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): July 31, 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 July 31, 2018, Devon Energy Corporation (the Company ) issued a press release announcing its financial and operational results for the quarter ended June 30, In connection with the earnings release, the Company also provided its operations report for the second quarter of Copies of the earnings release and second 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 (d) Financial Statements and Exhibits. Exhibits Exhibit No. Description of Exhibits 99.1 Earnings release, dated July 31, Second 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: July 31, 2018 DEVON ENERGY CORPORATION By: /s/jeffreyl.ritenour Jeffrey L. Ritenour Executive Vice President and Chief Financial Officer

4 Exhibit 99.1 Devon Energy Corporation 333 West Sheridan Avenue Oklahoma City, OK NEWS RELEASE Devon Energy Reports Second-Quarter 2018 Results Highlights Delaware Basin and STACK drive U.S oil production beat Light-oil production growth on track to expand 16 percent in 2018 EnLink ownership interests monetized at 12 times cash flow Industry-leading share-repurchase program increased to $4 billion Field-level cash margins expand by 31 percent year over year Corporate cost structure to improve by $475 million annually OKLAHOMA CITY July 31, 2018 Devon Energy Corp. (NYSE: DVN) today reported operational and financial results for the second quarter of Also included within the release is the company s guidance outlook for the third quarter and full-year Devon is executing at a very high level on our 2020 Vision, said Dave Hager, president and CEO. Operationally, our second-quarter performance was headlined by strong well productivity in the Delaware Basin and STACK, which drove light-oil production above the high end of our guidance expectations. Importantly, we converted this volume growth into higher profits with our access to premium pricing in advantaged markets and through our success in driving both field-level and corporate costs lower. With the strong well productivity we ve achieved year to date in the U.S., light-oil production growth is on track to advance 16 percent in 2018, which is 200 basis points above our original budget expectations, said Hager. We expect to deliver this improved outlook without any increase to our planned activity, and this disciplined investment program positions us to generate substantial amounts of free cash flow at today s market prices. In addition to our strong operating results, we took a significant step forward in achieving our 2020 Vision by further simplifying our asset portfolio through our monetization of EnLink, said Hager. This highly accretive transaction provides a strategic exit from EnLink at a value of 12 times cash flow, and we re returning the sales proceeds to our shareholders through our industry-leading $4 billion share-repurchase program. Delaware Basin and STACK Drive U.S. Oil Production Beat Production results in the quarter were highlighted by oil growth from Devon s U.S. resource plays, which are attaining the highest margins and returns in Devon s portfolio. In the quarter, light-oil production in the U.S. averaged 136,000 barrels per day, a 12 percent increase compared to the first quarter of This result exceeded the top end of guidance by 2,000 barrels per day. The strongest asset-level performance during the second quarter was from the company s Delaware Basin assets. Light-oil production increased 54 percent year over year in the quarter, driving total volumes in the Delaware to 79,000 oil-equivalent barrels (Boe) per day. Growth in the Delaware was driven by prolific well productivity, where the top 10 wells in the quarter averaged initial 30-day rates of approximately 3,000 Boe per day. 1

5 Devon s STACK assets also delivered strong results during the quarter. Total production in the STACK advanced 26 percent compared to the second quarter of Driven by several strong wells across the play, oil production delivered the highest growth rate, increasing 41 percent year over year. In Canada, net oil production averaged 109,000 barrels per day in the second quarter. Scheduled maintenance at the company s Jackfish facility curtailed production by approximately 15,000 barrels per day. Also contributing to lower production was a 2 percentage point increase in royalty rates because of higher commodity prices and improved profitability. Overall, total companywide production averaged 541,000 Boe per day in the second quarter. Oil accounted for the largest component of the product mix at 45 percent of total volumes. For additional details on Devon s E&P operations in the quarter, please refer to the company s second-quarter 2018 operations report at Light-Oil Production Growth on Track to Increase 16 Percent in 2018 With the strong well productivity Devon has achieved year to date in the U.S., light-oil production growth is on track to advance 16 percent in This growth rate is trending at approximately 200 basis points above the company s original budget expectations. The incremental oil growth in the U.S. is expected to be delivered without an increase to Devon s capital activity. This disciplined investment program positions the company to generate free cash flow in the second half of 2018 at today s market prices. EnLink Ownership Interests Monetized at 12 Times Cash Flow In mid-july, Devon completed the sale of its ownership interests in EnLink Midstream Partners, LP (NYSE: ENLK) and EnLink Midstream, LLC (NYSE: ENLC) for $3.125 billion. The company s interests in EnLink generated $265 million of cash distributions over the past year, valuing the investment at approximately 12 times cash flow. Devon expects no incremental corporate cash taxes resulting from this sale. With the closing of the EnLink transaction, combined with other minor asset sales achieved to date, total proceeds from Devon s divestiture program have now reached $4.2 billion. The company expects to monetize an additional $1 billion of minor, non-core assets across the United States by year-end. These divestiture packages include undeveloped leasehold in the southern Delaware Basin, enhanced oil recovery projects in the Rockies and Midland Basin along with Wise County acreage in the Barnett Shale. Data rooms are open for the majority of these packages and bids are expected throughout the second half of Industry-Leading Share-Repurchase Program Increased to $4 Billion In conjunction with closing the EnLink transaction, Devon s board of directors authorized an increase in the company s share-repurchase program to $4 billion. This authorization represents the largest share-repurchase program in the upstream industry when measured as a percentage of market capitalization. At the end of July, Devon had repurchased 24 million shares, or nearly 5 percent of outstanding shares, at a total cost of approximately $1 billion. For the remaining share-repurchase authorization, the company plans to utilize a series of accelerated stock repurchase programs (ASR) that are expected to commence in early August. With these ASR programs, Devon expects to complete its $4 billion share-repurchase program during the first half of Detailed forward-looking guidance on share count is provided later in this release. 2

