 

+60

%

 

$

0.81

 

 

 

+212

%

 

$

(0.73

)

Continuing Operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss)

 

$

764

 

 

 

+1

%

 

$

758

 

 

 

+232

%

 

$

(574

)

Net earnings (loss) per diluted share

 

$

1.52

 

 

 

+6

%

 

$

1.43

 

 

 

+225

%

 

$

(1.14

)

Core earnings (loss) (1)

 

$

587

 

 

 

+48

%

 

$

397

 

 

 

+207

%

 

$

(371

)

Core earnings (loss) per diluted share (1)

 

$

1.17

 

 

 

+57

%

 

$

0.75

 

 

 

+202

%

 

$

(0.73

)

Discontinued Operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss) attributable to Devon

 

$

2,300

 

 

 

+1543

%

 

$

140

 

 

 

+129

%

 

$

(481

)

Net earnings (loss) per diluted share attributable to Devon

 

$

4.58

 

 

 

+1596

%

 

$

0.27

 

 

 

+128

%

 

$

(0.95

)

Core earnings attributable to Devon (1)

 

$

68

 

 

 

+127

%

 

$

30

 

 

 

+580

%

 

$

4

 

Core earnings attributable to Devon per diluted share (1)

 

$

0.13

 

 

 

+120

%

 

$

0.06

 

 

 

+1628

%

 

$

0.00

 

Other Metrics:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retained production (MBoe/d)

 

 

500

 

 

 

+4

%

 

 

481

 

 

 

- 3

%

 

 

497

 

Total production (MBoe/d)

 

 

535

 

 

 

- 2

%

 

 

543

 

 

 

- 11

%

 

 

611

 

Realized price per Boe (2)

 

$

29.08

 

 

 

+12

%

 

$

25.96

 

 

 

+39

%

 

$

18.72

 

Operating cash flow from continuing operations

 

$

2,228

 

 

 

+1

%

 

$

2,209

 

 

 

+165

%

 

$

834

 

Capitalized expenditures, including acquisitions

 

$

2,576

 

 

 

+19

%

 

$

2,169

 

 

 

- 23

%

 

$

2,826

 

Cash and cash equivalents

 

$

2,414

 

 

 

- 9

%

 

$

2,642

 

 

 

+36

%

 

$

1,947

 

Total debt

 

$

5,947

 

 

 

- 13

%

 

$

6,864

 

 

 

+0

%

 

$

6,859

 

Reserves (MMBoe)

 

 

1,927

 

 

 

- 10

%

 

 

2,152

 

 

 

+5

%

 

 

2,058

 

(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”).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. In 2018, WTI oil prices averaged approximately $67/Bbl through October, supported by stronger-than-expected oil demand, market management by both OPEC and non-OPEC partners and unplanned supply outages. However, oil prices markedly declined in November and December, averaging approximately $53/Bbl and reaching as low as $42.53/Bbl in December. The deterioration of WTI was driven by OPEC and non-OPEC partners unwinding their production cut agreement, compounded by rising supply and concerns over slowing global economic growth. Western Canadian Select basis differentials were challenged in the fourth quarter of 2018 due to robust production outpacing local demand, pipeline capacity and rail capacity out of the region. Looking ahead, current market fundamentals indicate prices forthat 2019 crude oil and natural gas will continuepricing is expected to be depressed for much of 2016. Although changesimprove from its fourth quarter 2018 levels. Additionally, Western Canadian Select differentials are also projected to improve, driven by provincially mandated production cuts combined with takeaway capacity additions expected in late 2019. Changes in OPEC production strategies, the macro-economic forecasts,environment, geopolitical risks orand other factors could impact our current forecasts, we anticipate weak oil and natural gas prices throughout the majority of 2016.forecasts.

In 2015,2018, Devon marked its 44th30th year as a public company and 47th anniversary in the oil and gas business, and its 27th year as a public company. As an established companyso we are experienced in dealing with a strong leadership team, we have experience operating in periodsthe volatile nature of weak commodity prices. WithTo mitigate our focused strategy and portfolio of quality assets, we are preparedexposure to successfully navigate the current pricing challengescommodity market volatility and ensure our long-term financial strength.strength, we use a disciplined, risk-management hedging program. Our hedging program incorporates both systematic hedges added on a regular basis and discretionary hedges layered in on an opportunistic basis to take advantage of favorable market conditions. We have approximately 50% of our anticipated 2019 oil and gas volumes hedged, and we are currently adding hedges for 2020 as well. Further insulating our cash flow, we are proactively locking in hedges on the Western Canadian Select basis differential to WTI and currently have approximately 50% of our 2019 Canadian heavy oil production hedged.

Specifically, after completing26


Table of Contents

Index to Financial Statements

Despite the STACK acquisition,uncertainties pertaining to commodity prices, we began 2016 with approximately $3.9 billionremain focused on our strategic priorities 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 ourhaving a premier portfolio of assets, delivering superior execution as we drill and operate oil and natural gas wells, and maintaining our financial strength and flexibility. 2019 will be an important year for Devon as we plan to separate our Canadian and Barnett Shale assets and complete our multi-year transition to a U.S. oil company with operations focused on four core areas in the Delaware Basin, STACK, Eagle Ford and Rockies. With a focused portfolio of U.S. oil assets, we also intend to optimize our cost structure by reducing our annual capital costs, G&A costs, interest expense and production expenses by $780 million in the aggregate by 2021. We expect to deliver 70% of these annualized cost savings in 2019, as the Canadian and Barnett Shale assets are committedseparated, and we align our workforce with the retained business and reduce outstanding debt.

Importantly, the portfolio changes and optimized cost performance are expected to enhance our competitive positioning as oil production growth, price realizations, field-level margins and corporate rates-of-return should all improve. With these improved expected outcomes, we remained focused on our 2019 capital allocation priorities of funding our core operations, protecting our balance sheetinvestment-grade credit ratings and managingpaying 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

workforce and other G&A costs to better align with the activity level of our core business inshareholder dividend. Further, when considering the current commodity price environment. environment and our current hedge position, we can achieve all our capital allocation priorities at $46/Bbl WTI and $3.00/Mcf Henry Hub. Should WTI drop closer to $40/Bbl for an extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI rises above $46/Bbl, our free cash flow will accelerate, providing additional capital allocation opportunities.

Results of Operations – 2018 vs. 2017

The reductionsfollowing graphs, discussion and analysis are expectedintended to decrease gross G&A costsprovide an understanding of our results of operations and current financial condition. Specifically, the graph below shows the change in net earnings from 2017 to 2018. The material changes are further discussed by approximately $400 millioncategory on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to $500 million onnoncontrolling interests.

(1)

Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses.

27


Table of Contents

Index to Financial Statements

The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.

(2)

As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” in this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $254 million during 2018 with no impact to net earnings.


28


Table of Contents

Index to Financial Statements

Upstream Operations

Oil, Gas and NGL Production

 

 

2018

 

 

% of Total

 

 

2017

 

 

Change

 

Oil and bitumen (MBbls/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

42

 

 

 

17

%

 

 

29

 

 

 

+42

%

STACK

 

 

32

 

 

 

13

%

 

 

25

 

 

 

+28

%

Rockies Oil

 

 

14

 

 

 

6

%

 

 

10

 

 

 

+37

%

Heavy Oil

 

 

18

 

 

 

7

%

 

 

18

 

 

 

+1

%

Eagle Ford

 

 

28

 

 

 

12

%

 

 

34

 

 

 

- 17

%

Barnett Shale

 

 

1

 

 

 

0

%

 

 

1

 

 

 

- 7

%

Other

 

 

5

 

 

 

2

%

 

 

5

 

 

 

- 3

%

Retained assets

 

 

140

 

 

 

57

%

 

 

122

 

 

 

+14

%

U.S. divested assets

 

 

9

 

 

 

4

%

 

 

12

 

 

 

- 23

%

Total Oil

 

 

149

 

 

 

61

%

 

 

134

 

 

 

+11

%

Bitumen

 

 

97

 

 

 

39

%

 

 

110

 

 

 

- 12

%

Total Oil and bitumen

 

 

246

 

 

 

100

%

 

 

244

 

 

 

+1

%

 

 

2018

 

 

% of Total

 

 

2017

 

 

Change

 

Gas (MMcf/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

105

 

 

 

10

%

 

 

86

 

 

 

+22

%

STACK

 

 

334

 

 

 

30

%

 

 

294

 

 

 

+13

%

Rockies Oil

 

 

16

 

 

 

1

%

 

 

8

 

 

 

+85

%

Heavy Oil

 

 

10

 

 

 

1

%

 

 

17

 

 

 

- 39

%

Eagle Ford

 

 

79

 

 

 

7

%

 

 

95

 

 

 

- 17

%

Barnett Shale

 

 

447

 

 

 

41

%

 

 

475

 

 

 

- 6

%

Other

 

 

1

 

 

 

0

%

 

 

1

 

 

 

+6

%

Retained assets

 

 

992

 

 

 

90

%

 

 

976

 

 

 

+2

%

U.S. divested assets

 

 

108

 

 

 

10

%

 

 

227

 

 

 

- 52

%

Total

 

 

1,100

 

 

 

100

%

 

 

1,203

 

 

 

- 9

%

 

 

2018

 

 

% of Total

 

 

2017

 

 

Change

 

NGLs (MBbls/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

16

 

 

 

15

%

 

 

10

 

 

 

+53

%

STACK

 

 

37

 

 

 

35

%

 

 

30

 

 

 

+24

%

Rockies Oil

 

 

1

 

 

 

2

%

 

 

1

 

 

 

+75

%

Eagle Ford

 

 

13

 

 

 

12

%

 

 

13

 

 

 

+2

%

Barnett Shale

 

 

30

 

 

 

28

%

 

 

31

 

 

 

- 4

%

Other

 

 

1

 

 

 

1

%

 

 

1

 

 

 

- 5

%

Retained assets

 

 

98

 

 

 

93

%

 

 

86

 

 

 

+14

%

U.S. divested assets

 

 

8

 

 

 

7

%

 

 

13

 

 

 

- 40

%

Total

 

 

106

 

 

 

100

%

 

 

99

 

 

 

+7

%

 

 

2018

 

 

% of Total

 

 

2017

 

 

Change

 

Combined (MBoe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

75

 

 

 

14

%

 

 

54

 

 

 

+39

%

STACK

 

 

125

 

 

 

24

%

 

 

104

 

 

 

+20

%

Rockies Oil

 

 

17

 

 

 

3

%

 

 

12

 

 

 

+43

%

Heavy Oil

 

 

117

 

 

 

22

%

 

 

131

 

 

 

- 11

%

Eagle Ford

 

 

54

 

 

 

10

%

 

 

62

 

 

 

- 13

%

Barnett Shale

 

 

105

 

 

 

20

%

 

 

111

 

 

 

- 5

%

Other

 

 

7

 

 

 

1

%

 

 

7

 

 

 

- 3

%

Retained assets

 

 

500

 

 

 

94

%

 

 

481

 

 

 

+4

%

U.S. divested assets

 

 

35

 

 

 

6

%

 

 

62

 

 

 

- 44

%

Total

 

 

535

 

 

 

100

%

 

 

543

 

 

 

- 2

%

Focused development activities in the Delaware Basin, STACK and Rockies resulted in an annualized basis, excluding associated employee severanceapproximate 28% increase in production from those areas compared to 2017. These increases also drove a 17% increase in our U.S. retained oil production. This strong performance led to the overall growth in our retained assets during 2018. Production increases from our capital focused assets were partially offset by the effects of facility repairs and other restructuring costs. Following a numbermaintenance work at the Jackfish facilities, as well as by lower production resulting from our U.S. non-core divestitures.

Oil, Gas and NGL Prices

 

 

2018

 

 

Realization

 

 

2017

 

 

Change

 

Oil and bitumen (per Bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI index

 

$

64.79

 

 

 

 

 

 

$

50.99

 

 

 

+27

%

Access Western Blend index

 

$

34.75

 

 

 

 

 

 

$

36.90

 

 

 

- 6

%

U.S.

 

$

61.97

 

 

 

96%

 

 

$

49.41

 

 

 

+25

%

Canada

 

$

19.37

 

 

 

30%

 

 

$

29.99

 

 

 

- 35

%

Realized price, unhedged

 

$

42.04

 

 

 

65%

 

 

$

39.23

 

 

 

+7

%

Cash settlements

 

$

(0.49

)

 

 

 

 

 

$

0.23

 

 

 

 

 

Realized price, with hedges

 

$

41.55

 

 

 

64%

 

 

$

39.46

 

 

 

+5

%

 

 

2018

 

 

Realization

 

 

2017

 

 

Change

 

Gas (per Mcf)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Henry Hub index

 

$

3.09

 

 

 

 

 

 

$

3.11

 

 

 

- 1

%

Realized price, unhedged

 

$

2.37

 

 

 

77%

 

 

$

2.48

 

 

 

- 5

%

Cash settlements

 

$

0.01

 

 

 

 

 

 

$

0.08

 

 

 

 

 

Realized price, with hedges

 

$

2.38

 

 

 

77%

 

 

$

2.56

 

 

 

- 7

%

 

 

2018

 

 

Realization

 

 

2017

 

 

Change

 

NGLs (per Bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mont Belvieu blended index (1)

 

$

28.31

 

 

 

 

 

 

$

24.77

 

 

 

+14

%

Realized price, unhedged

 

$

24.74

 

 

 

87%

 

 

$

15.66

 

 

 

+58

%

Cash settlements

 

$

(1.17

)

 

 

 

 

 

$

(0.10

)

 

 

 

 

Realized price, with hedges

 

$

23.57

 

 

 

83%

 

 

$

15.56

 

 

 

+51

%

(1)

Based upon composition of our NGL barrel.

29


Table of cost-reduction initiatives culminating with our February 2016 workforce reduction, we are expecting a $700 millionContents

Index to $900 million reduction in operating and G&A costs on an annualized basis.Financial Statements

We estimate we will incur approximately $225 million to $275 million of restructuring costs

 

 

2018

 

 

2017

 

 

Change

 

Combined (per Boe)

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

$

31.86

 

 

$

24.88

 

 

 

+28

%

Canada

 

$

19.12

 

 

$

29.39

 

 

 

- 35

%

Realized price, unhedged

 

$

29.08

 

 

$

25.96

 

 

 

+12

%

Cash settlements

 

$

(0.43

)

 

$

0.27

 

 

 

 

 

Realized price, with hedges

 

$

28.65

 

 

$

26.23

 

 

 

+9

%

Upstream revenues increased as a result of the workforce reduction. We expect to recognize the majority of these restructuring costs in the first quarter of 2016higher unhedged, realized prices for our U.S. oil 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.

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.

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 SalesNGLs.

The volume and price changesincrease in the tables above caused the following changes to our oil gas and NGL sales.sales primarily resulted from higher average WTI crude index prices, which were 27% higher in 2018, resulting in an increase of approximately $568 million.

   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

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$351 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 lower14% higher NGL prices at the Mont Belvieu, Texas hub.

Prices 2014 vs. 2013 Oil, gas and NGL sales increased primarily because of a 20% increasehub, as well as improved realizations 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. NGL price.

These increases were partially offset by lowerwidening differentials to the WTI index for bitumen sales, which negatively impacted our upstream revenues by $406 million. In the fourth quarter of 2018, market forces widened Canadian heavy oil differentials beyond historical norms and NGLnegatively impacted the price we 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 withon our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as componentsCanadian production. We had basis swaps for approximately half of our revenues. The subsequent tables present our oil, gas and NGL prices with and withoutfourth quarter production to mitigate the effect of the lower market price. To further mitigate the effects of the cash settlements. The prices do not includelower price, we reduced our Jackfish production in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d. Our Canadian heavy oil unhedged realized price for the effects of fair value gains and losses.fourth quarter was near zero. To date in 2019, heavy oil differentials have significantly improved driven by provincially mandated production cuts combined with takeaway capacity additions expected in 2019.

 

   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
  

 

 

   

 

 

   

 

 

 

As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by approximately $254 million with no impact to net earnings.

   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  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
Commodity Derivatives

 

   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  
  

 

 

   

 

 

   

 

 

  

 

 

   

 

 

 

 

 

2018

 

 

2017

 

 

Change

 

 

 

Q

 

 

 

 

 

 

 

 

 

Oil

 

$

(44

)

 

$

21

 

 

 

- 310

%

Natural gas

 

 

5

 

 

 

35

 

 

 

- 86

%

NGL

 

 

(45

)

 

 

(3

)

 

 

- 1400

%

Total cash settlements

 

 

(84

)

 

 

53

 

 

 

- 258

%

Valuation changes

 

 

692

 

 

 

104

 

 

 

+565

%

Total

 

$

608

 

 

$

157

 

 

 

+287

%

 

   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 includedthe instruments described 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 relationshipsrelationship 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  
  

 

 

   

 

 

   

 

 

 

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 activitiesProduction Expenses

 

 

2018

 

 

2017

 

 

Change

 

LOE

 

$

995

 

 

$

927

 

 

 

+7

%

Gathering, processing & transportation

 

 

891

 

 

 

647

 

 

 

+38

%

Production taxes

 

 

278

 

 

 

194

 

 

 

+43

%

Property taxes

 

 

61

 

 

 

55

 

 

 

+11

%

Total

 

$

2,225

 

 

$

1,823

 

 

 

+22

%

Per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

LOE

 

$

5.10

 

 

$

4.67

 

 

 

+9

%

Gathering, processing &

   transportation

 

$

4.56

 

 

$

3.26

 

 

 

+40

%

Percent of oil, gas and NGL sales:

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

 

4.9

%

 

 

3.8

%

 

 

+27

%

LOE increased $68 million primarily due to a decrease in commodity prices.

2014 vs. 2013 Marketingcontinued focus on growing our liquids-rich assets within the STACK and midstream operating profit largely increased as a result ofDelaware Basin and higher prices and volumes,maintenance costs at our Jackfish facilities, partially offset by higher operationsour U.S. non-core divestitures.

As further discussed in Note 1 in “Item 8. Financial Statements and maintenance expenses. OfSupplementary Data” of this report, in 2018 the $339 millionpresentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an 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 operatingour upstream revenues and product purchases. The higher marketing revenues and product purchases areproduction expenses by approximately $254 million with no impact to net earnings.

Production taxes increased on an absolute dollar basis 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.

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. upstream revenues, on which the majority of our production taxes are assessed. Property taxesAdditionally, the increase in Oklahoma severance tax rates that became effective during the third quarter of 2018 also contributed to the increase on an absolute dollar basis and as a percentage of oil, gas and NGL salessales.

Property taxes increased during 2015as a result of higher property value assessments, primarily on our Texas properties, partially offset by our U.S. non-core divestitures.

Marketing Operations

 

 

2018

 

 

2017

 

 

Change

 

Marketing revenues

 

$

4,449

 

 

$

3,571

 

 

 

+25

%

Marketing expenses

 

 

(4,363

)

 

 

(3,619

)

 

 

- 21

%

Margin

 

$

86

 

 

$

(48

)

 

 

+279

%

30


Table of Contents

Index to Financial Statements

The overall increase in marketing operating margin was primarily due to ad valorem and other taxes thatimproved commodity prices, which were partially offset by the impact of our downstream marketing commitments.

Exploration Expenses

 

 

2018

 

 

2017

 

 

Change

 

Unproved impairments

 

$

95

 

 

$

217

 

 

 

- 56

%

Geological and geophysical

 

 

21

 

 

 

110

 

 

 

- 81

%

Exploration overhead and other

 

 

61

 

 

 

53

 

 

 

+15

%

Total

 

$

177

 

 

$

380

 

 

 

- 53

%

Unproved impairments in both periods primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not changeintend to pursue further exploration and development. Geological and geophysical costs decreased primarily in direct correlation withthe STACK and Delaware Basin.

Depreciation, Depletion and Amortization

 

 

2018

 

 

2017

 

 

Change

 

Oil and gas per Boe

 

$

7.98

 

 

$

7.15

 

 

 

+12

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas

 

$

1,559

 

 

$

1,419

 

 

 

+10

%

Other property and equipment

 

 

99

 

 

 

110

 

 

 

- 10

%

Total

 

$

1,658

 

 

$

1,529

 

 

 

+8

%

Our oil and gas DD&A increased primarily due to continued development in the STACK, Delaware Basin and NGL sales.Rockies properties. The increases were slightly offset by reduced production volumes at the Jackfish facilities and from our 2018 U.S. non-core asset divestitures.

2014 vs. 2013 Production

General and Administrative Expenses

 

 

2018

 

 

2017

 

 

Change

 

Labor and benefits

 

$

494

 

 

$

582

 

 

 

- 15

%

Non-labor

 

 

236

 

 

 

228

 

 

 

+4

%

Reimbursed G&A

 

 

(80

)

 

 

(73

)

 

 

- 10

%

Total Devon

 

$

650

 

 

$

737

 

 

 

- 12

%

Labor and property taxes increasedbenefits decreased primarily as a result of an increasethe workforce reduction that occurred during 2018 as discussed in our U.S. revenues.

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 16 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 unitNon-labor costs were higher due to an increase in costs related to automation and process improvements.

Financing Costs, net

Financing costs, net increased $277 million as a result 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 unita $312 million loss on early retirement of production, generally moves in the same direction as production volumes.

2015 vs. 2014DD&Adebt. For further discussion of early retirement premiums and reduced interest expense resulting from our oillower debt balances, see Note 15 in

“Item 8. Financial Statements and gas properties decreasedSupplementary Data” of this report.

Other

 

 

2018

 

 

2017

 

 

Change

 

Asset impairments

 

$

156

 

 

$

 

 

N/M

 

Asset dispositions

 

 

(263

)

 

 

(217

)

 

 

- 21

%

Restructuring

 

 

114

 

 

 

 

 

N/M

 

Other

 

 

140

 

 

 

(83

)

 

 

+269

%

Total

 

$

147

 

 

$

(300

)

 

 

+149

%

Additional information regarding the impairments is discussed 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. 2013DD&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

We recognized gains in conjunction with certain of our U.S. asset dispositions in 2017 and 2018. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

During 2015, 2014 and 2013,2018, we recognized restructuring and transaction costs of $78$114 million $46primarily as a result of our workforce reduction. See Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

The remaining change in other expense was driven primarily by changes on foreign currency exchange instruments as further discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.

Income Taxes

 

 

2018

 

 

2017

 

Current expense (benefit)

 

$

(70

)

 

$

112

 

Deferred expense (benefit)

 

 

226

 

 

 

(97

)

Total expense

 

$

156

 

 

$

15

 

Effective income tax rate

 

 

17

%

 

 

2

%

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

Discontinued Operations

Discontinued operations net earnings increased primarily due to the gain on the sale of our aggregate ownership interests in EnLink and the General Partner of $2.6 billion ($2.2 billion after-tax). For discussion on discontinued operations, see Note 19 in “Item 8. Financial Statements and Supplementary Data” of this report” of this report.

31


Table of Contents

Index to Financial Statements

Results of Operations – 2017 vs. 2016

The graph below shows the change in net earnings from 2016 to 2017. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

(1)

Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses.

The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.  

32


Table of Contents

Index to Financial Statements

Upstream Operations

Oil, Gas and NGL Production

 

 

2017

 

 

% of Total

 

 

2016

 

 

Change

 

Oil and bitumen (MBbls/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

29

 

 

 

12

%

 

 

32

 

 

 

- 7

%

STACK

 

 

25

 

 

 

11

%

 

 

18

 

 

 

+39

%

Rockies Oil

 

 

10

 

 

 

4

%

 

 

9

 

 

 

+9

%

Heavy Oil

 

 

18

 

 

 

7

%

 

 

22

 

 

 

- 19

%

Eagle Ford

 

 

34

 

 

 

14

%

 

 

39

 

 

 

- 14

%

Barnett Shale

 

 

1

 

 

 

0

%

 

 

1

 

 

 

- 25

%

Other

 

 

5

 

 

 

2

%

 

 

6

 

 

 

- 13

%

Retained assets

 

 

122

 

 

 

50

%

 

 

127

 

 

 

- 4

%

U.S. divested assets

 

 

12

 

 

 

5

%

 

 

24

 

 

 

- 51

%

Total Oil

 

 

134

 

 

 

55

%

 

 

151

 

 

 

- 11

%

Bitumen

 

 

110

 

 

 

45

%

 

 

109

 

 

 

+1

%

Total Oil and bitumen

 

 

244

 

 

 

100

%

 

 

260

 

 

 

- 6

%

 

 

2017

 

 

% of Total

 

 

2016

 

 

Change

 

Gas (MMcf/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

86

 

 

 

7

%

 

 

86

 

 

 

+1

%

STACK

 

 

294

 

 

 

24

%

 

 

282

 

 

 

+4

%

Rockies Oil

 

 

8

 

 

 

1

%

 

 

16

 

 

 

- 48

%

Heavy Oil

 

 

17

 

 

 

2

%

 

 

20

 

 

 

- 14

%

Eagle Ford

 

 

95

 

 

 

8

%

 

 

101

 

 

 

- 6

%

Barnett Shale

 

 

475

 

 

 

39

%

 

 

530

 

 

 

- 10

%

Other

 

 

1

 

 

 

0

%

 

 

1

 

 

 

- 10

%

Retained assets

 

 

976

 

 

 

81

%

 

 

1,036

 

 

 

- 6

%

U.S. divested assets

 

 

227

 

 

 

19

%

 

 

377

 

 

 

- 40

%

Total

 

 

1,203

 

 

 

100

%

 

 

1,413

 

 

 

- 15

%

 

 

2017

 

 

% of Total

 

 

2016

 

 

Change

 

NGLs (MBbls/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

10

 

 

 

10

%

 

 

11

 

 

 

- 10

%

STACK

 

 

30

 

 

 

30

%

 

 

25

 

 

 

+19

%

Rockies Oil

 

 

1

 

 

 

1

%

 

 

1

 

 

 

+23

%

Eagle Ford

 

 

13

 

 

 

13

%

 

 

16

 

 

 

- 19

%

Barnett Shale

 

 

31

 

 

 

32

%

 

 

34

 

 

 

- 9

%

Other

 

 

1

 

 

 

1

%

 

 

1

 

 

 

- 4

%

Retained assets

 

 

86

 

 

 

87

%

 

 

88

 

 

 

- 3

%

U.S. divested assets

 

 

13

 

 

 

13

%

 

 

28

 

 

 

- 53

%

Total

 

 

99

 

 

 

100

%

 

 

116

 

 

 

- 15

%

 

 

2017

 

 

% of Total

 

 

2016

 

 

Change

 

Combined (MBoe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware Basin

 

 

54

 

 

 

10

%

 

 

57

 

 

 

- 6

%

STACK

 

 

104

 

 

 

19

%

 

 

90

 

 

 

+15

%

Rockies Oil

 

 

12

 

 

 

2

%

 

 

13

 

 

 

- 3

%

Heavy Oil

 

 

131

 

 

 

24

%

 

 

134

 

 

 

- 2

%

Eagle Ford

 

 

62

 

 

 

11

%

 

 

72

 

 

 

- 13

%

Barnett Shale

 

 

111

 

 

 

21

%

 

 

123

 

 

 

- 10

%

Other

 

 

7

 

 

 

1

%

 

 

8

 

 

 

- 6

%

Retained assets

 

 

481

 

 

 

88

%

 

 

497

 

 

 

- 3

%

U.S. divested assets

 

 

62

 

 

 

12

%

 

 

114

 

 

 

- 45

%

Total

 

 

543

 

 

 

100

%

 

 

611

 

 

 

- 11

%

Production declines reduced our upstream revenues by $427 million primarily as a result of our U.S. divested assets. Retained production volumes decreased due to reduced completion activity in the Eagle Ford and $54natural production declines in the Barnett Shale. These decreases were partially offset by expanded drilling and performance in the STACK.

Oil, Gas and NGL Prices

 

 

2017

 

 

Realization

 

 

2016

 

 

Change

 

Oil and bitumen (per Bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI index

 

$

50.99

 

 

 

 

 

 

$

43.36

 

 

 

+18

%

Access Western Blend index

 

$

36.90

 

 

 

 

 

 

$

26.96

 

 

 

+37

%

U.S.

 

$

49.41

 

 

 

97%

 

 

$

38.92

 

 

 

+27

%

Canada

 

$

29.99

 

 

 

59%

 

 

$

20.53

 

 

 

+46

%

Realized price, unhedged

 

$

39.23

 

 

 

77%

 

 

$

29.65

 

 

 

+32

%

Cash settlements

 

$

0.23

 

 

 

 

 

 

$

(0.43

)

 

 

 

 

Realized price, with hedges

 

$

39.46

 

 

 

77%

 

 

$

29.22

 

 

 

+35

%

 

 

2017

 

 

Realization

 

 

2016

 

 

Change

 

Gas (per Mcf)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Henry Hub index

 

$

3.11

 

 

 

 

 

 

$

2.46

 

 

 

+26

%

Realized price, unhedged

 

$

2.48

 

 

 

80%

 

 

$

1.84

 

 

 

+35

%

Cash settlements

 

$

0.08

 

 

 

 

 

 

$

0.07

 

 

 

 

 

Realized price, with hedges

 

$

2.56

 

 

 

82%

 

 

$

1.91

 

 

 

+34

%

 

 

2017

 

 

Realization

 

 

2016

 

 

Change

 

NGLs (per Bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mont Belvieu blended index (1)

 

$

24.77

 

 

 

 

 

 

$

17.20

 

 

 

+44

%

Realized price, unhedged

 

$

15.66

 

 

 

63%

 

 

$

9.81

 

 

 

+60

%

Cash settlements

 

$

(0.10

)

 

 

 

 

 

$

(0.11

)

 

 

 

 

Realized price, with hedges

 

$

15.56

 

 

 

63%

 

 

$

9.70

 

 

 

+60

%

(1)

Based upon composition of average Devon NGL barrel.

 

 

2017

 

 

2016

 

 

Change

 

Combined (per Boe)

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

$

24.88

 

 

$

18.34

 

 

 

+36

%

Canada

 

$

29.39

 

 

$

20.07

 

 

 

+46

%

Realized price, unhedged

 

$

25.96

 

 

$

18.72

 

 

 

+39

%

Cash settlements

 

$

0.27

 

 

$

(0.05

)

 

 

 

 

Realized price, with hedges

 

$

26.23

 

 

$

18.67

 

 

 

+40

%

33


Table of Contents

Index to Financial Statements

Upstream revenues increased $1.4 billion as a result of higher unhedged, realized prices across our entire portfolio. The increase in oil and bitumen sales primarily resulted from higher average WTI crude index prices, which were 18% higher in 2017. Additionally, our oil and bitumen sales benefited from tighter differentials to the WTI index. The increase in gas sales was driven by higher North American regional index prices upon which our gas sales are based and higher NGL prices at the Mont Belvieu, Texas hub.

Commodity Derivatives

 

 

2017

 

 

2016

 

 

Change

 

 

 

Q

 

 

 

 

 

 

 

 

 

Oil

 

$

21

 

 

$

(41

)

 

 

+151

%

Natural gas

 

 

35

 

 

 

35

 

 

 

+0

%

NGL

 

 

(3

)

 

 

(5

)

 

 

+40

%

Total cash settlements

 

 

53

 

 

 

(11

)

 

N/M

 

Valuation changes

 

 

104

 

 

 

(190

)

 

 

+155

%

Total

 

$

157

 

 

$

(201

)

 

 

+178

%

Production Expenses

 

 

2017

 

 

2016

 

 

Change

 

LOE

 

$

927

 

 

$

1,027

 

 

 

- 10

%

Gathering, processing & transportation

 

 

647

 

 

 

555

 

 

 

+17

%

Production taxes

 

 

194

 

 

 

149

 

 

 

+30

%

Property taxes

 

 

55

 

 

 

74

 

 

 

- 26

%

Total

 

$

1,823

 

 

$

1,805

 

 

 

+1

%

Per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

LOE

 

$

4.67

 

 

$

4.59

 

 

 

+2

%

Gathering, processing &

   transportation

 

$

3.26

 

 

$

2.48

 

 

 

+31

%

Percent of oil, gas and NGL sales:

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

 

3.8

%

 

 

3.5

%

 

 

+7

%

LOE decreased $100 million respectively.primarily due to our U.S. property divestitures in 2016. Well optimization and cost reduction initiatives across our portfolio offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers.

Gathering and transportation expense increased $92 million primarily due to a full year of the Access Pipeline transportation tolls, which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $110 million annually.

Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed.

Property taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. asset divestitures.

Exploration Expenses

 

 

2017

 

 

2016

 

 

Change

 

Unproved impairments

 

$

217

 

 

$

77

 

 

 

+182

%

Geological and geophysical

 

 

110

 

 

 

65

 

 

 

+70

%

Exploration overhead and other

 

 

53

 

 

 

73

 

 

 

- 27

%

Total

 

$

380

 

 

$

215

 

 

 

+77

%

Unproved impairments primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs increased primarily in the STACK and Delaware Basin.

Depreciation, Depletion and Amortization

 

 

2017

 

 

2016

 

 

Change

 

Oil and gas per Boe

 

$

7.15

 

 

$

6.47

 

 

 

+11

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas

 

$

1,419

 

 

$

1,446

 

 

 

- 2

%

Other property and equipment

 

 

110

 

 

 

146

 

 

 

- 25

%

Total

 

$

1,529

 

 

$

1,592

 

 

 

- 4

%

Our oil and gas DD&A remained relatively flat as compared to the prior year. Increases in oil and gas DD&A rates due to continued development in the STACK and Delaware Basin were offset by reduced production volumes resulting from the 2016 U.S. asset divestitures. DD&A from our other property and equipment decreased due to the divestiture of the Access Pipeline in the fourth quarter of 2016.

Financing Costs, net

Financing costs, net decreased $400 million primarily as a result of our $2.1 billion early debt retirement in 2016. For further discussion of early retirement premiums and reduced interest expense resulting from our lower debt balances, see Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report.

Other

 

 

2017

 

 

2016

 

 

Change

 

Asset impairments

 

$

 

 

$

437

 

 

 

- 100

%

Asset dispositions

 

 

(217

)

 

 

(1,496

)

 

 

+85

%

Restructuring

 

 

 

 

 

261

 

 

 

- 100

%

Other

 

 

(83

)

 

 

101

 

 

 

- 183

%

Total

 

$

(300

)

 

$

(697

)

 

 

+57

%

In 2016, we recognized proved asset impairments on a portion of our U.S. assets. See Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report for additional information.

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Index to Financial Statements

We recognized gains in conjunction with certain of our asset dispositions in both 2016 and 2017 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

During 2016, we recognized restructuring and transaction costs of $261 million primarily as a result of our workforce reduction. 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.

GainsThe remaining change in other expense was driven primarily by changes on Asset Sales

In conjunction with the divestiture of certain Canadian properties, we recognized gains of $1.1 billionforeign currency exchange instruments, as further discussed in 2014. For further discussion, see Note 27 in “Item 8. Financial Statements and Supplementary Data” of this report.

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  
  

 

 

    

 

 

    

 

 

 

Income Taxes

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

 

 

2017

 

 

2016

 

Current expense

 

$

112

 

 

$

98

 

Deferred expense (benefit)

 

 

(97

)

 

 

43

 

Total expense

 

$

15

 

 

$

141

 

Effective income tax rate

 

 

2

%

 

 

(33

%)

For discussion on income taxes, see Note 138 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
  

 

 

  

 

 

  

 

 

 

Discontinued Operations

For discussion on income taxes,discontinued operations, see Note 719 in “Item 8. Financial Statements and Supplementary Data” of this report.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major source and use categories of ourchanges in cash and cash equivalents.equivalents for the time periods presented below.

