CORPORATE PRESENTATION ENCANA CORPORATION

Transcription

1 CORPORATE PRESENTATION ENCANA CORPORATION February 2018

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3 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 ( )* Additional financial capacity at normalized leverage of 1.5x ~$500 million 2019 free cash flow Ŧ * $400 million share repurchase program to be initiated in Q (a) Funded from cash on hand 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. (a) Subject to and following TSX approval. 1 FOCUSED ON SHAREHOLDER RETURNS ~$3 Billion of Free Cash Flow Ŧ Over Five Year Plan $400 million share repurchase program to be initiated in Q (a) ~$3 billion of cumulative free cash flow Ŧ ( F)* Balance sheet discipline Creates Options: Returns to Shareholders Resiliency Managing volatility Portfolio Value Creation Building on a quality portfolio SHAREHOLDER RETURNS *Assumes $55 WTI, $3 NYMEX, $1.50 AECO Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website (a) Share repurchase program subject to and following TSX approval. 2 1

4 ($MM) ($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 F Cash Flow Ŧ ~25% CAGR Updated 5 year plan is better across the board 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 5,000 4,000 3,000 2,000 1, ,000 2,000 1, F 2019F 2020F 2021F 2022F Cash From Operating Activities NCWC & Other Cash Flow (Non-GAAP) ~$3.0B of Cumulative Free Cash Flow Ŧ Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website F 2019F 2020F 2021F 2022F Capital Cumulative Free Cash Flow 4 2

5 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 Target ~1.5x F 2019F 2020F Net Debt / Adjusted EBITDA - Actual Net Debt / Adjusted EBITDA Analyst Consensus Net Debt / Adjusted EBITDA Normalized Mid-Cycle Target of ~1.5x Analyst consensus per Bloomberg, February 9, 2018 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 5 FOCUS ON CORPORATE RETURNS Differentiated ROCE 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. 6 3

6 Production (MBOE/d)** 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 expected to grow ~20% to ~$14/BOE Liquids mix Efficiency Access to markets Cash Flow Margin Ŧ Expansion ($/BOE) ~ F Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 7 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 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 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 8 4

7 % of Upstream Revenue MARGIN GROWTH DRIVEN BY LIQUIDS Premium Liquids Markets and Diversified Gas Markets >70% revenue from liquids Oil and condensate priced at ~WTI accounts for ~65% of revenue Canadian Condensate ~ at par with WTI Eagle Ford production priced at LLS Permian volumes priced at Midland, Houston and points beyond via international shipments Gas revenue exposure is highly diversified 2018 Canadian gas realized price expected to be NYMEX less ~US$0.45, including hedges 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% > 70% Revenue from Liquids (2018F 2020F) F F Non- AECO gas ~WTI Oil and Condy Other NGL All Other Gas AECO Gas 9 WORLD CLASS PORTFOLIO Encana's Resource In Context Core positions in four of North America s premier basins >23,000 total inventory locations ~11,000 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 *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. 10 5

8 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 11 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 Additional liquids handling capacity to come on in Q Growing liquids to 55,000-65,000 bbls/d in Q Basin leading operator Top well performance Most efficient operator with track record of innovation Longest laterals with highest completion intensity 12 6

9 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 13 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 14 7

10 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 15 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 16 8

11 Cumulative Production (MBOE)* 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 Days Permian High Intensity Design Keeps Frac Energy Closer *Well results normalized to 5000 lateral. High Intensity Design Base Design 17 CUBE DEVELOPMENT ABOVE-GROUND BENEFITS Development at Industrial Scale Highly efficient, agile development Multi-well pads 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 Cube Development Above Ground Benefits Multi-rig, Multispread Reoccupied facilities Integrated Supply Chain 18 9

12 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 19 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 Robust planning and logistics Leading industry safety performance year-over-year Scope and scale necessitates highly sophisticated planning and logistics Relentless pursuit of optimization opportunities 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 20 10

