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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, 2017
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   ☒     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, 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 30, 2017 was approximately $16.7 billion, based upon the closing price of $31.97 per share as reported by the New York Stock Exchange on such date. On February 7, 2018, 526.1 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s definitive Proxy Statement relating to Registrant’s 2018 annual meeting of stockholders have been incorporated by reference in Part III of this Annual Report on Form 10-K.

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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	 	16	
Item 1B.  Unresolved Staff Comments	 	23	
Item 3.     Legal Proceedings	 	23	
Item 4.     Mine Safety Disclosures	 	23	
 	 	 	
PART II	 	24	
 	 	 	
Item 5.     Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	 	24	
Item 6.     Selected Financial Data	 	26	
Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	27	
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	 	116	
Item 9A.  Controls and Procedures	 	116	
Item 9B.  Other Information	 	116	
 	 	 	
PART III	 	117	
 	 	 	
Item 10.   Directors, Executive Officers and Corporate Governance	 	117	
Item 11.   Executive Compensation	 	117	
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	117	
Item 13.   Certain Relationships and Related Transactions, and Director Independence	 	117	
Item 14.   Principal Accountant Fees and Services	 	117	
 	 	 	
PART IV	 	118	
 	 	 	
Item 15.   Exhibits and Financial Statement Schedules	 	118	
Item 16.   Form 10-K Summary	 	125	
Signatures	 	126	
 
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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, as amended and restated.
“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.
“ASC” means Accounting Standards Codification.
“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.
“EMH” means EnLink Midstream Holdings, LP.
“EnLink” means EnLink Midstream Partners, L.P., 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.
“GeoSouthern” means GeoSouthern Energy Corporation.
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
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“MLP” means master limited partnership.
“MMBbls” means million barrels.
“MMBoe” means million Boe.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“M&M operations” means marketing and midstream revenues minus marketing and midstream expenses.
“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.
“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.
“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.
“S&P 500 Index” means Standard and Poor’s 500 index.
“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.
“VEX” means Victoria Express Pipeline and related truck terminal and storage assets.
“WTI” means West Texas Intermediate.
“/d” means per day.
“/gal” means per gallon.

 

 

 

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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 “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2017 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to:
 	•	the volatility of oil, gas and NGL prices;	
 	•	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 oil and gas operations;	
 	•	regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;	
 	•	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 leases, 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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 PAR T 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. Additionally, we control EnLink, a publicly traded MLP with an integrated midstream business with significant size and scale in key operating regions in the U.S. For additional information regarding our control of, and ownership interest in, EnLink and its indirect general partner, the General Partner, see Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2017, Devon and its consolidated subsidiaries had approximately 4,900 employees, of which approximately 1,500 employees are employed by EnLink (through its subsidiaries).
Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports, with the SEC. Through our website, 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 .
Devon Strategy
Devon is committed to delivering consistent top-quartile shareholder return among its peer group through a highly engaged culture focused on innovation, safety, operational excellence, environmental stewardship and social responsibility. We also maintain a strong commitment to financial strength and flexibility through all commodity price cycles, as reflected in the company’s investment grade credit ratings.
Devon’s “2020 Vision” is our plan through the end of the decade intended to optimize returns and deliver top-tier capital-efficient, cash-flow growth. Our 2020 Vision is focused on the following strategic priorities:
 	•	Maximize cash flow by optimizing base production and reducing per-unit cash costs;	
 	•	Improve capital efficiency with a concentration of investment on highest-returning development projects in the Delaware Basin and STACK;	
 	•	Simplify our portfolio by monetizing non-core assets;	
 	•	Improve financial strength by reducing debt; and	
 	•	Return cash to shareholders.	
Our portfolio of exploration and production assets and operations provides stable, environmentally responsible production and a platform for future growth. In 2017, we continued the development of our world-class operations in the STACK and Delaware Basin. These assets provide us with a sustainable, multi-decade growth platform that continues to improve with our successful drilling programs. During 2017, we delivered the best well productivity in Devon’s 46-year history and continued a five-year streak of increasing Devon’s initial 90-day production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity and improving the performance of our established wells. Devon has more than doubled its onshore North American oil production since 2012 and has a deep inventory of development opportunities to deliver future oil growth.
 As we enter 2018 and look toward the future, we expect to achieve additional efficiencies across our portfolio. We expect to fund activity within our cash flow, and remain committed to allocating capital in a disciplined manner to maximize value and return.
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We believe we capture the full value of our assets and improve returns through maximizing our base production and optimizing our capital program. The activities that support this strategy include minimizing controllable downtime, enhancing well productivity, ensuring disciplined project execution, performing premier technical work, focusing on developmental drilling and reducing our operating and capital costs.
We also continue to implement new shareholder-friendly initiatives, which include new returns-based metrics aligned to employee compensation and the conversion to successful efforts accounting which provides greater transparency into our financial performance.
EnLink Strategy
EnLink focuses on providing gathering, transmission, processing, storage, fractionation and marketing to upstream oil and natural gas producers, including Devon.  
EnLink connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. Furthermore, EnLink purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines.
EnLink’s primary business objective is to provide stable cash flow, while growing through prudent and profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintaining a strong financial position through a conservative and balanced capital structure highlighted by its investment grade status. EnLink has consistently demonstrated expertise within the MLP space and continues to employ a proven business model that includes growing, expanding and executing on its strategy within top basins where Devon and other successful upstream producers operate.  
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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, 2017 are detailed in the map below. Notes 23 and  24 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.

Led by results from our franchise assets, STACK and Delaware Basin, Devon achieved the best drilling results in our 46-year history. Our initial 90-day production rates in 2017 increased more than 400% from 2012 levels. These productivity improvements were driven by activity focused in top resource plays, improved subsurface reservoir characterization, leading-edge completion designs and improvements in lateral placement. The most significant reserves growth came from our U.S. operations, where we replaced approximately 150% of our 2017 production with proved reserves additions from the drill bit.
 Delaware Basin – The Delaware Basin is one of Devon’s top-two franchise assets and continues to offer exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, Delaware, Wolfcamp and Leonard formations. We expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin to
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deliver high-margin growth for many years to come. During 2017, our continued appraisal and development work enabled us to increase our proved reserves by approximately 60%. At December 31, 2017, we had eight operated rigs developing this asset. In 2018, we plan to invest approximately $725 million of capital in the Delaware Basin as we shift to expanded development operations, primarily focused on the Bone Spring formation.
STACK  – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top-two franchise assets. Devon is currently targeting the Woodford Shale and the Meramec zones. Our STACK position is one of the largest and best in the industry, providing visible long-term growth. Completion design enhancements have resulted in greater productivity and improved economics. Drilling activity in the Meramec has produced record setting initial production across our core position in the oil and liquids window. At December 31, 2017, we had nine operated rigs with drilling focused in the Meramec formation. In 2018, we plan approximately $700 million of capital investment and expect to accelerate full-field development activity.
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 20 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, 2017. With our 50% partner, we continue to evaluate our development timeline for Pike. 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, high margin oil development play that produces heavy oil by conventional means, without the need for steam injection.
In 2018, we plan approximately $275 million of capital investment in our Canadian Heavy Oil business.
Eagle Ford – We acquired our position in the Eagle Ford in 2014, with acres located in DeWitt and Lavaca counties in south Texas. In 2017, we closed on the sale of our Lavaca assets for approximately $200 million. Since acquiring these assets, we have delivered tremendous results by producing 119 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. With the highest margins in our portfolio, our Eagle Ford assets generated significant cash flow in 2017. In 2018, we plan approximately $250 million of capital investment.
Rockies Oil – Our acreage in the Rockies is focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. Recent drilling success in these formations has expanded our drilling inventory, and we expect further growth as we continue to de-risk this emerging light-oil opportunity. As of December 31, 2017, we had one operated rig targeting the Turner formation in northern Converse County of the Powder River Basin. In 2018, we plan approximately $150 million of capital investment.
Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. The Johnson County assets are currently being marketed as part of our non-core divestiture program. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this asset into one of the top producing gas fields in North America. Given the sustained low gas price environment, we continue to focus on enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2018, we plan on minimal development activity, with planned capital investment of up to $50 million to optimize base production and further de-risk future development resources.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 24 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,
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operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group, (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators, 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 approximately 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 17 years, including the past 10 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 2017, we engaged two such firms to audit approximately 88% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited approximately 85% of our 2017 U.S. reserves, and Deloitte LLP audited approximately 99% 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.
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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)	 	
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	 	
2015	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Barnett Shale	 	 	—	 	 	 	—	 	 	 	291	 	 	 	17	 	 	 	66	 	
STACK	 	 	3	 	 	 	—	 	 	 	86	 	 	 	8	 	 	 	25	 	
Jackfish	 	 	—	 	 	 	31	 	 	 	—	 	 	 	—	 	 	 	31	 	
U.S.	 	 	60	 	 	 	—	 	 	 	579	 	 	 	50	 	 	 	206	 	
Canada	 	 	10	 	 	 	31	 	 	 	8	 	 	 	—	 	 	 	42	 	
Total North America	 	 	70	 	 	 	31	 	 	 	587	 	 	 	50	 	 	 	248	 	
 
 	 	Average Sales Price	 	 	 	 	 	
Year Ended December 31,	 	Oil (Per Bbl)	 	 	Bitumen (Per Bbl)	 	 	Gas (Per Mcf)	 	 	NGLs (Per Bbl)	 	 	Production Cost (Per Boe) (1)	 	
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	 	
2015	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Barnett Shale	 	$	46.47	 	 	$	—	 	 	$	2.00	 	 	$	9.62	 	 	$	5.96	 	
STACK	 	$	43.73	 	 	$	—	 	 	$	2.22	 	 	$	8.97	 	 	$	5.39	 	
Jackfish	 	$	—	 	 	$	23.41	 	 	$	—	 	 	$	—	 	 	$	12.43	 	
U.S.	 	$	44.01	 	 	$	—	 	 	$	2.14	 	 	$	9.32	 	 	$	7.52	 	
Canada	 	$	30.58	 	 	$	23.41	 	 	N/M	 	 	$	—	 	 	$	13.18	 	
Total North America	 	$	42.12	 	 	$	23.41	 	 	$	2.14	 	 	$	9.32	 	 	$	8.48	 	

(1)	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.	
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Index to Financial Statements
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	 	
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	 	
2015	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	298.6	 	 	 	1.8	 	 	 	40.7	 	 	 	—	 	 	 	339.3	 	 	 	1.8	 	 	 	341.1	 	
Canada	 	 	79.0	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	79.0	 	 	 	—	 	 	 	79.0	 	
Total North America	 	 	377.6	 	 	 	1.8	 	 	 	40.7	 	 	 	—	 	 	 	418.3	 	 	 	1.8	 	 	 	420.1	 	

(1)	Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests.	
The following table presents the wells that were in progress on December 31, 2017. As of February 1, 2018, these wells were still in progress.
 
 	 	Gross (1)	 	 	Net (2)	 	
U.S.	 	 	26.0	 	 	 	10.1	 	
Canada	 	 	5.0	 	 	 	5.0	 	
Total North America	 	 	31.0	 	 	 	15.1	 	

(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, 2017.

 	 	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.	 	 	9,165	 	 	 	3,379	 	 	 	10,103	 	 	 	7,245	 	 	 	19,268	 	 	 	10,624	 	
Canada	 	 	3,195	 	 	 	3,085	 	 	 	590	 	 	 	413	 	 	 	3,785	 	 	 	3,498	 	
Total North America	 	 	12,360	 	 	 	6,464	 	 	 	10,693	 	 	 	7,658	 	 	 	23,053	 	 	 	14,122	 	

(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 821 and 367 gross oil and gas wells, respectively, which had multiple completions.	
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Index to Financial Statements
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 14,600 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, 2017. Of our 4.3 million net acres, approximately 2.3 million acres are held by production. The acreage in the table includes 0.1 million, 0.2 million and 0.1 million net acres subject to leases that are scheduled to expire during 2018, 2019 and 2020, respectively. As of December 31, 2017, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.4 million net acres set to expire by December 31, 2020, 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 2017, we allowed approximately 0.2 million acres to expire.

 	 	Developed	 	 	Undeveloped	 	 	Total	 	
 	 	Gross (1)	 	 	Net (2)	 	 	Gross (1)	 	 	Net (2)	 	 	Gross (1)	 	 	Net (2)	 	
 	 	(Thousands)	 	
U.S.	 	 	1,808	 	 	 	1,203	 	 	 	3,587	 	 	 	1,598	 	 	 	5,395	 	 	 	2,801	 	
Canada	 	 	685	 	 	 	504	 	 	 	2,091	 	 	 	968	 	 	 	2,776	 	 	 	1,472	 	
Total North America	 	 	2,493	 	 	 	1,707	 	 	 	5,678	 	 	 	2,566	 	 	 	8,171	 	 	 	4,273	 	

(1)	Gross acres are the sum of all acres in which we own a working interest.	
(2)	Net acres are gross acres multiplied by our fractional working interests in the acreage.	
Title to Properties
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry, 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 counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
EnLink Midstream Properties
EnLink represents the primary component of our midstream operations. EnLink’s assets are comprised of systems and other assets located in four primary regions:
 	•	Texas – The Texas assets consist of natural gas gathering, processing and transmission operations in north Texas and the Midland and Delaware Basins in west Texas.	
 	•	Oklahoma – The Oklahoma assets consist of natural gas gathering, processing and transmission activities in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK and Central Northern Oklahoma Woodford shale areas.	
 	•	Louisiana – The Louisiana assets consist of natural gas pipelines, natural gas processing plants, gas and NGL storage facilities, fractionation facilities and NGL pipelines located in Louisiana.	
 	•	Crude and Condensate – The Crude and Condensate assets consist of Ohio River Valley crude oil, condensate, condensate stabilization, natural gas compression and brine disposal activities in the Utica and Marcellus Shales, crude oil operations in the Permian Basin and central Oklahoma, and crude oil activities associated with VEX located in the Eagle Ford Shale.	
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Index to Financial Statements
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 4 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2018, our production was sold under the following contract terms.

 	 	Short-Term	 	 	Long-Term	 	
 	 	Variable	 	 	Fixed	 	 	Variable	 	 	Fixed	 	
Oil and bitumen	 	 	80	%	 	 	—	 	 	 	20	%	 	 	—	 	
Natural gas	 	 	52	%	 	 	4	%	 	 	44	%	 	 	—	 	
NGLs	 	 	33	%	 	 	20	%	 	 	47	%	 	 	—	 	
 
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, 2017, 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)	 	 	86	 	 	 	31	 	 	 	49	 	 	 	6	 	
Natural gas (Bcf)	 	 	293	 	 	 	265	 	 	 	28	 	 	 	—	 	
NGLs (MMBbls)	 	 	11	 	 	 	11	 	 	 	—	 	 	 	—	 	
Total (MMBoe)	 	 	146	 	 	 	86	 	 	 	54	 	 	 	6	 	
 
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 2017, 2016 and 2015, no purchaser accounted for over 10% of our consolidated sales revenue.
Competition
See “Item 1A. Risk Factors.”
Public Policy and Government Regulation
Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting our industry have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. The following are significant areas of government control and regulation affecting our operations.
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Index to Financial Statements
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 integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, 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 been particularly active in recent years in evaluating and, in some cases, promulgating 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 are subject to frequent 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 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.
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Index to Financial Statements
Environmental, Pipeline Safety and Occupational Regulations
We are subject to many federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment 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. We consider the costs of environmental protection and safety and health compliance necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and 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.
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, in recent 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:
 	•	supply of and demand for oil, gas and NGLs, including consumer demand in emerging markets, such as China and India;	
 	•	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;	
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Index to Financial Statements
 	•	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; and	
 	•	governmental regulations and taxes.	
Commodity prices began to decline in the second half of 2014 and, despite a moderate recovery, have generally been pressured since then. This commodity price decline adversely affected our business and results of operations and led to substantial impairments to our oil and gas properties during 2015. A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:
 	•	reducing the amount of oil, gas and NGLs that we can produce economically;	
 	•	limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;	
 	•	reducing our revenues, operating cash flows and profitability;	
 	•	causing us to decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production of oil, gas and NGLs; and	
 	•	reducing the carrying value of our properties, resulting in additional noncash write-downs.	
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.
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.
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Index to Financial Statements
Oil and Gas 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.
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 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. 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 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. 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, income taxes and climate change, as discussed below.
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Index to Financial Statements
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 and/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 and/or hydraulic fracturing or are considering doing so. Although it is not possible at this time to predict the final outcome of these proposals, any new federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays in development or restrictions on our operations.
Pipeline Safety – The pipeline assets in which we own interests, through EnLink or otherwise, 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. 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 quarter of 2018. 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.
 
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. Recently enacted legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Legislation”) significantly affects U.S. tax law by changing how the U.S. imposes income tax on multinational corporations. These changes include, among others, a permanent reduction to the corporate income tax offset by other items intended to broaden the tax base (for example, by imposing significant additional limitations on the deductibility of interest expense and limiting the ability to deduct net operating losses).
 
The U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may significantly impact how we will apply the law and impact our results of operations in the period issued. Further, compliance with the Tax Reform Legislation and the accounting for such provisions require complex computations and accumulation of information not previously required or regularly produced. As a result, we have provided a provisional estimate in our financial statements of the effect of the Tax Reform Legislation. As additional regulatory guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which will be recorded in the period completed, may be different from our current provisional amounts, which could materially affect our tax obligations and effective tax rate.
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Climate Change – Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives 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 through inventories, limitations and/or taxes on greenhouse gas emissions. 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; however, following the change in presidential administrations, both agencies have published proposed rules that seek to delay implementation of their previously issued methane standards while the agencies review and reconsider both rules. Nevertheless, several states where we operate, including Wyoming, have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from the use of our products by our customers.
In Canada, greenhouse gas emissions are also being addressed at both the federal and provincial level. Recent climate policies include a legislated oil sands emission limit, and forthcoming policies include methane emissions reduction targets. Beginning January 1, 2018, large industrial emitters are subject to the Carbon Competitiveness Incentive Regulation (CCIR). This regulation 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 regulations is expected to be minimal in the near term. Oil and gas facilities that are not subject to the CCIR are exempt from the economy-wide carbon levy until 2023.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which 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 hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts. 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 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.
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Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us
As of December 31, 2017, we had total consolidated indebtedness of $10.4 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:
 	•	requiring us to dedicate a significant portion of our cash flows from operations to debt service payments, thereby limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other general corporate purposes;	
 	•	increasing our vulnerability to general adverse economic and industry conditions, including low commodity price environments; and	
 	•	limiting our ability to obtain additional financing due to higher costs and more restrictive covenants.	
In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that may impact our credit ratings include, among others, debt levels, planned 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 other assets, 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.
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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. Such midstream systems include EnLink’s systems, as well as other systems operated by us or third parties. Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time 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, we and third parties may be subject to constraints that limit our or their ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.
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, production, processing and transportation 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, insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk and war. Our insurance does not cover penalties or fines assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our profitability, financial condition and liquidity.
Competition for Assets, Materials, People and Capital Can Be Significant
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield services, which could adversely affect our ability to execute our development plans on a timely basis and within budget. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our competitors have financial and other resources substantially greater than ours. They also may have established strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for assets or services and accessing capital. 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.
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 as a result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets and potential post-closing claims for indemnification. Moreover, 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.
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Item 1B.  Unresolv ed 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 Gas Services, 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. On February 7, 2018, there were 7,466 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 from time to time, and will depend on Devon’s financial condition and other relevant factors. The following table sets forth the quarterly high and low prices for our common stock during 2017 and 2016, as well as the quarterly dividends per share.

 	 	Price Range of Common Stock	 	 	Dividends	 	
 	 	High	 	 	Low	 	 	Per Share	 	
Quarter Ended 2017:	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2017	 	$	42.60	 	 	$	33.98	 	 	$	0.06	 	
September 30, 2017	 	$	37.44	 	 	$	28.80	 	 	$	0.06	 	
June 30, 2017	 	$	43.50	 	 	$	29.89	 	 	$	0.06	 	
March 31, 2017	 	$	49.45	 	 	$	38.02	 	 	$	0.06	 	
Quarter Ended 2016:	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2016	 	$	50.66	 	 	$	36.64	 	 	$	0.06	 	
September 30, 2016	 	$	45.62	 	 	$	35.01	 	 	$	0.06	 	
June 30, 2016	 	$	39.47	 	 	$	25.55	 	 	$	0.06	 	
March 31, 2016	 	$	32.93	 	 	$	18.07	 	 	$	0.24	 	
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Performance Graph
The following graph compares the cumulative TSR over a five-year period on Devon’s common stock with the cumulative total returns of the S&P 500 Index 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, 2012 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.
Issuer Purchases of Equity Securities
The following table details purchases of our common stock that were made by us during the fourth quarter of 2017. During 2017, we did not repurchase any shares that were a part of a publicly announced program.
 
Period	 	Total Number of
Shares Purchased  (1)	 	 	Average Price Paid
per Share	 	
October 1 - October 31	 	 	9,768	 	 	$	35.27	 	
November 1 - November 30	 	 	29,160	 	 	$	38.68	 	
December 1 - December 31	 	 	2,321	 	 	$	39.06	 	
Total	 	 	41,249	 	 	$	37.89	 	

(1)	Share repurchases represent shares received by us from employees for the payment of personal income tax withholding on share-based compensation vesting.	
 Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 46,000 shares of our common
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stock in 2017, 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. Eligible employees purchased approximately 6,200 shares of our common stock in 2017. 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.
 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.
 
 	 	2017	 	 	2016*	 	 	2015*	 	 	2014*	 	 	2013*	 	
Statement of Earnings data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream revenues	 	$	5,307	 	 	$	3,981	 	 	$	5,885	 	 	$	11,619	 	 	$	7,296	 	
Total revenues	 	$	13,949	 	 	$	10,304	 	 	$	13,145	 	 	$	19,285	 	 	$	9,362	 	
Earnings (loss) from continuing operations (1)	 	$	1,078	 	 	$	(1,458	)	 	$	(13,645	)	 	$	(753	)	 	$	(938	)	
Earnings (loss) from continuing operations
   attributable to Devon (1)	 	$	898	 	 	$	(1,056	)	 	$	(12,896	)	 	$	(837	)	 	$	(938	)	
Earnings (loss) from continuing operations per share
   attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic (1)	 	$	1.71	 	 	$	(2.09	)	 	$	(31.72	)	 	$	(2.08	)	 	$	(2.34	)	
Diluted (1)	 	$	1.70	 	 	$	(2.09	)	 	$	(31.72	)	 	$	(2.08	)	 	$	(2.34	)	
Cash dividends per common share	 	$	0.24	 	 	$	0.42	 	 	$	0.96	 	 	$	0.94	 	 	$	0.86	 	
Balance Sheet data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets (1)	 	$	30,241	 	 	$	28,675	 	 	$	29,673	 	 	$	49,253	 	 	$	44,390	 	
Long-term debt (2)	 	$	10,291	 	 	$	10,154	 	 	$	12,056	 	 	$	9,761	 	 	$	7,888	 	
Stockholders' equity	 	$	14,104	 	 	$	12,722	 	 	$	11,111	 	 	$	24,789	 	 	$	20,729	 	
Common shares outstanding	 	 	525	 	 	 	523	 	 	 	418	 	 	 	409	 	 	 	406	 	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
(1)	Material asset impairments and acquisition and divestiture activity have had significant impacts on operating results and the carrying value of our oil and gas assets. 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 3 and  Note 6 of “Item 8. Financial Statements and Supplementary Data” of this report.  	
(2)	Debt balances at December 31, 2017, 2016, 2015 and 2014 include $3.5 billion, $3.3 billion, $3.1 billion and $2.0 billion, respectively, of EnLink and the General Partner debt that is non-recourse to Devon.	
 
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Item 7.  Management’s Discussion and Analy sis 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 2017 Results
During 2017, we generated solid operating results with our strategy of operating in North America’s best resource plays, delivering superior execution, continuing disciplined capital allocation and maintaining a high degree of financial strength. Led by our development in the STACK and Delaware Basin, we continued to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells.
Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in Devon’s earnings and cash flow during 2017. We exited 2017 with liquidity comprised of $2.7 billion of cash and $2.9 billion of available credit under our Senior Credit Facility. We have no significant debt maturities until 2021.
We further enhanced our financial strength by completing approximately $415 million of our announced $1 billion asset divestiture program in 2017. We anticipate closing the remaining divestitures in 2018.
In 2018 and beyond, we have the financial capacity to further accelerate investment across our best-in-class U.S. resource plays. We are increasing drilling activity and will continue to shift our production mix to high-margin products. We will continue our premier technical work to drive capital allocation and efficiency and industry-leading well productivity results. We will continue to maximize the value of our base production by sustaining the operational efficiencies we have achieved. Finally, we will continue to manage activity levels within our cash flows. We expect this disciplined approach will position us to deliver capital-efficient, cash-flow expansion over the next two years.
Key measures of our financial performance in 2017 are summarized in the following table. Increased commodity prices as well as continued focus on our production expenses improved our 2017 financial performance as compared to 2016, as seen in the table below. More details for these metrics are found within the “Results of Operations – 2017 vs. 2016”, below.
 
 	 	2017	 	 	Change	 	 	2016*	 	 	Change	 	 	2015*	 	
Net earnings (loss) attributable to Devon	 	$	898	 	 	 	+185	%	 	$	(1,056	)	 	 	+92	%	 	$	(12,896	)	
Net earnings (loss) per diluted share attributable to Devon	 	$	1.70	 	 	 	+181	%	 	$	(2.09	)	 	 	+93	%	 	$	(31.72	)	
Core earnings (loss) attributable to Devon  (1)	 	$	427	 	 	 	+217	%	 	$	(367	)	 	 	- 430	%	 	$	111	 	
Core earnings (loss) per diluted share attributable to Devon (1)	 	$	0.81	 	 	 	+210	%	 	$	(0.73	)	 	 	- 382	%	 	$	0.26	 	
Retained production (MBoe/d)	 	 	541	 	 	 	- 4	%	 	 	563	 	 	 	- 3	%	 	 	580	 	
Total production (MBoe/d)	 	 	543	 	 	 	- 11	%	 	 	611	 	 	 	- 10	%	 	 	680	 	
Realized price per Boe (2)	 	$	25.96	 	 	 	+39	%	 	$	18.72	 	 	 	- 14	%	 	$	21.68	 	
Operating cash flow	 	$	2,909	 	 	 	+94	%	 	$	1,500	 	 	 	- 69	%	 	$	4,898	 	
Capitalized expenditures, including acquisitions	 	$	2,937	 	 	 	- 25	%	 	$	3,908	 	 	 	- 32	%	 	$	5,712	 	
Shareholder and noncontrolling interests distributions	 	$	481	 	 	 	- 8	%	 	$	525	 	 	 	- 19	%	 	$	650	 	
Cash and cash equivalents	 	$	2,673	 	 	 	+36	%	 	$	1,959	 	 	 	- 15	%	 	$	2,310	 	
Total debt	 	$	10,406	 	 	 	+2	%	 	$	10,154	 	 	 	- 22	%	 	$	13,032	 	
Reserves (MMBoe)	 	 	2,152	 	 	 	+5	%	 	 	2,058	 	 	 	- 6	%	 	 	2,182	 	
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*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
(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
Devon marked its 46th anniversary in the oil and gas business and its 29th year as a public company during 2017. As an established company with a strong leadership team, we have experience operating in periods of challenged commodity prices. With our focused strategy and portfolio of quality assets, we are focused on navigating the current environment while ensuring our long-term financial strength.
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. During 2017, WTI oil prices ranged from approximately $42.00/Bbl to $60.00/Bbl, supported by increasing global demand and historically high OPEC compliance with its oil production cuts that were put in place in 2016 for the first half of 2017. Following the decision by both OPEC and non-OPEC producers to extend the agreement to reduce output by nearly 1.8 million barrels per day through the end of 2018, oil prices increased approximately 15% in the fourth quarter of 2017, averaging $55.49/Bbl. Current market fundamentals indicate improved prices for crude oil in 2018; however, changes in OPEC production strategies, the macro-economic environment, geopolitical risks or other factors could impact current forecasts. As such, we anticipate continued volatility into 2018 and we continue to execute on our hedging strategy to mitigate such volatility.
Leveraging the success of our 2017 results, we have a solid financial condition and anticipate expanding our oil and gas investment by approximately 10% in 2018, while drilling and completing approximately 25% more wells. Our 2018 outlook is focused on our high returning assets in the STACK and Delaware Basin and achieving top-line oil-equivalent production growth of 6%-9%, on a retained asset basis, through some of our best-in-class positions. Additionally, we continued to execute our hedging program in 2017 and now have approximately 40% of our oil and 50% of our gas production hedged for 2018. With our anticipated results and hedging program, we intend to fully fund our increased activity with our operating cash flow. Additionally, we are targeting reducing our debt by approximately $1 billion.
Finally, EnLink continues to be a strategic advantage for us. With annual distributions to us of approximately $270 million, EnLink provides a visible cash flow stream to be further invested in our upstream capital programs.

 

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Index to Financial Statements
Results of Operations – 2017 vs. 2016
 
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 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. Additional information regarding noncontrolling interests is discussed in Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.

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

*	Prior year amounts, including amounts in the following tables, have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report. 	
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Index to Financial Statements

 

Upstream Operations	
 
Oil, Gas and NGL Production
 
 	 	2017	 	 	% of Total	 	 	2016	 	 	Change	 	
Oil and bitumen (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	26	 	 	 	11	%	 	 	19	 	 	 	+38	%	
Delaware Basin	 	 	31	 	 	 	13	%	 	 	33	 	 	 	- 7	%	
Rockies Oil	 	 	14	 	 	 	6	%	 	 	14	 	 	 	+1	%	
Heavy Oil	 	 	18	 	 	 	7	%	 	 	22	 	 	 	- 19	%	
Eagle Ford	 	 	34	 	 	 	14	%	 	 	39	 	 	 	- 14	%	
Barnett Shale	 	 	1	 	 	 	1	%	 	 	1	 	 	 	- 25	%	
Other	 	 	8	 	 	 	2	%	 	 	11	 	 	 	- 28	%	
Retained assets	 	 	132	 	 	 	54	%	 	 	139	 	 	 	- 4	%	
Divested assets	 	 	2	 	 	 	1	%	 	 	12	 	 	 	- 87	%	
Total Oil	 	 	134	 	 	 	55	%	 	 	151	 	 	 	- 11	%	
Bitumen	 	 	110	 	 	 	45	%	 	 	109	 	 	 	+1	%	
Total Oil and bitumen	 	 	244	 	 	 	 	 	 	 	260	 	 	 	- 6	%	
 
 	 	2017	 	 	% of Total	 	 	2016	 	 	Change	 	
Gas (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	304	 	 	 	25	%	 	 	293	 	 	 	+4	%	
Delaware Basin	 	 	90	 	 	 	7	%	 	 	90	 	 	 	+1	%	
Rockies Oil	 	 	15	 	 	 	1	%	 	 	25	 	 	 	- 39	%	
Heavy Oil	 	 	17	 	 	 	2	%	 	 	20	 	 	 	- 14	%	
Eagle Ford	 	 	95	 	 	 	8	%	 	 	101	 	 	 	- 6	%	
Barnett Shale	 	 	667	 	 	 	55	%	 	 	741	 	 	 	- 10	%	
Other	 	 	11	 	 	 	1	%	 	 	13	 	 	 	- 16	%	
Retained assets	 	 	1,199	 	 	 	99	%	 	 	1,283	 	 	 	- 7	%	
Divested assets	 	 	4	 	 	 	1	%	 	 	130	 	 	 	- 97	%	
Total	 	 	1,203	 	 	 	 	 	 	 	1,413	 	 	 	- 15	%	
 
 	 	2017	 	 	% of Total	 	 	2016	 	 	Change	 	
NGLs (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	31	 	 	 	31	%	 	 	26	 	 	 	+18	%	
Delaware Basin	 	 	11	 	 	 	11	%	 	 	12	 	 	 	- 9	%	
Rockies Oil	 	 	1	 	 	 	1	%	 	 	1	 	 	 	+2	%	
Eagle Ford	 	 	13	 	 	 	13	%	 	 	16	 	 	 	- 19	%	
Barnett Shale	 	 	41	 	 	 	42	%	 	 	45	 	 	 	- 8	%	
Other	 	 	2	 	 	 	2	%	 	 	2	 	 	 	+39	%	
Retained assets	 	 	99	 	 	 	100	%	 	 	102	 	 	 	- 2	%	
Divested assets	 	 	—	 	 	 	—	 	 	 	14	 	 	 	- 100	%	
Total	 	 	99	 	 	 	 	 	 	 	116	 	 	 	- 15	%	
  
 	 	2017	 	 	% of Total	 	 	2016	 	 	Change	 	
Combined (MBoe/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	107	 	 	 	20	%	 	 	93	 	 	 	+15	%	
Delaware Basin	 	 	56	 	 	 	10	%	 	 	60	 	 	 	- 6	%	
Rockies Oil	 	 	17	 	 	 	3	%	 	 	19	 	 	 	- 8	%	
Heavy Oil	 	 	131	 	 	 	24	%	 	 	134	 	 	 	- 2	%	
Eagle Ford	 	 	62	 	 	 	11	%	 	 	72	 	 	 	- 13	%	
Barnett Shale	 	 	153	 	 	 	28	%	 	 	169	 	 	 	- 10	%	
Other	 	 	15	 	 	 	3	%	 	 	16	 	 	 	- 5	%	
Retained assets	 	 	541	 	 	 	99	%	 	 	563	 	 	 	- 4	%	
Divested assets	 	 	2	 	 	 	1	%	 	 	48	 	 	 	- 96	%	
Total	 	 	543	 	 	 	 	 	 	 	611	 	 	 	- 11	%	
 
Production declines reduced our upstream revenues by $427 million primarily as a result of our U.S. non-core divestitures that occurred throughout 2016 and 2017. 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 our NGL barrel.	

 
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Index to Financial Statements

  
 	 	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	%	
 
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 were 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.
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 will change from a net to a gross presentation. We estimate the change to increase our upstream revenues and production expenses by approximately $250 million annually with no impact to net earnings.
Commodity Derivatives
 
 	 	2017	 	 	2016	 	 	Change	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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	%	
 
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 4 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
 
 	 	2017	 	 	2016	 	 	Change	 	
LOE	 	$	927	 	 	$	1,027	 	 	 	- 10	%	
Gathering & transportation	 	 	647	 	 	 	555	 	 	 	+17	%	
Production taxes	 	 	194	 	 	 	147	 	 	 	+32	%	
Property taxes	 	 	55	 	 	 	74	 	 	 	- 26	%	
Total	 	$	1,823	 	 	$	1,803	 	 	 	+1	%	
Per Boe:	 	 	 	 	 	 	 	 	 	 	 	 	
LOE	 	$	4.67	 	 	$	4.59	 	 	 	+2	%	
Gathering & 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 non-core U.S. property divestitures in 2016. Continued well optimization and cost reduction initiatives across our portfolio have 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. non-core divestitures.
 
Marketing & Midstream Operations	
 
 	 	2017	 	 	2016	 	 	Change	 	
Operating revenues	 	$	5,740	 	 	$	4,252	 	 	 	+35	%	
Product purchases	 	 	(4,362	)	 	 	(3,015	)	 	 	+45	%	
Operations and maintenance expenses	 	 	(418	)	 	 	(398	)	 	 	+5	%	
EnLink margin	 	 	960	 	 	 	839	 	 	 	+14	%	
Devon margin	 	 	(48	)	 	 	(49	)	 	 	- 2	%	
Total	 	$	912	 	 	$	790	 	 	 	+15	%	
 
The overall increase in marketing and midstream operating margin was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities. Devon’s margins continue to be negatively impacted by downstream marketing commitments. We are actively engaged in optimization activities to reduce the costs of downstream commitments; however, we expect such commitments will continue to negatively impact our margin in 2018. As further discussed in Note 1 in “Item 8. Financials Statements and Supplementary Data” of this report, in 2018 EnLink’s marketing and midstream revenues are estimated to decrease by 6-10% with a corresponding decrease to marketing and midstream expenses as a result of complying with the new revenue recognition accounting standard.
 
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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	%	
Midstream and other assets	 	 	110	 	 	 	146	 	 	 	- 25	%	
Devon	 	 	1,529	 	 	 	1,592	 	 	 	- 4	%	
EnLink	 	 	545	 	 	 	504	 	 	 	+8	%	
Total	 	$	2,074	 	 	$	2,096	 	 	 	- 1	%	
 
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 midstream and other assets decreased due to the divestiture of the Access Pipeline in the fourth quarter of 2016.
 
General and Administrative Expenses	
 
 	 	2017	 	 	2016	 	 	Change	 	
Labor and benefits	 	$	589	 	 	$	614	 	 	 	- 4	%	
Non-labor	 	 	228	 	 	 	215	 	 	 	+6	%	
Reimbursed G&A	 	 	(73	)	 	 	(82	)	 	 	- 11	%	
Total Devon	 	 	744	 	 	 	747	 	 	 	- 0	%	
EnLink	 	 	128	 	 	 	118	 	 	 	+8	%	
Total	 	$	872	 	 	$	865	 	 	 	+1	%	
Labor and benefits decreased primarily as a result of the workforce reduction that occurred in February 2016 as discussed in Note 7 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. Reimbursed G&A decreased primarily due the divestitures of operated properties in 2016. EnLink G&A increased primarily due to higher compensation costs.
 
 Financing Costs, net	
 
Financing costs, net decreased $409 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 16 in “Item 8. Financial Statements and Supplementary Data” of this report.
 
Other	
 
 	 	2017	 	 	2016	 	 	Change	 	
Asset impairments	 	$	17	 	 	$	1,310	 	 	 	- 99	%	
Asset dispositions	 	 	(217	)	 	 	(1,483	)	 	 	- 85	%	
Restructuring	 	 	—	 	 	 	267	 	 	N/M	 	
Other	 	 	(124	)	 	 	108	 	 	 	- 215	%	
Total	 	$	(324	)	 	$	202	 	 	 	- 260	%	
 
Asset impairments in 2016 primarily related to goodwill and other intangible asset impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
We recognized gains in conjunction with our non-core U.S. upstream 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 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, we recognized restructuring and transaction costs of $267 million primarily as a result of our workforce reduction. For discussion of our reorganization programs and the associated restructuring costs, see Note 7 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	 	 	$	100	 	
Deferred expense (benefit)	 	 	(294	)	 	 	41	 	
Total expense (benefit)	 	$	(182	)	 	$	141	 	
Effective income tax rate	 	 	(20	%)	 	 	(11	%)	
 
For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.

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Results of Operations – 2016 vs. 2015
The graph below shows the change in net earnings from 2015 to 2016. 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. Additional information regarding noncontrolling interests is discussed in Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.

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

 

*	Prior year amounts, including amounts in the following tables, have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	

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Upstream Operations	
Oil, Gas and NGL Production
 
 	 	2016	 	 	% of Total	 	 	2015	 	 	Change	 	
Oil and bitumen (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	19	 	 	 	7	%	 	 	7	 	 	 	+152	%	
Delaware Basin	 	 	33	 	 	 	13	%	 	 	39	 	 	 	- 16	%	
Rockies Oil	 	 	14	 	 	 	5	%	 	 	15	 	 	 	- 9	%	
Heavy Oil	 	 	22	 	 	 	9	%	 	 	27	 	 	 	- 17	%	
Eagle Ford	 	 	39	 	 	 	15	%	 	 	61	 	 	 	- 35	%	
Barnett Shale	 	 	1	 	 	 	0	%	 	 	1	 	 	 	- 28	%	
Other	 	 	11	 	 	 	4	%	 	 	13	 	 	 	- 11	%	
Retained assets	 	 	139	 	 	 	53	%	 	 	163	 	 	 	- 15	%	
Divested assets	 	 	12	 	 	 	5	%	 	 	28	 	 	 	- 56	%	
Total Oil	 	 	151	 	 	 	58	%	 	 	191	 	 	 	- 21	%	
Bitumen	 	 	109	 	 	 	42	%	 	 	84	 	 	 	+29	%	
Total Oil and bitumen	 	 	260	 	 	 	 	 	 	 	275	 	 	 	- 6	%	
 
 	 	2016	 	 	% of Total	 	 	2015	 	 	Change	 	
Gas (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	293	 	 	 	21	%	 	 	239	 	 	 	+23	%	
Delaware Basin	 	 	90	 	 	 	6	%	 	 	71	 	 	 	+27	%	
Rockies Oil	 	 	25	 	 	 	2	%	 	 	40	 	 	 	- 37	%	
Heavy Oil	 	 	20	 	 	 	1	%	 	 	22	 	 	 	- 11	%	
Eagle Ford	 	 	101	 	 	 	7	%	 	 	141	 	 	 	- 28	%	
Barnett Shale	 	 	741	 	 	 	53	%	 	 	815	 	 	 	- 9	%	
Other	 	 	13	 	 	 	1	%	 	 	17	 	 	 	- 22	%	
Retained assets	 	 	1,283	 	 	 	91	%	 	 	1,345	 	 	 	- 5	%	
Divested assets	 	 	130	 	 	 	9	%	 	 	265	 	 	 	- 51	%	
Total	 	 	1,413	 	 	 	 	 	 	 	1,610	 	 	 	- 12	%	
 
 	 	2016	 	 	% of Total	 	 	2015	 	 	Change	 	
NGLs (MBbls/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	26	 	 	 	23	%	 	 	21	 	 	 	+22	%	
Delaware Basin	 	 	12	 	 	 	10	%	 	 	9	 	 	 	+28	%	
Rockies Oil	 	 	1	 	 	 	1	%	 	 	1	 	 	 	- 9	%	
Eagle Ford	 	 	16	 	 	 	14	%	 	 	23	 	 	 	- 33	%	
Barnett Shale	 	 	45	 	 	 	39	%	 	 	51	 	 	 	- 12	%	
Other	 	 	2	 	 	 	1	%	 	 	4	 	 	 	- 59	%	
Retained assets	 	 	102	 	 	 	88	%	 	 	109	 	 	 	- 7	%	
Divested assets	 	 	14	 	 	 	12	%	 	 	27	 	 	 	- 50	%	
Total	 	 	116	 	 	 	 	 	 	 	136	 	 	 	- 15	%	
  
 	 	2016	 	 	% of Total	 	 	2015	 	 	Change	 	
Combined (MBoe/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	 	 	93	 	 	 	15	%	 	 	68	 	 	 	+37	%	
Delaware Basin	 	 	60	 	 	 	10	%	 	 	60	 	 	 	- 1	%	
Rockies Oil	 	 	19	 	 	 	3	%	 	 	23	 	 	 	- 17	%	
Heavy Oil	 	 	134	 	 	 	22	%	 	 	115	 	 	 	+17	%	
Eagle Ford	 	 	72	 	 	 	12	%	 	 	107	 	 	 	- 33	%	
Barnett Shale	 	 	169	 	 	 	28	%	 	 	188	 	 	 	- 10	%	
Other	 	 	16	 	 	 	2	%	 	 	19	 	 	 	- 13	%	
Retained assets	 	 	563	 	 	 	92	%	 	 	580	 	 	 	- 3	%	
Divested assets	 	 	48	 	 	 	8	%	 	 	100	 	 	 	- 52	%	
Total	 	 	611	 	 	 	 	 	 	 	680	 	 	 	- 10	%	
Production declines reduced our upstream revenues by $620 million. Production volumes decreased due to our reduction in exploration and development activity related to our retained assets during 2016. While expanded drilling in the STACK and the performance of our Jackfish assets drove production increases, these production increases were more than offset by reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale and Rockies Oil. Additionally, our production decreased as a result of our U.S. non-core divestitures that occurred throughout 2016.
 
Oil, Gas and NGL Prices
 
 	 	2016	 	 	Realization	 	 	2015	 	 	Change	 	
Oil and bitumen (per Bbl)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
WTI index	 	$	43.36	 	 	 	 	 	 	$	48.87	 	 	 	- 11	%	
Access Western Blend index	 	$	26.96	 	 	 	 	 	 	$	32.18	 	 	 	- 16	%	
U.S.	 	$	38.92	 	 	 	90%	 	 	$	44.01	 	 	 	- 12	%	
Canada	 	$	20.53	 	 	 	47%	 	 	$	25.14	 	 	 	- 18	%	
Realized price, unhedged	 	$	29.65	 	 	 	68%	 	 	$	36.39	 	 	 	- 19	%	
Cash settlements	 	$	(0.43	)	 	 	 	 	 	$	20.72	 	 	 	 	 	
Realized price, with hedges	 	$	29.22	 	 	 	67%	 	 	$	57.11	 	 	 	- 49	%	
 
 	 	2016	 	 	Realization	 	 	2015	 	 	Change	 	
Gas (per Mcf)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Henry Hub index	 	$	2.46	 	 	 	 	 	 	$	2.67	 	 	 	- 8	%	
Realized price, unhedged	 	$	1.84	 	 	 	75%	 	 	$	2.14	 	 	 	- 14	%	
Cash settlements	 	$	0.07	 	 	 	 	 	 	$	0.57	 	 	 	 	 	
Realized price, with hedges	 	$	1.91	 	 	 	77%	 	 	$	2.71	 	 	 	- 30	%	

 	 	2016	 	 	Realization	 	 	2015	 	 	Change	 	
NGLs (per Bbl)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mont Belvieu blended index (1)	 	$	17.20	 	 	 	 	 	 	$	16.93	 	 	 	+2	%	
Realized price, unhedged	 	$	9.81	 	 	 	57%	 	 	$	9.32	 	 	 	+5	%	
Cash settlements	 	$	(0.11	)	 	 	 	 	 	$	—	 	 	 	 	 	
Realized price, with hedges	 	$	9.70	 	 	 	56%	 	 	$	9.32	 	 	 	+4	%	

(1)	Based upon composition of average Devon NGL barrel.	

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 	 	2016	 	 	2015	 	 	Change	 	
Combined (per Boe)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	$	18.34	 	 	$	21.12	 	 	 	- 13	%	
Canada	 	$	20.07	 	 	$	24.46	 	 	 	- 18	%	
Realized price, unhedged	 	$	18.72	 	 	$	21.68	 	 	 	- 14	%	
Cash settlements	 	$	(0.05	)	 	$	9.74	 	 	 	 	 	
Realized price, with hedges	 	$	18.67	 	 	$	31.42	 	 	 	- 41	%	
 
Upstream revenues decreased $580 million as a result of lower unhedged, realized prices for oil, bitumen and gas. The decrease in oil and bitumen sales primarily resulted from lower average WTI crude index prices, which were 11% lower in 2016 as compared to 2015. The decrease in gas sales was driven by lower North American regional index prices upon which our gas sales are based. These decreases were partially offset by slightly higher NGL prices at the Mont Belvieu, Texas hub.
Commodity Derivatives
 
 	 	2016	 	 	2015	 	 	Change	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil	 	$	(41	)	 	$	2,083	 	 	 	- 102	%	
Natural gas	 	 	35	 	 	 	333	 	 	 	- 89	%	
NGL	 	 	(5	)	 	 	—	 	 	N/M	 	
Total cash settlements	 	 	(11	)	 	 	2,416	 	 	 	- 100	%	
Valuation changes	 	 	(190	)	 	 	(1,913	)	 	 	+90	%	
Total	 	$	(201	)	 	$	503	 	 	 	- 140	%	
 
Production Expenses
 
 	 	2016	 	 	2015	 	 	Change	 	
LOE	 	$	1,027	 	 	$	1,509	 	 	 	- 32	%	
Gathering & transportation	 	 	555	 	 	 	595	 	 	 	- 7	%	
Production taxes	 	 	147	 	 	 	207	 	 	 	- 29	%	
Property taxes	 	 	74	 	 	 	128	 	 	 	- 42	%	
Total	 	$	1,803	 	 	$	2,439	 	 	 	- 26	%	
Per Boe:	 	 	 	 	 	 	 	 	 	 	 	 	
LOE	 	$	4.59	 	 	$	6.08	 	 	 	- 24	%	
Gathering & transportation	 	$	2.48	 	 	$	2.40	 	 	 	+4	%	
Percent of oil, gas and NGL sales:	 	 	 	 	 	 	 	 	 	 	 	 	
Production taxes	 	 	3.5	%	 	 	3.8	%	 	 	- 8	%	
 
LOE and LOE per BOE decreased as a result of our cost reduction initiatives, well optimization and our non-core oil and gas property divestitures. On an absolute dollar basis, LOE decreased approximately $200 million as a result of our U.S. upstream divestitures.
Gathering and transportation decreased primarily as a result of U.S. upstream asset divestitures partially offset by $28 million of Access Pipeline transportation tolls which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline.
 Production taxes decreased on an absolute dollar basis primarily due to the decrease 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. non-core divestitures.
 
Marketing & Midstream Operations	
 
 	 	2016	 	 	2015	 	 	Change	 	
Operating revenues	 	$	4,252	 	 	$	4,451	 	 	 	- 4	%	
Product purchases	 	 	(3,015	)	 	 	(3,245	)	 	 	- 7	%	
Operations and maintenance expenses	 	 	(398	)	 	 	(419	)	 	 	- 5	%	
EnLink margin	 	 	839	 	 	 	787	 	 	 	+7	%	
Devon margin	 	 	(49	)	 	 	12	 	 	N/M	 	
Total	 	$	790	 	 	$	799	 	 	 	- 1	%	
 
The overall decrease was primarily due to lower margins on Devon’s downstream marketing commitments, offset by EnLink’s margin growth largely related to its acquisition activity in late 2015 and the first quarter of 2016.
 
Exploration Expenses	
 
 	 	2016	 	 	2015	 	 	Change	 	
Unproved impairments	 	$	77	 	 	$	260	 	 	 	- 70	%	
Geological and geophysical	 	 	65	 	 	 	108	 	 	 	- 40	%	
Exploration overhead and other	 	 	73	 	 	 	83	 	 	 	- 13	%	
Total	 	$	215	 	 	$	451	 	 	 	- 52	%	
 
Unproved impairments primarily relate to a portion of acreage in our non-core U.S. operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs were lower due to a reduced exploration capital program in 2016.
 
Depreciation, Depletion and Amortization	
 
 	 	2016	 	 	2015	 	 	Change	 	
Oil and gas per Boe	 	$	6.47	 	 	$	13.99	 	 	 	- 54	%	
Oil and gas	 	$	1,446	 	 	$	3,474	 	 	 	- 58	%	
Midstream and other assets	 	 	146	 	 	 	161	 	 	 	- 10	%	
Devon	 	 	1,592	 	 	 	3,635	 	 	 	- 56	%	
EnLink	 	 	504	 	 	 	387	 	 	 	+30	%	
Total	 	$	2,096	 	 	$	4,022	 	 	 	- 48	%	
 
DD&A from our oil and gas properties decreased largely because of our significant asset impairments recognized in 2015. For discussion on asset impairments, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report. EnLink’s DD&A increased primarily due to acquisitions in 2015 and 2016.

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General and Administrative Expenses	
 
 	 	2016	 	 	2015	 	 	Change	 	
Labor and benefits	 	$	614	 	 	$	866	 	 	 	- 29	%	
Non-labor	 	 	215	 	 	 	310	 	 	 	- 31	%	
Reimbursed G&A	 	 	(82	)	 	 	(120	)	 	 	- 31	%	
Total Devon	 	 	747	 	 	 	1,056	 	 	 	- 29	%	
EnLink	 	 	118	 	 	 	137	 	 	 	- 14	%	
Total	 	$	865	 	 	$	1,193	 	 	 	- 27	%	
 
G&A decreased due to workforce reductions, as discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report, and other cost reduction initiatives in response to the decline in commodity prices. Reimbursed G&A decreased primarily due to a reduction in drilling activity, as well as the divestiture of operated properties. EnLink G&A decreased primarily due to lower employee compensation expense and other cost reduction initiatives during 2016.
 
Financing Costs, net	
Financing costs, net increased $388 million primarily as a result of our $2.1 billion early debt retirement. For further discussion, see Note 16 in “Item 8. Financial Statements and Supplementary Data” of this report.
 
Other	
 
 	 	2016	 	 	2015	 	 	Change	 	
Asset impairments	 	$	1,310	 	 	$	17,647	 	 	 	- 93	%	
Asset dispositions	 	 	(1,483	)	 	 	7	 	 	N/M	 	
Restructuring	 	 	267	 	 	 	78	 	 	 	+242	%	
Other	 	 	108	 	 	 	186	 	 	 	- 42	%	
Total	 	$	202	 	 	$	17,918	 	 	 	- 99	%	
  
Asset impairments largely related to our oil and gas assets and resulted from a significant decline in forecasted commodity prices during 2015 and 2016. Asset impairments for 2016 and 2015 also related to goodwill and other intangible asset impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
We recognized gains in conjunction with our non-core U.S. upstream asset dispositions in 2016 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.  
During 2016, we recognized restructuring and transactions costs of $267 million primarily as a result of our workforce reduction. For discussion of our restructuring programs and the associated restructuring costs, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
 
Income Taxes	
 
 	 	2016	 	 	2015	 	
Current expense	 	$	100	 	 	$	(237	)	
Deferred expense (benefit)	 	 	41	 	 	 	(5,976	)	
Total expense (benefit)	 	$	141	 	 	$	(6,213	)	
Effective income tax rate	 	 	(11	%)	 	 	31	%	
 
For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.

 

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Capital Resources, Uses and Liquidity
The following table presents the major source and use categories of Devon and EnLink’s cash and cash equivalents.
 
