CORPORATE PRESENTATION. October 2018

CORPORATE PRESENTATION October 2018

ENCANA Value Proposition Encana today: Great portfolio with large inventory Strong balance sheet Disciplined capital allocation Leading growth cash flow, margin and liquids production Culture of innovation and execution ~$3 billion of cumulative free cash flow Ŧ (2018-2022)* Additional financial capacity at normalized leverage of 1.5x ~$500 million 2019 free cash flow Ŧ * $400 million share repurchase program Repurchased 16.8MM shares for ~$200MM in H1 2018 Expect to complete program by year end TOP TIER RESOURCE OPERATIONAL EXCELLENCE BALANCE SHEET STRENGTH MARKET FUNDAMENTALS CAPITAL ALLOCATION * Assumes flat $55 WTI, $3 NYMEX Gas, $1.50 AECO Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website 1 FOCUSED ON SHAREHOLDER RETURNS ~$3 Billion of Free Cash Flow Ŧ Over Five Year Plan $400 million share repurchase program initiated, ~50% completed in H1 2018 ~$3 billion of cumulative free cash flow Ŧ (2018-2022F)* Balance sheet discipline Creates Options: Returns to Shareholders Resiliency Managing volatility Portfolio Value Creation Building on a quality portfolio *Assumes $55 WTI, $3 NYM EX, $1.50 AECO SHAREHOLDER RETURNS Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 2 1

($MM) ($MM) 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 grows over the 5 year plan ~25% Cash Flow Ŧ CAGR 2018F 2022F ~$3.0 Billion Free Cash Flow Ŧ 2018F 2022F Assumes flat $55/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. 3 AN OPERATOR INVESTORS CAN COUNT ON Increasing Value & Resiliency 2017-2022F Cash Flow Ŧ ~25% CAGR Updated 5 year plan is better across the board Maintaining efficiencies in a busier industry Major facility milestones achieved in Q4 2017 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 Expect to generate free cash flow Ŧ in 2018 ~$3 billion of cumulative free cash flow Ŧ (2018-2022F)* Leading corporate return generation 5,000 4,000 3,000 2,000 1,000 0 3,000 2,000 1,000 2017 2018F 2019F 2020F 2021F 2022F Cash From Operating Activities NCWC & Other Cash Flow (Non-GAAP) ~$3.0B of Cumulative Free Cash Flow Ŧ - 2017 2018F 2019F 2020F 2021F 2022F *Assumes $55 WTI, $3 NYM EX, $1.50 AECO Capital Cumulative Free Cash Flow Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 4 2

RESILIENT BUSINESS MODEL Capital Discipline & Risk Management Multi-basin portfolio Short cycle capital Highly focused capital allocation Integrated supply chain Flexible commercial arrangements Diversified market access Robust hedge program Investment grade credit rating 3.2x Net Debt to Adjusted EBITDA Ŧ 2.3x 2.1x Target ~1.5x 2016 2017 2018 Q2 2018F 2019F 2020F Net Debt / Adjusted EBITDA - Actual Net Debt / Adjusted EBITDA Analyst Consensus Analyst consensus per Bloomberg, July 25, 2018 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. Net Debt / Adjusted EBITDA Normalized Mid-Cycle Target of ~1.5x 5 MARGIN EXPANSION CONTINUES Profitable Growth Cash flow margin Ŧ continues to grow 2017 cash flow margin Ŧ up 81% versus 2016 Liquids mix Higher realized pricing Lower operating and corporate costs 2018 cash flow margin Ŧ now expected to be ~$16/BOE, up from ~$14/BOE Liquids mix Efficiency Access to markets Cash Flow Margin Ŧ Expansion ($/BOE) ~16.00 ~14.00 11.75 6.49 2016 2017 2018F Original 2018F Updated Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 6 3

$/BOE, Excluding Hedge Liquids Production Mbbls/d FOCUSED ON QUALITY LIQUIDS GROWTH 1 Year of Liquids Growth Captures Value Focused liquids growth drives cash flow Liquids production up 32 Mbbls/d vs H1 2017 Liquids mix improves to 45% from 37% contributing an additional $240MM to H1 2018 revenue Higher liquids prices in H1 2018 contributed an additional $365MM 200 175 150 125 100 75 50 25 - Liquids Production Growth H1 2017 H1 2018 7 CONVERTING PRICE TO MARGIN Growing Liquids, Holding Costs to Expand Operating Margin Ŧ Increased liquids mix Oil and condensate growth driving margin expansion Cost control Holding the line on costs results in margin capture as price rises Market diversification adds $1.60/BOE to margin in H1 2018 Margin, excl. hedge per BOE up 39% versus H1 2017 35.00 30.00 25.00 20.00 15.00 10.00 Converting Price Increase to Operating Margin 5.00 - H1 2017 H2 2017 H1 2018 Market Diversification $/BOE Operating Margin $/BOE Realized Price $/BOE Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 8 4

Production (MBOE/d) 5 YEAR PLAN Production Growth Within Cash Flow 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 650 550 450 350 250 Production Growth Within Cash Flow Ŧ 2017 2018F 2019F 2020F 2021F 2022F 2017 Total Production = 313 MBOE/d, or 279 MBOE/d excluding A&D assets 2018F Guidance 360-380 MBOE/d Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 9 2018 GUIDANCE Cash Flow Ŧ and Production Growing >30% Expect to generate free cash flow Ŧ in 2018 Total production is 95% from core assets Annual production growth of >30% excluding dispositions Q4 core asset production to average 400 425 MBOE/d (30-37% growth from Q4/17) Continued margin expansion driven by liquids growth 55 65 Mbbls/d of liquids in the Montney expected in Q4 Operating and G&A costs lower Benefit of focus on efficiency and scale Market diversification benefits Margin increase of ~$0.50-$0.75/BOE above additional T&P cost to access premium markets 2018F Guidance Capital Investment ($ billion) 1.8 1.9 Total Liquids (Mbbls/d) 165 175 Natural Gas (MMcf/d) 1,150 1,250 Total Production (MBOE/d) 360 380 Upstream Operating Expense ($/BOE)* 3.00 3.30 Transportation & Processing ($/BOE) 7.40 7.75 Administrative Expense ($/BOE)* 1.25 1.50 Production, Mineral & Other Taxes % of Revenue** 3.25 3.75% *Excludes long-term incentives; ** Upstream revenue excluding risk management activities Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures, including reconciliations, see the Company s website. 10 5

