DEVON ENERGY CORPORATION (Exact Name of Registrant as Specified in its Charter)

Transcription

1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): November 6, 2018 DEVON ENERGY CORPORATION (Exact Name of Registrant as Specified in its Charter) DELAWARE (State or Other Jurisdiction (Commission (IRS Employer of Incorporation) File Number) Identification Number) 333 W. SHERIDAN AVE., OKLAHOMA CITY, OKLAHOMA (Address of Principal Executive Offices) (Zip Code) Registrant s telephone number, including area code: (405) Not Applicable (Former Name or Former Address, if Changed Since Last Report) Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instructions A-2. Below): Written communications pursuant to Rule 425 under the Securities Act (17 CFR ) Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR a-12) Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR d-2(b)) Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR e-4(c)) Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 ( of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 ( b-2 of this chapter). 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.

2 Item 2.02 Results of Operations and Financial Condition. On November 6, 2018, Devon Energy Corporation (the Company ) issued a press release announcing its financial and operational results for the quarter ended September 30, In connection with the earnings release, the Company also provided its operations report for the third quarter of Copies of the earnings release and third quarter 2018 operations report are furnished as Exhibits 99.1 and 99.2, respectively, to this report and will be available on the Company s website at The information contained in this report and the exhibits hereto shall not be deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act ), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing. Item 7.01 Regulation FD Disclosure. The information in Item 2.02 above is incorporated herein by reference. Item 9.01 Financial Statements and Exhibits. (d) Exhibits Exhibit No. Description of Exhibits 99.1 Earnings release, dated November 6, Third quarter 2018 operations report.

3 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. Date: November 6, 2018 DEVON ENERGY CORPORATION By: /s/jeffreyl.ritenour Jeffrey L. Ritenour Executive Vice President and Chief Financial Officer

4 Exhibit 99.1 NEWS RELEASE Devon Energy Reports Third-Quarter 2018 Results Highlights Delaware Basin and Eagle Ford drive U.S. production outperformance Third-quarter upstream capital expenditures were 9 percent below guidance Operating cash flow expands 61 percent year over year to $807 million Free cash flow generation reaches $249 million in third quarter Stock-repurchase program on pace to decrease share count by 20 percent OKLAHOMA CITY Nov. 6, 2018 Devon Energy Corp. (NYSE: DVN) today reported operational and financial results for the third quarter of Also included within the release is the company s guidance outlook for the fourth quarter of Devon continued to execute at a high level on its U.S.-focused growth initiatives, said Dave Hager, president and CEO. Our third-quarter performance was highlighted by improving well productivity and capital efficiency that drove U.S. production above the high end of guidance with a total capital investment well below forecast. Furthermore, our unwavering commitment to capital discipline allowed us to comfortably fund our drilling programs and generate free cash flow in the quarter. In addition to our strong operational and financial results, we also made significant progress building per-share value through our industry-leading $4 billion share-repurchase program, Hager said. Given the value proposition of our current share price, we opportunistically accelerated the buyback of our shares and are on track to repurchase approximately 20 percent of the company s outstanding shares by the time we complete the program in the first quarter of Delaware Basin and Eagle Ford Drive U.S. Production Outperformance Devon s total companywide production averaged 522,000 oil-equivalent barrels (Boe) per day in the third quarter. With the company s capital programs focused on expanding higher-margin production, oil and natural gas liquids (NGLs) volumes increased to 67 percent of the product mix. Third-quarter production was highlighted by results from Devon s U.S. resource plays, which are attaining the highest returns in the company s portfolio. U.S. production averaged 418,000 Boe per day in the quarter, exceeding the company s third-quarter guidance range, adjusted for asset sales, of 398,000 to 417,000 Boe per day. Within Devon s diversified U.S. portfolio, the strongest asset-level performance was achieved by the company s Delaware Basin operations in southeast New Mexico. Oil production from this world-class asset increased 45 percent year over year, driving volumes in the Delaware to 79,000 Boe per day. A key driver of growth was seven prolific Wolfcamp wells around the state-line area that averaged initial 30-day rates of 4,000 Boe per day per well. 1

5 Devon s Eagle Ford assets in south Texas also delivered strong results, with production advancing 12 percent compared to the second quarter of The growth was driven by 20 high-rate wells brought online during the quarter that averaged initial 30-day rates of approximately 3,000 Boe per day per well. With the strong well productivity Devon has achieved year to date in the U.S., light-oil production growth from retained assets is on track to advance 17 percent in This growth rate is trending at approximately 200 basis points above the company s original budget expectations, adjusted for asset sales. For additional details on Devon s E&P operations and preliminary 2019 outlook, please refer to the company s third-quarter 2018 operations report at Capital Spending Below Q3 Guidance; No Change to 2018 Outlook In addition to the strong U.S. production performance, the company maintained discipline with its capital program. Devon s upstream capital spending was $523 million in the third quarter, which was $52 million, or 9 percent below the company s midpoint guidance. For the full year, Devon has made no modifications to its capital outlook and expects its upstream capital spending to be approximately $2.4 billion in Premium Gulf Coast Pricing Drives Upstream Revenue Higher Devon s upstream revenue, excluding commodity derivatives, totaled $1.6 billion in the third quarter, a 29 percent improvement compared to the year-ago quarter. Contributing factors to revenue growth were higher commodity price realizations and growth in higher-margin, liquids production. Revenue associated with NGLs production delivered the highest growth, advancing 134 percent year over year. The company s NGLs volumes are benefitting from direct access to premium Mont Belvieu pricing through fixed, low-cost transportation and fractionation agreements. Also contributing to higher revenues were firm transport and marketing agreements that provide the majority of Devon s U.S. oil production direct access to advantaged Gulf Coast pricing. Combined with price protection provided by regional basis swaps, oil realizations in the U.S. averaged approximately 97 percent of the West Texas Intermediate (WTI) benchmark. The company s heavy-oil business in Canada continues to benefit from Western Canadian Select (WCS) basis swaps on approximately 50 percent of its estimated oil production in These attractive WCS basis swaps are locked in at $15 off WTI pricing and have generated cash settlements of $193 million year to date. Operating Costs Improve and Field-Level Margins Expand Devon s largest field-level cost, lease operating expense and transportation, totaled $453 million, or $9.45 per Boe in the third quarter. This represents a $40 million improvement compared to the previous quarter and was 2 percent below guidance. The field-level cost savings were achieved in both the U.S. and Canada. The improving operating costs coupled with the benefits of improved price realizations and higher-margin liquids production resulted in margin expansion for Devon. Field-level cash margin reached $22 per Boe in the third quarter, a 34 percent increase compared to the year-ago period. Field-level cash margin is computed as upstream revenues, excluding commodity derivatives, less production expenses with the result divided by oil-equivalent production volumes. 2

