November 5, 2019 Q3 2019 Operations Report Exhibit 99.2

Q3 Summary – Efficiently Advancing the Business FINANCIAL RESULTS IMPROVING OUTLOOK OPERATING HIGHLIGHTS Operating cash flow increased 22% to $597 million (vs. Q2 2019) Repurchased $550 million of shares in Q3 ($4.8 billion since 2018) Outstanding share count to decline 30% by year-end (pg. 10) $100 million midstream transaction executed (pg. 12) Generated $56 million of free cash flow(1) in Q3 (pg. 3) Oil production exceeded top end of guidance (+19% vs. Q3 2018) Per-unit LOE improved 19% since Q3 2018 levels (pg. 4) Capital efficiency improvements accelerate in Delaware Basin (pg.16) Successful niobrara appraisal & spacing tests online (pg. 20) raising oil production guidance for the 3rd time in 2019 (pg. 5) Positioned for significant free cash flow in Q4 2019 (pg. 5) capital efficiency improvements highlight 2020 outlook (pgs. 7-9) (1) Free cash flow is a non-GAAP measure. Reconciliation provided in Q3 earnings materials.

Profitability continues to expand Share count (MM) and EBITDAX ($MM) EBITDAX ($MM) Share Count (MM) Share Count EBITDAX Share count down 27% EBITDAX up 30% Q3 2019 Change (vs Q2’19) Key Metrics(1) GAAP earnings (per share) Core earnings(2) (per share) EBITDAX(2) ($MM) $0.35 $0.29 $652 -13% +26% +4% Operating cash flow ($MM) Free cash flow(2) ($MM) Avg. basic share count (MM) $597 $56 397 +22% n/a -4% Q3 2019 – Financial Performance Profitability continues to expand in Q3 2019 Earnings and cash flow exceed consensus estimates Generated free cash flow of $56 million in quarter Key Financial Highlights Exceeded consensus estimates Represents results from Devon’s continuing operations. Refers to a non-GAAP measure. Reconciliation provided in Q3 earnings materials.

Beat Q3 midpoint guidance Q3 2019 – Operating Performance U.S. oil production(1) (MBOD) U.S. total production(1) (MBOED) Upstream capital ($MM) 148 325 $527(2) +19% +12% +1% WTI price ($/Bbl) Oil realizations (% of WTI) Q3 2019 (Continuing Ops.) $56.34 97% Change (vs. Q3’18) (Reported Results)(3) -19% +33% Key Metrics U.S. oil production exceeds guidance New Devon (MBOD) 148 (Q3 Guide: 141-147) 124 4,000 ABOVE MIDPOINT U.S. OIL PRODUCTION BARRELS PER DAY Represents New Devon performance (excludes Barnett Shale). Includes non-core upstream capital of $8 million. Represents reported amounts from Q3 2018, including discontinued operations. LOE & GP&T (per Boe) Prod. & property taxes ($MM) G&A expenses ($MM) Financing costs ($MM) $7.62 $68 $107 $60 -19% -32% -27% -25% G&A LOE & GP&T Interest Improving cost structure expands margins Per-unit cost (reported) ($/BOE) $11.86 $14.18 SINCE Q3 2018 DECLINE 16% Old DVN(3) DVN Today

Operational Success Driving Improved 2019 Outlook Scalable growth driving per-unit costs lower in Q4 Run-rate savings to reach >$200 million by year-end $1.7 billion debt redeemed YTD (annual interest savings: >$60 million) LOE & GP&T G&A Financing costs Lowering G&A expense outlook for 3rd time in 2019 Higher-cost Canadian assets exit portfolio Delaware, Eagle Ford and PRB to drive strong Q4 growth raising oil growth outlook for 3rd time in 2019 U.S. oil growth Q4 capital spending lower due to timing of completion activity Upstream capital Updated Guidance 20% – 21% (vs. 2018) $7.60 – $7.65 (per BOE) $460 – $470 ($ in millions) $245 – $255 ($ in millions) $1.83 – $1.87 ($ in billions) vs. Original Guidance Key Messages Represents New Devon performance target (excludes Barnett Shale). (1) (1) Improvement 15% Improvement 17% Improvement 22% Improvement Evaluating next steps for debt reduction program $50 Basis Point 550 Million Improvement Improved outlook Expect free cash flow to accelerate in Q4 2019