6 Financial Reporting Impact of EnLink Monetization With the closing of the EnLink transaction, the financial results of EnLink Midstream will no longer be consolidated with Devon s upstream business, and historical results related to EnLink will be presented as discontinued operations in the company s consolidated financial statements. To assist with this financial reporting transition, Devon has provided pro forma financial statements for its upstream business in a Form 8-K filing in July. Additionally, updated detailed forward-looking guidance for financial statement line items impacted by this transaction in 2018 is provided later in this release. Upstream Revenue Benefits from Premium Gulf Coast Pricing Devon s upstream revenue, excluding commodity derivatives, totaled $1.6 billion in the second quarter, a 15 percent improvement compared to the previous quarter. The strong growth in revenue was driven by growth in higher-margin, light-oil production coupled with improved price realizations across the company s asset portfolio. Also contributing to the improving price realizations in the quarter were Devon s firm transport and marketing agreements that provide the majority of U.S. oil production direct access to premium Gulf Coast markets. Combined with the price protection provided by regional basis swaps, second-quarter oil realizations in the U.S. averaged approximately 98 percent of the West Texas Intermediate benchmark. Importantly, the company is positioned to maintain these strong U.S. oil price realizations through the end of the decade. In Canada, Devon 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 the WTI benchmark price and have generated cash settlements of $109 million year to date. U.S. Operating Costs Improve and Field-Level Margins Expand Devon continued to effectively manage operating costs during the second quarter. Production expense, which represents field-level operating costs, totaled $572 million in the second quarter. The largest components of production expense are lease operating expense and transportation, which totaled $493 million in the quarter. Taxes also contributed $79 million to production expense during the second quarter. The company s U.S. resource plays delivered the strongest cost performance, where lease operating expense and transportation costs declined 3 percent on a per-unit basis compared to the first quarter. In Canada, production expense in the quarter was impacted by $21 million of non-recurring costs associated with maintenance work at the Jackfish complex. Overall, the benefits of higher-margin oil production, improved price realizations and a lower cost structure resulted in expanded margins for Devon. Fieldlevel cash margin reached $20.19 per Boe in the second quarter, a 31 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. 3

7 Corporate Cost Structure to Improve by $475 Million Annually Further expanding Devon s profitability is its improving general and administrative (G&A) cost structure. Upstream-related G&A expenses totaled $153 million, a 22 percent improvement compared to the first quarter. The significantly lower overhead costs were driven by reduced personnel expenses. The company has also reduced financing costs. With the early retirement of $807 million of debt early in the year, the company expects to reduce net financing costs by approximately $64 million on an annual basis. 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. Investment-Grade Financial Position Continues to Strengthen Devon s financial position remains exceptionally strong, with investment-grade credit ratings and excellent liquidity. The company exited the second quarter with $1.5 billion of cash on hand. Adjusted for the sale of EnLink Midstream in July, pro forma cash balances reached $4.6 billion and the company s consolidated debt declined by 40 percent to $6.1 billion. Second-Quarter Earnings and Cash-Flow Results The company reported a net loss attributable to Devon of $425 million or $0.83 per diluted share in the second quarter. Excluding the impact of noncontrolling interests, the company reported a net loss of $335 million. Devon s results were impacted by certain items securities analysts typically exclude from their published estimates. After excluding adjusting items, the company s core earnings totaled $177 million or $0.34 per diluted share. Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) reached $1.0 billion in the quarter. Devon s operating cash flow from continuing operations totaled $269 million in the second quarter. Operating cash flow in the quarter was impacted by several non-recurring or unusual items, including a non-cash foreign exchange loss, restructuring charges, EnLink s reclassification to discontinued operations and working capital changes. The most significant item was related to a non-cash, foreign exchange loss. This impact was driven by foreign currency denominated intercompany loan activity resulting in a realized loss of $244 million as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. For more understanding of the company s cash flow performance during the quarter please refer to the explanations and reconciliations provided later in this release. Pursuant to regulatory disclosure requirements, Devon is required to reconcile non-gaap (generally accepted accounting principles) financial measures to the related GAAP information. Reconciliations of these non-gaap measures are provided within the tables of this release. 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 second-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Aug. 1, 2018, and will serve primarily as a forum for analyst and investor questions and answers. 4

8 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. 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 June 30, Six Months Ended June 30, Oil and bitumen (MBbls/d) U. S. - Core Heavy Oil Retained assets Divested assets 3 2 Total Natural gas liquids (MBbls/d) U. S. - Core Divested assets Total Gas (MMcf/d) U. S. - Core 1,013 1,010 1,007 1,012 Heavy Oil Retained assets 1,025 1,024 1,019 1,030 Divested assets Total 1,128 1,208 1,152 1,218 Total oil equivalent (MBoe/d) U. S. - Core Heavy Oil Retained assets Divested assets Total

10 DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION PRODUCTION TREND Quarter 2 Quarter 3 Quarter 4 Quarter 1 Quarter 2 Oil and bitumen (MBbls/d) STACK Delaware Basin Rockies Oil Heavy Oil Eagle Ford Barnett Shale Other Retained assets Divested assets 3 2 Total Natural gas liquids (MBbls/d) STACK Delaware Basin Rockies Oil Eagle Ford Barnett Shale Other Retained assets Divested assets Total Gas (MMcf/d) STACK Delaware Basin Rockies Oil Heavy Oil Eagle Ford Barnett Shale Other Retained assets 1,024 1,026 1,000 1,014 1,025 Divested assets Total 1,208 1,201 1,175 1,177 1,128 Total oil equivalent (MBoe/d) STACK Delaware Basin Rockies Oil Heavy Oil Eagle Ford Barnett Shale Other Retained assets Divested assets Total

11 DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION BENCHMARK PRICES (average prices) Quarter 2 June YTD Oil ($/Bbl) - West Texas Intermediate (Cushing) $67.83 $48.32 $65.38 $50.16 Natural Gas ($/Mcf) - Henry Hub $ 2.80 $ 3.19 $ 2.90 $ 3.25 REALIZED PRICES Quarter Ended June 30, 2018 Oil /Bitumen (Per Bbl) NGL (Per Bbl) Gas (Per Mcf) Total (Per Boe) United States $ $ $ 2.01 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.01 $ Cash settlements $ (5.80) $ (1.66) $ 0.13 $ (2.68) Realized price, including cash settlements $ $ $ 2.14 $ Quarter Ended June 30, 2017 Oil /Bitumen (Per Bbl) NGL (Per Bbl) Gas (Per Mcf) Total (Per Boe) United States $ $ $ 2.50 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.50 $ Cash settlements $ 0.29 $ (0.03) $ 0.04 $ 0.22 Realized price, including cash settlements $ $ $ 2.54 $ Six Months Ended June 30, 2018 Oil /Bitumen (Per Bbl) NGL (Per Bbl) Gas (Per Mcf) Total (Per Boe) United States $ $ $ 2.21 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.21 $ Cash settlements $ (2.93) $ (1.13) $ 0.16 $ (1.23) Realized price, including cash settlements $ $ $ 2.37 $ Six Months Ended June 30, 2017 Oil /Bitumen (Per Bbl) NGL (Per Bbl) Gas (Per Mcf) Total (Per Boe) United States $ $ $ 2.59 $ Canada $ N/M N/M $ Realized price without hedges $ $ $ 2.59 $ Cash settlements $ 0.39 $ (0.02) $ $ 0.19 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 June 30, Six Months Ended June 30, Upstream revenues $1,069 $1,332 $2,388 $2,873 Marketing revenues 1, ,059 1,692 Total revenues 2,249 2,165 4,447 4,565 Production expenses , Exploration expenses Marketing expenses 1, ,033 1,728 Depreciation, depletion and amortization Asset impairments Asset dispositions 23 (22) 11 (30) General and administrative expenses Financing costs, net Restructuring and transaction costs Other expenses 24 (8) 45 (22) Total expenses 2,730 1,958 5,173 4,045 Earnings (loss) from continuing operations before income taxes (481) 207 (726) 520 Income tax benefit (7) (5) (41) Net earnings (loss) from continuing operations (474) 212 (685) 520 Net earnings from discontinued operations, net of income tax expense Net earnings (loss) (335) 245 (488) 562 Net earnings attributable to noncontrolling interests Net earnings (loss) attributable to Devon $ (425) $ 219 $ (622) $ 522 Basic net earnings (loss) per share: Basic earnings (loss) from continuing operations per share $ (0.92) $ 0.40 $ (1.33) $ 0.99 Basic earnings from discontinued operations per share Basic net earnings (loss) per share $ (0.83) $ 0.41 $ (1.20) $ 0.99 Diluted net earnings (loss) per share: Diluted earnings (loss) from continuing operations per share $ (0.92) $ 0.40 $ (1.33) $ 0.99 Diluted earnings from discontinued operations per share Diluted net earnings (loss) per share $ (0.83) $ 0.41 $ (1.20) $ 0.99 Weighted average common shares outstanding: Basic Diluted UPSTREAM REVENUES (in millions) Quarter Ended June 30, Six Months Ended June 30, Oil, gas and NGL sales $1,566 $1,206 $2,926 $2,515 Derivative cash settlements (131) 11 (120) 19 Derivative valuation changes (366) 115 (418) 339 Upstream revenues $1,069 $1,332 $2,388 $2,873 PRODUCTION EXPENSES (in millions) Quarter Ended June 30, Six Months Ended June 30, Lease operating expense $269 $ 239 $ 510 $ 462 Gathering, processing & transportation Production taxes Property taxes Production expense $572 $ 455 $ 1,115 $ 912 9