6 Corporate Cost Savings Initiatives Enhancing Profitability Further enhancing Devon s profitability is its improving general and administrative (G&A) cost structure. G&A expenses totaled $147 million in the third quarter, which was below the low end of guidance and represents a 13 percent improvement compared to the third quarter of The lower overhead costs were driven by reduced personnel expenses. With the retirement of $828 million of debt year to date, the company expects to reduce net financing costs by $66 million on an annual basis. With reduced debt balances, Devon s net borrowing costs (net financing costs plus capitalized interest) improved 17 percent year over year to $81 million. The aforementioned cost savings, combined with the financial benefits related to the sale of EnLink Midstream, position Devon s go-forward G&A and interest expense to improve by approximately $475 million annually. Earnings Exceeds Wall Street Consensus The company reported net earnings attributable to Devon of $2.5 billion or $5.14 per diluted share in the third quarter. Adjusting for items securities analysts typically exclude from their published estimates, the company s core earnings totaled $324 million or $0.65 per diluted share, exceeding the consensus estimates of analysts. With the closing of the EnLink transaction, EnLink s financial results are no longer consolidated with Devon s upstream business, and historical results related to EnLink are presented as discontinued operations in the company s consolidated financial statements. Operating Cash Flow Increases 61 Percent; Free Cash Flow Reaches $249 Million Devon s operating cash flow from continuing operations totaled $807 million in the third quarter, a 61 percent increase compared to the same period a year ago. This level of operating cash flow fully funded the company s total capital investments and generated $249 million of free cash flow in the quarter. The company also generated additional cash inflows through its ongoing divestiture activity. With the closing of the EnLink transaction in July, asset sale proceeds exceeded $3 billion in the third quarter. To date, total proceeds from Devon s divestiture program have now reached $4.7 billion, and the company expects to achieve its $5 billion divestiture target around year-end. Industry-Leading $4 Billion Share-Repurchase Program Advances The company s $4 billion share-repurchase authorization represents the largest in the upstream industry when measured as a percentage of market capitalization. To date, Devon has repurchased 67 million shares, or nearly 13 percent of outstanding shares, at a total cost of approximately $2.7 billion. The company expects to complete its $4 billion share-repurchase program during the first quarter of Devon exited the third quarter with $3.1 billion of cash on hand and an undrawn credit facility of $3 billion. Devon has a debt balance of $6.0 billion and no significant debt maturities until mid Overall, Devon s financial position remains exceptionally strong, with investment-grade credit ratings and excellent liquidity. 3

7 Conference Call Webcast and Supplemental Earnings Materials Also provided with today s release is the company s detailed operations report that is available on the company s website at The company s third-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Nov. 7, 2018, and will serve primarily as a forum for analyst and investor questions and answers. Non-GAAP Disclosures This release may include non-gaap (generally accepted accounting principles) financial measures. Such non-gaap measures are not alternatives to GAAP measures, and you should not consider these non-gaap measures in isolation or as a substitute for analysis of our results as reported under GAAP. Reconciliations of these non-gaap measures and other disclosures are provided below in this release. Forward-Looking Statements Thisreleaseincludes forward-lookingstatements asdefinedbythesecuritiesandexchangecommission(sec).suchstatementsincludethose concerningstrategicplans,expectationsandobjectivesforfutureoperations,andareoftenidentifiedbyuseofthewords expects, believes, will, would, could, forecasts, projections, estimates, plans, expectations, targets, opportunities, potential, anticipates, outlook andothersimilarterminology.allstatements,otherthanstatementsofhistoricalfacts,includedinthispressreleasethataddressactivities,eventsor developmentsthatthecompanyexpects,believesoranticipateswillormayoccurinthefutureareforward-lookingstatements.suchstatementsaresubject toanumberofassumptions,risksanduncertainties,manyofwhicharebeyondthecontrolofthecompany.statementsregardingourbusinessand operationsaresubjecttoalloftherisksanduncertaintiesnormallyincidenttotheexplorationforanddevelopmentandproductionofoilandgas.these risksinclude,butarenotlimitedto:thevolatilityofoil,gasandnglprices;uncertaintiesinherentinestimatingoil,gasandnglreserves;theextentto whichwearesuccessfulinacquiringanddiscoveringadditionalreserves;theuncertainties,costsandrisksinvolvedinoilandgasoperations;regulatory restrictions,compliancecostsandotherrisksrelatingtogovernmentalregulation,includingwithrespecttoenvironmentalmatters;risksrelatedtoour hedgingactivities;counterpartycreditrisks;risksrelatingtoourindebtedness;cyberattackrisks;ourlimitedcontroloverthirdpartieswhooperateouroil andgasproperties;midstreamcapacityconstraintsandpotentialinterruptionsinproduction;theextenttowhichinsurancecoversanylosseswemay experience;competitionforleases,materials,peopleandcapital;ourabilitytosuccessfullycompletemergers,acquisitionsanddivestitures;andanyofthe otherrisksanduncertaintiesidentifiedinourform10-kandourotherfilingswiththesec.investorsarecautionedthatanysuchstatementsarenot guaranteesoffutureperformanceandthatactualresultsordevelopmentsmaydiffermateriallyfromthoseprojectedintheforward-lookingstatements.the forward-lookingstatementsinthisreleasearemadeasofthedateofthisrelease,evenifsubsequentlymadeavailablebydevononitswebsiteorotherwise. Devondoesnotundertakeanyobligationtoupdatetheforward-lookingstatementsasaresultofnewinformation,futureeventsorotherwise.TheSEC permitsoilandgascompanies,intheirfilingswiththesec,todiscloseonlyproved,probableandpossiblereservesthatmeetthesec sdefinitionsforsuch terms,andpriceandcostsensitivitiesforsuchreserves,andprohibitsdisclosureofresourcesthatdonotconstitutesuchreserves.thisreleasemaycontain certainterms,suchasresourcepotential,potentiallocations,riskedandunriskedlocations,estimatedultimaterecovery(oreur),explorationtargetsize andothersimilarterms.theseestimatesarebytheirnaturemorespeculativethanestimatesofproved,probableandpossiblereservesandaccordinglyare subjecttosubstantiallygreaterriskofbeingactuallyrealized.thesecguidelinesstrictlyprohibitusfromincludingtheseestimatesinfilingswiththesec. InvestorsareurgedtoconsidercloselythedisclosureinourForm10-K,availableatwww.devonenergy.com.YoucanalsoobtainthisformfromtheSEC bycalling1-800-sec-0330orfromthesec swebsiteatwww.sec.gov. 4

8 About Devon Energy Devon Energy is a leading independent energy company engaged in finding and producing oil and natural gas. Based in Oklahoma City and included in the S&P 500, Devon operates in several of the most prolific oil and natural gas plays in the U.S. and Canada with an emphasis on achieving strong returns and capital-efficient cash-flow growth. For more information, please visit Investor Contacts Media Contact Scott Coody, John Porretto, Chris Carr,