Strategic Framework for the 2020 Planning Cycle CAPITAL ALLOCATION PRIORITIES Maintain base production Pursue high-return growth projects Return excess cash to shareholders Fund dividends 1 2 3 4 WTI PRICE (ASSUMES $2.50 HENRY HUB) Maintain capital discipline Free cash flow accelerates GREATER THAN $50 $50 $45 Protect financial strength Exercise capital flexibility Maintain operational continuity Balance growth & free cash flow Fund dividends Improve financial strength (Program funded @ $48 WTI)

SHARE COUNT VS. 2019 NEW DEVON ASSETS E&P CAPITAL PROGRAM Preliminary 2020 Outlook 7%-9% Growth $1.7-$1.9 Billion OPTIMIZED FOR RETURNS DESIGNED FOR ULTRA-LOW BREAKEVEN PRICING 6%-8% Reduction DRIVEN BY LOW-RISK DEVELOPMENT DRILLING OIL GROWTH SHARE REDUCTION $ ENHANCING PER-SHARE CASH FLOW GROWTH Program funded at $48 WTI & $2.50 Henry Hub Low maintenance capital provides planning flexibility Expect oil volumes to average up to 160 MBOD in 2020 Positioned for attractive free cash flow (see pg. 8) Key Messages

2020 Plan Positioned for Attractive Free Cash Flow $675 2020e Free Cash Flow ($MM) (before dividends) $400 2020e Free Cash Flow Yield Free Cash Flow Free Cash Flow Yield $125 $55 WTI $2.50 HH MILLION MILLION MILLION FY2020 OUTLOOK Note: Free cash flow yield assumes market capitalization based on share price as of 11/01/19 multiplied by expected shares outstanding at year-end 2019 (~375 mm shares). Free cash flow represents operating cash flow less total capital requirements before dividend. OIL GROWTH: 7%-9% BREAKEVEN: $48 WTI (Assumes $2.50 Henry Hub) EXCLUDES BARNETT SHALE

2019 & 2020 Outlook = Improved Capital Efficiency Original Plan (2/19/19 Guide) Oil production remains on track New Devon 2019-2020 cumulative oil production (MMBO) Efficiencies driving lower capital requirements New Devon 2019-2020 cumulative upstream capital ($B) Current Plan (11/05/19 Guide) New Devon Cumulative Upstream Capital ($B) (Cumulative Capital) (Cumulative Capital) Original Plan (2/19/19 Guide) Current Plan (11/05/19 Guide) New Devon Cumulative Oil Production (MMBO) ~$400 MILLION LESS CAPITAL (VS. ORIGINAL PLAN) (Cumulative Oil) (Cumulative Oil)

Dedicated to disciplined allocation of capital Committed to Return of Capital to Shareholders $11.0 Billion 30% SHARE COUNT REDUCTION 527 ~375(1) 521 491 459 415 ~ 397 Assumes remaining authorization is completed by year-end and incremental shares are repurchased at current share price. 434 Repurchase program accelerates per-share growth Outstanding basic shares (MM) Share buyback New Devon capital Debt reduction Dividends ALLOCATED TO SHAREHOLDER RETURNS & DEBT REDUCTION 70% ~ Uses of Cash Since 2018 383

Building a Fortress Balance Sheet Aggressive debt reduction improves financial strength Net debt(1) ($B) $10.7 $2.6 >75% SINCE 2015 ($ in billions) Total debt (GAAP) $4.3 Less cash $1.7 Net debt (Non-GAAP)(1) $2.6 EBITDAX (Non-GAAP)(1)(2) $2.6 Net debt to EBITDAX ratio 1.0x Low leverage provides competitive advantage $485 $73 Significant liquidity with no near-term debt maturities Debt maturities ($MM) $4,700 1.0x NET DEBT TO EBITDAX REDUCTION Liquidity NO DEBT MATURITIES SIGNIFICANT FINANCIAL FLEXIBILITY UNTIL 2025 AS OF 9/30/2019 Cash Credit Facility Debt redemption program: targeting up to $3 billion $1.7 billion of debt retired YTD Evaluating next steps for debt reduction program Potential interest savings of ~$130 million annually Hedging program further protects financial strength Majority of oil and gas volumes protected in Q4 2019 Targeting ~50% oil & gas production in 2020 Net debt and EBITDAX are non-GAAP measures. Non-GAAP reconciliations are provided in Q3 earnings release materials. Based on last 12 months results from continuing operations.

