Appendix€¦ · & restructuring costs • Run-rate annualized leverage of 1.8x . Ŧ,(1) o Represents normalized leverage post acquisition • 605 MBOE/d of production (54% liquids)

Appendix

2

3Q19 Consolidated Results3Q19

$ Millions $ Per Share

NET EARNINGS 149 0.11

NON-GAAP OPERATING EARNINGSŦ 195 0.15

CASH FROM OPERATING ACTIVITIES 756

NON-GAAP CASH FLOWŦ 817 0.62

CASH FLOW MARGINŦ $/BOE 14.67

CAPITAL INVESTMENT 566

FREE CASH FLOWŦ 251

BUYBACK ($ MILLIONS / MILLIONS OF SHARES) $213 / 47

WEIGHTED AVERAGE SHARES – DILUTED (MILLIONS) 1,322.8

SHARES O/S AT SEPTEMBER 30, 2019 (MILLIONS) 1,299.2

YTD19 Upstream Operating FCF Ŧ By Asset

>$600 MM (2)

• $251 MM of Free Cash Flow Ŧo Outperforming original synergy targets & proving operational

performanceo YTD Free cash flowŦ of $64 million, ~$230 million excluding acquisition

& restructuring costs

• Run-rate annualized leverage of 1.8x Ŧ,(1)

o Represents normalized leverage post acquisition

• 605 MBOE/d of production (54% liquids)o 237 Mbbls/d of oil and condensate production

(1) Net debt to adjusted EBITDA based on Adjusted EBITDA generated in 2Q19 and 3Q19 on an annualized basis.(2) Upstream operating free cash flow excluding hedge.Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.* Base includes Eagle Ford, Williston, Uinta and Duvernay.

20%

23%

23%

34%Permian

Anadarko

Montney

Base*Total 2019 Buyback program

$1.25B / 197 MM shs (~13% o/s shs)

3

Increased 2019 Production Guidance

* A reconciliation of pro-forma to reportable guidance is on the following slide(1) Original guidance assumed full year Arkoma & China production. Encana increased full year production guidance despite the loss of volumes in 4Q and a portion of 3Q(2) Excludes the impact of long-term incentive costs and restructuring costs. BOW office lease costs are included in administrative(3) Year to date proforma capital investment of $2,225 MM is upstream proforma capital.Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website

Guidance*

3Q YTD Reportable

3Q YTD Proforma

FY19 Proforma(New)

FY19 Midpoint

(Previous)

CAPITAL INVESTMENT($ MILLION) 2,052 2,225(3) 2,800 2,800

TOTAL LIQUIDS(MBBLS/D) 295 315 312 – 316 310

NATURAL GAS(MMCF/D) 1,562 1,635 1,615 – 1,630 1,600

TOTAL PRODUCTION(MBOE/D) 556 588 580 – 590 580

TOTAL COSTS PER BOE 2,Ŧ

UPSTREAM OPERATING AND T&P, PRODUCTION AND MINERAL TAXES PLUS ADMINISTRATIVE

12.66 n/a 12.60 – 12.90 13.00

• Raised FY19 production guidance

• Strong Anadarko Basin volumes driving outperformanceo Combined full year impact of ~25 MMcf/d of gas and

~1 Mbbls/d of liquids for Arkoma & China (~5 Mboe/d) 1

• Reiterated FY19 capex midpoint

• Guided Total Costs / BOE lower

• Increased G&A synergieso Annualized savings now $200 MM (original: $125 MM)

New FY19 Guidance

Production Outperformance (Mboe/d)+5 Raised FY19 guidance midpoint (585 vs 580)+5 Outperformance offsetting YTD dispositions 1

+10 Effective Outperformance

4

Reconciliation of Full Year Guidance to Reportable2 0 1 9 G U I D A N C E

Reportable: ECA plus Newfield post close February 13, 2019Impact of Newfield Jan 1 – Feb 13, 2019: Newfield activity January 1, 2019 – February 13, 2019Full year proforma: Results of ECA + Newfield combined for all of 2019

2019 Guidance: Reportable Versus Full Year Proforma

2019 Reportable Guidance

Impact of Newfield Jan 1 - Feb 13, 2019

FY19 Proforma

CAPITAL INVESTMENT ($ BILLION) 2.55 – 2.65 0.2 2.8

TOTAL LIQUIDS (MBBLS/d) 297 – 301 15 312 – 316

NATURAL GAS (MMCF/d) 1,560 – 1,575 55 1,615 – 1,630

TOTAL PRODUCTION (MBOE/d) 556 – 566 24 580 – 590

TOTAL COSTS PER BOE*Ŧ

UPSTREAM OPERATING AND T&P, PRODUCTION AND MINERAL TAXES PLUS ADMINISTRATIVE

12.60 – 12.90 - 12.60 – 12.90

Excludes the impact of long-term incentive costs and restructuring costs. Bow office building lease costs are included in these combined costsŦ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website