MBOE/d CONFIDENT IN 2018 EXECUTION Plan To Deliver >30% Production Growth* >30% annual production growth* while generating free cash flow Ŧ Capital program front end loaded Restarted Duvernay drilling in January Ramped up Eagle Ford drilling in Q1 Montney activity higher in Q1 and Q2 as part of liquids growth plan, preparing to fill liquids hubs Production growth weighted towards second half of 2018 Ramping liquids production into Montney facilities >20% production growth second half of 2018 versus first half of 2018 Efficiency & innovation offsetting service cost inflation 450 400 350 300 250 200 150 100 50 0 >20% Production Growth in 2nd Half 2018 2H 2016 1H 2017 2H 2017 1H 2018 2H 2018F Total Production for 2016 & 2017 excludes production from assets sold in 2016 & 2017 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website * Adjusted for 2017 dispositions. 11 STRONG FINANCIAL PERFORMANCE Q2 Highlights Expect to generate free cash flow Ŧ in 2018 Full year cash flow margin Ŧ increases to ~$16/BOE Margin expansion drives strong Q2 cash flow Ŧ High value oil and condensate production growth Risk management program increases realized prices, reduces risk Cost control Tax & interest recovery contributed to Q2 cash flow Capital program on track with guidance Activity front end loaded Share repurchase program Repurchased 16.8 million shares for ~$200MM; expect to complete $400MM authorization by year end 956.3 million shares outstanding as of June 30, 2018 Q2 2018 Q1 2018 Net Earnings ($MM) (151) 151 Operating Earnings Ŧ ($MM) 198 156 Cash Flow Ŧ ($MM) 586 400 - $ per share, diluted 0.61 0.41 Cash Flow Margin Ŧ ($/BOE) 19.09 13.70 Upstream Operating Cash Flow Ŧ, Incl. Hedge ($MM) Operating Margin Ŧ, Incl. Hedge ($/BOE) 610 578 19.65 19.34 Realized Hedge ($/BOE) 0.44 (1.13) Capital Investment ($MM) 595 508 Net Debt to Adjusted EBITDA Ŧ 2.1x 2.2x Weighted Avg. Shares Outstanding, millions 960.0 971.5 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 12 6

WORLD CLASS PORTFOLIO Encana's Resource In Context Core positions in four of North America s premier basins >23,000 total gross inventory locations* ~11,000 gross premium return locations >35% ATROR Ŧ returns Oil or condensate rich wells only Primary zones only** Industry typical well spacing*** Montney Duvernay Eagle Ford Permian *Locations as of December 31, 2017; includes 744 proved undeveloped locations, 1,399 probable undeveloped locations, and 6,857 un-risked contingent resource locations, categorized in accordance with the Canadian Oil and Gas Evaluation Handbook (COGEH), and locations not assigned to a reserves or resource category. See the advisories for additional information. **Includes only Wolfcamp, Spraberry, Jo Mill, Lower Eagle Ford,Duvernay, Upper & Lower Montney; ***450-660 in Permian, 330 in Eagle Ford, 1000 in Duvernay, 440-880 in Montney; Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures, including reconciliations, see the Company s website. 13 PERMIAN BASIN Highly Efficient Development at Scale Developing the cube Critical to creating value at industrial scale Reservoir & above-ground benefits Natural extension of our experience & capabilities Stacked pay & completions upside Innovation and technology driving performance New benches & advanced completions Coring up acreage boosts long lateral inventory Managing risk Execution efficiency offsetting cost inflation Just-in-time water infrastructure ensures availability & avoids over-capitalization Sophisticated supply-chain & logistics Market access secured 14 7

MONTNEY Driving Margin Expansion Encana s Montney is a condensate play Receives ~WTI pricing Stacked horizontal development Over 1,000 of pay, up to 6 stacked horizons Completions design driving productivity higher ~35% liquids CAGR through 2022 Increasing margins through condensate growth Tower liquids hub online ahead of schedule Pipestone liquids hub on schedule for early Q4 start-up Growing liquids to 55,000-65,000 bbls/d in Q4 2018 Basin leading operator Top well performance Most efficient operator with track record of innovation Longest laterals with highest completion intensity 15 EAGLE FORD Technical Innovation Unlocking Value Largely contiguous position in the Karnes Trough Most active and profitable trend in the Eagle Ford Completion innovations leading to better wells Stacked pay, infill spacing, Austin Chalk offer additional upside High value, high rate wells >80% of production is high value liquids Oil receives LLS pricing 16 8

DUVERNAY Industry Leading Well Performance Large contiguous land base within condensate window WTI pricing for condensate Significant future growth opportunity Highly efficient 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 17 TECHNOLOGY & 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 18 9

Cumulative Production (MBOE)* 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 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 19 INNOVATION IN ACTION Evolution in Completion Design Fueling Growth Advanced completion design is focused on creating better wells for lower costs Applying completions intensity thoughtfully Tight clusters and optimized hydraulics maximize fracture surface area Clean fluids improve fracture conductivity Fine grain proppant maximizes complexity Culture of innovation and company-wide knowledge sharing Structured and driven to business outcomes Real time knowledge sharing Analytics linked to deep understanding of first principles Realizing 25%+ improvement in IP180 Eagle Ford Innovations Doubling Productivity 250 2015 200 2016 2017 150 100 50 0 0 30 60 90 120 150 180 Days Permian High Intensity Design Keeps Frac Energy Closer *Well results normalized to 5000 lateral. High Intensity Design Base Design 20 10

