corporate presentation - encana · pdf file5 9 premier north american basin permian basin...

ENCANA

CORPORATION

CORPORATE PRESENTATION

April 2018

1

1

• 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 flowŦ (2018-2022)*

– Additional financial capacity at normalized leverage of 1.5x

– ~$500 million 2019 free cash flowŦ *

• $400 million share repurchase program to be

initiated in Q1 2018(a)

– Funded from cash on hand

ENCANAValue Proposition TOP TIER

RESOURCE

OPERATIONALEXCELLENCE

BALANCE SHEET STRENGTH

MARKETFUNDAMENTALS

CAPITALALLOCATION

* Assumes flat $55 WTI, $3 NYMEX Gas, $1.50 AECOŦ 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.

2

FOCUSED ON SHAREHOLDER RETURNS~$3 Billion of Free Cash FlowŦ Over Five Year Plan

*Assumes $55 WTI, $3 NYMEX, $1.50 AECO

$400 million share repurchase program to be initiated in Q1 2018(a)

~$3 billion of cumulative free cash flowŦ (2018-2022F)*

Balance sheet discipline

Creates Options:

SHAREHOLDER RETURNS

Returns to ShareholdersResiliency

Managing volatility

Portfolio Value Creation

Building on a quality portfolio

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

3

FOCUS ON QUALITY CORPORATE RETURNSOur Business Works Today

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.

• 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 EmployedŦ grows

over the 5 year plan~25% Cash FlowŦ CAGR

2018F – 2022F~$3.0 Billion Free Cash FlowŦ

2018F – 2022F

Strategy Execution

4

• 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 Q4 2017 ahead of

schedule & under budget

• Innovation & discipline delivering value

― Expanding margins

― Enhancing productivity & capital efficiency

― Balance sheet is very strong

• Well positioned for 2018 & beyond

― 2018 growth within cash flowŦ

― Generating strong free cash flowŦ from 2019 onward

― Leading corporate return generation

AN OPERATOR INVESTORS CAN COUNT ONIncreasing Value & Resiliency

2017-2022F Cash FlowŦ ~25% CAGR

-

1,000

2,000

3,000

2017 2018F 2019F 2020F 2021F 2022F

($M

M)

Capital Cumulative Free Cash Flow

~$3.0B of Cumulative Free Cash FlowŦ

Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

0

1,000

2,000

3,000

4,000

5,000

2017 2018F 2019F 2020F 2021F 2022F

Cash From Operating Activities NCWC & Other Cash Flow (Non-GAAP)

($M

M)

3

5

• 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

RESILIENT BUSINESS MODELCapital Discipline & Risk Management

Net Debt to Adjusted EBITDAŦ


3.2x

2.3x

2016 2017 2018F 2019F 2020F

Net Debt / Adjusted EBITDA - Actual

Net Debt / Adjusted EBITDA – Analyst Consensus

Net Debt / Adjusted EBITDA – Normalized Mid-Cycle

Target of ~1.5x

Target ~1.5x

Analyst consensus per Bloomberg, February 9, 2018

6

-1%

2%

5%

8%

2016A 2017F 2018F 2019F

ECA per External study US large Caps

US Small Caps Canadian Small Caps

Canadian Large Caps Excl. ECA

• Independent analysis of over 50 North

American E&P’s

― Encana “set to deliver above average ROCEŦ through

2019”*

― Assumptions / Methodology*

• Projected ROCEŦ 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

FOCUS ON CORPORATE RETURNSDifferentiated ROCE

Independent Analysis*

Return on Capital EmployedŦ

* Source: Macquarie Research: “Making Energy Great Again”, September 2017

.Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

4

7

• Cash flow marginŦ continues to grow

• 2017 cash flow marginŦ up 81% versus 2016

― Liquids mix

― Higher realized pricing

― Lower operating and corporate costs

• 2018 cash flow marginŦ expected to grow ~20% to

~$14/BOE

― Liquids mix

― Efficiency

― Access to markets

MARGIN EXPANSION CONTINUESProfitable Growth

6.49

11.75

~14.00

2016 2017 2018F

Cash Flow MarginŦ Expansion ($/BOE)


8

• 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

5 YEAR PLANProduction Growth Within Cash Flow

Pro

du

cti

on

(M

BO

E/d

)

* Assumes flat $50/bbl WTI and $3/MMBtu NYMEX..