• Per unit costs expected to fall through the year

• Excludes acquisition and restructuring costs

incurred in 2019 at $167 million

-

2.00

4.00

6.00

8.00

10.00

12.00

14.00

2018PF 2019F

$/BO

E

G&A Excl. LTIand Restr. Costs

PMOT

Upstream T&P

Upstream OpexExcl. LTI

5

2016 2018

Industry Leading ESG Performance

Note: All data represents FY 2018 unless otherwise noted. Sustainalytics peer group consists of APA, CHK, CLR, COG, CXO, DVN, EOG, HES, MRO, NBL, PXD. Report dated as of April 2019

Third Party ESG Assessment

5th Consecutive Safest Year Ever Proven Safety Results

#1 #2vs. 22 AXPC

peers in the USvs. 16 CAPP

peers in Canada

Environmental Performance

AJuly 2019 score

Top 1/3rd

of all MSCI reviewed O&G companies

Top quartile vs peer companies

>25%Score >25% above peer

average

Methane Intensity 2018 Water Use

% of Total WaterTons CH4 / MBOENumber of Recordable Injuries x 200,000 divided by exposure hours

~45%

Fresh Alternative

TRIF0.44

0.340.30 0.30 0.28

2014 2015 2016 2017 2018

0.43

0.22

6

Proactive ESG ApproachESG Impact Matrix

Safety•Process Safety •Climate change

•Water

Social•Community concerns

Governance•Stakeholder activism

Environmental

• Task Force on Climate-related Financial Disclosureso Climate-related risks have the potential to impact our business

o Governance framework allows us to effectively manage these risks

o Applicable concerns are integrated into planning and risk management

o Established history of measuring, managing and reporting ESG performance

• Sustainability Reporting and Programso An annual Sustainability Report is published on the ECA website

• Focus on Climate Change and Air Qualityo ECA has proactive programs in place for effective Emissions Management

– Electrifying production equipment and facilities

– Top Tier LDAR program utilizing Optical Gas Imaging for >10-years

• Founding member of The Environmental Partnershipo Committed to reducing VOC emissions through sustainable practices

ESG issues deemed most impactful to our strategy

7

(1) Insufficient 2016 data

ESG Performance MetricsCategory Metric Measurement 2018 2017 2016

Emis

sion

sGHG Intensity metric tons CO2e/gross annual production 17.33 25.05 27.12

Methane Intensity metric tons CH4/gross annual production 0.22 0.38 0.43

Indirect GHG Emissions metric tons CO2e 199,028 242,582 –1

Direct GHG Emissions metric tons CO2e 3,312,645 3,571,514 3,612,528

Methane Emissions metric tons CH4 41,686 54,602 57,679

Wat

er &

Spi

lls

Water Intensity Cubic meters/gross annual production 75.7 99.5 67.2

Fresh Water Intensity Cubic meters/gross annual production 43.1 74.1 47.1

Reportable Spills Regulatory reportable spills 49 59 65

Total Water Use MMbbls 91 89 56

Alternative Water % 43% 26% 30%

Safe

ty

To tal Recordable Injury Frequency (TRIF)

Number of Recordable Injuries x 200,000 divided by exposure hours 0.28 0.30 0.30

Recordable Injuries Workforce 63 64 54

8

Permian Anadarko

MontneyBase & Other

Liquids-Focused, Multi-Basin Portfolio StrengthM U L T I - B A S I N P O R T F O L I O W I T H S C A L E

ASSET NET ACRES 2018 PRODUCTION LIQUIDS %

CO

RE PERMIAN 115,000 92 MBOE/d 85%

ANADARKO 361,000 135 MBOE/d 60%

MONTNEY 793,000 191 MBOE/d 22%

BA

SE

EAGLE FORD 42,000 45 MBOE/d 81%

WILLISTON 80,000 21 MBOE/d 84%

UINTA 222,000 20 MBOE/d 87%

DUVERNAY 264,000 18 MBOE/d 44%

2.0 BBOE of Proforma Proved Reserves*

• Core positions in three of the top plays in North America

• 2.0 BBOE of proforma high quality proved reserves*o YE18 Reserve Life Index (RLI) of ~10 years

o >80% increase to RLI since 2015o 55% liquids

* All reserves are stated on an SEC (U.S. protocol) basis. 2.1 BBOE of proforma NI 51-101 (Canadian protocol) proved reserves. Refer to the advisories at the end of this presentation for additional information.

