EX-99.3 4 d702577dex993.htm EX-99.3

Strategic Update & Q4 2018 Operations Report February 19, 2019 Exhibit 99.3

Completing Transformation to a U.S. Oil Growth Company Sharpens focus on world-class U.S. oil assets Delaware, STACK, Eagle Ford and Powder River High-margins and low cost of supply Multi-decade growth platform Pursuing strategic alternatives for Barnett Shale and Canadian assets Outright sale or spin-off Expect to complete by year end Targeting at least $780 million of cost savings with retained U.S. oil business (details on pg. 7) Board increases share-buyback program to $5 billion $3.4 billion repurchased to date (~90 million shares) Potential to reduce share count by nearly 30% Increased quarterly dividend 13% to $0.09 per share 18 MBOED (71% OIL) STACK 126 MBOED (55% LIQUIDS) POWDER RIVER EAGLE FORD 61 MBOED (50% OIL) 84 MBOED (54% OIL) DELAWARE Production: 296 MBOED (Q4 2018) Revenue: 84% oil & liquids Oil growth rate: 17% in 2018 Multi-decade growth platform (see pg.6) New Devon Overview

A Track Record of Execution Divestiture Assets New Devon Brazil Azerbaijan China Russia GoM Shelf GoM Deepwater San Juan East Texas Mississippian Granite Wash Uinta Washakie Conventional Canadian Assets Midland Assets DIVESTITURE PROCEEDS EnLink West Africa $30 Billion > Heavy Oil(1) Barnett Shale(1) (1) Pursuing strategic alternatives and expect to exit assets by YE 2019 U.S. oil business has achieved operating scale Positioned for mid-teens oil growth and FCF above $46 WTI High-quality, multi-decade drilling inventory Dramatically improves cost structure and margins Accelerates value realization for Canada & Barnett STRATEGIC RATIONALE FOR TODAY’S ANNOUNCEMENT STACK POWDER RIVER EAGLE FORD DELAWARE (over last decade) Rockies CO2 (marketing)

New Devon’s World-Class Oil Assets Visualized Portfolio positioned in top oil basins Well level breakeven (PV-10, WTI to HH @ 20:1) ($/bbl) Net Acres 40,000 Net Acres 280,000 Net Acres 280,000 Net Acres 330,000 DOMINANT POSITION IN 4 TOP OIL PLAYS Source: RS Energy Group, December 2018. Breakeven($/bbl@20:1 WTI:HH) Note: acreage denoted represents core acreage positions

Unleashing Potential of World-Class Oil Assets U.S. well productivity showcases asset quality Source: IHS/Devon. All wells drilled since 2015 and includes operators with more than 100 wells. Superior oil growth and pricing +17% (vs. 2017) +1% (vs. 2017) DECLINE 20% (FY 2018) Improved per-unit costs 2018 LOE & transportation expense ($/BOE) Higher field-level margins 2018 field-level cash margins ($/BOE) $17.68 $27.67 INCREASE 56% (FY 2018) $9.66 Avg. 90-Day IPs BOED, 20:1 PEER AVG. 96% (of WTI) 65% (of WTI) Reported New Devon Top 40 U.S. Producers $7.76 SUPERIOR WELL RESULTS +40% VS. PEER AVG.

Inventory Supports Sustainable Long-Term Growth STACK Delaware Basin Eagle Ford PRB 4,200 operated locations (Avg. lateral length: ~7,500’) ~280 operated wells online (Avg. lateral length: ~8,000’) 15 YEAR INVENTORY (AT CURRENT ACTIVITY PACE) WTD AVG. IRR: >50% 6,500 operated locations (Avg. lateral length: <7,500’) (1) High-Return Inventory Potential(1) Gross operated inventory locations High-return inventory represents locations generating >20% IRR. Returns based on all-in E&P capital investment, which includes drilling, completion and well-site facilities and flow back. Requires additional appraisal work, cost efficiencies, spacing optimization and operating cost improvements to compete for capital allocation with current high-return inventory opportunity set. >20 YEAR INVENTORY (AT CURRENT ACTIVITY PACE)

