May 5, 2020 Q1 2020 Earnings Presentation Exhibit 99.2
Defining Devon Premier multi-basin oil portfolio Delivering industry-leading well productivity Achieving capital efficiencies across portfolio (pg. 8) Deep inventory of repeatable opportunities Disciplined returns-driven strategy Tailoring capital activity to market conditions Focused on improving cash cost structure (pg. 11) Positioned for low breakeven funding levels Significant financial strength & liquidity Cash and credit facility availability: $4.7 billion Disciplined hedging program protects cash flow Expect to generate net cash inflows in 2020 (pg. 12) No debt maturities until year-end 2025 29 MBOED (74% OIL) POWDER RIVER BASIN 162 MBOED (52% OIL) ANADARKO BASIN 98 MBOED (54% LIQUIDS) EAGLE FORD 50 MBOED (53% OIL) Net debt and EBITDAX are non-GAAP measures. Non-GAAP reconciliations are provided in Q1 earnings release materials. EBITDAX is based on trailing 12 months. DELAWARE BASIN oil weighted: 82% of revenue (Q1 2020) low leverage: 1.1x net debt-to-EBITDAX esg excellence (see pg. 13) SIGNIFICANT LIQUIDITY POSITION (SEE PAGE 3 FOR DETAILS) KEY DEVON ATTRIBUTES NEW NEW (1) NEW
Significant Financial Strength & Liquidity $73 Significant liquidity with no near-term debt maturities Outstanding debt maturities ($MM) $4,700 Liquidity PEER AVERAGE Source: Bloomberg, Morgan Stanley Research Balance sheet strength provides competitive advantage Cumulative % of debt maturing as a % of total debt (2020-2023) Industry Peers BEST-IN-CLASS DEBT MATURITY SCHEDULE ADVANTAGED POSITION VS. PEERS NO DEBT MATURITIES (UNTIL YE 2025) NO DEBT MATURITIES UNTIL YEAR-END 2025 SIGNIFICANT FINANCIAL STRENGTH CREDIT FACILITY $3,000 $1,700 CASH $485 >5.5 YEARS UNTIL INITIAL MATURITY (DUE 12/15/2025) (as of 3/31/20) Notes: Liquidity does not include cash deposit of $170 million received in April from the Barnett divestiture. $2.8 billion of the credit facility matures in Oct. 2024, with the balance maturing in Oct. 2023.
Hedging Program Protects Cash Flow 90% $42 WTI AVG. FLOOR PRICE Swaps & Collars Floating Price OIL VOLUMES Q2-Q4 2020 (% of oil volumes hedged) ATTRACTIVE HEDGE POSITION PROTECTS CASH FLOW Disciplined hedging strategy protects cash flow Combination of swaps & costless collars no pricing downside from 3-way collars Mark-to-market value: ~$750 million Oil hedges add certainty to 2020 cash flow Represents ~90% of oil volumes (Q2-Q4 2020) Average protected WTI floor price: $42 Regional basis swaps secure in-basin pricing Actively building out 2021 hedge position (~50% of 1H 2021 oil volumes protected) Opportunistically building gas & NGL positions Gas hedges lock-in ~50% of volumes (Q2-Q4 2020) Retain upside exposure to natural gas contango 1H 2021 (% of oil volumes hedged) ~ Note: Hedging positions as of May 1, 2020. Details are provided in Q1 earnings release materials. 50% $38 WTI AVG. FLOOR PRICE OIL VOLUMES ~
Strategic Asset Sales Enhance Financial Strength Strategic transactions enhance competitive position Barnett Shale sold for up to $830 million of proceeds Received an increased deposit of $170 million $570 million in cash at closing (Dec. 31, 2020) Includes up to $260 million of contingent payments Canadian Heavy Oil monetized for $3.8 billion (CAD) High-cost assets not competitive with U.S. portfolio Removed political, egress & pricing uncertainty Accretive multiple: sold for >10x cash flow Exited EnLink Midstream interests for $3.125 billion Streamlined organizational focus to core E&P business removed ~$4 billion of consolidated debt Accretive multiple: sold for 12x cash flow Proceeds: CAD $3.8 billion Closed: Q2 2019 Proceeds: up to $830 million Closing date: Dec. 31, 2020 Proceeds: $3.125 billion Closed: Q3 2018 BARNETT SHALE (RECEIVED $170 MILLION DEPOSIT) CLOSED ENLINK MIDSTREAM (DIVESTED CONTROLLING INTEREST) CANADIAN HEAVY OIL (COMPLETED EXIT FROM CANADA) CLOSED
