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UNITED STATESSECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORTPursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 20, 2018

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

DELAWARE 001-32318 73-1567067

(State or Other Jurisdictionof Incorporation)

(CommissionFile Number)

(IRS EmployerIdentification Number)

333 W. SHERIDAN AVE., OKLAHOMA CITY, OKLAHOMA 73102(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code: (405) 235-3611

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 followingprovisions (see General Instructions A-2. Below):

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-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 (§ 230.405 of this chapter) orRule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-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 orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Item 2.02 Results of Operations and Financial Condition.

On February 20, 2018, Devon Energy Corporation (the “Company”) issued a press release announcing its financial and operational results for the quarter andyear ended December 31, 2017. The release also included the Company’s three-year business outlook and its detailed guidance for 2018. In connection with theearnings release, the Company also provided (i) its operations report for the fourth quarter 2017 and (ii) supplemental financial information relating to theCompany’s recent conversion to successful efforts. Copies of the earnings release, fourth quarter 2017 operations report and supplemental financial information arefurnished as Exhibits 99.1, 99.2 and 99.3, respectively, to this report and will be available on the Company’s website at www.devonenergy.com.

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 Actof 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, asamended, 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 February 20, 2018.

99.2 Fourth quarter 2017 operations report.

99.3 Supplemental financial information relating to successful efforts conversion.

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 undersignedhereto duly authorized.

DEVON ENERGY CORPORATION

By: /s/JeffreyL.Ritenour Jeffrey L. Ritenour Executive Vice President and Chief Financial Officer

Date: February 20, 2018

Exhibit 99.1

Devon Energy Corporation333 West Sheridan Avenue

Oklahoma City, OK 73102-5015

NEWS RELEASE

Devon Energy Announces Three-Year Outlook and Detailed 2018 Guidance; Reports Fourth Quarter Earnings Results

OKLAHOMA CITY – Feb. 20, 2018 – Devon Energy Corp. (NYSE: DVN) today announced a three-year business outlook through the year 2020 and its detailedcapital and production outlook for 2018. Additionally, the company reported operational and financial results for the fourth quarter and full-year 2017.

Three-Year Outlook Highlights

More detailed commentary regarding Devon’s three-year business outlook is available within its fourth-quarter 2017 operations report at www.devonenergy.com .Outlook highlights from the report include:

• Greater than 15 percent corporate-level rates of return

• $2.5 billion of cumulative free cash flow through 2020

• Delaware and STACK oil production CAGR of greater than 25 percent

• Per-unit cash cost savings of approximately 15 percent by 2020

• Potential to monetize more than $5 billion of non-core assets

• Positioned for sustainable increase of cash to shareholders

“Devon has reached an inflection point by building operating momentum across its U.S. resource plays and has successfully transitioned these world-class assetsinto full-field development,” said Dave Hager, president and CEO. “In 2018 and beyond, with our low-risk development programs focused in the economic core ofthe Delaware Basin and STACK plays, we expect to deliver a dramatic step change in capital efficiency, achieve attractive corporate-level returns and generatesubstantial amounts of free cash flow at prices above our base planning scenario of $50 WTI pricing.”

“With our disciplined multi-year plan, Devon will accelerate value creation through the pursuit of capital-efficient cash-flow growth and portfolio simplification,not top-line production growth,” said Hager. “Looking beyond our initial priority of reducing up to $1.5 billion of debt from our upstream business, we plan toreturn excess cash flow from operations or divestitures to shareholders through both opportunistic share buybacks and dividend growth.”

February 2018 Production Update: Delaware and STACK Volume Growth Accelerates

In early 2018, production growth has accelerated in the company’s Delaware Basin and STACK assets, with current daily rates from these assets approximating195,000 oil-equivalent barrels (Boe) per day. The combined daily production rates from these two franchise growth assets represent greater than a 10 percentincrease compared to the fourth quarter of 2017 and nearly a 20 percent increase compared to the full-year 2017 average.

The substantial increase in daily production is driven by higher operated completion activity in the Delaware Basin and tie-in of more than 50 non-operated wells inthe STACK around year end. In aggregate, these two high-growth assets remain on plan to increase oil production by greater than 35 percent in 2018 compared to2017.

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Timing of Non-Operated Activity Limits Fourth Quarter Production

Devon’s net production averaged 548,000 Boe per day in the fourth quarter of 2017. Of this total, oil production in the quarter totaled 246,000 barrels per day,which was 14,000 barrels per day below the company’s midpoint guidance.

In the fourth quarter, net production in the U.S. was limited by approximately 9,000 barrels per day primarily due to the timing of well tie-ins associated withnon-operated activity in the STACK. This timing issue has been resolved with the tie-in of more than 50 non-operated wells around year end in the STACK (see“February 2018 Production Update” section for more details.)

In Canada, net production averaged 134,000 Boe per day in the fourth quarter, an 8 percent increase from the prior quarter. Facility modifications and temporarysteam constraints at the company’s Jackfish complex curtailed production by approximately 5,000 barrels per day in the fourth quarter.

Delivering Top-Tier Operated Well Productivity

Importantly, Devon’s operated well activity in the fourth quarter across its U.S. resource plays was delivered on plan with outstanding well productivity results.Led by the Delaware Basin and STACK, the company’s top 30 operated wells during the fourth quarter averaged initial 30-day production rates of greater than2,500 Boe per day (60 percent oil). These high-rate wells showcase Devon’s asset quality and technical excellence that has consistently generated top-tier wellproductivity in North America.

For additional details on well results and other information about Devon’s E&P operations, please refer to the company’s fourth-quarter 2017 operations report atwww.devonenergy.com .

Drilling Success Drives U.S. Oil Reserves 32 Percent Higher

Devon’s estimated proved reserves were 2.2 billion Boe on Dec. 31, 2017, a 5 percent increase compared to 2016. Proved developed reserves accounted for81 percent of the total. At year-end, liquids reserves advanced to 1.2 billion Boe, driven by a 32 percent increase in U.S. oil reserves during 2017.

The company’s reserve growth in 2017 came entirely from its U.S. resource plays, where proved reserves increased 11 percent to 1.7 billion Boe. Led by Devon’scapital programs in the Delaware Basin and STACK, the company’s U.S. resource plays exhibited strong growth by adding 327 million Boe of reserves in 2017.This result represents a replacement rate of approximately 215 percent. The capital costs incurred to contribute to these reserve additions were $1.7 billion,equating to a finding and development cost in the U.S. of only $5 per Boe.

Devon Converts to Successful-Efforts Accounting Method

As previously announced, in the fourth quarter Devon changed its method of accounting for oil and gas exploration and development activities from the full-costmethod to successful efforts. All reported financial results contained within this release reflect this change in accounting policy. The company has provided asupplemental information packet related to its conversion to successful efforts on its website at www.devonenergy.com , which includes a reconciliation offinancial results from full cost to successful efforts for prior financial reporting periods.

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Upstream Revenue Advances and EnLink Profitability Expands

The company’s upstream revenue totaled $1.3 billion in the fourth quarter, a 35 percent improvement compared to the fourth quarter of 2016. The strong year-over-year revenue growth was driven by higher commodity price realizations and an increase in higher-margin liquids production.

Devon’s midstream business generated operating profits of $272 million in the fourth quarter, increasing 35 percent year over year. This growth was driven entirelyby Devon’s strategic investment in EnLink Midstream. Overall, for 2017, Devon’s midstream profits reached $912 million, the highest in company history.

Devon has a 64 percent ownership interest in EnLink’s general partner (NYSE: ENLC) and a 23 percent interest in the limited partner (NYSE: ENLK). Inaggregate, the company’s ownership in EnLink has a market value of approximately $3.5 billion and generated cash distributions of nearly $270 million in 2017.

Per-Unit Cost Structure Continues to Improve

Devon’s production expense, which represents field-level operating costs, totaled $463 million in the fourth quarter. This result is a 1 percent improvement on aper-unit basis compared to the third quarter of 2017. The largest components of production expense are lease operating expense and transportation, which totaled$399 million or $7.90 per Boe in the quarter. Production and property taxes also contributed $64 million to production expense during the fourth quarter.

The company’s general and administrative expenses (G&A) totaled $222 million in the fourth quarter, a 1 percent improvement compared to the year-ago quarter.Excluding costs associated with EnLink, Devon’s G&A expense for the quarter was $192 million. Of this total upstream overhead, $48 million would havepreviously been categorized as capitalized G&A under the company’s prior full-cost accounting methodology.

Depreciation, depletion and amortization expense (DD&A) amounted to $528 million or $10.47 per Boe in the fourth quarter of 2017. Compared to the thirdquarter of 2017, the company’s per-unit DD&A declined by 1 percent. Exploration expense in the fourth quarter totaled $171 million, with the majority of theexpense related to non-cash impairments of unproved properties in the U.S.

Tax Reform to Provide Lower Tax Rates in 2018

In late 2017, significant changes to the U.S. federal income tax code were signed into law with legislation commonly referred to as the “Tax Cuts and Jobs Act.”This tax legislation did not have a material impact to Devon’s fourth-quarter 2017 results. In 2018 and beyond, Devon expects the tax reform to have an overallpositive impact on its business. This benefit is primarily due to the U.S. corporate tax rate being lowered from 35 percent to 21 percent along with the repeal ofalternative minimum tax provisions. The company will also benefit from legislation allowing the tax-efficient repatriation of future Canadian earnings to the U.S.

Higher-Margin Production Expands Cash Flow 94 Percent in 2017

In the fourth quarter of 2017, Devon’s operating cash flow totaled $725 million. For the full-year 2017, operating cash flow reached $2.9 billion, a 94 percentincrease compared to 2016. The increase is primarily attributable to improvements in commodity prices, a shift to higher-margin production and a lower coststructure.

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For the fourth quarter, Devon’s reported net earnings totaled $183 million or $0.35 per diluted share. Adjusting for items securities analysts typically exclude fromtheir published estimates, the company’s core earnings were $199 million or $0.38 per diluted share in the quarter.