Production Growth Within Cash FlowŦ


250

350

450

550

650

2017 2018F 2019F 2020F 2021F 2022F

2018F Guidance 360-380 MBOE/d

2017 Total Production = 313 MBOE/d, or 279 MBOE/d excluding A&D assets

5

9

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2016 2017 2018F 2019-2020F

% o

f U

pstr

eam

Reven

ue

Oil and Condy Other NGL All Other Gas AECO Gas

• >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

MARGIN GROWTH DRIVEN BY LIQUIDSPremium Liquids Markets and Diversified Gas Markets

> 70% Revenue from Liquids (2018F – 2020F)

~WTI

Non-

AECO

gas

10

• Capital balanced with expected cash flowŦ

• Total production is 95% from core assets

– Annual production growth of >30% excluding dispositions

• Q4 core asset production to average 400 – 425

MBOE/d (30-37% growth from Q4/17)

• Continued margin expansion driven by liquids

growth

– 55–65 Mbbls/d of liquids in the Montney expected in Q4

• Operating and G&A costs lower

– Benefit of focus on efficiency and scale

• Market diversification benefits

– Margin increase of ~$0.50-$0.75/BOE above additional T&P

cost to access premium markets

2018 GUIDANCECash FlowŦ and Production Growing >30%

2018F Guidance

Capital Investment ($ billion) 1.8 – 1.9

Total Liquids (Mbbls/d) 165 – 175

Natural Gas (MMcf/d) 1,150 – 1,250

Total Production (MBOE/d) 360 – 380

Upstream Operating Expense ($/BOE)* 3.00 – 3.30

Transportation & Processing ($/BOE) 7.40 – 7.75

Administrative Expense ($/BOE)* 1.25 – 1.50

Production, Mineral & Other Taxes

% of Revenue**3.25 – 3.75%

*Excludes long-term incentives;

** Upstream revenue excluding risk management activitiesŦ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures, including reconciliations, see the Company’s website.

6

11

2018 Full Year:

• Capital and cash flow balanced

• > 30% annual production growth on core assets

• Growth profile back half weighted

• Cash Flow margin up another 20% to ~$14/BOE

• Efficiency and innovation offsetting service cost inflation

– Equipment, services and market access secured

Q1/18:

• Overall core production flat from Q4/17

• Permian and Montney performing well

– Permian flat - offsetting strong Q4/17

– Montney – growth continues with new plant capacity from late 2017

• Modest declines in Duvernay and Eagle Ford

– 2017 capital program was weighted to first half (all of Duvernay and 70% of Eagle Ford wells)

GROWING MARGIN & CASH FLOW IN 2018Ahead of Plan on 5 Year Outlook

12

• Core positions in four of North America’s

premier basins

• >23,000 total inventory locations

• ~11,000 premium return locations

– >35% ATRORŦ returns

– Oil or condensate rich wells only

– Primary zones only*

– Industry typical well spacing**

Encana's Resource In Context

Eagle Ford

Permian

Montney

Duvernay

*Includes only Wolfcamp, Spraberry, Jo Mill, Lower Eagle Ford,Duvernay, Upper & Lower Montney; **450-660’ in Permian, 330’ in Eagle Ford, 1000’ in Duvernay, 440-880’

in Montney; Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures, including reconciliations, see the Company’s website.

WORLD CLASS PORTFOLIO

7

13

• 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

PERMIAN BASINHighly Efficient Development at Scale

14

• 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 Q4

2018

– Growing liquids to 55,000-65,000 bbls/d in Q4 2018

• Basin leading operator

– Top well performance

– Most efficient operator with track record of innovation

– Longest laterals with highest completion intensity

MONTNEYDriving Margin Expansion

8

15

• 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

EAGLE FORDTechnical Innovation Unlocking Value

16

• 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

DUVERNAYIndustry Leading Well Performance

9

17

TECHNOLOGY & INNOVATION LEADERSHIP AT ENCANAA Competitive Advantage

Drilling & Completions

• Proprietary in-house well

design

• Integrated team with

on-the-fly modeling

capabilities

• Advanced completions

• Fibre-optic real-time

pressure/completions

design analytics

Production Operations

• Real-time production data

capture & analysis

• Automation enables highly

efficient growth

• Remote surveillance and

control boosts well and

facility up-time

Commercial Arrangements

• 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

Subsurface

• Geo-cellular reservoir

modeling to identify the

best rocks

• Leveraging massive

proprietary analytics

dataset (core, logs,

seismic, micro-seismic,

fracture diagnostics,

production)

18

• 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

INNOVATION IN OPERATIONSDriven By Culture

Conceptual Advanced

Completions Design

Advanced

Completions

Tightening

clusters

maximizes

fracture

complexity

10

19

• 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

INNOVATION IN ACTIONEvolution in Completion Design Fueling Growth

Eagle Ford Innovations Doubling Productivity

Permian High Intensity Design Keeps Frac Energy Closer

High Intensity Design Base Design

0

50

100

150

200

250

0 30 60 90 120 150 180

Cu

mu

lati

ve P

rod

ucti

on

(M

BO

E)*

Days

2015

2016

2017

*Well results normalized to 5000’ lateral.