13 CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION Quarter Ended June 30, Six Months Ended June 30, Cash flows from operating activities: Net earnings (loss) $ (335) $ 245 $ (488) $ 562 Adjustments to reconcile net earnings to net cash from operating activities: Earnings from discontinued operations, net of tax (139) (33) (197) (42) Depreciation, depletion and amortization Asset impairments Leasehold impairments Accretion on discounted liabilities Total (gains) losses on commodity derivatives 497 (126) 538 (358) Cash settlements on commodity derivatives (131) 11 (120) 19 (Gains) and losses on asset dispositions 23 (22) 11 (30) Deferred income tax expense (benefit) 20 (17) (18) (32) Share-based compensation Early retirement of debt 312 Total (gains) losses on foreign exchange 31 (49) 81 (64) Settlements of intercompany foreign denominated assets/liabilities (244) 1 (243) 10 Other (20) 23 (50) 11 Changes in assets and liabilities, net (133) 102 (108) 133 Net cash from operating activities - continuing operations ,155 Cash flows from investing activities: Capital expenditures (602) (434) (1,253) (831) Acquisitions of property and equipment (10) (13) (16) (33) Divestitures of property and equipment Net cash from investing activities - continuing operations (52) (372) (662) (757) Cash flows from financing activities: Repayments of long-term debt principal (807) Early retirement of debt (304) Repurchases of common stock (428) (499) Dividends paid on common stock (42) (33) (74) (65) Shares exchanged for tax withholdings (6) (3) (44) (56) Net cash from financing activities - continuing operations (476) (36) (1,728) (121) Effect of exchange rate changes on cash: Settlements of intercompany foreign denominated assets/liabilities 244 (1) 243 (10) Other (17) 9 (31) 10 Total effect of exchange rate changes on cash continuing operations Net change in cash, cash equivalents and restricted cash of continuing operations (32) 186 (1,299) 277 Cash flows from discontinued operations: Operating activities Investing activities (222) (215) (402) (284) Financing activities Net change in cash, cash equivalents and restricted cash of discontinued operations Net change in cash, cash equivalents and restricted cash (1,159) 410 Cash, cash equivalents and restricted cash at beginning of period 1,470 2,119 2,684 1,959 Cash, cash equivalents and restricted cash at end of period $1,525 $2,369 $ 1,525 $2,369 Reconciliation of cash, cash equivalents and restricted cash: Cash and cash equivalents $1,460 $2,358 $ 1,460 $2,358 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 $1,525 $2,369 $ 1,525 $2,369 10

14 DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION CONSOLIDATED BALANCE SHEETS (in millions) June 30, December 31, Current assets: Cash and cash equivalents $ 1,460 $ 2,642 Accounts receivable 1, Current assets held for sale 10, Other current assets Total current assets 13,820 4,791 Oil and gas property and equipment, based on successful efforts accounting, net 12,957 13,318 Other property and equipment, net 1,164 1,266 Total property and equipment, net 14,121 14,584 Goodwill Other long-term assets Long-term assets held for sale 9,729 Total assets $29,159 $ 30,241 Current liabilities: Accounts payable $ 771 $ 633 Revenues and royalties payable Short-term debt Current liabilities held for sale 5, Other current liabilities 1, Total current liabilities 8,377 3,315 Long-term debt 5,790 6,749 Asset retirement obligations 1,088 1,099 Other long-term liabilities Long-term liabilities held for sale 3,936 Deferred income taxes Equity: Common stock Additional paid-in capital 6,888 7,333 Retained earnings Accumulated other comprehensive earnings 1,091 1,166 Treasury stock, at cost, 0.5 million shares in 2018 (22) Total stockholders equity attributable to Devon 8,014 9,254 Noncontrolling interests 4,834 4,850 Total equity 12,848 14,104 Total liabilities and equity $29,159 $ 30,241 Common shares outstanding CAPITAL EXPENDITURES (in millions) Quarter Ended June 30, 2018 Six Months Ended June 30, 2018 Upstream capital $ 607 $ 1,271 Land and other acquisitions Exploration and production (E&P) capital 619 1,289 Capitalized interest Other 9 22 Devon capital expenditures $ 645 $ 1,346 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 second-quarter 2018 earnings. Quarter Ended June 30, 2018 After Noncontrolling Interests Per Diluted Share (in millions, except per share amounts) Before-tax After-tax Continuing Operations Loss attributable to Devon (GAAP) $ (481) $ (474) $ (474) $ (0.92) Adjustments: Asset dispositions Asset and exploration impairments Deferred tax asset valuation allowance Fair value changes in financial instruments and foreign currency Restructuring and transaction costs Core earnings attributable to Devon (Non-GAAP) $ 219 $ 139 $ 139 $ 0.26 Discontinued Operations Earnings attributable to Devon (GAAP) $ 149 $ 139 $ 49 $ 0.09 Adjustments: Fair value changes and minimum volume commitment settlement (36) (30) (11) (0.01) Core earnings attributable to Devon (Non-GAAP) $ 113 $ 109 $ 38 $ 0.08 Total Loss attributable to Devon (GAAP) $ (332) $ (335) $ (425) $ (0.83) Adjustments: Continuing Operations Discontinued Operations (36) (30) (11) (0.01) Core earnings attributable to Devon (Non-GAAP) $ 332 $ 248 $ 177 $ 0.34 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. June 30, (in millions) 2018 Total debt (GAAP) (1) $ 6,067 Less cash and cash equivalents (1,460) Net debt (Non-GAAP) $ 4,607 (1) Excludes EnLink since its debt-related amounts are included in liabilities held for sale. 12