Financial Position Remains Strong

The company exited the fourth quarter with $2.7 billion of cash on hand. Overall, Devon’s financial position remains exceptionally strong, with investment-gradecredit ratings and no significant debt maturities until mid-2021.

Canadian Oil Swaps Protecting Cash Flow in 2018

Further bolstering the company’s financial strength is its hedge position in 2018. The company currently has around half of its expected oil and gas productionprotected in 2018. These contracts consist of collars and swaps based off the West Texas Intermediate (WTI) oil benchmark and the Henry Hub natural gas index.The volume and pricing details associated with the company’s hedges are provided in the tables within this release.

Also of note, the company has secured Western Canadian Select (WCS) basis swaps on approximately 50 percent of its estimated Canadian oil production in 2018.These attractive WCS basis swaps are locked-in at $15 off the WTI benchmark price and are currently valued at approximately $300 million.

2018 Capital and Production Outlook

Detailed forward-looking guidance for the first quarter and full-year 2018 is provided later in the release. A notable component of this outlook is Devon’s upstreamcapital budget of $2.2 billion to $2.4 billion. This disciplined capital program is expected to be self-funded at a $50 WTI price deck.

On a retained asset basis, Devon’s upstream capital plans are expected to drive U.S. oil production growth of approximately 14 percent compared to 2017. Thetrajectory of Devon’s U.S. oil production profile is expected to steadily advance throughout the year and exit 2018 at rates more than 25 percent higher than the2017 average.

Also of note, reflected in Devon’s forward-looking revenue and cost guidance are new revenue recognition accounting rules that will change the way certainprocessing fees are presented for natural gas and natural gas liquids. Historically, these fees have been recorded as a reduction to revenue. Now, these fees will berecorded directly to production expense beginning in the first quarter of 2018. This accounting change will have no impact to per-unit cash margin or net earningsbut will result in higher price realizations, increased revenues and increased production expenses.

Non-GAAP Reconciliations

Pursuant to regulatory disclosure requirements, Devon is required to reconcile non-GAAP (generally accepted accounting principles) financial measures to therelated GAAP information. Core earnings and core earnings per share and other items referenced within the commentary of this release are non-GAAP financialmeasures. Reconciliations of these and other non-GAAP measures are provided within the tables of this release.

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Conference Call Webcast and Supplemental Earnings Materials

Also included with today’s release is the company’s detailed operations report that is available on the company’s website at www.devonenergy.com . Thecompany’s fourth-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Feb. 21, 2018, and will serve primarily as a forum foranalyst and investor questions and answers.

Forward-Looking Statements

Thisreleaseincludes“forward-lookingstatements”asdefinedbytheSecuritiesandExchangeCommission(SEC).Suchstatementsincludethoseconcerningstrategicplans,expectationsandobjectivesforfutureoperations,andareoftenidentifiedbyuseofthewords“expects,”“believes,”“will,”“would,”“could,”“forecasts,”“projections,”“estimates,”“plans,”“expectations,”“targets,”“opportunities,”“potential,”“anticipates,”“outlook”andothersimilarterminology.Allstatements,otherthanstatementsofhistoricalfacts,includedinthispressreleasethataddressactivities,eventsordevelopmentsthatthecompanyexpects,believesoranticipateswillormayoccurinthefutureareforward-lookingstatements.Suchstatementsaresubjecttoanumberofassumptions,risksanduncertainties,manyofwhicharebeyondthecontrolofthecompany.Statementsregardingourbusinessandoperationsaresubjecttoalloftherisksanduncertaintiesnormallyincidenttotheexplorationforanddevelopmentandproductionofoilandgas.Theserisksinclude,butarenotlimitedto:thevolatilityofoil,gasandNGLprices;uncertaintiesinherentinestimatingoil,gasandNGLreserves;theextenttowhichwearesuccessfulinacquiringanddiscoveringadditionalreserves;theuncertainties,costsandrisksinvolvedinoilandgasoperations;regulatoryrestrictions,compliancecostsandotherrisksrelatingtogovernmentalregulation,includingwithrespecttoenvironmentalmatters;risksrelatedtoourhedgingactivities;counterpartycreditrisks;risksrelatingtoourindebtedness;cyberattackrisks;ourlimitedcontroloverthirdpartieswhooperateouroilandgasproperties;midstreamcapacityconstraintsandpotentialinterruptionsinproduction;theextenttowhichinsurancecoversanylosseswemayexperience;competitionforleases,materials,peopleandcapital;ourabilitytosuccessfullycompletemergers,acquisitionsanddivestitures;andanyoftheotherrisksanduncertaintiesidentifiedinourForm10-KandourotherfilingswiththeSEC.Investorsarecautionedthatanysuchstatementsarenotguaranteesoffutureperformanceandthatactualresultsordevelopmentsmaydiffermateriallyfromthoseprojectedintheforward-lookingstatements.Theforward-lookingstatementsinthisreleasearemadeasofthedateofthisrelease,evenifsubsequentlymadeavailablebyDevononitswebsiteorotherwise.Devondoesnotundertakeanyobligationtoupdatetheforward-lookingstatementsasaresultofnewinformation,futureeventsorotherwise.TheSECpermitsoilandgascompanies,intheirfilingswiththeSEC,todiscloseonlyproved,probableandpossiblereservesthatmeettheSEC’sdefinitionsforsuchterms,andpriceandcostsensitivitiesforsuchreserves,andprohibitsdisclosureofresourcesthatdonotconstitutesuchreserves.Thisreleasemaycontaincertainterms,suchasresourcepotential,potentiallocations,riskedandunriskedlocations,estimatedultimaterecovery(orEUR),explorationtargetsizeandothersimilarterms.Theseestimatesarebytheirnaturemorespeculativethanestimatesofproved,probableandpossiblereservesandaccordinglyaresubjecttosubstantiallygreaterriskofbeingactuallyrealized.TheSECguidelinesstrictlyprohibitusfromincludingtheseestimatesinfilingswiththeSEC.InvestorsareurgedtoconsidercloselythedisclosureinourForm10-K,availableatwww.devonenergy.com.YoucanalsoobtainthisformfromtheSECbycalling1-800-SEC-0330orfromtheSEC’swebsiteatwww.sec.gov.

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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&P500, 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 www.devonenergy.com . Investor Contacts Media Contact

Scott Coody, 405-552-4735 John Porretto, 405-228-7506Chris Carr, 405-228-2496

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FINANCIAL AND OPERATIONAL INFORMATION

PRODUCTION NET OF ROYALTIES Quarter Ended Year Ended December 31, December 31, 2017 2016 2017 2016 Oil and bitumen (MBbls/d)

U. S. 114 104 114 117 Heavy Oil 132 138 128 131

Retained assets 246 242 242 248 Divested assets — 2 2 12

Total 246 244 244 260

Natural gas liquids (MBbls/d) U. S. 106 89 99 102 Divested assets — 1 — 14

Total 106 90 99 116

Gas (MMcf/d) U. S. 1,160 1,198 1,182 1,263 Heavy Oil 15 18 17 20

Retained assets 1,175 1,216 1,199 1,283 Divested assets — 5 4 130

Total 1,175 1,221 1,203 1,413

Oil equivalent (MBoe/d) U. S. 414 392 410 429 Heavy Oil 134 141 131 134

Retained assets 548 533 541 563 Divested assets — 4 2 48

Total 548 537 543 611

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PRODUCTION TREND 2016 2017 Quarter 4 Quarter 1 Quarter 2 Quarter 3 Quarter 4 Oil and bitumen (MBbls/d)

STACK 19 21 25 27 30 Delaware Basin 29 30 30 31 32 Rockies Oil 11 13 13 12 15 Heavy Oil 138 137 122 121 132 Eagle Ford 32 46 34 28 27 Barnett Shale 1 1 1 1 1 Other 12 11 10 11 9

Retained assets 242 259 235 231 246 Divested assets 2 2 3 2 —

Total 244 261 238 233 246

Natural gas liquids (MBbls/d) STACK 21 26 31 32 34 Delaware Basin 10 10 10 11 13 Rockies Oil 1 1 1 1 1 Eagle Ford 11 15 10 12 13 Barnett Shale 43 43 42 36 42 Other 3 2 2 2 3

Retained assets 89 97 96 94 106 Divested assets 1 1 1 — —

Total 90 98 97 94 106

Gas (MMcf/d) STACK 284 287 298 313 316 Delaware Basin 88 87 94 90 89 Rockies Oil 17 15 17 11 17 Heavy Oil 18 23 14 16 15 Eagle Ford 86 115 92 86 87 Barnett Shale 710 683 675 672 638 Other 13 13 12 10 13

Retained assets 1,216 1,223 1,202 1,198 1,175 Divested assets 5 5 6 3 —

Total 1,221 1,228 1,208 1,201 1,175

Oil equivalent (MBoe/d) STACK 88 95 105 111 117 Delaware Basin 53 54 55 57 60 Rockies Oil 15 17 18 15 19 Heavy Oil 141 141 124 124 134 Eagle Ford 57 80 60 54 55 Barnett Shale 163 158 155 148 149 Other 16 15 15 15 14

Retained assets 533 560 532 524 548 Divested assets 4 3 4 3 —

Total 537 563 536 527 548

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BENCHMARK PRICES(average prices) Quarter 4 December YTD 2017 2016 2017 2016 Oil ($/Bbl) - West Texas Intermediate (Cushing) $55.49 $49.21 $50.99 $43.36 Natural Gas ($/Mcf) - Henry Hub $ 2.93 $ 2.98 $ 3.11 $ 2.46

REALIZED PRICES Quarter Ended December 31, 2017 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ 54.18 $ 18.46 $ 2.29 $ 26.18 Canada $ 32.54 N/M N/M $ 31.95

Realized price without hedges $ 42.59 $ 18.46 $ 2.29 $ 27.59 Cash settlements $ (0.38) $ (0.30) $ 0.19 $ 0.19

Realized price, including cash settlements $ 42.21 $ 18.16 $ 2.48 $ 27.78

Quarter Ended December 31, 2016 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ 46.74 $ 13.81 $ 2.34 $ 22.78 Canada $ 25.90 N/M N/M $ 25.39