 	 	Devon	 	 	EnLink	 	 	Consolidated	 	
 	 	2017	 	 	2016*	 	 	2015*	 	 	2017	 	 	2016*	 	 	2015*	 	 	2017	 	 	2016*	 	 	2015*	 	
Operating cash flow	 	$	2,209	 	 	$	834	 	 	$	4,271	 	 	$	700	 	 	$	666	 	 	$	627	 	 	$	2,909	 	 	$	1,500	 	 	$	4,898	 	
Issuance of common stock	 	 	—	 	 	 	1,469	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,469	 	 	 	—	 	
Divestitures of property
   and investments	 	 	415	 	 	 	3,020	 	 	 	106	 	 	 	192	 	 	 	93	 	 	 	1	 	 	 	607	 	 	 	3,113	 	 	 	107	 	
Capital expenditures	 	 	(1,968	)	 	 	(1,384	)	 	 	(4,214	)	 	 	(791	)	 	 	(663	)	 	 	(573	)	 	 	(2,759	)	 	 	(2,047	)	 	 	(4,787	)	
Acquisitions of property,
   equipment and businesses	 	 	(46	)	 	 	(849	)	 	 	(583	)	 	 	—	 	 	 	(792	)	 	 	(524	)	 	 	(46	)	 	 	(1,641	)	 	 	(1,107	)	
Debt activity, net	 	 	—	 	 	 	(3,383	)	 	 	770	 	 	 	2	 	 	 	228	 	 	 	1,061	 	 	 	2	 	 	 	(3,155	)	 	 	1,831	 	
Shareholder and noncontrolling
   interests distributions	 	 	(127	)	 	 	(221	)	 	 	(396	)	 	 	(354	)	 	 	(304	)	 	 	(254	)	 	 	(481	)	 	 	(525	)	 	 	(650	)	
EnLink and General Partner
   distributions	 	 	265	 	 	 	265	 	 	 	268	 	 	 	(265	)	 	 	(265	)	 	 	(268	)	 	 	—	 	 	 	—	 	 	 	—	 	
Subsidiary unit transactions	 	 	—	 	 	 	—	 	 	 	654	 	 	 	501	 	 	 	892	 	 	 	25	 	 	 	501	 	 	 	892	 	 	 	679	 	
Effect of exchange rate
   and other	 	 	(53	)	 	 	(96	)	 	 	4	 	 	 	34	 	 	 	139	 	 	 	(145	)	 	 	(19	)	 	 	43	 	 	 	(141	)	
Net change in cash and
   cash equivalents	 	$	695	 	 	$	(345	)	 	$	880	 	 	$	19	 	 	$	(6	)	 	$	(50	)	 	$	714	 	 	$	(351	)	 	$	830	 	
Cash and cash equivalents at
   end of period	 	$	2,642	 	 	$	1,947	 	 	$	2,292	 	 	$	31	 	 	$	12	 	 	$	18	 	 	$	2,673	 	 	$	1,959	 	 	$	2,310	 	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
Devon Sources and Uses of Cash
Operating Cash Flow
Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2017. Our operating cash flow increased $1.4 billion, or 165%, as compared to 2016 due to significantly higher commodity prices. In 2017, our operating cash flow fully funded our capital expenditure program as well as our dividends.
Our operating cash flow decreased $3.4 billion, or 80% from 2015 to 2016. While commodity prices decreased from 2015 to 2016, the primary driver of the decrease was due to the expiration of certain favorable hedge positions that provided us with an additional $2.4 billion of additional operating cash flow in 2015. In 2016 and 2015, 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.
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.
Divestitures of Property and Investments
During 2017, as part of our announced divestiture program, we sold non-core U.S. assets for $415 million. For further discussion, see Note 3 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
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repayment and to support capital investment in Devon’s core resource plays. For further discussion, see Note 3 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 2017 and 2016.
Capital Expenditures
The following table summarizes our capital expenditures and property acquisitions.
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016*	 	 	2015*	 	
Oil and gas	 	$	1,879	 	 	$	1,341	 	 	$	4,056	 	
Corporate and other	 	 	89	 	 	 	43	 	 	 	158	 	
Total capital expenditures	 	$	1,968	 	 	$	1,384	 	 	$	4,214	 	
Acquisitions	 	$	46	 	 	$	849	 	 	$	583	 	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
 
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 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 fully funding capital expenditures in 2017. In response to the lower commodity prices, our total capital expenditures have been reduced by approximately 50% since 2015.
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. In 2015 our acquisition activity primarily consisted of the Powder River Basin asset acquisition in the fourth quarter. For further discussion on acquisition activity, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
Debt Activity, Net
During 2016, our debt decreased $3.1 billion. The decrease was primarily 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.
During 2015, our net debt increased $770 million. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter.
Shareholder Distributions
Devon paid common stock dividends of $127 million, $221 million and $396 million during 2017, 2016 and 2015, respectively. In response to the depressed commodity price environment, we reduced our quarterly dividend from $0.24 to $0.06 per share in the second quarter of 2016.
EnLink and General Partner Distributions
Devon received $265 million, $265 million and $268 million in distributions from EnLink and the General Partner during 2017, 2016 and 2015, respectively.
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Index to Financial Statements
Subsidiary Unit Transactions
In 2015, we conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
EnLink Sources and Uses of Cash
EnLink’s operating cash flow has increased each year since 2015 as a result of the growth experienced from its acquisition activity and continued development activities.
Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. 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. For additional information on this acquisition, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. EnLink’s acquisitions in 2015 consisted of additional oil and gas pipeline assets, including gathering, transportation and processing facilities.
During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. Proceeds were primarily used to pay a portion of the first $250 million installment payment related to EnLink’s 2016 acquisition noted above.
During 2017, EnLink’s debt increased $247 million. In May 2017, EnLink issued $500 million of 5.45% senior notes due in 2047 to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. In June 2017, EnLink redeemed its 7.125% senior unsecured notes due in 2022 for aggregate cash consideration of $174 million. Additionally, EnLink reduced its credit facility borrowings to $74 million during 2017. As noted above, EnLink made the first installment payment in 2017 related to its 2016 acquisition.
EnLink and the General Partner distributed $354 million, $304 million and $254 million to non-Devon unitholders during 2017, 2016 and 2015, respectively.
During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3 million common units through general public offerings and its “at the market” equity program, generating net proceeds of approximately $107 million, $167 million and $25 million, respectively.
In 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.
In 2016, to fund a portion of the cash consideration of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction.  
In 2017 and 2016, EnLink received contributions from noncontrolling interests. For further discussion see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
Devon Liquidity
Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidity also include, among other things, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. The most significant source of liquidity in 2017 has come from our operating cash flow supplemented with approximately $415 million of proceeds related to our asset divestitures. We estimate the combination of these sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments, dividends and other contractual commitments as discussed in this section.
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Operating Cash Flow
Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow increased 165% in 2017 largely due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as we adjust our capital program to invest within our operating cash flow. Furthermore, proceeds from our non-core asset divestitures will provide additional liquidity as needed.
Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. 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. As a result, entering into 2018 we have hedged approximately 40% of our anticipated oil and 50% of our anticipated gas production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2017 are presented in Note 4 in “Item 8. Financial Statements and Supplementary Data” of this report.
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.
Divestitures of Property and Equipment –  In 2017, we announced a program to divest approximately $1 billion of upstream assets. These non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through December 31, 2017, Devon completed divestiture transactions totaling approximately $415 million. The most significant asset remaining in this program is select Barnett Shale properties which we expect to close in 2018.
Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2017, we had total debt of $6.9 billion that bears fixed interest rates averaging 5.7%.
As of December 31, 2017, we had open interest rate swap positions that are presented in Note 4 in “Item 8. Financial Statements and Supplementary Data” in this report.
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.
At the end of 2017, we held approximately $2.6 billion of cash. Included in this total was $732 million of cash held by our foreign subsidiaries.
Credit Availability
We have a $3.0 billion Senior Credit Facility. The maturity date for $164 million of the Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2017, there were no borrowings under our commercial paper program. See Note 16 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.
 The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our
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outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as oil and gas property impairments and goodwill impairments. As of December 31, 2017, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2017, as calculated pursuant to the terms of the agreement, was 27.2%.
Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the credit agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.
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. We are currently targeting up to $1.5 billion of debt reduction in 2018.
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 near-term and long-term production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. In March 2017, Fitch Ratings affirmed our BBB+ rating and revised our outlook to stable from negative. In April 2017, Moody’s Investor Service upgraded our credit rating from Ba2 to Ba1 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.
Capital Expenditures
Our 2018 exploration and development budget is expected to be approximately $2.2 billion to $2.4 billion and funded within operating cash flow. Although negative movements in any of the variables discussed above would impact our operating cash flow, we likely would not change our 2018 planned capital investment. Should our operating cash flow decrease from our forecasts, we could divest non-core assets to balance capital sources and uses.
EnLink Liquidity
EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2017, there were $10 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility and $74 million outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
As of December 31, 2017, EnLink had total debt of $3.5 billion. Of this amount, $3.4 billion bears fixed interest rates averaging 4.6% and $74 million is comprised of floating rate debt with interest rates averaging 3.2%.
EnLink’s 2018 capital budget includes approximately $600 million to $800 million of identified growth projects. EnLink’s primary capital projects for 2018 include the construction of the Thunderbird processing plant in Central Oklahoma, the Lobo III processing plant in the Delaware Basin and the development of additional gathering and compression assets in Central Oklahoma and the Permian Basin.
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EnLink expects to fund the growth capital expenditures with borrowings under its bank credit facility and proceeds from other debt and equity sources, including capital contributions by joint venture partners. EnLink expects to fund its 2018 maintenance capital expenditures from operating cash flows. EnLink employs a strategy that includes maintaining stable operating cash flows that are supported by long-term, fixed-fee contracts. Approximately 94% of EnLink’s cash flows were generated from fee-based services in 2017. It is possible that not all of the planned projects for 2018 will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.  
Contractual Obligations
The following table presents a summary of our contractual obligations as of December 31, 2017.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Payments Due by Period	 	
 	 	Total	 	 	Less Than 1 Year	 	 	1-3 Years	 	 	3-5 Years	 	 	More Than 5 Years	 	
Devon obligations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Debt (1)	 	$	6,933	 	 	$	115	 	 	$	162	 	 	$	1,500	 	 	$	5,156	 	
Interest expense (2)	 	 	6,188	 	 	 	390	 	 	 	756	 	 	 	715	 	 	 	4,327	 	
Purchase obligations (3)	 	 	1,880	 	 	 	613	 	 	 	1,133	 	 	 	134	 	 	 	—	 	
Operational agreements (4)	 	 	5,259	 	 	 	522	 	 	 	756	 	 	 	739	 	 	 	3,242	 	
Operational agreements with EnLink (5)	 	 	909	 	 	 	637	 	 	 	272	 	 	 	—	 	 	 	—	 	
Asset retirement obligations (6)	 	 	1,152	 	 	 	39	 	 	 	134	 	 	 	171	 	 	 	808	 	
Drilling and facility obligations (7)	 	 	629	 	 	 	216	 	 	 	218	 	 	 	89	 	 	 	106	 	
Lease obligations (8)	 	 	381	 	 	 	88	 	 	 	157	 	 	 	117	 	 	 	19	 	
Other (9)	 	 	115	 	 	 	115	 	 	 	—	 	 	 	—	 	 	 	—	 	
Total Devon obligations	 	 	23,446	 	 	 	2,735	 	 	 	3,588	 	 	 	3,465	 	 	 	13,658	 	
EnLink obligations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Debt (1)	 	 	3,574	 	 	 	—	 	 	 	474	 	 	 	—	 	 	 	3,100	 	
Interest expense (2)	 	 	2,573	 	 	 	160	 	 	 	304	 	 	 	298	 	 	 	1,811	 	
Other (9)	 	 	496	 	 	 	306	 	 	 	55	 	 	 	45	 	 	 	90	 	
Total EnLink obligations	 	 	6,643	 	 	 	466	 	 	 	833	 	 	 	343	 	 	 	5,001	 	
Total obligations	 	$	30,089	 	 	$	3,201	 	 	$	4,421	 	 	$	3,808	 	 	$	18,659	 	

(1)	Debt amounts represent scheduled maturities of debt obligations at December 31, 2017, 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.	
(5)	Operational agreements between Devon and EnLink represent fixed-fee gathering and processing and transportation agreements. These agreements also include minimum volume commitments that will remain in effect for approximately one more year, as well as annual rate escalators.	
(6)	Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2017 balance sheet.	
(7)	Drilling and facility obligations represent gross contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.	
(8)	Lease obligations consist primarily of non-cancelable leases for office space and equipment.	
(9)	Other Devon obligations primarily relate to uncertain tax positions as discussed in Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report. Other EnLink obligations primarily consist of a $250 million installment payment on the Anadarko Basin assets acquisition as discussed in  Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.	
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Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report.

Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.
 
Oil and Gas Assets Accounting, Reserves, Classification & Valuation
Change in Accounting Principle
In the fourth quarter of 2017, we changed our method of accounting for our oil and gas exploration and development activities from the full cost method to the successful efforts method. In accordance with FASB ASC 250 “ Accounting Changes and Error Corrections,” financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive Activities—Oil and Gas.” As required by ASC 250, we have presented the accumulated effect of the change in accounting principle from Devon’s inception to December 31, 2014 as a change in the beginning balance of our 2015 consolidated statements of equity.
To recast our financial statements, we made certain critical estimates, judgments and assumptions to apply successful efforts accounting to our historical operations. These critical items are similar to those pertaining to our ongoing successful efforts accounting, which are described below. For additional information regarding the effects of the change to the successful efforts method, including our underlying successful efforts accounting policies, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
To illustrate the effect of the change to successful efforts accounting, the following table summarizes the $1.9 billion increase to our historical equity as of September 30, 2017, the date of our conversion. The increase was primarily driven by lower impairments, offset by higher DD&A and less capitalized expenses.
 
Category	 	 	 	 	 	 	 	
Total equity as of September 30, 2017 (Full Cost)	 	 	 	 	$	11,934	 	
Adjustments from inception through 2007, net	 	 	 	 	 	(2,147	)	
Adjustments after 2007:	 	 	 	 	 	 	 	
Lower asset impairments, net	 	 	18,317	 	 	 	 	
Exploration expense	 	 	(5,402	)	 	 	 	
Higher DD&A, driven largely by lower impairments	 	 	(5,036	)	 	 	 	
G&A expensed rather than capitalized	 	 	(3,075	)	 	 	 	
Other (asset dispositions, foreign exchange cumulative translation adjustment, etc.)	 	 	418	 	 	 	 	
Deferred income tax on the above items	 	 	(1,152	)	 	 	 	
Total adjustments after 2007	 	 	 	 	 	4,070	 	
Equity increase (+16%)	 	 	 	 	 	1,923	 	
Total equity as of September 30, 2017 (Successful Efforts)	 	 	 	 	$	13,857	 	

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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 2017, 88% 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.
 
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 previous section. 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, 2017, 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. Based on this assessment, Devon impaired $139 million of undeveloped leasehold in the fourth quarter of 2017. At December 31, 2017, Devon had $1.4 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, 2017, $85 million is scheduled to expire in 2018. The leasehold expiring in 2018 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.
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 expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual 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
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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 2015 and 2016, we recognized significant asset impairments in each of those years. With more stabilized and higher pricing in 2017, we did not recognize material asset impairments.      
Goodwill and Other Intangibles
Goodwill
We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. While we use data as of October 31 for our test, we typically complete the test in late December or early January as the October 31 market data used in our test becomes available.
We assess the qualitative and quantitative factors to determine whether the fair value of a reporting unit is less than its carrying amount. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue growth rates driven by future commodity prices and volume expectations, operating margins and capital expenditures.
For the October 31, 2017 impairment tests for Devon’s U.S. reporting unit and each of EnLink’s reporting units, the fair value of each reporting unit exceeded its carrying value.
Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test for EnLink’s reporting units in 2015 and an update to be performed at December 31, 2015. Using the fair value approaches described above, it was determined that the estimated fair value of EnLink’s Texas, Louisiana and Crude and Condensate reporting units were less than their carrying amounts and a goodwill impairment loss of $492 million, $787 million and $49 million, respectively, was recognized in 2015.
Additionally, another interim impairment test was warranted during 2016 for EnLink’s reporting units. Using the fair value approaches described above, it was determined that the estimated fair value of EnLink’s Texas, General Partner and Crude and Condensate reporting units were less than their carrying amounts and a goodwill impairment loss of $473 million, $307 million and $93 million, respectively, was recognized in 2016.
 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
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future operating results, which could result in future goodwill impairments for our reporting units due to the potential impact on the cash flows of our operations.
The impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.
Other Intangible Assets
In 2015, the assessment of customer relationships was updated due to the factors described in the aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment.
The other intangible assets impairment has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. At the end of 2017 and 2016, we had deferred tax assets that largely resulted from the asset impairments recognized throughout 2016. As a result of our recent cumulative losses and our current realization assessment, we recorded a 100% valuation allowance against our U.S. deferred tax assets as of December 31, 2017 and December 31, 2016. Further, in 2017, we recognized a $660 million partial valuation allowance against certain Canadian deferred tax assets as a result of the Canadian legal entity restructuring.  
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.
 
We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S. and existing U.S. income tax laws, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.  
 
For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:
 
 	•	separate analysis of a diverse chain of foreign entities;	
 	•	relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;	
 	•	determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and	
 	•	further analysis of a variety of other inputs such as the earnings, profits, U.S./foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.	
 
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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.
Under the Tax Reform Legislation, the corporate income tax rate was reduced to 21% effective January 1, 2018.  We are required to recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax, remeasuring our U.S. deferred tax assets and liabilities and reassessing the net realizability of our deferred tax assets and liabilities.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, we consider the accounting of the transition tax, deferred tax remeasurements, and other items to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. We expect to complete our analysis within the measurement period in accordance with SAB 118.
Absent unexpected events and unexpected effects of the Tax Reform Legislation, Devon expects a positive impact on its future after-tax earnings, primarily due to the lower federal statutory tax rate.
Non-GAAP Measures
We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2017 Results” in this Item 7. that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring when comparing on an annual basis. In the table below, restructuring and transaction costs were incurred in two of the three year periods; however, these costs relate to different restructuring programs. Amounts excluded for 2017 relate to asset dispositions, noncash asset impairments including noncash unproved asset impairments (included in exploration expenses), 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 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.
Amounts excluded for 2015 relate to asset dispositions, noncash asset impairments (including an impairment of 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, derivatives and financial instrument fair value changes and repatriation of funds to the U.S.
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	 	
2017	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings attributable to Devon (GAAP)	$	896	 	 	$	1,078	 	 	$	898	 	 	$	1.70	 	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset dispositions	 	(217	)	 	 	(138	)	 	 	(138	)	 	 	(0.26	)	
Asset and exploration impairments	 	234	 	 	 	152	 	 	 	146	 	 	 	0.27	 	
U.S. tax reform	 	—	 	 	 	(211	)	 	 	(112	)	 	 	(0.21	)	
Deferred tax asset valuation allowance	 	—	 	 	 	(76	)	 	 	(76	)	 	 	(0.14	)	
Fair value changes in financial
   instruments and foreign currency	 	(218	)	 	 	(202	)	 	 	(201	)	 	 	(0.38	)	
Legal entity restructuring	 	—	 	 	 	(86	)	 	 	(86	)	 	 	(0.16	)	
Early retirement of debt	 	(9	)	 	 	(7	)	 	 	(4	)	 	 	(0.01	)	
Core earnings attributable to Devon (Non-GAAP)	$	686	 	 	$	510	 	 	$	427	 	 	$	0.81	 	
2016*	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss attributable to Devon (GAAP)	$	(1,317	)	 	$	(1,458	)	 	$	(1,056	)	 	$	(2.09	)	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset dispositions	 	(1,483	)	 	 	(989	)	 	 	(995	)	 	 	(1.95	)	
Asset and exploration impairments	 	1,430	 	 	 	1,230	 	 	 	807	 	 	 	1.60	 	
Rig stacking costs	 	10	 	 	 	6	 	 	 	6	 	 	 	0.01	 	
Deferred tax asset valuation allowance	 	—	 	 	 	385	 	 	 	385	 	 	 	0.76	 	
Restructuring and transaction costs	 	267	 	 	 	173	 	 	 	170	 	 	 	0.33	 	
Fair value changes in financial
   instruments and foreign currency	 	270	 	 	 	153	 	 	 	145	 	 	 	0.28	 	
Early retirement of debt	 	269	 	 	 	171	 	 	 	171	 	 	 	0.33	 	
Core loss attributable to Devon (Non-GAAP)	$	(554	)	 	$	(329	)	 	$	(367	)	 	$	(0.73	)	
2015*	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss attributable to Devon (GAAP)	$	(19,858	)	 	$	(13,645	)	 	$	(12,896	)	 	$	(31.72	)	
Adjustments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset dispositions	 	7	 	 	 	8	 	 	 	8	 	 	 	0.02	 	
Asset and exploration impairments	 	17,914	 	 	 	11,955	 	 	 	11,131	 	 	 	27.37	 	
Rig stacking costs	 	54	 	 	 	34	 	 	 	34	 	 	 	0.08	 	
Deferred tax asset valuation allowance	 	—	 	 	 	403	 	 	 	403	 	 	 	0.99	 	
Restructuring and transaction costs	 	78	 	 	 	52	 	 	 	52	 	 	 	0.13	 	
Fair value changes in financial
   instruments and foreign currency	 	1,967	 	 	 	1,349	 	 	 	1,346	 	 	 	3.31	 	
Repatriations	 	—	 	 	 	33	 	 	 	33	 	 	 	0.08	 	
Core earnings attributable to Devon (Non-GAAP)	$	162	 	 	$	189	 	 	$	111	 	 	$	0.26	 	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	

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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, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil 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, 2017 are presented in Note 4 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, 2017, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $260 million.
 
Interest Rate Risk
At December 31, 2017, we had total debt of $10.4 billion. Of this amount, $10.3 billion bears fixed interest rates averaging 5.3%, and approximately $74 million is comprised of floating rate debt with interest rates averaging 3.2%.
As of December 31, 2017, we had open interest rate swap positions that are presented in Note 4 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the three month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet or liquidity at December 31, 2017.
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, 2017 balance sheet.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of these subsidiaries hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Based on the amount of the cash and intercompany loans as of December 31, 2017, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.
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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 – Change in Accounting Principle	 	67	
Note 3 – Acquisitions and Divestitures	 	71	
Note 4 – Derivative Financial Instruments	 	73	
Note 5 – Share-Based Compensation	 	75	
Note 6 – Asset Impairments	 	79	
Note 7 – Other Expenses	 	80	
Note 8 – Income Taxes	 	81	
Note 9 – Net Earnings (Loss) Per Share Attributable to Devon	 	85	
Note 10 – Other Comprehensive Earnings	 	86	
Note 11 – Supplemental Information to Statements of Cash Flows	 	86	
Note 12 – Accounts Receivable	 	87	
Note 13 – Property, Plant and Equipment	 	87	
Note 14 – Goodwill and Other Intangible Assets	 	89	
Note 15 – Other Current Liabilities	 	90	
Note 16 – Debt and Related Expenses	 	91	
Note 17 – Asset Retirement Obligations	 	94	
Note 18 – Retirement Plans	 	94	
Note 19 – Stockholders’ Equity	 	98	
Note 20 – Noncontrolling Interests	 	98	
Note 21 – Commitments and Contingencies	 	99	
Note 22 – Fair Value Measurements	 	101	
Note 23 – Segment Information	 	102	
Note 24 – Supplemental Information on Oil and Gas Operations (Unaudited)	 	104	
Note 25 – Supplemental Quarterly Financial Information (Unaudited)	 	112	
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 Regist ered 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, 2017 and 2016, 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, 2017, 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, 2017, 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 as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, 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, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company has elected to change its method of accounting for oil and gas exploration and development activities from the full cost method of accounting to the successful efforts method of accounting in 2017.  
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 21, 2018
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Index to Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016*	 	 	2015*	 	
Upstream revenues	 	$	5,307	 	 	$	3,981	 	 	$	5,885	 	
Marketing and midstream revenues	 	 	8,642	 	 	 	6,323	 	 	 	7,260	 	
Total revenues	 	 	13,949	 	 	 	10,304	 	 	 	13,145	 	
Production expenses	 	 	1,823	 	 	 	1,803	 	 	 	2,439	 	
Exploration expenses	 	 	380	 	 	 	215	 	 	 	451	 	
Marketing and midstream expenses	 	 	7,730	 	 	 	5,533	 	 	 	6,461	 	
Depreciation, depletion and amortization	 	 	2,074	 	 	 	2,096	 	 	 	4,022	 	
Asset impairments	 	 	17	 	 	 	1,310	 	 	 	17,647	 	
Asset dispositions	 	 	(217	)	 	 	(1,483	)	 	 	7	 	
General and administrative expenses	 	 	872	 	 	 	865	 	 	 	1,193	 	
Financing costs, net	 	 	498	 	 	 	907	 	 	 	519	 	
Other expenses	 	 	(124	)	 	 	375	 	 	 	264	 	
Total expenses	 	 	13,053	 	 	 	11,621	 	 	 	33,003	 	
Earnings (loss) before income taxes	 	 	896	 	 	 	(1,317	)	 	 	(19,858	)	
Income tax expense (benefit)	 	 	(182	)	 	 	141	 	 	 	(6,213	)	
Net earnings (loss)	 	 	1,078	 	 	 	(1,458	)	 	 	(13,645	)	
Net earnings (loss) attributable to noncontrolling interests	 	 	180	 	 	 	(402	)	 	 	(749	)	
Net earnings (loss) attributable to Devon	 	$	898	 	 	$	(1,056	)	 	$	(12,896	)	
Net earnings (loss) per share attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	1.71	 	 	$	(2.09	)	 	$	(31.72	)	
Diluted	 	$	1.70	 	 	$	(2.09	)	 	$	(31.72	)	
Comprehensive earnings (loss):	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	 	$	1,078	 	 	$	(1,458	)	 	$	(13,645	)	
Other comprehensive earnings, net of tax:	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign currency translation and other	 	 	83	 	 	 	11	 	 	 	(443	)	
Pension and postretirement plans	 	 	29	 	 	 	22	 	 	 	10	 	
Other comprehensive earnings, net of tax	 	 	112	 	 	 	33	 	 	 	(433	)	
Comprehensive earnings (loss)	 	 	1,190	 	 	 	(1,425	)	 	 	(14,078	)	
Comprehensive earnings (loss) attributable to
   noncontrolling interests	 	 	180	 	 	 	(402	)	 	 	(749	)	
Comprehensive earnings (loss) attributable to Devon	 	$	1,010	 	 	$	(1,023	)	 	$	(13,329	)	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
 
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,	 	
 	 	2017	 	 	2016*	 	 	2015*	 	
Cash flows from operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	 	$	1,078	 	 	$	(1,458	)	 	$	(13,645	)	
Adjustments to reconcile net earnings (loss) to net cash
   from operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization	 	 	2,074	 	 	 	2,096	 	 	 	4,022	 	
Exploratory dry hole expense and unproved leasehold impairments	 	 	219	 	 	 	113	 	 	 	248	 	
Asset impairments	 	 	17	 	 	 	1,310	 	 	 	17,647	 	
Gains and losses on asset sales	 	 	(217	)	 	 	(1,483	)	 	 	7	 	
Deferred income tax expense (benefit)	 	 	(294	)	 	 	41	 	 	 	(5,976	)	
Commodity derivatives	 	 	(157	)	 	 	201	 	 	 	(503	)	
Cash settlements on commodity derivatives	 	 	53	 	 	 	1	 	 	 	2,416	 	
Other derivatives and financial instruments	 	 	23	 	 	 	185	 	 	 	(235	)	
Cash settlements on other derivatives and financial instruments	 	 	(6	)	 	 	(143	)	 	 	272	 	
Asset retirement obligation accretion	 	 	62	 	 	 	75	 	 	 	75	 	
Share-based compensation	 	 	198	 	 	 	233	 	 	 	244	 	
Other	 	 	(122	)	 	 	270	 	 	 	312	 	
Net change in working capital	 	 	21	 	 	 	24	 	 	 	(265	)	
Change in long-term other assets	 	 	(46	)	 	 	36	 	 	 	285	 	
Change in long-term other liabilities	 	 	6	 	 	 	(1	)	 	 	(6	)	
Net cash from operating activities	 	 	2,909	 	 	 	1,500	 	 	 	4,898	 	
Cash flows from investing activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(2,759	)	 	 	(2,047	)	 	 	(4,787	)	
Acquisitions of property, equipment and businesses	 	 	(46	)	 	 	(1,641	)	 	 	(1,107	)	
Divestitures of property and equipment	 	 	417	 	 	 	3,113	 	 	 	107	 	
Proceeds from sale of investment	 	 	190	 	 	 	—	 	 	 	—	 	
Other	 	 	(12	)	 	 	(19	)	 	 	(16	)	
Net cash from investing activities	 	 	(2,210	)	 	 	(594	)	 	 	(5,803	)	
Cash flows from financing activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Borrowings of long-term debt, net of issuance costs	 	 	2,376	 	 	 	2,145	 	 	 	4,772	 	
Repayments of long-term debt	 	 	(2,118	)	 	 	(4,409	)	 	 	(2,634	)	
Payment of installment payable	 	 	(250	)	 	 	—	 	 	 	—	 	
Net short-term debt repayments	 	 	—	 	 	 	(626	)	 	 	(307	)	
Early retirement of debt	 	 	(6	)	 	 	(265	)	 	 	—	 	
Issuance of common stock	 	 	—	 	 	 	1,469	 	 	 	—	 	
Sale of subsidiary units	 	 	—	 	 	 	—	 	 	 	654	 	
Issuance of subsidiary units	 	 	501	 	 	 	892	 	 	 	25	 	
Dividends paid on common stock	 	 	(127	)	 	 	(221	)	 	 	(396	)	
Contributions from noncontrolling interests	 	 	57	 	 	 	168	 	 	 	16	 	
Distributions to noncontrolling interests	 	 	(354	)	 	 	(304	)	 	 	(254	)	
Shares exchanged for tax withholdings	 	 	(68	)	 	 	(35	)	 	 	(51	)	
Other	 	 	(2	)	 	 	(10	)	 	 	(13	)	
Net cash from financing activities	 	 	9	 	 	 	(1,196	)	 	 	1,812	 	
Effect of exchange rate changes on cash	 	 	6	 	 	 	(61	)	 	 	(77	)	
Net change in cash and cash equivalents	 	 	714	 	 	 	(351	)	 	 	830	 	
Cash and cash equivalents at beginning of period	 	 	1,959	 	 	 	2,310	 	 	 	1,480	 	
Cash and cash equivalents at end of period	 	$	2,673	 	 	$	1,959	 	 	$	2,310	 	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
 
See accompanying notes to consolidated financial statements.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED BALANCE SHEETS
 
 	 	December 31, 2017	 	 	December 31, 2016*	 	
ASSETS	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	2,673	 	 	$	1,959	 	
Accounts receivable	 	 	1,670	 	 	 	1,356	 	
Assets held for sale	 	 	—	 	 	 	193	 	
Other current assets	 	 	448	 	 	 	264	 	
Total current assets	 	 	4,791	 	 	 	3,772	 	
Oil and gas property and equipment, based on successful efforts
   accounting, net	 	 	13,318	 	 	 	12,998	 	
Midstream and other property and equipment, net	 	 	7,853	 	 	 	7,535	 	
Total property and equipment, net	 	 	21,171	 	 	 	20,533	 	
Goodwill	 	 	2,383	 	 	 	2,383	 	
Other long-term assets	 	 	1,896	 	 	 	1,987	 	
Total assets	 	$	30,241	 	 	$	28,675	 	
LIABILITIES AND EQUITY	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	
Accounts payable	 	$	819	 	 	$	642	 	
Revenues and royalties payable	 	 	1,180	 	 	 	908	 	
Short-term debt	 	 	115	 	 	 	—	 	
Other current liabilities	 	 	1,201	 	 	 	1,066	 	
Total current liabilities	 	 	3,315	 	 	 	2,616	 	
Long-term debt	 	 	10,291	 	 	 	10,154	 	
Asset retirement obligations	 	 	1,113	 	 	 	1,226	 	
Other long-term liabilities	 	 	583	 	 	 	894	 	
Deferred income taxes	 	 	835	 	 	 	1,063	 	
Equity:	 	 	 	 	 	 	 	 	
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued
   525 million and 523 million shares in 2017 and 2016, respectively	 	 	53	 	 	 	52	 	
Additional paid-in capital	 	 	7,333	 	 	 	7,237	 	
Retained earnings (accumulated deficit)	 	 	702	 	 	 	(69	)	
Accumulated other comprehensive earnings	 	 	1,166	 	 	 	1,054	 	
Total stockholders’ equity attributable to Devon	 	 	9,254	 	 	 	8,274	 	
Noncontrolling interests	 	 	4,850	 	 	 	4,448	 	
Total equity	 	 	14,104	 	 	 	12,722	 	
Total liabilities and equity	 	$	30,241	 	 	$	28,675	 	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
 
See accompanying notes to consolidated financial statements.
 
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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	 	
Previously reported as of December 31, 2014	 	 	409	 	 	$	41	 	 	$	4,088	 	 	$	16,631	 	 	$	779	 	 	$	—	 	 	$	4,802	 	 	$	26,341	 	
Effect of change in accounting principle	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(2,227	)	 	 	675	 	 	 	—	 	 	 	—	 	 	 	(1,552	)	
Balance as of December 31, 2014 as recast*	 	 	409	 	 	$	41	 	 	$	4,088	 	 	$	14,404	 	 	$	1,454	 	 	$	—	 	 	$	4,802	 	 	$	24,789	 	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(12,896	)	 	 	—	 	 	 	—	 	 	 	(749	)	 	 	(13,645	)	
Other comprehensive loss, net of tax	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(433	)	 	 	—	 	 	 	—	 	 	 	(433	)	
Stock option exercises	 	 	—	 	 	 	—	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	
Restricted stock grants, net of cancellations	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Common stock repurchased	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(35	)	 	 	—	 	 	 	(35	)	
Common stock retired	 	 	—	 	 	 	—	 	 	 	(35	)	 	 	—	 	 	 	—	 	 	 	35	 	 	 	—	 	 	 	—	 	
Common stock dividends	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(396	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(396	)	
Common stock issued	 	 	7	 	 	 	1	 	 	 	198	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	199	 	
Share-based compensation	 	 	—	 	 	 	—	 	 	 	165	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	165	 	
Share-based compensation tax expense	 	 	—	 	 	 	—	 	 	 	(9	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(9	)	
Subsidiary equity transactions	 	 	—	 	 	 	—	 	 	 	585	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	141	 	 	 	726	 	
Distributions to noncontrolling interests	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(254	)	 	 	(254	)	
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	 	

*	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.	
 
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.	Summary of Significant Accounting Policies	
Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities through its ownership in EnLink and the General Partner.
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.
Change in Accounting Principle and Presentation Changes
In the fourth quarter of 2017, Devon changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method. In accordance with FASB ASC 250 “ Accounting Changes and Error Corrections ,” financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “ Extractive Activities—Oil and Gas .” Although the full cost method of accounting for oil and gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the preferred method and is more widely used in the industry and will improve comparison to Devon’s peer group . Devon believes the successful efforts method provides a more transparent representation of its results of operations. The successful efforts method also provides our investments in oil and gas properties to be assessed for impairment as of the balance sheet date in accordance with FASB ASC 360 “ Property, Plant and Equipment ” rather than valuations based on 12-month historical prices and costs prescribed under the full cost method. For more detailed information regarding the effects of the change in accounting principle to the successful efforts method, see Note 2 .
As Devon recast its financial statements to the successful efforts method, the financial statements and disclosures were examined through the lens of simplicity and transparency. From this assessment, certain changes were made to the financial statement presentation not specifically required by the successful efforts method of accounting. In general, Devon sought to simplify the presentation of its consolidated comprehensive statements of earnings and provide expanded and improved disclosures of key components in its operating results. These presentation judgments improve the clarity and utility of the financial operating results for investors and other stakeholders. As a result, certain prior period amounts have been reclassified to align to this new approach. To ensure financial statement users clearly understand the changes, a description of each enhancement is provided below.
 	•	Operating income – Devon previously segregated expenses between operating and nonoperating on the statement of operations. The only material nonoperating expense was generally financing costs. Devon streamlined the overall comprehensive statements of earnings by eliminating the operating income distinction.	
 	•	Upstream revenues – On the statement of operations, Devon is combining sales of oil, gas and NGL volumes, as well as oil, gas and NGL derivative activity, into this new line item. With the streamlined presentation of upstream revenues, MD&A and other disclosures of these items were expanded.	
 	•	Production expenses – Similar to streamlining the presentation of upstream revenues, Devon is simplifying the presentation of cash-based expenses associated with upstream production. Previously these expenses were reported separately as lease operations and production and property taxes in the comprehensive statements of earnings. These items are now combined in this new line item. Devon has expanded the MD&A and other disclosures of expenses for lease operations, gathering and transportation, production taxes and property taxes.	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	•	Asset impairments – Except for unproved oil and gas property impairments, this line item will capture all impairments of Devon’s assets. After research of peers, Devon decided to report unproved impairments as part of exploration expenses. Because asset impairments are non-routine adjustments to the cost basis of assets, this item was placed adjacent to DD&A, the routine adjustment of the cost basis of assets, on the comprehensive statements of earnings.	
 	•	Asset dispositions – This line item will capture gains and losses from dispositions of assets. As a full cost company, Devon rarely had material gains and losses on asset dispositions. However, when it did, such amounts were reported as part of revenues. Devon has more gains and losses under the successful efforts method of accounting. Since recognizing gains and losses on asset dispositions are largely affected by previously recognized DD&A and asset impairments, this item was placed adjacent to those items on the comprehensive statements of earnings.	
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.
Devon completed a business combination in 2014 whereby Devon controls both EnLink and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.
Use of Estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
 	•	proved reserves and related present value of future net revenues;	
 	•	evaluation of suspended well costs;	
 	•	the carrying and fair values of oil and gas properties, midstream assets and product and equipment inventories;	
 	•	derivative financial instruments;	
 	•	the fair value of reporting units and related assessment of goodwill for impairment;	
 	•	the fair value of intangible assets other than goodwill;	
 	•	income taxes;	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	•	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.	
Revenue Recognition
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title typically is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. 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.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2017, 2016 and 2015, 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. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps, costless price collars and call options. 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. The 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 to the collars. The call options give counterparties the right to purchase production at a predetermined price.
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, 2017, 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
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2017, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets.
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, 2017, 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
Independent of EnLink, Devon grants share-based awards to members of its Board of Directors and select employees. EnLink and the General Partner also grant 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 7 , certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying 2016 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 and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable 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. Under this method 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
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
successful 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”) in accordance with ASC 932 “ Extractive Activities – Oil and Gas ” 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)
 
Midstream and Other Property and Equipment
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using the straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.

Asset Retirement Obligations
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an 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 an assessment of qualitative and quantitative factors. The 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, then goodwill is written down to the fair value of the goodwill through a charge to expense. 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 and EnLink performed annual impairment tests of goodwill in the fourth quarters of 2017, 2016 and 2015. No impairment was required as a result of the annual tests in 2017 or 2016; however, sustained weakness in the overall energy sector driven by lower commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units. See Note 14 for further discussion.
Intangible Assets
Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10 to 20 years. During 2017, 2016 and 2015, EnLink’s customer relationships were also evaluated for impairment, and in 2015, a portion of these intangible assets was considered impaired. See Note 14 for further discussion.
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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.
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 2017, Devon adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting . Its objective is to simplify several aspects of the accounting for share-based payments, including income taxes when awards vest or are settled, statutory withholding and forfeitures. As the result of adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefits and deficiencies in the consolidated comprehensive statements of
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
earnings and as operating cash flows in the consolidated statements of cash flows. Devon also retrospectively applied the new cash flow statement guidance dictating the presentation of shares exchanged for tax-withholding purposes as a financing activity. The adoption of the new guidance did not materially impact the consolidated financial statements for the year ended December 31, 2017 or previously reported financial information but could have a more material future impact.
In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill And Other (Topic 350) , Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test. Under ASU 2017-04, an entity should perform its goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, Devon elected to early adopt ASU 2017-04. The adoption had no impact on the consolidated financial statements.
Issued Accounting Standards Not Yet Adopted
  
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which established ASC Topic 606, Revenue from Contracts with Customers (ASC 606). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (ASU 2016-12), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. Devon will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018.  
 
Devon has aggregated and reviewed its contracts that are within the scope of ASC 606. Based on its evaluation, Devon does not anticipate the adoption of ASC 606 will have a material impact on its balance sheet or related consolidated statements of earnings, equity or cash flows . Accordingly, Devon will continue to recognize revenue at the time commodities are delivered. However, ASC 606 will affect how certain transactions are presented in its financial statements. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Devon will change its presentation of certain processing arrangements from a net presentation to a gross presentation. This change will impact Devon’s upstream revenues and production expenses by approximately $250 million for 2016 and 2017, and will impact 2018 by a similar amount . EnLink will change the presentation of certain marketing and midstream revenues to marketing and midstream operating expenses or from marketing and midstream operating expenses to marketing and midstream revenues. Devon estimates this reclassification will result in a net decrease in EnLink’s marketing and midstream revenues of approximately 6-10%. These estimates are based on historical information and could change based on future volumes and commodity prices. These presentation changes will have no impact on net earnings or cash flows.
65

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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Based on the disclosure requirements of ASC 606, upon adoption, Devon expects to provide expanded disclosures relating to its revenue recognition policies and how these relate to its revenue-generating contractual performance obligations. In addition, Devon expects to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of its revenues.  
 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. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019. Early adoption is permitted, but Devon does not plan to early adopt. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. However, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842), Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The proposed ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented.  Devon is in the process of evaluating contracts and gathering the necessary terms and data elements for purposes of determining the impact this ASU will have on its consolidated financial statements and related disclosures. Recently, the FASB issued ASU No. 2018-01, Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842 . This ASU would permit an entity not to apply Topic 842 to land easements and rights-of-way that exist or expired before the effective date of Topic 842 and that were not previously assessed under Topic 840. An entity would continue to apply its current accounting policy for accounting for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements and rights-of-way to determine whether the arrangement should be accounted for as a lease. For Devon, these contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.
Based on continuing research, Devon estimates a large number of contracts and data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective. Devon has preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact the adoption will have on its consolidated financial statements. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls and is evaluating technology requirements and solutions needed to comply with the requirements of this ASU. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities.
 
The FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU will require 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. This ASU is effective for Devon beginning January 1, 2018, and income statement presentation changes will be applied retrospectively, while service cost component capitalization will be applied prospectively. Upon adoption of this ASU, Devon will reclassify $7 million, $14 million and $16 million of non-service cost components of net periodic benefit costs for 2017, 2016 and 2015, respectively, as other expenses. Such amounts are currently classified in Devon’s G&A. No other changes upon adopting this ASU are expected to be material.
 
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The FASB issued 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. This reconciliation can be presented either on the face of the consolidated statement of cash flows or in the notes to the financial statements. This ASU is effective for Devon beginning January 1, 2018, and will be applied retrospectively. Currently, Devon does not expect the adoption to have a material impact on its consolidated statement of cash flows.
 
The FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This ASU clarifies the definition of a business to assist entities with evaluating whether a set of transferred assets and activities should be accounted for as an acquisition or disposals of assets or as a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires that a set of assets must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for Devon beginning January 1, 2018, and will be applied prospectively. Devon does not expect the adoption to have a material impact on its consolidated financial statements; however these amendments could result in the recording of fewer business combinations in future periods.
 
The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This ASU will expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company's risk management activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This ASU only applies to entities that elect hedge accounting, which Devon has not for derivative financial instruments during the three year period ended December 31, 2017. This ASU is effective for annual and interim periods beginning January 1, 2019, with early adoption permitted in 2018. The ASU is required to be adopted using a cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements if hedge accounting were elected by Devon in the future.  

 2. Change in Accounting Principle
In the fourth quarter of 2017, Devon changed its method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. In addition, gains or losses, if applicable, are recognized more frequently on the dispositions of oil and gas property and equipment under the successful efforts method. Devon has recast certain historical information for all periods presented, including the Consolidated Comprehensive Statements of Earnings, Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Equity and related information in Notes 1 ,  2 ,  3 ,  5 ,  6 ,  7 ,  8 ,  9 ,  10 ,  11 ,  13 ,  14 ,  16 ,  22 ,  23 ,  24 and  25 .
The following tables present the effects of the change to the successful efforts method in the consolidated financial statements.
 
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	 	Changes to the Consolidated Comprehensive	 	
 	 	Statement of Earnings	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2017	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Exploration expenses	 	$	—	 	 	$	380	 	 	$	380	 	
Depreciation, depletion and amortization	 	 	1,579	 	 	 	495	 	 	 	2,074	 	
Asset dispositions	 	 	(5	)	 	 	(212	)	 	 	(217	)	
General and administrative expenses	 	 	682	 	 	 	190	 	 	 	872	 	
Financing costs, net	 	 	494	 	 	 	4	 	 	 	498	 	
Other expenses	 	 	(102	)	 	 	(22	)	 	 	(124	)	
Earnings before income taxes	 	 	1,731	 	 	 	(835	)	 	 	896	 	
Income tax benefit	 	 	(140	)	 	 	(42	)	 	 	(182	)	
Net earnings	 	 	1,871	 	 	 	(793	)	 	 	1,078	 	
Net earnings attributable to Devon	 	 	1,691	 	 	 	(793	)	 	 	898	 	
Net earnings per share attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	3.22	 	 	 	(1.51	)	 	 	1.71	 	
Diluted	 	 	3.20	 	 	 	(1.50	)	 	 	1.70	 	
Comprehensive earnings:	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	1,871	 	 	 	(793	)	 	 	1,078	 	
Foreign currency translation and other	 	 	4	 	 	 	79	 	 	 	83	 	
Comprehensive earnings	 	 	1,904	 	 	 	(714	)	 	 	1,190	 	
Comprehensive earnings attributable to Devon	 	 	1,724	 	 	 	(714	)	 	 	1,010	 	
 
 	 	Changes to the Consolidated Comprehensive	 	
 	 	Statement of Earnings	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2016	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Exploration expenses	 	$	—	 	 	$	215	 	 	$	215	 	
Depreciation, depletion and amortization	 	 	1,792	 	 	 	304	 	 	 	2,096	 	
Asset impairments	 	 	4,975	 	 	 	(3,665	)	 	 	1,310	 	
Asset dispositions	 	 	(1,887	)	 	 	404	 	 	 	(1,483	)	
General and administrative expenses	 	 	658	 	 	 	207	 	 	 	865	 	
Financing costs, net	 	 	904	 	 	 	3	 	 	 	907	 	
Other expenses	 	 	403	 	 	 	(28	)	 	 	375	 	
Loss before income taxes	 	 	(3,877	)	 	 	2,560	 	 	 	(1,317	)	
Income tax expense (benefit)	 	 	(173	)	 	 	314	 	 	 	141	 	
Net loss	 	 	(3,704	)	 	 	2,246	 	 	 	(1,458	)	
Net loss attributable to Devon	 	 	(3,302	)	 	 	2,246	 	 	 	(1,056	)	
Net loss per share attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	(6.52	)	 	 	4.43	 	 	 	(2.09	)	
Diluted	 	 	(6.52	)	 	 	4.43	 	 	 	(2.09	)	
Comprehensive loss:	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	(3,704	)	 	 	2,246	 	 	 	(1,458	)	
Foreign currency translation and other	 	 	32	 	 	 	(21	)	 	 	11	 	
Comprehensive loss	 	 	(3,650	)	 	 	2,225	 	 	 	(1,425	)	
Comprehensive loss attributable to Devon	 	 	(3,248	)	 	 	2,225	 	 	 	(1,023	)	
 
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	 	Changes to the Consolidated Comprehensive	 	
 	 	Statement of Earnings	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2015	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Exploration expenses	 	$	—	 	 	$	451	 	 	$	451	 	
Depreciation, depletion and amortization	 	 	3,129	 	 	 	893	 	 	 	4,022	 	
Asset impairments	 	 	20,820	 	 	 	(3,173	)	 	 	17,647	 	
Asset dispositions	 	 	—	 	 	 	7	 	 	 	7	 	
General and administrative expenses	 	 	868	 	 	 	325	 	 	 	1,193	 	
Financing costs, net	 	 	517	 	 	 	2	 	 	 	519	 	
Other expenses	 	 	179	 	 	 	85	 	 	 	264	 	
Loss before income taxes	 	 	(21,268	)	 	 	1,410	 	 	 	(19,858	)	
Income tax benefit	 	 	(6,065	)	 	 	(148	)	 	 	(6,213	)	
Net loss	 	 	(15,203	)	 	 	1,558	 	 	 	(13,645	)	
Net loss attributable to Devon	 	 	(14,454	)	 	 	1,558	 	 	 	(12,896	)	
Net loss per share attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	(35.55	)	 	 	3.83	 	 	 	(31.72	)	
Diluted	 	 	(35.55	)	 	 	3.83	 	 	 	(31.72	)	
Comprehensive loss:	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	(15,203	)	 	 	1,558	 	 	 	(13,645	)	
Foreign currency translation and other	 	 	(559	)	 	 	116	 	 	 	(443	)	
Comprehensive loss	 	 	(15,752	)	 	 	1,674	 	 	 	(14,078	)	
Comprehensive loss attributable to Devon	 	 	(15,003	)	 	 	1,674	 	 	 	(13,329	)	
 
 	 	Changes to the Consolidated	 	
 	 	Statement of Cash Flows	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2017	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Net earnings	 	$	1,871	 	 	$	(793	)	 	$	1,078	 	
Depreciation, depletion and amortization	 	 	1,579	 	 	 	495	 	 	 	2,074	 	
Exploratory dry hole expense and unproved
   leasehold impairments	 	 	—	 	 	 	219	 	 	 	219	 	
Gains and losses on asset sales	 	 	(5	)	 	 	(212	)	 	 	(217	)	
Deferred income tax benefit	 	 	(252	)	 	 	(42	)	 	 	(294	)	
Share-based compensation	 	 	158	 	 	 	40	 	 	 	198	 	
Other	 	 	(108	)	 	 	(14	)	 	 	(122	)	
Net cash from operating activities	 	 	3,216	 	 	 	(307	)	 	 	2,909	 	
Capital expenditures	 	 	(3,074	)	 	 	315	 	 	 	(2,759	)	
Divestitures of property and equipment	 	 	425	 	 	 	(8	)	 	 	417	 	
Net cash from investing activities	 	 	(2,517	)	 	 	307	 	 	 	(2,210	)	
 
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	 	Changes to the Consolidated	 	
 	 	Statement of Cash Flows	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2016	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Net loss	 	$	(3,704	)	 	$	2,246	 	 	$	(1,458	)	
Depreciation, depletion and amortization	 	 	1,792	 	 	 	304	 	 	 	2,096	 	
Exploratory dry hole expense and unproved
   leasehold impairments	 	 	—	 	 	 	113	 	 	 	113	 	
Asset impairments	 	 	4,975	 	 	 	(3,665	)	 	 	1,310	 	
Gains and losses on asset sales	 	 	(1,887	)	 	 	404	 	 	 	(1,483	)	
Deferred income tax expense (benefit)	 	 	(273	)	 	 	314	 	 	 	41	 	
Share-based compensation	 	 	194	 	 	 	39	 	 	 	233	 	
Other	 	 	303	 	 	 	(33	)	 	 	270	 	
Net cash from operating activities	 	 	1,778	 	 	 	(278	)	 	 	1,500	 	
Capital expenditures	 	 	(2,330	)	 	 	283	 	 	 	(2,047	)	
Divestitures of property and equipment	 	 	3,118	 	 	 	(5	)	 	 	3,113	 	
Net cash from investing activities	 	 	(872	)	 	 	278	 	 	 	(594	)	
 
 	 	Changes to the Consolidated	 	
 	 	Statement of Cash Flows	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2015	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Net loss	 	$	(15,203	)	 	$	1,558	 	 	$	(13,645	)	
Depreciation, depletion and amortization	 	 	3,129	 	 	 	893	 	 	 	4,022	 	
Exploratory dry hole expense and unproved
   leasehold impairments	 	 	—	 	 	 	248	 	 	 	248	 	
Asset impairments	 	 	20,820	 	 	 	(3,173	)	 	 	17,647	 	
Gains and losses on asset sales	 	 	—	 	 	 	7	 	 	 	7	 	
Deferred income tax benefit	 	 	(5,828	)	 	 	(148	)	 	 	(5,976	)	
Share-based compensation	 	 	181	 	 	 	63	 	 	 	244	 	
Other	 	 	281	 	 	 	31	 	 	 	312	 	
Net cash from operating activities	 	 	5,419	 	 	 	(521	)	 	 	4,898	 	
Capital expenditures	 	 	(5,308	)	 	 	521	 	 	 	(4,787	)	
Net cash from investing activities	 	 	(6,324	)	 	 	521	 	 	 	(5,803	)	
 
 	 	Changes to the Consolidated Balance Sheet	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2017	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Oil and gas property and equipment, net	 	$	9,702	 	 	 	3,616	 	 	$	13,318	 	
Total property and equipment, net	 	 	17,555	 	 	 	3,616	 	 	 	21,171	 	
Goodwill	 	 	3,964	 	 	 	(1,581	)	 	 	2,383	 	
Total assets	 	 	28,206	 	 	 	2,035	 	 	 	30,241	 	
Deferred income taxes	 	 	434	 	 	 	401	 	 	 	835	 	
Additional paid-in capital	 	 	7,206	 	 	 	127	 	 	 	7,333	 	
Retained earnings	 	 	44	 	 	 	658	 	 	 	702	 	
Accumulated other comprehensive earnings	 	 	317	 	 	 	849	 	 	 	1,166	 	
Total stockholders’ equity attributable to Devon	 	 	7,620	 	 	 	1,634	 	 	 	9,254	 	
Total equity	 	 	12,470	 	 	 	1,634	 	 	 	14,104	 	
Total liabilities and equity	 	 	28,206	 	 	 	2,035	 	 	 	30,241	 	
 
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	 	Changes to the Consolidated Balance Sheet	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Year Ended December 31, 2016	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Oil and gas property and equipment, net	 	$	8,655	 	 	$	4,343	 	 	$	12,998	 	
Total property and equipment, net	 	 	16,190	 	 	 	4,343	 	 	 	20,533	 	
Goodwill	 	 	3,964	 	 	 	(1,581	)	 	 	2,383	 	
Total assets	 	 	25,913	 	 	 	2,762	 	 	 	28,675	 	
Deferred income taxes	 	 	648	 	 	 	415	 	 	 	1,063	 	
Accumulated deficit	 	 	(1,646	)	 	 	1,577	 	 	 	(69	)	
Accumulated other comprehensive earnings	 	 	284	 	 	 	770	 	 	 	1,054	 	
Total stockholders’ equity attributable to Devon	 	 	5,927	 	 	 	2,347	 	 	 	8,274	 	
Total equity	 	 	10,375	 	 	 	2,347	 	 	 	12,722	 	
Total liabilities and equity	 	 	25,913	 	 	 	2,762	 	 	 	28,675	 	

3 .	Acquisitions and Divestitures	
Devon Acquisitions
In January 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $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.
In December 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. The allocation of the purchase price was $393 million to unproved properties and $106 million to proved properties.
Devon Asset Divestitures
Upstream Assets
In May 2017, Devon announced a program to divest approximately $1 billion of upstream assets. The non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through December 31, 2017, Devon completed divestiture transactions with proceeds totaling approximately $415 million, before purchase price adjustments, and a net gain of $212 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves. Devon’s remaining divestiture of Johnson County assets is expected to close in 2018.
During 2016, in several separate transactions with different purchasers, Devon divested non-core assets located in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. The following table presents a summary of Devon’s divestiture activity for 2016.
 