CUBE DEVELOPMENT Maximizing Value Through Optimized Development Spacing & stacking across multiple zones Vertical and horizontal optimizations System based approach considers how wells interact in the sub-surface over time Parent-child well impacts minimized with co-development in cubes Preserves economic locations Child wells can be 30% less EUR than parent wells Driving capital efficiency Shared and re-used surface facilities reduce capital costs Higher rig & frac spread productivity Scope and scale necessitates highly sophisticated planning and logistics Relentless pursuit of optimization opportunities IRR per well Acreage NPV Cube Development Maximizes NPV Target NPV Increasing well density (number of wells per section) 21 CUBE DEVELOPMENT Improved Resource Recovery & Efficiency Higher recovery from stacked pay reservoirs Generating effective draw down within cube Highly efficient, agile development Higher utilization of services & infrastructure Rapid cycle times Accelerated learnings Cube development approach in 2018 Data driven innovation Testing new benches Spacing & stacking trials Incorporating advanced completion designs Evaluating emerging technologies Cube Development Maximizing Recovery from the Stack 22 11

COMMERCIAL INNOVATION Delivering Value in any Environment Fully offsetting service cost inflation with sourcing and efficiency improvements Seamless linkage between supply chain and operations Actively managing the supply chain Self-sourcing commodities (sand, water, OCTG) Driving efficiencies with vendors Security of supply with commercial flexibility Rigs, pressure pumping and D&C services secured Challenging industry norms Logistics and local mines will drive sand costs lower Recycling water, optimizing trucking and fuel Increasing pump time per day ECA 2018 D&C Cost Breakdown ~35% of well cost is drilling ~65% of well cost is completions D&C Key Component Cost Breakdown 20-30% sand & water 10-15% pressure pumping 10-15% D&C services 6-8% casing 5-8% drilling rig 4-7% cement and mud 23 MIDSTREAM AND MARKETING 12

$MM EXPANDING MARGINS & DE-RISKING GROWTH Midstream & Marketing Contributes ~$100 MM YTD Ensuring market access Manage flow assurance through flexible and reliable midstream arrangements Diversified physical sales portfolio backed with firm transportation to major markets Maximizing price realizations Netback optimization, active management of sales portfolio Financial price risk mitigation (active basis and benchmark price hedge programs) Supporting strategy execution De-risks growth plan Minimize commitments and maximize flexibility Reduces cash flow volatility and manages balance sheet risk Market Diversification adds ~$100 MM YTD 600 500 400 300 200 100 0 + 8% to Cash Flow Ŧ Q1 2018 Q2 2018 Cash Flow Excl. Diversification + 13% to Cash Flow Ŧ Diversification, Net of Cost Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 25 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 Midland-Sealy Pipeline) No take or pay commitments 26 13

PERMIAN MIDSTREAM & MARKETING OVERVIEW Diversified Price Exposure Dedicated oil gathering 90% of oil gathered on Medallion system Provides better margins and flow assurance In system storage with multiple sales points Oil marketing Firm transportation to Houston In basin sales at Gulf Coast pricing with firm transport WTI-Midland differential hedges protect in basin sales price Gas gathering & marketing Three midstream providers on P.O.P.*** contracts Ability to take-in-kind to self market Financial basis hedges for Waha Permian 2018* 2019 WTI/Midland Differential Hedges Swap Price (US$/bbl) 33 Mbbls/d $(0.85)/bbl 18 Mbbls/d $(1.42)/bbl Firm oil takeaway 25 Mbbls/d 43 Mbbls/d Waha Basis Hedges Swap Price (US$/Mcf)** 45 MMcf/d $(0.35)/Mcf 45 MMcf/d $(0.35)/Mcf Risk management positions as at June 30, 2018. * July to December 2018 positions. ** Price stated is the differential versus NYMEX pricing. Hedged volumes are converted to Mcf at a 1:1 ratio from MMBtu. *** P.O.P. Percentage of Proceeds 27 MARKET DIVERSIFICATION PAYS Q2 Permian Price Uplift Delivers Value Ensuring market access Firm transport to Houston Maximizing price realizations Portion of Permian volumes linked to Houston pricing Basis hedges insulate cash flow risk of wider Midland differential Supporting strategy execution Superior price realizations and cash flow protection matched to the Permian growth plan Q2 Permian Realized Oil Price (incl. Basis Hedge) WTI $67.88/bbl 28 14

DIVERSIFIED MARKET EXPOSURE IN WESTERN CANADA Portfolio Approach to Price Risk Management 100% firm capacity on Nova Gas Transmission System (NGTL) Condensate sold into premium local market Condensate Imports ~500MMcf/d AECO basis hedged at ($0.88/Mcf) to Henry Hub ~500 MMcf/d firm transportation out of the basin 100% firm capacity secured on NGTL for expected production growth limited curtailment risk Condensate sold into local market at ~WTI prices To US Northwest To Dawn To Chicago Natural Gas Export Pipeline Condensate Import Pipeline 29 BASIS RISK MANAGEMENT PROGRAM Market Access & Price Risk Management Western Canada Realized price including hedge expected to be ~$0.20 below NYMEX in 2018 AECO US$0.25 fluctuation equals less than US$15MM cash flow in 2018 after hedge Western Canada 2018 * 2019-2020 AECO Basis Hedges Swap Price US$/Mcf** 475 MMcf/d $(0.87)/Mcf 500 MMcf/d $(0.88)/Mcf Transport to Dawn 316 MMcf/d 316 MMcf/d Transport to Sumas/Malin 136 MMcf/d 134 MMcf/d Transport to Chicago 52 MMcf/d 100 MMcf/d Risk management positions as at June 30, 2018. * July to December 2018 positions. ** Price stated is the differential versus NYMEX pricing. Hedged and transport volumes are converted to Mcf at a 1:1 ratio from MMBtu. 30 15