Realized price without hedges $ 34.90 $ 13.81 $ 2.34 $ 23.47 Cash settlements $ — $ (0.31) $ (0.11) $ (0.30)


Year Ended December 31, 2017 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ 49.41 $ 15.66 $ 2.48 $ 24.88 Canada $ 29.99 N/M N/M $ 29.39

Realized price without hedges $ 39.23 $ 15.66 $ 2.48 $ 25.96 Cash settlements $ 0.23 $ (0.10) $ 0.08 $ 0.27


Year Ended December 31, 2016 Oil /Bitumen NGL Gas Total (Per Bbl) (Per Bbl) (Per Mcf) (Per Boe) United States $ 38.92 $ 9.81 $ 1.84 $ 18.34 Canada $ 20.53 N/M N/M $ 20.07

Realized price without hedges $ 29.65 $ 9.81 $ 1.84 $ 18.72 Cash settlements $ (0.43) $ (0.11) $ 0.07 $ (0.05)


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CONSOLIDATED STATEMENTS OF EARNINGS(in millions, except per share amounts) Quarter Ended Year Ended December 31, December 31, 2017 2016* 2017 2016* Upstream revenues $1,333 $ 988 $ 5,307 $ 3,981 Marketing and midstream revenues 2,650 1,820 8,642 6,323

Total revenues 3,983 2,808 13,949 10,304

Production expenses (1) 463 409 1,823 1,803 Exploration expenses 171 37 380 215 Marketing and midstream expenses 2,378 1,617 7,730 5,533 Depreciation, depletion and amortization 528 469 2,074 2,096 Asset impairments 8 80 17 1,310 Asset dispositions (18) (575) (217) (1,483) General and administrative expenses 222 218 872 865 Financing costs, net 126 335 498 907 Other expenses 5 (53) (124) 375

Total expenses 3,883 2,537 13,053 11,621

Earnings (loss) before income taxes 100 271 896 (1,317) Income tax expense (benefit) (204) 75 (182) 141

Net earnings (loss) 304 196 1,078 (1,458) Net earnings (loss) attributable to noncontrolling interests 121 (11) 180 (402)

Net earnings (loss) attributable to Devon $ 183 $ 207 $ 898 $ (1,056)

Net earnings (loss) per share attributable to Devon: Basic $ 0.35 $ 0.41 $ 1.71 $ (2.09) Diluted $ 0.35 $ 0.41 $ 1.70 $ (2.09)

Weighted average common shares outstanding: Basic 525 524 525 513 Diluted 528 526 528 513

* Prior year amounts have been recast due to change in accounting principle.

(1) PRODUCTION EXPENSES(in millions) Quarter Ended December 31, Year Ended December 31, 2017 2017 2016 2017 2016 Lease operating expense $ 236 $ 209 $ 927 $ 1,027 Gathering & transportation 163 158 647 555 Production taxes 51 32 194 147 Property taxes 13 10 55 74

Production expenses $ 463 $ 409 $ 1,823 $ 1,803

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CONSOLIDATED STATEMENTS OF CASH FLOWS(in millions) Quarter Ended Year Ended December 31, December 31, 2017 2016* 2017 2016* Cash flows from operating activities:

Net earnings (loss) $ 304 $ 196 $ 1,078 $(1,458) Adjustments to reconcile net earnings (loss) to net cash from operating activities:

Depreciation, depletion and amortization 528 469 2,074 2,096 Exploratory dry hole expense and unproved leasehold impairments 139 5 219 113 Asset impairments 8 80 17 1,310 Gains and losses on asset sales (18) (575) (217) (1,483) Deferred income tax expense (benefit) (245) 47 (294) 41 Commodity derivatives 57 171 (157) 201 Cash settlements on commodity derivatives 10 (14) 53 1 Other derivatives and financial instruments 7 (144) 23 185 Cash settlements on other derivatives and financial instruments (6) 5 (6) (143) Asset retirement obligation accretion 15 17 62 75 Share-based compensation 47 40 198 233 Other 16 337 (122) 270 Net change in working capital (73) (184) 21 24 Change in long-term other assets (58) 26 (46) 36 Change in long-term other liabilities (6) (8) 6 (1)

Net cash from operating activities 725 468 2,909 1,500

Cash flows from investing activities: Capital expenditures (799) (593) (2,759) (2,047) Acquisitions of property, equipment and businesses (7) — (46) (1,641) Divestitures of property and equipment 101 1,224 417 3,113 Proceeds from sale of investment — — 190 — Other (7) (26) (12) (19)

Net cash from investing activities (712) 605 (2,210) (594)

Cash flows from financing activities: Borrowings of long-term debt, net of issuance costs 168 483 2,376 2,145 Repayments of long-term debt (168) (1,687) (2,118) (4,409) Payment of installment payable — — (250) — Net short-term debt repayments — — — (626) Early retirement of debt — (183) (6) (265) Issuance of common stock — — — 1,469 Issuance of subsidiary units 15 57 501 892 Dividends paid on common stock (32) (31) (127) (221) Contributions from noncontrolling interests 10 17 57 168 Distributions to noncontrolling interests (107) (80) (354) (304) Shares exchanged for tax withholdings (1) (5) (68) (35) Other — (4) (2) (10)

Net cash from financing activities (115) (1,433) 9 (1,196)

Effect of exchange rate changes on cash (6) (66) 6 (61)

Net change in cash and cash equivalents (108) (426) 714 (351) Cash and cash equivalents at beginning of period 2,781 2,385 1,959 2,310

Cash and cash equivalents at end of period $2,673 $ 1,959 $ 2,673 $ 1,959


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CONSOLIDATED BALANCE SHEETS(in millions) December 31, December 31, 2017 2016* Current assets:

Cash and cash equivalents $ 2,673 $ 1,959 Accounts receivable 1,670 1,356 Assets held for sale — 193 Other current assets 448 264

Total current assets 4,791 3,772

Oil and gas property and equipment, based on successful efforts accounting, net 13,318 12,998 Midstream and other property and equipment, net 7,853 7,535

Total property and equipment, net 21,171 20,533 Goodwill 2,383 2,383 Other long-term assets 1,896 1,987

Total assets $ 30,241 $ 28,675

Current liabilities: Accounts payable $ 819 $ 642 Revenues and royalties payable 1,180 908 Short-term debt 115 — Other current liabilities 1,201 1,066

Total current liabilities 3,315 2,616

Long-term debt 10,291 10,154 Asset retirement obligations 1,113 1,226 Other long-term liabilities 583 894 Deferred income taxes 835 1,063 Equity:

Common stock 53 52 Additional paid-in capital 7,333 7,237 Retained earnings (accumulated deficit) 702 (69) Accumulated other comprehensive earnings 1,166 1,054

Total stockholders’ equity attributable to Devon 9,254 8,274 Noncontrolling interests 4,850 4,448

Total equity 14,104 12,722

Total liabilities and equity $ 30,241 $ 28,675

Common shares outstanding 525 523 * Prior year amounts have been recast due to change in accounting principle.

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CONSOLIDATING STATEMENTS OF OPERATIONS(in millions) Quarter Ended December 31, 2017

Devon U.S. &

Canada EnLink Eliminations Total Upstream revenues $ 1,333 $ — $ — $1,333 Marketing and midstream revenues 1,048 1,756 (154) 2,650

Total revenues 2,381 1,756 (154) 3,983

Production expenses 463 — — 463 Exploration expenses 171 — — 171 Marketing and midstream expenses 1,048 1,484 (154) 2,378 Depreciation, depletion and amortization 389 139 — 528 Asset impairments — 8 — 8 Asset dispositions (17) (1) — (18) General and administrative expenses 192 30 — 222 Financing costs, net 78 48 — 126 Other expenses 10 (5) — 5

Total expenses 2,334 1,703 (154) 3,883

Earnings before income taxes 47 53 — 100 Income tax expense (benefit) 3 (207) — (204)

Net earnings 44 260 — 304 Net earnings attributable to noncontrolling interests — 121 — 121

Net earnings attributable to Devon $ 44 $ 139 $ — $ 183

OTHER KEY STATISTICS(in millions) Quarter Ended December 31, 2017

Devon U.S. &

Canada EnLink Eliminations Total Cash flow statement related items:

Operating cash flow $ 553 $ 172 $ — $ 725 Divestitures of property and equipment $ 101 $ — $ — $ 101 Capital expenditures $ (670) $ (129) $ — $ (799) EnLink distributions received (paid) $ 66 $ (173) $ — $ (107)

Balance sheet statement items: Net debt (1) $ 4,222 $3,511 $ — $7,733

(1) Net debt is a non-GAAP measure. For a reconciliation of the comparable GAAP measure, see “Non-GAAP Financial Measures” later in this release.

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CAPITAL EXPENDITURES(in millions) Quarter Ended Year Ended December 31, 2017 December 31, 2017 Exploration and development capital $ 648 $ 1,947 Land and other acquisitions 9 56

Exploration and production (E&P) capital 657 2,003 Capitalized interest 18 69 Other 33 97

Devon capital expenditures (1) $ 708 $ 2,169

(1) Excludes $132 million and $768 million attributable to EnLink for the fourth quarter and year end of 2017, respectively.