Next Steps to Optimize New Devon Cost Structure Aggressively pursuing improved cost structure New Devon expected cost savings by area vs. 2018 results ($MM) $780 ANNUAL COST SAVINGS BY 2021 MILLION Timing of annual cost savings Cumulative estimated annual cost savings ($MM) Interest G&A D&C(1) LOE G&A $300 MM Interest $130 MM Per-Unit Recurring LOE $50 MM D&C Efficiencies $300 MM Restructuring to unlock potential of New Devon One functional focus across entire organization Reduced complexity provides for further focus on competitive advantages in U.S. Refocused and streamlined leadership structure Realigning personnel with go-forward business Cost savings designed to be front-end weighted ~70% of targeted savings achieved by year-end 2019 Targeted G&A level: ~$2.50 per Boe Structural D&C efficiencies reflected in 2019 outlook PV10 of cost savings plan: ~$4.5 billion (over next 10 years) COMMITTED TO OPTIMIZING CAPITAL EFFICIENCY AND OPERATIONAL EXCELLENCE (1) D&C costs assume flat service cost environment versus 2018 (1)

Disciplined Returns-Focused Strategy KEY STRATEGIC OBJECTIVES Fund high-return projects Maintain financial strength Return cash to shareholders Generate free cash flow 1 2 3 4 (1) Price sensitivity also assumes $3 Henry Hub and current hedge position. $40 Free cash flow accelerates (no change to activity levels over 3-year plan) Key strategic objectives achieved (3-year plan delivers mid-teens oil growth within cash flow) Maintain financial strength and operational continuity (New Devon FCF breakeven below $40 in 2019 with hedging gains) WTI PRICE(1) $46 $46 GREATER THAN APPROACH TO THE CURRENT ENVIRONMENT

New Devon: 3-Year Performance Targets CUMULATIVE FREE CASH FLOW OIL GROWTH COST SAVINGS DEBT TARGET CAPITAL PROGRAM RETURN ON CAPITAL TARGET: >15%(1) (At $50 WTI & $3 HH) $1.6 At $55 WTI & $3 HH 12% – 17% CAGR (FY2018 – 2021) Total Light-Oil Production $780 MM By 2021 See pg. 7 for detail 1.0x to 1.5x Debt to EBITDA Funded Assumes $3 HH price At $46 WTI Improve financial strength and flexibility Sustainably pay and grow dividend Opportunistically repurchase shares Reinvest in high-return U.S. oil business Free Cash Flow Priorities (See page 10 for FCF sensitivities) Internal rate of return on capital investment after burdening for G&A and corporate costs. Metric further detailed in proxy and driver of management compensation. Assumes cost savings detailed on page 7 are fully realized at the beginning of 2019. BILLION (2)

New Devon: Free Cash Flow Yield to Investors ($50 WTI) ($55 WTI) Cumulative Free Cash Flow $2.3B Cumulative Free Cash Flow ($B) Cumulative Free Cash Flow $1.6B Free Cash Yield (Annual Avg.) Cumulative Free Cash Flow $0.8B Note: Free cash flow yield assumes market capitalization based on current share price multiplied by expected shares outstanding at year-end 2019 (~375 mm shares). Cumulative free cash flow represents the aggregate operating cash flow less total capital requirements before dividend. Assumes $3 HH price. Cumulative Free Cash Flow Free Cash Flow Yield (Annual Avg.) (1) Assumes cost savings detailed on page 7 are fully realized at the beginning of 2019. OIL CAGR: 12%-17% BREAKEVEN: $46 WTI (BREAKEVEN CALC INCLUSIVE OF ALL CAPEX) 3-YEAR CAPITAL PLAN (1) (1) (1)