13 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 21 RISK MANAGEMENT Adds Greater Certainty to Cash Flow and De-Risks Capital Program 2018 Price sensitivity to a $5 decrease to WTI is about $120 million to cash flow 2018 Price sensitivity to a $0.25 decrease to NYMEX gas is about $40 million to cash flow F/X Risk is managed via US Dollar denominated currency swaps: $(0.87)/Mcf $650 million notional U.S. dollar denominated ± currency swaps at an average exchange rate of US$ to C$1, which mature monthly throughout $0.01 Change to F/X (eg to 0.79) has annual impact of less than $10 million to cash flow BENCHMARK HEDGES 2018* 2019 Oil and Condensate WTI Fixed Price Swap Swap Price (US$/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$/bbl) Natural Gas NYMEX Fixed Price Swap Swap Price US$/Mcf** 78 Mbbls/d $54.21/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 767 MMcf/d $3.04/Mcf 15 Mbbls/d $58.30/bbl Risk management positions as at January 31, * January to December 2018 positions.** Hedged volumes are converted to Mcf at a 1:1 ratio from MMBtu

14 BASIS RISK MANAGEMENT PROGRAM Market Access & Price Risk Management Western Canada Realized price including hedge expected to be ~$0.45 below NYMEX in 2018 AECO US$0.25 fluctuation equals less than US$15MM cash flow in 2018 after hedge Western Canada AECO Basis Hedges Swap Price US$/Mcf** 475 MMcf/d $(0.87)/Mcf 500 MMcf/d $(0.88)/Mcf Transport to Dawn 316 MMcf/d 316 MMcf/d Transport to Sumas/Malin 124 MMcf/d 134 MMcf/d Transport to Chicago 52 MMcf/d 100 MMcf/d Positions as at January 31, Hedged and transport volumes are converted to Mcf at a 1:1 ratio from MMBtu. ** Price stated is the differential versus NYMEX pricing. Permian Permian volumes priced at Midland, Houston and points beyond via international shipments Permian WTI/Midland Differential Hedges Swap Price (US$/bbl) Transport to Houston (EPD Midland to Houston*) Positions as at January 31, *Enterprise Products Partners L.P 34 Mbbls/d $(0.78)/bbl 10 Mbbls/d $(1.09)/bbl 19 Mbbls/d 39 Mbbls/d 23 ASSET OVERVIEW Permian drilling in Midland County 12

15 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 & $3.00 NYMEX; Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures, including reconciliations, see Company s website. 25 PERMIAN 2018 Program FY 2018 Plan Acreage (net acres) 118,000 Average Working Interest (%) 94% Average Royalty Rate (%) 25% Development Capital (net) ($MM) $ Gross Rig Count 4-5 HZ Wells Drilled (net) HZ Wells On-stream (net) 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 FY2017 to FY % 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% 26 13

16 (MBOE/d) Cumulative Production (MBOE)* PERMIAN CONTINUES STRONG EXECUTION Targeting 30% Annual Growth Finished 2017 ahead of plan with Q4 production of >82MBOE/d Innovation continues to drive well productivity improvements and operational efficiencies Improved targeting of reservoir compartments Completion design enhancing near well complexity Well performance on track with expectations and validates type curve assumptions Cube development continuing 70% of 2018 program to target Midland/Martin/Upton Counties Services secured for 2018 Service cost inflation will be offset by self-sourced commodities and operational efficiencies to hold well costs flat year-over-year Local sand expected to make up >90% of 2018 program Firm transport on Enterprise Midland-Sealy pipeline Provides additional transport and market diversity Permian Cube Performance Abbie Laine Q RAB 2 Q Davidson 02 E Q Davidson 02 W Q Cowden 30 Q Davidson 38 Q Days Targeting 30% Annual Growth Midland Type Curve IP180 *3-stream production, normalized to 7500 lateral F 27 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 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 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 Midland-Sealy 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 Local Refineries Pipelines Under Construction Permian Supply Source: Wells Fargo Securities, Encana Potential price risk (timing of future projects) Existing Pipelines Identified Pipeline Projects Current oil export infrastructure ~3 MMbbls/d ~300 Mbbls/d additional capacity put in place in 2017 Enterprise Midland-Sealy pipeline expected to be in full service April 1, 2018 Subsequent projects targeting 2H 2019 in-service dates Strong production growth increases potential for temporary Midland differential weakness prior to the next set of expansions 31 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, ,

19 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, Estimated inventory based on ft spacing, 7,500 lateral length, Permian type curves are stated on a three stream basis. 33 MONTNEY 2018 Program FY 2018 Plan Acreage (net acres) 379,000 British Columbia (CRP) 289,000 Alberta (Pipestone) 90,000 Working Interest (%) 63% (includes Pipestone) Average Royalty Rate (%) 5 10% Development Capital (net) $MM $400 $450 Gross Rig Count (average) 8 Net Wells Drilled (CRP) Net Wells Drilled (Pipestone) Net Wells On-stream (CRP) Net Wells On-stream (Pipestone) D&C Cost* ($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 Q liquids production of 55-65Mbbls/d double Q rates Tower and Pipestone Liquids hubs on track for Q 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 34 17