Our Approach to the Current Environment 1 2 3 4 TOP PRIORITIES IN CURRENT MARKET Protect financial strength Reduce capital & operating costs Preserve operational continuity Fund dividend 1 2 3 4 Preserve liquidity and financial flexibility Revenue protected by hedging program (pg. 4) Positioned to generate net cash inflows (pg. 12) Continue to fund the dividend Dynamically adapt to volatile market conditions Prepared to further recalibrate capital activity Evaluate curtailments & shut-in of select wells Preserve operational capabilities Achieve cost savings across the portfolio Continue to drive capital efficiencies (pg. 17) Capture lower service & supply costs Reduce cash operating and G&A costs (pg. 11)
Tailoring Capital Activity to Current Environment REVISED 2020 CAPITAL PLAN E&P CAPITAL ($MM) NEW WELLS ONLINE (Operated) ESTIMATED DUCs (At YE 2020) Delaware Basin $750 105-115 50-60 Powder River $150 25-35 10-15 Eagle Ford $80 43 22 Anadarko Basin $20 4 6 Total $1,000 190 100 Revised plan funded with cash flow (pg.12) Capital activity focused in the Delaware Basin Efficiencies driving significant improvement in costs (pg. 17) Suspending activity in the Anadarko, Eagle Ford & PRB Prepared to further recalibrate capital activity as needed Vast majority of service contracts are short-term Minimal long-term commitments & leasehold is held Recalibrating capital activity to protect liquidity 2020e E&P capital ($B) 2020 CAPITAL OUTLOOK 45% REDUCTION Note: Based on midpoint of 2020 guidance range. Delaware Basin Powder River Eagle Ford & Anadarko Basin $1.0 Billion $1.8 Billion Original Budget Current Outlook
Efficiencies Drive Maintenance Capital Improvements 145-150 ~100 DUCs IN BACKLOG AT YEAR-END 2020 KEY TAKEAWAYS Efficiencies driving maintenance capital lower Maintenance capital ($ billions) DECLINE DRIVEN BY EFFICIENCIES & SERVICE COSTS Note: Maintenance capital is defined as investment required to keep oil production flat on an annualized basis. 2020 CAPITAL $1.0 BILLION $1.4 $1.1 $1.25 Resilient oil production profile Oil production (MBOD) Targeting a >20% improvement in maintenance capital requirements by 2021 Maintenance capital target driven by Delaware Basin efficiencies & supply chain pricing Year-end exit rates and DUC backlog position Devon for resilient production profile in 2021 Q2 2020 curtailments estimated to limit oil production by 10,000 BOD (20 MBOED in Q2 2020) Curtailments include shut-in production, restricted flowback on select wells and the deferral of a few completions in Q2. 145-155 10 MBOD CURTAILMENTS IN Q2 2020 (1) ASSUMES MINIMAL SHUT-IN VOLUMES IN 2H 2020 >20% REDUCTION VS 2019
Managing Production to Market Conditions Adjusting activity in Q2 due to market conditions Reducing to 8 operated rigs by mid-year Plan to exit Q2 with 65% less frac crews (vs. Q1 avg.) restricting flowback on new well activity Variable cost analysis drives shut-in decisions Expect to produce if pricing exceeds variable costs Must also consider lease terms or mechanical risk Decisions made on a month-to-month basis High-graded portfolio has low variable costs Proactive actions lock-in May & June pricing Minimal production curtailments (10 MBOD in Q2) Planning for 3rd-party physical constraint scenarios Flow assurance enhanced by firm agreements (pg. 10) DYNAMICALLY MANAGING PRODUCTION
