Q2 2019 Operations Report August 6, 2019 Exhibit 99.2
Defining the “New Devon” World-class U.S. oil portfolio Unrivaled acreage position in top basins Multi-decade growth inventory Resource depth allows for portfolio high-grading Disciplined returns-driven strategy Aggressively improving cost structure Growing higher-margin oil production Generating free cash flow Delivering value to shareholders Committed to return of capital Capital-efficient per-share growth 21 MBOED (73% OIL) STACK 124 MBOED (25% OIL) POWDER RIVER EAGLE FORD 49 MBOED (48% OIL) 120 MBOED (56% OIL) DELAWARE Production: 321 MBOED (Q2 2019) Revenue: 72% oil Oil growth rate: 18%-20% in 2019 (pg. 12) Multi-decade growth inventory New Devon Overview
Unleashing Potential of World-Class Oil Assets U.S. well productivity showcases asset quality Source: IHS/Devon. All wells drilled from 2015 through 2019 YTD. Includes operators with more than 150 wells. Avg. 90-Day IPs BOED, 20:1 PEER AVG. Top 50 U.S. Producers SUPERIOR WELL RESULTS >45% VS. PEER AVG. Inventory provides multi-decade growth opportunity Gross operated inventory locations (non-operated locations not included) >20 YEAR INVENTORY (AT CURRENT DRILLING PACE) STACK Delaware Basin Eagle Ford PRB 6,500 operated locations 4,200 operated locations ~280 operated wells online 15 YEAR INVENTORY (AT CURRENT DRILLING PACE) Note: High-return inventory represents locations estimated to generate >20% IRR. Returns based on all-in E&P capital investment, which includes drilling, completion and well-site facilities and flow back. DELIVERING IMPROVED CAPITAL EFFICIENCY (SEE PAGE 6 FOR DETAILS)
Executing on Our Disciplined Strategy Oil growth outlook raised for 2nd time in 2019 Delaware well productivity drives volumes +58% (pg. 14) Capital spending outlook lowered in 2019 (pg. 6) Cost savings program: $780 million/year (>70% in 2019) Divestiture program advances with sale of Canada Debt reduced by >80% (since 2015 – pg. 10) returned >$4 billion of cash to shareholders (since 2018) ü ü ü ü ü ü KEY ACCOMPLISHMENTS ü Fund high-return projects Improve financial strength Return cash to shareholders Generate free cash flow 1 2 3 4 KEY STRATEGIC OBJECTIVES
Beat Q2 guidance Devon Delivers Strong Q2 Outperformance LOE & GP&T (per Boe) G&A expenses ($MM) EBITDAX(3) ($MM) Upstream capital(1) ($MM) Free cash flow(3)(4) Average share count (MM) Dividend (per share) $7.61 $114 $627 $478 $59 415 $0.09 -11% -16% +4% -11% n/a -20% +13% U.S. oil volumes(1) (MBOD) Oil realizations(2) (% of WTI) Q2 2019 142 97% YoY Change +13% 0% Key Metrics U.S. oil production exceeds top-end of guidance New Devon (MBOD) 142 (Q2 Guide: 134-141) 126 G&A LOE & GP&T Interest Improving cost structure expands margins Per-unit cost ($/BOE) SINCE Q1 2018 DECLINE 22% $12.29 $15.67 5,000 ABOVE GUIDANCE U.S. OIL PRODUCTION BARRELS PER DAY Represents New Devon performance (excludes Barnett Shale). Includes benefits of basis swaps and firm transport. EBITDAX and free cash flow are non-GAAP measures. Reconciliation provided in Q2 earnings release. Includes discontinued operations.