COSTS INCURRED(in millions) Total Year Ended December 31, 2017 2016* Property acquisition costs:

Proved properties $ 2 $ 237 Unproved properties 54 1,358

Exploration costs 677 360 Development costs 1,261 929

Costs incurred $ 1,994 $ 2,884

United States Year Ended December 31, 2017 2016* Property acquisition costs:

Proved properties $ 2 $ 237 Unproved properties 50 1,356

Exploration costs 590 282 Development costs 1,036 875

Costs incurred $ 1,678 $ 2,750

Canada Year Ended December 31, 2017 2016* Property acquisition costs:

Proved properties $ — $ — Unproved properties 4 2

Exploration costs 87 78 Development costs 225 54

Costs incurred $ 316 $ 134


14



RESERVES RECONCILIATION Total

Oil / Bitumen(MMBbls)

Gas (Bcf)

NGL (MMBbls)

Total (MMBoe)

As of December 31, 2016: Proved developed 367 5,377 387 1,649 Proved undeveloped 328 254 38 409

Total Proved 695 5,631 425 2,058

Revisions due to prices (26) 399 32 73 Revisions other than price (2) 2 (10) (12) Extensions and discoveries 106 403 63 237 Production (89) (439) (36) (198) Sale of reserves (3) (9) (1) (6)


Total Proved 681 5,987 473 2,152

United States


Gas (Bcf)

NGL (MMBbls)

Total (MMBoe)


Total Proved 194 5,615 425 1,554

Revisions due to prices 12 398 32 111 Revisions other than price 6 — (10) (5) Extensions and discoveries 90 403 63 221 Production (42) (433) (36) (150) Sale of reserves (3) (9) (1) (6)


Total Proved 257 5,974 473 1,725

Canada


Gas (Bcf)

NGL (MMBbls)

Total (MMBoe)

As of December 31, 2016: Proved developed 207 16 — 210 Proved undeveloped 294 — — 294

Total Proved 501 16 — 504

Revisions due to prices (38) 1 — (38) Revisions other than price (8) 2 — (7) Extensions and discoveries 16 — — 16 Production (47) (6) — (48)

As of December 31, 2017: Proved developed 215 13 — 218 Proved undeveloped 209 — — 209

Total Proved 424 13 — 427

15



NON-GAAP FINANCIAL MEASURES

This release includes non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider thesenon-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of thenon-GAAP measures used in this 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’sfinancial results. Accordingly, the company also uses the measures of core earnings and core earnings per share attributable to Devon. Devon believes thesenon-GAAP measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believes these non-GAAPmeasures can facilitate comparisons of its performance between periods and to the performance of its peers. The following table summarizes the effects of theseitems on fourth-quarter 2017 earnings. (in millions, except per share amounts) Quarter Ended December 31, 2017

Before-tax After-tax

After Noncontrolling

Interests Per Diluted

Share Earnings attributable to Devon (GAAP) $ 100 $ 304 $ 183 $ 0.35 Adjustments:

Asset and exploration impairments 146 94 91 0.18 Fair value changes in financial instruments and foreign currency 74 30 31 0.06 Asset dispositions (18) (11) (11) (0.02) Legal entity restructuring — (86) (86) (0.16) Deferred tax asset valuation allowance — 103 103 0.18 U.S. tax reform — (211) (112) (0.21)

Core earnings attributable to Devon (Non-GAAP) $ 302 $ 223 $ 199 $ 0.38

NET DEBT

Devon defines net debt as debt less cash and cash equivalents and net debt attributable to the consolidation of EnLink Midstream as presented in the followingtable. Devon believes that netting these sources of cash against debt and adjusting for EnLink net debt provides a clearer picture of the future demands on cashfrom Devon to repay debt. (in millions) December 31, 2017 Devon U.S. & Canada EnLink Devon Consolidated Total debt (GAAP) $ 6,864 $3,542 $ 10,406

Less cash and cash equivalents (2,642) (31) (2,673)

Net debt (Non-GAAP) $ 4,222 $3,511 $ 7,733

16


FORWARD LOOKING GUIDANCE

PRODUCTION GUIDANCE Quarter 1 Full Year Low High Low High Oil and bitumen (MBbls/d)

U.S. 117 122 128 133 Heavy Oil 125 130 125 130

Total 242 252 253 263

Natural gas liquids (MBbls/d) 98 103 105 110 Gas (MMcf/d)

U.S. 1,125 1,175 1,150 1,200 Heavy Oil 14 16 14 16

Total 1,139 1,191 1,164 1,216

Oil equivalent (MBoe/d) U.S. 403 421 425 443 Heavy Oil 127 133 127 133

Total 530 554 552 576

PRICE REALIZATIONS GUIDANCE Quarter 1 Full Year Low High Low High Oil and bitumen - % of WTI

U.S. 95% 100% 95% 100% Canada 25% 35% 25% 50%

NGL - realized price (1) $ 22 $ 27 $ 20 $ 25 Natural gas - % of Henry Hub (1) 75% 85% 75% 85%

OTHER GUIDANCE ITEMS

Quarter 1 Full Year ($ millions, except %) Low High Low High Marketing & midstream operating profit $260 $280 $1,050 $1,150 Production expenses (1)(2) $500 $550 $2,100 $2,200 Exploration expenses $ 25 $ 35 $ 90 $ 100 Depreciation, depletion and amortization $530 $580 $2,300 $2,400 General & administrative expenses $210 $230 $ 800 $ 850 Financing costs, net $115 $125 $ 465 $ 515 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%

Net earnings attributable to noncontrolling interests $ 30 $ 50 $ 150 $ 200

CAPITAL EXPENDITURES GUIDANCE

Quarter 1 Full Year (in millions) Low High Low High Exploration and production $550 $650 $2,200 $2,400 Capitalized interest 15 20 60 90 Other 20 30 75 125

Devon capital expenditures (3) $585 $700 $2,335 $2,615

(1) In 2018, Devon adopted new accounting regulations that will change the way certain processing fees are presented for natural gas and natural gas liquids.

Historically, these fees have been recorded as a reduction to revenue. Now, these fees will be recorded directly to production expense beginning in the firstquarter of 2018 and prior periods will be recast for consistent presentation. This accounting change will have no impact to per-unit cash margin or netearnings but will result in higher price realizations, increased revenues and increased production expenses.

(2) Production expense includes LOE, transportation, gathering and production and property taxes.(3) Excludes capital expenditures related to EnLink.

17


FORWARD LOOKING GUIDANCE Oil Commodity Hedges

Price Swaps Price Collars

Period Volume (Bbls/d)

Weighted Average Price

($/Bbl) Volume (Bbls/d)

Weighted Average FloorPrice ($/Bbl)

Weighted AverageCeiling Price

($/Bbl) Q1-Q4 2018 49,625 $ 52.13 51,860 $ 46.06 $ 56.06 Q1-Q4 2019 7,307 $ 52.22 6,559 $ 45.82 $ 55.82

Oil Basis Swaps

Period Index Volume (Bbls/d) Weighted Average Differential to

WTI ($/Bbl) Q1-Q4 2018 Midland Sweet 23,000 $ (1.02) Q1-Q4 2018 Argus LLS 12,000 $ 3.95 Q1-Q4 2018 Western Canadian Select 75,490 $ (14.84) Q1-Q4 2019 Midland Sweet 27,000 $ (0.47)

Natural Gas Commodity Hedges Price Swaps Price Collars

Period Volume (MMBtu/d)

Weighted Average Price($/MMBtu)

Volume (MMBtu/d)

Weighted Average Floor Price ($/MMBtu)

Weighted AverageCeiling Price ($/MMBtu)

Q1-Q4 2018 371,956 $ 3.06 197,516 $ 2.94 $ 3.26 Q1-Q4 2019 28,466 $ 2.98 28,466 $ 2.84 $ 3.14

Natural Gas Basis Swaps

Period Index Volume (MMBtu/d) Weighted Average Differential to

Henry Hub ($/MMBtu) Q1-Q4 2018 Panhandle Eastern Pipe Line 50,000 $ (0.29)

Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price. Devon’s natural gas derivatives settleagainst the Inside FERC first of the month Henry Hub index. Commodity hedge positions are shown as of December 31, 2017.

18

Highlights & CEO Perspective 2 2020 Vision: Strategic Priorities 3 2020 Vision: 3-Year Outlook 4 2018 Detailed Guidance 6 Q4 2017 Key Modeling Stats 8 Q4 2017 Operating Results 9 Delaware Basin11 STACK15 Rockies19 Cash Flow Generating Assets21 Q4 2017 Operations Report February 20, 2018 NYSE: DVN devonenergy.com Exhibit 99.2

Highlights & CEO Perspective Dave Hager President & CEO Three-Year Outlook >15% corporate-level rates of return $2.5 billion of cumulative free cash flow through 2020 Per-unit cash cost savings of ~15 percent by 2020 Potential to monetize >$5 billion of non-core assets Positioned for sustainable increase of cash to shareholders 2018 Guidance Self-funded budget at $50 WTI Delaware & STACK oil growth: >35% Up to $1.5 billion of debt-reduction Operational Highlights Current daily rates in Delaware & STACK: ~195 MBOED Multi-zone projects progressing on plan Anaconda project reaches peak rates Showboat attains 30% drilling efficiencies Initial Coyote well: 24-hour IP 8,200 BOED CEO Perspective Devon’s “Inflection Point” Since I joined Devon a decade ago, we have aggressively reshaped our portfolio to have scalable positions in the very best plays on the North American cost curve. Now with our world-class assets in the Delaware and STACK shifting to full-field development, I can confidently state that Devon has reached an “inflection point” as a company. In 2018 and beyond, as we concentrate investment in the economic core of the Delaware and STACK, we expect to deliver a dramatic “step change” in capital efficiency that is self-funded at $50 WTI pricing. With this disciplined multi-year plan, which we have branded as our “2020 Vision”, Devon will accelerate value creation through the pursuit of capital-efficient cash-flow growth, not top-line production growth. This disciplined plan will be reinforced by our recently approved management incentives program which will prioritize corporate-level returns within our compensation framework. For more commentary on the principles supporting the 2020 Vision, our 3-year outlook and management compensation details, I encourage every investor to read pages 3-5 in this report.

2020 Vision: Strategic Priorities Leverage technology to optimize base production and aggressively reduce per-unit cash costs. Optimize returns across the portfolio through more measured and consistent capital investment in the Delaware & STACK. Bring forward value by monetizing non-core assets at the appropriate value as market conditions allow. Sustainably return increasing amounts of cash to shareholders through higher dividends and opportunistic share buybacks. Maximize cash flow Focus on capital efficiency Portfolio simplification Improve financial strength Return cash to shareholders TOP OBJECTIVES: OPTIMIZE RETURNS & DELIVER CAPITAL-EFFICIENT, CASH-FLOW GROWTH Attain a top-tier balance sheet in the E&P space by targeting a net debt to EBITDA ratio of 1.0x - 1.5x and maintain the ratio in a sustained $50 WTI price environment.