Attractive Entry Point for World-Class Oil Business New Devon: trading at significant discount $ in Billions $15.7 $2.5 $16.8 Peer trading multiples 2019e EV/EBITDAX(1) Peer average 6.8x (1) Estimates were sourced from Credit Suisse and assumes $54 WTI and $3.05 HH. “EV” stands for enterprise value. (2) 2019e Adjusted EBITDAX assumes cost savings discussed on page 7 are realized at the first of the year and assumes Credit Suisse price deck of $54 WTI and $3.05 HH. (3) Represents estimated 2019 Adjusted EBITDAX multiplied by peer average multiple of 6.8x. (4) Assumes share count, debt and cash at 12/31/18 and current share price. (2) (3) (4) Discounted valuation with asset sale upside Note: Adjusted EBITDAX is non-GAAP measure and is reconciled to GAAP on a historic basis in our Form 10-K. Valuation Gap (6.8x * $2.5B) Peer Multiple * New DVN EBITDAX

Why Own New Devon? World-class U.S. oil company Unrivaled acreage position in top basins Multi-decade inventory to drive sustainable growth Accelerating value realization for Canada & Barnett Focused on operational excellence Aggressively reducing costs Shifting to higher-margin production Positioned for mid-teens oil growth and free cash flow generation above $46 WTI Delivering value to shareholders Committed to return of capital Capital-efficient per-share growth Strong value proposition with attractive valuation 18 MBOED (71% OIL) STACK 126 MBOED (55% LIQUIDS) POWDER RIVER EAGLE FORD 61 MBOED (50% OIL) 84 MBOED (54% OIL) DELAWARE Production: 296 MBOED (Q4 2018) Revenue: 84% oil & liquids Oil growth rate: 17% in 2018 Multi-decade growth platform (see pg.6) New Devon Overview

Q4 2018 Operations Report & 2019 Outlook

Q4 2018 - ASSET DETAIL DELAWARE STACK PRB EAGLE FORD PRODUCTION Oil (MBbl/d) 45 31 13 30 NGL (MBbl/d) 18 37 2 15 Gas (MMcf/d) 127 343 20 95 Total (MBoe/d) 84(1) 126 18(1) 61 ASSET MARGIN (per Boe) Realized price $37.84(2) $29.40 $46.27 $44.20 Lease operating expenses ($6.04) ($1.84) ($6.95) ($2.69) Gathering, processing & transportation ($2.06) ($4.62) ($1.95) ($5.72) Production & property taxes ($2.71) ($1.30) ($5.40) ($2.44) Cash margin $27.03 $21.64 $31.97 $33.35 CAPITAL ACTIVTY Upstream capital ($MM) $252 $195 $56 $32 Operated development rigs (avg.) 10 5 2 Operated frac crews (avg.) 2.5 2 0.5 Operated spuds 31 17 12 Operated wells tied-in 27 25 8 Average lateral length 8,800’ 8,400’ 9,500’ Q4 production was impacted by timing of completions. Delaware production has increased to 96 MBOED in January. PRB production has increased to 22 MBOED in January. Includes benefits of regional basis swaps and firm transport in the Delaware totaling $35 million. Q4 2018 - Key Modeling Stats

New Devon: Pro Forma Financials KEY METRICS (WTI / HH) Q4 2018 ($58.80 / $3.65) FY 2018 ($64.79 / $3.09) FY 2019 (ASSUMES PRO FORMA COSTS) ($50 / $3) Oil production (MBbls/d) 125 121 137 - 143 NGL production (MBbls/d) 73 69 70 - 74 Gas production (MMcf/d) 589 537 520 - 550 Total production (MBoe/d) 296 279 294 - 309 Oil realizations (% of WTI) 95% 96% 90% - 100% Gas realizations (% of Henry Hub) 78% 76% 66% - 72% LOE & GP&T ($/BOE) $7.71 $7.76 $7.30 - $7.50 Production & property taxes ($/BOE) $2.19 $2.40 $2.10 - $2.30 General & administrative ($MM) $151 $650 ~$350 Financing costs, net (includes capitalized interest) ($MM) $70 $323 ~$170 Upstream capital ($MM) $547 $2,056 $1,800 - $2,000 Adjusted field-level cash margins ($/BOE) $24.91 $27.67 $20.00 - $22.00 Adjusted EBITDAX ($MM) $548 $1,900 ~$2,400 Note: Adjusted field-level cash margins and Adjusted EBITDAX are non-GAAP measures and are reconciled to GAAP on a historic basis in our Form 10-K.

