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3 ENCANA CORPORATION MONTNEY INVESTOR DAY NEW YORK CITY MAY 17, 216 Doug Suttles President & Chief Executive Officer ENCANA IN 216 Well Positioned for Success TOP TIER RESOURCE 95% of 216F capital allocated to core four 216 program focused on core acreage in each asset OPERATIONAL EXCELLENCE Significant D&C cost efficiencies Rapid application of innovations across portfolio RPH* model unlocks value BALANCE SHEET STRENGTH MARKET FUNDAMENTALS Maximizing realized prices Informs capital allocation Actively managing volatility CAPITAL ALLOCATION Driven from the top Significant flexibility to scale capital based on commodity prices *Resource Play Hub: Encana s development model using repeatable, transferable operations techniques to reduce costs and improve safety and environmental performance. 2

4 ENCANA Multi-Basin Portfolio Advantage Core of the core positions in four of North America s top basins Over 16, high quality locations Operational excellence Rapid application of innovations across the portfolio Significant D&C cost efficiencies 22-44% improvement in Q1 216 Focused portfolio with significant financial flexibility 95% of 216 capex invested into core four assets Montney 1, well locations Duvernay 1, well locations Permian 5, well locations Eagle Ford 6 well locations Montney inventory based on ft spacing 3 ENCANA CORPORATION EXECUTION EXCELLENCE Michael McAllister EVP & COO

5 ENCANA S EXECUTION EXCELLENCE Basin Leading Operator INNOVATION CONTINUOUS IMPROVEMENT PORTFOLIO ADVANTAGE BASIN LEADING OPERATOR DISCIPLINED BENCHMARKING TO COMPETITORS 5 INNOVATION AT A GLANCE Driving Efficiency Across the Portfolio 6

6 Gross Operated Production (MMcf/d) Drilling Cost (MM$/1 ) Rate (BOE/d) ENCANA MONTNEY Development History MMcf/d 1, 75 5 Prior to 23 Conventional vertical development 26 First HZ well drilled HZ development of BC Montney Land capture in Pipestone HZ development in Gordondale Unconventional Montney resource evaluation Land capture in Montney BC 212 Cutbank Ridge Partnership (CRP) joint venture with Mitsubishi Focus on condensate rich areas Completions design optimization Veresen KKR infrastructure deal ENCANA IS THE MONTNEY LEADER Combined Scale and Efficiency Largest producer in the Montney Drilling cost leader Over a decade of operations in the play Longest laterals with highest completion intensity Massive wells Wells up to 2.5 MMBoe, IP >2,5 BOE/d Condensate rich wells flowing >4 bbls/d Largest Producer Cost Leader Massive Wells 1,2 1,.4 3, 2, , 1,5 1, 5 5 mi Producing Days Peer acreage sourced from RS Energy Group, Inc. & Company Presentations 8

7 North American Demand Growth ENCANA CORPORATION FUNDAMENTALS Renee Zemljak EVP Midstream, Marketing & Fundamentals David Thorn Vice President, Marketing Northern Operations NORTH AMERICAN NATURAL GAS FUNDAMENTALS Demand Expected to Grow by 14 Bcf/d by 22 Bcf/d F 217F 218F 219F 22F Power Other Residental/Commercial Industrial Export to Mexico Gulf Coast LNG Total Supply Source: Encana Fundamentals, EIA, Ventyx, IHS 1

8 NORTH AMERICAN NATURAL GAS FUNDAMENTALS Future Demand Growth will be Concentrated in the Gulf Coast 2. Canada West Midwest Northeast Gulf Coast 3. Southeast Source: Encana Fundamentals 11 NORTH AMERICAN NATURAL GAS FUNDAMENTALS Low-Cost Supply Basins Continue to Grow Montney expected to grow to ~7% of North American natural gas production by 22 Bcf/d 1 1% 8 8% 6 6% 4 4% 2 2% Montney Montney % of NA Source: Encana Fundamentals, IHS % 12

9 NORTH AMERICAN NATURAL GAS FUNDAMENTALS Montney - Highly Competitive Break-even Cost Break-even ($/MMBtu) $6.5 $6. $5.5 $5. $4.5 $4. $3.5 $3. $2.5 $2. Arkoma Woodford Fayetteville Piceance Utica Haynesville Marcellus Deep Basin Montney Current Source: RS Energy Group, Inc. Hardcore Canada May NORTH AMERICAN NATURAL GAS FUNDAMENTALS Activity Maintained in Lowest Cost Basins Montney represents ~21% 216F North American gas rig count, while Northeast represents ~24 % Rigs Activity remains strong in low-cost basins Rig activity declining in high cost plays Other North America Montney US Northeast Source: Encana Fundamentals, Baker Hughes (U.S. rigs), IHS (Canadian rigs) 14

