CORPORATE PRESENTATION ENCANA CORPORATION

Transcription

1 CORPORATE PRESENTATION ENCANA CORPORATION November 2017

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3 ENCANA Our Objectives North American leader in: Generating free cash flow Ŧ ~$1.5 billion cumulative over plan Cash flow Ŧ growth ~ 25% CAGR Corporate returns ROCE Ŧ climbs to 10-15% Execution efficiency ~$9,000 per flowing BOE Disciplined capital allocation 99% of capital to core assets Multi-basin advantage World class premium inventory in Texas oil and Canadian condensate Strong balance sheet Innovation company Focus on environmental, health, and safety performance TOP TIER RESOURCE OPERATIONAL EXCELLENCE BALANCE SHEET STRENGTH MARKET FUNDAMENTALS CAPITAL ALLOCATION Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 1 FOCUS ON QUALITY CORPORATE RETURNS Our Business Works Today Strategy Execution World class portfolio of assets Execution excellence Market fundamentals Disciplined capital allocation Unconventionals are all we do Track record of delivery Culture of innovation both technical and commercial Leader in industrial scale development Integrated supply chain management Managing risk Return on Capital Employed Ŧ climbs to 10-15% over the 5 year plan ~25% Cash Flow Ŧ CAGR 2017F 2022F ~$1.5 Billion Free Cash Flow Ŧ 2018F 2022F Assumes flat $50/bbl WTI oil price, flat $3/MMBtu NYMEX natural gas price. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 2 1

4 ROCE Ŧ (%) FOCUS ON CORPORATE RETURNS Generating Value Innovation & Discipline Drive Returns 15% 5 year plan Return on Capital Employed Ŧ climbs to 10-15% 10% Stringent capital discipline Highly efficient execution fueled by innovation Among the lowest overhead costs in industry Minimizing non-well capital & managing risk 5% 0% 2018F 2019F 2020F 2021F 2022F Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 3 FOCUS ON CORPORATE RETURNS Differentiated Results Independent analysis of over 50 North American E&P s Encana set to deliver above average ROCE Ŧ through 2019 * Assumptions / Methodology* Projected ROCE Ŧ based on 2018 at US$46/bbl, 2019 at $49/bbl Calculated with non-gaap adjusted net income, denominator adds back cumulative historical impairments 2014 forward 8% 5% 2% -1% Independent Analysis* Return on Capital Employed Ŧ 2016A 2017F 2018F 2019F ECA per External study US Small Caps Canadian Large Caps Excl. ECA US large Caps Canadian Small Caps * Source: Macquarie Research: Making Energy Great Again, September Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 4 2

5 Production (MBOE/d)** Capital ($MM) Cum. Free Cash Flow Ŧ ($MM) Cash Flow Ŧ ($MM) Corporate Margin Ŧ ($/BOE) AN OPERATOR INVESTORS CAN COUNT ON Increasing Value & Resiliency 2017F-2022F Cash Flow Ŧ ~25% CAGR Updated 5 year plan is better across the board Capital productivity, margins, cash flow Ŧ growth & leverage all improved by >10% with a $5/bbl lower oil price Maintaining efficiencies in a busier industry Exit-to-exit production growth well ahead of plan Major facility milestones achieved in Q ahead of schedule & under budget Innovation & discipline delivering value Expanding margins Enhancing productivity & capital efficiency Balance sheet is very strong Well positioned for 2018 & beyond 2018 growth within cash flow Ŧ Generating strong free cash flow Ŧ from 2019 onward Leading corporate return generation 4,000 3,000 2,000 1,000 3,000 2,000 1,000 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website F 2018F 2019F 2020F 2021F 2022F Cash Flow Corporate Margin ~$1.5B of Cumulative Free Cash Flow Ŧ 2017F 2018F 2019F 2020F 2021F 2022F Capital Cumulative Free Cash Flow 1,750 1,500 1,250 1, YEAR PLAN Self-Funding Post 2017 Resilient to operational risk Focus on high margin production Continuous improvement drives quality corporate returns Liquids production CAGR of ~20% Leading capital and operating efficiency sets up free cash flow Production Growth Within Cash Flow Ŧ 2017F 2018F 2019F 2020F 2021F 2022F * Assumes flat $50/bbl WTI and $3/MMBtu NYMEX. **2017 production does not include volumes from assets divested in

6 RESILIENT BUSINESS MODEL Capital Discipline & Risk Management Multi-basin portfolio Net Debt to Adjusted EBITDA Ŧ Short cycle capital x Highly focused capital allocation Integrated supply chain Flexible commercial arrangements Diversified market access Robust hedge program Investment grade credit rating x ~2x <2x 1.5x Q3 2017F 2018F 2019F- 2022F Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 7 WORLD CLASS PORTFOLIO Encana's Resource In Context Core positions in four of North America s premier basins >23,000 total inventory locations YTD premium inventory increased by ~6x 2017 drilling activity ~11,000 premium return locations >35% ATROR Ŧ returns Oil or condensate rich wells only Primary zones only* Industry typical well spacing** Montney 6,900 premium locations Duvernay 500 premium locations Permian 3,450 premium locations Eagle Ford 220 premium locations *Includes only Wolfcamp, Spraberry, Jo Mill, Lower Eagle Ford,Duvernay, Upper & Lower Montney; ** in Permian, 330 in Eagle Ford, 1000 in Duvernay, in Montney; Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures, including reconciliations, see the Company s website. 8 4

7 PERMIAN BASIN Premier North American Basin Developing the cube Critical to creating value at industrial scale Reservoir & above-ground benefits Natural extension of our experience & capabilities Type curves increased IP30s & IP180s up by ~20% Innovation and technology driving performance Stacked pay & completions upside New benches & advanced completions Coring up acreage boosts long lateral inventory Managing risk Execution efficiency offsetting inflation Just-in-time water infrastructure ensures availability & avoids over-capitalization Sophisticated supply-chain & logistics Market access secure *Estimated inventory based on ft spacing 9 ENCANA IN THE MONTNEY A Premier North American Play Encana s Montney is a condensate play 6,900 premium condensate-rich inventory* Stacked horizontal development Over 1,000 of pay, up to 6 stacked horizons Completions design driving productivity higher 5 year growth plan Increase margins through condensate growth Grow liquids to 50,000-60,000 bbls/d by end of 2018 ~35% liquids CAGR through 2022 Highly efficient plant infrastructure now on stream Basin leading operator Top well performance Most efficient operator with track record of innovation Longest laterals with highest completion intensity *Estimated inventory based on ft spacing 10 5

8 EAGLE FORD Core Position in the Oil Window Largely contiguous position in the Karnes Trough Most active and profitable trend in the Eagle Ford Completion innovations leading to better wells 2017 well inventory improvement Stacked pay, infill spacing, Austin Chalk offer premium inventory upside High value, high rate wells >80% of production is high value liquids Top quartile performance within industry 11 DUVERNAY Premier Position in World Class Reservoir Large contiguous land base within core of play Significant growth opportunity Industry leading operating performance Multi-well pads and integrated infrastructure significantly reduce cost structures Consistently delivering industry leading well performance Takeaway solution in place Rich Gas Premium agreement with Aux Sable, gas transport on Alliance Condensate transport on Pembina s Peace Pipeline WTI pricing for condensate 12 6