Divestiture Program Accelerates Value Creation Resource depth allows for portfolio high-grading Cotton Draw midstream partnership formed Contributing gathering & compression assets Devon to remain operator of the assets Receive $100 million cash distribution in Q4 Partner to fund $40 million of expansion capital Barnett Shale divestiture process progressing Data rooms opened in early Q3 Initial bids received in September Ongoing negotiations with advantaged bidders Exited Canada for CAD $3.8 billion (USD $2.8B) Transaction closed in Q2 2019 Devon Assets Divestiture Assets POWDER RIVER STACK DELAWARE EAGLE FORD Rockies CO2 Barnett Shale Q3 Production: 100 MBOED Sales process: Ongoing Q3 Production: 3 MBOED Sales process: Ongoing ACCRETIVE MULTIPLE: ~10x CASH FLOW SOLD SALES PRICE: CAD $3.8 BILLION CANADIAN HEAVY OIL CLOSED: Q2 2019 Cotton draw (Midstream partnership) Proceeds: $100 million Gathering: 90 miles Compression: 4 stations NEW

Highly-Regarded ESG Performance For additional information see our 2019 Sustainability Report Included within the Dow Jones Sustainability Index top-quartile ESG ratings vs. peers ESG metrics incorporated in compensation structure Established methane emission reduction target Key Messages ENVIRONMENT SOCIAL GOVERNANCE Note: ISS scoring scale ranges from 1 to 10. The best score possible is 1. Peer group comprised of 13 E&P companies. DVN’s SCORE: 2 PEER AVERAGE: 3.8 +48% VERSUS PEER AVG. DVN’s SCORE: 2 PEER AVERAGE: 3.3 +40% VERSUS PEER AVG. DVN’s SCORE: 2 PEER AVERAGE: 5.2 +61% VERSUS PEER AVG. Devon is rated in the top-quartile of its peers (Highest rating achieved in governance) Note: Sustainalytics scores and rankings updated 10/21/2019. Peer group comprised of 20 E&P companies.

Q3 2019 - ASSET DETAIL NEW DEVON DELAWARE STACK POWDER RIVER EAGLE FORD(1) OTHER PRODUCTION Oil (MBbl/d) 148 70 32 18 22 6 NGL (MBbl/d) 79 28 37 2 11 1 Gas (MMcf/d) 588 167 317 28 75 1 Total (MBoe/d) 325 127 121 25 45 7 ASSET MARGIN (per Boe) Realized price $30.32 $33.48 $22.07 $41.20 $35.10 $46.41 Lease operating expenses ($3.73) ($4.17) ($2.08) ($7.28) ($3.20) ($15.06) Gathering, processing & transportation ($3.74) ($2.20) ($5.05) ($2.07) ($5.93) ($0.29) Production & property taxes ($2.06) ($2.69) ($0.86) ($4.73) ($1.95) ($3.30) Field-level cash margin $20.79 $24.42 $14.08 $27.12 $24.02 $27.76 CAPITAL INVESTMENT ($MM) Operated capital $444 $257 $59 $85 $38 $5 Non-operated capital $75 $5 $8 $4 $52 $6 Total capital investment $519 $262 $67 $89 $90 $11 . CAPITAL ACTIVITY Operated development rigs (avg.) 19 9 2 4 4 Operated frac crews (avg.) 7 3 1 1 2 Operated spuds 74 38 4 14 18 Operated wells tied-in 68 34 16 18 – Average lateral length (based on wells tied-in) 9,600’ 9,700’ 9,600’ 9,500’ N/A Operated working interest (based on wells tied-in) 79% 87% 56% 81% N/A Includes partner activity. Asset-Level Modeling Stats For additional modeling stats and updated guidance see our Q3 earnings release tables