9 DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION PRODUCTION NET OF ROYALTIES Quarter Ended Nine Months Ended September 30, September 30, Oil and bitumen (MBbls/d) U. S Heavy Oil Retained assets U.S. divested assets Total Natural gas liquids (MBbls/d) U. S U.S. divested assets Total Gas (MMcf/d) U. S Heavy Oil Retained assets 1, U.S. divested assets Total 1,046 1,201 1,117 1,212 Total oil equivalent (MBoe/d) U. S Heavy Oil Retained assets U.S. divested assets Total

10 DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION PRODUCTION TREND Quarter 3 Quarter 4 Quarter 1 Quarter 2 Quarter 3 Oil and bitumen (MBbls/d) STACK Delaware Basin Rockies Oil Heavy Oil Eagle Ford Barnett Shale 1 Other Retained assets U.S. divested assets Total Natural gas liquids (MBbls/d) STACK Delaware Basin Rockies Oil Eagle Ford Barnett Shale Other Retained assets U.S. divested assets Total Gas (MMcf/d) STACK Delaware Basin Rockies Oil Heavy Oil Eagle Ford Barnett Shale Other Retained assets ,001 U.S. divested assets Total 1,201 1,175 1,177 1,128 1,046 Total oil equivalent (MBoe/d) STACK Delaware Basin Rockies Oil Heavy Oil Eagle Ford Barnett Shale Other Retained assets U.S. divested assets Total

11 DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION BENCHMARK PRICES (average prices) Quarter 3 September YTD Oil ($/Bbl) - West Texas Intermediate (Cushing) $69.60 $48.14 $66.79 $49.48 Natural Gas ($/Mcf) - Henry Hub $ 2.91 $ 2.99 $ 2.90 $ 3.17 REALIZED PRICES Quarter Ended September 30, 2018 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ $ $ 2.19 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.19 $ Cash settlements $ (3.04) $ (2.50) $ 0.01 $ (1.89) Realized price, including cash settlements $ $ $ 2.20 $ Quarter Ended September 30, 2017 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ $ $ 2.45 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.45 $ Cash settlements $ 0.54 $ (0.03) $ 0.12 $ 0.52 Realized price, including cash settlements $ $ $ 2.57 $ Nine Months Ended September 30, 2018 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ $ $ 2.21 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.21 $ Cash settlements $ (2.97) $ (1.62) $ 0.10 $ (1.44) Realized price, including cash settlements $ $ $ 2.31 $ Nine Months Ended September 30, 2017 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ $ $ 2.54 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.54 $ Cash settlements $ 0.45 $ (0.02) $ 0.05 $ 0.29 Realized price, including cash settlements $ $ $ 2.59 $

12 CONSOLIDATED STATEMENTS OF EARNINGS (in millions, except per share amounts) DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION Quarter Ended Nine Months Ended September 30, September 30, Upstream revenues $1,332 $1,101 $ 3,720 $ 3,974 Marketing revenues 1, ,306 2,524 Total revenues 2,579 1,933 7,026 6,498 Production expenses ,669 1,360 Exploration expenses Marketing expenses 1, ,250 2,571 Depreciation, depletion and amortization ,235 1,139 Asset impairments Asset dispositions (6) (170) 5 (200) General and administrative expenses Financing costs, net Restructuring and transaction costs Other expenses (31) (70) 14 (92) Total expenses 2,417 1,726 7,590 5,771 Earnings (loss) from continuing operations before income taxes (564) 727 Income tax expense (benefit) (138) 13 (179) 13 Net earnings (loss) from continuing operations (385) 714 Net earnings from discontinued operations, net of income tax expense 2, , Net earnings 2, , Net earnings attributable to noncontrolling interests Net earnings attributable to Devon $2,537 $ 193 $ 1,915 $ 715 Basic net earnings (loss) per share: Basic earnings (loss) from continuing operations per share $ 0.61 $ 0.37 $ (0.76) $ 1.36 Basic earnings from discontinued operations per share Basic net earnings per share $ 5.17 $ 0.37 $ 3.74 $ 1.36 Diluted net earnings (loss) per share: Diluted earnings (loss) from continuing operations per share $ 0.61 $ 0.37 $ (0.76) $ 1.35 Diluted earnings from discontinued operations per share Diluted net earnings per share $ 5.14 $ 0.37 $ 3.71 $ 1.35 Weighted average common shares outstanding: Basic Diluted UPSTREAM REVENUES (in millions) Quarter Ended Nine Months Ended September 30, September 30, Oil, gas and NGL sales $1,608 $1,245 $ 4,534 $ 3,760 Derivative cash settlements (91) 24 (211) 43 Derivative valuation changes (185) (168) (603) 171 Upstream revenues $1,332 $1,101 $ 3,720 $ 3,974 PRODUCTION EXPENSES (in millions) Quarter Ended Nine Months Ended September 30, September 30, Lease operating expense $ 234 $ 229 $ 744 $ 691 Gathering, processing & transportation Production taxes Property taxes Production expense $ 554 $ 448 $ 1,669 $ 1,360 9

13 CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION Quarter Ended Nine Months Ended September 30, September 30, Cash flows from operating activities: Net earnings $ 2,563 $ 212 $ 2,075 $ 774 Adjustments to reconcile net earnings to net cash from operating activities: Earnings from discontinued operations, net of tax (2,263) (18) (2,460) (60) Depreciation, depletion and amortization ,235 1,139 Asset impairments Leasehold impairments Accretion on discounted liabilities Total (gains) losses on commodity derivatives (214) Cash settlements on commodity derivatives (91) 24 (211) 43 (Gains) losses on asset dispositions (6) (170) 5 (200) Deferred income tax benefit (114) (25) (132) (57) Share-based compensation Early retirement of debt 312 Total (gains) losses on foreign exchange (28) (74) 53 (138) Settlements of intercompany foreign denominated assets/liabilities (243) 10 Other 42 (14) (8) (3) Changes in assets and liabilities, net (51) (12) (159) 121 Net cash from operating activities - continuing operations ,686 1,656 Cash flows from investing activities: Capital expenditures (598) (467) (1,851) (1,298) Acquisitions of property and equipment (19) (6) (35) (39) Divestitures of property and equipment Net cash from investing activities - continuing operations (528) (193) (1,190) (950) Cash flows from financing activities: Repayments of long-term debt principal (21) (828) Early retirement of debt (304) Repurchases of common stock (1,698) (2,197) Dividends paid on common stock (38) (30) (112) (95) Shares exchanged for tax withholdings (3) (1) (47) (57) Net cash from financing activities - continuing operations (1,760) (31) (3,488) (152) Effect of exchange rate changes on cash: Settlements of intercompany foreign denominated assets/liabilities 243 (10) Other (21) 22 Total effect of exchange rate changes on cash - continuing operations Net change in cash, cash equivalents and restricted cash of continuing operations (1,471) 289 (2,770) 566 Cash flows from discontinued operations: Operating activities Investing activities 2,950 (191) 2,548 (475) Financing activities Net change in cash, cash equivalents and restricted cash of discontinued operations 3, , Net change in cash, cash equivalents and restricted cash 1, Cash, cash equivalents and restricted cash at beginning of period 1,525 2,369 2,684 1,959 Cash, cash equivalents and restricted cash at end of period $ 3,121 $2,854 $ 3,121 $ 2,854 Reconciliation of cash, cash equivalents and restricted cash: Cash and cash equivalents $ 3,102 $2,639 $ 3,102 $ 2,639 Restricted cash included in other current assets Cash and cash equivalents included in current assets held for sale Total cash, cash equivalents and restricted cash $ 3,121 $2,854 $ 3,121 $ 2,854 10