Executing on Disciplined Strategy in 2018 Shifted U.S. oil assets into development U.S. oil growth +17% in 2018 (vs. 2017) Divestiture program reached ~$5 billion Reduced consolidated debt by >40% Raised quarterly dividend 33% Repurchased 15% of stock in 2018 ü ü ü ü ü Share buyback $6.8 Billion Upstream capital Debt reduction Dividends $2.4B $3.0B $1.2B $0.2B >60% OF CASH ALLOCATED TO SHAREHOLDER-FRIENDLY INITIATIVES KEY ACCOMPLISHMENTS ü

Capital Efficiencies Accelerate in 2019 Focused on top-tier oil development opportunities 2019e E&P capital (New Devon) $1.8-$2.0 E&P CAPITAL 47% DELAWARE 21% STACK 16% POWDER RIVER 16% EAGLE FORD BILLION 2019 CAPITAL ACTIVITY E&P CAPITAL ($MM) NEW WELLS ONLINE (Operated) Delaware Basin $900 100-110 STACK $400 85-95 Powder River $300 35-40 Eagle Ford $300 40-50 New Devon Total $1,800 - $2,000 CAPITAL PROGRAM FUNDED AT $46 WTI Structural improvements drive capital efficiency: Outlook assumes flat service & supply costs vs. 2018 Facility cost savings up to 40% across U.S. by year end Wolfcamp costs and cycle times improving (20% vs 2018) STACK infill spacing design optimized (15% vs. 2018) Dedicated frac crew to lower PRB costs (17% vs. 2018) >15% more wells drilled for ~10% less capital (vs. 2018)

Disciplined Growth Benefits From Buyback Activity Focused on delivering sustainable, high-margin growth (funded at $46 WTI) Driven by U.S. oil growth (+13%-18% vs. 2018) U.S. oil exit rate: >20% vs. 2018 avg. Top-line production to advance (+8% vs. 2018) Eagle Ford timing to impact Q1 (see pg. 25) Margins to benefit from improved cost structure LOE rates to decline ~10% by Q4 2019 Additional cost saving initiatives underway (pg. 7) Board increased share-repurchase authorization to $5 billion Potential to reduce share count by ~30% $3.4 billion repurchased to date (~90 million shares) 13% - 18% OIL GROWTH >20% (2019 exit rate vs. FY 2018) 2018 vs 2019 Positioned for high-return growth in 2019 New Devon U.S oil production (MBOD) Repurchase program accelerates per-share growth Outstanding shares (MM) ~30% SHARE COUNT REDUCTION 527 ~375(1) 521 491 459 437 ((1) Assumes shares are repurchased at current share price.

