UBS Global Oil and Gas Conference

Transcription

1 UBS Global Oil and Gas Conference May 23, 2018 NYSE: DVN devonenergy.com

2 Investor Contacts & Notices Investor Relations Contacts Scott Coody Chris Carr VP, Investor Relations Supervisor, Investor Relations Investor Notices Forward-Looking Statements This presentation includes "forward-looking statements" as defined by the Securities and Exchange Commission (the SEC ). Such statements include those concerning strategic plans, expectations and objectives for future operations, and are often identified by use of the words expects, believes, will, would, could, forecasts, projections, estimates, plans, expectations, targets, opportunities, potential, anticipates, outlook and other similar terminology. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. Statements regarding our business and operations are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to: the volatility of oil, gas and NGL prices; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; the uncertainties, costs and risks involved in oil and gas operations; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate our oil and gas properties; midstream capacity constraints and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for leases, materials, people and capital; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties identified in our Form 10-K and our other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this presentation are made as of the date of this presentation, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. Use of Non-GAAP Information This presentation may include non-gaap financial measures. Such non-gaap measures are not alternatives to GAAP measures, and you should not consider these non-gaap measures in isolation or as a substitute for analysis of our results as reported under GAAP. For additional disclosure regarding such non-gaap measures, including reconciliations to their most directly comparable GAAP measure, please refer to Devon s first-quarter 2018 earnings release at Cautionary Note to Investors The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This presentation may contain certain terms, such as resource potential, potential locations, risked and unrisked locations, estimated ultimate recovery (EUR), exploration target size and other similar terms. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available at You can also obtain this form from the SEC by calling SEC-0330 or from the SEC s website at 2

3 Investment Thesis Delaware & STACK focused Rapidly expanding cash flow Disciplined capital allocation Multi-decade growth platform >30,000 DELAWARE & STACK POTENTIAL LOCATIONS Significant financial strength 3

4 Devon s 2020 Vision TOP OBJECTIVE: OPTIMIZE RETURNS & DELIVER CAPITAL-EFFICIENT, CASH-FLOW GROWTH Maximize cash flow Focus on capital efficiency Portfolio simplification Improve financial strength Return cash to shareholders Leverage technology to optimize base production Improve margins by aggressively lowering cost structure Enhance returns through disciplined capital investment Concentrated activity in economic core of Delaware & STACK High-grade resource-rich asset portfolio >$5 billion of divestiture potential Further improve investment-grade credit ratings Net debt to EBITDA target: 1.0x 1.5x $1 billion share repurchase program underway Consistently grow and sustain dividend 4

5 2020 Vision: Driving Significant Cash Flow Growth Growing higher-value production U.S. Oil Production (MBOD) Cost savings to expand margins Upstream Per-Unit Cash Cost ($/BOE) 200 $18 15% COST SAVINGS MID-TEENS CAGR DRIVEN BY >25% CAGR IN DELAWARE & STACK $12 $6 Interest G&A Op. Cost e 2019e 2020e $ e 2019e 2020e Note: 2017 costs are pro forma for revenue recognition accounting rules recently implemented. Driving upstream cash flow expansion $ Billions ($60 WTI & $2.75 HH) Significant free cash flow generation Through 2020 ($60 WTI & $2.75 HH) $2.2 >25% CAGR 2.5Billion CUMULATIVE FREE CASH FLOW e 2019e 2020e 5

6 Shareholder-Friendly Initiatives $1 billion share-repurchase program underway $204 million repurchased (as of 4/30/18) Average price: $33 per share Expect program to be completed by year end KEY INITIATIVES UNDERWAY $1 Billion share repurchase program initiated Raised quarterly dividend by 33% Target cash flow payout ratio: 5% - 10% Positioned for sustainable dividend growth 33% Increase in quarterly cash dividend Recently tendered $807 million of debt Plan to retire $277 million of maturing debt (next 9 months) $1 Billion debt reduction plan 6

7 Portfolio Simplification Strategy Resource quality & depth allows for highgrading of portfolio Heavy Oil Potential for >$5 billion of asset disposals Divest proceeds to date: $1.1 billion Optionality to monetize oil or gas Multiple initiatives underway to further focus portfolio footprint Actively pursuing larger asset divestitures Marketing ~$1 billion of non-core asset packages Rockies Delaware Basin Eagle Ford Portfolio Simplification >$5 Billion STACK Barnett POTENTIAL ASSET SALE PROCEEDS 7

8 Significant Financial Strength Investment-grade credit ratings PROTECTING OUR ABILITY TO EXECUTE Net debt to EBITDA target: 1.0x to 1.5x Significant investment in EnLink Midstream Disciplined hedging program ~60% of 2018 oil & gas volumes protected Excellent Liquidity Cash: $1.4B INVESTMENT- GRADE CREDIT RATINGS EnLink Investment Market Value: ~$3.5B (as of May 2018) Attractive WCS & Midland basis swaps For additional information on hedges see the appendix Disciplined Hedging 2018: ~60% 8