14 DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION CONSOLIDATED BALANCE SHEETS (in millions) September 30, December 31, Current assets: Cash and cash equivalents $ 3,102 $ 2,642 Accounts receivable 1, Current assets held for sale 760 Other current assets Total current assets 4,757 4,791 Oil and gas property and equipment, based on successful efforts accounting, net 13,056 13,318 Other property and equipment, net 1,146 1,266 Total property and equipment, net 14,202 14,584 Goodwill Other long-term assets Long-term assets held for sale 9,729 Total assets $ 20,172 $ 30,241 Current liabilities: Accounts payable $ 777 $ 633 Revenues and royalties payable Short-term debt Current liabilities held for sale 991 Other current liabilities 1, Total current liabilities 3,224 3,315 Long-term debt 5,791 6,749 Asset retirement obligations 1,103 1,099 Other long-term liabilities Long-term liabilities held for sale 3,936 Deferred income taxes Equity: Common stock Additional paid-in capital 5,217 7,333 Retained earnings 2, Accumulated other comprehensive earnings 1,164 1,166 Treasury stock, at cost, 0.9 million shares in 2018 (35) Total stockholders equity attributable to Devon 8,898 9,254 Noncontrolling interests 4,850 Total equity 8,898 14,104 Total liabilities and equity $ 20,172 $ 30,241 Common shares outstanding CAPITAL EXPENDITURES (in millions) Quarter Ended Nine Months Ended September 30, 2018 September 30, 2018 Upstream capital $ 523 $ 1,794 Land and other acquisitions Exploration and production (E&P) capital 545 1,833 Capitalized interest 6 41 Other 7 30 Devon capital expenditures $ 558 $ 1,904 11

15 NON-GAAP FINANCIAL MEASURES DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION This press release includes non-gaap financial measures. These non-gaap measures are not alternatives to GAAP measures, and you should not consider these non-gaap measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-gaap measures used in this press release, including reconciliations to their most directly comparable GAAP measure. CORE EARNINGS Devon s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the company s financial results. Accordingly, the company also uses the measures of core earnings and core earnings per share attributable to Devon. Devon believes these non-gaap measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believes these non-gaap measures can facilitate comparisons of its performance between periods and to the performance of its peers. The following table summarizes the effects of these items on third-quarter 2018 earnings. (in millions, except per share amounts) Quarter Ended September 30, 2018 After Noncontrolling Before-tax After-tax Interests Per Diluted Share Continuing Operations Earnings attributable to Devon (GAAP) $ 162 $ 300 $ 300 $ 0.61 Adjustments: Asset dispositions (6) (5) (5) (0.01) Asset and exploration impairments Deferred tax asset valuation allowance (130) (130) (0.27) Fair value changes in financial instruments and foreign currency Restructuring and transaction costs Core earnings attributable to Devon (Non-GAAP) $ 345 $ 309 $ 309 $ 0.63 Discontinued Operations Earnings attributable to Devon (GAAP) $ 2,650 $ 2,263 $ 2,237 $ 4.53 Adjustments: Gain on sale of EnLink and the General Partner (2,607) (2,222) (2,222) (4.51) Core earnings attributable to Devon (Non-GAAP) $ 43 $ 41 $ 15 $ 0.02 Total Earnings attributable to Devon (GAAP) $ 2,812 $ 2,563 $ 2,537 $ 5.14 Adjustments: Continuing Operations Discontinued Operations (2,607) (2,222) (2,222) (4.51) Core earnings attributable to Devon (Non-GAAP) $ 388 $ 350 $ 324 $ 0.65 NET DEBT Devon defines net debt as debt less cash and cash equivalents. Devon believes that netting these sources of cash against debt provides a clearer picture of the future demands on cash from Devon to repay debt. (in millions) September 30, 2018 Total debt (GAAP) $ 6,048 Less cash and cash equivalents (3,102) Net debt (Non-GAAP) $ 2,946 12

16 FREE CASH FLOW DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION Devon defines free cash flow as operating cash flow from continuing operations less capital expenditures. Devon believes that free cash flow provides a useful measure of available cash generated by operating activities for other investing and financing activities. Quarter Ended (in millions) September 30, 2018 Operating cash flow from continuing operations $ 807 Less capital expenditures: Upstream capital (523) Land and other acquisitions (22) Capitalized interest (6) Other (7) Free cash flow $

17 DEVON ENERGY CORPORATION FORWARD LOOKING GUIDANCE PRODUCTION GUIDANCE Quarter 4 Low High Oil and bitumen (MBbls/d) U.S Heavy Oil (1) 110(1) 115(1) Retained assets U.S. divested assets 6 8 Total Natural gas liquids (MBbls/d) Retained assets U.S. divested assets 3 5 Total Gas (MMcf/d) U.S ,000 Heavy Oil 5 10 Retained assets 955 1,010 U.S. divested assets Total 980 1,045 Total oil equivalent (MBoe/d) U.S Heavy Oil Retained assets U.S. divested assets Total (1) Guidance assumes Jackfish complex curtailments continue throughout December PRICE REALIZATIONS GUIDANCE OTHER GUIDANCE ITEMS Quarter 4 Low High Oil and bitumen - % of WTI U.S. 90% 100% Canada 10% 20% NGL - realized price $23 $ 28 Natural gas - % of Henry Hub 70% 80% Quarter 4 ($ millions, except Boe and %) Low High Marketing & midstream operating profit $ 20 $ 30 LOE & GP&T per BOE $9.50 $9.75 Production & Property Tax $ 85 $ 95 Exploration expenses $ 25 $ 35 Depreciation, depletion and amortization $ 420 $ 460 General & administrative expenses $ 140 $ 160 Financing costs, net $ 75 $ 85 Other expenses $ 15 $ 20 Current income tax rate 0% 5% Deferred income tax rate 20% 25% Total income tax rate 20% 30% Average basic share count outstanding (MM)

18 CAPITAL EXPENDITURES GUIDANCE Quarter 4 (in millions) Low High Upstream capital $550 $650 Other 5 15 Devon capital expenditures $555 $665 14