MARKET DIVERSIFICATION PAYS YTD Canada Gas Price Uplift Demonstrates Value Ensuring market access Diversified sales points to Dawn, Chicago, and US Northwest Maximizing price realizations Diverse market price points Basis and fixed price hedges insulate cash flow risk of wider AECO differential and NYMEX price risk Supporting strategy execution Superior price realizations and cash flow protection to support liquids focused development in the Montney H1 2018 Canada Realized Gas Price 103% of NYMEX H1 2018 Average NYMEX Price US$2.90/MMBtu 31 RISK MANAGEMENT Adds Greater Certainty to Cash Flow and De-Risks Capital Program 2018 balance of year price sensitivity to a $5 increase to WTI is ~$20 million to cash flow 2018 balance of year price sensitivity to a $0.25 increase to NYMEX gas is ~$15 million to cash flow F/X Risk is managed via US Dollar denominated currency swaps: $700 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$ 0.7604 to C$1, which mature monthly throughout 2018 $0.01 Change to F/X has annual impact of less than $10 million to cash flow $250 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$ 0.7581 to C$1, which mature monthly throughout 2019 Risk management positions as at June 30, 2018. *July to December 2018 positions. ** Hedged volumes are converted to Mcf at a 1:1 ratio from MMBtu. BENCHMARK HEDGES 2018* 2019 Oil and Condensate WTI Fixed Price Swap Swap Price (US$/bbl) WTI 3-Way Option Short Put (US$/bbl) Long Put (US$/bbl) Short Call (US$/bbl) WTI Costless Collar Long Put (US$/bbl) Short Call (US$/bbl) WTI Fixed Price Swaptions Strike Price (US$/bbl) Natural Gas The WTI fixed price swaptions give the counterparty the option to extend 2018 fixed price swaps to June 30, 2019 at the strike price. The NYMEX fixed price swaptions give the counterparty the option to extend 2018 fixed price swaps to June 30, 2019 at the strike price. NYMEX Fixed Price Swap ** Swap Price US$/Mcf*** NYMEX Fixed Price Swaptions Strike Price US$/Mcf*** 102 Mbbls/d $55.52/bbl 16 Mbbls/d $36.88/bbl $47.17/bbl $54.49/bbl $(0.88)/Mcf ± 10 Mbbls/d $45.00/bbl $57.08/bbl 1,084 MMcf/d $3.02/Mcf 35 Mbbls/d $60.31/bbl 42 Mbbls/d $48.21/bbl $59.11/bbl $68.38/bbl 12 Mbbls/d $63.13/bbl 699 MMcf/d $2.72/Mcf 149 MMcf/d $2.99/Mcf 32 16

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 gross well inventory* 3,450 premium locations <1,000 wells drilled in 5 year plan 9,600 gross well inventory* 6,900 premium locations <800 wells drilled in 5 year plan Remaining Inventory Premium** assumption 450-660 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 gross well inventory* 220 premium locations ~200 wells drilled in 5 year plan Duvernay 1,000 gross well inventory* 500 premium locations <200 wells drilled in 5 year plan Premium** assumption 330 spacing Premium** assumption 1,000 spacing *Locations as of December 31, 2017; of the 23,000 total gross inventory locations, includes 744 proved undeveloped locations, 1,399 probable undeveloped locations, and 6,857 un-risked contingent resource locations, categorized in accordance with COGEH, and locations not assigned to a reserves or resource category. See the advisories for additional information. **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. 34 17

Cumulative Production MBOE* Cumulative Production MBOE* PERMIAN 2018 Program FY 2018 Plan Acreage (net acres) 118,000 Average Working Interest (%) 94% Average Royalty Rate (%) 25% Development Capital (net) ($MM) $750-800 Gross Rig Count 4-5 HZ Wells Drilled (net) 100 115 HZ Wells On-stream (net) 100 115 D&C Cost* ($MM/well) ~$5.6 Average Lateral Length (ft) 7,500 10,000 Production Split Oil/condensate** % 66% NGLs % 17% Natural gas %*** 17% 2018 Program 30% growth from FY 2017 to FY 2018 70% program focused in Midland/Martin Cube development continues to add significant value through operational efficiencies, shared infrastructure and services and improved resource recovery *Normalized to 7,500' lateral length **Includes plant and field condensate *** Natural gas % varies based on mix of wells drilled and has ranged between 16-19% 35 PERMIAN CUBE DEVELOPMENT Driving Efficient Execution Permian currently at record production of >90 MBOE/d Strong production performance from new cube developments Brought on 3 cubes in Midland and Martin counties in Q2 4 Jo Mill wells in Martin County exceeding type curve expectations- average IP30 oil of 1,100bbls/d Industry-leading drilling performance Fewest days from spud to rig release Q2 pace-setter, drilled >1 mile of lateral in 24hours Average 2018 lateral length 9,250 Increasing recycled water usage 7 interconnected water resource hubs with 6MMbbls of storage Expect to average 40% recycled water use, with some cubes up to ~80% recycled 2019 production expected to grow to match take-away and basis protection *Results normalized to 7500 lateral 175 150 125 100 75 50 25 175 150 125 100 Continued Strong Performance in Martin Martin Type Curve IP180 0 0 30 60 Days 90 120 150 180 2016 Martin Cube 2017 Martin Cube 75 50 25 Encouraging Early Jo Mill Performance Martin Type Curve IP180 0 0 30 60 Days 90 120 150 180 Well 1 Well 2 Well 3 Well 4 36 18

MBOE/d 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 D&C cost savings up to $300k/well LOE savings up to ~$0.80/BOE Martin County Central Water Resource Hub 37 PERMIAN 5 Year Growth 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 240 200 160 120 80 Five Year Production Profile 40-2017 2018F 2019F 2020F 2021F 2022F 38 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 1,450 350 900 3,450 39 PREMIUM INCREASE OUTPACING DRILLING Gross Premium Return Inventory County Midland/ Upton Martin Howard Glasscock IP30 (BOE/d) 985 950 825 800 IP180 (BOE/d) 700 650 600 550 EUR/Well (Mbbls) 610 675 550 530 EUR/Well (MBOE) 1,020 1,000 875 765 GOR (scf/bbl) 2,800 2,000 2,450 1,960 Gross Premium Return Inventory 1,450 750 900 350 Estimated inventory based on 450-660 ft spacing, 7,500 lateral length, Permian type curves are stated on a three stream basis. Premium return locations are >35% ATROR at $50 WTI Oil and $3.00 NYMEX Gas and are a subset of total inventory locations. See the advisories for additional information. 40 20