 

  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  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

 

Year ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Operating cash flow from continuing operations

 

$

2,228

 

 

$

2,209

 

 

$

834

 

Divestitures of property and equipment

 

 

1,013

 

 

 

426

 

 

 

3,020

 

Capital expenditures

 

 

(2,451

)

 

 

(1,968

)

 

 

(1,384

)

Acquisitions of property and equipment

 

 

(55

)

 

 

(46

)

 

 

(849

)

Debt activity, net

 

 

(1,226

)

 

 

 

 

 

(3,383

)

Repurchases of common stock

 

 

(2,956

)

 

 

 

 

 

 

Common stock dividends

 

 

(149

)

 

 

(127

)

 

 

(221

)

Issuance of common stock

 

 

 

 

 

 

 

 

1,469

 

Effect of exchange rate and other

 

 

151

 

 

 

(53

)

 

 

(96

)

Net change in cash, cash equivalents and restricted cash

   from discontinued operations

 

 

3,207

 

 

 

284

 

 

 

259

 

Net change in cash, cash equivalents and restricted cash

 

$

(238

)

 

$

725

 

 

$

(351

)

Cash, cash equivalents and restricted cash at end of period

 

$

2,446

 

 

$

2,684

 

 

$

1,959

 

                      

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

Operating Cash Flow – Continuing Operations

Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2015.2018. Our operating cash flow decreased 10% during 2015 primarily duewas relatively flat compared 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 with2017. In 2018, 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 2015expenditure program and 2014, respectively. In 2015 and 2014, leveraging our liquidity and other capital resources, we also useddividends. We utilized available cash balances short-term debt, proceeds from EnLink transactions and divestiture proceeds to fundsupplement our acquisitions, dividends and capital requirements.

Saleoperating cash flows. Operating cash flow for 2018 included a realized foreign exchange loss of Subsidiary Units

In early 2015, we conducted an underwritten secondary public offering of 26.2$241 million common units representing limited partner interestsrelating to foreign currency denominated intercompany loan activity as described in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 177 in “Item 8. Financial Statements and Supplementary Data” of this report.

There was an offset in the effect of exchange rate and other line in the above table, resulting in no impact to the net change in cash, cash equivalents and restricted cash.

Our operating cash flow increased $1.4 billion, or 165%, from 2016 to 2017. In 2017, our operating cash flow fully funded our capital expenditures program as well as our dividends. In 2016, our operating cash flow did not fully fund our capital requirements and dividends; as a result, we utilized available cash balances and divestiture proceeds to supplement our operating cash flows.

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Table of Contents

Index to Financial Statements

Divestitures of Property and EquipmentInvestments

During 2014, we completed2018, as part of our Canadian assetannounced divestiture program, we sold non-core U.S. upstream assets for approximately $1.0 billion. For further discussion, see Note 2 in “Item 8. Financial Statements and received proceedsSupplementary Data” of approximately $2.9 billion. Additionally, we completed the divestment of certainthis report.

During 2017, as part of our announced divestiture program, we sold non-core U.S. upstream assets for approximately $420 million. For further discussion, see Note 2 in “Item 8. Financial Statements and received proceedsSupplementary Data” of approximately $2.2 billion.this report.

During 2013,2016, we solddivested certain non-core upstream assets in the U.S. and our Thunder Creek operations50% interest in Wyomingthe Access Pipeline in Canada for approximately $148 million$3.0 billion, net of purchase price adjustments. Proceeds from these divestitures were used primarily for debt repayment and to support capital investment in our Bear Paw Basin assetscore resource plays. For further discussion, see Note 2 in Havre, Montana for approximately $73 million. “Item 8. Financial Statements and Supplementary Data” of this report.

We also sold other minor oildid not have significant current cash income taxes resulting from the divestitures in 2018, 2017 and gas assets.2016.

Capital Expenditures

The following table summarizes our capital expenditures and property acquisitions.

 

   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  
  

 

 

   

 

 

   

 

 

 

 

 

Year ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Oil and gas

 

$

2,395

 

 

$

1,879

 

 

$

1,341

 

Corporate and other

 

 

56

 

 

 

89

 

 

 

43

 

Total capital expenditures

 

$

2,451

 

 

$

1,968

 

 

$

1,384

 

Acquisitions

 

$

55

 

 

$

46

 

 

$

849

 

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations our midstream operations,and 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 responseOur capital program is designed to loweroperate within or near operating cash flow and may fluctuate with changes to 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.and other factors impacting cash flow. This change is evidenced by a 48% decreaseour operating cash flow funding approximately 91% of capital expenditures in exploration2018 and developmentfully funding capital expenditures in 2017.

Acquisition costs fromin 2016 primarily consisted of Devon’s bolt-on acquisition of assets in the fourth quarterSTACK play for $1.5 billion. Approximately $849 million was paid in cash at closing with the remainder of 2014the purchase price funded with equity consideration. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report for more information.

Debt Activity, Net

During 2018, our debt decreased $922 million due to the fourth quartercompleted tender offers of 2015,certain long-term debt as well as the maturity of certain senior notes. In conjunction with the tender offers, we recognized a 24% decrease$312 million loss on the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see Note 15 in total“Item 8. Financial Statements and Supplementary Data” of this report.

During 2016, our debt decreased $3.1 billion due to completed tender offers to purchase and redeem $2.1 billion of debt securities prior to their maturity and a $1 billion reduction in short-term borrowings. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt, including $265 million of cash retirement costs and fees. For additional information, see Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report.

Repurchases of Common Stock and Shareholder Distributions

In June 2018, in conjunction with the announcement of the divestiture of our investment in EnLink and the General Partner, our Board of Directors authorized a $4.0 billion share repurchase program of our common stock. The share repurchase program expires December 31, 2019. As discussed further in Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report, we repurchased 78.1 million shares of common stock for $3.0 billion, or $38.11 per share, under the ASR agreement and through open-market share repurchases through December 31, 2018.

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Table of Contents

Index to Financial Statements

Devon paid common stock dividends of $149 million, $127 million and $221 million during 2018, 2017 and 2016, respectively. During the second quarter of 2018, we increased our quarterly dividend 33% to $0.08 per share as part of our initiative to return cash to shareholders. Our prior quarterly dividend was $0.06 per share subsequent to a reduction from $0.24 per share in the second quarter of 2016 due to the depressed commodity price environment. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

Issuance of Common Stock

In February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.

Cash Flows from Discontinued Operations

All cash flows in the following table relate to activities of EnLink and the General Partner.

 

 

Year ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Cash flows from discontinued operations:

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

476

 

 

$

700

 

 

$

666

 

Capital expenditures and other

 

 

(556

)

 

 

(801

)

 

 

(1,381

)

Divestitures of investments

 

 

3,104

 

 

 

190

 

 

 

 

Investing activities

 

 

2,548

 

 

 

(611

)

 

 

(1,381

)

Debt activity, net

 

 

347

 

 

 

2

 

 

 

228

 

Issuance of subsidiary units

 

 

1

 

 

 

501

 

 

 

892

 

Distributions to noncontrolling interests

 

 

(217

)

 

 

(354

)

 

 

(304

)

Other

 

 

52

 

 

 

46

 

 

 

158

 

Financing activities

 

 

183

 

 

 

195

 

 

 

974

 

Net change in cash, cash equivalents and

   restricted cash of discontinued operations

 

$

3,207

 

 

$

284

 

 

$

259

 

Operating cash flow in 2018 decreased $224 million and $190 million from 2017 and 2016, respectively, as a result of the divestiture of our aggregate ownership interests in EnLink and the General Partner in July 2018.

Cash flows from investing activities for 2018 includes $3.125 billion received from the divestiture of our aggregate ownership interests in EnLink and the General Partner, partially offset by 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.

other items. Capital expenditures for Devon’sEnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelinespipelines. During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. During 2016, EnLink acquired Anadarko Basin gathering and are largely impacted by Devon’s oil and gas drilling activities. Our 2014 and 2013processing midstream capital expenditures largely related toassets for $1.5 billion. Approximately $792 million was paid in cash at closing with 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 consistedremainder of the Powder River Basin asset acquisitionpurchase price funded with equity consideration and debt.

Cash flows from financing activities includes common and preferred units EnLink issued and sold during 2017 and 2016 generating net proceeds of approximately $501 million and $892 million, respectively. Distributions to noncontrolling interests in the fourth quarter. The majority oftable above exclude 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.

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,distributions EnLink and the General Partner distributed $254 and $135 millionpaid to non-Devon unitholders during 2015 and 2014, respectively.

EnLink and General PartnerDevon, which have been eliminated in consolidation. Distributions

Devon received $268 million and $158 million in distributions from EnLink Enlink and the General Partner paid to Devon were $134 million, $265 million and $265 million during 20152018, 2017 and 2014,2016, respectively.

EnLink DropdownsLiquidity

In the second quarterThe business of 2015, Devon received $167 million in cashexploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from EnLink in exchange for VEX. For further discussion, see Note 2 in “Item 8.existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.

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Table of Contents

Index to 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.

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 funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds and cash on hand.proceeds. 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, If needed, we can also issue debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well asSEC. In February 2019, we also announced plans to separate our Canadian and Barnett Shale assets and operations. We expect to complete these asset separations in 2019. We plan to use the sale of a portion of ourproceeds from these transactions for debt repayments and common units representing interests in our investment in EnLink and the General Partner.share repurchases. We estimate the combination of theseour sources of capital will continue to be adequate to fund futureour planned capital expenditures, debt repayments and other contractual commitmentsrequirements as discussed in this section.

Operating Cash Flow

Key inputs into determining our planned capital investment is the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of 2018, we held approximately $2.4 billion of cash. Our operating cash flow isforecasts are sensitive to many variables theand include a measure of uncertainty as these variables differ from our expectations.

Commodity Prices – The most uncertain and volatile of whichvariables for our operating cash flow 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 lowerFor illustration, our operating cash flow slightly increased in 2018 largely due to 16% growth from our retained U.S. liquids portfolio, as well as 32% higher realized pricing related to these assets. These increases were mostly offset by a significant decrease in our realized price for our bitumen production in 2018. Western Canadian Select basis differentials widened significantly above historical norms due to robust production outpacing local demand, pipeline capacity and rail capacity out of the region. The market fundamentals led our fourth quarter unhedged realized price for bitumen to be near $0 per Bbl. In the first two months of 2019, government-mandated production curtailments and current market fundamentals have led to a significant improvement in the Western Canadian Select basis differential.

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to continue throughout 2016, and currently,protect a portion of our production is largely unhedged. Ifagainst downside price risk. We target hedging approximately 50% of our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity prices remain consistentprice volatility. We supplement the systematic hedging program with 2015discretionary hedges that take advantage of favorable market conditions. We currently have approximately 50% of our anticipated 2019 oil and gas volumes hedged, and we are unable to obtain favorable hedge contractsadding hedges for 2020 as well. Further insulating our 2016 production, our 2016 operating cash flow, could materially decline from what it waswe are proactively locking in 2015.

hedges on the Western Canada Select basis differential to WTI and currently have approximately 50% of our 2019 Canadian heavy oil production hedged. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 20152018 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities at $46/Bbl WTI and $3.00/Mcf Henry Hub. Should WTI drop closer to $40/Bbl for an extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI/Bbl rises above $46, our free cash flow will accelerate, providing additional capital allocation opportunities.

Operating Expenses – 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 PropertyFor 2019, we expect to aggressively optimize our cost structure in conjunction with our planned Canadian and Equipment – InBarnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with 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.retained business and reduce outstanding debt. We anticipate these divestituresthe planned $780 million reduction of annualized costs will generate approximately $2 billionoccur over three years, with roughly 70% of the savings delivered by the end of 2019. Approximately 40% of the reduced costs relate to $3 billion of proceedsour capital programs and the remainder relates to further strengthen our financial position in 2016.operating expenses, including G&A, interest expense and production expenses.

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%.

Credit Losses– Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed toThis includes the credit risk of therelated to customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related toproduction, 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 ofoperate and 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 history38


Table of investing more than 100%Contents

Index to Financial Statements

Divestitures of our operating cash flow into capital development activities to grow our companyProperty 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. Equipment

In the current environment, assuming current pricing expectations,first quarter of 2019, we sold non-core assets for approximately $300 million. We also anticipate separating our 2016 explorationCanadian and development capital budget is expected to be approximately $900 million to $1.1 billion, or roughly 75% less thanBarnett Shale businesses from 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, resultingCompany in a 6% production decline in our core assets.2019.

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 theOur 2018 Senior Credit Facility, isunder which we have $2.9 billion of available borrowing capacity at December 31, 2018, matures on October 24, 2017. The5, 2023, with the option to extend the maturity date for $164 million of theby two additional one-year periods subject to lender consent. The 2018 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 of short-term credit under our 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, 2015,2018, there were no borrowings under the Senior Credit Facility.our commercial paper program. See Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

The 2018 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, 2015,2018, we were in compliance with this covenant. Ourcovenant with a 21.0% debt-to-capitalization ratio at December 31, 2015, as calculated pursuant to the terms of the agreement, was 23.7%.ratio.

Our access to funds from the 2018 Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the credit

agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.

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.

In January 2019, we repaid the $162 million of 6.30% senior notes at maturity with cash on hand.

Debt Ratings

Devon and EnLink are rated byWe receive debt ratings from the major debt ratings agencies in the U.S. However, the General Partner does not receive debt ratings. In determining thoseour debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales near-term and long-termproduction growth opportunitiesopportunities. Our credit rating from Standard and capital allocation challenges.Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Ba1 with a positive outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should our debt ratingsrating 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 ExpendituresShare Repurchase Program

In January 2016, Devon acquired Anadarko Basin STACK assets for approximately $1.5February 2019, our Board of Directors increased our share repurchase program by an additional $1 billion. The $5 billion in cashshare repurchase program expires December 31, 2019. Through February 15, 2019, we have executed $3.4 billion of the authorized program.

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Capital Expenditures

Our 2019 exploration and equity, subject to certain adjustments. Including this acquisition but excluding EnLink, our 2016 capital expenditures aredevelopment budget is expected to range from $1.2be approximately $2.0 billion to $1.4$2.25 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 connectionassociated with our acquisition of the STACK playCanadian 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.

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 OakBarnett Shale upstream 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, 2015.2018.

 

   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  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

Payments Due by Period

 

 

 

Total

 

 

Less Than 1 Year

 

 

1-3 Years

 

 

3-5 Years

 

 

More Than 5 Years

 

Devon obligations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt (1)

 

$

6,011

 

 

$

162

 

 

$

500

 

 

$

1,000

 

 

$

4,349

 

Interest expense (2)

 

 

4,951

 

 

 

317

 

 

 

623

 

 

 

535

 

 

 

3,476

 

Purchase obligations (3)

 

 

1,248

 

 

 

541

 

 

 

707

 

 

 

 

 

 

 

Operational agreements (4)

 

 

5,626

 

 

 

587

 

 

 

892

 

 

 

773

 

 

 

3,374

 

Asset retirement obligations (5)

 

 

1,057

 

 

 

27

 

 

 

76

 

 

 

79

 

 

 

875

 

Drilling and facility obligations (6)

 

 

445

 

 

 

274

 

 

 

133

 

 

 

22

 

 

 

16

 

Lease obligations (7)

 

 

500

 

 

 

64

 

 

 

74

 

 

 

51

 

 

 

311

 

Other (8)

 

 

295

 

 

 

32

 

 

 

78

 

 

 

27

 

 

 

158

 

Total obligations

 

$

20,133

 

 

$

2,004

 

 

$

3,083

 

 

$

2,487

 

 

$

12,559

 

 

(1)

Debt amounts represent scheduled maturities of Devon’s debt obligations at December 31, 2015,2018, excluding $28 million of net discounts and debt issue costs 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(including current portion of our floating-rate notes. These amounts include $1.8 billion of interest expense related to EnLink.long term debt).

(4)

(3)

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

(5)

(4)

Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets. Operational agreements include approximately $1.7Approximately $1.9 billion relates to the transportation agreement we entered in 2016 in which we dedicated our thermal-oil acreage to the Access Pipeline for an initial term of minimum volume commitments between Devon and EnLink. The initial terms25 years following the divestment of the gas volume contracts with EnLink are summarizedour 50% interest in the following table. In addition, DevonAccess Pipeline. For additional information, see Note 2 in “Item 8. Financial Statements and EnLink have a 30 MBbls/d minimum transportation volume commitment for the VEX pipeline. All contracts with EnLink expire in 2019.Supplementary Data” of this report.

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)

(5)

Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 20152018 balance sheet.

(7)

(6)

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)

(7)

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

(9)

(8)

These amounts include $133 million related

Other obligations primarily relate to uncertainvarious tax positions.obligations.

(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 1820 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

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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

Oil and Gas Assets Accounting, Classification, Reserves & Valuation

Successful Efforts Method of Accounting and Proved Classification

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management’s assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, management considers current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the Consolidated Comprehensive Statement of Earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2018, Devon had approximately $200 million of well costs suspended for more than one year, which largely pertain to its Pike Heavy Oil project. Stratigraphic testing has demonstrated reserves can be produced economically at Pike. However, this capital intensive, long-duration project remains unsanctioned by Devon and its 50% partner, which is the primary reason reserves have not been designated as proven at Pike. With no lease expiration at Pike in the near future, management continues to keep the Pike exploratory costs capitalized.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2018, Devon had $1.2 billion of undeveloped leasehold and capitalized interest, which includes approximately $750 million related to Pike. Consistent with the evaluation above on suspended well costs, the costs for Pike continue to remain capitalized. Of the remaining undeveloped leasehold costs at December 31, 2018, approximately $10 million is scheduled to expire in 2019. The leasehold expiring in 2019 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Reserves

Our estimates of proved and proved developed reserves are a major component of the depletion and full cost ceilingDD&A 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%2018, 89% of our reserves were subjected to such audits.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than 3%5% 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 quantitiesValuation of Long-Lived Assets

Long-lived assets used in operations, including 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 Canadianunproved oil and gas properties, that will approximate theare depreciated and assessed for impairment recognizedannually or whenever changes in the fourth quarter of 2015. While difficult to measure, we estimate that the first quarter 2016 impairments will approximate $3 billionfacts and circumstances indicate a possible significant deterioration 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

base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the livesflows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual

41


Table of the contracts are discounted primarily using U.S. Treasury bill rates. These pricing and discounting variables are sensitiveContents

Index to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.Financial Statements

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 dollarsassets 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 maturityjudgmental assessment of the contractslowest level (“common operating field”) for which there are discounted using Treasury rates. These discounting variablesidentifiable cash flows that are sensitive to the periodlargely independent of the contractcash flows of other groups of assets. The determination of common operating fields is largely based on geological structural features or stratigraphic condition, which requires judgment. Management also considers the nature of production, common infrastructure, common sales points, common processing plants, common regulation and market volatility.management oversight to make common operating field determinations. These determinations impact the amount of DD&A recognized each period and could impact the determination and measurement of a potential asset impairment.

We periodically validate our valuation techniques by comparing our internally generatedManagement evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value estimates with those obtained from contract counterparties.

Counterparty credit risk has not hadvalue. Because there usually is a significant effect on our cash flow calculations and derivative valuations. This is primarily the resultlack 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 actualquoted 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 thelong-lived 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.

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 beimpaired assets is typically determined based on ourthe present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Besides the estimates of reserves and future oil, natural gas and NGL prices. Our estimates ofproduction volumes, future commodity prices are based onthe largest driver in the variability of undiscounted pre-tax cash flows. For our own analysis of pricing trends. These estimates are based on current data obtained with regard to regionalimpairment determinations, we generally utilize the forward strip prices for the first five years 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.

apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future prices to apply to the estimated reserve quantities acquired,capital 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 discountedby using a rate determined appropriate at the time of the business combination based upon ourmethod that correlates cost of capital.

We also apply these same general principlesmovements 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 considerprice movements similar 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 allocatedrecent history. Changes to the fair value of midstream facilities and equipment, generally consisting of processing facilities and pipeline systems. Estimating the fair valueany of these assets requires certain assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Due to be made regarding future quantities of commodities estimated to be processedsuppressed commodity prices in 2016, we recognized significant asset impairments. With generally higher pricing in 2017 and transported through these facilities and pipelines, as well as estimates of future expected prices and operating and capital costs.2018, we did not recognize material asset impairments.      

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 asAs of OctoberDecember 31, for our test, we typically complete2018, the test in late December or early January as the October 31 market data used in our test becomes available. U.S. reporting unit had goodwill totaling $841 million.

We first assess theperform a qualitative factorsassessment 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.amount. If we determineour qualitative assessment determines 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 less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. As part of our qualitative assessment, we considered the general macroeconomic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers, and stock performance. If the qualitative assessment determines that a quantitative goodwill impairment test is required, then the fair value of each reporting unit is compared to itsthe carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair 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

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.

ForBased on our qualitative assessment as of October 31, 20152018, it is not more likely than not that the fair value of the U.S. reporting unit is less than its carrying amount. Since our annual test for goodwill impairment test, step oneon October 31, 2018 was performed, our stock price decreased 30% from October 31 to December 31. As such, we performed an updated assessment as of our impairment analysis showedDecember 31, 2018 to determine if it is more likely than not that the fair value of our reporting unit is less than its carrying amount. Based on our qualitative assessment as of December 31, 2018, it is not more likely than not that the fair value of the U.S. reporting unit exceededis less than its carrying value.

Sustained weaknessOur impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the overall energy sector beginningperiod 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 determinedwhich we would determine 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 exceeds fair value. We would expect that a prolonged or sustained period of EnLink’s Crude and Condensatelower commodity prices would adversely affect the estimate of future operating results, which could result in future goodwill impairments for our U.S. reporting unit approximated its fair value.due to the potential impact on the cash flows of our operations.

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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,2017, we recorded a 100% valuation allowance against our U.S. deferred tax assets. Upon closing the EnLink divestiture in the third quarter of 2018, Devon reassessed its position and determined that its U.S. segment is no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, as of December 31, 2015.including certain tax credits and state net operating losses. Devon also has recorded a partial valuation allowance against certain Canadian deferred tax assets that were generated by a 2017 Canadian legal entity restructuring.  

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.laws. 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 and 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.

 

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.


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Index to Financial Statements

Non-GAAP Measures

Core Earnings

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 20152018 Results” in this Item 7.7 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 (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash or non-recurringand other items that are typically excluded by securities analysts in their published estimates of our financial results. Additionally, we’ve presented our discontinued operations associated with the sale of our aggregate ownership interests in EnLink and the General Partner separately to show our results on a go-forward basis. For more information on the results of operations for EnLink and the General Partner, see Note 19 in “Item 8. Financial Statements and Supplementary Data” in this report. 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 20152018 relate to asset dispositions, the gain on the sale of Devon’s aggregate ownership interests in EnLink and the General Partner, noncash asset impairments including noncash unproved asset impairments, deferred tax asset valuation allowance, costs associated with early retirement of debt, fair value changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with the 2018 workforce reduction and settlements relating to minimum volume contract commitments.

Amounts excluded for 2017 relate to asset dispositions, noncash asset impairments including noncash unproved asset impairments, U.S. tax reform changes, deferred tax asset valuation allowance, derivatives and financial instrument fair value changes, legal entity restructuring and costs associated with early retirement of debt.

Amounts excluded for 2016 relate to asset dispositions, noncash asset impairments (including an impairment of EnLink goodwill), including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig stacking costs, deferred tax asset valuation allowance, restructuring and transaction costs and repatriation of funds toassociated with the U.S. Amounts excluded for 2014 relate to2016 workforce reduction, 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 onassociated with 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

debt.

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.analysts, which typically make similar adjustments in their estimates of our financial results. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

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Index to Financial Statements

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

 

Before tax

 

 

After tax

 

 

After Noncontrolling Interests

 

 

Per Diluted Share

 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings attributable to Devon (GAAP)

$

920

 

 

$

764

 

 

$

764

 

 

$

1.52

 

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset dispositions

 

(263

)

 

 

(202

)

 

 

(202

)

 

 

(0.41

)

Asset and exploration impairments

 

257

 

 

 

198

 

 

 

198

 

 

 

0.40

 

Deferred tax asset valuation allowance

 

 

 

 

(42

)

 

 

(42

)

 

 

(0.08

)

Early retirement of debt

 

312

 

 

 

240

 

 

 

240

 

 

 

0.48

 

Fair value changes in financial

   instruments and foreign currency

 

(614

)

 

 

(458

)

 

 

(458

)

 

 

(0.92

)

Restructuring and transaction costs

 

114

 

 

 

87

 

 

 

87

 

 

 

0.18

 

Core earnings attributable to Devon (Non-GAAP)

$

726

 

 

$

587

 

 

$

587

 

 

$

1.17

 

Discontinued Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings attributable to Devon (GAAP)

$

2,863

 

 

$

2,460

 

 

$

2,300

 

 

$

4.58

 

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain on sale of EnLink and the General Partner

 

(2,607

)

 

 

(2,222

)

 

 

(2,222

)

 

 

(4.43

)

Fair value changes, and minimum volume commitment settlement

 

(34

)

 

 

(28

)

 

 

(10

)

 

 

(0.02

)

Core earnings attributable to Devon (Non-GAAP)

$

222

 

 

$

210

 

 

$

68

 

 

$

0.13

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings attributable to Devon (GAAP)

$

3,783

 

 

$

3,224

 

 

$

3,064

 

 

$

6.10

 

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

 

(194

)

 

 

(177

)

 

 

(177

)

 

 

(0.35

)

Discontinued Operations

 

(2,641

)

 

 

(2,250

)

 

 

(2,232

)

 

 

(4.45

)

Core earnings attributable to Devon (Non-GAAP)

$

948

 

 

$

797

 

 

$

655

 

 

$

1.30

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings attributable to Devon (GAAP)

$

773

 

 

$

758

 

 

$

758

 

 

$

1.43

 

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset dispositions

 

(217

)

 

 

(138

)

 

 

(138

)

 

 

(0.26

)

Asset and exploration impairments

 

217

 

 

 

138

 

 

 

138

 

 

 

0.25

 

Deferred tax asset valuation allowance

 

 

 

 

(76

)

 

 

(76

)

 

 

(0.14

)

Fair value changes in financial

   instruments and foreign currency

 

(214

)

 

 

(199

)

 

 

(199

)

 

 

(0.37

)

Legal entity restructuring

 

 

 

 

(86

)

 

 

(86

)

 

 

(0.16

)

Core earnings attributable to Devon (Non-GAAP)

$

559

 

 

$

397

 

 

$

397

 

 

$

0.75

 

Discontinued Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings attributable to Devon (GAAP)

$

123

 

 

$

320

 

 

$

140

 

 

$

0.27

 

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. tax reform

 

 

 

 

(211

)

 

 

(112

)

 

 

(0.21

)

Asset dispositions, impairments, fair value changes and early retirement of debt

 

4

 

 

 

4

 

 

 

2

 

 

 

0.00

 

Core earnings attributable to Devon (Non-GAAP)

$

127

 

 

$

113

 

 

$

30

 

 

$

0.06

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings attributable to Devon (GAAP)

$

896

 

 

$

1,078

 

 

$

898

 

 

$

1.70

 

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

 

(214

)

 

 

(361

)

 

 

(361

)

 

 

(0.68

)

Discontinued Operations

 

4

 

 

 

(207

)

 

 

(110

)

 

 

(0.21

)

Core earnings attributable to Devon (Non-GAAP)

$

686

 

 

$

510

 

 

$

427

 

 

$

0.81

 

45


Table of Contents

 

   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  
  

 

 

   

 

 

   

 

 

 

Index to Financial Statements

 

Before tax

 

 

After tax

 

 

After Noncontrolling Interests

 

 

Per Diluted Share

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss attributable to Devon (GAAP)

$

(433

)

 

$

(574

)

 

$

(575

)

 

$

(1.14

)

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset dispositions

 

(1,496

)

 

 

(1,001

)

 

 

(1,001

)

 

 

(1.97

)

Asset and exploration impairments

 

537

 

 

 

340

 

 

 

340

 

 

 

0.69

 

Rig stacking costs

 

10

 

 

 

6

 

 

 

6

 

 

 

0.01

 

Deferred tax asset valuation allowance

 

 

 

 

385

 

 

 

385

 

 

 

0.76

 

Restructuring and transaction costs

 

261

 

 

 

168

 

 

 

168

 

 

 

0.33

 

Fair value changes in financial

   instruments and foreign currency

 

248

 

 

 

135

 

 

 

135

 

 

 

0.26

 

Early retirement of debt

 

269

 

 

 

171

 

 

 

171

 

 

 

0.33

 

Core loss attributable to Devon (Non-GAAP)

$

(604

)

 

$

(370

)

 

$

(371

)

 

$

(0.73

)

Discontinued Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss attributable to Devon (GAAP)

$

(884

)

 

$

(884

)

 

$

(481

)

 

$

(0.95

)

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset impairments

 

893

 

 

 

890

 

 

 

467

 

 

 

0.91

 

Asset dispositions, restructuring and transaction costs and fair value changes

 

41

 

 

 

35

 

 

 

18

 

 

 

0.04

 

Core earnings attributable to Devon (Non-GAAP)

$

50

 

 

$

41

 

 

$

4

 

 

$

0.00

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss attributable to Devon (GAAP)

$

(1,317

)

 

$

(1,458

)

 

$

(1,056

)

 

$

(2.09

)

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

 

(171

)

 

 

204

 

 

 

204

 

 

 

0.41

 

Discontinued Operations

 

934

 

 

 

925

 

 

 

485

 

 

 

0.95

 

Core loss attributable to Devon (Non-GAAP)

$

(554

)

 

$

(329

)

 

$

(367

)

 

$

(0.73

)


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EBITDAX and Field-Level Cash Margin

To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; depreciation, depletion and amortization; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL revenues less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.

We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.

We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.

Below are reconciliations of net earnings from continuing operations to EBITDAX and a further reconciliation to Field-Level Cash Margin. Because we have sold upstream assets in the periods presented and have plans to dispose our Canadian and Barnett Shale businesses, which represent approximately 40% of our 2018 production volumes, we have also excluded the EBITDAX and Field-Level Cash Margin for our divested assets, Canada and the Barnett Shale to compute Adjusted EBITDAX and Adjusted Field-Level Cash Margin. We use Adjusted EBITDAX and Adjusted Field-Level Cash Margin to assess the performance of our portfolio of upstream assets on a “same-store” basis across periods.

47


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Index to Financial Statements

 

Year Ended December 31,

 

 

2018

 

 

2017

 

 

2016

 

Net earnings from continuing operations (GAAP)

$

764

 

 

$

758

 

 

$

(574

)

Financing costs, net

 

594

 

 

 

317

 

 

 

717

 

Income tax expense

 

156

 

 

 

15

 

 

 

141

 

Exploration expenses

 

177

 

 

 

380

 

 

 

215

 

Depreciation, depletion and amortization

 

1,658

 

 

 

1,529

 

 

 

1,592

 

Asset impairments

 

156

 

 

 

 

 

 

437

 

Asset disposition gains

 

(263

)

 

 

(217

)

 

 

(1,496

)

Share-based compensation

 

122

 

 

 

141

 

 

 

124

 

Derivative and financial instrument non-cash valuation changes

 

(614

)

 

 

(214

)

 

 

248

 

Restructuring and transaction costs

 

114

 

 

 

 

 

 

261

 

Accretion on discounted liabilities and other

 

61

 

 

 

29

 

 

 

44

 

EBITDAX (non-GAAP)

 

2,925

 

 

 

2,738

 

 

 

1,709

 

Marketing revenues and expenses, net

 

(86

)

 

 

48

 

 

 

49

 

Commodity derivative cash settlements

 

84

 

 

 

(53

)

 

 

11

 

General and administration expenses, cash-based

 

529

 

 

 

596

 

 

 

609

 

Field-level cash margin (non-GAAP)

$

3,452

 

 

$

3,329

 

 

$

2,378

 

 

 

 

 

 

 

 

 

 

 

 

 

EBITDAX (non-GAAP)

$

2,925

 

 

$

2,738

 

 

$

1,709

 

EBITDAX, Divested assets

 

(184

)

 

 

(267

)

 

 

(346

)

EBITDAX, Canada

 

(593

)

 

 

(748

)

 

 

(491

)

EBITDAX, Barnett Shale

 

(248

)

 

 

(262

)

 

 

(148

)

Adjusted EBITDAX (non-GAAP)

$

1,900

 

 

$

1,461

 

 

$

724

 

 

 

 

 

 

 

 

 

 

 

 

 

Field-level cash margin (non-GAAP)

$

3,452

 

 

$

3,329

 

 

$

2,378

 

Field-level cash margin, divested assets

 

(184

)

 

 

(267

)

 

 

(346

)

Field-level cash margin, Canada

 

(210

)

 

 

(812

)

 

 

(490

)

Field-level cash margin, Barnett Shale

 

(248

)

 

 

(262

)

 

 

(148

)

Adjusted field-level cash margin (non-GAAP)

$

2,810

 

 

$

1,988

 

 

$

1,394

 


48


Table of Contents

Index to Financial Statements

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, bitumen, 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, bitumen, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodicallysystematically 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, 20152018 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, 2015,2018, a 10% change in the forward curves associated with our commodity derivative instruments would not have materially impactedchanged our balance sheet at December 31, 2015.net asset positions by approximately $270 million.

Interest Rate Risk

At December 31, 2015,2018, we had total debt of $13.1$5.9 billion. Of this amount, $11.7 billion bearsAll of our debt is based on fixed interest rates averaging 5.3%, and $1.4 billion is comprised of floating rate debt with interest rates averaging 1.1%5.4%. Our commercial paper borrowings typically have maturities between 1 and 90 days.

As of December 31, 2015,2018, we had one open interest rate swap positionsposition that areis presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair valuesvalue of our interest rate swaps areswap is largely determined by estimates of the forward curves of the 3three month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet or liquidity at December 31, 2015.2018.

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, 20152018 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of our subsidiaries hold Canadian-dollar cash and engageDevon engages in intercompany loansloan activity between subsidiaries with Canadian subsidiaries that are based in Canadian dollars.different functional currencies. The value of the Canadian-dollar cash andthese foreign currency denominated intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollarsubsidiaries’ 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, 2015,2018, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.

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Index to Financial Statements

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

51

Consolidated Financial Statements

Consolidated Comprehensive Statements of Earnings

58

53

Consolidated Statements of Cash Flows

59

54

Consolidated Balance Sheets

60

55

Consolidated Statements of Stockholders’ Equity

61

56

Notes to Consolidated Financial Statements

57

Note 1 – Summary of Significant Accounting Policies

62

57

Note 2 – Acquisitions and Divestitures

67

Note 3 – Derivative Financial Instruments

69

Note 4 – Share-Based Compensation

71

Note 5 – Asset Impairments

74

Note 6 – Restructuring and Transaction Costs

74

Note 7 – Other Expenses

75

Note 8 – Income Taxes

76

Note 9 – Net Earnings (Loss) Per Share From Continuing Operations

81

Note 10 – Other Comprehensive Earnings

81

Note 11 – Supplemental Information to Statements of Cash Flows

82

Note 12 – Accounts Receivable

82

Note 13 – Property, Plant and Equipment

83

Note 14 – Other Current Liabilities

84

Note 15 – Debt and Related Expenses

85

Note 16 – Asset Retirement Obligations

87

Note 17 – Retirement Plans

87

Note 18 – Stockholders’ Equity

91

Note 19 – Discontinued Operations and Assets Held For Sale

93

Note 20 – Commitments and Contingencies

95

Note 21 – Fair Value Measurements

97

Note 22 – Segment Information

98

Note 23 – Supplemental Information on Oil and Gas Operations (Unaudited)

100

Note 24 – Supplemental Quarterly Financial Information (Unaudited)

107

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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Table of Contents

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Devon Energy Corporation:

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries (the “Company”) as of December 31, 20152018 and 2014, and2017, the related consolidated comprehensive statements of comprehensive earnings, stockholders’ equity, and cash flows and stockholders’ equity for each of the years in the three-year period ended December 31, 2015.2018, and the related notes (collectively, the “consolidated financial statements”). We also have audited Devon Energy Corporation’sthe Company’s internal control over financial reporting as of December 31, 2015,2018, based on criteria established inInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)Commission.  

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company  as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Adoption of New Accounting Standard

As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for revenue from contracts with customers in 2018 due to the adoption of Accounting Standards Update 2014-09, Revenue from Contracts with Customers (ASC 606). Devon Energy Corporation’s

Basis for Opinion

The Company’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 the accompanying Management’s Annual Report on Internal Control over Financial Reporting contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K.Procedures.” Our responsibility is to express an opinion on thesethe Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.statements. 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.

Definition and Limitations of Internal Control Over Financial Reporting

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

51


Table of Contents

Index to Financial Statements

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 inInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

We have served as the Company’s auditor since 1980.