9 INNOVATION LEADERSHIP AT ENCANA A Competitive Advantage Subsurface Drilling & Completions Production Operations Commercial Arrangements Geo-cellular reservoir modeling to identify the best rocks Leveraging massive proprietary analytics dataset (core, logs, seismic, micro-seismic, fracture diagnostics, production) Proprietary in-house well design Integrated team with on-the-fly modeling capabilities Advanced completions Fibre-optic real-time pressure/completions design analytics Real-time production data capture & analysis Automation enables highly efficient growth Remote surveillance and control boosts well and facility up-time Creating optionality and managing risk Disrupting the commercial status quo Culture of Innovation Structured and driven to business outcomes Real time knowledge sharing across portfolio Analytics linked with deep understanding of first principles 13 INNOVATION IN OPERATIONS Driven By Culture Chiefs organizational structure Promotes rapid transfer of technology between plays Rapidly translated success in tight cluster design from Eagle Ford to other plays Scaling to cube development model Applying advanced completions at tighter well densities Well results keep getting better Type curves updated across the portfolio to reflect productivity improvements Deliberate and disciplined approach driving incremental value Data-driven innovation linked with first principles Short cycle times facilitate rapid implementation, learning and refinement Conceptual Advanced Completions Design Advanced Completions Tightening clusters maximizes fracture complexity 14 7

10 INNOVATION SUCCESS Identifying Optimal Completion Design and Geometry Applying advanced completions to high-density, stacked development Key principles: Tight cluster spacing and optimal hydraulics maximize fracture surface area Clean, non-guar based fluids lead to higher fracture conductivity Fine grained proppant maximizes fracture complexity Higher recovery from stacked pay reservoir Effective draw-down within cube Evaluating emerging technology Continued evolution and data-driven refinement Key Completion Design Factors 15 EXECUTION EXCELLENCE Efficient Operations are Safe Operations Leveraging our experience >4,500 horizontal wells drilled Rapid knowledge transfer between basins Leading industry safety performance year-over-year Development approach reduces risk Scope and scale necessitates highly sophisticated planning and logistics Integrated supply chain and established relationships with service providers Economies of scale reduce costs and improve infrastructure utilization Relentlessly pursuing additional optimization opportunities Multi-Spread Completions Plan vs. Actual Lease 16 8

11 CUBE DEVELOPMENT ABOVE-GROUND BENEFITS Development at Industrial Scale Highly efficient, agile development Multi-well pads Higher utilization of services & infrastructure Multiple drilling rigs and frac spreads on a pad Rapid cycle times Accelerated learnings Integrated supply chain Leveraging economies of scale Centralized planning and logistics Water Management Reliable market access Multi-well Pads Cube Development Above Ground Benefits Multi-rig, Multispread Reoccupied facilities Integrated Supply Chain 17 CUBE DEVELOPMENT Differentiated Execution Reservoir benefits Optimizes resource recovery Minimizes inter-wellbore communication Less downtime on existing wells Eliminates parent-child in-fill drilling No poor performing child wells in depleted reservoir Maximizes corporate returns Maximizing value from multi-zone stacked development 18 9

12 Volume (Mbbls/d) Volume (Bcf/d) MANAGING INFLATION Delivering in a Busier Environment Fully offsetting inflation with efficiency improvements Capital spent & wells drilled/on-stream match plan Seamless linkage between supply chain and ops teams Managing the supply chain Self-sourcing sand, water, OCTG, chemicals, drilling mud Better pricing & security of supply Secured services with options to extend Locked-in rates for majority of frac services for 2018 Legacy rig contracts expiring and renegotiated at lower market rates Reducing consumable usage Recycling water, optimizing trucking and fuel Challenging industry norms Increasing pump time per day Combination of logistics and local sand has driven delivered sand costs lower ECA D&C Cost Breakdown 40% of well cost is drilling 60% of well cost is completions D&C Key Component Cost Breakdown 30-35% sand & water 10-12% casing 10-12% pressure pumping 9-11% drilling rig 6-8% cement and mud 19 RISK MANAGEMENT PROGRAM Adds Greater Certainty to Cash Flow and De-Risks Capital Program 100 Oil and Condensate Positions 1.50 Natural Gas Positions 75 $39.40 x $49.95 x $61.40 /bbl $36.88 x $47.17 x $54.49 /bbl $45.00 x $57.08/bbl $46.22 x $56.05/bbl $52.27/bbl $52.98/bbl $2.27 x $2.75 x $3.07 /Mcf $2.96 x $3.57/Mcf $3.13/Mcf $3.75/Mcf $3.07/Mcf * ** 2018 WTI Fixed Price Swap WTI 3-Way Option WTI Costless Collar NYMEX Fixed Price Swap NYMEX 3-Way Option NYMEX Costless Collar NYMEX Call Option Sold Risk management positions as at October 31, * November to December 2017 positions. ** December 2017 positions

13 ASSET OVERVIEW Permian drilling in Midland County ENCANA S POTENTIAL PREMIUM RETURN INVENTORY Only Premium Inventory Consumed in Growth Plan Permian Basin Montney Premium Inventory 12,000 well inventory 3,450 premium locations <1,000 wells drilled in 5 year plan 9,600 well inventory 6,900 premium locations <800 wells drilled in 5 year plan Remaining Inventory Premium assumption spacing on average of 2.5 zones across basin Premium assumption 440 spacing in very rich gas condensate & volatile oil 660 spacing in rich gas condensate 990 spacing in wet gas Eagle Ford Premium Inventory 800 well inventory 220 premium locations ~200 wells drilled in 5 year plan Premium assumption 330 spacing Duvernay 1,000 well inventory 500 premium locations <200 wells drilled in 5 year plan Remaining Inventory Premium assumption 1,000 spacing *Premium locations are >35% ATROR Ŧ at $50 WTI & $3.00 NYMEX; Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures, including reconciliations, see Company s website

14 (MBOE/d) ENCANA S PERMIAN ACREAGE Core Position in Midland Basin Martin Howard In the Permian, execution efficiency at industrial scale is going to be critical Industry leader in driving efficiency at scale Cowden Pad Multi-Spread Operations Midland Glasscock Upton Reagan Encana Land Basin Core 23 PERMIAN TRACK RECORD OF DELIVERY Advanced Completions Fueling 50% Permian Growth 2017 program delivering 50% growth Q416 to Q417 Reinforced by strong Q4 results to date October oil production 50 Mbbls/d October production 80 MBOE/d Highly efficient operations Large pads leverage economies of scale Concurrent operations reduce cycle times Advanced sand and water logistics Re-occupied infrastructure Frac services secured for 2018 On Track to Grow Permian Production to ~75MBOE/d in Q Q4 16 Q1 17 Q2 17 Q3 17 Oct 17 Q4 17F 24 12