Date	 	Proceeds Received	 	 	Gains on Sale	 	 	Proved Reserves
(MMBoe)	 	 	Percentage of U.S. Proved Reserves	 	
Second quarter 2016	 	$	200	 	 	$	83	 	 	 	11	 	 	 	1	%	
Third quarter 2016	 	 	1,653	 	 	 	726	 	 	 	146	 	 	 	9	%	
Total	 	$	1,853	 	 	$	809	 	 	 	157	 	 	 	10	%	
71

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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

These divestitures in 2017 and 2016 primarily related to sales of entire common operating fields. Therefore, Devon recognized a gain on the transactions. As part of the gain computations, approximately $290 million of asset retirement obligations were assumed by purchasers and $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.
EnLink Acquisitions
In January 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.4 billion. The purchase price was $1.0 billion to intangible assets and approximately $400 million to property and equipment. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily financed with the issuance of EnLink preferred units. The remaining $500 million of the purchase price was to be paid within one year with the option to defer $250 million of the final payment 24 months from the close date. The first installment payment of $250 million was paid in January 2017 using divestiture proceeds, proceeds from equity issuances and borrowings under EnLink’s credit facility. T he remaining $250 million payment is reported in other current liabilities in the accompanying consolidated balance sheets and was made in January 2018 using proceeds from equity issuances and borrowings under EnLink’s credit facility.  
In August 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $251 million of existing non-monetary assets and cash to the joint venture and had committed an additional $285 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including cash contributions of approximately $144 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.
In November 2016, EnLink entered into a gathering and compression joint venture with a commitment of approximately $40 million to expand its midstream assets in the STACK. The joint venture is initially owned 30% by EnLink and 70% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $29 million in cash for new infrastructure build. After the initial capital commitment, EnLink and the joint venture partner will be responsible for their proportionate share of capital costs.
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The following table presents a summary of EnLink’s acquisition activity for 2015.
 
 	 	 	 	Purchase Price	 	 	Allocation	 	
Date	 	Midstream assets	 	Cash	 	 	EnLink
Units	 	 	PP&E	 	 	Goodwill	 	 	Intangibles	 	 	Other	 	
January 2015	 	Permian Basin	 	$	108	 	 	 	—	 	 	$	30	 	 	$	30	 	 	$	43	 	 	$	5	 	
March 2015	 	Permian Basin	 	$	240	 	 	$	360	 	 	$	302	 	 	$	18	 	 	$	281	 	 	$	(1	)	
October 2015	 	Delaware Basin	 	$	141	 	 	 	—	 	 	$	36	 	 	$	11	 	 	$	99	 	 	$	(5	) )	
 
EnLink Asset Divestitures and Dropdowns
In December 2016, EnLink entered into definitive agreements to divest approximately $278 million of certain non-core midstream assets. As of December 31, 2016, these assets were classified as held for sale. D uring the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.
In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.
In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.

4.	 Derivative Financial Instruments	
Commodity Derivatives
As of December 31, 2017, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second 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 2018	 	 	49,625	 	 	$	52.13	 	 	 	51,860	 	 	$	46.06	 	 	$	56.06	 	
Q1-Q4 2019	 	 	7,307	 	 	$	52.22	 	 	 	6,559	 	 	$	45.82	 	 	$	55.82	 	
 
 	 	Oil Basis Swaps	 	 	Oil Basis Collars	 	
Period	 	Index	 	Volume
(Bbls/d)	 	 	Weighted Average
Differential to WTI
($/Bbl)	 	 	Volume
(Bbls/d)	 	 	Weighted
Average Floor
Differential to WTI ($/Bbl)	 	 	Weighted
Average Ceiling
Differential to WTI ($/Bbl)	 	
Q1-Q4 2018	 	Midland Sweet	 	 	23,000	 	 	$	(1.02	)	 	 	—	 	 	$	—	 	 	$	—	 	
Q1-Q4 2018	 	Argus LLS	 	 	12,000	 	 	$	3.95	 	 	 	—	 	 	$	—	 	 	$	—	 	
Q1-Q4 2018	 	Western Canadian Select	 	 	75,490	 	 	$	(14.84	)	 	 	1,830	 	 	$	(15.50	)	 	$	(13.93	)	
Q1-Q4 2019	 	Midland Sweet	 	 	27,000	 	 	$	(0.47	)	 	 	—	 	 	$	—	 	 	$	—	 	
 
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
As of December 31, 2017, 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 2018	 	 	371,956	 	 	$	3.06	 	 	 	197,516	 	 	$	2.94	 	 	$	3.26	 	
Q1-Q4 2019	 	 	28,466	 	 	$	2.98	 	 	 	28,466	 	 	$	2.84	 	 	$	3.14	 	
 
 	 	Natural Gas Basis Swaps	 	
Period	 	Index	 	Volume
(MMBtu/d)	 	 	Weighted Average
Differential to
Henry Hub
($/MMBtu)	 	
Q1-Q4 2018	 	Panhandle Eastern Pipe Line	 	 	50,000	 	 	$	(0.29	)	
 
As of December 31, 2017, 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 2018	 	Ethane	 	 	6,747	 	 	$	11.89	 	
Q1-Q4 2018	 	Natural Gasoline	 	 	5,500	 	 	$	54.24	 	
Q1-Q4 2018	 	Normal Butane	 	 	6,750	 	 	$	38.46	 	
Q1-Q4 2018	 	Propane	 	 	9,500	 	 	$	33.19	 	
 
As of December 31, 2017, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.
 
Period	 	Product	 	Volume (Total)	 	Weighted Average Price Paid	 	Weighted Average Price Received	
Q1-Q4 2018	 	Propane	 	 	681	 	MBbls	 	Index	 	$0.88/gal	
Q1 2018-Q1 2019	 	Natural Gas	 	 	122,629	 	MMBtu/d	 	Index	 	$2.57/MMBtu	
 
Interest Rate Derivatives
As of December 31, 2017, Devon had the following open interest rate derivative positions:
 
Notional	 	 	Rate Received	 	 	Rate Paid	 	 	Expiration	
$	750	 	 	Three Month LIBOR	 	 	2.98%	 	 	December 2048 (1)	
$	100	 	 	1.76%	 	 	Three Month LIBOR	 	 	January 2019	

(1)	Mandatory settlement in December 2018.	

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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Commodity derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream revenues	 	$	157	 	 	$	(201	)	 	$	503	 	
Marketing and midstream revenues	 	 	(1	)	 	 	(13	)	 	 	9	 	
Interest rate derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	
Other expenses	 	 	(22	)	 	 	(19	)	 	 	(20	)	
Foreign currency derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	
Other expenses	 	 	—	 	 	 	(153	)	 	 	246	 	
Net gains (losses) recognized	 	$	134	 	 	$	(386	)	 	$	738	 	
 
The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.
 
 	 	December 31, 2017	 	 	December 31, 2016	 	
Commodity derivative assets:	 	 	 	 	 	 	 	 	
Other current assets	 	$	209	 	 	$	9	 	
Other long-term assets	 	 	2	 	 	 	1	 	
Interest rate derivative assets:	 	 	 	 	 	 	 	 	
Other current assets	 	 	1	 	 	 	1	 	
Total derivative assets	 	$	212	 	 	$	11	 	
Commodity derivative liabilities:	 	 	 	 	 	 	 	 	
Other current liabilities	 	$	267	 	 	$	187	 	
Other long-term liabilities	 	 	27	 	 	 	16	 	
Interest rate derivative liabilities:	 	 	 	 	 	 	 	 	
Other current liabilities	 	 	64	 	 	 	—	 	
Other long-term liabilities	 	 	—	 	 	 	41	 	
Total derivative liabilities	 	$	358	 	 	$	244	 	

5.	Share-Based Compensation	
In the second quarter of 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.
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The vesting for certain share-based awards was accelerated in 2016 in conjunction with the reduction of workforce described in Note 7 . Approximately $60 million of associated expense for these accelerated awards is included in other expenses 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,	 	
 	 	2017	 	 	2016	 	 	2015	 	
G&A	 	$	141	 	 	$	124	 	 	$	185	 	
Exploration expenses	 	 	7	 	 	 	6	 	 	 	9	 	
Total Devon	 	 	148	 	 	 	130	 	 	 	194	 	
G&A	 	 	37	 	 	 	24	 	 	 	31	 	
Marketing and midstream expenses	 	 	11	 	 	 	7	 	 	 	5	 	
Total EnLink	 	 	48	 	 	 	31	 	 	 	36	 	
Total	 	$	196	 	 	$	161	 	 	$	230	 	
Related income tax benefit	 	$	6	 	 	$	6	 	 	$	67	 	
 
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 12/31/16	 	 	6,407	 	 	$	34.40	 	 	 	585	 	 	$	37.60	 	 	 	2,604	 	 	 	 	 	$	46.66	 	
Granted	 	 	2,691	 	 	$	44.87	 	 	 	223	 	 	$	44.85	 	 	 	1,010	 	 	 	 	 	$	52.58	 	
Vested	 	 	(2,431	)	 	$	39.51	 	 	 	(233	)	 	$	41.27	 	 	 	(832	)	 	 	 	 	$	78.19	 	
Forfeited	 	 	(339	)	 	$	35.92	 	 	 	—	 	 	$	—	 	 	 	(24	)	 	 	 	 	$	40.70	 	
Unvested at 12/31/17	 	 	6,328	 	 	$	36.81	 	 	 	575	 	 	$	38.92	 	 	 	2,758	 	 	(1	)	 	$	41.21	 	

(1)	A maximum of 5.5 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.
 
 	 	2017	 	 	2016	 	 	2015	 	
Restricted Stock Awards and Units	 	$	105	 	 	$	73	 	 	$	101	 	
Performance-Based Restricted Stock Awards	 	$	10	 	 	$	5	 	 	$	8	 	
Performance Share Units	 	$	38	 	 	$	13	 	 	$	22	 	
 
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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, 2017.
 
 	 	 	 	 	 	Performance-Based	 	 	 	 	 	
 	 	Restricted Stock	 	 	Restricted Stock	 	 	Performance	 	
 	 	Awards and Units	 	 	Awards	 	 	Share Units	 	
Unrecognized compensation cost	 	$	135	 	 	$	5	 	 	$	28	 	
Weighted average period for recognition (years)	 	 	2.4	 	 	 	1.6	 	 	 	1.9	 	
 
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.
Performance-Based Restricted Stock Awards
Performance-based restricted stock awards are 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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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.
 
 	 	2017	 	 	2016	 	 	2015	 	
Grant-date fair value	 	$	51.05	 	 	—	 	$	53.12	 	 	$	9.24	 	 	—	 	$	10.61	 	 	$	81.99	 	 	—	 	$	85.05	 	
Risk-free interest rate	 	1.50%	 	 	0.94%	 	 	1.06%	 	
Volatility factor	 	45.8%	 	 	37.7%	 	 	26.2%	 	
Contractual term (years)	 	2.89	 	 	2.83	 	 	2.89	 	
 
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 2017, 2016 and 2015. 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, 2016	 	 	2,532	 	 	$	68.06	 	 	 	 	 	 	 	 	 	
Expired	 	 	(786	)	 	$	63.67	 	 	 	 	 	 	 	 	 	
Outstanding at December 31, 2017	 	 	1,746	 	 	$	70.04	 	 	 	1.33	 	 	$	—	 	
Exercisable at December 31, 2017	 	 	1,746	 	 	$	70.04	 	 	 	1.33	 	 	$	—	 	
 
The aggregate intrinsic value of stock options that were exercised during 2015 was $0.2 million. As of December 31, 2017, Devon had no unrecognized compensation cost related to unvested stock options.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
EnLink Share-Based Awards
In March 2017, the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees. The combined grant date fair value was $10 million, and the total cost was recognized in the first quarter of 2017 due to the awards vesting immediately.
The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of December 31, 2017.
 
 	 	General Partner	 	 	EnLink	 	
 	 	Restricted	 	 	Performance	 	 	Restricted	 	 	Performance	 	
 	 	Incentive Units	 	 	Units	 	 	Incentive Units	 	 	Units	 	
Unrecognized compensation cost	 	$	11	 	 	$	5	 	 	$	12	 	 	$	5	 	
Weighted average period for recognition (years)	 	 	1.7	 	 	 	1.8	 	 	 	1.7	 	 	 	1.8	 	

 
6.	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,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Proved oil and gas assets	 	$	—	 	 	$	435	 	 	$	16,076	 	
EnLink goodwill	 	 	—	 	 	 	873	 	 	 	1,328	 	
EnLink other intangible assets	 	 	—	 	 	 	—	 	 	 	223	 	
Other assets	 	 	17	 	 	 	2	 	 	 	20	 	
Total asset impairments	 	$	17	 	 	$	1,310	 	 	$	17,647	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Unproved impairments	 	$	217	 	 	$	77	 	 	$	260	 	
 
Proved Oil and Gas Impairments
In 2015 and 2016, Devon impaired a significant portion of its U.S. oil and gas portfolio due to lower forecasted oil, gas and NGL prices.
EnLink Goodwill and Other Intangible Assets Impairments
In 2016 and 2015, Devon recognized goodwill and other intangible asset impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 14 .
Unproved   Impairments
In 2017, 2016 and 2015, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
7.	Other Expenses	
The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statement of earnings.
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Foreign exchange (gain) loss, net	 	$	(132	)	 	$	39	 	 	$	25	 	
Asset retirement obligation accretion	 	 	62	 	 	 	75	 	 	 	75	 	
Restructuring and transaction costs	 	 	—	 	 	 	267	 	 	 	78	 	
Other, net	 	 	(54	)	 	 	(6	)	 	 	86	 	
Total	 	$	(124	)	 	$	375	 	 	$	264	 	
 
Certain of Devon’s non-Canadian foreign subsidiaries have a U.S. dollar functional currency, hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. During 2017, Devon recognized foreign exchange gains related to these activities resulting from the weakening of the U.S. dollar in relation to the Canadian dollar.
 
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, 2015	 	$	13	 	 	$	63	 	 	$	76	 	
Changes related to prior years' restructurings	 	 	35	 	 	 	(1	)	 	 	34	 	
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	 	
 
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.
In 2015, Devon recognized $24 million of employee-related and other costs associated with the reduction in workforce made subsequent to the completion of the Jackfish development projects and a decrease in planned Canadian capital investment resulting from the drop in commodity prices.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
As part of the U.S. corporate headquarters office consolidation, Devon recognized an additional $54 million expense in 2015, due to the inability to fully sublease remaining office space.
Transaction Costs
In 2016, Devon and EnLink recognized $17 million in transaction costs primarily associated with the closing of the acquisitions discussed in Note 3 .

8.	 Income Taxes	
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Current income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. federal	 	$	10	 	 	$	5	 	 	$	(243	)	
Various states	 	 	—	 	 	 	(11	)	 	 	(8	)	
Canada and various provinces	 	 	102	 	 	 	106	 	 	 	14	 	
Total current tax expense (benefit)	 	 	112	 	 	 	100	 	 	 	(237	)	
Deferred income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. federal	 	 	(192	)	 	 	(3	)	 	 	(5,487	)	
Various states	 	 	(5	)	 	 	—	 	 	 	(332	)	
Canada and various provinces	 	 	(97	)	 	 	44	 	 	 	(157	)	
Total deferred tax expense (benefit)	 	 	(294	)	 	 	41	 	 	 	(5,976	)	
Total income tax expense (benefit)	 	$	(182	)	 	$	141	 	 	$	(6,213	)	
 
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following:
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Total income tax expense (benefit)	 	$	(182	)	 	$	141	 	 	$	(6,213	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. statutory income tax rate	 	 	35	%	 	 	35	%	 	 	35	%	
Non-deductible goodwill and intangible impairment	 	 	0	%	 	 	(23	%)	 	 	(3	%)	
U.S. Tax Reform	 	 	8	%	 	 	0	%	 	 	0	%	
Legal entity restructuring	 	 	(81	%)	 	 	6	%	 	 	0	%	
Other	 	 	(13	%)	 	 	0	%	 	 	1	%	
Deferred tax asset valuation allowance	 	 	31	%	 	 	(29	%)	 	 	(2	%)	
Effective income tax rate	 	 	(20	%)	 	 	(11	%)	 	 	31	%	
 
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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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 judgements 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.
2017
On December 22, 2017, the Tax Reform Legislation was enacted into law and contains several key tax provisions that affect 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, among others. Devon is 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.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, Devon considers the accounting of the transition tax, deferred tax remeasurements, and other items to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. Devon expects to complete its analysis within the measurement period in accordance with SAB 118. Provisional amounts recorded this quarter are as follows:
(a) Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings.  
(b) Devon’s U.S. segment recognized $108 million in deferred tax expense and EnLink recognized $211 million in deferred tax benefit related to the reduction of the U.S. corporate income tax rate to 21%.
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.
Throughout 2017, Devon continued to maintain 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. The valuation allowances impacted the effective tax rate and are discussed in the next section.
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. During 2017, “other” is primarily related to the taxation of other financing items.
2016
 During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its deferred tax assets. The allowance results from continued financial losses in 2016. As of December 31, 2016, the
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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.  
In the first quarter of 2016, EnLink recognized a goodwill impairment of approximately $873 million. Additionally, during the third quarter of 2016, Devon derecognized $83 million of goodwill related to its U.S. operations in conjunction with the divestiture of certain non-core U.S. upstream oil and gas assets. These items are not deductible for purposes of calculating income tax and, therefore, impact the effective tax rate.
2015
In the third and fourth quarters of 2015, EnLink recognized goodwill and intangibles impairments of approximately $1.6 billion, which impacted the effective tax rate.
During 2015, Devon recognized approximately $16 billion of oil and gas impairments related to its U.S. operations. These impairments resulted in deferred tax assets against which Devon recognized a $403 million valuation allowance.
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,	 	
 	 	2017	 	 	2016	 	
Deferred tax assets:	 	 	 	 	 	 	 	 	
Asset retirement obligations	 	$	313	 	 	$	488	 	
Accrued liabilities	 	 	62	 	 	 	130	 	
Net operating loss carryforwards	 	 	865	 	 	 	777	 	
Pension benefit obligations	 	 	54	 	 	 	98	 	
Canadian capital loss carryforwards	 	 	760	 	 	 	17	 	
Other	 	 	135	 	 	 	186	 	
Total deferred tax assets before valuation allowance	 	 	2,189	 	 	 	1,696	 	
Less: valuation allowance	 	 	(968	)	 	 	(645	)	
Net deferred tax assets	 	 	1,221	 	 	 	1,051	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	 	
Property and equipment	 	 	(1,703	)	 	 	(1,635	)	
Long-term debt	 	 	(92	)	 	 	(53	)	
Other	 	 	(261	)	 	 	(426	)	
Total deferred tax liabilities	 	 	(2,056	)	 	 	(2,114	)	
Net deferred tax liability	 	$	(835	)	 	$	(1,063	)	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
At December 31, 2017, Devon has recognized $865 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segment has $710 million of noncapital loss carryforwards expiring between 2029 and 2037. Devon’s U.S. segment has $2.4 billion of U.S. federal carryforwards expiring between 2036 and 2037 and $1.7 billion of U.S. state carryforwards expiring between 2018 and 2037. EnLink has $259 million of U.S. federal carryforwards expiring between 2034 and 2037 and $263 million of state carryforwards expiring between 2028 and 2037. In the current environment, Devon expects tax benefits from the Canadian carryforwards to be utilized in 2018 and beyond and EnLink carryforwards to be utilized in 2020 and beyond. Devon currently does not anticipate utilizing the U.S. federal or state net operating loss carryforwards, as indicated by the full valuation allowance position in the U.S. segment.
As a result of the reduction in U.S. statutory income tax rate and favorable temporary differences, Devon reduced its valuation allowance by $337 million against the U.S. deferred tax assets in 2017 and remains in a full valuation allowance position. Also during 2017, Devon’s Canadian segment recognized a $660 million partial valuation allowance 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.
As of December 31, 2017, Devon’s unremitted foreign earnings from its international operations totaled approximately $908 million. All of this amount was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.
 
 	 	December 31,	 	
 	 	2017	 	 	2016	 	
Balance at beginning of year	 	$	202	 	 	$	131	 	
Tax positions taken in prior periods	 	 	(7	)	 	 	36	 	
Tax positions taken in current year	 	 	(3	)	 	 	—	 	
Accrual of interest related to tax positions taken	 	 	16	 	 	 	39	 	
Settlements	 	 	(101	)	 	 	—	 	
Lapse of statute of limitations	 	 	—	 	 	 	(5	)	
Foreign currency translation	 	 	8	 	 	 	1	 	
Balance at end of year	 	$	115	 	 	$	202	 	
 
Devon’s unrecognized tax benefit balance at December 31, 2017 and 2016 included $28 million and $68 million, respectively, of interest and penalties. If recognized, $115 million of Devon’s unrecognized tax benefits as of December 31, 2017 would affect Devon’s effective income tax rate. During 2017, Devon removed $101 million of unrecognized tax benefits, including $50 million of interest, as a result of the settlement of certain tax examinations. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Jurisdiction	 	Tax Years Open	
U.S. Federal	 	2012-2017	
Various U.S. states	 	2012-2017	
Canada Federal	 	2004-2017	
Various Canadian provinces	 	2004-2017	
 
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.  

9 .	Net Earnings (Loss) Per Share Attributable to Devon	
The following table reconciles net earnings (loss) attributable to Devon and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Net earnings (loss):	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss) attributable to Devon	 	$	898	 	 	$	(1,056	)	 	$	(12,896	)	
Attributable to participating securities	 	 	(10	)	 	 	(2	)	 	 	(5	)	
Basic and diluted earnings (loss)	 	$	888	 	 	$	(1,058	)	 	$	(12,901	)	
Common shares:	 	 	 	 	 	 	 	 	 	 	 	 	
Common shares outstanding - total	 	 	525	 	 	 	513	 	 	 	412	 	
Attributable to participating securities	 	 	(5	)	 	 	(6	)	 	 	(5	)	
Common shares outstanding - basic	 	 	520	 	 	 	507	 	 	 	407	 	
Dilutive effect of potential common shares issuable	 	 	3	 	 	 	—	 	 	 	—	 	
Common shares outstanding - diluted	 	 	523	 	 	 	507	 	 	 	407	 	
Net earnings (loss) per share attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	1.71	 	 	$	(2.09	)	 	$	(31.72	)	
Diluted	 	$	1.70	 	 	$	(2.09	)	 	$	(31.72	)	
Antidilutive options (1)	 	 	2	 	 	 	3	 	 	 	4	 	

(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.	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
10.	Other Comprehensive Earnings	
Components of other comprehensive earnings consist of the following:
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Foreign currency translation and other:	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning accumulated foreign currency translation and other	 	$	1,226	 	 	$	1,215	 	 	$	1,658	 	
Change in cumulative translation adjustment and other	 	 	113	 	 	 	22	 	 	 	(490	)	
Income tax benefit (expense)	 	 	(30	)	 	 	(11	)	 	 	47	 	
Ending accumulated foreign currency translation and other	 	 	1,309	 	 	 	1,226	 	 	 	1,215	 	
Pension and postretirement benefit plans:	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning accumulated pension and postretirement benefits	 	 	(172	)	 	 	(194	)	 	 	(204	)	
Net actuarial loss and prior service cost arising in current year	 	 	10	 	 	 	(28	)	 	 	(5	)	
Recognition of net actuarial loss and prior service cost in earnings (1)	 	 	19	 	 	 	26	 	 	 	21	 	
Curtailment and settlement of pension benefits	 	 	—	 	 	 	24	 	 	 	—	 	
Income tax expense	 	 	—	 	 	 	—	 	 	 	(6	)	
Ending accumulated pension and postretirement benefits	 	 	(143	)	 	 	(172	)	 	 	(194	)	
Accumulated other comprehensive earnings, net of tax	 	$	1,166	 	 	$	1,054	 	 	$	1,021	 	

(1)	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of earnings. See Note 18 for additional details.	
 
11.	Supplemental Information to Statements of Cash Flows	
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Net change in working capital accounts,
    net of assets and liabilities assumed:	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable	 	$	(284	)	 	$	(176	)	 	$	942	 	
Income taxes receivable	 	 	8	 	 	 	130	 	 	 	384	 	
Other current assets	 	 	(12	)	 	 	215	 	 	 	(57	)	
Accounts payable	 	 	105	 	 	 	(167	)	 	 	(190	)	
Revenues and royalties payable	 	 	257	 	 	 	96	 	 	 	(526	)	
Other current liabilities	 	 	(53	)	 	 	(74	)	 	 	(818	)	
Net change in working capital	 	$	21	 	 	$	24	 	 	$	(265	)	
Interest paid (net of capitalized interest)	 	$	481	 	 	$	569	 	 	$	497	 	
Income taxes paid (received)	 	$	78	 	 	$	(159	)	 	$	(279	)	
 
In 2016, Devon’s acquisition of certain STACK assets included the noncash issuance of Devon common stock. 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. See Note 3 for additional details.
 
In 2015, Devon’s acquisition of certain Powder River Basin assets included a noncash common stock issuance totaling $199 million. EnLink’s acquisitions in 2015 also included $360 million of noncash equity. 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
12.	Accounts Receivable	
Components of accounts receivable include the following:
 
 	 	December 31, 2017	 	 	December 31, 2016	 	
Oil, gas and NGL sales	 	$	559	 	 	$	487	 	
Joint interest billings	 	 	134	 	 	 	110	 	
Marketing and midstream revenues	 	 	959	 	 	 	708	 	
Other	 	 	29	 	 	 	69	 	
Gross accounts receivable	 	 	1,681	 	 	 	1,374	 	
Allowance for doubtful accounts	 	 	(11	)	 	 	(18	)	
Net accounts receivable	 	$	1,670	 	 	$	1,356	 	

 13. Property, Plant and Equipment
 
Capitalized Costs
 
The following tables reflect the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
 
 	 	December 31, 2017	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
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	 	
Accumulated DD&A	 	 	(32,379	)	 	 	(4,055	)	 	 	(36,434	)	
Oil and gas property and equipment, net	 	$	9,096	 	 	$	4,222	 	 	$	13,318	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31, 2016	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Proved	 	$	38,842	 	 	$	6,163	 	 	$	45,005	 	
Unproved and properties under development	 	 	2,115	 	 	 	1,277	 	 	 	3,392	 	
Total oil and gas	 	 	40,957	 	 	 	7,440	 	 	 	48,397	 	
Accumulated DD&A	 	 	(31,979	)	 	 	(3,420	)	 	 	(35,399	)	
Oil and gas property and equipment, net	 	$	8,978	 	 	$	4,020	 	 	$	12,998	 	
 
 	 	December 31,	 	
 	 	2017	 	 	2016	 	
EnLink	 	$	9,120	 	 	$	8,381	 	
Devon	 	 	1,955	 	 	 	1,919	 	
Total midstream and other	 	 	11,075	 	 	 	10,300	 	
EnLink	 	 	(2,533	)	 	 	(2,124	)	
Devon	 	 	(689	)	 	 	(641	)	
Total accumulated DD&A	 	 	(3,222	)	 	 	(2,765	)	
Midstream and other property and equipment, net	 	$	7,853	 	 	$	7,535	 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2017.
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Beginning balance	 	$	261	 	 	$	225	 	 	$	199	 	
Additions pending determination of proved reserves	 	 	504	 	 	 	247	 	 	 	348	 	
Charges to exploration expense	 	 	—	 	 	 	(29	)	 	 	(5	)	
Reclassifications to proved properties	 	 	(466	)	 	 	(189	)	 	 	(285	)	
Foreign currency translation adjustment	 	 	14	 	 	 	7	 	 	 	(32	)	
Ending balance	 	$	313	 	 	$	261	 	 	$	225	 	
 
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,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Exploratory well costs capitalized for a period of one year or less	 	$	113	 	 	$	88	 	 	$	60	 	
Exploratory well costs capitalized for a period greater than one year	 	 	200	 	 	 	173	 	 	 	165	 	
Ending balance	 	$	313	 	 	$	261	 	 	$	225	 	
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. Devon continues to assess the development timeline of these long cycle projects. 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 14.  Goodwill and Other Intangible Assets
Goodwill
The following table presents a summary of Devon’s goodwill. For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.
 
 	 	U.S.	 	 	EnLink	 	 	Total	 	
Balance as of December 31, 2015	 	$	923	 	 	$	2,414	 	 	$	3,337	 	
Acquired during period	 	 	—	 	 	 	2	 	 	 	2	 	
Asset divestitures	 	 	(83	)	 	 	—	 	 	 	(83	)	
Impairment	 	 	—	 	 	 	(873	)	 	 	(873	)	
Balance as of December 31, 2016	 	$	840	 	 	$	1,543	 	 	$	2,383	 	
 
The following table presents the General Partner’s and EnLink’s goodwill activity by reporting unit. For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.
 
 	 	Texas	 	 	Oklahoma	 	 	Crude and
Condensate	 	 	General Partner	 	 	Total	 	
Balance as of December 31, 2015	 	$	704	 	 	$	190	 	 	$	93	 	 	$	1,427	 	 	$	2,414	 	
Acquired during period	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	
Impairment	 	 	(473	)	 	 	—	 	 	 	(93	)	 	 	(307	)	 	 	(873	)	
Balance as of December 31, 2016	 	$	233	 	 	$	190	 	 	$	—	 	 	$	1,120	 	 	$	1,543	 	
 
Asset Divestitures
In conjunction with the U.S. non-core upstream asset divestitures in 2016 discussed in Note 3 , Devon removed goodwill allocated to these assets.
Impairment
As further discussed in Note 1 , Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units in the first quarter of 2016. Based on that test, EnLink recorded noncash goodwill impairments related to its Texas, Crude and Condensate and General Partner reporting units.
Additionally, during 2015, EnLink recorded noncash goodwill impairments related to its Texas, Louisiana and Crude and Condensate reporting units.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Other Intangible Assets
The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.
 
 	 	December 31, 2017	 	 	December 31, 2016	 	
Customer relationships	 	$	1,796	 	 	$	1,796	 	
Accumulated amortization	 	 	(299	)	 	 	(172	)	
Net intangibles	 	$	1,497	 	 	$	1,624	 	
 
The weighted-average amortization period for the customer relationships is 15 years. Amortization expense for intangibles was approximately $127 million, $117 million and $56 million for the years ended 2017, 2016 and 2015, respectively. The remaining aggregate amortization expense is estimated to be approximately $123 million in each of the next five years.

15.	Other Current Liabilities	
 
Components of other current liabilities include the following:
 
 	December 31, 2017	 	 	December 31, 2016	 	
Derivative liabilities	$	331	 	 	$	187	 	
Installment payment - see Note 3	 	250	 	 	 	249	 	
Income taxes payable	 	145	 	 	 	32	 	
Accrued interest payable	 	131	 	 	 	130	 	
Restructuring liabilities	 	19	 	 	 	48	 	
Other	 	325	 	 	 	420	 	
Other current liabilities	$	1,201	 	 	$	1,066	 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
16.	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, 2017	 	 	December 31, 2016	 	
Devon debt:	 	 	 	 	 	 	 	 	
8.25% due July 1, 2018 (1)(2)	 	$	20	 	 	$	20	 	
2.25% due December 15, 2018 (1)	 	 	95	 	 	 	95	 	
6.30% due January 15, 2019 (1)	 	 	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 (1)	 	 	485	 	 	 	485	 	
7.50% due September 15, 2027 (1)(2)	 	 	73	 	 	 	73	 	
7.875% due September 30, 2031 (1)(3)	 	 	1,059	 	 	 	1,059	 	
7.95% due April 15, 2032 (1)	 	 	789	 	 	 	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	 	 	(30	)	 	 	(30	)	
Debt issuance costs	 	 	(39	)	 	 	(44	)	
Total Devon debt	 	 	6,864	 	 	 	6,859	 	
EnLink and General Partner debt:	 	 	 	 	 	 	 	 	
Credit facilities	 	 	74	 	 	 	148	 	
2.70% due April 1, 2019	 	 	400	 	 	 	400	 	
7.125% due June 1, 2022	 	 	—	 	 	 	163	 	
4.40% due April 1, 2024	 	 	550	 	 	 	550	 	
4.15% due June 1, 2025	 	 	750	 	 	 	750	 	
4.85% due July 15, 2026	 	 	500	 	 	 	500	 	
5.60% due April 1, 2044	 	 	350	 	 	 	350	 	
5.05% due April 1, 2045	 	 	450	 	 	 	450	 	
5.45% due June 1, 2047	 	 	500	 	 	 	—	 	
Net premium (discount) on debentures and notes	 	 	(6	)	 	 	9	 	
Debt issuance costs	 	 	(26	)	 	 	(25	)	
Total EnLink and General Partner debt	 	 	3,542	 	 	 	3,295	 	
Total debt	 	 	10,406	 	 	 	10,154	 	
Less amount classified as short-term debt (4)	 	 	115	 	 	 	—	 	
Total long-term debt	 	$	10,291	 	 	$	10,154	 	

(1)	These senior notes were included in 2016 tender offer redemptions discussed below.	
(2)	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.	
(3)	Issued in October 2001, these are unsecured and unsubordinated obligations of Devon Financing, a wholly owned finance subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon.	
(4)	2017 short-term debt consists of $20 million of 8.25% senior notes due July 1, 2018 and $95 million of 2.25% senior notes due December 15, 2018.	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Debt maturities as of December 31, 2017, excluding debt issuance costs, premiums and discounts, are as follows:
  
 	 	Devon	 	 	EnLink	 	 	Total	 	
2018	 	$	115	 	 	$	—	 	 	$	115	 	
2019	 	 	162	 	 	 	474	 	 	 	636	 	
2020	 	 	—	 	 	 	—	 	 	 	—	 	
2021	 	 	500	 	 	 	—	 	 	 	500	 	
2022	 	 	1,000	 	 	 	—	 	 	 	1,000	 	
Thereafter	 	 	5,156	 	 	 	3,100	 	 	 	8,256	 	
Total	 	$	6,933	 	 	$	3,574	 	 	$	10,507	 	
Credit Lines
Devon has a $3.0 billion Senior Credit Facility. The facility matures as follows: $164 million on October 24, 2018 and the remaining $2.8 billion on October 24, 2019. Amounts borrowed under the 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 Senior Credit Facility currently provides for an annual facility fee of $7.4 million. As of December 31, 2017, Devon had $59 million in outstanding letters of credit under the Senior Credit Facility. There were no borrowings under the Senior Credit Facility as of December 31, 2017.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2017, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 27.2%. Devon’s change to successful efforts did not materially change this ratio.
Commercial Paper
Devon’s 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, 2017, Devon had no outstanding commercial paper borrowings.
Retirement of Senior Notes
During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 3 . 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)
 
EnLink Debt
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
EnLink has a $1.5 billion unsecured revolving credit facility that will mature on March 6, 2020. As of December 31, 2017, there were $10 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019. As of December 31, 2017, the General Partner had $74 million in outstanding borrowings under the $250 million credit facility at a weighted average borrowing rate of 3.2%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2017.
In the second quarter of 2017, EnLink issued $500 million of 5.45% unsecured senior notes due in 2047. The proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive statement of earnings.
In July 2016, EnLink issued $500 million of 4.85% unsecured senior notes due 2026. EnLink used the net proceeds to repay outstanding borrowings under its revolving credit facility and for general partnership purposes.
Financing Costs, Net
The following schedule includes the components of net financing costs.
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Devon net financing costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest based on debt outstanding	 	$	390	 	 	$	488	 	 	$	450	 	
Early retirement of debt	 	 	—	 	 	 	269	 	 	 	—	 	
Capitalized interest	 	 	(69	)	 	 	(61	)	 	 	(52	)	
Other	 	 	(4	)	 	 	21	 	 	 	14	 	
Total Devon net financing costs	 	 	317	 	 	 	717	 	 	 	412	 	
EnLink net financing costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest based on debt outstanding	 	 	167	 	 	 	144	 	 	 	115	 	
Interest accretion on deferred installment payment	 	 	26	 	 	 	52	 	 	 	—	 	
Early retirement of debt	 	 	(9	)	 	 	—	 	 	 	—	 	
Other	 	 	(3	)	 	 	(6	)	 	 	(8	)	
Total EnLink net financing costs	 	 	181	 	 	 	190	 	 	 	107	 	
Total net financing costs	 	$	498	 	 	$	907	 	 	$	519	 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
17.	Asset Retirement Obligations	
The following table presents the changes in asset retirement obligations.
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	
Asset retirement obligations as of beginning of period	 	$	1,272	 	 	$	1,414	 	
Liabilities incurred and assumed through acquisitions	 	 	40	 	 	 	27	 	
Liabilities settled and divested	 	 	(68	)	 	 	(324	)	
Revision of estimated obligation	 	 	(184	)	 	 	66	 	
Accretion expense on discounted obligation	 	 	62	 	 	 	75	 	
Foreign currency translation adjustment	 	 	30	 	 	 	14	 	
Asset retirement obligations as of end of period	 	 	1,152	 	 	 	1,272	 	
Less current portion	 	 	39	 	 	 	46	 	
Asset retirement obligations, long-term	 	$	1,113	 	 	$	1,226	 	
 
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.
 
During 2016, Devon reduced its asset retirement obligation by $287 million for those obligations that were assumed by purchasers of certain upstream U.S. assets.

18.	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 $60 million, $64 million and $79 million to these plans in 2017, 2016 and 2015, respectively.
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 since 2007; 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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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 $342 million and $311 million at December 31, 2017 and 2016, 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 $401 million and $367 million at December 31, 2017 and 2016, respectively.
Equity – Devon’s equity securities include a commingled global equity fund that invests in large, mid- and small capitalization stocks across the world’s developed and emerging markets. These equity 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 $157 million and $171 million at December 31, 2017 and 2016, respectively.
Other – Devon’s other securities include short-term investments funds, an actively traded global mutual fund focusing on alternative investment strategies and a hedge fund that invests 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 $135 million and $136 million at December 31, 2017 and 2016, respectively.
Defined Postretirement Plans
Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. The plans provide medical and in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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, 2017 and 2016.
 
 	 	Pension Benefits	 	 	Postretirement Benefits	 	
 	 	2017	 	 	2016	 	 	2017	 	 	2016	 	
Change in benefit obligation:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Benefit obligation at beginning of year	 	$	1,249	 	 	$	1,308	 	 	$	21	 	 	$	23	 	
Service cost	 	 	15	 	 	 	15	 	 	 	—	 	 	 	—	 	
Interest cost	 	 	42	 	 	 	42	 	 	 	—	 	 	 	1	 	
Actuarial loss (gain)	 	 	59	 	 	 	63	 	 	 	—	 	 	 	(1	)	
Plan amendments	 	 	—	 	 	 	2	 	 	 	—	 	 	 	—	 	
Plan curtailments	 	 	—	 	 	 	(31	)	 	 	—	 	 	 	—	 	
Plan settlements	 	 	—	 	 	 	(94	)	 	 	—	 	 	 	—	 	
Foreign exchange rate changes	 	 	2	 	 	 	1	 	 	 	—	 	 	 	—	 	
Participant contributions	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	
Benefits paid	 	 	(88	)	 	 	(57	)	 	 	(3	)	 	 	(2	)	
Benefit obligation at end of year	 	 	1,279	 	 	 	1,249	 	 	 	19	 	 	 	21	 	
Change in plan assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at beginning of year	 	 	985	 	 	 	1,059	 	 	 	—	 	 	 	—	 	
Actual return on plan assets	 	 	122	 	 	 	61	 	 	 	—	 	 	 	—	 	
Employer contributions	 	 	14	 	 	 	16	 	 	 	2	 	 	 	2	 	
Participant contributions	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	
Plan settlements	 	 	—	 	 	 	(94	)	 	 	—	 	 	 	—	 	
Benefits paid	 	 	(88	)	 	 	(57	)	 	 	(3	)	 	 	(2	)	
Foreign exchange rate changes	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	
Fair value of plan assets at end of year	 	 	1,035	 	 	 	985	 	 	 	—	 	 	 	—	 	
Funded status at end of year	 	$	(244	)	 	$	(264	)	 	$	(19	)	 	$	(21	)	
Amounts recognized in balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other long-term assets	 	$	4	 	 	$	3	 	 	$	—	 	 	$	—	 	
Other current liabilities	 	 	(13	)	 	 	(13	)	 	 	(3	)	 	 	(3	)	
Other long-term liabilities	 	 	(235	)	 	 	(254	)	 	 	(16	)	 	 	(18	)	
Net amount	 	$	(244	)	 	$	(264	)	 	$	(19	)	 	$	(21	)	
Amounts recognized in accumulated other
   comprehensive earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net actuarial loss (gain)	 	$	257	 	 	$	285	 	 	$	(11	)	 	$	(11	)	
Prior service cost (credit)	 	 	6	 	 	 	8	 	 	 	(3	)	 	 	(5	)	
Total	 	$	263	 	 	$	293	 	 	$	(14	)	 	$	(16	)	
 
Certain of Devon’s pension plans are unfunded and have a combined projected benefit obligation and accumulated benefit obligation of $239 million and $225 million, respectively, at December 31, 2017 and $234 million and $211 million, respectively, at December 31, 2016.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
 
 	 	Pension Benefits	 	 	Postretirement Benefits	 	
 	 	2017	 	 	2016	 	 	2015	 	 	2017	 	 	2016	 	 	2015	 	
Net periodic benefit cost:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Service cost	 	$	15	 	 	$	15	 	 	$	33	 	 	$	—	 	 	$	—	 	 	$	1	 	
Interest cost	 	 	42	 	 	 	42	 	 	 	52	 	 	 	—	 	 	 	1	 	 	 	1	 	
Expected return on plan assets	 	 	(54	)	 	 	(55	)	 	 	(58	)	 	 	—	 	 	 	—	 	 	 	—	 	
Recognition of net actuarial loss (gain) (1)	 	 	19	 	 	 	25	 	 	 	20	 	 	 	(1	)	 	 	(1	)	 	 	(1	)	
Recognition of prior service cost (1)	 	 	2	 	 	 	3	 	 	 	4	 	 	 	(1	)	 	 	(1	)	 	 	(2	)	
Total net periodic benefit cost (2)	 	 	24	 	 	 	30	 	 	 	51	 	 	 	(2	)	 	 	(1	)	 	 	(1	)	
Other comprehensive loss (earnings):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Actuarial loss (gain) arising in current year	 	 	(9	)	 	 	26	 	 	 	5	 	 	 	(1	)	 	 	—	 	 	 	(1	)	
Prior service cost (credit) arising in current year	 	 	—	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	
Recognition of net actuarial loss, including settlement
   expense, in net periodic benefit cost (3)	 	 	(19	)	 	 	(43	)	 	 	(20	)	 	 	1	 	 	 	1	 	 	 	1	 	
Recognition of prior service cost, including
   curtailment, in net periodic benefit cost (3)	 	 	(2	)	 	 	(9	)	 	 	(4	)	 	 	1	 	 	 	1	 	 	 	1	 	
Total other comprehensive loss (earnings)	 	 	(30	)	 	 	(24	)	 	 	(19	)	 	 	1	 	 	 	2	 	 	 	2	 	
Total recognized	 	$	(6	)	 	$	6	 	 	$	32	 	 	$	(1	)	 	$	1	 	 	$	1	 	

(1)	These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.	
(2)	Net periodic benefit cost is a component of G&A on the accompanying consolidated comprehensive statements of earnings.	
(3)	These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2016. See Note 7 for further discussion.	
The estimated net actuarial loss and prior service cost for our pension and postretirement benefits that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2018 are $14 million and $1 million, respectively.
 
Assumptions
 
 	 	Pension Benefits	 	 	Postretirement Benefits	 	
 	 	2017	 	 	2016	 	 	2015	 	 	2017	 	 	2016	 	 	2015	 	
Assumptions to determine benefit obligations:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	3.59%	 	 	 	4.07%	 	 	 	4.25%	 	 	3.25%	 	 	 	3.46%	 	 	 	3.63%	 	
Rate of compensation increase	 	2.50%	 	 	 	4.49%	 	 	 	4.49%	 	 	N/A	 	 	N/A	 	 	N/A	 	
Assumptions to determine net periodic benefit cost:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	4.08%	 	 	 	4.39%	 	 	 	3.90%	 	 	3.46%	 	 	 	3.63%	 	 	3.25%	 	
Rate of compensation increase	 	4.48%	 	 	 	4.49%	 	 	 	4.49%	 	 	N/A	 	 	N/A	 	 	N/A	 	
Expected return on plan assets	 	5.69%	 	 	 	5.20%	 	 	 	5.22%	 	 	N/A	 	 	N/A	 	 	N/A	 	
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.  
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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 and the actuary’s best estimate of mortality for the population of participants in Devon’s plans.
Other assumptions – For measurement of the 2017 benefit obligation for the other postretirement medical plans, a 7.3% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. A one percentage point change in assumed health care cost trend rates would not have a material impact on periodic benefit cost or benefit obligations.
 
Expected Cash Flows
Devon expects benefit plan payments to average approximately $76 million a year for the next five years and $406 million total for the five years thereafter. Of these payments to be paid in 2018, $3 million is expected to be funded from Devon’s available cash and cash equivalents.

19.	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 3 . 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.  
In December 2015, Devon issued approximately 7 million shares of common stock as part of the Powder River Basin asset acquisition discussed in Note 3 .    
Dividends
Devon paid common stock dividends of $127 million, $221 million and $396 million during 2017, 2016 and 2015, respectively. 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.
 
20.	Noncontrolling Interests	
 
Subsidiary Equity Transactions
 EnLink has the ability to sell common units through its “at the market” equity offering programs. In the third quarter of 2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common
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units through its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3 million common units through its “at the market” program and general public offerings, generating net proceeds of $107 million, $167 million and $25 million, respectively. During the first quarter of 2016, the General Partner issued common units in conjunction with the Anadarko Basin assets acquisition discussed in Note 3.
In October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 million in proceeds. In 2015, Devon conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising net proceeds of $654 million.
In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds of approximately $394 million. As a result of these transactions and EnLink’s acquisition and dropdown activity discussed further in Note 3 , the table below shows the ownership interest activity in the General Partner and EnLink for the last three years.
 
 	 	EnLink	 	 	General Partner	 	
Ownership interest as of	 	Devon	 	 	Non-Devon Unitholders	 	 	General Partner	 	 	Devon	 	 	Non-Devon Unitholders	 	
December 31, 2015	 	 	28%	 	 	 	45%	 	 	 	27%	 	 	 	70%	 	 	 	30%	 	
December 31, 2016	 	 	24%	 	 	 	53%	 	 	 	23%	 	 	 	64%	 	 	 	36%	 	
December 31, 2017	 	 	23%	 	 	 	55%	 	 	 	22%	 	 	 	64%	 	 	 	36%	 	
Distributions to Noncontrolling Interests
EnLink and the General Partner distributed $354 million, $304 million and $254 million to non-Devon unitholders during 2017, 2016 and 2015, respectively.

21.	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 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 gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. These suits typically assert various allegations, including that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in the underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and 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.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.
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.
Commitments
The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2017.
 
Year Ending December 31,	 	Purchase Obligations	 	 	Drilling and Facility Obligations	 	 	Operational Agreements	 	 	Office and Equipment Leases	 	 	EnLink Obligations	 	
2018	 	$	613	 	 	$	216	 	 	$	1,159	 	 	$	88	 	 	$	53	 	
2019	 	 	577	 	 	 	109	 	 	 	562	 	 	 	84	 	 	 	36	 	
2020	 	 	556	 	 	 	109	 	 	 	466	 	 	 	73	 	 	 	19	 	
2021	 	 	134	 	 	 	51	 	 	 	366	 	 	 	61	 	 	 	18	 	
2022	 	 	—	 	 	 	38	 	 	 	373	 	 	 	56	 	 	 	17	 	
Thereafter	 	 	—	 	 	 	106	 	 	 	3,242	 	 	 	19	 	 	 	90	 	
Total	 	$	1,880	 	 	$	629	 	 	$	6,168	 	 	$	381	 	 	$	233	 	
 
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 $67 million, $78 million and $88 million in 2017, 2016 and 2015, respectively.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

22.	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, 2017 and December 31, 2016, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items and the pension plan assets is provided in Note 6 ,  Note 14 and  Note 18 , respectively.
 
 	 	 	 	 	 	 	 	 	 	Fair Value	 	
 	 	 	 	 	 	 	 	 	 	Measurements Using:	 	
 	 	Carrying	 	 	Total Fair	 	 	Level 1	 	 	Level 2	 	
 	 	Amount	 	 	Value	 	 	Inputs	 	 	Inputs	 	
December 31, 2017 assets (liabilities):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash equivalents	 	$	1,533	 	 	$	1,533	 	 	$	1,454	 	 	$	79	 	
Commodity derivatives	 	$	211	 	 	$	211	 	 	$	—	 	 	$	211	 	
Commodity derivatives	 	$	(294	)	 	$	(294	)	 	$	—	 	 	$	(294	)	
Interest rate derivatives	 	$	1	 	 	$	1	 	 	$	—	 	 	$	1	 	
Interest rate derivatives	 	$	(64	)	 	$	(64	)	 	$	—	 	 	$	(64	)	
Debt	 	$	(10,406	)	 	$	(11,782	)	 	$	—	 	 	$	(11,782	)	
Installment payment	 	$	(250	)	 	$	(250	)	 	$	—	 	 	$	(250	)	
Capital lease obligations	 	$	(4	)	 	$	(3	)	 	$	—	 	 	$	(3	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2016 assets (liabilities):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash equivalents	 	$	1,542	 	 	$	1,542	 	 	$	1,298	 	 	$	244	 	
Commodity derivatives	 	$	10	 	 	$	10	 	 	$	—	 	 	$	10	 	
Commodity derivatives	 	$	(203	)	 	$	(203	)	 	$	—	 	 	$	(203	)	
Interest rate derivatives	 	$	1	 	 	$	1	 	 	$	—	 	 	$	1	 	
Interest rate derivatives	 	$	(41	)	 	$	(41	)	 	$	—	 	 	$	(41	)	
Debt	 	$	(10,154	)	 	$	(10,760	)	 	$	—	 	 	$	(10,760	)	
Installment payment	 	$	(473	)	 	$	(477	)	 	$	—	 	 	$	(477	)	
Capital lease obligations	 	$	(7	)	 	$	(6	)	 	$	—	 	 	$	(6	)	
 
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 U.S. and Canadian treasury securities and money market investments. 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.
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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. The fair values of commercial paper and credit facility balances are the carrying values.
Installment payment – The fair value of the EnLink installment payment was based on Level 2 inputs from third-party market quotations.
Capital lease obligations – The fair value was calculated using inputs from third-party banks.