Oklahoma City, Oklahoma

February 17, 2016

20, 2019

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Index to Financial Statements

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    7,667    2,066  
  

 

 

  

 

 

  

 

 

 

Total operating revenues

   13,145    19,566    10,397  
  

 

 

  

 

 

  

 

 

 

Lease operating expenses

   2,104    2,332    2,268  

Marketing and midstream operating expenses

   6,420    6,815    1,553  

General and administrative expenses

   855    847    617  

Production and property taxes

   388    535    461  

Depreciation, depletion and amortization

   3,129    3,319    2,780  

Asset impairments

   20,820    1,953    1,976  

Restructuring costs

   78    46    54  

Gains and losses on asset sales

   —      (1,072  9  

Other operating items

   78    93    112  
  

 

 

  

 

 

  

 

 

 

Total operating expenses

   33,872    14,868    9,830  
  

 

 

  

 

 

  

 

 

 

Operating income (loss)

   (20,727  4,698    567  

Net financing costs

   517    526    417  

Other nonoperating items

   24    113    1  
  

 

 

  

 

 

  

 

 

 

Earnings (loss) before income taxes

   (21,268  4,059    149  

Income tax expense (benefit)

   (6,065  2,368    169  
  

 

 

  

 

 

  

 

 

 

Net earnings (loss)

   (15,203  1,691    (20

Net earnings (loss) attributable to noncontrolling interests

   (749  84    —    
  

 

 

  

 

 

  

 

 

 

Net earnings (loss) attributable to Devon

  $(14,454 $1,607   $(20
  

 

 

  

 

 

  

 

 

 

Net earnings (loss) per share attributable to Devon:

    

Basic

  $(35.55 $3.93   $(0.06

Diluted

  $(35.55 $3.91   $(0.06

Comprehensive earnings (loss):

    

Net earnings (loss)

  $(15,203 $1,691   $(20

Other comprehensive earnings (loss), net of tax:

    

Foreign currency translation

   (559  (465  (548

Pension and postretirement plans

   10    (24  45  
  

 

 

  

 

 

  

 

 

 

Other comprehensive loss, net of tax

   (549  (489  (503
  

 

 

  

 

 

  

 

 

 

Comprehensive earnings (loss)

   (15,752  1,202    (523

Comprehensive earnings (loss) attributable to noncontrolling interests

   (749  84    —    
  

 

 

  

 

 

  

 

 

 

Comprehensive earnings (loss) attributable to Devon

  $(15,003 $1,118   $(523
  

 

 

  

 

 

  

 

 

 

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Upstream revenues

 

$

6,285

 

 

$

5,307

 

 

$

3,981

 

Marketing revenues

 

 

4,449

 

 

 

3,571

 

 

 

2,772

 

Total revenues

 

 

10,734

 

 

 

8,878

 

 

 

6,753

 

Production expenses

 

 

2,225

 

 

 

1,823

 

 

 

1,805

 

Exploration expenses

 

 

177

 

 

 

380

 

 

 

215

 

Marketing expenses

 

 

4,363

 

 

 

3,619

 

 

 

2,821

 

Depreciation, depletion and amortization

 

 

1,658

 

 

 

1,529

 

 

 

1,592

 

Asset impairments

 

 

156

 

 

 

 

 

 

437

 

Asset dispositions

 

 

(263

)

 

 

(217

)

 

 

(1,496

)

General and administrative expenses

 

 

650

 

 

 

737

 

 

 

733

 

Financing costs, net

 

 

594

 

 

 

317

 

 

 

717

 

Restructuring and transaction costs

 

 

114

 

 

 

 

 

 

261

 

Other expenses

 

 

140

 

 

 

(83

)

 

 

101

 

Total expenses

 

 

9,814

 

 

 

8,105

 

 

 

7,186

 

Earnings (loss) from continuing operations before income taxes

 

 

920

 

 

 

773

 

 

 

(433

)

Income tax expense

 

 

156

 

 

 

15

 

 

 

141

 

Net earnings (loss) from continuing operations

 

 

764

 

 

 

758

 

 

 

(574

)

Net earnings (loss) from discontinued operations, net of income tax expense

 

 

2,460

 

 

 

320

 

 

 

(884

)

Net earnings (loss)

 

 

3,224

 

 

 

1,078

 

 

 

(1,458

)

Net earnings (loss) attributable to noncontrolling interests

 

 

160

 

 

 

180

 

 

 

(402

)

Net earnings (loss) attributable to Devon

 

$

3,064

 

 

$

898

 

 

$

(1,056

)

Basic net earnings (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

 

Basic earnings (loss) from continuing operations per share

 

$

1.53

 

 

$

1.44

 

 

$

(1.14

)

Basic earnings (loss) from discontinued operations per share

 

 

4.61

 

 

 

0.27

 

 

 

(0.95

)

Basic net earnings (loss) per share

 

$

6.14

 

 

$

1.71

 

 

$

(2.09

)

Diluted net earnings (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

 

Diluted earnings (loss) from continuing operations per share

 

$

1.52

 

 

$

1.43

 

 

$

(1.14

)

Diluted earnings (loss) from discontinued operations per share

 

 

4.58

 

 

 

0.27

 

 

 

(0.95

)

Diluted net earnings (loss) per share

 

$

6.10

 

 

$

1.70

 

 

$

(2.09

)

Comprehensive earnings (loss):

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss)

 

$

3,224

 

 

$

1,078

 

 

$

(1,458

)

Other comprehensive earnings (loss), net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation

 

 

(152

)

 

 

83

 

 

 

11

 

Pension and postretirement plans

 

 

44

 

 

 

29

 

 

 

22

 

Other comprehensive earnings (loss), net of tax

 

 

(108

)

 

 

112

 

 

 

33

 

Comprehensive earnings (loss)

 

 

3,116

 

 

 

1,190

 

 

 

(1,425

)

Comprehensive earnings (loss) attributable to noncontrolling interests

 

 

160

 

 

 

180

 

 

 

(402

)

Comprehensive earnings (loss) attributable to Devon

 

$

2,956

 

 

$

1,010

 

 

$

(1,023

)

See accompanying notes to consolidated financial statements.

53


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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss)

 

$

3,224

 

 

$

1,078

 

 

$

(1,458

)

Adjustments to reconcile net earnings to net cash from operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

Net (earnings) loss from discontinued operations, net of income tax expense

 

 

(2,460

)

 

 

(320

)

 

 

884

 

Depreciation, depletion and amortization

 

 

1,658

 

 

 

1,529

 

 

 

1,592

 

Asset impairments

 

 

156

 

 

 

 

 

 

437

 

Leasehold impairments

 

 

95

 

 

 

219

 

 

 

113

 

Accretion on discounted liabilities

 

 

61

 

 

 

63

 

 

 

75

 

Total (gains) losses on commodity derivatives

 

 

(608

)

 

 

(157

)

 

 

201

 

Cash settlements on commodity derivatives

 

 

(84

)

 

 

53

 

 

 

1

 

Gains on asset dispositions

 

 

(263

)

 

 

(217

)

 

 

(1,496

)

Deferred income tax expense (benefit)

 

 

226

 

 

 

(97

)

 

 

43

 

Share-based compensation

 

 

161

 

 

 

150

 

 

 

203

 

Early retirement of debt

 

 

312

 

 

 

 

 

 

269

 

Total (gains) losses on foreign exchange

 

 

139

 

 

 

(132

)

 

 

(121

)

Settlements of intercompany foreign denominated assets/liabilities

 

 

(241

)

 

 

9

 

 

 

63

 

Other

 

 

(5

)

 

 

(1

)

 

 

4

 

Changes in assets and liabilities, net

 

 

(143

)

 

 

32

 

 

 

24

 

Net cash from operating activities - continuing operations

 

 

2,228

 

 

 

2,209

 

 

 

834

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

 

(2,451

)

 

 

(1,968

)

 

 

(1,384

)

Acquisitions of property and equipment

 

 

(55

)

 

 

(46

)

 

 

(849

)

Divestitures of property and equipment

 

 

1,013

 

 

 

426

 

 

 

3,020

 

Net cash from investing activities - continuing operations

 

 

(1,493

)

 

 

(1,588

)

 

 

787

 

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

Repayments of long-term debt principal

 

 

(922

)

 

 

 

 

 

(2,492

)

Net short-term debt repayments

 

 

 

 

 

 

 

 

(626

)

Early retirement of debt

 

 

(304

)

 

 

 

 

 

(265

)

Issuance of common stock

 

 

 

 

 

 

 

 

1,469

 

Repurchases of common stock

 

 

(2,956

)

 

 

 

 

 

 

Dividends paid on common stock

 

 

(149

)

 

 

(127

)

 

 

(221

)

Shares exchanged for tax withholdings

 

 

(48

)

 

 

(59

)

 

 

(35

)

Other

 

 

(7

)

 

 

 

 

 

 

Net cash from financing activities - continuing operations

 

 

(4,386

)

 

 

(186

)

 

 

(2,170

)

Effect of exchange rate changes on cash:

 

 

 

 

 

 

 

 

 

 

 

 

Settlements of intercompany foreign denominated assets/liabilities

 

 

241

 

 

 

(9

)

 

 

(63

)

Other

 

 

(35

)

 

 

15

 

 

 

2

 

Total effect of exchange rate changes on cash - continuing operations

 

 

206

 

 

 

6

 

 

 

(61

)

Net change in cash, cash equivalents and restricted cash of continuing operations

 

 

(3,445

)

 

 

441

 

 

 

(610

)

Cash flows from discontinued operations:

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

 

476

 

 

 

700

 

 

 

666

 

Investing activities

 

 

2,548

 

 

 

(611

)

 

 

(1,381

)

Financing activities

 

 

183

 

 

 

195

 

 

 

974

 

Net change in cash, cash equivalents and restricted cash of discontinued operations

 

 

3,207

 

 

 

284

 

 

 

259

 

Net change in cash, cash equivalents and restricted cash

 

 

(238

)

 

 

725

 

 

 

(351

)

Cash, cash equivalents and restricted cash at beginning of period

 

 

2,684

 

 

 

1,959

 

 

 

2,310

 

Cash, cash equivalents and restricted cash at end of period

 

$

2,446

 

 

$

2,684

 

 

$

1,959

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reconciliation of cash, cash equivalents and restricted cash:

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

2,414

 

 

$

2,642

 

 

$

1,947

 

Restricted cash included in other current assets

 

 

32

 

 

 

11

 

 

 

 

Cash and cash equivalents included in current assets held for sale

 

 

 

 

 

31

 

 

 

12

 

Total cash, cash equivalents and restricted cash

 

$

2,446

 

 

$

2,684

 

 

$

1,959

 

 

   Year Ended December 31, 
   2015  2014  2013 
   (Millions) 

Cash flows from operating activities:

    

Net earnings (loss)

  $(15,203 $1,691   $(20

Adjustments to reconcile net earnings (loss) to net cash from operating activities:

    

Depreciation, depletion and amortization

   3,129    3,319    2,780  

Asset impairments

   20,820    1,953    1,976  

Gains and losses on asset sales

   —      (1,072  9  

Deferred income tax expense (benefit)

   (5,828  1,891    97  

Derivatives and other financial instruments

   (738  (2,070  135  

Cash settlements on derivatives and financial instruments

   2,688    104    277  

Other noncash charges

   537    457    309  

Net change in working capital

   (301  50    (298

Change in long-term other assets

   285    (421  10  

Change in long-term other liabilities

   (6  79    161  
  

 

 

  

 

 

  

 

 

 

Net cash from operating activities

   5,383    5,981    5,436  
  

 

 

  

 

 

  

 

 

 

Cash flows from investing activities:

    

Capital expenditures

   (5,308  (6,988  (6,502

Acquisitions of property, equipment and businesses

   (1,107  (6,462  (256

Divestitures of property and equipment

   107    5,120    419  

Purchases of short-term investments

   —      —      (1,076

Redemptions of short-term investments

   —      —      3,419  

Redemptions of long-term investments

   —      57    —    

Other

   (16  89    (3
  

 

 

  

 

 

  

 

 

 

Net cash from investing activities

   (6,324  (8,184  (3,999
  

 

 

  

 

 

  

 

 

 

Cash flows from financing activities:

    

Borrowings of long-term debt, net of issuance costs

   4,772    5,340    2,233  

Repayments of long-term debt

   (2,634  (7,189  —    

Net short-term debt repayments

   (307  (385  (1,872

Stock option exercises

   4    93    3  

Sale of subsidiary units

   654    —      —    

Issuance of subsidiary units

   25    410    —    

Dividends paid on common stock

   (396  (386  (348

Distributions to noncontrolling interests

   (254  (235  —    

Other

   (16  (2  4  
  

 

 

  

 

 

  

 

 

 

Net cash from financing activities

   1,848    (2,354  20  
  

 

 

  

 

 

  

 

 

 

Effect of exchange rate changes on cash

   (77  (29  (28
  

 

 

  

 

 

  

 

 

 

Net change in cash and cash equivalents

   830    (4,586  1,429  

Cash and cash equivalents at beginning of period

   1,480    6,066    4,637  
  

 

 

  

 

 

  

 

 

 

Cash and cash equivalents at end of period

  $2,310   $1,480   $6,066  
  

 

 

  

 

 

  

 

 

 

See accompanying notes to consolidated financial statements.

54


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

  December 31, 2015 December 31, 2014 
  (Millions, except share data) 

 

December 31, 2018

 

 

December 31, 2017

 

ASSETS   

 

 

 

 

 

 

 

 

Current assets:

   

 

 

 

 

 

 

 

 

Cash and cash equivalents

  $2,310   $1,480  

 

$

2,414

 

 

$

2,642

 

Accounts receivable

   1,105    1,959  

 

 

885

 

 

 

989

 

Derivatives, at fair value

   43    1,993  

Income taxes receivable

   147    522  

Current assets held for sale

 

 

197

 

 

 

760

 

Other current assets

   421    544  

 

 

941

 

 

 

400

 

  

 

  

 

 

Total current assets

   4,026    6,498  

 

 

4,437

 

 

 

4,791

 

  

 

  

 

 

Property and equipment, at cost:

   

Oil and gas, based on full cost accounting:

   

Subject to amortization

   78,190    75,738  

Not subject to amortization

   2,584    2,752  
  

 

  

 

 

Total oil and gas

   80,774    78,490  

Midstream and other

   10,380    9,695  
  

 

  

 

 

Total property and equipment, at cost

   91,154    88,185  

Less accumulated depreciation, depletion and amortization

   (72,086  (51,889
  

 

  

 

 

Property and equipment, net

   19,068    36,296  
  

 

  

 

 

Oil and gas property and equipment, based on successful efforts

accounting, net

 

 

12,813

 

 

 

13,318

 

Other property and equipment, net

 

 

1,122

 

 

 

1,266

 

Total property and equipment, net

 

 

13,935

 

 

 

14,584

 

Goodwill

   5,032    6,303  

 

 

841

 

 

 

841

 

Other long-term assets

   1,406    1,540  

 

 

353

 

 

 

296

 

  

 

  

 

 

Long-term assets held for sale

 

 

 

 

 

9,729

 

Total assets

  $29,532   $50,637  

 

$

19,566

 

 

$

30,241

 

  

 

  

 

 
LIABILITIES AND STOCKHOLDERS’ EQUITY   

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

 

Current liabilities:

   

 

 

 

 

 

 

 

 

Accounts payable

  $906   $1,400  

 

$

662

 

 

$

633

 

Revenues and royalties payable

   763    1,193  

 

 

898

 

 

 

748

 

Short-term debt

   976    1,432  

 

 

162

 

 

 

115

 

Deferred income taxes

   —      730  

Current liabilities held for sale

 

 

69

 

 

 

991

 

Other current liabilities

   650    1,180  

 

 

435

 

 

 

828

 

  

 

  

 

 

Total current liabilities

   3,295    5,935  

 

 

2,226

 

 

 

3,315

 

  

 

  

 

 

Long-term debt

   12,137    9,830  

 

 

5,785

 

 

 

6,749

 

Asset retirement obligations

   1,370    1,339  

 

 

1,030

 

 

 

1,099

 

Other long-term liabilities

   853    948  

 

 

462

 

 

 

549

 

Long-term liabilities held for sale

 

 

 

 

 

3,936

 

Deferred income taxes

   888    6,244  

 

 

877

 

 

 

489

 

Stockholders’ equity:

   

Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 418 million and 409 million shares in 2015 and 2014, respectively

   42    41  

Equity:

 

 

 

 

 

 

 

 

Common stock, $0.10 par value. Authorized 1.0 billion shares; issued

450 million and 525 million shares in 2018 and 2017, respectively

 

 

45

 

 

 

53

 

Additional paid-in capital

   4,996    4,088  

 

 

4,486

 

 

 

7,333

 

Retained earnings

   1,781    16,631  

 

 

3,650

 

 

 

702

 

Accumulated other comprehensive earnings

   230    779  

 

 

1,027

 

 

 

1,166

 

  

 

  

 

 

Treasury stock, at cost, 1.0 million shares in 2018

 

 

(22

)

 

 

 

Total stockholders’ equity attributable to Devon

   7,049    21,539  

 

 

9,186

 

 

 

9,254

 

Noncontrolling interests

   3,940    4,802  

 

 

 

 

 

4,850

 

  

 

  

 

 

Total stockholders’ equity

   10,989    26,341  
  

 

  

 

 

Commitments and contingencies (Note 18)

   

Total liabilities and stockholders’ equity

  $29,532   $50,637  
  

 

  

 

 

Total equity

 

 

9,186

 

 

 

14,104

 

Total liabilities and equity

 

$

19,566

 

 

$

30,241

 

See accompanying notes to consolidated financial statements.

55


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retained

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 Common Stock Additional
Paid-In
Capital
  Retained
Earnings
  Accumulated
Other

Comprehensive
Earnings
  Treasury
Stock
  Noncontrolling
Interests
  Total
Stockholders’
Equity
 

 

 

 

 

 

 

 

 

 

Additional

 

 

Earnings

 

 

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 Shares Amount 

 

Common Stock

 

 

Paid-In

 

 

(Accumulated

 

 

Comprehensive

 

 

Treasury

 

 

Noncontrolling

 

 

Total

 

 (Millions) 

 

Shares

 

 

Amount

 

 

Capital

 

 

Deficit)

 

 

Earnings

 

 

Stock

 

 

Interests

 

 

Equity

 

Balance as of December 31, 2012

  406   $41   $3,688   $15,778   $1,771   $—     $—     $21,278  

Balance as of December 31, 2015

 

 

418

 

 

$

42

 

 

$

4,996

 

 

$

1,112

 

 

$

1,021

 

 

$

 

 

$

3,940

 

 

$

11,111

 

Net loss

  —      —      —      (20  —      —      —      (20

 

 

 

 

 

 

 

 

 

 

 

(1,056

)

 

 

 

 

 

 

 

 

(402

)

 

 

(1,458

)

Other comprehensive loss, net of tax

  —      —      —      —      (503  —      —      (503

Stock option exercises

  —      —      3    —      —      —      —      3  

Common stock repurchased

  —      —      —      —      —      (36  —      (36

Common stock retired

  —      —      (36  —      —      36    —      —    

Common stock dividends

  —      —      —      (348  —      —      —      (348

Share-based compensation

  —      —      121    —      —      —      —      121  

Share-based compensation tax benefits

  —      —      4    —      —      —      —      4  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Balance as of December 31, 2013

  406    41    3,780    15,410    1,268    —      —      20,499  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Net earnings

  —      —      —      1,607    —      —      84    1,691  

Other comprehensive loss, net of tax

  —      —      —      —      (489  —      —      (489

Stock option exercises

  1    —      93    —      —      —      —      93  

Restricted stock grants, net of cancellations

  2    —      —      —      —      —      —      —    

Common stock repurchased

  —      —      —      —      —      (27  —      (27

Common stock retired

  —      —      (27  —      —      27    —      —    

Common stock dividends

  —      —      —      (386  —      —      —      (386

Share-based compensation

  —      —      151    —      —      —      —      151  

Share-based compensation tax expense

  —      —      (3  —      —      —      —      (3

Acquisition of noncontrolling interests

  —      —      —      —      —      —      4,670    4,670  

Subsidiary equity transactions

  —      —      93    —      —      —      277    370  

Distributions to noncontrolling interests

  —      —      —      —      —      —      (235  (235

Other

  —      —      1    —      —      —      6    7  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Balance as of December 31, 2014

  409    41    4,088    16,631    779    —      4,802    26,341  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Net loss

  —      —      —      (14,454  —      —      (749  (15,203

Other comprehensive loss, net of tax

  —      —      —      —      (549  —      —      (549

Stock option exercises

  —      —      4    —      —      —      —      4  

Other comprehensive earnings, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

33

 

 

 

 

 

 

 

 

 

33

 

Restricted stock grants, net of cancellations

  2    —      —      —      —      —      —      —    

 

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock repurchased

  —      —      —      —      —      (35  —      (35

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(28

)

 

 

 

 

 

(28

)

Common stock retired

  —      —      (35  —      —      35    —      —    

 

 

 

 

 

 

 

 

(28

)

 

 

 

 

 

 

 

 

28

 

 

 

 

 

 

 

Common stock dividends

  —      —      —      (396  —      —      —      (396

 

 

 

 

 

 

 

 

(96

)

 

 

(125

)

 

 

 

 

 

 

 

 

 

 

 

(221

)

Common stock issued

  7    1    198    —      —      —      —      199  

 

 

103

 

 

 

10

 

 

 

2,117

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2,127

 

Share-based compensation

  —      —      165    —      —      —      —      165  

 

 

 

 

 

 

 

 

168

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

168

 

Share-based compensation tax expense

  —      —      (9  —      —      —      —      (9

Subsidiary equity transactions

  —      —      585    —      —      —      141    726  

 

 

 

 

 

 

 

 

80

 

 

 

 

 

 

 

 

 

 

 

 

1,214

 

 

 

1,294

 

Distributions to noncontrolling interests

  —      —      —      —      —      —      (254  (254

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(304

)

 

 

(304

)

 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Balance as of December 31, 2015

  418   $42   $4,996   $1,781   $230   $—     $3,940   $10,989  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Balance as of December 31, 2016

 

 

523

 

 

$

52

 

 

$

7,237

 

 

$

(69

)

 

$

1,054

 

 

$

 

 

$

4,448

 

 

$

12,722

 

Net earnings

 

 

 

 

 

 

 

 

 

 

 

898

 

 

 

 

 

 

 

 

 

180

 

 

 

1,078

 

Other comprehensive earnings, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

112

 

 

 

 

 

 

 

 

 

112

 

Restricted stock grants, net of cancellations

 

 

1

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1

 

Common stock repurchased

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(44

)

 

 

 

 

 

(44

)

Common stock retired

 

 

 

 

 

 

 

 

(44

)

 

 

 

 

 

 

 

 

44

 

 

 

 

 

 

 

Common stock dividends

 

 

 

 

 

 

 

 

 

 

 

(127

)

 

 

 

 

 

 

 

 

 

 

 

(127

)

Share-based compensation

 

 

1

 

 

 

 

 

 

126

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

126

 

Subsidiary equity transactions

 

 

 

 

 

 

 

 

14

 

 

 

 

 

 

 

 

 

 

 

 

576

 

 

 

590

 

Distributions to noncontrolling interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(354

)

 

 

(354

)

Balance as of December 31, 2017

 

 

525

 

 

$

53

 

 

$

7,333

 

 

$

702

 

 

$

1,166

 

 

$

 

 

$

4,850

 

 

$

14,104

 

Net earnings

 

 

 

 

 

 

 

 

 

 

 

3,064

 

 

 

 

 

 

 

 

 

160

 

 

 

3,224

 

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(108

)

 

 

 

 

 

 

 

 

(108

)

Restricted stock grants, net of cancellations

 

 

3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock repurchased

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(3,017

)

 

 

 

 

 

(3,017

)

Common stock retired

 

 

(79

)

 

 

(8

)

 

 

(2,987

)

 

 

 

 

 

 

 

 

2,995

 

 

 

 

 

 

 

Common stock dividends

 

 

 

 

 

 

 

 

 

 

 

(149

)

 

 

 

 

 

 

 

 

 

 

 

(149

)

Share-based compensation

 

 

1

 

 

 

 

 

 

140

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

140

 

Divestment of subsidiary equity investment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2

 

 

 

 

 

 

(4,863

)

 

 

(4,861

)

Subsidiary equity transactions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

72

 

 

 

72

 

Distributions to noncontrolling interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(219

)

 

 

(219

)

Other

 

 

 

 

 

 

 

 

 

 

 

33

 

 

 

(33

)

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2018

 

 

450

 

 

$

45

 

 

$

4,486

 

 

$

3,650

 

 

$

1,027

 

 

$

(22

)

 

$

 

 

$

9,186

 

See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.

Summary of Significant Accounting Policies

Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada.

As further discussed in Note 2, Devon also owns natural gas pipelines, plants and treatment facilities throughsold its ownershipinterests in EnLink and the General Partner.Partner on July 18, 2018. Activity relating to EnLink and the General Partner are classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows. The associated assets and liabilities of EnLink and the General Partner are presented as assets and liabilities held for sale on the consolidated balance sheets.

Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U.S. and reflect industry practices. The more significant of such policies are discussed below.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.

As discussed more fully in Note 2, Devon completed a business combination in 2014 whereby Devon controls both EnLink and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.

Use of Estimates

The preparation of financial statements requires management to make estimates 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. Significant items subject to such estimates and assumptions include the following:

proved reserves and related present value of future net revenues;

evaluation of suspended well costs;

the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories;

derivative financial instruments;

the fair value of reporting units and related assessment of goodwill for impairment;

income taxes;

asset retirement obligations;

obligations related to employee pension and postretirement benefits;

legal and environmental risks and exposures; and

general credit risk associated with receivables and other assets.

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proved reserves and related present value of future net revenues;Index to Financial Statements

 

the carrying value of oil and gas properties, midstream assets and product and equipment inventories;

derivative financial instruments;

the fair value of reporting units and related assessment of goodwill for impairment;

the fair value of intangible assets other than goodwill;

income taxes;

asset retirement obligations;

obligations related to employee pension and postretirement benefits;

legal and environmental risks and exposures; and

general credit risk associated with receivables and other assets.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Revenue Recognition

Impact of ASC 606 Adoption

In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. 

The impact of adoption in the current period results is as follows:

 

 

Year Ended December 31, 2018

 

 

 

Under ASC

606

 

 

Under ASC

605

 

 

Increase/

(Decrease)

 

Upstream revenues

 

$

6,285

 

 

$

6,031

 

 

$

254

 

Marketing revenues

 

 

4,449

 

 

 

4,449

 

 

 

 

Total impacted revenues

 

$

10,734

 

 

$

10,480

 

 

$

254

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production expenses

 

$

2,225

 

 

$

1,971

 

 

$

254

 

Marketing expenses

 

 

4,363

 

 

 

4,363

 

 

 

 

Total impacted expenses

 

$

6,588

 

 

$

6,334

 

 

$

254

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings from continuing

   operations before income taxes

 

$

920

 

 

$

920

 

 

$

 

Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses.

Upstream Revenues

Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, titlecontrol has transferred and collectability of the revenue is probable. DeliveryDevon’s performance obligations are satisfied at a point in time. This occurs and title typicallywhen control is transferred whento the purchaser upon delivery of contract specified production has been deliveredvolumes at a specified point. The transaction price used to recognize revenue is a pipeline, railcar or truck. Cashfunction of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received relating to futurewithin 30 days of the end of the production is deferred and recognized when all revenue recognition criteria are met.month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Natural gas and NGL sales

Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statements of earnings.

In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings.

Oil sales

Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings.

Marketing and midstreamRevenues

Marketing revenues are recordedgenerated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold or services are provided to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, titlecontrol has transferred and collectability of the revenue is probable. RevenuesThe transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases transportation and processing contracts are reported on a gross basis when Devon takes title tocontrol of the products and has risks and rewards of ownership.


Satisfaction of Performance Obligations and Revenue Recognitions

Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the natural gas, NGLs or crude oil are delivered at a fixed or determinable price.


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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Transaction Price Allocated to Remaining Performance Obligations

Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets.

Disaggregation of Revenue

Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. Disaggregation of revenue disclosures can be found in Note 22.

Customers

During 2015, 20142018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue.

During 2017 and 2013,2016, no purchaser accounted for more than 10% of Devon’s operating revenues.consolidated sales revenue.

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars and call options.collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes both two-way price collars and three-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterpartycounterparty. The three-way price collars consist of a two-way collar with an additional short put option sold by Devon, and cash-settle similarly to the collars. The call options give counterpartiestwo-way collars unless the rightmarket price falls below the additional short put causing the company to purchase production at a predetermined price.receive the market price plus the long put to short put price differential.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of December 31, 2018, Devon did not have any open foreign exchange contracts.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2015,2018, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2015 and December 31, 2014,2018, Devon held $75 million and $524 million, respectively, ofno cash collateral which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. Theits counterparties nor posted collateral is reported in other current liabilities in the accompanying consolidated balance sheets.to its counterparties.

General and Administrative Expenses

G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.Devon.

Share-Based Compensation

Independent of EnLink, Devon grants share-based awards to independent members of its Board of Directors and selected employees. EnLink and the General Partner also grant share-based awards to independent members of its Board of Directors and selectedselect employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated comprehensive statements of earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase.

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 78 for further discussion.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.

Net Earnings (Loss) Per Share Attributable to Devon

Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.unvested performance share units.

Cash and Cash Equivalents

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.

Accounts Receivable

Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable, including joint interest receivables, for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance.

Investments

Devon periodically invests excess cash in U.S. and Canadian treasury securities and other marketable securities. Devon considers securities with original contractual maturities in excess of three months but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale. Devon reports its investments and other marketable securities at fair value.

Property and Equipment

Oil and Gas Property and Equipment

Devon follows the full costsuccessful efforts method of accounting for its oil and gas properties. Accordingly, allExploration costs, incidentalsuch as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful

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Index to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also

Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Interest costs incurred and attributable to unprovedDevon groups its oil and gas properties under current evaluationwith a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and majoraccounting for asset dispositions.

Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development projectsactivities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly.

Capitalized costs of proved oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Depletion is calculated using the capitalizedProved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly.annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred intoamortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms.

Proved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the depletion calculation over holding periods ranging from threecarrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to four years.estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review.

SalesGains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized upon disposal ofrecognized.

Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country. As discussed more fully in Note 2, the 2014 divestitures of certain Canadian assets significantly altered such relationship, and Devon recognized a gain, which is included as a separate item in the accompanying consolidated comprehensive statements of earnings.

Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10% per annum, net of related tax effects. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book valuemajor development projects of oil and gas properties.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Other Property and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2015 qualified for hedge accounting treatment.Equipment

Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.

Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.

Asset Retirement Obligations

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes ana qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative andassessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative factors.goodwill impairment test is performed. The quantitative goodwill impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. Thethe fair value of each reporting unit is estimated andbe compared to the net bookcarrying value of the reporting unit. If the estimated fair value of the reporting unit is less than the net bookcarrying value, including goodwill, thenan impairment charge will be recognized for the goodwill is written down toamount by which the impliedcarrying amount exceeds the fair value of the goodwill through a charge to expense.value. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.

Devon performed annual impairment tests of goodwill in the fourth quarters of 2015, 20142018, 2017 and 2013.2016. No impairment of goodwill was required in 2013. However, write-downs were required in 2015 and 2014 based onas a result of the annual impairment test. EnLink’s Texas, Louisiana and Crude and Condensate reporting segment goodwill were deemed impairedtests in 2015, and Devon’s Canadian reporting unit goodwill was deemed impaired in 2014. See Note 12 for further discussion.these time periods.

Intangible Assets

Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years. During 2015, EnLink’s customer relationships were also evaluated for impairment, and a portion of these intangibles was considered impaired. See Note 12 for further discussion.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Fair Value Measurements

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Foreign Currency Translation Adjustments

The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the 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. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity.

Noncontrolling Interests

Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.

Recently IssuedAdopted Accounting Standards

The FASB issuedIn January 2018, Devon adopted ASU 2014-09,Revenue from Contracts with Customers (ASC 606), using the modified retrospective method. See revenue recognition section above for further discussion regarding Devon’s adoption of this revenue recognition standard.

In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 606)715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU supersedesrequires entities to present the revenue recognition requirements in Topic 605,Revenue Recognition and industry-specific guidance in Subtopic 932-605,Extractive Activities – Oil and Gas – Revenue Recognition.This ASU provides guidance concerning the recognition and measurementservice cost component of revenue from contracts with customers. Its objective is to increase the usefulness of informationnet periodic benefit cost in the financial statements regardingsame line item as other employee compensation costs. Only the nature, timing and uncertaintyservice cost component of revenues. The effective datenet periodic benefit cost is eligible for ASU 2014-09 was delayed through the issuance of ASU 2015-14,Revenue from Contracts with Customers – Deferralcapitalization. As a result of the Effective Date,to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. Devon is evaluating the impactof this ASU, will have on its consolidated financial statements of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively. Upon adoption, Devon reclassified $7 million and related disclosures$14 million of non-service cost components of net periodic benefit costs for 2017 and does not plan on early adopting.2016, respectively, from G&A to other expenses.

The FASB issued ASU 2015-02,Consolidation (Topic 810): Amendments65


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Index to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU

Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

is considered to be an improvement on current accounting requirements as it reduces the numberIn January 2018, Devon adopted ASU 2016-18, Statement of existing consolidation models.Cash Flows (Topic 230): Restricted Cash. This ASU is effective forrequires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon beginning January 1, 2016made changes to the statement of cash flows to include the required presentation and will be applied usingreconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows.

In the retrospective approach.fourth quarter of 2018, Devon early adopted ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220). This ASU willallows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. As a result of adopting this ASU, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet.

In the fourth quarter of 2018, Devon early adopted ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU eliminated and added certain disclosure requirements for employers that sponsors defined benefit plans and/or other postretirement plans. Other than changes to required disclosures, this ASU did not have a material impact on Devon’s consolidated financial statements and related disclosures.

The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification, which amends various SEC disclosure requirements determined to be redundant, duplicative, overlapping, outdated or superseded as part of the SEC’s ongoing disclosure effectiveness initiative. The rule was effective November 5, 2018. The rule amended numerous SEC rules, items and forms covering a diverse group of topics. Devon has implemented these required changes to disclosures which generally reduced or eliminated disclosures. Devon will adopt the requirement of presenting a current and comparative year-to-date change in stockholder’s equity roll forward during the first quarter of 2019.

Issued Accounting Standards Not Yet Adopted

The FASB issued ASU 2015-03,Interest2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Short-term leases can continue being accounted for off balance sheet based on a policy election. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. Devon is adopting this ASU beginning January 1, 2019.

Devon will apply the guidance using a modified retrospective transition method at the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also has elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases. Devon will be allowed to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented with the 2019 adoption year. Devon has implemented processes, controls, and a technology solution needed to comply with the requirements of this ASU.

To adopt Topic 842, Devon expects to recognize right-of-use assets of approximately $400 million with a corresponding lease liability based on the present value of the remaining term minimum lease payments. Devon’s right-of-use assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Additionally, Devon will recognize a $24 million before tax, $19 million net of tax cumulative-effect adjustment to reduce retained earnings.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Imputation(Continued)

The FASB issued ASU 2018-04, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement. This ASU will eliminate, add and modify certain disclosure requirements for fair value measurement. The ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the entire standard or only the provisions that eliminate or modify requirements. The ASU requires the additional disclosure requirements to be adopted using a retrospective approach. Devon is currently evaluating the provisions of Interest (Topic 835)this ASU and assessing the impact it may have on its disclosures in the notes to the consolidated financial statements.

The FASB issued ASU 2018-05-15, Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40): SimplifyingCustomer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. This ASU will require a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the Presentation of Debt Issuance Costs and ASU 2015-15,Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.These ASUs require debt issuanceinternal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet ashosting arrangement that is a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective for Devon beginning January 1, 2016 andservice contract will be applied usingamortized over the retrospective approach. These ASUs will not have a material impact on Devon’s consolidated financial statements and related disclosures.

The FASB issued ASU 2015-17,Balance Sheet Classificationterm of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet.hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively,January 1, 2020, with early adoption permitted. ThisEntities have the option to adopt the ASU will be early-adopted byusing either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of the adoption. Devon effective January 1, 2016is currently evaluating the provisions of this ASU and will be applied usingassessing the retrospective approach. This ASU will notimpact it may have a material impact on Devon’sits consolidated financial statements and related disclosures.statements.

 

2.