10 WESTERN CANADIAN MARKET FUNDAMENTALS Natural Gas Export Basin Premium Condensate Market Western Canadian Sedimentary Basin (WCSB) West Coast LNG Potential Montney Nova Gas Transmission System (NGTL) Condensate Imports 255 Mbbl/d 15 Bcf/d gas production 5 Bcf/d regional demand 5 Bcf working storage 11.7 Bcf gas export capacity 22 Mbbls/d condensate production 4 Mbbls/d condensate demand To Pacific Northwest 4.1 Bcf To Eastern Canada 4.2 Bcf To U.S. Midwest *3.4 Bcf Natural Gas Export Pipeline Condensate Import Pipeline Source: Encana Fundamentals *Net Effective Capacity (Bakken Access) 15 WESTERN CANADIAN NATURAL GAS FUNDAMENTALS Montney is the Growth Engine for WCSB Bcf/d Historical peak production Forecast % 4% 35% 3% 25% 2% 15% 1% 5% % Montney expected to grow to 7 Bcf/d in 22, representing 38% of WCSB production Montney expected to lead WCSB growth back toward 26 historical peak Other WCSB Montney Montney % of WCSB Source: Encana Fundamentals, IHS 16

11 WESTERN CANADIAN NATURAL GAS FUNDAMENTALS Local Demand Growth Driven by Oil Sands Bcf/d Forecast Local Distribution Companies/Other Industrial Power Oil Sands >1 Bcf/d of growth from oil sands & power sector expected through 22 Strong historical local demand growth has reduced reliance on total takeaway capacity Demand growth plus base declines add ~1.8 Bcf of incremental market Source: Encana Fundamentals, Statistics Canada 17 WESTERN CANADIAN NATURAL GAS FUNDAMENTALS Required Exports and Currently Available Capacity Bcf/d F 217F 218F 219F 22F Substantial existing physical export capacity Exceeds required exports by >1.5 Bcf/d Montney does not require any new transport capacity to grow WCSB Required Exports* Current Physical WCSB Export Capacity Source: Encana Fundamentals *Required Exports = Expected Supply Minus Expected Demand 18

12 WESTERN CANADIAN NATURAL GAS FUNDAMENTALS What is AECO? West Coast LNG Potential Montney Nova Gas Transmission System (AECO Price) AECO is benchmark price for volumes traded on Nova Gas Transmission system (NGTL) Equivalent to NYMEX at Henry Hub Largest and most liquid gas trading hub in North America AECO Basis is price difference versus NYMEX To Pacific Northwest 4.1 Bcf To Eastern Canada 4.2 Bcf To U.S. Midwest *3.4 Bcf Basis set by marginal cost of transportation to neighboring markets Financial derivative market as liquid as any in North America Source: Encana Fundamentals *Net Effective Capacity (Bakken Access) 19 AECO BASIS Price-Setting Mechanism Bcf/d $/MMBtu 1. WCSB Required Exports & Contracted Capacity 4. Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr (.5) (1.) (1.5) Concurrent widening in AECO basis when required exports exceed contracts Required WCSB Exports* AECO Nominal Basis Contracted Capacity Oversupply resulting in incremental required exports and widening AECO Basis (2.) Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 *Required Exports = Expected Supply Minus Expected Demand 2

13 AECO BASIS Forward Market Trends Toward Historical Levels $US/MMbtu $.5 $. ($.5) ($1.) AECO basis has historically averaged $(.5) Basis has recovered rapidly when it has widened before The market sees a directional return toward historical levels ($1.5) Forward Market Historical Market Source: Encana Fundamentals, NGX, CME Group 21 MONTNEY ACCESS TO NORTH AMERICAN MARKETS Efficient Access to Market Montney West Gate Export A/BC Border NGTL Oil Sands/ WCSB Demand East Gate Export Empress/McNeill Border NGTL: ~11 Bcf/d of supply, >15, miles of pipeline, and thousands of receipt & delivery points Required expansions are inexpensive, timely, and provide system-wide access Approach is efficient and different than single system connection seen in US production areas Minimal regulatory impediments Alliance and Westcoast offer additional flexibility Source: Encana Fundamentals 22

14 MONTNEY ACCESS TO NORTH AMERICAN MARKETS Existing WCSB Export Infrastructure Allows for Growth Bcf/d F 217F 218F 219F 22F WCSB Required Exports* Current Physical WCSB Export Capacity Source: Encana Fundamentals *Required Exports = Expected Supply minus Expected Demand 23 MONTNEY ACCESS TO NORTH AMERICAN MARKETS WCSB Transportation Cost Advantage to Northeast Market Existing capacity will outcompete new-build economics to Eastern Canadian markets by ~$.15-$.3/MMBtu Montney continues to compete in Western markets, capturing demand growth and offsetting declines in the region Existing Infrastructure Greenfield Infrastructure Northeast U.S. production will continue to capture South and Southeastern demand via existing pipelines and shorter greenfield connectivity Source: Encana Fundamentals, Various Pipeline Websites 24

15 FUNDAMENTALS The Montney Competes on a Delivered Cost Basis Montney growth is required to balance increasing North American demand Highly competitive supply cost Advantaged into Western and Eastern (Dawn) markets Existing export pipeline capacity allows for competitive access to markets Minimal regulatory risk WCSB production should naturally meet western demand growth With a declining rate base and increased contracting, TCPL tolls will be competitive in Eastern markets 25 ENCANA CORPORATION RESOURCE IN CONTEXT David Hill EVP Exploration & Business Development Blair Porter Advisor, Engineering Exploration & Business Development