Marketing Agreements Provide Flow Assurance POWDER RIVER BASIN ANADARKO BASIN EAGLE FORD DELAWARE BASIN 95% of oil sold on firm contracts no exposure to West Texas Light crude pricing Sales points split between in-basin & Gulf Coast POWDER RIVER BASIN EAGLE FORD ANADARKO BASIN KEY MARKETING TERMS & AGREEMENTS DELAWARE BASIN Crude oil preferred by regional refiners (~40 degree / low sulfur) Contractual price protection on majority of volumes ($6 off WTI) May & June pricing locked in above variable costs Proximity to Gulf Coast demand center provides optionality Majority of volumes have firm commitments in Q2 May & June pricing locked in above variable costs Combo play benefits from gas and NGL pricing 50% of oil sold on firm contracts storage tanks provide flexibility (~300k Bbls) KEY MESSAGES Plan to flow barrels if pricing is above variable costs Arrangements provide strong flow assurance Majority of oil sold backstopped by “firm” contracts
Cost Structure Continues to Improve Production Expenses General & Administrative Financing Costs $1.90 $1.65 LEASE OPERATING & GP&T EXPENSES $8.07 -9% VS Q1 19 KEY METRICS Q1 2020 RESULTS PRODUCTION & PROPERTY TAXES FINANCING COSTS GENERAL & ADMINSTRATIVE 7.67% -3% BELOW GUIDE $102 MM -33% VS Q1 19 $65 MM -10% VS Q1 19 Note: 2019 comparisons include results from discontinued operations. Updated guidance includes severance tax credits of ~$50 million. Original 2020 Guidance Updated 2020 Guidance Reducing 2020 cash cost expectations Cash costs ($ in billions) For additional results and guidance see our Q1 earnings release tables $250 MILLION 2020 SAVINGS TARGET
Positioned to Generate Net Cash Inflows in 2020 2020 operating plan positioned to generate net cash inflows at ultra-low pricing ($ in billions) Assumes actual prices YTD and $20 WTI for the remainder of 2020. Proceeds from Barnett sale closing, which is expected in December 2020. Other includes a one-time tax payment related to the divestiture of Canada and share repurchases completed to date partially offset by an income tax refund in the U.S. $1.0 B $3.2 B $1.65 B $0.1 B $0.3 B UPSTREAM REVENUES DIVEST PROCEEDS (1) GENERATING EXCESS CASH IN 2020 Cash flow enhanced by Barnett divestiture (pg. 5) Efficiencies and activity cuts drive capital lower (pgs. 7 & 17) Plan to achieve $250MM of cost savings in 2020 (pg. 11) $0.15 B (3) (2) ASSUMES $20 WTI FOR REMAINDER OF 2020 (1)
ESG Performance Remains a Top Priority top-quartile vs. peers top-half vs. peers 15 consecutive years of CDP reporting top-decile vs. peers ENVIRONMENT SOCIAL & SAFETY GOVERANCE On track to meet our methane intensity target of 0.28% or lower by 2025 U.S. recycled water increased >300% since 2016 Reduced methane emissions by ~20% over the last three years Provided STEM resources across our communities, impacting 17,000 students 88% of operational spending is with our highest safety-rated contractors 521,629 man-hours worked on 2 rigs over 4 years without a safety incident ESG metrics incorporated in compensation structure Board independence and tenure in-line with S&P 500 averages Diverse board consisting of 27% women board members For additional information please refer to Devon Energy’s 2019 Sustainability Report +61% overall score vs. peers avg. DELIVERING TOP-TIER ESG RATINGS
Q1 2020 – Operating Highlights OIL VOLUMES EXCEED GUIDANCE (Q1 2020 +3 MBOD vs. midpoint guidance) CAPITAL SPENDING BELOW EXPECTATIONS (12% below midpoint guidance) GENERATED FREE CASH FLOW OF $104 MILLION (Positioned to deliver net cash inflows in 2020) WOLFCAMP DRIVES DELAWARE RESULTS (Q1 activity highlighted by strong Tomb Raider wells) SUCCESSFUL EAGLE FORD SPACING TEST (Redevelopment test confirms up to 12 wells per section)