16 ADJUSTED EBITDA DEVON ENERGY CORPORATION FINANCIAL AND OPERATIONAL INFORMATION We define Adjusted EBITDA, a non-gaap financial measure, as EBITDA adjusted for certain items presented in the accompanying reconciliation. We believe that EBITDA is widely used by investors to measure a company s performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. In addition, Adjusted EBITDA generally excludes certain other items that management believes affect the comparability of operating results or are not related to Devon s ongoing operations. Management uses Adjusted EBITDA to evaluate the company s operational trends and performance relative to other oil and gas companies. ADJUSTED EBITDA (in millions) Quarter Ended June 30, 2018 Continuing Discontinued Operations Operations Total Net earnings (loss) $ (474) $ 139 $ (335) Financing costs, net Income tax expense (benefit) (7) 10 3 Depreciation, depletion and amortization Accretion of discounted liabilities EBITDA $ 16 $ 300 $ 316 Non-cash stock compensation Asset and leasehold impairments Asset disposition losses Restructuring and transaction costs Derivative and financial instrument valuation changes EnLink minimum volume commitment settlement (48) (48) Adjusted EBITDA $ 748 $ 274 $1,022 PRO FORMA CASH & CASH EQUIVALENTS Devon defines pro forma cash and cash equivalents as cash and cash equivalents plus proceeds from the recently closed EnLink Midstream sale. Devon believes adjusting for this item provides a clearer picture of Devon s financial position. June 30, (in millions) 2018 Cash and cash equivalents (GAAP) $ 1,460 Proceeds from EnLink Midstream monetization that closed in mid-july 3,125 Pro forma cash and cash equivalents (Non-GAAP) $ 4,585 13

17 DEVON ENERGY CORPORATION FORWARD LOOKING GUIDANCE PRODUCTION GUIDANCE Quarter 3 Full Year Low High Low High Oil and bitumen (MBbls/d) U.S. retained assets Heavy Oil Total retained assets Natural gas liquids (MBbls/d) Total retained assets Gas (MMcf/d) U.S. retained assets 1,010 1,060 1,000 1,050 Heavy Oil Total retained assets 1,021 1,073 1,011 1,063 Total oil equivalent (MBoe/d) U.S. retained assets Heavy Oil Total retained assets PRICE REALIZATIONS GUIDANCE Quarter 3 Full Year Low High Low High Oil and bitumen - % of WTI U.S. (1) 88% (1) 93% (1) 92% (1) 97% (1) Canada (1) 40% (1) 50% (1) 37% (1) 42% (1) NGL - realized price $23 $ 28 $22 $ 27 Natural gas - % of Henry Hub 70% 80% 70% 80% (1) Does not include benefits from basis swaps and firm transportation agreements. OTHER GUIDANCE ITEMS Quarter 3 Full Year ($ millions, except Boe and %) Low High Low High Marketing & midstream operating profit $ 5 $ 15 $ 40 $ 50 LOE & GP&T per BOE $9.50 $9.75 $ 9.40 $ 9.90 Production & Property Tax (% of upstream sales) 5.20% 5.40% 5.20% 5.40% Exploration expenses $ 20 $ 30 $ 90 $ 100 Depreciation, depletion and amortization $ 420 $ 470 $1,700 $1,800 General & administrative expenses $ 150 $ 170 $ 650 $ 700 Financing costs, net (2) $ 70(2) $ 80(2) $ 285(2) $ 295(2) Other expenses $ 15 $ 20 $ 60 $ 80 Current income tax rate 0% 5% 0% 5% Deferred income tax rate 20% 25% 20% 25% Total income tax rate 20% 30% 20% 30% Average basic share count outstanding (MM) (2) On a go-forward basis interest expense that had been historically capitalized will now be included in financing costs, net. CAPITAL EXPENDITURES GUIDANCE Quarter 3 Full Year (in millions) Low High Low High Upstream capital $550 $600 $2,200 $2,400 Capitalized interest and other (2) Total $570 $630 $2,300 $2,550 14

18 DEVON ENERGY CORPORATION FORWARD LOOKING GUIDANCE Oil Commodity Hedges Price Swaps Price Collars Weighted Weighted Average Price Average Floor Weighted Average Ceiling Price ($/Bbl) Period Volume (Bbls/d) ($/Bbl) Volume (Bbls/d) Price ($/Bbl) Q3-Q ,300 $ ,700 $ $ Q1-Q ,225 $ ,875 $ $ 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) Q3-Q Midland Sweet 23,000 $ (1.02) $ $ Q3-Q Argus LLS 12,000 $ 3.95 $ $ Q3-Q Argus MEH 15,832 $ 2.82 $ $ Q3-Q NYMEX Roll 21,315 $ 0.63 $ $ Q3-Q Western Canadian Select 78,000 $ (14.91) 2,000 $ (15.50) $ (13.93) Q1-Q Midland Sweet 28,000 $ (0.46) $ $ Q1-Q Argus LLS 1,000 $ 4.60 $ $ Q1-Q Argus MEH 16,000 $ 2.84 $ $ Q1-Q NYMEX Roll 24,000 $ 0.51 $ $ Q1-Q NYMEX Roll 24,000 $ 0.31 $ $ Natural Gas Commodity Hedges - Henry Hub Price Swaps Price Collars Weighted Weighted Average Price Volume Average Floor ($/MMBtu) (MMBtu/d) Price ($/MMBtu) Weighted Average Ceiling Price ($/MMBtu) Period Volume (MMBtu/d) Q3-Q ,750 $ ,500 $ 2.76 $ 3.09 Q1-Q ,000 $ ,750 $ 2.64 $ 3.03 Natural Gas Basis Swaps Weighted Average Differential to Period Index Volume (MMBtu/d) Henry Hub ($/MMBtu) Q3-Q Panhandle Eastern Pipe Line 120,000 $ (0.51) Q3-Q El Paso Natural Gas 100,000 $ (1.25) Q3-Q Houston Ship Channel 115,000 $ 0.01 Q3-Q Transco Zone 4 15,000 $ (0.03) Q1-Q Panhandle Eastern Pipe Line 62,500 $ (0.77) Q1-Q El Paso Natural Gas 120,000 $ (1.48) Q1-Q Houston Ship Channel 100,000 $ (0.01) Q1-Q Transco Zone 4 7,500 $ (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 July 27,