Delaware Basin – Capital-Efficient Growth Engine DELAWARE BASIN OVERVIEW RATTLESNAKE Q4 2018 Key Wells Upcoming Projects THISTLE/GAUCHO POTATO BASIN TODD COTTON DRAW Seawolf (7 Wolfcamp wells) Avg. IP 30: 3,000 BOED/well 2,800 BOED 30-DAY IPs Fighting Okra Flowing Back New Mexico Texas 15 WELLS AVG. Eddy Lea Spud Muffin Drilling Lusitano (1 Bone Spring well) Avg. IP 30: 2,200 BOED Ko Lanta (2 Leonard wells) Avg. IP 30: 2,600 BOED/well North Thistle Completing Morab (2 Bone Spring wells) Avg. IP 30: 1,600 BOED/well High-rate wells drive Q4 growth Net production increased 49% vs. Q4 2017 January 2019 production: 96 MBOED (+14% vs. Q4) Wolfcamp program headlines Q4 performance Seawolf development reaches peak rates Strong appraisal results achieved in Todd area Fighting Okra project achieves 1st production Firm transport and basis swaps protect pricing Q4 oil realizations: 98% of WTI(1) Swaps & firm transport protect ~75% of 2019e oil Field-level cash flow expands 72% (vs. FY2017) Per-unit costs improve 15% year over year Capital requirements funded within cash flow Q4 2018 KEY WELLS Tomb Raider (3 Wolfcamp wells) Avg. IP 30: 3,500 BOED/well RECORD WELL PRODUCTIVITY ACHIEVED IN 2018 (see pg. 20) LEVERAGING INFRASTRUCTURE TO EXPAND MARGINS & RETURNS Cats (Offsets Boundary Raider) Completing (1) Includes benefits of basis swaps & firm transport Flagler (Phase 1) Completing

Step-Change in Delaware Basin Well Productivity Well productivity reaching record highs Average cumulative oil production per well (MBO) Months Online 2018 average 2015-2017 average Bone Spring Wolfcamp Leonard Significant growth platform at $50 WTI Gross operated inventory locations generating IRR >20%(1) 2,000 locations (Avg. lateral length: 7,500’) BOUNDARY RAIDER & WOLFCAMP FOCUS IN 2019 2018 Boundary Raider wells 16 YEAR INVENTORY (AT CURRENT ACTIVITY PACE) Weighted Avg. IRR: >50% (>90% improvement vs. 3-year avg.) (1) IRR on E&P capital investment (includes drilling, completion and well-site facilities and flow back). (targeting Bone Spring)

Focusing on Wolfcamp & Bone Spring Projects in 2019 Todd Area Bone Spring “Cats” Area (~20 wells online in 2019) Eddy Boundary Raider (2 wells) Avg. IP 24: 12 MBOED/well RATTLESNAKE DEVELOPMENT ACTIVITY Rattlesnake Area Lea ACCELERATING TODD DEVELOPMENT PROGRAM Flagler (Phase 1) Completing Lea Wolfcamp program: ~45% of 2019 drilling activity Six key projects underway in Rattlesnake area Seawolf delivers massive rates (IP30: ~40 MBOED) Fighting Okra flowing back (all wells online) Multi-phase Flagler project underway (~20 wells) Development of Bone Spring in Todd area underway Activity offsetting prolific Boundary Raider wells Initial wells had highest rates in Delaware history ~20 new wells to be brought online in 2019 (see map) Leonard & Wolfcamp appraisal success in Q4 Ko Lanta (2 wells) Avg. IP 30: 2,600 BOED/well Tomb Raider (3 wells) Avg. IP 30: 3,500 BOED/well Bone Spring Leonard Wolfcamp Fighting Okra Flowing back Peak rates: 1H 2019 Arena Roja 2H 2019 Spud Mean Green 2H 2019 Spud Jayhawk 1H 2019 Spud Seawolf 12 Wolfcamp wells Avg. IP 30: 3,300 BOED/well Wolfcamp

Delaware Basin – Focused Development Plan in 2019 Diversified state-line activity Percent of activity by formation Delivering high-margin growth Net production (MBOED) 2019 DRILLING ACTIVITY Wolfcamp (45%) Bone Spring (30%) Leonard (25%) Top-funded asset in portfolio (~$900 million) Low-risk development activity: ~95% of program Running 11 operated rigs (spud ~125 wells) Average lateral length increases to ~8,000’ High-margin oil growth (~40% vs. 2018) LOE rates to decline by >15% by year end Infrastructure drives sustainable savings and ESG benefits Operating costs to improve >60% vs. peak rates Concentrated acreage position & activity levels (~280k acres) Nearly all oil and water on pipe (avoids high-cost trucking) Operate ~50 disposal wells and 8 water reuse facilities >90% of water used in completions is recycled Note: 2016-2017 costs are pro forma for revenue recognition accounting rules recently implemented. >15% IMPROVEMENT (2019 EXIT VS. 2018) Operating scale drives costs lower LOE & GP&T expense ($/BOE)