2020 Vision: 3-Year Outlook >15% CORPORATE LEVEL RETURNS >25% CAGR DELAWARE + STACK OIL PRODUCTION FREE CASH FLOW GENERATION ABOVE $50 WTI & $3 HH ~15% COST SAVINGS EXPECTED BY 2020 PORTFOLIO SIMPLIFICATION POTENTIAL FOR >$5 BILLION OF ASSET DIVESTITURES 1.0x-1.5x NET DEBT TO EBITDA >15% CAGR UPSTREAM CASH FLOW PER-UNIT CASH SHAREHOLDER RETURNS $2.5 BILLION OF CUMULATIVE FREE CASH FLOW AT $60 WTI (See page 7 – “Strategic Deployment of Excess Cash”) MID-TEENS CAGR U.S. OIL PRODUCTION 1) 3-year performance targets reflect capabilities of current asset portfolio and do not include assumptions for divestitures. See page 5 for return measure targets and calculations. 3-YEAR PERFORMANCE TARGETS(1) (ASSUMING $50 WTI & $3 HENRY HUB)

2020 Vision: Management Incentives In an effort to further refine performance management within Devon, the company has modified its compensation program to prioritize two new targets that measure rate of return. These return measures will fully support Devon’s top strategic objective of capital-efficient, cash-flow growth (see details below). Additionally, the company will provide transparency to the results associated with these performance metrics through its published financial statements and increased operational disclosures on a quarterly basis. ALIGNING COMPENSATION WITH SHAREHOLDERS Cash Flow from Operations + After-tax Interest Expense + EnLink Distributions Average Book Equity + Average Net Debt Internal rate of return on capital investment over 2 year period, after burdening for G&A and corporate costs RETURN MEASURE #1 CASH RETURN ON CAPITAL EMPLOYED RETURN MEASURE #2 RETURN ON CAPITAL PROGRAM = 20% TARGET = 15% TARGET

2018 Detailed Guidance Shift to Development Mode Drives Capital Efficiency Higher In 2018, Devon’s E&P capital investment is expected to range from $2.2 to $2.4 billion (see table). Nearly 90% of the capital expenditures are devoted to U.S. resource plays, with the vast majority concentrated in the Delaware Basin and STACK. The 2018 program will deliver a step-change improvement in capital efficiency resulting from the shift to full-field development in the Delaware Basin and STACK, where the company expects to bring online >25% more wells year over year. This disciplined capital program is expected to be self-funded at a $50 WTI price deck and Devon has no plans to increase activity levels with higher prices. Delaware & STACK Oil Growth >35% In 2018, on a retained asset basis, Devon expects to increase U.S. oil production by 14% compared to 2017 (based on midpoint guidance). The trajectory of Devon’s U.S. oil production profile is expected to steadily advance throughout the year and exit 2018 at rates >25% above the 2017 average. This high-returning capital program is expected to increase oil production in the Delaware and STACK by >35% in 2018 and to drive per-unit costs lower throughout the year. Key Messages Self-funded at $50 WTI Step-change in capital efficiency Bring online >25% more wells YoY Delaware & STACK oil growth of >35% Up to $1.5 billion of debt-reduction 2018 CAPITAL OUTLOOK E&P CAPITAL ($MM) NEW WELLS ONLINE (Operated) Delaware Basin $725 >100 STACK $700 >100 Canada $275 n/a Eagle Ford $250 60(1) Rockies $150 20 Barnett $50 n/a Technology & Land $100 n/a Total $2,200 - $2,400 (1) Includes partner activity.

2018 Detailed Guidance Strategic Deployment of Excess Cash The company’s top capital allocation priority in 2018 is to fund its operational plans in the Delaware Basin and STACK as these early-stage assets transition to full-field development. The company’s next priority will be to utilize a portion of its strong liquidity position ($2.7 billion of cash) to reduce its debt balances by up to $1.5 billion. Devon will finalize size and timing of its initial debt repurchase program in the coming weeks. Looking beyond the debt repurchase plan in 2018, the company plans to return future excess cash flow to shareholders through share buybacks and dividend growth. Q1 2018 Capital and Production Outlook Devon’s E&P activity in Q1 is expected to result in ~$600 million of capital expenditures. This level of investment is projected to be the highest quarterly spend rate in 2018 due to seasonal drilling in Canada and timing of completion activity in the Eagle Ford. The capital spend for the remaining 3 quarters of 2018 is estimated to average ~$550 million per quarter. Excluding the Eagle Ford, Q1 oil production from Devon’s U.S. resource plays is expected to increase by >15% compared to Q4 2017. Timing of new well connects in the Eagle Ford (see discussion pg. 22) and severe winter weather in January are expected to impact Q1 production by ~10,000 barrels per day. Overall, total oil production is expected to be relatively stable compared to Q4, ranging between 242,000 and 252,000 barrels per day. Q1 2018 OIL PRODUCTION (MBOD) Q4 2017 Actual 246 U.S. resource play growth (excluding Eagle Ford) 16 Severe winter weather in U.S. (~5 MBOED impact) (2) Eagle Ford well timing (>30 new wells in Q2 2018) (8) Canada (higher royalties and performance) (5) Q1 2018 Guidance (based on midpoint) 247

Q4 2017 Key Modeling Stats Q4 RESULTS Q4 GUIDANCE Q4 ACTUALS U.S. oil (MBbls/d) 120 - 125 114 Canada oil (MBbls/d) 135 - 140 132 Total NGLs (MBbls/d) 99 - 103 106 Total gas (MMcf/d) 1,184 - 1,216 1,175 Total (MBoe/d) 551 - 571 548 Marketing & midstream operating profit $245 - $265 $272 LOE, gathering & transportation $360 - $410 $399 General & administrative expenses N/A(1) $222 Production and property taxes $65 - $75 $64 Depreciation, depletion & amortization N/A(1) $528 Net financing costs $120 - $130 $126 Exploration & development capital N/A(1) $648 (1) Guidance is not applicable due to the conversion to successful efforts in Q4. (2) Wells achieving 1st production in the quarter (not 30-day IP rates). Q4 OPERATIONAL DETAIL DELAWARE BASIN STACK ROCKIES EAGLE FORD BARNETT HEAVY OIL Oil (MBbl/d) 32 30 15 27 1 132 NGL (MBbl/d) 13 34 1 13 42 - Gas (MMcf/d) 89 316 17 87 638 15 Total (MBoe/d) 60 117 19 55 149 134 Exploration & development capital $153 $230 $66 $41 $25 $80 LOE & transportation costs per Boe $7.73 $4.55 $10.02 $5.25 $7.47 $11.69 Operated development rigs (12/31/17) 8 9 1 n/a - Operated spuds (Q4/YTD) 22/72 37/95 10/23 9/31 3/5 Operated wells tied-in (Q4/YTD) (2) 20/50 27/100 11/20 3/65 2/2 Note: all dollars shown in millions. BARNETT STACK EAGLE FORD DELAWARE BASIN ROCKIES HEAVY OIL

Q4 2017 Operating Results Devon’s production averaged 548,000 Boe per day in the fourth quarter (64% liquids). Q4 oil production totaled 246,000 barrels per day. This result was 14,000 barrels per day below midpoint guidance (see table). During the quarter, Devon’s U.S. oil production was limited by ~9,000 barrels per day primarily due to the timing of well tie-ins associated with non-operated partner activity in the STACK. February 2018 Production Update In aggregate, current daily rates in the Delaware and STACK have increased to 195,000 Boe per day. This represents a ~20% increase compared to 2017. In the STACK, the tie-in of >50 non-operated wells around year-end helped increase current rates to 130,000 BOED. With a 2nd dedicated frac crew added in Q4, current production in the Delaware Basin has increased to ~65,000 Boe per day. Timing of Non-Operated Activity Limits Volumes in Q4 The timing of non-operated well tie-ins was attributable to multiple partners in the STACK. These wells are now online (see “February 2018 Production Update” in previous section). In Canada, net production averaged 134,000 Boe per day in Q4. Facility modifications and temporary steam constraints at Jackfish curtailed production by ~5,000 barrels per day in the fourth quarter. 164 Delaware & STACK Production MBOED GROWTH ACCELERATES 7% (vs. 2017) ~20% (vs. 2017) Q4 2017 OIL VARIANCE (MBOD) Q4 2017 Guidance (based on midpoint) 260 STACK well timing (non-operated) (6) Other U.S. resource plays (3) Jackfish complex maintenance (5) Q4 2017 Actual 246

Q4 2017 Operating Results Drill-Bit Success Drives U.S. Oil Reserves 32% Higher At Dec. 31, 2017, Devon’s proved reserves totaled 2.2 billion Boe (81% proved developed). Of this amount, 1.7 billion Boe of reserves resided within Devon’s U.S. resource plays, which exhibited strong growth by adding 327 million Boe of reserves. The highest reserve growth in the U.S. came from oil, which advanced 32% year over year. This increase in oil reserves was driven by drill-bit success in the Delaware Basin and STACK. Overall, the company achieved a reserve replacement rate in the U.S. of ~215% during 2017, at a F&D cost of only $5 per Boe. Outstanding Operated Well Productivity in Q4 Importantly, Devon’s operated wells in Q4 were delivered on plan and with outstanding well productivity results. Devon’s top 30 operated wells in Q4 averaged 30-day IP rates of >2,500 Boe per day (~60% oil). This strong drill-bit productivity was highlighted by 12 STACK wells concentrated in the over-pressured oil window that achieved average 30-day rates of ~3,200 Boe per day (~55% oil). The company’s strong STACK well productivity in Q4 was highlighted by 5 prolific wells that attained 30-day rates of >4,000 Boe per day. (Each of these prolific wells tested different objectives that are discussed in greater detail on page 18). The Delaware Basin also delivered several high-rate oil wells. This activity was headlined by 6 Bone Spring wells around the state-line area that attained 30-day rates of 1,750 Boe per day (~70% oil). These strong wells in Q4 continue a trend of outstanding results that in aggregate for 2017 resulted in the best well productivity in the company’s 46-year history. Q4 HIGH-RATE WELLS 30 WELLS 2,500 > AVG. 30-DAY IP: BOED