20 (Mbbls/d) Operating Margin ($/BOE) Diversified Market Exposure in Western Canada Portfolio Approach to Price Risk Management To US Northwest ~115 MMcf/d 100% firm capacity on Nova Gas Transmission System (NGTL) Condensate sold into premium local market Condensate Imports To Dawn 316 MMcf/d To Chicago ~88 MMcf/d ~500 MMcf/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 Natural Gas Export Pipeline Condensate Import Pipeline 35 MONTNEY DELIVERING CONDENSATE GROWTH Significant Margin Expansion Margin Expansion Driving Cash Flow Ŧ Growth Margin expansion driven by liquids growth Liquids more than doubled from Q4/16 to Q4/17 and are set to double again in Q4/18 to 55-65Mbbls/d Cube development and advanced completions are delivering strong productivity and efficient growth New bench tests in Tower and Dawson South delivering initial CGR of bbls/mmcf Completions innovation and operating efficiencies reduced Pipestone completions cycle times by >30% New plants realized ~98% runtime in December Ramp into facilities will continue in first half of 2018 South CLH Phase II on-stream in Q Currently operating at peak 2018 rig count Tower and Pipestone liquids hubs on track for Q start-up Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 Montney Liquids Production Set to Double Again in Q Q4 16 Q4 17 Q4 18F 14 Q4 16 Q4 17 Q4 18F Condensate 29 Other NGLs

21 ($MM) MONTNEY CASH FLOW GROWTH High Quality Condensate Play Montney growth has been self-funded Transition to liquids and increase in scale driving margin expansion 2018 significant production growth while generating free cash flow Ŧ Additional growth in free cash Ŧ expected in 2019 Competes with the best plays in North America Liquids-Rich Montney Permian D&C Cost ($MM) Oil/C5 IP180 (bbls/d) Royalty Rate 5-10% 25% Montney Free Operating Cash Flow Ŧ in 2018 & ,400 1,200 1, F 2019F Capital Upstream Operating CF Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. 37 AGREEMENT WITH VERESEN MIDSTREAM Fee-for-Service Structure Tower, Sunrise and Saturn plants on-stream Q 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 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 38 19

22 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) Existing Facilities 1,150 42,000 15,500 1 Tower NCLH Q , Pipestone CLH** Q ,500 0 Total Net Capacity Year End ,150 61,500 15,500 Tower 1 Dawson South 3 Pipestone ~2021/2022 TBD TBD TBD 3 Expansion** 2 Commissioning of Tower, Sunrise and Saturn in 2017 added approximately 450 MMcf/d of gas, 19 Mbbls/d of condensate, and 10 Pipestone Mbbls/d of NGL to existing capacity 40mi / 65km *Condensate and NGL capacities assume a 30% cut on C3+ facility capacities. Capacities are net ECA, and stated after shrink and before royalties. **Pipestone facilities are not included in the VMLP agreement. 39 ENCANA MONTNEY 5 Year Growth Profile Development focused in condensate rich areas 2018 program to fill new liquids capacity Liquids Growth Profile Additional capacity comes online late 2018 Operating margin expected to increase >40% by 2022 Liquids production of Mbbls/d Q Expect liquids production of >70 Mbbls/d by , F 2019F 2020F 2021F 2022F Gas Growth Profile Liquid weighting grows to >25% of total by ,000 Liquids handling expansions support growth plans 500 Volumes quoted are net to Encana F 2019F 2020F 2021F 2022F 40 20

23 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 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 41 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) < < >250 Gross Premium Return Inventory 1, Estimated inventory based on ft. spacing, 8,200-9,800 lateral length. Volumes are stated on a shrunk condensate and a raw gas basis

24 Annual Production (MBOE/d) Cumulative Production (MBOE)* EAGLE FORD & DUVERNAY Quality Assets Generating Free Operating Cash Flow Completions design continues to drive productivity improvements and expand inventory Eagle Ford and Austin Chalk ahead of type curve Duvernay advanced completions driving 25% uplift in first 90 days Continued margin expansion Highly efficient operations reducing OPEX Eagle Ford sales into premium Houston & LLS markets >40% of Duvernay production is condensate that receives ~WTI pricing 2018 program will focus on developing best inventory Assets generating combined ~$300MM annual free operating cash flow Ŧ *Normalized to 8,900 lateral. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-gaap measures see the Company s website. Duvernay Completions Innovation Leads to 25% Uplift in IP Simonette South VRGC Type Curve IP Days Simonette South Base Design Simonette South High Intensity Design Eagle Ford & Duvernay Maintaining ~65 MBOE/d Combined F 43 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 $ Gross Rig Count (average) 2 Wells Drilled (net) Wells on Stream (net) 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 ~2/3 Eagle Ford and ~1/3 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 44 22