Liquids Mbbls/d MONTNEY 2018 Program FY 2018 Plan Acreage (net acres) 379,000 British Columbia 289,000 Alberta (Pipestone) 90,000 Working Interest (%) 63% (includes Pipestone) Average Royalty Rate (%) 5 10% Development Capital (net) $MM $400 $450 Gross Rig Count (average) 8 Net Wells Drilled (CRP) 85 95 Net Wells Drilled (Pipestone) 25 30 Net Wells On-stream (CRP) 110 120 Net Wells On-stream (Pipestone) 22 25 D&C Cost* ($MM/well) $3.1 - $5.1 Average Lateral Length (ft) 7,200-9,000 Production Split Oil/condensate** % 16% NGLs (C2 C4) % 6% Natural gas % 78% 2018 Program 2018 significant production growth while generating free cash flow Targeting Q4 2018 liquids production of 55-65Mbbls/d double Q4 2017 rates Tower liquids hub on-line in Q2 and Pipestone liquids hubs on track for early Q4 start-up Improved liquids mix and efficient operations at scale driving margin expansion Drilling activity weighted to first half of year Expect rig count to drop to ~half by YE *Normalized to 7,200 lateral length for CRP and 9,000' lateral length for Pipestone **Includes plant and field condensate 41 MONTNEY LIQUIDS GROWTH ON TRACK Liquids Production to Double Q4 17 to Q4 18 Montney liquids production up >18% in Q2 vs Q1 Strong liquids growth continuing in Q3 Currently producing >45 Mbbls/d Early start-up of Tower liquids hub de-risks Q4 liquids targets Adds 9,000 bbls/d of net condensate capacity Drilling program on track to deliver 55,000-65,000 bbls/d of liquids in Q4 Construction of Pipestone liquids hub on schedule for early Q4 start-up Successful Q2 plant turn around at Sexsmith ~5,000 BOE/d impact on the quarter 70 60 50 40 30 20 10 0 Q4 2016 Montney Liquids Set to Double Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Current Rate Q2 2018 Tower Liquids Hub On-Stream Q3 Q4 2018F 2018F 42 21

($MM) British Columbia Alberta MONTNEY OPTIONALITY Activity Focused on Richest Reservoir Strong liquids growth continuing in Q3 Early start-up of Tower liquids hub de-risks Q4 liquids targets Construction of Pipestone liquids hub on schedule for early Q4 start-up Encana s Montney acreage spans the maturity window from dry gas to volatile oil Initial condensate gas ratios (CGRs) vary from <10-800bbls/MMcf across ECA lands Short cycle times provide opportunity to adjust program to market conditions Optimizing drilling program to focus on higher CGR wells to drive cash flow, margins and returns On track to deliver Q4 liquids volumes of 55,000-65,000 bbls/d 1 2 Tower Drilling Program Focused on Liquids Rich Areas 3 miles Dawson South 3 miles 72-9W6 72-8W6 71-9W6 71-8W6 1 2 3 miles 3 Encana Land Basin Core Initial Condensate-Gas Ratio >100 bbls/mmcf 10-100 bbls/mmcf <10 bbls/mmcf 40mi / 65km 3 Pipestone 43 MONTNEY CASH FLOW GROWTH High Quality Condensate Play Montney growth has been self-funded Transition to liquids and increase in scale driving margin expansion 2018 significant production growth while generating free cash flow Ŧ Additional growth in free cash Ŧ expected in 2019 Competes with the best plays in North America 1,400 1,200 1,000 800 Montney Free Operating Cash Flow Ŧ in 2018 & 2019 Liquids-Rich Montney Permian D&C Cost ($MM) 4.0 5.5 5.6 Oil/C5 IP180 (bbls/d) 250-800 500 Royalty Rate 5-10% 25% 600 400 200-2017 2018F 2019F Capital Upstream Operating CF Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 44 22

Alberta BC PIPESTONE INFRASTRUCTURE SOLUTION Agreement with Keyera Supports condensate-focused growth in Pipestone Infrastructure supports Montney 5-year plan Includes Pipestone Liquids Hub and Pipestone Processing Facility Encana will design, construct and initially operate the facilities Innovative risk-sharing arrangement Competitive fee-for-service structure Land dedication Revenue guarantee on a fraction of initial capacity rights Canadian per unit T&P costs expected to be similar to current rates 1 2 Facility Pipestone Liquids Hub Pipestone Processing Facility Pipestone Montney Infrastructure Additions Tower 40mi / 65km Dawson South Expected In-Service Early Q4 2018 Gas Capacity* (mmcf/d) 1 2 Pipestone Enc ana Land Basin Cor e Existing Gas Plant Liquids Hub Condensate Capacity* (bbls/d) NGL Capacity* (bbls/d) - 10,500-2021 150 19,400 4,100 *Capacities are net ECA and stated after shrink and before royalties. Plant design not finalized, capacities subject to change 45 AGREEMENT WITH VERESEN MIDSTREAM Fee-for-Service Structure Tower, Sunrise and Saturn plants on-stream Q4 2017 Facilities came on ahead of schedule and under budget Tower liquids hub on-line Q2 2018 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 continue to increase in 2018 Driven by condensate growth New plant fees lower than average Canadian per unit T&P expense All 3 Montney Plants On-Stream 46 23