19 Q Operations Report Key Messages 2 Modeling Stats 3 Q2 Results 4 Outlook 6 Delaware Basin 12 STACK17 Eagle Ford 21 Rockies 22 Barnett Shale 23 Heavy Oil 24 NYSE: DVN devonenergy.com Exhibit 99.2

20 Q2 light-oil production exceeds high end of guidance Driven by strong well productivity in Delaware and STACK U.S. light-oil growth running ahead of original budget YTD No change to full-year capital spending budget Free cash flow positioned to rapidly expand Majority of U.S. oil has access to premium Gulf Coast pricing G&A and interest savings to reach ~$475 MM annually(1) Per-unit LOE on track to improve by ~10% by 1H 2019 Divestiture program accelerates value creation Ownership in EnLink Midstream monetized for 12x cash flow Expect to exceed $5 billion divestiture target around year end (pg. 10) Shareholder-friendly initiatives underway Recently increased share-repurchase program to $4 billion Consolidated debt has declined by ~40% YTD(1) Executing the 2020 Vision Focus on capital efficiency Portfolio simplification Improve financial strength Return cash to shareholders Maximize cash flow DEVON S 2020 VISION (1) Includes the pro forma benefits related to the sale of EnLink Midstream in mid-july.

21 KEY divestiture. METRICS General Q2 & ACTUALS(1) administrative Q2 expense GUIDANCE guidance U.S. range oil was (MBbls/d) adjusted 136 by 129 $30 - million 134 Canada to exclude oil (MBbls/d) EnLink Midstream Net NGLs financing (MBbls/d) costs guidance range 100 Gas was (MMcf/d) adjusted by 1,025 $45 million 1,001 to 1,053 exclude Total EnLink retained Midstream. (MBoe/d) On 520 a go-forward Production basis, interest expenses ($MM) that had $572 been $530 historically - $580 General capitalized & administrative will now be included expenses in ($MM) financing $153 costs, $150 net. - $170(2) Includes Financing benefits of costs, regional net ($MM) basis swaps $62 $60 and - firm $70(3) transport Upstream in the capital Delaware ($MM) totaling $607 $15 $550 million. - $650 Includes Q higher - ASSET cost DETAIL enhanced DELAWARE oil recovery properties STACK ROCKIES that are currently EAGLE being FORD marketed. BARNETT(1) Includes HEAVY benefits OIL of regional PRODUCTION basis swaps Oil in (MBbl/d) Canada totaling $12 28 million. 1(1) 109 NGL (MBbl/d) (1) - Gas (MMcf/d) (1) 12 Total (MBoe/d) (1) 111 ASSET MARGIN (per Boe) Realized price $45.05(5) $29.77 $55.46 $47.03 $16.05 $32.38(7) Lease operating expenses ($5.48) ($2.62) ($10.29)(6) ($2.41) ($2.45) ($11.38) Gathering, processing & transportation ($1.95) ($4.73) ($1.23) ($5.22) ($7.39) ($4.35) Production & property taxes ($3.50) ($0.88) ($6.79) ($2.45) ($0.58) ($0.75) Cash margin $34.12 $21.54 $37.15 $36.95 $5.63 $15.90 CAPITAL ACTIVTY (Q2 avg.) Upstream capital ($MM) $178 $252 $35 $58 $19 $40 Operated development rigs Operated frac crews Operated spuds Operated wells tied-in Average lateral length 9,600 6,700 9,000 5,200 UPDATED GUIDANCE Q3 2018e FY 2018e U.S. oil (MBbls/d) Canada oil (MBbls/d) NGLs (MBbls/d) Gas (MMcf/d) 1,021 1,073 1,011-1,063 Total retained (MBoe/d) Lease operating expense & GP&T (per BOE) $ $9.75 $ $9.90 Production taxes (% of upstream sales) 5.2% - 5.4% 5.2% - 5.4% General & administrative expenses ($MM) $150 - $170 $650 - $700 Financing costs, net ($MM)(4) $70 - $80(4) $285 - $295(4) Upstream capital ($MM) $550 - $600 $2,200 - $2,400 Capitalized interest & other capital ($MM)(4) $20 - $30(4) $100 - $150(4) Avg. basic share count outstanding (MM) Key Modeling Stats Production results exclude Johnson County

22 Q Results U.S. Oil Growth Accelerates U.S. oil production exceeds guidance 2,000 barrels per day above top end of range 12% increase in oil production vs. Q Delaware & STACK continue to deliver strong growth Delaware oil production 54% higher year over year STACK oil volumes increase 41% vs. Q Multi-zone developments building momentum Prolific wells brought online drive Q2 oil beat 4-well Cotton Draw package IP30: 14 MBOED (pg. 12) Top 10 STACK wells avg. IP30 2,400 BOED per well Capital spending reduced 9% vs. Q Driven by reduced seasonal drilling in Canada and timing of Eagle Ford activity IP30: 14,000 BOED (70% oil) (Total rate from 4-well package in Cotton Draw area) Top Delaware Well Results Top 10 STACK Well Results HIGH-RATE WELLS DRIVE Q2 OIL BEAT Avg. IP30: 2,400 BOED (~50% oil) (Top well: Porcupine 1H w/ IP30 of 3,700 BOED) High-returning U.S. oil production exceeds guidance MBOD 136 (Q2 Guide: ) 2,000 ABOVE GUIDANCE U.S. OIL PRODUCTION 122 BARRELS PER DAY

23 Q Results - Margins Continue to Expand Production shifting to higher-value product mix Light-oil production is highest growth product Liquids reach 67% of retained asset volumes Majority of light-oil production has access to premium Gulf Coast pricing Q U.S. oil realizations: 98% of WTI(1) Field-level cash flow expands in U.S. resource plays 53% higher compared to Q Per-unit LOE improves ~3% vs. last quarter Corporate cost structure continues to significantly improve G&A and interest declines 21% vs. Q With declining corporate costs Upstream G&A & interest ($MM) Resulting in margin expansion U.S. field-level operating margin (retained assets) Strong oil realizations across U.S. U.S. oil realizations as % of WTI 53% OPERATING MARGIN YEAR OVER YEAR DECLINE 21% INCREASE (2) Q U.S. field-level operating margin for retained assets was $830 million. (1) Includes benefits of basis swaps & firm transport 98% of WTI(1) BASIS SWAPS & FIRM TRANSPORT FIELD-LEVEL REALIZATIONS

24 2018 Outlook U.S. oil production growth exceeding budget YTD On track to deliver 16% growth vs ~200 basis points above original budget expectations Q3 volumes impacted by timing of completions Canada production to increase to ~120 MBOED in Q3 Jackfish 1 turnaround extends into Q3 (pg. 24) Cost structure to improve throughout the year G&A/interest savings to reach ~$475 MM annually(1) Per-unit LOE to improve by ~10% by 1H 2019 No change to 2018 capital spending outlook Capital trending toward around top end of guidance Positioned to generate free cash flow in 2H 2018 U.S. oil growth exceeding expectations YTD U.S. oil production growth rates (retained assets) Basis Points +200 ~$475 MILLION Significantly improving corporate cost structure G&A and interest(1)(2)(3) ($MM) (1) Includes the pro forma benefits related to the sale of EnLink Midstream in mid-july (2) Includes EnLink Midstream G&A and interest for 2017 and 1H of 2018 (3) Includes capitalized interest for each period