16 98 Hydrocarbon Bearing Reservoir MONTNEY MOST ACTIVE GAS PLAY Q1 216 Average Rig Activity Montney Rig activity concentrated in lowest cost basins Marcellus/Utica Play 1Q16 Rig Activity Montney 54 Marcellus/Utica 46 Rockies 33 Haynesville 17 Rockies Haynesville Sources: IHS, DrillingInfo, Nickles, EIA Active Rigs data as of March 216 Gas Wells Oil Wells Oil and Gas Wells Active Rigs 27 MONTNEY GEOLOGY OVERVIEW Depositional Environment AA Condensate Rich Gas Super Condensate Tower British Columbia Dawson South A B C D E F G H SEXSMITH Basal Alberta Pipestone Siltstone reservoir Not a shale High quality condensate & gas regions Robust performance across all fluid windows Multiple stacked zones Deposited in thick, stacked layers 28

17 MONTNEY REGIONAL SCALE Areal Extent Same as Marcellus Montney Marcellus Alberta Size and scale of Montney same as Marcellus Montney condensate window larger and richer British Columbia Peak 3d Rate (BOE/d) Miles (375 x 13 miles) Source: IHS 29 ENCANA S MONTNEY ACREAGE Massive Contiguous Land Position Encana Montney Acreage 81, gross acres (525, net) Alberta Miles 2 Peer Acreage Encana Acreage Peer acreage sourced from RS Energy Group, Inc. & Company Presentations 3

18 Alberta MONTNEY RESOURCE POTENTIAL Stacked Zones Comparable to the Permian NW Montney (35 miles) Upper Montney to Base Sexsmith SE 1, Permian Midland Basin (1 miles) Middle Spraberry to Base Wolfcamp C SE NW 2, 5 to 2 Bcf/section Up to 6 stacked laterals >15 MMbbls/section >8 stacked laterals SW Hydrocarbon Filled Porosity Marcellus (35 miles) 5 to 6 Bcf/section Single lateral NE 25 W Eagle Ford (2 miles) 3 to 4 MMbbls/section Up to two stacked laterals E MONTNEY PLAY Three Distinct Regions Conventional Northwest Super Condensate Rich (>1 bbls/mmcf) Condensate Rich (1-1 bbls/mmcf) Gas (<1 bbls/mmcf) Central Southeast Peak 3d Rate (BOE/d) Northwest 94 Hz wells drilled; 265 in 215 Narrow region of high performance Central 2,1 Hz wells drilled; 26 in 215 Highest quality pay Prolific condensate window Thickest stacked reservoirs Southeast 45 Hz wells drilled; 13 in 215 High quality condensate Minimal activity in gas window Source: IHS 32

19 1, Alberta Alberta MONTNEY REGIONAL SCALE Encana s Acreage is in the Core of the Basin Northwest Encana Acreage Central Peak 3d Rate (BOE/d) Conventional Super Condensate Rich Condensate Rich Gas Southeast Source: IHS Core Acreage 33 CROSS-SECTION OF THE MONTNEY Stacking Adds Scale NW Northwest Central Montney Regional Section: Hydrocarbon Filled Porosity Southeast SE NW SE Northwest (Structural Complexity) Central (Stacked, High Quality) Southeast (Stacked, Condensate Rich) Hydrocarbon filled porosity 34

20 Gas Rate (MMcf/d) (Normalized to 8,2 ) Alberta Gas Rate (MMcf/d) (Normalized to 8,2 ) Alberta WORLD CLASS GAS PLAY Best Rocks Drive Performance Northwest 8 Average Gas Well Performance by Region (Wells Since 214) Central 6 4 Conventional Super Condensate Rich Condensate Rich Gas 2 Central Non-Core Northwest Core Northwest Non-Core Central Core Cumulative Gas Production (Bcf) (Normalized to 8,2 ) Source: IHS, Encana data 35 CORE POSITION IN A WORLD CLASS GAS PLAY Operational Excellence Driving Basin Leading Performance Northwest Central Average Gas Well Performance by Region (Wells Since 214) Conventional Super Condensate Rich Condensate Rich Gas Northwest Core Central Non-Core Northwest Non-Core Encana 215 Montney (25 Wells) Central Core Cumulative Gas Production (Bcf) (Normalized to 8,2 ) Source: IHS, Encana data 36

21 Condensate Rate (bbls/d) (Normalized to 8,2 ) Gas Rate (Mcf/d) (Normalized to 8,2 ) Gas Rate (MMcf/d) (Normalized to 8,2 ) MONTNEY COMPETES WITH CORE MARCELLUS Encana Innovation Driving Productivity 16 Average Well Performance Marcellus vs. Encana Montney Encana 215 Montney Marcellus SW Core Marcellus NE Core Cumulative Gas Production (Bcf) (Normalized to 8,2 ) Source: IHS, Encana data 37 SIGNIFICANT CONDENSATE OPPORTUNITY Encana Delivering Strong Condensate Wells Montney 3 Day Peak Condensate Rates by Region Encana Recent Condensate Well Results SE Central Central Central Super Condensate Area >1 bbls/mmcf Condensate Area 1-1 bbls/mmcf Gas Area -1 bbls/mmcf 7, 6, 5, 4, 3, 2, 1, Pipestone (Super-Condensate area >1 bbls/mmcf) 1,65 bbls/d of condensate & 2.6 MMcf/d (~2,8 BOE/d) Tower (Condensate area 1-1 bbls/mmcf) 37 bbls/d of condensate & 5.5 MMcf/d (~1,32 BOE/d) Dawson South (Condensate area 1 1 bbls/mmcf) 5 bbls/d of condensate & 8.4 MMcf/d (~1,9 BOE/d) Condensate Natural Gas Source: IHS (data limited to wells with substantial liquids volumes reported in condensate areas) 38