9

Deep Inventory of High Return Growth Assets

>75% of 2019F** capital directed to core growth assets

~20% less capital (2019F** vs 2018*) expected to generate growth and free cash flowŦ

H I G H R E T U R N S

2019F** Capital $2.75-2.85BContinued Liquids Growth

* Full year proforma basis above includes legacy Newfield activity from January 1, 2019 to February 13, 2019. Excludes Montney dispositions of Gordondale assets in 2016.** Full year proforma basis above includes legacy Newfield activity from January 1 to February 13, 2019. On a reportable basis, amounts for volumes, capital and expenses exclude amounts for this period. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

0

100

200

300

2016 2017 2018 2019F*

Liqu

ids

Prod

uctio

n (M

bbls

/d)

Permian Montney Anadarko

10

Disciplined Approach

Priority #3 - Sustain Business

Maintain cash flowŦ and liquids production in core areas

Priority #2 – Dividends*

Sustain current dividend

Priority #1 - Financial Strength

Manage leverage at mid-cycle prices to ~1.5x net debt to adjusted EBITDAŦ

Maintain strong liquidityInvestment grade credit ratings

* Declaration and payment of future dividends subject to board approvalŦ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website

Priority #5 – Excess Free Cash FlowŦ

Priority #4 – Dividend Growth

Dividend increase as sustainable free cash flowŦ grows

C A P I T A L D I S C I P L I N E

Growth investment that generates strong full-cycle returns and

expands free cash flowŦOpportunistic share buybacks Deleverage balance sheet

Reduce debt

11

$0.0

$0.5

$1.0

$1.5

$2.0

2018 2019F

Dis

trib

utio

ns t

o Sh

areh

olde

rs (

$B)

Dividends Buyback

Returning Capital to ShareholdersR E T U R N O F C A P I T A L

• Sold >$13 billion of assets since 2013o >80% of production and proved reserves sold were

natural gaso Reshaped portfolio to liquids while returning cash to

shareholders

• Strong liquidity and lowered leverage to maintain flexibility to fund investor initiatives

• Ongoing commitment to return cash to shareholders*o $1.25 billion buyback

• 196.7 million shares repurchased to September 30, 2019

o 25% increase in dividend as of 1Q19

* Declaration and payment of future dividends is subject to Board approval. Year to date share buyback as at September 30, 2019.

2018 – 2019F Planned Returns*

12

2019 ProgramP E R M I A N

• 75% activity focused on Midland, Martin and Upton counties

• Continuing to innovate completion design and cube development

* Includes plant and field condensate

FY19 PLANACREAGE (net acres) / AVERAGE WORKING INTEREST % 115,000 / 92%

2019 AVERAGE WORKING INTEREST (%) 96%

AVERAGE ROYALTY RATE (%) 25%

CAPITAL (net) ($MM) $920 – $950

NET WELLS DRILLED 110 – 120

NET WELLS ON STREAM 115 – 125

D&C COST ($MM/well) $6.1

AVERAGE LATERAL LENGTH (ft) 8,500

TOTAL PRODUCTION SPLIT

OIL/CONDENSATE* % 64%

NGLs (C2 – C4) % 19%

NATURAL GAS % 17%

13

Midstream And Marketing OverviewP E R M I A N

• Majority of oil production gathered via pipeline with access to multiple physical markets

• Firm gas gathering and processing with access to Gulf Coast and Mont Belvieu markets

• Minimal Waha basis risk

• Secured market access to Gulf Coast refining/export markets

Permian

Colorado C ity

Midland

Crane

Pipelines connect to

Cushing and Gulf Coast

Proximity to market and environment of responsive infrastructure development

(1) 4Q 2019 risk management positions as at September 30, 2019. Hedged volumes are converted to Mcf at a 1:1 ratio from MMBtu.

Permian (1) 2019 2020WTI/MIDLAND DIFFERENTIAL HEDGESSWAP PRICE (US$/bbl)

18 Mbbls/d $(1.44)/bbl


FIRM OIL MARKET ACCESS 45 Mbbls/d 66 Mbbls/d

WAHA BASIS HEDGESSWAP PRICE (US$/Mcf)

65 MMcf/d$(0.67)/Mcf


FIRM GAS MARKET ACCESS 50 MMBtu/d 50 MMBtu/d

WAHA TO HOUSTON SHIP CHANNEL TRANSPORT HEDGES

50 MMcf/d$0.76/Mcf

14

2019 ProgramA N A D A R K O

• >90% program focused in Kingfisher, Blaine and Canadian Counties

• Cube development expected to unlock significant synergies via reduced well costs and improved capital efficiency

o $1 MM per well savings original target, increased to $1.4 MM per well

• Supply chain management and self-sourcing of services unlocking additional returns

* Includes plant and field condensate** Full year proforma basis above includes legacy Newfield activity from January 1 to February 13, 2019. On a reportable basis, amounts for volumes, capital (~$140MM) and expenses exclude amounts for this period.