25 Supply Chain Strategy Effectively Mitigating Inflation Devon expects low-to-mid single-digit inflation (vs. 2017) No change to 2018 capital spending outlook Minimal inflation expected in 2H 2018 Development efficiencies offsetting cost pressures YTD Multi-year development plans allow for longer-term commitments at below-market rates Decoupling historically bundled services across supply chain Expanded vendor universe to achieve LOE and capital savings Vast majority of services and supplies secured through 2019 Innovative contracting strategy is delivering strong results 75% of rigs price protected at below market rates Long-term dedicated frac crews in Delaware & STACK at significant discounts to market rates Regional sand strategy delivering 30% savings SERVICES & SUPPLIES SECURED SERVICES & SUPPLIES SECURED

26 Protecting Price & Flow Assurance Majority of U.S. oil production has access to Gulf Coast markets (premium to WTI pricing) Delaware Basin positioned for attractive oil pricing (pg. 13) Basis swaps & firm transport protect ~90% of oil volumes Firm transport secured for 2019 gas growth expectations Basis swaps protect gas production STACK volumes have access to advantaged markets (pg. 18) Pipeline access to premium Gulf Coast oil pricing Firm transport covers vast majority of gas production ~60% of gas volumes price protected (~$0.50 off HH) Basis hedges protecting cash flow in Canada WCS swaps protect ~50% of oil volumes in 2018 ($15 off WTI) Gulf Coast Access to Premium Gulf Coast Markets Firm transport: 30 MBOD (Marketlink) Gas protected by swaps & firm transport STACK Delaware Basin Firm transport: ~20 MBOD (Longhorn) Firm sales: 100 MBOD (guaranteed flow) Basis swaps protect in-basin sales

27 EnLink Sale Drives $4 Billion Share-Buyback Program SALES PRICE: $3.125 Billion ACCRETIVE MULTIPLE: 12x Cash Flow ENLC ENLK 115 MM Units 95 MM Units TRANSACTION DETAILS Devon exits EnLink position for $3.125 billion Accretive transaction at 12x cash flow No tax leakage associated with sale Transaction closed in mid-july Board increases share-buyback program to $4 billion Largest authorization of any E&P company to date(1) ~$1 billion repurchased through July (24 million shares) Utilizing ASR programs to execute authorization(2) Initial ASR program to begin in August $4 billion authorization to be completed by 1H 2019 Financial reporting benefits of EnLink sale Reduces consolidated debt by $3.9 billion G&A and interest savings of ~$300 million annually Measured as a % of market capitalization ASR is an acronym for accelerated share repurchase $4 Billion Share-Repurchase Program Underway $1 BILLION Repurchased To Date Repurchased to date (~$1 billion or ~5% of shares) Remaining program $3 BILLION REMAINING

28 Resource quality & depth allows for high-grading of portfolio Announced $4.2 billion of divestitures to date Closed EnLink transaction in July ($3.125 billion) Upstream asset sales: $1.1 billion No incremental cash taxes from transactions Marketing additional ~$1 billion of assets Southern Delaware Mi Vida acreage (~9k acres) Barnett Shale: Western Wise County (~100k acres) Minor legacy oil assets across U.S. (~10 MBOD)(1) Expect to exceed $5 billion divestiture target by around year end Continuously evaluating options to high-grade portfolio Asset Divestiture Update Ward Reeves Key Stats Non-Operated Acreage Operated Acreage Production: ~3 MBOED Net acres: ~9,000 Bids due: Q Mi Vida Acreage SOUTHERN DELAWARE MI VIDA ASSET PACKAGE (1) Minor legacy oil assets include: Rockies and Midland CO2 assets and various Central Basin Platform properties. Note: Not shown on map are ~6k net acres for sale across the S. Delaware Divest Acreage BARNETT SHALE ASSET PACKAGE Key Stats Net acres: ~100k Data rooms: Open Production: ~5 MBOED Bids due: Q Denton Wise Jack

29 2020 Vision: Next Steps Expand per-unit margins Maintain capital discipline Portfolio simplification Shareholder-friendly initiatives NEXT STEPS TO FURTHER OPTIMIZE RETURNS & CAPITAL-EFFICIENCY FOR SHAREHOLDERS Maintain strong pricing through basis swaps & firm transport Maintain discipline: no change to multi-year development plans Expect to exceed $5 billion divestiture target by around year end Retire ~$280 million of maturing debt by early next year Positioned to sustainably grow quarterly dividend rate Currently marketing ~$1 billion of non-core assets across the U.S. Execute on light-oil growth plans (mid-teens CAGR through 2020) Concentrate activity in economic core of Delaware & STACK Improve per-unit cash costs by ~10% by 1H 2019(1) Complete $4 billion share-repurchase program by 1H 2019 Generate free cash flow in 2H 2018(2) Continuously evaluating options to high-grade portfolio (1) Cash costs include LOE, G&A and interest expense. (2) Assumes $65 WTI & $2.75 Henry Hub pricing

30 Delaware Basin Q Results Production increased 42% year over year Driven by focused activity in economic core of play Oil volumes achieve highest growth (54% vs. Q2 17) Prolific Bone Spring well results achieved in Q2 Top 10 new wells: avg. IP30 ~3,000 BOED (75% oil) Record results in Cotton Draw area (see graphic) Multi-zone development success continues Boomslang online (Last 3 wells avg: IP30 of 2,400 BOED) Lusitano Wolfcamp wells now flowing back Seawolf expected to be online by the end of Q3 Field-level cash flow expands 119% year over year Per-unit costs improve 15% vs. Q $66 million of free cash flow generated in Q2 42% GROWTH YEAR OVER YEAR High-returning production growth MBOED Record Well Results (Cotton Draw acreage) Generating Free Cash Flow Asset level cash flow (in $MM) Q Revenue $322(1) Production Expenses $78 Cash Margin $244 Capital Expenditures $178 Free Cash Flow $66 (1) Includes benefits of regional basis swaps and firm transport. Cotton Draw Unit H (4-well package) IP30: ~14 MBOED (70% oil) (Note: IP30 represents cumulative rate of the 4 wells)