22 STACKED RESOURCE POTENTIAL 1, Inventory Locations Stacking Development Layers (#) Gross Acres Spacing Inventory Super Rich Condensate 82, 44 3, Condensate 125, 66 3,6 Conventional Super Condensate Rich Condensate Rich Gas Gas 185, 88 3,4 Total Inventory 1, 8,2' Well Length 39 ENCANA CORPORATION Development Plans Jim Roberts Vice-President & General Manager, Northern Operations

23 ENCANA IN THE MONTNEY A Premier North American Play Large resource poised for significant growth 525, net acres in 3 contiguous core blocks Over 1, of pay, up to 6 stacked horizons Up to 22 Bcf/section with up to 45 bbls/mmcf condensate 1, gross well inventory Basin leading operator Most efficient operator with track record of innovation Cost reductions of 22% 216 Q1 vs. 215 Longest laterals with highest completion intensity Generates superior economic performance Flexible infrastructure plan Innovative midstream arrangement 8 MMcf/d of expansion under construction Growing net production to over 75, bbls/d and 1.8 Bcf/d by 226 Tower Saturn Dawson South 3% Gordondale 36% Pipestone 34% 1, Well Inventory Gas ( - 1 bbls/mmcf) Condensate (1-1 bbls/mmcf) Super-Condensate (>1 bbls/mmcf) Encana Core Montney Encana Non-core Montney Estimated inventory based on ft spacing 41 ENCANA IN THE MONTNEY History of Well Design Innovation 26 4,2 ft lateral 3 lb/ft proppant 3.5 bbls/ft fluid 9 ft cluster spacing 9 ft stage spacing ,2-7,8 ft lateral 3-1, lb/ft proppant 6 bbls/ft fluid 165 ft cluster spacing 66 ft stage spacing Present Day Design 7,2-9, ft lateral 65-1,8 lb/ft proppant bbls/ft fluid 8 ft cluster spacing 41 ft stage spacing 8,2-9, ft lateral 1, - 1,2 lb/ft proppant bbls/ft fluid 65-8 ft cluster spacing ft stage spacing 42

24 F&D ($/BOE) EUR (MBOE) IP3 (BOE/d) D&C Cost ($/1, ) Proppant (lb/ft) Lateral length (ft) ENCANA IN THE MONTNEY Drilling & Completions 1, 8, 6, 4, 2, 2, 1,5 1, F Lateral Length Increased ~2X Proppant Loading Increased ~4X F Completions Drilling F Drilling and Completion Cost* Decreased 5% *All data normalized to $.75 FX 43 ENCANA IN THE MONTNEY Well Performance and F&D IP3 Increased ~5X - 2, 1,5 1, 5 $8 $7 $6 $5 $4 $3 $2 $1 $ F F F EUR Increased ~8X F&D Reduced ~6X *All data normalized to $.75 FX 44

25 Rate (BOE/d) ENCANA IN THE MONTNEY Resource Play Hub at Work Water Resource Hub: Centralized Water Handling Facility Capacity of 5, bbls/d, recycling and saline, non-potable source wells Made possible by concentrated, continuous activity and growth plan Environmentally sustainable: reduces demand on domestic water supplies Offers certainty for completions execution Reduces impact on stakeholders: traffic, dust, noise >$32 MM in savings to date ~4, less truck loads ~$5.85/bbl operating cost savings ~$3K/well capital cost savings Project ROR ~3% 45 CONDENSATE (1-1 bbls/mmcf) Tower 3, 2,5 Type Curve IP18 Condensate = 37 bbls/d IP18 Gas = 5.4 MMcf/d EUR = 1.2 MMBOE D&C = $4.4 MM Lateral Length = 8, ft 216 Drill 5-1 Pad 2-12 Pad Tower 5 to >1 bbls/mmcf 2, After 5 months 36% higher than type curve 1,5 5mi / 8km 1, 5 Type Curve Actuals Producing Days Type Well Metrics ECA Net Leveraged Unleveraged Btax IRR (%) >2 8 Btax Payout (Months) 1 16 Operating Margin ($/BOE) Year Free Cash Flow ($MM) All metrics based on $3./MMBtu NYMEX, $5/bblWTI, and $.75 FX 46