25 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 45 EAGLE FORD Gross Premium Return Inventory Type Curve Eagle Ford Austin Chalk IP30 (BOE/d) IP180 (BOE/d) EUR/Well (Mbbls) EUR/Well (MBOE) premium return inventory locations Testing additional opportunity in both the Graben area of the Eagle Ford and in the Austin Chalk GOR (scf/bbl) 2,000 1,500 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

26 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 $ 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. 47 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 48 24

27 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, 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 49 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 H Evaluating commerciality (access to services, commodities, mid-stream, etc.) 50 25

28 $MM $/BOE SUPPLEMENTAL MAXIMIZING MARGIN Cost Control of Corporate Items Enhances Per Unit Margin Benefit of scale as per unit cost per BOE driven lower by cost control and growing production volumes Interest on debt is expected to be ~$70 million per quarter, with consolidated interest expense in the $90- $95 million range per quarter. Administrative expense excluding long-term incentives is expected to be around $45 million per quarter for Market optimization segment will include transportation costs of about $30-$35 million per quarter for Overall, the segment operating loss is expected to be around $16-$20 million per quarter Corporate Items Cost Control F Interest Expense G&A Excluding LTI Market Optimization Combined Cost $/BOE 52 26

29 PRODUCT VALUE CHAIN Projected Composition of Total Production Canada US 2018F* 2018F Pricing 2018F* 2018F Pricing (Mbbls/d) (%WTI) (Mbbls/d) (%WTI) Oil % % Condensate** % % Butane % % Propane % % Ethane % % Canada US 2018F* 2018F Pricing 2018F* 2018F Pricing (MMcf/d) (%NYMEX) (MMcf/d) (%NYMEX) Natural Gas 1,000 1,100 73% % *2018F based on company guidance as at February 15, 2018, excluding impact of hedges; production ranges are not additive; **Includes plant condensate 53 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 54 27

30 (US$ MM) DISCIPLINED FINANCIAL MANAGEMENT Access to Ample Liquidity Through 2020 $4.5B fully committed, unsecured, revolving credit facilities $4.5B available at December 31, 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 Ŧ = debt + equity + $7.7B equity adjustment 22% as at December 31, 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 Ŧ Ratio 36% 30% 60% Threshold 28% 23% 22% 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. 55 DISCIPLINED FINANCIAL MANAGEMENT Debt Portfolio as at December 31, 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,

31 FUTURE ORIENTED INFORMATION This presentation contains certain forward-looking statementsor information (collectively, FLS ) within the meaning of applicable securities legislation, including the U.S. Private Securities Litigation ReformAct of FLS include: expectation of meeting or exceeding targets in corporate guidance and five-year plan anticipated capital program, including focus of development 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, 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 expansion, including expected timeframes 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 metrics being indicative of future well 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 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 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 growth 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 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 growth, 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 laws and regulations, including recent U.S. tax reform anticipated share repurchase program, including amount and number of shares, anticipated timeframe, regulatory filings and approval thereof, method and location of purchases and benefits of program 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 of shares, method, location and timing of purchases, if any, pursuant to the share repurchase program, including regulatory filings and approvals thereof; timing and costs of well, facilities and pipeline construction; business interruption, property 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 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 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 fromtime 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 not exhaustive. FLS are madeas of the date hereof and, except as required by law, Encana undertakes no obligation to update publicly or revise any FLS. The FLS contained herein 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-taxbasis 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 taxreturns greater than 35% at $50/bblWTI 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. 57 ADVISORY REGARDING OIL & GAS INFORMATION All estimates in this news release are effective as of December 31, 2017, prepared by qualified reserves evaluators in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook, National Instrument (NI ) and SEC regulations, as applicable. On August 14, 2017, Encana was granted an exemption by the Canadian Securities Administrators from the requirements under NI that each qualified reserves evaluator or qualified reserves auditor appointed under section 3.2 of NI and who execute the report under Item 2 of Section 2 of NI be independent of Encana. Notwithstanding 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 will be contained in the Form F1 and Annual Report on Form 10-K, respectively, as described in Note 2. Additional detail regarding Encana's economic contingent resources disclosure will be 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 will be contained in the Form F1. For additional information relating to risks associated with 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 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 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 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 bein strict accordance with COGEH. Estimates by engineering and geo-technical practitioners may vary and the differences may besignificant. 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 40 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 tobarrels 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