Delaware Basin Highlights Current daily rates ~65 MBOED Exit rate growth of >40% in 2018 Production ramps at Anaconda Record drilling times at Boomslang Wolfcamp drilling activity accelerates in Rattlesnake area Momentum Builds with 2nd Frac Crew Net production increased to 60,000 Boe per day in Q4. With a 2nd dedicated frac crew added in Q4, Devon accelerated well tie-ins around year-end and current daily rates are ~65,000 Boe per day. Growth in Q4 was driven by the ramp-up of the Anaconda project (see pg. 12) and several high-rate wells near the NM state line. The state line activity was highlighted by 6 Bone Spring wells that attained IP30’s of 1,750 BOED, at a cost of $5.4 million per well. In 2018, Devon expects to invest around $725 million in the Delaware Basin, a ~50% increase in capital investment versus 2017. With this development-focused capital plan, the company expects the 2018 program to deliver its highest returns and most consistent well results to date in the basin. During the year, Devon expects to drill and tie-in >100 operated wells. The average lateral length associated with this activity will be ~7,500 feet. High-Return Production Growth Expected in 2018 This drilling activity will be balanced between the company’s 3 most economic formations, the Leonard Shale, Bone Spring and Wolfcamp near the state-line area. As a result of these higher activity levels in the economic core of the play, production in the Delaware is expected to deliver exit rate growth >40% in 2018. As production rapidly grows in the upcoming year, per-unit LOE is expected to decline by >10% on a year-over-year basis. Delaware Production MBOED EXIT RATE GROWTH >40%

DELAWARE BASIN DEVELOPMENT ACTIVITY Delaware Basin Production Ramps at Anaconda A key driver of production growth in Q4 was the Anaconda project, which is Devon’s 1st multi-zone development in the Delaware. The 10-well project, which co-developed 3 Leonard intervals, attained average per-well 30-day rates of ~1,600 BOED (65% oil). At Anaconda, the company realized cost savings of $1 million per well compared to traditional pad development activity. Centralized processing facilities, faster drill times and completion efficiencies (up to 13 stages per day) drove the savings. Also contributing to the strong return profile of this project was a short cycle time (spud to 1st production) of only 5.8 months. Multi-Zone Development Activity Building Momentum in 2018 In addition to the Anaconda project, Devon has 6 additional multi-zone developments that are scheduled for 2018, along with several other projects that are ready for development in the near future (see map). Approximately 70% of the company’s capital activity in 2018 will be associated with multi-zone development projects. Devon estimates that efficiency gains, improved recoveries and short cycle times with multi-zone developments will dramatically increase NPV on a per-section basis. ANACONDA 10-WELL AVG. 30-DAY IP ~1,600 BOE PER DAY

Delaware Basin Record Drilling Efficiencies at Boomslang Another key multi-zone project is the 11-well Boomslang project in the Thistle area, which is co-developing both the Leonard Shale and multiple Bone Spring intervals. Devon’s 2-rig drilling program at Boomslang concluded in early 2018, with rig productivity reaching nearly 1,400 feet drilled per day. This record-setting drill time represents a ~15% improvement in feet drilled per day compared to the company’s Anaconda project. Completion work is currently underway with 7 of the 11 wells at Boomslang in the early stages of flowing back. The cycle time at Boomslang from spud to 1st production was on par with the Anaconda project at ~6 months. The company expects to attain peak 30-day production rates for the entire Boomslang project during Q2. Wolfcamp Activity Advances in World-Class Rattlesnake Area Devon also continues to advance its initial Wolfcamp multi-zone development within its world-class Rattlesnake leasehold. With this development, called the Seawolf project, the company is drilling a 12-well pattern on multiple Wolfcamp intervals. A 3-rig drilling program is underway and is expected to conclude by the end of March. Completion activity at Seawolf is scheduled for Q2, with 1st production expected in 2H 2018. Seawolf offsets Devon’s prolific Fighting Okra Wolfcamp well. The Fighting Okra infill program will also progress in 2018 and be a key contributor to production growth in 2019 (see map pg. 12). BONE SPRING 3rd WOLFCAMP XY A UPPER MIDDLE LOWER Seawolf Development - Rattlesnake Area (Testing 28-wells per section across 5 landing zones) Initial Development Future Potential

Delaware Basin Future Projects Accelerated by Innovative Permitting Strategy Devon possesses massive resource upside in the Delaware Basin with up to 15 different prospective intervals across 300,000 surface acres or >1.3 million net effective acres. To accelerate permitting associated with Devon’s multi-zone development plans, the company has submitted 7 of its 10 master development plans (MDPs) to regulatory agencies. These MDPs are designed to accommodate up to 1,600 future drilling permits. This innovative permitting strategy consists of submitting a comprehensive regional development plan to the BLM for approval, expediting the approval of future drilling activity. To date, Devon has received approval for 4 of these MDPs and the company expects to receive several additional MDP approvals during 2018. Multi-Zone Projects Progressing as Planned In addition to the Boomslang and Seawolf projects (discussed on page 13), Devon has several other multi-zone projects that are scheduled for 2018 (timeline below). Q1-2018 Q2-2018 Q3-2018 Q4-2018 Boomslang (11 well pattern across 3 intervals in the Leonard Shale and Bone Spring) Drilling Completion Production Drilling Completion Production Drilling Completion Fighting Okra (12 well pattern across 6 intervals in the Leonard Shale and Wolfcamp) Completion Production Production Seawolf (12 well pattern across 4 Wolfcamp intervals ) Lusitano (6 well pattern across multiple intervals in the Leonard, Bone Spring and Wolfcamp) Drilling Completion Medusa (13 well pattern across 3 intervals in the Leonard Shale and Bone Spring) Production Snapping (6 well pattern across 2 intervals in the Leonard Shale) Drilling Completion

STACK Highlights Current daily rates ~130,000 BOED STACK oil production advances 52% YoY Five wells exceed rates of 4,000 BOED Showboat drilling efficiencies reach 30% Initial Coyote well achieves 24-hour IP of 8,200 BOED Production Accelerates in Early 2018 Devon’s STACK production averaged 117,000 Boe per day in Q4, with daily rates exiting 2017 at >120,000 Boe per day. Production growth further accelerated in early 2018, primarily due to the company’s participation in >50 non-operated wells that achieved 1st production. The higher non-operated activity, combined with operated wells brought online in early 2018, has grown current daily rates to ~130,000 Boe per day. This represents a >10% increase compared to Q4 2017. In Q4, top-line production in the STACK increased 33% compared to the year-ago period. The most significant growth was driven by a 52% increase in oil production. A key driver of volume growth in Q4 was 12 high-rate operated wells brought online that averaged 30-day IP’s of ~3,200 Boe per day. These prolific wells were disbursed across 5 different landing intervals primarily within the over-pressured oil window of the play (see map). Meramec Oil Window Delivers Outstanding Well Results in Q4 11 McCarthy 2H IP 30: 2,100 BOED 12 McCarthy 1H IP 30: 2,150 BOED Kraken IP 30: 2,000 BOED Molly Grace IP 30: 1,900 BOED 1 2 3 4 5 Lookabaugh IP 30: 5,100 BOED Cassowary IP 30: 4,850 BOED Faith Marie IP 30: 4,700 BOED Birch IP 30: 4,600 BOED Brachiosauras IP 30: 2,300 BOED 6 7 8 9 10 Big Earl IP 30: 2,300 BOED Sphinx IP 30: 1,850 BOED Marcia IP 30: 4,000 BOED KEY Q4 STACK WELL RESULTS & UPCOMING ACTIVITY

STACK Full-Field Development Accelerates: 7 Projects Scheduled for 2018 As Devon’s STACK assets transition from appraisal to full-field development, an increasing amount of go-forward capital will be devoted to larger, multi-zone projects. In 2018, the company expects to bring online >100 operated wells with ~60% of capital activity related to multi-zone development activity (see timeline below). These projects are concentrated in the core of the over-pressured oil window that has consistently generated superior economics compared to other portions of the STACK play. Q1-2018 Q2-2018 Q3-2018 Q4-2018 Showboat (24 well development across 3 intervals in Meramec and 1 Woodford zone) Drilling Completing Producing Drilling Completing Producing Coyote (7 well development in Lower Meramec) Drilling Completing Kraken (16 wells across 3 intervals in Meramec and 1 Woodford zone) Completing Producing Horsefly (10 well development across 3 Meramec intervals) Bernhardt (8 well development across 3 Meramec intervals) Producing Completing Activity Shifting to Meramec Oil Window Devon expects to invest ~$700 million of capital in the STACK during 2018, with >95% allocated to oil-driven Meramec activity. With this development-focused capital plan, the company expects the 2018 program to deliver its highest returns and most consistent well results to date in the play. As a result of activity concentrated in the core of the play, oil production is expected to deliver exit-rate growth of >40% for 2018. Additionally, the company expects unit LOE costs to improve by ~10% compared to 2017. Note: Other development projects scheduled to spud in 2018 include the Geis and Cascade projects (see map on pg. 17) STACK Production MBOED >140 (>40% oil growth)

STACK DEVELOPMENT ACTIVITY STACK Drilling Efficiencies Reach 30% at Showboat Devon’s initial multi-zone STACK development, the Showboat project, consists of 24 wells across 2 drilling units in the over-pressured oil window (see map). The 5-rig drilling program at Showboat concluded in January with average rig productivity of >1,000 feet drilled per day. The rig productivity represents a 30% increase in feet drilled per day, translating into savings of $500,000 per well compared to prior activity in the play. Drilling activity was headlined by the Mosasaurus 13-H, which achieved a spud to rig release time of only 9 days. Showboat Completion Activity Underway In early February, completion activity began at Showboat with 4 frac crews onsite. To maximize completion efficiencies, Devon will utilize zipper fracs on up to 3 wells concurrently with the same crew. The technique is projected to materially shrink the duration between pumping frac stages and drive faster completion times. Initial production results at Showboat are expected in Q2, resulting in a cycle time of less than 9 months. Initial Coyote Well IP’s at 8,200 BOED At the 7-well Coyote project in Blaine County the company achieved significant drilling efficiencies. Feet drilled per day improved by up to 25% ($1 million savings) compared to the offsetting Faith Marie well. Devon initiated completion operations at Coyote in early 2018. The company’s initial well from the Coyote development is now flowing back, achieving a 24-hour IP of 8,200 Boe per day (>60% oil).