26 Rate (BOE/d) Rate (BOE/d) CONDENSATE (1-1 bbls/mmcf) Saturn Saturn 3, 2,5 2, After 8 months 7% higher than type curve Type Curve IP18 Condensate = 35 bbls/d IP18 Gas = 7.5 MMcf/d EUR = 1.3 MMBOE D&C = $4.3 MM Lateral Length = 8,2 ft 216 Drill , 6-2, 8-2 Pads 1,5 1-1 bbls/mmcf 5mi / 8km 1, 5 Rate restricted due to facility limitations Type Curve Actuals Producing Days Type Well Metrics ECA Net Leveraged Unleveraged Btax IRR (%) >2 1 Btax Payout (Months) 1 15 Operating Margin ($/BOE) Year Free Cash Flow ($MM) All metrics based on $3./MMBtu NYMEX, $5/bblWTI, and $.75 FX 47 CONDENSATE (1-1 bbls/mmcf) Dawson South Dawson South 3, 2,5 New E4-17 Lower Montney IP 23% condensate 67% above type curve Lower Montney Type Curve IP18 Condensate = 35 bbls/d IP18 Gas = 7.1 MMcf/d EUR = 2.1 MMBOE D&C = $5.2 MM Lateral Length = 9,8 ft 9-35 Pad Pad 1-1 bbls/mmcf 216 Drills Pad 216 Drills 4-17 Pad 2, New B11-17 Lower Montney IP 9% condensate 46% above type curve 216 Drills Pad 12-5 Pad 1,5 <1 bbls/mmcf 5mi / 8km 1, 5 Lower Montney Type Curve Lower Montney Actuals Upper Montney Actuals Producing Days Lower Montney Type Well Metrics ECA Net Leveraged Unleveraged Btax IRR (%) >2 15 Btax Payout (Months) 1 14 Operating Margin ($/BOE) Year Free Cash Flow ($MM) All metrics based on $3./MMBtu NYMEX, $5/bblWTI, and $.75 FX 48

27 Rate (BOE/d) SUPER-CONDENSATE (>1 bbls/mmcf) Pipestone 3, 216 Drills Pad Pipestone ,5 2, New 14-1 Pad well IP 56% condensate Type Curve IP18 Condensate = 61 bbls/d IP18 Gas = 2.6 MMcf/d EUR = 1.2 MMBoe D&C = $5.4 MM Lateral Length = 9,8 ft 216 Drills 14-1 Pad >1 bbls/mmcf 1,5 1, 5mi / 8km 5 Type Curve Actuals 2-15 Actuals Producing Days Type Well Metrics ECA Net Btax IRR (%) 139 Btax Payout (Months) 1 Operating Margin ($/BOE) 25 2 Year Free Cash Flow ($MM) 8.6 All metrics based on $3./MMBtu NYMEX, $5/bblWTI, and $.75 FX 49 ENCANA MONTNEY TYPE CURVES Total Gross Inventory BRITISH COLUMBIA ALBERTA Region Gas Condensate Super - Condensate Condensate Super - Condensate IP3 (BOE/d) 1,5-2, 1,4-1,8 9-1,1 1,85-2,5 6-8 IP18 (BOE/d) 1,4-1,7 1,3-1,7 8-1, 1,45-1,65 9-1,1 EUR/Well (Bcfe) EUR/Well (MBOE) 1,6-1,8 1,25 1,5 9-1,1 2, - 2,3 9-1,2 Condensate Yield (bbls/mmcf) <1 1-1 >1 1-1 >1* D&C Cost/well ($MM) Average Lateral Length (ft)** 8,2 8,2 8,2 8,2 8,2 Total Gross Inventory 3,4 2,4 1,1 1,2 1,9 Estimated inventory based on ft spacing. *Alberta Super-Condensate averages >3 bbls/mmcf **Actuals vary between 7,8-9,9 5

28 Drilling Cost (MM$/1 ) Drilling Cost (MM$/1 ) Average Lateral Length (ft) Gross Operated Production (MMcf/d) MONTNEY PRODUCERS AT A GLANCE Encana is the Largest Producer 1,2 1, Peer acreage sourced from RS Energy Group, Inc. & Company Presentations Rig Count AAV APA ARC BIR CNRL COP Encana MUR NVA Other PPY Progress 7Gen RDS TOU Total 215Q Q Source : Industry data. Rig counts displayed for the most active and key peers. 51 ENCANA MONTNEY VS. COMPETITORS Drilling Performance Encana leading with longer laterals ~35 % greater than industry average Continuous improvement and innovation to reduce costs Bit design & optimization High performance motors Vendor sourcing for volume discounts Fluid system evolution Load leveling Competitor benchmarking Customized drilling parameters unique to reservoir 1, 8, 6, 4, 2, Lateral Length: ECA vs Industry Southeast Encana Drilling Cost Comparison Industry Average Central.. Source : Industry Data: The Well Completions and Frac Database (Canadian Discovery) and Industry Report 52