19 DEVON ENERGY CORPORATION FORWARD LOOKING GUIDANCE Oil Commodity Hedges Price Swaps Price Collars Weighted Weighted Average Price Volume Average Floor ($/Bbl) (Bbls/d) Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) Period Volume (Bbls/d) Q ,800 $ ,200 $ $ Q1-Q ,130 $ ,904 $ $ Q1-Q ,740 $ ,973 $ $ Oil Basis Swaps Oil Basis Swaps Oil Basis Collars Weighted Average Differential to WTI ($/Bbl) Weighted Average Floor Differential to WTI ($/Bbl) Weighted Average Ceiling Differential to WTI ($/Bbl) Period Index Volume (Bbls/d) Volume (Bbls/d) Q Midland Sweet 23,000 $ (1.02) $ $ Q Argus LLS 12,000 $ 3.95 $ $ Q Argus MEH 16,000 $ 2.84 $ $ Q Western Canadian Select 62,109 $ (16.41) 1,000 $ (15.50) $ (13.93) Q1-Q Midland Sweet 28,000 $ (0.46) $ $ Q1-Q Argus LLS 15,000 $ 4.88 $ $ Q1-Q Argus MEH 16,000 $ 2.84 $ $ Q1-Q Western Canadian Select 10,647 $ (23.39) $ $ Natural Gas Commodity Hedges - Henry Hub Price Swaps Price Collars Weighted Average Price ($/MMBtu) Weighted Average Floor Price ($/MMBtu) Weighted Average Ceiling Price ($/MMBtu) Volume Period Volume (MMBtu/d) (MMBtu/d) Q ,000 $ ,000 $ 2.76 $ 3.09 Q1-Q ,129 $ ,241 $ 2.65 $ 3.03 Q1-Q ,075 $ ,545 $ 2.66 $ 2.96 Natural Gas Basis Swaps Weighted Average Period Index Volume (MMBtu/d) Differential to Henry Hub ($/MMBtu) Q Panhandle Eastern Pipe Line 120,000 $ (0.51) Q El Paso Natural Gas 100,000 $ (1.25) Q Houston Ship Channel 110,000 $ 0.01 Q Transco Zone 4 30,000 $ (0.03) Q1-Q Panhandle Eastern Pipe Line 74,384 $ (0.75) Q1-Q El Paso Natural Gas 130,000 $ (1.46) Q1-Q Houston Ship Channel 137,637 $ 0.01 Q1-Q Transco Zone 4 7,397 $ (0.03) Devon s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price. Devon s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index. Commodity hedge positions are shown as of November 1,

20 Q Operations Report Key Messages 2 Outlook 3 Modeling Stats 7 Q3 Results 8 Delaware Basin 11 STACK15 Rockies 18 Eagle Ford & Barnett Shale 19 Heavy Oil 20 NYSE: DVN devonenergy.com Exhibit 99.2

21 Disciplined Growth Strategy U.S. oil growth ahead of plan (+200 basis point vs. budget) No change to capital spending outlook Corporate cost savings: ~$475 million/year Operating cash flow accelerates in Q3 (+61% YoY) Reduced consolidated debt by >40% Repurchasing ~20% of outstanding stock Raised quarterly dividend 33% KEY ACCOMPLISHMENTS IN 2018 ü ü ü ü ü ü KEY STRATEGIC OBJECTIVES Fund high-return projects Maintain financial strength Return cash to shareholders Generate free cash flow ü

22 2018 Outlook: U.S. Growth Initiatives Ahead of Plan U.S. growth exceeding expectations YTD 2018e oil production growth rates (retained assets) U.S. Oil Production (MBOD) 2018e 2017 % Delaware Basin STACK Rockies Eagle Ford Other 6 6 Total retained assets % Divested assets (sold or to be sold) 9 11 Total reported oil production % Basis Points +200 FOR ADDITIONAL DETAILS ON ASSET DIVESTITURES SEE PAGE 10 No change to capital spending plans 2018e E&P capital $2.4B 10% 90% U.S. ASSETS 2018e E&P CAPITAL CANADA KEY MESSAGES U.S. oil growth to accelerate into 2019 No change to activity with higher pricing Generating free cash flow ($249 million in Q3)

23 OUTSTANDING SHARES U.S. RETAINED ASSETS E&P CAPITAL PROGRAM 2019 Preview: Keeping Our Discipline 15%-19% Growth $2.4-$2.7 Billion OPTIMIZED FOR RETURNS POSITIONED FOR FREE CASH FLOW ~20% Reduction DRIVEN BY LOW-RISK DEVELOPMENT PROGRAM OIL GROWTH SHARE REDUCTION $ ENHANCING PER-SHARE CASH FLOW GROWTH KEY MESSAGES U.S. resource plays account for ~90% of capital Delaware Basin top-funded asset in portfolio STACK & Rockies key contributors to oil growth

24 2018e Executing the Multi-Year Business Plan +15% 17% CAGR Multi-Year Targets ( ) 17% YoY growth 9% YoY growth in U.S. G&A/interest: $475 MM Trending above 3-year plan ~$5 billion by year end >40% decrease in debt Note: Assumes $65 WTI, $3 Henry Hub and current WCS strip pricing U.S. oil production (retained assets) Total BOE production (retained assets) Per-unit cost savings (G&A, interest & LOE) Cash flow growth Excess cash inflow (Free cash flow + divestiture proceeds) Net debt to EBITDA ratio Exceeding 2018 plan On track with 2018 plan +5% 7% CAGR >20% by 2020 $6 $8 billion ~1.0x 1.5x >20% CAGR (on a per-share basis)

25 Strategic Deployment of Excess Cash $4 billion share-repurchase program underway Represents ~20% of outstanding shares $2.7 billion repurchased to date Expect program to be completed by Q Raised quarterly dividend by 33% in 2018 Target cash flow payout ratio: 5% - 10% Expect to deliver sustainable dividend growth Retired $828 million of upstream debt year to date Reduces interest expense by $66 million annually EnLink sale further deleverages balance sheet Plan to retire maturing debt of $257 million by early 2019 Industry leading share-repurchase program Average outstanding shares (MM) ~20% REDUCTION 527 ~420 Aggressively deleveraging the balance sheet Consolidated debt ($B) >40% REDUCTION YEAR TO DATE $6.0 (net debt: $2.9)