Acquisitions and Divestitures

Formation of EnLink and the General Partner

On March 7, 2014, Devon and Crosstex completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a midstream business that consists of the General Partner and EnLink, which are both publicly traded.Acquisitions

In exchange for a controlling interest in both EnLink and the General Partner, Devon contributed its equity interest in a newly formed Devon subsidiary, EMH, and $100 million in cash. EMH owned midstream assets in the Barnett Shale in north Texas and the Cana- and Arkoma-Woodford Shales in Oklahoma, as well as an economic interest in Gulf Coast Fractionators in Mont Belvieu, Texas.

This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, EMH was the accounting acquirer because its parent company, Devon, obtained control of EnLink and the General Partner as a result of the business combination. Consequently, EMH’s assets and liabilities retained their carrying values. Additionally, the Crosstex assets acquired and liabilities assumed by the General Partner and EnLink in the business combination, as well as the General Partner’s noncontrolling interest in EnLink, were recorded at their fair values which were measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of Crosstex’s net assets acquired was recorded as goodwill.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes the purchase price (millions, except unit price).

Crosstex Energy, Inc. outstanding common shares:

  

Held by public shareholders

   48.0  

Restricted shares

   0.4  
  

 

 

 

Total subject to conversion

   48.4  

Exchange ratio

   1.0
  

 

 

 

Converted shares

   48.4  

Crosstex Energy, Inc. common share price(1)

  $37.60  
  

 

 

 

Crosstex Energy, Inc. consideration

  $1,823  

Fair value of noncontrolling interests in E2(2)

   18  
  

 

 

 

Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests

  $1,841  
  

 

 

 

Crosstex Energy, LP outstanding units:

  

Common units held by public unitholders

   75.1  

Preferred units held by third party (3)

   17.1  

Restricted units

   0.4  
  

 

 

 

Total

   92.6  

Crosstex Energy, LP common unit price(4)

  $30.51  
  

 

 

 

Crosstex Energy, LP common units value

  $2,825  

Crosstex Energy, LP outstanding unit options value

   4  
  

 

 

 

Total fair value of noncontrolling interests in Crosstex Energy, LP(4)

   2,829  
  

 

 

 

Total consideration and fair value of noncontrolling interests

  $4,670  
  

 

 

 

(1)The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014.
(2)Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2.
(3)Crosstex Energy, LP converted the preferred units to common units in February 2014.
(4)The final purchase price is based on the fair value of Crosstex Energy, LP’s common units as of the closing date, March 7, 2014.

The allocation of the purchase price is as follows (millions):

Assets acquired:

  

Current assets

  $437  

Property, plant and equipment, net

   2,438  

Intangible assets

   569  

Equity investment

   222  

Goodwill (1)

   3,283  

Other long-term assets

   1  

Liabilities assumed:

  

Current liabilities

   (515

Long-term debt

   (1,454

Deferred income taxes

   (210

Other long-term liabilities

   (101
  

 

 

 

Total consideration and fair value of noncontrolling interests

  $4,670  
  

 

 

 

(1)Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

EnLink Acquisitions

The following table presents a summary of EnLink’s acquisition activity for 2015.

        Purchase Price
(Millions)
     Allocation
(Millions)
 

Date

  Acquiree    Cash     EnLink
Units
     PP&E     Goodwill     Intangibles     Other 

January 31

  LPC    $108       —        $30      $30      $43      $5  

March 16

  Coronado    $240      $360      $302      $18      $281      $(1

October 1

  Matador    $145       —        $36      $9      $99      $1  

On January 7, 2016, EnLink also acquired Anadarko Basin gathering and processing midstream assets from Tall Oak for approximately $1.5 billion, subject to certain adjustments. EnLink paid approximately $800 million of cash at the time of closing, primarily funded with the issuance of EnLink preferred units, with another $500 million of cash to be paid within 24 months. The remainder of the purchase price consisted of approximately 15.6 million General Partner common units.

EnLink Dropdowns

In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.

In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.

Devon Acquisitions

On February 28, 2014, Devon completed its acquisition of interests in certain affiliates of GeoSouthern for approximately $6.0 billion. Devon funded the acquisition with cash on hand and debt financing. In connection with the GeoSouthern transaction, Devon acquired approximately 82,000 net acres (unaudited) located in DeWitt and Lavaca counties in south Texas. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The allocation of the purchase price is as follows (millions).

Cash and cash equivalents

  $95  

Other current assets

   256  

Proved properties

   5,026  

Unproved properties

   1,007  

Midstream assets

   86  

Current liabilities

   (434

Long-term liabilities

   (6
  

 

 

 

Net assets acquired

  $6,030  
  

 

 

 

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On December 17, 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. A preliminary allocation of the purchase price at December 31, 2015 was $386 million to unproved properties and $113 million to proved properties and gathering systems.

On January 7, 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $850$849 million of cash, after adjustments, and $659 million of equity. The allocation of the purchase price was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.

Pro Forma Financial InformationDivestitures

The following unaudited pro forma financial information has been prepared assuming both

EnLink and General Partner

During the third quarter of 2018, Devon completed the sale of its aggregate ownership interests in EnLink formation and the GeoSouthern acquisition occurred on January 1, 2013. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devon’s results of operationsGeneral Partner for any future period.

   Year Ended December 31, 
       2014           2013     
   (Millions) 

Total operating revenues

  $20,213    $12,979  

Net earnings

  $1,716    $35  

Noncontrolling interests

  $97    $45  

Net earnings (loss) attributable to Devon

  $1,619    $(10

Net earnings (loss) per common share attributable to Devon

  $3.94    $(0.02

Asset Divestitures

During 2014, Devon divested certain properties located throughout Canada and the U.S. as part of its asset portfolio transformation.

Canada

In the second quarter of 2014, Devon sold Canadian conventional assets for $2.8$3.125 billion ($3.125 billion Canadian dollars) and recognized a gain totaling $1.1of approximately $2.6 billion ($0.62.2 billion after-tax). ThisThe proceeds from the sale were utilized to increase Devon’s share repurchase program to $4.0 billion, which is discussed further in Note 18. Additional information on these discontinued operations can be found in Note 19.

Upstream Assets

During 2018, Devon received proceeds of approximately $1.0 billion and recognized a net gain is included as a separate itemon asset dispositions of approximately $260 million, primarily from sales of non-core assets in the accompanying consolidated comprehensive statementsBarnett Shale and Delaware Basin. As part of earnings. Included in the gain calculation were asset retirement obligations oftransactions, approximately $700 million assumed by the purchaser as well as the derecognition of approximately $700 million of goodwill allocated to the sold assets. In conjunction with the divestiture, Devon repatriated approximately $2.8 billion of proceeds to the U.S. in the second quarter of 2014, which was utilized to repay commercial paper and term loan balances. Between collecting the divestiture proceeds and repatriating funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign exchange currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings.

U.S.

In the third quarter of 2014, Devon sold certain U.S. assets for $2.2 billion. Additionally, approximately $200 million of asset retirement obligations were assumed by the purchaser. No gainpurchasers. In conjunction with the divestitures, Devon settled certain gas processing contracts and recognized $40 million in settlement expense, which is included in asset dispositions within the 2018 consolidated statements of earnings. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 267 MMBoe, or loss was recognized on the sale. These proceeds were used toward the early retirement18%, of $1.9 billion in senior notes in November 2014 as discussed in Note 13.

total U.S. proved reserves.  

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

3. DerivativeAdditionally, in the first quarter of 2019, Devon completed two separate divestitures of non-core assets in the Permian Basin totaling $300 million. One of the divestitures related to the sale of an entire common operating field, and Devon expects to recognize a gain of approximately $35 million during the first quarter of 2019. As of December 31, 2018, these associated assets and liabilities were classified as held for sale in the accompanying consolidated balance sheet. See Note 19 for additional information. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 25 MMBoe, or less than 2%, of total U.S. proved reserves.

During 2017, Devon received proceeds totaling approximately $420 million, and recognized a net gain on asset dispositions of $212 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves.

During 2016, Devon received proceeds totaling approximately $1.9 billion and recognized a net gain on asset dispositions of $809 million, primarily from sales of non-core assets in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. Estimated proved reserves associated with these assets were approximately 157 MMBoe, or 10%, of total U.S. proved reserves. As part of the transactions, approximately $290 million of asset retirement obligations were assumed by purchasers and approximately $80 million of goodwill was allocated to these divested assets.

Access Pipeline

In October 2016, Devon divested its 50% interest in Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes.

Canada and Barnett Shale (Subsequent Event)

In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from the Company, based on authorizations provided by its Board of Directors subsequent to December 31, 2018. Devon will evaluate multiple methods of separation for these assets, including potential sales or spin-offs. Devon is in the early stages of marketing these assets and does not currently have any indications that it would recognize an impairment upon separating its Canadian business or its Barnett Shale assets.

Devon anticipates reporting all financial information for its Canadian business and Barnett Shale assets as discontinued operations in 2019 when all the requisite criteria are met for such financial statement presentation.

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Table of Contents

Index to Financial InstrumentsStatements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3.

Derivative Financial Instruments

Commodity Derivatives

As of December 31, 2015,2018, Devon had the following open oil derivative positions. The first table presentstwo tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The secondthird table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

 

  Call Options Sold 

 

Price Swaps

 

 

Price Collars

 

Period

  Volume (Bbls/d)   Weighted Average
Price  ($/Bbl)
 

 

Volume

(Bbls/d)

 

 

Weighted

Average

Price ($/Bbl)

 

 

Volume

(Bbls/d)

 

 

Weighted

Average Floor

Price ($/Bbl)

 

 

Weighted

Average

Ceiling Price

($/Bbl)

 

Q1-Q4 2016

   18,500    $73.18  

Q1-Q4 2019

 

 

51,719

 

 

$

59.48

 

 

 

87,921

 

 

$

54.48

 

 

$

64.49

 

Q1-Q4 2020

 

 

1,740

 

 

$

62.88

 

 

 

8,951

 

 

$

52.85

 

 

$

63.13

 

 

   Oil Basis Swaps 

Period

  Index        Volume (Bbls/d)         Weighted Average
Differential to WTI
($/Bbl)
 

Q1-Q4 2016

  Western Canadian Select   5,249    $(13.67

Q1-Q4 2016

  West Texas Sour   5,000    $(0.53

Q1-Q4 2016

  Midland Sweet   13,000    $0.25  

 

 

Three-Way Price Collars

 

Period

 

Volume

(Bbls/d)

 

 

Weighted

Average Floor Sold

Price ($/Bbl)

 

 

Weighted

Average Floor Purchased

Price ($/Bbl)

 

 

Weighted

Average

Ceiling Price

($/Bbl)

 

Q1-Q4 2019

 

 

5,000

 

 

$

50.00

 

 

$

63.00

 

 

$

74.80

 

 

 

Oil Basis Swaps

 

Period

 

Index

 

Volume

(Bbls/d)

 

 

Weighted Average

Differential to WTI

($/Bbl)

 

Q1-Q4 2019

 

Midland Sweet

 

 

28,000

 

 

$

(0.46

)

Q1-Q4 2019

 

Argus LLS

 

 

17,500

 

 

$

5.00

 

Q1-Q4 2019

 

Argus MEH

 

 

16,000

 

 

$

2.84

 

Q1-Q4 2019

 

NYMEX Roll

 

 

38,000

 

 

$

0.45

 

Q1-Q4 2019

 

Western Canadian Select

 

 

31,505

 

 

$

(21.73

)

Q1-Q4 2020

 

NYMEX Roll

 

 

38,000

 

 

$

0.31

 

Q1-Q4 2020

 

Western Canadian Select

 

 

915

 

 

$

(20.75

)

As of December 31, 2015,2018, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.

 

  Price Swaps   Call Options Sold 

 

Price Swaps

 

 

Price Collars

 

Period

  Volume (MMBtu/d)   Weighted Average
Price ($/MMBtu)
   Volume
(MMBtu/d)
   Weighted Average
Price ($/MMBtu)
 

 

Volume (MMBtu/d)

 

 

Weighted Average Price ($/MMBtu)

 

 

Volume (MMBtu/d)

 

 

Weighted Average Floor Price ($/MMBtu)

 

 

Weighted Average

Ceiling Price ($/MMBtu)

 

Q1-Q4 2016

           54,650            $3.17     400,000    $4.30  

Q1-Q4 2019

 

 

266,293

 

 

$

2.86

 

 

 

231,474

 

 

$

2.69

 

 

$

3.06

 

Q1-Q4 2020

 

 

26,480

 

 

$

2.92

 

 

 

24,490

 

 

$

2.74

 

 

$

3.04

 

69


Table of Contents

 

   Natural Gas Basis Swaps 

Period

  Index  Volume (MMBtu/d)   Weighted Average
Differential to Henry
Hub ($/MMBtu)
 

Q1-Q4 2016

  Panhandle Eastern Pipe Line   175,000    $(0.34

Q1-Q4 2016

  El Paso Natural Gas   125,000    $(0.12

Q1-Q4 2016

  Houston Ship Channel   30,000    $0.11  

Q1-Q4 2016

  Transco Zone 4   70,000    $0.01  

Q1-Q4 2017

  Panhandle Eastern Pipe Line   150,000    $(0.34

Q1-Q4 2017

  El Paso Natural Gas   50,000    $(0.14

Q1-Q4 2017

  Houston Ship Channel   35,000    $0.06  

Q1-Q4 2017

  Transco Zone 4   185,000    $0.03  

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

 

Natural Gas Basis Swaps

 

Period

 

Index

 

Volume

(MMBtu/d)

 

 

Weighted Average

Differential to

Henry Hub

($/MMBtu)

 

Q1-Q4 2019

 

Panhandle Eastern Pipe Line

 

 

84,466

 

 

$

(0.73

)

Q1-Q4 2019

 

El Paso Natural Gas

 

 

130,000

 

 

$

(1.46

)

Q1-Q4 2019

 

Houston Ship Channel

 

 

142,637

 

 

$

0.01

 

Q1-Q4 2019

 

Transco Zone 4

 

 

7,397

 

 

$

(0.03

)

 

As of December 31, 2015, EnLink2018, Devon had the following open NGL derivative positions associated with gas processing and fractionation. EnLink’spositions. Devon’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.

 

 

 

 

 

Price Swaps

 

Period

 

Product

 

Volume (Bbls/d)

 

 

Weighted Average Price ($/Bbl)

 

Q1-Q4 2019

 

Ethane

 

 

1,000

 

 

$

11.55

 

Q1-Q4 2019

 

Natural Gasoline

 

 

4,500

 

 

$

55.93

 

Q1-Q4 2019

 

Normal Butane

 

 

4,000

 

 

$

33.69

 

Q1-Q4 2019

 

Propane

 

 

8,500

 

 

$

30.01

 

Period

ProductVolume (Total)Weighted Average
Price Paid
Weighted Average
Price Received

Q1 2016-Q4 2016

Ethane571MBbls$0.29/galIndex

Q1 2016-Q4 2016

Propane812MBblsIndex$0.81/gal

Q1 2016-Q4 2016

Normal Butane113MBblsIndex$0.61/gal

Q1 2016-Q4 2016

Natural Gasoline61MBblsIndex$1.02/gal

Q1 2016-Q1 2017

Natural Gas13,829MMBtu/d$2.65/MMBtuIndex

Interest Rate Derivatives

As of December 31, 2015,2018, Devon had the following open interest rate derivative positions:

 

Notional

  Rate Received Rate Paid Expiration
(Millions)       

$100

  Three Month LIBOR 0.92% December 2016

$100

  1.76% Three Month LIBOR January 2019

$750

  Three Month LIBOR 2.98% December 2048 (1)

Notional

 

 

Rate Received

 

 

Rate Paid

 

Expiration

$

100

 

 

1.76%

 

 

Three Month LIBOR

 

January 2019

 

(1)Mandatory settlement in December 2018.

Foreign Currency Derivatives

As of December 31, 2015, Devon had the following open foreign currencyIn January 2019, this interest rate derivative position:position settled.

 

Forward Contract

Currency

  Contract
Type
  CAD
Notional
  Weighted Average
Fixed Rate  Received
  Expiration
      (Millions)  (CAD-USD)   

Canadian Dollar

  Sell  $3,560  0.723  March 2016

Financial Statement Presentation

The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption.

 

  Year Ended December 31, 
  2015   2014   2013 

 

Year Ended December 31,

 

  (Millions) 

 

2018

 

 

2017

 

 

2016

 

Commodity derivatives:

      

 

 

 

 

 

��

 

 

 

 

 

 

Oil, gas and NGL derivatives

  $503    $1,989    $(191

Marketing and midstream revenues

   9     22     —    

Upstream revenues

 

$

608

 

 

$

157

 

 

$

(201

)

Marketing revenues

 

 

(1

)

 

 

3

 

 

 

(2

)

Interest rate derivatives:

      

 

 

 

 

 

 

 

 

 

 

 

 

Other nonoperating items

   (20   (1   —    

Other expenses

 

 

65

 

 

 

(22

)

 

 

(19

)

Foreign currency derivatives:

      

 

 

 

 

 

 

 

 

 

 

 

 

Other nonoperating items

   246     60     56  
  

 

   

 

   

 

 

Other expenses

 

 

 

 

 

 

 

 

(153

)

Net gains (losses) recognized

  $738    $2,070    $(135

 

$

672

 

 

$

138

 

 

$

(375

)

  

 

   

 

   

 

 

70


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.

 

  December 31,
2015
   December 31,
2014
 
  (Millions) 

 

December 31, 2018

 

 

December 31, 2017

 

Commodity derivative assets:

    

 

 

 

 

 

 

 

 

Derivatives, at fair value

  $34    $1,984  

Other current assets

 

$

637

 

 

$

203

 

Other long-term assets

   1     11  

 

 

40

 

 

 

2

 

Interest rate derivative assets:

    

 

 

 

 

 

 

 

 

Derivatives, at fair value

   1     1  

Other long-term assets

   1     —    

Foreign currency derivative assets:

    

Derivatives, at fair value

   8     8  
  

 

   

 

 

Other current assets

 

 

 

 

 

1

 

Total derivative assets

  $45    $2,004  

 

$

677

 

 

$

206

 

  

 

   

 

 

Commodity derivative liabilities:

    

 

 

 

 

 

 

 

 

Other current liabilities

  $14    $28  

 

$

67

 

 

$

259

 

Other long-term liabilities

   4     28  

 

 

1

 

 

 

27

 

Interest rate derivative liabilities:

    

 

 

 

 

 

 

 

 

Other current liabilities

   —       1  

 

 

 

 

 

64

 

Other long-term liabilities

   22     —    

Foreign currency derivative liabilities:

    

Other current liabilities

   8     —    
  

 

   

 

 

Total derivative liabilities

  $48    $57  

 

$

68

 

 

$

350

 

  

 

   

 

 

 

4.

Share-Based Compensation

In the second quarter of 2015,2017, Devon’s stockholders approved the 2015 Long-Term Incentive2017 Plan. The 20152017 Plan replaces the 2009 Long-Term Incentive Plan, as amended.2015 Plan. From the effective date of the 20152017 Plan, no further awards may be made under the 20092015 Plan, and awards previously granted will continue to be governed by the terms of the 2009 Plan.respective award documents. Subject to the terms of the 20152017 Plan, awards may be made under the 2015 Plan for a total of 2833.5 million shares of Devon common stock, plus the number of shares available for issuance under the 20092015 Plan (including shares subject to outstanding awards underthat were transferred to the 20092017 Plan that are subsequently forfeited, canceled or expire)in accordance with its terms). The 20152017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance awards or units and stock appreciation rights to eligible employees. The 20152017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 20152017 Plan, options and stock appreciation rights represent one share and other awards represent three2.3 shares.

Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.

Devon did not have an annual long-term incentive grant in 2013 due to revisions in the timing of the employee compensation cycle. The annual long-term incentive grant related to 2013 performance was granted in February 2014.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the effects of share-based compensation included in Devon’s accompanying consolidated comprehensive statements of earnings. Gross G&A for the years ended December 31, 2015 and 2014 includes $31 million and $17 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.

The vesting for certain share-based awards was accelerated in 20142018 and 2016 in conjunction with the divestiturereduction of Devon’s Canadian conventional assets. For the year ended December 31, 2014, approximately $15 million of associated expense for these accelerated awardsworkforce activities described in Note 6 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.

 

   Year Ended December 31, 
   2015   2014   2013 
   (Millions) 

Gross general and administrative expense for share-based compensation

  $225    $199    $157  

Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties

  $63    $53    $60  

Related income tax benefit

  $45    $42    $29  

The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings.

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

G&A

 

$

122

 

 

$

141

 

 

$

124

 

Exploration expenses

 

 

4

 

 

 

7

 

 

 

6

 

Restructuring and transaction costs

 

 

31

 

 

 

 

 

 

60

 

Total

 

$

157

 

 

$

148

 

 

$

190

 

Related income tax benefit

 

$

22

 

 

$

6

 

 

$

6

 

71


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plans.

 

 

Restricted Stock

 

 

Performance-Based

 

 

Performance

 

  Restricted Stock
Awards and Units
   Performance-Based
Restricted Stock Awards
   Performance Share
Units
 

 

Awards and Units

 

 

Restricted Stock Awards

 

 

Share Units

 

  Awards
and
Units
 Weighted
Average
Grant-Date
Fair Value
   Awards Weighted
Average
Grant-Date
Fair Value
   Units Weighted
Average
Grant-Date
Fair Value
 

 

Awards and

Units

 

 

Weighted

Average

Grant-Date

Fair Value

 

 

Awards

 

 

Weighted

Average

Grant-Date

Fair Value

 

 

Units

 

 

 

 

Weighted

Average

Grant-Date

Fair Value

 

  (Thousands, except fair value data) 

 

(Thousands, except fair value data)

 

Unvested at 12/31/14

   4,304   $60.85     380   $59.41     1,477   $70.90  

Unvested at 12/31/17

 

 

6,328

 

 

$

36.81

 

 

 

575

 

 

$

38.92

 

 

 

2,758

 

 

 

$

41.21

 

Granted

   2,771   $63.57     236   $62.02     786   $84.14  

 

 

3,592

 

 

$

35.98

 

 

 

 

 

$

 

 

 

845

 

 

 

$

37.40

 

Vested

   (1,834 $60.33     (153 $59.49     (337 $66.00  

 

 

(3,114

)

 

$

38.75

 

 

 

(273

)

 

$

42.22

 

 

 

(571

)

 

 

$

84.22

 

Forfeited

   (503 $62.22     (29 $64.18     (67 $79.20  

 

 

(843

)

 

$

35.58

 

 

 

 

 

$

 

 

 

(164

)

 

 

$

33.92

 

  

 

    

 

    

 

  

Unvested at 12/31/15

   4,738   $62.49     434   $60.48     1,859(1)  $76.17  
  

 

    

 

    

 

  

Unvested at 12/31/18

 

 

5,963

 

 

$

35.47

 

 

 

302

 

 

$

35.93

 

 

 

2,868

 

 

(1

)

 

$

30.14

 

 

(1)

A maximum of 3.75.7 million common shares could be awarded based upon Devon’s final TSR ranking.

The following table presents the aggregate fair value of awards and units that vested during the indicated period.

 

   2015   2014   2013 
   (Millions) 

Restricted stock awards and units

  $101    $112    $141  

Performance-based restricted stock awards

  $8    $10    $5  

Performance share units

  $22    $—      $—    

 

 

2018

 

 

2017

 

 

2016

 

Restricted Stock Awards and Units

 

$

111

 

 

$

105

 

 

$

73

 

Performance-Based Restricted Stock Awards

 

$

10

 

 

$

10

 

 

$

5

 

Performance Share Units

 

$

20

 

 

$

38

 

 

$

13

 

The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2015.2018.

 

  Restricted Stock
Awards and Units
  Performance-Based
Restricted Stock
Awards
  Performance
Share Units
 

Unrecognized compensation cost (millions)

 $198   $6   $45  

Weighted average period for recognition (years)

  2.5    2.6    1.8  

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

 

 

 

 

 

Performance-Based

 

 

 

 

 

 

 

Restricted Stock

 

 

Restricted Stock

 

 

Performance

 

 

 

Awards and Units

 

 

Awards

 

 

Share Units

 

Unrecognized compensation cost

 

$

117

 

 

$

1

 

 

$

23

 

Weighted average period for recognition (years)

 

 

2.4

 

 

 

1.0

 

 

 

1.7

 

 

Restricted Stock Awards and Units

Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zeroone to four years. During the vesting period, recipients of restricted stock awards made under the 2015 Plan or 2009 Plan receive dividends that are not subject to restrictions or other limitations. However, dividends declared during the vesting period with respect to restricted stock awards made under the 2017 Plan and all restricted stock units will not be paid until the underlying award vests. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period.

72


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards arewere granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zeroone to four years. In order for awards to vest, the performance target must be met in the first year, and ifyear. If the performance target is met, recipients arethe recipient is entitled to dividends onunder the awards over the remaining service vesting period.same terms described above for nonperformance-based restricted stock. If the performance target and service period requirements are not met, the award does not vest. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period.

Performance Share Units

Performance share units are granted to certain members of Devon’s management and senior management.employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200% of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.

At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted.

 

  2015  2014  2013

 

2018

 

 

2017

 

 

2016

 

Grant-date fair value

  $81.99 – $85.05  $70.18 – $81.05  $61.27 – $63.48

 

 

$36.23

 

 

 

$

37.88

 

 

 

$51.05

 

 

 

 

$53.12

 

 

 

$9.24

 

 

 

 

$10.61

 

Risk-free interest rate

  1.06%  0.54%  0.26% – 0.36%

 

2.28%

 

 

1.50%

 

 

0.94%

 

Volatility factor

  26.2%  28.8%  30.3%

 

45.8%

 

 

45.8%

 

 

37.7%

 

Contractual term (years)

  2.89  2.89  3.0

 

2.89

 

 

2.89

 

 

2.83

 

Stock Options

In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zeroone to four years. The fair value of stock options on

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions, including a volatility factor, dividend yield rate, risk-free interest rate and expected term. No stock options were granted in 2015, 20142018, 2017 and 2013.2016. The following table presents a summary of Devon’s outstanding stock options.

 

 

 

 

 

 

Weighted Average

 

 

 

 

 

 

 

Options

 

 

Exercise Price

 

 

Remaining Term

 

 

Intrinsic Value

 

 

 

(Thousands)

 

 

 

 

 

 

(Years)

 

 

 

 

 

Outstanding at December 31, 2017

 

 

1,746

 

 

$

70.04

 

 

 

 

 

 

 

 

 

Expired

 

 

(1,029

)

 

$

72.51

 

 

 

 

 

 

 

 

 

Outstanding at December 31, 2018

 

 

717

 

 

$

66.49

 

 

 

0.87

 

 

$

 

Exercisable at December 31, 2018

 

 

717

 

 

$

66.49

 

 

 

0.87

 

 

$

 

73


Table of Contents

 

      Weighted Average     
   Options  Exercise
Price
   Remaining
Term
   Intrinsic
Value
 
   (Thousands)      (Years)   (Millions) 

Outstanding at December 31, 2014

   4,218   $70.56      

Granted

   —     $—        

Exercised

   (63 $64.25      

Expired

   (680 $84.36      

Forfeited

   (27 $66.71      
  

 

 

      

Outstanding at December 31, 2015

   3,448   $67.98     2.41    $—    
  

 

 

      

Vested and expected to vest at December 31, 2015

   3,448   $67.98     2.41    $—    
  

 

 

      

Exercisable at December 31, 2015

   3,448   $67.98     2.41    $—    
  

 

 

      

The aggregate intrinsic value of stock options that were exercised during 2015, 2014 and 2013 was $0.2 million, $9 million and $0.3 million, respectively. Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2015,2018, Devon had no unrecognized compensation cost related to unvested stock options.

EnLink Share-Based Awards

In March 2015, the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees for 2014. The combined grant fair value was $7 million, and the total cost was recognized in the first quarter of 2015 due to the awards vesting immediately.

5.

Asset Impairments

The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units asconsolidated comprehensive statements of December 31, 2015.earnings.

 

   General Partner   EnLink 
   Restricted
Incentive Units
   Performance
Units
   Restricted
Incentive Units
   Performance
Units
 

Unrecognized compensation cost (millions)

  $17    $3    $16    $3  

Weighted average period for recognition (years)

   1.6     2.0     1.6     2.0  

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Proved oil and gas assets

 

$

109

 

 

$

 

 

$

435

 

Other assets

 

 

47

 

 

 

 

 

 

2

 

Total asset impairments

 

$

156

 

 

$

 

 

$

437

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unproved impairments

 

$

95

 

 

$

217

 

 

$

77

 

Proved Oil and Gas and Other Asset Impairments

In 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and approximately $47 million of non-oil and gas asset impairments.

In 2016, Devon impaired a portion of its U.S. oil and gas portfolio due to lower forecasted oil, gas and NGL prices.

UnprovedImpairments

In 2018, 2017 and 2016, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments.

6.

Restructuring and Transaction Costs

The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets.

 

 

Other

 

 

Other

 

 

 

 

 

 

 

Current

 

 

Long-term

 

 

 

 

 

 

 

Liabilities

 

 

Liabilities

 

 

Total

 

Balance as of December 31, 2016

 

$

48

 

 

$

62

 

 

$

110

 

Changes related to prior years’ restructurings

 

 

(29

)

 

 

(31

)

 

 

(60

)

Balance as of December 31, 2017

 

$

19

 

 

$

31

 

 

$

50

 

Changes due to 2018 workforce reductions

 

 

30

 

 

 

 

 

 

30

 

Changes related to prior years’ restructurings

 

 

(2

)

 

 

(15

)

 

 

(17

)

Balance as of December 31, 2018

 

$

47

 

 

$

16

 

 

$

63

 

74


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

5.Asset Impairments

The following table presents the asset impairments recognized in 2015, 2014 and 2013.

   Year Ended December 31, 
   2015   2014   2013 
   (Millions) 

U.S. oil and gas assets

  $17,992    $—      $1,110  

Canada oil and gas assets

   1,257     —       843  

Canada goodwill

   —       1,941     —    

EnLink goodwill

   1,328     —       —    

EnLink other intangible assets

   223     —       —    

Other assets

   20     12     23  
  

 

 

   

 

 

   

 

 

 

Total asset impairments

  $20,820    $1,953    $1,976  
  

 

 

   

 

 

   

 

 

 

Oil and Gas Impairments

Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.

The oil and gas impairments resulted from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, natural gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves. For further information, see Note 21.

Goodwill and Other Intangible Assets Impairments2018 Workforce Reductions

In 2015,2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized goodwill and other intangible asset impairments related to EnLink’s business. In 2014, Devon recognized a goodwill impairment related to its Canadian reporting unit. Additional information regarding these impairments is discussed in Note 12.

6.Restructuring Costs

Canadian Reduction in Work Force

In 2015, Devon recognized $24$114 million of employee related and other costs associated with the reduction in work force made subsequent to the completionrestructuring expenses during 2018, primarily consisting of the Jackfish development projects and a decrease in planned capital investment resulting from the drop in commodity prices. Devon incurred employee severance, lease obligation and other costs related to the vacated office space as part of the cost reduction plan.

Canadian Divestitures

During 2014, Devon recognized $46employee-related costs. Of these expenses, $31 million of employee related and other costs associated with its divestiture of certain Canadian assets. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are noncash charges.

Office Consolidation

Near the end Additionally, $14 million resulted from estimated settlements of 2012, Devon consolidated its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon closed its office in Houston,

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)defined retirement benefits.

 

transferred operational responsibilities for assetsPrior Years’ Restructurings

In 2016, Devon recognized $227 million in south Texas, east Texasemployee-related and Louisiana to Oklahoma City and incurred $134 million of restructuringother costs associated with a reduction in workforce that was made in response to the consolidation. The employee severance and retentiondepressed commodity price environment. Of these employee-related costs, included amounts related to cash severance costs andapproximately $60 million resulted from accelerated vesting of share-based grants. The lease obligations and other costsgrants, which are associated withnoncash charges. Additionally, approximately $24 million resulted from estimated defined benefit settlements.

As a result of the reduction of workforce, Devon ceased using certain office space that iswas subject to non-cancellable operating lease agreementsarrangements. Devon recognized $23 million in restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using.

Transaction Costs

In 2016, Devon ceased using as partrecognized $11 million in transaction costs primarily associated with the closing of the office consolidation.STACK acquisition discussed in Note 2.

Due to a lack of demand for vacated office space in which Devon’s remaining leases are located, in 2015, Devon recognized an additional $54 million expense as a result of its inability to fully sublease remaining office space.

Financial Statement Presentation

7.

Other Expenses

The following table summarizes restructuring costsDevon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings.

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Foreign exchange (gain) loss, net

 

$

139

 

 

$

(132

)

 

$

39

 

Asset retirement obligation accretion

 

 

59

 

 

 

62

 

 

 

75

 

Other, net

 

 

(58

)

 

 

(13

)

 

 

(13

)

Total

 

$

140

 

 

$

(83

)

 

$

101

 

 

   Year Ended December 31, 
     2015       2014       2013   
   (Millions) 

Office consolidation and offshore divestiture:

      

Employee severance and retention

  $—      $—      $13  

Lease obligations and other

   54     —       41  

Canada divestitures:

      

Employee severance and retention

   11     42     —    

Lease obligations and other

   13     4     —    
  

 

 

   

 

 

   

 

 

 

Restructuring costs

  $78    $46    $54  
  

 

 

   

 

 

   

 

 

 

The following table summarizes Devon’s restructuring liabilities.Foreign exchange (gain) loss, net

 

  Other
Current
Liabilities
  Other
Long-term
Liabilities
  Total 
  (Millions) 

Balance as of December 31, 2013

 $27   $18   $45  

Changes due to office consolidation and offshore divestiture

  (18  (11  (29

Changes due to Canadian divestitures

  4    —      4  
 

 

 

  

 

 

  

 

 

 

Balance as of December 31, 2014

  13    7    20  

Changes due to office consolidation and offshore divestiture

  1    46    47  

Changes due to Canadian divestitures

  (1  10    9  
 

 

 

  

 

 

  

 

 

 

Balance as of December 31, 2015

 $13   $63   $76  
 

 

 

  

 

 

  

 

 

 

The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. The amounts in the table above include both unrealized and realized foreign exchange impacts of foreign currency denominated monetary assets and liabilities, including intercompany loans between subsidiaries with different functional currencies. Unrealized gains and losses arise from the remeasurement of these foreign currency denominated monetary assets and liabilities and intercompany loans. Realized gains and losses arise when there are settlements of these foreign currency denominated monetary assets and liabilities and intercompany loans.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Foreign currency denominated intercompany loan activity during 2018 resulted in a realized loss of $241 million, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. These losses during 2018, were partially offset by reversing $195 million of previously recognized unrealized losses on intercompany loan activity.

Foreign currency denominated intercompany loan activity during 2016 resulted in a realized gain of $63 million, as a result of the weakening of the U.S. dollar in relation to the Canadian dollar. These gains during 2016, were partially offset by reversing $10 million of previously recognized unrealized gains on intercompany loan activity.

7.

8.

Income Taxes

Income Tax Expense (Benefit)

The following table presents Devon’s income tax components.