Net production increases 11% vs. Q4 2017 Oil production increased 9% (vs. Q3 2018) Growth driven by infill development activity (see map) Highest Q4 rates from Chipmunk & Faith Marie activity Safari project design supports future infill spacing Spaced at 5 wells per unit (Avg. IP30: 1,400 BOED) Well placement targeted Upper Meramec interval D&C savings reach ~30% vs. legacy parent well Early results at Pony Express, Northwoods & Scott further confirms view on spacing Learnings from infill development activity to date Lighter-spaced pilots delivering improved returns Upper Meramec is the best performing interval Flowback approach designed to optimize oil recoveries STACK – Optimizing Infill Spacing Kingfisher Canadian Blaine Upcoming Developments STACK DEVELOPMENT ACTIVITY Developments Online Safari (5 wells/DSU) Avg. IP30: 1,400 BOED Chipmunk (3 wells) Avg. IP30: 4,400 BOED Geis (7 wells/DSU) Avg. IP120: 900 BOED(1) Faith Marie (2 wells) Avg. IP30: 3,100 BOED 4-6 wells UPCOMING ACTIVITY PER DSU Efficiencies accelerate at Safari development Feet drilled per day >90% Improvement 30% D&C INFILL COSTS BELOW PARENT WELL Scott (5 wells/DSU) Avg. IP10: 3,100 BOED(1) Pony Express (4 wells/DSU) Avg. IP30: 1,600 BOED(1) Northwoods (5 wells/DSU) Avg. IP30: 1,500 BOED (1) Normalized for 10,000’ laterals

STACK – 2019 Strategic Priorities Transitioning infill developments to 4-6 wells per unit Investment concentrated in volatile-oil window Wells primarily targeting Upper Meramec interval Strategic priorities for 2019 capital program Generate attractive infill development returns Prioritizing free cash flow over volume growth Retain operational flexibility to increase investment 2nd highest funded asset in portfolio Capital investment: ~$400 million (4-rig program) Expect stable production profile (vs. 2018) Timing of activity to impact Q1 production profile Significant growth inventory remaining 130,000 net acres in over-pressured oil window High-quality Woodford optionality Significant free cash flow contributor in 2019 Free cash flow ($MM)(2) ($55 WTI/$2.75HH) Type Curve (10K LATERAL) Well Spacing (per DSU) 4 – 6 wells 30-DAY IP (BOED) 1,300 – 1,600 EUR (MBOE) 1,200 – 1,400 D&C COST ~$7.5 MM LIQUIDS MIX (% OF EUR) 55% -65% Updated infill development type curve expectations Early results in line with type curve expectations (BOED) ~100% GROWTH (VS 2018 ASSUMING $50 WTI) 1,400 (30-day IP) 1,600(1) (30-day IP) 5 WELLS/DSU 5 WELLS/DSU 5 WELLS/DSU (1) Normalized for 10,000’ laterals 1,500 (30-day IP) 3,100(1) (10-day IP) 4 WELLS/DSU (2) Calculated as cash margin (see pg. 15) less capital expenditures

Eagle Ford Q4 production averaged 61 MBOED (50% oil) Net production 11% higher vs. Q4 2017 15 new wells: Avg. IP30 3,700 BOED High-rates driven by larger completion design Increasing activity to a 3 rig program in 2019 ~70 spuds planned (40-50 wells online by year-end) Targeting up to 25 horizontal refracs Initiating Austin Chalk appraisal program ~5 appraisal tests scheduled in 2019 Program to derisk >200 inventory locations 1st production at initial appraisal well in Q2 2019 Activity underway to stabilize volumes by year end Q1 outlook: 50-55 MBOED (~10 wells tied-in) Positioned to deliver volume growth in 2020 Q4 Results 15 Lower Eagle Ford Wells Avg. 30-Day IP: 3,700 BOED/Well EAGLE FORD OVERVIEW (in $MM) 2018 Revenue $926 Production Expenses $208 Cash Margin $718 Capital Expenditures $203 Free Cash Flow $515 Free cash flow generation Austin Chalk Appraisal Well Q1 2019 Spud Austin Chalk Appraisal Well 1st Production in Q2 2019 FREE CASH FLOW 515 $ MILLION IN 2018 700 High-return locations Strong inventory upside Potential locations High-Return Locations (With Upside) ~