20

• Highly efficient, agile development

• Multi-well pads

– Higher utilization of services & infrastructure

• Multiple drilling rigs and frac spreads on a pad

– Rapid cycle times

– Accelerated learnings

• Integrated supply chain

– Leveraging economies of scale

– Centralized planning and logistics

CUBE DEVELOPMENT ABOVE-GROUND BENEFITSDevelopment at Industrial Scale

Cube Development

Above Ground Benefits

Multi-well Pads

Multi-rig, Multi-

spread

Integrated Supply Chain

Re-occupied facilities

Reliable market access

Water Manage-

ment

11

21

• 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

CUBE DEVELOPMENTDifferentiated Execution

Maximizing value from multi-zone

stacked development

22

• 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 DEVELOPMENTImproved Resource Recovery & Efficiency

Cube Development Maximizing Recovery from the Stack

12

23

• 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

COMMERCIAL INNOVATIONDelivering Value in any Environment

ECA 2018 D&C Cost Breakdown

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

~35% of well cost is drilling

~65% of well cost is completions

24

• 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:

– $650 million notional U.S. dollar denominated

currency swaps at an average exchange rate of

US$0.7597 to C$1, which mature monthly

throughout 2018.

– $0.01 Change to F/X (eg. 0.80 to 0.79) has annual

impact of less than $10 million to cash flow

RISK MANAGEMENT

Adds Greater Certainty to Cash Flow and De-Risks Capital Program

$(0.88)/Mcf±

BENCHMARK HEDGES 2018* 2019

Oil and Condensate

WTI Fixed Price Swap

Swap Price (US$/bbl)

78 Mbbls/d

$54.21/bbl

15 Mbbls/d

$58.30/bbl

WTI 3-Way Option

Short Put (US$/bbl)

Long Put (US$/bbl)

Short Call (US$/bbl)

16 Mbbls/d

$36.88/bbl

$47.17/bbl

$54.49/bbl

WTI Costless Collar

Long Put (US$/bbl)

Short Call (US$/bbl)

10 Mbbls/d

$45.00/bbl

$57.08/bbl

Natural Gas

NYMEX Fixed Price Swap

Swap Price US$/Mcf**

767 MMcf/d

$3.04/Mcf

Risk management positions as at January 31, 2018. * January to December 2018 positions.** Hedged volumes are

converted to Mcf at a 1:1 ratio from MMBtu.

13

25

• 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

• Permian

– Permian volumes priced at Midland,

Houston and points beyond via

international shipments

BASIS RISK MANAGEMENT PROGRAMMarket Access & Price Risk Management

Western Canada 2018 2019 - 2020

AECO Basis Hedges

Swap Price US$/Mcf**475 MMcf/d

$(0.87)/Mcf

500 MMcf/d

$(0.88)/Mcf

Transport to Dawn 316 MMcf/d 316 MMcf/d

Transport to Sumas/Malin 124 MMcf/d 134 MMcf/d

Transport to Chicago 52 MMcf/d 100 MMcf/d

Permian 2018 2019 - 2020

WTI/Midland Differential Hedges

Swap Price (US$/bbl)

34 Mbbls/d

$(0.78)/bbl

10 Mbbls/d

$(1.09)/bbl

Transport to Houston

(EPD Midland to Houston*)19 Mbbls/d 39 Mbbls/d

Positions as at January 31, 2018. Hedged and transport volumes are converted to Mcf at a 1:1 ratio from MMBtu. **Price stated is the

differential versus NYMEX pricing.

Positions as at January 31, 2018. *Enterprise Products Partners L.P

ASSET OVERVIEW

Permian drilling in Midland County

14

27

ENCANA’S POTENTIAL PREMIUM RETURN INVENTORYOnly Premium Inventory Consumed in Growth Plan

Permian Basin Montney

DuvernayEagle Ford

12,000 well inventory

3,450 premium locations

<1,000 wells drilled in 5 year plan

Premium assumption

450-660’ spacing on average of 2.5 zones

across basin

*Premium locations are >35% ATRORŦ 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.


6,900 premium locations

<800 wells drilled in 5 year plan

Premium assumption

440’ spacing in very rich gas condensate & volatile oil

660’ spacing in rich gas condensate

990’ spacing in wet gas


500 premium locations

<200 wells drilled in 5 year plan

Premium assumption

1,000’ spacing

800 well inventory

220 premium locations

~200 wells drilled in 5 year plan

Premium assumption

330’ spacing

Remaining Inventory

Premium Inventory

Premium

Inventory

28

PERMIAN2018 Program

FY 2018 PlanAcreage (net acres) 118,000

Average Working Interest (%) 94%

Average Royalty Rate (%) 25%

Development Capital (net) ($MM) $750-800

Gross Rig Count 4 - 5

HZ Wells Drilled (net) 100 – 115

HZ Wells On-stream (net) 100 – 115

D&C Cost* ($MM/well) ~$5.6

Average Lateral Length (ft) 7,500 – 10,000

Production Split

Oil/condensate** % 66%

NGLs % 17%

Natural gas %*** 17%

*Normalized to 7,500' lateral length **Includes plant and field condensate *** Natural gas % varies based on mix of wells dri lled and has ranged between 16-19%