15 Cumulative Production (MBOE)* Oil Production IP180/1,000ft (bbls/d) WELL PRODUCTIVITY Encana Wells Outpacing Peer Results 75 Producers with high density stack development Peer 1 Peer 2 ECA Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Data sourced from IHS, includes Midland Basin data from 2014 onward. Peers include APA, AREX, CPE, CVX, CXO, EGN, END, EPE, FANG, LPI, OXY, PXD, QEP, RSPP, SM and XOM 25 PERMIAN MAXIMIZING RETURNS AND RECOVERY 2017 Cube Development Results Step-change productivity increases Cube development approach continues to evolve in 2017 Data-driven innovation Added new benches Spacing and stacking trials Implemented advanced completion designs Evaluating emerging technologies Recent Midland County 10-well cube onstream First wells averaging >1,600 BOE/d over 14 days Continue to lead industry in dense-well development Abbie Laine Q RAB 2 Q Permian Cube Evolution Davidson 02 E Q Davidson 02 W Q Cowden 30 Q Days * 3-stream pad average, well results normalized to 7,500 Midland Type Curve IP

16 CUBE DEVELOPMENT ABOVE-GROUND BENEFITS Effective Water Management Improves capital efficiency and de-risks supply 3 frac spreads per hub Simple and effective catch basin design Water hubs pay out in less than 12 months Mitigates risk of water supply restrictions County-by-County solution Howard County water infrastructure transaction minimizes infrastructure investment Water provider can service broader market for a lower fee Reducing all-in water costs by ~$1/bbl On track to average 25% recycled water use in 2017 Expect to average 40% in 2018 D&C cost savings up to $300k/well LOE savings up to ~$0.80/BOE Martin County Central Water Resource Hub 27 EXPANDING MARGINS Reducing Operating Costs Improving efficiencies Company-wide effort Accountability at the operator level Working smarter >80% of produced water on pipe >70% of production on remote monitoring and control Negotiating the best price $/BOE $12 $10 $8 $6 Permian Direct Operating Cost Reductions ~30% Improvement in operating costs $4 $2 $ F 28 14

17 MBOE/d PERMIAN 5 Year Growth Profile Five Year Production Profile >50% of Encana s capital directed to the Permian in 2018 Permian production expected to grow 3x 5 year CAGR 25% Quality inventory with scale No infrastructure or midstream limitations Minimal vertical program F 2018F 2019F 2020F 2021F 2022F 29 MIDSTREAM AND MARKETING OVERVIEW Permian Permian Gathering system links production to pipeline hubs Midland Crane Colorado City Pipelines connect to Cushing and Gulf Coast Majority of oil production gathered via pipeline with access to multiple physical markets Firm gas gathering and NGL processing with access to Waha and Mt. Bellvieu markets Permian: Proximity to market and environment of responsive infrastructure development Secured capacity on Enterprise (Echo Pipeline) adds market diversity and reduces physical risk (2018) Secured firm, low-cost pipeline capacity to Gulf Coast refining/export markets (Enterprise Echo Pipeline 2018) No take or pay commitments 30 15

18 Crude Oil Production / Takeaway Capacity (Mbbls/d) Q1'12A Q3'12A Q1'13A Q3'13A Q1'14A Q3'14A Q1'15A Q3'15A Q1'16A Q3'16A Q1'17E Q3'17E Q1'18E Q3'18E Q1'19E Q3'19E Q1'20E Q3'20E Q1'21E Q3'21E Q1'22E Q3'22E PERMIAN BASIN FUNDAMENTALS Past & Future Pipeline Capacity Expansions Align with Growth 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Periods of temporary dramatic weakness in local price Potential price risk (timing of future projects) Current oil export infrastructure >2.7 MMbbls/d ~300 Mbbls/d additional capacity put in place in 2017 Enterprise Midland-Sealy pipeline expected to be in service Q Proposed projects targeting 2018/2019 in-service dates Production growth and timing of pipeline projects creates potential for temporary Midland differential weakness Local Refineries Pipelines Under Construction Permian Supply Existing Pipelines Identified Pipeline Projects Source: Wells Fargo Securities, Encana 31 PERMIAN RISK MANAGEMENT PROGRAM Market Access & Price Risk Management 2018F 2019F F ~10% 10 Mbbls/d ($1.09)/bbl 19 Mbbls/d to Houston 37 Mbbls/d ($0.78)/bbl ~40% 39 Mbbls/d to Houston Midland Exposure EPD* Midland to Houston WTI-Midland Differential Hedges Positions as at September 30, * Enterprise Products Partners L.P 32 16

19 PERMIAN RESERVOIR Massive Potential with Stacked Benches Zone Martin Midland/ Upton Glasscock Howard Clear Fork M. SPBY Jo Mill L. SPBY L. SPBY- 2 nd WCMP A WCMP A- 2 nd WCMP B WCMP C WCMP D / Cline Deep Targets Total Total Inventory 2,200 5,200 1,300 3,600 ~12,000 Premium 750 1, , PREMIUM INCREASE OUTPACING DRILLING Gross Premium Return Inventory County Midland/ Upton Martin Howard Glasscock IP30 (BOE/d) IP180 (BOE/d) EUR/Well (Mbbls) EUR/Well (MBOE) 1,020 1, GOR (scf/bbl) 2,800 2,000 2,450 1,960 Gross Premium Return Inventory 1, ,450 premium return inventory locations Increase of 700 locations 40% from tighter well density 30% from increased type curve 30% from longer laterals 410 more in Martin/Midland/Upton 200 more in Howard 90 more in Glasscock 3.3 billion BOE premium EUR Increase of 1 billion BOE since October update Estimated inventory based on ft spacing, 7,500 lateral length, Permian type curves are stated on a three stream basis

20 Condensate IP180 (bbls/d, BOE/d) 1,000 Montney 650 Montney B.C. Alberta MONTNEY Core Position Tower/Dawson (up to 6 laterals) Pipestone (up to 4 laterals) Tower Dawson South Pipestone 40mi 35 MONTNEY WELL PRODUCTIVITY Top Performance vs. Peers ECA IP180 yields of bbls/mmcf Focused on higher margin, higher return condensate rich wells Peer data sourced from RS Energy Group, raw data provided by geoscout

