2Q19 C 19 Confe ference C Call July 31, 2019 S E C O N D Q U A - - PowerPoint PPT Presentation

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2Q19 C 19 Confe ference C Call July 31, 2019 S E C O N D Q U A - - PowerPoint PPT Presentation

2Q19 C 19 Confe ference C Call July 31, 2019 S E C O N D Q U A R T E R 2 Key Highl hlight ghts s Demonst strate e Profi fitable e Business ess Net E Earn rnings gs Cash h Flow ow Free C Fr Cas ash Fl Flow $336 $336


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SLIDE 1

2Q19 C 19 Confe ference C Call

July 31, 2019

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SLIDE 2

2

Key Highl hlight ghts s Demonst strate e Profi fitable e Business ess

S E C O N D Q U A R T E R

Fr Free C Cas ash Fl Flow Ŧ

$127 $127 MM

SIGNIFICANTLY GROWING FCF IN 2H19

Net E Earn rnings gs

$336 $336 MM

$0.24 / SHARE

FCF CF Y Yiel eld

#1 #1 VS PEE EERS

Buyback ack

149M 149MM

  • SHS. Y

. YTD

~10% OF O/S SHARES

Cash h Flow

  • w Ŧ

$877 $877 MM

$0.64 / SHARE

Divide idend

+25% +25% YTD

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

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SLIDE 3

3

$127 M MM o M of Free ee Cash F FlowŦ

Positioned to grow free cash flow in H2

$175 MM M annualiz ized G&A / op. cos

  • st syner

ergies es

$50 MM greater than original estimate

2Q 2Q19 a annua nualized ed l leverage o

  • f 1.7x Ŧ,(1)

Represents normalized leverage post acquisition

Fi Financi cial al

Continued ed r ref efinem emen ent o

  • f the p

he portfolio

Announced China exit & Arkoma divestiture

Str trate tegic gic

On track ck t to deli liver er p prod

  • duction

ion & & capit ital g guid ide

15% FY19 YoY liquids growth from three core growth assets

Redu duced S d STACK w well cost sts t s to $6.5 M MM

$1.4 MM D&C cost reduction since NFX acquisition

STACK o K oil produc uction growth 3 h 31% o

  • ver

er 1 1Q19

63% oil growth since 1Q18

Recor

  • rd Anadarko a
  • and P

d Permian p produ

  • duction
  • n

163 MBOE/d & 104 MBOE/d, respectively

Mont ntne ney liquids up 5 55% Y YTD Asse sets ts generati ating u g upstr stream am o

  • perati

ting FCF Ŧ

Wha hat Y You Ne

  • u Need t

to

  • Kno

Know Operat ational al

(1) Net debt to adjusted EBITDA based on Adjusted EBITDA generated in 2Q19 on an annualized basis. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

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SLIDE 4

4

2Q1 Q19 Conso solidate ted Resu esults

S T R O N G N G F F I N A N A N C N C I A L R E S U L U L T S

2Q 2Q19 19

$ M Millio llions ns $ Per S r Share re

NET EARNINGS 336 0.24 NON-GAAP OPERATING EARNINGSŦ 290 0.21 CASH FROM OPERATING ACTIVITIES 906 NON-GAAP CASH FLOWŦ 877 0.64 CASH FLOW MARGINŦ $/BOE 16.27 CAPITAL INVESTMENT 750 FREE CASH FLOWŦ 127 BUYBACK ($ MILLIONS / MILLIONS OF SHARES) $637 / 94 WEIGHTED AVERAGE SHARES – DILUTED (MILLIONS) 1,381.0 SHARES O/S AT JUNE 30, 2019 (MILLIONS) 1,346.5

2Q 2Q19 U Ups pstream O Ope perati ting F FCF Ŧ By A Asse sset

~$250 M MM (2)

  • $127 M

MM o M of Free ee Cash F Flow Ŧ

  • Outperforming original synergy targets & proving operational

performance

  • 2Q19 a

annualized ed l leve verage o e of 1 1.7x Ŧ,(1)

  • Represents normalized leverage post acquisition
  • Repaid $

$500 M MM M of 6 6.5% S Senior ior N Notes es

  • Optimized financial structure through commercial paper

(1) Net debt to adjusted EBITDA based on Adjusted EBITDA generated in 2Q19 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.

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SLIDE 5

5

Strong

  • ng F

Financ ncial a and O Operationa

  • nal Perfor

formanc nce

Results lts a and Guida dance

1Q19 2Q19 Expected 2H ‘19 Run Rate FY19 Reportable (Unchanged) FY19 Proforma (Unchanged) CAPITAL INVESTMENT ($ MILLION) 736 736 750 750 500 500 – 600 600 2,500 – 2,700 2,700 – 2,900 TOTAL LIQUIDS (1) (MBBLS/D) 229 229 320 320 310 310 - 320 320 290 – 310 300 – 320 NATURAL GAS (1) (MMCF/D) 1, 1,38 383 1, 1,53 530 1,500 – 1, 1,60 600 1,500 – 1,600 1,550 – 1,650 TOTAL PRODUCTION (1) (MBOE/D) 459 459 576 576 565 565 - 585 585 540 – 580 560 – 600 TOTAL COSTS PER BOE Ŧ,(2)

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

13. 13.44 12. 12.78 <13.00 12.75 – 13.25 12.75 – 13.25

(1) Excludes production from Arkoma and China operations for 1Q19 , 2Q19 and 3Q – 4Q run rate. Consolidated full year guidance is unchanged. (2) Excludes the impact of long-term incentive costs and restructuring costs. BOW office lease costs are included in administrative. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

  • 2019 c

capita ital i l investm tment a t and productio tion o

  • n track
  • 2Q

2Q19 n 19 non-GAAP AP c cash f flo low Ŧ of $877 MM ($0.64/sh sh)

  • Non-GAAP cash flow marginŦ of $16.27/BOE
  • Increased e

estim timated G d G&A / A / op.