lowering 2019 capital outlook by $50 million Structural improvements driving capital efficiency: Wolfcamp cycle times and costs improving (pg. 16) Turner development activity lowering PRB costs (pg. 19) Eagle Ford D&C costs improving (pg. 20) STACK activity tailored to current environment (pg. 21) redeploying STACK capital to Delaware & PRB in 2H19 Capital efficiency showcased with Q2 results New Devon upstream capital 9% Q2 2019 CAPITAL SPENDING Q2 2019 CAPITAL: $478 MILLION BELOW GUIDANCE Efficiencies driving improved capital outlook New Devon 2019e E&P capital Improved 2019 Capital Spending Outlook $1.8-$1.9 E&P CAPITAL 51% DELAWARE 18% STACK 13% POWDER RIVER 18% EAGLE FORD BILLION RAISING OIL GROWTH OUTLOOK FOR 2ND TIME IN 2019 (SEE PAGE 12 FOR DETAILS) Previous Guidance ($1.8 - $2.0 billion)
Cost savings initiatives trending ahead of plan Estimated cost savings by area as of 7/31/19 ($MM) Optimizing New Devon’s 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 G&A $300 MM Interest $130 MM Per-Unit Recurring LOE $50 MM D&C Efficiencies $300 MM (1) 75% BY YEAR-END 2019 >50% BY YEAR-END 2019 (1) Assumes $3 billion of debt repayments with sales proceeds from the exit of Canada and Barnett. Cost savings momentum driving improved guidance reducing G&A guidance for 2nd time in 2019 D&C efficiencies: raising 2019 cost savings target by 10% Debt redemption leading to improved interest outlook Delaware success driving LOE rates lower vs. plan (1) (Run-rate as of 7/31/19) CURRENTLY ACHIEVED (Based on decisions made) UPCOMING 2019 SAVINGS (Expected during 2020 & 2021) FUTURE COST INITIATIVES
Multi-basin portfolio provides market diversification Physical & financial hedges further mitigate risk Q2 oil realizations: 97% of WTI(1) (72% of revenue) Flexibility to move product to advantaged markets Positioned for flow assurance & advantaged pricing Majority of oil has exposure to Gulf Coast pricing Gas has access to premium markets in southeast U.S. NGLs priced off Mt. Belvieu (access to export markets) Delaware marketing strategy creating value No exposure to West Texas Light crude Average Delaware API gravity: ~41 degrees Contractual gravity protection up to 60 degree API Basis Swaps protect >80% of gas ($12 million uplift in Q2) Marketing Strategy to Maximize Margins Gulf Coast Access to premium gulf coast markets STACK Delaware Basin Eagle Ford Majority of oil has exposure to Gulf Coast pricing Includes benefits of basis swaps & firm transport. Marketing strategy delivering differentiated results New Devon oil realizations (% of WTI) Basis swaps & firm transport uplift Floating oil realizations 97% 98% 99% 97% 97%
Dedicated to disciplined allocation of capital Committed to Return of Capital to Shareholders $10.3 Billion 30% SHARE COUNT REDUCTION 527 ~380(3) 521 491 459 415 ~ 402 Debt reduction includes debt that was redeemed in July 2019. Share buyback includes repurchases made year-to-date. Assumes remaining authorization is completed by year-end and incremental shares are repurchased at current share price. 434 Repurchase program accelerates per-share growth Outstanding shares (MM) Share buyback(2) New Devon capital Debt reduction(1) Dividends ALLOCATED TO SHAREHOLDER RETURNS & DEBT REDUCTION 70% ~ Key Uses of Cash Since 2018
Building a Fortress Balance Sheet Aggressive debt reduction improves financial strength Net debt ($B) $10.8 $2.0 >80% SINCE 2015 ($ in billions) Total debt (GAAP)(1) $4.3 Less cash(1) $2.3 Net debt (Non-GAAP) $2.0 EBITDAX (Non-GAAP)(2) $2.6 Net debt to EBITDAX ratio 0.8x Low leverage provides competitive advantage $485 $73 Significant liquidity with no near-term debt maturities Debt maturities ($MM) $5,300 0.8x NET DEBT TO EBITDAX REDUCTION Liquidity NO DEBT MATURITIES SIGNIFICANT FINANCIAL FLEXIBILITY Cash and debt adjusted for the $1.5 billion debt redemption in July 2019. Based on last 12 months results for continuing operations. Non-GAAP reconciliation provided in Q2 earnings release. UNTIL 2025 AS OF 7/31/2019 Cash Credit Facility (1) Expect to reduce up to $3 billion of debt by year-end $1.7 billion of debt redeemed YTD More debt reduction expected in 2H 2019 Potential interest savings of ~$130 million annually Hedging program further protects financial strength Mark-to-market value: $185 million (as of 8/2/19) Majority of oil and gas volumes protected in 2H 2019