 

  Year Ended December 31, 
  2015   2014   2013 

 

Year Ended December 31,

 

  (Millions) 

 

2018

 

 

2017

 

 

2016

 

Current income tax expense (benefit):

      

 

 

 

 

 

 

 

 

 

 

 

 

U.S. federal

  $(243  $152    $73  

 

$

(14

)

 

$

9

 

 

$

3

 

Various states

   (8   18     (5

 

 

(3

)

 

 

 

 

 

(11

)

Canada and various provinces

   14     307     4  

 

 

(53

)

 

 

103

 

 

 

106

 

  

 

   

 

   

 

 

Total current tax expense (benefit)

   (237   477     72  

 

 

(70

)

 

 

112

 

 

 

98

 

  

 

   

 

   

 

 

Deferred income tax expense (benefit):

      

 

 

 

 

 

 

 

 

 

 

 

 

U.S. federal

   (5,033   1,610     198  

 

 

248

 

 

 

 

 

 

 

Various states

   (336   93     59  

 

 

63

 

 

 

 

 

 

 

Canada and various provinces

   (459   188     (160

 

 

(85

)

 

 

(97

)

 

 

43

 

  

 

   

 

   

 

 

Total deferred tax expense (benefit)

   (5,828   1,891     97  

 

 

226

 

 

 

(97

)

 

 

43

 

  

 

   

 

   

 

 

Total income tax expense (benefit)

  $(6,065  $2,368    $169  
  

 

   

 

   

 

 

Total income tax expense

 

$

156

 

 

$

15

 

 

$

141

 

Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following:

 

 

Year Ended December 31,

 

  Year Ended December 31, 

 

2018

 

 

2017

 

 

2016

 

  2015 2014 2013 

Total income tax expense (benefit) (millions)

  $(6,065 $2,368   $169  

Current income tax expense (benefit)

 

$

(70

)

 

$

112

 

 

$

98

 

Deferred income tax expense (benefit)

 

 

226

 

 

 

(97

)

 

 

43

 

Total income tax expense

 

$

156

 

 

$

15

 

 

$

141

 

  

 

  

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. statutory income tax rate

   (35)%   35  35

 

 

21

%

 

 

35

%

 

 

35

%

Non-deductible goodwill and intangible impairment

   2  23  0

Taxation on Canadian operations

   1  (4)%   9

U.S. Tax Reform

 

 

0

%

 

 

36

%

 

 

0

%

Legal entity restructuring

 

 

2

%

 

 

(94

%)

 

 

19

%

State income taxes

   (1)%   2  23

 

 

5

%

 

 

0

%

 

 

10

%

Repatriations

   0  2  65

Change in unrecognized tax benefits

 

 

(5

%)

 

 

2

%

 

 

(16

%)

Other

 

 

(0

%)

 

 

(13

%)

 

 

8

%

Deferred tax asset valuation allowance

   4  0  0

 

 

(6

%)

 

 

36

%

 

 

(89

%)

Other

   0  0  (19)% 
  

 

  

 

  

 

 

Effective income tax rate

   (29)%   58  113

 

 

17

%

 

 

2

%

 

 

(33

%)

  

 

  

 

  

 

 

Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examinationexaminations by the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business.

Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

allowance. Numerous judgementsjudgments and assumptions are inherent in the determination of future taxable income, including factors such as future operationoperating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

2015

2018

In the thirdsecond quarter of 2018, Devon’s Canadian segment utilized a portion of its capital losses as a part of an internal legal entity restructuring. A valuation allowance remains recorded against the remaining balance of the capital losses.

During 2018, Devon recorded a tax benefit of $42 million related to unrecognized tax benefits, primarily as a result of a favorable Canadian court decision and fourththe closure of prior year IRS audits.

Throughout 2017 and through the first two quarters of 2015,2018, Devon’s U.S. segment maintained a 100% valuation allowance against its U.S. deferred tax assets. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period projected net operating loss utilization, and projections of future taxable income, Devon reassessed its position and determined that its U.S. segment is no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses. As part of its reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon’s U.S. segment would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the $259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations. A partial valuation allowance continues to be held against certain Canadian segment deferred tax assets. During 2018, the Canadian segment reduced its valuation allowance by approximately $59 million.  

2017

The Tax Reform Legislation, enacted on December 22, 2017, contained several key tax provisions that affected Devon, including a one-time mandatory transition tax on accumulated foreign earnings and a reduction of the corporate income tax rate to 21% effective January 1, 2018. Devon was required to recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax, remeasuring U.S. deferred tax assets and liabilities and reassessing the net realizability of deferred tax assets and liabilities. Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings, and $108 million in deferred tax expense related to the reduction of the U.S. corporate income tax rate to 21%.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In the fourth quarter of 2017, Devon’s Canadian segment generated nonrecurring capital losses from internal legal entity restructuring. A deferred tax asset of $727 million was recognized related to the capital losses, offset by a $641 million increase in the valuation allowance.

Devon maintained a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to asset impairments and significant net operating losses for U.S. federal and state income tax. Devon reduced its U.S. segment valuation allowance by $323 million in 2017 based primarily on the financial income recorded during the period. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.

Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in 2017 due to lower relative earnings during the period.

2016

Devon recorded a tax expense of $63 million related to unrecognized tax benefits during 2016, primarily as a result of Canadian audits and legal proceedings.

During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its deferred tax assets. The allowance resulted from continued financial losses in 2016. As of December 31, 2016, the allowance continued to represent a 100% valuation against the U.S. net deferred tax assets. Additionally, the Canadian segment recognized a $71 million partial valuation allowance resulting from continued financial losses.   

During the third quarter of 2016, Devon derecognized $83 million of goodwill related to its U.S. operations in conjunction with the divestiture of certain non-core U.S. upstream oil and intangibles impairments of approximately $1.6 billion. gas assets. These impairments areitems were not deductible for purposes of calculating income tax and, therefore, have an impact onimpacted the effective tax rate.

During 2015, Devon recorded approximately $18 billion78


Table of oil and gas impairments relatedContents

Index to its U.S. operations. These impairments resulted in deferred tax assets against which we recognized a $967 million valuation allowance that impacted the effective tax rate and is discussed in the next section.Financial Statements

2014

In the second and fourth quarters of 2014, goodwill was removed in conjunction with the Canadian conventional asset divestitures, and Devon recorded a goodwill impairment in the Canadian reporting unit, respectively. These transactions are not deductible for purposes of calculating income tax and therefore have an impact on the effective tax rate.

Additionally, during 2014, Devon repatriated to the U.S. $2.8 billion of cash relating to the Canadian asset divestiture. In conjunction with the repatriation, Devon recognized approximately $105 million of additional income tax expense for the full year. Prior to the repatriation, Devon had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, Devon retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax. After the use of foreign tax credits, the current income tax on the repatriation was $67 million.

Furthermore, Devon completed its divestiture program of certain assets in the U.S. In conjunction with the divestiture closing and due to the availability of additional tax deductions, Devon recognized $294 million of current income tax expense. The current tax expense was entirely offset by the recognition of deferred tax benefits.

Devon also recorded a $46 million deferred tax liability in conjunction with the formation of EnLink in 2014.

2013

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Deferred Tax Assets and Liabilities

The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities.

 

 December 31, 
 2015 2014 

 

December 31,

 

 (Millions) 

 

2018

 

 

2017

 

Deferred tax assets:

  

 

 

 

 

 

 

 

 

Property and equipment

 $490   $—    

Asset retirement obligations

  485    458  

 

$

300

 

 

$

313

 

Accrued liabilities

  160    150  

 

 

50

 

 

 

62

 

Net operating loss carryforwards

  175    200  

 

 

287

 

 

 

796

 

Pension benefit obligations

  106    113  

 

 

44

 

 

 

54

 

Canadian capital loss carryforwards

 

 

609

 

 

 

760

 

Other

  162    180  

 

 

87

 

 

 

135

 

 

 

  

 

 

Total deferred tax assets before valuation allowance

  1,578    1,101  

 

 

1,377

 

 

 

2,120

 

Less: valuation allowance

  (967  —    

 

 

(640

)

 

 

(968

)

 

 

  

 

 

Net deferred tax assets

  611    1,101  

 

 

737

 

 

 

1,152

 

 

 

  

 

 

Deferred tax liabilities:

  

 

 

 

 

 

 

 

 

Property and equipment

  (1,187  (6,940

 

 

(1,473

)

 

 

(1,288

)

Fair value of financial instruments

  —      (699

Long-term debt

  (36  (115

 

 

 

 

 

(92

)

Other

  (271  (160

 

 

(141

)

 

 

(261

)

 

 

  

 

 

Total deferred tax liabilities

  (1,494  (7,914

 

 

(1,614

)

 

 

(1,641

)

 

 

  

 

 

Net deferred tax liability

 $(883 $(6,813

 

$

(877

)

 

$

(489

)

 

 

  

 

 

At December 31, 2015,2018, Devon has $175recognized $287 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segment has $595 million of noncapital loss carryforwards expiring between 2029 and 2038. Devon’s U.S. segment has $389 million of U.S. federal net operating loss carryforwards consist of $495 million of Canadian carryforwards that expire between 2030expiring in 2037 and 2035, $275$784 million of U.S. state net operating loss carryforwards that expireexpiring between 20182019 and 2035 and $205 million of carryforwards related to EnLink’s operations that expire between 2028 and 2035.2038. In the current environment, Devon expects the tax benefits from the U.S. federal, majority of U.S. state and Canadian and EnLink net operatingnoncapital loss carryforwards to be utilized in 20172019 and beyond. Devon also has $6 million of deferred tax assets related to alternative minimum tax credits, which have no expiration date and will be available for use against tax on future taxable income.beyond.

At the end of 2015, Devon had deferred tax assets that largely resulted from the full cost impairments recognized during 2015. As a result of Devon’s sale of its aggregate ownership interests in EnLink and the recent cumulative financial losses, Devon recorded a $967General Partner during the third quarter of 2018, Devon’s U.S. segment reassessed its position and released its full valuation allowance position, maintaining only $31 million or 100%,of valuation allowance against the U.S.certain deferred tax assets, asincluding certain tax credits and state net operating losses. Also during 2018, Devon’s Canadian segment maintained a valuation allowance of December 31, 2015.$609 million against the deferred tax asset related to the Canadian capital loss carryforward due to projected lack of future capital gain income. In the event Devon were to determine that it would be able to realize the deferred income tax assets in the future, Devon would adjust the valuation allowance, reducing the provision for income taxes in the period of such adjustment.

AsAfter enactment of the Tax Reform Legislation, Devon’s Canadian segment is the sole foreign operation to be considered for the indefinitely reinvested assertion of APB 23. Devon’s Canadian operations are robust and active and requires continuing capital investment. Accordingly, as of December 31, 2015,2018, no income taxes should be accrued by Devon relative to its investment in its Canadian operations. In view of Devon’s unremitted foreign earnings from its other international operations totaled approximately $1.2 billion. All but $37 milliondecision in February 2019 to dispose of the $1.2 billion was deemed to beCanadian business, the indefinitely reinvested into the developmentassertion of APB 23 and growthany required accrual of Devon’s Canadian business. Therefore, Devon has not recognized a deferredincome tax liability for U.S. income taxes associated with such earnings. If such earnings werewill be reevaluated in 2019.

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Index to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.

Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

For the remaining $37 million of unremitted earnings deemed not to be indefinitely reinvested, Devon has recognized a $10 million deferred tax liability associated with such unremitted earnings as of December 31, 2015.

Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits.

 

  December 31, 
  2015   2014 

 

December 31,

 

  (Millions) 

 

2018

 

 

2017

 

Balance at beginning of year

  $241    $243  

 

$

115

 

 

$

202

 

Tax positions taken in prior periods

   (19   —    

 

 

(43

)

 

 

(7

)

Tax positions taken in current year

   31     —    

 

 

(2

)

 

 

(3

)

Accrual of interest related to tax positions taken

   (5   2  

 

 

3

 

 

 

16

 

Settlements

   (108   —    

 

 

 

 

 

(101

)

Foreign currency translation

   (9   (4

 

 

(3

)

 

 

8

 

  

 

   

 

 

Balance at end of year

  $131    $241  

 

$

70

 

 

$

115

 

  

 

   

 

 

Devon’s unrecognized tax benefit balance at December 31, 20152018 and 20142017 included $29$12 million and $34$28 million, respectively, of interest and penalties. If recognized, $131$70 million of Devon’s unrecognized tax benefits as of December 31, 20152018 would affect Devon’s effective income tax rate.During 2018, Devon removed $43 million of unrecognized tax benefits, including $20 million of interest, as a result of the closure of certain tax examinations. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.

 

Jurisdiction

Tax Years Open

U.S. Federal

2008-2015

2015-2018

Various U.S. states

2008-2015

2014-2018

Canada Federal

2003-2015

2004-2018

Various Canadian provinces

2003-2015

2004-2018

Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process.  As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

8.

9.

Net Earnings (Loss) Per Share Attributable to Devonfrom Continuing Operations

The following table reconciles net earnings (loss) attributable to Devonfrom continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.share from continuing operations.

 

 

Year Ended December 31,

 

  Year Ended December 31, 

 

2018

 

 

2017

 

 

2016

 

      2015         2014         2013     
  (Millions, except per share amounts) 

Net earnings (loss):

    

Net earnings (loss) attributable to Devon

  $(14,454 $1,607   $(20

Net earnings (loss) from continuing operations:

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss) from continuing operations

 

$

764

 

 

$

758

 

 

$

(574

)

Attributable to participating securities

   (5  (17  (2

 

 

(9

)

 

 

(8

)

 

 

(2

)

  

 

  

 

  

 

 

Basic and diluted earnings (loss)

  $(14,459 $1,590   $(22
  

 

  

 

  

 

 

Basic and diluted earnings (loss) from continuing operations

 

$

755

 

 

$

750

 

 

$

(576

)

Common shares:

    

 

 

 

 

 

 

 

 

 

 

 

 

Common shares outstanding - total

   412    409    406  

 

 

499

 

 

 

525

 

 

 

513

 

Attributable to participating securities

   (5  (4  (4

 

 

(5

)

 

 

(5

)

 

 

(6

)

  

 

  

 

  

 

 

Common shares outstanding - basic

   407    405    402  

 

 

494

 

 

 

520

 

 

 

507

 

Dilutive effect of potential common shares issuable

   —      2    —    

 

 

3

 

 

 

3

 

 

 

 

  

 

  

 

  

 

 

Common shares outstanding - diluted

   407    407    402  

 

 

497

 

 

 

523

 

 

 

507

 

  

 

  

 

  

 

 

Net earnings (loss) per share attributable to Devon:

    

Net earnings (loss) per share from continuing operations:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

  $(35.55 $3.93   $(0.06

 

$

1.53

 

 

$

1.44

 

 

$

(1.14

)

Diluted

  $(35.55 $3.91   $(0.06

 

$

1.52

 

 

$

1.43

 

 

$

(1.14

)

Antidilutive options (1)

   4    3    7  

 

 

1

 

 

 

2

 

 

 

3

 

 

(1)

Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.

 

9.

10.

Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

 

  Year Ended December 31, 
  2015 2014 2013 

 

Year Ended December 31,

 

  (Millions) 

 

2018

 

 

2017

 

 

2016

 

Foreign currency translation:

    

 

 

 

 

 

 

 

 

 

 

 

 

Beginning accumulated foreign currency translation

  $983   $1,448   $1,996  

 

$

1,309

 

 

$

1,226

 

 

$

1,215

 

Change in cumulative translation adjustment

   (621  (499  (574

 

 

(166

)

 

 

113

 

 

 

22

 

Income tax benefit

   62    34    26  
  

 

  

 

  

 

 

Income tax benefit (expense)

 

 

14

 

 

 

(30

)

 

 

(11

)

Ending accumulated foreign currency translation

   424    983    1,448  

 

 

1,157

 

 

 

1,309

 

 

 

1,226

 

  

 

  

 

  

 

 

Pension and postretirement benefit plans:

    

 

 

 

 

 

 

 

 

 

 

 

 

Beginning accumulated pension and postretirement benefits

   (204  (180  (225

 

 

(143

)

 

 

(172

)

 

 

(194

)

Net actuarial gain (loss) and prior service cost arising in current year

   (5  (57  48  

Net actuarial loss and prior service cost arising in current year

 

 

(3

)

 

 

10

 

 

 

(28

)

Recognition of net actuarial loss and prior service cost in earnings (1)

   21    20    24  

 

 

12

 

 

 

19

 

 

 

26

 

Income tax benefit (expense)

   (6  13    (27
  

 

  

 

  

 

 

Curtailment and settlement of pension benefits

 

 

47

 

 

 

 

 

 

24

 

Income tax expense

 

 

(12

)

 

 

 

 

 

 

Other (2)

 

 

(33

)

 

 

 

 

 

 

Ending accumulated pension and postretirement benefits

   (194  (204  (180

 

 

(132

)

 

 

(143

)

 

 

(172

)

  

 

  

 

  

 

 

Other

 

 

2

 

 

 

 

 

 

 

Accumulated other comprehensive earnings, net of tax

  $230   $779   $1,268  

 

$

1,027

 

 

$

1,166

 

 

$

1,054

 

  

 

  

 

  

 

 

 

(1)

These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A onother expenses in the accompanying consolidated comprehensive statements of earnings. See Note 1517 for additional details.

81


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

10.

(2)

As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1 for additional details.

11.

Supplemental Information to Statements of Cash Flows

 

 

Year Ended December 31,

 

  Year Ended December 31, 

 

2018

 

 

2017

 

 

2016

 

  2015   2014   2013 
  (Millions) 

Net change in working capital accounts:

      

Changes in assets and liabilities, net

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

  $942    $128    $(288

 

$

88

 

 

$

(94

)

 

$

(58

)

Income taxes receivable

   384     (467   29  

Other current assets

   (57   (222   20  

 

 

(128

)

 

 

20

 

 

 

326

 

Other long-term assets

 

 

(28

)

 

 

(47

)

 

 

36

 

Accounts payable

   (190   (68   26  

 

 

 

 

 

113

 

 

 

(196

)

Revenues and royalties payable

   (526   133     35  

 

 

153

 

 

 

106

 

 

 

(26

)

Income taxes payable

   (275   30     —    

Other current liabilities

   (579   516     (120

 

 

(150

)

 

 

(53

)

 

 

(74

)

  

 

   

 

   

 

 

Net change in working capital

  $(301  $50    $(298
  

 

   

 

   

 

 

Other long-term liabilities

 

 

(78

)

 

 

(13

)

 

 

16

 

Total

 

$

(143

)

 

$

32

 

 

$

24

 

Supplementary cash flow data - total operations:

 

 

 

 

 

 

 

 

 

 

 

 

Interest paid (net of capitalized interest)

  $494    $514    $406  

 

$

385

 

 

$

481

 

 

$

569

 

Income taxes paid (received)

  $(279  $899    $13  

 

$

40

 

 

$

78

 

 

$

(159

)

On March 7, 2014, Devon completed a business combination to form EnLink. With the exception of a $100 million cash payment to noncontrolling interests, the business combination was a non-monetary transaction. EnLink’s noncash acquisition activity during 2015 included a portion of the Coronado transaction.

As discussed in Note 2,In 2016, Devon’s acquisition of certain Powder RiverSTACK assets included the noncash issuance of Devon common stock. See Note 2 for additional details. Further, in 2016, EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets included noncash issuance of General Partner common stock issuance totaling $199 million.units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions.  

 

11.

12.

Accounts Receivable

Components of accounts receivable include the following:

 

 December 31, 2015   December 31, 2014 
 (Millions) 

 

December 31, 2018

 

 

December 31, 2017

 

Oil, gas and NGL sales

 $362    $723  

 

$

430

 

 

$

559

 

Joint interest billings

  211     475  

 

 

155

 

 

 

134

 

Marketing and midstream revenues

  520     706  

Marketing revenues

 

 

285

 

 

 

278

 

Other

  30     71  

 

 

23

 

 

 

29

 

 

 

   

 

 

Gross accounts receivable

  1,123     1,975  

 

 

893

 

 

 

1,000

 

Allowance for doubtful accounts

  (18   (16

 

 

(8

)

 

 

(11

)

 

 

   

 

 

Net accounts receivable

 $1,105    $1,959  

 

$

885

 

 

$

989

 

 

 

   

 

 

82


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

12.Goodwill and Other Intangible Assets

Goodwill13.Property, Plant and Equipment

Capitalized Costs

The following table presents a summary ofreflects the aggregate capitalized costs related to Devon’s goodwill.oil and gas and non-oil and gas activities.

 

   U.S.   Canada   EnLink   Total 
   (Millions) 

Balance as of December 31, 2013

  $2,618    $2,838    $402    $5,858  

Acquired during period

   —       —       3,283     3,283  

Asset divestitures

   —       (706   —       (706

Impairment

   —       (1,941   —       (1,941

Foreign currency translation adjustments

   —       (191   —       (191
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2014

  $2,618    $—      $3,685    $6,303  

Acquired during period

   —       —       57     57  

Impairment

   —       —       (1,328   (1,328
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2015

  $2,618    $—      $2,414    $5,032  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

 

December 31, 2018

 

 

 

U.S.

 

 

Canada

 

 

Total

 

Property and equipment:

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

$

40,378

 

 

$

6,427

 

 

$

46,805

 

Unproved and properties under development

 

 

833

 

 

 

1,434

 

 

 

2,267

 

Total oil and gas

 

 

41,211

 

 

 

7,861

 

 

 

49,072

 

Less accumulated DD&A

 

 

(32,229

)

 

 

(4,030

)

 

 

(36,259

)

Oil and gas property and equipment, net

 

$

8,982

 

 

$

3,831

 

 

$

12,813

 

Other property and equipment

 

 

 

 

 

 

 

 

 

 

1,832

 

Less accumulated DD&A

 

 

 

 

 

 

 

 

 

 

(710

)

Other property and equipment, net

 

 

 

 

 

 

 

 

 

 

1,122

 

Property and equipment, net

 

 

 

 

 

 

 

 

 

$

13,935

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

U.S.

 

 

Canada

 

 

Total

 

Property and equipment:

 

 

 

 

 

 

 

 

 

 

 

 

Proved

 

$

40,491

 

 

$

6,804

 

 

$

47,295

 

Unproved and properties under development

 

 

984

 

 

 

1,473

 

 

 

2,457

 

Total oil and gas

 

 

41,475

 

 

 

8,277

 

 

 

49,752

 

Less accumulated DD&A

 

 

(32,379

)

 

 

(4,055

)

 

 

(36,434

)

Oil and gas property and equipment, net

 

$

9,096

 

 

$

4,222

 

 

$

13,318

 

Other property and equipment

 

 

 

 

 

 

 

 

 

 

1,955

 

Less accumulated DD&A

 

 

 

 

 

 

 

 

 

 

(689

)

Other property and equipment, net

 

 

 

 

 

 

 

 

 

 

1,266

 

Property and equipment, net

 

 

 

 

 

 

 

 

 

$

14,584

 

Suspended Exploratory Well Costs

The following table presentssummarizes the General Partner’s and EnLink’s goodwill activity by reporting unit.changes in suspended exploratory well costs for the three years ended December 31, 2018.

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Beginning balance

 

$

313

 

 

$

261

 

 

$

225

 

Additions pending determination of proved reserves

 

 

672

 

 

 

504

 

 

 

247

 

Charges to exploration expense

 

 

 

 

 

 

 

 

(29

)

Reclassifications to proved properties

 

 

(662

)

 

 

(466

)

 

 

(189

)

Foreign currency translation adjustment

 

 

(19

)

 

 

14

 

 

 

7

 

Ending balance

 

$

304

 

 

$

313

 

 

$

261

 

83


Table of Contents

 

   Texas  Louisiana  Oklahoma   Crude and
Condensate
  General
Partner
   Total 
   (Millions) 

Balance as of December 31, 2013

  $326   $—     $76    $—     $—      $402  

Acquired during period

   842    787    114     113    1,427     3,283  
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

   

 

 

 

Balance as of December 31, 2014

  $1,168   $787   $190    $113   $1,427    $3,685  

Acquired during period

   28    —      —       29    —       57  

Impairment

   (492  (787  —       (49  —       (1,328
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

   

 

 

 

Balance as of December 31, 2015

  $704   $—     $190    $93   $1,427    $2,414  
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

   

 

 

 

Acquired During PeriodIndex to Financial Statements

Included in the assets Devon contributed to EMH was $402 million of goodwill. See Note 2 for discussion of acquired goodwill resulting from EnLink’s formation in 2014 and acquisitions in 2015.

Asset Divestitures

In conjunction with the Canadian conventional asset divestitures in 2014, Devon removed $706 million of goodwill, which was allocated to these assets.

Impairment

As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units. Furthermore, due to the continued impact of declining commodity prices and EnLink unit price, an update was performed as of December 31, 2015. As a result of these tests, noncash goodwill impairments were recorded related to EnLink’s Texas, Louisiana and Crude and Condensate reporting units in 2015.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

In the fourth quarter of 2014, as a result of its annual impairment test of goodwill, Devon concluded the implied fair value of its Canadian goodwill was zero and wrote off the remaining goodwill. This conclusion was largely based on the significant decline in benchmark oil prices, particularly after OPEC’s decision not to reduce its production targets that was announced in late November 2014. Devon’s Canadian goodwill was originally recognized in 2001 as a result of a business combination consisting almost entirely of conventional gas assets that Devon no longer owns.

Other Intangible Assets

During 2015, EnLink’s customer relationships were also evaluated for impairment due to the factors in the aforementioned goodwill impairment analysis. 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. This assessment resulted in a $223 million noncash impairment related to EnLink’s Crude and Condensate customer relationships in 2015.

The following table presents other intangible assets reported in other long-term assetsprovides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Exploratory well costs capitalized for a period of one year or less

 

$

110

 

 

$

113

 

 

$

88

 

Exploratory well costs capitalized for a period greater than one year

 

 

194

 

 

 

200

 

 

 

173

 

Ending balance

 

$

304

 

 

$

313

 

 

$

261

 

Number of projects with exploratory well costs capitalized for a

   period greater than one year

 

 

2

 

 

 

2

 

 

 

2

 

Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling relate to Devon’s heavy oil operations. Management believes these projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development. Currently, Devon has not planned additional exploratory work in the accompanying consolidated balance sheets.near future on these assets and will continue to assess its future development timeline of these long cycle projects as it competes for capital allocation within Devon’s portfolio. Devon’s interest in this acreage does not begin to expire until 2025.

 

   December 31, 2015   December 31, 2014 
   (Millions) 

Customer relationships

  $745    $569  

Accumulated amortization

   (55   (36
  

 

 

   

 

 

 

Net intangibles

  $690    $533  
  

 

 

   

 

 

 

14.

Other Current Liabilities

The weighted-average amortization period forComponents of other current liabilities include the customer relationships is 12.6 years. Amortization expense for intangibles was approximately $56 million and $36 million for the years ended December 31, 2015 and December 31, 2014, respectively. The remaining aggregate amortization expense is estimatedfollowing:

 

December 31, 2018

 

 

December 31, 2017

 

Derivative liabilities

$

67

 

 

$

323

 

Accrued interest payable

 

80

 

 

 

96

 

Income taxes payable

 

14

 

 

 

144

 

Restructuring liabilities

 

47

 

 

 

19

 

Other

 

227

 

 

 

246

 

Other current liabilities

$

435

 

 

$

828

 

84


Table of Contents

Index to be approximately $46 million each of the next five years.

Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

13.

15.

Debt and Related Expenses

ASee below for a summary of debt is as follows:instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.  

 

   December 31, 2015   December 31, 2014 
   (Millions) 

Devon debt

    

Commercial paper

  $626    $932  

Floating rate due December 15, 2015

   —       500  

Floating rate due December 15, 2016

   350     350  

8.25% due July 1, 2018

   125     125  

2.25% due December 15, 2018

   750     750  

6.30% due January 15, 2019

   700     700  

4.00% due July 15, 2021

   500     500  

3.25% due May 15, 2022

   1,000     1,000  

5.85% due December 15, 2025

   850     —    

7.50% due September 15, 2027

   150     150  

7.875% due September 30, 2031

   1,250     1,250  

7.95% due April 15, 2032

   1,000     1,000  

5.60% due July 15, 2041

   1,250     1,250  

4.75% due May 15, 2042

   750     750  

5.00% due June 15, 2045

   750     —    

Net discount on debentures and notes

   (28   (18
  

 

 

   

 

 

 

Total Devon debt

   10,023     9,239  
  

 

 

   

 

 

 

EnLink debt

    

Credit facilities

   414     237  

2.70% due April 1, 2019

   400     400  

7.125% due June 1, 2022

   163     163  

4.40% due April 1, 2024

   550     550  

4.15% due June 1, 2025

   750     —    

5.60% due April 1, 2044

   350     350  

5.05% due April 1, 2045

   450     300  

Net premium on debentures and notes

   13     23  
  

 

 

   

 

 

 

Total EnLink debt

   3,090     2,023  
  

 

 

   

 

 

 

Total debt

   13,113     11,262  

Less amount classified as short-term debt (1)

   976     1,432  
  

 

 

   

 

 

 

Total long-term debt

  $12,137    $9,830  
  

 

 

   

 

 

 

 

 

December 31, 2018

 

 

December 31, 2017

 

8.25% due July 1, 2018 (1)

 

$

 

 

$

20

 

2.25% due December 15, 2018

 

 

 

 

 

95

 

6.30% due January 15, 2019

 

 

162

 

 

 

162

 

4.00% due July 15, 2021

 

 

500

 

 

 

500

 

3.25% due May 15, 2022

 

 

1,000

 

 

 

1,000

 

5.85% due December 15, 2025

 

 

485

 

 

 

485

 

7.50% due September 15, 2027 (1)

 

 

73

 

 

 

73

 

7.875% due September 30, 2031 (2) (3)

 

 

675

 

 

 

1,059

 

7.95% due April 15, 2032 (2)

 

 

366

 

 

 

789

 

5.60% due July 15, 2041

 

 

1,250

 

 

 

1,250

 

4.75% due May 15, 2042

 

 

750

 

 

 

750

 

5.00% due June 15, 2045

 

 

750

 

 

 

750

 

Net discount on debentures and notes

 

 

(24

)

 

 

(30

)

Debt issuance costs

 

 

(40

)

 

 

(39

)

Total debt

 

 

5,947

 

 

 

6,864

 

Less amount classified as short-term debt (4)

 

 

162

 

 

 

115

 

Total long-term debt

 

$

5,785

 

 

$

6,749

 

 

(1)

2015

These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.

(2)

These senior notes were included in 2018 tender offer repurchases discussed below.

(3)

Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon.

(4)

2018 short-term debt consists of $626$162 million of commercial paper and the $350 million floating rate6.30% senior notes due on DecemberJanuary 15, 2016. 2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015.2019.

Debt maturities as of December 31, 2018, excluding debt issuance costs, premiums and discounts, are as follows:

 

 

Total

 

2019

 

$

162

 

2020

 

 

 

2021

 

 

500

 

2022

 

 

1,000

 

2023

 

 

 

Thereafter

 

 

4,349

 

Total

 

$

6,011

 

85


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Debt maturities asCredit Lines

Under its 2012 Senior Credit Facility, Devon had $3.0 billion of December 31, 2015, excluding premiumsavailable credit. On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and discounts, are as follows (millions):

2016

  $976  

2017

   —    

2018

   875  

2019

   1,100  

2020

   414  

Thereafter

   9,763  
  

 

 

 

Total

  $13,128  
  

 

 

 

Credit Lines

Devon has asubsequently entered into its new $3.0 billion revolving 2018 Senior Credit Facility. The maturity date for $30 million of the2018 Senior Credit Facility ismatures on October 24, 2017. The5, 2023, with the option to extend 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.by two additional one-year periods subject to lender consent. Amounts borrowed under the 2018 Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The 2018 Senior Credit Facility currently provides for an annual facility fee of $3.8 million that is payable quarterly in arrears.$6.1 million. As of December 31, 2015, there2018, Devon had $48 million in outstanding letters of credit under the 2018 Senior Credit Facility. There were no borrowings under the Senior Credit Facility.Facility as of December 31, 2018.

The 2018 Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. Also,For example, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwillasset impairments. As of December 31, 2015,2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.7%21.0%.

Commercial Paper

Devon’s 2018 Senior Credit Facility supports its $3.0 billion of short-term credit under its 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, Devon’s2018, Devon had no outstanding commercial paper borrowings had a weighted-average borrowing rate of 0.63%.borrowings.

IssuanceRetirement of Senior Notes

In June 2015,During 2018, Devon issued $750completed tender offers to repurchase $807 million in aggregate principal amount of debt using cash on hand. This included $384 million of 5.0%the 7.875% senior notes due 2045 that are unsecuredSeptember 30, 2031 and unsubordinated obligations. Devon used the net proceeds to repay the floating rate senior notes that matured on December 15, 2015, as well as outstanding commercial paper balances.

In December 2015, in conjunction with the announcement$423 million of the Powder River Basin and STACK acquisitions, Devon issued $850 million of 5.85%7.95% senior notes due 2025 thatApril 15, 2032. Devon recognized a $312 million loss on early retirement of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along with other charges associated with retiring the debt, are unsecuredincluded in net financing costs in the consolidated comprehensive statements of earnings. In December 2018, Devon repaid the $95 million of 2.25% senior notes at maturity. Additionally, in January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity.

During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 2. Devon recognized a loss on early retirement of debt, primarily consisting of $265 million in cash retirement costs and unsubordinated obligations. Devon usedother fees. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net proceedsfinancing costs in the consolidated comprehensive statements of earnings.

86


Table of Contents

Index to fund the cash portion of these acquisitions.

Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Retirement of Senior Notes

In November 2014, Devon redeemed $1.9 billion of senior notes prior to their scheduled maturity, primarily with proceeds received from its asset divestitures. The redemption includes the 2.4% $500 million senior notes due 2016, the 1.2% $650 million senior notes due 2016 and the 1.875% $750 million senior notes due 2017. The notes were redeemed for $1.9 billion, which included 100% of the principal amount and a make-whole premium of $40 million. On the date of redemption, these notes also had an unamortized discount of $2 million and unamortized debt issuance costs of $6 million. The make-whole premium, unamortized discounts and debt issuance costs are included in net financing costs on the accompanying 2014 consolidated comprehensive statement of earnings.

Other Debentures and Notes

Following are descriptions of the various other debentures and notes outstanding at December 31, 2015 and 2014, as listed in the table presented at the beginning of this note.

GeoSouthern Debt

In December 2013, in conjunction with the planned GeoSouthern acquisition, Devon issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes. Devon repaid the floating rate senior notes due 2015 upon maturity and redeemed the 1.2% senior notes due December 15, 2016 in November 2014. As of December 31, 2015, the floating rate senior notes due 2016 and the 2.25% senior notes due December 15, 2018 were outstanding. The floating rate senior notes due 2016 bear interest at a rate equal to three-month LIBOR plus 0.54%, which will be reset quarterly.

Other Notes

In 2012, 2011, 2009 and 2002, Devon issued senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper, credit facility borrowings and other long-term debt. The schedule below summarizes the key terms of these notes (millions).

   Date Issued 
   May 2012   July 2011   January 2009   March 2002 

3.25% due May 15, 2022

  $1,000    $—      $—      $—    

4.75% due May 15, 2042

   750     —       —       —    

4.00% due July 15, 2021

   —       500     —       —    

5.60% due July 15, 2041

   —       1,250     —       —    

6.30% due January 15, 2019

   —       —       700     —    

7.95% due April 15, 2032

   —       —       —       1,000  

Discount and issuance costs

   (28   (24   (8   (14
  

 

 

   

 

 

   

 

 

   

 

 

 

Net proceeds

  $1,722    $1,726    $692    $986  
  

 

 

   

 

 

   

 

 

   

 

 

 

Ocean Debt

On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2015, including the fair value of the debt at April 25, 2003 and the effective interest rate of the debt after determining the fair values using

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

April 25, 2003 market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.

   Fair Value of
Debt  Assumed
   Effective Rate of
Debt Assumed
 

Debt Assumed

  (Millions)     

8.25% due July 2018 (principal of $125 million)

  $147     5.5

7.50% due September 2027 (principal of $150 million)

  $169     6.5

7.875% Debentures due September 30, 2031

In October 2001, Devon, through Devon Financing, a wholly owned finance subsidiary, sold debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed, on an unsecured and unsubordinated basis, the obligations of Devon Financing under the debt securities. The proceeds were used to fund a portion of the Anderson Exploration acquisition.

EnLink Debt

All of EnLink’s and the General Partner’s debt is non-recourse to Devon.

The table below summarizes the fair value of EnLink’s debt as of March 7, 2014, the formation date of EnLink. The premiums are being amortized using the effective interest method.

   March 7, 2014
Fair Value

of Debt
   Effective 
Rate of Debt
 
   (Millions)     

8.875% due February 2018 (principal of $725 million)(1)

  $760     7.7

7.125% due June 2022 (principal of $197 million)

   226     5.3

Credit facilities

   468    
  

 

 

   

Total long-term debt

  $1,454    
  

 

 

   

(1)The 2018 senior notes were redeemed on April 18, 2014.

In February 2015, the commitments under EnLink’s $1.0 billion unsecured revolving credit facility were increased to $1.5 billion, and the maturity date was extended by a year to March 6, 2020. As of December 31, 2015, there were $11 million in outstanding letters of credit and $414 million outstanding borrowings, with a weighted-average borrowing rate of 1.7%, under the $1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019. As of December 31, 2015, the General Partner had no outstanding borrowings under the $250 million credit facility. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2015.