FY19 PLAN**ACREAGE (net acres) / AVERAGE WORKING INTEREST % 363,000 / ~57%


AVERAGE ROYALTY RATE (%) 17 – 20%

CAPITAL (net) ($MM) $825 - $875



2018 AVERAGE D&C COST ($MM/well) $7.9

2019 D&C COST ($MM/well) $6.5




NGLs (C2 – C4) % 26%

NATURAL GAS % 38%

15

Midstream And Marketing OverviewA N A D A R K O

Cushing

Anadarko

O il pipe corridor

Gas pipe corridor

• STACK growth area – high demand oil qualityo Oil gathering and pipeline access to Cushing limits physical

flow risko Barrel delivered to Cushing unblended in segregated stream

• Minimal differential risk for oil

• Firm gas gathering and processing with access to S.E. gas and Mont Belvieu markets

• Incremental residue gas infrastructure expected 1H 2020 will expand market access

Oi l gathering and pi peline access for ST ACK growth area

Fi rm market for a ma terial portion of

re sidue gas

Bennington

To Perryville LA

Ma jority of NGL e xposure at Mont

Be l vieu

16

2019 ProgramM O N T N E Y

• Investment aligned with local market conditions

• ~Balanced activity between Cutbank Ridge Partnership (60% partnership interest) and Pipestone (100% working interest)

• ~C$100 MM of remaining third party capital to be fully consumed within Cutbank Ridge Partnership

FY19 PLANACREAGE (net acres) / AVERAGE WORKING INTEREST % 793,000 / 64%

- PIPESTONE ACREAGE / WI % 89,000 / 100%


AVERAGE ROYALTY RATE (%) 5 – 10%

CAPITAL (net) ($MM) $350 – $400



D&C COST ($MM/well) $4.3




NGLs (C2 – C4) % 7%

NATURAL GAS % 75%

* Includes plant and field condensate

17

Midstream And Marketing OverviewM O N T N E Y

To US Northwest To Dawn

To Chicago

Condensate Imports

100% firm capacity on Nova Gas

Transmission Sy stem(NGTL)

Condensate so ld into premium

local market

Natural Gas PipelineCondensate Pipeline

(1) 4Q 2019 and full year 2020 risk management positions as at September 30, 2019* Price stated is the differential versus NYMEX pricing. Hedged and transport volumes are converted to Mcf at a 1:1 ratio from MMBtu.

• Combination of firm export capacity and basis hedges to manage AECO gas price* risko Realized price including hedge expected to be ~$0.25 below NYMEX in

2019o AECO US $0.25 fluctuation equals less than US $4 MM cash flow in 2019

Q4 after hedge

• 100% firm capacity secured on NGTL for expected production growth – limited curtailment risk

• Condensate sold into local market at close to WTI prices

Western Canada (1) 2019 2020

AECO BASIS HEDGESSWAP PRICE US$/Mcf*

405 MMcf/d$(0.88)/Mcf

495 MMcf/d$(0.88)/Mcf

TRANSPORT TO DAWN 316 MMcf/d 316 MMcf/d

TRANSPORT TO SUMAS / MALIN 132 MMcf/d 132 MMcf/d

TRANSPORT TO CHICAGO 88 MMcf/d 108 MMcf/d

18

0

25

50

75

100

125

2018 2019F

MBO

E/d

Optimizing Free Cash FlowŦ

Duvernay Uinta Williston Eagle Ford

Base AssetsO P T I M I Z I N G F R E E C A S H F L O W

FY 2019 PLAN* EAGLE FORD WILLISTON DUVERNAY UINTA

ACREAGE (net acres) /AVERAGE WORKING INTEREST (%) 42,000 / 96% 81,000 / 59% 264,000 / 51% 222,000 / 80%

2019 AVG WORKING INTEREST (%) 92% 70% 51% 70%

AVERAGE ROYALTY RATE (%) 20 – 25% 17 – 20% 5 – 10% 17 – 20%

CAPITAL (net) ($MM) $250 – 270 $140 – 160 $100 – 120 $60 – 70

TOTAL PRODUCTION SPLIT*

OIL/CONDENSATE** % 67% 69% 38% 83%

NGLs (C2 – C4) % 15% 13% 6% 3%

NATURAL GAS % 18% 18% 56% 13%

• Focused D&C capital with minimal infrastructure and non-well capital requirements

• Wells drilled generate similar returns as Core 3

Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website* Full year proforma basis above includes legacy Newfield activity from January 1 to February 13, 2019. ** Includes plant and field condensate

19

Maximizing MarginC O S T C O N T R O L O F C O R P O R A T E I T E M S E N H A N C E S P E R U N I T M A R G I N

• G&A >30% lower on a per BOE1 basiso On track for $200 million in annualized G&A savings, increased by

$75 million versus original estimate

• Quarterly G&A run rate for remainder of year: ~$75 MMo Run-rate G&A costs include approximately $25 MM per quarter for

the BOW lease costs, previously classified in interest expense and corporate segment operating costs

o About 50% of BOW related costs included in G&A are recovered through sub-lease revenues

o Excluding the impact of the BOW office cost reclassification, quarterly run-rate G&A costs are down from $65 MM previous estimate to ~$50 MM

• Market optimization segment loss of ~$40 MM per quarter

• Interest expense on debt of ~$100 MM per quarter

(1) G&A per BOE includes the impact of Bow office related costs and excludes Long Term Incentives costs.(2) Full year proforma basis above includes legacy Newfield activity in 2018 and 2019; 2019F excludes $134 MM of restructuring costs Q3 ’19 year to date.