Divestiture Program Accelerates Value Creation New Devon Assets Divestiture Assets POWDER RIVER STACK DELAWARE BASIN EAGLE FORD Rockies CO2 Barnett Shale Q2 Production: 100 MBOED Data room: Open Q2 Production: 3 MBOED Sales process: Ongoing ACCRETIVE MULTIPLE: ~10x CASH FLOW SOLD SALES PRICE: CAD $3.8 BILLION CANADIAN HEAVY OIL CLOSED: Q2 2019 Resource depth allows for portfolio high-grading Canada sale closed: CAD $3.8 billion (USD $2.8B) accretive multiple at ~10x cash flow(1) Removes political, egress & pricing uncertainty Net proceeds: USD $2.6 billion (after FX & PPA(2)) Retained Canadian cash balances (USD $500 million) Progressing Barnett Shale divestiture process Data room currently open Initial bids expected by end of Q3 Expect to exit position by year-end Utilizing proceeds for debt reduction Assuming $55 WTI oil pricing and $20 WCS differentials. Refers to purchase price adjustments. (1)
Strong Execution Driving Improved 2019 Outlook Scalable growth in Delaware & PRB driving U.S. costs lower Canada exit improves G&A outlook by ~$80 million annually $1.7 billion debt redeemed YTD (reduced interest by >$60 million) LOE & GP&T G&A Financing costs Run-rate savings to exceed $200 million by year-end Higher-cost Canadian assets exit portfolio More growth expected in Q4 vs. Q3 (timing of high-impact wells) raising oil growth outlook for 2nd time in 2019 U.S. oil growth Structural improvements driving capital efficiency gains (pg. 6) Capital investment redeploying STACK capital to Delaware & PRB in 2H 2019 Updated Guidance 18% – 20% (vs. 2018) $7.50 – $7.75 (per BOE) $450 – $490 ($ in millions) $250 – $270 ($ in millions) $1.8 – $1.9 ($ in billions) vs. Original Guidance Key Messages Represents New Devon performance target (excludes Barnett Shale) (1) (1) Improvement 15% Improvement 16% Improvement 19% Improvement More debt reduction expected in 2H 2019 $50 Basis Point 400 Million Improvement
Q2 2019 - ASSET DETAIL NEW DEVON DELAWARE STACK POWDER RIVER EAGLE FORD(3) OTHER NEW DEVON PRODUCTION Oil (MBbl/d) 142 67 31 15 23 6 NGL (MBbl/d) 82 27 40 2 12 1 Gas (MMcf/d) 575 158 313 22 81 1 Total (MBoe/d) 321 120 124 21 49 7 ASSET MARGIN (per Boe) Realized price $31.68 $34.83(2) $23.96 $45.44 $37.50 $47.43 Lease operating expenses ($3.66) ($4.33) ($1.84) ($6.95) ($2.85) ($20.34) Gathering, processing & transportation ($3.80) ($2.31) ($5.10) ($1.71) ($5.59) ($0.09) Production & property taxes ($2.34) ($2.84) ($1.25) ($4.99) ($2.43) ($4.33) Cash margin $21.88 $25.35 $15.77 $31.79 $26.63 $22.67 CAPITAL ACTIVITY Upstream capital ($MM) $478 $235 $94 $87 $53 $9 Operated development rigs (avg.) 20 9 3 4 4 Operated frac crews (avg.) 6 2 2 1 1 Operated spuds 87 23 16 17 31 Operated wells tied-in 64 28 21 6 9 Average lateral length 8,000’ 7,500’ 9,000’ 9,500’ 6,000’ OTHER KEY STATS General & administrative expenses ($MM) $114(1) Financing costs, net ($MM) $66 Share count (MM) (avg.) 415 Includes Barnett until the asset is divested. Includes benefits of regional basis swaps and firm transport in the Delaware totaling $10 million. Includes partner activity. Q2 2019 – Key Asset Modeling Stats For additional modeling stats and updated guidance see our Q2 earnings release tables
Delaware Basin – Capital-Efficient Growth Engine Generating high-return production growth Production (MBOED) 120 76 Operating scale driving per-unit costs lower LOE & GP&T expense ($/BOE) >30% IMPROVEMENT Gas NGL Oil GROWTH 58% Activity diversified by formation across 5 core areas 28 new wells: Avg. IP30 2,100 BOED (7,500’ laterals) Efficiencies driving higher activity (+5 wells vs. budget) Base production efforts improve decline profile outperformed plan by 10% year-to-date Driven by reduced downtime and well optimization Wolfcamp program continues to build momentum Strong initial rates at Flagler (IP30/1k ft: 425 BOED) Drilling times improve by 20% vs. 2018 results Facility redesign reducing capital by up to 50% per well Water infrastructure investment creating value Operate ~40 disposal wells and 8 water reuse facilities >90% of produced water on pipe (water use: 80% recycled) Delivering savings of >$2 per barrel of water (vs. trucking and sourcing of water) YEAR OVER YEAR