21 (MBOE/d) % Liquids Cumulative Condensate Production* (MBbls) MONTNEY TRACK RECORD OF DELIVERY Delivering Condensate Growth Well targeting and completion design driving well productivity 28 well Tower cube average IP30 of 700 bbls/d condensate Recent Dawson South Upper Montney well stabilized on test at >700 bbls/d condensate and >11MMcf/d of gas Q3 Pipestone two well pad average IP90 of 750 bbls/d condensate All 3 plants are on-stream 1-6 months ahead of schedule and ~10% under budget Saturn plant started up November 1, 2017 October production of 147 MBOE/d, including >25 Mbbls/d liquids Dawn service began November 1st *Pipestone well results normalized to 9,000 & Tower normalized to 8,200 Significant Condensate Production Across Montney Acreage Days Q3 Avg Tower GC Production Q3 Avg Tower RGC Production Q3 Avg Pipestone VO Production Pipestone VO Type Curve IP30 Tower RGC Type Curve IP30 Tower GC Type Curve IP30 Montney Liquids Production to Double Over Q416 Q4 16 Q1 17 Q2 17 Q3 17 Oct 17 Q4 17F Total Production % Liquids 25% 20% 15% 10% 5% 0% 37 AGREEMENT WITH VERESEN MIDSTREAM Fee-for-Service Structure Tower, Sunrise and Saturn plants on-stream Facilities came on ahead of schedule and under budget Encana designed, built and operates the facilities Innovative risk-sharing arrangement No up-front capital spend by Encana No traditional take-or-pay Competitive fee structure Canadian margins are improving Q Condensate growth New plants expected to reduce Canadian per unit T&P expense All 3 Montney Plants On-Stream 38 19

22 Net Raw Capacity bbls/d Normalized $/BOE* % Liquids MONTNEY MARGIN EXPANSION Driving Cash Flow Ŧ Growth Montney liquids production set to more than double from Q to Q Margin impact is significant Q operating margin Ŧ expected to be up >50% versus Q driven by greater liquids mix This expansion equates to an incremental ~$200 million in annualized operating cash flow Ŧ Montney Margin Expansion with Increased Liquids % % % % % % Q4 16 Q1 17 Q2 17 Q3 17 Q4 17F Netback $/BOE, normalized % Liquids Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. * Per unit Netback normalized to US$50.00 WTI Oil, US$3.00 NYMEX Gas and US$1.00 AECO Differential, no hedge impact & flat FX. 39 MONTNEY MIDSTREAM INFRASTRUCTURE Liquids Handling Capacity Supports Growth & Flexibility Key Montney Infrastructure Additions 100,000 85,000 Current Net Raw Capacity Expect >70,000 bbls/d Sales 70,000 55,000 40,000 25,000 10,000-5,000 Existing Processing Capacity Tower (Sept. 2017) South Central Hub 1 (Q4 2017) Sunrise (Oct 2017) Saturn Phase 2 (Nov 2017) South Central Hub 2 (Q1 2018) Tower Hub (Late 2018) Processing Capacity (2018) Pipestone Hub (Late 2018) Processing Capacity (2019) Condensate *Condensate and NGL capacities assume a 30% cut on C3+ facility capacities. All volumes are before shrink and royalties. **Saturn Phase 2 includes liquids associated with the existing compression on-site and a 3,600 bbls/d addition at the adjacent 9-27 facility. ***Pipestone facilities are not included in the VMLP agreement. NGL 40 20

23 $/BOE % Liquids Condensate-Gas Ratio (bbls/mmcf) MONTNEY SUSTAINED CONDENSATE PRODUCTION Detailed Reservoir Engineering Condensate-gas ratio (CGR) varies with time Type curves reflect phase behaviour Initial condensate ratios up to 800 bbls/mmcf in the VO window ~1/2 of 2017 program are VO, VRGC and RGC GC development makes up remainder of program Expect a similar mix in Average Montney CGR Type-Curve Trends *WG=wet gas, GC = gas condensate, RGC = rich gas condensate, VRGC = very rich gas condensate, VO = volatile oil Months GC RGC VRGC VO 41 ENCANA MONTNEY Operating Cost Performance Grande Prairie Operations Control Centre Workforce collaboration across the asset Optimizing water handling Managing field work using automated work orders and integrated scheduling Leveraging technology through the Operation Control Center Evaluating key contracts with suppliers & contractors Negotiating reduced rates and costs Scope of work reductions Critical review of all repairs / maintenance and well workovers Reduction in Direct Operating Expense 18% 15% 12% 9% 6% 3% 0% F LOE $/BOE Liquids % 42 21

24 MMcf/d Mbbls/d ENCANA MONTNEY 5 Year Growth Profile Development focused in condensate rich areas 2018 program to keep liquids capacity full Additional capacity comes online late 2018 Operating margin expected to increase >40% by 2022 Expect liquids production of >70 Mbbls/d by 2019 Liquid weighting grows to >25% of total by 2019 Liquids handling expansions support growth plans ,500 1,000 Liquids Growth Profile 2017F 2018F 2019F 2020F 2021F 2022F Gas Growth Profile F 2018F 2019F 2020F 2021F 2022F Volumes quoted are net to Encana 43 WESTERN CANADIAN MARKET FUNDAMENTALS Premium Condensate Market & Natural Gas Export Basin Natural Gas Export Pipeline Condensate Import Pipeline ~97% YTD WTI Price Realization Condensate is a premium product in Western Canada ~4% 2018F total revenue exposed to AECO Combination of physical transportation and basis hedges 100% Natural Gas Export Pipeline Condensate Import Pipeline Firm transport for expected growth Limited production curtailment risk Source: Encana Fundamentals, RBC Capital Markets, Various Pipeline Postings; *Net Effective Capacity (Bakken Access) 44 22

25 WCSB RISK MANAGEMENT PROGRAM Market Access & Price Risk Management* 2018F 2019F F ~ 20% Less than 1/2 316 MMcf/d to Dawn 475 MMcf/d ($0.87)/Mcf ± < 33% 500 MMcf/d ($0.88)/Mcf ± 46 MMcf/d to Chicago 120 MMcf/d to Sumas/Malin 316 MMcf/d to Dawn 88 MMcf/d to Chicago 114 MMcf/d to Malin AECO Exposure Physical Export Transport** AECO Basis Hedges *Charts represent expected Western Canadian Sedimentary Basin natural gas production only. Positions as at September 30, Hedged and transport volumes are converted to Mcf at a 1:1 ratio from MMBtu. **Includes fixed transport to West Coast (Malin), Chicago & Eastern Canada (Dawn). ± Price stated is the differential versus NYMEX pricing. 45 MONTNEY Cutbank Ridge Partnership (CRP) Partnership with a subsidiary of Mitsubishi Encana: 60% interest Mitsubishi: 40% interest Investment structure (C$2.9B) C$1.45 billion upfront in 2012 Further investment of C$1.45 billion during the commitment period Third party carry capital expected to extend through F third party capital ~C$225 $250 million third party capital C$450 - $500 million Post carry period Mitsubishi funds its 40% of the Partnership's future capital investment 46 23