Delaware Basin – Capital-Efficient Growth Engine Leonard Shale headlines Q3 operating performance Represents ~50% of new wells online (15 wells in Q3) Leonard well performance exceeding expectations Top project: N. Thistle 10 (EURs: 1.4 MMBOE/well) (pg. 17) Scalable infrastructure driving cost savings LOE rates decline >30% since 2016 (Q3 2019: $6.37/BOE) Oil & produced water gathered on pipe (avoids trucking) Operate ~40 disposal wells and 8 water reuse facilities Delivering savings of >$2 per barrel of water Positioned for strong operating results in Q4 2019 Expect to bring online >30 new wells Drilling & completion efficiencies accelerate (pg. 16) High-impact Cat Scratch 2.0 project flowing back (pg. 18) LOE rates to decline >10% by year-end (vs. Q3’19) Generating high-return production growth Production (MBOED) 127 79 Operating scale driving per-unit costs lower LOE & GP&T expense ($/BOE) >30% IMPROVEMENT Gas NGL Oil GROWTH 59% YEAR OVER YEAR

Productivity Improvement (2019 vs. 2018) 90 Day Oil IP Rate per 1K lateral, BOD (2019) PEER AVG. PEER AVG. APA CVX NBL XOM MTDR FANG PDCE CRZO PRIVATES WPX CXO MRO CDEV OXY EOG COP DVN Source: IHS, Goldman Sachs Global Investment Research Note: Bubble size represents 2019 wells as a percent of Delaware Basin total Delaware Basin – Step-Change in Operating Results Development focus driving best-in-class wells 90-day oil IPs, BOD vs. improvement in performance (2019 vs. 2018) Achieving best-in-class well productivity in 2019 Capital efficiency improvements continue to accelerate D&C costs decline by 12% in Q3 vs. 2018 ($851 per foot) Wolfcamp driving capital efficiency improvements (chart) Lower facility costs to contribute to future cost savings Drilling and completion efficiencies accelerate Drilled and completed feet per day (Wolfcamp formation) 65% COMPLETION IMPROVEMENT Drilling Completions 45% DRILLING IMPROVEMENT 900 750 700 625

Delaware – Development Projects Advancing on Plan Q3-2019a Q4-2019e Q1-2020e Q2-2020e Completion Spud Muffin (7 wells in the Bone Spring and Wolfcamp) Production Completion Lusitano (Phase 2: 5 wells in the Bone Spring and Wolfcamp) Production Cat Scratch (Phase 2: 10 Bone Spring wells) Drilling Completion Completion Thistle Cobra (7 wells in the Leonard and Wolfcamp) Production Production Chincoteague (5 Bone Spring wells) Drilling Completion Production 1 2 3 4 5 Green Wave (5 Wolfcamp wells) Drilling Completion Production 6 Projects Driving Q4 2019 Growth Future activity transitioning to Wolfcamp formation % of Delaware Basin activity 24% 45% 65% 2018 2019e 2020e Jayhawk (8 Wolfcamp wells) Drilling Completion Production Flagler (Phase 2: 10 wells in the Leonard and Bone Spring) Drilling Completion Production 7 8 High-confidence projects to drive strong Q4 growth Upcoming developments POTATO BASIN TODD COTTON DRAW THISTLE/GAUCHO RATTLESNAKE Eddy Lea New Mexico Texas Recent Developments Projects Underway Q3 2019 KEY WELLS 2,100 ~ BOED/WELL AVG. IP30 3 2 1 4 5 6 Belloq 5 Bone Spring wells Avg. IP30: 1,900 BOED/well Tomb Raider 5 Bone Spring & Leonard wells Avg. IP30: 2,400 BOED/well Bell Lake 5 Leonard wells Avg. IP30: 2,300 BOED/well Mean Green 4 Bone Spring & Wolfcamp wells Avg. IP30: 1,500 BOED/well 7 8 Chiles 3 Bone Spring wells Avg. IP30: 2,300 BOED/well DELAWARE BASIN DEVELOPMENT ACTIVITY N Thistle 10 6 Leonard wells Avg. IP30: 1,900 BOED/well