9 Operational Excellence Capture FULL VALUE Improve RETURNS Maximize base production Minimize controllable downtime Enhance well productivity Leverage midstream operations Control operating costs Optimize capital program Disciplined project execution Perform premier technical work Focus on development drilling Accelerate operational efficiencies 9

10 Updated 2018 Outlook Raised 2018 U.S. oil production guidance 16% growth vs (~30% exit-rate growth) Guidance increased by ~200 basis points Driven by efficiencies and well productivity Positioned for significant cash flow expansion Driven by high-margin U.S. oil growth Canadian WCS pricing improving G&A and interest savings: ~$175 MM annually Improving 2018 oil production outlook U.S. oil production (retained assets) (MBOD) Growing upstream cash flow (1) ($MM) $800 ~35% GROWTH ~30% EXIT-RATE INCREASE VS FY 2017 Q Q2 2018e 2H 2018e 2018e Exit Rate $600 $400 Q Q2 2018e Q3 2018e Q4 2018e (1) Represents Devon upstream cash flow. Assumes $65 WTI and $2.75 Henry Hub for Q2 Q

11 The Next Frontier Of Efficiency Gains Multi-zone projects to drive returns higher Increase rig & frac crew efficiencies Centralized facilities improve cost structure Higher recoveries from stacked pay Focused activity maintains short cycle times Initial Delaware & STACK development highlights: Capital savings of up to $1.5 MM per well Record drill times (~30% improvement) Frac efficiencies reaching as high as 15 stages/day TARGETING >20% COST SAVINGS PER WELL For additional information see our Q1 operations report 11

12 Securing The Supply Chain Services and supplies secured through 2019 Dedicated frac crews in Delaware & STACK SERVICES SERVICES & SUPPLIES SUPPLIES SECURED SECURED Development efficiencies driving rig reductions Self-sourcing regional sand (~30% savings) Industry leader in water recycling Attaining top-tier services at below-market rates Decoupling historically bundled services Securing longer-term relationships Development efficiencies offsetting inflation 12

13 Protecting Price & Flow Assurance Delaware Basin positioned for premium oil pricing Swaps & firm transport protect ~90% of oil volumes Gas flows to West Coast (avoids WAHA hub) Basis swaps protect ~40% of gas production STACK volumes have access to advantaged markets WTI pricing with pipeline access to Cushing Firm transport covers vast majority of gas production ~60% of gas volumes price protected (~$0.50 off HH) Basis hedges protecting cash flow in Canada WCS swaps protect ~50% of oil volumes in 2018 ($15 off WTI) Premium Pricing in the Delaware Basin Delaware gas volumes flow to west coast markets Waha In-basin oil sales protected by basis swaps ~40% of 2018 Delaware volumes transported on Longhorn DELAWARE BASIN: OIL BASIS SWAPS Houston Midland oil swaps (MBbls/d) For additional information on hedges see the appendix Avg. differential to WTI ($/Bbl) ($1.02) ($0.46) 13

14 Delaware Basin Franchise Asset World-class oil opportunity Multi-decade growth platform Up to 15 target intervals Potato Basin POTATO BASIN Eddy TODD Tomb Raider Boomslang Flowing Back Cobra COTTON DRAW Flagler North Thistle Spud Medusa Drilling Anaconda 10 Wells Online Lea THISTLE/GAUCHO Accelerating development activity Lusitano Completing Seawolf Completing Snapping Current Developments Future Projects (Timing TBD) Core Development Area Van Doo Dah Loving Fighting Okra Drilling RATTLESNAKE 14

15 Delaware Basin Advantaged State-Line Area Activity targeting the most prolific zones Delivered the top wells in Delaware Basin history 2018 E&P ACTIVITY Leonard Bone Spring Wolfcamp Boundary Raider 6-7 Com 212H IP24: 12,868 BOED (82% oil) Boundary Raider 6-7 Com 213H IP24: 11,149 BOED (76% oil) Positioned for high-return production growth Production (MBOED) Improving cost structure to boost margins LOE & Transportation Expense ($/BOE) 73 >85 $9.10 $8.97 $ ~$7.50 Q March e Exit Rate 1H H 2017 Q Year End 2018e Note: 2017 costs are pro forma for revenue recognition accounting rules recently implemented. 15