In March 2014, EnLink issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400 million of its 2.70% senior notes due 2019, $450 million of its 4.40% senior notes due 2024 and $350 million of its 5.60% senior notes due 2044, at discounts of their face value. EnLink used the net proceeds to redeem the 2018 senior notes, reduce outstanding credit facility borrowings, for capital expenditures and for general operations.

In November 2014, EnLink issued $100 million of its 4.40% senior notes due 2024 and $300 million of its 5.05% senior notes due 2045, at a premium and discount, respectively, of their face value. The 2024 notes were

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

offered as an additional issue of EnLink’s outstanding 4.40% senior notes due 2024, issued in March 2014. The 2024 notes issued in March 2014 and November 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. EnLink used the net proceeds for capital expenditures and for general operations.

In May 2015, EnLink issued $900 million principal amount of unsecured senior notes, consisting of $750 million principal amount of its 4.15% senior notes due 2025 and an additional $150 million principal amount of its 5.05% senior notes due 2045. EnLink used the net proceeds to repay outstanding revolving credit facility borrowings, for capital expenditures and for general operations.

Net Financing Costs, Net

The following schedule includes the components of net financing costs.

 

   Year Ended December 31, 
     2015       2014       2013   
   (Millions) 

Interest based on debt outstanding

  $565    $532    $466  

Early retirement of debt

   —       48     —    

Capitalized interest

   (62   (70   (56

Other fees and expenses

   20     26     27  
  

 

 

   

 

 

   

 

 

 

Interest expense

   523     536     437  

Interest income

   (6   (10   (20
  

 

 

   

 

 

   

 

 

 

Net financing costs

  $517    $526    $417  
  

 

 

   

 

 

   

 

 

 

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Interest based on debt outstanding

 

$

339

 

 

$

390

 

 

$

488

 

Early retirement of debt

 

 

312

 

 

 

 

 

 

269

 

Capitalized interest

 

 

(41

)

 

 

(69

)

 

 

(61

)

Other

 

 

(16

)

 

 

(4

)

 

 

21

 

Total net financing costs

 

$

594

 

 

$

317

 

 

$

717

 

 

14.

16.

Asset Retirement Obligations

The following table presents the changes in asset retirement obligations.

 

  Year Ended December 31, 
        2015               2014       

 

Year Ended December 31,

 

  (Millions) 

 

2018

 

 

2017

 

Asset retirement obligations as of beginning of period

  $1,399    $2,228  

 

$

1,138

 

 

$

1,258

 

Liabilities incurred

   63     97  

 

 

39

 

 

 

40

 

Liabilities settled and divested(1)

   (89   (1,009

Liabilities settled and divested

 

 

(116

)

 

 

(68

)

Revision of estimated obligation

   62     70  

 

 

(25

)

 

 

(184

)

Accretion expense on discounted obligation

   75     89  

 

 

59

 

 

 

62

 

Foreign currency translation adjustment

   (96   (76

 

 

(38

)

 

 

30

 

  

 

   

 

 

Asset retirement obligations as of end of period

   1,414     1,399  

 

 

1,057

 

 

 

1,138

 

Less current portion

   44     60  

 

 

27

 

 

 

39

 

  

 

   

 

 

Asset retirement obligations, long-term

  $1,370    $1,339  

 

$

1,030

 

 

$

1,099

 

  

 

   

 

 

 

During 2018, Devon reduced its asset retirement obligation by $84 million, primarily as a result of Devon’s 2018 divestitures. For additional information, see Note 2.

During 2017, Devon reduced its asset retirement obligations by $184 million, primarily due to changes in the assumed inflation rate and retirement dates for its oil and gas assets.

(1)

17.

During 2014, Devon reduced its asset retirement obligation by $953 million for those obligations that were assumed by purchasers of Devon’s Canadian and U.S. divested oil and gas properties.

Retirement Plans

Defined Contribution Plans

Devon sponsors defined contribution plans covering its employees in the U.S. and Canada. Such plans include its 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. Devon contributed $50 million, $53 million and $57 million to these plans in 2018, 2017 and 2016, respectively.

87


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

15.Retirement Plans

Defined Benefit Plans

Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certaincovering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits forunder the qualifieddefined benefit plans arehave been closed to new employees; however, eligible employees continue to accrue benefits based on the employees’upon years of service and compensation andcompensation. Benefits are primarily funded from assets held in the plans’ trusts.

The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans’ benefits are based on the employees’ years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans’ benefit obligations. The total value of these trusts was $22 million and $25 million at December 31, 2015 and 2014, respectively and is included in other long-term assets in the accompanying consolidated balance sheets. For the remaining nonqualified plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.

Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. The plans provide medical and, in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Benefit Obligations and Funded Status

The following table presents the funded status of Devon’s qualified and nonqualified pension and postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans was $1.2 billion at December 31, 2015 and 2014. Devon’s benefit obligations and plan assets are measured each year as of December 31. The projected benefit obligations for Devon’s qualified plans were fully funded as of December 31, 2015 and 2014.

   Pension Benefits   Postretirement Benefits 
   2015   2014       2015           2014     
   (Millions) 

Change in benefit obligation:

        

Benefit obligation at beginning of year

  $1,377    $1,177    $24    $24  

Service cost

   33     30     1     1  

Interest cost

   52     55     1     1  

Actuarial loss (gain)

   (68   203     (2   —    

Plan amendments

   —       —       1     —    

Plan settlements

   —       (4   —       —    

Foreign exchange rate changes

   (6   (3   —       —    

Participant contributions

   —       —       2     2  

Benefits paid

   (80   (81   (4   (4
  

 

 

   

 

 

   

 

 

   

 

 

 

Benefit obligation at end of year

   1,308     1,377     23     24  
  

 

 

   

 

 

   

 

 

   

 

 

 

Change in plan assets:

        

Fair value of plan assets at beginning of year

   1,149     1,006     —       —    

Actual return on plan assets

   (16   200     —       —    

Employer contributions

   11     29     2     2  

Participant contributions

   —       —       2     2  

Plan settlements

   —       (4   —       —    

Benefits paid

   (80   (81   (4   (4

Foreign exchange rate changes

   (5   (1   —       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets at end of year

   1,059     1,149     —       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Funded status at end of year

  $(249  $(228  $(23  $(24
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in balance sheet:

        

Other long-term assets

  $2    $22    $—      $—    

Other current liabilities

   (12   (10   (3   (3

Other long-term liabilities

   (239   (240   (20   (21
  

 

 

   

 

 

   

 

 

   

 

 

 

Net amount

  $(249  $(228  $(23  $(24
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in accumulated other comprehensive earnings:

        

Net actuarial loss (gain)

  $302    $317    $(11  $(11

Prior service cost (credit)

   14     19     (6   (9
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $316    $336    $(17  $(20
  

 

 

   

 

 

   

 

 

   

 

 

 

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $11 million and $10 million for 2015 and 2014, respectively, which were transferred from the trusts established for the nonqualified plans.

Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2015 and 2014, as presented in the following table.

   December 31, 
   2015   2014 
   (Millions) 

Projected benefit obligation

  $244    $250  

Accumulated benefit obligation

  $199    $191  

Fair value of plan assets

  $—      $—    

Net Periodic Benefit Cost and Other Comprehensive Earnings

The following table presents the components of net periodic benefit cost and other comprehensive earnings.

   Pension Benefits  Postretirement Benefits 
   2015  2014  2013  2015  2014  2013 
   (Millions) 

Net periodic benefit cost:

       

Service cost

  $33   $30   $36   $1   $1   $1  

Interest cost

   52    55    51    1    1    1  

Expected return on plan assets

   (58  (54  (62  —      —      —    

Curtailment and settlement expense

   —      1    —      —      —      —    

Recognition of net actuarial loss (gain)(1)

   20    18    22    (1  (1  (1

Recognition of prior service cost(1)

   4    4    4    (2  (2  (1
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total net periodic benefit cost(2)

   51    54    51    (1  (1  —    

Other comprehensive loss (earnings):

       

Actuarial loss (gain) arising in current year

   5    57    (39  (1  —      (3

Prior service cost (credit) arising in current year

   —      —      2    1    —      (8

Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost

   (20  (19  (22  1    1    1  

Recognition of prior service cost, including curtailment, in net periodic benefit cost

   (4  (4  (4  1    2    1  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total other comprehensive loss (earnings)

   (19  34    (63  2    3    (9
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total recognized

  $32   $88   $(12 $1   $2   $(9
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(1)These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
(2)Net periodic benefit cost is a component of G&A on the accompanying consolidated comprehensive statements of earnings.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2016.

   Pension
Benefits
   Postretirement
Benefits
 
   (Millions) 

Net actuarial loss (gain)

  $22    $(2

Prior service cost (credit)

   4     (1
  

 

 

   

 

 

 

Total

  $26    $(3
  

 

 

   

 

 

 

Assumptions

The following table presents the weighted-average actuarial assumptions used to determine obligations and periodic costs.

   Pension Benefits  Postretirement Benefits 
   2015  2014  2013  2015  2014  2013 

Assumptions to determine benefit obligations:

       

Discount rate

   4.25  3.90  4.80  3.63  3.25  3.65

Rate of compensation increase

   4.49  4.49  4.48  N/A    N/A    N/A  

Assumptions to determine net periodic benefit cost:

       

Discount rate

   3.90  4.80  3.85  3.25  3.65  3.30

Rate of compensation increase

   4.49  4.49  4.48  N/A    N/A    N/A  

Expected return on plan assets

   5.22  5.42  5.48  N/A    N/A    N/A  

Discount rate – Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.

At the end of 2015, Devon changed the approach used to measure service and interest costs for pension and other postretirement benefits. For 2015, Devon measured service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016, Devon elected to measure service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. Devon believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations nor the funded status of the plans. The change in the service and interest costs going forward is not expected to be significant. This change has been accounted for as a change in accounting estimate.

Rate of compensation increase – For measurement of the 2015 benefit obligation for the pension plans, a 4.49% compensation increase was assumed.

Expected return on plan assets – The expected rate of return on plan assets was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types. See the pension plan assets section below for more information on Devon’s target allocations.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Mortality rate assumptions – In 2014, the Society of Actuaries issued updated versions of its mortality tables and mortality improvement scale, reflecting the increasing life expectancies in the U.S. While not required to strictly adhere to this data, Devon utilized actuary-produced mortality tables and an improvement scale derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in Devon’s plans.

Other assumptions – For measurement of the 2015 benefit obligation for the other postretirement medical plans, a 7.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2015 by less than $1 million and would change the 2015 service and interest cost components of net periodic benefit cost by less than $1 million.

Pension Plan Assets

Devon’s overall investment objective for its pension plans’ assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocationallocations for its pension plan assets.

   December 31, 
       2015          2014     

Fixed income

   70  70

Equity

   20  20

Other

   10  10

Theassets are 70% fixed income, 20% equity and 10% other. See the following tables present the fair values ofdiscussion for Devon’s pension assets by asset class.

   December 31, 2015 
          Fair Value Measurements Using: 
   Actual
Allocation
  Total   Level 1
Inputs
   Level 2
Inputs
   Level 3
Inputs
 
   (Millions) 

Fixed-income securities:

         

U.S. Treasury obligations

   17 $179    $88    $91    $—    

Corporate bonds

   48  507     371     136     —    

Other bonds

   3  35     35     —       —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total fixed-income securities

   68  721     494     227     —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Equity securities:

         

Global (large, mid, small cap)

   18  186     —       186     —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Other securities:

         

Hedge fund and alternative investments

   11  120     —       —       120  

Short-term investments

   3  32     6     26     —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total other securities

   14  152     6     26     120  
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total investments

   100 $1,059    $500    $439    $120  
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

   December 31, 2014 
          Fair Value Measurements
Using:
 
   Actual
Allocation
  Total   Level 1
Inputs
   Level 2
Inputs
   Level 3
Inputs
 
   (Millions) 

Fixed-income securities:

         

U.S. Treasury obligations

   35 $405    $50    $355    $—    

Corporate bonds

   32  364     269     95     —    

Other bonds

   3  30     30     —       —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total fixed-income securities

   70  799     349     450     —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Equity securities:

         

Global (large, mid, small cap)

   17  197     —       197     —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Other securities:

         

Hedge fund and alternative investments

   10  112     —       —       112  

Short-term investments

   3  41     15     26     —    
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total other securities

   13  153     15     26     112  
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total investments

   100 $1,149    $364    $673    $112  
  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

The following methods and assumptions were used to estimate the fair values in the tables above.

Fixed-income securities – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.

Devon’s fixed income securities also includeprices and were $193 million and $342 million at December 31, 2018 and 2017, respectively. Also, included are commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.managers and were $301 million and $401 million at December 31, 2018 and 2017, respectively.

Equity securities– Devon’s equity securities include a commingled global equity fundfunds that investsinvest in large, mid and small capitalization stocks across the world’s developed and emerging markets.markets and international large cap equity securities. These equity securities can be redeemedsold on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.managers and were $84 million and $157 million at December 31, 2018 and 2017, respectively.

Other securities – Devon’s other securities include cash and commingled, short-term investment funds. The short-term investment funds’ securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.

Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategiesfunds and a hedge fund of funds that investsinvest both long and short using a variety of investment strategies. Devon’s hedge fund of funds is not actively traded, and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3these securities is based upon the net asset values provided by investment representsmanagers and were $132 million and $135 million at December 31, 2018 and 2017, respectively.

Defined Postretirement Plans

Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the fair valueplans is to fund the benefits as determined bythey become payable with available cash and cash equivalents.

Benefit Obligations and Funded Status

The following table summarizes the hedge fund manager.

benefit obligations, assets, funded status and balance sheet impacts associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2018 and 2017.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

 

Pension Benefits

 

 

Postretirement Benefits

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

Change in benefit obligation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit obligation at beginning of year

 

$

1,279

 

 

$

1,249

 

 

$

19

 

 

$

21

 

Service cost

 

 

10

 

 

 

15

 

 

 

 

 

 

 

Interest cost

 

 

39

 

 

 

42

 

 

 

 

 

 

 

Actuarial loss (gain)

 

 

(83

)

 

 

59

 

 

 

(3

)

 

 

 

Plan amendments

 

 

 

 

 

 

 

 

 

 

 

 

Plan curtailments

 

 

2

 

 

 

 

 

 

2

 

 

 

 

Plan settlements

 

 

(241

)

 

 

 

 

 

 

 

 

 

Foreign exchange rate changes

 

 

(3

)

 

 

2

 

 

 

 

 

 

 

Participant contributions

 

 

 

 

 

 

 

 

2

 

 

 

1

 

Benefits paid

 

 

(60

)

 

 

(88

)

 

 

(3

)

 

 

(3

)

Benefit obligation at end of year

 

 

943

 

 

 

1,279

 

 

 

17

 

 

 

19

 

Change in plan assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value of plan assets at beginning of year

 

 

1,035

 

 

 

985

 

 

 

 

 

 

 

Actual return on plan assets

 

 

(36

)

 

 

122

 

 

 

 

 

 

 

Employer contributions

 

 

14

 

 

 

14

 

 

 

1

 

 

 

2

 

Participant contributions

 

 

 

 

 

 

 

 

2

 

 

 

1

 

Plan settlements

 

 

(241

)

 

 

 

 

 

 

 

 

 

Benefits paid

 

 

(60

)

 

 

(88

)

 

 

(3

)

 

 

(3

)

Foreign exchange rate changes

 

 

(3

)

 

 

2

 

 

 

 

 

 

 

Fair value of plan assets at end of year

 

 

709

 

 

 

1,035

 

 

 

 

 

 

 

Funded status at end of year

 

$

(234

)

 

$

(244

)

 

$

(17

)

 

$

(19

)

Amounts recognized in balance sheet:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other long-term assets

 

$

3

 

 

$

4

 

 

$

 

 

$

 

Other current liabilities

 

 

(14

)

 

 

(13

)

 

 

(3

)

 

 

(3

)

Other long-term liabilities

 

 

(223

)

 

 

(235

)

 

 

(14

)

 

 

(16

)

Net amount

 

$

(234

)

 

$

(244

)

 

$

(17

)

 

$

(19

)

Amounts recognized in accumulated other

   comprehensive earnings:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss (gain)

 

$

202

 

 

$

257

 

 

$

(11

)

 

$

(11

)

Prior service cost (credit)

 

 

4

 

 

 

6

 

 

 

(2

)

 

 

(3

)

Total

 

$

206

 

 

$

263

 

 

$

(13

)

 

$

(14

)

During the third quarter of 2018, Devon entered into a group annuity contract, under which a third party has permanently assumed certain of Devon’s defined benefit pension obligations. The purchase of this group annuity contract reduced Devon’s pension assets and liabilities and is the primary component of the $241 million of plan settlements within the preceding table. In connection with the group annuity contract transaction, Devon recorded a settlement expense of approximately $33 million, which was reclassified from other comprehensive earnings to other expense on the consolidated comprehensive statements of earnings in 2018.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2018 and December 31, 2017, as presented in the table below.

 

 

December 31,

 

 

 

2018

 

 

2017

 

Projected benefit obligation

 

$

922

 

 

$

1,255

 

Accumulated benefit obligation

 

$

906

 

 

$

1,226

 

Fair value of plan assets

 

$

685

 

 

$

1,007

 

 

The following table presents a summarythe components of net periodic benefit cost and other comprehensive earnings.

 

 

Pension Benefits

 

 

Postretirement Benefits

 

 

 

2018

 

 

2017

 

 

2016

 

 

2018

 

 

2017

 

 

2016

 

Net periodic benefit cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

10

 

 

$

15

 

 

$

15

 

 

$

 

 

$

 

 

$

 

Interest cost

 

 

39

 

 

 

42

 

 

 

42

 

 

 

 

 

 

 

 

 

1

 

Expected return on plan assets

 

 

(49

)

 

 

(54

)

 

 

(55

)

 

 

 

 

 

 

 

 

 

Recognition of net actuarial loss (gain) (1)

 

 

13

 

 

 

19

 

 

 

25

 

 

 

(1

)

 

 

(1

)

 

 

(1

)

Recognition of prior service cost (1)

 

 

1

 

 

 

2

 

 

 

3

 

 

 

(1

)

 

 

(1

)

 

 

(1

)

Total net periodic benefit cost (2)

 

 

14

 

 

 

24

 

 

 

30

 

 

 

(2

)

 

 

(2

)

 

 

(1

)

Other comprehensive loss (earnings):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Actuarial loss (gain) arising in current year

 

 

4

 

 

 

(9

)

 

 

26

 

 

 

(1

)

 

 

(1

)

 

 

 

Prior service cost arising in current year

 

 

 

 

 

 

 

 

2

 

 

 

 

 

 

 

 

 

 

Recognition of net actuarial gain (loss), including

   settlement expense, in net periodic benefit cost (3)

 

 

(60

)

 

 

(19

)

 

 

(43

)

 

 

1

 

 

 

1

 

 

 

1

 

Recognition of prior service cost, including

   curtailment, in net periodic benefit cost (3)

 

 

(2

)

 

 

(2

)

 

 

(9

)

 

 

1

 

 

 

1

 

 

 

1

 

Total other comprehensive loss (earnings)

 

 

(58

)

 

 

(30

)

 

 

(24

)

 

 

1

 

 

 

1

 

 

 

2

 

Total recognized

 

$

(44

)

 

$

(6

)

 

$

6

 

 

$

(1

)

 

$

(1

)

 

$

1

 

(1)

These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.

(2)

The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings.

(3)

These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6 for further discussion.

Assumptions

 

 

Pension Benefits

 

 

Postretirement Benefits

 

 

 

2018

 

 

2017

 

 

2016

 

 

2018

 

 

2017

 

 

2016

 

Assumptions to determine benefit obligations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

4.21%

 

 

3.59%

 

 

4.07%

 

 

4.01%

 

 

3.25%

 

 

3.46%

 

Rate of compensation increase

 

2.50%

 

 

2.50%

 

 

4.49%

 

 

N/A

 

 

N/A

 

 

N/A

 

Assumptions to determine net periodic benefit cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate - service cost

 

3.98%

 

 

4.29%

 

 

4.39%

 

 

4.13%

 

 

4.22%

 

 

3.63%

 

Discount rate - interest cost

 

3.22%

 

 

2.99%

 

 

4.39%

 

 

2.67%

 

 

2.39%

 

 

3.63%

 

Rate of compensation increase

 

2.50%

 

 

4.48%

 

 

4.49%

 

 

N/A

 

 

N/A

 

 

N/A

 

Expected return on plan assets

 

5.67%

 

 

5.69%

 

 

5.20%

 

 

N/A

 

 

N/A

 

 

N/A

 

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Discount Rate - Future pension and post-retirement obligations are discounted based on the rate at which obligations could be effectively settled, considering the timing of expected future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.  

Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types.

Mortality rate – Devon utilized the Society of Actuaries produced mortality tables and an improvement scale derived from the updated tables for 2017 and 2018 and the actuary’s best estimate of mortality for 2016 for the population of participants in Devon’s plans.

Other assumptionsFor measurement of the changes2018 benefit obligation for the other postretirement medical plans, a 7.1% annual rate of increase in Devon’s Level 3 plan assets (millions).the per capita cost of covered health care benefits was assumed for 2019. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter.

 

December 31, 2013

  $ 112  

Disbursements

   (6

Investment returns

   6  
  

 

 

 

December 31, 2014

   112  

Purchases

   5  

Investment returns

   3  
  

 

 

 

December 31, 2015

  $120  
  

 

 

 

Expected Cash Flows

The following table presents expected cash flow informationDevon expects benefit plan payments to average approximately $59 million a year for Devon’s pensionthe next five years and postretirement benefit plans.

   Pension
Benefits
   Postretirement
Benefits
 
   (Millions) 

Devon’s 2016 contributions

  $12    $3  

Benefit payments:

    

2016

  $73    $3  

2017

  $75    $3  

2018

  $77    $3  

2019

  $78    $3  

2020

  $83    $2  

2021 to 2025

  $446    $7  

Expected contributions included in$153 million total for the table above include amounts related to Devon’s qualified plans, nonqualified plans and postretirement plans.five years thereafter. Of the benefits expectedthese payments to be paid in 2016, the $122019, $17 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans, and the $3 million of postretirement benefits is expected to be funded from Devon’s available cash, cash equivalents and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.

Defined Contribution Plans

Independent of EnLink, Devon maintains defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. EnLink also maintains a 401(k) plan covering eligible employees. The following table presents expense related to these defined contribution plans.assets.

 

   Year Ended December 31, 
   2015   2014   2013 
   (Millions) 

401(k) and enhanced contribution plans

  $63    $49    $41  

Canadian pension and savings plans

   16     20     26  
  

 

 

   

 

 

   

 

 

 

Total

  $79    $69    $67  
  

 

 

   

 

 

   

 

 

 

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

16.

18.

Stockholders’ Equity

The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.

Common Stock Issued

In December 2015, Devon issued approximately 7 million shares of common stock as part of the Powder River Basin asset acquisition discussed in Note 2. Additionally, in January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition.acquisition discussed in Note 2. Additionally, in February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.

DividendsShare Repurchase Program

In March 2018, Devon announced a share repurchase program to buy up to $1.0 billion of shares of common stock. In June 2018, in conjunction with the announced divestiture of its investment in EnLink and the General Partner, Devon increased its program by an additional $3.0 billion. In February 2019, Devon’s Board of Directors authorized an expansion of the share repurchase program by an additional $1.0 billion, bringing the total to $5.0 billion. The share repurchase program expires December 31, 2019.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During the third quarter of 2018, Devon entered into and completed an ASR transaction to repurchase $1.0 billion of the $4.0 billion program. The table below provides information regarding purchases of Devon’s common stock that were made during 2018 (shares in thousands).

 

 

Total Number of

Shares Purchased

 

 

Dollar Value of

Shares Purchased

 

 

Average Price Paid

per Share

 

First quarter 2018:

 

 

 

 

 

 

 

 

 

 

 

 

Open-Market

 

 

2,561

 

 

$

82

 

 

$

32.19

 

Second quarter 2018:

 

 

 

 

 

 

 

 

 

 

 

 

Open-Market

 

 

11,154

 

 

 

439

 

 

 

39.35

 

Third quarter 2018:

 

 

 

 

 

 

 

 

 

 

 

 

Open-Market

 

 

16,492

 

 

 

712

 

 

 

43.13

 

ASR

 

 

24,330

 

 

 

1,000

 

 

 

41.10

 

Total

 

 

40,822

 

 

 

1,712

 

 

 

41.92

 

Fourth quarter 2018:

 

 

 

 

 

 

 

 

 

 

 

 

Open-Market

 

 

23,612

 

 

 

745

 

 

 

31.57

 

Total year-to-date

 

 

78,149

 

 

$

2,978

 

 

$

38.11

 

Dividends

The table below summarizes the dividends Devon paid on its common stock dividends of $396 million, $386 million and $348 million in 2015, 2014 and 2013, respectively. Thestock.

 

Amounts

 

 

Rate Per Share

 

Year Ended 2018:

 

 

 

 

 

 

 

First quarter

$

32

 

 

$

0.06

 

Second quarter

 

42

 

 

$

0.08

 

Third quarter

 

38

 

 

$

0.08

 

Fourth quarter

 

37

 

 

$

0.08

 

Total year-to-date

$

149

 

 

 

 

 

Year Ended 2017:

 

 

 

 

 

 

 

First quarter

$

32

 

 

$

0.06

 

Second quarter

 

33

 

 

$

0.06

 

Third quarter

 

30

 

 

$

0.06

 

Fourth quarter

 

32

 

 

$

0.06

 

Total year-to-date

$

127

 

 

 

 

 

Year Ended 2016:

 

 

 

 

 

 

 

First quarter

$

125

 

 

$

0.24

 

Second quarter

 

33

 

 

$

0.06

 

Third quarter

 

32

 

 

$

0.06

 

Fourth quarter

 

31

 

 

$

0.06

 

Total year-to-date

$

221

 

 

 

 

 

In response to the depressed commodity price environment, Devon reduced the quarterly cash dividend was $0.20 per share in the first quarter of 2013. Devon increased the dividend rate from $0.24 to $0.22$0.06 per share in the second quarter of 2013 and2016. Devon increased the quarterly dividend by 33% to $0.24$0.08 per share in the second quarter of 2014.2018. In February 2019, Devon announced a 12.5% increase to its quarterly dividend, to $0.09 per share, beginning in the second quarter of 2019.

Stock Option Proceeds92


Devon received $4 million, $93 million and $3 million from stock option proceeds in 2015, 2014 and 2013, respectively.Table of Contents

 

17.Noncontrolling Interests

Acquisition of Noncontrolling InterestsIndex to Financial Statements

In March 2014, EnLink was formed as a publicly traded consolidated subsidiary of Devon to provide midstream services to Devon and third parties. Devon obtained approximately 120.5 million units, or a 52% ownership interest, as a result of this transaction. Approximately 92.7 million units were issued to the public for a 41% ownership interest, with the remaining 7% ownership interest held by the General Partner.

Subsidiary Equity Transactions

Through its equity distribution agreements, EnLink has the ability to sell common units through an “at the market” equity offering program. During 2015 and 2014, EnLink issued and sold approximately 1.3 million and 14.8 million common units through its at the market program and general public offerings, generating net proceeds of $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.

In 2015, Devon conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising net proceeds of $654 million.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

As a result of these transactions, the Coronado acquisition and dropdown transactions discussed in Note 2, the ownership of EnLink at December 31, 2015 is approximately:

 

28% – Devon

19.

Discontinued Operations and Assets Held For Sale

 

27% – General Partner (controlled by Devon)

45% – Public unitholders

The net gains and losses and related income taxes resulting from these transactions have been recorded asOn June 6, 2018, Devon announced that it had entered into an adjustmentagreement to equity, and the changesell its aggregate ownership interests in ownership reflected as an adjustment to noncontrolling interests.

As further discussed in Note 2, in January 2016, EnLink acquired midstream assets in exchange for cash and equity. Subsequent to this transaction, the ownership of the General Partner is approximately:

64% – Devon

36% – Public unitholders

Subsequent to this transaction, the ownership of EnLink is approximately:

25% – Devon

23% – General Partner (controlled by Devon)

52% – Public unitholders

Distributions to Noncontrolling Interests

In conjunction with the formation of the General Partner in 2014, Devon made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $254 millionfor $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and $135 millionmet the requirements of assets held for sale and discontinued operations. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire midstream business ownership; 2) EnLink and the General Partner are a separate reportable segment and are a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, debt, revenues, net earnings and operating cash flows. As a result, Devon classified the results of operations and cash flows related to non-Devon unitholders during 2015EnLink and 2014, respectively.the General Partner as discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was signed.

 

On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125  billion and recognized a gain of approximately $2.6  billion ($2.2  billion after-tax). Current (cash) income tax associated with the transaction was approximately $12 million. The vast majority of the tax effect relates to deferred tax expense offset by the valuation allowance adjustment explained inNote 8.

As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon has minimum volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant through early 2021.

From the period of July 19, 2018 through December 31, 2018, Devon had net outflows of approximately $380 million with EnLink, which primarily related to gathering and processing expenses. These net outflows represent gross cash amounts and not net working interest amounts.

Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations.

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Marketing and midstream revenues

 

$

3,567

 

 

$

5,071

 

 

$

3,551

 

Marketing and midstream expenses

 

 

2,912

 

 

 

4,111

 

 

 

2,712

 

Depreciation, depletion and amortization

 

 

244

 

 

 

545

 

 

 

504

 

General and administrative expenses

 

 

65

 

 

 

128

 

 

 

118

 

Financing costs, net

 

 

98

 

 

 

181

 

 

 

190

 

Asset impairments

 

 

 

 

 

17

 

 

 

873

 

Asset dispositions

 

 

(2,607

)

 

 

 

 

 

13

 

Other expenses

 

 

(8

)

 

 

(34

)

 

 

25

 

Total expenses

 

 

704

 

 

 

4,948

 

 

 

4,435

 

Earnings (loss) from discontinued operations before income taxes

 

 

2,863

 

 

 

123

 

 

 

(884

)

Income tax expense (benefit)

 

 

403

 

 

 

(197

)

 

 

 

Net earnings (loss) from discontinued operations, net of

   income tax expense

 

 

2,460

 

 

 

320

 

 

 

(884

)

Net earnings (loss) attributable to noncontrolling interests

 

 

160

 

 

 

180

 

 

 

(403

)

Net earnings (loss) from discontinued operations attributable to Devon

 

$

2,300

 

 

$

140

 

 

$

(481

)

The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets. The assets and liabilities classified as held for sale at December 31, 2018 are related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2. The assets and liabilities classified as held for sale at December 31, 2017 are related to the divestiture of EnLink and the General Partner.

 

 

December 31, 2018

 

 

December 31, 2017

 

Cash and cash equivalents

 

$

 

 

$

31

 

Accounts receivable

 

 

7

 

 

 

681

 

Other current assets

 

 

 

 

 

48

 

Oil and gas property and equipment, based on

   successful efforts accounting, net

 

 

190

 

 

 

 

Midstream and other property and equipment, net

 

 

 

 

 

6,587

 

Goodwill

 

 

 

 

 

1,542

 

Other long-term assets

 

 

 

 

 

1,600

 

Total assets held for sale

 

$

197

 

 

$

10,489

 

 

 

 

 

 

 

 

 

 

Accounts payable

 

$

3

 

 

$

186

 

Revenues and royalties payable

 

 

 

 

 

432

 

Other current liabilities

 

 

19

 

 

 

373

 

Long-term debt

 

 

 

 

 

3,542

 

Deferred income taxes

 

 

 

 

 

346

 

Asset retirement obligations

 

 

47

 

 

 

14

 

Other long-term liabilities

 

 

 

 

 

34

 

Total liabilities held for sale

 

$

69

 

 

$

4,927

 

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

18.

20.

Commitments and Contingencies

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.

Royalty Matters

Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. TheDevon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits allegeare claims that the producers and related partiesDevon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Environmental Matters

Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.

Beginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although we cannot predict the ultimate outcome of these matters, Devon is vigorously defending against these claims.

Other Matters

Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Commitments

The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2015.2018.

 

Year Ending December 31,

  Purchase
Obligations
   Drilling
and
Facility
Obligations
   Operational
Agreements
   Office and
Equipment
Leases
 

 

Purchase Obligations

 

 

Drilling and Facility Obligations

 

 

Operational Agreements

 

 

Office and Equipment Leases

 

  (Millions) 

2016

  $557    $69    $994    $70  

2017

   703     51     972     58  

2018

   791     34     936     76  

2019

   803     5     402     68  

 

$

541

 

 

$

274

 

 

$

587

 

 

$

64

 

2020

   845     2     255     42  

 

 

567

 

 

 

85

 

 

 

519

 

 

 

43

 

2021

 

 

140

 

 

 

48

 

 

 

373

 

 

 

31

 

2022

 

 

 

 

 

14

 

 

 

419

 

 

 

26

 

2023

 

 

 

 

 

8

 

 

 

354

 

 

 

25

 

Thereafter

   206     28     1,042     129  

 

 

 

 

 

16

 

 

 

3,374

 

 

 

311

 

  

 

   

 

   

 

   

 

 

Total

  $3,905    $189    $4,601    $443  

 

$

1,248

 

 

$

445

 

 

$

5,626

 

 

$

500

 

  

 

   

 

   

 

   

 

 

Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s 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 Devon’s internal estimate of future condensate market prices.

Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. The value of the drilling obligations reported is based on gross contractual value.

Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.

Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in G&A underrecognized for operating leases, net of sublease income, was $88$11 million, $64$7 million and $26$11 million in 2015, 20142018, 2017 and 2013,2016, respectively.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

19.

21.

Fair Value Measurements

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at December 31, 20152018 and December 31, 2014.2017, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, information regarding the fair values of oil and gas assets goodwill and other intangible assetsrelated impairments are measured as of the impairment date using Level 3 inputs. Additional information on asset impairments and the pension plan assets is provided in Note 5, and Note 12 and Note 15,17, respectively.

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements Using:

 

      Fair Value Measurements Using: 

 

Carrying

 

 

Total Fair

 

 

Level 1

 

 

Level 2

 

  Carrying
Amount
 Total Fair
Value
   Level 1  
Inputs
     Level 2  
Inputs
   Level 3  
Inputs
 

 

Amount

 

 

Value

 

 

Inputs

 

 

Inputs

 

  (Millions) 

December 31, 2015 assets (liabilities):

       

December 31, 2018 assets (liabilities):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash equivalents

 

$

1,505

 

 

$

1,505

 

 

$

1,405

 

 

$

100

 

Commodity derivatives

 

$

677

 

 

$

677

 

 

$

 

 

$

677

 

Commodity derivatives

 

$

(68

)

 

$

(68

)

 

$

 

 

$

(68

)

Debt

 

$

(5,947

)

 

$

(5,965

)

 

$

 

 

$

(5,965

)

December 31, 2017 assets (liabilities):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash equivalents

  $1,871   $1,871   $1,471    $400   $—    

 

$

1,533

 

 

$

1,533

 

 

$

1,454

 

 

$

79

 

Commodity derivatives

  $35   $35   $—      $35   $—    

 

$

205

 

 

$

205

 

 

$

 

 

$

205

 

Commodity derivatives

  $(18 $(18 $—      $(18 $—    

 

$

(286

)

 

$

(286

)

 

$

 

 

$

(286

)

Interest rate derivatives

  $2   $2   $—      $2   $—    

 

$

1

 

 

$

1

 

 

$

 

 

$

1

 

Interest rate derivatives

  $(22 $(22 $—      $(22 $—    

 

$

(64

)

 

$

(64

)

 

$

 

 

$

(64

)

Foreign currency derivatives

  $8   $8   $—      $8   $—    

Foreign currency derivatives

  $(8 $(8 $—      $(8 $—    

Debt

  $(13,113 $(11,927 $—      $(11,927 $—    

 

$

(6,864

)

 

$

(8,131

)

 

$

 

 

$

(8,131

)

Capital lease obligations

  $(17 $(16 $—      $(16 $—    

December 31, 2014 assets (liabilities):

       

Cash equivalents

  $950   $950   $340    $610   $—    

Commodity derivatives

  $1,995   $1,995   $—      $1,995   $—    

Commodity derivatives

  $(56 $(56 $—      $(56 $—    

Interest rate derivatives

  $1   $1   $—      $1   $—    

Interest rate derivatives

  $(1 $(1 $—      $(1 $—    

Foreign currency derivatives

  $8   $8   $—      $8   $—    

Debt

  $(11,262 $(12,472 $—      $(12,472 $—    

Capital lease obligations

  $(20 $(20 $—      $(20 $—    

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 1 Fair Value Measurements

Cash equivalents– Amounts consist primarily of money market investments. Theinvestments and the fair value approximates the carrying value.

