Table of Contents
 
Index to Financial Statements
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 
(Mark One)
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the fiscal year ended December 31, 2018
or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
Commission File Number 001-32318

DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Delaware	 	73-1567067	
(State or other jurisdiction of incorporation or organization)	 	(I.R.S. Employer identification No.)	
 	 	
333 West Sheridan Avenue, Oklahoma City, Oklahoma	 	73102-5015	
(Address of principal executive offices)	 	(Zip code)	
Registrant’s telephone number, including area code:
(405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:
 
 	Title of each class	 	Name of each exchange on which registered	 	
 	Common stock, par value $0.10 per share	 	The New York Stock Exchange	 	
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   ☒     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   ☒
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   ☒     No   ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).    Yes   ☒     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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
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   ☒
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 29, 2018 was approximately $22.5 billion, based upon the closing price of $43.96 per share as reported by the New York Stock Exchange on such date. On February 6, 2019, 438.3 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s definitive Proxy Statement 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.

Table of Contents
 
Index to Financial Statements
DEVON ENERGY CORPORATION
FORM 10-K
TABLE OF CONTENTS
 
PART I	 	6	
 	 	 	
Items 1 and 2. Business and Properties	 	6	
Item 1A.  Risk Factors	 	14	
Item 1B.  Unresolved Staff Comments	 	21	
Item 3.     Legal Proceedings	 	21	
Item 4.     Mine Safety Disclosures	 	21	
 	 	 	
PART II	 	22	
 	 	 	
Item 5.     Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	 	22	
Item 6.     Selected Financial Data	 	24	
Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	25	
Item 7A.  Quantitative and Qualitative Disclosures about Market Risk	 	49	
Item 8.     Financial Statements and Supplementary Data	 	50	
Item 9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	 	109	
Item 9A.  Controls and Procedures	 	109	
Item 9B.  Other Information	 	109	
 	 	 	
PART III	 	110	
 	 	 	
Item 10.   Directors, Executive Officers and Corporate Governance	 	110	
Item 11.   Executive Compensation	 	110	
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	110	
Item 13.   Certain Relationships and Related Transactions, and Director Independence	 	110	
Item 14.   Principal Accountant Fees and Services	 	110	
 	 	 	
PART IV	 	111	
 	 	 	
Item 15.   Exhibits and Financial Statement Schedules	 	111	
Item 16.   Form 10-K Summary	 	116	
Signatures	 	117	
 
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DEFINITIONS
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon,” the “Company” and “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, unless stated otherwise.
“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.
“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.
“EnLink” means EnLink Midstream Partners, 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, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
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“Mcf” means thousand cubic feet.
“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.
“OPIS” means Oil Price Information Service.
“PHMSA” means United States Department of Transportation Pipeline and Hazardous Materials Safety Administration.
“SEC” means United States Securities and Exchange Commission.
“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.
“Tax Reform Legislation” means 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.
“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 include 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. All statements, other than statements of historical facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the 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;	
 	•	uncertainties inherent in estimating oil, gas and NGL reserves;	
 	•	the extent to which we are successful in acquiring and discovering additional reserves;	
 	•	the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct;	
 	•	regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;	
 	•	risks related to regulatory, social and market efforts to address climate change;	
 	•	risks related to our hedging activities;	
 	•	counterparty credit risks;	
 	•	risks relating to our indebtedness;	
 	•	cyberattack risks;	
 	•	our limited control over third parties who operate some of our oil and gas properties;	
 	•	midstream capacity constraints and potential interruptions in production;	
 	•	the extent to which insurance covers any losses we may experience;	
 	•	competition for assets, materials, people and capital;	
 	•	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 an 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. In July 2018, we exited the midstream business by divesting our aggregate ownership interests in EnLink and the General Partner.
Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2018, Devon and its consolidated subsidiaries had approximately 2,900 employees.
Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports, with the SEC. Through our website, 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 documents available on our website include our Code of Ethics for Chief Executive Officer, Chief Financial Officer and Chief Accounting 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. Reports filed with the SEC are also made available on its website at www.sec.gov .
Our Strategy
Our business strategy is focused on delivering a consistently competitive shareholder return among our peer group. Because the business of exploring for, developing and producing oil and natural gas is 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 uncertain 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 prices relative to natural gas, we have been positioning our portfolio to be more heavily weighted to U.S. oil assets in recent years.
During 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 Company. 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 our capital programs and production operations, with an underlying objective of reducing absolute and per unit costs and enhancing our returns. We also strive to 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.
As 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, as well as adequate liquidity and financial flexibility, in order to operate competitively 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 core operations, protecting our investment-grade credit ratings, and paying and growing our shareholder dividend.
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During 2018, we reduced our 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 add itional common shares . As a result of our planned dispositions, our Board of Directors has increased our share repurchase program to $5 billion in February 2019 and raised our quarterly dividend 12.5% to $0.09 per share .
Oil and Gas Properties
Property Profiles
Key summary data from each of our areas of operation as of and for the year ended December 31, 2018 are detailed in the map below. Notes 22 and 23 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.

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Delaware Basin – The Delaware Basin is 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, Wolfcamp and Leonard formations. We expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin to deliver high-margin growth 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 2019, we plan to invest approximately $900 million of capital in the Delaware Basin, making it the top-funded asset in the portfolio.
STACK  – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top assets. Our STACK position is one of the largest in the industry, providing visible long-term stable production. At December 31, 2018, we had five operated rigs with drilling focused in the Meramec formation. In 2019, we plan approximately $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 2014. Since acquiring these assets, we have delivered tremendous results by producing 173 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. Our Eagle Ford assets generated significant cash flow in 2018. In 2019, we plan approximately $300 million of capital investment.
Rockies Oil – Our acreage in the Rockies is focused on emerging oil opportunities in the Powder River Basin. Recent drilling success in this 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. As of December 31, 2018, we had two operated rigs targeting the Turner, Parkman, Teapot and Niobrara formations in northern Converse County of the Powder River Basin. In 2019, we plan approximately $300 million of capital 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, an 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. The Jackfish operation consists of three facilities. We expect Jackfish to maintain a reasonably flat production profile for greater than 15 years requiring approximately $200 million of 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, 2018. Currently, we have minimal planned capital outlays for Pike in the near future. The majority of our Pike leasehold does not expire until 2025 and 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 oil development play that produces heavy oil by conventional means, without the need for steam injection.
In 2019, we plan to separate our operations in Canada.
Barnett Shale – This is our largest property in terms of proved reserves. Our leases are located primarily in Denton, 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. In 2019, we plan to separate our Barnett Shale assets.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 23 in “Item 8. Financial Statements and Supplementary Data” of this report.
Proved oil and gas reserves are those quantities of oil, gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators, 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 Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates. The Group reports to and is managed through our finance department. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.
The Director of the Group has over 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 Society of Petroleum Engineers and 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.  
Throughout the year, the Group performs internal reserves reviews of each operating country’s reserves. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2018, we engaged two such firms to audit approximately 89% of our proved reserves in accordance 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 members of our Reserves Committee 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 following tables present production, price and cost information for each significant field, country and continent.
 
 	 	Production	 	
Year Ended December 31,	 	Oil (MMBbls)	 	 	Bitumen (MMBbls)	 	 	Gas (Bcf)	 	 	NGLs (MMBbls)	 	 	Total (MMBoe)	 	
2018	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Barnett Shale	 	 	—	 	 	 	—	 	 	 	186	 	 	 	12	 	 	 	43	 	
STACK	 	 	12	 	 	 	—	 	 	 	121	 	 	 	14	 	 	 	45	 	
Jackfish	 	 	—	 	 	 	35	 	 	 	—	 	 	 	—	 	 	 	35	 	
U.S.	 	 	47	 	 	 	—	 	 	 	397	 	 	 	39	 	 	 	153	 	
Canada	 	 	7	 	 	 	35	 	 	 	4	 	 	 	—	 	 	 	42	 	
Total North America	 	 	54	 	 	 	35	 	 	 	401	 	 	 	39	 	 	 	195	 	
2017	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Barnett Shale	 	 	—	 	 	 	—	 	 	 	237	 	 	 	14	 	 	 	54	 	
STACK	 	 	9	 	 	 	—	 	 	 	107	 	 	 	11	 	 	 	38	 	
Jackfish	 	 	—	 	 	 	40	 	 	 	—	 	 	 	—	 	 	 	40	 	
U.S.	 	 	42	 	 	 	—	 	 	 	433	 	 	 	36	 	 	 	150	 	
Canada	 	 	7	 	 	 	40	 	 	 	6	 	 	 	—	 	 	 	48	 	
Total North America	 	 	49	 	 	 	40	 	 	 	439	 	 	 	36	 	 	 	198	 	
2016	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Barnett Shale	 	 	—	 	 	 	—	 	 	 	265	 	 	 	15	 	 	 	60	 	
STACK	 	 	7	 	 	 	—	 	 	 	103	 	 	 	9	 	 	 	33	 	
Jackfish	 	 	—	 	 	 	40	 	 	 	—	 	 	 	—	 	 	 	40	 	
U.S.	 	 	47	 	 	 	—	 	 	 	510	 	 	 	42	 	 	 	174	 	
Canada	 	 	8	 	 	 	40	 	 	 	7	 	 	 	—	 	 	 	49	 	
Total North America	 	 	55	 	 	 	40	 	 	 	517	 	 	 	42	 	 	 	223	 	
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 	 	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)	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 production expense per BOE 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)	 	
Year Ended December 31,	 	Productive	 	 	Dry	 	 	Productive	 	 	Dry	 	 	Productive	 	 	Dry	 	 	Total	 	
2018	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	165.6	 	 	 	3.1	 	 	 	69.4	 	 	 	—	 	 	 	235.0	 	 	 	3.1	 	 	 	238.1	 	
Canada	 	 	70.5	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	70.5	 	 	 	—	 	 	 	70.5	 	
Total North America	 	 	236.1	 	 	 	3.1	 	 	 	69.4	 	 	 	—	 	 	 	305.5	 	 	 	3.1	 	 	 	308.6	 	
2017	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	149.8	 	 	 	—	 	 	 	44.0	 	 	 	—	 	 	 	193.8	 	 	 	—	 	 	 	193.8	 	
Canada	 	 	100.5	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	100.5	 	 	 	—	 	 	 	100.5	 	
Total North America	 	 	250.3	 	 	 	—	 	 	 	44.0	 	 	 	—	 	 	 	294.3	 	 	 	—	 	 	 	294.3	 	
2016	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	88.5	 	 	 	—	 	 	 	36.4	 	 	 	2.0	 	 	 	124.9	 	 	 	2.0	 	 	 	126.9	 	
Canada	 	 	21.5	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	21.5	 	 	 	—	 	 	 	21.5	 	
Total North America	 	 	110.0	 	 	 	—	 	 	 	36.4	 	 	 	2.0	 	 	 	146.4	 	 	 	2.0	 	 	 	148.4	 	

(1)	Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests.	
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The following table presents the wells that were in progress on December 31, 2018. As of February 1, 2019, these wells were still in progress.
 
 	 	Gross (1)	 	 	Net (2)	 	
U.S.	 	 	184.0	 	 	 	105.2	 	
Canada	 	 	1.0	 	 	 	1.0	 	
Total North America	 	 	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, 2018.

 	 	Oil Wells (1)	 	 	Natural Gas Wells	 	 	Total Wells (1)	 	
 	 	Gross (2)(4)	 	 	Net (3)	 	 	Gross (2)(4)	 	 	Net (3)	 	 	Gross (2)(4)	 	 	Net (3)	 	
U.S.	 	 	9,284	 	 	 	3,445	 	 	 	8,235	 	 	 	5,703	 	 	 	17,519	 	 	 	9,148	 	
Canada	 	 	3,183	 	 	 	3,071	 	 	 	544	 	 	 	380	 	 	 	3,727	 	 	 	3,451	 	
Total North America	 	 	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 902 and 350 gross oil and gas wells, respectively, which had multiple 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 12,900 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and construction 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, 2018. Of our 3.8 million net acres, approximately 1.9 million acres are held by production. The acreage in the table includes 0.2 million, 0.1 million and 0.1 million net acres subject to leases that are scheduled to expire during 2019, 2020 and 2021, respectively. As of December 31, 2018, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.3 million net acres set to expire by December 31, 2021, we anticipate 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 2018, we allowed approximately 0.1 million acres to expire.

 	 	Developed	 	 	Undeveloped	 	 	Total	 	
 	 	Gross (1)	 	 	Net (2)	 	 	Gross (1)	 	 	Net (2)	 	 	Gross (1)	 	 	Net (2)	 	
 	 	(Thousands)	 	
U.S.	 	 	1,449	 	 	 	909	 	 	 	3,373	 	 	 	1,463	 	 	 	4,822	 	 	 	2,372	 	
Canada	 	 	674	 	 	 	495	 	 	 	2,086	 	 	 	967	 	 	 	2,760	 	 	 	1,462	 	
Total North America	 	 	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, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records 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.
Marketing Activities
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 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 2019, our production was sold under the following contract terms.

 	 	Short-Term	 	 	Long-Term	 	
 	 	Variable	 	 	Fixed	 	 	Variable	 	 	Fixed	 	
Oil and bitumen	 	 	75	%	 	 	—	 	 	 	25	%	 	 	—	 	
Natural gas	 	 	67	%	 	 	4	%	 	 	29	%	 	 	—	 	
NGLs	 	 	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, 2018, we were committed to deliver the following fixed quantities of production.
 