29 Daily Rate (BOE/d) Completion Cost ($MM/1, ) Daily Rate (BOE/d) Completion Cost ($MM/1, ) ENCANA MONTNEY VS. COMPETITORS Tower Performance and Economics Completion Cost/1, in Tower Completion Comparison Encana Peer* Tower.6 Proppant Density (lb/ft) 1,2 1,2 Fluid (gal/ft) Stage Spacing (ft) Tower Peer ECA Tower 216 Pacesetter Cluster density 5 2 Completion Type Cased Cased *Tower specific average ECA Tower wells outperform IRR by 35% and payout 1% faster Production Production & Economic Comparison 1,6 Encana Peer* 1,2 EUR/1 (BOE) IP18/1 (BOE/d) ECA 5-1 Pad Type Curve Btax IRR% Disc Payout (years) Tower Peer Type Curve 2 Year Netback ($/BOE) Months All metrics based on $3./MMBtu NYMEX, $5/bbl WTI, and $.75 FX *Source : Industry Data, The Well Completions and Frac Database (Canadian Discovery), and Company Presentations 53 ENCANA MONTNEY VS. COMPETITORS Saturn Performance and Economics Completion Cost/1, in Saturn Saturn Peer ECA Saturn 216 Pacesetter Completion Comparison Encana Peer* Proppant Density (lb/ft) 1,2 675 Fluid (gal/ft) Stage Spacing (ft) Cluster density 5 - Completion Type Cased Open Hole *Saturn specific average Saturn ECA Saturn wells outperform IRR by 7% and payout 2% faster Production Production & Economic Comparison 2, Encana Peer* 1,6 EUR/1 (BOE) ,2 ECA 8-2 Pad Type Curve IP18/1 (BOE/d) Btax IRR% Disc Payout (years) Saturn Peer Type Curve 2 Year Netback ($/BOE) Months All metrics based on $3./MMBtu NYMEX, $5/bbl WTI, and $.75 FX *Source : Industry Data, The Well Completions and Frac Database (Canadian Discovery), and Company Presentations 54

30 Gas (MMcf/d) Liquids (bbls/d) ENCANA MONTNEY 1 Year Growth Plan > 5, bbls/d & 1 Bcf/d by 218 Decades of inventory remaining Utilizes 3rd party capital to fund infrastructure growth Unique fee-for-service arrangement Capital focused on higher return D&C activities vs. facilities Enables double the production growth Generates superior financial returns Free cash flow positive 217+ $7 MM free cash flow per year within a decade Resilient to commodity prices 2, 1,8 1,6 1,4 1,2 1, Year Production Forecast Gas Rate Liquid Rate , 1, 75, 5, 25, 55 INFRASTRUCTURE PLAN Building Flexibility for Growth Encana utilizing ~1. Bcf/d of processing capacity Fort St. John 3 rd party midstream facilities ECA owned facilities Unique fee for service agreement with Veresen Midstream Limited Partnership (VMLP) Processing capacity expansions underway Bundled infrastructure model Spectra McMahon Spectra West Doe Tower 3-7 Spectra BC Station 2 Dawson Saturn Dawson Phase 2 Creek Sunrise 4-26 AltaGas Gordondale AECO ECA Sexsmith Inlet and field compression, liquids handling, and gas processing in one location ~8 MMcf/d of additional gas processing by 218 Veresen Steeprock Veresen Hythe COP Wembley New Processing Tower Sunrise Saturn Gas Capacity (MMcf/d) Condensate Production (bbls/d) 1, 1,6 4, NGL (C2-C4) Production (bbls/d) 8,3 4,2 13,2 To North American Market Existing Future To North American Market Grande Prairie On-stream Date Late 217 Late 217 Mid

31 INFRASTRUCTURE PLAN Bundled Infrastructure Growth Unbundled infrastructure model Model typically used by industry Field compression, liquids handling, and gathering away from main processing facility Benchmark processing facility cost ~$1MM per MMcf/d of capacity Encana bundled infrastructure model Larger and more efficient production growth Smaller environmental footprint with less risk of regulatory delays Lower construction cost Lower operating costs Bundled infrastructure cost: $1.6MM/MMcf/d Plant Cost: ~$1MM/MMcf/d Sunrise 4 MMcf/d Plant Example Gathering $1 MM/MMcf/d gas processing $4 Gathering, compression, and liquids handling + $24 Well Head Liquids Handling Compression Gas Processing Sales Meter Total Cost (MM$ USD) $64 57 LANDMARK AGREEMENT WITH VERESEN MIDSTREAM (VMLP) Innovative Fee-for-Service Structure Maximizing flexibility while managing execution In 215, Encana and CRP sold infrastructure to VMLP and entered into gathering and processing arrangement for Montney acreage Encana controls the pace and construction of facilities needed within ten years with VMLP funding Increased financial flexibility VMLP is guaranteed a simple payout of incurred cost eight years after facilities are on-stream Production in the current development plan exceeds production required for simple payout of facilities cost Production from all sources* contribute to the simple payout calculation Fee-for-service with a top-up Tolls are based upon a pre-agreed fee structure No exposure to unutilized demand charges beyond the simple payout of incurred cost No escalation in capital component of fees Encana manages the operating component of fees while operating facilities *Sources include any Encana or third party production routed through VMLP funded facilities 58