31 Delaware Infrastructure Supports Profitable Growth Positioned for flow assurance and premium pricing Q2 oil realizations: 97% of WTI(1) Swaps & firm transport protect ~90% of oil volumes Firm oil sales contracts guarantee in basin flow assurance (100 MBOD of contractual capacity in basin) Firm transport secured for 2019 gas growth expectations Historic infrastructure investment drives sustainable cost savings Operating costs improved by >50% vs. peak rates Nearly all oil and produced water on pipe (avoids trucking) 80% of water used in operations is recycled Operate ~50 disposal wells and 8 water reuse facilities Bottom line impact: per-unit margins expanded by >60% year over year Note: costs are pro forma for revenue recognition accounting rules recently implemented. >50% IMPROVEMENT 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 Improved infrastructure driving lower costs LOE & Transportation Expense ($/BOE) FLOW ASSURANCE PLAN Positioned for flow assurance & premium pricing Includes benefits of basis swaps and firm transport to Gulf Coast Long-term guaranteed contractual capacity with firm transport partners PROTECTING PRICE ~90% PRICE PROTECTED BASIS SWAPS FIELD-LEVEL PRICING LONGHORN (FIRM TRANSPORT)

32 DEVELOPMENT STRATEGY BUILDING MOMENTUM Delaware Development Projects Advancing on Plan Boomslang project reaches peak rates (Avg. IP30 across 11 wells: ~1,650 BOED) Wolfcamp development program builds momentum in 2H 2018 (see pg. 15) Q2-2018a Q3-2018e Q4-2018e Q1-2019e Completion Production Completion Production Completion Fighting Okra (9 well pattern across 3 intervals in the Wolfcamp) Production Seawolf (12 well pattern across 4 Wolfcamp intervals) Lusitano (6 well pattern across multiple intervals in the Leonard, Bone Spring and Wolfcamp) Completion Medusa (12 well pattern across 3 intervals in the Leonard Shale and Bone Spring) Production Snapping (5 well pattern across 2 intervals in the Leonard) Drilling Completion North Thistle 34 (6 well pattern across 1 interval in the Leonard) Drilling Completion Drilling Drilling Drilling DELAWARE BASIN DEVELOPMENT ACTIVITY Developments online Projects underway Seawolf Completing Fighting Okra Completing Van Doo Dah Potato Basin Tomb Raider Cobra Flagler Lusitano Completing Boomslang (11 wells) Avg. IP30: ~1,650 BOED Medusa Completing North Thistle spud Future projects Snapping 2018 spud

33 Delaware Wolfcamp Program Building Momentum Seawolf project to deliver 1st production in Q3 Developing Wolfcamp sweet spot in Lea County 12 wells across multiple Wolfcamp landing zones Average working interest: 50% Peak project rates expected by Q Drilling operations completed at Fighting Okra Project developing 9 Wolfcamp wells Parent well achieved IP30 of 3,000 BOED Initial Wolfcamp wells at Lusitano project online Appraising Wolfcamp potential in Cotton Draw area RATTLESNAKE DEVELOPMENT ACTIVITY Rattlesnake Fighting Okra Drilling completed Peak rates: 1H 2019 New Mexico Texas Lea Current Project Lease Acreage Seawolf Completing Peak rates: Q LEONARD B C BONE SPRING 2nd 3rd WOLFCAMP XY A UPPER Located in Cotton Draw area (see map pg. 14) 6-well appraisal project testing multiple intervals WOLFCAMP WELLS FLOWING BACK AT LUSITANO PROJECT INITIAL WOLFCAMP WELLS NOW ONLINE (PEAK RATES IN Q3)

34 Delaware Basin Outlook 2018 capital & production plan on track Q3 volumes impacted by timing of completions Multi-zone projects to accelerate production growth in Q Mitigating inflation: no change to $725 MM capital budget Franchise asset provides multi-decade oil growth opportunity ~300k net surface acres (>1.3 million net effective acres) SIGNIFICANT RESOURCE OPPORTUNITY Net surface acreage ~300,000 (90% in SE New Mexico) Stacked-pay opportunity >15 landing zones Net effective acres >1.3 million Risked inventory >6,500 locations 2018 Capital Program Remains on Track Leonard Bone Spring Wolfcamp $725 MM 2018 E&P CAPITAL Delivering Prolific Growth (MBOED) ~50% EXIT RATE GROWTH 73-78

35 STACK Q Results Production increases 26% year over year Driven by oil volumes (up 41% vs. Q2 2017) Showboat project a key contributor to growth Liquids volumes account for ~80% of revenue STACK play continues to deliver high-rate wells Top 10 new wells in Q2: avg. IP30 2,400 BOED Highlighted by Porcupine 1HX (IP30: 3,700 BOED) Four infill development projects to achieve first production by year-end 2018 Coyote wells attain average IP30 of 4,400 BOED Showboat achieves peak 30-day rates (pg. 19) Horsefly & Bernhardt online in August High-returning production growth (MBOED) % GROWTH YEAR OVER YEAR KEY Q STACK WELL RESULTS WELL NAME 30-DAY IP (BOED) % LIQUID Porcupine 1HX 3,700 70% Ladybug 27-1HX 3,200 50% Mosasaurus 16-12H 2,800 81% C-Farm 23-1H 2,600 76% C-Farm 23-2H 2,400 71% Willow 12-1HX 2,200 62%

36 STACK Access to Premium Markets Expands Margins (1) Includes benefits of Marketlink firm transport to Gulf Coast Oil production has access to premium gulf coast pricing Marketlink firm transport (30 MBOD): covers ~75% of oil In-basin sales have cost-effective access to Cushing Strong oil realizations: 99% of WTI(1) in Q Firm transport and basis swaps protect gas prices ~60% of gas volumes price protected (~$0.50 off HH) Firm transport agreements to diversified sales points guarantees flow assurance Anchor customer on Midship pipeline (in service in 2019) Local infrastructure in place to support growth plans Oil gathering buildout reducing trucking requirements Per-unit costs to trend lower through end of decade Bottom line impact: Per-unit margins expand 30% year over year Access to Premium Gulf Coast Markets Firm transport on Marketlink to Gulf Coast: 30 MBOD STACK Cushing $16.58 $21.54 Driving higher margins ($ per BOE) Advantaged pricing (% STACK oil volumes) 75% GULF COAST 25% CUSHING

37 STACK Infill Development Strategy Next 3 projects designed to inform future infill decisions Testing 8, 10 & 12 Meramec wells per drilling unit All wells now online at Showboat (12 wells per drilling unit) Average 30-day rates: ~1,800 BOED(1) (56% oil) Undeveloped upper Meramec zones delivered best results Early flow rates indicate higher declines than parent well Expect 1st production at Horsefly and Bernhardt in August Peak project flow rates expected by end of Q3 Horsefly D&C costs improved to ~$7.5 million per well Additional cost savings expected at Bernhardt project Leveraging learnings to optimize future developments Initial data suggests Showboat infill spacing not optimized Continue to deliver cost efficiencies (>20% savings vs. legacy wells) Upside initiatives: working to mitigate parent well impact Devon Acreage Current Projects Current Projects to Inform Future Infill Decisions MERAMEC RESOURCE Over-pressured oil acreage 130,000 net surface acres Stacked-pay opportunity 5 Meramec landing zones Risked inventory 6 wells per surface section Infill spacing tests 8 to 12 wells per surface section (1) Normalized for 10,000 laterals at a 1.75 multiplier. Horsefly 10 wells per drilling unit Completing Showboat 12 wells per drilling unit Avg. 30-Day IP: 1,800 BOED(1) Bernhardt 8 wells per drilling unit Completing OVER- PRESSURED OIL WINDOW BLACK OIL WINDOW