 	 	Total	 	 	Less Than 1 Year	 	 	1-3 Years	 	 	3-5 Years	 	
Oil and bitumen (MMBbls)	 	 	53	 	 	 	25	 	 	 	28	 	 	 	—	 	
Natural gas (Bcf)	 	 	360	 	 	 	220	 	 	 	125	 	 	 	15	 	
NGLs (MMBbls)	 	 	10	 	 	 	10	 	 	 	—	 	 	 	—	 	
Total (MMBoe)	 	 	123	 	 	 	72	 	 	 	49	 	 	 	2	 	
 
We expect to fulfill our delivery commitments primarily with production from our proved developed reserves. 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 can and may use spot market purchases to satisfy the commitments.
Customers
During 2018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.
During 2017 and 2016, no purchaser accounted for over 10% of our consolidated 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;	
 	•	location, drilling and casing of wells;	
 	•	well design;	
 	•	hydraulic fracturing;	
 	•	well production;	
 	•	spill prevention plans;	
 	•	emissions and discharge permitting;	
 	•	use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;	
 	•	surface usage and the restoration of properties upon which wells have been drilled;	
 	•	calculation and disbursement of royalty payments and production taxes;	
 	•	plugging and abandoning of wells;	
 	•	transportation of production; and	
 	•	endangered species and habitat.	
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the forced pooling or unitization 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 Indian 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, tribes or tribal members. The federal government has, from time to time, evaluated and, in some cases, promulgated 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 calculation in Canada is a significant factor in the profitability of Canadian oil and gas production. Oil 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. For pre-payout oil sands projects, the regulations prescribe lower royalty rates for oil sands projects until allowable capital costs have been recovered. In
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early 2016, the Alberta government adopted the recommendation of its Royalty Review Panel. The new royalty framework preserves the existing royalty structure and rates for oil sands. For conventional oil and gas royalty calculations , wells drilled after January 1, 2017 would use the Modernized Royalty Framework (MRF) which prescribes a lower royalty 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 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 curtailment amounts are expected to reduce over 2019 to an average of approximately 95 MBbls/d as storage levels ease and price differential improve, and the Rules terminate on December 31, 2019. Devon’s curtailments in the first quarter of 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 and natural resources. Environmental laws and regulations relate to:
 	•	the discharge of pollutants into federal, provincial and state waters;	
 	•	assessing the environmental impact of seismic acquisition, drilling or construction activities;	
 	•	the generation, storage, transportation and disposal of waste materials, including hazardous substances;	
 	•	the emission of certain gases into the atmosphere;	
 	•	the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;	
 	•	the development of emergency response and spill contingency plans;	
 	•	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. Moreover, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. Environmental protection and health and safety 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 may 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 Significantly 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. Historically, market prices and our realized prices have been volatile. For example, over the last five years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from a high of over $100 per Bbl and $6 per MMBtu, respectively, to a low 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 market, 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 results of operations in 2018, and 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, 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.	
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 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.
Our Operations Are Uncertain and Involve Substantial Costs and Risks
Our operating 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 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, 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.	
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Moreover, certain of these events 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 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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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 Activities Limit Participation in Commodity Price Increases and Involve Other Risks
We enter into financial 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 will 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 share 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 obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or 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 and condition.
Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us
As of December 31, 2018, we had total indebtedness of $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 portion of our cash flows from operations to debt service payments, thereby limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other general corporate purposes;	
 	•	increasing our vulnerability to general adverse economic and industry conditions, including low commodity price environments; and	
 	•	limiting our ability to obtain additional financing due to higher costs and more restrictive covenants.	
In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that may impact our credit ratings include, among others, debt levels, planned asset sales and purchases, liquidity, forecasted production growth and commodity prices. We 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.  
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 Operations
Our business has become increasingly dependent on digital technologies, and we anticipate expanding our use of technology in our operations, including through process automation and data analytics. Concurrent with this growing dependence on technology 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 does 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 breaches from cyber attacks, which, in turn, could adversely impact our operations and compromise our information. Although we have not suffered material losses related to cyber attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, including litigation risks. Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.  
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 gas production and to transport our oil, gas and NGL production to downstream markets. All or a portion of our production in one or more regions may be interrupted or shut in from time to time due 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, the midstream operators may be subject to constraints that limit 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 and may have established superior strategic long-term positions and relationships, including with respect to midstream take-away capacity. As a consequence, we may be at a competitive disadvantage in bidding for assets or 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 Business Could Be Adversely Impacted by Investors Attempting to Effect Change
Stockholder activism has been increasing in our industry, and investors 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 Acquisition and Divestiture Activities Involve Substantial Risks
Our business depends, in part, on making acquisitions that complement or expand our current business and successfully integrating any acquired assets or businesses. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
 	•	mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;	
 	•	difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and	
 	•	unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.	
In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets 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 terminate a transaction prior to closing.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 3. Legal Proceedings
We are involved in various 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 under the “DVN” ticker symbol. On February 6, 2019, there were 7,094 holders of record of our common stock. We began paying regular quarterly cash dividends in the second quarter of 1993. The declaration of future dividends is a business decision made by our Board of Directors, and will depend on Devon’s financial condition and other relevant factors. Additional information on our dividends can be found in Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.
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 and a peer group of companies 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., Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Noble Energy, Inc., Occidental Petroleum Corporation and Pioneer Natural Resources Company. The graph was prepared assuming $100 was invested on December 31, 2013 in Devon’s common stock, the S&P 500 Index and the peer 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 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	 	 	 	 	 	

 	(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 for the payment of personal income tax withholding on vesting 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 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 39,000 shares of our common stock in 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 this 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. 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 2018, there were no shares purchased by Canadian 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	 	

 	(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.	
 	(2)	Material asset impairments and acquisition and divestiture activity had significant impacts on operating results and the carrying value of our oil and gas assets. Specifically, there were asset impairments of $0.4 billion, $16.1 billion and $3.4 billion in 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 assets related to our aggregate ownership interest in EnLink and 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 and the General Partners’ assets to assets held for sale, which are included within this amount.	
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.
Overview of 2018 Results
2018 was a pivotal year for Devon as we took several significant steps toward achieving our long-term strategic goals. Operationally, we successfully transitioned our U.S. oil business into full-field development, which resulted in high-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 reducing our financial leverage by more than 40 percent.
 	•	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.	
 
	 	As presented in the graph at the left, our operating achievements are subject to the volatility of commodity prices. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub prices ranged 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 fourth quarter of 2018. In the first two months of 2019, Western Canadian Select differentials have improved significantly.  	
	 	Key measures of our financial performance in 2018 are summarized in the following table. Increased oil and 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 the General Partner during 2018. More details for these metrics are found within the “Results of Operations – 2018 vs. 2017” below.
 	
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 	 	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 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)	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 that 2019 crude pricing is expected to improve 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 environment, geopolitical risks and other factors could impact our current forecasts.
In 2018, Devon marked its 30 th year as a public company and 47 th anniversary in the oil and gas business, so we are experienced in dealing with the volatile nature of commodity prices. To mitigate our exposure to commodity market volatility and ensure our financial 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.
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Despite the uncertainties pertaining to commodity prices, we remain focused on our strategic priorities of having 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 fo r Devon as we pla n to sepa rate 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 B arnett Shale assets are sepa rated , 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 investment-grade credit ratings and paying our shareholder dividend. Further, when considering the current commodity price 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 following graphs, discussion and analysis are intended to provide 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 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.	
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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.	

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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 approximate 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 maintenance 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.	

 
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 	 	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 higher unhedged, realized prices for our U.S. oil and NGLs.
The increase in oil sales primarily resulted from higher average WTI crude index prices, which were 27% higher in 2018, resulting in an increase of approximately $568 million.
NGL sales increased $351 million as a result of 14% higher NGL prices at the Mont Belvieu, Texas hub, as well as improved realizations in our NGL price.
These increases were partially offset by widening 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 negatively impacted the price we realized on our Canadian production. We had basis swaps for approximately half of our fourth quarter production to mitigate the effect of the lower market price. To further mitigate the effects of the lower 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 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.
 
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.
Commodity Derivatives
 
 	 	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	%	
 
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.  
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 relationship between contract prices and the associated forward curves.

 
Production 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 continued focus on growing our liquids-rich assets within the STACK and Delaware Basin and higher maintenance costs at our Jackfish facilities, partially offset by our U.S. non-core divestitures.
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 .
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. Additionally, 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 sales.
Property taxes increased as 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	%	
 
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The overall increase in marketing operating margin was primarily due to improved 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 intend to pursue further exploration and development. Geological and geophysical costs decreased primarily in the 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 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.
 
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 benefits decreased primarily as a result of the workforce reduction that occurred during 2018 as discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report. Non-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 a $312 million loss on early retirement of debt. 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	
 
 	 	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 Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.
 
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 2018, we recognized restructuring and transaction costs of $114 million primarily 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.
 
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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.  

 

 
 
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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 natural 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	%	
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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 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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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.
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	
 
 	 	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 8 in “Item 8. Financial Statements and Supplementary Data” of this report.
 
Discontinued Operations	
For discussion on discontinued operations, see  Note 19  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 changes in cash and cash equivalents for the time periods presented below.
 
 	 	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	 	
                      
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2018. Our operating cash flow was relatively flat compared to 2017. In 2018, our operating cash flow funded approximately 86% of our capital expenditure program and dividends. We utilized available cash balances and divestiture proceeds to supplement our operating cash flows. Operating cash flow for 2018 included a realized foreign exchange loss of $241 million relating to foreign currency denominated intercompany loan activity as described in Note 7 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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Divestitures of Property and Investments
During 2018, as part of our announced 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 Supplementary Data” of this 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 Supplementary Data” of this report.
During 2016, we divested certain non-core upstream assets in the U.S. and our 50% interest in the Access Pipeline in Canada for approximately $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 core resource plays. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
We did not have significant current cash income taxes resulting from the divestitures in 2018, 2017 and 2016.
Capital Expenditures
The following table summarizes our capital expenditures and property acquisitions.
 
 	 	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 and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. Our capital program is designed to operate within or near operating cash flow and may fluctuate with changes to commodity prices and other factors impacting cash flow. This is evidenced by our operating cash flow funding approximately 91% of capital expenditures in 2018 and fully funding capital expenditures in 2017.
Acquisition costs in 2016 primarily consisted of Devon’s bolt-on acquisition of assets in the STACK play for $1.5 billion. Approximately $849 million was paid in cash at closing with the remainder of the 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 completed tender offers of certain long-term debt as well as the maturity of certain senior notes. In conjunction with the tender offers, we recognized a $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 “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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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 and other items. Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. During 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets for $1.5 billion. Approximately $792 million was paid in cash at closing with the remainder of the purchase 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 table above exclude the distributions EnLink and the General Partner paid to Devon, which have been eliminated in consolidation. Distributions Enlink and the General Partner paid to Devon were $134 million, $265 million and $265 million during 2018, 2017 and 2016, respectively.
Liquidity
The business of exploring 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 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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Index to Financial Statements
Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture 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. If needed, we can also issue debt and equity securities pursuant to our shelf registration statement filed with the SEC. 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 proceeds from these transactions for debt repayments and common share repurchases. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements 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 forecasts are sensitive to many variables and include a measure of uncertainty as these variables differ from our expectations.
Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, bitumen, gas and NGLs we produce and sell. 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. For 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 protect a portion of our production against 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 price volatility. We supplement the systematic hedging program with discretionary 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 adding hedges for 2020 as well. Further insulating our cash flow, we are proactively locking in 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, 2018 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.
For 2019, we expect to aggressively optimize our cost structure in conjunction with our planned Canadian and Barnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with the retained business and reduce outstanding debt. We anticipate the planned $780 million reduction of annualized costs will occur over three years, with roughly 70% of the savings delivered by the end of 2019. Approximately 40% of the reduced costs relate to our capital programs and the remainder relates to our operating expenses, including G&A, interest expense and production expenses.
Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate 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.
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Divestitures of Property and Equipment
In the first quarter of 2019, we sold non-core assets for approximately $300 million. We also anticipate separating our Canadian and Barnett Shale businesses from our Company in 2019.
Credit Availability
Our 2018 Senior Credit Facility, under which we have $2.9 billion of available borrowing capacity at December 31, 2018, matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods subject to lender consent. The 2018 Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2018, there were no borrowings under 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%. As of December 31, 2018, we were in compliance with this covenant with a 21.0% debt-to-capitalization 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.
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
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and 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 contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.
Share Repurchase Program
In February 2019, our Board of Directors increased our share repurchase program by an additional $1 billion. The $5 billion share 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 development budget is expected to be approximately $2.0 billion to $2.25 billion, including capital associated with our Canadian and Barnett Shale upstream assets.
Contractual Obligations
The following table presents a summary of our contractual obligations as of December 31, 2018.
 
 	 	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 debt obligations at December 31, 2018, excluding net discounts and debt issue costs included in the carrying value of debt.	
(2)	Interest expense represents the scheduled cash payments on long-term fixed-rate debt (including current portion of long term debt).	
(3)	Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.	
(4)	Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets. Approximately $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 25 years following the divestment of our 50% interest in the Access Pipeline. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
(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, 2018 balance sheet.	
(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.	
(7)	Lease obligations consist primarily of non-cancelable leases for office space and equipment.	
(8)	Other obligations primarily relate to various tax obligations.	
Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 20 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.
 