2018 Program

• 30% growth from FY2017 to FY2018

• 70% program focused in Midland/Martin

• Cube development continues to add significant

value through operational efficiencies, shared

infrastructure and services and improved resource

recovery

15

29

• 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 CONTINUES STRONG EXECUTIONTargeting 30% Annual Growth

0

25

50

75

100

125

150

175

0 30 60 90 120 150 180

Cu

mu

lati

ve P

rod

ucti

on

(M

BO

E)*

Days

Abbie Laine Q1 2017

RAB 2 Q2 2017

Davidson 02 E Q2 2017

Davidson 02 W Q2 2017

Cowden 30 Q3 2017

Davidson 38 Q4 2017

Permian Cube Performance

Midland

Type

Curve

IP180

*3-stream production, normalized to 7500’ lateral. 0

20

40

60

80

100

2016 2017 2018F

(MB

OE

/d)

Targeting 30% Annual Growth

30

• 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

CUBE DEVELOPMENT ABOVE-GROUND BENEFITSEffective Water Management

Martin County – Central Water Resource Hub

16

31

-

40

80

120

160

200

240

2017 2018F 2019F 2020F 2021F 2022FM

BO

E/d

PERMIAN5 Year Growth Profile

• ~50% of Encana’s capital directed to the

Permian in 2018

• Permian production expected to grow 3x

– 5 year CAGR 25%

• Quality inventory with scale

• No infrastructure or midstream limitations

• Minimal vertical program

Five Year Production Profile

32

MIDSTREAM AND MARKETING OVERVIEWPermian

Gathering system links production to

pipeline hubs

Permian

• 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

• Secured firm, low-cost pipeline capacity

to Gulf Coast refining/export markets

(Enterprise Midland-Sealy Pipeline 2018)

• No take or pay commitments

Colorado

City

Midland

Crane

Pipelines connect to

Cushing and Gulf Coast

Permian: Proximity to market and environment

of responsive infrastructure development

Secured capacity on Enterprise (Echo

Pipeline) adds market diversity and reduces physical risk

(2018)

17

33

Past & Future Pipeline Capacity Expansions Align with Growth

Source: Wells Fargo Securities, Encana

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Q1

'12A

Q3

'12A

Q1

'13A

Q3

'13A

Q1

'14A

Q3

'14A

Q1

'15A

Q3

'15A

Q1

'16A

Q3

'16A

Q1

'17

E

Q3

'17

E

Q1

'18

E

Q3

'18

E

Q1

'19

E

Q3

'19

E

Q1

'20

E

Q3

'20

E

Q1

'21E

Q3

'21

E

Q1

'22

E

Q3

'22

E

Cru

de

Oil

Pro

du

ctio

n /

Tak

eaw

ay C

apac

ity

(Mb

bls

/d)

Local Refineries Existing Pipelines

Pipelines Under Construction Identified Pipeline Projects

Permian Supply

• 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

Periods of temporary dramatic

weakness in local price

Potential price risk (timing of

future projects)

PERMIAN BASIN FUNDAMENTALS

34

PERMIAN RESERVOIRMassive Potential with Stacked Benches

Zone MartinMidland/

UptonGlasscock Howard

Clear Fork ✓ ✓

M. SPBY ✓ ✓

Jo Mill ✓ ✓

L. SPBY ✓ ✓ ✓ ✓

L. SPBY- 2nd✓ ✓ ✓ ✓

WCMP A ✓ ✓ ✓ ✓

WCMP A- 2nd✓ ✓

WCMP B ✓ ✓ ✓

WCMP C ✓ ✓

WCMP D / Cline ✓ ✓ ✓ ✓

Deep Targets ✓ ✓ Total

Total Inventory 2,200 5,200 1,300 3,600 ~12,000

Premium 750 1,450 350 900 3,450

18

35

PREMIUM INCREASE OUTPACING DRILLINGGross Premium Return Inventory

CountyMidland/

UptonMartin Howard Glasscock

IP30 (BOE/d) 985 950 825 800

IP180 (BOE/d) 700 650 600 550

EUR/Well (Mbbls) 610 675 550 530

EUR/Well (MBOE) 1,020 1,000 875 765

GOR (scf/bbl) 2,800 2,000 2,450 1,960

Gross Premium Return Inventory

1,450 750 900 350

Estimated inventory based on 450-660 ft spacing, 7,500’ lateral length, Permian type curves are stated on a three stream basis.