23.	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 24 .
Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment.
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 	 	U.S. (1)	 	 	Canada	 	 	EnLink (1)	 	 	Eliminations	 	 	Total	 	
Year Ended December 31, 2017:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from external customers	 	$	7,326	 	 	$	1,552	 	 	$	5,071	 	 	$	—	 	 	$	13,949	 	
Intersegment revenues	 	$	—	 	 	$	—	 	 	$	669	 	 	$	(669	)	 	$	—	 	
Depreciation, depletion and amortization	 	$	1,149	 	 	$	380	 	 	$	545	 	 	$	—	 	 	$	2,074	 	
Asset impairments	 	$	—	 	 	$	—	 	 	$	17	 	 	$	—	 	 	$	17	 	
Asset dispositions	 	$	(218	)	 	$	1	 	 	$	—	 	 	$	—	 	 	$	(217	)	
Interest expense	 	$	324	 	 	$	69	 	 	$	181	 	 	$	(57	)	 	$	517	 	
Earnings before income taxes	 	$	500	 	 	$	273	 	 	$	123	 	 	$	—	 	 	$	896	 	
Income tax expense (benefit)	 	$	9	 	 	$	6	 	 	$	(197	)	 	$	—	 	 	$	(182	)	
Net earnings	 	$	491	 	 	$	267	 	 	$	320	 	 	$	—	 	 	$	1,078	 	
Net earnings attributable to noncontrolling interests	 	$	—	 	 	$	—	 	 	$	180	 	 	$	—	 	 	$	180	 	
Net earnings attributable to Devon	 	$	491	 	 	$	267	 	 	$	140	 	 	$	—	 	 	$	898	 	
Property and equipment, net	 	$	10,274	 	 	$	4,310	 	 	$	6,587	 	 	$	—	 	 	$	21,171	 	
Total assets	 	$	14,254	 	 	$	5,498	 	 	$	10,538	 	 	$	(49	)	 	$	30,241	 	
Capital expenditures, including acquisitions	 	$	1,821	 	 	$	348	 	 	$	768	 	 	$	—	 	 	$	2,937	 	
Year Ended December 31, 2016:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from external customers	 	$	5,722	 	 	$	1,031	 	 	$	3,551	 	 	$	—	 	 	$	10,304	 	
Intersegment revenues	 	$	—	 	 	$	—	 	 	$	701	 	 	$	(701	)	 	$	—	 	
Depreciation, depletion and amortization	 	$	1,178	 	 	$	414	 	 	$	504	 	 	$	—	 	 	$	2,096	 	
Asset impairments	 	$	435	 	 	$	2	 	 	$	873	 	 	$	—	 	 	$	1,310	 	
Asset dispositions	 	$	(955	)	 	$	(541	)	 	$	13	 	 	$	—	 	 	$	(1,483	)	
Restructuring and transaction costs	 	$	242	 	 	$	19	 	 	$	6	 	 	$	—	 	 	$	267	 	
Interest expense	 	$	624	 	 	$	184	 	 	$	190	 	 	$	(84	)	 	$	914	 	
Earnings (loss) before income taxes	 	$	(673	)	 	$	240	 	 	$	(884	)	 	$	—	 	 	$	(1,317	)	
Income tax expense (benefit)	 	$	(8	)	 	$	149	 	 	$	—	 	 	$	—	 	 	$	141	 	
Net earnings (loss)	 	$	(665	)	 	$	91	 	 	$	(884	)	 	$	—	 	 	$	(1,458	)	
Net earnings (loss) attributable to noncontrolling interests	 	$	1	 	 	$	—	 	 	$	(403	)	 	$	—	 	 	$	(402	)	
Net earnings (loss) attributable to Devon	 	$	(666	)	 	$	91	 	 	$	(481	)	 	$	—	 	 	$	(1,056	)	
Property and equipment, net	 	$	10,166	 	 	$	4,110	 	 	$	6,257	 	 	$	—	 	 	$	20,533	 	
Total assets	 	$	13,390	 	 	$	5,071	 	 	$	10,276	 	 	$	(62	)	 	$	28,675	 	
Capital expenditures, including acquisitions	 	$	2,640	 	 	$	186	 	 	$	1,082	 	 	$	—	 	 	$	3,908	 	
Year Ended December 31, 2015:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from external customers	 	$	8,360	 	 	$	1,012	 	 	$	3,773	 	 	$	—	 	 	$	13,145	 	
Intersegment revenues	 	$	—	 	 	$	—	 	 	$	679	 	 	$	(679	)	 	$	—	 	
Depreciation, depletion and amortization	 	$	3,164	 	 	$	471	 	 	$	387	 	 	$	—	 	 	$	4,022	 	
Asset impairments	 	$	16,069	 	 	$	15	 	 	$	1,563	 	 	$	—	 	 	$	17,647	 	
Asset dispositions	 	$	(33	)	 	$	39	 	 	$	1	 	 	$	—	 	 	$	7	 	
Restructuring and transaction costs	 	$	54	 	 	$	24	 	 	$	—	 	 	$	—	 	 	$	78	 	
Interest expense	 	$	368	 	 	$	97	 	 	$	107	 	 	$	(46	)	 	$	526	 	
Loss before income taxes	 	$	(17,898	)	 	$	(576	)	 	$	(1,384	)	 	$	—	 	 	$	(19,858	)	
Income tax expense (benefit)	 	$	(6,100	)	 	$	(143	)	 	$	30	 	 	$	—	 	 	$	(6,213	)	
Net loss	 	$	(11,798	)	 	$	(433	)	 	$	(1,414	)	 	$	—	 	 	$	(13,645	)	
Net earnings (loss) attributable to noncontrolling interests	 	$	1	 	 	$	—	 	 	$	(750	)	 	$	—	 	 	$	(749	)	
Net loss attributable to Devon	 	$	(11,799	)	 	$	(433	)	 	$	(664	)	 	$	—	 	 	$	(12,896	)	
Property and equipment, net	 	$	10,357	 	 	$	4,962	 	 	$	5,667	 	 	$	—	 	 	$	20,986	 	
Total assets	 	$	14,399	 	 	$	5,830	 	 	$	9,541	 	 	$	(97	)	 	$	29,673	 	
Capital expenditures, including acquisitions	 	$	4,143	 	 	$	591	 	 	$	978	 	 	$	—	 	 	$	5,712	 	

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

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

24.	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.
Included in this note are disclosures of Devon’s results of operations for oil and gas producing activities and standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. In conjunction with Devon’s oil and gas accounting policy change discussed in Note 1 , Devon also modified its treatment of certain “production support” costs in these two disclosures. Production support costs consisted of labor, supervision, materials and supplies for oil and gas production monitoring and support activities, including information technology, accounting and certain other administrative support functions. These costs are included in G&A expenses in the accompanying consolidated comprehensive statements of earnings. Devon used a method to allocate these costs to its country-based results of operations and standardized measure disclosures. In 2016 and 2015, Devon’s results of operations disclosures included production support costs of $168 million and $224 million, respectively, and its standardized measure disclosures included estimated future production support costs of $2.8 billion and $2.7 billion, respectively.
Devon’s 2016 and 2015 disclosures have been revised to exclude these amounts.
Based on research conducted by Devon, diversity of practice has existed across peer companies regarding the treatment of production support costs in results of operations and standardized measure disclosures. Devon’s research of public filings indicates most companies exclude such costs from results of operations and standardized measure disclosures, but some companies appear to include such costs in their disclosures. Considering the apparent diversity of practice, Devon is making this disclosure change for two primary reasons. First, by converting to the successful efforts method of accounting and making this disclosure change, Devon’s results of operations and standardized measure disclosures will be most comparable to the vast majority of its peers. Second, allocating these costs to more granular common operating fields as opposed to country-based full cost pools is cost prohibitive and not materially important to investors and stakeholders, considering such allocated costs represented approximately 4% of Devon’s 2016 and 2015 oil, gas and NGL sales.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.
 
 	 	Year Ended December 31, 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	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31, 2015	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Property acquisition costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Proved properties	 	$	193	 	 	$	2	 	 	$	195	 	
Unproved properties	 	 	635	 	 	 	81	 	 	 	716	 	
Exploration costs	 	 	432	 	 	 	120	 	 	 	552	 	
Development costs	 	 	2,982	 	 	 	351	 	 	 	3,333	 	
Costs incurred	 	$	4,242	 	 	$	554	 	 	$	4,796	 	
 
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 $69 million, $61 million and $52 million in 2017, 2016 and 2015, respectively.
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.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	 	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	 	
 
 	 	December 31, 2016	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Oil, gas and NGL sales	 	$	3,198	 	 	$	984	 	 	$	4,182	 	
Production expenses	 	 	(1,311	)	 	 	(492	)	 	 	(1,803	)	
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	 	$	1,107	 	 	$	35	 	 	$	1,142	 	
Depreciation, depletion and amortization per Boe	 	$	6.11	 	 	$	7.75	 	 	$	6.47	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31, 2015	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Oil, gas and NGL sales	 	$	4,356	 	 	$	1,026	 	 	$	5,382	 	
Production expenses	 	 	(1,853	)	 	 	(586	)	 	 	(2,439	)	
Exploration expenses	 	 	(323	)	 	 	(128	)	 	 	(451	)	
Depreciation, depletion and amortization	 	 	(3,051	)	 	 	(423	)	 	 	(3,474	)	
Asset dispositions	 	 	32	 	 	 	(39	)	 	 	(7	)	
Asset impairments	 	 	(16,061	)	 	 	(15	)	 	 	(16,076	)	
Accretion of asset retirement obligations	 	 	(47	)	 	 	(28	)	 	 	(75	)	
Income tax benefit	 	 	5,783	 	 	 	50	 	 	 	5,833	 	
Results of operations	 	$	(11,164	)	 	$	(143	)	 	$	(11,307	)	
Depreciation, depletion and amortization per Boe	 	$	14.79	 	 	$	10.08	 	 	$	13.99	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
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, 2014	 	 	351	 	 	 	23	 	 	 	374	 	 	 	521	 	 	 	7,651	 	 	 	36	 	 	 	7,687	 	 	 	578	 	 	 	2,205	 	 	 	549	 	 	 	2,754	 	
Revisions due to prices	 	 	(53	)	 	 	4	 	 	 	(49	)	 	 	103	 	 	 	(1,412	)	 	 	(9	)	 	 	(1,421	)	 	 	(119	)	 	 	(408	)	 	 	106	 	 	 	(302	)	
Revisions other than price	 	 	(52	)	 	 	2	 	 	 	(50	)	 	 	(84	)	 	 	(3	)	 	 	(6	)	 	 	(9	)	 	 	(6	)	 	 	(59	)	 	 	(83	)	 	 	(142	)	
Extensions and discoveries	 	 	51	 	 	 	3	 	 	 	54	 	 	 	11	 	 	 	171	 	 	 	—	 	 	 	171	 	 	 	24	 	 	 	104	 	 	 	14	 	 	 	118	 	
Purchase of reserves	 	 	5	 	 	 	—	 	 	 	5	 	 	 	—	 	 	 	17	 	 	 	—	 	 	 	17	 	 	 	1	 	 	 	9	 	 	 	—	 	 	 	9	 	
Production	 	 	(60	)	 	 	(10	)	 	 	(70	)	 	 	(31	)	 	 	(579	)	 	 	(8	)	 	 	(587	)	 	 	(50	)	 	 	(206	)	 	 	(42	)	 	 	(248	)	
Sale of reserves	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(37	)	 	 	—	 	 	 	(37	)	 	 	—	 	 	 	(7	)	 	 	—	 	 	 	(7	)	
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	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2014	 	 	255	 	 	 	23	 	 	 	278	 	 	 	137	 	 	 	6,948	 	 	 	36	 	 	 	6,984	 	 	 	486	 	 	 	1,900	 	 	 	165	 	 	 	2,065	 	
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	 	
Proved developed-producing reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2014	 	 	224	 	 	 	19	 	 	 	243	 	 	 	137	 	 	 	6,746	 	 	 	34	 	 	 	6,780	 	 	 	467	 	 	 	1,815	 	 	 	162	 	 	 	1,977	 	
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	 	
Proved undeveloped reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2014	 	 	96	 	 	 	—	 	 	 	96	 	 	 	384	 	 	 	703	 	 	 	—	 	 	 	703	 	 	 	92	 	 	 	305	 	 	 	384	 	 	 	689	 	
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	 	

(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 2017 (MMBoe).
 
 	 	U.S.	 	 	Canada	 	 	Total	 	
Proved undeveloped reserves as of December 31, 2016	 	 	115	 	 	 	294	 	 	 	409	 	
Extensions and discoveries	 	 	116	 	 	 	12	 	 	 	128	 	
Revisions due to prices	 	 	—	 	 	 	(27	)	 	 	(27	)	
Revisions other than price	 	 	(21	)	 	 	(6	)	 	 	(27	)	
Conversion to proved developed reserves	 	 	(9	)	 	 	(64	)	 	 	(73	)	
Proved undeveloped reserves as of December 31, 2017	 	 	201	 	 	 	209	 	 	 	410	 	
 
Total proved undeveloped reserves remained consistent from 2016 to 2017 with the year-end 2017 balance representing 19% of total proved reserves. Devon’s focus on drilling and development activities in the STACK and Delaware Basin was the primary driver of the 128 MMBoe increase in extensions and discoveries. Continued development primarily at Jackfish led to the conversion of 73 MMBoe, or 18%, of the 2016 proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $237 million for 2017.     
A significant amount of Devon’s proved undeveloped reserves at the end of 2017 related to its Jackfish operations. At December 31, 2017 and 2016, Devon’s Jackfish proved undeveloped reserves were 209 MMBoe and 294 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 2028. At the end of 2017, approximately 196 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 88 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop.
Price Revisions
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 its royalties, which decreases its after-royalty volumes.
Reserves decreased 27 MMBoe and 302 MMBoe during 2016 and 2015, respectively, 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.
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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Revisions Other Than Price
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).
Revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish were primarily due to a refined reserves methodology that resulted in a reduced recovery factor.
Extensions and Discoveries
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, which was 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 consisting of 73 MMBoe related to STACK.
2015 – Of the 118 MMBoe of extensions and discoveries, 38 MMBoe related to the Delaware Basin, 30 MMBoe related to the Anadarko Basin, 21 MMBoe related to the Eagle Ford and 11 MMBoe related to Jackfish.
The 2015 extensions and discoveries included 13 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 11 MMBoe at Jackfish.
Purchase of Reserves
2016 – Primarily related to Devon’s acquisition in the STACK play.
2015 – Primarily related to Devon’s acquisition in the Powder River Basin.
Sale of Reserves
2017 – Related to Devon’s non-core asset divestitures in the U.S. as discussed further in Note 3 .
2016 – Related to Devon’s non-core upstream asset divestitures discussed further in Note 3 .
 
109

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Index to Financial Statements
 
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Standardized Measure
The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.
 
 	 	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	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31, 2015	 	
 	 	U.S.	 	 	Canada	 	 	Total	 	
Future cash inflows	 	$	27,398	 	 	$	13,047	 	 	$	40,445	 	
Future costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Development	 	 	(3,306	)	 	 	(2,759	)	 	 	(6,065	)	
Production	 	 	(14,938	)	 	 	(6,501	)	 	 	(21,439	)	
Future income tax expense	 	 	—	 	 	 	(580	)	 	 	(580	)	
Future net cash flow	 	 	9,154	 	 	 	3,207	 	 	 	12,361	 	
10% discount to reflect timing of cash flows	 	 	(3,230	)	 	 	(1,248	)	 	 	(4,478	)	
Standardized measure of discounted future net cash flows	 	$	5,924	 	 	$	1,959	 	 	$	7,883	 	
 
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 2017 estimates, Devon’s future realized prices were assumed to be $47.86 per Bbl of oil, $31.86 per Bbl of bitumen, $2.43 per Mcf of gas and $16.25 per Bbl of NGLs. Of the $5.2 billion of future development costs as of the end of 2017, $0.9 billion, $0.8 billion and $0.5 billion are estimated to be spent in 2018, 2019 and 2020, respectively.
Future development costs include not only development costs but also future asset retirement costs. Included as part of the $5.2 billion of future development costs are $1.3 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.
110

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
 
 	 	Year Ended December 31,	 	
 	 	2017	 	 	2016	 	 	2015	 	
Beginning balance	 	$	5,440	 	 	$	7,883	 	 	$	21,583	 	
Net changes in prices and production costs	 	 	5,218	 	 	 	(2,027	)	 	 	(21,330	)	
Oil, bitumen, gas and NGL sales, net of production costs	 	 	(3,327	)	 	 	(2,379	)	 	 	(2,943	)	
Changes in estimated future development costs	 	 	789	 	 	 	112	 	 	 	1,313	 	
Extensions and discoveries, net of future development costs	 	 	2,497	 	 	 	674	 	 	 	1,102	 	
Purchase of reserves	 	 	2	 	 	 	224	 	 	 	93	 	
Sales of reserves in place	 	 	(3	)	 	 	(577	)	 	 	(77	)	
Revisions of quantity estimates	 	 	(318	)	 	 	(21	)	 	 	(1,312	)	
Previously estimated development costs incurred during the period	 	 	559	 	 	 	663	 	 	 	2,158	 	
Accretion of discount	 	 	1,034	 	 	 	537	 	 	 	702	 	
Foreign exchange and other	 	 	(7	)	 	 	74	 	 	 	(1,148	)	
Net change in income taxes	 	 	(547	)	 	 	277	 	 	 	7,742	 	
Ending balance	 	$	11,337	 	 	$	5,440	 	 	$	7,883	 	

 
111

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
25.	Supplemental Quarterly Financial Information (Unaudited)	
Net Earnings (Loss) Attributable to Devon
The following tables present a summary of Devon’s unaudited interim results of operations as recast under the successful efforts method of accounting. See Note 2 for additional details. As a result of the conversion to the successful efforts method of accounting in the fourth quarter of 2017, Devon has provided the full consolidated comprehensive statements of earnings for each interim quarter in 2017 to aid investors and facilitate comparative periods to be shown during 2018. Devon has provided the required summary information for each interim quarter in 2016.  
 	 	2017, under Successful Efforts	 	
 	 	First Quarter	 	 	Second Quarter	 	 	Third Quarter	 	 	Fourth Quarter	 	 	Full Year	 	
Upstream revenues	 	$	1,541	 	 	$	1,332	 	 	$	1,101	 	 	$	1,333	 	 	$	5,307	 	
Marketing and midstream revenues	 	 	2,010	 	 	 	1,927	 	 	 	2,055	 	 	 	2,650	 	 	 	8,642	 	
Total revenues	 	 	3,551	 	 	 	3,259	 	 	 	3,156	 	 	 	3,983	 	 	 	13,949	 	
Production expenses	 	 	457	 	 	 	455	 	 	 	448	 	 	 	463	 	 	 	1,823	 	
Exploration expenses	 	 	95	 	 	 	57	 	 	 	57	 	 	 	171	 	 	 	380	 	
Marketing and midstream expenses	 	 	1,814	 	 	 	1,714	 	 	 	1,824	 	 	 	2,378	 	 	 	7,730	 	
Depreciation, depletion and amortization	 	 	528	 	 	 	506	 	 	 	512	 	 	 	528	 	 	 	2,074	 	
Asset impairments	 	 	7	 	 	 	—	 	 	 	2	 	 	 	8	 	 	 	17	 	
Asset dispositions	 	 	(3	)	 	 	(27	)	 	 	(169	)	 	 	(18	)	 	 	(217	)	
General and administrative expenses	 	 	233	 	 	 	214	 	 	 	203	 	 	 	222	 	 	 	872	 	
Financing costs, net	 	 	128	 	 	 	116	 	 	 	128	 	 	 	126	 	 	 	498	 	
Other expenses	 	 	(33	)	 	 	(20	)	 	 	(76	)	 	 	5	 	 	 	(124	)	
Total expenses	 	 	3,226	 	 	 	3,015	 	 	 	2,929	 	 	 	3,883	 	 	 	13,053	 	
Earnings before income taxes	 	 	325	 	 	 	244	 	 	 	227	 	 	 	100	 	 	 	896	 	
Income tax expense (benefit)	 	 	8	 	 	 	(1	)	 	 	15	 	 	 	(204	)	 	 	(182	)	
Net earnings	 	 	317	 	 	 	245	 	 	 	212	 	 	 	304	 	 	 	1,078	 	
Net earnings attributable to noncontrolling interests	 	 	14	 	 	 	26	 	 	 	19	 	 	 	121	 	 	 	180	 	
Net earnings attributable to Devon	 	$	303	 	 	$	219	 	 	$	193	 	 	$	183	 	 	$	898	 	
Net earnings per share attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	0.58	 	 	$	0.41	 	 	$	0.37	 	 	$	0.35	 	 	$	1.71	 	
Diluted	 	$	0.58	 	 	$	0.41	 	 	$	0.37	 	 	$	0.35	 	 	$	1.70	 	
Comprehensive earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	$	317	 	 	$	245	 	 	$	212	 	 	$	304	 	 	$	1,078	 	
Other comprehensive earnings, net of tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign currency translation and other	 	 	8	 	 	 	28	 	 	 	42	 	 	 	5	 	 	 	83	 	
Pension and postretirement plans	 	 	5	 	 	 	4	 	 	 	5	 	 	 	15	 	 	 	29	 	
Other comprehensive earnings, net of tax	 	 	13	 	 	 	32	 	 	 	47	 	 	 	20	 	 	 	112	 	
Comprehensive earnings	 	 	330	 	 	 	277	 	 	 	259	 	 	 	324	 	 	 	1,190	 	
Comprehensive earnings attributable to
   noncontrolling interests	 	 	14	 	 	 	26	 	 	 	19	 	 	 	121	 	 	 	180	 	
Comprehensive earnings attributable to Devon	 	$	316	 	 	$	251	 	 	$	240	 	 	$	203	 	 	$	1,010	 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
 	 	2016, under Successful Efforts	 	
 	 	First Quarter	 	 	Second Quarter	 	 	Third Quarter	 	 	Fourth Quarter	 	 	Full Year	 	
Total revenues	 	$	2,126	 	 	$	2,488	 	 	$	2,882	 	 	$	2,808	 	 	$	10,304	 	
Earnings (loss) before income taxes	 	$	(2,036	)	 	$	(339	)	 	$	787	 	 	$	271	 	 	$	(1,317	)	
Net earnings (loss) attributable to Devon	 	$	(1,550	)	 	$	(326	)	 	$	613	 	 	$	207	 	 	$	(1,056	)	
Basic net earnings (loss) per share attributable to Devon	 	$	(3.27	)	 	$	(0.63	)	 	$	1.17	 	 	$	0.41	 	 	$	(2.09	)	
Diluted net earnings (loss) per share attributable to Devon	 	$	(3.27	)	 	$	(0.63	)	 	$	1.16	 	 	$	0.41	 	 	$	(2.09	)	
The 2017 results include gains from asset dispositions of approximately $217 million (or $0.42 per diluted share), as discussed in Note 3 .
The 2016 results include asset impairments of $1.2 billion (or $2.59 per diluted share) and $81 million (or $0.15 per diluted share), during the first quarter and the fourth quarter of 2016, respectively, as discussed in Note 6 . Additionally, the 2016 quarterly results include gains from asset dispositions of approximately $3 million (or $0.01 per diluted share), $75 million (or $0.14 per diluted share), $830 million (or $1.59 per diluted share) and $575 million (or $1.10 per diluted share) during the first quarter through the fourth quarter of 2016, respectively, as discussed in  Note 3 .
 
The following tables present a summary of Devon’s quarterly consolidated comprehensive statements of earnings information for 2017 and 2016 reported under the full cost method.
 
 	 	2017, under Full Cost	 	
 	 	First Quarter	 	 	Second Quarter	 	 	Third Quarter	 	 	Fourth Quarter	 	 	Full Year	 	
Total revenues	 	$	3,551	 	 	$	3,259	 	 	$	3,156	 	 	$	3,983	 	 	$	13,949	 	
Earnings before income taxes	 	$	598	 	 	$	458	 	 	$	272	 	 	$	403	 	 	$	1,731	 	
Net earnings attributable to Devon	 	$	565	 	 	$	425	 	 	$	228	 	 	$	473	 	 	$	1,691	 	
Basic net earnings per share attributable to Devon	 	$	1.08	 	 	$	0.81	 	 	$	0.43	 	 	$	0.90	 	 	$	3.22	 	
Diluted net earnings per share attributable to Devon	 	$	1.07	 	 	$	0.80	 	 	$	0.43	 	 	$	0.89	 	 	$	3.20	 	
 
 	 	2016, under Full Cost	 	
 	 	First Quarter	 	 	Second Quarter	 	 	Third Quarter	 	 	Fourth Quarter	 	 	Full Year	 	
Total revenues	 	$	2,126	 	 	$	2,488	 	 	$	2,882	 	 	$	2,808	 	 	$	10,304	 	
Earnings (loss) before income taxes	 	$	(3,685	)	 	$	(1,745	)	 	$	1,178	 	 	$	375	 	 	$	(3,877	)	
Net earnings (loss) attributable to Devon	 	$	(3,056	)	 	$	(1,570	)	 	$	993	 	 	$	331	 	 	$	(3,302	)	
Basic net earnings (loss) per share attributable to Devon	 	$	(6.44	)	 	$	(3.04	)	 	$	1.90	 	 	$	0.63	 	 	$	(6.52	)	
Diluted net earnings (loss) per share attributable to Devon	 	$	(6.44	)	 	$	(3.04	)	 	$	1.89	 	 	$	0.63	 	 	$	(6.52	)	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Quarterly Cash Flow
The following table presents a summary of Devon’s quarterly cash flow information as recast under the successful efforts method of accounting. See Note 2 for additional details. Devon has provided this information for each interim quarter in 2017 to aid investors and facilitate comparative periods to be shown during 2018.

 	 	2017	 	
 	 	First Quarter	 	 	Second Quarter	 	 	Third Quarter	 	 	Fourth Quarter	 	 	Full Year	 	
Net earnings	 	$	317	 	 	$	245	 	 	$	212	 	 	$	304	 	 	$	1,078	 	
Net cash from operating activities	 	 	746	 	 	 	738	 	 	 	700	 	 	 	725	 	 	 	2,909	 	
Net cash from investing activities	 	 	(454	)	 	 	(587	)	 	 	(457	)	 	 	(712	)	 	 	(2,210	)	
Net cash from financing activities	 	 	(124	)	 	 	91	 	 	 	157	 	 	 	(115	)	 	 	9	 	
Effect of exchange rate changes on cash	 	 	(8	)	 	 	8	 	 	 	12	 	 	 	(6	)	 	 	6	 	
Net change in cash and cash equivalents	 	 	160	 	 	 	250	 	 	 	412	 	 	 	(108	)	 	 	714	 	
Cash and cash equivalents at beginning of period	 	 	1,959	 	 	 	2,119	 	 	 	2,369	 	 	 	2,781	 	 	 	1,959	 	
Cash and cash equivalents at end of period	 	$	2,119	 	 	$	2,369	 	 	$	2,781	 	 	$	2,673	 	 	$	2,673	 	
  Effects of Accounting Change on Fourth Quarter
As Devon recast the financial statements due to a change in accounting principle during the fourth quarter of 2017, the effects of the accounting change on the fourth quarter consolidated comprehensive statement of earnings and consolidated statement of cash flow are included below. See Note 2 for additional details.
 
 	 	Changes to the Consolidated Comprehensive	 	
 	 	Statement of Earnings	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Quarter Ended December 31, 2017	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Exploration expenses	 	$	—	 	 	$	171	 	 	$	171	 	
Depreciation, depletion and amortization	 	 	417	 	 	 	111	 	 	 	528	 	
Asset dispositions	 	 	1	 	 	 	(19	)	 	 	(18	)	
General and administrative expenses	 	 	174	 	 	 	48	 	 	 	222	 	
Financing costs, net	 	 	124	 	 	 	2	 	 	 	126	 	
Other expenses	 	 	15	 	 	 	(10	)	 	 	5	 	
Earnings before income taxes	 	 	403	 	 	 	(303	)	 	 	100	 	
Income tax benefit	 	 	(191	)	 	 	(13	)	 	 	(204	)	
Net earnings	 	 	594	 	 	 	(290	)	 	 	304	 	
Net earnings attributable to Devon	 	 	473	 	 	 	(290	)	 	 	183	 	
Net earnings per share attributable to Devon:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	0.90	 	 	 	(0.55	)	 	 	0.35	 	
Diluted	 	 	0.89	 	 	 	(0.54	)	 	 	0.35	 	
Comprehensive earnings:	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	594	 	 	 	(290	)	 	 	304	 	
Foreign currency translation and other	 	 	6	 	 	 	(1	)	 	 	5	 	
Comprehensive earnings	 	 	615	 	 	 	(291	)	 	 	324	 	
Comprehensive earnings attributable to Devon	 	 	494	 	 	 	(291	)	 	 	203	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 	 	Changes to the Consolidated	 	
 	 	Statement of Cash Flows	 	
 	 	 	 	 	 	 	 	 	 	As Reported Under	 	
For the Quarter Ended December 31, 2017	 	Under Full Cost	 	 	Changes	 	 	Successful Efforts	 	
Net earnings	 	$	594	 	 	$	(290	)	 	$	304	 	
Depreciation, depletion and amortization	 	 	417	 	 	 	111	 	 	 	528	 	
Exploratory dry hole expense and unproved
   leasehold impairments	 	 	—	 	 	 	139	 	 	 	139	 	
Gains and losses on asset sales	 	 	1	 	 	 	(19	)	 	 	(18	)	
Deferred income tax benefit	 	 	(232	)	 	 	(13	)	 	 	(245	)	
Share-based compensation	 	 	36	 	 	 	11	 	 	 	47	 	
Other	 	 	26	 	 	 	(10	)	 	 	16	 	
Net cash from operating activities	 	 	796	 	 	 	(71	)	 	 	725	 	
Capital expenditures	 	 	(871	)	 	 	72	 	 	 	(799	)	
Divestitures of property and equipment	 	 	102	 	 	 	(1	)	 	 	101	 	
Net cash from investing activities	 	 	(783	)	 	 	71	 	 	 	(712	)	

 

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Item 9.  Changes in and Disagreements with Ac countants 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, 2017 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 21, 2018, management concluded that its internal control over financial reporting was effective as of December 31, 2017.
The effectiveness of our internal control over financial reporting as of December 31, 2017 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, 2017, 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
In the fourth quarter of 2017, we added and modified certain internal control processes as a result of changing our method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. There were no other changes in our internal control over financial reporting during the fourth quarter of 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 Item 9B.  Other Information
Not applicable.

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Index to Financial Statements
 PART III
 Item 10.  Directors, Executive Officers and Corporate Governance
The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2017.
 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, 2017.
 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, 2017.
 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, 2017.
 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, 2017.

 
117

Table of Contents
 
Index to Financial Statements
 
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	 	Agreement and Plan of Merger dated October 21, 2013, by and among Registrant, Devon Gas Services, L.P., Acacia Natural Gas Corp I, Inc., Crosstex Energy, Inc., New Public Rangers L.L.C., Boomer Merger Sub, Inc. and Rangers Merger Sub, Inc. ( incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed October 22, 2013; File No. 001-32318 ).	
 	 	 	
  2.2	 	Contribution Agreement dated October 21, 2013, by and among Registrant, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., Crosstex Energy, L.P. and Crosstex Energy Services, L.P. ( incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed October 22, 2013; File No. 001-32318 ).	
 	 	 	
  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 ).	
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Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  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. 3, dated as of December 19, 2013, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.25% Senior Notes due 2018 ( incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 19, 2013; File No. 001-32318 ).	
 	 	 	
  4.5	 	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 ).	
 	 	 	
  4.6	 	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 ).	
 	 	 	
  4.7	 	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 ).	
 	 	 	
  4.8	 	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 ).	
 	 	 	
  4.9	 	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 ).	
 	 	 	
  4.10	 	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	 	Indenture, dated as of July 8, 1998, among Devon OEI Operating, L.L.C. (as successor to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank, N.A. (as successor to Norwest Bank Minnesota, National Association), as Trustee, relating to the 8.25% Senior Notes due 2018 ( incorporated by reference to Exhibit 10.24 to Ocean Energy, Inc.’s Form 10-Q filed August 14, 1998; File No. 001-14252 ).	
 	 	 	
  4.12	 	First Supplemental Indenture, dated March 30, 1999, to Indenture dated as of July 8, 1998, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and Wells Fargo Bank, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 ( incorporated by reference to Exhibit 4.5 to Ocean Energy, Inc.’s Form 10-Q filed May 17, 1999; File No. 001-08094 ).	
 	 	 	
  4.13	 	Second Supplemental Indenture, dated as of May 9, 2001, to Indenture dated as of July 8, 1998, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and Wells Fargo Bank, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 ( incorporated by reference to Exhibit 99.2 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444 ).	
119

Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  4.14	 	Third Supplemental Indenture, dated January 23, 2006, to Indenture dated as of July 8, 1998, by and among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as Successor Guarantor, and Wells Fargo Bank, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 ( incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K filed March 3, 2006; File No. 001-32318 ).	
 	 	 	
  4.15	 	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 ).	
 	 	 	
  4.16	 	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 ).	
 	 	 	
  4.17	 	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 ).	
 	 	 	
  4.18	 	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 ).	
 	 	 	
  4.19	 	Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee (the “EnLink Indenture”) ( incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Form 8-K filed March 21, 2014; File No. 001-36340 ).†	
 	 	 	
  4.20	 	First Supplemental Indenture, dated as of March 19, 2014, to the EnLink Indenture, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee ( incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Form 8-K filed March 21, 2014; File No. 001-36340 ).†	
 	 	 	
  4.21	 	Second Supplemental Indenture, dated as of November 12, 2014, to the EnLink Indenture, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee ( incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Form 8-K filed November 12, 2014; File No. 001-36340 ).†	
 	 	 	
  4.22	 	Third Supplemental Indenture, dated as of May 12, 2015, to the EnLink Indenture, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee ( incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Form 8-K filed May 12, 2015; File No. 001-36340 ).†	
 	 	 	
  4.23	 	Fourth Supplemental Indenture, dated as of July 14, 2016, to the EnLink Indenture, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee ( incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Form 8-K filed July 14, 2016; File No. 001-36340 ).†	
 	 	 	
  4.24	 	Fifth Supplemental Indenture, dated as May 11, 2017, to the EnLink Indenture, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee ( incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Form 8-K filed May 11, 2017; File No. 001-36340 ).†	
120

Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  10.1	 	Credit Agreement, dated as of October 24, 2012, among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender ( incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 29, 2012; File No. 001-32318 ).	
 	 	 	
  10.2	 	Extension Agreement, dated as of September 3, 2013, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender, with respect to the extension of the maturity date from October 24, 2017 to October 24, 2018 ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 6, 2013; File No. 001-32318 ).	
 	 	 	
  10.3	 	First Amendment to Credit Agreement, dated as of February 3, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender ( incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed February 7, 2014; File No. 001-32318 ).	
 	 	 	
  10.4	 	Extension Agreement, dated as of October 17, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to the extension of the maturity date from October 24, 2018 to October 24, 2019 ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 5, 2014; File No. 001-32318 ).	
 	 	 	
  10.5
 	 	Devon Energy Corporation 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 ).*	
 	 	 	
  10.6	 	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 ).*	
 	 	 	
  10.7	 	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 ).*	
 	 	 	
  10.8	 	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 ).*	
 	 	 	
  10.9	 	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 ).*	
 	 	 	
  10.10	 	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 ).*	
 	 	 	
  10.11	 	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 ).*	
 	 	 	
  10.12	 	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 ).*	
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Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  10.13	 	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 ).*	
 	 	 	
  10.14	 	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 ).*	
 	 	 	
  10.15	 	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 ).*	
 	 	 	
  10.16	 	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 ).*	
 	 	 	
  10.17	 	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 ).*	
 	 	 	
  10.18	 	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 ).*	
 	 	 	
  10.19	 	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 ).*	
 	 	 	
  10.20	 	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 ).*	
 	 	 	
  10.21	 	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 ).*	
 	 	 	
  10.22	 	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 ).*	
 	 	 	
  10.23	 	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 ).*	
 	 	 	
  10.24	 	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 ).*	
 	 	 	
  10.25	 	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 ).*	
 	 	 	
  10.26	 	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 ).*	
 	 	 	
  10.27	 	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 ).*	
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Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  10.28	 	Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2018), executed December 18, 2017.*	
 	 	 	
  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 10.25 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318 ).*	
 	 	 	
  10.34	 	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 ).*	
 	 	 	
  10.35	 	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 ).*	
 	 	 	
  10.36	 	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 ).*	
 	 	 	
  10.37	 	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 ).*	
 	 	 	
  10.38	 	Form of Notice of Grant of Performance Share Unit 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 share units awarded ( incorporated by reference to Exhibit 10.32 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318 ).*	
 	 	 	
  10.39	 	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 ).*	
 	 	 	
  10.40	 	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 ).*	
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Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  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	 	Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all non-management directors for nonqualified stock options granted ( incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed on February 25, 2010; File No. 001-32318 ).*	
 	 	 	
  10.44	 	Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Thomas L. Mitchell for restricted stock awarded ( incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318 ).*	
 	 	 	
  10.45	 	Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2015 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 August 5, 2015; File No. 001-32318 ).*	
 	 	 	
  10.46	 	2017 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Devon and all non-management directors for restricted stock awarded ( incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 2, 2017; File No. 001-32318 ).*	
 	 	 	
  10.47	 	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 ).*	
 	 	 	
  10.48	 	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 ).*	
 	 	 	
  10.49	 	Amendment to Performance Share Unit Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Share Unit Award Agreement dated February 10, 2015 ( incorporated by reference to Exhibit 10.43 to Registrant’s Form 10-K filed February 17, 2016; File No. 001-32318 ).*	
 	 	 	
  10.50	 	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 ).*	
 	 	 	
  12	 	Statement of computations of ratios of earnings to fixed charges.	
 	 	 	
  21	 	List of Subsidiaries.	
 	 	 	
  23.1	 	Consent of KPMG LLP.	
 	 	 	
  23.2	 	Consent of LaRoche Petroleum Consultants, Ltd.	
 	 	 	
  23.3	 	Consent of Deloitte LLP.	
124

Table of Contents
 
Index to Financial Statements
 
Exhibit No.	 	Description	
 	 	 	
  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.	
 	 	 	
  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.	

†	As of December 31, 2017, the aggregate amount of debt issued under the EnLink Indenture, as supplemented, exceeded ten percent of Devon’s consolidated total assets. Devon has not filed any other instruments defining the rights of holders of long-term indebtedness of EnLink, as such instruments do not represent debt exceeding ten percent of the total assets of Devon and its subsidiaries on a consolidated basis. Devon hereby agrees to furnish a copy of any such agreements to the SEC upon request.	
*	Indicates management contract or compensatory plan or arrangement.	

 Item 16. Form 10-K Summary
 
Not applicable.
 
125

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 21, 2018
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 21, 2018	
David A. Hager	 	Director (Principal executive officer)	 	
 	 	 	 	
/s/ JEFFREY L. RITENOUR	 	Executive Vice President	February 21, 2018	
Jeffrey L. Ritenour	 	and Chief Financial Officer
(Principal financial officer)	 	
 	 	 	 	
/s/ JEREMY D. HUMPHERS	 	Senior Vice President	February 21, 2018	
Jeremy D. Humphers	 	and Chief Accounting Officer
(Principal accounting officer)	 	
 	 	 	 	
/s/ JOHN RICHELS	 	Chairman of the Board	February 21, 2018	
John Richels	 	 	 	
 	 	 	 	
/s/ BARBARA M. BAUMANN	 	Director	February 21, 2018	
Barbara M. Baumann	 	 	 	
 	 	 	 	
/s/ JOHN E. BETHANCOURT	 	Director	February 21, 2018	
John E. Bethancourt	 	 	 	
 	 	 	 	
/s/ ROBERT H. HENRY	 	Director	February 21, 2018	
Robert H. Henry	 	 	 	
 	 	 	 	
/s/ MICHAEL M. KANOVSKY	 	Director	February 21, 2018	
Michael M. Kanovsky	 	 	 	
 	 	 	 	
/s/ ROBERT A. MOSBACHER, JR.	 	Director	February 21, 2018	
Robert A. Mosbacher, Jr.	 	 	 	
 	 	 	 	
/s/ DUANE C. RADTKE	 	Director	February 21, 2018	
Duane C. Radtke	 	 	 	
 	 	 	 	
/s/ MARY P. RICCIARDELLO	 	Director	February 21, 2018	
Mary P. Ricciardello	 	 	 	

 
 
126

Exhibit 10.28
DEVON ENERGY CORPORATION
INCENTIVE SAVINGS PLAN
 
As Amended and Restated Effective January 1, 2018

 

TABLE OF CONTENTS
 
Page

ARTICLE I	BACKGROUND AND STATEMENT OF PURPOSE	1	
1.01	Background	1	
1.02	Purposes	1	
1.03	Rights Affected	1	
1.04	Qualification under the Internal Revenue Code	1	
1.05	Documents	1	
ARTICLE II	DEFINITIONS	2	
2.01	"Account"	2	
2.02	"Actual Deferral Percentage"	2	
2.03	"Affiliated Company"	2	
2.04	"Alternate Payee"	2	
2.05	"Annual Addition"	3	
2.06	"Asset Allocation Fiduciary"	3	
2.07	"Automatic Enrollment Date"	3	
2.08	"Average Actual Deferral Percentage"	3	
2.09	"Average Contribution Percentage"	3	
2.10	"Beneficiary"	3	
2.11	"Benefit Payment Date"	3	
2.12	"Board of Directors"	4	
2.13	"Code"	4	
2.14	"Committee"	4	
2.15	"Company"	4	
2.16	"Company Common Stock"	4	
2.17	"Company Common Stock Account"	4	
2.18	"Company Common Stock Fund"	4	
2.19	"Company Retirement Contribution"	4	
2.20	"Company Retirement Contribution Account"	4	
2.21	"Company Retirement Contribution Eligible Participant"	4	
2.22	"Compensation"	4	
2.23	"Contribution Percentage"	5	
2.24	"Disability"	6	
2.25	"Effective Date"	6	
2.26	"Eligible Borrower"	6	
2.27	"Eligible Employee"	6	
2.28	"Employee"	7	
2.29	"Employment Commencement Date"	7	
2.30	"Employer"	7	
2.31	"ERISA"	7	
2.32	"Highly Compensated Employee"	7	
2.33	"Hour of Service"	7	
2.34	"Investment Committee"	8	
2.35	"Investment Fund"	8	
2.36	"Loan Account"	8	
2.37	"Matching Contribution"	8	
i

TABLE OF CONTENTS
(continued)
Page

2.38	"Matching Contribution Account"	8	
2.39	"Named Fiduciary"	8	
2.40	"Non-Highly Compensated Employee"	8	
2.41	"Normal Retirement Age"	8	
2.42	"Participant"	8	
2.43	"Pension Plan"	8	
2.44	"Period of Severance"	8	
2.45	"Plan"	9	
2.46	"Plan Year"	9	
2.47	"QDRO"	9	
2.48	"Qualified Matching Contribution"	9	
2.49	"Qualified Matching Contribution Account"	9	
2.50	"Qualified Military Service"	9	
2.51	"Qualified Nonelective Contribution"	9	
2.52	"Qualified Nonelective Contribution Account"	9	
2.53	"Reemployment Commencement Date"	9	
2.54	"Rollover Account"	9	
2.55	"Rollover Contributions"	9	
2.56	"Roth 401(k) Account"	10	
2.57	"Roth 401(k) Contribution"	10	
2.58	"Roth In-Plan Conversion Account"	10	
2.59	"Roth Rollover Account"	10	
2.60	"Roth Rollover Contributions"	10	
2.61	"Salary Deferral Account"	10	
2.62	"Salary Deferrals"	10	
2.63	"Severance from Service"	10	
2.64	"Severance Date"	11	
2.65	"Spouse"	11	
2.66	"Target Fund"	11	
2.67	"Trust Agreement"	11	
2.68	"Trustee"	11	
2.69	"Trust Fund"	11	
2.70	"Valuation Date"	11	
2.71	"Years of Credited Service"	11	
2.72	"Years of Service"	12	
ARTICLEIII	PARTICIPATION ELIGIBILITY	13	
3.01	Eligibility to Participate	13	
3.02	Ineligible Employees	13	
3.03	Reemployment	13	
3.04	Transfer of Employment	13	
3.05	Procedure for and Effect of Participation	13	
3.06	Plan Mergers and Asset Transfers	13	
ARTICLE IV	CONTRIBUTIONS	14	
4.01	Salary Deferral Contributions and Roth 401(k) Contributions	14	
ii

TABLE OF CONTENTS
(continued)
Page

4.02	Increase in or Reduction of Salary Deferrals and/or Roth 401(k) Contributions	16	
4.03	Combined Limit on Contributions	17	
4.04	Company Retirement Contributions	17	
4.05	Matching Contributions	20	
4.06	Rollover Contributions and Roth In-Plan Conversions	21	
4.07	Qualified Nonelective Contributions and Qualified Matching Contributions	22	
4.08	Contributions with Respect to Military Service	23	
4.09	Timing of Contributions	24	
4.10	Contingent Nature of Contributions	25	
4.11	Exclusive Benefit; Refund of Contributions	25	
ARTICLE V	LIMITATIONS ON CONTRIBUTIONS	26	
5.01	Calendar Year Limitation on Salary Deferrals and Roth 401(k) Contributions	26	
5.02	Nondiscrimination Limitations on Salary Deferrals, Roth 401(k) Contributions, and Matching Contributions	27	
5.03	Correction of Discriminatory Contributions	28	
5.04	Annual Additions Limitations	30	
ARTICLE VI	INVESTMENT AND VALUATION OF TRUST FUND; MAINTENANCE OF ACCOUNTS	31	
6.01	Investment of Assets	31	
6.02	Investment in Investment Funds	31	
6.03	Investment Elections	31	
6.04	Change of Election	32	
6.05	Transfers Between Investment Funds	32	
6.06	Individual Accounts	32	
6.07	Valuation	32	
6.08	Voting and Tender of Mutual Fund Shares	32	
6.09	Special Rules for Company Common Stock Fund	33	
6.10	Fiduciary Responsibility	35	
ARTICLE VII	VESTING	36	
7.01	Full and Immediate Vesting of Salary Deferrals, Roth 401(k) Contributions, Qualified Nonelective Contributions, Qualified Matching Contributions and Rollovers	36	
7.02	Vesting of Employer Contributions	38	
7.03	Effects of Certain Periods of Severance	37	
7.04	Forfeiture of Nonvested Amounts and Restoration upon Reemployment	37	
ARTICLE VIII	BENEFIT DISTRIBUTIONS	39	
8.01	Death Benefits	39	
8.02	Benefits upon Severance from Service	39	
8.03	Form and Timing of Benefit Payment	40	
8.04	Withdrawals	41	
8.05	Beneficiary Designation Right	43	
8.06	Domestic Relations Orders	44	
iii

TABLE OF CONTENTS
(continued)
Page

8.07	Post Distribution Credits	45	
8.08	Direct Rollovers	45	
8.09	Waiver of 2009 Required Distributions	46	
ARTICLE IX	PARTICIPANT LOANS	47	
9.01	Loans in General	47	
9.02	Loans as Trust Fund Investments	48	
ARTICLE X	PROVISIONS RELATING TO TOP-HEAVY PLANS	52	
10.01	Definitions	52	
10.02	Determination of Top-Heavy Status	53	
10.03	Top-Heavy Plan Minimum Allocation	54	
ARTICLE XI	ALLOCATION AND DELEGATION OF AUTHORITY	55	
11.01	Delegation	55	
11.02	Authority and Responsibilities of the Committee	55	
11.03	Authority and Responsibilities of the Trustee	55	
11.04	Authority and Responsibilities of the Investment Committee	55	
11.05	Authority and Responsibilities of the Asset Allocation Fiduciary	56	
11.06	Limitations on Obligations of Named Fiduciaries	56	
11.07	Designation and Delegation	56	
11.08	Engagement of Assistants and Advisers	56	
11.09	Payment of Expenses	56	
11.10	Indemnification	57	
11.11	Bonding	57	
ARTICLE XII	ADMINISTRATION	58	
12.01	Committee	58	
12.02	Authority and Responsibility of the Committee	58	
12.03	Investment Committee	60	
12.04	Committee Procedures	60	
12.05	Serving in More than One Capacity	60	
12.06	Appointment of the Trustee	60	
12.07	Reporting and Disclosure	61	
12.08	Construction of the Plan	61	
12.09	Compensation of the Committee and the Investment Committee	61	
12.10	Ministerial Functions	61	
12.11	Allocation of Duties and Responsibilities	61	
ARTICLE XIII	APPLICATION FOR BENEFITS AND CLAIMS PROCEDURES	62	
13.01	Application for Benefits	62	
13.02	Claims Procedure	62	
ARTICLE XIV	AMENDMENT AND TERMINATION	65	
14.01	Amendment	65	
14.02	Amendments to the Vesting Schedule	65	
14.03	Plan Termination	66	
14.04	Mergers and Consolidations of Plans	66	
ARTICLE XV	CHANGE OF CONTROL	67	
15.01	Change of Control	67	
iv

TABLE OF CONTENTS
(continued)
Page

15.02	Amendment of this ARTICLE XV by the Company	69	
ARTICLE XVI	MISCELLANEOUS PROVISIONS	70	
16.01	Nonalienation of Benefits	70	
16.02	No Contract of Employment	70	
16.03	Severability of Provisions	70	
16.04	Heirs, Assigns and Personal Representatives	70	
16.05	Headings and Captions	70	
16.06	Gender and Number	70	
16.07	Controlling Law	71	
16.08	Funding Policy	71	
16.09	Title to Assets; Source of Benefits	71	
16.10	Payments to Minors, Etc	71	
16.11	Reliance on Data and Consents	71	
16.12	Deemed Acceptance of Act or Omission by a Plan Fiduciary	71	
16.13	Lost Payees	72	
16.14	No Warranties	72	
16.15	Notices	72	
16.16	Recovery of Overpayment	72	
APPENDIX A	DIRECT TRANSFER FROM KERR-MCGEE CORPORATION SAVINGS INVESTMENT PLAN	A-1	
APPENDIX B	PENNZENERGY COMPANY SAVINGS AND INVESTMENT PLAN MERGER	B-1	
APPENDIX C	SANTA FE ENERGY SNYDER SAVINGS INVESTMENT PLAN MERGER	C-1	
APPENDIX D	MITCHELL ENERGY & DEVELOPMENT CORP. THRIFT & SAVINGS PLAN MERGER	D-1	
APPENDIX E	OCEAN RETIREMENT SAVINGS PLAN MERGER	E-1	
APPENDIX F	THUNDER CREEK GAS SERVICES, L.L.C. RETIREMENT SAVINGS PLAN MERGER	F-1	
APPENDIX G	SPECIAL PROVISIONS FOR GEOSOUTHERN CONTINUED EMPLOYEES	G-1	
APPENDIX H	SPECIAL PROVISIONS FOR EMPLOYEES TRANSFERRING TO ENLINK MIDSTREAM OPERATING, LP	H-1	
APPENDIX I	SPECIAL PROVISIONS FOR EMPLOYEES TRANSFERRING TO ENLINK MIDSTREAM OPERATING, LP IN CONNECTION WITH THE CONTRIBUTION OF THE VICTORIA EXPRESS PIPELINE	I-1	

v

ARTICLE I 
 
BACKGROUND AND STATEMENT OF PURPOSE
 1.01 Background .  The Devon Energy Corporation Incentive Savings Plan (the " Plan ") is maintained by Devon Energy Corporation (the " Company ").  The Plan was originally established by the Company on January 1, 1990.  The Plan was amended and restated effective as of October 1, 2007.  The Plan was amended and restated generally effective January 1, 2012 and January 1, 2013, in each case to reflect certain design changes; incorporate amendments; and make certain other clarifying changes.  The Plan was most recently amended and restated generally effective January 1, 2014, except as otherwise required by law or provided therein , to incorporate amendments (including the amendment to reflect the Company's sale of its ownership interest in Thunder Creek Gas Services, L.L.C. and the Plan ceasing to be a multiple employer plan as a result of such sale); amend the definition of "Spouse," to reflect the Supreme Court's decision in United States v. Windsor ; and related guidance and to make certain other clarifying changes.  The Plan again is amended and restated, generally effective January 1, 2018 (the " Effective Date ") , except as otherwise provided herein, to incorporate recent amendments; extend the application of the Plan's automatic advance feature, effective on and after January 1, 2018, to Participants (as defined below) hired before January 1, 2008; and make certain other clarifying changes.
 1.02 Purposes .  The purposes of the Plan are to encourage systematic savings to meet the financial needs of Eligible Employees both during active employment and during retirement and to make available a number of investment vehicles for such savings.  
 1.03 Rights Affected .  Except as otherwise required by law or an amendment or as provided to the contrary herein, the provisions of this amended and restated Plan shall apply only to Employees who complete an Hour of Service on or after the Effective Date.  The rights of any other person shall be governed by the Plan as in effect on the date of his Severance from Service, except to the extent expressly provided in any amendment adopted subsequently thereto.
 1.04 Qualification under the Internal Revenue Code .  It is intended that the Plan be a qualified profit-sharing plan within the meaning of Code section 401(a), that the requirements of Code section 401(k) or 414(v) be satisfied as to that portion of the Plan represented by contributions made pursuant to Participant Salary Deferral elections, that the requirements of Code section 401(m) be satisfied as to that portion of the Plan represented by Matching Contributions and that the trust or other funding vehicle associated with the Plan be exempt from federal income taxation pursuant to the provisions of Code section 501(a).  The Company Common Stock Fund has been designated an employee stock ownership plan as defined in Code section 4975(e)(7).
 1.05 Documents .  The Plan consists of the Plan document as set forth herein, and any amendment thereto.  Certain provisions relating to the Plan and its operation are contained in the corresponding Trust Agreement (or documents establishing any other funding vehicle for the Plan), and any amendments, supplements, appendices and riders to any of the foregoing.
1

ARTICLE II 
 
DEFINITIONS
 2.01 " Account " shall mean the entire interest of a Participant in the Plan.  A Participant's Account shall consist of one or more separate accounts reflecting the various types of contributions permitted under the Plan, as hereinafter provided.  Without limiting the foregoing, the term "Account" shall also include any separate account established for purposes of accounting for the assets that have been transferred to the Trust Fund from another plan.  Participants' rights with respect to such separate accounts shall be determined in accordance with the terms of the Plan or, if applicable, the terms of the Plan as in effect at the time such separate accounts were established.  
 2.02 " Actual Deferral Percentage " shall mean the ratio (expressed as a percentage to the nearest one-hundredth of one percent) of (a) (1) an active Participant's Salary Deferrals and Roth 401(k) Contributions for the Plan Year (excluding any Salary Deferrals and Roth 401(k) Contributions that are (A) taken into account in determining the Contribution Percentage, (B) distributed to an active Participant who is not a Highly Compensated Employee pursuant to a claim for distribution under Section 5.01, (C) returned to the Participant pursuant to Section 5.04 or (D) contributed pursuant to Section 4.01(b)), plus (2) at the election of the Committee, any portion of the Qualified Nonelective Contributions allocated to the Participant for the Plan Year permitted to be taken into account under Code section 401(k), plus (3) in the case of any Highly Compensated Employee who is eligible to participate in more than one cash or deferred arrangement maintained by the Employer or an Affiliated Company, elective deferrals made on his behalf under all such arrangements (excluding those that are not permitted to be aggregated with the Plan under Treas. Reg. § 1.401(k)-1(b)(4)) for the Plan Year, to (b) the Participant's Compensation for the entire Plan Year, including the portion of the Plan Year when he was an Employee but was not eligible to participate in the Plan.
 2.03 " Affiliated Company " shall mean any entity which (a) with the Company constitutes (1) a "controlled group of corporations" within the meaning of Code section 414(b), (2) a "group of trades or businesses under common control" within the meaning of Code section 414(c), or (3) an "affiliated service group" within the meaning of Code section 414(m), or (b) is required to be aggregated with the Company pursuant to Treasury Regulations under Code section 414(o).  An entity shall be considered an Affiliated Company only with respect to such period as the relationship described in the preceding sentence exists.  For purposes of Section 2.05 or 5.04, "Affiliated Company" shall mean an Affiliated Company, but determined with "more than 50 percent" substituted for the phrase "at least 80 percent" in Code section 1563(a)(1) when applying Code sections 414(b) and (c).
 2.04 " Alternate Payee " shall mean the person entitled to receive payment of benefits under the Plan pursuant to a QDRO.
2