Oil and Gas Assets Accounting, Classification, Reserves & Valuation
Successful Efforts Method of Accounting and 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 DD&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 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 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.
Valuation of Long-Lived Assets
Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual
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assets based on a judgmental assessment of the lowest level (“common operating field”) for which there are identifiable cash flows that are largely independent of the cash 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 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.
Management 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. Because there usually is 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. 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 production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we generally utilize the forward strip prices for the first five years and apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost movements to price movements similar to recent history. Changes to any of these assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Due to suppressed commodity prices in 2016, we recognized significant asset impairments. With generally higher pricing in 2017 and 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. As of December 31, 2018, the U.S. reporting unit had goodwill totaling $841 million.
We perform a 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 our qualitative assessment 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 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 the 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. 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.
Based on our qualitative assessment as of October 31, 2018, 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 on 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 December 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 is less than its carrying value.
Our 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 period in which we would determine that the carrying value exceeds fair value. We would expect that a prolonged or sustained period of lower commodity prices would adversely affect the estimate of future operating results, which could result in future goodwill impairments for our U.S. reporting unit 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.
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 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, 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. 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:
 
 	•	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.	
 
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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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 2018 Results” in this Item 7 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and 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 performance measure. Amounts excluded for 2018 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 associated with the 2016 workforce reduction, derivatives and financial instrument fair value changes and costs associated with early retirement of debt.
 
We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities 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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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

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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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Index to Financial Statements
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	 	

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Index to Financial Statements
Item 7A. Quantitative and Qual itative 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 systematically hedge a portion of our production through various financial transactions. The key terms to our oil and gas derivative financial instruments as of December 31, 2018 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, 2018, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $270 million.
 
Interest Rate Risk
At December 31, 2018, we had total debt of $5.9 billion. All of our debt is based on fixed interest rates averaging 5.4%.
As of December 31, 2018, we had one open interest rate swap position that is presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair value of our interest rate swap is largely determined by estimates of the forward curves of the three month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet or liquidity at December 31, 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, 2018 balance sheet.
Devon engages in intercompany loan activity between subsidiaries with different functional currencies. The value of these foreign currency denominated intercompany loans increases or decreases from the remeasurement into the subsidiaries’ functional currency. Based on the amount of the intercompany loans as of December 31, 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 Statemen ts and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
 
Report of Independent Registered Public Accounting Firm	 	51	
 	 	 	
Consolidated Financial Statements	 	 	
Consolidated Comprehensive Statements of Earnings	 	53	
Consolidated Statements of Cash Flows	 	54	
Consolidated Balance Sheets	 	55	
Consolidated Statements of Equity	 	56	
Notes to Consolidated Financial Statements	 	57	
Note 1 – Summary of Significant Accounting Policies	 	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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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, 2018 and 2017, the related consolidated statements of comprehensive earnings, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the “consolidated financial statements”). We also have audited the Company’s 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.  
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) .
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.” Our responsibility is to express an opinion on the 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 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 regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial 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
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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.
/s/ KPMG LLP
We have served as the Company’s auditor since 1980.
Oklahoma City, Oklahoma
February 20, 2019
52

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Index to Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
 
 	 	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.
 
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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	 	
 
See accompanying notes to consolidated financial statements.
54

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Index to Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
 	 	December 31, 2018	 	 	December 31, 2017	 	
ASSETS	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	2,414	 	 	$	2,642	 	
Accounts receivable	 	 	885	 	 	 	989	 	
Current assets held for sale	 	 	197	 	 	 	760	 	
Other current assets	 	 	941	 	 	 	400	 	
Total current assets	 	 	4,437	 	 	 	4,791	 	
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	 	 	841	 	 	 	841	 	
Other long-term assets	 	 	353	 	 	 	296	 	
Long-term assets held for sale	 	 	—	 	 	 	9,729	 	
Total assets	 	$	19,566	 	 	$	30,241	 	
LIABILITIES AND EQUITY	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	
Accounts payable	 	$	662	 	 	$	633	 	
Revenues and royalties payable	 	 	898	 	 	 	748	 	
Short-term debt	 	 	162	 	 	 	115	 	
Current liabilities held for sale	 	 	69	 	 	 	991	 	
Other current liabilities	 	 	435	 	 	 	828	 	
Total current liabilities	 	 	2,226	 	 	 	3,315	 	
Long-term debt	 	 	5,785	 	 	 	6,749	 	
Asset retirement obligations	 	 	1,030	 	 	 	1,099	 	
Other long-term liabilities	 	 	462	 	 	 	549	 	
Long-term liabilities held for sale	 	 	—	 	 	 	3,936	 	
Deferred income taxes	 	 	877	 	 	 	489	 	
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	 	 	4,486	 	 	 	7,333	 	
Retained earnings	 	 	3,650	 	 	 	702	 	
Accumulated other comprehensive earnings	 	 	1,027	 	 	 	1,166	 	
Treasury stock, at cost, 1.0 million shares in 2018	 	 	(22	)	 	 	—	 	
Total stockholders’ equity attributable to Devon	 	 	9,186	 	 	 	9,254	 	
Noncontrolling interests	 	 	—	 	 	 	4,850	 	
Total equity	 	 	9,186	 	 	 	14,104	 	
Total liabilities and equity	 	$	19,566	 	 	$	30,241	 	
 
See accompanying notes to consolidated financial statements.
 
55

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Index to Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
 
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Retained	 	 	Accumulated	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Additional	 	 	Earnings	 	 	Other	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Common Stock	 	 	Paid-In	 	 	(Accumulated	 	 	Comprehensive	 	 	Treasury	 	 	Noncontrolling	 	 	Total	 	
 	 	Shares	 	 	Amount	 	 	Capital	 	 	Deficit)	 	 	Earnings	 	 	Stock	 	 	Interests	 	 	Equity	 	
Balance as of December 31, 2015	 	 	418	 	 	$	42	 	 	$	4,996	 	 	$	1,112	 	 	$	1,021	 	 	$	—	 	 	$	3,940	 	 	$	11,111	 	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1,056	)	 	 	—	 	 	 	—	 	 	 	(402	)	 	 	(1,458	)	
Other comprehensive earnings, net of tax	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	33	 	 	 	—	 	 	 	—	 	 	 	33	 	
Restricted stock grants, net of cancellations	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Common stock repurchased	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(28	)	 	 	—	 	 	 	(28	)	
Common stock retired	 	 	—	 	 	 	—	 	 	 	(28	)	 	 	—	 	 	 	—	 	 	 	28	 	 	 	—	 	 	 	—	 	
Common stock dividends	 	 	—	 	 	 	—	 	 	 	(96	)	 	 	(125	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(221	)	
Common stock issued	 	 	103	 	 	 	10	 	 	 	2,117	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,127	 	
Share-based compensation	 	 	—	 	 	 	—	 	 	 	168	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	168	 	
Subsidiary equity transactions	 	 	—	 	 	 	—	 	 	 	80	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,214	 	 	 	1,294	 	
Distributions to noncontrolling interests	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(304	)	 	 	(304	)	
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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Index to Financial Statements
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 sold its interests in EnLink and the General 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.
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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Table of Contents
 
Index to Financial Statements
 
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, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production 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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Table of Contents
 
Index to Financial Statements
 
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 Revenues
Marketing revenues are generated 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 to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. The 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 are reported on a gross basis when Devon takes control 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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Table of Contents
 
Index to Financial Statements
 
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 2018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue.
 
During 2017 and 2016, no purchaser accounted for more than 10% of Devon’s 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 enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. 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. 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 counterparty. 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 two-way collars unless the market price falls below the additional short put causing the company to receive the market price plus the long put to short put price differential.
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Index to Financial Statements
 
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, 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.
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, 2018, Devon held no cash collateral of its counterparties nor posted collateral 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.
Share-Based Compensation
Devon grants share-based awards to members of its Board of Directors and select 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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Index to Financial Statements
 
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 8 for further discussion.
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 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 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.
Property and Equipment
Oil and Gas Property and Equipment
Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such 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 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. Devon groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting 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 activities 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 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. Proved 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, net of estimated salvage 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 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 amortized 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 carrying 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 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.
Gains 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.
Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major 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 Equipment
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 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 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 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 a 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 assessment 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 goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of each reporting unit be compared to the 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 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 impairment tests of goodwill in the fourth quarters of 2018, 2017 and 2016. No impairment was required as a result of the annual tests in these time periods.
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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Index to Financial Statements
 
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 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 Adopted Accounting Standards
In 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 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost . This ASU requires entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. As a result of the adoption of this ASU, consolidated statements of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively. Upon adoption, Devon reclassified $7 million and $14 million of non-service cost components of net periodic benefit costs for 2017 and 2016, respectively, from G&A to other expenses.
65

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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
In January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash . This ASU requires 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 made changes to the statement of cash flows to include the required presentation and reconciliation 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 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 allows 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 2016-02,  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 – (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 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): Customer’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 internal-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 hosting arrangement that is a service contract will be amortized over the term of the 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 January 1, 2020, with early adoption permitted. Entities have the option to adopt the ASU using either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of the adoption. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements.
 
2.	Acquisitions and Divestitures	
Acquisitions
In January 2016, Devon acquired approximately 80,000 net acres and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $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.
Divestitures
 
EnLink and General Partner
 
During the third quarter of 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). The 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 on asset dispositions of approximately $260 million, primarily from sales of non-core assets in the Barnett Shale and Delaware Basin.   As part of the transactions, approximately $84 million of asset retirement obligations were assumed by the purchasers. 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 18%, of total U.S. proved reserves.  
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Additionally, 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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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
3.	Derivative Financial Instruments	
Commodity Derivatives
As of December 31, 2018, Devon had the following open oil derivative positions. The first two tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The third table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
 
 	 	Price Swaps	 	 	Price Collars	 	
Period	 	Volume
(Bbls/d)	 	 	Weighted
Average
Price ($/Bbl)	 	 	Volume
(Bbls/d)	 	 	Weighted
Average Floor
Price ($/Bbl)	 	 	Weighted
Average
Ceiling Price
($/Bbl)	 	
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	 	
 
 	 	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, 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	 	 	Price Collars	 	
Period	 	Volume (MMBtu/d)	 	 	Weighted Average Price ($/MMBtu)	 	 	Volume (MMBtu/d)	 	 	Weighted Average Floor Price ($/MMBtu)	 	 	Weighted Average
Ceiling Price ($/MMBtu)	 	
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	 	
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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, 2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas 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	 	

Interest Rate Derivatives
As of December 31, 2018, Devon had the following open interest rate derivative positions:
 
Notional	 	 	Rate Received	 	 	Rate Paid	 	Expiration	
$	100	 	 	1.76%	 	 	Three Month LIBOR	 	January 2019	
 
In January 2019, this interest rate derivative position settled.
 
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,	 	
 	 	2018	 	 	2017	 	 	2016	 	
Commodity derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream revenues	 	$	608	 	 	$	157	 	 	$	(201	)	
Marketing revenues	 	 	(1	)	 	 	3	 	 	 	(2	)	
Interest rate derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	
Other expenses	 	 	65	 	 	 	(22	)	 	 	(19	)	
Foreign currency derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	
Other expenses	 	 	—	 	 	 	—	 	 	 	(153	)	
Net gains (losses) recognized	 	$	672	 	 	$	138	 	 	$	(375	)	
 
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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, 2018	 	 	December 31, 2017	 	
Commodity derivative assets:	 	 	 	 	 	 	 	 	
Other current assets	 	$	637	 	 	$	203	 	
Other long-term assets	 	 	40	 	 	 	2	 	
Interest rate derivative assets:	 	 	 	 	 	 	 	 	
Other current assets	 	 	—	 	 	 	1	 	
Total derivative assets	 	$	677	 	 	$	206	 	
Commodity derivative liabilities:	 	 	 	 	 	 	 	 	
Other current liabilities	 	$	67	 	 	$	259	 	
Other long-term liabilities	 	 	1	 	 	 	27	 	
Interest rate derivative liabilities:	 	 	 	 	 	 	 	 	
Other current liabilities	 	 	—	 	 	 	64	 	
Total derivative liabilities	 	$	68	 	 	$	350	 	

4.	Share-Based Compensation	
In 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards that were transferred to the 2017 Plan in accordance with its terms). The 2017 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 units and stock appreciation rights to eligible employees. The 2017 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 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.
The vesting for certain share-based awards was accelerated in 2018 and 2016 in conjunction with the reduction of workforce activities described in Note 6 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.
 
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	 	
 
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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	 	
 	 	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	 	
 	 	(Thousands, except fair value data)	 	
Unvested at 12/31/17	 	 	6,328	 	 	$	36.81	 	 	 	575	 	 	$	38.92	 	 	 	2,758	 	 	 	 	 	$	41.21	 	
Granted	 	 	3,592	 	 	$	35.98	 	 	 	—	 	 	$	—	 	 	 	845	 	 	 	 	 	$	37.40	 	
Vested	 	 	(3,114	)	 	$	38.75	 	 	 	(273	)	 	$	42.22	 	 	 	(571	)	 	 	 	 	$	84.22	 	
Forfeited	 	 	(843	)	 	$	35.58	 	 	 	—	 	 	$	—	 	 	 	(164	)	 	 	 	 	$	33.92	 	
Unvested at 12/31/18	 	 	5,963	 	 	$	35.47	 	 	 	302	 	 	$	35.93	 	 	 	2,868	 	 	(1	)	 	$	30.14	 	

(1)	A maximum of 5.7 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.
 
 	 	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, 2018.
 
 	 	 	 	 	 	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 one 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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Performance-Based Restricted Stock Awards
Performance-based restricted stock awards were 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 one to four years. In order for awards to vest, the performance target must be met in the first year. If the performance target is met, the recipient is entitled to dividends under the 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 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 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.
 