36

MONTNEY2018 Program


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) 85 – 95

Net Wells Drilled (Pipestone) 25 – 30

Net Wells On-stream (CRP) 110 – 120

Net Wells On-stream (Pipestone) 22 – 25

D&C Cost* ($MM/well) $3.1 - $5.1

Average Lateral Length (ft) 7,200 - 9,000

Production Split


NGLs (C2 – C4) % 6%

Natural gas % 78%

*Normalized to 7,200’ lateral length for CRP and 9,000' lateral length for Pipestone **Includes plant and field condensate

2018 Program

• 2018 significant production growth while generating

free cash flow

• Targeting Q4 2018 liquids production of 55-65Mbbls/d

– double Q4 2017 rates

• Tower and Pipestone Liquids hubs on track for Q4

2018 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

19

37

DIVERSIFIED MARKET EXPOSURE IN WESTERN CANADAPortfolio Approach to Price Risk Management

To US Northwest

~115 MMcf/d

To Dawn

316 MMcf/d

To Chicago

~88 MMcf/d

Condensate

Imports

• ~500MMcf/d AECO basis hedged at

($0.88/Mcf) to Henry Hub

• ~500 MMcf/d firm transportation out of

the basin

• 100% firm capacity secured on NGTL for

expected production growth – limited

curtailment risk

• Condensate sold into local market at

~WTI prices

Natural Gas Export Pipeline

Condensate Import Pipeline

100% firm

capacity on

Nova Gas

Transmission

System

(NGTL)

Condensate

sold into

premium

local

market

38

0

10

20

30

40

50

60

70

Q4 16 Q4 17 Q4 18F

(Mb

bls

/d)

Condensate Other NGLs

MONTNEY DELIVERING CONDENSATE GROWTHSignificant Margin Expansion

Margin Expansion Driving Cash FlowŦ Growth

Montney Liquids Production Set to Double Again in Q4 2018

• 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 100-300 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 Q4 2017

• Currently operating at peak 2018 rig count

• Tower and Pipestone liquids hubs on track for Q4

2018 start-up

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

Q4 16 Q4 17 Q4 18F

Op

era

tin

g M

arg

in (

$/B

OE

)

14

29

55-65


20

39

• Montney growth has been self-funded

• Transition to liquids and increase in scale driving

margin expansion

• 2018 significant production growth while generating

free cash flowŦ

• Additional growth in free cashŦ expected in 2019

• Competes with the best plays in North America

MONTNEY CASH FLOW GROWTH High Quality Condensate Play

-

200

400

600

800

1,000

1,200

1,400

2017 2018F 2019F

($M

M)

Capital Upstream Operating CF

Montney Free Operating Cash FlowŦ in 2018 & 2019

Liquids-Rich

MontneyPermian

D&C Cost ($MM) 4.0–5.5 5.6

Oil/C5 IP180 (bbls/d) 250-800 500

Royalty Rate 5-10% 25%


40

• Tower, Sunrise and Saturn plants on-stream Q4 2017

– 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

AGREEMENT WITH VERESEN MIDSTREAM Fee-for-Service Structure

All 3 Montney Plants On-Stream

21

41

Commissioning of Tower, Sunrise and Saturn in 2017 added approximately 450

MMcf/d of gas, 19 Mbbls/d of condensate, and 10 Mbbls/d of NGL to existing

capacity

MONTNEY INFRASTRUCTURE PLANLiquids Handling Capacity Supports Growth & Flexibility

*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 part of the recently announced Keyera Partnership agreement.

***In the process of finalizing the liquids recovery design.

Net Encana Capacity

Icon NameAnticipated

TimingGas*

(MMcf/d)Condensate*

(bbls/d)NGLs*

(bbls/d)

Existing Facilities 1,150 42,000 15,500

Tower NCLH Q4 2018 0 9,000 0

Pipestone CLH** Q4 2018 0 10,500 0

Total Net Capacity Year End 2018 1,150 61,500 15,500

Pipestone Expansion**

2021 150 17,000 TBD***

40mi / 65km

Dawson South

Pipestone

Tower

BC

Alb

erta

1

Key Montney Infrastructure Additions

2

1

2

3 3

42

-

500

1,000

1,500

2017 2018F 2019F 2020F 2021F 2022F

MM

cf/

d

ENCANA MONTNEY5 Year Growth Profile

• Development focused in condensate rich areas

• 2018 program to fill new liquids capacity

‒ Additional capacity comes online late 2018

• Operating margin expected to increase >40% by

2022

• Liquids production of 55-65 Mbbls/d Q4 2018

• Expect liquids production of >70 Mbbls/d by 2019

‒ Liquid weighting grows to >25% of total by 2019

• Liquids handling expansions support growth

plans

-

30

60

90

2017 2018F 2019F 2020F 2021F 2022F

Mb

bls

/d

Gas Growth Profile

Liquids Growth Profile

Volumes quoted are net to Encana.