32 F&D ($/BOE) Income Margin ($/BOE) Cum. BT Operating Cash Flow ($MM) Liquids Production (Mbbls/d) Gas Production (MMcf/d) INFRASTRUCTURE STRATEGY Capital Efficiency Driving Higher Production Growth Midstream strategy allows Encana to focus capital on higher return D&C activities vs. facilities Delivers 2x growth Encana Liquids Production Outlook Encana Natural Gas Production Outlook 1 1-Year CAGR ECA Self Build 2, 1-Year CAGR ECA Self Build 8 Liquids 9% 5% 1,5 Gas 1% 6% 6 1, ECA Self Build ECA Self Build Self Build = Theoretical Encana self build scenario where Encana incurs all facility construction costs 59 INFRASTRUCTURE STRATEGY Growth Driving Incremental Value Material improvements to cash flow and returns ~3% higher operating cash flow over 1 years 5% higher IRR F&D improvement outweighs margin impact ~3% better F&D with third party infrastructure build Development Scenario $5 Oil & $3. Gas ECA Self Build Capital ($MM) ~$4,2 BTax IRR 125% 75% Positive Cash Flow 1 year 1.5 years ECA vs Self Build : Income Margin and Cum. Op. Cash Flow $2 $8, Notes I. Plot includes existing production II. Income Margin is Operating Margin less F&D 3% $15 $6, $1 $4, $5 $2, $ $ ECA Income Margin Self Build Income Margin ECA Cum BT Op. Cash Flow Self Build Cum BT Op. Cash Flow $4 $3 $2 $1 $ ECA F&D Self Build F&D Self Build = Theoretical Encana self build scenario where Encana incurs all facility construction costs 6

33 Gas Production (MMcf/d) Liquids Production (bbls/d) MONTNEY DEVELOPMENT PLAN Free Cash Flow Generator Capital vs. Cash Flow at $5 WTI and $3. NYMEX Self funding Montney generates free cash flow after development capital spending Sustainable value generation at lower commodity prices Free cash flow generation continues in a lower price environment Self Build scenario requires 4.5 years to achieve positive cash flow $MM $1,6 $1,2 $8 $4 $ Development Capital Operating Cash Flow Capital vs. Cash Flow at $4 WTI and $2.5 NYMEX $MM $1,6 $1,2 $8 $4 Self Build = Theoretical Encana self build scenario where Encana incurs all facility construction costs $ Development Capital Operating Cash Flow 61 ENCANA MONTNEY Positioned for Growth Development Plan & Upside* Growth Forecast Massive resource poised for significant growth Encana holds a commanding position in the core of the Montney 1, wells to drill Unique infrastructure model enables sustainable growth Capital focused on higher return D&C activities vs. facilities Exceptionally strong financial results Free cash flow generator Resilient to low prices 4, 3,5 3, 2,5 2, 1,5 1, , 125, 1, 75, 5, 25, Gas Gas (Upside) Liquids Liquids (Upside) Estimated inventory based on ft spacing *Upside scenario includes an incremental ~1,2 locations. 62

34 DELIVERING QUALITY RETURNS FROM A PREMIER ASSET Montney among the lowest supply cost basins Advantaged into Western and Dawn gas markets on a delivered cost basis Encana is positioned in the core of the play Massive inventory poised for significant gas and condensate growth Basin leading operator Innovative, flexible infrastructure plan to support future growth Self funding development generates significant free cash flow FUTURE ORIENTED INFORMATION This presentation contains certain forward-looking statements or information (collectively, FLS ) within the meaning of applicable securities legislation. FLS include: Encana s 216 capital program, including the amount allocated to its core four assets anticipated capital and cost efficiencies, including drilling and completion, operating and corporate costs, and future savings to be realized ability to scale or redirect capital program well performance, completions intensity, location of acreage and costs relative to peers and within plays competitiveness of Montney within North America and commodity composition anticipated natural gas demand growth and sources of growth anticipated production, growth profile completions intensity, free cash flow, capital coverage, payout, net present value, rates of return and operating margins, including expected timeframes expected net exports, available capacity, expansion in infrastructure and anticipated savings commodity price outlook number of wells and locations, decline rates, focus of drilling program and operating performance compared to type curves and drilling and completions costs anticipated reserves and resources, including product types and stacked resource potential expected rig count and rig release metrics increases to average IP3, EUR, proppant intensity and lateral length innovation and asset quality to drive capital productivity anticipated third-party incremental and joint venture carry capital anticipated hedging and outcomes of risk management program, including amount of hedged production anticipated proceeds from divestitures, use of proceeds therefrom, satisfaction of closing conditions and timing of closing 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 for results todiffer materially from those expressed or implied. These assumptions include: assumptions contained in Encana s 216 corporate guidance and in this presentation data contained in key modeling statistics availability of attractive hedges and enforceability of risk management program results from innovations expectation that counterparties will fulfill their obligations under gathering, midstream and marketing agreements access to transportation and processing facilities where Encana operates effectiveness of Encana s resource play hub model to drive productivity and efficiencies expectations and projections made in light of, and generally consistent with, Encana s historical experience and its perception of historical trends, including with respect to the pace of technological development, the benefits achieved and general industry expectations Risks and uncertainties that may affect these business outcomes include: risks inherent to closing announced divestitures on a timely basis or at all and adjustments that may reduce the expected proceeds and value to Encana; commodity price volatility; timing and costs of well, facilities and pipeline construction; ability to secure adequate product transportation and potential pipeline curtailments; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk; fluctuations in currency and interest rates; risk and effect of a downgrade in credit rating, including below an investment-grade credit rating, and its impact on access to capital markets and other sources of liquidity; variability and discretion of Encana s Board to declare and pay dividends, if any; the ability to generate sufficient cash flow to meet Encana s obligations; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; Encana s ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from resource plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; changes in or interpretation of royalty, tax, environmental, accounting and other laws; risks associated with past and future divestitures of certain assets or other transactions or receive amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer tofrom time totime as "partnerships" or "joint ventures" and the funds received in respect thereof which Encana may refer tofrom 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 MD&A, financial statements, Annual Information Form and Form 4-F, as filed on SEDAR and EDGAR. Although Encana believes the expectations represented by such FLS are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. FLS are made as of the date of this presentation and, except as required by law, Encana undertakes no obligation to update publicly or revise any FLS. The FLS contained in this presentation are expressly qualified by these cautionary statements. Certain future oriented financial information or financial outlook information is included in this presentation to communicate current expectations as to Encana s performance. Readers are cautioned that it may not be appropriate for other purposes. This presentation may contain references to non-gaap measures, which do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. These measures are presented to provide shareholders and potential investors with additional information regarding Encana s liquidity and its ability to generate funds to finance its operations. Rates of return for a particular play 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 play are a composite of the best drilling performance and best completions performance wells in the current quarter in such play and are presented for comparison purposes relative to other companies. 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. 64