 	 	2018	 	 	2017	 	 	2016	 	
Grant-date fair value	 	 	$36.23	 	 	—	 	$	37.88	 	 	 	$51.05	 	 	—	 	 	$53.12	 	 	 	$9.24	 	 	—	 	 	$10.61	 	
Risk-free interest rate	 	2.28%	 	 	1.50%	 	 	0.94%	 	
Volatility factor	 	45.8%	 	 	45.8%	 	 	37.7%	 	
Contractual term (years)	 	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 one to four years. The fair value of stock options on the date of grant is expensed over the applicable vesting period. No stock options were granted in 2018, 2017 and 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	 	 	$	—	 	
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

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 consolidated comprehensive statements of earnings.
 
 	 	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.
Unproved   Impairments
 
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	 	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
2018 Workforce Reductions
In 2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized $114 million of restructuring expenses during 2018, primarily consisting of employee-related costs. Of these expenses, $31 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, $14 million resulted from estimated settlements of defined retirement benefits.
 
Prior Years’ Restructurings
In 2016, Devon recognized $227 million in employee-related and other costs associated with a reduction in workforce that was made in response to the depressed commodity price environment. Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash 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 was subject to non-cancellable operating lease arrangements. 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 recognized $11 million in transaction costs primarily associated with the closing of the STACK acquisition discussed in Note 2 .
 
7.	Other Expenses	
The following table summarizes Devon’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	 	
 
Foreign exchange (gain) loss, net
 
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.
 
8.	Income Taxes	
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
 
 	 	Year Ended December 31,	 	
 	 	2018	 	 	2017	 	 	2016	 	
Current income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. federal	 	$	(14	)	 	$	9	 	 	$	3	 	
Various states	 	 	(3	)	 	 	—	 	 	 	(11	)	
Canada and various provinces	 	 	(53	)	 	 	103	 	 	 	106	 	
Total current tax expense (benefit)	 	 	(70	)	 	 	112	 	 	 	98	 	
Deferred income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. federal	 	 	248	 	 	 	—	 	 	 	—	 	
Various states	 	 	63	 	 	 	—	 	 	 	—	 	
Canada and various provinces	 	 	(85	)	 	 	(97	)	 	 	43	 	
Total deferred tax expense (benefit)	 	 	226	 	 	 	(97	)	 	 	43	 	
Total income tax expense	 	$	156	 	 	$	15	 	 	$	141	 	
 
Total income tax expense 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,	 	
 	 	2018	 	 	2017	 	 	2016	 	
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	 	 	21	%	 	 	35	%	 	 	35	%	
U.S. Tax Reform	 	 	0	%	 	 	36	%	 	 	0	%	
Legal entity restructuring	 	 	2	%	 	 	(94	%)	 	 	19	%	
State income taxes	 	 	5	%	 	 	0	%	 	 	10	%	
Change in unrecognized tax benefits	 	 	(5	%)	 	 	2	%	 	 	(16	%)	
Other	 	 	(0	%)	 	 	(13	%)	 	 	8	%	
Deferred tax asset valuation allowance	 	 	(6	%)	 	 	36	%	 	 	(89	%)	
Effective income tax rate	 	 	17	%	 	 	2	%	 	 	(33	%)	
 
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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 examinations 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 allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.
 
2018
 
In the second 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 the closure of prior year IRS audits.
 
Throughout 2017 and through the first two quarters of 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
T he 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.   
D uring 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 gas assets. These items were not deductible for purposes of calculating income tax and, therefore, impacted the effective tax rate.
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Index to Financial Statements
 
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,	 	
 	 	2018	 	 	2017	 	
Deferred tax assets:	 	 	 	 	 	 	 	 	
Asset retirement obligations	 	$	300	 	 	$	313	 	
Accrued liabilities	 	 	50	 	 	 	62	 	
Net operating loss carryforwards	 	 	287	 	 	 	796	 	
Pension benefit obligations	 	 	44	 	 	 	54	 	
Canadian capital loss carryforwards	 	 	609	 	 	 	760	 	
Other	 	 	87	 	 	 	135	 	
Total deferred tax assets before valuation allowance	 	 	1,377	 	 	 	2,120	 	
Less: valuation allowance	 	 	(640	)	 	 	(968	)	
Net deferred tax assets	 	 	737	 	 	 	1,152	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	 	
Property and equipment	 	 	(1,473	)	 	 	(1,288	)	
Long-term debt	 	 	—	 	 	 	(92	)	
Other	 	 	(141	)	 	 	(261	)	
Total deferred tax liabilities	 	 	(1,614	)	 	 	(1,641	)	
Net deferred tax liability	 	$	(877	)	 	$	(489	)	
 
At December 31, 2018, Devon has recognized $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 expiring in 2037 and $784 million of U.S. state net operating loss carryforwards expiring between 2019 and 2038. In the current environment, Devon expects tax benefits from the U.S. federal, majority of U.S. state and Canadian noncapital loss carryforwards to be utilized in 2019 and beyond .
As a result of Devon’s sale of its aggregate ownership interests in EnLink and the General 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 of valuation allowance against certain deferred tax assets, including certain tax credits and state net operating losses. Also during 2018, Devon’s Canadian segment maintained a valuation allowance of $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.
After 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, 2018, no income taxes should be accrued by Devon relative to its investment in its Canadian operations. In view of Devon’s decision in February 2019 to dispose of the Canadian business, the indefinitely reinvested assertion of APB 23 and any required accrual of income tax will be reevaluated in 2019.
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.
 
 	 	December 31,	 	
 	 	2018	 	 	2017	 	
Balance at beginning of year	 	$	115	 	 	$	202	 	
Tax positions taken in prior periods	 	 	(43	)	 	 	(7	)	
Tax positions taken in current year	 	 	(2	)	 	 	(3	)	
Accrual of interest related to tax positions taken	 	 	3	 	 	 	16	 	
Settlements	 	 	—	 	 	 	(101	)	
Foreign currency translation	 	 	(3	)	 	 	8	 	
Balance at end of year	 	$	70	 	 	$	115	 	
 
Devon’s unrecognized tax benefit balance at December 31, 2018 and 2017 included $12 million and $28 million, respectively, of interest and penalties. If recognized, $70 million of Devon’s unrecognized tax benefits as of December 31, 2018 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	 	2015-2018	
Various U.S. states	 	2014-2018	
Canada Federal	 	2004-2018	
Various Canadian provinces	 	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.  

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
9 .	Net Earnings (Loss) Per Share from Continuing Operations	
The following table reconciles net earnings (loss) from continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share from continuing operations.
 
 	 	Year Ended December 31,	 	
 	 	2018	 	 	2017	 	 	2016	 	
Net earnings (loss) from continuing operations:	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss) from continuing operations	 	$	764	 	 	$	758	 	 	$	(574	)	
Attributable to participating securities	 	 	(9	)	 	 	(8	)	 	 	(2	)	
Basic and diluted earnings (loss) from continuing operations	 	$	755	 	 	$	750	 	 	$	(576	)	
Common shares:	 	 	 	 	 	 	 	 	 	 	 	 	
Common shares outstanding - total	 	 	499	 	 	 	525	 	 	 	513	 	
Attributable to participating securities	 	 	(5	)	 	 	(5	)	 	 	(6	)	
Common shares outstanding - basic	 	 	494	 	 	 	520	 	 	 	507	 	
Dilutive effect of potential common shares issuable	 	 	3	 	 	 	3	 	 	 	—	 	
Common shares outstanding - diluted	 	 	497	 	 	 	523	 	 	 	507	 	
Net earnings (loss) per share from continuing operations:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	1.53	 	 	$	1.44	 	 	$	(1.14	)	
Diluted	 	$	1.52	 	 	$	1.43	 	 	$	(1.14	)	
Antidilutive options (1)	 	 	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.	
 
10.	Other Comprehensive Earnings	
Components of other comprehensive earnings consist of the following:
 
 	 	Year Ended December 31,	 	
 	 	2018	 	 	2017	 	 	2016	 	
Foreign currency translation:	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning accumulated foreign currency translation	 	$	1,309	 	 	$	1,226	 	 	$	1,215	 	
Change in cumulative translation adjustment	 	 	(166	)	 	 	113	 	 	 	22	 	
Income tax benefit (expense)	 	 	14	 	 	 	(30	)	 	 	(11	)	
Ending accumulated foreign currency translation	 	 	1,157	 	 	 	1,309	 	 	 	1,226	 	
Pension and postretirement benefit plans:	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning accumulated pension and postretirement benefits	 	 	(143	)	 	 	(172	)	 	 	(194	)	
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)	 	 	12	 	 	 	19	 	 	 	26	 	
Curtailment and settlement of pension benefits	 	 	47	 	 	 	—	 	 	 	24	 	
Income tax expense	 	 	(12	)	 	 	—	 	 	 	—	 	
Other (2)	 	 	(33	)	 	 	—	 	 	 	—	 	
Ending accumulated pension and postretirement benefits	 	 	(132	)	 	 	(143	)	 	 	(172	)	
Other	 	 	2	 	 	 	—	 	 	 	—	 	
Accumulated other comprehensive earnings, net of tax	 	$	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 other expenses in the accompanying consolidated comprehensive statements of earnings. See Note 17 for additional details.	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
(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,	 	
 	 	2018	 	 	2017	 	 	2016	 	
Changes in assets and liabilities, net	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable	 	$	88	 	 	$	(94	)	 	$	(58	)	
Other current assets	 	 	(128	)	 	 	20	 	 	 	326	 	
Other long-term assets	 	 	(28	)	 	 	(47	)	 	 	36	 	
Accounts payable	 	 	—	 	 	 	113	 	 	 	(196	)	
Revenues and royalties payable	 	 	153	 	 	 	106	 	 	 	(26	)	
Other current liabilities	 	 	(150	)	 	 	(53	)	 	 	(74	)	
Other long-term liabilities	 	 	(78	)	 	 	(13	)	 	 	16	 	
Total	 	$	(143	)	 	$	32	 	 	$	24	 	
Supplementary cash flow data - total operations:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest paid (net of capitalized interest)	 	$	385	 	 	$	481	 	 	$	569	 	
Income taxes paid (received)	 	$	40	 	 	$	78	 	 	$	(159	)	
 
In 2016, Devon’s acquisition of certain STACK 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 units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions.  

12.	Accounts Receivable	
Components of accounts receivable include the following:
 
 	 	December 31, 2018	 	 	December 31, 2017	 	
Oil, gas and NGL sales	 	$	430	 	 	$	559	 	
Joint interest billings	 	 	155	 	 	 	134	 	
Marketing revenues	 	 	285	 	 	 	278	 	
Other	 	 	23	 	 	 	29	 	
Gross accounts receivable	 	 	893	 	 	 	1,000	 	
Allowance for doubtful accounts	 	 	(8	)	 	 	(11	)	
Net accounts receivable	 	$	885	 	 	$	989	 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
13. Property, Plant and Equipment
 
Capitalized Costs
 
The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
 
 	 	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 summarizes the 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	 	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The following table provides 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 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.
 
14.	Other Current Liabilities	
Components of other current liabilities include the following:
 
 	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	 	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
15.	Debt and Related Expenses	
See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.  
 
 	 	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)	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 $162 million of 6.30% senior notes due January 15, 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	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Credit Lines
Under its 2012 Senior Credit Facility, Devon had $3.0 billion of available credit. On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and subsequently entered into its new $3.0 billion revolving 2018 Senior Credit Facility. The 2018 Senior Credit Facility matures on October 5, 2023, with the option to extend the maturity date 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 $6.1 million. As of December 31, 2018, Devon had $48 million in outstanding letters of credit under the 2018 Senior Credit Facility. There were no borrowings under the Senior Credit 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. For example, total capitalization is adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 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, 2018, Devon had no outstanding commercial paper borrowings.
Retirement of Senior Notes
During 2018, Devon completed tender offers to repurchase $807 million in aggregate principal amount of debt using cash on hand. This included $384 million of the 7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 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 included 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 other fees. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Financing Costs, Net
The following schedule includes the components of net financing costs.
 
 	 	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	 	

16.	Asset Retirement Obligations	
The following table presents the changes in asset retirement obligations.
 
 	 	Year Ended December 31,	 	
 	 	2018	 	 	2017	 	
Asset retirement obligations as of beginning of period	 	$	1,138	 	 	$	1,258	 	
Liabilities incurred	 	 	39	 	 	 	40	 	
Liabilities settled and divested	 	 	(116	)	 	 	(68	)	
Revision of estimated obligation	 	 	(25	)	 	 	(184	)	
Accretion expense on discounted obligation	 	 	59	 	 	 	62	 	
Foreign currency translation adjustment	 	 	(38	)	 	 	30	 	
Asset retirement obligations as of end of period	 	 	1,057	 	 	 	1,138	 	
Less current portion	 	 	27	 	 	 	39	 	
Asset retirement obligations, long-term	 	$	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.
 
17.	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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Defined Benefit Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans covering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits under the defined benefit plans have been closed to new employees; however, eligible employees continue to accrue benefits based upon years of service and compensation. Benefits are primarily funded from assets held in the plans’ trusts.  
Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 70% fixed income, 20% equity and 10% other. See the following discussion for Devon’s pension assets by asset class.
Fixed-income – 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 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 securities are based upon the net asset values provided by the investment managers and were $301 million and $401 million at December 31, 2018 and 2017, respectively.
Equity – Devon’s equity securities include commingled global equity funds that invest in large, mid and small capitalization stocks across the world’s developed and emerging markets and international large cap equity securities. These equity securities can be sold on demand but are not actively traded. The fair values of these securities are based upon the net asset values provided by the investment managers and were $84 million and $157 million at December 31, 2018 and 2017, respectively.
Other – Devon’s other securities include short-term investment funds and a hedge fund that invest both long and short using a variety of investment strategies. The fair value of these securities is based upon the net asset values provided by investment managers 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 plans is to fund the benefits as they become payable with available cash and cash equivalents.
Benefit Obligations and Funded Status
The following table summarizes the 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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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 the 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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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 assumptions – For measurement of the 2018 benefit obligation for the other postretirement medical plans, a 7.1% annual rate of increase in 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.
 