-

0.50

1.00

1.50

2.00

2.50

0

150

300

450

600

2018 2019F

$/B

OE

$MM

Bow Related Costs G&A Excl. LTI

G&A per BOE

Lower Total G&A2

20

Product Value Chain Excluding HedgeP R O J E C T E D C O M P O S I T I O N O F T O T A L P R O D U C T I O N

(1) 2019F based on company guidance as at September 30, 2019, excluding impact of hedges; production ranges are not additive. Reflects YTD Q3 actual results and fourth quarter forecast.(2) US Oil production range excludes estimated partial year volumes for China(3) Includes plant condensate

Canada US2019F (1)

(Mbbls/d)2019F Pricing

(% WTI)2019F(1)

(Mbbls/d)2019F Pricing

(% WTI)

Oil (2) 0 – 1 85% 170 – 175 98%

Condensate (3) 40 – 43 90% 10 – 12 77%

Butane 6 – 8 21% 12 – 14 41%Propane 7 – 9 14% 23 – 26 31%Ethane 0 – 1 16% 32 – 34 6%

Canada US2019F(1)

(MMcf/d)2019F Pricing

(% NYMEX)2019F(1)

(MMcf/d)2019F Pricing

(% NYMEX)

Natural Gas 975 – 1,055 75% 550 – 650 78%

21

Hedging SummaryM I D S T R E A M A N D M A R K E T I N G

(1) Risk management positions as at September 30, 2019(2) Natural gas hedged volumes are converted to Mcf at a 1:1 ratio from MMBtuŦ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

• Hedges reduce cash flow risk and build on market diversification efforts

• WTI Oilo Majority of oil hedges through option-based structures

allows for upside capture to ~$67.00/bbl

• NYMEX Gaso Greater than 50% hedged for balance of 2019 and 2020

• Foreign Exchangeo ~$5 MM per $0.05 change in F/X to 2019 Q4 cash flowŦ

after hedge

HEDGE SUMMARY ( 1) 2019 2020

Oil and Condensate

WTI HEDGES 176 Mbbls/d 119 Mbbls/d

Natural Gas

NYMEX NATURAL GAS (2) 864 MMcf/d 1,038 MMcf/d

Foreign Exchange

Notional US$ Currency SwapsAverage Exchange Rate US$ to C$1

US$250 MMUS$0.7516

US$425 MMUS$0.7483

22

Oil Hedges and Sensitivity

• WTI Oilo ~$50 MM per $5.00/bbl increase in NYMEX WTI to

2019 Q4 cash flowŦ after hedge (1)

o ~$20 MM per $5.00/bbl decrease in NYMEX WTI to 2019 Q4 cash flowŦ after hedge (1)

o Majority of oil hedges through option-based structures allows for upside capture to ~$67.00/bbl

• Midland differential hedges complement firm oil market access to multiple physical markets

KEY HEDGES (2) 2019 2020

O i l and Condensate

WTI FIXED PRICE SWAPSWAP PRICE (US$/bbl)

45 Mbbls/d $60.24/bbl

24 Mbbls/d $60.05/bbl

WTI 3-WAY OPTIONSHORT PUT (US$/bbl)LONG PUT (US$/bbl)SHORT CALL (US$/bbl)

88 Mbbls/d$45.86/bbl$56.47/bbl$67.72/bbl

80 Mbbls/d$43.44/bbl$53.44/bbl$61.68/bbl

WTI COSTLESS COLLARLONG PUT (US$/bbl)SHORT CALL (US$/bbl)

43 Mbbls/d$56.28/bbl$66.57/bbl

15 Mbbls/d$50.00/bbl$68.71/bbl

WTI/MIDLAND DIFFERENTIAL HEDGESSWAP PRICE (US$/bbl)



(1) Q4 2019 sensitivity based on mid-point of guidance volumes(2) Risk management positions as at September 30, 2019Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

23

Natural Gas Hedges and Sensitivity

• NYMEX Gas Benchmarko ~$15 MM per $0.25/Mcf change in NYMEX gas to 2019

Q4 cash flowŦ after hedge (1)

• AECO basiso US$0.25 fluctuation equals less than US $4MM cash

flow (1)Ŧ in 2019 Q3-Q4 after hedge (1)

NATURAL GAS HEDGES (2) (3) 2019 2020

Natural Gas Benchmark Hedges

NYMEX FIXED PRICE SWAPSWAP PRICE US$/Mcf

687 MMcf/d$2.72/Mcf

653 MMcf/d$2.69/Mcf

NYMEX 3-WAY OPTIONSHORT PUT (US$/mcf)LONG PUT (US$/mcf)SHORT CALL (US$/mcf)

330 MMcf/d$2.25/Mcf$2.60/Mcf$2.72/Mcf

NYMEX COSTLESS COLLARLONG PUT (US$/Mcf)SHORT CALL (US$/Mcf)