26 Oil Production IP180/1,000ft (bbls/d) MONTNEY Gross Premium Return Inventory Region Tower Dawson South Pipestone Type Wet Gas Gas Condensate Rich Gas Condensate Wet Gas Gas Condensate Gas Condensate Rich Gas Condensate Very Rich Gas Condensate Volatile Oil IP30 (BOE/d) 1,800 1,900 1,200 1,400 1,450 1,550 2,000 2,200 2,400 2,600 1,500 1,600 1,850 1,900 1,750 1, ,200 IP180 (BOE/d) 1,700 1,800 1,150 1,350 1,250 1,350 1,600 2,000 1,900 2,100 1,250 1,350 1,600 1,700 1,750 1,800 1,000 1,300 EUR/Well (MBOE) 1,850 1,950 1,350 1,450 1,300 1,400 1,750 1,850 1,500 1, ,000 1,100 1,200 1,300 1, ,200 Condensate Yield (bbls/mmcf) Gross Premium Return Inventory < < >250 1, premium return locations added to Montney inventory Driven primarily by type curve improvements due to enhanced productivity Implementation of advanced completions represents further upside Estimated inventory based on ft. spacing, 8,200-9,800 lateral length. Volumes are stated on a shrunk condensate and a raw gas basis. 47 LEADING OPERATOR Top Karnes County Producers Top Performance vs Peers* Eagle Ford *Data sourced from IHS, Inc. Includes all data from August 2016 onward. Peers include DVN, COP, EOG, MRO, MUR, COG, CRZO, NBL, EPE, CHK, STO, SN and SM 48 24

27 (MBOE/d) Cumulative Production (MBOE) EAGLE FORD TRACK RECORD OF DELIVERY Generating Free Cash Flow Ŧ Strong performance from Eagle Ford and Austin Chalk Q3 production of 52 MBOE/d Maintaining production while generating free cash flow Ŧ Focus on completions design evolution to increase productivity and optimize capital Evaluating spacing and stacking in Eagle Ford & Austin Chalk Safely and effectively managed through Hurricane Harvey with no damage and minimal impact Days 75 Average 2017 Eagle Ford Program Productivity* 2017 Avg Eagle Ford Prod 2017 Avg Austin Chalk Prod Austin Chalk Type Curve IP180 Eagle Ford Type Curve IP180 Eagle Ford Maintaining Plateau Production ~50 MBOE/d *Well results normalized to 5, Q4 16 Q1 17 Q2 17 Q3 17 Oct 17 Q4 17F Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 49 EXPANDING MARGINS Reducing Operating Costs Leveraging company-wide effort Optimized repairs, maintenance, and workovers Shifting work in-house Supply management gains Lower costs on chemicals, water hauling Improved artificial lift performance $/BOE $10 $9 $8 $7 Eagle Ford Direct Operating Cost Reductions ~20% Improvement in operating costs $6 $5 $ F 50 25

28 MIDSTREAM AND MARKETING OVERVIEW Eagle Ford Close proximity to market and well-developed infrastructure Eagle Ford Three Rivers Corpus Christi Houston Firm gas gathering and NGL processing aligned with asset development program Infield gathering and extensive market assets in place to ensure flow and downstream connectivity Diverse physical marketing portfolio with access to Gulf Coast refining markets Proximity to market minimizes transportation cost and related commitments while maximizing margins 51 EAGLE FORD Gross Premium Return Inventory Type Curve Eagle Ford Austin Chalk IP30 (BOE/d) IP180 (BOE/d) EUR/Well (Mbbls) EUR/Well (MBOE) GOR (scf/bbl) 2,000 1, premium return inventory locations Inventory adds driven primarily by type curve increases Have added ~2X premium inventory since Oct 2016 Testing additional opportunity in both the Graben area of the Eagle Ford and in the Austin Chalk Gross Premium Return Inventory Estimated Eagle Ford inventory based on 330 ft spacing, 5,000 lateral length. Type curves are stated on a three stream basis

29 (MBOE/d) Cumulative Production (MBOE) Condensate Production IP180/1,000ft (bbls/d) LARGEST PRODUCER IN THE PLAY Duvernay Production at a Glance Top Productivity vs. Peers* Encana Land Core Reef Duvernay Acreage Alberta Simonette South Simonette North Fox Creek 10 0 Encana Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 12 miles Data sourced from RS Energy Group, Peers include MUR, RDSA, CVX, Hiltic & Vesta 53 DUVERNAY TRACK RECORD OF DELIVERY Delivering Record Performance Strong production performance October production of >24 MBOE/d Asset generating free cash flow Ŧ Advanced completion design Encouraging early results Industry leading costs and productivity Efficient operations driving down LOE 70% reduction in operating cost since Days Average 2017 Duvernay Program Productivity* 2017 Avg South Simonette VRGC Prod 2017 Avg North Simonette VRGC Prod Duvernay Production Growth in 2017 Simonette South VRGC Type Curve IP180 Simonette North VRGC Type Curve IP180 0 Q4 16 Q1 17 Q2 17 Q3 17 Oct 17 Q4 17F *Simonette North normalized to 8,200, Simonette South normalized to 8,900 lateral length Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website

30 EXPANDING MARGINS Duvernay Operating Cost Performance Dramatic reduction in operating costs Three plants on-stream since 2014 Optimized for liquids handling Reduced trucking from location $/BOE $7 $6 $5 Duvernay Direct Operating Cost Reductions >70% reduction in operating costs $4 $3 $2 $1 $0 High CGR Gas Plants F 55 MIDSTREAM AND MARKETING OVERVIEW Duvernay Condensate sales via pipeline to premium Edmonton market center Duvernay Condensate to Edmonton market center Alliance Pipeline to U.S. Midwest (Chicago) Firm market access aligned with development program Achieved liquids price upgrade while minimizing midstream capex via Alliance pipeline Diversified pricing exposure for liquids and natural gas in Chicago market 56 28

31 STRATEGIC INFRASTRUCTURE CONNECTIVITY Duvernay Built For Purpose Midstream Solution Plants inter-connected through pipeline network Can operate in NGL recovery or rejection mode Requires minimal equipment on well sites Gross infrastructure capacity 155 MMcf/d & 30 Mbbls/d Potential future build-out Debottleneck existing plants to maximize liquids throughput Gross Facility Capacity Gas Capacity 155 MMcf/d Liquids Handling 30,000 bbls/d Keyerra Simonette Expansion planned at the end of the decade 40 mi Production/Fuel Gas Trunk Line 36 mi Water Distribution Line Semcams KA High CGR Gas Plants 57 DUVERNAY JOINT VENTURE Brion (formerly Phoenix, a subsidiary of PetroChina) agreed to invest C$2.18 billion for 49.9% working interest C$1.18 billion up front cash in 2012 Further investment of C$1.0 billion during the commitment period JV carry capital reduces Encana s capital & leverages economics 2017F consumes remaining carry capital ~C$95 million 58 29