Expected Cash Flows
Devon expects benefit plan payments to average approximately $59 million a year for the next five years and $153 million total for the five years thereafter. Of these payments to be paid in 2019, $17 million is expected to be funded from Devon’s available cash, cash equivalents and other assets.
 
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 January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset 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.
Share 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.
 
 	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 dividend rate from $0.24 to $0.06 per share in the second quarter of 2016. Devon increased the quarterly dividend by 33% to $0.08 per share in the second quarter of 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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

19.	Discontinued Operations and Assets Held For Sale	
 
On June 6, 2018, Devon announced that it had entered into an agreement to sell its aggregate ownership interests in EnLink and the General Partner for $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 met 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 EnLink and 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 in Note 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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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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. Devon 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 are claims that Devon 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.
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 legal proceedings incidental to its business. However, to Devon’s knowledge, there were no material pending legal proceedings to which Devon is a party or to which any of its property is subject.
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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, 2018.
 
Year Ending December 31,	 	Purchase Obligations	 	 	Drilling and Facility Obligations	 	 	Operational Agreements	 	 	Office and Equipment Leases	 	
2019	 	$	541	 	 	$	274	 	 	$	587	 	 	$	64	 	
2020	 	 	567	 	 	 	85	 	 	 	519	 	 	 	43	 	
2021	 	 	140	 	 	 	48	 	 	 	373	 	 	 	31	 	
2022	 	 	—	 	 	 	14	 	 	 	419	 	 	 	26	 	
2023	 	 	—	 	 	 	8	 	 	 	354	 	 	 	25	 	
Thereafter	 	 	—	 	 	 	16	 	 	 	3,374	 	 	 	311	 	
Total	 	$	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 recognized for operating leases, net of sublease income, was $11 million, $7 million and $11 million in 2018, 2017 and 2016, respectively.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, 2018 and December 31, 2017, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets and related 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 17 , respectively.
 
 	 	 	 	 	 	 	 	 	 	Fair Value Measurements Using:	 	
 	 	Carrying	 	 	Total Fair	 	 	Level 1	 	 	Level 2	 	
 	 	Amount	 	 	Value	 	 	Inputs	 	 	Inputs	 	
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	 	$	1,533	 	 	$	1,533	 	 	$	1,454	 	 	$	79	 	
Commodity derivatives	 	$	205	 	 	$	205	 	 	$	—	 	 	$	205	 	
Commodity derivatives	 	$	(286	)	 	$	(286	)	 	$	—	 	 	$	(286	)	
Interest rate derivatives	 	$	1	 	 	$	1	 	 	$	—	 	 	$	1	 	
Interest rate derivatives	 	$	(64	)	 	$	(64	)	 	$	—	 	 	$	(64	)	
Debt	 	$	(6,864	)	 	$	(8,131	)	 	$	—	 	 	$	(8,131	)	
 
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 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 derivatives – The fair values of commodity and interest rate 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.
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.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 23 .
Devon considers EnLink, combined with the General Partner, to be a segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located in the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. However, with Devon’s closing of the divestment of EnLink and 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 assets and liabilities held for sale on the consolidated balance sheets. Additional information can be found in Note 19 .
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 	 	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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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	 	

 
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.
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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, 2017	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Property acquisition costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Proved properties	 	$	2	 	 	$	—	 	 	$	2	 	
Unproved properties	 	 	50	 	 	 	4	 	 	 	54	 	
Exploration costs	 	 	590	 	 	 	87	 	 	 	677	 	
Development costs	 	 	1,036	 	 	 	225	 	 	 	1,261	 	
Costs incurred	 	$	1,678	 	 	$	316	 	 	$	1,994	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31, 2016	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Property acquisition costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Proved properties	 	$	237	 	 	$	—	 	 	$	237	 	
Unproved properties	 	 	1,356	 	 	 	2	 	 	 	1,358	 	
Exploration costs	 	 	282	 	 	 	78	 	 	 	360	 	
Development costs	 	 	875	 	 	 	54	 	 	 	929	 	
Costs incurred	 	$	2,750	 	 	$	134	 	 	$	2,884	 	
 
Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations. 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 $41 million, $69 million and $61 million in 2018, 2017 and 2016, respectively.
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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.
 
 	 	Year Ended December 31, 2018	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Oil, gas and NGL sales	 	$	4,863	 	 	$	814	 	 	$	5,677	 	
Production expenses	 	 	(1,620	)	 	 	(605	)	 	 	(2,225	)	
Exploration expenses	 	 	(129	)	 	 	(48	)	 	 	(177	)	
Depreciation, depletion and amortization	 	 	(1,234	)	 	 	(325	)	 	 	(1,559	)	
Asset dispositions	 	 	262	 	 	 	—	 	 	 	262	 	
Asset impairments	 	 	(109	)	 	 	—	 	 	 	(109	)	
Accretion of asset retirement obligations	 	 	(35	)	 	 	(24	)	 	 	(59	)	
Income tax (expense) benefit	 	 	(460	)	 	 	51	 	 	 	(409	)	
Results of operations	 	$	1,538	 	 	$	(137	)	 	$	1,401	 	
Depreciation, depletion and amortization per Boe	 	$	8.08	 	 	$	7.63	 	 	$	7.98	 	
 
 	 	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	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Proved Reserves
The following table presents Devon’s estimated proved reserves by product and by country.
 
 	 	 	 	 	 	 	 	 	 	 	 	 	 	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	 	

(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.	
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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 2018 (MMBoe).
 
 	 	U.S.	 	 	Canada	 	 	Total	 	
Proved undeveloped reserves as of December 31, 2017	 	 	201	 	 	 	209	 	 	 	410	 	
Extensions and discoveries	 	 	107	 	 	 	6	 	 	 	113	 	
Revisions due to prices	 	 	1	 	 	 	6	 	 	 	7	 	
Revisions other than price	 	 	(8	)	 	 	(15	)	 	 	(23	)	
Sale of reserves	 	 	(10	)	 	 	—	 	 	 	(10	)	
Conversion to proved developed reserves	 	 	(52	)	 	 	—	 	 	 	(52	)	
Proved undeveloped reserves as of December 31, 2018	 	 	239	 	 	 	206	 	 	 	445	 	
 
Total proved undeveloped reserves increased 9% from 2017 to 2018 with the year-end 2018 balance representing 23% of total proved reserves. Devon’s focus on drilling and development activities in the STACK and Delaware Basin was the primary driver of the 113 MMBoe in extensions and discoveries. Continued development primarily in the STACK and Delaware Basin led to the conversion of 52 MMBoe, or 26%, of the 2017 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $691 million for 2018.     
A significant amount of Devon’s proved undeveloped reserves at the end of 2018 related to its Jackfish operations. At December 31, 2018 and 2017, Devon’s Jackfish proved undeveloped reserves were 206 MMBoe and 209 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 five 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 2032. At the end of 2018, approximately 125 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 81 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Price Revisions
Reserves 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 38 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 for oil and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes.
Revisions Other Than Price
Total revisions other than price in 2018 primarily related to Devon’s evaluation of certain oil and dry gas regions, with the largest revisions being made in the STACK.
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 STACK (Cana-Woodford Shale).
Extensions and Discoveries
2018 – Approximately 72% of the additions were through our focused efforts in the STACK (87 MMBoe) and the Delaware Basin (88 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.
The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling activities, primarily relating to the STACK.
2017 – Over 80% of the additions were through our focused efforts in the STACK (120 MMBoe) and the Delaware Basin (79 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.
The 2017 extensions and discoveries included 66 MMBoe related to additions from Devon’s infill drilling activities primarily related to the STACK.
2016 – Of the 126 MMBoe of extensions and discoveries, 97 MMBoe related to STACK, 18 MMBoe related to the Delaware Basin and 7 MMBoe related to the Eagle Ford.
The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling activities primarily related to the STACK.
Purchase of Reserves
2016 – Primarily related to Devon’s acquisition in the STACK play.
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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, 2017	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Future cash inflows	 	$	34,701	 	 	$	13,602	 	 	$	48,303	 	
Future costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Development	 	 	(3,316	)	 	 	(1,853	)	 	 	(5,169	)	
Production	 	 	(15,526	)	 	 	(5,986	)	 	 	(21,512	)	
Future income tax expense	 	 	—	 	 	 	(988	)	 	 	(988	)	
Future net cash flow	 	 	15,859	 	 	 	4,775	 	 	 	20,634	 	
10% discount to reflect timing of cash flows	 	 	(7,541	)	 	 	(1,756	)	 	 	(9,297	)	
Standardized measure of discounted future net cash flows	 	$	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	 	
 
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 2018 estimates, Devon’s future realized prices were assumed to be $58.64 per Bbl of oil, $22.12 per Bbl of bitumen, $2.45 per Mcf of gas and $24.72 per Bbl of NGLs. Of the $5.0 billion of future development costs as of the end of 2018, $1.2 billion, $0.6 billion and $0.3 billion are estimated to be spent in 2019, 2020 and 2021, respectively.
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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 $5.0 billion of future development costs are $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,	 	
 	 	2018	 	 	2017	 	 	2016	 	
Beginning balance	 	$	11,337	 	 	$	5,440	 	 	$	7,883	 	
Net changes in prices and production costs	 	 	(243	)	 	 	5,218	 	 	 	(2,027	)	
Oil, bitumen, gas and NGL sales, net of production costs	 	 	(3,452	)	 	 	(3,327	)	 	 	(2,377	)	
Changes in estimated future development costs	 	 	(216	)	 	 	789	 	 	 	112	 	
Extensions and discoveries, net of future development costs	 	 	3,139	 	 	 	2,497	 	 	 	674	 	
Purchase of reserves	 	 	—	 	 	 	2	 	 	 	224	 	
Sales of reserves in place	 	 	(588	)	 	 	(3	)	 	 	(577	)	
Revisions of quantity estimates	 	 	(414	)	 	 	(318	)	 	 	(21	)	
Previously estimated development costs incurred during the period	 	 	962	 	 	 	559	 	 	 	663	 	
Accretion of discount	 	 	960	 	 	 	1,034	 	 	 	537	 	
Foreign exchange and other	 	 	(329	)	 	 	(7	)	 	 	72	 	
Net change in income taxes	 	 	(964	)	 	 	(547	)	 	 	277	 	
Ending balance	 	$	10,192	 	 	$	11,337	 	 	$	5,440	 	
 
24.	Supplemental Quarterly Financial Information (Unaudited)	
The following tables present a summary of Devon’s unaudited interim results of operations.
 
 	 	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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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 .	

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedure s
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, 2018 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 in Internal Control – Integrated Framework issued 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 20, 2019, management concluded that its internal control over financial reporting was effective as of December 31, 2018.
The effectiveness of our internal control over financial reporting as of December 31, 2018 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, 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 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Not applicable.

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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 no later than 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 no later than 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 no later than 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 no later than 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 no later than 120 days following the fiscal year ended December 31, 2018.

 
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PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are included 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	
 	 	 	
  2.1	 	Purchase Agreement, dated June 7, 2018, by and among Devon Gas Services, L.P. and Southwestern Gas Pipeline, L.L.C., as sellers, and Enlink 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 June 7, 2018; File No. 001-32318 ).	
 	 	 	
  3.1	 	Registrant’s Restated Certificate of Incorporation ( incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318 ).	
 	 	 	
  3.2	 	Registrant’s Bylaws ( incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed January 27, 2016; File No. 001-32318 ).	
 	 	 	
  4.1	 	Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee ( incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318 ).	
 	 	 	
  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 by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318 ).	
 	 	 	
  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 by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012; File No. 001-32318 ).	
 	 	 	
  4.4	 	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 by reference to Exhibit 4.1 to Registrant’s Form 8-K filed June 16, 2015; File No. 001-32318 ).	
 	 	 	
  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 by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 15, 2015; File No. 001-32318 ).	
 	 	 	
  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 by reference to Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176 ).	
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Exhibit No.	 	Description	
 	 	 	
  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 by reference to Exhibit 4.2 to Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176 ).	
 	 	 	
  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 by reference to Exhibit 4.1 to Registrant’s Form 8-K filed January 9, 2009; File No. 000-32318 ).	
 	 	 	
  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, among Devon Financing Company, L.L.C. (f/k/a Devon Financing Corporation, 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 by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4 filed October 31, 2001; File No. 333-68694 ).	
 	 	 	
  4.11	 	Senior Indenture, dated as of September 1, 1997, between Devon OEI Operating, L.L.C. (as successor to Seagull Energy 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 due 2027 ( incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K filed March 23, 1998; File No. 001-08094 ).	
 	 	 	
  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., its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 ( incorporated by reference to Exhibit 4.10 to Ocean Energy, Inc.’s Form 10-Q filed May 17, 1999; File No. 001-08094 ).	
 	 	 	
  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., its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 ( incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444 ).	
 	 	 	
  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 due 2027 ( incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K filed March 3, 2006; File No. 001-32318 ).	
 	 	 	
  10.1	 	Credit Agreement, dated as of October 5, 2018, among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, and each Lender and L/C Issuer from time to time party thereto ( incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 9, 2018; File No. 001-32318 ).	
 	 	 	