Level 2 Fair Value Measurements

Cash equivalents – Amounts consist primarily of commercial paper and Canadian agency and provincial securities investments. The fair value approximates the carrying value.

Commodity and interest rate and foreign currency derivatives– The fair values of commodity and interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. The fair values of commercial paper and credit facility balances are the carrying values.

Capital lease obligations – The fair value was calculated using inputs from third-party banks.

 

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

20.

22.

Segment Information

Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian exploration and production operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas exploration and production activities, and certain information regarding such activities for each segment is included in Note 21.23.

Devon considers EnLink, combined with the General Partner, to be an operatinga segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located acrossin the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore,However, with Devon’s closing of the divestment of EnLink isand the General Partner in July 2018, activity related to EnLink and the General Partner have now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows, and the associated assets and liabilities of EnLink and the General Partner are presented as a separate reporting segment. Forassets and liabilities held for sale on the reporting periods prior to the formationconsolidated balance sheets. Additional information can be found in Note 19.

98


Table of EnLink, Devon has reclassified, from its U.S. segment to the EnLink segment, all asset-level amounts related to the midstream assets that it contributed to EnLink.Contents

 

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

   U.S. (1)  Canada  EnLink (1)  Eliminations  Total 
   (Millions) 

Year Ended December 31, 2015:

      

Revenues from external customers

  $8,360   $1,012   $3,773   $—     $13,145  

Intersegment revenues

  $—     $—     $679   $(679 $—    

Depreciation, depletion and amortization

  $2,220   $522   $387   $—     $3,129  

Asset impairments

  $18,000   $1,257   $1,563   $—     $20,820  

Interest expense

  $368   $94   $107   $(46 $523  

Loss before income taxes

  $(18,214 $(1,670 $(1,384 $—     $(21,268

Income tax expense (benefit)

  $(5,650 $(445 $30   $—     $(6,065

Net loss

  $(12,564 $(1,225 $(1,414 $—     $(15,203

Net earnings (loss) attributable to noncontrolling interests

  $1   $—     $(750 $—     $(749

Net loss attributable to Devon

  $(12,565 $(1,225 $(664 $—     $(14,454

Property and equipment, net

  $8,811   $4,590   $5,667   $—     $19,068  

Total assets

  $14,600   $5,464   $9,565   $(97 $29,532  

Capital expenditures

  $4,575   $680   $978   $—     $6,233  

Year Ended December 31, 2014:

      

Revenues from external customers

  $14,854   $2,063   $2,649   $—     $19,566  

Intersegment revenues

  $—     $—     $859   $(859 $—    

Depreciation, depletion and amortization

  $2,475   $560   $284   $—     $3,319  

Asset impairments

  $12   $1,941   $—     $—     $1,953  

Gains and losses on asset sales

  $5   $(1,077 $—     $—     $(1,072

Interest expense

  $441   $85   $54   $(44 $536  

Earnings (loss) before income taxes

  $4,390   $(657 $326   $—     $4,059  

Income tax expense

  $1,797   $495   $76   $—     $2,368  

Net earnings (loss)

  $2,593   $(1,152 $250   $—     $1,691  

Net earnings attributable to noncontrolling interests

  $1   $—     $83   $—     $84  

Net earnings (loss) attributable to Devon

  $2,592   $(1,152 $167   $—     $1,607  

Property and equipment, net

  $24,463   $6,790   $5,043   $—     $36,296  

Total assets

  $32,037   $8,517   $10,207   $(124 $50,637  

Capital expenditures

  $11,214   $1,344   $1,001   $—     $13,559  

Year Ended December 31, 2013:

      

Revenues from external customers

  $6,807   $2,656   $934   $—     $10,397  

Intersegment revenues

  $—     $—     $1,362   $(1,362 $—    

Depreciation, depletion and amortization

  $1,744   $849   $187   $—     $2,780  

Asset impairments

  $1,133   $843   $—     $—     $1,976  

Interest expense

  $392   $80   $—     $(35 $437  

Earnings (loss) before income taxes

  $495   $(532 $186   $—     $149  

Income tax expense (benefit)

  $258   $(156 $67   $—     $169  

Net earnings (loss)

  $237   $(376 $119   $—     $(20

Property and equipment, net

  $18,201   $8,478   $1,768   $—     $28,447  

Total assets

  $27,080   $13,560   $2,237   $—     $42,877  

Capital expenditures

  $4,589   $1,841   $213   $—     $6,643  

 

(1)Due to Devon’s control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recasted periods.

 

 

U.S.

 

 

Canada

 

 

Total

 

Year Ended December 31, 2018:

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers (1)

 

$

9,674

 

 

$

1,060

 

 

$

10,734

 

Depreciation, depletion and amortization

 

$

1,328

 

 

$

330

 

 

$

1,658

 

Interest expense

 

$

469

 

 

$

166

 

 

$

635

 

Asset impairments

 

$

156

 

 

$

 

 

$

156

 

Asset dispositions

 

$

(263

)

 

$

 

 

$

(263

)

Restructuring and transaction costs

 

$

97

 

 

$

17

 

 

$

114

 

Earnings (loss) from continuing operations before income taxes

 

$

1,294

 

 

$

(374

)

 

$

920

 

Income tax expense (benefit)

 

$

294

 

 

$

(138

)

 

$

156

 

Net earnings (loss) from continuing operations

 

$

1,000

 

 

$

(236

)

 

$

764

 

Property and equipment, net

 

$

10,026

 

 

$

3,909

 

 

$

13,935

 

Total assets (2)

 

$

14,853

 

 

$

4,516

 

 

$

19,369

 

Capital expenditures, including acquisitions

 

$

2,294

 

 

$

282

 

 

$

2,576

 

Year Ended December 31, 2017:

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

7,326

 

 

$

1,552

 

 

$

8,878

 

Depreciation, depletion and amortization

 

$

1,149

 

 

$

380

 

 

$

1,529

 

Interest expense

 

$

324

 

 

$

12

 

 

$

336

 

Asset dispositions

 

$

(218

)

 

$

1

 

 

$

(217

)

Earnings from continuing operations before income taxes

 

$

443

 

 

$

330

 

 

$

773

 

Income tax expense

 

$

9

 

 

$

6

 

 

$

15

 

Net earnings from continuing operations

 

$

434

 

 

$

324

 

 

$

758

 

Property and equipment, net

 

$

10,274

 

 

$

4,310

 

 

$

14,584

 

Total assets (3)

 

$

14,254

 

 

$

5,498

 

 

$

19,752

 

Capital expenditures, including acquisitions

 

$

1,821

 

 

$

348

 

 

$

2,169

 

Year Ended December 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

5,722

 

 

$

1,031

 

 

$

6,753

 

Depreciation, depletion and amortization

 

$

1,178

 

 

$

414

 

 

$

1,592

 

Interest expense

 

$

624

 

 

$

100

 

 

$

724

 

Asset impairments

 

$

435

 

 

$

2

 

 

$

437

 

Asset dispositions

 

$

(955

)

 

$

(541

)

 

$

(1,496

)

Restructuring and transaction costs

 

$

242

 

 

$

19

 

 

$

261

 

Earnings (loss) from continuing operations before income taxes

 

$

(757

)

 

$

324

 

 

$

(433

)

Income tax expense (benefit)

 

$

(8

)

 

$

149

 

 

$

141

 

Net earnings (loss) from continuing operations

 

$

(749

)

 

$

175

 

 

$

(574

)

Property and equipment, net

 

$

10,166

 

 

$

4,110

 

 

$

14,276

 

Total assets (3)

 

$

13,390

 

 

$

5,071

 

 

$

18,461

 

Capital expenditures, including acquisitions

 

$

2,640

 

 

$

186

 

 

$

2,826

 

(1) Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers.

(2) Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million.

(3) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

The following table presents revenue from contracts with customers that are disaggregated based on the type of good.

 

 

Year Ended December 31, 2018

 

 

 

U.S.

 

 

Canada

 

 

Total

 

Oil

 

$

2,957

 

 

$

814

 

 

$

3,771

 

Gas

 

 

950

 

 

 

 

 

 

950

 

NGL

 

 

956

 

 

 

 

 

 

956

 

Oil, gas and NGL revenues from

   contracts with customers

 

 

4,863

 

 

 

814

 

 

 

5,677

 

Oil, gas and NGL derivatives

 

 

457

 

 

 

151

 

 

 

608

 

Upstream revenues

 

 

5,320

 

 

 

965

 

 

 

6,285

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

2,745

 

 

 

95

 

 

 

2,840

 

Gas

 

 

738

 

 

 

 

 

 

738

 

NGL

 

 

871

 

 

 

 

 

 

871

 

Total marketing revenues from

   contracts with customers

 

 

4,354

 

 

 

95

 

 

 

4,449

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

9,674

 

 

$

1,060

 

 

$

10,734

 

21.

23.

Supplemental Information on Oil and Gas Operations (Unaudited)

Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country.

100


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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Costs Incurred

The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.

 

 

Year Ended December 31, 2018

 

 

U.S.

 

 

Canada

 

 

Total

 

Property acquisition costs:

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

 

$

2

 

 

$

 

 

$

2

 

Unproved properties

 

 

71

 

 

 

 

 

 

71

 

Exploration costs

 

 

679

 

 

 

85

 

 

 

764

 

Development costs

 

 

1,537

 

 

 

249

 

 

 

1,786

 

Costs incurred

 

$

2,289

 

 

$

334

 

 

$

2,623

 

  Year Ended December 31, 2015 

 

 

 

 

 

 

 

 

 

 

 

 

  U.S.   Canada   Total 

 

Year Ended December 31, 2017

 

  (Millions) 

 

U.S.

 

 

Canada

 

 

Total

 

Property acquisition costs:

      

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

  $193    $2    $195  

 

$

2

 

 

$

 

 

$

2

 

Unproved properties

   634     83     717  

 

 

50

 

 

 

4

 

 

 

54

 

Exploration costs

   478     109     587  

 

 

590

 

 

 

87

 

 

 

677

 

Development costs

   3,269     402     3,671  

 

 

1,036

 

 

 

225

 

 

 

1,261

 

  

 

   

 

   

 

 

Costs incurred

  $4,574    $596    $5,170  

 

$

1,678

 

 

$

316

 

 

$

1,994

 

  

 

   

 

   

 

 
  Year Ended December 31, 2014 

 

 

 

 

 

 

 

 

 

 

 

 

  U.S.   Canada   Total 

 

Year Ended December 31, 2016

 

  (Millions) 

 

U.S.

 

 

Canada

 

 

Total

 

Property acquisition costs:

      

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

  $5,210    $—      $5,210  

 

$

237

 

 

$

 

 

$

237

 

Unproved properties

   1,176     1     1,177  

 

 

1,356

 

 

 

2

 

 

 

1,358

 

Exploration costs

   270     52     322  

 

 

282

 

 

 

78

 

 

 

360

 

Development costs

   4,400     1,063     5,463  

 

 

875

 

 

 

54

 

 

 

929

 

  

 

   

 

   

 

 

Costs incurred

  $11,056    $1,116    $12,172  

 

$

2,750

 

 

$

134

 

 

$

2,884

 

  

 

   

 

   

 

 
  Year Ended December 31, 2013 
  U.S.   Canada   Total 
  (Millions) 

Property acquisition costs:

      

Proved properties

  $19    $3    $22  

Unproved properties

   213     3     216  

Exploration costs

   443     152     595  

Development costs

   3,838     1,251     5,089  
  

 

   

 

   

 

 

Costs incurred

  $4,513    $1,409    $5,922  
  

 

   

 

   

 

 

Costs incurred

Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.

Pursuant to the full cost method of accounting, Devon capitalizes certain of its G&A that is related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $372 million, $376 million and $368 million in 2015, 2014 and 2013, respectively. Also,Additionally, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $54$41 million, $45$69 million and $42$61 million in 2015, 20142018, 2017 and 2013,2016, respectively.

101


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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Capitalized Costs

The following tables reflect the aggregate capitalized costs related to oil and gas activities.

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

Proved properties

  $64,443    $13,747    $78,190  

Unproved properties

   1,352     1,232     2,584  
  

 

 

   

 

 

   

 

 

 

Total oil and gas properties

   65,795     14,979     80,774  

Accumulated DD&A

   (58,312   (11,185   (69,497
  

 

 

   

 

 

   

 

 

 

Net capitalized costs

  $7,483    $3,794    $11,277  
  

 

 

   

 

 

   

 

 

 
   December 31, 2014 
   U.S.   Canada   Total 
   (Millions) 

Proved properties

  $59,849    $15,889    $75,738  

Unproved properties

   1,460     1,292     2,752  
  

 

 

   

 

 

   

 

 

 

Total oil and gas properties

   61,309     17,181     78,490  

Accumulated DD&A

   (38,213   (11,347   (49,560
  

 

 

   

 

 

   

 

 

 

Net capitalized costs

  $23,096    $5,834    $28,930  
  

 

 

   

 

 

   

 

 

 

The following table presents a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2015.

   Costs Incurred In 
   2015   2014   2013   Prior to
2013
   Total 
   (Millions) 

Acquisition costs

  $672    $412    $61    $510    $1,655  

Exploration costs

   191     132     69     170     562  

Development costs

   9     28     17     128     182  

Capitalized interest

   50     37     32     66     185  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total oil and gas properties not subject to amortization

  $922    $609    $179    $874    $2,584  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Included in the $2.6 billion of oil and gas properties not subject to amortization are approximately $1.9 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada and the newly acquired Powder River Basin assets. Devon anticipates determining its Pike development timeline in mid-2016, with its 50% partner. Based on the development plans, Pike costs will begin to be included in the amortization computation when the first phase of this project is fully approved and Devon subsequently begins recognizing the associated proved reserves. Devon is evaluating and plans to develop the newly acquired Powder River Basin properties over the next four to five years.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Results of Operations

The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including DD&A and after giving effect to permanent differences.

 

  December 31, 2015 
  U.S.   Canada   Total 

 

Year Ended December 31, 2018

 

  (Millions) 

 

U.S.

 

 

Canada

 

 

Total

 

Oil, gas and NGL sales

  $4,356    $1,026    $5,382  

 

$

4,863

 

 

$

814

 

 

$

5,677

 

Lease operating expenses

   (1,551   (553   (2,104

General and administrative expenses

   (196   (28   (224

Production and property taxes

   (309   (33   (342

Production expenses

 

 

(1,620

)

 

 

(605

)

 

 

(2,225

)

Exploration expenses

 

 

(129

)

 

 

(48

)

 

 

(177

)

Depreciation, depletion and amortization

   (2,107   (474   (2,581

 

 

(1,234

)

 

 

(325

)

 

 

(1,559

)

Asset dispositions

 

 

262

 

 

 

 

 

 

262

 

Asset impairments

   (17,992   (1,257   (19,249

 

 

(109

)

 

 

 

 

 

(109

)

Accretion of asset retirement obligations

   (47   (27   (74

 

 

(35

)

 

 

(24

)

 

 

(59

)

Income tax benefit

   5,547     314     5,861  
  

 

   

 

   

 

 

Income tax (expense) benefit

 

 

(460

)

 

 

51

 

 

 

(409

)

Results of operations

  $(12,299  $(1,032  $(13,331

 

$

1,538

 

 

$

(137

)

 

$

1,401

 

  

 

   

 

   

 

 

Depreciation, depletion and amortization per Boe

  $10.21    $11.30    $10.40  

 

$

8.08

 

 

$

7.63

 

 

$

7.98

 

  

 

   

 

   

 

 
  December 31, 2014 
  U.S.   Canada   Total 
  (Millions) 

Oil, gas and NGL sales

  $7,867    $2,043    $9,910  

Lease operating expenses

   (1,559   (773   (2,332

General and administrative expenses

   (153   (57   (210

Production and property taxes

   (466   (37   (503

Depreciation, depletion and amortization

   (2,365   (531   (2,896

Gain on sale of assets

   —       1,077     1,077  

Accretion of asset retirement obligations

   (49   (39   (88

Income tax expense

   (1,199   (568   (1,767
  

 

   

 

   

 

 

Results of operations(1)

  $2,076    $1,115    $3,191  
  

 

   

 

   

 

 

Depreciation, depletion and amortization per Boe

  $11.41    $13.80    $11.79  
  

 

   

 

   

 

 
  December 31, 2013 
  U.S.   Canada   Total 
  (Millions) 

Oil, gas and NGL sales

  $5,964    $2,558    $8,522  

Lease operating expenses

   (1,257   (1,011   (2,268

General and administrative expenses

   (125   (77   (202

Production and property taxes

   (380   (59   (439

Depreciation, depletion and amortization

   (1,640   (825   (2,465

Asset impairments

   (1,110   (843   (1,953

Accretion of asset retirement obligations

   (47   (64   (111

Income tax benefit (expense)

   (510   88     (422
  

 

   

 

   

 

 

Results of operations

  $895    $(233  $662  
  

 

   

 

   

 

 

Depreciation, depletion and amortization per Boe

  $8.69    $12.87    $9.75  
  

 

   

 

   

 

 

 

(1)During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information.

 

 

Year Ended December 31, 2017

 

 

 

U.S.

 

 

Canada

 

 

Total

 

Oil, gas and NGL sales

 

$

3,746

 

 

$

1,404

 

 

$

5,150

 

Production expenses

 

 

(1,232

)

 

 

(591

)

 

 

(1,823

)

Exploration expenses

 

 

(346

)

 

 

(34

)

 

 

(380

)

Depreciation, depletion and amortization

 

 

(1,050

)

 

 

(369

)

 

 

(1,419

)

Asset dispositions

 

 

211

 

 

 

1

 

 

 

212

 

Accretion of asset retirement obligations

 

 

(38

)

 

 

(24

)

 

 

(62

)

Income tax expense

 

 

 

 

 

(104

)

 

 

(104

)

Results of operations

 

$

1,291

 

 

$

283

 

 

$

1,574

 

Depreciation, depletion and amortization per Boe

 

$

6.97

 

 

$

7.73

 

 

$

7.15

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

 

 

U.S.

 

 

Canada

 

 

Total

 

Oil, gas and NGL sales

 

$

3,198

 

 

$

984

 

 

$

4,182

 

Production expenses

 

 

(1,313

)

 

 

(492

)

 

 

(1,805

)

Exploration expenses

 

 

(176

)

 

 

(39

)

 

 

(215

)

Depreciation, depletion and amortization

 

 

(1,066

)

 

 

(380

)

 

 

(1,446

)

Asset dispositions

 

 

946

 

 

 

1

 

 

 

947

 

Asset impairments

 

 

(435

)

 

 

 

 

 

(435

)

Accretion of asset retirement obligations

 

 

(49

)

 

 

(26

)

 

 

(75

)

Income tax expense

 

 

 

 

 

(13

)

 

 

(13

)

Results of operations

 

$

1,105

 

 

$

35

 

 

$

1,140

 

Depreciation, depletion and amortization per Boe

 

$

6.11

 

 

$

7.75

 

 

$

6.47

 

102


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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Proved Reserves

The following tables presenttable presents Devon’s estimated proved reserves by product and by country.

 

   Oil (MMBbls) 
   U.S.   Canada   Total 

Proved developed and undeveloped reserves:

  

December 31, 2012

   205     65     270  

Revisions due to prices

   1     (1   —    

Revisions other than price

   (18   —       (18

Extensions and discoveries

   69     7     76  

Purchase of reserves

   1     —       1  

Production

   (28   (15   (43

Sale of reserves

   (1   —       (1
  

 

 

   

 

 

   

 

 

 

December 31, 2013

   229     56     285  

Revisions due to prices

   (1   —       (1

Revisions other than price

   (38   1     (37

Extensions and discoveries

   94     5     99  

Purchase of reserves

   132     —       132  

Production

   (48   (10   (58

Sale of reserves

   (17   (29   (46
  

 

 

   

 

 

   

 

 

 

December 31, 2014

   351     23     374  

Revisions due to prices

   (53   4     (49

Revisions other than price

   (52   2     (50

Extensions and discoveries

   51     3     54  

Purchase of reserves

   5     —       5  

Production

   (60   (10   (70
  

 

 

   

 

 

   

 

 

 

December 31, 2015

   242     22     264  
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2012

   166     62     228  

December 31, 2013

   194     56     250  

December 31, 2014

   255     23     278  

December 31, 2015

   203     22     225  

Proved developed-producing reserves as of:

      

December 31, 2012

   155     56     211  

December 31, 2013

   178     51     229  

December 31, 2014

   224     19     243  

December 31, 2015

   192     19     211  

Proved undeveloped reserves as of:

      

December 31, 2012

   39     3     42  

December 31, 2013

   35     —       35  

December 31, 2014

   96     —       96  

December 31, 2015

   39     —       39  

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Bitumen

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MMBbls)

 

 

(MMBbls)

 

 

Gas (Bcf)

 

 

(MMBbls)

 

 

Combined (MMBoe) (1)

 

 

 

U.S.

 

 

Canada

 

 

Total

 

 

Canada

 

 

U.S.

 

 

Canada

 

 

Total

 

 

U.S.

 

 

U.S.

 

 

Canada

 

 

Total

 

Proved developed and undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

242

 

 

 

22

 

 

 

264

 

 

 

520

 

 

 

5,808

 

 

 

13

 

 

 

5,821

 

 

 

428

 

 

 

1,638

 

 

 

544

 

 

 

2,182

 

Revisions due to prices

 

 

(18

)

 

 

(2

)

 

 

(20

)

 

 

23

 

 

 

(103

)

 

 

 

 

 

(103

)

 

 

(13

)

 

 

(48

)

 

 

21

 

 

 

(27

)

Revisions other than price

 

 

(2

)

 

 

3

 

 

 

1

 

 

 

(19

)

 

 

628

 

 

 

10

 

 

 

638

 

 

 

48

 

 

 

151

 

 

 

(14

)

 

 

137

 

Extensions and discoveries

 

 

36

 

 

 

2

 

 

 

38

 

 

 

 

 

 

280

 

 

 

 

 

 

280

 

 

 

42

 

 

 

124

 

 

 

2

 

 

 

126

 

Purchase of reserves

 

 

8

 

 

 

 

 

 

8

 

 

 

 

 

 

33

 

 

 

 

 

 

33

 

 

 

7

 

 

 

20

 

 

 

 

 

 

20

 

Production

 

 

(47

)

 

 

(8

)

 

 

(55

)

 

 

(40

)

 

 

(510

)

 

 

(7

)

 

 

(517

)

 

 

(42

)

 

 

(174

)

 

 

(49

)

 

 

(223

)

Sale of reserves

 

 

(25

)

 

 

 

 

 

(25

)

 

 

 

 

 

(521

)

 

 

 

 

 

(521

)

 

 

(45

)

 

 

(157

)

 

 

 

 

 

(157

)

December 31, 2016

 

 

194

 

 

 

17

 

 

 

211

 

 

 

484

 

 

 

5,615

 

 

 

16

 

 

 

5,631

 

 

 

425

 

 

 

1,554

 

 

 

504

 

 

 

2,058

 

Revisions due to prices

 

 

12

 

 

 

(1

)

 

 

11

 

 

 

(37

)

 

 

398

 

 

 

1

 

 

 

399

 

 

 

32

 

 

 

111

 

 

 

(38

)

 

 

73

 

Revisions other than price

 

 

6

 

 

 

2

 

 

 

8

 

 

 

(10

)

 

 

 

 

 

2

 

 

 

2

 

 

 

(10

)

 

 

(5

)

 

 

(7

)

 

 

(12

)

Extensions and discoveries

 

 

90

 

 

 

4

 

 

 

94

 

 

 

12

 

 

 

403

 

 

 

 

 

 

403

 

 

 

63

 

 

 

221

 

 

 

16

 

 

 

237

 

Production

 

 

(42

)

 

 

(7

)

 

 

(49

)

 

 

(40

)

 

 

(433

)

 

 

(6

)

 

 

(439

)

 

 

(36

)

 

 

(150

)

 

 

(48

)

 

 

(198

)

Sale of reserves

 

 

(3

)

 

 

 

 

 

(3

)

 

 

 

 

 

(9

)

 

 

 

 

 

(9

)

 

 

(1

)

 

 

(6

)

 

 

 

 

 

(6

)

December 31, 2017

 

 

257

 

 

 

15

 

 

 

272

 

 

 

409

 

 

 

5,974

 

 

 

13

 

 

 

5,987

 

 

 

473

 

 

 

1,725

 

 

 

427

 

 

 

2,152

 

Revisions due to prices

 

 

12

 

 

 

1

 

 

 

13

 

 

 

10

 

 

 

94

 

 

 

(3

)

 

 

91

 

 

 

12

 

 

 

40

 

 

 

11

 

 

 

51

 

Revisions other than price

 

 

(10

)

 

 

2

 

 

 

(8

)

 

 

2

 

 

 

(163

)

 

 

(4

)

 

 

(167

)

 

 

(23

)

 

 

(60

)

 

 

3

 

 

 

(57

)

Extensions and discoveries

 

 

93

 

 

 

5

 

 

 

98

 

 

 

7

 

 

 

446

 

 

 

 

 

 

446

 

 

 

64

 

 

 

232

 

 

 

11

 

 

 

243

 

Production

 

 

(47

)

 

 

(7

)

 

 

(54

)

 

 

(35

)

 

 

(397

)

 

 

(4

)

 

 

(401

)

 

 

(39

)

 

 

(153

)

 

 

(42

)

 

 

(195

)

Sale of reserves

 

 

(7

)

 

 

 

 

 

(7

)

 

 

 

 

 

(1,195

)

 

 

 

 

 

(1,195

)

 

 

(61

)

 

 

(267

)

 

 

 

 

 

(267

)

December 31, 2018

 

 

298

 

 

 

16

 

 

 

314

 

 

 

393

 

 

 

4,759

 

 

 

2

 

 

 

4,761

 

 

 

426

 

 

 

1,517

 

 

 

410

 

 

 

1,927

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

203

 

 

 

22

 

 

 

225

 

 

 

219

 

 

 

5,694

 

 

 

13

 

 

 

5,707

 

 

 

411

 

 

 

1,563

 

 

 

243

 

 

 

1,806

 

December 31, 2016

 

 

160

 

 

 

17

 

 

 

177

 

 

 

190

 

 

 

5,361

 

 

 

16

 

 

 

5,377

 

 

 

387

 

 

 

1,439

 

 

 

210

 

 

 

1,649

 

December 31, 2017

 

 

178

 

 

 

15

 

 

 

193

 

 

 

200

 

 

 

5,619

 

 

 

13

 

 

 

5,632

 

 

 

410

 

 

 

1,524

 

 

 

218

 

 

 

1,742

 

December 31, 2018

 

 

198

 

 

 

16

 

 

 

214

 

 

 

187

 

 

 

4,331

 

 

 

2

 

 

 

4,333

 

 

 

359

 

 

 

1,278

 

 

 

204

 

 

 

1,482

 

Proved developed-producing reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

192

 

 

 

19

 

 

 

211

 

 

 

219

 

 

 

5,546

 

 

 

13

 

 

 

5,559

 

 

 

393

 

 

 

1,509

 

 

 

240

 

 

 

1,749

 

December 31, 2016

 

 

143

 

 

 

13

 

 

 

156

 

 

 

190

 

 

 

5,243

 

 

 

16

 

 

 

5,259

 

 

 

370

 

 

 

1,386

 

 

 

207

 

 

 

1,593

 

December 31, 2017

 

 

165

 

 

 

12

 

 

 

177

 

 

 

197

 

 

 

5,512

 

 

 

13

 

 

 

5,525

 

 

 

397

 

 

 

1,481

 

 

 

212

 

 

 

1,693

 

December 31, 2018

 

 

189

 

 

 

12

 

 

 

201

 

 

 

187

 

 

 

4,261

 

 

 

2

 

 

 

4,263

 

 

 

349

 

 

 

1,249

 

 

 

199

 

 

 

1,448

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

39

 

 

 

 

 

 

39

 

 

 

301

 

 

 

114

 

 

 

 

 

 

114

 

 

 

17

 

 

 

75

 

 

 

301

 

 

 

376

 

December 31, 2016

 

 

34

 

 

 

 

 

 

34

 

 

 

294

 

 

 

254

 

 

 

 

 

 

254

 

 

 

38

 

 

 

115

 

 

 

294

 

 

 

409

 

December 31, 2017

 

 

79

 

 

 

 

 

 

79

 

 

 

209

 

 

 

355

 

 

 

 

 

 

355

 

 

 

63

 

 

 

201

 

 

 

209

 

 

 

410

 

December 31, 2018

 

 

100

 

 

 

 

 

 

100

 

 

 

206

 

 

 

428

 

 

 

 

 

 

428

 

 

 

67

 

 

 

239

 

 

 

206

 

 

 

445

 

 

   Bitumen (MMBbls) 
   U.S.   Canada   Total 

Proved developed and undeveloped reserves:

  

December 31, 2012

   —       528     528  

Revisions due to prices

   —       (11   (11

Revisions other than price

   —       16     16  

Extensions and discoveries

   —       38     38  

Production

   —       (19   (19
  

 

 

   

 

 

   

 

 

 

December 31, 2013

   —       552     552  

Revisions due to prices

   —       (37   (37

Revisions other than price

   —       18     18  

Extensions and discoveries

   —       8     8  

Production

   —       (20   (20
  

 

 

   

 

 

   

 

 

 

December 31, 2014

   —       521     521  

Revisions due to prices

   —       103     103  

Revisions other than price

   —       (84   (84

Extensions and discoveries

   —       11     11  

Production

   —       (31   (31
  

 

 

   

 

 

   

 

 

 

December 31, 2015

   —       520     520  
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2012

   —       99     99  

December 31, 2013

   —       111     111  

December 31, 2014

   —       137     137  

December 31, 2015

   —       219     219  

Proved developed-producing reserves as of:

      

December 31, 2012

   —       99     99  

December 31, 2013

   —       111     111  

December 31, 2014

   —       137     137  

December 31, 2015

   —       219     219  

Proved undeveloped reserves as of:

      

December 31, 2012

   —       429     429  

December 31, 2013

   —       441     441  

December 31, 2014

   —       384     384  

December 31, 2015

   —       301     301  

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

   Gas (Bcf) 
   U.S.   Canada   Total 

Proved developed and undeveloped reserves:

  

December 31, 2012

   8,762     684     9,446  

Revisions due to prices

   405     161     566  

Revisions other than price

   (299   67     (232

Extensions and discoveries

   471     19     490  

Purchase of reserves

   1     —       1  

Production

   (709   (165   (874

Sale of reserves

   (81   (8   (89
  

 

 

   

 

 

   

 

 

 

December 31, 2013

   8,550     758     9,308  

Revisions due to prices

   191     45     236  

Revisions other than price

   (299   4     (295

Extensions and discoveries

   335     8     343  

Purchase of reserves

   457     —       457  

Production

   (660   (41   (701

Sale of reserves

   (923   (738   (1,661
  

 

 

   

 

 

   

 

 

 

December 31, 2014

   7,651     36     7,687  

Revisions due to prices

   (1,412   (9   (1,421

Revisions other than price

   (3   (6   (9

Extensions and discoveries

   171     —       171  

Purchase of reserves

   17     —       17  

Production

   (579   (8   (587

Sale of reserves

   (37   —       (37
  

 

 

   

 

 

   

 

 

 

December 31, 2015

   5,808     13     5,821  
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2012

   7,391     679     8,070  

December 31, 2013

   7,707     752     8,459  

December 31, 2014

   6,948     36     6,984  

December 31, 2015

   5,694     13     5,707  

Proved developed-producing reserves as of:

      

December 31, 2012

   7,091     624     7,715  

December 31, 2013

   7,425     680     8,105  

December 31, 2014

   6,746     34     6,780  

December 31, 2015

   5,546     13     5,559  

Proved undeveloped reserves as of:

      

December 31, 2012

   1,371     5     1,376  

December 31, 2013

   843     6     849  

December 31, 2014

   703     —       703  

December 31, 2015

   114     —       114  

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

   Natural Gas Liquids (MMBbls) 
     U.S.       Canada       Total   

Proved developed and undeveloped reserves:

  

December 31, 2012

   571     20     591  

Revisions due to prices

   8     3     11  

Revisions other than price

   (50   3     (47

Extensions and discoveries

   64     1     65  

Production

   (41   (4   (45
  

 

 

   

 

 

   

 

 

 

December 31, 2013

   552     23     575  

Revisions due to prices

   7     1     8  

Revisions other than price

   2     —       2  

Extensions and discoveries

   47     —       47  

Purchase of reserves

   57     —       57  

Production

   (50   (1   (51

Sale of reserves

   (37   (23   (60
  

 

 

   

 

 

   

 

 

 

December 31, 2014

   578     —       578  

Revisions due to prices

  ��(119   —       (119

Revisions other than price

   (6   —       (6

Extensions and discoveries

   24     —       24  

Purchase of reserves

   1     —       1  

Production

   (50   —       (50
  

 

 

   

 

 

   

 

 

 

December 31, 2015

   428     —       428  
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2012

   431     20     451  

December 31, 2013

   468     23     491  

December 31, 2014

   486     —       486  

December 31, 2015

   411     —       411  

Proved developed-producing reserves as of:

      

December 31, 2012

   406     19     425  

December 31, 2013

   442     21     463  

December 31, 2014

   467     —       467  

December 31, 2015

   393     —       393  

Proved undeveloped reserves as of:

      

December 31, 2012

   140     —       140  

December 31, 2013

   84     —       84  

December 31, 2014

   92     —       92  

December 31, 2015

   17     —       17  

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

   Total (MMBoe)(1) 
   U.S.   Canada   Total 

Proved developed and undeveloped reserves:

  

December 31, 2012

   2,236     727     2,963  

Revisions due to prices

   76     18     94  

Revisions other than price

   (117   29     (88

Extensions and discoveries

   212     49     261  

Purchase of reserves

   1     —       1  

Production

   (189   (64   (253

Sale of reserves

   (14   (1   (15
  

 

 

   

 

 

   

 

 

 

December 31, 2013

   2,205     758     2,963  

Revisions due to prices

   38     (29   9  

Revisions other than price

   (86   21     (65

Extensions and discoveries

   197     14     211  

Purchase of reserves

   265     —       265  

Production

   (207   (39   (246

Sale of reserves

   (207   (176   (383
  

 

 

   

 

 

   

 

 

 

December 31, 2014

   2,205     549     2,754  

Revisions due to prices

   (408   106     (302

Revisions other than price

   (59   (83   (142

Extensions and discoveries

   104     14     118  

Purchase of reserves

   9     —       9  

Production

   (206   (42   (248

Sale of reserves

   (7   —       (7
  

 

 

   

 

 

   

 

 

 

December 31, 2015

   1,638     544     2,182  
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2012

   1,829     294     2,123  

December 31, 2013

   1,947     315     2,262  

December 31, 2014

   1,900     165     2,065  

December 31, 2015

   1,563     243     1,806  

Proved developed-producing reserves as of:

      

December 31, 2012

   1,743     278     2,021  

December 31, 2013

   1,857     297     2,154  

December 31, 2014

   1,815     162     1,977  

December 31, 2015

   1,509     240     1,749  

Proved undeveloped reserves as of:

      

December 31, 2012

   407     433     840  

December 31, 2013

   258     443     701  

December 31, 2014

   305     384     689  

December 31, 2015

   75     301     376  

(1)

Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil.

103


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Proved Undeveloped Reserves

The following table presents the changes in Devon’s total proved undeveloped reserves during 20152018 (MMBoe).

 

 

U.S.