2.05 " Annual Addition " shall mean, for any Participant for any Plan Year, the sum of the following amounts allo cated to a Participant's Accounts under the Plan and any other qualified defined contribution plan maintained by the Employer or an Affiliated Company:
(a) Employer contributions (including Matching Contributions; Salary Deferral amounts, except Salary Deferrals contributed pursuant to Section 4.01(b) or distributed pursuant to Section 5.01; Roth 401(k) Contributions; Company Retirement Contributions; Qualified Nonelective Contributions and Qualified Matching Contributions);
(b) Participant contributions (including mandatory or voluntary employee contributions made under a qualified defined benefit plan of the Employer or an Affiliated Company, but excluding Rollover Contributions and amounts repaid pursuant to Section 9.02(f));
(c) forfeitures (to the extent not used to pay Plan expenses); and
(d) amounts described in Code section 415(l)(1) (relating to contributions allocated to individual medical accounts which are part of a pension or annuity plan) and Code section 419A(d)(2) (relating to contributions allocated to post-retirement medical benefit accounts for key employees).
 2.06 " Asset Allocation Fiduciary " shall mean, if and to the extent appointed by the Investment Committee, the Named Fiduciary with the authority and responsibilities set forth in Section 11.05.
 2.07 " Automatic Enrollment Date " shall mean, for each Eligible Employee who has an Employment Commencement Date on and after January 1, 2008 and who does not make an affirmative election to make (or not to make) Salary Deferrals to the Plan in accordance with Section 4.01, the first day of the payroll period commencing as soon as administratively practicable following the Eligible Employee's Employment Commencement Date.  
 2.08 " Average Actual Deferral Percentage " shall mean the average (expressed as a percentage to the nearest one-hundredth of one percent) of the Actual Deferral Percentages of a specified group of active Participants.
 2.09 " Average Contribution Percentage " shall mean the average (expressed as a percentage to the nearest one-hundredth of one percent) of the Contribution Percentages of a specified group of active Participants.
 2.10 " Beneficiary " shall mean the person or entity designated or otherwise determined to be such in accordance with Section 8.05.
 2.11 " Benefit Payment Date " shall mean, for any Participant or Beneficiary of a deceased Participant, the date as of which the first benefit payment from a Participant's Account is due; provided, however, that the Benefit Payment Date applicable to any amount withdrawn pursuant to Section 8.04 shall not be taken into account in determining the Participant's Benefit Payment Date with respect to the remainder of his Account.
3

2.12 " Board of Directors " shall mean the board of directors of the Company or a committee of the Board of Director s to which the Board of Directors has delegated some or all of its responsibilities hereunder.  
 2.13 " Code " shall mean the Internal Revenue Code of 1986, as the same may be amended from time to time, and any successor statute of similar purpose.
 2.14 " Committee " shall mean the Benefits Committee appointed by the Compensation Committee of the Board of Directors to administer the Plan or an individual or entity to which the Committee has delegated some or all of its responsibilities.
 2.15 " Company " shall mean Devon Energy Corporation, a Delaware corporation, and its successors.
 2.16 " Company Common Stock " shall mean the voting common stock of Devon Energy Corporation.
 2.17 " Company Common Stock Account " shall mean the Account to which the Trustee shall credit (a) the Participant's allocable share of Company Common Stock Fund purchased by the Trustee or contributed by the Company to the Trust Fund for that year; (b) the Participant's allocable share of any forfeitures of Company Common Stock Fund arising under the Plan during that year; and (c) any stock dividends declared and paid during that year on Company Common Stock credited to the Participant's Company Common Stock Account.
 2.18 " Company Common Stock Fund " shall mean a separate Investment Fund invested primarily in Company Common Stock.  
 2.19 " Company Retirement Contribution " shall mean a contribution made by an Employer pursuant to Section 4.04.
 2.20 " Company Retirement Contribution Account " shall mean so much of a Participant's Account attributable to Company Retirement Contributions allocated to such Participant's Account, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable thereagainst and all withdrawals and distributions therefrom.
 2.21 " Company Retirement Contribution Eligible Participant " shall mean a Participant who (i) became employed before October 1, 2007 and voluntarily elected to cease or to not begin accruing a benefit under the Pension Plan; (ii) has an Employment Commencement Date on or after October 1, 2007; (iii) has an Employment Commencement Date before October 1, 2007 and ceases to be an active participant under the Pension Plan; or (iv) is a nonresident alien Employee paid through the Employer's United States payroll.
 2.22 " Compensation " shall mean for any Employee for any Plan Year:
 (a) Except as otherwise provided in this definition, (i) all base pay, overtime pay and annual discretionary performance bonuses (which, by example, shall not include stay payments, signing bonuses, Christmas or holiday bonuses, or retention bonuses, among other
4

items) paid to a Participant by the Employer during a Plan Year; (ii) any amounts deferred or excluded from gross income pursuant to Code section 401(k), 125 (which shall be deemed to include any amounts not available to a Participant in cash in lieu of group health coverage because the Participant is unable to certify that he has other health coverage, so long as the Employer does not request or collect information regarding the Participant's other health coverage as part of the enrollment process for the Employer's health plan), 402(e)(3), 402(h) or 403(b) w ith respect to employee benefit plans sponsored by the Employer; and (iii) amounts that are not includible in the gross income of the Participant by reason of Code section 132(f)(4).  
(b) Compensation shall include the amount of any differential military wage payments paid to the Participant by the Employer with respect to any period of active military service in accordance with Code sections 3401(h) and 414(u)(12).
(c) Only $200,000 of a Participant's Compensation (adjusted in accordance with Code section 401(a)(17)(B)) shall be taken into account for purposes of the Plan.
(d) Notwithstanding anything to the contrary herein, Compensation shall not include (i) amounts paid to a Participant after termination of employment as a cash out or payment of unused vacation pay, sick pay or other paid time off or (ii) other amounts paid to a Participant after termination of employment, other than payments made within three weeks of the date of termination of employment and which is regular pay that is paid in accordance with the Employer's normal payroll processes and which would have been paid to the Participant prior to the termination of employment if the Participant had continued in the employment of the Employer.  By way of example, and not limitation, Compensation shall not include severance pay or severance bonus amounts regardless of when such amounts are paid to a Participant.
(e) For purposes of Section 4.08, "Compensation" shall mean the Compensation, as defined in subsection (a), that the Participant would have received during a period of Qualified Military Service (or, if the amount of such Compensation is not reasonably certain, the Participant's average earnings from the Employer or an Affiliated Company for the 12-month period immediately preceding the Participant's period of Qualified Military Service); provided, however, that the Participant returns to work within the period during which his right to reemployment is protected by law.
(f) For purposes of applying the nondiscrimination limitations of Section 5.02, the Annual Additions limitations of Section 5.04, the top-heavy provisions of ARTICLE X, and the definition of Highly Compensated Employee, Compensation shall mean compensation as defined in Treas. Reg. § 1.415(c)-2(d)(4) (including all of the mandatory and optional items of compensation described in the special timing rules set forth in Treas. Reg. § 1.415(c)-2(e)).
 2.23 " Contribution Percentage " shall mean the ratio (expressed as a percentage to the nearest one-hundredth of one percent) of (a) (1) the Matching Contributions allocated to an active Participant's Account for the Plan Year (excluding any Matching Contributions forfeited pursuant to ARTICLE V), plus (2) at the election of the Committee, any portion of the Qualified Nonelective Contributions or Qualified Matching Contributions allocated to the Participant for the Plan Year required or permitted to be taken into account under Code section 401(m), plus (3) in the case of any Highly Compensated Employee who is eligible to participate in more than one
5

plan maintained by the Employer or an Affiliated Company to which employee or matching contributions are made, after-tax employee contributions and employer matching co ntributions made on his behalf under all such plans (excluding those that are not permitted to be aggregated with the Plan under Treas. Reg. § 1.401(m)-1(b)(4)) for the Plan Year, to (b) the Participant's Compensation for the entire Plan Year, including th e portion of the Plan Year when he was an Employee but was not eligible to participate in the Plan.  For purposes of determining Contribution Percentages, the Employer or the Committee may take Salary Deferrals into account (excluding Salary Deferrals cont ributed pursuant to Section 4.01(b) ) and Roth 401(k) Contributions, in accordance with Treasury Regulations, so long as the requirements of Section   5.02(a) are met both when the Salary Deferrals used in determining Contribution Percentages are and are not included in determining Actual Deferral Percentages.
 2.24 " Disability " shall mean the definition of such term under the federal Social Security Act where the Participant becomes entitled to, and commences receipt of, disability benefits under such Act.
 2.25 " Effective Date " shall mean January 1, 2018, the effective date of this amended and restated Plan.  The original effective date of the Plan is January 1, 1990.
 2.26 " Eligible Borrower " means a Participant or Beneficiary who meets the eligibility requirements of Section 9.01(a) for a loan from the Plan.
 2.27 " Eligible Employee " means:
(a) Except as otherwise provided by this definition, each Employee of the Employer.
 (b) Eligible Employees do not include: (1) Employees whose terms and conditions of employment are determined through collective bargaining and set forth in a collective bargaining agreement to which the Employer is a party, where the issue of retirement benefits has been the subject of good-faith bargaining, unless such agreement provides for the participation of such Employees in the Plan; (2) any person who is an Employee solely by reason of being a leased employee within the meaning of Code section 414(n) or 414(o); (3) an Employee of the Employer who is a nonresident alien and who does not receive from the Employer any earned income under Code section 911(d)(2) that constitutes income from sources within the United States under Code section 861(a)(3), provided, however, that a nonresident alien who is paid through the Employer's United States payroll, shall not be included in this clause (3); (4) any person whose services have been obtained through a separate contract and who is classified as a fee-for-service worker, leased employee, or an independent contractor or otherwise as a person who is not treated as an employee for purposes of withholding federal employment taxes, regardless of any contrary governmental or judicial determination relating to such employment status or tax withholding obligation; (5) any Employee who is employed by a non-U.S. Affiliated Company and whose services with such non-U.S. Affiliated Company are covered by a secondment agreement (or similar agreement) with the Employer; and (6) any person who is classified as an "intern" under the Employer's standard personnel policies.  If a person described in the preceding sentence is subsequently reclassified as, or determined to be, an employee by the Internal Revenue Service, any other governmental agency or authority, or a
6

court, or if an Employer or Affiliated Company is required to reclassify such an individual as an employee as a result of such reclassification or determination (including any reclassification by an Employer or Affiliated Company in settlem ent of any claim or action relating to such individual's employment status), such individual shall not become eligible to become a Participant in this Plan by reason of such reclassification or determination.
 2.28 " Employee " shall mean any person who is employed by the Employer or an Affiliated Company and who is classified by the Employer or Affiliated Company as a common-law employee.  A person who is not otherwise employed by an Employer or Affiliated Company shall be deemed to be employed by any such company if (i) he is a leased employee with respect to whose services such Employer or Affiliated Company is the recipient, within the meaning of Code section 414(n) or 414(o), but to whom Code section 414(n)(5) does not apply, or (ii) under common law agency rules, he has performed services for the Employer and/or a related person (within the meaning of Code section 414(n)(6)) under the direction and control of such Employer and/or related person, pursuant to an agreement between the Employer and any other individual or entity, on a substantially full-time basis for a period of at least one year.
 2.29 " Employment Commencement Date " shall mean, with respect to any person, the first date on which that person performs an Hour of Service or, with respect to a person who has incurred a Period of Severance, the first date following the Period of Severance on which that person performs an Hour of Service; provided, however, that  for purposes of Sections 4.04 and 4.05, "Employment Commencement Date" shall mean the first date on which that person performs an Hour of Service as an Eligible Employee or, if applicable, the first date following the Period of Severance on which that person performs an Hour of Service as an Eligible Employee.
 2.30 " Employer " shall mean the Company and any Affiliated Company as may from time to time participate in the Plan by authorization of the Board of Directors and authorization of the board of directors of such Affiliated Company.
 2.31 " ERISA " shall mean the Employee Retirement Income Security Act of 1974, as the same may be amended from time to time, and any successor statute of similar purpose.
 2.32 " Highly Compensated Employee " shall mean any Employee who performed services for an Employer or an Affiliated Company during the Plan Year for which a determination is being made (the " Determination Year ") and who:
(a) was at any time in the Determination Year or the immediately preceding Determination Year a 5% owner, as defined in Code section 416(i); or
(b) for the immediately preceding Determination Year, received Compensation from the Employer or an Affiliated Company in excess of $80,000, as adjusted by the Secretary of the Treasury in accordance with Code section 414(q).
 2.33 " Hour of Service " shall mean, for any Employee, an hour for which he is directly or indirectly compensated, or is entitled to be compensated by the Employer or an Affiliated Company, for the performance of duties, including each hour for which he is absent for Qualified Military Service; provided that the Employee returns to service with the Employer or Affiliated Company within such period as his right to reemployment is protected by law.
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2.34 " Investment Committe e " shall mean the Retirement Plans Investment Committee appointed by the Compensation Committee of the Board of Directors as provided herein.
 2.35 " Investment Fund " shall mean any of the funds established pursuant to Section 6.02 for the investment of the assets of the Trust Fund.
 2.36 " Loan Account " shall mean the Account described in Section 9.02 and shall have the meaning set forth therein.
 2.37 " Matching Contribution " shall mean an Employer contribution made pursuant to Section 4.05.
 2.38 " Matching Contribution Account " shall mean so much of a Participant's Account as consists of amounts attributable to Matching Contributions allocated to such Participant's Account, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable thereagainst and by all withdrawals and distributions therefrom.
 2.39 " Named Fiduciary " shall mean the Compensation Committee of the Board of Directors, the Trustee, the Investment Committee, the Committee and, if and to the extent appointed, the Asset Allocation Fiduciary.  Each Named Fiduciary shall have only those particular powers, duties, responsibilities and obligations as are specifically delegated to him under the Plan or the Trust Agreement.  Any fiduciary, if so appointed, may serve in more than one fiduciary capacity and may also serve in a non-fiduciary capacity.
 2.40 " Non-Highly Compensated Employee " shall mean an Employee who is not a Highly Compensated Employee.
 2.41 " Normal Retirement Age " shall mean age 65.
 2.42 " Participant " shall mean an Eligible Employee who meets the eligibility requirements of Section 3.01 and who becomes a Participant as provided in ARTICLE III hereof, or a person who has an undistributed interest in the Trust Fund.
 2.43 " Pension Plan " shall mean the Retirement Plan for Employees of Devon Energy Corporation (or any successor plan) as amended from time to time.
 2.44 " Period of Severance " shall mean a 12-consecutive-month period beginning on an Employee's Severance Date or any anniversary thereof and ending on the next succeeding anniversary of such Severance Date during which the Employee is not credited with at least one Hour of Service.  In the case of an Employee who is absent from work for maternity or paternity reasons, the 12-consecutive-month period beginning on the first anniversary of the first day of such absence shall not constitute a Period of Severance.  For the purposes of this Section, an absence from work for maternity or paternity reasons means an absence (a) by reason of the pregnancy of the Employee, (b) by reason of the birth of a child of the Employee, (c) by reason of the placement of a child with the Employee in connection with the adoption of such child by such Employee, or (d) for purposes of caring for such child for a period beginning immediately following such birth or placement.  An Employee's absence from work for maternity or paternity
8

reasons shall be determined in accordance with such uniform and nondiscriminatory procedures as the Committee may establish.
 2.45 " Plan " shall mean the Devon Energy Corporation Incentive Savings Plan, as set forth herein, and as the same may from time to time hereafter be amended.
 2.46 " Plan Year " means the 12-month period that begins January 1 and ends December 31.
 2.47 " QDRO " shall mean a "qualified domestic relations order" within the meaning of section 206(d)(3)(B) of ERISA and Code section 414(p).
 2.48 " Qualified Matching Contribution " shall mean a contribution made by an Employer pursuant to Section 4.07.
 2.49 " Qualified Matching Contribution Account " shall mean so much of a Participant's Account as consists of amounts attributable to Qualified Matching Contributions allocated to such Participant's Account, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.
 2.50 " Qualified Military Service " shall mean any service in the uniformed services (as defined in chapter 43 of title 38, United States Code) where the Participant's right to reemployment is protected by law.
 2.51 " Qualified Nonelective Contribution " shall mean a contribution made by an Employer pursuant to Section 4.07.
 2.52 " Qualified Nonelective Contribution Account " shall mean so much of a Participant's Account as consists of amounts attributable to Qualified Nonelective Contributions allocated to such Participant's Account, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.
 2.53 " Reemployment Commencement Date " shall mean, with respect to any person, the first date on which that person performs an Hour of Service following his or her most recent Severance from Service; provided, however, that for purposes of Sections 4.04 and 4.05, "Reemployment Commencement Date" shall mean the first date on which that person performs an Hour of Service as an Eligible Employee following his or her most recent Severance from Service.
 2.54 " Rollover Account " shall mean so much of a Participant's Account as consists of his Rollover Contributions that are not Roth Rollover Contributions, including all earnings and gains attributable thereto, and reduced by all losses attributable thereto, all expenses chargeable thereto and all withdrawals and distributions therefrom.
 2.55 " Rollover Contributions " shall mean amounts contributed by an Eligible Employee pursuant to Section 4.06(a).
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2.56 " Roth 401( k) Account " shall mean so much of the Participant's Account under the Plan as is comprised of the Roth 401(k) Contributions credited to the Participant under the Plan, including all earnings and gains attributable thereto, and reduced by all losses a ttributable thereto, all expenses chargeable thereto and all withdrawals and distributions therefrom.
 2.57 " Roth 401(k) Contribution " shall mean so much of a Participant's Account as is attributable to Salary Deferrals irrevocably designated by the Participant as Roth 401(k) Contributions pursuant to Section 4.01(a)(6).
 2.58 " Roth In-Plan Conversion Account " shall mean so much of a Participant's Account as is composed of amounts converted to Roth 401(k) Contributions pursuant to a Roth in-plan conversion election in accordance with Section 4.06(b)(1) and the requirements of Code section 402A(c)(4) and the regulations and rulings promulgated thereunder, including all earnings and gains attributable thereto, and reduced by all losses attributable thereto, all expenses chargeable thereto and all withdrawals and distributions therefrom.
 2.59 " Roth Rollover Account " shall mean so much of a Participant's Account as consists of his Roth Rollover Contributions and amounts attributable to his Rollover Account (other than Roth Rollover Contributions) for which he made a Roth in-plan conversion election under Section 4.06(b)(2), including all earnings and gains attributable thereto, and reduced by all losses attributable thereto, all expenses chargeable thereto and all withdrawals and distributions therefrom.
 2.60 " Roth Rollover Contributions " shall mean amounts contributed by an Eligible Employee pursuant to Section 4.06 and attributable to a direct rollover from a designated Roth contribution account (within the meaning of Code section 402A(b)(2)).
 2.61 " Salary Deferral Account " shall mean so much of a Participant's Account as consists of his Salary Deferrals, including all earnings and gains attributable thereto, and reduced by all losses attributable thereto, all expenses chargeable thereto and all withdrawals and distributions therefrom.
 2.62 " Salary Deferrals " shall mean the portion of a Participant's Compensation (other than Roth 401(k) Contributions) that is reduced in accordance with Sections 4.01(a) and 4.01(b) and with respect to which a corresponding contribution is made to the Plan by the Employer pursuant to Section 4.01(d).
 2.63 " Severance from Service " shall mean, for any Employee, his severance from employment, death, retirement, voluntary or involuntary termination, or any other absence or termination that causes him to cease to be an Employee.
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2.64 " Severance Date " shall mean the earlier of (a) the date on which an Employee incurs a Severance from Service, or (b) the first anniversary of the date that the Employ ee is otherwise first absent from work from the Employer and all Affiliated Companies (with or without pay) for any other reason (other than a period of long-term disability under a long-term disability plan or program sponsored by the Employer, or an appr oved leave of absence granted in writing by the Employer according to a uniform rule applied without discrimination; provided that the Employee returns to the employ of the Employer upon completion of the approved leave); provided, however, that an Employe e shall not be considered to have had a Severance Date during a period of Qualified Military Service if he returns to active service with the Employer or an Affiliated Company within such period during which his reemployment rights are protected by law.
 2.65 " Spouse " shall mean for periods on and after June 26, 2013 an individual (whether of the same or opposite sex) to whom the Participant is legally married under applicable state or foreign law; provided, however, that from June 26, 2013 through September 15, 2013, the Participant's marital status, in the case of a same-sex marriage, shall be determined under the laws of the state in which the Participant is domiciled.  The term "Spouse" shall also include a former Spouse of a Participant to the extent required by a QDRO.
 2.66 " Target Fund " shall have the meaning assigned in Section 6.02(c).  
 2.67 " Trust Agreement " shall mean the trust instrument executed by the Company and the Trustee for purposes of providing a vehicle for investment of the assets of the Plan.
 2.68 " Trustee " shall mean the party or parties so designated pursuant to the Trust Agreement and each of their respective successors.
 2.69 " Trust Fund " shall mean all of the assets of the Plan held by the Trustee under the Trust Agreement.
 2.70 " Valuation Date " shall mean each business day and such other dates as determined by the Committee.
 2.71 " Years of Credited Service " shall mean the service credited to a Company Retirement Contribution Eligible Participant for purposes of determining the amount of such Participant's Company Retirement Contributions pursuant to Section 4.04.  The following rules shall apply in calculating Years of Credited Service under the Plan:
(a) Except as otherwise provided herein, Years of Credited Service shall mean the sum of (1) the years of benefit accrual service earned under the Pension Plan, and (2) Years of Service credited under the Plan for periods after December 31, 2007.
(b) For any Company Retirement Contribution Eligible Participant with a Severance from Service on or after October 1, 2007, Years of Credited Service shall not include any Years of Service accumulated prior to such Severance from Service.
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2.72 " Years of Service " shall mean the service credited to an Employee for purposes of determining an Employee's ve sted interest in his Account.  The following rules shall apply in calculating Years of Service under this Plan.
 (a) An Employee shall be credited with full and partial Years of Service for the period from his Employment Commencement Date to his Severance Date.  Years of Service shall be calculated on the basis that 12 consecutive months of employment equal one year and nonconsecutive periods of service for vesting purposes that are not disregarded under Section 7.03 shall be aggregated.  Fractional periods of a year will be expressed in terms of days.  The following additional rules shall apply in calculating Years of Service under this subsection (a):
(1) If an Employee retires, quits or is discharged or otherwise experiences a Severance from Service, the period commencing on the Employee's Severance Date and ending on the first date on which he again performs an Hour of Service shall be taken into account, if such date is within 12 consecutive months of the date on which he last performed an Hour of Service.
(2) If an Employee is absent from work for a reason other than one specified in Section 2.63 and within 12 months of the first day of such absence the Employee retires, quits or is discharged, or otherwise experiences a Severance from Service, the period commencing on the first day of such absence and ending on the first day he again performs an Hour of Service shall be taken into account, if such day is within 12 months of the date his absence began.
 (3) If a Participant has a Period of Severance, Years of Service before the Period of Severance shall be taken into account only after he completes one Year of Service following the end of such Period of Severance.   
(4) Years of Service shall include employment with an Affiliated Company.
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ARTICLE III 
 
 PARTICIPATION ELIGIBILITY
 3.01 Eligibility to Participate .
(a) Each Eligible Employee as of the Effective Date who was eligible to participate in the Plan immediately before the Effective Date shall be eligible to participate in the Plan as of the Effective Date.  
(b) Each other Eligible Employee shall be eligible to participate in the Plan immediately upon his Employment Commencement Date.
 3.02 Ineligible Employees .  In the event an Employee who is not an Eligible Employee becomes an Eligible Employee, such Employee shall be eligible to participate in the Plan immediately upon becoming an Eligible Employee.  In the event a Participant becomes ineligible to participate because he is no longer an Eligible Employee, such Employee shall participate immediately upon again becoming an Eligible Employee.
 3.03 Reemployment .  An Employee or Participant who incurs a Severance Date shall become eligible to participate in the Plan immediately upon his date of rehire as an Eligible Employee.
 3.04 Transfer of Employment .  If a Participant transfers employment from one Employer to another Employer, such transfer shall not be deemed a Severance from Service for purposes of the Plan.
 3.05 Procedure for and Effect of Participation .  Each Participant shall complete such forms, either in writing or via electronic means, and provide such data as are reasonably required by the Committee as a precondition of such participation.  Participation shall commence as soon as administratively practicable after the later of the Eligible Employee's Employment Commencement Date and the date on which the Eligible Employee has completed the required enrollment procedures for the Plan.  Notwithstanding the foregoing, an Eligible Employee shall become a Participant on his Automatic Enrollment Date if such Eligible Employee is deemed to have made an election to reduce his Compensation as set forth in Section 4.01(a)(1).  By becoming a Participant, each Eligible Employee shall for all purposes be deemed conclusively to have assented to the terms and provisions of the Plan and the corresponding Trust Agreement, and all amendments to such instruments.
 3.06 Plan Mergers and Asset Transfers .  Individuals who have Accounts in the Plan by reason of an asset transfer or plan merger with and into the Plan, but who do not otherwise commence participation in the Plan in accordance with this ARTICLE III shall be subject to the Plan's terms in the same manner as any other Participant who accumulated an Account in the Plan and then experienced a Severance from Service.
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ARTICLE IV 
 
CONTRIBUTIONS
 4.01 Salary Deferral Contributions and Roth 401(k) Contributions .  
 (a) Elections .  
 (1) Subject to Section 3.05 and the limitations set forth herein and in ARTICLE V, each Participant may elect to reduce any Compensation received during a payroll period beginning on and after the effective date of the election, through payroll reductions, by an amount up to 50% and contribute such amounts to the Plan as Salary Deferrals.  Any such election shall be denominated in such percentage multiples or dollar amounts as the Committee may prescribe and shall otherwise be subject to such uniform and nondiscriminatory procedures as the Committee may establish.  Without limiting the foregoing, the Committee may permit Participants to make separate deferral elections for annual discretionary performance bonuses.  Amounts contributed to the Plan as Salary Deferrals shall be contributed to the Participant's Salary Deferral Account.
(2) Each Eligible Employee with an Automatic Enrollment Date shall be deemed to have made an election, effective as of such Automatic Enrollment Date, to reduce his Compensation (effective January 1, 2016, including Compensation attributable to annual discretionary performance bonuses) by 3% and to contribute such amounts to the Plan as Salary Deferrals.
 (3) Each Eligible Employee as of November 15, 2015 who (A) is determined by the Committee or its delegate, in accordance with uniform and nondiscriminatory procedures, to have elected to contribute to the Plan as Salary Deferrals and/or Roth Contributions a percentage of Compensation attributable to the annual discretionary performance bonus that is less than the maximum percentage of Matching Contributions for which the Eligible Employee is eligible under Section 4.05(a) and (B) does not otherwise make an affirmative election to the contrary, shall be deemed to have made an election, effective January 14, 2016, to increase the reduction in his or her Compensation attributable to his annual discretionary performance bonus by such amount as the Committee or its delegate determines in accordance with uniform and nondiscriminatory procedures is necessary for the Eligible Employee to receive the maximum Matching Contribution for which the Eligible Employee would be eligible under Section 4.05(a) and to contribute such amount to the Plan as Salary Deferrals (or as Roth 401(k) Contributions if the Eligible Employee has an election in effect as of November 15, 2015 to designate 100% of his Salary Deferrals as Roth 401(k) Contributions); provided, however, that if the Committee or its delegate determines in accordance with uniform and nondiscriminatory procedures that the Eligible Employee is expected to reach the limit described under Section 5.01(a) before December 31, 2016, the Eligible Employee shall not be deemed to have made an election to change his contribution percentages under this Paragraph.
 (4) Each Eligible Employee as of February 19, 2016 (other than any Eligible Employee who will cease to be employed by reason of the reduction in force announced by the Company in February 2016) who (A) is determined by the Committee or its delegate, in accordance with uniform and nondiscriminatory procedures, to have elected to contribute to the
14

Plan as Salary Deferrals and/or Roth Contributions a percentage of Compensation that is less than the maximum percentage of Matching Contributions for which the Eligible E mployee is eligible under Section 4.05(a) and (B) does not otherwise make an affirmative election to the contrary, shall be deemed to have made an election, effective April 22, 2016, to contribute a percentage of his or her Compensation (other than Compensation attributable to his annual discretionary performance bonus) to the Plan as Salary Deferrals (or as Roth 401(k) Contributions if the Eligible Employee has an election in effect as of February 19, 2016 to designate 100% of his Salary Deferrals as Roth 401(k) Contributions) that is equal to the maximum percentage of Matching Contributions for which the Eligible Employee is eligible under Section 4.05(a) ; provided, however, that if the Committee or its delegate determines in accordance with uniform and nondiscriminatory procedures that the Eli gible Employee is expected to reach the limit described under Section 5.01(a) before December 31, 2016, the Eligible Employee shall not be deemed to have made an election to change his contribution percentages under this Paragraph.
(5) Each Eligible Employee (before January 1, 2018, each Eligible Employee who has an Employment Commencement date on and after January 1, 2008), other than an Eligible Employee who is eligible to participate in the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as determined under that plan), as of the Determination Date who (A) is determined to have elected to contribute to the Plan as Salary Deferrals and/or Roth Contributions a percentage of Compensation (including the separate election, if any, for annual discretionary performance bonus amounts) that is less than the maximum percentage of Matching Contributions for which the Eligible Employee is eligible under Section 4.05(a) and (B) does not otherwise make an affirmative election to the contrary, shall be deemed to have made an election, effective the first pay period in January of the following Plan Year (starting with the Plan Year beginning on January 1, 2017), to make or increase the reduction in his or her Compensation (up to the maximum percentage of Matching Contributions for which the Eligible Employee is eligible under Section 4.05(a)) and, effective in February of that Plan Year, if the Participant would still be contributing less than the maximum Matching Contributions, his annual discretionary performance bonus (up to the maximum percentage of Matching Contributions for which the Eligible Employee is eligible under Section 4.05(a)), in aggregate by such amount as is necessary for the Eligible Employee to receive the maximum Matching Contribution for which the Eligible Employee would be eligible under Section 4.05(a) and to contribute such amount to the Plan as Salary Deferrals (or as Roth 401(k) Contributions if the Eligible Employee has an election in effect as of the Determination Date to designate 100% of his Salary Deferrals as Roth 401(k) Contributions); provided, however, that if the Eligible Employee is expected to reach the limit described under Section 5.01(a) before December 31 of the Plan Year for which the deemed election is made, the Eligible Employee shall not be deemed to have made an election to change his contribution percentages under this Paragraph.  All determinations made under this Paragraph shall be made by the Committee or its delegate, in accordance with uniform and nondiscriminatory procedures.
(A) For purposes of this Para graph, "Determination Date" means the date determined by the Committee or its delegate and applied to all Participants each Plan Year.
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(6) Each Participant may irrevocably designate, in the manner prescribed by the Benefits Committee, in whole percentages, all or any portion of the Salary Deferrals contributed to the Plan under Section 4.01 (a) (1) as Roth 401(k) Contributions.  Such amounts shall be contributed, through payroll deductions, to a Participant's Roth 401(k) Account with respect to any payroll period after the date of the election.  Any election made under this Section  4.01 (a) (6) shall be prospective only.
(7) If a Participant makes a hardship withdrawal from his Accounts under Section 8.04(b), he shall be prohibited from making Salary Deferrals and/or Roth 401(k) Contributions for six months after receipt of the hardship withdrawal.
 (b) Additional Salary Deferrals and Roth 401(k) Contributions  .  Each Participant who has attained, or will attain, age 50 prior to the end of the Participant's taxable year may elect to reduce his Compensation by an amount equal to the lesser of (A) $5,000 (or such other amount as may be applicable under Code section 414(v)) or (B) the excess of the Participant's Compensation over the Salary Deferrals and Roth 401(k) Contributions contributed on the Participant's behalf under subsection (a) above for the Plan Year; provided, however, that Salary Deferrals or Roth 401(k) Contributions shall not be treated as contributed pursuant to this subsection (b) unless the Participant is unable to make additional Salary Deferrals or Roth 401(k) Contributions for the Plan Year under subsection (a) due to limitations imposed by the Plan or applicable federal law.  Any such election shall be subject to such uniform and nondiscriminatory procedures as the Committee may establish.  Salary Deferrals for the Plan Year under this subsection (b) shall not be subject to the limitations described in ARTICLE V.  
(c) Limitation on Salary Deferral Elections and Roth 401(k) Contributions .  The Salary Deferrals and/or Roth 401(k) Contributions set forth in a Participant's elections shall be tentative and shall become final only after the Employer or the Committee has made such adjustments thereto as they (or either of them) deem necessary to maintain the qualified status of the Plan and to satisfy all applicable requirements of Code sections 401(k), 401(m) and/or 414(v).
 (d) Contribution and Allocation of Salary Deferrals and Roth 401(k) Contributions .  The Employer shall contribute to the Plan with respect to each Plan Year an amount equal to the Salary Deferrals and/or Roth 401(k) Contributions of its Eligible Employees for such Plan Year, as determined pursuant to Salary Deferral and Roth 401(k) Contributions elections in force pursuant to this Section.  There shall be allocated to the Salary Deferral Account and/or Roth 401(k) Account of each Participant the Salary Deferrals and/or Salary Deferrals designated as Roth 401(k) Contributions contributed by the Employer to the Plan with respect to that Participant.
 4.02 Increase in or Reduction of Salary Deferrals and/or Roth 401(k) Contributions .  An active Participant may, in the manner prescribed by the Committee, elect to increase or reduce the rate of his Salary Deferrals and/or Roth 401(k) Contributions (including the cessation or recommencement of such Salary Deferrals and/or Roth 401(k) Contributions) within the limits described in Section 4.01.  Any new election made pursuant to this Section shall be prospectively effective as soon as administratively feasible following the Committee's receipt of the election and shall be subject to such uniform and nondiscriminatory procedures as the Committee may establish.
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4.03 Combined Limit on Contributions .  Th e Committee, in its sole discretion, may limit the maximum amount of the Salary Deferrals, Roth 401(k) Contributions and Matching Contributions for all Participants or any class of Participants to the extent it determines that such limitation is appropriat e or that such limitation is necessary to comply with the applicable requirements of Code sections 401(a), (k) and (m).
 4.04 Company Retirement Contributions .  The Employer shall make Company Retirement Contributions with respect to each Company Retirement Contribution Eligible Participant as set forth in this Section 4.04.  A Company Retirement Contributions Eligible Participant is not required to make Salary Deferrals and/or Roth 401(k) Contributions in order to be eligible to receive Company Retirement Contributions.
 (a) Employment Commencement Dates On or After August 1, 2011 .  With respect to each Company Retirement Contribution Eligible Participant not entitled to a Company Retirement Contribution set forth in subparagraph (b) below, the Employer shall make a Company Retirement Contribution to the Plan equal to 8% of such Participant's Compensation for the Plan Year.
 (b) Employment Commencement Dates Before August 1, 2011 and Grandfathered Company Retirement Contribution Eligible Participants .  With respect to each Company Retirement Contribution Eligible Participant who (i) has an Employment Commencement Date before August 1, 2011 and (ii) does not have a Severance from Service on or after August 1, 2011, and each Grandfathered Company Retirement Contribution Eligible Participant, the Employer shall make a Company Retirement Contribution to the Plan equal to the product of (A) the contribution rate from the table below for such individual based upon his Years of Credited Service determined as of the first day of the Plan Year, multiplied by (B) such individual's Compensation for the Plan Year; provided, however, that effective for Plan Years beginning on and after January 1, 2012, in the event that the anniversary of such individual's Employment Commencement Date occurring during a Plan Year would result in an increase in the contribution rate based on the table below, the Employer's Company Retirement Contribution to the Plan for the Plan Year shall be calculated by applying (I) the lower contribution rate to such individual's Compensation for the Plan Year until the first payroll period on or after the anniversary of the Employment Commencement Date and (II) the higher contribution rate to such individual's Compensation for the remainder of the Plan Year beginning on the first payroll period on or after the anniversary of the Employment Commencement Date.  For Plan Years beginning before January 1, 2012, Years of Credited Service shall be determined at the beginning of the applicable Plan Year for which the Company Retirement Contribution is made with respect to such Company Retirement Contribution Eligible Participant, and, in making such determination, partial Years of Credited Service will be rounded up to the next whole Year of Credited Service.  

Years of Credited Service	Contribution Rate	
0 – 9	8%	
10 – 14	12%	
15 or more	16%	
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(c) Allocation of Company Retirement Contributions .  Company Retirement Contributions shall be contributed to the Plan by the Employer and allocated to the Company Retirement Contribution Accounts of the Company Retirement Contribution Eligible Participants at such time or times and in such amounts as the Employer deems to be appropriate, in its sole discretion, and in accordance with nondiscriminatory administrative procedures.
(d) Additional Company Retirement Contribution .  Notwithstanding anything in this Section 4.04 to the contrary, for the Plan Year ending on December 31, 2010 and subsequent Plan Years, the Employer shall make an additional Company Retirement Contribution to each Special Company Retirement Contribution Participant (as defined in Section 4.04(e) below) in an amount equal to the difference, if any, between such Participant's Minimum Company Retirement Contribution (as defined in Section 4.04(e) below) and such Participant's Company Retirement Contribution determined under subsection (a) or (b) of this Section 4.04, as the case may be.  Any such additional Company Retirement Contribution shall be allocated to the Company Retirement Contribution Account of the Special Company Retirement Contribution Participant.
 (e) Definitions .  For purposes of this Section 4.04:
(1) " Eligibility Computation Period " shall mean with respect to each Employee, (A) the 12 consecutive month period commencing on the Employee's most recent Employment Commencement Date (such Employee's "initial" Eligibility Computation Period), and (B) commencing with the Plan Year in which such Employee's initial Eligibility Computation Period ends, each full Plan Year during which the Employee is in the service of the Employer.
(2) " Grandfathered Company Retirement Contribution Eligible Participant " shall mean a Company Retirement Contribution Eligible Participant who (A) received an offer of employment from an Employer on or before August 1, 2011 that included the contribution rate(s) described in the table in subsection (b); (B) accepted such offer; (C) has an Employment Commencement Date on or after August 1, 2011; and (D) does not have a Severance from Service after becoming a Grandfathered Company Retirement Contribution Eligible Participant.
 (3) " Hours of Eligibility Service " shall mean each hour with respect to an Employee: (A) each hour for which the Employee is paid or entitled to payment for the performance of duties for an Employer or Affiliated Company; (B) each hour for which the Employee is directly or indirectly paid, or entitled to payment, by the Employer or an Affiliated Company on account of a period during which no duties are performed (whether or not the employment relationship has been terminated) due to vacation, holiday, illness, incapacity (including short-term disability), layoff, jury duty, Qualified Military Service or authorized leave of absence; and (C) each hour for which back pay, irrespective of mitigation of damages, is either awarded or agreed to by the Employer or Affiliated Company; provided, however, that, the same Hours of Eligibility Service shall not be counted more than once under (A), (B) and (C).  For these purposes, a payment shall be deemed to be made or due from an Employer or an
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Affiliated Company regardless of whether it is made directly or indirectly through a trust fund, insurer or other entity to which the Employer or Affiliated Company contribut es or pays premiums.  Hours of Eligibility Service shall be computed and credited in a manner consistent with the regulations promulgated by the Secretary of Labor (published at 29 CFR §§ 2530.200b-2(b) and (c)) and shall be credited to the applicable Elig ibility Computation Period in which earned, regardless of when determined or awarded.  Partial hours shall be aggregated.  
In the case of an Employee for whom hours of service are not counted for the performance of duties, 45 Hour of Eligibility Service shall be credited for each week during which the Employee has at least one Hour of Eligibility Service.
Notwithstanding the foregoing, and except as provided in the following sentence, (I) not more than 501 Hours of Eligibility Service shall be credited to an employee on account of any single continuous period (whether or not such period occurs in a single Eligibility Computation Period) during which the Employee performs no duties for the Employer or any Affiliated Company; (II) no credit shall be given for any period with respect to which the Employee receives payment or is entitled to payment under a plan maintained solely for the purpose of complying with applicable workers' compensation or disability insurance laws; and (III) no credit shall be granted for a payment which solely reimburses for medical or medically related expenses incurred by the employee.  For any period of absence for Qualified Military Service in which the Employee returns to the Employer or an Affiliated Company within the period during which the Employee has legally protected reemployment rights, the Employee shall be credited with a number of Hours of Eligibility Service equal to the number of Hours of Eligibility Service that would have been credited to the Employee with respect to the period based upon the Employee's regular work schedule during the one-month period immediately preceding the date on which absence of Qualified Military Service commenced.
Service performed for an entity prior to the date on which it became an Affiliated Company and service performed for such entity after it ceased to be an Affiliated Company shall not be credited as Hours of Eligibility Service unless the Plan otherwise specifically provides.
(4) " Minimum Company Retirement Contribution " shall mean 7.5% of the Special Company Retirement Contribution Participant's Minimum Company Retirement Contribution Compensation (as defined below) with respect to the applicable Plan Year.
(5) " Minimum Company Retirement Contribution Compensation " shall mean compensation as defined in Treas. Reg. § 1.415(c)-2(d)(2) and including differential wage payments described in Code section 414(u)(12) made by reason of Qualified Military Service.  Only $200,000 (adjusted in accordance with Code section 401(a)(17)(B)) of a Participant's Minimum Company Retirement Contribution Compensation shall be counted.
(6) " Special Company Retirement Contribution Participant " shall mean, for an applicable Plan Year, a Participant who (A) is a Non-Highly Compensated Employee; (B) is at least 21 years old; (C) has at least 1,000 Hours of Eligibility Service during any Eligibility Computation Period (for purposes of clarity, a Participant who is credited with 1,000 Hours of Eligibility Service during his initial Eligibility Computation Period, as defined in Section 4.04(e)(1)(A), shall satisfy the requirements of this clause (C) beginning with the Plan Year in which such Eligibility Computation Period ends); and (D) is an Employee on the last day of the applicable Plan Year.
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4.05 Matching Contributions .   
 (a) Matching Contributions and Matching Rates .  Subject to the limitations described in ARTICLE V, with respect to each Plan Year, the Employer may contribute to the Plan, on behalf of each Participant who has made Salary Deferrals and/or Roth 401(k) Contributions, a Matching Contribution in an amount as the Employer determines, in its sole discretion, equal to a percentage of such Participant's Salary Deferrals and/or Roth 401(k) Contributions under Section 4.01(a) for the Plan Year.  The Matching Contribution may be subject to such other limitations as the Employer deems appropriate for such Plan Year.  No minimum Hours of Service are required for a Participant to be eligible for a Matching Contribution.  The matching rate that applies to a Participant shall be determined on the basis of the Participant's classification as of the first day of the applicable Plan Year to which the matching rate shall apply; provided, however, that if a Participant's classification is projected to change during the Plan Year, such change in classification shall be deemed to occur on the first day of the applicable Plan Year to which the matching rate shall apply.  The matching rates shall be based on the Participant's classification, the eligibility for which shall be determined by the Employer in a uniform and nondiscriminatory manner, as follows:
(1) A Participant who has attained the fifth anniversary of the later of his or her (i) Employment Commencement Date and (ii) Reemployment Commencement Date shall receive a Matching Contribution equal to 100% of such Participant's Salary Deferrals and/or Roth 401(k) Contributions, so long as such Salary Deferrals and/or Roth 401(k) Contributions do not exceed 6% of the Participant's Compensation for the Plan Year;
(2) A Participant who has not yet attained the fifth anniversary of the later of his or her (i) Employment Commencement Date and (ii) Reemployment Commencement Date shall receive a Matching Contribution equal to 100% of such Participant's Salary Deferrals and/or Roth 401(k) Contributions, so long as such Salary Deferrals and/or Roth 401(k) Contributions do not exceed 3% of the Participant's Compensation for the Plan Year; and
(3) A Participant who (i) was an active participant in the Pension Plan on October 1, 2007, (ii) elected to continue to accrue benefits under the Pension Plan and (iii) is not a Company Retirement Contribution Eligible Participant shall receive a Matching Contribution equal to 100% of such Participant's Salary Deferrals and/or Roth 401(k) Contributions, so long as such Salary Deferrals and/or Roth 401(k) Contributions do not exceed 6% of the Participant's Compensation for the Plan Year.
 (b) True-Up Matching Contribution .  In the event that the Employer makes Matching Contributions more frequently than once per Plan Year (and at least quarterly), the Employer shall make a "True-Up Matching Contribution" to a Participant for each calendar quarter of the Plan Year (i.e., the quarters ending March 31, June 30, September 30 and December 31) in which the Employer makes Matching Contributions.  The True-Up Matching Contribution shall be equal to the amount by which, if any, the sum of all prior Matching Contributions made during the applicable quarter of the Plan Year on behalf of the Participant is less than the amount of the Matching Contribution that would have been made on behalf of the Participant if the Matching Contribution had been calculated and made only once at the end of the applicable quarter of the Plan Year.  A Participant must be an Employee on the last day of the
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applicable quarter of the Plan Year in order to be eligible to receive a True-Up Matching Contribution for that quarter of the Plan Year.  Notwithstanding anything in this Section 4.05 (b) to the contrary, for the Plan Year beginning January 1, 2013, if the Employer makes Matching Contributions more frequently than once per Plan Year, the Employer shall make a True-Up Matching Contribution for the six-month period beginning January 1, 2013 and ending June 30 , 2013 (and the Employer shall not be required to make a True-Up Matching Contribution for the calendar quarter ending March 31, 2013); provided, however, that a Participant must be an Employee on June 30, 2013 in order to be eligible to receive a True-Up Matching Contribution for the six-month period ending June 30, 2013.
 (c) Allocation .   Matching Contributions made pursuant to subsection (a) shall be contributed to the Plan by the Employer and allocated to the Matching Contribution Accounts of the Participants who are eligible to share in such contributions at such time as the Employer deems to be appropriate, in its sole discretion.  If Matching Contributions are contributed to the Plan and allocated prior to the end of the Plan Year, such allocations shall be made to the Matching Contribution Accounts of the Participants who are otherwise eligible to receive them regardless of whether such Participant has a Severance from Service.  True-Up Matching Contributions made pursuant to subsection (b) shall be contributed to the Plan by the Employer and allocated to the Matching Contribution Accounts of the Participants who are eligible to receive such contributions, as determined under subsection (b), as the Employer deems to be appropriate, in its sole discretion.
 4.06 Rollover Contributions and Roth In-Plan Conversions .  
 (a) Rollover Contributions.  Subject to such uniform and nondiscriminatory procedures established by the Committee, the Plan shall accept, as "Rollover Contributions" made on behalf of any Eligible Employee, cash equal to (1) all or a portion of the amount (excluding after-tax contributions) received by the Eligible Employee as a distribution from an eligible rollover plan as defined in Section 8.08, or (2) an amount (excluding after-tax contributions) transferred directly to the Plan (pursuant to Code section 401(a)(31)) on the Eligible Employee's behalf by the trustee of an eligible rollover plan as defined in Section 8.08, but only if the amount qualifies as a rollover as defined in Code section 402 (or Code section 408, with respect to a rollover from an individual retirement account under Code section 408(b)).  Rollover Contributions may include Roth Rollover Contributions but only to the extent that such amounts are transferred directly to the Plan on the Eligible Employee's behalf by the trustee of an "applicable retirement plan" (as described in Code section 402A(e)(1)) and only to the extent that the rollover is permitted under the rules of Code section 402(c).  If the amount received does not qualify as a rollover, the amount (plus any earnings attributable thereto) shall be refunded to the Eligible Employee.  To the extent not attributable to Roth Rollover Contributions, Rollover Contributions shall be allocated to the Eligible Employee's Rollover Account and invested in accordance with the provisions of ARTICLE VI.  A Rollover Contribution that is a Roth Rollover Contribution shall be allocated to the Eligible Employee's Roth Rollover Account and invested in accordance with the provisions of ARTICLE VI; provided, however, that any such Roth Rollover Contribution must be accompanied by a statement from the plan administrator of the distributing plan indicating either (i) that the Roth Rollover Contribution is a qualified distribution within the meaning of Code section 402A or (ii) the first year of the five-taxable-year period for the Eligible Employee and the portion of the distribution attributable to basis.
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(b) Roth In-Plan Conversions .
 (1) Roth In-Plan Conversions of Accounts other than Rollover Accounts .  Subject to the requirements of Code section 402A(c)(4) and regulations and rulings promulgated thereunder, a Participant may convert all or a portion of the non-Roth amounts in his vested Accounts, other than amounts in his Rollover Account, to Roth 401(k) Contributions, subject to the conditions set forth herein, by making a Roth in-plan conversion election.  A Participant may make a Roth in-plan conversion election in accordance with the rules and procedures established by the Committee for such purpose.  Amounts converted pursuant to this paragraph (1) shall be held in the Participant's Roth In-Plan Conversion Account, or one or more subaccounts established for such purposes.  Amounts in the Participant's Roth In-Plan Conversion Account, and any earnings on those amounts, shall retain the same distribution restrictions, withdrawal rights and characteristics (including by way of example, and not limitation, treatment as a Salary Deferral or Matching Contribution for purposes of ARTICLE V) that applied to the amount prior to its conversion.
 (2) Roth In-Plan Conversions of Rollover Account .  Subject to the requirements of this Section 4.06(b) and Code section 402A(c)(4) and the regulations and rulings promulgated thereunder, a Participant may convert all or a portion of the amounts in his Rollover Account to Roth Rollover Contributions.  A Participant may make a Roth in-plan conversion election at any time following notification to the Committee in accordance with the rules and procedures established by the Committee for such purpose.  Amounts converted pursuant to this paragraph (2) shall be held in the Participant's Roth Rollover Account.
 4.07 Qualified Nonelective Contributions and Qualified Matching Contributions .  
(a) Qualified Nonelective Contributions .  Subject to the limitations described in ARTICLE V, the Employer may, in its discretion, make "Qualified Nonelective Contributions" for a Plan Year, which shall be allocated within 12 months after the close of the Plan Year for which such contributions are related to the Qualified Nonelective Contribution Accounts of some or all of those active Participants who are not Highly Compensated Employees for the Plan Year, as determined by the Employer at the time such contributions are made, in an amount necessary to satisfy at least one of the tests in Section 5.02.  Notwithstanding the foregoing, if Actual Deferral Percentages or Contribution Percentages of Participants who are not Highly Compensated Employees computed for the prior Plan Year are used in conducting the tests set forth in Section 5.02 for a Plan Year, any Qualified Nonelective Contributions for the Plan Year shall be allocated no later than the end of the Plan Year being so tested.  To the extent permitted by applicable law, Qualified Nonelective Contributions for a Plan Year shall be allocated in one of the following methods:
(1) In the ratio in which each such Non-Highly Compensated Employee's Compensation for the Plan Year for which the Qualified Nonelective Contribution is being made bears to the total such Compensation of all such Non-Highly Compensated Employees for such Plan Year.
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(2) To the lowest-paid Participant or Participants, who are Non-Highly Co mpensated Employees, in an amount equal to the lesser of (A) the amount that, when allocated to the Participant (alone, or in conjunction with either an allocation of Qualified Matching Contributions or a return of contributions under Section 5.03(a) or 5.03(b) ), causes the nondiscrimination te sts described in Sections 5.02(a) and 5.02(b) to be satisfied for the Plan Year, (B) the amount that is equal to the maximum Annual Addition permitted under Section  5.04 that may be contributed for the Participant for the Plan Year, or (C) for Plan Years beginning on or after January 1, 2006, the amount permitted to be allocated under Treas. Reg. § 1.401(k)-2(a)(6) or § 1.401(m) ‑2(a)(6), as applicable.
(b) Qualified Matching Contributions .  The Employer may, in its sole discretion, elect to make "Qualified Matching Contributions" in any amount to satisfy any of the nondiscrimination tests described in Sections 5.02(a) and/or 5.02(b) for a Plan Year, which shall be allocated within 12 months after the close of the Plan Year to which such contribution relates.  Notwithstanding the foregoing, if Actual Deferral Percentages or Contribution Percentages of Participants who are not Highly Compensated Employees computed for the prior Plan Year are used in conducting the tests set forth in Section 5.02 for a Plan Year, any Qualified Matching Contributions for the Plan Year shall be allocated no later than the end of the Plan Year being so tested.  Qualified Matching Contributions for a Plan Year shall be allocated to the Qualified Matching Contribution Accounts of Participants who are Non-Highly Compensated Employees and who would be eligible for an allocation of Matching Contributions in accordance with Section 4.05 and in the ratio in which the Salary Deferrals for such Plan Year of each Participant who is a Non-Highly Compensated Employee and who is eligible for a Matching Contribution for such Plan Year bear to the total Salary Deferrals of all such Non-Highly Compensated Employees for such Plan Year.
(c) Other Corrections .  Notwithstanding the foregoing, Qualified Nonelective Contributions and Qualified Matching Contributions may also be made to facilitate correction under any Internal Revenue Service correction program.
 4.08 Contributions with Respect to Military Service .  
(a) Salary Deferral Contributions and Roth 401(k) Contributions .  A Participant who returns to employment with the Employer or an Affiliated Company following a period of Qualified Military Service shall be permitted to make additional Salary Deferrals and/or Roth 401(k) Contributions, within the limits described in Section 4.01, up to an amount equal to the Salary Deferrals and/or Roth 401(k) Contributions that the Participant would have been permitted to contribute to the Plan if he had continued to be employed and received Compensation during the period of Qualified Military Service.  Salary Deferrals and Roth 401(k) Contributions under this Section may be made during the period that begins on the date such Participant returns to employment and which has the same length as the lesser of (i) three multiplied by the period of Qualified Military Service and (ii) five years.
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(b) Company Retirement Contributions .  The Employer shall contribute to the Plan, o n behalf of each Participant who returns from Qualified Military Service as described in subsection (a) and who is a Company Retirement Contribution Eligible Participant, an amount equal to the Company Retirement Contributions that would have been required under Section  4.04 had such Participant continued to be employed and received Compensation during the period of Qualified Military Service.
(c) Matching Contributions .  The Employer shall contribute to the Plan, on behalf of each Participant who has made Salary Deferrals and/or Roth 401(k) Contributions under subsection (a), an amount equal to the Matching Contribution that would have been required under Section 4.05 had such Salary Deferrals and/or Roth 401(k) Contributions been made during the period of Qualified Military Service.
(d) Qualified Nonelective Contributions and Qualified Matching Contributions .  The Employer shall contribute to the Plan, on behalf of each Participant who returns from Qualified Military Service as described in subsection (a), an amount equal to the Qualified Nonelective Contributions or Qualified Matching Contributions that would have been required under Section 4.07 had such Participant continued to be employed and received Compensation during the period of Qualified Military Service.
(e) Limitations on Contributions .  To the extent required by Code sections 414(u) and 414(v), the Salary Deferrals, Roth 401(k) Contributions, Company Retirement Contributions, Matching Contributions, Qualified Nonelective Contributions and Qualified Matching Contributions made under this Section shall be subject to the limitations described in ARTICLE V for the Plan Year to which such contributions relate.
(f) Reduction of Amounts Contributed During Period of Qualified Military Service .  Notwithstanding anything in this Section to the contrary, any Salary Deferral, Roth 401(k) Contribution, Company Retirement Contribution, Matching Contribution, Qualified Nonelective Contribution or Qualified Matching Contribution made to the Plan on behalf of a Participant while such Participant is on a period of Qualified Military Service shall reduce any Salary Deferral, Roth 401(k) Contribution, Company Retirement Contribution, Matching Contribution, Qualified Nonelective Contribution or Qualified Matching Contribution that can be made on behalf of such Participant under the terms of this Section if the Participant returns to employment with the Employer or an Affiliated Company following a period of Qualified Military Service.
 4.09 Timing of Contributions .  Company Retirement Contributions and Matching Contributions (including True-Up Matching Contributions) for any Plan Year under this Article shall be made no later than the last date on which amounts so paid may be deducted for federal income tax purposes for the taxable year of the Employer in which the Plan Year ends.  Except as otherwise set forth in Section 4.07, Qualified Nonelective Contributions and Qualified Matching Contributions for any Plan Year shall be made no later than 12 months after the close of the Plan Year to which the contributions relate.  Amounts contributed as Salary Deferrals and Roth 401(k) Contributions shall be remitted to the Trustee as soon as administratively practicable following the month in which such contributions were withheld from the Participant's Compensation.  The requirements of this Section shall not apply to contributions made pursuant to Section 4.08 with respect to Qualified Military Service.
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4.10 Contingent Nature of Contributions .  Each contribution made by the Employer pursuant to the provisions of this Article is made expressly contingent on its deductibility for federal income tax purposes for the fiscal year with respect to which such contribution is made, and no such contribution shall be made for an y year to the extent it would exceed the deductible limit for such year as set forth in Code section 404.  Contributions by the Employer or any Affiliated Company for any Employee who should have been included as a Participant but was erroneously omitted, contributions necessary to satisfy the top-heavy requirements of Code section 416, and contributions for reemployed Participants made to restore the undistributed portion of the reemployed Participant's account balance are not conditioned upon the deductib ility of the contribution to the Employer or Affiliated Company.
 4.11 Exclusive Benefit; Refund of Contributions .  All contributions made to the Plan are made for the exclusive benefit of the Participants and their Beneficiaries, and such contributions shall not be used for, or diverted to, purposes other than for the exclusive benefit of the Participants and their Beneficiaries (including the costs of maintaining and administering the Plan and corresponding trust).  Notwithstanding the foregoing, to the extent that such refunds do not, in themselves, deprive the Plan of its qualified status, refunds of contributions shall be made to the Employer under the following circumstances and subject to the following limitations:
(a) Initial Nonqualification .  If, upon the timely filing of a determination letter application on the qualified status of the Plan, the Plan is determined not to initially satisfy the qualification requirements of Code section 401(a), and if the Employer declines to amend the Plan to satisfy such qualification requirements of Code section 401(a), contributions made prior to the determination that the Plan has failed to qualify shall be returned to the Employer within one year of such determination.
(b) Disallowance of Deduction .  To the extent that a federal income tax deduction is disallowed, in whole or in part, for any contribution made by an Employer, or such contribution is otherwise nondeductible and recovery thereof is permitted, the Trustee shall refund to the Employer the amount so disallowed within one year of the date of such disallowance or as otherwise permitted by applicable administrative rules.
(c) Mistake of Fact .  In the case of a contribution that is made in whole or in part by reason of a mistake of fact, so much of the Employer contribution as is attributable to the mistake of fact shall be returnable to the Employer upon demand, upon presentation of evidence of the mistake of fact to the Trustee and of calculations as to the impact of such mistake.  Demand and repayment must be effectuated within one year after the payment of the contribution to which the mistake applies.
In the event that any refund is paid to the Employer hereunder, such refund shall be made without regard to net investment gains attributable to the contribution, but shall be reduced to reflect net investment losses attributable thereto.
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ARTICLE V 
 