Powder River Basin Net production increased 27% vs. Q4 2017 8 wells online in late December (Avg. IP30: 1,500 BOED) January 2019 production: 22 MBOED (+25% vs. Q4) Increasing activity to 4 rigs in 2019 Represents 2x increase in activity from 2018 Dedicated and decoupled stimulation services improve capital efficiency No permitting or infrastructure constraints Capital program focused in Super Mario area Prioritizing Turner development activity (~35 spuds) Advancing Niobrara delineation work (~10 spuds) Year-end exit-rates: >50% oil growth (vs. Q4’ 18) ~20% oil growth expected in Q1 (vs. Q4’ 18) Operating scale to drive ~10% LOE savings in 2019 KEY POWDER RIVER BASIN ACTIVITY 2019 Activity Q4 2018 Activity Super Mario Area RU JFW Fed 14-4 (Turner) Avg. 30-Day IP: 1,600 BOED (~80% oil) (9,500’ lateral) CWDU FED 31-3 (Parkman) Avg. 30-Day IP: 1,200 BOED (~95% oil) (9,500’ lateral) PRB Activity ~50 Spuds Downs Fed 02-1 (Teapot) Avg. 30-Day IP: 1,400 BOED (~95% oil) (9,000’ lateral) EMERGING OIL GROWTH OPPORTUNITY STACKED PAY POSITION IN OIL FAIRWAY (Planned for 2019) RU Fed 14-C (Turner) Avg. 30-Day IP: 2,000 BOED (~80% oil) (9,500’ lateral) RU JFW Fed 14-3 (Parkman) Avg. 30-Day IP: 1,100 BOED (~95% oil) (9,300’ lateral) CU Downs Fed 35-1 (Teapot) Avg. 30-Day IP: 1,500 BOED (~95% oil) (10,200’ lateral) CU Downs Fed 15-2 (Teapot) Avg. 30-Day IP: 1,800 BOED (~95% oil) (10,500’ lateral) Downs Fed 02-3 (Teapot) Avg. 30-Day IP: 1,400 BOED (~95% oil) (8,500’ lateral)

Barnett Shale Canada Dow JV efficiently maintaining base production Q4 production: 103 MBOED (~30% NGLs) Minimum volume commitments expired at year end Wise County divestiture package closed in October Stable production outlook expected in 2019 Capital investment: $65 million (~35 new wells online) GP&T expense ~$90 million lower due to MVC expiry BARNETT SHALE OVERVIEW Sale price: ~$50 million Production: ~4 MBOED Denton Wise Divest Details 2019e Dow JV Activity CLOSED Q4 2018 Q4 impacted by curtailments & royalties Reduced production due to market conditions (17 MBOD) Royalty adjustments increased Q4 volumes (due to ↓ pricing) WCS hedges deliver $144 million of cash settlements Q4 PRODUCTION GROSS NET Jackfish 1 (MBOD) 33.7 39.3 Jackfish 2 (MBOD) 31.3 30.7 Jackfish 3 (MBOD) 30.7 29.9 Lloydminster (MBOED) 19.7 21.5 Total Heavy Oil (MBOED) 115.4 121.4 Regional pricing improves due to industry curtailments Positioned to generate free cash flow above $50 WTI Hedging position mitigates WCS downside risk in 2019 Q1 net production expected to reach ~115 MBOED

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 fourth-quarter 2018 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 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.