 

 

Canada

 

 

Total

 

  U.S.   Canada   Total 

Proved undeveloped reserves as of December 31, 2014

   305     384     689  

Proved undeveloped reserves as of December 31, 2017

 

 

201

 

 

 

209

 

 

 

410

 

Extensions and discoveries

   13     11     24  

 

 

107

 

 

 

6

 

 

 

113

 

Revisions due to prices

   (115   80     (35

 

 

1

 

 

 

6

 

 

 

7

 

Revisions other than price

   (40   (80   (120

 

 

(8

)

 

 

(15

)

 

 

(23

)

Sale of reserves

 

 

(10

)

 

 

 

 

 

(10

)

Conversion to proved developed reserves

   (88   (94   (182

 

 

(52

)

 

 

 

 

 

(52

)

  

 

   

 

   

 

 

Proved undeveloped reserves as of December 31, 2015

   75     301     376  
  

 

   

 

   

 

 

Proved undeveloped reserves as of December 31, 2018

 

 

239

 

 

 

206

 

 

 

445

 

Proved

Total proved undeveloped reserves decreased 45%increased 9% from year-end 20142017 to year-end 2015, and2018 with the year-end 20152018 balance represents 17%representing 23% of total proved reserves. DrillingDevon’s focus on drilling and development activities increased Devon’s proved undeveloped reserves 24in the STACK and Delaware Basin was the primary driver of the 113 MMBoe in extensions and resulteddiscoveries. Continued development primarily in the STACK and Delaware Basin led to the conversion of 18252 MMBoe, or 26%, of the 20142017 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $2.2 billion$691 million for 2015. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 120 MMBoe primarily due to evaluations of certain properties in the U.S. and Canada. The largest revisions, which reduced reserves by 80 MMBoe, relate to evaluations of Jackfish bitumen reserves. Of the 40 MMBoe revisions recorded for U.S. properties, a reduction of approximately 27 MMBoe represents reserves that Devon now does not expect to develop in the next five years, including 20 MMBoe attributable to the Eagle Ford.2018.     

A significant amount of Devon’s proved undeveloped reserves at the end of 20152018 related to its Jackfish operations. At December 31, 20152018 and 2014,2017, Devon’s Jackfish proved undeveloped reserves were 301206 MMBoe and 384209 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35 MBbl daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than 5five years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends through to 2030.2032. At the end of 2015,2018, approximately 184125 MMBoe of proved undeveloped reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of the reserves. Furthermore, approximately 18081 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop.

104


Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Price Revisions

2015Reserves increased 40 MMBoe in the U.S. primarily due to price increases in the trailing 12 month average for oil, gas and NGLs in 2018. Reserves increased 11 MMBoe in Canada due to a decrease in the trailing 12 month average price for bitumen in 2018. The decreased price has the effect of decreasing the applicable royalties, which increases the after-royalty volumes.

Reserves increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12 month average for oil, gas and NGLs in 2017. Reserves decreased 30238 MMBoe in Canada due to a significant increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing the royalties, which decreases the after-royalty volumes.

Reserves decreased 27 MMBoe during 2016 primarily due to lower commodity prices across all products.for oil and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes.

2014 – Reserves increased 9 MMBoe primarily due to higher gas prices in the Barnett Shale and the Anadarko Basin, partially offset by higher bitumen prices, which result in lower after-royalty volumes, in Canada.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2013 – Reserves increased 94 MMBoe primarily due to higher gas prices. Of this increase, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area.

Revisions Other Than Price

Total revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish are primarily due to a refined reserves methodology that resulted in a reduced recovery factor. Revisions other than price in 2014 and 20132018 primarily related to Devon’s evaluation of certain oil and dry gas regions, with the largest revisions being made in the Cana-WoodfordSTACK.

Total revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and NGLs, with the largest revisions being made in the Barnett Shale and Barnett Shale.STACK (Cana-Woodford Shale).

Extensions and Discoveries

20152018 Of Approximately 72% of the 118 MMBoe of extensionsadditions were through our focused efforts in the STACK (87 MMBoe) and discoveries, 38 MMBoe related to the Delaware Basin 30 MMBoe related to(88 MMBoe). The remaining extensions were added throughout the Anadarko Basin, 21 MMBoe related to the Eagle Ford and 11 MMBoe related to Jackfish.remainder of Devon’s portfolio.

The 20152018 extensions and discoveries included 1321 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 11 MMBoe at Jackfish.

2014 – Of the 211 MMBoe of extensions and discoveries, 70 MMBoe relatedrelating to the PermianSTACK.

2017 – Over 80% of the additions were through our focused efforts in the STACK (120 MMBoe) and the Delaware Basin 54 MMBoe related to(79 MMBoe). The remaining extensions were added throughout the Eagle Ford, 36 MMBoe related to the Barnett Shale, 14 MMBoe related to the Anadarko Basin, 8 MMBoe related to Jackfish and 14 MMBoe related to the Mississippian-Woodford Trend.remainder of Devon’s portfolio.

The 20142017 extensions and discoveries included 566 MMBoe related to additions from Devon’s infill drilling activities primarily consisting of 4 MMBoe atrelated to the Permian Basin.STACK.

20132016 Of the 261126 MMBoe of extensions and discoveries, 7697 MMBoe related to STACK, 18 MMBoe related to the PermianDelaware Basin 54and 7 MMBoe related to the Barnett Shale, 42 MMBoe related to the Anadarko Basin, 38 MMBoe related to Jackfish and 32 MMBoe related to the Mississippian-Woodford Trend.Eagle Ford.

The 20132016 extensions and discoveries included 17574 MMBoe related to additions from Devon’s infill drilling activities including 23 MMBoe atprimarily related to the Cana-Woodford Shale, 54 MMBoe at the Barnett Shale, 38 MMBoe at Jackfish, 33 MMBoe at the Permian Basin and 20 MMBoe at the Mississippian-Woodford Trend.STACK.

Purchase of Reserves

20152016 Of the 9 MMBoe of reserves purchases, 6 MMBoe Primarily related to Devon’s acquisition in the Powder River Basin.STACK play.

2014 – Of the 265 MMBoe105


Table of reserves purchases, 246 MMBoe relatedContents

Index to Devon’s GeoSouthern acquisition in the Eagle Ford.Financial Statements

Sale of Reserves

2015 – The 7 MMBoe of reserves sales related to Devon’s asset divestitures in the San Juan Basin.

2014 – The total 383 MMBoe of reserves sales related to Devon’s asset divestitures in the U.S. and Canada.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Sale of Reserves

Related to Devon’s 2018, 2017 and 2016 U.S. non-core asset divestitures as discussed further in Note 2.

Standardized Measure

The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.

 

 

Year Ended December 31, 2018

 

 

U.S.

 

 

Canada

 

 

Total

 

Future cash inflows

 

$

40,183

 

 

$

9,146

 

 

$

49,329

 

Future costs:

 

 

 

 

 

 

 

 

 

 

 

 

Development

 

 

(3,444

)

 

 

(1,558

)

 

 

(5,002

)

Production

 

 

(18,107

)

 

 

(5,445

)

 

 

(23,552

)

Future income tax expense

 

 

(2,969

)

 

 

 

 

 

(2,969

)

Future net cash flow

 

 

15,663

 

 

 

2,143

 

 

 

17,806

 

10% discount to reflect timing of cash flows

 

 

(6,897

)

 

 

(717

)

 

 

(7,614

)

Standardized measure of discounted future net cash flows

 

$

8,766

 

 

$

1,426

 

 

$

10,192

 

  Year Ended December 31, 2015 

 

 

 

 

 

 

 

 

 

 

 

 

  U.S.   Canada   Total 

 

Year Ended December 31, 2017

 

  (Millions) 

 

U.S.

 

 

Canada

 

 

Total

 

Future cash inflows

  $27,398    $13,047    $40,445  

 

$

34,701

 

 

$

13,602

 

 

$

48,303

 

Future costs:

      

 

 

 

 

 

 

 

 

 

 

 

 

Development

   (3,306   (2,759   (6,065

 

 

(3,316

)

 

 

(1,853

)

 

 

(5,169

)

Production

   (17,251   (6,891   (24,142

 

 

(15,526

)

 

 

(5,986

)

 

 

(21,512

)

Future income tax expense

   —       (475   (475

 

 

 

 

 

(988

)

 

 

(988

)

  

 

   

 

   

 

 

Future net cash flow

   6,841     2,922     9,763  

 

 

15,859

 

 

 

4,775

 

 

 

20,634

 

10% discount to reflect timing of cash flows

   (1,973   (1,102   (3,075

 

 

(7,541

)

 

 

(1,756

)

 

 

(9,297

)

  

 

   

 

   

 

 

Standardized measure of discounted future net cash flows

  $4,868    $1,820    $6,688  

 

$

8,318

 

 

$

3,019

 

 

$

11,337

 

  

 

   

 

   

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

 

U.S.

 

 

Canada

 

 

Total

 

Future cash inflows

 

$

22,847

 

 

$

9,672

 

 

$

32,519

 

Future costs:

 

 

 

 

 

 

 

 

 

 

 

 

Development

 

 

(2,784

)

 

 

(2,201

)

 

 

(4,985

)

Production

 

 

(11,934

)

 

 

(6,049

)

 

 

(17,983

)

Future income tax expense

 

 

 

 

 

(121

)

 

 

(121

)

Future net cash flow

 

 

8,129

 

 

 

1,301

 

 

 

9,430

 

10% discount to reflect timing of cash flows

 

 

(3,524

)

 

 

(466

)

 

 

(3,990

)

Standardized measure of discounted future net cash flows

 

$

4,605

 

 

$

835

 

 

$

5,440

 

 

   Year Ended December 31, 2014 
   U.S.   Canada   Total 
   (Millions) 

Future cash inflows

  $75,847    $31,371    $107,218  

Future costs:

      

Development

   (7,168   (3,619   (10,787

Production

   (29,740   (14,232   (43,972

Future income tax expense

   (11,021   (3,026   (14,047
  

 

 

   

 

 

   

 

 

 

Future net cash flow

   27,918     10,494     38,412  

10% discount to reflect timing of cash flows

   (12,819   (5,119   (17,938
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

  $15,099    $5,375    $20,474  
  

 

 

   

 

 

   

 

 

 

   Year Ended December 31, 2013 
   U.S.   Canada   Total 
   (Millions) 

Future cash inflows

  $61,983    $33,305    $95,288  

Future costs:

      

Development

   (5,448   (5,308   (10,756

Production

   (26,663   (15,709   (42,372

Future income tax expense

   (9,046   (2,327   (11,373
  

 

 

   

 

 

   

 

 

 

Future net cash flow

   20,826     9,961     30,787  

10% discount to reflect timing of cash flows

   (10,346   (4,700   (15,046
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

  $10,480    $5,261    $15,741  
  

 

 

   

 

 

   

 

 

 

Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 20152018 estimates, Devon’s future realized prices were assumed to be $44.33$58.64 per Bbl of oil, $23.84$22.12 per Bbl of bitumen, $2.06$2.45 per Mcf of gas and $10.11$24.72 per Bbl of NGLs. Of the $6.1$5.0 billion of future development costs as of the end of 2015, $0.62018, $1.2 billion, $0.6 billion and $0.4$0.3 billion are estimated to be spent in 2016, 20172019, 2020 and 2018,2021, respectively.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Future development costs include not only development costs but also future asset retirement costs. Included as part of the $6.1$5.0 billion of future development costs are $1.2$1.4 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.

The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:

 

 Year Ended December 31, 
 2015 2014 2013 

 

Year Ended December 31,

 

 (Millions) 

 

2018

 

 

2017

 

 

2016

 

Beginning balance

 $20,474   $15,741   $13,221  

 

$

11,337

 

 

$

5,440

 

 

$

7,883

 

Net changes in prices and production costs

  (20,756  2,561    3,018  

 

 

(243

)

 

 

5,218

 

 

 

(2,027

)

Oil, bitumen, gas and NGL sales, net of production costs

  (2,704  (6,865  (5,613

 

 

(3,452

)

 

 

(3,327

)

 

 

(2,377

)

Changes in estimated future development costs

  1,313    (768  399  

 

 

(216

)

 

 

789

 

 

 

112

 

Extensions and discoveries, net of future development costs

  1,129    4,836    4,047  

 

 

3,139

 

 

 

2,497

 

 

 

674

 

Purchase of reserves

  95    6,422    14  

 

 

 

 

 

2

 

 

 

224

 

Sales of reserves in place

  (79  (2,384  (44

 

 

(588

)

 

 

(3

)

 

 

(577

)

Revisions of quantity estimates

  (1,451  (746  (1,040

 

 

(414

)

 

 

(318

)

 

 

(21

)

Previously estimated development costs incurred during the period

  2,158    1,933    1,986  

 

 

962

 

 

 

559

 

 

 

663

 

Accretion of discount

  567    1,746    1,940  

 

 

960

 

 

 

1,034

 

 

 

537

 

Foreign exchange and other

  (1,254  (107  (583

 

 

(329

)

 

 

(7

)

 

 

72

 

Net change in income taxes

  7,196    (1,895  (1,604

 

 

(964

)

 

 

(547

)

 

 

277

 

 

 

  

 

  

 

 

Ending balance

 $6,688   $20,474   $15,741  

 

$

10,192

 

 

$

11,337

 

 

$

5,440

 

 

 

  

 

  

 

 

 

22.

24.

Supplemental Quarterly Financial Information (Unaudited)

The following tables present a summary of Devon’s unaudited interim results of operations.

 

   2015 
   First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
  Full
Year
 
   (Millions, except per share amounts) 

Operating revenues

  $3,265   $3,393   $3,601   $2,886   $13,145  

Loss before income taxes

  $(5,624 $(4,479 $(5,623 $(5,542 $(21,268

Net loss attributable to Devon

  $(3,599 $(2,816 $(3,507 $(4,532 $(14,454

Basic net loss per share attributable to Devon

  $(8.88 $(6.94 $(8.64 $(11.12 $(35.55

Diluted net loss per share attributable to Devon

  $(8.88 $(6.94 $(8.64 $(11.12 $(35.55
   2014 
   First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
  Full
Year
 
   (Millions, except per share amounts) 

Operating revenues

  $3,725   $4,510   $5,336   $5,995   $19,566  

Earnings before income taxes

  $560   $1,554   $1,654   $291   $4,059  

Net earnings (loss) attributable to Devon

  $324   $675   $1,016   $(408 $1,607  

Basic net earnings (loss) per share attributable to Devon

  $0.80   $1.65   $2.48   $(1.01 $3.93  

Diluted net earnings (loss) per share attributable to Devon

  $0.79   $1.64   $2.47   $(1.01 $3.91  

 

 

2018

 

 

 

First Quarter

 

 

Second Quarter

 

 

Third Quarter

 

 

Fourth Quarter

 

 

Full Year

 

Total revenues

 

$

2,198

 

 

$

2,249

 

 

$

2,579

 

 

$

3,708

 

 

$

10,734

 

Asset dispositions (1)

 

$

(12

)

 

$

23

 

 

$

(6

)

 

$

(268

)

 

$

(263

)

Earnings (loss) from continuing operations before income taxes (2)

 

$

(245

)

 

$

(481

)

 

$

162

 

 

$

1,484

 

 

$

920

 

Net earnings (loss) from continuing operations

 

$

(211

)

 

$

(474

)

 

$

300

 

 

$

1,149

 

 

$

764

 

Net earnings from discontinued operations, net of income

   tax expense (3)

 

$

58

 

 

$

139

 

 

$

2,263

 

 

$

 

 

$

2,460

 

Net earnings (loss) attributable to Devon

 

$

(197

)

 

$

(425

)

 

$

2,537

 

 

$

1,149

 

 

$

3,064

 

Basic net earnings (loss) per share attributable to Devon

 

$

(0.38

)

 

$

(0.83

)

 

$

5.17

 

 

$

2.50

 

 

$

6.14

 

Diluted net earnings (loss) per share attributable to Devon

 

$

(0.38

)

 

$

(0.83

)

 

$

5.14

 

 

$

2.48

 

 

$

6.10

 

 

 

2017

 

 

 

First Quarter

 

 

Second Quarter

 

 

Third Quarter

 

 

Fourth Quarter

 

 

Full Year

 

Total revenues

 

$

2,400

 

 

$

2,165

 

 

$

1,933

 

 

$

2,380

 

 

$

8,878

 

Asset dispositions (1)

 

$

(8

)

 

$

(22

)

 

$

(170

)

 

$

(17

)

 

$

(217

)

Earnings from continuing operations before income taxes

 

$

313

 

 

$

207

 

 

$

207

 

 

$

46

 

 

$

773

 

Net earnings from continuing operations

 

$

308

 

 

$

212

 

 

$

194

 

 

$

44

 

 

$

758

 

Net earnings from discontinued operations, net of income

   tax expense

 

$

9

 

 

$

33

 

 

$

18

 

 

$

260

 

 

$

320

 

Net earnings attributable to Devon

 

$

303

 

 

$

219

 

 

$

193

 

 

$

183

 

 

$

898

 

Basic net earnings per share attributable to Devon

 

$

0.58

 

 

$

0.41

 

 

$

0.37

 

 

$

0.35

 

 

$

1.71

 

Diluted net earnings per share attributable to Devon

 

$

0.58

 

 

$

0.41

 

 

$

0.37

 

 

$

0.35

 

 

$

1.70

 

(1)

Additional discussion regarding asset dispositions can be found in Note 2.

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(2)

Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5.

(3)

Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19.

 

Net Earnings (Loss) Attributable108


Table of Contents

Index to DevonFinancial Statements

The 2015 quarterly results include asset impairments of $5.5 billion (or $13.46 per diluted share), $4.2 billion (or $10.27 per diluted share), $5.9 billion ($14.41 per diluted share) and $5.3 billion (or $13.09 per diluted share) for the first quarter through the fourth quarter of 2015, respectively, as discussed in Note 5.

The fourth quarter of 2014 includes asset impairments of $1.9 billion (or $4.79 per diluted share) as discussed in Note 5.

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

Not Applicable.applicable.

Item 9A.Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 20152018 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control – Integrated Frameworkissued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, which was completed on February 17, 2016,20, 2019, management concluded that its internal control over financial reporting was effective as of December 31, 2015.2018.

The effectiveness of our internal control over financial reporting as of December 31, 20152018 has been audited by KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as of and for the year ended December 31, 2015,2018, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” of this report.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the fourth quarter of 20152018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.Other Information

Not Applicable.

applicable.

109


Table of Contents

Index to Financial Statements

PART III

Item 10.Directors, Executive Officers and Corporate Governance

The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018.

Item 11.Executive Compensation

The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018.

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

The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018.

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

The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018.

Item 14.Principal Accountant Fees and Services

The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.

120 days following the fiscal year ended December 31, 2018.

110


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Index to Financial Statements

PART IV

Item 15.Exhibits and Financial Statement Schedules

(a) The following documents are filedincluded as part of this report:

1. Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report.

2. Consolidated Financial Statement Schedules

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.

3. Exhibits

 

Exhibit No.

Description

Exhibit No.

Description

  2.1

1.1

Underwriting

Purchase Agreement, dated June 11, 2015,7, 2018, by and among Registrant and Goldman, Sachs & Co. and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed June 16, 2015; File No. 001-32318).

1.2Underwriting Agreement dated December 10, 2015, by and among Registrant and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed December 15, 2015; File No. 001-32318).
2.1Agreement and Plan of Merger dated October 21, 2013, by and among Registrant, Devon Gas Services, L.P., Acacia Natural and Southwestern Gas Corp I, Inc., Crosstex Energy, Inc., New Public RangersPipeline, L.L.C., Boomer Merger Sub, Inc.as sellers, and Rangers Merger Sub, Inc. (incorporatedEnlink Midstream Manager, LLC, Registrant, and GIP III Stetson I, L.P. and GIP III Stetson II, L.P., as acquirors (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed October 22, 2013;June 7, 2018; File No. 001-32318)001-32318).

2.2

  3.1

Contribution Agreement dated October 21, 2013, by and among Registrant, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., Crosstex Energy, L.P. and Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed October 22, 2013; File No. 001-32318).
2.3Purchase and Sale Agreement dated November 20, 2013, among GeoSouthern Intermediate Holdings, LLC, GeoSouthern Energy Corporation (solely with respect to certain sections specified therein), and Devon Energy Production Company, L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K/A filed May 19, 2014; File No. 001-32318).
2.4Letter Agreement dated February 28, 2014 amending certain provisions of the Purchase and Sale Agreement dated November 20, 2013 among GeoSouthern Intermediate Holdings, LLC, GeoSouthern Energy Corporation and Devon Energy Production Company, L.P (incorporated by reference to Exhibit 2.4 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318).
3.1

Registrant’s Restated Certificate of Incorporation (incorporated(incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K for the fiscal year ending December 31, 2012;filed February 21, 2013; File No. 001-32318)001-32318).

3.2

Registrant’s Bylaws (incorporated(incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed January 27, 2016; File No. 001-32318)001-32318).

4.1Registration Rights Agreement dated January 7, 2016, among Registrant and EnCap FEx Holdings, LLC, Felix Stack Investments, LLC, Felix STACK Holdings, LLC and the other selling stockholders from time to time party thereto.

Exhibit No.

Description

  4.1

  4.2

Registration Rights Agreement dated December 17, 2015, among Registrant and NewWoods Petroleum, LLC and the other selling stockholders from time to time party thereto.
  4.3

Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318)001-32318).

  4.4

  4.2

Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated(incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318)001-32318).

  4.5

  4.3

Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 3.250% Senior Notes due 2022 and the 4.750% Senior Notes due 2042 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012; File No. 001-32318)001-32318).

  4.6

  4.4

Supplemental Indenture No. 3, dated as of December 19, 2013, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the Floating Rate Senior Notes due 2016 and the 2.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 19, 2013; File No. 001-32318).
  4.7

Supplemental Indenture No. 4, dated as of June 16, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.000% Senior Notes due 2045 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed June 16, 2015; File No. 001-32318)001-32318).

  4.8

  4.5

Supplemental Indenture No. 5, dated as of December 15, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.850% Senior Notes due 2025 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 15, 2015; File No. 001-32318)001-32318).

  4.9

  4.6

Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee (incorporated(incorporated by reference to Exhibit 4.1 of Registrant’sForm 8-K filed April 9, 2002; File No. 000-30176)000-30176).

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Index to Financial Statements

Exhibit No.

Description

4.10

  4.7

Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated(incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed April 9, 2002; File No.000-30176) 000-30176).

4.11

  4.8

Supplemental Indenture No. 3, dated as of January 9, 2009, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 6.30% Senior Notes due 2019 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed January 9, 2009; File No.000-32318) 000-32318).

4.12

  4.9

Supplemental Indenture No. 4, dated as of March 22, 2018, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Notes due 2032 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed March 22, 2018; File No. 000-32318).

  4.10

Indenture, dated as of October 3, 2001, by and among Devon Financing Company, L.L.C. (f/k/a Devon Financing Corporation, L.L.C.U.L.C.), as Issuer, Registrant, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 7.875% Debentures due 2031 (incorporated(incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4 as filed October 31, 2001; File No. 333-68694)333-68694).

4.13

  4.11

Senior Indenture, dated as of July 8, 1998 amongSeptember 1, 1997, between Devon OEI Operating, L.L.C. (as successor by merger to OceanSeagull Energy Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 10.24 to the Form 10-Q for the period ended June 30, 1998 of Ocean Energy, Inc.; File No. 001-14252).

Exhibit No.

Description

  4.14First Supplemental Indenture, dated March 30, 1999 to Indenture dated as of July 8, 1998 among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.5 to Ocean Energy, Inc.’s Form 10-Q for the period ended March 31, 1999; File No. 001-08094).
  4.15Second Supplemental Indenture, dated as of May 9, 2001 to Indenture dated as of July 8, 1998 among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 99.2 to Ocean Energy, Inc.’sForm 8-K filed May 14, 2001; File No. 033-06444).
  4.16Third Supplemental Indenture, dated January 23, 2006 to Indenture dated as of July 8, 1998 among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as Successor Guarantor, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K for the year ended December 31, 2005; File No. 001-32318).
  4.17Senior Indenture dated September 1, 1997, among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.)Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee, and related Specimen of 7.50% Senior Notes (incorporateddue 2027 (incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K for the year ended December 31, 1997;filed March 23, 1998; File No. 001-08094)001-08094).

  4.18

  4.12

First Supplemental Indenture, dated as of March 30, 1999, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Duedue 2027 (incorporated(incorporated by reference to Exhibit 4.10 to Ocean Energy’sEnergy, Inc.’s Form 10-Q for the period ended March 31,filed May 17, 1999; File No. 001-08094)001-08094).

  4.19

  4.13

Second Supplemental Indenture, dated as of May 9, 2001, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors,Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Duedue 2027 (incorporated(incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444)033-06444).

  4.20

  4.14

Third Supplemental Indenture, dated as of December 31, 2005, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Duedue 2027 (incorporated(incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K for the year ended December 31, 2005;filed March 3, 2006; File No. 001-32318)001-32318).

  4.21

  10.1

Registrant has not filed instruments defining the rights of holders of long-term indebtedness of Registrant’s majority owned subsidiary, EnLink Midstream Partners, LP, as none of which exceeds ten percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant hereby agrees to furnish a copy of any such agreements to the Commission upon request.
10.1

Credit Agreement, dated as of October 24, 2012,5, 2018, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers,Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, and each lender from time to time party thereto, eachLender and L/C Issuer from time to time party thereto and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated(incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 29, 2012;9, 2018; File No. 001-32318)001-32318).

Exhibit No.

Description

  10.2

10.2

Extension Agreement dated September 3, 2013 to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower,

Devon NECEnergy Corporation 2009 Long-Term Incentive Plan (as amended and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender, with respect to Borrower’s extension of the Maturity Date from October 24, 2017 to October 24, 2018 (incorporatedrestated effective June 6, 2012) (incorporated by reference to Exhibit 10.110.2 to the Registrant’s Form 10-Q8-K filed November 6, 2013;June 8, 2012; File No. 001-32318)001-32318).*

10.3

First Amendment to Credit Agreement dated February 3, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form8-K filed February 7, 2014; File No. 001-32318).
10.4Extension Agreement dated as of October 17, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to the extension of the maturity date from October 24, 2018 to October 24, 2019 (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 5, 2014; File No. 001-32318).
10.5

Devon Energy Corporation 2015 Long-Term Incentive Plan (incorporated(incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666)333-204666).*

112


Table of Contents

Index to Financial Statements

Exhibit No.

Description

10.6

  10.4

Devon Energy Corporation 20092017 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated(incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 18, 2012;7, 2017; File No. 333-182198)333-218561).*

10.7

  10.5

Devon Energy Corporation

2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2013; File No. 001-32318)001-32318).*

10.8

  10.6

Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.8 to Registrant’s Form S-8 filed August 17, 2005; File No. 333-127630).*

10.9First Amendment to Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Appendix A to Registrant’s Proxy Statement for the 2006 Annual Meeting of Stockholders filed on April 28, 2006; File No. 001-32318).*
10.10Devon Energy Corporation Incentive Compensation Plan (incorporated(amended and restated effective as of January 1, 2017) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed June 8, 2012;12, 2017; File No. 001-32318)001-32318).*

10.11

  10.7

Devon Energy Corporation Non-Qualified Deferred Compensation Plan Amended(amended and Restated Effectiverestated effective as of April 15, 2014 (incorporated2014) (incorporated by reference to Exhibit 10.1 to Registrant’sForm 10-Q filed August 6, 2014; File No. 001-32318)001-32318).*

10.12

  10.8

Devon Energy Corporation

Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan as amended(amended and restated effective April 15, 2014 (incorporated2014) (incorporated by reference to Exhibit 10.11 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318)001-32318).*

10.13

  10.9

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to Exhibit 10.13 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*

  10.10

Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014).*

  10.11

Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).*

Exhibit No.

Description

  10.12

10.14

Devon Energy Corporation

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.6 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).*

10.15

  10.13

Devon Energy Corporation

Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318)001-32318).*

10.16

  10.14

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*

  10.15

Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).*

10.17

  10.16

Devon Energy Corporation

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).*

10.18

  10.17

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*

  10.18

Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012).*

  10.19

Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).*

113


Table of Contents

Index to Financial Statements

Exhibit No.

Description

10.19

  10.20

Devon Energy Corporation

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).*

10.20

  10.21

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.23 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*

  10.22

Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).*

10.21

  10.23

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.25 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*

  10.24

Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).*

10.22

  10.25

Devon Energy Corporation

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).*

10.23

  10.26

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*

  10.27

Devon Energy Corporation Incentive Savings Plan as amended(amended and restated effective January 1, 2014, executed September 22, 2014 (incorporated2018) (incorporated by reference to Exhibit 10.2110.28 to Registrant’s Form 10-K filed February 20, 2015;21, 2018; File No. 001-32318)001-32318).*

10.24

  10.28              

Devon Energy Corporation

Amendment 2015-1,2018-1, executed April 15, 2015,December 14, 2018, to the Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2014) (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318)2018).*

10.25

  10.29

Amended and Restated Form of Employment Agreement between Registrant and certain executive officers (incorporated(incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009; File No. 001-32318)001-32318).*

10.26

  10.30

Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant and certain executive officers (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011; File No. 001-32318)001-32318).*

10.27

  10.31

Form of Employment Agreement between Registrant and certain executive officers (Amended and Restated Form of Employment Agreement dated December 15, 2008 (Exhibit 10.22 above), as amended by Amendment No. 1 thereto dated April 19, 2011 (Exhibit 10.23 above)) (incorporated(incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318)001-32318).*

Exhibit No.

Description

  10.32

Employment Agreement, dated April 19, 2017, by and between Registrant and Mr. Jeffrey L. Ritenour (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed on April 20, 2017; File No. 001-32318).*

10.28

  10.33

Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318).*

10.29Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.25 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).*
10.30Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted stock awarded (incorporated(incorporated by reference to Exhibit 10.29 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318)001-32318).*

10.31

  10.34

Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and David A. Hager for performance based restricted stock awarded (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 4, 2015; File No. 001-32318)001-32318).*

114


Table of Contents

Index to Financial Statements

Exhibit No.

Description

10.32

  10.35

Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 4, 2016; File No. 001-32318).*

  10.36

2017 Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 3, 2017; File No. 001-32318).*

  10.37

2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 2, 2018; File No. 001-32318).*

  10.38

Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 20092015 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted share units awarded (incorporated(incorporated by reference to Exhibit 10.1710.3 to Registrant’s Form 10-K10-Q filed February 21, 2013;May 4, 2016; File No. 001-32318)001-32318).*

10.33

  10.39

2017 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 20092015 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted share units awarded (incorporated(incorporated by reference to Exhibit 10.2810.2 to Registrant’s Form 10-K10-Q filed February 28, 2014;May 3, 2017; File No. 001-32318)001-32318).*

10.34

  10.40

2018 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 20092017 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted share units awarded (incorporated(incorporated by reference to Exhibit 10.3210.2 to Registrant’s Form 10-K10-Q filed February 20, 2015;May 2, 2018; File No. 001-32318)001-32318).*

10.35

  10.41

Form of Notice of Grant of Incentive Stock OptionOptions and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for incentive stock options granted (incorporated(incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318)001-32318).*

10.36

  10.42

Form of EmployeeNotice of Grant of Nonqualified Stock OptionOptions and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for nonqualified stock options granted (incorporated(incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318)001-32318).*

10.37Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for nonqualified stock options granted (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed on February 25, 2010; File No. 001-32318).*

Exhibit No.

Description

  10.43

10.38

Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Thomas L. Mitchell for restricted stock awarded (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318).*
10.39Form of Notice of Grant of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all non-management directors for restricted stock awards (incorporated by reference to Exhibit 10.33 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).*
10.40

2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 20152017 Long-Term Incentive Plan between Registrant and all non-management directors for restricted stock awards (incorporatedawarded  (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 5, 2014;May 2, 2018; File No. 001-32318)001-32318).*

10.41

  10.44

Form of Letter Agreement amending the restricted stock award agreements and nonqualified stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette (incorporated(incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318)001-32318).*

10.42

  10.45

Form of Amendment to Incentive Stock Option Award Agreements between Registrant and post-retirement eligible executives relating to incentive stock options under the 2009 Long-Term Incentive Plan (incorporated(incorporated by reference to Exhibit 10.24 to Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318)001-32318).*

115


Table of Contents

Index to Financial Statements

Exhibit No.

Description

10.43

  10.46

Amendment to Performance Share Unit Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Share Unit Award Agreement dated February 10, 2015.*
10.44

Amendment to Performance Restricted Stock Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Restricted Stock Award Agreement dated

February 10, 2015.2015 (incorporated by reference to Exhibit 10.44 to Registrant’s Form 10-K filed February 17, 2016; File No. 001-32318).*

12

  21

Statement

List of computations of ratios of earnings to fixed charges.Subsidiaries.

21

  23.1

Registrant’s Significant Subsidiaries.
23.1

Consent of KPMG LLP.

23.2

Consent of LaRoche Petroleum Consultants, Ltd.

23.3

Consent of Deloitte.Deloitte LLP.

31.1

Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1

Report of LaRoche Petroleum Consultants, Ltd.

99.2

Report of Deloitte.Deloitte LLP.

  101.INS

XBRL Instance Document – the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

  101.SCH

XBRL Taxonomy Extension Schema Document.

  101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

  101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

  101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

  101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

 

*

Compensatory plans

Indicates management contract or arrangementscompensatory plan or arrangement.

Item 16.Form 10-K Summary

Not applicable.

116


Table of Contents

Index to Financial Statements

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

DEVON ENERGY CORPORATION

By:

By:  /s/ DAVID A. HAGER                

/s/ JEFFREY L. RITENOUR

David A. Hager

Jeffrey L. Ritenour

Executive Vice President and
Chief ExecutiveFinancial Officer

February 17, 201620, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

 

/s/ DAVID A. HAGER

President, and Chief Executive Officer and

February 17, 201620, 2019

David A. Hager

(Principal

Director (Principal executive officer)

/s/ THOMASJEFFREY L. MITCHELLRITENOUR

Executive Vice President

February 17, 201620, 2019

Jeffrey L. Ritenour

Thomas L. Mitchell

and Chief Financial Officer

(Principal financial officer)

/s/ JEREMY D. HUMPHERS

Senior Vice President

February 17, 201620, 2019

Jeremy D. Humphers

and Chief Accounting Officer

(Principal accounting officer)

/s/ J. LARRY NICHOLS

Executive Chairman of the BoardFebruary 17, 2016
J. Larry Nichols

/s/ JOHN RICHELS

Chairman of the Board

February 20, 2019

John Richels

/s/ DUANE C. RADTKE

Vice Chairman of the Board

February 17, 201620, 2019

Duane C. Radtke

John Richels

/s/ BARBARA M. BAUMANN

Director

February 17, 201620, 2019

Barbara M. Baumann

/s/ JOHN E. BETHANCOURT

Director

February 17, 201620, 2019

John E. Bethancourt

/s/ ROBERT H. HENRY

Director

February 17, 201620, 2019

Robert H. Henry

/s/ MICHAEL M. KANOVSKY

Director

February 17, 201620, 2019

Michael M. Kanovsky

/s/ JOHN KRENICKI JR.

Director

February 20, 2019

John Krenicki Jr.

/s/ ROBERT A. MOSBACHER, JR.

Director

February 17, 201620, 2019

Robert A. Mosbacher, Jr.

/s/ DUANE C. RADTKE

DirectorFebruary 17, 2016
Duane C. Radtke

/s/ MARY P. RICCIARDELLO

Director

February 17, 201620, 2019

Mary P. Ricciardello

INDEX TO EXHIBITS

 

Exhibit No.

Description

    4.1Registration Rights Agreement dated January 7, 2016, among Registrant and EnCap FEx Holdings, LLC, Felix Stack Investments, LLC, Felix STACK Holdings, LLC and the other selling stockholders from time to time party thereto.
    4.2Registration Rights Agreement dated December 17, 2015, among Registrant and NewWoods Petroleum, LLC and the other selling stockholders from time to time party thereto.
  10.43Amendment to Performance Share Unit Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Share Unit Award Agreement dated February 10, 2015.*
  10.44Amendment to Performance Restricted Stock Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Restricted Stock Award Agreement dated February 10, 2015.*
  12Statement of computations of ratio of earnings to fixed charges.
  21Registrant’s Significant Subsidiaries.
  23.1Consent of KPMG LLP.
  23.2Consent of LaRoche Petroleum Consultants., Ltd.
  23.3Consent of Deloitte.
  31.1Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  31.2Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  32.1Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  32.2Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  99.1Report of LaRoche Petroleum Consultants, Ltd.
  99.2Report of Deloitte.
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema Document.
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
101.LABXBRL Taxonomy Extension Labels Linkbase Document.
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.

*Compensatory plans or arrangements

 

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