MMcf/d Mbbls/d BC Alberta MONTNEY INFRASTRUCTURE PLAN Liquids Handling Capacity Supports Growth & Flexibility Net Encana Capacity Key Montney Infrastructure Additions Icon Name Anticipated Timing Gas* (MMcf/d) Condensate* (bbls/d) NGLs* (bbls/d) 1 2 Existing Facilities 1,150 42,000 15,500 Tower NCLH On-line 0 9,000 0 Pipestone Liquids Hub** Early Q4 2018 0 10,500 0 Total Net Capacity Year End 2018 1,150 61,500 15,500 Tower 1 Dawson South 3 Pipestone Processing 2021 150 19,400 4,100 2 3 Facility** Pipestone Commissioning of Tower, Sunrise and Saturn in 2017 added approximately 450 MMcf/d of gas, 19 Mbbls/d of condensate, and 10 Mbbls/d of NGL to existing capacity 40mi / 65km *Condensate capacity includes field & plant condensate. Capacities are net ECA, and stated after shrink and before royalties. **Pipestone facilities part of the recently announced Keyera Partnership agreement. 47 ENCANA MONTNEY 5 Year Growth Profile Development focused in condensate rich areas 2018 program to fill new liquids capacity Additional capacity comes online late 2018 Operating margin expected to increase >40% by 2022 Liquids production of 55-65 Mbbls/d Q4 2018 Expect liquids production of >70 Mbbls/d by 2019 Liquid weighting grows to >25% of total by 2019 Liquids handling expansions support growth plans High-grading drilling program to focus on higher CGR wells to drive cash flow and margin 90 60 30-1,500 1,000 500 - Liquids Growth Profile 2017 2018F 2019F 2020F 2021F 2022F Gas Growth Profile 2017 2018F 2019F 2020F 2021F 2022F Volumes quoted are net to Encana. 48 24

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 capital expected to extend into 2019 2018 third party capital ~C$300 million 2019 third party capital ~C$135 million Post commitment period, Mitsubishi funds its 40% of the Partnership's future capital investment 49 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 1,800 800 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 1,650 950 1,000 1,100 1,200 1,300 1,350 900 1,200 Condensate Yield (bbls/mmcf) <20 20-50 50-150 <20 20-50 20-50 50 150 150 250 >250 Gross Premium Return Inventory 1,230 950 860 690 460 740 840 150 980 Estimated inventory based on 440-990 ft. spacing, 8,200-9,800 lateral length. Volumes are stated on a shrunk condensate and a raw gas basis. Premium return locations are >35% ATROR at $50 WTI Oil and $3.00 NYMEX Gas and are a subset of total inventory locations. See the advisories for additional information. 50 25

Cumulative Production MBOE* EAGLE FORD & DUVERNAY Generating Significant Free Operating Cash Flow Ŧ Eagle Ford returned to growth Brought on 11 wells in Eagle Ford in Q2 2018 production results de-risking potential future premium inventory Strong well results fully off-setting base declines Access to premium markets driving strong operating margins Generated ~$115MM of combined free operating cash flow Ŧ YTD Drilling activity in both assets weighted to H1 2018 Eagle Ford receives LLS prices; resulting in Q2 margin ~$40/BOE Expect load-levelled program for Eagle Ford in 2019 Additional activity capitalizes on strong margins Optimizes utilization of existing capacity Duvernay returning to growth in second half 2019 continued drill to fill strategy 200 180 160 140 120 100 80 60 40 20 Strong 2018 Austin Chalk Results Austin Chalk Type Curve IP180 0 0 30 60 90 120 150 180 Days Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. *Results normalized to 5000 lateral 51 EAGLE FORD 2018 Program FY 2018 Plan Acreage (net acres) 42,000 Average Working Interest (%) 92% Average Royalty Rate (%) 20 25% Development Capital (net) $MM $270-310 Gross Rig Count (average) 2 Wells Drilled (net) 45 50 Wells on Stream (net) 45 50 D&C Cost* ($MM/well) ~$4.8 Average Lateral Length (ft) 5,000 Production Split Oil/condensate** % 70% NGLs % 13% Natural gas % 17% 2018 Program Maximize free operating cash flow Program weighted ~60% Eagle Ford and ~40% Austin Chalk Completion design innovations continue to add upside to the play Strong pricing realizations at Houston and LLS *Normalized to 5,000' lateral length **Includes plant and field condensate 52 26

MIDSTREAM AND MARKETING OVERVIEW Eagle Ford Close proximity to market and well-developed infrastructure Eagle Ford 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 Three Rivers Corpus Christi Proximity to market minimizes transportation cost and related commitments while maximizing margins 53 EAGLE FORD Gross Premium Return Inventory Type Curve Eagle Ford Austin Chalk IP30 (BOE/d) 1200 1400 IP180 (BOE/d) 950 1040 EUR/Well (Mbbls) 490 590 EUR/Well (MBOE) 650 770 GOR (scf/bbl) 2,000 1,500 220 premium return inventory locations Testing additional opportunity in both the Graben area of the Eagle Ford and in the Austin Chalk Gross Premium Return Inventory 155 65 Estimated Eagle Ford inventory based on 330 ft spacing, 5,000 lateral length. Type curves are stated on a three stream basis. Premium return locations are >35% ATROR at $50 WTI Oil and $3.00 NYMEX Gas and are a subset of total inventory locations. See the advisories for additional information. 54 27

DUVERNAY 2018 Program FY 2018 Plan Simonette Acreage (net acres) 91,000 Average Working Interest (%) 50% Average Royalty Rate (%) 5 10% Development Capital (net) $MM $100 130 Gross Rig Count (average) 1 Wells Drilled (net) 7 9 Wells on Stream (net) 7 9 D&C Cost* ($MM/well) ~$9.7 Average Lateral Length (ft) 9,000 Production Split Oil/condensate** % 40% NGLs (C2 C4) % 8% Natural gas % 52% 2018 Program Maximize free operating cash flow Strong margin driven by ~50% liquids and ~WTI realizations for condensate Advanced completions contributing to 25% productivity improvement Activity weighted to first half of 2018 *Normalized to 9,000' lateral length **Includes plant and field condensate. 55 MIDSTREAM AND MARKETING OVERVIEW Duvernay Condensate sales via pipeline to premium Edmonton market center Duvernay Condensate to Edmonton market center Firm market access aligned with development program Achieved liquids price upgrade while minimizing midstream capex via Alliance pipeline Alliance Pipeline to U.S. Midwest (Chicago) Diversified pricing exposure for liquids and natural gas in Chicago market 56 28