22

43

• Partnership with a subsidiary of Mitsubishi

– Encana: 60% interest

– Mitsubishi: 40% interest

• Investment structure (C$2.9B)

– C$1.45 billion upfront in 2012

– Further investment of C$1.45 billion during the

commitment period

• Third party capital expected to extend into 2019

– 2018 third party capital ~C$300 million

– 2019 third party capital ~C$135 million

• Post commitment period, Mitsubishi funds its

40% of the Partnership's future capital

investment

MONTNEYCutbank Ridge Partnership (CRP)

44

Region Tower Dawson South Pipestone

Type Wet GasGas

Condensate

Rich Gas

CondensateWet Gas

Gas

Condensate

Gas

Condensate

Rich Gas

Condensate

Very Rich Gas

CondensateVolatile Oil

IP30 (BOE/d) 1,800 – 1,900 1,200 – 1,400 1,450 – 1,550 2,000 – 2,200 2,400 – 2,600 1,500 – 1,600 1,850 – 1,900 1,750 – 1,800 800 – 1,200

IP180 (BOE/d) 1,700 – 1,800 1,150 – 1,350 1,250 – 1,350 1,600 – 2,000 1,900 – 2,100 1,250 – 1,350 1,600 – 1,700 1,750 – 1,800 1,000 – 1,300

EUR/Well (MBOE) 1,850 – 1,950 1,350 – 1,450 1,300 – 1,400 1,750 – 1,850 1,500 – 1,650 950 – 1,000 1,100 – 1,200 1,300 – 1,350 900 – 1,200

Condensate Yield (bbls/MMcf)

<20 20 - 50 50 - 150 <20 20 - 50 20 - 50 50 – 150 150 – 250 >250


1,230 950 860 690 460 740 840 150 980

MONTNEYGross Premium Return Inventory

Estimated inventory based on 440 - 990 ft. spacing, 8,200 - 9,800’ lateral length. Volumes are stated on a shrunk condensate and a raw gas basis.

23

45

• 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 flowŦ

EAGLE FORD & DUVERNAY Quality Assets Generating Free Operating Cash Flow

Eagle Ford & Duvernay Maintaining ~65 MBOE/d Combined

0

50

100

150

200

250

300

0 30 60 90 120 150 180

Cu

mu

lati

ve P

rod

ucti

on

(M

BO

E)*

Days

Simonette South Base Design Simonette South High Intensity Design

Duvernay Completions Innovation Leads to 25% Uplift in IP90

Simonette South VRGC

Type Curve IP180

0

20

40

60

80

2016 2017 2018F

An

nu

al

Pro

du

cti

on

(M

BO

E/d

)


*Normalized to 8,900’ lateral.

46

EAGLE FORD 2018 Program




Development Capital (net) $MM $270 - 310


Wells Drilled (net) 45 – 50

Wells on Stream (net) 45 – 50


Average Lateral Length (ft) 5,000

Production Split


NGLs % 13%

Natural gas % 17%

*Normalized to 5,000' lateral length **Includes plant and field condensate

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

24

47

MIDSTREAM AND MARKETING OVERVIEWEagle Ford

• 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

Houston

Corpus Christi

Three Rivers

Close proximity to market and

well-developed infrastructure

Eagle Ford

48

Type Curve Eagle Ford Austin Chalk

IP30 (BOE/d) 1200 1400

IP180 (BOE/d) 950 1040

EUR/Well (Mbbls) 490 590

EUR/Well (MBOE) 650 770

GOR (scf/bbl) 2,000 1,500

Gross Premium Return Inventory 155 65

EAGLE FORDGross Premium Return Inventory

• 220 premium return

inventory locations

• Testing additional

opportunity in both the

Graben area of the Eagle

Ford and in the Austin Chalk

Estimated Eagle Ford inventory based on 330 ft spacing, 5,000’ lateral length. Type curves are stated on a three stream basis.

25

49

DUVERNAY2018 Program

FY 2018 PlanSimonette Acreage (net acres) 91,000



Development Capital (net) $MM $100 – 130


Wells Drilled (net) 7 – 9

Wells on Stream (net) 7 – 9


Average Lateral Length (ft) 9,000

Production Split


NGLs (C2 – C4) % 8%

Natural gas % 52%

*Normalized to 9,000' lateral length **Includes plant and field condensate.