26 KEY Q METRICS Key Modeling Q3 ACTUALS Stats & U.S. Outlook oil retained (MBbls/d) 125 Canada oil (MBbls/d) 102 NGLs retained (MBbls/d) 107 Gas - retained (MMcf/d) 1,001 Total retained assets (MBoe/d) 500 U.S. divested assets (MBoe/d) 22 Total (MBoe/d) 522 LOE & GP&T ($/BOE) $9.45 General & administrative expenses ($MM) $147 Financing costs, net ($MM) $75 Upstream capital ($MM) $523 Q ASSET DETAIL DELAWARE STACK ROCKIES EAGLE FORD BARNETT HEAVY OIL RETAINED PRODUCTION Oil (MBbl/d) NGL (MBbl/d) Gas (MMcf/d) Total (MBoe/d) ASSET MARGIN (per Boe) Realized price $46.80(2) $31.48 $55.83 $49.44 $17.78 $39.99(3) Lease operating expenses ($4.90) ($2.16) ($6.90) ($2.34) ($2.14) ($9.61) Gathering, processing & transportation ($2.01) ($5.05) ($1.68) ($4.92) ($7.53) ($3.93) Production & property taxes ($3.37) ($1.71) ($6.81) ($2.72) ($1.24) ($0.83) Cash margin $36.52 $22.56 $40.44 $39.46 $6.87 $25.62 CAPITAL ACTIVTY (Q3 avg.) Upstream capital ($MM) $198 $167 $29 $35 $15 $60 Operated development rigs Operated frac crews Operated spuds Operated wells tied-in Average lateral length 7,000 9,800 8,700 5,200 GUIDANCE Q4 2018e U.S. oil retained (MBbls/d) Canada oil (MBbls/d)(2) (1) NGLs retained (MBbls/d) Gas retained (MMcf/d) 955 1,010 Total retained assets (MBoe/d) U.S. divested assets (MBoe/d) Total (MBoe/d) Lease operating expense & GP&T ($/BOE) $9.50 $9.75 Production & property taxes ($MM) $85 $95 General & administrative expenses ($MM) $140 $160 Financing costs, net ($MM) $75 $85 Upstream capital ($MM) $550 $650 Avg. basic share count outstanding (MM) Guidance assumes Jackfish complex curtailments continue throughout December. Includes benefits of regional basis swaps and firm transport in the Delaware totaling $42 million. Includes benefits of regional basis swaps in Canada totaling $84 million.

27 Corporate cost structure continues to improve G&A declines 42% vs. peak rates Borrowing costs reduced 17% vs. Q Capital discipline accelerates free cash flow growth Q3 capital 9% below midpoint guidance Generated $249 million of free cash flow in Q3 Q3 Results Headlined by Free Cash Flow Generation Total U.S. production exceeds guidance Driven by Delaware Basin & Eagle Ford Firm transport and basis swaps protect pricing Light-oil has access to Gulf Coast markets Secured NGLs access to Mt. Belvieu (pg. 9) WCS swaps protect Canadian cash flow Achieving improved capital efficiency Upstream capital Strong oil realizations across U.S. U.S. oil realizations as % of WTI Light-oil growth advances U.S. oil production retained assets (MBOD) (2) Includes benefits of basis swaps & firm transport 97% of WTI(2) BASIS SWAPS & FIRM TRANSPORT FIELD-LEVEL REALIZATIONS INCREASE 24% $523 million Q3 CAPITAL INVESTMENT 9% BELOW GUIDANCE (1) Excludes divesture assets (see pg. 3 for asset detail)

28 One of the largest NGLs producers in the U.S. Q3 retained NGLs production: 107 MBbls per day Represents ~20% of production mix 98% of NGLs have access to Mont Belvieu markets(1) >30% premium to Conway pricing (see chart) Margins to benefit from contractual rights to recover operated ethane production Legacy contracts lock in below-market fees with no exposure to rising spot rates Firm sales contractually guarantee flow assurance Devon possesses excess capacity at Mont Belvieu ~10 MBbls/day of excess fractionating capacity Supports NGL growth plans through end of decade Capturing the Benefit of Higher NGLs Pricing (1) Represents percentage of operated production Mont Belvieu Flow Assurance to Premium NGLs Markets STACK Delaware Basin Advantaged Pricing at Mont Belvieu $/Barrel (Mont Belvieu vs. Conway Pricing) Mont Belvieu Conway Mont Belvieu >30% premium to Conway markets North Texas 98% of Devon s volumes access Mont Belvieu(1)

29 Divestiture Program Accelerates Value Creation SALES PRICE: $3.125 Billion ACCRETIVE MULTIPLE: 12x Cash Flow TRANSACTION DETAILS CLOSED Resource quality & depth allows for high-grading of portfolio Announced $4.7 billion of divestitures to date Closed EnLink transaction in July ($3.125 billion) Upstream asset sales: $1.6 billion No incremental cash taxes from transactions Expect to exceed $5 billion divestiture target around year end Rockies CO2 projects (bids by year end) Central Basin Platform assets (bids by year end) Continuously evaluating options to further high-grade upstream portfolio Next Steps in High-Grading Portfolio Rockies CO2 Central Basin Platform Production: 4 MBOED (~80% oil) Data room: Open Production: 4 MBOED (~45% oil) Data room: Open

30 Delaware Basin Q Results 79 (Q3 Guide: 70-75)(1) 45% GROWTH YEAR OVER YEAR Q3 Production Outperforms Guidance(1) Retained production (MBOED) Delaware Well Productivity Reaching Record Highs Average Cumulative Oil Production Per Well (MBOD) avg. Months Online >70% IMPROVEMENT 2018 VERSUS 3-YEAR AVERAGE Production increased 45% year over year(1) 4,000 BOE per day above top end of guidance Oil and liquids reach 78% of product mix Step-change improvement in 2018 well results >70% improvement in productivity vs. 3-year avg. Driven by focused program in state-line area Q3 performance driven by strong well productivity Top 10 wells achieved IP30: ~3,400 BOED (60% oil) Driven by prolific Wolfcamp results (see pg. 12) Effectively mitigating inflation pressures Per-unit LOE declined 8% vs. Q Capital in line with budget expectations YTD (1) Production and guidance range adjusted for Mi Vida and other non-core asset divestitures (~3 MBOED impact).

31 Delaware Wolfcamp Program Delivers Prolific Results WOLFCAMP DEVELOPMENT PROGRAM BUILDING MOMENTUM Current Projects COTTON DRAW RATTLESNAKE New Mexico Texas Development Areas ~4,000 Q3 WOLFCAMP WELLS(1) BOED AVG. 30-DAY IPs Lusitano 2 Wolfcamp wells online Avg. IP 30: 4,600 BOED/well Seawolf 5 of 12 Wolfcamp wells online Avg. IP 30: 3,700 BOED/well(1) Fighting Okra Completing Peak rates: 1H 2019 BONE SPRING 3rd WOLFCAMP XY A UPPER MIDDLE LOWER Seawolf Development - Rattlesnake Area Avg. IP30: 3,700 BOED(1) Peak Rates: Q Well productivity at Seawolf trending above plan Wolfcamp sweet spot in southern Lea County Avg. IP30: 3,700 BOED(1) (represents 5 of 12 wells) Peak rates for remaining 7 wells expected in Q4 Lusitano derisks Cotton Draw Wolfcamp potential 6-well project testing Leonard and Wolfcamp Wolfcamp wells avg. IP30: 4,600 BOED (50% oil) Flagler Drilling Peak rates: mid-2019 (1) Includes two appraisal wells (avg. lateral 5,700 ) that were normalized for 10,000 at a 1.75 multiplier.