STACK Best-In-Class STACK Position: Ownership in 90% of Top 50 Wells Devon has the premier STACK position in the industry with >600,000 net acres by formation in the core of the play providing the opportunity to deliver repeatable, high-returning wells for the foreseeable future. Across the STACK, the company has identified 5,700 risked drilling locations concentrated within the most economic portions of the Meramec and Woodford plays. The quality of Devon’s position in this early-stage development play is evidenced by its prolific Q4 results (see “Prestigious 4000 Club” section) and ownership interest in 45 out of the top 50 most productive wells in the STACK. The Prestigious “4000” Club The company’s strong operated well productivity in Q4 was highlighted by 5 prolific wells in the STACK play that exceeded 4,000 Boe per day (see map pg. 15). The highest-rate well was the Lookabaugh 25-1H, which achieved a 30-day rate of 5,100 Boe per day. This Upper Meramec well extends the economic core of the oil window further into Blaine county. The Cassowary well (IP30 4,850 BOED), located in Kingfisher county, was Devon’s first 3-mile lateral in the play and is the longest producing lateral in Oklahoma. Another noteworthy well, the Faith Marie 1-H had a 30-day rate of 4,700 Boe per day. This is the highest productivity of any well to date targeting the Lower Meramec interval. Further to the west in the condensate window within Blaine County, the Birch 36-1H achieved peak rates of 4,600 Boe per day. The Marcia 11-H well targeted the Woodford formation in the liquids-rich gas window. A larger, improved completion design drove the 30-day rate to 4,000 Boe per day. 45 OF TOP 50 STACK WELLS OWNERSHIP INTEREST IN

Rockies Highlights Production advances 26% in Q4 Turner spacing tests online Super Mario activity accelerates in 2018 Niobrara delineation activity underway Super Mario Highlights Q4 Activity Production averaged 19,000 Boe per day, a 26% increase compared to Q3 2017. Production growth in Q4 was driven by Turner appraisal activity in the Super Mario area (map right). Activity at Super Mario in Q4 was highlighted by a 4 well Turner spacing test. Normalized for 10,000’ laterals, these wells averaged facility constrained 30-day rates of >1,500 Boe per day (~80% oil). In development mode, Turner well productivity in the Super Mario area is expected to improve by >20%. POWDER RIVER BASIN ACTIVITY (1) All activity normalized for 10,000’ laterals

Rockies Niobrara Appraisal Underway Devon possesses significant upside potential in the Powder River Basin with ~400,000 net surface acres and >10 different prospective intervals identified across its acreage position. To further define the potential across this stacked-pay asset, the company will begin appraising the Niobrara formation with several wells in 2018. The first appraisal well (2-mile lateral) recently hit target depth under budget with initial flow-back results expected around mid-year. To improve upon historical Niobrara well productivity and returns in the area, Devon will deploy a larger, more advanced completion design. This well design will utilize >3,000 pounds of proppant per lateral foot with tighter perf clusters to increase stimulated rock volume around the well bore. 2018 Outlook: Super Mario Area Builds Momentum In 2018, Devon expects its capital investment in the Rockies to be ~$150 million and expects to spud ~20 new wells. The majority of capital activity in 2018 (~75%) will be concentrated on high-return Turner opportunities advancing the Super Mario area toward development mode. With this level of investment, production in the Rockies is expected to advance by >10% in 2018 compared to 2017. This production increase is driven by higher activity levels across the Super Mario area. UPCOMING POWDER RIVER BASIN ACTIVITY

Cash Flow Generating Assets Summary Devon possesses top-tier cash flow generating assets in North America (see graphic) and the company’s strategy with these assets is two-fold: 1) Efficiently manage base production and maintain a low cost structure. 2) Redeploy harvested cash flow into Delaware Basin and STACK growth opportunities. These high-quality assets cumulatively generated $2.3 billion of cash flow in 2017.(1) The upstream capital requirement to deliver this cash flow in 2017 was $480 million. HEAVY OIL BARNETT EAGLE FORD 30% EAGLE FORD 20% BARNETT 15% ENLINK $2.3B(1) CASH FLOW 2017 35% HEAVY OIL (1) Represents field-level cash flow before G&A and taxes.

Cash Flow Generating Assets Eagle Ford Partner Completion Activity to Accelerate in Q2 2018 Net production in the Eagle Ford averaged 55,000 Boe per day in Q4. The sale of Lavaca County impacted production by 3,000 Boe per day. For the full-year 2018, the company is budgeting a capital investment of $250 million for its non-operated Eagle Ford interest. This assumes a 2-rig program and ~60 new wells brought online. Due to the timing of well tie-ins, the company expects production in the first quarter to decline to ~40,000 Boe per day. In Q2 2018, Devon expects its partner to accelerate completion activity and bring online >30 new wells, boosting production to a ~55,000 Boe per day. Heavy Oil Attractive WCS Hedges Underpin Strong Cash Flow in 2018 For 2018, Devon expects net production to range from 127,000 to 133,000 Boe per day. The outlook includes a planned turnaround at Jackfish 1 (~15,000 BOD impact in Q2 2018). This production outlook in 2018 assumes an 7% royalty rate based on current market pricing compared to a 5% rate in 2017. To protect cash flow, the company secured WCS basis swaps on ~50% of its estimated production in 2018 at $15 off WTI pricing. With the company’s production outlook for the year, coupled with the attractive WCS basis swaps, Devon expects to generate ~$400 million of free cash flow in 2018 (see table). In the first quarter, Devon projects its Canadian net oil production to range from 125,000 to 130,000 barrels per day, with ~85% derived from the company’s Jackfish complex. 2018e CASH FLOW ($MM) Upstream Revenue ~$1,000 WCS Hedges $300 Production Expenses ($650) Cash Flow $650 CapEx ($275) Free Cash Flow ~$400 Note: Assumes $60 WTI & $25 differential.

Cash Flow Generating Assets Barnett Shale Johnson County Divestiture Package Progressing Net production averaged 149,000 Boe per day or 894 MMcfe per day during Q4. Capital activity in the quarter was highlighted by a 6-well drilling pilot primarily centered in Denton County that leveraged an improved completion design. Initial 30-day production rates from this 6-well pilot program attained per-well rates as high as 6,500 Mcfe per day, with capital costs of ~$3 million per well. To bring forward value in the Barnett Shale, Devon is working toward monetizing select leasehold in Johnson County and surrounding areas. Net production associated with these assets is ~200 MMcfe per day. Data rooms for Johnson County were opened in September and multiple bids were received during Q4. The company is currently in advanced negotiations with a preferred buyer and a sale announcement is expected by the end of Q1 2018. EnLink Midstream Midstream Profitability Expected to Expand by 20% in 2018 Devon’s midstream business generated $272 million of operating profit in Q4 2017. For the full year 2017, midstream operating profit reached $912 million, a 15% increase compared to 2016. In aggregate, Devon received ~$270 million in distributions from EnLink during 2017, and the company’s investment in EnLink has a market value of ~$3.5 billion (table right). For 2018, the company expects its midstream operating profit to expand by ~20% compared to 2017. This growth is entirely driven by the company’s investment in EnLink. DEVON’S OWNERSHIP MARKET VALUE ($B) ENLC (115 MM Units) $2.0 ENLK (95 MM Units) $1.5 DVN’s Ownership $3.5 As of February 2018

Contacts & Investor Notices Investor Relations Contacts Scott CoodyChris Carr VP, Investor RelationsSupervisor, Investor Relations 405-552-4735405-228-2496 Email: [email protected] Forward-Looking Statements This presentation includes "forward-looking statements" as defined by the Securities and Exchange Commission (the “SEC”). Such statements include those concerning strategic plans, expectations and objectives for future operations, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. Statements regarding our business and operations are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to: the volatility of oil, gas and NGL prices; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; the uncertainties, costs and risks involved in oil and gas operations; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate our oil and gas properties; midstream capacity constraints Investor Notices and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for leases, materials, people and capital; our ability to successfully complete mergers,acquisitions and divestitures; and any of the other risks and uncertainties identified in our Form 10-K and our other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this presentation are made as of the date of this presentation, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. Use of Non-GAAP Information This presentation may include non-GAAP 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. For additional disclosure regarding such non-GAAP measures, including reconciliations to their most directly comparable GAAP measure, please refer to Devon’s fourth-quarter 2017 earnings release at www.devonenergy.com. Cautionary Note to Investors The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This presentation may contain certain terms, such as resource potential, potential locations, risked and unrisked locations, estimated ultimate recovery (EUR), exploration target size and other similar terms. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com. You can also obtain this form from the SEC by calling 1-800-SEC-0330or from the SEC’s website at www.sec.gov.

Exhibit 99.3

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS Quarter ended December 31, 2017 Full Cost Changes Successful Efforts (millions) Upstream revenues $ 1,333 — $ 1,333 Marketing and midstream revenues 2,650 — 2,650

Total revenues 3,983 — 3,983

Production expenses 463 — 463 Exploration expenses — 171 171 Marketing and midstream expenses 2,378 — 2,378 Depreciation, depletion and amortization 417 111 528 Asset impairments 8 — 8 Asset dispositions 1 (19) (18) General and administrative expenses 174 48 222 Financing costs, net 124 2 126 Other expenses 15 (10) 5

Total expenses 3,580 303 3,883

Earnings before income taxes 403 (303) 100 Income tax benefit (191) (13) (204)

Net earnings 594 (290) 304 Net earnings attributable to noncontrolling interests 121 — 121

Net earnings attributable to Devon $ 473 (290) $ 183

Net earnings per share attributable to Devon: Basic $ 0.90 $ (0.55) $ 0.35 Diluted $ 0.89 $ (0.54) $ 0.35

Devon’s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of thecompany’s financial results. Accordingly, the company also uses the measures of core earnings and core earnings per share attributable to Devon. Devonbelieves these non-GAAP measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believesthese non-GAAP measures can facilitate comparisons of its performance between periods and to the performance of its peers. The table below summarizesthe effects of these items on fourth-quarter 2017 earnings.