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

50

MIDSTREAM AND MARKETING OVERVIEWDuvernay

• Condensate sales via pipeline to premium

Edmonton market center

• 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

Duvernay

Alliance Pipeline to U.S. Midwest

(Chicago)

Condensate to Edmonton market

center

26

51

DUVERNAYGross Premium Return Inventory

Region Simonette South Simonette North

Type Rich Gas CondensateVery Rich Gas Condensate

Rich Gas CondensateVery Rich Gas Condensate

IP30 (BOE/d) 1,550 – 1,650 1,600 - 1,700 1,200 – 1,300 1,200 – 1,300

IP180 (BOE/d) 1,100 – 1,200 1,150 – 1,250 850 - 950 850 - 950

EUR/Well (MBOE) 1,350 - 1450 1,300 – 1,400 1,000 – 1,100 950 – 1,050

Condensate Yield (bbls/MMcf) 50 - 150 150 - 250 50 – 150 150 – 250


150 120 60 170

Gas heat content of 1,200 Btu/scf.

Estimated inventory based on 1,000 ft. spacing, Simonette North at 8,200’ lateral length, Simonette South at 8,900' lateral length . Volumes are stated on a shrunk condensate and a raw gas basis

52

SAN JUAN BASINEvaluating Liquids Growth Potential

• Strong 2017 well results

– 5 Tocito wells exceeding type curve

expectations

– Targeted best rock with transverse orientation

and advanced completion design to generate

more frac complexity

– Evaluated secondary El Vado zone

• 2018 objectives

– 6 well program in H2 2018

– Evaluating commerciality (access to services,

commodities, mid-stream, etc.)

27

SUPPLEMENTAL

54

• Benefit of scale driving lower per unit BOE costs

– Reducing costs & growing production volumes

• Interest on debt expected to be ~$70MM/quarter

– Consolidated interest expense $90-$95MM/quarter

• Administrative expense, ex. LTI’s, expected to be

~$45MM/quarter for 2018

• Market optimization segment includes T&P costs of

$30-$35MM/quarter for 2018

– Segment operating loss expected to be $16-$20MM/quarter

MAXIMIZING MARGINCost Control of Corporate Items Enhances Per Unit Margin

-

1.00

2.00

3.00

4.00

5.00

6.00

-

100

200

300

400

500

600

700

2017 2018F

$/B

OE

$M

M

Interest Expense G&A Excluding LTI

Market Optimization Combined Cost $/BOE

Corporate Items Cost Control

28

55

PRODUCT VALUE CHAINProjected Composition of Total Production

*2018F based on company guidance as at February 15, 2018, excluding impact of hedges; production ranges are not additive; **I ncludes plant condensate

Canada US

2018F*

(Mbbls/d)

2018F Pricing

(%WTI)

2018F*

(Mbbls/d)

2018F Pricing

(%WTI)

Oil 0 – 1 98% 87 – 90 100%

Condensate** 38 – 40 98% 3 – 4 88%

Butane 6 – 8 63% 4 – 5 61%

Propane 7 – 9 45% 8 – 9 54%

Ethane 0 – 1 20% 9 – 10 13%

Canada US

2018F*

(MMcf/d)

2018F Pricing

(%NYMEX)

2018F*

(MMcf/d)

2018F Pricing

(%NYMEX)

Natural Gas 1,000 – 1,100 73% 140 – 160 85%

56

WESTERN CANADIAN CONDENSATE FUNDAMENTALSPremium Condensate Market

Source: RBC Capital Markets and Government Data

Condensate demand in

western Canada is

expected to outstrip

domestic supply –

with imports bridging

the gap

29

57

36%

30%28%

23% 22%

0%

10%

20%

30%

40%

50%

60%

70%

80%

YE 2013 YE 2014 YE 2015 YE 2016 YE 2017

• $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 capitalizationŦ = debt + equity + $7.7B equity adjustment

• 22% as at December 31, 2017

• Debt to adjusted capitalization ratio has improved since 2013

DISCIPLINED FINANCIAL MANAGEMENTAccess to Ample Liquidity Through 2020

ECA Ratio Well Within Covenant ThresholdDebt to Adjusted CapitalizationŦ Ratio

60% Threshold


58

• 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

DISCIPLINED FINANCIAL MANAGEMENTDebt Portfolio as at December 31, 2017

0

250

500

750

1,000

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

20

31

20

32

20

33

20

34

20

35

20

36

20

37

20

38

20

39

20

40

20

41

(US$

MM

)

Fixed Debt Maturity Schedule

30

59

• 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

This presentation contains certain forward-looking statements or information (collectively, “FLS”) within the meaning of applicable securities legislation, including the U.S. Private Securities Litigation Reform Act of 1995. FLS include:

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 from time to time in Encana’s other periodic filings as filed on SEDAR and EDGAR.

Although Encana believes the expectations represented by FLS are reasonable, there can be no assurance FLS will prove to be correct. Readers are cautioned that the above assumptions, risks and uncertainties are not exhaustive.