32 Delaware Infrastructure Supports Profitable Growth Premium oil pricing and flow assurance Q3 oil realizations: 97% of WTI(1) Swaps & firm transport protect ~75% of 2019 oil Firm oil sales contracts guarantee in basin flow assurance (100 MBOD of contractual capacity in basin) NGLs have firm transport to Mont Belvieu (see pg. 9) Revenue improves ~30% vs. Q Swaps protect gas production through 2019 Infrastructure drives sustainable cost savings Operating costs improved ~60% vs. peak rates Oil and produced water gathered on pipe (avoids trucking) Operate ~50 disposal wells and 8 water reuse facilities 80% of water used in operations is recycled Includes benefits of basis swaps and firm transport to Gulf Coast Long-term guaranteed contractual capacity with firm transport partners Positioned for flow assurance & premium pricing Firm transport: ~20 MBOD on Longhorn Firm sales(2): 100 MBOD in basin Established local refinery relationships ~85% of oil gathered on pipe >90% of produced water on pipe FLOW ASSURANCE PLAN STRONG PRICE REALIZATIONS 97% OF WTI(1) BASIS SWAPS FIELD-LEVEL PRICING LONGHORN (FIRM TRANSPORT) Q3 RESULTS Note: costs are pro forma for revenue recognition accounting rules recently implemented. ~60% IMPROVEMENT Improved infrastructure driving lower costs LOE & Transportation Expense ($/BOE)

33 Delaware Basin Raising Growth Outlook Raising 2018 production growth estimates Increasing 2018 exit rate growth: ~90 MBOED(1) Non-core divestitures: 3 MBOED impact to Q4 Activity to reach 10 operated rigs around year end Ramping-up capital investment in 2019 Delaware is top-funded asset by a wide margin Capital investment: up to $1.0 billion Oil production growth: ~40% vs Per-unit LOE to decline 10% to 15% Accelerating Todd 2nd Bone Spring program Two Boundary Raider wells delivered highest rates in Delaware history (IP24: 24 MBOED) Drill >20 wells in focus area over next year (see map) Todd 2018 Activity Focus Area Bone Spring Focus Area (Drill >20 wells next year) Eddy Lea Two Boundary Raider Wells IP24: 24,000 BOED 2019 PREVIEW: ACCELERATING TODD 2ND BONE SPRING PROGRAM Upcoming wells (vs. 2018) High-return oil growth positioned to accelerate Retained production (MBOED) ~90(1) >5 MBOED vs. plan(1) RAISING GUIDANCE (1) Production and guidance range adjusted for Mi Vida and other minor non-core asset divestitures (~3 MBOED impact).

34 STACK Initial Infill Spacing Results Initial Infill Spacing Results Showboat 12 wells/unit (avg. lateral: 7,000 ) Avg. 90-Day IP: 800 BOED Horsefly 10 wells per drilling unit Avg. 30-Day IP: 1,475 BOED Coyote 7-well development project Avg. 90-Day IP: 3,100 BOED Bernhardt 8 wells per drilling unit Avg. 30-Day IP: 1,300 BOED BLACK OIL WINDOW OVER- PRESSURED OIL WINDOW Devon Acreage Current Projects ~35 Days COMPLETIONS (68% of well cost) DRILLING (32% of well cost) SAVINGS PER WELL Drilling Days Reduced Extended reach laterals >30% >50% DECREASE Significant Capital Savings Bernhardt D&C costs vs. parent well Q3 net production up 16% year over year Dewey County assets sold in Q3 (~7 MBOED) NGLs up ~30% with benefits of Mont Belvieu pricing Total volume growth limited by infill pilot performance Capital efficiency improves (spending 31% vs. 1H 2018 avg.) Infill activity accelerates D&C capital efficiencies Horsefly costs reduced to ~$7.5 million per well Bernhardt achieves >30% savings vs. parent (~$7MM/well) Pilots testing higher-density spacing not optimized Showboat upside test underperforms vs. plan (12 wells/unit) Horsefly delivered improved results (10 wells/unit) Bernhardt rates limited by flowback strategy (8 wells/unit) Lighter-spaced Coyote project delivers best results

35 STACK Next Steps to Optimize Development Returns Learnings from high-density infill tests Initial results indicate spacing was too tight Flowback approach key for oil recoveries Upper Meramec delivered best well results Vertical communication observed Substantial D&C savings achieved (pg. 15) Reverting to base case spacing to optimize returns Upcoming activity targeting 4-8 wells per unit Well placement focused in Upper Meramec Flowback adjusted to improve performance Project IRRs to benefit from less capital intensity Utilizing tailored, more capital efficient completions Projects to benefit from less infrastructure capital on centralized facilities Pony Express 4 wells per unit Online Q ML Block 8 wells per unit 2019 project Kingfisher Canadian Custer Blaine Upcoming Developments BLACK OIL WINDOW OVER- PRESSURED OIL WINDOW UPCOMING STACK DEVELOPMENT ACTIVITY Geis 7 wells per unit Flowing Back Shangri-La 5 wells per unit Online Q Showboat 12 wells per unit Safari 4 wells per unit Online Q Doppelganger/Kraken 8 & 7 wells per unit 2019 project Scott 6 wells per unit 2019 project wells UPCOMING ACTIVITY PER UNIT Developments Online Horsefly 10 wells per unit Bernhardt 8 wells per unit Coyote 7-well project Whiskey Jack 5 wells per unit Online Q Northwoods 4 wells per unit 2019 project Brachiosaurus 4 wells per unit 2019 project Minnie Ha Ha 6 wells per unit 2019 project Morning Thunder 4 wells per unit 2019 project

36 STACK Outlook Upcoming activity highly accretive to corporate return targets Q4 activity: 20 to 25 new wells online Re-establishes growth trajectory by year end Positioned for production growth in nd highest funded asset in portfolio Capital investment: $500-$700 million Expect to bring online wells Targeting 4-8 wells per drilling unit Significant growth inventory remaining 130,000 net acres in over-pressured oil window Acreage position >90% undeveloped Meramec inventory risked at 6 wells per unit High-quality Woodford optionality Asset sales: ~7 MBOED Spacing pilots: ~5 MBOED 125(1) 104(1) KEY ITEMS IMPACTING Q4 (1) Production adjusted for recent Dewey County asset sale. KEY MESSAGES Growth trajectory re-established by year end Upcoming infill projects recalibrated to optimize IRRs D&C costs expected to further decline in 2019 PRODUCTION GROWTH TO RESUME IN 2019 Retained production (MBOED)