Q1 2020 - ASSET DETAIL DEVON DELAWARE POWDER RIVER EAGLE FORD ANADARKO OTHER PRODUCTION Oil (MBbl/d) 163 84 21 26 24 8 NGL (MBbl/d) 80 37 3 9 30 1 Gas (MMcf/d) 634 244 29 86 272 3 Total (MBoe/d) 348 162 29 50 98 9 ASSET MARGIN (per Boe) Realized price $25.43 $26.19 $33.65 $29.94 $18.14 $39.15 Lease operating expenses ($3.96) ($3.61) ($6.65) ($2.93) ($2.79) ($18.95) Gathering, processing & transportation ($4.11) ($2.71) ($2.32) ($5.96) ($6.36) ($0.31) Production & property taxes ($1.95) ($2.15) ($4.20) ($1.85) ($0.77) ($4.34) Field-level cash margin $15.41 $17.72 $20.48 $19.20 $8.22 $15.55 CAPITAL INVESTMENT ($MM) Operated capital $373 $211 $87 $70 $4 $1 Non-operated capital $18 $9 $3 – – $6 Total capital investment $391 $220 $90 $70 $4 $7 . CAPITAL ACTIVITY Operated development rigs (avg.) 15 9 3 3 0 Operated frac crews (avg.) 6 2 1 3 0 Gross operated spuds 60 38 12 10 0 Gross operated wells tied-in 80 32 14 30(1) 4 Net operated wells tied-in 52 25 10 14 3 Average lateral length (based on wells tied-in) 7,300’ 8,000’ 9,100’ 5,400’ 9,800’ Q1 2020 – Asset-Level Modeling Stats For additional modeling stats and guidance see our Q1 earnings release tables Includes all wells brought online during the quarter, of which 19 reached 30-day peak rates.
Delaware Basin – Q1 2020 Operating Results Eddy New Mexico Lea POTATO BASIN THISTLE/GAUCHO RATTLESNAKE COTTON DRAW TODD Spud Muffin 2.0 (9,900’ laterals) 2 Wolfcamp wells Avg. IP30: 3,200 BOED/well(1) WOLFCAMP PROGRAM HEADLINES Q1 RESULTS SUSTAINABLE RESOURCE OPPORTUNITY >250,000 NET ACRES WITH STACKED PAY DEVELOPMENT EFFICIENCIES CONTINUE TO ACCELERATE Q1 production averaged 162 MBOED 32 new wells brought online Average IP30: 2,500 BOED rates restricted due to market conditions Capital spending results below plan Q1 capital: $220 million (↓14% vs plan) Driven by efficiency gains (pg. 17) Record Wolfcamp well drilled in 16 days Production costs continue to improve Unit costs improve 11% (vs. Q1 2019) Scalable infrastructure driving savings Expect cost reductions throughout 2020 Production rates reflect restricted flowback methodology due to current market conditions. Maldives (15,100’ laterals) 2 Bone Spring wells Avg. IP30: 3,900 BOED/well(1) 2nd bone SPRING SWEET SPOT IN TODD derisks deeper WOLFCAMP potential Jayhawk (8,600’ laterals) 8 Wolfcamp wells Avg. IP30: 2,400 BOED/well(1) validates WOLFCAMP development spacing Flagler 2.0 (4,600’ laterals) 10 Bone Spring & Leonard wells Avg. IP30: 1,300 BOED/well confirms multi-zone commerciality Tomb Raider 2.0 (9,400’ laterals) 5 Wolfcamp wells Avg. IP30: 4,900 BOED/well Successful infill WOLFCAMP development
Delaware Basin – Efficiencies Continue to Accelerate Delaware Basin capital efficiencies accelerate Drilled and completed feet per day (Wolfcamp formation) Drilling Completions 990 900 625 Wolfcamp capital efficiencies driving lower well costs On track for >35% decline in D&C costs by year-end Repetition gains & NPT(1) improvements reducing costs Lower service costs also contributing to savings Successfully drilled first 3-mile lateral under budget 725 Capital efficiency improvements continue to accelerate Wolfcamp D&C costs ↓42% in Q1 vs. 2018 ($705/ft) Driven by optimized completion designs & execution Facility redesign efforts driving incremental cost savings Expect additional efficiency gains throughout 2020 Wolfcamp on track to achieve significant cost savings Drilling and completion costs ($MM) (2-mile Wolfcamp well) $7.0 - $7.5 >35% CAPITAL REDUCTION $8.5 $10.2 $11.3 Represents non-productive time D&C COSTS IMPROVE 42% ($705 PER FOOT)