  10.2	 	Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) ( incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed June 8, 2012; File No. 001-32318 ).*	
 	 	 	
  10.3	 	Devon Energy Corporation 2015 Long-Term Incentive Plan ( incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666 ).*	
 	 	 	
112

Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
  10.4
 	 	Devon Energy Corporation 2017 Long-Term Incentive Plan ( incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 7, 2017; File No. 333-218561 ).*	
 	 	 	
  10.5	 	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 by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2013; File No. 001-32318 ).*	
 	 	 	
  10.6	 	Devon Energy Corporation Annual Incentive Compensation Plan (amended and restated effective as of January 1, 2017) ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed June 12, 2017; File No. 001-32318 ).*	
 	 	 	
  10.7	 	Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective as of April 15, 2014) ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 6, 2014; File No. 001-32318 ).*	
 	 	 	
  10.8	 	Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014) ( incorporated by reference to Exhibit 10.11 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318 ).*	
 	 	 	
  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 by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318 ).*	
 	 	 	
  10.12	 	Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) ( incorporated by reference to Exhibit 10.6 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318 ).*	
 	 	 	
  10.13	 	Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318 ).*	
 	 	 	
  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 by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318 ).*	
 	 	 	
  10.16	 	Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) ( incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318 ).*	
 	 	 	
  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 by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318 ).*	
113

Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  10.20	 	Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) ( incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318 ).*	
 	 	 	
  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 by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318 ).*	
 	 	 	
  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 by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318 ).*	
 	 	 	
  10.25	 	Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) ( incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318 ).*	
 	 	 	
  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 (amended and restated effective January 1, 2018) ( incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 21, 2018; File No. 001-32318 ).*	
 	 	 	
  10.28              	 	Amendment 2018-1, executed December 14, 2018, to the Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2018). *	
 	 	 	
  10.29	 	Amended and Restated Form of Employment Agreement between Registrant and certain executive officers ( incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009; File No. 001-32318 ).*	
 	 	 	
  10.30	 	Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant and certain executive officers ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011; File No. 001-32318 ).*	
 	 	 	
  10.31	 	Form of Employment Agreement between Registrant and certain executive officers ( incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318 ).*	
 	 	 	
  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 ).*	
 	 	 	
  10.33	 	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 executive officers for performance based restricted stock awarded ( incorporated by reference to Exhibit 10.29 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318 ).*	
 	 	 	
  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 by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 4, 2015; File No. 001-32318 ).*	
114

Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  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 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded ( incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed May 4, 2016; File No. 001-32318 ).*	
 	 	 	
  10.39	 	2017 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded ( incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 3, 2017; File No. 001-32318 ).*	
 	 	 	
  10.40	 	2018 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded ( incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 2, 2018; File No. 001-32318 ).*	
 	 	 	
  10.41	 	Form of Notice of Grant of Incentive Stock Options and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for incentive stock options granted ( incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318 ).*	
 	 	 	
  10.42	 	Form of Notice of Grant of Nonqualified Stock Options and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for nonqualified stock options granted ( incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318 ).*	
 	 	 	
  10.43	 	2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and all non-management directors for restricted stock awarded  ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 2, 2018; File No. 001-32318 ).*	
 	 	 	
  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 John Richels ( incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318 ).*	
 	 	 	
  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 by reference to Exhibit 10.24 to Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318 ).*	
 	 	 	
115

Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
  10.46	 	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 ( incorporated by reference to Exhibit 10.44 to Registrant’s Form 10-K filed February 17, 2016; File No. 001-32318 ).*	
 	 	 	
  21	 	List of Subsidiaries.	
 	 	 	
  23.1	 	Consent of KPMG LLP.	
 	 	 	
  23.2	 	Consent of LaRoche Petroleum Consultants, Ltd.	
 	 	 	
  23.3	 	Consent of 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 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.	

*	Indicates management contract or compensatory plan or arrangement.	

Item 16. Form 10-K Summary
 
Not applicable.
 
116

Table of Contents
 
Index to Financial Statements
 
SIG NATURES
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:	/s/ JEFFREY L. RITENOUR	
 	 	Jeffrey L. Ritenour	
 	 	Executive Vice President and
Chief Financial Officer	
 
February 20, 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, Chief Executive Officer and	February 20, 2019	
David A. Hager	 	Director (Principal executive officer)	 	
 	 	 	 	
/s/ JEFFREY L. RITENOUR	 	Executive Vice President	February 20, 2019	
Jeffrey L. Ritenour	 	and Chief Financial Officer
(Principal financial officer)	 	
 	 	 	 	
/s/ JEREMY D. HUMPHERS	 	Senior Vice President	February 20, 2019	
Jeremy D. Humphers	 	and Chief Accounting Officer
(Principal accounting officer)	 	
 	 	 	 	
/s/ JOHN RICHELS	 	Chairman of the Board	February 20, 2019	
John Richels	 	 	 	
 	 	 	 	
/s/ DUANE C. RADTKE	 	Vice Chairman of the Board	February 20, 2019	
Duane C. Radtke	 	 	 	
 	 	 	 	
/s/ BARBARA M. BAUMANN	 	Director	February 20, 2019	
Barbara M. Baumann	 	 	 	
 	 	 	 	
/s/ JOHN E. BETHANCOURT	 	Director	February 20, 2019	
John E. Bethancourt	 	 	 	
 	 	 	 	
/s/ ROBERT H. HENRY	 	Director	February 20, 2019	
Robert H. Henry	 	 	 	
 	 	 	 	
/s/ MICHAEL M. KANOVSKY	 	Director	February 20, 2019	
Michael M. Kanovsky	 	 	 	
 	 	 	 	
/s/ JOHN KRENICKI JR.	 	Director	February 20, 2019	
John Krenicki Jr.	 	 	 	
 	 	 	 	
/s/ ROBERT A. MOSBACHER, JR.	 	Director	February 20, 2019	
Robert A. Mosbacher, Jr.	 	 	 	
 	 	 	 	
/s/ MARY P. RICCIARDELLO	 	Director	February 20, 2019	
Mary P. Ricciardello	 	 	 	

 
 
117

EXHIBIT 10.10
AMENDMENT 2018-1
TO THE
DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN
The Devon Energy Corporation Non-Qualified Deferred Compensation Plan (the " Plan ") is irrevocably amended as follows:
1. Article X of the Plan (" Amendment and Termination ") is amended to add a new Section 10.2 to the end thereof to read as follows:
 "10.2 Termination of Plan for EnLink Participants .  On July 18, 2018, the Company consummated the sale of its ownership interests in EnLink Midstream Partners, LP and EnLink Midstream, LLC described in the Purchase Agreement, dated June 5, 2018, by and among Devon Gas Services, L.P. And Southwestern Gas Pipeline, L.L.C., as Sellers, Enlink Midstream Manager, LLC, Devon Energy Corporation, And GIP III Stetson I, L.P. And GIP III Stetson II, L.P., as Acquirors (the " EnLink Sale "), which constituted a change in control event within the meaning of Treasury Regulation §1.409A-3(i)(5). Accordingly, in connection with the consummation of the EnLink Sale the portion of the Plan consisting of the Accounts of the Participants who were employed by a company that experienced a change in control event upon the EnLink Sale (the " Affected Participants ") is irrevocably terminated and liquidated in accordance with Treasury Regulation §1.409A-3(j)(4)(ix)(B), and all accrued and unpaid benefits payable to the Affected Participants under the Plan shall be distributed to Affected Participants in a single lump sum payment in accordance with Treasury Regulation §1.409A-3(j)(4)(ix)(B).    "
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

1

IN WITNESS WHEREOF, Devon Energy Corporation (acting through its authorized delegate) has caused this Amendment 2018 -1 to the Plan to be executed t his 21 st day of August,  2018 .
DEVON ENERGY CORPORATION
 
By:	 	/s/ Tana K. Cashion	
Name:	 	Tana K. Cashion	
Title:	 	Senior Vice President, Human Resources	
 
[ Signature Page to Amendment 2018-1 to the Devon Energy Non-Qualified Deferred Compensation Plan ]

EXHIBIT 10.18
AMENDMENT 2018-1
TO THE
DEVON ENERGY CORPORATION
DEFINED CONTRIBUTION RESTORATION PLAN
The Devon Energy Corporation Defined Contribution Restoration Plan (the " Plan ") is irrevocably amended as follows:
1. Article IX of the Plan (" Amendment and Termination ") is amended to add a new Section 9.2 is added to the Plan to read as follows:
"9.2 Termination of the Plan for EnLink Participants .  On July 18, 2018, the Company consummated the sale of its ownership interests in EnLink Midstream Partners, LP and EnLink Midstream, LLC described in the Purchase Agreement, dated June 5, 2018, by and among Devon Gas Services, L.P. And Southwestern Gas Pipeline, L.L.C., as Sellers, Enlink Midstream Manager, LLC, Devon Energy Corporation, And GIP III Stetson I, L.P. And GIP III Stetson II, L.P., as Acquirors (the " EnLink Sale "), which constituted a change in control event within the meaning of Treasury Regulation §1.409A-3(i)(5).  Accordingly, in connection with the consummation of the EnLink Sale, the portion of the Plan consisting of the Accounts of the Participants who were employed by a company that experienced a change in control event upon the EnLink Sale (the " Affected Participants ") is irrevocably terminated and liquidated in accordance with Treasury Regulation §1.409A-3(j)(4)(ix)(B), and all accrued and unpaid benefits payable to Affected Participants under the Plan shall be distributed to the Affected Participants in a single lump sum payment in accordance with Treasury Regulation §1.409A-3(j)(4)(ix)(B)."
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

1

IN WITNESS WHEREOF, Devon Energy Corporation (acting through its authorized delegate) has caused this Amendment 201 8 -1 to the Plan to be executed this 21 st day of August, 201 8 .  
DEVON ENERGY CORPORATION
 
By:	 	/s/ Tana K. Cashion	
Name:	 	Tana K. Cashion	
Title:	 	Senior Vice President, Human Resources	
 
[ Signature Page to Amendment 2018-1 to the Devon Energy Corporation
Defined Contribution Restoration Plan ]

EXHIBIT 10.28
AMENDMENT 2018-1
TO THE
DEVON ENERGY CORPORATION
INCENTIVE SAVINGS PLAN
The Devon Energy Corporation Incentive Savings Plan (the " Plan ") is amended, effective January 1, 2019, as follows:
1. Paragraph ( 7) of Section 4.01(a) of the Plan (" Elections "), which begins "If a Participant makes a hardship withdrawal . . . .", is deleted in its entirety and all subsequent sections and cross-references are adjusted accordingly.
2. Section 8.04(b) of the Plan (" Hardship Withdrawals ") is amended in its entirety to read as follows:
 "(b) Hardship Withdrawals .  Each Participant who has exhausted all of his withdrawal rights under subsection (a) hereof, and any in-service withdrawal rights set forth in an Appendix hereto, shall have the right to make a withdrawal from (i) his Salary Deferral Account, (ii) his Roth 401(k) Account, (iii) his Roth In-Plan Conversion Account (to the extent such amounts are attributable to a Roth in-plan conversion of amounts from his Salary Deferral Account), and (iv) effective on and after January 1, 2019, the earnings in such Accounts described in clauses (i)–(iii) hereof.  If the Committee determines that a requested withdrawal is on account of an immediate and heavy financial need of the Participant, and the withdrawal is necessary to satisfy such financial need, the Committee shall permit the Participant to withdraw all or a portion of the amounts eligible for hardship withdrawal; provided, however, that the aggregate amount of a Participant's withdrawals from each of his Salary Deferral Account, Roth 401(k) Account, and/or Roth In-Plan Conversion Account shall not exceed the Participant's undistributed Salary Deferrals or Roth 401(k) Contributions, and for periods on and after January 1, 2019, earnings on such contributions, in each of the Accounts. For Participants with amounts eligible for hardship withdrawal in multiple Accounts, withdrawals shall be taken from such Accounts on a pro rata basis.
(1) A withdrawal on or after January 1, 2019 shall be deemed to be on account of an immediate and heavy financial need of a Participant when the withdrawal is on account of:
(A) expenses incurred or necessary for medical care of the Participant, the Participant's Spouse, any dependents, or a designated primary Beneficiary, of the Participant that would be deductible under Code section 213(d) (determined without regard to whether the expenses exceed 7.5% of adjusted gross income);
(B) the purchase (excluding mortgage payments) of a principal residence for the Participant;
 (C) the payment of tuition, related educational fees and room and board for up to the next 12 months of post-secondary education for the Participant, his Spouse, children, dependents (as defined in Code section 152 without
1

regard to Code sections 152(b)(1), (b)(2) and (d)(1)(B)) , or a designated primary Beneficiary ;
(D) expenses for the repair of damage to the Participant's principal residence that would qualify for the casualty deduction under Code section 165 (determined without regard to whether the loss exceeds 10% of adjusted gross income and, effective January 1, 2018, without regard to Code section 165(h)(5));
(E) the need to prevent the eviction of the Participant from, or foreclosure on the mortgage of, the Participant's principal residence;
(F) payments for burial or funeral expenses for the Participant's deceased parent, Spouse, child, dependent (as defined in Code section 152 and without regard to Code section 152(d)(1)(B)), or a designated primary Beneficiary;
(G) federal, state or local income taxes or penalties reasonably anticipated to result from the distribution;
(H) expenses and losses (including loss of income) on account of a disaster declared by the Federal Emergency Management Agency (" FEMA ") under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, Public Law 100–707, provided that the Participant's principal residence or principal place of employment at the time of the disaster was located in an area designated by FEMA for individual assistance; or
(I) such other circumstances as may be prescribed by the Secretary of the Treasury or his delegate.
The term "designated primary Beneficiary" for purposes of this subsection (1) means a primary Beneficiary under the Plan who has an unconditional right, upon the death of the Participant, to all or a portion of the Participant's Account under the Plan.
(2) A withdrawal on or after January 1, 2019 shall be necessary to satisfy the financial need of a Participant if:
(A) the amount of the withdrawal does not exceed the amount of the Participant's immediate and heavy financial need, including, at the election of the Participant, any amounts necessary to pay any federal, state or local income taxes or penalties reasonably anticipated to result from the distribution and a Participant making such application represents in writing to the Committee (and the Committee does not have actual knowledge to the contrary) that such need cannot be relieved:
(i) through reimbursement or compensation by insurance or otherwise;
 (ii) by reasonable liquidation of the Participant's assets, including those assets of his Spouse and minor children that are reasonably
2