 LIMITATIONS ON CONTRIBUTIONS
 5.01 Calendar Year Limitation on Salary Deferrals and Roth 401(k) Contributions .  
 (a) Notwithstanding anything contained herein to the contrary, Salary Deferrals and Roth 401(k) Contributions made on behalf of an active Participant under this Plan together with elective deferrals (as defined in Code section 402(g)) and Roth deferrals made under any other plan or arrangement maintained by the Employer or an Affiliated Company shall not exceed such amount as is applicable for a calendar year under Code section 402(g) and the Treasury Regulations thereunder for any calendar year (including, if applicable, the amount of Salary Deferrals permitted to be made pursuant to Section 4.01(b) of the Plan for a calendar year as catch-up contributions under Code section 414(v)).  Participants who formerly participated in another plan not maintained by the Employer or an Affiliated Company prior to their Employment Commencement Date may notify the Committee of such prior plan participation and shall provide documentation of any contributions credited under such prior plan.  Furthermore, should a Participant claim that his Salary Deferrals and/or Roth 401(k) Contributions under this Plan when added to his other elective deferrals under any other plan or arrangement (whether or not maintained by an Employer or an Affiliated Company) exceed the limit imposed by Code section 402(g) for the calendar year in which the deferrals occurred, the Committee shall distribute, by April 15 of the following calendar year, the amount of Salary Deferrals (including, if applicable, Salary Deferrals made pursuant to Section 4.01(b) as catch-up contributions) and/or Roth 401(k) Contributions specified in the Participant's claim, plus income thereon determined in the manner described in Section 5.03(c) or recharacterize such excess Salary Deferrals as Salary Deferrals contributed pursuant to Section 4.01(b) to the extent permitted by Code section 414(v) and regulations issued thereunder.  The Participant's claim shall be in writing and shall be submitted to the Committee prior to March 1 following the calendar year in which such deferrals occurred.  A Participant shall be deemed to have made a claim for distribution of excess deferrals from the Plan to the extent that his Salary Deferrals and/or Roth 401(k) Contributions together with his elective deferrals under any other plan or arrangement maintained by the Employer or an Affiliated Company exceed the limit imposed by Code section 402(g) for the calendar year.  For purposes of determining the necessary reduction, (1) Salary Deferrals previously distributed pursuant to Section 5.03(a) or returned to the Participant pursuant to Section 5.04 shall be treated as distributed under this Section, and (2) Salary Deferrals not taken into account in determining Matching Contributions under Section 4.05 shall be reduced first.
 (b) In the event a Participant receives a distribution of excess Salary Deferrals and/or Roth 401(k) Contributions pursuant to subsection (a), the Participant shall forfeit any Matching Contributions (plus income thereon determined as described in Section 5.03(c)) allocated to the Participant by reason of the distributed Salary Deferrals and/or Roth 401(k) Contributions.  Amounts forfeited shall be used first to reduce future Matching Contributions made pursuant to Section 4.05 and then Company Retirement Contributions made pursuant to Section 4.04.
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5.02 Nondiscrimination Limitations on Salary Deferrals, Roth 401(k) Contributions, and Matching Contr ibutions .   
 (a) Salary Deferral and Roth 401(k) Contribution Limitations .  With respect to Salary Deferrals for any Plan Year (excluding Salary Deferrals contributed pursuant to Section 4.01(b)) and Roth 401(k) Contributions, one of the following tests must be satisfied:
(1) The Average Actual Deferral Percentage for active Participants who are Highly Compensated Employees for the Plan Year shall not exceed the Average Actual Deferral Percentage for all other active Participants for the Plan Year multiplied by 1.25; or
(2) The Average Actual Deferral Percentage for active Participants who are Highly Compensated Employees for the Plan Year shall not exceed the Average Actual Deferral Percentage for all other active Participants for the Plan Year multiplied by two; provided that the Average Actual Deferral Percentage for such Highly Compensated Employees does not exceed the applicable Average Actual Deferral Percentage for all other active Participants by more than two percentage points.
 (b) Matching Contribution Limitations .  With respect to Matching Contributions for any Plan Year, one of the following tests must be satisfied:
(1) The Average Contribution Percentage for active Participants who are Highly Compensated Employees for the Plan Year shall not exceed the Average Contribution Percentage for all other active Participants for the Plan Year multiplied by 1.25; or
(2) The Average Contribution Percentage for active Participants who are Highly Compensated Employees for the Plan Year shall not exceed the Average Contribution Percentage for all other active Participants for the Plan Year multiplied by two; provided that the Average Contribution Percentage for such Highly Compensated Employees does not exceed the applicable Average Contribution Percentage for all other active Participants by more than two percentage points.
(c) For purposes of subsections (a) and (b), this Plan shall be aggregated and treated as a single plan with other plans maintained by the Employer or an Affiliated Company to the extent that this Plan is aggregated with any such other plan for purposes of satisfying Code section 410(b) (other than Code section 410(b)(2)(A)(ii)).
(d) If the Committee elects to apply Code section 410(b)(4)(B) in determining whether Salary Deferrals and any Qualified Nonelective Contributions and Qualified Matching Contributions treated as Salary Deferrals under Section 4.07 meet the requirements of Section 5.02(a) or determining whether Matching Contributions (other than Qualified Matching Contributions treated as Salary Deferrals for the Plan Year under Section 4.07) meet the requirements of Section 5.02(b), the Committee may either exclude from consideration all Participants (other than Highly Compensated Employees) who have not met the minimum age and service requirements of Code section 410(a)(1)(A), or disaggregate the Employees who have not met such minimum age and service requirements and test them separately.
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(e) The determination and treatment of the Salary Deferrals, Roth 401(k) Contributions, Matching Contributio ns, Qualified Nonelective Contributions, and Qualified Matching Contributions, Actual Deferral Percentage and Contribution Percentage of any Participant shall satisfy such other requirements as may be prescribed by the Secretary of the Treasury.
 5.03 Correction of Discriminatory Contributions .  
 (a) If the nondiscrimination tests of Section 5.02(a) are not satisfied with respect to Salary Deferrals for any Plan Year, the Committee shall (1) determine the amount by which the Actual Deferral Percentage for the Highly Compensated Employee or Employees with the highest Actual Deferral Percentage for the Plan Year would need to be reduced to comply with the limit in Section 5.02(a); (2) convert the excess percentage amount determined under clause (1) into a dollar amount; and (3) reduce the Salary Deferrals of the Highly Compensated Employee or Employees with the greatest dollar amount of Salary Deferrals by the lesser of (A) the amount by which the Highly Compensated Employee's Salary Deferrals exceeds the Salary Deferrals of the Highly Compensated Employee with the next highest dollar amount of Salary Deferrals or (B) the amount of the excess dollar amount determined under clause (2).  This process shall be repeated until the Salary Deferrals of Highly Compensated Employees have been reduced by an amount equal to the excess dollar amount determined under clause (2).  The Salary Deferrals of any Highly Compensated Employee which must be reduced pursuant to this subsection (a) shall be reduced (i) first, by distributing Salary Deferrals not taken into account in determining Matching Contributions under Section 4.05, and (ii) next by distributing Salary Deferrals not described in clause (i), within 12 months of the close of the Plan Year with respect to which the reduction applies, and the provisions of Section 5.01(b) regarding the forfeiture of related Matching Contributions shall apply.  For purposes of determining the necessary reduction, Salary Deferrals previously distributed pursuant to Section 5.01 shall be treated as distributed under this Section 5.03(a) and Salary Deferrals contributed pursuant to Section 4.01(b) shall not be taken into account.  Notwithstanding the foregoing, at the election of the Committee and in accordance with rules uniformly applicable to all affected Participants, the Actual Deferral Percentage reduction described in this Section may be accomplished, in whole or in part, by recharacterizing excess Salary Deferrals as Salary Deferrals contributed pursuant to Section 4.01(b) to the extent permitted by Code section 414(v) and regulations issued thereunder.  For purposes of this subsection (a), Roth 401(k) Contributions shall be treated in the same manner as Salary Deferrals.  To the extent the Participant made both Salary Deferrals and Roth 401(k) Contributions to the Plan, excess amounts shall be distributed from the Participant's Account(s) in the following order: Salary Deferral Account, Roth In-Plan Conversion Account (to the extent such amounts are attributable to a Roth in-plan conversion of Salary Deferrals for the Plan Year), and Roth 401(k) Contribution Account.
 (b) If the nondiscrimination tests of Section 5.02(b) are not satisfied with respect to Matching Contributions for any Plan Year, the Committee shall (1) determine the amount by which the Actual Contribution Percentage for the Highly Compensated Employee or Employees with the highest Actual Contribution Percentage for the Plan Year would need to be reduced to comply with the limit in Section 5.02(b); (2) convert the excess percentage amount determined under clause (1) into a dollar amount; and (3) reduce the excess contributions of the Highly Compensated Employee or Employees with the greatest dollar amount of Matching
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Contributions by the lesser of (A) the amount by which the dollar amount of the affected Highly Compensated Employee's Matching Contributions exceeds the dol lar amount of the Matching Contributions of the Highly Compensated Employee with the next highest dollar amount of Matching Contributions or (B) the amount of the excess dollar amount determined under clause (2).  This process shall be repeated until the M atching Contributions of the Highly Compensated Employees has been reduced by an amount equal to the excess dollar amount determined under clause (2).  The Matching Contributions of any Highly Compensated Employee that must be reduced pursuant to this subs ection (b) shall be reduced by distributing Matching Contributions (or forfeiting such Matching Contributions if the Participant is not vested in such amounts) first from the Participant's Matching Contribution Account, and second, if applicable, from the Participant's Roth In-Plan Conversion Account (to the extent such amounts are attributable to a Roth in-plan conversion of Matching Contributions for the Plan Year), within 12 months of the close of the Plan Year with respect to which the reduction applies .  Amounts forfeited under this subsection (b) shall be applied in the following order of priority:  (i) first, to restore a reemployed Participant' s Account as provided under Section 7.04 and to restore the Account of a Participant who was unlocatable as provided under Section 16.13, (ii) next, to reduce future Matching Contributions made pursuant to Section 4.05 , (iii) next, to reduce future Company Retirement Contributions made pursuant to Section 4.04 , (iv) next, to satisfy the top-heavy minimum allocation provisions under Section 10.03 , (v) next, to provide Qualified Nonelective Contributions or Qualified Matching Contributions under Section 4.07 , and (vi) last, to reduce the reasonable expenses of the administration of the Plan.
 (c) Any distribution, recharacterization or forfeiture of Salary Deferrals, Roth 401(k) Contributions or Matching Contributions necessary pursuant to subsection (a) or (b) shall include a distribution or forfeiture of the income, if any, allocable to such contributions.  Such income shall be equal to the allocable gain or loss for the Plan Year (determined by multiplying the income allocable to the Participant's Salary Deferrals, Roth 401(k) Contributions or Matching Contributions, as applicable, for the Plan Year by a fraction, the numerator of which is the Participant's excess Salary Deferrals, Roth 401(k) Contributions or Matching Contributions, as applicable, for the Plan Year and the denominator is the sum of the Participant's Salary Deferral Account, Roth In-Plan Conversion Account, Roth 401(k) Account or Matching Contribution Account, as applicable, as of the beginning of the Plan Year plus any contributions made to the applicable Account during the Plan Year).
 (d) Notwithstanding anything in this Section to the contrary, for any Highly Compensated Employee who is an active Participant in the Plan while eligible to participate in any other qualified retirement plan maintained by the Employer or an Affiliated Company (excluding any such plan which is not permitted to be aggregated with the Plan pursuant to Treas. Reg. § 1.401(k)-1(b)(4)) under which the Employee has made employee contributions or elective deferrals, or is credited with employer matching contributions for the year, the Committee shall coordinate corrective actions under the Plan and such other plan for the year.
(e) In lieu of or in addition to the actions described in subsections (a) through (d) of this Section, to satisfy the tests in Section 5.02, the Employer may make Qualified Nonelective Contributions or Qualified Matching Contributions as described in Section 4.07.
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5.04 Annual Additions Limitations .  In no event shall the Annual Addition on behalf of any Participant for any Plan Year exceed the lesser of:
(1) $40,000, adjusted in accordance with Code section 415(d), or
(2) 100% of such Participant's Compensation for the Plan Year.
The limitation referred to in subsection (2) above shall not apply to any contribution for medical benefits within the meaning of Code section 401(h) or 419A(f)(2) which is otherwise treated as an Annual Addition under Code section 415(l)(1) or 419A(d)(2).
If the amount otherwise allocable to the Account of a Participant would exceed the amount described above as a result of the reallocation of forfeitures (if any available), a reasonable error in estimating the Participant's Compensation, a reasonable error in determining the amount of elective deferrals (within the meaning of Code section 402(g)) that may be made under the limitations of Code section 415, or such other circumstances as permitted by law, the Committee shall take the following steps to correct such violation:
(a) First, the Committee shall reduce the Annual Addition under the Plan by determining the portion, if any, of such excess amount that is attributable to the Participant's Salary Deferrals, Roth 401(k) Contributions, Matching Contributions, Company Retirement Contributions, Qualified Nonelective Contributions and/or Qualified Matching Contributions, if any, until such excess amount has been exhausted.  To the extent any portion of a Participant's Salary Deferrals or Roth 401(k) Contributions are determined to be excess under this Section, such Salary Deferrals or Roth 401(k) Contributions, with income thereon, shall be returned to the Participant as soon as administratively practicable; provided, however, that excess Salary Deferrals and Roth 401(k) Contributions under this Section may be recharacterized as made under Section 4.01(b) to the extent permitted under Code section 414(v) and regulations issued thereunder.  To the extent any portion of the Matching Contributions, Company Retirement Contributions, Qualified Nonelective Contributions and/or Qualified Matching Contributions allocable to a Participant are determined to be excess under this Section, while the Participant remains an Eligible Employee, his excess Matching Contributions, Company Retirement Contributions, Qualified Nonelective Contributions and/or Qualified Matching Contributions shall be held in a suspense account (which shall share in investment gains and losses of the Trust Fund) by the Trustee until the following Plan Year (or any succeeding Plan Years), at which time such amounts shall be allocated to the Participant's Account before any Matching Contributions, Company Retirement Contributions, Qualified Nonelective Contributions and/or Qualified Matching Contributions are made on his behalf for the Plan Year.  When the Participant ceases to be an Eligible Employee, his excess Matching Contributions, Company Retirement Contributions, Qualified Nonelective Contributions and/or Qualified Matching Contributions held in the suspense account shall be allocated in the following Plan Year (or any succeeding Plan Years) to the Accounts of other Participants in the Plan.  Furthermore, the Committee shall perform any other actions as may be necessary to preserve the Plan's status as a qualified plan.
(b) Second, the Annual Addition shall be reduced under such other plans as may be maintained by the Employer in accordance with the provisions set forth therein.
(c) Notwithstanding the foregoing, any distribution of amounts otherwise allocable to the Account of a Participant as described above shall be made in accordance with the rules and procedures set forth in Rev. Proc. 2016-51 and any successor thereto.
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ARTICLE VI 
 
 INVESTMENT AND VALUATION OF TRUST FUND; 
MAINTENANCE OF ACCOUNTS
 6.01 Investment of Assets .  All existing assets of the Trust Fund and all future contributions shall be invested by the Trustee in accordance with the terms of the Trust Agreement and Section 6.02.
 6.02 Investment in Investment Funds .  
(a) General .  Except as provided in subsection (b) and (c) hereof, the Investment Committee shall designate the available Investment Funds to which a Participant shall direct the investment of amounts credited to his Account.  The Investment Committee, in its sole discretion, may from time to time designate additional Investment Funds of the same or different types or modify, cease to offer or eliminate any existing Investment Funds.  A portion of the Trust Fund, as determined by the Investment Committee, may be held in the form of uninvested cash or in a liquid asset account for temporary periods pending reinvestment or distribution, or for other liquidity purposes.
 (b) Company Common Stock Fund Status as Employee Stock Ownership Plan .  The Company Common Stock Fund constitutes an "employee stock ownership plan" for purposes of Code section 4975(e)(7).  Consistent with the requirements of Code section 4975(e)(7) and applicable law, the Company Common Stock Fund shall invest primarily in the Company's Common Stock, without regard to considerations relating to (1) diversification of assets, (2) the risk of investments in Company Common Stock, (3) the amount of income provided by Company Common Stock, and (4) the fluctuation in the fair market value of Company Common Stock; provided, moreover, that, notwithstanding the foregoing, the Company Common Stock Fund is intended as a permanent investment option with respect to the Plan and the Investment Committee shall not have the authority to remove the Company Common Stock Fund from the Plan except in the exercise of its duties and responsibilities under Section 12.03 and section 404(a) of ERISA.
 (c) Default Investment Funds .  The Company designates the age appropriate Target Date Retirement Fund (the " Target Fund ") as the Investment Fund that shall be the "default" investment fund for purposes of Participants (by reason of the automatic enrollment provisions of Section 4.01 or otherwise) who do not make an affirmative election in accordance with Section 6.03 to invest all or a portion of their Account among the Plan's available Investment Funds.  The Target Fund is an Investment Fund that provides a mixture of fixed income and equity investments that are matched to an individual's age and assumed retirement age of 65.  The Target Fund is the Investment Fund that the Company has designated as the Plan's "qualified default investment alternative" for purposes of section 404(c)(5) of ERISA.
 6.03 Investment Elections .  Each Participant, upon commencing or recommencing active participation under Section 4.01, shall direct, in the form and at the time prescribed by the Committee, the investment of contributions made on his behalf in any one or more of the available Investment Funds in accordance with such uniform and nondiscriminatory procedures
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and limitations as the Committee may prescribe.   Without limitin g a Participant's rights to reallocate his Company Retirement Contribution Account pursuant to Section 6.05 , the Committee may prescribe the Invest ment Funds that are available for the investment of the Company Retirement Contributions at the time they are contributed to the Plan and allocated to the Company Retirement Contribution Accounts of the Company Retirement Contribution Eligible Participants .
 6.04 Change of Election .  Each Participant may change his investment direction with respect to the investment of his future contributions at the time or times prescribed by the Committee, by making a new election in such form, at such time in advance, and in accordance with other uniform and nondiscriminatory procedures and subject to such restrictions as the Committee or its delegate may prescribe.
 6.05 Transfers Between Investment Funds .  Subject to such limits as imposed by the Investment Committee, a Participant may reallocate his entire Account among and between the available Investment Funds (subject to such specific rules and limits applicable to the Company Common Stock Fund as described in Section 6.09) at any time.  Each Participant may elect to make such transfers at the time or times prescribed by the Committee, by making a transfer election in such form, at such time in advance, and in accordance with other uniform and nondiscriminatory procedures and subject to such restrictions as the Committee or its delegate may prescribe or as may otherwise be imposed by the Investment Fund(s) involved in the transfer.
 6.06 Individual Accounts .  There shall be maintained on the books of the Plan with respect to each Participant, an Account with such separate subaccounts as are necessary to account for the types and amounts of contributions made to and by the Participant under the Plan.  Each such Account and subaccount shall separately reflect the Participant's interest in each Investment Fund relating to such Account and subaccount.  Each Participant shall receive, at periodic intervals, a statement of his Account showing the balances in each Investment Fund.  A Participant's interest in any Investment Fund shall be determined and accounted for based on his beneficial interest in any such fund, and no Participant shall have any interest in or rights to any specific asset of any Investment Fund.
 6.07 Valuation .  As of each Valuation Date, the Trustee shall adjust the net credit balance of each Participant's Account, in the respective investment fund of the Trust Fund, upward or downward, pro rata, so that the aggregate of such unit credit balances will equal the net worth of each Investment Fund of the Trust Fund as of that Valuation Date, using fair market values as determined by the Trustee.
 6.08 Voting and Tender of Mutual Fund Shares .  To the extent that shares of one or more of the regulated investment companies offered by the Investment Funds are allocated to Participants' Accounts, the Trustee shall vote or tender such shares solely in accordance with written instructions furnished to it by each Participant (or Beneficiary of a deceased Participant); provided that the Trustee shall be responsible for delivery to each Participant (or Beneficiary of a deceased Participant) of all notices, proxies and proxy soliciting materials related to any such shares.  Any such instructions shall remain in the strict confidence of the Trustee.  Shares, including fractional shares, for which voting or tender instructions are not received shall not be voted or tendered.
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6.09 Special Rules for Company Common Stock Fund .
(a) Investment in Company Common Stock Fund .  A Participant shall be eligible to direct investment of a percentage, in an amount up to 15%, of Salary Deferrals, Roth 401(k) Contributions and/or Rollover Contributions into the Company Common Stock Fund.  No Participant may direct the investment of any of his then-existing Account balances into the Company Common Stock Fund.  To the extent that Matching Contributions are made on Salary Deferrals and/or Roth 401(k) Contributions that are directed for investment into the Company Common Stock Fund, such Matching Contributions shall automatically be directed for investment into the Company Common Stock Fund.  A Participant's investment in the Company Common Stock Fund shall be credited to his Company Common Stock Account.  
(b) Diversification of Company Common Stock .  A Participant may elect to reallocate up to 100% of the Company Common Stock Fund held in his Company Common Stock Account to any one or more of the Investment Funds at any time.
(c) Sale, Purchase and Valuation of Company Common Stock .  The Trustee shall either sell or buy Company Common Stock as provided in this Section 6.09 within a reasonable time following receipt of any such direction, considering all of the then-existing market conditions with respect to the Company Common Stock.  Upon receiving direction to sell or buy Company Common Stock, such direction shall remain in effect until completed, and the Participant may not cancel such previous direction.  If the Trustee determines that such quotations or trading prices do not accurately reflect the market value, the fair market value of the Company Common Stock as of the Valuation Date shall be determined by an independent appraiser meeting requirements similar to the requirements of the Department of Labor Regulations promulgated under section 3(18) of ERISA.
(d) Special Rule Regarding Appraisal of Company Common Stock .  If at any time the Company Common Stock held in the Company Common Stock Fund is not readily tradable on an established securities market, all valuations of such Company Common Stock with respect to activities carried on by the Plan shall be made by an independent appraiser meeting the requirements of Code section 401(a)(28).
 (e) Dividends on Company Common Stock Fund .  A Participant may make an election, in accordance with the uniform and nondiscriminatory procedures prescribed by the Committee that provide such opportunity no less frequently than annually, that all cash dividends paid by the Company with respect to shares of Company Common Stock held in the Company Common Stock Fund and allocated to such Participant's Company Common Stock Account on the record date for the dividend shall be either reinvested in the Company Common Stock Fund or distributed to the Participant.  A Participant who does not make an affirmative election to receive dividends in cash will be deemed to have chosen to have those dividends reinvested into the Company Common Stock Fund.  Notwithstanding anything in the Plan to the contrary, a Participant shall have a fully (100%) vested and nonforfeitable interest in any cash dividends paid by the Company with respect to shares of Company Common Stock held in the Company Common Stock Fund.
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(f) Voting of Company Common Stock .  All whole and fractional shares of Company Common Stock allocated to a Participant's or Beneficiary's Company Common Stock Account shall be voted by the Trustee as the Participant or Beneficiary directs in writing from time to time.  The Trustee shall solicit the directions from each Participant or Beneficiary before each annual or special stockholders' meeting of the Company, from each Member.  Upon timely receipt of the directions, the Trustee shall vote t hose shares in accordance with the directions received.  Unless otherwise provided in the Trust Agreement, shares for which timely receipt of directions is not received shall not be voted by the Trustee.
(g) Tender of Company Common Stock .  The Trustee, in its sole discretion, shall determine the manner in which to respond to any offer to purchase, exchange or otherwise dispose of Company Common Stock made by any person or entity other than a Participant or Beneficiary.  If the Company Common Stock is sold, exchanged or disposed of, the proceeds shall be reinvested in the Company Common Stock Fund.
(h) Distribution of Company Common Stock .  When a Participant is entitled to a distribution of his Account under the Plan, the Participant may elect to receive either cash or Company Common Stock that is allocated to his Company Common Stock Account.  If cash is to be received from the Company Common Stock Account, then the Trustee will use reasonable efforts to sell such Company Common Stock and the proceeds from such sale (less all reasonable expenses incurred in such sale) will be distributed to the Participant.  If the Participant elects to receive shares of Company Common Stock, then the shares of Company Common Stock plus cash in lieu of fractional shares (less all reasonable expenses incurred in such sale) will be distributed to the Participant.
(i) Put Option .  In accordance with Code sections 409(h)(4), (5) and (6), if Company Common Stock held in the Company Common Stock Fund is or becomes not readily tradable on an established market (within the meaning of Code section 409(h)(1)(B)), then any Participant who otherwise is entitled to a distribution of such Company Common Stock shall have the right (hereinafter referred to as the " Put Option ") to require that his Company Common Stock be repurchased by the Company.  The Put Option shall only be exercisable during the 60-day period immediately following the date of distribution, and if the Put Option is not exercised within such 60-day period, it can be exercised for an additional 60 days in the following Plan Year.  The amount paid for the Company Common Stock pursuant to the exercise of a Put Option as part of a total distribution shall be paid in substantially equal periodic payments (not less frequently than annually) over a period beginning not later than 30 days after the request for total distribution is made and not exceeding five years, and there shall be adequate security provided, and reasonable interest paid, on any unpaid balance due.  If the Company is required to repurchase Company Common Stock as part of an installment distribution, the amount to be paid for the Company Common Stock will be paid not later than 30 days after the exercise of the Put Option.
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(j) Special Rules .  The Company has established the Company Common Stock Fund to be, and currently intends the Company Common Stock Fund remain, an unleveraged employee stock ownership plan with respect to qualifying employer securities that are publically traded within the meaning of Treas. Reg. § 54.4975-7(b)(iv) .  The Trustee is prohibited from allowing the Company Common Stock Fund to become a leveraged ESOP for purposes of Code section 4975(e)(7) and from entering into an Exempt Loan transaction on the Plan's behalf.  Without limiting the foregoing, an "Exempt Loan" means a loan or loans made to the Plan by a Disqualified Person or a loan or loans to the Plan which is guaranteed by a Disqualified Person.  The term "Exempt Loan" includes a direct loan of cash, a purchase-money transaction, and an assumption of th e obligation of the Plan.  For purposes of this Section, a "guarantee" includes an unsecured guarantee and the use of assets of a Disqualified Person as collateral for a loan, even though the use of assets may not be a guarantee under applicable state law.   A "Disqualified Person" means any person described in Code section 4975(e)(2).
 6.10 Fiduciary Responsibility .  This Plan is intended to constitute a plan described in section 404(c) of ERISA, and Title 29 of the Code of Federal Regulations § 2550.404c-1.  Neither the Company, an Employer, the Committee, the Investment Committee, the Trustee nor any other Plan fiduciary shall be liable for any losses that are the direct and necessary result of investment instructions provided by any Participant, Beneficiary or Alternate Payee.
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ARTICLE VII 
 
 VESTING
 7.01 Full and Immediate Vesting of Salary Deferrals, Roth 401(k) Contributions, Qualified Nonelective Contributions, Qualified Matching Contributions and Rollovers .  A Participant, at all times, shall have a fully (100%) vested and nonforfeitable interest in the portion of his Account attributable to Salary Deferrals, Qualified Nonelective Contributions, Qualified Matching Contributions, and Rollover Contributions (including all earnings, dividends and gains attributable to such contributions).
 7.02 Vesting of Employer Contributions .  
 (a) Matching Contributions and Company Retirement Contributions .  A Participant's interest in the portion of his Account attributable to Matching Contributions, Company Retirement Contributions or any other Employer contributions not otherwise referenced in Section 7.01 (including all earnings, dividends and gains attributable to such contributions) shall vest based on his Years of Service in accordance with the following schedule:

Years of Service	Vested Percentage	
Less than 1 year	0%	
1 year	25%	
2 years	50%	
3 years	75%	
4 or more years	100%	
 
 (b) Accelerated Vesting upon Death, Normal Retirement Age and Disability Retirement Date .  Notwithstanding anything in the Plan to the contrary, a Participant's interest in the portion of his Account that is subject to the vesting schedule described in Section 7.02(a) hereof shall be fully (100%) vested and nonforfeitable upon:
(1) the Participant's death while an Eligible Employee.  In addition, in the event a Participant dies during a period of Qualified Military Service, such Participant shall be treated for purposes of this Section 7.02(b) as if he resumed employment and then died while an Eligible Employee.  
(2) the Participant reaching Normal Retirement Age while an Eligible Employee.
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(c) Accelerated Vesting of Participants Employed by Thunder Creek Gas Services, L.L.C .  Notwithstanding anything in the Plan to the contrary, a Participant who is an Employee of Thunder Creek Gas Services, L.L.C. on August 16, 2013 (or such later date as of the occurrence of the "Closing" of the sale of the Company's own ership interest in Thunder Creek Gas Services L.L.C., as defined in the Purchase and Sale Agreement dated July 12, 2013, by and between the Company and Meritage G&P, LLC (the "Purchase and Sale Agreement")) shall have a fully (100%) vested and nonforfeitab le interest in the portion of his Account that is subject to the vesting schedule described in Section 7.02 (a) if such Participant is a "Continuing Employee" as defined in the Purchase and Sale Agreement.
(d) Accelerated Vesting of Participants Terminated as a Result of the Sale of Assets to Linn Energy .  Notwithstanding anything in the Plan to the contrary, a Participant who is an Employee on August 29, 2014 (or on such date as is the occurrence of the "Closing," as defined in the Purchase and Sale Agreement dated June 27, 2014, by and between the Company and Linn Energy Holdings, LLC ("Purchase and Sale Agreement")) of the sale of assets described in the Purchase and Sale Agreement shall have a fully (100%) vested and nonforfeitable interest in the portion of his Account that is subject to the vesting schedule described in Section 7.02(a) if such Participant is terminated as a result of the Closing.
 7.03 Effects of Certain Periods of Severance .  
 (a) If a Participant had a vested interest in his Account at the time he incurred a Period of Severance and he is later reemployed by the Company or an Affiliated Company, his Years of Service before his Period of Severance shall be taken into account for purposes of determining his vested interest in his Account.  
 (b) If a Participant had no vested interest in his Account at the time he incurred a Period of Severance and he is later reemployed by the Company or an Affiliated Company, his Years of Service before his Period of Severance shall be taken into account for purposes of determining his vested interest in his Account only if he (1) completes a Year of Service as described in Section 2.72(a)(3), and (2) completes an Hour of Service at a time when his consecutive Periods of Severance do not equal or exceed five.  Otherwise, such Participant's pre-severance Years of Service shall be cancelled.
(c) Notwithstanding anything in subsection (a) or (b) to the contrary, if a Participant or Employee has incurred five or more consecutive Periods of Severance, under no circumstances shall his Years of Service after he again completes an Hour of Service be counted in determining his vested interest in the portion of his Account attributable to periods before his Period of Severance.
 7.04 Forfeiture of Nonvested Amounts and Restoration upon Reemployment .  
 (a) The Account of a Participant who has had a Severance from Service shall be closed, and the forfeitable amount held therein shall be forfeited on the earlier of:
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(1) the date on which he receives a distribution of his entire vested interest in his Account (for these purposes, a Participant who incurs a Severance from Service without a vested interest in his Account sha ll be deemed to have received a distribution of his entire vested interest in his Account on the date of his Severance from Service); or
(2) the fifth anniversary of his Severance Date.
 (b) Amounts forfeited from a Participant's Account under subsection (a) shall be applied in the following order of priority:  (1) first, to reduce the reasonable expenses of the administration of the Plan that are not otherwise paid by the Employer or satisfied through other means; (2) next, to restore a reemployed Participant's Account as provided under this Section and to restore the Account of a Participant who could not be located as provided under Section 16.13, (3) next, to reduce future Matching Contributions made pursuant to Section 4.05; (4) next, to reduce future Company Retirement Contributions made pursuant to Section 4.04; (5) next, to provide Qualified Nonelective Contributions or Qualified Matching Contributions under Section 4.07; and (6) last, to satisfy the top-heavy minimum allocation provisions under Section 10.03.
 (c) If a Participant who has received a distribution described in subsection (a)(1) , whereby any part of his Account has been forfeited, again becomes an Eligible Employee prior to the fifth anniversary of his Severance Date, the amount so forfeited shall be restored (unadjusted by any subsequent gains and losses) to his Account; provided that the Participant repays to the Trustee the full amount of any such distribution prior to the fifth anniversary of the date such Participant again becomes an Eligible Employee.    Amounts restored under this subsection (c) shall be funded through current forfeitures or additional contributions by the Participant's Employer.
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ARTICLE VIII 
 
BENEFIT DISTRIBUTIONS
 8.01 Death Benefits .  
(a) Amount and form of Death Benefit .  Subject to Section 9.02(f), in the event of a Participant's death prior to his Benefit Payment Date, his Beneficiary shall be entitled to receive a death benefit equal to the vested balance of his Account, determined as of the Valuation Date related to the Benefit Payment Date for the Participant's Beneficiary.  The Beneficiary shall have the option to select any form of payment under Section 8.03.
(b) Time of Distribution .  Death benefits shall be paid to the Participant's Beneficiary as soon as practicable after the Participant's death; provided, however, that, in the event that the Participant dies after commencement of distributions but before all of his vested Account balance is distributed, the remaining portion of his vested Account balance shall continue to be distributed at least as rapidly as under the method of distribution being used prior to the Participant's death.
 (c) Regulatory Requirements .  Distributions under this Section shall otherwise comply with the requirements of Code section 401(a)(9), including the incidental death benefit requirements, in accordance with the final Treasury Regulations under Code section 401(a)(9) that were published on April 17, 2002.
 8.02 Benefits upon Severance from Service .
(a) Amount of Benefit .  Subject to Section 9.02(f), the Plan benefit payable to a Participant upon such Participant's Severance from Service for reasons other than death, shall be equal to the vested balance of his Account, determined as of the Valuation Date related to the Benefit Payment Date for the Participant.
 (b) Time of Distribution .
(1) General Rule .  Distribution of benefits under this Section to the Participant shall be made as soon as practicable after the Participant's Severance from Service; provided, however, that in the case of a Participant whose vested Account balance exceeds $5,000, no distribution shall be made at such time without the written consent of the Participant.  If the Participant does not so consent, then distribution will be deferred until any subsequent date elected by the Participant in writing or such other manner acceptable to the Committee pursuant to such uniform and nondiscriminatory procedures as the Committee may impose; provided, however, that benefit payments shall begin no later than the applicable date under Section 8.02(b)(3).
 (2) Cash-Out of Amounts of $5,000 or Less .  In the event a Participant's vested Account balance (excluding amounts attributable to rollovers and earnings allocable thereon, but including amounts in a Participant's Roth In-Plan Conversion Account) is $5,000 or less at the time of the Participant's Severance from Service, the Committee shall direct the payment of the Participant's vested Account balance in a lump sum cash payment to the
39

Participant as soon as practicable after the Participant's Severance from Service; provided, however, that for cash-outs pursuant to this subsection (2) , if such Account balance is greater than $1,000 and the Participant does not consent to the distribution of such Account balance, then the Committee shall pay the distribution in a direct rollover described in Section 8.08 to an individual retirement plan of a designated trustee or insurer selected by the Committee, in its sole discretion, for such purposes.
 (3) Required Distribution Dates .
(A) Except as otherwise elected by the Participant or provided in this Section, the Benefit Payment Date for any Participant shall not be later than the 60th day following the close of the Plan Year in which the later of the following events occurs:  (i) the Participant reaches age 65, (ii) the tenth anniversary of the year in which the Participant commenced participation in the Plan or (iii) the Participant has a Severance from Service.  
(B) Notwithstanding any provision in the Plan to the contrary, a Participant's Benefit Payment Date shall not be later than April 1 of the calendar year following the later of (I) the calendar year in which the Participant attains age 70½; or (II) in the case of a Participant who is not a 5% owner (within the meaning of Code section 416(i)) with respect to the Plan Year ending in the calendar year in which the Participant attains age 70½, the calendar year in which the Participant's Severance from Service occurs.  
(C) Distributions under this Section 8.02 shall otherwise comply with the requirements of Code section 401(a)(9) and the final regulations published thereunder on April 17, 2002, including the incidental death benefit requirements of Treas. Reg. § 1.401(a)(9)-5.
(c) Election Period .  A Participant's election to commence payment must be made within the 180-day period ending on the Benefit Payment Date elected by the Participant and in no event earlier than the date the Committee provides the Participant with written information relating to his right to defer payment and his right to make a direct rollover as set forth in Section 8.08.  Such information must be supplied not less than 30 days or more than 180 days prior to the Benefit Payment Date.  Notwithstanding the preceding sentence, a Participant's Benefit Payment Date may occur less than 30 days after such information has been supplied to the Participant; provided that after the Participant has received such information and has been advised of his right to a 30-day period to make a decision regarding the distribution, the Participant affirmatively elects a distribution.
 8.03 Form and Timing of Benefit Payment .  A Participant's Account shall be distributed to the Participant or his Beneficiaries in cash in the form of either (a) a single, lump sum or (b) substantially equal payments in monthly, quarterly, semiannual or annual installments for a period less than the life expectancy of the Participant or his Beneficiaries, as the case may be; provided, however, that portion of a withdrawal or distribution consisting of the Company Common Stock Fund shall be made in either cash or stock, as the Participant or his Beneficiaries may elect.  Any fractional shares of Company Common Stock will be paid in cash.
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8.04 Withdrawals .  A Participant may, in the manner prescribed by the Committee, request a withdrawal from his Accou nt in accordance with the following rules:
(a) In-Service Withdrawals .
(1) Upon written application submitted to the Committee, a Participant who has attained age 59½ may withdraw up to 100% of his vested Accounts.  A Participant may direct the vested Accounts from which a withdrawal pursuant to this paragraph shall be made; provided, however, that a withdrawal from Accounts attributable to Employer contributions shall be taken from the Participant's vested Matching Contribution Account, Company Retirement Account and Roth In-Plan Conversion Account (to the extent attributable to amounts formerly in the Participant's Matching Contribution Account and Company Retirement Contribution Account, and any earnings on such amounts).  The portion of a withdrawal consisting of the Company Common Stock Fund shall be made in either cash or stock, as the Participant may elect.  Any fractional shares of Company Common Stock will be paid in cash.
(2) Upon written application submitted to the Committee, a Participant may withdraw up to 100% of his Rollover Account and/or Roth Rollover Account.
(3) Notwithstanding the foregoing, a Participant who converts his account(s) described under any Appendix to Roth 401(k) Contributions in accordance with Section 4.06(b)(1) may withdraw the portion of his Roth In-Plan Conversion Account attributable to any account described under the applicable Appendix, including any earnings on such account, in accordance with the terms of the applicable Appendix.
 (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 his Salary Deferral Account, Roth 401(k) Account and 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).  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, respectively. 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 distribution shall be deemed to be on account of an immediate and heavy financial need of a Participant when the distribution is on account of:
(A) expenses incurred or necessary for medical care of the Participant, the Participant's Spouse, or any dependents 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);
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(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 or dependents (as defined in Code section 152 without regard to Code sections 152(b)(1), (b)(2) and (d)(1)(B));
(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);
(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 or dependent (as defined in Code section 152 and without regard to Code section 152(d)(1)(B));
(G) federal, state or local income taxes or penalties reasonably anticipated to result from the distribution; or
(H) such other circumstances as may be prescribed by the Secretary of the Treasury or his delegate.
(2) A withdrawal shall be necessary to satisfy the financial need of a Participant if:
(A) a Participant making such application represents in writing to the Committee that he has an immediate and heavy financial need, that the amount requested to be withdrawn is necessary to relieve such need, and that such need cannot be relieved:
(B) through reimbursement or compensation by insurance or otherwise;
(C) by reasonable liquidation of the Participant's assets, including those assets of his Spouse and minor children that are reasonably available to him, to the extent such liquidation would not itself cause an immediate and heavy financial need;
(D) by cessation of Salary Deferrals and/or Roth 401(k) Contributions; or
(E) by other currently available distributions or nontaxable (at the time of the loan) loans from the Plan or any other plan maintained by the Employer or by any other employer, or by borrowing from commercial sources on reasonable commercial terms, in an amount sufficient to satisfy the need.
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(3) If the Participant does not represent in writing to the Committee that he has an immediate and heavy financial need, a withdrawal 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;
(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) and nontaxable loans 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 currently permissible distributions and nontaxable loans under the Plan shall not be sufficient to satisfy the financial need; and
(C) the Participant agrees to be bound by the rules of subsection (4) below.
 (4) If the Participant withdraws any amount eligible for hardship withdrawal pursuant to Section 8.04(b), or withdraws any elective deferrals under any other qualified retirement plan maintained by the Employer or an Affiliated Company which other plan conditions such withdrawal upon the Participant's being subject to rules similar to those stated in this paragraph (4), such Participant may not make Salary Deferrals and/or Roth 401(k) Contributions under the Plan or employee contributions (other than mandatory contributions under a defined benefit plan) or, to the extent required by applicable law, elective deferrals under any other plan of deferred compensation maintained by the Employer or an Affiliated Company for a period of six months commencing on the date of his receipt of the withdrawal.
(c) All withdrawals shall be made in a single-sum payment.
(d) Notwithstanding anything in this Section to the contrary, no Participant shall be permitted to withdraw any portion of his Account pledged as security for a loan pursuant to ARTICLE IX.
 8.05 Beneficiary Designation Right .  
 (a) Spouse as Beneficiary .  The Beneficiary of a death benefit payable pursuant to Section 8.01 shall be the Participant's Spouse as of the Participant's date of death; provided, however, that the Participant may designate a Beneficiary other than his Spouse pursuant to subsection (b) if:
(1) the requirements of subsection (c) are satisfied; or
 (2) the Participant has no Spouse; or
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(3) the Committee determines that the Spouse cannot be located or such other circumstances exist under which Spousal consent is not required, as pr escribed by Treasury Regulations.
 (b) Beneficiary Designation Right .  Each Participant who is permitted to designate a Beneficiary other than his Spouse pursuant to subsection (a) shall have the right to designate one or more primary and one or more contingent Beneficiaries to receive any benefit becoming payable upon the Participant's death.  All Beneficiary designations shall be in writing in a form satisfactory to the Committee.  Each Participant shall be entitled to change his Beneficiaries at any time and from time to time by filing a written notice of such change with the Committee.  However, the Participant's Spouse must again consent in writing to such change, unless (1) the change is a revocation of the prior consent or (2) one of the exceptions described in subsection (a)(2)or (a)(3) applies.
In the event that the Participant fails to designate a Beneficiary to receive a benefit that becomes payable pursuant to Section 8.01, or in the event that the Participant is predeceased by all designated primary and contingent Beneficiaries, the death benefit shall be payable to the Participant's estate.
After a Participant's death, any Beneficiary of the deceased Participant may designate one or more secondary beneficiaries to receive the Beneficiary's interest in the Plan attributable to the Participant's benefits after the Beneficiary's death, to the extent such designation is not inconsistent with the Participant's beneficiary designation.  If the Beneficiary fails to designate a beneficiary or if none of his designated beneficiaries survive him, the death benefit shall be payable to the Beneficiary's estate.
 (c) Form and Content of Spouse's Consent .  A Spouse may consent to the designation of one or more Beneficiaries other than such Spouse; provided that such consent shall be in writing, must consent to the specific alternate beneficiary or beneficiaries designated, must acknowledge the effect of such consent, and must be witnessed by a Plan representative or notary public.  Such Spouse's consent shall be irrevocable, unless expressly made revocable.  The consent of a Spouse in accordance with this subsection (c) shall not be effective with respect to any subsequent Spouse of the Participant.
 8.06 Domestic Relations Orders .  
(a) General .  Except as otherwise provided in this Section, an Alternate Payee shall have no rights to a Participant's benefit and shall have no rights under this Plan other than those rights specifically granted to the Alternate Payee pursuant to a QDRO.  Notwithstanding the foregoing, an Alternate Payee shall have the right to make a claim for any benefits awarded to the Alternate Payee pursuant to a QDRO, as provided in ARTICLE XIII.  Any interest of an Alternate Payee in the Account of a Participant, other than an interest payable solely upon the Participant's death pursuant to a QDRO which provides that the Alternate Payee shall be treated as the Participant's surviving spouse, shall be separately accounted for by the Trustee in the name and for the benefit of the Alternate Payee.
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(1) Distribution .  Notwithstanding anything in this Plan to the contrary, a QDRO may provide that any benefits of a Participan t payable to an Alternate Payee that are separately accounted for shall be distributed immediately or at any other time specified in the order.  If the order does not specify the time at which benefits shall be payable to the Alternate Payee, the Alternate Payee may elect to have benefits commence at any time after the order is determined to be qualified.
(b) Withdrawals .  Unless a QDRO establishing a separate account for an Alternate Payee provides to the contrary, an Alternate Payee for whom a separate account is established shall not be permitted to make any withdrawals under this ARTICLE VIII.
(c) Death Benefits .  Unless a QDRO establishing a separate account for an Alternate Payee provides to the contrary, an Alternate Payee for whom a separate account is established shall have the right to designate a Beneficiary, in the same manner as provided in Section 8.05 with respect to a Participant (except that no Spousal consent shall be required), who shall receive benefits payable to an Alternate Payee which have not been distributed at the time of an Alternate Payee's death.  Upon an Alternate Payee's death, a separate account shall be established for any such Beneficiary.  If the Alternate Payee for whom a separate account is established does not designate a Beneficiary, or if the Beneficiary predeceases the Alternate Payee, benefits payable to the Alternate Payee that have not been distributed shall be paid to the Alternate Payee's estate.  
(d) Investment Direction .  Unless a QDRO establishing a separate account for an Alternate Payee provides to the contrary, an Alternate Payee for whom a separate account is established shall have the right to direct the investment of any portion of a Participant's Accounts payable to the Alternate Payee under such order in the same manner as provided in ARTICLE VI with respect to a Participant, which amounts shall be separately accounted for by the Trustee in the Alternate Payee's name.
(e) Loans .  An Alternate Payee shall not be permitted to receive a loan under ARTICLE IX.
 8.07 Post Distribution Credits .  In the event that, after the payment of a single-sum distribution under this Plan (other than an in-service benefit distribution described in Section 8.04), any funds shall be subsequently credited to the Participant's Account, such additional funds shall be paid to the Participant or applied to the Participant's Account as promptly as practicable thereafter.
 8.08 Direct Rollovers .  In the event any payment or payments to be made under the Plan to a Participant, a Beneficiary, or an Alternate Payee would constitute an "eligible rollover distribution," such individual may request that such payment or payments be transferred directly from the Trust to the trustee of an "eligible rollover plan."  Any such request shall be made in the form prescribed by the Committee for such purpose, at such time in advance as the Committee may specify.  
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For purposes of this Section,
 (a) " eligible rollover distribution " shall mean a distribution from the Plan, excluding (1) any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) over the life (or life expectancy) of the individual, the joint lives (or joint life expectancies) of the individual and the individual's designated Beneficiary, or a specified period of 10 or more years; (2) any distribution to the extent such distribution is required under Code section 401(a)(9); and (3) any hardship distribution; and
(b) " eligible rollover plan " shall mean (1) an individual retirement account described in Code section 408(a), (2) an individual retirement annuity described in Code section 408(b) (other than an endowment contract), (3) an annuity plan described in Code section 403(a), (4) a qualified plan, the terms of which permit the acceptance of rollover distributions, (5) an eligible deferred compensation plan described in Code section 457(b) that is maintained by an eligible employer described in Code section 457(e)(i)(A) that shall separately account for the distribution, or (6) an annuity contract described in Code section 403(b); provided, however, that, effective January 1, 2007, with respect to a distribution (or portion of a distribution) consisting of after-tax employee contributions, the term "eligible rollover plan" shall mean a plan described in clauses (4) and (6) that separately accounts for such amounts transferred and earnings on such amounts or a plan described in clause (1) or (2).  Effective January 1, 2008, an "eligible rollover plan" shall also mean an individual retirement account described in Code section 408A; provided that the distribution to the individual retirement account described in Code section 408A constitutes a "qualified rollover contribution" under Code section 408A(e).  Notwithstanding the foregoing, if any portion of an eligible rollover distribution is attributable to payments or distributions from a Participant's Roth 401(k) Account, Roth Rollover Account or Roth In-Plan Conversion Account, an eligible rollover plan with respect to such portion shall include only another designated Roth 401(k) account described in Code section 402A or a Roth individual retirement account described in Code section 408A, and only to the extent the rollover is permitted under the rules of Code section 402(c).  Effective January 1, 2007, in the case of a distribution to a nonspouse Beneficiary who is a designated Beneficiary within the meaning of Code section 401(a)(9)(E), an "eligible rollover plan" is an individual retirement account established on behalf of the designated Beneficiary that will be treated as an inherited individual retirement account pursuant to the provisions of Code section 402(c)(11).
 8.09 Waiver of 2009 Required Distributions .  Notwithstanding anything in this ARTICLE VIII to the contrary, a Participant or Beneficiary who would have been required to receive required minimum distributions for 2009 but for enactment of Code section 401(a)(9)(H) (" 2009 RMDs "), and who would have satisfied that requirement by receiving distributions that are (i) equal to the 2009 RMDs, or (ii) one or more payments in a series of substantially equal distributions that include the 2009 RMDs made at least annually and expected to last for the life (or life expectancy) of the Participant, the joint lives (or joint life expectancy) of the Participant and the Participant's designated Beneficiary, or for a period of at least 10 years, will not receive those distributions for 2009 unless the Participant or Beneficiary chooses to receive such distributions.  Participants and Beneficiaries described in the preceding sentence will be given the opportunity to elect to receive the distributions described in the preceding sentence.  A direct rollover will be offered only for distributions that would be eligible rollover distributions (as defined in Section 8.08) without regard to Code section 401(a)(9)(H).
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ARTICLE IX 
 