16 Delaware Basin Significant Growth Opportunity Multi-decade oil growth opportunity Massive stacked-pay potential ~300k net surface acres focused in state-line area >1.3 million net effective acres (up to 15 target intervals) Significant resource upside with Wolfcamp delineation DELAWARE BASIN RESOURCE FORMATION NET EFFECTIVE ACRES GROSS RISKED LOCATIONS GROSS UNRISKED LOCATIONS Leonard Shale 160,000 1,000 3,500 Bone Spring 530,000 3,200 6,000 Wolfcamp 460,000 1,500 8,500 Other Targets 180, ,500 Total >1,300,000 6,500 >20,000 16

17 STACK Franchise Asset Blaine Kingfisher Best-in-class acreage position >600k net acres by formation Coyote Avg. 30-Day IP 4,400 BOED Minnie Haha Showboat Flowing back Cascade 2018 Spud Up to 4 target intervals per unit Kraken 2018 Spud Northwoods Accelerating development activity Projects Online 2018 Developments Centaur Horsefly Completing ML Block 2018 Spud Geis 2018 Spud Bernhardt Drilling Future Projects (Timing TBD) Caddo Canadian 17

18 STACK Infill Projects Delivering Efficiencies Record flow rates achieved at Coyote project Project developing Lower Meramec sweet spot Average IP30: 4,400 BOED (60% oil) Drilling times improved by ~25% Completion costs reduced by ~10% vs. prior activity Showboat cost savings: ~$1.5 million per well 30% faster drill times vs. prior activity 2x improvement in frac stages per day 1 st production achieved 40 days ahead of plan Peak project flow rates expected by mid-year Coyote Project 4 of 7 wells online Avg. 30-day IP: 4,400 BOED 16N 12W Flowing Back Online in 2018 Coyote Area: A Lower Meramec Sweet Spot 17N 12W Cottontail Parent Well Online Q1 18 IP30: 4,400 BOED Faith Marie Parent Well Online Q4 17 IP30: 4,700 BOED Showboat Cost Savings $1.5 MM Savings Per Well Drilling Completions Facilities Frac Stages Per Day (Showboat) ~8 avg. (up to 11 per day) Showboat Avg. 18

19 STACK Meramec Drives Strong Oil Growth Activity concentrated in over-pressured oil window (best returns in play) Activity shifting to economic core Multi-zone projects to accelerate production growth Positioned for significant resource & inventory upside High-returning production growth Production (MBOED) >140 (>40% oil growth) WOODFORD 2018 E&P ACTIVITY MERAMEC ACTIVITY >95% 129 SIGNIFICANT MERAMEC RESOURCE UPSIDE 117 Q Q e Exit Rate Over-pressured oil acreage Stacked-pay opportunity Risked inventory Current infill spacing tests 130,000 net surface acres Up to 5 Meramec landing zones 6 wells per surface section 9 to 12 wells per surface section 19

20 Investment Thesis Delaware & STACK focused Rapidly expanding cash flow Disciplined capital allocation Multi-decade growth platform >30,000 DELAWARE & STACK POTENTIAL LOCATIONS Significant financial strength 20

21 Thank you. For additional information see our Q1 Operations Report Thank you.

22 Rockies An Emerging Oil Growth Asset Premier Powder River Basin position Q1 net production: 23 MBOED Stacked pay: >10 prospective intervals Testing Niobrara potential (~400k prospective acres) Initial well flowing back Completion work underway at 2 nd appraisal well Q Activity Key Wells to Date Upcoming Turner Tests T Cosner Fed 29-2XPH Parkman 30-Day IP: 2,100 BOED KEY POWDER RIVER BASIN ACTIVITY T Cosner Fed 29-1XPH Parkman 30-Day IP: 1,850 BOED Super Mario Area T Cosner Fed 29-3XPH Parkman 30-Day IP: 2,400 BOED T Cosner Fed 29-4XPH Parkman 30-Day IP: 2,550 BOED 2 nd Niobrara Test 30-Day rates in 2H18 Super Mario Turner activity accelerating ~10 wells scheduled for remainder of 2018 Turner 4-well test Avg. 30-Day IP: 1,500 BOED/well 1 st Niobrara Test 30-Day rates in Q2 Moore Land Trust 21 1TH Teapot 30-Day IP: 2,500 BOED 4 Parkman Wells Avg. 30-Day IP: 1,200 BOED/well Avg. Well cost: ~$5mm Teapot Appraisal Well Avg. 30-Day IP: 1,700 BOED/well Well cost: ~$5mm Moore Land Trust 21 2TH Teapot 30-Day IP: 2,300 BOED 22