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 1,250 850-950 850-950 EUR/Well (MBOE) 1,350-1450 1,300 1,400 1,000 1,100 950 1,050 Condensate Yield (bbls/mmcf) Gross Premium Return Inventory 50-150 150-250 50 150 150 250 150 120 60 170 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. Premium return locations are >35% ATROR at $50 WTI Oil and $3.00 NYMEX Gas and are a subset of total inventory locations. See the advisories for additional information. 57 SAN JUAN BASIN Evaluating Liquids Growth Potential Strong 2017 well results 5 Tocito wells exceeding type curve expectations Targeted best rock with transverse orientation and advanced completion design to generate more frac complexity Evaluated secondary El Vado zone 2018 objectives 6 well program in H2 2018 Evaluating commerciality (access to services, commodities, mid-stream, etc.) 58 29

$MM $/BOE SUPPLEMENTAL MAXIMIZING MARGIN Cost Control of Corporate Items Enhances Per Unit Margin Benefit of scale driving lower per unit BOE costs Reducing costs & growing production volumes Interest on debt expected to be ~$70MM/quarter Consolidated interest expense $90-$95MM/quarter Administrative expense, ex. LTI s, expected to be ~$45MM/quarter for 2018 Market optimization segment includes T&P costs of $30-$35MM/quarter for 2018 Segment operating loss expected to be $12-$14MM/quarter Combined corporate costs impacting cash flow are ~$120MM/quarter, excluding cash impact of long-term incentives Long term incentive cash costs typically vest in first quarter, primarily 3 year vesting cycle Corporate Items Cost Control 700 6.00 600 5.00 500 4.00 400 3.00 300 200 2.00 100 1.00 - - 2017 2018F Interest Expense G&A Excluding LTI Market Optimization Combined Cost $/BOE 60 30

PRODUCT VALUE CHAIN Projected Composition of Total Production Excluding Hedge Canada US 2018F* 2018F Pricing 2018F* 2018F Pricing (Mbbls/d) (%WTI) (Mbbls/d) (%WTI) Oil 0 1 88% 87 90 97% Condensate** 37 40 95% 3 4 83% Butane 6 8 57% 4 5 56% Propane 7 9 33% 8 9 48% Ethane 0 1 17% 9 10 10% Canada US 2018F* (MMcf/d) 2018F Pricing (%NYMEX) 2018F* (MMcf/d) 2018F Pricing (%NYMEX) Natural Gas 1,000 1,100 73% 140 160 76% *2018F based on company guidance as at February 15, 2018, excluding impact of hedges; production ranges are not additive; **Includes plant condensate 61 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 62 31

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 (US$ MM) DISCIPLINED FINANCIAL MANAGEMENT Access to Ample Liquidity Through 2022 $4.0B fully committed, unsecured, revolving credit facilities $4.0B available at June 30, 2018 Committed to July 2022 No use of credit facility to back-stop long term commitments Single financial covenant Debt cannot exceed 60% of adjusted capitalization Adjusted capitalization Ŧ = debt + equity + $7.7B equity adjustment 23% as at June 30, 2018 Debt to adjusted capitalization ratio has improved since 2013 80% 70% 60% 50% 40% 30% 20% ECA Ratio Well Within Covenant Threshold Debt to Adjusted Capitalization Ŧ Ratio 36% 30% 60% Threshold 28% 23% 22% 10% 0% YE 2013 YE 2014 YE 2015 YE 2016 YE 2017 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 63 DISCIPLINED FINANCIAL MANAGEMENT Debt Portfolio as at June 30, 2018 Total debt reduced by ~$3 billion since Y/E 2014 Significant financial flexibility ~75% of fixed rate long-term debt not due until 2030 and beyond Investment grade credit rating $4.0B fully committed, unsecured, revolving credit facilities Fixed Debt Maturity Schedule 1,000 750 500 250 0 64 32