PARTICIPANT LOANS
 9.01 Loans in General .  
 (a) Permissibility .  Each Participant or Beneficiary who satisfies such uniform and nondiscriminatory conditions as may from time to time be adopted by the Committee may apply for a loan from the Plan.
(b) Application .  Subject to such uniform and nondiscriminatory rules as may from time to time be adopted by the Committee, the Trustee, upon application by such Eligible Borrower in such manner as may be approved by the Committee, may make a loan or loans to such applicant.
(c) Limitation on Amount .  
(1) Loans shall be at least $1,000 in amount, and in no event shall total loans exceed the lesser of (A) 50% of the vested balance of such Eligible Borrower's Accounts (other than such Eligible Borrower's Company Retirement Contributions Account, which shall not be included in determining the loan limit), or (B) $50,000, reduced by the excess, if any, of (i) the highest outstanding balance of all loans during the 12 months prior to the time the new loan is to be made, over (ii) the outstanding balance of loans made to the Eligible Borrower prior to the date such new loan is made.  Loans under any other qualified plan sponsored by the Employer or any Affiliated Company shall be aggregated with loans under the Plan in determining whether or not the limitation stated herein has been exceeded.  
(2) Pending the final determination by the Plan Administrator of whether a domestic relations order is a QDRO, no loan to any Eligible Borrower may exceed an amount greater than the maximum permissible loan amount that would be available assuming that the benefit described in the domestic relations order had already been distributed to the alternate payee under a QDRO; provided, however, that the Committee may, in its sole discretion, adopt a policy that universally prohibits loans to an otherwise Eligible Borrower pending the final determination of whether a domestic relations order is a QDRO.
(d) Equality of Borrowing Opportunity .  Loans shall be available to all Eligible Borrowers who are parties in interest on a reasonably equivalent and nondiscriminatory basis.  Loans shall not be made available to Eligible Borrowers who are or were Highly Compensated Employees in an amount greater than the amount available to other Eligible Borrowers.
(e) Loan Statement .  Every Eligible Borrower receiving a loan hereunder will receive a statement from the Committee clearly reflecting the charges involved in each transaction, including the dollar amount and annual interest rate of the finance charges.  The statement will provide all information required to meet applicable "truth-in-lending" laws.
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(f) Restriction on Loans .  The Committee will not approve any loan if it is the belief of the Committee that such loan, if made, would constitute a prohibited transaction (within the meaning of section 406 of ERISA or Code section 4975(c)), would constitute a distribution taxable for federal income tax purposes, or would imperil the status of the Plan or any part thereof under Code section 401(k).  An Eligible Borrower may have no more than two loans outstanding at any time, which may include no more than one loan that is for the purchase of a primary residence.
 9.02 Loans as Trust Fund Investments .  All loans shall be considered as fixed income investments of a segregated account of the Trust Fund (a " loan fund ") directed by the borrower.  Accordingly, the following conditions shall apply with respect to each such loan:
(a) Security .  All loans shall be secured by the pledge of such portion of the Eligible Borrower's Account as is sufficient to secure repayment of the loan.
(b) Interest Rate .  The interest rate on any loan shall be commensurate with the prevailing interest rate charged on similar commercial loans under like circumstances by persons in the business of lending money and shall be determined by the Committee.
 (c) Loan Term .  Loans shall be for terms of up to five years or, with respect to a loan used to acquire a dwelling unit which will be used as the principal residence of the Eligible Borrower, 15 years; provided, however, that if the Eligible Borrower is absent from work for the performance of military service in any branch of the uniformed services (as defined in chapter 43 of title 38, United States Code), any payments may be suspended during such period of military service and, if suspended, shall resume following the completion of the period of such military service.  Any such resumed payments shall be made, following the period of such military service, at least as frequently as, and in an amount not less than, the original loan payments.  In the event of such military service, the term of the loan may be extended by a period not to exceed the original term of the loan plus the period of such military service.  With respect to loans that are outstanding when an Eligible Borrower begins a period of such military service, the interest rate on any such loans shall be limited to 6% to the extent required to comply with section 207 of the Servicemembers Civil Relief Act (or any successor statute thereto); provided that the Committee may require that the Eligible Borrower has provided the Committee with written notice and a copy of the military orders calling the Eligible Employee to military service and any orders further extending military service no later than 180 days after the date of the Eligible Employee's termination or release from military service.  Any loan fees charged to the Accounts of the Eligible Borrower during the period of military service shall be included as interest for purposes of calculating the maximum 6% interest rate.  
(d) Promissory Note .  Any loan made to an Eligible Borrower under this Article shall be evidenced by the promissory note returned to the Eligible Borrower after the loan has been processed.  Such promissory note shall contain the irrevocable consent of the Eligible Borrower to the payroll withholding described in subsection (f), if applicable.  The Committee shall have the right to require the Eligible Borrower to submit revised materials to the extent the Committee determines it is necessary to comply with ERISA or the Code.
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(e) Refinancing of Loans .  An Eligible Borrower may not refinance an existing loan.
 (f) Default and Remedies .  In the event that:
(1) an Eligible Borrower (other than an Eligible Borrower who continues to be a party in interest) has a Severance from Service and fails to make adequate arrangements, as determined by the Committee, in its sole discretion, to continue to make installment payments and does not repay the full unpaid balance of the loan plus applicable interest within such time as may be designated by the Committee; or
(2) in the case of a deceased Eligible Borrower, the Beneficiary fails to repay the full unpaid balance of the loan plus applicable interest within such time as may be designated by the Committee; or
(3) the Eligible Borrower fails to pay any installment by the end of the calendar quarter following the calendar quarter in which the installment payment became delinquent as provided in Section 9.02(g)(2); or
(4) the Eligible Borrower (A) makes an assignment for the benefit of creditors, (B) files a petition for bankruptcy, (C) is adjudicated insolvent or bankrupt, or (D) becomes the subject of any wage earner plan under the federal Bankruptcy Code as now or hereafter in effect, or under any applicable state insolvency law; or
(5) there is started against the Eligible Borrower any bankruptcy, insolvency or other similar proceeding which has not been dismissed by the 60th day after the date on which the proceeding was started, or the Eligible Borrower consents to or approves of any such proceeding or the appointment of any receiver for the Eligible Borrower or any substantial part of the Eligible Borrower's property, or the appointment of any such receiver is not discharged within 60 days; the unpaid balance of the loan, with interest due thereon, shall become immediately due and payable.  In the event that a loan becomes immediately due and payable (in " default "), the Eligible Borrower (or his Beneficiary in the event of his death) may satisfy the loan by paying the outstanding balance in full within 60 days of receiving written notice from the Committee of such default; provided, however, that any such satisfaction of a loan in default must be made no later than the last day of the grace period, if any, designated by the Committee (which grace period shall not extend beyond the last day of the calendar quarter following the calendar quarter in which the required installment was due).  Otherwise, any such outstanding loan or loans (plus unpaid interest) shall be deducted from any benefit which is or becomes payable to the Eligible Borrower or his Beneficiary from the amount and the portions of his Account pledged as security for the loan as soon as is practicable after such default; provided, however, that if the Eligible Borrower has not died or incurred a Severance from Service, the Eligible Borrower's Salary Deferral Account, Roth 401(k) Contributions Account, and portion of the Participant's Roth In-Plan Conversion Account attributable to Salary Deferral Contributions shall only be used to reduce the Eligible Borrower's indebtedness at such time as the Eligible Borrower is entitled to a distribution under Section 8.02 or a withdrawal under Section 8.04 from his Salary Deferral Account and Roth 401(k) Contributions Account and the applicable portion of his Roth In-Plan Conversion Account.  Such action shall not operate as a waiver of the rights of the Employer, the Committee, the Trustee or the Plan under applicable law.
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(g) Repayment .
(1) Loans shall be amortized and repaid in equal installments (not less frequently than quarterly) through payroll withholding; provided, however, that the Committee, in its sole discretion, may authorize an Eligible Borrower who has incurred a Severance from Service or a Disability or transferred to an Affiliated Company, or who is otherwise not actively employed by an Employer, to repay his loan by making direct installment payments.  Notwithstanding the foregoing, in the event of an Eligible Borrower's unpaid leave of absence, the Committee may suspend the Eligible Borrower's installment payment for up to 12 months; provided, however, (i) the loan must still be repaid by the end of the term of the loan, which may be extended by the Committee, in its sole discretion, as provided herein, and (ii) the remaining balance of the loan must be reamortized upon the Eligible Borrower's recommencing active employment.  In the event that repayment of a loan is suspended as provided in this subsection (g), the term of such loan may be extended provided that such extension shall in no event be longer than the maximum period allowable for such loan at the time it was made as provided in subsection (c) above.
 (2) An installment payment shall be delinquent if the Eligible Borrower fails to pay the installment payment within 30 days of the date the installment payment is due.
(3) Loans may be prepaid in full or in part at any time without penalty, in accordance with the procedures established by the Committee for such purposes.
(4) No distribution of an Eligible Borrower's Accounts shall be made to the Eligible Borrower or the Eligible Borrower's Beneficiary or estate until all loans, together with accrued interest, have been paid in full.
(h) Loan Fees .  Fees properly chargeable in connection with a loan may be charged, in accordance with a uniform and nondiscriminatory policy established by the Committee, against the Account of the Eligible Borrower to whom the loan is granted.
(i) Applicable Accounts and Investment Funds .
(1) At such time as it is determined that an Eligible Borrower is to receive a loan from the Plan, the loan shall be made from the Eligible Borrower's applicable Account as indicated hereafter and such amount shall be deemed to be credited to a separate Account established for such purposes (the " Loan Account "), with a corresponding debit to occur to his Account as of the first day of the month in which such loan occurs.  Effective January 1, 2012, the loan may be made from any of the Eligible Borrower's Accounts, other than an account holding Company Retirement Contributions, if any, in accordance with the uniform and nondiscriminatory procedures adopted by the Committee for such purposes.  All loans shall be funded from the Investment Funds in which the Eligible Borrower's Account that is being debited is invested on a pro rata basis.
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(2) All interest pa yments to be made pursuant to the terms and provisions of the loan shall be credited to the applicable Account in such a manner so that the Loan Account will reflect unpaid principal and interest from time to time.  The earnings attributable to the Loan Ac count shall be allocable only to the Loan Account of such Eligible Borrower and shall not be considered as general earnings of the Trust Fund to be allocated to other Eligible Borrowers.  Other than for the limited purposes of establishing a separate accou nt for the allocation of the interest thereto, an Eligible Borrower's Loan Account shall, for all other purposes, be considered as a part of the applicable Account.  
(3) Loan repayments to the Plan by the Eligible Borrower shall be invested in the Investment Funds on the basis of the Eligible Borrower's current investment election under Section 6.03, or the Eligible Borrower's most recent investment election, if no investment election is currently in effect, unless the Eligible Borrower elects otherwise in accordance with rules prescribed by the Committee.
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ARTICLE X 
 
PROVISIONS RELATING TO TOP-HEAVY PLANS
 10.01 Definitions .  For purposes of this Article, the following terms shall have the following meanings:
(a) " Aggregation Group " shall mean the group of qualified plans sponsored by the Employer or by an Affiliated Company formed by including in such group (1) all such plans in which a Key Employee participates in the Plan Year containing the Determination Date, including any frozen or terminated plan that was maintained within the five-year period ending on the Determination Date; (2) all such plans which enable any plan described in clause (1) to meet the requirements of either Code section 401(a)(4) or 410; and (3) such other qualified plans sponsored by the Employer or an Affiliated Company as the Employer elects to include in such group, as long as the group, including those plans electively included, continues to meet the requirements of Code sections 401(a)(4) and 410.
(b) " Determination Date " shall mean the last day of the preceding Plan Year or, in the case of the first Plan Year, the last day of such Plan Year.
(c) " Key Employee " shall mean a person employed or formerly employed by the Employer or an Affiliated Company who, during the Plan Year, was any of the following:
(1) An officer of the Employer having an annual Compensation of more than $140,000 or such other amount as may be in effect under Code section 416(i)(1)(A)(i). The number of persons to be considered officers in any Plan Year and the identity of the persons to be so considered shall be determined pursuant to the provisions of Code section 416(i) and the regulations published thereunder.
(2) A 5% owner of the Employer.
(3) A person who is both an Employee whose annual Compensation exceeds $150,000 and a 1% owner of the Employer.
The beneficiary of any deceased Participant who was a Key Employee shall be considered a Key Employee for the same period as the deceased Participant would have been so considered.
 (d) " Key Employee Ratio " shall mean the ratio (expressed as a percentage) for any Plan Year, calculated as of the Determination Date with respect to such Plan Year, determined by dividing the amount described in paragraph (1) hereof by the amount described in paragraph (2) hereof, after deduction from both such amounts of the amount described in paragraph (3) hereof.
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(1) The amount described in this paragraph (1) is the sum of (A) the aggregate of the present value of all accrued benefits of Key Employees under all qualified defined benefit plans included in the Aggregation Group, (B) the aggregate of the balances in all of the accounts standing to the credit of Key Employees under all qualified defined contribution plans included in the Aggregation Group, and (C) the sum of the amount of any in-service distributions during the period of five Plan Year s ending on the Determination Date, and the amount of any other distributions during the one-year period ending on the Determination Date, to or on behalf of any Key Employee for all plans in the Aggregation Group.
 (2) The amount described in this paragraph (2) is the sum of (A) the aggregate of the present value of all accrued benefits of all Participants under all qualified defined benefit plans included in the Aggregation Group, (B) the aggregate of the balances in all of the accounts standing to the credit of all Participants under all qualified defined contribution plans included in the Aggregation Group, and (C) the sum of the amount of any in-service distributions during the period of five Plan Years ending on the Determination Date, and the amount of any other distributions during the one-year period ending on the Determination Date, and the amount of any other distributions during the one-year period ending on the Determination Date, to or on behalf of any Participant from all plans in the Aggregation Group.
 (3) The amount described in this paragraph (3) is the sum of (A) all rollover contributions (or similar transfers) to plans included in the Aggregation Group initiated by an Employee from a plan sponsored by an employer which is not the Employer or an Affiliated Company, (B) any amount that would have been included under paragraph (1) or (2) hereof with respect to any person who has not rendered service to any Employer at any time during the one-year period ending on the Determination Date, and (C) any amount that is included in paragraph (2) hereof for, on behalf of, or on account of, a person who is a Non-Key Employee as to the Plan Year of reference but who was a Key Employee as to any earlier Plan Year.
The present value of accrued benefits under any defined benefit plan shall be determined under the method used for accrual purposes for all plans maintained by the Employer and all Affiliated Companies if a single method is used by all such plans, or otherwise, the slowest accrual method permitted under Code section 411(b)(1)(C).
(e) " Non-Key Employee" shall mean any Employee or former Employee who is not a Key Employee as to that Plan Year, or a beneficiary of a deceased Participant who was a Non-Key Employee.
 10.02 Determination of Top-Heavy Status .  The Plan shall be deemed "top-heavy" as to any Plan Year if, as of the Determination Date with respect to such Plan Year, either of the following conditions are met:
(a) The Plan is not part of an Aggregation Group and the Key Employee Ratio, determined by substituting the "Plan" for the "Aggregation Group" each place it appears in Section 10.01(d), exceeds 60%, or
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(b) The Plan is part of an Aggregation Group, and the Key Employee Ratio of such Aggregation Group exceeds 60%.
 10.03 Top-Heavy Plan Minimum Allocation .  The aggregate allocation made under the Plan to the Account of each active Participant who is a Non-Key Employee for any Plan Year in which the Plan is a Top-Heavy Plan and who remained in the employ of the Employer or an Affiliated Company through the end of such Plan Year (whether or not in the status of Eligible Employee) shall be not less than the lesser of:
 (a) 3% of the Compensation of each such Participant for such Plan Year; or
 (b) The percentage of such Compensation so allocated under the Plan to the Account of the Key Employee for whom such percentage is the highest for such Plan Year.
(c) If any person who is an active Participant in the Plan is a Participant under any defined benefit pension plan qualified under Code section 401(a) sponsored by the Employer or an Affiliated Company, there shall be substituted " 5%" for " 3%" in subsection (a).  For the purposes of determining whether the provisions of this Section have been satisfied, (1) contributions or benefits under chapter 2 of the Code (relating to tax on self-employment income), chapter 21 of the Code (relating to Federal Insurance Contributions Act), title II of the Social Security Act, or any other Federal or state law are disregarded; (2) all defined contribution plans in the Aggregation Group shall be treated as a single plan; and (3) elective deferrals under all plans in the Aggregation Group shall be disregarded.  For the purposes of determining whether the requirements of this Section have been satisfied, contributions allocable to the account of the Participant under any other qualified defined contribution plan that is part of the Aggregation Group shall be deemed to be contributions made under the Plan, and, to the extent thereof, no duplication of such contributions shall be required hereunder solely by reason of this Section.  Subsection (b) shall not apply in any Plan Year in which the Plan is part of an Aggregation Group containing a defined benefit pension plan (or a combination of such defined benefit pension plans) if the Plan enables a defined benefit pension plan required to be included in such Aggregation Group to satisfy the requirements of either Code section 401(a)(4) or 410.  In determining the amount of Employer contributions that are needed to satisfy the requirements of this Section, amounts contributed under Section 4.01 for Non-Key Employees shall not be taken into account.
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ARTICLE XI 
 
ALLOCATION AND DELEGATION OF AUTHORITY
 11.01 Delegation .  A fiduciary shall have only those specific powers, duties, responsibilities and obligations as are specifically given to him or her under this Plan or under the Trust Agreement or delegated to him or her by another fiduciary.  In general, the Employer, by action of the Board of Directors or a committee thereof, shall have the sole responsibility for making contributions provided for under Sections 4.01(d), 4.04, 4.05 and 4.07; and the Compensation Committee of the Board of Directors shall have the sole authority to appoint and remove the Trustee, the members of the Committee and the Investment Committee, and the Company, by action of the Board of Directors or a committee thereof, shall have the sole authority to curtail or terminate, in whole or in part, the Plan or the Trust Agreement and, except as otherwise provided herein with respect to shared authority, to amend the Plan.  The Committee shall have the sole responsibility for the administration of the Plan, which responsibility is specifically described in this Plan and the Trust Agreement, except for the responsibility of the Investment Committee.  The Investment Committee shall have the sole responsibility for the selection and monitoring of the Investment Funds, establishing investment objectives, deciding whether to appoint and appointing the Asset Allocation Fiduciary and selecting and monitoring any fiduciary consultant or advisor.  The Trustee shall have the sole responsibility for the administration of the Trust Fund and the management of the assets held in the Trust Fund, all as specifically provided in the Trust Agreement.  The Asset Allocation Fiduciary shall have the sole responsibility for the determination of the allocation of investments within any Target Fund or portfolio, which shall be made from other investment alternatives selected by the Investment Committee.
 11.02 Authority and Responsibilities of the Committee .  The Committee shall have the authority and responsibilities imposed by ARTICLE XII hereof, except to the extent delegated to other persons or otherwise provided for herein.  With respect to the said authority and responsibility, the Committee shall be a "Named Fiduciary," and, as such, shall have no authority and responsibility other than as granted in the Plan, or as imposed by law.
 11.03 Authority and Responsibilities of the Trustee .  The Trustee shall be the "Named Fiduciary" with respect to those powers and duties set forth in the Trust Agreement.  The Trustee shall keep complete and accurate accounts of all of the assets of, and the transactions involving, the Trust Fund.  All such accounts shall be open to inspection by the Committee during normal business hours.
 11.04 Authority and Responsibilities of the Investment Committee .  The Investment Committee shall have the authority and responsibilities imposed by ARTICLE XII hereof, except to the extent delegated to other persons or otherwise provided for herein.  With respect to said authority and responsibility, the Investment Committee shall be a "Named Fiduciary" and, as such, shall have no authority and responsibility other than as granted in the Plan or as imposed by law.
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11.05 Authority and Responsibilities of the Asset Allocation Fiduciary .  If and to the extent appointed by the Investment Committee, the Asset Allocation Fiduciary shall have the authority and responsib ilities for the determination of the allocation of investments within any Target Fund or portfolio, which shall be made from other investment alternatives selected by the Investment Committee, except to the extent delegated to other persons or otherwise pr ovided for herein.  With respect to said authority and responsibility, the Asset Allocation Fiduciary shall be a "Named Fiduciary" and, as such, shall have no authority and responsibility other than as granted in the Plan or as imposed by law.  If the Inve stment Committee does not appoint an Asset Allocation Fiduciary, the Investment Committee shall have the authority and responsibilities set forth in this section.   
 11.06 Limitations on Obligations of Named Fiduciaries .  No Named Fiduciary shall have authority or responsibility to deal with matters other than as delegated to it under the Plan, under the Trust Agreement, or by operation of law.  Except as provided by section 405 of ERISA, a Named Fiduciary shall not in any event be liable for breach of fiduciary responsibility or obligation by another fiduciary (including other Named Fiduciaries) if the responsibility or authority of the act or omission deemed to be a breach was not within the scope of the said Named Fiduciary's authority or delegated responsibility.  The determination of any Named Fiduciary as to any matter involving its responsibilities hereunder shall be conclusive and binding on all persons.
 11.07 Designation and Delegation .  Each Named Fiduciary may designate other persons to carry out such of its responsibilities hereunder for the operation and administration of the Plan as it deems advisable and delegate to the persons so designated such of its powers as it deems necessary to carry out such responsibilities.  Such designation and delegation shall be subject to such terms and conditions as the Named Fiduciary deems necessary or proper.  Any action or determination made or taken in carrying out responsibilities hereunder by the persons so designated by the Named Fiduciary shall have the same force and effect for all purposes as if such action or determination had been made or taken by such Named Fiduciary.
 11.08 Engagement of Assistants and Advisers .  Any Named Fiduciary shall have the right to hire, at the expense of the Trust Fund, such professional assistants, counsel and consultants as it, in its sole discretion, deems necessary or advisable.
 11.09 Payment of Expenses .  The reasonable expenses incurred by the Named Fiduciaries in connection with the operation of the Plan, including, but not limited to, the expenses incurred by reason of the engagement of professional assistants, counsel and consultants, shall be expenses of the Plan and shall be payable from the Trust Fund at the direction of the Committee.  The Employer shall have the option, but not the obligation, to pay any such expenses, in whole or in part, and by so doing, to relieve the Trust Fund from the obligation of bearing such expenses.  Payment of any such expenses by any Employer on any occasion shall not bind the Employer to thereafter pay any similar expenses.
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11.10 Indemnification .  Each person who is a Named Fiduciary or a member of any committee or board comprising a Named Fiduciary (other than the Trustee), and each employee of the Employer who is a delegee of a Named Fiduciary, may be indemnified by the Employer against costs, expenses and liabilities (other than amounts paid in settlement to which the Employer does not consent) reasonabl y incurred by him in connection with any action to which he may be a party by reason of his service as a Named Fiduciary to the extent permitted under applicable law.  The foregoing right to indemnification shall be in addition to such other rights as the person may enjoy as a matter of law or by reason of insurance coverage of any kind, but shall not extend to costs, expenses and/or liabilities otherwise covered by insurance or that would be so covered by any insurance then in force if such insurance conta ined a waiver of subrogation.  Rights granted hereunder shall be in addition to and not in lieu of any rights to indemnification to which the person may be entitled pursuant to the bylaws of the Company.  Service as a Named Fiduciary shall be deemed in par tial fulfillment of the person's function as an employee, officer and/or director of the Company, if he serves in that capacity as well as in the role of Named Fiduciary.
 11.11 Bonding .  The Committee shall arrange for such bonding as is required by law for persons who are Employees and/or members of the Board of Directors, but no bonding in excess of the amount required by law shall be considered required by the Plan.  The Company shall obtain, and pay the expense of, any bond required by law.
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ARTICLE XII 
 
ADMINISTRATION
 12.01 Committee .  The Committee, which shall consist of at least one person, shall be appointed by and serve at the pleasure of the Compensation Committee of the Board of Directors.  The termination of a Committee member's employment shall automatically constitute a resignation from the Committee.  The Committee shall act by a majority of its members with minutes being recorded for each meeting.  Such minutes shall be made available to any member upon written request.
 12.02 Authority and Responsibility of the Committee .  The Committee shall be the Plan "administrator" as such term is defined in section 3(16) of ERISA, and as such, except as otherwise set forth under the terms of the Plan, shall have the following duties and responsibilities:
(a) to adopt and enforce such rules and regulations and prescribe the use of such forms as may be deemed necessary to carry out the provisions of the Plan;
(b) to maintain and preserve records relating to Participants, former Participants, Beneficiaries and Alternate Payees in accordance with Section 12.07;
(c) to prepare and furnish to Participants, Beneficiaries and Alternate Payees all information and notices required under federal law or the provisions of the Plan;
(d) to prepare and file or publish with the Secretary of Labor, the Secretary of the Treasury, their delegates and all other appropriate government officials all reports and other information required under law to be so filed or published;
(e) to provide directions to the Trustee with respect to methods of benefit payment, valuations at dates other than regular Valuation Dates and on all other matters where called for in the Plan or requested by the Trustee;
(f) to determine all questions of the eligibility of Employees and of the status of rights of Participants, Beneficiaries and Alternate Payees, to make factual determinations, to construe the provisions of the Plan, to correct defects therein and to supply omissions thereto;
(g) to determine the amount, manner and timing of any distribution of benefits or any withdrawal under the Plan and ensure the proper application of any Federal, state, or local tax withholding or other governmental charge;
(h) to approve the repayment of any loan to a Participant under the Plan;
(i) to appoint or employ advisors, including legal counsel, to render advice with respect to any of the Committee's responsibilities under the Plan;
(j) to arrange for bonding, if required by law;
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(k) to construe and interpret the Plan and ma ke other determinations as described in Section 12.08 ;
(l) to provide procedures for determination of claims for benefits and to establish rules, not inconsistent with the provisions or purposes of the Plan, as it may deem necessary or desirable for the proper administration of the Plan or transaction of its business;
(m) to resolve any claim for benefits in accordance with ARTICLE XIII;
(n) to determine whether any domestic relations order constitutes a QDRO and to take such action as the Committee deems appropriate in light of such domestic relations order;
(o) to make such determinations as are required pursuant to the provisions of Section 8.04 hereof;
(p) to retain records on elections and waivers by Participants, their Spouses and their Beneficiaries and Alternate Payees;
(q) to select an independent qualified public accountant to examine, at the expense of the Company, the Trustee's accounts and records and render an opinion;
(r) to perform such other functions and duties as are set forth in the Plan that are not specifically given to another Named Fiduciary;
(s) to allocate among themselves who shall be responsible for specific fiduciary duties and to designate fiduciaries (other than the Committee members ) to carry out fiduciary responsibilities (other than Trustee responsibilities) under the Plan; provided that such allocation shall be reduced to writing, signed by all Committee members and filed in a permanent Committee minute book;
(t) to take such voluntary corrective action as it considers necessary and appropriate to remedy any inequity that results from incorrect information received or communicated in good faith or as a consequence of administrative or operational error.  Such steps may include, but shall not be limited to, taking any action required under the employee plans compliance resolution system of the Internal Revenue Service, any asset management or fiduciary conduct error correction program available through the Department of Labor, any similar correction program instituted by the Internal Revenue Service, Department of Labor or other administrative agency, reallocation of plan assets, adjustments in amounts of future payments to Participants, Beneficiaries or Alternate Payees under QDROs, and institution and prosecution of actions to recover benefit payments made in error or on the basis of incorrect or incomplete information;
(u) to maintain continuing review of ERISA and the Code, and implementing regulations thereto, and suggest changes and modifications to the Company in connection with amendments to the Plan; and
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(v) to perform such functions and duties as are necessary to carry out its responsibilities under the Plan.
 12.03 Investment Committee .  The Investment Committee, which consists of at least one person, shall be appointed by and serve at the pleasure of the Compensation Committee of the Board of Directors.  The termination of an Investment Committee member's employment shall automatically constitute a resignation from the Investment Committee.  The Investment Committee shall have the following duties and responsibilities:
(a) selection and monitoring of the Investment Funds;
(b) establishment of investment objectives;
(c) evaluating and recommending to the Company organizations to provide services to the Plan, such as trustee, custodian, asset performance evaluation and recordkeeping services;
(d) selection and monitoring of any fiduciary consultant or other advisor who performs services on behalf of the Plan with respect to the Investment Funds; and
(e) selection and appointment of an Asset Allocation Fiduciary.
 12.04 Committee Procedures .  The Committee and the Investment Committee may act at a meeting or in writing without a meeting.  The Company shall appoint a chairman of each of the Committee and the Investment Committee.  Each of the Committee and the Investment Committee may appoint a secretary, who may or may not be a member of the committee.  Each of the Committee and the Investment Committee may adopt such bylaws, regulations and charters as it deems desirable for the conduct of its affairs; provided, however, that such bylaws, regulations and charters shall not be inconsistent with any charters that may be established by the Company.  All decisions of each committee shall be made by the vote of the majority (if more than one person be serving as a member), including actions in writing taken without a meeting.
 12.05 Serving in More than One Capacity .  An individual person may serve in more than one capacity as a fiduciary.
 12.06 Appointment of the Trustee .  The Compensation Committee of the Board of Directors shall have sole responsibility for appointing and removing the Trustee.  
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12.07 Reporting and Discl osure .  To the extent required by applicable law, the Committee shall keep all individual and group records relating to Plan Participants, Beneficiaries and Alternate Payees, and all other records necessary for the proper operation of the Plan.  Such recor ds shall be made available to the Employer and to each Participant, Beneficiary and Alternate Payee for examination during normal business hours except that a Participant, Beneficiary or Alternate Payee shall examine only such records as pertain exclusivel y to the examining Participant, Beneficiary or Alternate Payee and those records and documents relating to all Participants generally.  The Committee shall prepare and shall file as required by law or regulation all reports, forms, documents and other item s required by ERISA, the Code, and every other relevant statute, each as amended, and all regulations thereunder.  This provision shall not be construed as imposing upon the Committee the responsibility or authority for the preparation, preservation, publi cation or filing of any document required to be prepared, preserved or filed by the Trustee or by any other Named Fiduciary to whom such responsibilities are delegated by law or by the Plan.
 12.08 Construction of the Plan .  The Committee shall take such steps as are considered necessary and appropriate to remedy any inequity that results from incorrect information received or communicated in good faith or as the consequence of an administrative error.  The Committee shall have full discretionary power and authority to make factual determinations, to interpret the Plan, to make benefit eligibility determinations, and to determine all questions arising in the administration, interpretation and application of the Plan.  The Committee shall correct any defect, reconcile any inconsistency, resolve any ambiguity or supply any omission with respect to the Plan.  All such corrections, reconciliations, interpretations, determinations, and completions of Plan provisions shall be final, binding and conclusive upon the parties, including the Employer, the Employees, their families, dependents, Beneficiaries and any Alternate Payees.  The Committee shall have no authority, discretion, or power to add to, subtract from or modify any of the terms of the Plan, or to change or add to any benefits provided by the Plan, or to waive or fail to apply any requirements of eligibility for a benefit under the Plan.
 12.09 Compensation of the Committee and the Investment Committee .  Any members of the Committee or the Investment Committee who are Employees shall not receive compensation with respect to their services as such.  
 12.10 Ministerial Functions .  The Committee shall delegate its ministerial duties or functions to such person or persons as the Committee shall select.  Such person or persons shall be responsible for the general administration of the Plan under the policy guidance of the Committee.  Such person may be in the employ of the Employer and shall be compensated for services and expenses by the Employer according to its normal employment policies, without special or additional compensation for his service hereunder.
 12.11 Allocation of Duties and Responsibilities .  The Committee may allocate among its members or Employees any of its duties and responsibilities not already allocated under the Plan or may designate persons other than members or Employees to carry out any of the Plan Administrator's duties and responsibilities under the Plan.
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ARTICLE XIII 
 
APPLICATION FOR BENEFITS AND CLAIMS PROCEDURES
 13.01 Application for Benefits .  Each Participant, Beneficiary or Alternate Payee believing himself eligible for benefits under the Plan shall apply for such benefits by applying to the Committee (or a person named by the Committee to receive claims under the Plan) in the form and manner specified by the Committee.  Before the date on which benefit payments commence, each such application must be supported by such information and data as the Committee deems relevant and appropriate.  Evidence of age, marital status (and, in the appropriate instances, death), and location of residence shall be required of all applicants for benefits.  In the event a Participant, Beneficiary or Alternate Payee fails to apply to the Committee prior to the applicable required distribution date described in Sections 8.01(c) or 8.02(b)(3), the Committee shall make diligent efforts to locate such Participant, Beneficiary or Alternate Payee and obtain such application.  In the event the Participant, Beneficiary, or Alternate Payee fails to make application by the applicable date described in Section 8.01(c) or 8.02(b)(3), the Committee shall commence distribution as of such date without such application.  However, if the Committee fails to locate the Participant, Beneficiary or Alternate Payee so that distribution as of the applicable date described in Section 8.01(c) or 8.02(b)(3) is not possible, the Participant, Beneficiary or Alternate Payee shall be considered a lost payee as described in Section 16.13; provided, however, that, in the event that the Participant, Beneficiary or Alternate Payee is located, payment shall be made as soon as administratively practicable after the date on which the Participant, Beneficiary or Alternate Payee is located.
 13.02 Claims Procedure .  
(a) Establishment of Claims Procedures .  The Committee shall establish claims and appeals procedures in accordance with this Section 13.02 and applicable law and shall afford a reasonable opportunity to any Participant whose claim for benefits has been denied for a full and fair review of the decision denying such claim.  
 (b) Appeals of Denied Claims for Benefits .  In the event that any claim for benefits is denied in whole or in part, the Participant, Beneficiary or Alternate Payee whose claim has been so denied shall be notified of such denial in writing or electronically by the Committee (or a person named by the Committee to receive claims under the Plan).  For purposes of this Section, the person or persons designated to determine initial claims shall be referred to as the "Claims Fiduciary" and the person or persons designated to determine appeals shall be referred to as the "Named Appeals Fiduciary," and any references to the Claims Fiduciary or Named Appeals Fiduciary in this Section 13.02 shall mean the Committee (and references to the Committee shall also mean the Claims Fiduciary or Named Appeals Fiduciary) as the context so provides.  The Claims Fiduciary will review such request and respond within a reasonable time after receiving the claim.  The notice advising of the denial shall be furnished to the Participant, Beneficiary or Alternate Payee within 90 days of receipt of the benefit claim by the Committee, unless special circumstances require an extension of time to process the claim.  If an extension is required, the Claims Fiduciary shall provide notice of the extension prior to the termination of the applicable period.  In no event may the extension exceed a total of 180 days from the date of the original receipt of the claim.  The notice advising of the denial shall specify
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the reason or reasons for denial, make specific reference to pertinent Plan provisions, describe any additional material or information necessary for the claimant to perfect the claim (explaining why such material or informa tion is needed), and shall advise the Participant, Beneficiary or Alternate Payee, as the case may be, of the procedure for the appeal of such denial and the time limits applicable to such procedures, including a statement of the claimant's right to bring a civil action under section 502(a) of ERISA following an adverse benefit determination on review.  All appeals shall be made by the following procedure:
(1) The Participant, Beneficiary or Alternate Payee whose claim has been denied shall file with the Claims Fiduciary a notice of desire to appeal the denial.  Such notice shall be filed within 60 days of notification by Claims Fiduciary, as the case may be, of claim denial, shall be made in writing, and shall set forth all of the facts upon which the appeal is based.  In connection with any such appeal, the Participant, Beneficiary or Alternate Payee shall be provided, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits.  Appeals not timely filed shall be barred.
(2) The Named Appeals Fiduciary shall consider the merits of the claimant's written presentations, the merits of any facts or evidence in support of the denial of benefits, and such other facts and circumstances as the Named Appeals Fiduciary shall deem relevant, without regard to whether such information was submitted or considered in the initial determination.
(3) The Named Appeals Fiduciary shall ordinarily render a determination upon the appealed claim within 60 days after its receipt which determination shall be accompanied by a written or electronic statement setting forth (i) the reasons therefor; (ii) specific references to the pertinent Plan provisions on which the decisions is based; (iii) a description of the claimant's right to, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits; (iv) a description of any voluntary appeal procedures offered by the Plan; and (v) a statement of the claimant's right to bring a civil action under section 502(a) of ERISA.  However, in special circumstances the Named Appeals Fiduciary may extend the response period for up to an additional 60 days, in which event it shall notify the claimant in writing prior to commencement of the extension.  Any determination rendered by the Named Appeals Fiduciary shall be final and binding upon all parties.
(4) If the Claimant challenges the decision of the Named Appeals Fiduciary, a review by a court shall be permitted only in accordance with subsection (d) below. Failure to comply with the time limits set forth above will bar the claimant from filing suit in court.  Any review by a court shall be limited to the facts, evidence and issues presented during the claims procedure set forth above.  Facts and evidence that become known to the claimant after having exhausted the review process may be submitted for reconsideration of the review in accordance with the time limits established above.  Issues not raised during the review process shall be deemed waived.
 (c) Authority to Determine Claims .  The Committee has exclusive authority to decide all claims under the Plan.  The Committee has exclusive authority to review and resolve
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any appeal of a denied claim.  The Committee is a Plan fiduciary with full discretionary authority to do the following: to make findings of fact; to interpret the Plan and resolve ambiguities therein; to determine whether a claimant is eligible for benefits; to decide the amount, form and timing of benefits; and to resolve any other matter which is raised by a claimant or identified by the Committee.  In the case of an appeal, the decision of the Committee shall be final and binding upon all parties.
 (d) Exhaustion of Claims Procedures .  A claim or action (1) to recover benefits allegedly due under the Plan or by reason of any law; (2) to enforce rights under the Plan; (3) to clarify rights to future benefits under the Plan; or (4) that relates to the Plan and seeks a remedy, ruling or judgment of any kind against the Plan or a Plan fiduciary or party in interest (collectively, a " Judicial Claim "), may not be commenced in any court or forum until after the claimant has exhausted the Plan's claims and appeals procedures (an " Administrative Claim ").  A claimant must raise all arguments and produce all evidence the claimant believes supports the claim or action in the Administrative Claim and shall be deemed to have waived every argument and the right to produce any evidence not submitted to the Claims and Appeal Fiduciaries as part of the Administrative Claim.  Any Judicial Claim must be commenced in the appropriate court or forum no later than 24 months from the earliest of (A) the date the first benefit payment was made or allegedly due; (B) the date the Plan Administrator or its delegate first denied the claimant's request; or (C) the first date the claimant knew or should have known the principal facts on which such claim or action is based; provided, however, that, if the claimant commences an Administrative Claim before the expiration of such 24-month period, the period for commencing a Judicial Claim shall expire on the later of the end of the 24-month period and the date that is three months after the final denial of the claimant's Administrative Claim, such that the claimant has exhausted the Plan's claims and appeals procedures.  Any claim or action that is commenced, filed or raised, whether a Judicial Claim or an Administrative Claim, after expiration of such 24-month limitations period (or, if applicable, expiration of the three-month limitations period following exhaustion of the Plan's claims and appeals procedures) shall be time-barred.  Filing or commencing a Judicial Claim before the claimant exhausts the Administrative Claim requirements shall not toll the 24-month limitations period (or, if applicable, the three-month limitations period).
(e) Venue .  The courts of competent jurisdiction in Oklahoma City, Oklahoma shall have exclusive jurisdiction for all claims, actions and other proceedings involving or relating to the Plan, a Plan fiduciary or a party in interest, including, by way of example and not limitation, claim or action (1) to recover benefits allegedly due under the Plan or by reason of any law; (2) to enforce rights under the Plan; (3) to clarify rights to future benefits under the Plan; or (4) that relates to the Plan and seeks a remedy, ruling or judgment of any kind against the Plan or a plan fiduciary or a party in interest.
(f) Reliance on Records .  The records of the Employer and any Affiliated Company with respect to length of employment, employment history, compensation, absences from employment and all other relevant matters may be conclusively relied on by the Committee for purposes of determining an individual's eligibility or entitlement to Plan benefits, the amount of Plan benefits payable to an individual, the appropriate timing of payment of Plan benefits to an individual, and so forth.  If an individual claiming benefits under the Plan believes those records are incorrect, the individual may provide documentation supporting his or her position to the Committee for review and consideration.  However, the decision of the Committee with respect to any records dispute shall be final and binding on all parties.
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ARTICLE XIV 
 
AMENDMENT AND TERMINATION
 14.01 Amendment .  The provisions of the Plan may be amended at any time and from time to time by the Company; provided, however, that:
(a) No amendment shall increase the duties or liabilities of the Committee or of the Trustee without the consent of that party;
(b) No amendment shall deprive any Participant, Beneficiary or Alternate Payee of any of the benefits to which he is entitled under the Plan with respect to contributions previously made, nor shall any amendment decrease the vested percentage of any Participant's Account nor result in the elimination or reduction of a benefit "protected" under Code section 411(d)(6), unless otherwise permitted or required by law;
(c) No amendment shall provide for the use of funds or assets held to provide benefits under the Plan other than for the benefit of Participants and their Beneficiaries or Alternate Payees or to meet the administrative expenses of the Plan, except as may be specifically authorized by statute or regulation.
Each amendment shall be approved by or pursuant to a resolution adopted by the Board of Directors (or its duly authorized delegate); provided, however, that the Committee (or its duly authorized delegate) may make (1) any technical, administrative or compliance amendment to the Plan and (2) any amendment to the Plan that will not result in a material increase in cost of the Plan to the Company, as the Committee (or its duly authorized delegate) shall deem necessary or appropriate in its sole discretion, including any amendment and restatement of the Plan to include such amendments.
 14.02 Amendments to the Vesting Schedule .  
(a) If the vesting schedule under this Plan is amended, each active Participant who has completed at least three Years of Service prior to the end of the election period specified in this Section may elect, during such election period, to have the vested percentage of his Account determined without regard to such amendment.
(b) For the purposes of this Section, the election period shall begin as of the date on which the amendment changing the vesting schedule is adopted, and shall end on the latest of the following dates:
(1) the date occurring 60 days after the Plan amendment is adopted; or
(2) the date which is 60 days after the day on which the Plan amendment becomes effective; or
(3) the date which is 60 days after the day the Participant is issued written notice of the Plan amendment by the Committee or by the Employer; or
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(4) such later date as may be specified by the Committee.
The election provided for in this Section shall be made in writing and shall be irrevocable when made.
 14.03 Plan Termination .  
(a) It is the intention of the Company that the Plan will be permanent.  However, each entity constituting the Employer reserves the right to terminate its participation in this Plan by action of its board of directors or other governing body.  Furthermore, the Company reserves the power to terminate the Plan at any time for any reason by action of the Board of Directors.
(b) Any termination of the Plan shall become effective as of the date designated by the Board of Directors.  Except as expressly provided elsewhere in the Plan, prior to the satisfaction of all liabilities with respect to the benefits provided under the Plan, no termination shall cause any part of the funds or assets held to provide benefits under the Plan to be used other than for the benefit of Participants and their Beneficiaries or Alternate Payees or to meet the administrative expenses of the Plan.  Upon termination or partial termination of the Plan, or upon complete discontinuance of contributions, the rights of all affected persons to benefits accrued to the date of such termination shall be nonforfeitable.  Upon termination of the Plan, Accounts shall be distributed in accordance with applicable law.
 14.04 Mergers and Consolidations of Plans .  Pursuant to action by the Board of Directors, the Plan may be merged or consolidated with, or a portion of its assets and liabilities may be transferred to, another qualified plan.  In the event of any merger or consolidation with, or transfer of assets or liabilities to, any other plan, each Participant shall have a benefit in the surviving or transferee plan if such plan were then terminated immediately after such merger, consolidation or transfer that is equal to or greater than the benefit he would have had immediately before such merger, consolidation or transfer in the plan in which he was then a participant had such plan been terminated at that time and no such merger, consolidation or transfer shall result in the elimination or reduction of a benefit "protected" under Code section 411(d)(6), unless otherwise permitted or required by applicable law.  For the purposes hereof, former Participants, Beneficiaries and Alternate Payees shall be considered Participants.
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ARTICLE XV 
 
CHANGE OF CONTROL
 15.01 Change of Control .  
(a) General .  In the event that there is a Change of Control (as defined in Section 15.01(b)) of the Company, then, the Accounts of all Participants in the Plan shall become immediately fully (100%) vested and nonforfeitable as of the date of the Change of Control.
 (b) Definition of Change of Control .  For purposes of this Section 15.01, the term " Change of Control " shall mean, and shall be deemed to have occurred, each time the date on which one of the events described in paragraph (1), (2), (3), or (4) below occurs; provided that if a Change of Control occurs by reason of an acquisition by any Person that comes within the provisions of paragraph (1) below, no additional Change of Control shall be deemed to occur under such paragraph (1) by reason of subsequent changes in holdings by such Person (except if the holdings by such Person are reduced below 30% and thereafter increase to 30% or above).  For the purpose of this paragraph (b), the term " Company " shall include Devon Energy Corporation, a Delaware corporation, and any successor thereto.
 (1) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the " Exchange Act ")) (a " Person ") if, immediately after such acquisition, such Person has beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 30% or more of either (I) the then outstanding shares of common stock of the Company (the " Outstanding Company Common Stock ") or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the " Outstanding Company Voting Securities "); provided, however, that the following acquisitions shall not constitute a Change of Control:  (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company; or (D) any acquisition by any corporation pursuant to a transaction which complies with clauses (A), (B), and (C) of paragraph (3) below.
 (2) Individuals who, as of the Effective Date, constitute the Board of Directors (the " Incumbent Board ") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the Effective Date whose election, appointment or nomination for election by the Company's shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board of Directors.
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(3) A reorganization, share exchange, merger or consolidation (a " Business Comb ination "), in each case, unless, following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securiti es immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the ultimate parent entity resulting from such Business Combination (including, without limitation, an entity which, as a result of such transaction, has ownership of the Company or all or sub stantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially the same relative proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and O utstanding Company Voting Securities, as the case may be, (B) no Person (excluding any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 30% or m ore of, respectively, the then outstanding common stock of the ultimate parent entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership ex isted prior to the Business Combination, and (C) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreem ent, or of the action of the Incumbent Board providing for such Business Combination, or were elected, appointed or nominated by the Incumbent Board.
 (4) Approval by the shareholders of the Company of (A) a complete liquidation or dissolution of the Company or, (B) the sale or other disposition of all or substantially all of the assets of the Company, other than to an entity with respect to which following such sale or other disposition, (i) more than 50% of, respectively, the then outstanding shares of common stock of such entity and the combined voting power of the then outstanding voting securities of such entity entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such sale or other disposition in substantially the same relative proportions as their ownership, immediately prior to such sale or other disposition, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) less than 30% of, respectively, the then outstanding shares of common stock of such entity and the combined voting power of the then outstanding voting securities of such entity entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by any Person (excluding any employee benefit plan (or related trust) of the Company or such entity), except to the extent that such Person owned 30% or more of the Outstanding Company Common Stock or Outstanding Company Voting Securities prior to the sale or disposition, and (iii) at least a majority of the members of the board of directors of such entity were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Incumbent Board providing for such sale or other disposition of assets of the Company, or were elected, appointed or nominated by the Incumbent Board.
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15.02 Amendment of this ARTICLE XV by the Company .  Notwithstanding any of the provisions in t he Plan to the contrary, this ARTICLE XV may be amended or deleted in any manner as the Company determines prior to the time that a Change of Contro l occurs.  Upon or after a Change of Control, this ARTICLE XV may not be amended, modified or terminated without the consent of the affected Partic ipant unless such amendment, modification or termination is necessary to satisfy the requirements of the Code and the failure to satisfy such requirements of the Code would result in the disqualification of the Plan.
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ARTICLE XVI 
 
MISCELLANEOUS PROVISIONS
 16.01 Nonalienation of Benefits .  
(a) Except as provided in Section 16.01(b), none of the payments, benefits or rights of any Participant, Alternate Payee or Beneficiary shall be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee's process, or any other legal or equitable process available to any creditor of such Participant, Alternate Payee or Beneficiary.  Except as provided in Section 16.01(b), no Participant, Alternate Payee or Beneficiary shall have the right to alienate, anticipate, commute, pledge, encumber or assign any of the benefits or payments which he may expect to receive, contingently or otherwise, under the Plan, except the right to designate a Beneficiary or Beneficiaries as hereinabove provided.
 (b) Compliance with the provisions and conditions of (1) any QDRO, (2) any federal tax levy made pursuant to Code section 6331, or (3) subject to the provisions of Code section 401(a)(13), a judgment relating to the Participant's conviction of a crime involving the Plan or a judgment, order, decree or settlement agreement between the Participant and the Secretary of Labor or the Pension Benefit Guaranty Corporation relating to a violation (or an alleged violation) of part 4 of subtitle B of title I of ERISA shall not be considered a violation of this provision.
 16.02 No Contract of Employment .  Neither the establishment of the Plan, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Participant or Employee, or any person whomsoever, the right to be retained in the service of the Employer, and all Participants and other Employees shall remain subject to discharge to the same extent as if the Plan had never been adopted.
 16.03 Severability of Provisions .  If any provision of the Plan shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof, and the Plan shall be construed and enforced as if such provisions had not been included.
 16.04 Heirs, Assigns and Personal Representatives .  This Plan shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, Beneficiary and Alternate Payee, present and future (except that no successor to the Employer shall be considered a Plan sponsor unless that successor adopts the Plan).
 16.05 Headings and Captions .  The headings and captions herein are provided for reference and convenience only, shall not be considered part of the Plan, and shall not be employed in the construction of the Plan.
 16.06 Gender and Number .  Except where otherwise clearly indicated by context, the masculine and the neuter shall include the feminine and the neuter, the singular shall include the plural, and vice-versa.
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16.07 Controlling Law .  This Plan shall be construed and enforced according to the laws of the State of Oklahoma to the extent not preempted by federal law, which shall otherwise control.  All contributions to the Trust Fund shall be deemed to take place in the State of Oklahoma.
 16.08 Funding Policy .  The Investment Committee appointed under Section 12.03 (or the Committee, if no Investment Committee has been appointed) shall establish, and communicate to the Trustee, a funding policy and method consistent with the objectives of the Plan and of the Trust Fund.  
 16.09 Title to Assets; Source of Benefits .  No person shall have any right to, or interest in, any assets of the Trust Fund, except as provided from time to time under the Plan, and then only to the extent of the benefits payable under the Plan to such person or out of the assets of the Trust Fund.  All payments of benefits as provided for in the Plan shall be made from the assets of the Trust Fund, and neither the Employer nor any other person shall be liable therefore in any manner.
 16.10 Payments to Minors, Etc .  Any benefit payable to or for the benefit of a minor, an incompetent person or other person incapable of receipting therefor shall be deemed paid when paid to such person's guardian or to the party providing or reasonably appearing to provide for the care of such person, and such payment (which may be in installments) shall fully discharge the Trustee, the Committee, the Employer and all other parties with respect thereto.
 16.11 Reliance on Data and Consents .  The Employer, the Trustee, the Committee, all fiduciaries with respect to the Plan, and all other persons or entities associated with the operation of the Plan, the management of its assets, and the provision of benefits thereunder, may reasonably rely on the truth, accuracy and completeness of all data provided by any Participant, Beneficiary or Alternate Payee, including, without limitation, data with respect to age, health and marital status.  Furthermore, the Employer, the Trustee, the Committee and all fiduciaries with respect to the Plan may reasonably rely on all consents, elections and designations filed with the Plan or those associated with the operation of the Plan and its corresponding trust by any Participant, the spouse of any Participant, any Beneficiary of any Participant, any Alternate Payee of any Participant or the representatives of such persons without duty to inquire into the genuineness of any such consent, election or designation.  None of the aforementioned persons or entities associated with the operation of the Plan, its assets and the benefits provided under the Plan shall have any duty to inquire into any such data, and all may rely on such data being current to the date of reference, it being the duty of the Participants, spouses of Participants, Beneficiaries and Alternate Payees to advise the appropriate parties of any change in such data.
 16.12 Deemed Acceptance of Act or Omission by a Plan Fiduciary .  If a Plan fiduciary (as determined under ERISA) or an individual or entity with authority delegated by a Plan fiduciary, acts or fails to act with respect to a Participant or a Participant's Account under the Plan and the Participant has direct or indirect knowledge of such act or failure to act, the Participant's failure to notify the Plan fiduciary (or the Plan fiduciary's delegate) within a reasonable period of time that such act or failure to act was incorrect or inconsistent with the Participant's intent or election shall be deemed to be an acceptance and ratification of the Plan fiduciary's (or the Plan fiduciary's delegate) act or failure to act.
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16.13 Lost Payees .  A benefit shall be deemed forfeited, and used as set forth in Section 7.04(b) , if the Committee is unable to locate a Participant, a Beneficiary or an Alternate Payee to whom payment is due; provided, however, that such benefit shall be reinstated, without any earnings from the date deemed forfeited to the date reinstated, if a claim is made by the party to whom properly payable.
 16.14 No Warranties .  Neither the Board of Directors nor its members nor the Committee nor the Company nor any Employer nor any Affiliated Company nor the Trustee warrants or represents in any way that the value of each Participant's Accounts will increase or will not decrease.  The Participant assumes all risk in connection with any change in values.
 16.15 Notices .  Each Participant, Beneficiary and Alternate Payee shall be responsible for furnishing the Committee with the current and proper address for the mailing of notices, reports and benefit payments.  Any notice required or permitted to be given shall be deemed given if directed to the person to whom addressed at such address and mailed by regular United States mail, first-class and prepaid.  If any check mailed to such address is returned as undeliverable to the addressee, mailing of checks will be suspended until the Participant, Beneficiary or Alternate Payee furnishes the proper address.  This provision shall not be construed as requiring the mailing of any notice or notification if the regulations issued under ERISA deem sufficient notice to be given by the posting of notice in appropriate places, or by any other publication device.
 16.16 Recovery of Overpayment .  The Plan has a right of reimbursement against any person who receives or holds a payment from the Plan in excess of the amount to which a Participant, Spouse, Alternate Payee, or Beneficiary is entitled under the terms of the Plan. The Plan's right to recover overpayments from any Participant, Spouse, Alternate Payee or Beneficiary exists regardless of the error, event or other circumstances giving rise to the overpayment and shall not be conditioned upon or mitigated by the behavior of any involved party.  The Participant, Spouse, Alternate Payee, or Beneficiary shall not be permitted to raise reliance, estoppel or other legal or equitable defenses in response to any action by the Plan to recovery an overpayment.  The Plan's right to recovery is an equitable lien by agreement, and the  Committee or Trustee may recover the amount overpaid in any manner determined by the Committee or Trustee to be in the best interests of the Plan, including, but not limited to, by legal action against the recipient and/or holder of the overpayment or by offset against other or future benefits payable to or with respect to the Participant, Spouse, Alternate Payee, or Beneficiary under the Plan, regardless of whether the overpaid amounts remain in his or her possession.  The provisions of this Section are intended to clarify existing rights of the Plan and apply to all past or future overpayments.
[REMAINDER OF THE PAGE INTENTIONALLY LEFT BLANK]
 
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This amended and restated version of the Devon Energy Corpora tion Incentive Savings Plan is executed this 18th day of December, 2017.
DEVON ENERGY CORPORATION

By: /s/ Tana K. Cashion
Name: Tana K. Cashion
Title:  Senior Vice President, Human Resources

 

 
[ Signature Page to Amended and Restated Plan Effective January 1, 2018 ]

APPENDIX A 
 
DIRECT TRANSFER FROM KERR-MCGEE CORPORATION 
SAVINGS INVESTMENT PLAN
This Appendix A shall apply with regard to those Employees (whether or not Participants under the Plan) whose Accounts under the Plan include amounts transferred to the Trust Fund from the Kerr-McGee Savings Investment Plan (the " KM Plan ") in connection with the merger, effective as of January 1, 1997, of the KM Plan with and into the Plan.
 