available to him, to the extent such liquidation would not itself cause an immediate and heavy financial need; or
(iii) by other currently available distributions from the Plan or any other plan maintained by the Employer or by any other employer, in an amount sufficient to satisfy the need.
(3) If the Participant does not represent in writing to the Committee that he has an immediate and heavy financial need, a withdrawal on or after January 1. 2019 shall be deemed necessary to satisfy the financial need of a Participant if:
(A) the amount of the withdrawal does not exceed the amount of the Participant's immediate and heavy financial need, including, at the election of the Participant, any amounts necessary to pay any federal, state or local income taxes or penalties reasonably anticipated to result from the distribution; and
(B) the Participant has obtained all currently available distributions (including, if currently available pursuant to Section 6.09(e), by electing to receive dividend distributions in cash, but other than hardship distributions) under the Plan, if applicable, and all other qualified retirement plans maintained by the Employer and all Affiliated Companies (unless the Participant certifies that the amount that may be obtained through all such currently available distributions shall not be sufficient to satisfy the financial need).
 (4) With respect to a hardship withdrawal that is made on or after January 1, 2020, the Participant must represent (in writing or electronically in accordance with rules and procedures established by the Committee) that he has insufficient cash or other liquid assets to satisfy the need.  The Committee may rely on the Participant's representation unless the Committee has actual knowledge to the contrary.
(5) Notwithstanding anything in the Plan to the contrary, in the case of a Participant who received a hardship withdrawal before January 1, 2019, any suspension of such Participant's ability to make Salary Deferrals and/or Roth 401(k) Contributions or any other employee contributions due to the receipt of such hardship withdrawal will be cancelled, and the Participant will again be eligible to make such Salary Deferrals and/or Roth 401(k) or other employee contributions on and after January 1, 2019 to the extent permitted by law."
[REMAINDER OF PAGE INTENTIONALLY BLANK ]
 
3

IN WITNESS WHEREOF , Devon Energy Corporation (acting through its authorized delegate) has caused this Amendment 2018-1 to the Devon Energy Corporation Incentive Savings Plan to be executed this 14 th day of December, 2018.
DEVON ENERGY CORPORATION
 
By:	 	/s/ Tana K. Cashion	
Name:	 	Tana K. Cashion	
Title:	 	Senior Vice President, Human Resources	

[ Signature Page to Amendment 2018-1 to the Devon Energy Corporation Incentive Savings Plan ]

 
Exhibit 21
 
DEVON ENERGY CORPORATION
 
List of Subsidiaries 1 as of December 31, 2018
 
 	1.	Devon Energy Corporation (Oklahoma), an Oklahoma corporation	
 	2.	Devon OEI Holdings, L.L.C., a Delaware limited liability company	
 	3.	Devon OEI Operating, L.L.C., a Delaware limited liability company	
 	4.	Devon Energy Production Company, L.P., an Oklahoma limited partnership	
 	5.	Devon Financing Company, L.L.C., a Delaware limited liability company	
 	6.	Devon Canada Corporation, an Alberta corporation	
 	7.	Devon Gas Co., L.L.C., a Delaware limited liability company	
 	8.	Devon Gas Services, L.P., a Texas limited partnership	
 	9.	Devon Energy International, L.L.C., a Delaware limited liability company	
 	10.	Devon Headquarters, L.L.C., an Oklahoma limited liability company	

 	
1  	The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of the end of the year covered by this report, as defined under Securities and Exchange Commission Regulation S-X, Rule 1-02(w).	

Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
 
The Board of Directors 
 Devon Energy Corporation:
We consent to the incorporation by reference in the registration statement (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333-103679, 333-127630, 333-159796, 333-179181, 333-182198, 333-204666 and 333-218561) on Form S-8 and the registration statement (File No. 333-220462) on Form S-3 of Devon Energy Corporation of our report dated February 20, 2019, with respect to the consolidated balance sheets of Devon Energy Corporation as of December 31, 2018 and 2017, the related consolidated comprehensive statement of earnings, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the “consolidated financial statements”), and the effectiveness of internal control over financial reporting as of December 31, 2018, which report appears in the December 31, 2018 annual report on Form 10‑K of Devon Energy Corporation.
Our report refers to a change in its method of accounting for revenues from contracts with customers in 2018 due to the adoption of Accounting Standards Update 2014-19, Revenue from Contracts with Customers (ASC 606).
 
/s/ KPMG LLP
Oklahoma City, Oklahoma
February 20, 2019

 
Exhibit 23.2

 

 
ENGINEER'S CONSENT

 
We consent to the incorporation by reference in the registration statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333‑103679, 333-127630, 333-159796, 333-179181, 333-182198, 333-204666 and 333-218561) on Form S-8 and the registration statement (File No. 333-220462) on Form S-3 of Devon Energy Corporation (the “Company”) of our report for the Company and the references to our firm and said report, in the context in which they appear, in this Annual Report on Form 10-K of the Company for the year ended December 31, 2018 (this “Form 10-K”), which report is included as an exhibit to this Form 10-K.

				
 	LaRoche Petroleum Consultants, Ltd.
By LPC, Inc., General Partner	

 	 	 	 	
 	By:	/s/ William M. Kazmann	
 	 	William M. Kazmann	
 	 	President	

 
February 20, 2019

 

 

 

 
Exhibit 23.3

 

ENGINEER'S CONSENT

We consent to the incorporation by reference in the registration statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333‑103679, 333-127630, 333-159796, 333-179181, 333-182198, 333-204666 and 333-218561) on Form S-8 and the registration statement (File No. 333-220462) on Form S-3 of Devon Energy Corporation (the “Company”) of our report for the Company and the references to our firm and said report, in the context in which they appear, in this Annual Report on Form 10-K of the Company for the year ended December 31, 2018 (this “Form 10-K”), which report is included as an exhibit to this Form 10-K.

 
				
 	Deloitte LLP	

 	 	 	 	
 	By:	/s/ Robin G. Bertram	
 	 	Robin G. Bertram, P.Eng	

 
February 20, 2019

Exhibit 31.1
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, David A. Hager, certify that:
1.     I have reviewed this annual report on Form 10-K of Devon Energy Corporation;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
Date: February 20, 2019	 	 	
 	 	 	
 	 	/s/ David A. Hager	
 	 	David A. Hager	
 	 	President and Chief Executive Officer	

Exhibit 31.2
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Jeffrey L. Ritenour, certify that:
1.     I have reviewed this annual report on Form 10-K of Devon Energy Corporation;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
Date: February 20, 2019	 	 	
 	 	 	
 	 	/s/ Jeffrey L. Ritenour	
 	 	Jeffrey L. Ritenour	
 	 	Executive Vice President and Chief Financial Officer	

Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Report of Devon Energy Corporation (“Devon”) on Form 10-K for the period ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David A. Hager, President and Chief Executive Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
 	(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

 	
/s/ David A. Hager	
David A. Hager	
President and Chief Executive Officer	
February 20, 2019	

Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Report of Devon Energy Corporation (“Devon”) on Form 10-K for the period ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey L. Ritenour, Executive Vice President and Chief Financial Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
 	(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

 	
/s/ Jeffrey L. Ritenour	
Jeffrey L. Ritenour	
Executive Vice President and Chief Financial Officer	
February 20, 2019	

 
Exhibit 99.1

January 25, 2019

Mr. Bob Fant
Director Reserves and Economics
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102
 
Dear Mr. Fant:
 
At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has audited the estimates of proved reserves and future net cash flow, as of December 31, 2018, to the Devon Energy Corporation (Devon) interest in certain properties located in Devon’s US Division in the United States as prepared and completed by Devon on January 11, 2019.  The reserve estimates were prepared by Devon for public disclosure according to the United States Security and Exchange Commission (SEC) guidelines, and our audit is to confirm the accuracy of those estimates and classifications within the applicable SEC rules, regulations, and guidelines. It should be understood that our audit described herein does not constitute a complete reserve study of the oil and gas properties of Devon.  It is our understanding that the properties audited by LPC comprise approximately eighty-seven percent (87%) of Devon’s aggregate proved reserves for the US Division as estimated and reported by Devon.  We prepared our own estimates of proved reserves and net cash flow for all of the properties audited and compared our estimates to those prepared by Devon to complete our audit of such properties.  We believe the assumptions, data, methods, and procedures used are appropriate for the purpose of this audit.  Estimates by Devon and LPC are based on constant prices and costs as set forth in this letter and conform to our understanding of the SEC guidelines, reserves definitions, and applicable accounting rules.
 
It is our understanding that the properties audited by LPC and reflected in this audit report comprise approximately sixty-eight percent (68%) of Devon’s aggregate, corporate proved reserves as estimated and reported by Devon.
 
The US Division reserves discussed above are for the field areas designated by Devon’s internal naming system.  These areas include:
 
Anadarko Basin Sub-Division
Field Groups: Cana, Panhandle, and WOK Conventional
 
Delaware Basin Sub-Division
Field Groups: Catclaw Draw Area, Corbin Area, Crane Other, Hackberry, Keystone/Kermit, McKnight, Potato Basin Area, Rattlesnake/Arena Roja Area, Thjistle/Gaucho Area, Todd//Apache, Waddell North, and Waddell South
 
Texas Sub-Division
Field Groups: Boonsville, Boonsville South, De Witt, FWB Conventional Minor, FWB Conventional Minor South, NEBS Core Lean, NEBS Core N Denton, NEBS Core Rich Denton, NEBS Core Rich Wise, NEBS Noncore Denton, NEBS Noncore W Viola South, NEBS Noncore Western Extension, NEBS Noncore Wise, and Southern Other
 
2435 N Central Expressway, Suite 1500  ●  Dallas TX 75080  ●  Phone (214) 363-3337 ●  Fax (214) 363-1608

Rocky Mountain Sub-Division
Field Groups: Anton Irish, Big Sand Draw, Fullerton Area, NPRB Barlow, NPRB Other, Piceance, Reeves, Seagraves Other, Slaughter, Wasson, and Welch Area
 
The oil reserves include crude oil and condensate.  Oil and natural gas liquid (NGL) reserves are expressed in barrels which are equivalent to 42 United States gallons.  Gas volumes are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases.
 
The estimated reserves and future cash flow are for proved developed producing, proved developed non-producing, and proved undeveloped reserves.  Devon’s estimates do not include any value for unproven reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in undeveloped acreage beyond those tracts for which reserves have been estimated.
 
When compared on a field-by-field basis, some estimates determined by Devon are greater and some are less than the estimates determined by LPC.  However, in our opinion, Devon’s estimates of proved oil and gas reserves and future cash flow, as audited by LPC, are in the aggregate reasonable, are within ten (10) percent of our estimates, and have been prepared in accordance with generally accepted petroleum engineering and evaluation methods and procedures.  These methods and procedures are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers.  We are satisfied with the methods and procedures used by Devon in preparing the December 31, 2018 reserve and future cash flow estimates.  We saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Devon.
 
The estimated reserves and future cash flow amounts in this audit of the Devon report are related to hydrocarbon prices.  The price calculation methodology specified by the SEC regulations was used in the preparation of those estimates; however, actual future prices may vary significantly from the SEC-specified pricing.  In addition, future changes in taxation affecting oil and gas producing companies and their products and changes in environmental and administrative regulations may significantly affect the ability of Devon to operate and produce oil and gas at the projected levels.  Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this audit.
 
Estimates of reserves for this audit were prepared using standard geological and engineering methods generally accepted by the petroleum industry.  The reserves in this audit have been estimated using deterministic methods.  The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history.  Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance.  In some instances, comparisons were made to similar properties where more complete data were available.  We have used all methods and procedures that we considered necessary under the circumstances to prepare this audit.  We have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting rather than engineering or geosciences.
 
 Benchmark prices used in this audit are based on the twelve-month, unweighted arithmetic average of the first day of the month price for the period January through December 2018.  Oil prices used by Devon are based on a Cushing West Texas Intermediate crude oil price of $65.56 per barrel, as published in Platts Oilgram, adjusted by lease for gravity, crude quality, transportation fees, and regional price differentials.  Gas prices are based on a Henry Hub gas price of $3.10 per MMBtu, as published in Platts Gas Daily, adjusted by lease for energy content, transportation fees, and regional price differentials.  NGL prices are based on a Mt. Belvieu composite product price of $28.70 per barrel, as published in the OPIS daily price bulletin, adjusted by area for composition, quality, transportation fees, and regional price differentials.  Price differentials and adjustments to physical
LaRoche Petroleum Consultants, Ltd.

spot prices as of December 2018 were furnished by Devon and were accepted as presented.  Oil and gas prices are held constant throughout the life of the properties.  The weighted average prices over the life of the properties audited are $ 60.49 per barrel for oil, $2 .45 per Mcf for gas, and $ 24.47 per bar rel for NGL.
 
Lease and well operating expenses were furnished by Devon and were confirmed by LPC from a review of Devon accounting data on a Sub-Division or Division basis.  As requested, expenses for the Devon-operated properties include only direct lease and field level costs.  For properties operated by others, these expenses include the per-well overhead costs allowed under joint operating agreements along with direct lease and field level costs.  Headquarters general and administrative overhead expenses of Devon are not included. Operating expenses are held constant throughout the life of the properties.  
 