177 MMcf/d$2.89/Mcf$3.05/Mcf

55 MMcf/d$2.50/Mcf$2.88/Mcf

Natural Gas Basis Differential Hedges

AECO BASIS HEDGESSWAP PRICE US$/Mcf

405 MMcf/d$(0.88)/Mcf

495 MMcf/d$(0.88)/Mcf

WAHA BASIS HEDGESSWAP PRICE (US$/Mcf)



(1) Q4 2019 sensitivity based on mid-point of guidance volumes(2) Risk management positions as at September 30, 2019(3) Natural gas hedged volumes are converted to Mcf at a 1:1 ratio from MMBtuŦ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

24FUTURE ORIENTED INFORMATION

• expectation of meeting or exceeding targets in corporate guidance• 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• 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 andexecution efficiency, operating, income and c ash flow margin, and margin growth, including exp ectedtimeframes

• well performance, completions intensity, location, running room and scale of assets, including itscompetitiveness and pace of growth against peers, and costs within assets

• number of potential drilling locations, well spacing, numb er of wells p er p ad, decline rate, rig count, rigrelease 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

• pacesetting metrics being indicative of future well performance and costs, and sustainability thereof• timing, success and benefits from innovation, cube development appro ach, advanced completions design,

scale of development, high-intensity completions and precision targeting, and transferability of ideas• anticipated efficiencies, including well costs, G&A, drilling and completion cycle times, supply chain

management, and operating, corporate, transportation and processing activities• leading position and quality of plays in North America

• estimated reserves and resources, including product types and stacked resource potential• expected transportation and processing capacity, commitments, curtailments and restrictions, including

flexibility of commercial arrangements and costs and timing of certain infrastructure being operational• anticipated outlook and prio rities therein, man agement of balance sheet and c redit rating, access to

liquidity, available free cash flow, returns, dividend growth, deleveraging, and focus on capital and efficientoperations

• growth in long-term sh areholder valu e and plan to return c ash to shareholders, including anticipateddividends

• expected net debt, net debt to adjusted EBITDA, target leverage, financial capacity and other debt metrics• commodity price outlook• outcomes of risk management pro gram, including exposure to co mmodity pric es and foreign exchange,

amount of hedged production, market access, market diversification strategy and physical sales locations• environmental, health and safety performance• portfolio refinement and timing of closing thereof• advantages of multi-basin portfolio• the company’s sustainable business roadmap and elements thereof• ESG approach, performance and results, and sustainability thereof

FLS involve assumptions, risks and uncert ainties that may c ause such statements not to occur or results to differ mat erially. Th ese assumptions include: future commodity pric es and differentials; foreign exch ange rat es; assumptionscontained in corporate guidance and as specified herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; results from innovations; expectation thatcounterparties will fulfill their obligations; access to transportation and processing f acilities; assumed tax, royalty and regulatory regimes; and exp ectations and projections mad e in light of Encana's historical experience and itsperception of historical trends. Risks and uncertainties include: ability to gen erate sufficient cash flow to meet obligations; commodity price volatility; ability to secure adequate t ransportation and potential pipeline curt ailments;variability and discretion to declare and p ay dividends, if any; timin g and costs of well, facilities and pipeline construction; business interruption, property and casualty losses o r unexpect ed technical difficulties; counterparty and creditrisk; changes in credit rating and its impact on access to liquidity, including ability to issue commercial paper; currency and interest rates; risks inherent in corporate guidance; failure to achieve cost and efficiency initiatives; risks inmarketing operations; risks associated with technology; changes in or interp retation of laws or regulations; risks associated with existing and potential lawsuits and regulatory actions; impact of disputes arising with partners, includingsuspension of certain obligations and inability to dispose of assets or interests in certain arrangements; ability to acquire or find additional reserves; imprecision of reserves estimates and estimat es of recoverable quantities and futurenet revenue; risks associated with p ast and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the trans action agreements (such transactions may include third-partycapital investments, farm-outs or partnerships, which Encana may refer to fro m time to time as “partn erships” or “joint ventures” and the funds received in resp ect thereof which Encana may refer to from time to time as “proceeds”,“deferred purchase price” and/or “c arry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties, as described in Encana’s most recent Annual R eport on Form 10-K andQuarterly Report on Form 10-Q and as described from time to time in Encana’s other periodic filings as filed on SEDAR and EDGAR.

Although Encana believes such FLS are reasonable, there can be no assurance they will prove to be correct. Th e above assumptions, risks and uncertainties are not exhaustive. FLS are made as of the date hereof and, exc ept asrequired by law, Encana undertakes no obligation to update or revise any FLS. Certain future orient ed financial information or financial outlook information is included in this p resent ation to communicat e current expectations as toEncana’s performance. Readers are c autioned that it may not be appropriate for other purposes. Rat es of return for a particular asset o r well are on a before-tax basis and are based on specified commodity prices with local pricin goffsets, capital costs associated with drilling, completing and equipping a well, field operating expenses and certain type curve assumptions. Paces etter well costs for a particular asset are a composite of the best drillin g performanc eand best completions performance wells in the current quarter in such asset and are presented for co mparison purposes. Drilling and completions costs have been normaliz ed as specified in this presentation bas ed on cert ain lat erallengths for a particular asset. Fo r convenience, references in this present ation to “Encana”, the “Company”, “we”, “us” and “our” may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations andpartnerships (“Subsidiaries”) of Encana Corporation, and the assets, activities and initiatives of such Subsidiaries.