37 Rockies An Emerging Growth Opportunity Net production increased 17% vs. Q Oil production ~75% of product mix Powder River barrels receive WTI pricing Accelerating capital activity in 2019 Expect to operate 4 rigs by early next year Represents 2x increase in activity from 2018 No permitting or infrastructure constraints Shifting Super Mario area into development ~35 Turner wells planned to spud in 2019 Multi-year Turner inventory (~200 wells) Niobrara provides significant upside potential Initial 3 wells successful (product mix: ~90% oil) >10 additional tests scheduled in 2019 Net acres: ~200,000 in oil fairway 2019 Outlook: Accelerating Activity Drilling activity by zone Niobrara Other 2019 DRILLING ACTIVITY 25 (wells) (wells) Turner RECENT POWDER RIVER BASIN ACTIVITY Super Mario Area Turner Niobrara OIL Converse FAIR WAY RU DILTS Fed 1X & 3X Avg. 30-Day IP: 1,050 BOED per well RU JFW Fed 13 3X & 4X Avg. 30-Day IP: 1,500 BOED per well Conley Draw 1X Avg. 30-Day IP: 1,300 BOED (~90% oil) SDU Tillard 1X Avg. 30-Day IP: 1,200 BOED (~90% oil) PDU WJ Ranch 22 Avg. 30-Day IP: 1,100 BOED (~90% oil) RU State Fed 2X & 4X Avg. 30-Day IP: 1,450 BOED per well SDU Tillard 2X Avg. 30-Day IP: 1,650 BOED (~90% oil)

38 Eagle Ford and Barnett Shale Q3 Results 20 Eagle Ford Wells Avg. 30-Day IP: ~3,000 BOED/Well EAGLE FORD OVERVIEW Q3 production averaged 60 MBOED (51% oil) Strong well results drive 10% growth vs. Q2 20 new wells : IP30 ~3,000 BOED (50% oil) Completion design contributes to performance Free cash flow accelerates (~$500 million in 2018e) Q4 outlook: ~60 MBOED (15 new wells online) BARNETT SHALE OVERVIEW Sale price: ~$50 million Production: ~4 MBOED Denton Wise Dewitt Divest Details 2018 Dow JV Activity FREE CASH FLOW 500 $ Q3 production averaged 105 MBOED (~30% NGLs) Dow JV and refrac activity stabilizing production NGL pricing drives margin expansion GP&T expense to decline by ~$90 million in 2019 Wise County package sold for ~$50 million (Q4 close) MILLION IN 2018e SOLD ~ 10% OIL GROWTH (VS Q2 2018)

39 Heavy Oil Overview & Outlook Q3 net production: 104,000 Boe per day Jackfish 1 maintenance impact: ~15 MBOD Jackfish 2&3 produced at nameplate capacity LOE per Boe declined 16% vs. Q Full-scale operations restored at Jackfish complex Rates reach ~110% of nameplate capacity in October Adjusted November production rates at Jackfish due to market conditions (~8 MBOD impact to Q4) Previously incorporated in Q4 oil production outlook (press release issued 10/16/18) Potential to continue curtailing barrels in December Decision based on real-time pricing WCS basis swaps protect Q4 cash flow (~$150 MM benefit) SAGD Sweet Spot 1 $ INCREASE PER BBL FOR EVERY INCREMENTAL 40 MM $ ANNUALIZED CASH FLOW Q3 PRODUCTION GROSS NET Jackfish 1 (MBOD) Jackfish 2 (MBOD) Jackfish 3 (MBOD) Lloydminster (MBOED) Total Heavy Oil (MBOED)

40 Heavy Oil Mitigating Pricing Pressures in 2019 Actively adding WCS financial swaps in 2019 (21 MBOD at ~$23 off WTI in 1H 2019) Secured firm transport to Gulf Coast (Agreements cover ~10% of production) Seeking accretive rail contracts (Targeting up to 20% of production) Directly connected to Northwest upgrader (Limits impact of future apportionments) Line 3 expansion in Q (+370 MBOD capacity) PADD 2 Houston Edmonton Jackfish Enbridge Mainline Flanagan South ~$30 off WTI in 2019 WCS Pricing Pipelines Rail Seaway Cushing ~$2 off WTI in 2019 Gulf Coast WCS Pricing All in cost: ~$20/BBL Rail Opportunities Canadian Heavy Oil Marketing Opportunities Differentials Narrowing into 2019 $/Barrel Differential (WCS vs. WTI) WCS differential to WTI Further improvements expected as industry adds incremental rail activity

41 Investor acquisitions from the Contacts SEC s and divestitures; & website Notices at Investor and any Relations of the other Contacts risks and Scott uncertainties CoodyChris identified Carr VP, in Investor our Form RelationsSupervisor, 10-K and our other filings Investor with Relations the SEC Investors are cautioned that any such investor.relations@dvn.com statements are not guarantees Forward-Looking of future performance Statements and This that presentation actual results includes or developments "forward-looking may differ statements" materially as from defined those by projected the Securities in the and forward-looking Exchange Commission statements. (the The SEC ). forward-looking Such statements include this those presentation concerning are strategic made as plans, of the expectations date of this presentation, and objectives even for future if subsequently operations, made and available are often by identified Devon on by its use website of the words otherwise. expects, Devon believes, does not will, undertake would, any obligation could, to forecasts, update the projections, forward-looking estimates, statements plans, as a result expectations, of new information, targets, future opportunities, events or otherwise. potential, Use anticipates, of Non-GAAP outlook Information and This other presentation similar terminology. may include All non-gaap statements, financial other than measures. statements Such of non-gaap historical facts, measures included are not in this alternatives presentation to GAAP that address measures, activities, and you events should or developments not consider these that non-gaap the Company measures expects, in believes isolation or or anticipates as a substitute will for may analysis occur of in our the results future as are reported forward-looking under GAAP. statements. For additional Such statements disclosure are regarding subject to such a number non-gaap of assumptions, measures, risks including and uncertainties, reconciliations many to their of which most directly are beyond comparable the control GAAP of the measure, Company. please Statements refer to regarding Devon s third-quarter our business 2018 and operations earnings release are subject at to all of the risks and uncertainties Cautionary Note normally to Investors incident The to the SEC exploration permits oil for and and gas development companies, and in their production filings with of oil the and SEC, gas. to These disclose risks only include, proved, but probable are not limited and possible to: the volatility reserves that of oil, meet gas the and SEC's NGL definitions prices; uncertainties for such terms, inherent and price in estimating and cost oil, sensitivities gas and NGL for such reserves; reserves, the extent and prohibits to which disclosure we are successful of resources in acquiring that do not and constitute discovering such Investor reserves. Notices This presentation additional reserves; may contain the uncertainties, terms, costs such as and resource risks involved potential, in oil potential and gas locations, operations; risked regulatory and unrisked restrictions, locations, compliance estimated costs ultimate and other recovery risks (EUR), relating exploration to governmental target regulation, size and other including similar with terms. respect These to estimates environmental are by matters; their nature risks more related speculative to our hedging than estimates activities; of counterparty proved, probable credit and risks; possible risks relating reserves to and our accordingly indebtedness; are cyberattack subject to substantially risks; our limited greater control risk of over being third actually parties realized. who operate The SEC our oil guidelines and gas strictly properties; prohibit midstream us from capacity including constraints these estimates and potential in filings interruptions with the SEC. in production; Investors are the urged extent to to consider which insurance closely the covers disclosure any losses in our we Form may 10-K, experience; available competition at for leases, materials, You people can also and obtain capital; this our form ability from to the successfully SEC by calling complete SEC-0330 mergers,