38 STACK Centralized Facilities to Drive Returns Higher Centralized facilities designed to support future regional development projects (see map) Central tank battery connected to gathering systems Designed to support multiple development projects Project IRRs to benefit from less capital intensity Improves avg. project economics by up to 20% Future projects benefit from less infrastructure capital Expect significant operating synergies over the development life cycle Oil and water connected to gathering systems (avoids trucking, driving per-unit costs lower) Less labor requirements in the field drives lower LOE Centralized facilities to have less maintenance & downtime SHARED INFRASTRUCTURE PROVIDES STRATEGIC COST ADVANTAGE Showboat 12 wells per unit Flowing back North Star Central Tank Battery Cascade Privott Chisolm Scott Flowlines to tank battery Development projects Existing Devon lease acreage Oil Gathering Water Gathering

39 MILLION Eagle Ford Q2 Results 8 Lower Eagle Ford Avg. 30-Day IP: 3,100 BOED Q2 Results 15 Lower Eagle Ford Avg. 30-Day IP: 3,300 BOED EAGLE FORD OVERVIEW 25% Oil Prolific well results drive strong Q2 oil growth Net production 31% higher vs. Q wells average IP30 of ~3,200 BOED (60% oil) High-rates driven by improved completion design Margins benefit from premium LLS oil pricing Q2 oil realizations 103% of WTI (gas 104% of HH) Per-unit LOE declines 20% from prior quarter Expect stable production in 2H wells tied-in per quarter Austin Chalk delineation work underway (vs. Q1 2018) Premium Oil Pricing (103% of WTI) Growth Production Profile to Stabilize MBOED (in $MM) 2018e Revenue $850 Production Expenses $200 Cash Margin $650 Capital Expenditures $250 Free Cash Flow $400 31% GROWTH QUARTER OVER QUARTER $ 400 Significant Free Cash Flow Generation (1) Assumes $65 WTI & $2.75 Henry Hub for 2H e FREE CASH FLOW(1)

40 Rockies Parkman Turner Niobrara 2018 ACTIVITY ~20 WELLS Growth plans on track MBOD Teapot Powder River Basin activity Activity by zone Oil production increased 22% vs. Q Two Turner wells brought online in Q2 (8k laterals) Avg. IP30: 1,450 BOED (75% oil) Powder River barrels receive WTI pricing Light, sweet crude with ~40 degree API Majority sold to in-basin refiners Niobrara exploration work progressing Significant upside potential (~200k acres) Initial two wells flowing back (results in 2H18) Preparing for higher activity levels in 2019 Preparing to run up to 4 rigs next year Potential for 2x increase in activity from 2018 Shifting Super Mario area into development Select appraisal work to expand inventory Q2 POWDER RIVER BASIN ACTIVITY Super Mario Area RU JFW Fed 13-24s Completing 2 wells Niobrara #1 Flowing Back Turner Niobrara OIL Converse FAIR WAY RU State Fed 4X Avg. 30-Day IP: 1,400 Niobrara #2 Flowing Back RU State Fed 2X Avg. 30-Day IP: 1,500

41 Barnett Shale Johnson County sale completed in May Gross proceeds: $553 million Q2 production: 21 MBOED (80% gas) Stable production outlook for remainder of year Driven by Dow JV and refrac program Minimum volume commitments to expire in 2018 ~$100 million cash flow benefit in 2019 BARNETT SHALE OVERVIEW New Drills RETAINED ASSET OVERVIEW Net acres: 400k Production: 111 BOED 2018 activity: 20 new drills / 50 refracs Denton Refracs Wise Tarrant 2018 ACTIVITY Stable Production Outlook Retained Assets MBOED

42 Heavy Oil Q2 PRODUCTION GROSS NET Jackfish 1 (MBOD) Jackfish 2 (MBOD) Jackfish 3 (MBOD) Lloydminster (MBOED) Total Heavy Oil (MBOED) SAGD Sweet Spot (1) Assumes $65 WTI and $25 differential for 2H 2018 and includes benefits of basis swaps. Q2 volumes impacted by turnaround and royalties Jackfish maintenance impact: ~15 MBOD Royalties ~2 percentage points higher than Q1 18 Net production increases to ~120 MBOED in Q3 Turnaround efforts at Jackfish identified additional maintenance requirements Maintenance extends facility ramp-up into Q3 Peak production rates expected in Q4 Significant free cash flow generation in 2018 WCS basis swaps continue to protect pricing ~50% hedged at $15 off WTI 2018 free cash flow: ~$500 million(1) Higher pricing accelerates Jackfish 2 payout Potential to occur as early as first half of 2019 ~3-4 MBOD impact at current strip pricing 1 $ INCREASE IN WCS PER BBL FOR EVERY INCREMENTAL 40 MM $ ANNUALIZED CASH FLOW

43 Investor acquisitions 0330 from Contacts and the divestitures; SEC s & Notices website Investor and at 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 second-quarter our business and 2018 operations earnings are release subject at to all of the risks and uncertainties Cautionary normally Note to incident Investors to The the SEC exploration permits for oil and development gas companies, and in production their filings of with oil and the SEC, gas. These to disclose risks include, only proved, but are probable not limited and to: possible the volatility reserves of that oil, meet gas and the SEC's NGL prices; definitions uncertainties for such terms, inherent and in price estimating and cost oil, sensitivities gas and NGL for reserves; such reserves, the extent and prohibits to which we disclosure are successful of resources in acquiring that do and not discovering constitute such Investor reserves. Notices This additional presentation reserves; may contain the uncertainties, terms, costs such and as risks resource involved potential, in oil potential and gas operations; locations, risked regulatory and unrisked restrictions, locations, compliance estimated costs ultimate and other recovery risks relating (EUR), to exploration governmental target regulation, size and including other similar with terms. respect These to environmental estimates are matters; by their nature risks related more speculative to our hedging than activities; estimates counterparty of proved, probable credit risks; and possible risks relating reserves to our and indebtedness; accordingly are cyberattack subject to risks; substantially our limited greater control risk over of being third actually parties who realized. operate The our SEC oil guidelines and gas properties; strictly prohibit midstream us from capacity including constraints these estimates and potential in filings interruptions with the SEC. in production; Investors the are extent urged to which consider insurance closely covers the disclosure any losses in our we Form may experience; 10-K, available competition at for leases, materials, You people can and also capital; obtain this our form ability from to successfully the SEC by complete calling SEC- mergers,