FUTURE ORIENTED INFORMATION This presentationcontains certainforward-looking statements or information (collectively, FLS ) within the meaning ofapplicable securities legislation, includingthe U.S. Private Securities Litigation Reform Act of 1995. FLS include: expectation of meeting or exceeding targets in corporate guidance and five-year plan anticipated capital program, including 2019 strategy, focus of development and allocation thereof, number of w ells on stream, level of capital productivity, expected return and source of funding w ell performance, completions intensity, location of acreage and costs relative to peers and w ithin assets anticipated production, including grow th from core assets, cash flow, free cash flow, capital coverage, payout, profit, net present value, rates of return, recovery, return on capital employed, production and execution efficiency, operating, income and cash flow margin, and margin grow th, including expected timeframes number of potential drilling locations (including premium return inventory and ability to add to or consume such inventory), w ell spacing, number of w ells 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 grow th against peers pacesetting metrics being indicative of future w ell performance and costs, and sustainability thereof timing, success and benefits from innovation, cube development approach, advanced completions design, scale of development, high-intensity completions and precision targeting, 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 estimated reserves and resources at December 31, 2017, including product types and stacked resource potential anticipated third-party incremental and joint venture carry capital ability to manage costs and efficiencies, including drilling and completion, operating, corporate, transportation and processing, staffing, services and materials secured and supply chain management expected net debt, net debt to adjusted EBITDA, target leverage, financial capacity and other debt metrics grow th in long-term shareholder value, options to maximize shareholder returns and timing thereof commodity price outlook outcomes of risk management program, including exposure to commodity prices and foreign exchange, amount of hedged production, market access, market diversification strategy and physical sales locations management of balance sheet and credit rating, including access to sources of liquidity and available cash execution of strategy and future outlook in five-year plan, including expected grow th, returns, free cash flow, projections based on commodity prices and use of cash therefrom environmental, health and safety performance advantages of Encana s multi-basin portfolio anticipated dividends or changes thereto impact of changes in law s and regulations, including recent U.S. tax reform anticipated shares to be acquired under share repurchase program 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; ability to access credit facilities and shelf prospectuses; assumptions contained in the Company s corporate guidance, five-year plan and as specified herein; 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; 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; variability in the amount, number ofshares and timing of purchases, if any, pursuant to the share repurchase program; timing and costs ofwell, facilities and pipeline construction; business interruption, property and casualty losses orunexpected 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 royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential lawsuits and regulatory actions made against Encana; impact of disputes arising with its 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 liquids and natural gas from plays and othersources notcurrentlyclassifiedas proved, probableor possible reserves oreconomic contingentresources, including futurenetrevenue estimates; risks associated with pastand future acquisitions or divestitures ofcertain 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 respectthereofwhich Encanamayrefer to from time to timeas proceeds, deferred purchase price and/or carry capital, regardless ofthe legal form) as a resultof various conditions notbeingmet; and other risks and uncertainties impacting Encana's business, as described in its mostrecentannual Reporton 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 FLS are reasonable, there can be no assurance FLS will prove to be correct. Readers are cautioned that the above assumptions, risks and uncertainties are notexhaustive. FLS aremade as ofthe date hereofand, exceptas required bylaw,encana undertakes no obligation toupdate publiclyor revise anyfls. The FLS contained herein areexpresslyqualified bythese cautionarystatements. Certain future oriented financial information orfinancial outlook information is included in this presentation to communicate currentexpectations as to Encana s performance. Readers are cautionedthatitmaynotbe 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 arepresented for comparison purposes. Drilling and completions costs have been normalizedas specified in this presentationbasedon 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 and are a subset of total inventory locations. The designation of a location as a premium return location does not imply a different or distinct criteria with respect to the technical certainty status of the location or to the corresponding reserves / resource categorization. For convenience, references in this presentation to Encana, the Company, we, us and our may, where applicable, refer onlyto or include anyrelevant direct and indirect subsidiarycorporations andpartnerships ( Subsidiaries ) ofencana Corporation, and the assets, activities and initiatives ofsuchsubsidiaries. 65 ADVISORY REGARDING OIL & GAS INFORMATION All reserves and economic contingent resources estimates in this presentation are effective as of December 31, 2017, prepared by qualified reserves evaluators in accordance w ith procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook, National Instrument 51-101 (NI 51-101) and SEC regulations, as applicable. On August 14, 2017, Encana w as granted an exemption by the Canadian Securities Administrators from the requirements under NI 51-101 that each qualified reserves evaluator or qualified reserves auditor appointed under section 3.2 of NI 51-101 and w ho execute the report under Item 2 of Section 2 of NI 51-101 be independent of Encana. Notw ithstanding this exemption, for year-ended December 31, 2017, Encana involved independent qualified reserves auditors to audit a portion of the Company s reserves and economic contingent resources estimates. Detailed Canadian and U.S. protocol disclosure w ill be contained in the Form 51-101F1 and Annual Report on Form 10-K, respectively, as described in Note 2. Additional detail regarding Encana's economic contingent resources disclosure w ill be available in the Supplemental Disclosure Document filed concurrently w ith the Form 51-101F1. Information on the forecast prices and costs used in preparing the Canadian protocol estimates w ill be contained in the Form 51-101F1. For additional information relating to risks associated w ith the estimates of reserves and resources, see "Item 1A. Risk Factors" of 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 know n accumulations, from a given date forw ard, based on: analysis of drilling, geological, geophysical and engineering data, the use of established technology, and specified economic conditions, w hich are generally accepted as being reasonable. Proved reserves are those reserves w hich can be estimated w ith a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered w ill 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 w ill be greater or less than the sum of the estimated proved plus probable reserves. Contingent resources do not constitute, and should not be confused w ith, reserves. Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from know n accumulations using established technology or technology under development, but w hich are not currently considered to be commercially recoverable due to one or more contingencies. There is uncertainty that it w ill 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 how ever 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 defined as economic contingent resources if they are currently economically recoverable and 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. None of Encana s estimated contingent resources are subject to technical contingencies. 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 know n to exist over a large areal expanse and/or thick vertical section, w hich w hen compared to a conventional play, typically has a low er geological and/or commercial development risk and low er 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 know n 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, w ith the substitution of natural gas and crude oil w here appropriate for the w ord petroleum. As used by Encana, estimated ultimate recovery ( EUR ), w hich 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 w hich are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom. Encana has provided information w ith respect to its assets w hich are analogous information as defined in NI 51-101, 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 w ell as from a variety of publicly available information sources w hich 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 w ith 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 w ill be discovered. There is no certainty that it w ill be commercially viable to produce any portion of the estimated PIIP, NGIP, COIP or EUR. Estimates of potential gross inventory locations, including premium return w ell inventory, include proved undeveloped reserves, probable undeveloped reserves, un-risked 2C contingent resources and unbooked inventory locations. Approximately 40 percent of all locations stated in this presentation are booked as of December 31, 2017 and are in respect of gross locations that have been categorized as either reserves or contingent resources, including 744 proved undeveloped locations, 1,399 probable undeveloped locations and 6,857 un-risked 2C contingent resource locations (in the development pending, development on-hold or development unclarified project maturity sub-classes). Unbooked locations have not been classified as either reserves or resources and are internal estimates that have been identified by management as an estimation of Encana's multi-year potential drilling activities based on evaluation of applicable geologic, seismic, engineering, production, resource and acreage information. There is no certainty that Encana w ill drill all unbooked locations and if drilled there is no certainty that such locations w ill result in additional oil and gas reserves, resources or production. The locations on w hich Encana w ill actually drill w ells, 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 res ervoir information that is obtained, production rate recovery, transportation constraints and other factors. While certain of the unbooked locations may have been de-ris ked by drilling existing w ells in relative close proximity to such locations, many of other unbooked locations are farther aw ay from existing w ells w here management has less information about the characteristics of the reservoir and therefore there is more uncertainty w hether w ells w ill be drilled in such loc ations and if drilled there is more uncertainty that such w ells w ill 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 w ellhead. Readers are cautioned that BOE may be misleading, particularly if used in isolation. 66 33