Todd Area – A Significant Long-Term Growth Platform Delivering highly-economic results across multiple formations Charged reservoir with stacked-pay potential Large, contiguous units with high working interest (>90%) 2019 capital activity: ~30 new wells online Q4 catalyst alert: Cat Scratch Fever 2.0 flowing back 10-wells offsetting prolific phase 1.0 (targeting 2nd Bone Spring) A visible, long-term growth platform in the Delaware Expect to bring online >30 new wells in 2020 Activity diversified between Leonard, Bone Spring & Wolfcamp Several hundred undrilled inventory locations remaining A VISIBLE LONG-TERM GROWTH PLATFORM 30 > NEW WELLS ONLINE IN 2020 A KEY GROWTH DRIVER IN UPCOMING YEAR Bone Spring Leonard Wolfcamp Ko Lanta 2 wells (9,700’ laterals) Avg. IP30: 2,600 BOED/well Tomb Raider 3 wells (9,900’ laterals) Avg. IP30: 3,500 BOED/well Boundary Raider 2 wells (9,800’ laterals) Avg. IP30: 3,900 BOED/well Belloq 5 wells (8,700’ laterals) Avg. IP30: 1,900 BOED/well Cat Scratch Fever 2.0 10 wells flowing back Eddy Lea Cat Scratch Fever 1.0 10 wells (8,300’ laterals) Avg. IP30: 3,600 BOED/well (Facility constrained rates) TODD DEVELOPMENT AREA STRONG GROWTH PLATFORM CAT SCRATCH 2.0 ONLINE Tomb Raider 4 wells (9,800’ laterals) Avg. IP30: 2,600 BOED/well Tomb Raider (4,700’ lateral) IP30: 1,500 BOED

Powder River Basin – Delivering Robust Oil Growth High-margin oil volume growth accelerating Turner program driving volume growth Initial Niobrara spacing tests successful (pg. 20) raising 2019 production exit-rate targets Expect >70% oil growth vs. Q4‘18 (prior target: >50%) Achieving operational efficiencies with Turner program Ranked #1 in industry for IP90 well performance D&C capital savings reach 20% per well vs. 2018 Well costs to improve to ~$6.5 million by year-end Operating scale to drive LOE >20% lower by Q4 2019 Raising oil growth outlook Net production (MBOED) Gas NGL Oil Ranked #1 in well productivity Avg. 90-day IPs BOED (Turner formation, 20:1) +50% VS. PEERS >20% IMPROVEMENT BY YEAR-END Operating scale drives costs lower LOE expense ($/BOE)

Niobrara – An Emerging Oil Resource Play Niobrara acreage resides in the core of oil fairway Significant potential with 200,000 net acres High working interest across position (>85%) Large, contiguous units secure operatorship Extended-reach drilling units maximize efficiencies Industry permitting & drilling activity accelerating 8 operated wells online (avg. IP30: 1,300 BOED; 87% oil) Delivering highest rate oil wells in basin Activity includes two successful spacing tests Appraisal activity focused in Atlas West area (see map) 2019 program: >10 operated spuds expected DVN & industry testing spacing of 3 to 7 wells/unit Potential to double Niobrara drilling activity in 2020 NIOBRARATYPE LOG 200 ft. Potential landing zones C B A SIGNIFICANT POTENTIAL 200,000 NET ACRES STACKED PAY POSITION IN OIL FAIRWAY POWDER RIVER BASIN NIOBRARA ACTIVITY Converse OIL FAIRWAY PDU WJ Ranch 22-1X Avg. IP30: 1,100 BOED (85% oil) Conley Draw 9-1X Avg. IP30: 1,300 BOED (89% oil) 100 ft. SDU Tillard 17-1X Avg. IP30: 1,200 BOED (88% oil) ATLAS WEST ATLAS EAST SSU MLT 16-2X Avg. IP30: 1,400 BOED (86% oil) SDU Tillard 25-1X Avg. IP30: 1,500 BOED (88% oil) (Stacked test with Turner) Tillard 18-1 spacing test (3 wells) Avg. IP30: 1,300 BOED/well (87% oil) Appraisal Wells Spacing Tests Upcoming Activity