Delaware Basin – Revised 2020 Outlook COTTON DRAW THISTLE RATTLESNAKE POTATO BASIN TODD 19% 21% 18% 18% 24% WOLFCAMP ACCOUNTS FOR 75% OF ACTIVITY $750 MM E&P CAPITAL Previous Guidance ($1,050 million) Diversified capital program across five core areas 2020e Delaware Basin revised capital activity (20-25 Spuds) (25-30 Spuds) (20-25 Spuds) (15-20 Spuds) (15-20 Spuds) Revised 2020 capital spending outlook Program designed to maintain operational continuity Activity remains diversified across 5 core areas Capital spending decreased ~30% vs. original plan Cash flow protected by hedges & flow assurance Basis swaps cover majority of oil volumes no exposure to West Texas Light pricing Firm sales agreements cover ~95% of production Managing Q2 production due to market conditions Reducing completion crews by ~50% vs. Q1 2020 DUC inventory to approach 55 wells by quarter end Plan to dynamically manage production flow rates
Q1 production averaged 29 MBOED (74% oil) Delivered highest margins in portfolio (+30% vs. DVN avg.) 14 new wells online in quarter (Avg. IP30: 1,200 BOED) Development activity highlighted by 4 Teapot wells Niobrara appraisal activity continues to progress Tillard 36-4X appraisal well brought online in Q1 (see map) Positive delineation result in central portion of Atlas West next catalyst: 3-well spacing test in Atlas West (see map) Targeted D&C cost by year-end: <$7 million per well(1) Revising capital spending outlook downward 2020e capital spend: ~$150 million (↓55% vs. original plan) Remaining 2020 activity focused on niobrara appraisal Deferring development-oriented activity due to pricing No leasehold drilling obligations Powder River Basin – Advancing Niobrara Appraisal STACKED PAY POSITION IN OIL FAIRWAY EMERGING OIL RESOURCE OPPORTUNITY STACKED PAY POSITION IN OIL FAIRWAY POWDER RIVER BASIN ACTIVITY Converse ATLAS WEST ATLAS EAST Tillard 36-4X (9,200’ lateral) Niobrara Appraisal well Avg. IP90: 1,200 BOED (85% oil) Steinle Pad (9,600’ laterals) Niobrara Spacing Test (3 wells) Completing in late June Downs Unit (10,600’ laterals) 4 Teapot Development wells Avg. IP30: 1,300 BOED/well (97% oil) REVISED CAPITAL MILLION IN 2020e $150 NEW NIOBRARA APPRAISAL WELL ONLINE SUCCESSFUL TEAPOT DEVELOPMENT ACTIVITY For a development well, excluding facilities. 3-WELL NIOBRAra SPACING TEST
Eagle Ford – Expanding Resource Opportunity Q1 production averaged 50 MBOED (53% oil) Net production increased 11% vs. prior quarter Capital investment: $70 million (as of 3/31/20) Production costs decline 16% (vs. Q4 2019) Successful appraisal activity unlocks resource Initial 4-well redevelopment spacing test online E Butler Unit: average IP30 of 2,000 BOED (60% oil) Tested up to 440’ spacing in Upper Eagle Ford Minimal communication with existing wells in section Decreasing activity in current environment Partnership released all rigs & frac crews in mid-April Capital spending decreased 75% vs. original budget Uncompleted well inventory: 22 wells (at 4/30/20) EAGLE FORD ACTIVITY Dewitt Karnes E Butler Unit (5,700’ laterals) 4 Eagle Ford Redevelopment wells Avg. IP30: 2,000 BOED/well UPPER EAGLE FORD LOWER EAGLE FORD 440’ Confirms redevelopment spacing up to 12 wells/section Existing development spacing at 12 wells/section Sandy (4,700’ laterals) 4 Eagle Ford Redevelopment wells Flowing back 440’ 440’ Migura B (6,200’ laterals) 5 Lower Eagle Ford wells Avg. IP30: 2,200 BOED/well SUCCESSFUL Eagle FORD DEVELOPMENT project 2nd redevelopment spacing test flowing back Initial REDEVELOPMENT SPACING TEST online