Earnings attributable to Devon (GAAP) $ 0.89 $ (0.54) $ 0.35 Adjustments:

Asset dispositions — (0.02) (0.02) Asset and exploration impairments 0.01 0.17 0.18 U.S. tax reform (0.21) — (0.21) Deferred tax asset valuation allowance 0.04 0.14 0.18 Fair value changes in financial instruments and foreign currency 0.06 — 0.06 Legal entity restructuring (0.16) — (0.16)

Core earnings attributable to Devon (Non-GAAP) (1) $ 0.63 $ (0.25) $ 0.38

(1) This non-GAAP measure is not an alternative to the GAAP measure, and you should not consider this non-GAAP measure in isolation or as a substitutefor analysis of our results as reported under GAAP. This measure is additional disclosure regarding the non-GAAP measures used, includingreconciliations to their most directly comparable GAAP measure.


CONSOLIDATED STATEMENTS OF CASH FLOWS Quarter Ended December 31, 2017 Full Cost Changes Successful Efforts (millions) Cash flows from operating activities:

Net earnings $ 594 (290) $ 304 Adjustments to reconcile net earnings to net cash from operating activities:

Depreciation, depletion and amortization 417 111 528 Exploratory dry hole expense and unproved leasehold impairments — 139 139 Asset impairments 8 — 8 Gains and losses on asset sales 1 (19) (18) Deferred income tax benefit (232) (13) (245) Commodity derivatives 57 — 57 Cash settlements on commodity derivatives 10 — 10 Other derivatives and financial instruments 7 — 7 Cash settlements on other derivatives and financial instruments (6) — (6) Asset retirement obligation accretion 15 — 15 Share-based compensation 36 11 47 Other 26 (10) 16 Net change in working capital (73) — (73) Change in long-term other assets (58) — (58) Change in long-term other liabilities (6) — (6)

Net cash from operating activities 796 (71) 725

Cash flows from investing activities: Capital expenditures (871) 72 (799) Acquisitions of property, equipment and businesses (7) — (7) Divestitures of property and equipment 102 (1) 101 Other (7) — (7)

Net cash from investing activities (783) 71 (712)

Cash flows from financing activities: Borrowings of long-term debt, net of issuance costs 168 — 168 Repayments of long-term debt (168) — (168) Issuance of subsidiary units 15 — 15 Dividends paid on common stock (32) — (32) Contributions from noncontrolling interests 10 — 10 Distributions to noncontrolling interests (107) — (107) Shares exchanged for tax withholdings (1) — (1)

Net cash from financing activities (115) — (115)

Effect of exchange rate changes on cash (6) — (6)

Net change in cash and cash equivalents (108) — (108) Cash and cash equivalents at beginning of period 2,781 — 2,781

Cash and cash equivalents at end of period $ 2,673 — $ 2,673


CONSOLIDATED BALANCE SHEETS December 31, 2017

FullCost Changes Successful Efforts

(millions, except share data) ASSETS

Current assets: Cash and cash equivalents $ 2,673 — $ 2,673 Accounts receivable 1,670 — 1,670 Other current assets 448 — 448

Total current assets 4,791 — 4,791 Oil and gas property and equipment, based on successful efforts accounting, net 9,702 3,616 13,318 Midstream and other property and equipment, net 7,853 — 7,853

Total property and equipment, net 17,555 3,616 21,171 Goodwill 3,964 (1,581) 2,383 Other long-term assets 1,896 — 1,896

Total assets $28,206 2,035 $ 30,241

LIABILITIES AND EQUITY Current liabilities:

Accounts payable $ 819 — $ 819 Revenues and royalties payable 1,180 — 1,180 Short-term debt 115 — 115 Other current liabilities 1,201 — 1,201

Total current liabilities 3,315 — 3,315

Long-term debt 10,291 — 10,291 Asset retirement obligations 1,113 — 1,113 Other long-term liabilities 583 — 583 Deferred income taxes 434 401 835 Equity:

Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 525 million shares in 2017 53 — 53 Additional paid-in capital 7,206 127 7,333 Retained earnings 44 658 702 Accumulated other comprehensive earnings 317 849 1,166

Total stockholders’ equity attributable to Devon 7,620 1,634 9,254 Noncontrolling interests 4,850 — 4,850

Total equity 12,470 1,634 14,104

Total liabilities and equity $28,206 2,035 $ 30,241


CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS 2017, under Successful Efforts First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (millions, except per share amounts) Upstream revenues $ 1,541 $ 1,332 $ 1,101 $ 1,333 $ 5,307 Marketing and midstream revenues 2,010 1,927 2,055 2,650 8,642

Total revenues 3,551 3,259 3,156 3,983 13,949

Production expenses 457 455 448 463 1,823 Exploration expenses 95 57 57 171 380 Marketing and midstream expenses 1,814 1,714 1,824 2,378 7,730 Depreciation, depletion and amortization 528 506 512 528 2,074 Asset impairments 7 — 2 8 17 Asset dispositions (3) (27) (169) (18) (217) General and administrative expenses 233 214 203 222 872 Financing costs, net 128 116 128 126 498 Other expenses (33) (20) (76) 5 (124)

Total expenses 3,226 3,015 2,929 3,883 13,053

Earnings before income taxes 325 244 227 100 896 Income tax expense (benefit) 8 (1) 15 (204) (182)

Net earnings 317 245 212 304 1,078

Net earnings attributable to noncontrolling interests 14 26 19 121 180

Net earnings attributable to Devon $ 303 $ 219 $ 193 $ 183 $ 898

Net earnings per share attributable to Devon: Basic $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.71 Diluted $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.70

Devon’s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of thecompany’s financial results. Accordingly, the company also uses the measures of core earnings and core earnings per share attributable to Devon. Devonbelieves these non-GAAP measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believesthese non-GAAP measures can facilitate comparisons of its performance between periods and to the performance of its peers. The table below summarizesthe effects of these items on 2017 quarterly earnings.

Earnings attributable to Devon (GAAP) $ 0.58 $ 0.41 $ 0.37 $ 0.35 $ 1.70 Adjustments:

Asset dispositions (0.01) (0.03) (0.21) (0.02) (0.26) Asset and exploration impairments 0.06 0.02 0.02 0.18 0.27 U.S. tax reform — — — (0.21) (0.21) Deferred tax asset valuation allowance (0.19) (0.10) (0.04) 0.18 (0.14) Fair value changes in financial instruments and foreigncurrency (0.31) (0.20) 0.07 0.06 (0.38)

Legal entity restructuring — — — (0.16) (0.16) Early retirement of debt — (0.01) — — (0.01)

Core earnings attributable to Devon (Non-GAAP) (1) $ 0.13 $ 0.09 $ 0.21 $ 0.38 $ 0.81

(1) This non-GAAP measure is not an alternative to the GAAP measure, and you should not consider this non-GAAP measure in isolation or as a substitutefor analysis of our results as reported under GAAP. This measure is additional disclosure regarding the non-GAAP measures used, includingreconciliations to their most directly comparable GAAP measure.


CONSOLIDATED STATEMENTS OF CASH FLOWS 2017, under Successful Efforts First Quarter Second Quarter Third Quarter Fourth Quarter Full Year (millions) Cash flows from operating activities:

Net earnings $ 317 $ 245 $ 212 $ 304 $ 1,078 Adjustments to reconcile net earnings to net cash fromoperating activities:

Depreciation, depletion and amortization 528 506 512 528 2,074 Exploratory dry hole expense and unprovedleasehold impairments 42 22 16 139 219

Asset impairments 7 — 2 8 17 Gains and losses on asset sales (3) (27) (169) (18) (217) Deferred income tax benefit (12) (13) (24) (245) (294) Commodity derivatives (232) (126) 144 57 (157) Cash settlements on commodity derivatives 8 11 24 10 53 Other derivatives and financial instruments (9) 16 9 7 23 Cash settlements on other derivatives and financialinstruments (2) 2 — (6) (6)

Asset retirement obligation accretion 17 14 16 15 62 Share-based compensation 55 53 43 47 198 Other (6) (48) (84) 16 (122) Net change in working capital 15 72 7 (73) 21 Change in long-term other assets 1 9 2 (58) (46) Change in long-term other liabilities 20 2 (10) (6) 6

Net cash from operating activities 746 738 700 725 2,909

Cash flows from investing activities: Capital expenditures (653) (649) (658) (799) (2,759)

Acquisitions of property, equipment and businesses (20) (13) (6) (7) (46) Divestitures of property and equipment 32 76 208 101 417 Proceeds from sale of investment 190 — — — 190 Other (3) (1) (1) (7) (12)

Net cash from investing activities (454) (587) (457) (712) (2,210)

Cash flows from financing activities:

Borrowings of long-term debt, net of issuance costs 813 982 413 168 2,376 Repayments of long-term debt (587) (792) (571) (168) (2,118) Payment of installment payable (250) — — — (250) Early retirement of debt — (6) — — (6) Issuance of subsidiary units 55 17 414 15 501 Dividends paid on common stock (32) (33) (30) (32) (127) Contributions from noncontrolling interests 21 8 18 10 57 Distributions to noncontrolling interests (81) (82) (84) (107) (354) Shares exchanged for tax withholdings (61) (3) (3) (1) (68) Other (2) — — — (2)

Net cash from financing activities (124) 91 157 (115) 9

Effect of exchange rate changes on cash (8) 8 12 (6) 6

Net change in cash and cash equivalents 160 250 412 (108) 714 Cash and cash equivalents at beginning of period 1,959 2,119 2,369 2,781 1,959

Cash and cash equivalents at end of period $ 2,119 $ 2,369 $ 2,781 $ 2,673 $ 2,673

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