FLS are made as 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-tax basis and are based on specified commodity prices with local pricing offsets, capital costs associated with drilling, completing and equipping a well, field

operating expenses and certain type curve assumptions. Pacesetter well costs for a particular asset are a composite of the best drilling performance and best completions performance wells in the current quarter in such asset and

are presented for comparison purposes. Drilling and completions costs have been normalized as specified in this presentation based on certain lateral lengths for a particular asset. Premium well locations are locations with expected

after tax returns greater than 35% at $50/bbl WTI and $3/MMBtu NYMEX. For convenience, references in this presentation to “Encana”, the “Company”, “we”, “us” and “our” may, where applicable, refer only to or include any relevant

direct and indirect subsidiary corporations and partnerships (“Subsidiaries”) of Encana Corporation, and the assets, activities and initiatives of such Subsidiaries.

FUTURE ORIENTES INFORMATION

60

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 51-101 (NI 51-101) and SEC regulations, as applicable. On August 14, 2017, Encana was granted an exemption by the Canadian Securities Administrators from the requirements under NI 51-101 that each qualified

reserves evaluator or qualified reserves auditor appointed under section 3.2 of NI 51-101 and who execute the report under Item 2 of Section 2 of NI 51-101 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 51-101F1 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 51-101F1. Information on the forecast prices and costs used in preparing the Canadian protocol estimates will be contained in the Form 51-101F1. 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 51-101, including estimates of PIIP, NGIP, COIP, EUR and production type curves. This analogous information is presented on

a basin, sub-basin or area basis utilizing data derived from Encana's internal sources, as well as from a variety of publicly available information sources which are predominantly independent in nature. Production type curves are based on a

methodology of analog, empirical and theoretical assessments and workflow with consideration of the specific asset, and as depicted in this presentation, is representative of Encana’s current program, including relative to current

performance, but are not necessarily indicative of ultimate recovery. Some of this data may not have been prepared by qualified reserves evaluators, may have been prepared based on internal estimates, and the preparation of any

estimates may not be in strict accordance with COGEH. Estimates by engineering and geo-technical practitioners may vary and the differences may be significant. Encana believes that the provision of this analogous information is relevant

to Encana's oil and gas activities, given its acreage position and operations (either ongoing or planned) in the areas in question, and such information has been updated as of the date hereof unless otherwise specified. Due to the early life

nature of the various emerging plays discussed in this presentation, PIIP is the most relevant specific assignable category of estimated resources. There is no certainty that any portion of the resources will be discovered. There is no

certainty that it will be commercially viable to produce any portion of the estimated PIIP, NGIP, COIP or EUR. Estimates of drilling locations and premium return well inventory include proved, probable, contingent and unbooked locations.

These estimates are prepared internally based on Encana's prospective acreage and are based on an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Approximately 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, 2017. Unbooked locations do not

have attributed reserves or resources and have been identified by management as an estimation of Encana's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves

information. There is no certainty that Encana will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The locations on which Encana will

actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of capital, regulatory and partner approvals, seasonal restrictions, equipment and personnel, oil and natural gas prices, costs, actual

drilling results, additional reservoir information that is obtained, production rate recovery, transportation constraints and other factors. While certain of the unbooked locations have been de-risked by drilling existing wells in relative close

proximity to such locations, many of other unbooked locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will

be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional proved or probable reserves, resources or production.

30-day IP and other short-term rates are not necessarily indicative of long-term performance or of ultimate recovery. The conversion of natural gas volumes to barrels of oil equivalent (“BOE”) is on the basis of six thousand cubic feet to one

barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be misleading,

particularly if used in isolation.

ADVISORY REGARDING OIL & GAS INFORMATION

31

61

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 MEASURES

• 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 (2018 – 2022)

• 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 2022.

Net change in other assets and liabilities is assumed to be about $100M per year for

2018 through 2022.

~$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.

62

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:

NON-GAAP MEASURES

• 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.

2018F ENCANA CORPORATE GUIDANCE

US$, U.S. GAAP

February 15, 20182018F

Capital Investment ($ billions)

Total Capital Investment 1.8 – 1.9

Production (after royalties)

Liquids (Mbbls/d) 165 – 175

Natural Gas (MMcf/d) 1,150 – 1,250

Total Production (MBOE/d) 360 – 380

Operating Costs ($/BOE at 6:1 ratio)

Upstream Operating Expense (1) 3.00 – 3.30

Transportation and Processing 7.40 – 7.75

Administrative Expense (1) 1.25 – 1.50

Production, Mineral & Other Taxes (% of Revenue (2)) 3.25 – 3.75%

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 1995. 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 in Encana’s other periodic filings as filed on SEDAR and EDGAR.

Although Encana believes the expectations represented by such FLS are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the

assumptions, risks and uncertainties referenced above are not exhaustive. FLS are made as of the date of this document and, except as required by law, Encana undertakes no obligation to update

publicly or revise any FLS. FLS contained in this document are expressly qualified by these cautionary statements. FLS included in the 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 2018. 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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