Capital costs and timing of all investments have been provided by Devon and are included as required for workovers, new development wells, and production equipment.  Devon has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled.  Devon's estimates of the cost to plug and abandon the wells net of salvage value are included and scheduled at the end of the economic life of individual properties.  These costs are held constant.
 
LPC has made no investigation of possible gas volume and value imbalances that may have been the result of overdelivery or underdelivery to the Devon interest.  Our projections are based on Devon receiving its net revenue interest share of estimated future gross oil, gas, and NGL production.
 
An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC.  The costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.
 
The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this audit.  In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements.  Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in our projections.
 
In our audit, we accepted without independent verification the accuracy and completeness of the information and data furnished by Devon with respect to ownership interest, oil and gas production, well test data, oil and gas prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production.  However, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data.
 
 The reserves estimated in our audit process and those presented by Devon are estimates only and should not be construed as exact quantities.  They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts.  These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations.  A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates.  Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production.  These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data.  It may be necessary to revise these estimates up or down in the
LaRoche Petroleum Consultants, Ltd.

future as additional performance data become available.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.
 
The results of our third-party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Devon Energy Corporation.
 
Devon Energy Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Securities Exchange Act.  Furthermore, Devon Energy Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference.  We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Devon Energy Corporation of the references to our name together with references to our third-party audit for Devon Energy Corporation, which appears in the December 31, 2018 annual report on Form 10-K and/or 10-K/A of Devon Energy Corporation.  Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.
 
We have provided Devon Energy Corporation with a digital version of the original signed copy of this audit letter.  In the event there are any differences between the digital version included in filings made by Devon Energy Corporation and the original signed audit letter, the original signed audit letter shall control and supersede the digital version.
 
LPC’s technical personnel responsible for preparing this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers.  The technical person primarily responsible for overseeing the preparation of the LPC audit is William M. Kazmann.  Mr. Kazmann is a Professional Engineer licensed in the State of Texas who has 44 years of engineering experience in the oil and gas industry.  He has prepared and overseen preparation of reports for public filings for LPC for the past 22 years. We are independent petroleum engineers, geologists, and geophysicists and are not employed on a contingent basis.  Data pertinent to the audit are maintained on file in our office.
 
Very truly yours,
 
LaRoche Petroleum Consultants, Ltd.
State of Texas Registration Number F-1360
By LPC, Inc. General Partner
 
                                             /s/ William M. Kazmann
 
William M. Kazmann
Licensed Professional Engineer
State of Texas No. 45012
 
                                   /s/ Joe A. Young
 
Joe A. Young
Licensed Professional Engineer
State of Texas No. 62866
 
WMK:jsc
18-600

LaRoche Petroleum Consultants, Ltd.

 

 

	
Please be advised that the digital document you are viewing is provided by LaRoche Petroleum Consultants, Ltd. (LPC) as a convenience to our clients.  The digital document is intended to be substantively the same as the original signed document maintained by LPC.  The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.	

LaRoche Petroleum Consultants, Ltd.

Exhibit 99.2

	 Deloitte LLP
 850- 2nd Street S.W.
Suite 700
Calgary AB  T2P 0R8
Canada
 
 Tel: 403 267 1700
 Fax: 587 774 5398
 www.deloitte.ca

  

 

  

	

 

January 16, 2019
  
 Devon Energy Corporation
333 West Sheridan
Oklahoma City, Oklahoma
USA 73102
 
Attention: Mr. Bob Fant
 
RE: Devon Canada Corporation
December 31, 2018 Reserve audit opinion
 At your request and authorization, Deloitte LLP (Deloitte) has audited the reserves management processes and practices of Devon Canada Corporation (Devon Canada) as of December 31, 2018. Our audit was completed on January 11, 2019 and included such tests and procedures, as we considered necessary under the circumstances, to render our opinion.
 
During the course of our examination, we audited in excess of 96 percent of Devon Canada’s total proved reserves in the Bonnyville and Jackfish fields within Western Canada. Deloitte’s estimate for the audited properties varied from Devon Canada’s estimates by less than 10 percent. When compared to Devon Canada’s parent corporation, Devon Energy Corporation, Deloitte audited 20 percent of the company’s total proved reserves.
 
The scope of the audit consisted of the independent preparation of our own estimates of the proved reserves and the comparison of our proved reserve results to the estimates prepared by the company. When compared on a field-by-field basis, some estimates prepared by Devon Canada are greater than and some are less than those prepared by Deloitte. However, in our opinion, the estimates prepared by Devon Canada are in aggregate reasonable, are within the established audit tolerance of plus or minus 10 percent, and the estimates have been prepared in accordance with generally accepted petroleum engineering practices and procedures. These practices and procedures are detailed within the Canadian Oil and Gas Evaluation Handbook (COGEH), set out by the Society of Petroleum Evaluation Engineers (SPEE), as well as the Society of Petroleum Engineers’ (SPE) Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves. We believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report. For the purpose of this audit, only deterministic methods were used. The proved reserve estimates prepared by both Devon Canada and Deloitte conform to the reserve definitions as set forth in the SEC’s Regulation S-X Part 210.4-10(a) and as clarified in subsequent Commission Staff Accounting Bulletins. We believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report.

Member of Deloitte Touche Tohmatsu Limited

Deloitte was provided with Devon Canada’s base hydrocarbon prices (oil, gas, condensate , and natural gas liquids) as of December 31, 2018 in order to estimate the company’s net after royalty reserves. In accordance with SEC requirements, all prices and costs (capital and operating) were held constant. The effects of derivative instruments designated as price hedges of oil and gas quantities , if any, are not reflected in Deloitte’s individual property evaluations. An oil equivalent conversion factor of 6.0   Mcf per 1.0 barrel oil was used for sales gas.
 
The extent and character of ownership and all factual data supplied by Devon Canada Corporation were accepted as presented. A field inspection and environmental/safety assessment of the properties was not made by Deloitte and the consultant makes no representations and accepts no responsibilities in this regard.
 
It should be understood that our audit does not constitute a complete reserves study of the oil and gas properties of your company. In the conduct of our examinations, we have not independently verified the accuracy and completeness of all the information and data furnished by your company with respect to ownership interests, oil and gas production, historical costs of operations and development, product prices, and agreements relating to current and future operations and sales of production. However, we have specifically identified to you the information and data upon which we relied so that you can subject it to procedures you consider necessary. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any of the information or data, we did not rely on that information or data until we had satisfactorily resolved our questions or independently verified it.
 
The accuracy of any reserve and production estimates is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates adhere to Regulation S-K, 229.1202 and Regulation S-X, 4-10(a) (as applicable), the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. If government regulations change, the net after royalty recoverable reserve volumes may change materially.
 
We are independent with respect to the company as provided in the standards pertaining to the estimating and auditing of oil and gas reserves information included in COGEH and the Association of Professional Engineers and Geoscientists’ of Alberta (APEGA).
 
This audit is for the information of your company and for the information and assistance of its independent public accountants in connection with their review of, and report upon, the financial statements of your company. Supporting data documenting the audit, along with data provided by Devon Canada, are on file in our office. The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Devon Energy Corporation.

Member of Deloitte Touche Tohmatsu Limited

Devon Energy Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Devon Energy Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-X of Devon Energy Corporation to the references to our name as well as to the references to our audit for Devon Energy Corporation, which appears in the December 31, 2018 annual report on Form 10-K of Devon Energy Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.
 
Yours truly,

Original signed by: “Robin G. Bertram”

 
 Robin G. Bertram
 Partner 
 Deloitte LLP
  
 /sp
 
Member of Deloitte Touche Tohmatsu Limited

 

		

Certificate of qualification

 
I, R. G. Bertram, a Professional Engineer, of 700, 850 – 2 Street S.W., Calgary, Alberta, Canada hereby certify that:

1.	I am a Partner of Deloitte LLP, which did prepare an evaluation of certain oil and gas assets of the interests Devon Canada Corporation. The effective date of this evaluation is December 31, 2018.	
2.	I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities Devon Canada Corporation.	
3.	I attended the University of Alberta and graduated with a Bachelor of Science Degree in Petroleum Engineering in 1985; that I am a Registered Professional Engineer in the Province of Alberta; and I have in excess of 33 years of engineering experience.	
4.	I am a Qualified Reserves Auditor as defined in the Canadian Oil and Gas Evaluation Handbook, Section 5.4.3.	
5.	A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities.	

 

 

 
 
Original signed by: “R. G. Bertram”
R. G. Bertram, P. Eng.
 
January 16, 2019
Date

 

 

 

 

 
Audit procedure
Definitions and methodology
Effective as of December 2018

 

 

 

 

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Table of contents
Definitions

•	Reserves audit methodology	
•	Reserve definitions	
 
Resource and reserve estimation
 
Production forecasts
 
Land schedules
 
Geology
 
Royalties and taxes
 
Capital and operating considerations
 
Pricing overview

 
 
© Deloitte LLP and affiliated entities

Definitions
Reserves audit methodology
Deloitte has prepared its report in accordance with SEC Regulation S-K, 229.1202 and Regulation S-X, 210.4-10.
A “Reserves Audit” is the process carried out by a qualified reserves auditor that results in a reasonable assurance, in the form of an opinion, that the reserves information has in all material respects been determined and presented according to the principles and definitions adopted by the Society of Petroleum Evaluation Engineers (“SPEE”) (Calgary Chapter) and Association of Professional Engineers and Geoscientists of Alberta (“APEGA”), and are; therefore, free of material misstatement.
The reserves evaluations prepared by the Corporation have been audited, not for the purpose of verifying exactness, but the reserves information, company policies, procedures, and methods used in estimating the reserves will be examined in sufficient detail so that Deloitte can express an opinion as to whether, in the aggregate, the reserves information presented by the Corporation are reasonable.
Deloitte may require its own independent evaluation of the reserves to test for reasonableness of the Corporation’s evaluations. The tests to be applied to the Corporation’s evaluations insofar as their methods and controls and the properties selected to be re-evaluated will be determined by Deloitte, in its sole judgment, to arrive at an opinion as to the reasonableness of the Corporation’s evaluations.
Reserve definitions and classification
Reserves are classified by Deloitte in accordance with the definitions that are described in the United States Securities and Exchange Commission Regulation S-X Part 210.4-10(a).

 

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Resource and reserve estimation
Deloitte generally assigns reserves to properties via deterministic methods. Probabilistic estimation techniques are typically used where there is a low degree of certainty in the information available and is generally used in resource evaluations and when utilized will be stated within the detailed property reports. Both techniques comply as defined in Regulation S-X, 210.4-10(a).

© Deloitte LLP and affiliated entities

Production forecasts
Production forecasts were based on historical trends or by comparison with other wells in the immediate area producing from similar reservoirs. Non-producing gas reserves were forecast to come on-stream within the first two years from the effective date under direct sales pricing and deliverability assumptions, if a tie-in point to an existing gathering system was in close proximity (approximately two miles). If the tie-in point was of a greater distance (and dependent on the reserve volume and risk), the reserves were forecast to come on-stream in years three or four from the effective date. These on-stream dates were used when the company could not provide specific on-stream date information.
For reserve volumes that meet all reserve category rules but are behind casing and waiting on depletion of the producing zone, these volumes are forecast to be brought on-stream following the end of the existing production.

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Land schedule
The evaluated Corporation provided schedules of land ownership, which included lessor and lessee royalty burdens. The land data was accepted as factual and no investigation of title by Deloitte was made to verify the records.

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Geology
An initial review of each property is undertaken to establish the produced maturity of the reservoir being evaluated. Where extensive production history exists, a geologic analysis is not conducted since the remaining hydrocarbons can be determined by productivity analysis.
For properties that are not of a mature production nature, a geologic review is conducted. This work consists of:

•	Developing a regional understanding of the play,	
•	Assessing reservoir parameters from the nearest analogous production,	
•	Analysis of all relevant well data including logs, cores, and tests to measure net formation thickness (pay), porosity, and initial water saturation,	
•	Auditing of client mapping or developing maps to meet Deloitte’s need to establish volumetric hydrocarbons-in-place.	

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Royalties and taxes
General
All royalties and taxes, including the lessor and overriding royalties, are based on government regulations, negotiated leases or farmout agreements that were in effect as of the evaluation effective date. If regulations change, the net after royalty recoverable reserve volumes may differ materially.
Deloitte utilizes a variety of reserves and valuation products in determining the result sets.

© Deloitte LLP and affiliated entities

Capital and operating considerations
Reserves estimated to meet the standards for constant prices and costs, are based on Regulation S-X 210.4-10(a).
Capital costs were provided by the Corporation and reviewed by Deloitte for reasonableness.
Operating costs were determined from historical data on the property as provided by the evaluated Corporation.

 

© Deloitte LLP and affiliated entities

Pricing overview
Devon provided Deloitte with hydrocarbon prices (oil, gas condensate, and natural gas liquids) appropriate for use in the preparation of a reserves report to be filed with the SEC with an effective date of December 31, 2016. These prices were calculated in accordance with the definition (22)(v) of Regulation S-X, 210.4-10(a) and were determined by taking the un-weighted average of the prices on the first day of the month for the preceding 12 months (January 1, 2018 through to December 1, 2018).
The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in Deloitte’s individual property evaluations.

 	Benchmark	Benchmark price
($US)	Weighted average realized report price ($US)	
Oil	NYMEX WTI @ Cushing	$65.56/bbl	$29.60/bbl	
Bitumen	Edmonton AWB	$35.52/bbl	$22.12/bbl	
Gas	NYMEX Henry Hub	$3.10/mcf	$0.87/mcf	

 

 

 

 

 

 

 
 
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