Development Projects Advancing on Plan POTATO BASIN TODD COTTON DRAW THISTLE/GAUCHO RATTLESNAKE Eddy Lea New Mexico Texas DELAWARE BASIN DEVELOPMENT ACTIVITY N Thistle 10 Jayhawk Spud Muffin Lusitano (Phase 2) Cat Scratch (Phase 2) 2019 developments online Projects underway Belloq Rio Blanco (7,000’ laterals) 4 Bone Spring wells Avg. IP30: 1,500 BOED 1 5 Fighting Okra (9,500’ laterals) 9 Wolfcamp wells Avg. IP30: 3,200 BOED Gaucho (5,500’ laterals) 5 Bone Spring wells Avg. IP30: 2,100 BOED 2 6 Cat Scratch (8,000’ laterals) 10 Bone Spring wells Avg. IP24 hr: 10 MBOED (Top 5 wells) Snapping (7,500’ laterals) 5 Leonard wells Avg. IP30: 1,900 BOED 3 7 N Thistle 34 (10,000’ laterals) 6 Leonard wells Avg. IP30: 2,100 BOED 4 8 Cotton Draw (10,000’ laterals) 4 Leonard wells Avg. IP30: 2,200 BOED Flagler (4,500’ laterals) 7 Wolfcamp wells Avg. IP30: 2,000 BOED 1 2 3 5 6 7 4 8 VanMar (10,000’ laterals) 4 Bone Spring wells Avg. IP30: 2,700 BOED 9 9 Loving 2019 YTD ACTIVITY 2,500 ~ BOED/WELL AVG. IP30 Q2-2019a Q3-2019e Q4-2019e Q1-2020e Completion Thistle Cobra (8 wells in the Leonard 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 Drilling Drilling Completion Spud Muffin (8 wells in the Bone Spring and Wolfcamp) Drilling Production Production Belloq (5 Bone Spring wells) Completion Production Jayhawk (8 Wolfcamp wells) Drilling Completion Production Activity transitioning to Wolfcamp formation % of Delaware Basin activity 24% 45% 65% 2018 2019e 2020e Thistle Cobra N Thistle 10 (6 Leonard wells) Completion Production
Step-Change in Well Productivity and Efficiency Gains Strong initial rates translating into improving recoveries Oil EUR improvement by Northern Delaware operator (2018 vs. 2017) 200% IMPROVEMENT SINCE 2015 > Development focus driving productivity gains Avg. 90-day IPs BOED results (20:1) 600 2,000 Improving drilling times Drilled feet per day (Wolfcamp formation) Peer Avg. High-graded development in core areas Integrated reservoir characterization Optimized completion designs & execution IMPROVEMENT DRIVEN BY: 750 625 700 Source: Seaport Global Securities. Represents peers in Northern Delaware Basin within Seaport coverage. 1,180 820 880 Completing wells faster Completed feet per day (Wolfcamp formation)
Delaware – Acreage Located in the Best Part of the Play Top-tier well productivity… IP BOE/Lateral foot Highest oil content… Gas-oil ratio, SCF/BBL Lower operating costs (less water disposal) Water-oil ratio, BBL/BBL DVN Focus Area Source: Tudor Pickering, Holt & Company IP BOE/Lateral Low High Gas-Oil Ratio Low High Water-Oil Ratio Low High DVN Focus Area DVN Focus Area
Acreage Trades Optimizing Value of Our Resource Delaware Leonard Bone Spring Wolfcamp Thistle Cotton Draw Todd Potato Basin Rattlesnake ~5,000 feet of pay (Resource potential) Acreage trades enhancing the value of stacked-pay position Graphic for illustrative purposes Leading acreage position in SE New Mexico Net acreage: >250,000 surface acres Concentrated in economic core of play Significant value uplift from acreage trades Traded ~35,000 net acres over past 3 years increases working interest in operated sections Allows for drilling longer laterals Reduces non-core, lower-return acreage Value creating trades accelerating in 2019 $110 million of NPV uplift (12 trades YTD) Lowers non-op capital exposure by $240 million top highlight: 5,500 acres added to Todd area (Additive to Boundary Raider/Cat Scratch Fever development) 2,000 “HIGH-RETURN” OPERATED LOCATIONS DERISKED(1) (16-YEAR INVENTORY WITH SIGNIFICANT UPSIDE FROM APPRAISAL ACTIVITY) High-return inventory represents locations estimated to generate >20% IRR. Returns based on all-in E&P capital investment, which includes drilling, completion and well-site facilities and flow back. Up to 4 wells/ landing zone Up to 4 wells/ landing zone 4 -8 wells/ landing zone Up to 4 wells/ landing zone