23 Heavy Oil Oil production at high end of guidance in Q1 Q2 volumes impacted by turnaround and royalties Jackfish turnaround impact: ~15 MBOD Higher royalties: ~3 MBOD WCS hedges protecting cash flow in 2018 ~50% hedged at $15 off WTI Free cash flow in 2018: $550 million (1) Heavy Oil 2018e Free Cash Flow ($MM) $1,225 $250 ($650) SAGD Sweet Spot FOR EVERY PER BBL $ 1 INCREASE IN WCS INCREMENTAL $ 40 MM ANNUALIZED CASH FLOW Q1 PRODUCTION GROSS NET ($275) $550 Jackfish 1 (MBOD) Jackfish 2 (MBOD) Jackfish 3 (MBOD) Lloydminster (MBOED) Upstream Revenues WCS Hedges Production Expenses (1) Assumes $65 WTI & $25 differential for remainder of Capex Free Cash Flow Total Heavy Oil (MBOED)

24 Eagle Ford Strong production growth in Q2 (chart below) Two frac crews currently on site 25 wells to be tied-in Plan in place to stabilize production 35 to 40 new wells online in 2H 2018 Free cash flow in 2018: >$400 million (1) Stabilizing High-Margin Production (MBOED) EAGLE FORD HIGHLIGHTS Two Completion Crews 25 Wells Expected Online in Q2 10 Staggered laterals Lower Eagle Ford Tied In: Q Staggered laterals Lower Eagle Ford Tied In: Q KEY STATS Q1 18 Q4 17 Net production (MBOED) Upstream capital ($MM) $78 $41 Q Q2 2018e 2H 2018e (1) Assumes $65 WTI & $2.75 Henry Hub for remainder of

25 Barnett Shale Johnson County divestiture announced Proceeds: $553 million (closing late May) Q1 production: 33 MBOED (18% liquids) Partnership formed with DowDupont Selling ½ working interest in 116 locations Devon to receive ~$75 million over 5 yrs Drilling commitment of up to 24 wells/year No restrictions on exiting Barnett ~50 horizontal refracs planned in 2018 Capital program to stabilize production for retained Barnett assets (table right) Dow JV Acreage 2018e activity: ~20 wells drilled 2018 BARNETT SHALE ACTIVITY OUTLOOK Refrac Focus Area 2018e activity: ~50 horizontal refracs PRODUCTION (MBOED) Q1 18 Q2 18e 2H 18e Retained Barnett assets Johnson County divestiture Total Barnett production

26 Innovation Momentum - Technology Projects In Flight SUBSURFACE DRILLING & COMPLETIONS PRODUCTION OPERATIONS WATER MANAGEMENT CORPORATE Improved 3D seismic interpretation High-graded location selection Optimized landing zones Well productivity predictions Depletion analysis Geospatial optimization Cyber-geosteering Flat, in-zone wells Fiber-optic sensing Prolonged drill-bit life Coiled-tubing drill-outs Efficient flowbacks Cutting-edge frac modeling Predictive pump failures Field-issue prioritization Optimized compressors Production monitoring Flood optimization Inter-well communication (data analytics) Gas lift for EOR Water-treatment options Frac fluid chemistry Data acquisition and management systems Leak detection in piping systems Water transfer and storage safety Accounting process automation World-class partnerships in digital innovation platforms Enterprise dashboards for information Accessible mobile applications across all aspects of the business Targeting hundreds of millions in value creation annually 26

27 Hedge Position OIL DERIVATIVES PERIOD VOLUME SWAPS COLLARS MIDLAND BASIS SWAPS WCS BASIS SWAPS WEIGHTED AVG. PRICE VOLUME WEIGHTED AVG. FLOOR PRICE WEIGHTED AVG. CEILING PRICE VOLUME WEIGHTED AVG. DIFF. to WTI VOLUME WEIGHTED AVG. DIFF. to WTI (MBPD) ($/BBL) (MBPD) ($/BBL) ($/BBL) (MBPD) ($/BBL) (MBPD) ($/BBL) Q2-Q $ $51 $61 20 ($1.02) 69 ($14.91) FY $ $52 $62 28 ($0.46) NATURAL GAS DERIVATIVES SWAPS COLLARS BASIS SWAPS PERIOD WEIGHTED VOLUME AVG. PRICE (MMBTU/D) ($/MMBTU) VOLUME (MMBTU/D) WEIGHTED AVG. FLOOR PRICE ($/MMBTU) WEIGHTED AVG. CEILING PRICE ($/MMBTU) Q2-Q $ $2.77 $3.10 FY $ $2.69 $3.06 INDEX PANHANDLE EASTERN PANHANDLE EASTERN VOLUME (MMBTU/D) WTD. AVG. DIFF to HENRY HUB ($/MMBTU) INDEX VOLUME (MMBTU/D) WTD. AVG. DIFF to HENRY HUB ($/MMBTU) 93.5 ($0.48) EL PASO 53.5 ($1.17) 5.0 ($0.81) EL PASO 60.0 ($1.58) 27