32 DUVERNAY Gross Premium Return Inventory Region Simonette South Simonette North Type Rich Gas Condensate Very Rich Gas Condensate Rich Gas Condensate Very Rich Gas Condensate IP30 (BOE/d) 1,550 1,650 1,600-1,700 1,200 1,300 1,200 1,300 IP180 (BOE/d) 1,100 1,200 1,150 1, premium return inventory locations 100% replacement of wells drilled since October 2016 EUR/Well (MBOE) 1, ,300 1,400 1,000 1, ,050 Condensate Yield (bbls/mmcf) Gross Premium Return Inventory Gas heat content of 1,200 Btu/scf. Estimated inventory based on 1,000 ft. spacing, Simonette North at 8,200 lateral length, Simonette South at 8,900' lateral length. Volumes are stated on a shrunk condensate and a raw gas basis 59 SAN JUAN BASIN Evaluating Liquids Growth Potential 2017 operation highlights 6 well program 6,100 average completed lateral length Evaluation Program Target best rock Advanced completion design Well spacing trial Stacked pay potential 2017 program 60 30

33 SUPPLEMENTAL LIQUIDS VALUE CHAIN Projected Composition of Total Liquids Production 2017F* (Mbbls/d) Canada 2017F Pricing (%WTI) 2017F* (Mbbls/d) US 2017F Pricing (%WTI) Oil % % Condensate** % % Butane % % Propane % % Ethane % % Liquids primarily comprised of higher-value products *2017F based on company guidance as at July 21, 2017; production ranges are not additive; **Includes plant condensate 62 31

34 G&A $/BOE Production MBOE/d WESTERN CANADIAN CONDENSATE FUNDAMENTALS Premium Condensate Market Condensate demand in western Canada is expected to outstrip domestic supply with imports bridging the gap Source: RBC Capital Markets and Government Data 63 BUILDING ON OUR TRACK RECORD Maintaining Corporate Efficiency Low overhead costs enable returns Interest expense on debt stable with long term fixed rate maturities ~$70MM quarterly* Market optimization carries legacy unutilized costs for assets disposed ~$25MM per quarter Top quartile G&A/BOE Expected to further improve as production growth continues Current G&A levels can support activity levels in 2018 and beyond ~$45MM quarterly** Encana and Peers: G&A per BOE and Production MBOE/d *** $ $ $ $0 - Peer 11 Peer 10 Peer 9 Peer 8 Peer 7 Peer 6 Peer 5 Peer 4 Peer 3 Peer 2 ECA Peer G&A/BOE Production * Excluding one time payments. (Quarterly averages) **Excluding restructuring and long-term incentive costs. *** YTD June 2017, Source: IHS Company Insights; ECA internal figures. Peers include: CNQ, CXO, EGN, EOG, FANG, LPI, MRO, MUR, PXD, RSPP, SN 64 32

35 (US$ MM) DISCIPLINED FINANCIAL MANAGEMENT Access to Ample Liquidity Through 2020 $4.5B fully committed, unsecured, revolving credit facilities $4.5B available at September 30, 2017 Committed to July 2020 No use of credit facility to back-stop long term commitments Single financial covenant Debt cannot exceed 60% of adjusted capitalization Adjusted capitalization = debt + equity + $7.7B equity adjustment* 22% as at September 30, 2017 Debt to adjusted capitalization ratio has improved since % 70% 60% 50% 40% 30% 20% 10% ECA Ratio Well Within Covenant Threshold Debt to Adjusted Capitalization Ratio 36% 30% 60% Threshold 28% 23% 22% 0% YE 2013 YE 2014 YE 2015 YE 2016 Q *Add back equity adjustment for cumulative historical ceiling test impairments recorded YE 2011 in conjunction with adoption of US GAAP; see MD&A for additional detail on ratio calculation. 65 DISCIPLINED FINANCIAL MANAGEMENT Debt Portfolio as at September, 2017 Total debt reduced by ~$3 billion since Y/E 2014 Significant financial flexibility with no debt maturities until 2019 ~75% of fixed rate long-term debt not due until 2030 and beyond Investment grade credit rating $4.5B fully committed, unsecured, revolving credit facilities Fixed Debt Maturity Schedule 1,