1.	Plan Merger .  The KM Plan shall be merged with and into the Plan, effective as of January 1, 1997.  The provisions of the Plan shall become fully applicable to the participants, former participants, beneficiaries and alternate payees of the KM Plan, except as provided in this Appendix.	
2.	Date of Plan Participation .  All Employees with undistributed account balances in the KM Plan that were merged with and into the Plan shall be eligible to become Participants in the Plan effective January 1, 1997.  Any individual who participated in the KM Plan but who terminated employment prior to, and who does not have an Employment Commencement Date on or after, January 1, 1997, shall not become a Participant in the Plan, except for a limited purpose, including, without limitation, investment allocation and distributions, as outlined in Section 3.06.	
3.	Asset Transfer Provisions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Transfer of Plan Assets .  Effective as of January 1, 1997, or as soon as administratively practicable thereafter, assets and liabilities from the trust fund for the KM Plan shall be transferred to the Trust Fund.  All assets and liabilities transferred to the Plan from the trust fund for the KM Plan shall be administered in accordance with the generally applicable terms of the Plan, together with such other provisions that are applicable to former participants in the KM Plan (" KM Plan Participants ") as set forth in this Appendix	
 	(b)	Regulatory Requirements .  As required by Treas. Reg. § 414(l)-1(d), each employee who has an account balance from the KM Plan transferred to the Plan shall receive a benefit immediately after the transfer contemplated under subsection (a) above that is equal to or greater than the benefit that he would have been entitled to receive immediately before such transfer (as if either the KM Plan or the Plan had then terminated).  	
A-1

 	(c)	Segregation of Transferred Amounts .  The Committee shall separately account for the amounts transferred to the Plan pursuant to subsection (a) above for recordkeeping purposes and shall establish such segregated accounts or subaccounts as are necessary to provide for this separate accounting.  These separate accounts and subaccounts shall be referred to collectively as the " KM Accounts ."  Except as otherwise provided in this Appendix, the KM Accounts shall be treated in the same manner as all other Accounts under the Plan.	
4.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Special Vesting of KM Plan Participants .  Notwithstanding anything to the contrary herein, KM Plan Participants shall be 100% vested in all KM Accounts.	
 	(b)	KM Accounts .	
 	(i)	" SMART Savings Contributions Account ," as defined in the KM Plan, shall mean those monies held in that account which are transferred to the Plan.  The SMART Savings Contributions Account shall be considered a part of the Salary Deferral Account.	
 	(ii)	" KM Matching Contributions Account ," as defined in the KM Plan under the term "Matching Contributions Account," shall mean those monies held in that account which are transferred to the Plan.  The KM Matching Contributions Account shall be considered part of the Matching Contributions Account.	
 	(iii)	" CAPITAL Savings Contributions Account ," as defined in the KM Plan, means the monies held in that account which are transferred to the Plan.  The CAPITAL Savings Contributions Account represents after-tax contributions (nondeductible contributions) for all purposes.	
 	(c)	KM Account Withdrawals .  The following provisions shall apply to the  KM Accounts of any Participant:	
 	(i)	A Participant may withdraw any portion of the value of his CAPITAL Savings Contributions Account in whole dollars.  In addition, a Participant may withdraw vested amounts from his KM Matching Contributions Account, except that a Participant who has not been a Participant under the KM Plan and/or the Plan for at least five years shall not be permitted to make such a withdrawal with respect to any Matching Contributions which have not been credited to his Matching Contributions Account for at least two years.  Except as may be required by law, such withdrawal shall be first from the CAPITAL Savings Contributions Account and then from the Matching Contributions Account.	
A-2

 	(ii)	All withdrawal requests pursuant to this Appendix shall be filed with the Committee and shall be made on such withdrawal request form and in such manner as the Committee may prescribe from time to time.  In addition, withdrawals and withdrawal payments pursuant to this Appendix shall be subject to and made in accordance with such rules and procedures as the Committee may prescribe from time to time, including rules governing the withdrawal and charging of withdrawal payments among the subaccounts in the Participant's KM Account in the case of a withdrawal of less than 100% of the funds available for withdrawal.  Withdrawals from a Participant's CAPITAL Savings Contribution Account shall be attributed to the Participant's CAPITAL Savings Contributions mad e prior to January 1, 1987, to the extent allowed by the Code.	
 	(iii)	A Participant shall not be permitted to make more than one in-service withdrawal from his KM Account under the provisions of subsection (i) above during any 12-month period.	

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APPENDIX B 
 
PENNZENERGY COMPANY SAVINGS AND 
INVESTMENT PLAN MERGER
This Appendix B shall apply with regard to those employees who were previously employed by PennzEnergy Company (" Pennz ") whose Accounts under the Plan include amounts transferred to the Plan from the PennzEnergy Company Savings and Investment Plan (the " Pennz Plan ") in connection with the merger, effective as of November 1, 2000, of the Pennz Plan with and into the Plan.
 
1.	Plan Merger .  The Pennz Plan shall be merged with and into the Plan, effective as of November 1, 2000.  The provisions of the Plan shall become fully applicable to the participants, former participants, beneficiaries and alternate payees of the Pennz Plan, except as provided in this Appendix.	
2.	Date of Plan Participation .  Any participant in the Pennz Plan on October 31, 2000 shall become a Participant in the Plan on November 1, 2000; provided, however, that any individual who participated in the Pennz Plan but who terminated employment prior to, and who does not have an Employment Commencement Date on or after, November 1, 2000 shall not become a Participant in the Plan, except for a limited purpose, including, without limitation, investment allocation and distributions, as outlined in Section 3.06 of the Plan.	
3.	Asset Transfer Provisions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Transfer of Plan Assets .  Effective as of November 1, 2000, or as soon as administratively practicable thereafter, assets and liabilities from the trust fund for the Pennz Plan shall be transferred to the Trust Fund.  All assets and liabilities transferred to the Plan from the trust fund for the Pennz Plan shall be administered in accordance with the generally applicable terms of the Plan, together with such other provisions that are applicable to former participants in the Pennz Plan (" Pennz Plan Participants ") as set forth in this Appendix.	
 	(b)	Regulatory Requirements .  As required by Treas. Reg. § 414(l)‑1(d), each Pennz employee who has an account balance from the Pennz Plan transferred to the Plan shall receive a benefit immediately after the transfer contemplated under subsection (a) above that is equal to or greater than the benefit that he would have been entitled to receive immediately before such transfer (as if either the Pennz Plan or the Plan had then terminated).  	
 	(c)	Segregation of Transferred Amounts .  The Committee shall separately account for the amounts transferred to the Plan pursuant to subsection (a) above for record-keeping purposes and shall establish such segregated accounts or subaccounts as are necessary to provide for this separate accounting.  These separate accounts and subaccounts shall be referred to collectively as the " Pennz Accounts ."  Except as otherwise provided in this Appendix, the Pennz Accounts shall be treated in the same manner as all other Accounts under the Plan.	
B-1

4.	Special Conditions .  Notwit hstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Special Vesting of Pennz Accounts .  Pennz Accounts that were fully (100%) vested and nonforfeitable when transferred to the Trust Fund as set forth in Section 3(a) of this Appendix shall remain fully (100%) vested and nonforfeitable in this Plan, including:	
 	(i)	Pennz Accounts of any Participant who was a participant in the Pennz Plan and who was subject to immediate taxation on his employer matching contributions under the Pennz Plan pursuant to applicable Canadian income tax laws.	
 	(ii)	Pennz Accounts of any Participant who was employed by Pennzoil Sulphur Company as of June 30, 1994 whose service with the Pennzoil Sulphur Company is terminated from and after July 1, 1994 and on or before December 31, 1995.	
 	(iii)	Pennz Accounts of any Participant who terminated service by reason of the sale of Vermejo Park by Pennzoil Company on or about June 1, 1996.	
 	(iv)	Any portion of Pennz Accounts which were previously in the Pennz Plan and were invested in shares of Pennzoil-Quaker State Company, or the proceeds of the sale of such stock.	
 	(v)	Pennz Accounts of any Participant who was a participant in the Pennz Plan and who was an employee of Pennz in active service on May 19, 1999 and who terminated employment with Pennz or the Company prior to the second anniversary of the closing date of the "Transaction" contemplated by, and as defined in, the Amended and Restated Agreement and Plan of Merger by and among the Company, Devon Oklahoma Corporation and Pennz, dated as of May 19, 1999.	
 	(b)	Special Vesting of Certain Pennz Plan Participants .  Notwithstanding anything to the contrary herein, any Participant who is a Pennz Plan Participant and whose employment with the Company terminated between August 18, 2000 and August 18, 2002 will be 100% vested in all of his Accounts in the Plan.	
 	(c)	Pennz After-Tax Contribution Account and Withdrawals .  The following provisions shall apply to the Pennz After-Tax Contribution Account of any Participant:	
 	(i)	" Pennz After-Tax Contribution Account " shall mean the separate Account representing a Participant's nondeductible contributions that were made to the Pennz Plan and transferred to the Plan as described in Section 3(a) of this Appendix, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.	
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 	(ii)	A Participant may, in the manner prescribed by the Committee, request a withdrawal from his Pennz After-Tax Contribution Account.  No forfeitures will occur solely as a result of the Participant's withdrawal of all or part of his Pennz After-Tax Contribution Account.  After receipt of the request, the Committee shall cause the Trustee to pay over the designated amount in not less than 90 days from the date such request shall have been delivered to the Committee.	
 	(iii)	All Pennz After-Tax Contributions made prior to January 1, 1987 will be maintained in a separate subaccount (the " Pre-1987 Account ") which is part of the Participant's Pennz After-Tax Contribution Account.  Withdrawals made from the Pre-1987 Account made under subsection (ii) above will not include any earnings attributable to such Pre-1987 Account.	
 	(iv)	All Pennz After-Tax Contributions made after December 31, 1986 will be maintained in a separate subaccount (the " After-1986 Account ") which is part of the Participant's Pennz After-Tax Contribution Account.  Withdrawals made from the After-1986 Account as provided under subsection (ii) above will include earnings attributable to such After-1986 Account.  The amount of earnings on Pennz After-Tax Contributions which must be distributed with each withdrawal will be calculated by multiplying the total amount of earnings then held in the After-1986 Account by a fraction the numerator of which is the amount of Pennz After-Tax Contributions that is included in the distribution and the denominator of which is the balance of all Pennz After-Tax Contributions then held in the After-1986 Account.	
 	(d)	Withdrawal of Rollover Account .  A Participant who is a Pennz Plan Participant may withdraw any or all of his Rollover Account by giving 30 days' prior notice to the Committee.	
 	(e)	In-Service Withdrawals .  A Participant who is a Pennz Plan Participant and has participated in the Pennz Plan and/or the Plan for at least five full Plan Years shall be entitled, at his election, to receive a distribution of all or any portion of his vested Employer Contribution Account attributable to the balance in his Employer Contribution Account on November 1, 2000, provided that the Participant has previously withdrawn the entire amount of his "Prior Plan Account" (as defined in the Pennz Plan) and his Rollover Account, if any, and the Participant is not on suspended status; provided, further, that a Participant may make only one withdrawal under this subsection (e) every five full Plan Years.	
 	(f)	Loans to Pennz Plan Participants .  Notwithstanding anything in the Plan to the contrary, the Committee may make a loan with a term not in excess of 20 years to a Participant who is a Pennz Plan Participant if the proceeds of such loan are used to purchase any dwelling within a reasonable time that is to be used as a principal residence of the Participant.	
 
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APPENDIX C 
 
SANTA FE ENERGY SNYDER SAVINGS 
INVESTMENT PLAN MERGER
This Appendix C shall apply with regard to those employees who were previously employed by Santa Fe Snyder Corporation or any subsidiary (" Santa Fe ") whose Accounts under the Plan include amounts transferred to the Plan from Santa Fe Energy Snyder Savings Investment Plan (the " Santa Fe Plan ") in connection with the merger, effective January 1, 2001, of the Santa Fe Plan with and into the Plan.  
 
1.	Plan Merger .  The Santa Fe Plan shall be merged with and into the Plan, effective as of January 1, 2001.  The provisions of the Plan shall become fully applicable to the participants, former participants, beneficiaries and alternate payees of the Santa Fe Plan, except as provided in this Appendix.	
2.	Date of Plan Participation .  Each Participant who was employed by the Employer on August 29, 2000 and continued to be employed by such Employer immediately thereafter shall continue to participate in the Plan in accordance with its terms.  Notwithstanding anything in to the contrary herein, any Employee who was employed by Santa Fe immediately prior to the merger of a subsidiary of the Company with and into Santa Fe on August 29, 2000 shall not be eligible to participate in the Plan.  Any participant in the Santa Fe Plan on December 31, 2000 shall become a Participant in the Plan on January 1, 2001.  Any individual who participated in the Santa Fe Plan but who terminated employment prior to, and who does not have an Employment Commencement Date on or after, January 1, 2001, shall not become a Participant in the Plan, except for a limited purpose, including, without limitation, investment allocation and distributions, as outlined in Section 3.06 of the Plan.	
3.	Asset Transfer Provisions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Transfer of Plan Assets .  Effective as of January 1, 2001, or as soon as administratively practicable thereafter, assets and liabilities from the trust fund for the Santa Fe Plan shall be transferred to the Trust Fund.  All assets and liabilities transferred to the Plan from the trust fund for the Santa Fe Plan shall be administered in accordance with the generally applicable terms of the Plan, together with such other provisions that are applicable to former participants in the Santa Fe Plan (" Santa Fe Plan Participants ") as set forth in this Appendix.	
 	(b)	Regulatory Requirements .  As required by Treas. Reg. § 414(l)‑1(d), each Santa Fe employee who has an account balance from the Santa Fe Plan transferred to the Plan shall receive a benefit immediately after the transfer contemplated under subsection (a) above that is equal to or greater than the benefit that he would have been entitled to receive immediately before such transfer (as if either the Santa Fe Plan or the Plan had then terminated).  	
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 	(c)	Segregation of Transferred Amounts .  The Committee shall separately account for the amounts transferred to the Plan pursuant to subsection (a) above for record-keeping purposes and shall establish such segregated accounts or subaccounts as are necessary to provide for this separate accounting.  These separate accounts and subaccounts shall be referred to collectively as the " Santa Fe Accounts ."  Except as otherwise provided in this Appendix, the Santa Fe Accounts shall be treated in the same manner as all other Accounts under the Plan.	
4.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Special Vesting of Certain Santa Fe Plan Participants .  Notwithstanding anything to the contrary herein, any Participant who became a participant in the Santa Fe Plan on the original effective date of the Santa Fe Plan, or was a participant in the Santa Fe Plan on May 5, 1999 (including those who became participants in the Santa Fe Plan upon the merger of the Snyder Oil Corporation Profit Sharing and Savings Plan into the Santa Fe Plan), shall be 100% vested in all of his Accounts at all times after such applicable event.	
 	(b)	Santa Fe After-Tax Contribution Account and Withdrawals .  The following provisions shall apply to the Santa Fe After-Tax Contribution Account of any Participant:	
 	(i)	" Santa Fe After-Tax Contribution Account " shall mean the separate Account representing a Participant's nondeductible contributions that were held in his SFP Plan Participant Contributions Account in the Santa Fe Plan and merged into the Plan as described in Section 3(a) of this Appendix, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.	
 	(ii)	A Participant may, in the manner prescribed by the Committee, request a withdrawal from his Santa Fe After-Tax Contribution Account.  No forfeitures will occur solely as a result of the Participant's withdrawal of all or part of his Santa Fe After-Tax Contribution Account.  After receipt of the request, the Committee shall cause the Trustee to pay over the designated amount in not less than 90 days from the date such request shall have been delivered to the Committee.	
 	(iii)	All Santa Fe After-Tax Contributions made prior to January 1, 1987 will be maintained in a separate subaccount (the " Pre-1987 Account ") which is part of the Participant's Santa Fe After-Tax Contribution Account.  Withdrawals made from the Pre-1987 Account made under subsection (ii) above will not include any earnings attributable to such Pre-1987 Account.	
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 	(iv)	All Santa Fe After-Tax Contributions made after December 31, 1986 will be maintained in a separate subaccount (the " After-1986 Account ") which is part of the Participant's Santa After-Tax Contribution Account.  Withdrawals made from the After-1986 Account as provided under subsection (ii) above will include earnings attributable to such After-1986 Account.  The amount of earnings on Santa Fe After-Tax Contributions which must be d istributed with each withdrawal will be calculated by multiplying the total amount of earnings then held in the After-1986 Account by a fraction the numerator of which is the amount of Santa Fe After-Tax Contributions that is included in the distribution a nd the denominator of which is the balance of all Santa Fe After-Tax Contributions then held in the After-1986 Account.	

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APPENDIX D 
 
MITCHELL ENERGY & DEVELOPMENT CORP. 
THRIFT & SAVINGS PLAN MERGER
This Appendix D shall apply with regard to those employees who were previously employed by Mitchell Energy & Development Corp. (" Mitchell ") whose Accounts under the Plan include amounts transferred to the Plan from Mitchell Energy & Development Corp. Thrift & Savings Plan (the " Mitchell Savings Plan ") in connection with the merger, effective March 1, 2002, of the Mitchell Plan and the Mitchell Energy Development Corp. Thrift & Savings Trust (the " Mitchell Trust ") with and into the Plan.  
 
1.	Plan Merger .  The Mitchell Savings Plan shall be merged with and into the Plan, and the Trust Fund shall accept the assets and liabilities of the Mitchell Trust, effective as of March 1, 2002.  The provisions of the Plan shall become fully applicable to the participants, former participants, beneficiaries and alternate payees of the Mitchell Savings Plan, except as provided in this Appendix.	
2.	Date of Plan Participation .  All Employees who are "members" (the " Members ") (as such term is defined in the Mitchell Savings Plan) in the Mitchell Savings Plan immediately prior to March 1, 2002 shall be eligible to become Participants in the Plan upon March 1, 2002.  Any individual who participated in the Mitchell Savings Plan but who terminated employment prior to, and who does not have an Employment Commencement Date on or after, March 1, 2002, shall not become a Participant in the Plan, except for a limited purpose, including, without limitation, investment allocation and distributions, as outlined in Section 3.06 of the Plan.	
3.	Asset Transfer Provisions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Transfer of Plan Assets .  Effective as of March 1, 2002, or as soon as administratively practicable thereafter, assets and liabilities from the Mitchell Trust shall be transferred to the Trust Fund.  All assets and liabilities transferred to the Plan from the Mitchell Trust shall constitute the beginning balances of the individual accounts in the Plan of the Members and shall be administered in accordance with the generally applicable terms of the Plan, together with such other provisions that are applicable to former participants in the Mitchell Savings Plan (" Mitchell Savings Plan Participants ") as set forth in this Appendix.	
 	(b)	Regulatory Requirements .  As required by Treas. Reg. § 414(l)‑1(d), each Mitchell employee who has an account balance from the Mitchell Savings Plan transferred to the Plan shall receive a benefit immediately after the transfer contemplated under subsection (a) above that is equal to or greater than the benefit that he would have been entitled to receive immediately before such transfer (as if either the Mitchell Savings Plan or the Plan had then terminated).  	
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 	(c)	Segregation of Transferred Amounts .  The Committee shall separately account for the amounts transferred to the Plan pursuant to subsection (a) above for record-keeping purposes and shall establish such segregated accounts or subaccounts as are necessary to provide for this separate accounting.  These separate accounts and subaccounts shall be referred to collectively as the " Mitchell Accounts ." Except as otherwise provided in this Appendix, the Mitchell Accounts shall be treated in the same manner as all other Accounts under the Plan.  Notwithstanding the foregoing, the "Cash or Deferred Accounts" and "Member Match Contribution Accounts" (each a s defined under the Mitchell Savings Plan) of Mitchell Savings Plan Participants shall be maintained as "Salary Deferral Accounts" and "Matching Contribution Accounts" under the Plan.  	
4.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Special Years of Service Rules for Certain Mitchell Savings Plan Participants .  Any Employee who was in active employment of Mitchell and who became an employee of an Employer or Affiliated Company on the date the Company acquired the stock of and merged with Mitchell (January 24, 2002) (the " Acquisition Date ") shall receive credit for Years of Service under the Plan consisting of (i) the years and months of service for vesting credited to the Employee under the Mitchell Savings Plan prior to the Mitchell Savings Plan's vesting computation period during which the merger of the Mitchell Savings Plan into the Plan occurs and (ii) the greater of (A) the Years of Service that would be credited to the Employee under the Plan for his service during the eligibility computation period of the Plan during which the merger of the Mitchell Savings Plan into the Plan occurs or (B) the vesting service credited to the Employee under the Mitchell Savings Plan as of March 1, 2002 less the vesting service taken into account under the foregoing clause (i)	
 	(b)	Vesting for Mitchell Savings Plan Participants .  Any unvested portions of the transferred account balances credited to the Mitchell Accounts shall continue to vest in accordance with the terms of the Plan.  Notwithstanding the foregoing, however, any Mitchell Savings Plan Participant whose employment is involuntarily terminated within one year of the Acquisition Date shall be fully (100%) vested in his Mitchell Accounts as of such date.	
 	(c)	Optional Forms of Benefit Preserved .  Any forms of distribution available under the Mitchell Savings Plan, but not available under the Plan on the day before the March 1, 2002, shall be available solely as to the assets held in the Mitchell Accounts attributable to participation in the Mitchell Savings Plan.  In addition, any forms of distribution available under the Plan on the day before the March 1, 2002 merger shall be available as to amounts credited to all Accounts maintained under the Plan, including the Mitchell Accounts.	

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APPENDIX E 
 
OCEAN RETIREMENT SAVINGS PLAN MERGER
This Appendix E shall apply with regard to those employees who were previously employed by Ocean Energy, Inc. (" Ocean ") whose Accounts under the Plan include amounts transferred to the Plan from the Ocean Retirement Savings Plan (the " Ocean Plan ") in connection with the merger, effective as of January 1, 2004, of the Ocean Plan with and into the Plan.
 
1.	Plan Merger .  The Ocean Plan shall be merged with and into the Plan, effective as of January 1, 2004.  The provisions of the Plan shall become fully applicable to the participants, former participants, beneficiaries and alternate payees of the Ocean Plan, except as provided in this Appendix.	
2.	Date of Plan Participation .  Effective January 1, 2004, every Employee who was employed by Ocean as of April 25, 2003, was an active participant in the Ocean Plan and is an Employee as of January 1, 2004 shall be a Participant in the Plan.  An individual who participated in the Ocean Plan but who terminated employment prior to, and who does not have an Employment Commencement Date on or after, January 1, 2004, shall not become a Participant in the Plan, except for a limited purpose, including, without limitation, investment allocation and distributions, as outlined in Section 3.06 of the Plan.	
3.	Asset Transfer Provisions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Transfer of Plan Assets .  Effective as of January 1, 2004, or as soon as administratively practicable thereafter, assets and liabilities from the trust fund for the Ocean Plan shall be transferred to the Trust Fund.  All assets and liabilities transferred to the Plan from the trust fund for the Ocean Plan shall be administered in accordance with the generally applicable terms of the Plan, together with such other provisions that are applicable to former participants in the Ocean Plan (" Ocean Plan Participants ") as set forth in this Appendix.	
 	(b)	Regulatory Requirements .  As required by Treas. Reg. § 414(l)‑1(d), each Ocean employee who has an account balance from the Ocean Plan transferred to the Plan shall receive a benefit immediately after the transfer contemplated under subsection (a) above that is equal to or greater than the benefit that he would have been entitled to receive immediately before such transfer (as if either the Ocean Plan or the Plan had then terminated).  	
 	(c)	Segregation of Transferred Amounts .  The Committee shall separately account for the amounts transferred to the Plan pursuant to subsection (a) above for record-keeping purposes and shall establish such segregated accounts or subaccounts as are necessary to provide for this separate accounting.  These separate accounts and subaccounts shall be referred to collectively as the " Ocean Accounts ."  Except as otherwise provided in this Appendix, the Ocean Accounts shall be treated in the same manner as all other Accounts under the Plan.	
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4.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Ocean Accounts .  The Ocean Accounts shall be held in the Plan and credited to the applicable corresponding account in the Plan.  	
 	(i)	" Ocean After-Tax Contribution Account " shall mean the separate Account representing a Participant's nondeductible contributions that were made to the Ocean Plan and transferred to the Plan as described in Section 3(a) of this Appendix, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.	
 	(ii)	" Ocean Before-Tax Contribution Account " shall mean the account established pursuant to the Ocean Plan that represents a Participant's deferrals under Section 401(k) of the Code into the Ocean Plan, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.  The Ocean Before-Tax Contribution Account will be credited and held pursuant to the terms of the Salary Deferral Account in the Plan.	
 	(iii)	" Ocean Employer Discretionary Contribution Account " shall mean the profit-sharing contribution account maintained in the Ocean Plan, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.  The Ocean Employer Discretionary Contribution Account shall be subject to the vesting schedule described in this Appendix.	
 	(iv)	" Ocean Employer Matching Contribution Account " shall mean the account which held Ocean Employer Matching Contributions pursuant to the terms of the Ocean Plan, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.  The Ocean Employer Matching Contribution Account shall be considered a part of the Matching Contribution Account in the Plan, but shall be subject to the vesting schedule described in this Appendix.	
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 	(v)	" Ocean ESOP Account " shall mean the special account established pursuant to the terms of the Ocean Plan which was considered to be an "employee stock ownership plan" pursuant to the terms of the Code and the Ocean Plan, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.  The Ocea n ESOP Account shall be maintained as a separate account in this Plan, but shall be distributed at the same time and in the same manner as the Ocean Discretionary Contribution Account.  An Ocean Participant's benefit in the Ocean ESOP Account shall be full y (100%) vested and nonforfeitable effective April 25, 2003, if such Ocean participant was employed by Ocean on such date.	
 	(vi)	" Ocean Rollover Contribution Account " shall mean the separate account established pursuant to the terms of the Ocean Plan, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.  The Ocean Rollover Contribution Account shall be held and administered in accordance with the terms of the Rollover Account in the Plan.	
 	(vii)	" Ocean Loan Account " shall mean an Ocean Participant's separate account established pursuant to the terms of the Ocean Plan in the event such participant has a loan outstanding pursuant to the terms of the Ocean Plan as of December 31, 2003.  The Ocean Loan Account shall be maintained as part of the Loan Account in the Plan.	
Notwithstanding the foregoing, effective on and after January 1, 2004, no additional contributions shall be made to any of the Ocean Accounts other than with respect to repayment of any loans under the Ocean Loan Account.  All future Contributions made to this Plan will be credited to the applicable Account maintained in this Plan that is not an Ocean Account.

 	(b)	Year of Service .  Effective January 1, 2004, Years of Service under the Plan shall include service with Ocean or any of its subsidiaries with respect to those employees of Ocean or any of its subsidiaries who were (i) employed by Ocean on April 25, 2003, (ii) participants in the Ocean Plan on December 31, 2003 and (iii) employed by the Company on December 31, 2003.  The calculation of Years of Service of an Ocean Participant shall be determined in accordance with the applicable provisions of the Plan.  Except as provided in this subsection with respect to the recognition of employment service for determining Years of Service, the Ocean Participants shall be considered as newly hired Employees.	
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 	(c)	Vesting of Ocean Accounts .  Except as otherwise set forth in Section 4 (d) of this Appendix, the Ocean Employer Discre tionary Contribution Account and Ocean Employer Matching Contribution Account (together, the " Ocean Employer Contribution Accounts ") of a Participant who is an Ocean Plan Participant shall vest in accordance with the following schedule:	
		
Years of Service	Vested Percentage	
Less than 1 year	0%	
1 year	34%	
2 years	67%	
3 or more years	100%	

 	(d)	Special Accelerated Vesting for Ocean Participants .  If an Ocean Participant shall cease to be employed by reason of reduction in force, as hereinafter described, such Ocean Participant shall have a fully (100%) vested and nonforfeitable interest in his Ocean Employer Discretionary Account and Ocean Employer Matching Contribution Account which were previously contributed by Ocean and which were not otherwise fully (100%) vested and nonforfeitable.  The employment of an Ocean Participant shall be considered as being terminated because of a "reduction in force" if such termination is the result of a manpower reduction or reorganization by the Employer.	
 	(e)	Ocean After-Tax Contribution Account and Withdrawals .  The following provisions shall apply to the Ocean After-Tax Contribution Account of any Participant:	
 	(i)	A Participant may, in the manner prescribed by the Committee, request a withdrawal from his Ocean After-Tax Contribution Account.  No forfeitures will occur solely as a result of the Participant's withdrawal of all or part of his Ocean After-Tax Contribution Account.  After receipt of the request, the Committee shall cause the Trustee to pay over the designated amount in not less than 90 days from the date such request shall have been delivered to the Committee.	
 	(ii)	All Ocean After-Tax Contributions made prior to January 1, 1987 will be maintained in a separate subaccount (the " Pre-1987 Account ") which is part of the Participant's Ocean After-Tax Contribution Account.  Withdrawals made from the Pre-1987 Account made under subsection (i) above will not include any earnings attributable to such Pre-1987 Account.	
 	(iii)	All Ocean After-Tax Contributions made after December 31, 1986 will be maintained in a separate subaccount (the " After-1986 Account ") which is part of the Participant's Ocean After-Tax Contribution Account.  Withdrawals made from the After-1986 Account as provided under	
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 		subsection (i) above will include earnings attributable to such After-1986 Account.  The amoun t of earnings on Ocean After-Tax Contributions which must be distributed with each withdrawal will be calculated by multiplying the total amount of earnings then held in the After-1986 Account by a fraction the numerator of which is the amount of Ocean Aft er-Tax Contributions that is included in the distribution and the denominator of which is the balance of all Ocean After-Tax Contributions then held in the After-1986 Account.	
 	(f)	In-Service Withdrawals for Ocean Accounts .  	
 	(i)	An Ocean Participant may withdraw from his Ocean After-Tax Contribution Account and/or Ocean Rollover Contribution Account any or all amounts held in such Accounts.	
 	(ii)	An Ocean Participant who has withdrawn all amounts in his Ocean After-Tax Contribution Account and Ocean Rollover Contribution Account may withdraw from his Ocean Employer Matching Contribution Account any or all amounts held in such Ocean Account that have been so held for 24 months or more, but not in excess of such Participant's vested interest in such Ocean Account.	
 	(iii)	An Ocean Participant who has attained age 59½ may withdraw from his Ocean Before-Tax Contribution Account, his Ocean Employer Matching Contribution Account and his Ocean Rollover Contribution Account an amount not exceeding such Participant's vested interest in the then-value of such Ocean Accounts.  Such withdrawal shall come first, from the Participant's Ocean Before-Tax Contribution Account, second, from the Participant's Vested Interest in his Ocean Employer Matching Contribution Account and, finally, from his Ocean Rollover Contribution Account.	
 	(iv)	An Ocean Participant who has a financial hardship, as determined by the Committee, and who has made all available withdrawals pursuant to the Plan and pursuant to the provisions of any other plans of the Employer and any Affiliated Company of which he is a member and who has obtained all available loans pursuant to ARTICLE IX and pursuant to the provisions of any other plans of the Employer and any Affiliated Company of which he is a member may withdraw from his Ocean Employer Matching Contribution Account and his Ocean Before-Tax Contribution Account amounts not to exceed the lesser of (1) such Participant's vested interest in such Ocean Accounts or (2) the amount determined by the Committee as being available for withdrawal pursuant to this subsection.  Such withdrawal shall come first, from the Ocean Participant's vested interest in his Ocean Employer Matching Contribution Account and then, from his Ocean Before-Tax Contribution Account.  For purposes of this subsection, "financial hardship" shall mean the immediate	
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 		and heavy financial needs of the Ocean Participant.  A withdrawal based upon financial hardship purs uant to this subsection shall not exceed the amount required to meet the immediate financial need created by the hardship and not reasonably available from other resources of the Ocean Participant.  The amount required to meet the immediate financial need may include any amounts necessary to pay any federal, state, or local income taxes or penalties reasonably anticipated to result from the distribution.  The determination of the existence of an Ocean Participant's financial hardship and the amount required to be distributed to meet the need created by the hardship shall be made by the Committee.  The decision of the Committee shall be final and binding, provided that all Participants similarly situated shall be treated in a uniform and nondiscriminatory man ner.  A withdrawal shall be deemed to be made on account of an immediate and heavy financial need of an Ocean Participant if the withdrawal is for:	
 	(A)	Expenses for medical care described in Code section 213(d) previously incurred by the Ocean Participant, the Ocean Participant's spouse, or any dependents of the Ocean Participant (as defined in Code section 152) or necessary for those persons to obtain medical care described in Code section 213(d) and not reimbursed or reimbursable by insurance;	
 	(B)	Costs directly related to the purchase of a principal residence of the Ocean Participant (excluding mortgage payments);	
 	(C)	Payment of tuition and related educational fees, and room and board expenses, for the next 12 months of post-secondary education for the Ocean Participant or the Ocean Participant's spouse, children, or dependents (as defined in Code section 152);	
 	(D)	Payments necessary to prevent the eviction of the Ocean Participant from his principal residence or foreclosure on the mortgage of the Ocean Participant's principal residence; or	
 	(E)	Such other financial needs that the Commissioner of Internal Revenue may deem to be immediate and heavy financial needs through the publication of revenue rulings, notices, and other documents of general applicability.	
 The above notwithstanding:  (1) withdrawals under this subsection from an Ocean Participant's Ocean Before-Tax Contribution Account shall be limited to the sum of the Ocean Participant's Before-Tax Contributions to the Plan, plus income allocable thereto and credited to the Ocean Participant's Ocean Before-Tax Contribution Account as of December 31, 1988, less any previous withdrawals of such amounts, and (2) withdrawals from an Ocean Participant's Ocean Employer Contribution Accounts
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attributable to contri butions after December 31, 1988 that constitute income allocable thereto or attributable to qualified nonelective contributions or qualified matching contributions shall not be permitted.  An Ocean Participant who makes a withdrawal from his Ocean Before-T ax Contribution Account under this subsection may not make Salary Deferrals under the Plan or any other qualified or nonqualified plan of the Employer or any Affiliated Company for a period of six months following the date of such withdrawal.  Further, suc h Ocean Participant may not make Salary Deferrals and Roth 401(k) Contributions under the Plan or any other plan maintained by the Employer or any Affiliated Company for such Ocean Participant's taxable year immediately following the taxable year of the wi thdrawal in excess of the applicable limit set forth in Code section 402(g) for such next taxable year less the amount of such Ocean Participant's elective contributions for the taxable year of the withdrawal.

 	(g)	Restrictions on Ocean In-Service Withdrawals .  	
 	(i)	All withdrawals pursuant to this Appendix shall be made in accordance with the procedures established by the Committee.	
 	(ii)	Notwithstanding the provisions of this subsection (g), not more than one withdrawal pursuant to Section 4(f)(ii) of this Appendix or two withdrawals pursuant to Section 4(f)(iii) of this Appendix may be made in any one Plan Year, and no withdrawal shall be made from an Ocean Account to the extent such Ocean Account has been pledged to secure a loan from the Plan.	
 	(iii)	If a Participant's Ocean Account from which a withdrawal is made is invested in more than one Investment Fund, the withdrawal shall be made pro rata from each Investment Fund in which such Ocean Account is vested.	
 	(iv)	All withdrawals under Section 4(f) of this Appendix shall be paid in cash.	
 	(v)	Any withdrawal hereunder that constitutes an "eligible rollover distribution," as defined in Section 8.08(a) of the Plan, shall be subject to the provisions of Section 8.08 of the Plan.	
 	(vi)	Section 4(f) of this Appendix shall not be applicable to an Ocean Participant following termination of employment and the amounts in such Ocean Participant's Ocean Accounts shall be distributable only in accordance with the other provisions of ARTICLE VIII of the Plan.	
 
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APPENDIX F 
 
THUNDER CREEK GAS SERVICES, L.L.C. 
RETIREMENT SAVINGS PLAN MERGER
This Appendix F shall apply with regard to those employees who are employed or were previously employed by Thunder Creek Gas Services, L.L.C. (" Thunder Creek ") whose Accounts under the Plan include amounts transferred to the Plan from the Thunder Creek Gas Services, L.L.C. Retirement Savings Plan (the " Thunder Creek Plan ") in connection with the merger, effective December 18, 2009 of the Thunder Creek Plan with and into the Plan.  
 
1.	Plan Merger .  The Thunder Creek Plan shall be merged with and into the Plan, effective as of December 18, 2009.  The provisions of the Plan shall become fully applicable to the participants, former participants, beneficiaries and alternate payees of the Thunder Creek Plan, except as provided in this Appendix.	
2.	Date of Plan Participation .  Any participant in the Thunder Creek Plan on December 17, 2009 shall become a Participant in the Plan on December 18, 2009.  Any individual who participated in the Thunder Creek Plan but who terminated employment prior to, and who does not have an Employment Commencement Date on or after, December 18, 2009 shall not become a Participant in the Plan, except for a limited purpose, including, without limitation, investment allocation and distributions, as outlined in Section 3.06 of the Plan.	
3.	Asset Transfer Provisions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Transfer of Plan Assets .  Effective as of December 18, 2009, or as soon as administratively practicable thereafter, assets and liabilities from the trust fund for the Thunder Creek Plan shall be transferred to the Trust Fund.  All assets and liabilities transferred to the Plan from the trust fund for the Thunder Creek Plan shall be administered in accordance with the generally applicable terms of the Plan, together with such other provisions that are applicable to former participants in the Thunder Creek Plan (" Thunder Creek Plan Participants ") as set forth in this Appendix.	
 	(b)	Regulatory Requirements .  As required by Treas. Reg. § 414(l)‑1(d), each Thunder Creek employee who has an account balance from the Thunder Creek Plan transferred to the Plan shall receive a benefit immediately after the transfer contemplated under subsection (a) above that is equal to or greater than the benefit that he would have been entitled to receive immediately before such transfer (as if either the Thunder Creek Plan or the Plan had then terminated).  	
F-1

 	(c)	Segregation of Transferred Amounts .  The Committee shall separately account for the amounts transferred to the Plan pursuant to subsection (a) above for record-keeping purposes and shall establish such segregated accounts or subaccounts as are necessary to provide for this separate accounting.  These separate accounts and subaccounts shall be referred to collectively as the " Thunder Creek Accounts ."  Except as otherwise provided in this Appendix, the Thunder Creek Accounts shall be treated in the same manner as all other Accounts under the Plan.	
4.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Definitions.	
 	(i)	" Thunder Creek Employer Contributions " shall mean the employer contributions made to the Thunder Creek Plan before its merger into the Plan on December 18, 2009.	
 	(ii)	" Thunder Creek Employer Contributions Account " shall mean the separation Account that holds the Thunder Creek Employer Contributions made to a Thunder Creek Plan Participant and that were merged into the Plan as described in Section 3(a) of this Appendix, including all earnings and gains attributable thereto and reduced by all losses attributable thereto, all expenses chargeable there against and by all withdrawals and distributions therefrom.	
 	(b)	Special Vesting of Thunder Creek Employer Contributions .  Except as otherwise set forth in this Appendix, the Thunder Creek Employer Contributions Account of a Participant who is a Thunder Creek Plan Participant shall vest in accordance with the following schedule:	
		
Years of Service	Vested Percentage	
Less than 3 years	0%	
3 or more years	100%	
 
F-2

APPENDIX G 
 
SPECIAL PROVISIONS FOR GEOSOUTHERN 
CONTINUED EMPLOYEES
This Appendix G shall apply with regard to those employees who (a) remain employed by GeoSouthern Energy Corporation or one of its affiliates ("GeoSouthern") until the closing of the transaction set forth in the GeoSouthern Purchase Agreement (as defined in Section 3 of this Appendix) and (b) become Employees of the Company in connection with such transaction.  

1.	Transfer of Employees from GeoSouthern .  Each GeoSouthern Continued Employee (as defined in Section 3 of this Appendix) shall become an Eligible Employee upon the "Closing Date" (as defined in the GeoSouthern Purchase Agreement) in accordance with the terms of the Plan.  The provisions of the Plan shall apply to each GeoSouthern Continued Employee, except as provided in this Appendix.  Notwithstanding any provision of the Plan or this Appendix to the contrary, no GeoSouthern Continued Employee shall be eligible for a Company Retirement Contribution at a rate determined under Section 4.04(b) of the Plan.	
2.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Special Employment Commencement Date or Reemployment Commencement Date for Participation Eligibility and Matching Contributions for GeoSouthern Continued Employees .  A GeoSouthern Continued Employee's Employment Commencement Date or Reemployment Commencement Date for purposes of (i) participation under ARTICLE III of the Plan and (ii) determining his rate of Matching Contributions under Section 4.05 of the Plan shall be the date of the GeoSouthern Continued Employee's most recent employment commencement date or reemployment commencement date, as the case may be, with GeoSouthern.	
 	(b)	Years of Service .  A GeoSouthern Continued Employee's Years of Service under the Plan shall include service with GeoSouthern previously recognized under any profit sharing or 401(k) plan sponsored by GeoSouthern.	
3.	Definitions .  For purposes of this Appendix G, the following terms shall have the following meanings:	
 	(i)	" GeoSouthern Continued Employee " shall mean a "Continued Employee," as defined in the GeoSouthern Purchase Agreement.	
 	(ii)	" GeoSouthern Purchase Agreement " shall mean the Purchase and Sale Agreement among GeoSouthern Intermediate Holdings, LLC, Devon Energy Production Company, L. P., and GeoSouthern Energy Corporation, dated November 20, 2013.	
G-1

APPENDIX H 
 
SPECIAL PROVISIONS FOR EMPLOYEES TRANSFERRING 
TO ENLINK MIDSTREAM OPERATING, LP
This Appendix H shall apply with regard to those Employees who (a) transfer to EnLink Midstream Operating, LP in connection with the closing of the transaction set forth in the EnLink Merger Agreement (as defined in Section 3 of this Appendix) and (b) cease being Eligible Employees upon such transfer.  

1.	Transfer of Employees to EnLink Midstream Operating, LP .  Each Transferring Employee (as defined in Section 3 of this Appendix) shall cease to be an Eligible Employee on his Severance from Service in accordance with the terms of the Plan.  The provisions of the Plan shall apply to such Transferring Employee, except as provided in this Appendix.	
2.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Special Eligibility for True-Up Matching Contribution .  An EnLink Transferring Employee shall continue to be eligible to receive a True-Up Matching Contribution for the quarter in which he becomes an employee of EnLink Midstream Operating, LP even though such Participant is not an Employee on the last day of such applicable quarter of the Plan Year.  	
 	(b)	Special Vesting for EnLink Transferring Employees .  An EnLink Transferring Employee shall have a fully (100%) vested and nonforfeitable interest in the portion of his Account that is subject to the vesting schedule described in Section 7.02(a) of the Plan.  	
 	(c)	Special Rollover of Loans .  An EnLink Transferring Employee who is an Eligible Borrower may make a direct rollover, as described in Section 8.08 of the Plan, of the full unpaid balance of any loan plus applicable interest to any "qualified employer plan" (as defined in Code section 72(p)(4) that accepts rollovers of loans.  Any EnLink Transferring Employee who makes such a rollover shall not be in "default" under Section 9.02(f) of the Plan solely as a result of his Severance from Service.	
3.	Definitions .  For purposes of this Appendix H, the following terms shall have the following meanings:	
 	(i)	" EnLink Merger Agreement " shall mean the Agreement and Plan of Merger by and among Devon Energy Corporation, Devon Gas Services, L.P., Acacia Natural Gas Corp I, Inc., Crosstex Energy, Inc., New Public Rangers, L.L.C., Boomer Merger Sub, Inc., and Rangers Merger Sub, Inc., dated October 21, 2013.	
 	(ii)	" EnLink Transferring Employee " shall mean a Participant who is (A) an Employee on the "Closing Date" of the "Mergers," each as defined under the EnLink Merger Agreement and (B) a "Transferring Employee," as defined in the EnLink Merger Agreement.	
H-1

APPENDIX I 
 
SPECIAL PROVISIONS FOR EMPLOYEES TRANSFERRING TO 
ENLINK MIDSTREAM OPERATING, LP IN CONNECTION WITH THE 
 CONTRIBUTION OF THE VICTORIA EXPRESS PIPELINE
This Appendix I shall apply with regard to those Employees who (a) transfer to EnLink Midstream Operating, LP in connection with the closing of the transaction set forth in the Victoria Express Pipeline Contribution Agreement (as defined in Section 3 of this Appendix); and (b) cease being Eligible Employees upon such transfer.

1.	Transfer of Employees to EnLink Midstream Operating, LP .  Each Victoria Express Pipeline Transferring Employee (as defined in Section 3 of this Appendix) shall cease to be an Eligible Employee on his Severance from Service in accordance with the terms of the Plan.  The provisions of the Plan shall apply to such Victoria Express Pipeline Transferring Employee, except as provided in this Appendix.	
2.	Special Conditions .  Notwithstanding the provisions of the Plan, the following provisions shall apply:	
 	(a)	Special Vesting for Victoria Express Pipeline Transferring Employees .  A Victoria Express Pipeline Transferring Employee shall have a fully (100%) vested and nonforfeitable interest in the portion of his Account that is subject to the vesting schedule described in Section 7.02(a) of the Plan.	
3.	Definitions .  For purposes of this Appendix I, the following terms shall have the following meanings:	
 	(i)	" Victoria Express Pipeline Contribution Agreement " shall mean the Contribution, Conveyance and Assumption Agreement by and between Devon Gas Services, L.P. and EnLink Midstream Partners, LP, dated as of March 23, 2015.	
 	(ii)	" Victoria Express Pipeline Transferring Employee " shall mean a Participant who is (A) an Employee on the "Closing Date" of the "Transactions," each as defined under the Victoria Express Pipeline Contribution Agreement; and (B) a "Transferring Employee," as defined in the Victoria Express Pipeline Contribution Agreement.	
 
I -1

Exhibit 12
RATIO OF EARNINGS TO FIXED CHARGES
December 31, 2017
 
 	 	Years Ended December 31,	 	
 	 	2017	 	 	2016*	 	 	2015*	 	 	2014*	 	 	2013*	 	
 	 	(Millions, except ratio amounts)	 	
Earnings (loss) from continuing operations before income taxes	 	$	896	 	 	$	(1,317	)	 	$	(19,858	)	 	$	604	 	 	$	(1,291	)	
Capitalized interest, net of amortization	 	 	(71	)	 	 	(63	)	 	 	(53	)	 	 	(59	)	 	 	(53	)	
 	 	 	825	 	 	 	(1,380	)	 	 	(19,911	)	 	 	545	 	 	 	(1,344	)	
Fixed charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expensed and capitalized	 	 	592	 	 	 	986	 	 	 	587	 	 	 	613	 	 	 	493	 	
Estimate of interest within rental expense	 	 	22	 	 	 	26	 	 	 	29	 	 	 	20	 	 	 	8	 	
Total fixed charges	 	 	614	 	 	 	1,012	 	 	 	616	 	 	 	633	 	 	 	501	 	
Earnings available (insufficient) for payment of fixed charges	 	$	1,439	 	 	$	(368	)	 	$	(19,295	)	 	$	1,178	 	 	$	(843	)	
Ratio of earnings to fixed charges	 	 	2.34	 	 	N/A	 	 	N/A	 	 	 	1.86	 	 	N/A	 	
Insufficient earnings to fixed charges	 	N/A	 	 	$	1,380	 	 	$	19,911	 	 	N/A	 	 	$	1,344	 	

  *	Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” within Devon’s annual report on Form 10-K for the year ended December 31, 2017.	
N/A	Not applicable.	

 

 

Exhibit 21

DEVON ENERGY CORPORATION
 
List of Subsidiaries 1 as of December 31, 2017

 	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, a Nova Scotia corporation	
 	7.	Devon Operating Company Ltd., an Alberta corporation	
 	8.	Devon Gas Co., L.L.C., a Delaware limited liability company	
 	9.	Devon Gas Services, L.P., a Texas limited partnership	
 	10.	Devon Energy International, Ltd., a Delaware corporation	
 	11.	Devon Realty Advisors, L.L.C., an Oklahoma limited liability company	
 	12.	Devon Headquarters, L.L.C., an Oklahoma limited liability company	
 	13.	EnLink Midstream, Inc., a Delaware corporation	
 	14.	EnLink Midstream, LLC, a Delaware limited liability company	
 	15.	EnLink Midstream Partners, LP, a Delaware limited partnership	
 	16.	EnLink Midstream Operating, LP, a Delaware limited partnership	
 	17.	EnLink Midstream Services, LLC, a Texas limited liability company	
 	18.	EnLink Midstream Holdings, LP, a Delaware limited partnership	
 	19.	EnLink NGL Pipeline, LP, a Texas limited partnership	
 	20.	EnLink Oklahoma Gas Processing, LP, a Delaware limited partnership	
 	21.	EnLink North Texas Gathering, LP, a Texas limited partnership	
 	22.	EnLink LIG Liquids, LLC, a Louisiana limited liability company	
 	23.	TOM-STACK, LLC, a Delaware limited liability company	
 	24.	Coronado Midstream LLC, a Texas limited liability company	
 	25.	Delaware G&P LLC, a Delaware 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 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 of our report dated February 21, 2018, with respect to the consolidated balance sheets of Devon Energy Corporation as of December 31, 2017 and 2016, and the related consolidated comprehensive statements of earnings, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes, and the effectiveness of internal control over financial reporting as of December 31, 2017, which report appears in the December 31, 2017 annual report on Form 10-K of Devon Energy Corporation.
Our report refers to a change in its method of accounting for oil and gas exploration and development activities from the full cost method of accounting to the successful efforts method of accounting in 2017.
/s/ KPMG LLP
Oklahoma City, Oklahoma
February 21, 2018

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, 2017 (this “Form 10-K”), which report is included as an exhibit to this Form 10-K.

				
 	LaRoche Petroleum Consultants, Ltd.	

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

 
February 21, 2018

 

 

 

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, 2017 (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 21, 2018

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 21, 2018	 	 	
 	 	 	
 	 	/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 21, 2018	 	 	
 	 	 	
 	 	/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, 2017 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 21, 2018	

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, 2017 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 21, 2018	

 
Exhibit 99.1

January 16, 2018
 
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, 2017, 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 8, 2018.  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-five percent (85%) 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 presented above are for the field areas designated by Devon’s internal naming system.  These areas include:
 
Anadarko Basin Sub-Division
Field Groups: Cana and Sheetrock
 
Delaware Basin Sub-Division
Field Groups: Cotton Draw Area and Hackberry
 
North Texas Sub-Division
Field Groups: NEBS Core Lean, NEBS Core N Wise, NEBS Core Rich Denton, NEBS Core Rich Wise, NEBS Noncore Denton, NEBS Noncore Lean, NEBS Noncore South, NEBS Noncore W Viola North, NEBS Noncore W Viola South, and NEBS Noncore Wise
 
Rocky Mountain Sub-Division
2435 N Central Expressway, Suite 1500  ●  Dallas TX 75080  ●  Phone (214) 363-3337  ●  Fax (214) 363-1608

Field Groups: Anton Irish, Big Horn Worland Area, CPRB Crossroads, CPRB Hilight, CPRB House Creek, CPRB Other, CPRB Pine Tree, CPRB South, Fullerton Area, Reeves, SPRB East, SPRB Other, SPRB South Dilts, SPRB West, Wasson, Welch Area, Wind River Beaver Crk, and Wind River Riverton
 
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, 2017 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 2017.  Oil prices used by Devon are based on a Cushing West Texas Intermediate crude oil price of $51.34 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 $2.98 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 $24.85 per barrel, as published in the OPIS daily price bulletin, adjusted by area for composition, quality,
LaRoche Petroleum Consultants, Ltd.

transportation fees, and regional price differentials.  Price differentials and adjustments to physical spot prices as of December 2017 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 $48.19 per barrel for oil, $2.43 per Mcf for gas, and $16.12 per barrel 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
LaRoche Petroleum Consultants, Ltd.

production and pressure data.  It may be necessary to revise these estimates up or down in the 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, 2017 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 42 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 21 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	
 	
/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:jb
17-600
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

	  	
700, 850 – 2 nd Street SW
Calgary AB T2P 0R8
Canada
 
 Tel: 403-267-1700
Fax: 587-774-5398
www.deloitte.ca

 

  

 

 

January 17, 2018

 
 
Devon Energy Corporation
333 West Sheridan
Oklahoma City, Oklahoma
USA  73102
 
Attention: Mr. Bob Fant
 
RE: Devon Canada Corporation
December 31, 2017 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, 2017. Our audit was completed on January 12, 2017 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 98 percent of Devon Canada’s total proved reserves in the Lloydminster 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 19 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.
 
Deloitte was provided with Devon Canada’s base hydrocarbon prices (oil, gas, condensate and natural gas liquids) as of December 31, 2017 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. We have, however, 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.
 
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, 2017 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, P. Eng.
Partner
Deloitte LLP

 

	 	

 
Certificate of qualification

 
I, R. G. Bertram, a Professional Engineer, of 700, 850 – 2 nd 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 of Devon Canada Corporation.  The effective date of this evaluation is December 31, 2017.	

 
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 of 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 thirty two years of engineering experience.	

 
4.	I am a Qualified Reserves Auditor as defined in the Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 3.2.	

 
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 17, 2018
Date

 

 

 

 
 
Audit procedure
Definitions and methodology

 

 

 

 

 
 
Effective as of December 2017

5
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

 

6
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.

 

7
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).
 
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).
 
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.

8
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.
 
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.	

9
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.
 
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.

 

Devon Energy Corporation
December 31, 2017 reserve audit opinion
Page 10
 
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, 2017 through to December 1, 2017).
 
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	$51.34/bbl	$34.38/bbl	
Bitumen	Edmonton AWB	$37.25/bbl	$31.86/bbl	
Gas	NYMEX Henry Hub	$2.98/MMbtu	$1.56/MMbtu