Anadarko Basin – Optimizing Base Production Results Base production efforts improve decline profile Q1 net production: 98 MBOED (54% liquids) outperformed plan 7% year-to-date Driven by well workovers and reduced downtime Tailoring activity to current environment reducing capital outlook in 2020 by $55 million 2020e capital spend: ~$20 million (↓95% YoY) MVC expirations to provide $65 million benefit in 2021 Postponing Dow drilling partnership activity Initial project: 18-well Jacobs Row delayed (timing TBD) drilling carry of ~$100 million over next 4 years Dow to fund 65% of partnership capital requirements ANADARKO BASIN ACTIVITY Blaine Canadian Kingfisher Future Dow Activity DELAYING DOW DRILLING PARTNERSHIP ACTIVITY FUTURE DOW FOCUS AREA Jacobs Row (2 DSUs) 18 Woodford wells 10,000’ laterals Project delayed (timing TBD) Recent Results Privott (9,800’ laterals) 4 Meramac wells Avg. IP30: 1,200 BOED/well(1) REDUCING CAPITAL VERSUS 2019 ACTIVITY LEVLES 95% INFILL DEVELOPMENT (ACTIVITY NOT RELATED TO DOW) INITIAL DOW JV ACTIVITY (DRILLING partnership) FOCUSED ON OPTIMIZING CASH FLOW GENERATION Production rates reflect restricted flowback methodology due to current market conditions.
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 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 such as “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 those, identified below. The COVID-19 pandemic and its related repercussions have created significant volatility, uncertainty and turmoil in the global economy and our industry. This turmoil has included an unprecedented supply-and-demand imbalance for oil and other commodities, resulting in a swift and material decline in commodity prices in early 2020. Our future actual results could Investor Notices differ materially from the forward-looking statements in this presentation due to the COVID-19 pandemic and related impacts, including, by, among other things: contributing to a sustained or further deterioration in commodity prices; causing takeaway capacity constraints for production, resulting in further production shut-ins and additional downward pressure on impacted regional pricing differentials; limiting our ability to access sources of capital due to disruptions in financial markets; increasing the risk of a downgrade from credit rating agencies; exacerbating counterparty credit risks and the risk of supply chain interruptions; and increasing the risk of operational disruptions due to social distancing measures and other changes to business practices. In addition to the risks associated with the COVID-19 pandemic and its related impacts, our actual future results could differ materially from our expectations due to other factors, including, among other things: 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 our operations, including as a result of employee misconduct; 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; risks related to investors attempting to effect change; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our 2019 Annual Report on Form 10-K, our first-quarter 2020 Form 10-Q and our other filings with the SEC. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on 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 first-quarter 2020 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. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com or the SEC’s website.