36 NON-GAAP MEASURES Certain measures in this presentation do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-gaap measures. These measures may not be comparable to similar measures presented by other companies. These measures have been provided for meaningful comparisons between current results and other periods and should not be viewed as a substitute for measures reported under U.S. GAAP. For additional information regarding non-gaap measures, including reconciliations, see the Company s website and Encana s most recent Annual Report as filed on SEDAR and EDGAR. Non-GAAP measures include: Non-GAAP Cash Flow, Free Cash Flow and Corporate Margin Non-GAAP Cash Flow (or Cash Flow) is defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and current tax on sale of assets. Corporate Margin is Non-GAAP Cash Flow per BOE of production. Free Cash Flow is defined as Non-GAAP Cash Flow in excess of capital investment, excluding net acquisitions and divestitures. Management believes these measures are useful to the company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, and are an indication of the company s ability to generate cash to finance capital programs, to service debt and to meet other financial obligations. These measures may be used, along with other measures, in the calculation of certain performance targets for the company s management and employees. Net Debt, Adjusted EBITDA and Net Debt to Adjusted EBITDA Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents. Management uses this measure as a substitute for total long-term debt in certain internal debt metrics as a measure of the company s ability to service debt obligations and as an indicator of the company s overall financial strength. Adjusted EBITDA is defined as trailing 12-month net earnings (loss) before income taxes, DD&A, impairments, accretion of asset retirement obligation, interest, unrealized gains/losses on risk management, foreign exchange gains/losses, gains/losses on divestitures and other gains/losses. Net Debt to Adjusted EBITDA is monitored by management as an indicator of the company s overall financial strength and as a measure considered comparable to peers in the industry. Non-GAAP Operating Earnings (Loss) is defined as Net Earnings (Loss) excluding non-recurring or non-cash items that management believes reduces the comparability of the company s financial performance between periods. These items may included but are not limited to, unrealized gains/losses on risk management, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures and gains on debt retirement. Income taxes may include valuation allowances and the provision related to the pre-tax items listed, as well as income taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate. After-Tax Rate of Return (ATROR) is defined as the discount rate at which the net present value of the after-tax cash flows is equal to zero. Encana uses nine percent as the discount rate for its standard investment decisions, which is intended to represent the Company s long term cost of capital. For project evaluation, cost of capital includes land, drilling and completion costs (D&C), seismic, facilities and gathering. D&C costs include all capital outlay for activities related to drilling and completing the well in addition to permanent production equipment such as site compressors, separation equipment and liquid storage tanks. Corporate Return is defined as the After-Tax Rate of Return (ATROR) including the impact of non-well capital costs and overhead costs, such as administrative and interest expenses. Operating Margin/Operating Netback Product revenues less costs associated with delivering the product to market, including production, mineral and other taxes, transportation and processing and operating expenses. When presented on a per BOE basis, Operating Margin/Operating Netback is defined as indicated divided by average barrels of oil equivalent sales volumes. Operating Margin/Operating Netback is used by management as an internal measure of the profitability of a play(s). Income Margin is defined as Operating Margin less finding and development costs, non-well capital costs and allocated overhead costs, such as administrative and interest expenses. When presented on a per BOE basis, Income Margin is defined as indicated divided by average barrels of oil equivalent production volumes. Income Margin is used by management as an internal measure of the profitability of a resource play. 67 FUTURE ORIENTED INFORMATION This presentation contains certain forward-looking statements or information (collectively, FLS ) within the meaning of applicable securities legislation, including the U.S. Private Securities Litigation Reform Act of FLS include: expectation of meeting or exceeding the targets in Encana s corporate guidance and five-year plan anticipated capital program, including focus of development, amount and allocation thereof, number of wells on stream, level of capital productivity, expected return and source of funding well performance, completions intensity, location of acreage and costs relative to peers and within assets anticipated production, including growth from core assets, cash flow, capital coverage, payout, profit, net present value, rates of return, recovery, return on capital employed, production efficiency, execution efficiency, operating, income and corporate margins, including expected timeframes, impact of prices and commodity mix number of potential drilling locations (including premium return inventory and ability to add to or consume such inventory), well spacing, number of wells per pad, decline rate, rig count, rig release metrics, focus and timing of drilling, anticipated vertical and horizontal drilling, cycle times, commodity composition, gas-oil ratios and operating performance compared to type curves running room and scale of assets, including its competitiveness and pace of growth against peers pacesetting operational metrics being indicative of future well performance and costs, and sustainability thereof timing, success and benefits from innovation, cube development approach, advanced completions design, technology advancements and asset quality, including efficiency, capital productivity and transferability of ideas expected transportation and processing capacity, commitments, curtailments and restrictions, including flexibility of commercial arrangements and costs and timing of certain infrastructure being operational anticipated reserves and resources, including product types and stacked resource potential anticipated third-party incremental and joint venture carry capital ability to manage costs and maintain or enhance efficiencies, including drilling and completion, operating, corporate, transportation and processing, associated staffing levels, services secured and sustainability thereof expected net debt and debt ratios growth in long-term shareholder value and timing thereof commodity price outlook anticipated hedging and outcomes of risk management program, including exposure to commodity prices and foreign exchange, amount of hedged production, market access and physical sales locations management of balance sheet and credit rating, including access to sources of liquidity expected growth, returns and free cash flow in Encana s five-year plan, including projections based on commodity prices and use of cash therefrom environmental, health and safety performance advantages of Encana s multi-basin portfolio execution of strategy and future outlook, including funding within cash flow, production, growth and leverage, and momentum into 2018 Readers are cautioned against unduly relying on FLS which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; ability to access its credit facilities and shelf prospectuses; assumptions contained in Encana s corporate guidance, five-year plan and in this presentation; data contained in key modeling statistics; enforceability of risk management program; results from innovations; expectation that counterparties will fulfill their obligations under the gathering, midstream and marketing agreements; access to transportation and processing facilities where Encana operates; assumed tax, royalty and regulatory regimes; and expectations and projections made in light of, and generally consistent with, Encana's historical experience and its perception of historical trends, including with respect to the pace of technological development, benefits achieved and general industry expectations. Risks and uncertainties that may affect these business outcomes include: ability to generate sufficient cash flow to meet obligations; commodity price volatility; ability to secure adequate transportation and potential pipeline curtailments; variability and discretion of Encana's board of directors to declare and pay dividends, if any; timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties, including impact of weather; counterparty and credit risk; impact of a downgrade in credit rating and its impact on access to sources of liquidity; fluctuations in currency and interest rates; risks inherent in Encana's corporate guidance; failure to achieve cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation of laws or regulations; risks associated with existing and potential lawsuits and regulatory actions made against Encana; impact of disputes arising with partners, including suspension of certain obligations and inability to dispose of assets or interests in certain arrangements; Encana's ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as partnerships or joint ventures and the funds received in respect thereof which Encana may refer to from time to time as proceeds, deferred purchase price and/or carry capital, regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties impacting Encana's business, as described in its most recent Annual Report on Form 10-K and as described from time to time in Encana s other periodic filings as filed on SEDAR and EDGAR. Although Encana believes the expectations represented by such FLS are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. FLS are made as of the date of this presentation and, except as required by law, Encana undertakes no obligation to update publicly or revise any FLS. The FLS contained in this presentation are expressly qualified by these cautionary statements. Certain future oriented financial information or financial outlook information is included in this presentation to communicate current expectations as to Encana s performance. Readers are cautioned that it may not be appropriate for other purposes. Rates of return for a particular asset or well are on a before-tax basis and are based on specified commodity prices with local pricing offsets, capital costs associated with drilling, completing and equipping a well, field operating expenses and certain type curve assumptions. Pacesetter well costs for a particular asset are a composite of the best drilling performance and best completions performance wells in the current quarter in such asset and are presented for comparison purposes. Drilling and completions costs have been normalized as specified in this presentation based on certain lateral lengths for a particular asset. Premium well locations are locations with expected after tax returns greater than 35% at $50/bbl WTI and $3/MMBtu NYMEX. For convenience, references in this presentation to Encana, the Company, we, us and our may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships ( Subsidiaries ) of Encana Corporation, and the assets, activities and initiatives of such Subsidiaries