32 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, see the Company s website and/or the advisories at the back of this presentation. Non-GAAP measures include: Non-GAAP Cash Flow, Free Cash Flow and Cash Flow 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. Cash Flow 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. Forward looking Non-GAAP Cash Flow, Free Cash Flow and Cash Flow Margin: $3 Billion Cumulative Free Cash Flow ( ) In total, 2018 through 2022 Cash From Operating Activities is expected to be $13.4B with $500M in net change in non-cash working capital and net change in other assets and liabilities added back, resulting in estimated cumulative Non- GAAP Cash Flow of $13.9B. Cumulative capital expenditures for 2018 through 2022 is expected to be $10.9B, resulting in cumulative Free Cash Flow of $3B. Net change in non-cash working capital is assumed to be zero for 2018 through Net change in other assets and liabilities is assumed to be about $100M per year for 2018 through ~$14.00/BOE Cash Flow Margin (2018) 2018 Cash From Operating Activities is expected to be approximately $1.8B with approximately $100M net change in non-cash working capital and net change in other assets and liabilities added back, resulting in an estimated Non-GAAP Cash Flow of $1.9B. This amount divided by the mid-point of the 2018 production guidance of 370 MBOE/d equals the expected Cash Flow Margin of ~$14.00/BOE. ~$500 million Free Cash Flow (2019) 2019 Cash From Operating Activities is expected to be approximately $2.2B with approximately $100M net change in non-cash working capital and net change in other assets and liabilities added back, resulting in an estimated Non-GAAP Cash Flow of about $2.3B. Capital expenditures are expected to be about 1.8 billion resulting in non-gaap free cash flow of $500 million 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. 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. Cash Costs are defined as the summation of production, mineral and other taxes, transportation and processing expense, operating expense, administrative expense and interest expense. Development Capital Includes drilling, completion and facility costs, but excludes land and lease, seismic, appraisal and capitalized internal costs. Capitalized internal costs include salaries, benefits and other costs directly identifiable with acquisition, exploration and development activities. Debt to Adjusted Capitalization Debt to Adjusted Capitalization is a proxy for Encana s financial covenant under the Company s credit facilities which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders equity and an equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company s January 1, 2012 adoption of U.S. GAAP. 59 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, see the Company s website and Encana s most recent Annual Report as filed on SEDAR and EDGAR. Non-GAAP measures include: Operating Margin/Operating Cash Flow/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 Netback is defined as indicated divided by average barrels of oil equivalent sales volumes. Operating Margin/Operating Cash Flow/Operating Netback is used by management as an internal measure of the profitability of a play(s). Free Operating Cash Flow Operating Cash Flow in excess of capital investment, excluding net acquisitions and divestitures. Return on Capital Employed (ROCE) Adjusted Operating Earnings divided by Capital Employed. Adjusted Operating Earnings is defined as Non-GAAP Operating Earnings (Loss) plus after-tax interest expense. Capital Employed is defined as average debt plus average shareholders equity. 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 include, 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. 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

33 2018F ENCANA CORPORATE GUIDANCE US$, U.S. GAAP February 15, F Capital Investment ($ billions) Total Capital Investment Production (after royalties) Liquids (Mbbls/d) Natural Gas (MMcf/d) 1,150 1,250 Total Production (MBOE/d) Operating Costs ($/BOE at 6:1 ratio) Upstream Operating Expense (1) Transportation and Processing Administrative Expense (1) Production, Mineral & Other Taxes (% of Revenue (2) ) % 1. Excludes long-term incentives. 2. Upstream revenue excluding risk management activities. ADVISORY: This document contains certain forward-looking statements or information (collectively, FLS ) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of FLS include: capital investment, liquids, natural gas and total production; and operating costs. 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 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 of shares, method, location and timing of purchases, if any, pursuant to the share repurchase program, including regulatory filings and approvals thereof; timing and costs of well, facilities and pipeline construction; business interruption, property 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 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 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 inencana 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 2018F 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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