This present ation contains forward-looking statements or information (collectively, “FLS”) within the meaning of applicable s ecurities legislation, including Section 27A of the Securities Act of 1933, as amended, and Section 21E ofthe Securities Exchange Act of 1934, as amended. FLS include:

25ADVISORY REGARDING OIL & GAS INFORMATIONAll reserves estimat es in this presentation are effective as of December 31, 2018, 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 Ad ministrators from the requirements under NI 51-101 that eachqualified 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. Detailed Canadian and U.S. protocoldisclosure will be contained in the Form 51-101F1 and Annual Report on Form 10-K, respectively. Information on the forecast prices and costs used in preparing the Canadian protocol estimat es are contained in the Fo rm 51-101F1. Foradditional information relating to risks associated with the estimates of reserves, see "Item 1A. Risk Factors" of the Annual Report on Form 10-K.

Reserves are the estimated remaining quantities of oil and n atural gas and related substances anticipated to be recoverable fro m known accumulations, from a given d ate forward, bas ed on: an alysis of drilling, geologic al, geophysicaland engineering dat a, the use of established technology, and specified economic conditions, which are generally acc epted as being reasonable. Proved res erves are those res erves which can be estimated with a high d egree of cert aintyto be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Encana uses the terms play and resourc e play. Play encompasses resource plays, geological formations and conventional plays. Resource play describes an accumulation of hydrocarbons known to exist over a large areal expans eand/or thick vertic al section, which when co mpared to a conventional play, typically has a lower geological and/or commercial d evelopment risk and lower average decline rate. As used by Enc ana, estimat ed ultimate recovery (“EUR” )has the meaning set out jointly by th e Society of Petroleu m En gineers and World P etroleum Congress in the year 2000, being those quantities of petroleum which are estimated, on a given date, to be potentially recoverable fro m anaccumulation, plus those quantities al ready produced therefrom. Encan a has provided information with resp ect to its assets which are “analo gous information” as d efined in NI 51-101, including estimates of EUR and production typecurves. 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 predomin antlyindependent in nature. Production type curves are b ased on a methodology of analog, empiric al and theoretical assessments and workflow with consideration of the specific asset, and as depicted in this pres entation, is representativeof Encana’s current program, including relative to current performance, but are not nec essarily indicative of ultimate recovery. Some of this data may not have been p repared by qualified res erves evaluators, may have been prep aredbased on internal estimates, and the prep aration of any estimates may not be in strict accordance with COG EH. Estimates by engin eering and geo-technical practitioners may vary and the differences may b e significant. Encan abelieves 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 beenupdated as of the dat e hereof unless otherwis e specified. Due to the early life nature of the various emerging plays discussed in this presentation, EUR is th e most relevant specific assignable cat egory of estimated resourc es. Th ere isno certainty that any portion of the resources will b e discovered. Th ere is no certainty that it will be commercially viable to produce any portion of the estimated EUR. Estimat es of Encan a potential gross inventory locations, includingpremium return well inventory, include proved undeveloped res erves, probable undeveloped res erves, un-risked 2C contingent resources and unbooked inventory locations. As of December 31, 2018, on a proforma basis, 2,012 provedundeveloped locations, 3,844 probable undeveloped locations and 3,265 un-risked 2C contingent resource locations (in the development pending, development on-hold or development unclarified project maturity sub-classes) havebeen categorized as either res erves or contingent resources. Unbooked locations have not been classified as either reserves or resources and are intern al estimates that have b een identified by man agement as an estimation ofEncana's multi-year potential drilling activities based on evaluation of applicable geologic, seismic, engineering, production, resource and acreage information. Th ere is no certainty that Encana will drill all unbooked locations and ifdrilled there is no certainty that such locations will result in additional oil and gas res erves, resources o r production. The locations on which Encana will actually drill wells, including the numb er and timing thereof is ultimatelydependent 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 f actors. While cert ain of the unbooked locations may have been de-risked by drillin g existing wells in relative close p roximity to such locations, many of other unbookedlocations are farth er away fro m existing wells where management has less information about the characteristics of the res ervoir and therefore there is more uncert ainty whether wells will b e drilled in such locations and if drilled thereis more uncertainty that such wells will result in additional proved or probable reserves, resources or production.

30-day IP and other short-term rat es are not necessarily indicative of long-term performance or of ultimate recovery. Th e conversion of natural gas volumes to barrels of oil equivalent (“BOE”) is on the basis of six thousand cubic feet toone barrel. BOE is based on a gen eric energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. R eaders are cautioned that BOE may b emisleading, particularly if used in isolation.