37 ADVISORY REGARDING OIL & GAS INFORMATION All proved and probable reserve and economic contingent resource estimates in this presentation are effective as of December 31, 2016, prepared by internal qualified reserves evaluators in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation Handbook ( COGEH ), National Instrument ( NI ) and SEC regulations, as applicable, and are audited by independent qualified reserves auditors engaged by Encana. Detailed Canadian protocol disclosure is contained in Encana s Form F1 for the year-ended December 31, 2016 ( Form F1 ) and detailed U.S. protocol disclosure is contained in Encana s Annual Report on Form 10-K for the yearended December 31, 2016 ( Annual Report on Form 10-K ), each of which Encana has filed with applicable securities regulatory authorities on February 27, Additional detail regarding Encana s economic contingent resources disclosure is available in the Supplemental Disclosure Document filed concurrently with the Form F1. Information on the forecast prices and costs used in preparing the Canadian protocol estimates is contained in the Form F1. For additional information relating to risks associated with such estimates, see Item 1A. Risk Factors in the Annual Report on Form 10-K. Reserves are the estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: analysis of drilling, geological, geophysical and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are those reserves which can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Contingent resources do not constitute, and should not be confused with, reserves. Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is uncertainty that it will be commercially viable to produce any portion of the resources. All of the resources classified as contingent are considered to be discovered, and as such have been assigned a 100% chance of discovery, but have however been risked for the chance of development. The chance of development is defined as the likelihood of a project being commercially viable and development proceeding in a timely fashion. Determining the chance of development requires taking into consideration each contingency and quantifying the risks into an overall development risk factor at a project level. Contingent resources are categorized as economic if those contingent resources have a positive net present value under currently forecasted prices and costs. In examining economic viability, the same fiscal conditions have been applied as in the estimation of Encana s reserves. Contingencies include factors such as required corporate or third party (such as joint venture partners) approvals, legal, environmental, political and regulatory matters or a lack of infrastructure or markets. Encana uses the terms play, resource play, total petroleum initially-in-place ( PIIP ), natural gas-in-place ( NGIP ), and crude oil-in-place ( COIP ). Play encompasses resource plays, geological formations and conventional plays. Resource play describes an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which when compared to a conventional play, typically has a lower geological and/or commercial development risk and lower average decline rate. PIIP is defined by the Society of Petroleum Engineers - Petroleum Resources Management System ( SPE-PRMS ) as that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to total resource potential ). NGIP and COIP are defined in the same manner, with the substitution of natural gas and crude oil where appropriate for the word petroleum. As used by Encana, estimated ultimate recovery ( EUR ), which Encana may refer to as recoverable resource potential, has the meaning set out jointly by the Society of Petroleum Engineers and World Petroleum Congress in the year 2000, being those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom. Encana has provided information with respect to its assets which are analogous information as defined in NI , including estimates of PIIP, NGIP, COIP, EUR and production type curves. This analogous information is presented on a basin, sub-basin or area basis utilizing data derived from Encana's internal sources, as well as from a variety of publicly available information sources which are predominantly independent in nature. Production type curves are based on a methodology of analog, empirical and theoretical assessments and workflow with consideration of the specific asset, and as depicted in this presentation, is representative of Encana s current program, including relative to current performance, but are not necessarily indicative of ultimate recovery. Some of this data may not have been prepared by qualified reserves evaluators, may have been prepared based on internal estimates, and the preparation of any estimates may not be in strict accordance with COGEH. Estimates by engineering and geo-technical practitioners may vary and the differences may be significant. Encana believes that the provision of this analogous information is relevant to Encana's oil and gas activities, given its acreage position and operations (either ongoing or planned) in the areas in question, and such information has been updated as of the date hereof unless otherwise specified. Due to the early life nature of the various emerging plays discussed in this presentation, PIIP is the most relevant specific assignable category of estimated resources. There is no certainty that any portion of the resources will be discovered. There is no certainty that it will be commercially viable to produce any portion of the estimated PIIP, NGIP, COIP or EUR. Estimates of drilling locations and premium return well inventory include proved, probable, contingent and unbooked locations. These estimates are prepared internally based on Encana's prospective acreage and are based on an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Approximately 36 percent of all locations specified in our core assets are booked as either reserves or resources, as prepared by internal qualified reserves evaluators using forecast prices and costs as of December 31, Unbooked locations do not have attributed reserves or resources and have been identified by management as an estimation of Encana's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Encana will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The locations on which Encana will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of capital, regulatory and partner approvals, seasonal restrictions, equipment and personnel, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained, production rate recovery, transportation constraints and other factors. While certain of the unbooked locations have been de-risked by drilling existing wells in relative close proximity to such locations, many of other unbooked locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional proved or probable reserves, resources or production. 30-day IP and other short-term rates are not necessarily indicative of long-term performance or of ultimate recovery. The conversion of natural gas volumes to barrels of oil equivalent ( BOE ) is on the basis of six thousand cubic feet to one barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be misleading, particularly if used in isolation

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39 2017F ENCANA CORPORATE GUIDANCE (1) US$, U.S. GAAP July 21, F Capital Investment ($ billions) Total Capital Investment Production (after royalties) Liquids (Mbbls/d) % Oil & Condensate (2) 80 85% % Natural Gas Liquids 15 20% Natural Gas (MMcf/d) 1,075 1,125 Total Production (MBOE/d) Core Asset 4Q16 to 4Q17 Production Growth (5) 25-30% Operating Costs ($/BOE at 6:1 ratio) Upstream Operating Expense (3) Transportation and Processing Administrative Expense (3) Production, Mineral & Other Taxes (% of Revenue (4) ) % 1. Guidance incorporates the impact of second quarter of 2017 year to date dispositions and the assumed close of the Piceance asset disposition in the third quarter of Includes plant & field condensate. 3. Excludes long-term incentives and restructuring charges. 4. Upstream revenue excluding risk management activities. 5. Reflects quarter over quarter growth of average production during the period for Encana s core assets (Montney, Duvernay, Eagle Ford and Permian). ADVISORY: This document contains certain forward-looking statements or information (collectively, FLS ) within the meaning of applicable securities legislation. FLS include: capital investment; natural gas, liquids and total production, including anticipated commodity mix; core asset production growth over the period specified; operating costs; and expected consideration from transactions, use of proceeds, satisfaction of closing conditions and timing thereof. Readers are cautioned against unduly relying on FLS which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; Encana s ability to access its revolving credit facilities and shelf prospectuses; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of Encana's drive to productivity and efficiencies; results from innovations; expectation that counterparties will fulfill their obligations under the gathering, midstream and marketing agreements; access to transportation and processing facilities where Encana operates; assumed tax, royalty and regulatory regimes; enforceability of transaction agreements; ability to satisfy closing conditions and regulatory approvals, successful closing of, and value of post-closing and other adjustments associated with announced sale of assets; and expectations and projections made in light of, and generally consistent with, Encana's historical experience and its perception of historical trends, including with respect to the pace of technological development, the benefits achieved and general industry expectations. Risks and uncertainties that may affect these business outcomes include: the ability to generate sufficient cash flow to meet Encana's obligations; risks inherent to completing transactions on a timely basis or at all and adjustments that may impact expected proceeds or value to Encana; commodity price volatility; ability to secure adequate product transportation and potential pipeline curtailments; variability and discretion of Encana's board of directors to declare and pay dividends, if any; the timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk; risk and effect of a downgrade in credit rating and its impact on access to capital markets and other sources of liquidity; fluctuations in currency and interest rates; risks inherent in Encana's corporate guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential future lawsuits and regulatory actions made against Encana; impact to Encana as a result of disputes arising with its partners, including the suspension by its partners of certain of their obligations and the inability to dispose of assets or interests in certain arrangements; Encana's ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of liquids and natural gas from plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as partnerships or joint ventures and the funds received in respect thereof which Encana may refer to from time to time as proceeds, deferred purchase price and/or carry capital, regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties impacting Encana's business, as described in its most recent Annual Report on Form 10-K and as described from time to time in Encana s other periodic filings as filed on SEDAR and EDGAR. Although Encana believes the expectations represented by such FLS are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. FLS are made as of the date of this document and, except as required by law, Encana undertakes no obligation to update publicly or revise any FLS. FLS contained in this document are expressly qualified by these cautionary statements. FLS included in the 2017F Encana Corporate Guidance dated prior to the date hereof are revoked in their entirety and should not be relied upon. Certain future oriented financial information or financial outlook information is included in this document to communicate Encana s current expectations as to its performance in Readers are cautioned that it may not be appropriate for other purposes. The conversion of natural gas volumes to barrels of oil equivalent ( BOE ) is on the basis of six thousand cubic feet to one barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be misleading, particularly if used in isolation.

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