Powder River Basin – Oil Growth Accelerating Net production increased 29% year over year Delivering highest margins in portfolio (+18% vs. Q1) 6 wells brought online (Avg. IP30: 1,500 BOED; 80% oil) Turner development driving operational efficiencies YTD drilling times improve ~40% vs. 2018 D&C cost savings: >$1 million per well by year-end High-return oil growth accelerates in 2H 2019 Year-end exit-rates: >50% oil growth (vs. Q4 ‘18) Efficiencies driving higher activity (+10 spuds vs. plan) Operating scale to drive LOE >25% lower vs. 1H Niobrara provides significant upside potential 4th appraisal well flowing back (see map) resource catalyst: initial spacing test online in 2H Drilling times improving Drilled feet per day (Turner formation) Significant capital savings Drilling and completion cost savings (Turner formation) $1.0 SAVINGS PER WELL MILLION WELL DESIGN & DRILLING COMPLETION EFFICIENCIES > UNBUNDLING SUPPLY CHAIN 658 915 764 ~40% IMPROVEMENT POWDER RIVER BASIN ACTIVITY Upcoming Activity Q2 2019 Key Activity RU DILTS 35-4XTLH (Turner) Avg. IP30: 1,900 BOED Initial Niobrara spacing test Online in 2H 2019 Converse Super Mario Area RU JFW 14-1XTH (Turner) Avg. IP30: 1,100 BOED RU DILTS 35-CXTUH (Turner) Avg. IP30: 1,300 BOED RU PRCC 36-4XTUH (Turner) Avg. IP30: 1,500 BOED RU PRCC 36-2XTLH (Turner) Avg. IP30: 2,300 BOED Niobrara appraisal well Flowing back
Eagle Ford – Expanding Resource Opportunity Muir 5 Lower Eagle Ford wells Avg. IP30: 3,600 BOED/Well EAGLE FORD ACTIVITY Vasbinder A 11H EF Redevelopment well Avg. IP30: 2,400 BOED 2019 Refrac Program Krause B 2H Eagle Ford Refrac Avg. IP30 Uplift: 1,250 BOED Bednorz B 11H EF Redevelopment well Avg. IP30: 2,000 BOED Dewitt Gonzales Karnes Q2 2019 Key Activity FREE CASH FLOW ($MM) 500 $ LAST 12 MONTHS Q2 production averaged 49 MBOED (~50% oil) 9 new wells online (Avg. IP30: 2,500 BOED) Activity increased to 4 drilling rigs in the quarter Production exit-rate: >50 MBOED by year-end Achieving improved capital results with new partner Initial results indicate D&C savings of >10% Potential for capital savings of >$500,000 per well Appraisal initiatives expanding resource opportunity Initial 3 Eagle Ford redevelopment wells successful Refrac IRRs competing with new well economics 10-year drilling inventory with upside potential 700 “high-return” undrilled locations identified(1) 200 risked refrac candidates identified (>700 potential) (1) High-return inventory represents locations estimated to generate >20% IRR. Returns based on all-in E&P capital investment, which includes drilling, completion and well-site facilities and flow back. Muir C 4H Eagle Ford Refrac Avg. IP30 Uplift: 1,400 BOED Immenhauser A 14H EF Redevelopment well Avg. IP30: 1,100 BOED ~ Upcoming 2H 2019 Activity Eagle Ford development wells
STACK – Optimizing Development Activity Lighter-spaced projects delivered strong results 17 strong Meramec wells online in Q2 Top highlights: Baker & Everett projects (see map) YTD drilling times improve ~20% vs. 2018 Tailoring capital activity to current environment reducing capital outlook by $50 million 2H 2019 activity to decline by ~40% (vs. 1H 2019) Prioritizing free cash flow over volume growth 2019e free cash flow: ~$300 million Midship pipeline to provide pricing upside by YE19 Evaluating partner opportunities to optimize development of play Significant inventory provides long-term optionality REDUCING CAPITAL (in $MM) 2019e Revenue $1,000 Production Expenses $350 Cash Margin $650 Capital Expenditures $325-$375 Free Cash Flow Substantial free cash flow ~$300 (2019e CAPITAL: $325-$375) 50 $ MM OUTLOOK STACK DEVELOPMENT ACTIVITY Key 2019 Meramec Results Upcoming Developments Baker (4 wells/DSU) Avg. IP30: 2,400 BOED/Well 2019 Meramec Focus Area Blaine Kingfisher Canadian ML (5 wells/DSU) Avg. IP30: 1,400 BOED/Well Morning Thunder (4 wells/DSU) Avg. IP30: 1,900 BOED/Well(1) Everett (4 wells/DSU) Avg. IP30: 3,000 BOED/Well (1) Normalized for 10,000’ laterals. Kraken (7 wells/DSU) (online Q1) Avg. IP30: 2,000 BOED/Well
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 second-quarter 2019 earnings release 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.