35 ADVISORY REGARDING RESERVES DATA & OTHER OIL & GAS INFORMATION National Instrument ( NI ) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. Encana complies with NI disclosure requirements in its most recently filed annual information form ( AIF ). Detailed Canadian protocol disclosure is contained in Appendix A and under Narrative Description of the Business of the AIF. Certain disclosure is also prepared in accordance with U.S. disclosure requirements as set forth in Appendix D of the AIF. A description of the primary differences between the disclosure requirements under Canadian standards and under U.S. standards is set forth under the heading Reserves and Other Oil and Gas Information in the AIF. Additional detail regarding Encana s economic contingent resources disclosure is available in the Supplemental Disclosure Document filed concurrently with the AIF. All estimates are effective as of December 31, 215, are derived from reports prepared by independent qualified reserves evaluators engaged by Encana and are prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation Handbook ( COGEH ), NI and SEC regulations, as applicable. Information on the forecast prices and costs used in preparing the estimates are contained in the AIF. For additional information relating to risks associated with the estimates of reserves and resources, see Risk Factors in the AIF. 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. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible 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 1% chance of discovery, but have however been risked for the chance of development. The chance of development is defined as the likelihood of a project being commercially viable and development proceeding in a timely fashion. Determining the chance of development requires taking into consideration each contingency and quantifying the risks into an overall development risk factor at a project level. Contingent resources are categorized as economic if those contingent resources have a positive net present value under currently forecasted prices and costs. In examining economic viability, the same fiscal conditions have been applied as in the estimation of Encana s reserves. Contingencies include factors such as required corporate or third party (such as joint venture partners) approvals, legal, environmental, political and regulatory matters or a lack of infrastructure or markets. Encana uses the terms play, resource play, total petroleum initially-in-place ( PIIP ), natural gas-in-place ( NGIP ), and crude oil-in-place ( COIP ). Play encompasses resource plays, geological formations and conventional plays. Resource play describes an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which when compared to a conventional play, typically has a lower geological and/or commercial development risk and lower average decline rate. PIIP is defined by the Society of Petroleum Engineers - Petroleum Resources Management System ( SPE-PRMS ) as that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to total resources ). 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 ) has the meaning set out jointly by the Society of Petroleum Engineers and World Petroleum Congress in the year 2, 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. In this presentation, Encana has provided information with respect to certain of its plays and emerging opportunities which is analogous information as defined in NI This analogous information includes estimates of PIIP, NGIP, COIP or EUR, all as defined in the COGEH or by the SPE-PRMS, 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. Some of this data may not have been prepared by qualified reserves evaluators or auditors, may have been prepared based on internal estimates, and the preparation of any estimates may not be in strict accordance with COGEH. Estimates by engineering and geo-technical practitioners may vary and the differences may be significant. Encana believes that the provision of this analogous information is relevant to Encana's oil and gas activities, given its acreage position and operations (either ongoing or planned) in the areas in question, and such information has been updated as of the date hereof unless otherwise specified. Due to the early life nature of the various emerging plays discussed in this presentation, PIIP is the most relevant specific assignable category of estimated resources. There is no certainty that any portion of the resources will be discovered. There is no certainty that it will be commercially viable to produce any portion of the estimated PIIP, NGIP, COIP or EUR. Disclosure regarding drilling locations is based on internal estimates, may include proved, probable and unbooked locations, and assume a number of wells that can be drilled per section based on industry practice and/or internal review. The drilling locations which Encana will actually drill will ultimately depend upon the availability of capital, regulatory and partner approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. 3-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. 65

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