Eagle Ford – Operational Momentum Established Strong production momentum heading into Q4 2019 Peak capital spending occurred in Q3 (+70% vs. 1H’19) Q4 2019e net production rate: 50-55 MBOED Growth driven by >25 Eagle Ford wells Achieving sustainable capital efficiencies Attained cost reductions of >$1 MM per well YTD Drilling costs per rig line improved by 20% Completion efficiencies & supply chain lowering costs Appraisal initiatives expanding resource opportunity Initial redevelopment wells successful (IP30: 2.2 MBOED) Refrac IRRs competing for capital (200 risked locations) Redevelopment & refrac spacing tests planned in 2020 Austin Chalk appraisal activity to continue next year 2020 targeted activity: average of 3-4 rig lines EAGLE FORD ACTIVITY Dewitt Karnes 2019 Refrac Program PRODUCTION RATE 50-55 Q4 2019 Activity >25 Eagle Ford wells MBOED Q4 2019e Muir C 4H Eagle Ford Refrac Avg. IP30 Uplift: 1,400 BOED Redevelopment Wells Avg. IP30: 2,200 BOED/well Krause B 2H Eagle Ford Refrac Avg. IP30 Uplift: 1,250 BOED Key 2019 Activity (in $MM) Last 12 months Revenue $740 Production expenses $205 Cash margin $535 Capital expenditures $222 Free cash flow $313 Substantial free cash flow Improved capital efficiency Drilling & completion cost ($MM) (6,500’ lateral) >$7.5 $6.5 Drilling Completions $1 MM DECLINE > (VS. 2018 AVG.)

STACK – Tailoring Activity to Current Price Environment Infill program achieving strong operational results Recent developments spaced at 4-6 wells per unit Well productivity exceeding type curve expectations Q3 net production: 121 MBOED (56% liquids) top highlight: Centaur project (IP30: 2,600 BOED/well) Prioritizing free cash flow over volume growth Free cash flow in 2019: ~$370 million Midship pipeline to provide pricing upside Firm oil transport to Gulf Coast provides flexibility Tailoring capital activity to current environment reducing Q4 2019 activity due to commodity prices Planning for lower activity levels in 2020 Evaluating partnerships to enhance capital efficiency Significant inventory provides long-term optionality Key Q3 2019 Results Future Developments 2019 Meramec Focus Area Blaine Kingfisher Canadian Centaur (5 wells/DSU) Avg. IP30: 2,600 BOED/well Harold (5 wells/DSU) Avg. IP30: 1,400 BOED/well Pickaroon (4 wells/DSU) Avg. IP30: 1,700 BOED/well Fleenor 2HX Avg. IP30: 2,300 BOED 370 $ FREE CASH FLOW MILLION IN 2019e Infill productivity exceeding type curve expectations Average cumulative production per well (MBOE) STACK DEVELOPMENT ACTIVITY Note: All results normalized for 10,000’ laterals Type Curve (10K LATERAL) 30-DAY IP (BOED) 1,300 – 1,600 EUR (MBOE) 1,200 – 1,400 D&C COST ~$7.5 MM ~

Investor Contacts & Notices Investor Relations Contacts Scott CoodyChris Carr VP, Investor RelationsManager, Investor Relations 405-552-4735405-228-2496 Email: investor.relations@dvn.com 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, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to: the volatility of oil, gas and NGL prices; uncertainties inherent in estimating oil, gas and NGL Investor Notices 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 regulatory, social and market efforts to address climate change; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate some of our oil and gas properties; midstream capacity constraints and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for assets, materials, people and capital; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our Form 10-K and 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 third-quarter 2019 earnings materials at www.devonenergy.com and Form 10-Q filed with the SEC. 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 high-return inventory, 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-0330 or from the SEC’s website at www.sec.gov.