26NON-GAAP MEASURES

Certain measures in this presentation do not hav e any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measurespresented by other companies. These measures have been prov ided for meaningful comparisons betw een current results and other periods and should not bev iew ed as a substitute for measures reported under U.S. GAAP. Foradditional information regarding non-GAAP measures, including reconciliations, see the Company’s website and Encana’s most recent Annual Report as filed on SEDAR and EDGAR. Non-GAAPmeasures include:

• Non-GAAP Cash Flow, Non-GAAP Cash Flow Per Shar e (CFPS ), Non-GAAP Fr ee Cash Flow, Non-GAAP Fr eeCash Flow Yield and Non-GAAP Cash Flow Mar gin – Non-GAAP Cash Flow (or Cash Flow) is defined as cash f rom(used in) opera ting activities ex cluding net c hange in other assets and liabilities, net change in non-cas h working capitaland curren t tax on sale of assets. Non-GAAP CFPS is Non-G AAP Cas h Flow divided by the weighted average numberof common shares outstanding. Non-G AAP Free Cash Flow (or Free Cas h Flow) is Non-GAA P Cash Flow in ex cess ofcapital ex penditures, ex cluding net acquisitions and divestitu res. Non-GAAP Free Cash Flow Yield is annualized Non-GAAP Free Cash Flow compared to curren t market c apitalization. Non-GAA P Cash Flow Margin is Non-G AAP CashFlow per BOE of production. Management believes thes e meas ures are useful to the company and its investo rs as ameasure of operating and financial perfo rmance across periods and against other companies in the indust ry, and are anindication of the company’s ability to generate cas h to finance capital programs, to service debt and to meet otherfinancial obligations. These measures may be us ed, along with other measures, in the calculation of certainperformance targets for the company’s management and employees.

• Total Costs per BOE is defined as the summation of production, mineral and other tax es, upst ream transportation andprocessing ex pense, upst ream operating ex pense and administrative ex pense, ex cluding the impact of long-te rmincentive and restructuring costs, per BOE of production . Management believes this measure is useful to the companyand its investors as a measure of operational efficiency across periods.

• Non-GAAP Oper ating Ear nings (Loss) – is defined as Net Earnings (Loss) ex cluding non-recurring or non-cash itemsthat management believes reduces the c omparability of the company’s financial perfo rmance between periods. Theseitems may include, but are not limited to, unrealized gains/losses on risk management, impairments, rest ructu ringcharges, non-operating fo reign ex change gains/losses, gains/losses on divestitu res and gains on debt reti rement.Income tax es may include v aluation allowances and the provision related to the pre-tax items listed, as well as inc ometax es related to divestitu res and U.S. tax refo rm, and adjustments to normalize the effect of income tax es calculatedusing the estimated annual effective income tax rate.

• Net Deb t, Adjusted E BITDA, Net Debt to Adjusted E BITDA and Annualized Lever age – Net Debt is de fined as long-term debt, including the current portion, less c ash and cas h equivalents. Management uses this measure as a substitutefor total long-te rm debt in certain in ternal debt metrics as a meas ure of the company’s ability to service debt obligationsand as an indicato r of the company’s overall financial st rength. Adjusted EBITDA is defined as trailing 12-month netearnings (loss) before inc ome tax es, DD&A, impairments, accre tion of asset retirement obligation, inte rest, unrealizedgains/losses on risk management, fo reign ex change gains/losses, gains/losses on divestitures and other gains/losses.Net Debt to Adjusted EBITDA is monito red by management as an indicator of the company’s overall financial st rength.Annualized leverage is defined as net debt to adjusted EBITDA based on Adjusted EBITDA generated in the period onan annualized basis.

• Oper ating Mar gin/Oper ating Cash Flow/Oper ating Netback – Product revenues less costs associated with deliveringthe product to market , including production, mineral and other tax es, transportation and processing and operatingex penses. When presented on a per BOE basis, Operating Margin/Opera ting Cas h Flow/Operating Netback is definedas indicated divided by av erage barrels of oil equivalent s ales volumes. O perating Margin/Operating CashFlow/Operating Netback is used by management as an internal measure of the profitability of a play(s).

• Fr ee Oper ating Cash Flow – O perating Cash Flow in ex cess of capital investment, ex cluding net acquisitions anddivestitures.

• Upstr eam Oper ating Cash Flow – Upstream Operating Cas h Flow is a measure tha t adjusts the Canadian, USA andChina Operations revenues for production, mineral and other tax es, transportation and processing ex pense, andoperating ex pense. Management monitors Upstream O perating Cash Flow as it reflects operating performance andmeasures the amount of cash generated from the company’s upstream operations.

• Upstr eam Oper ating Fr ee Cash Flow – is defined as Upst ream Operating Cash Flow in ex cess of capital investment,ex cluding net acquisitions and divestitures.

Contact Investor Relations:

403.645.3550 | 281.210.5110 | [email protected]

Documents

Appendix€¦ · & restructuring costs • Run-rate annualized leverage of 1.8x . Ŧ,(1) o Represents normalized leverage post acquisition • 605 MBOE/d of production (54% liquids)