  • p. cost s

t synergies

  • Sustainable annualized savings of $175 MM (original target: $125 MM)
  • FY19 p

prod

  • duction g

n gui uidance unc unchang nged p pos

  • st-div

ivestm tments ts

  • Strong production offsets impact of China exit & Arkoma sale: 2Q run

rate of 16 MBOE/d

O P E R A T I O N S O N T R A C K

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SLIDE 6

6

8% 4% 4% 4% 4% 3% 2% 1% (2%) (2%) (9%) ECA Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 15% 13% 12% 12% 11% 10% 8% 8% 4% (2%) (10%) Peer 1 Peer 2 ECA Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10

Encan Encana De Demons nstrating Fi Financ nancial Ex Excellenc nce

(1) FactSet data as of July 22, 2019. FCF Yield represents actual 2Q19 ECA FCF of $127 MM and peer consensus estimates for 2Q19. ROCE is a non-GAAP measure calculated for peers and ECA using GAAP Earnings plus after-tax interest expense divided by average net debt plus average stockholders’ equity. For simplicity, after-tax interest expense assumes a 21% tax rate for all companies. Peers include APA, APC, CLR, COG, CXO, DVN, EOG, MRO, NBL, PXD. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

Top T Tier FC r FCF Y F YieldŦ & RO ROCEŦ ~1.6% Dividend Y Yield Dividend +25% Y YTD $1.25B S Share Buyb yback

2Q19 Free C ee Cash Flow Y Yiel eld Ŧ,(1)

$

1 2 3 4

2017 & 2017 & 2018 A 2018 Average ge ROCE (1)

S U S T S T A I N A B L E B B U S I S I N E S S S S M O D E L

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SLIDE 7

7

Top North A America can P Produ

  • ducer

(1) Reportable oil & condensate production. (2) Peer data is reported 1Q19 net production from public filings. ECA reflects 2Q19 reportable production volumes. Peers include APA, APC, CLR, COG, CXO, DVN, EOG, MRO, NBL, PXD. Liquids production peers exclude CLR and CXO as they report 2-stream production.

Peer 8 Peer 7 Peer 6 Peer 5 Peer 4 Peer 3 ECA Peer 2 Peer 1

  • Multi

ti-basin l leader i in uncon conve vention ional d l devel velop

  • pmen

ent

  • Amongst the largest E&P producers in North America
  • Transition

ioned t to a qualit ity, l , liquid ids-foc focused ed portfol folio io

  • ~7.0x oil & condensate production growth since 2013
  • ~$13B in divestitures since 2013 (China & Arkoma in 2019)

Liquids ids P Productio tion Mbbls Mbbls/d d (2)

Peer 10 Peer 9 Peer 8 Peer 7 Peer 6 Peer 5 Peer 4 Peer 3 ECA Peer 2 Peer 1 324 (>70% oil + condensate) 592

Equiv ivale lent P t Productio tion M MBOE/d (2)

Avg O Oil + + conden ensa sate e API o

  • f ~46

Trans nsfor

  • rmationa

nal Oil il & Cond

  • ndens

nsate Growth (Mbbl Mbbls/d) (1)

35

235

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SLIDE 8

8

Anad nadarko

  • Consi

sistent w well r resu sults, l lower c r cost sts, s, s strong r return rns

  • STACK returns competitive with Permian and Montney
  • D&C well costs reduced to $6.5 MM, $1.4 MM below baseline
  • Gener

eratin ing f free u ee upstrea eam o

  • per

eratin ing c cash f flo low Ŧ while le growin ing volumes

  • 2Q19 p

19 produc uction o n of 1 163 3 MBOE/d

  • Anadarko liquids production up 47% since 1Q18
  • STACK oil production up 31% over 1Q19 and 63% since 1Q18
  • Anadarko oil and condensate averaged 60 Mbbls/d in Q2
  • ~200 o
  • per

erated ed S STACK i infi fill w l well ells

  • Recent Encana cube-style completions showing improved oil results

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

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SLIDE 9

9

STACK CK Deliv liverin ing Con

  • nsis

istent Result lts at Lo Lower Cos Costs

  • 89 STACK Me

Meramec w wells lls o

  • n-stre

ream Y YTD

  • 48 net STACK wells on-stream in 2Q19
  • Sta

tages & & slu lurry v volu lumes pu pumpe ped pe per da day u up p 58% & % & 37% 37%, r respectively, o

  • ver 1Q

1Q19 19

  • Cont
  • ntinui

uing t to

  • op
  • ptimize com
  • mpletion &

n & well s spacing ng f for

  • r

maxi ximum um D DSU v value

  • Infill development delivering >50% IRR

Ide denti tified Additi d Additional S STACK W Well ll C Cost S t Savings

(2,000 / 2,000 Completion)

(1) Normalized to 10,000’ lateral length..

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10

STACK CK Cu Cube bes Pos

  • stin

ing Stron

  • ng Result

lts

(1) Infill wells normalized to 10,000’ lateral length.

MBOE Mbbls Pre ECA Cube Dev STACK 2019 TC

BLAINE NE

Infill Parent

MERAMEC

KINGFISH ISHER

First ECA Cube Style Completions (6 – 8 well spacing)

(18 wells) (24 wells) Pre ECA Cube Dev STACK 2019 TC (18 wells) (24 wells)

  • Oil

il outperfor

  • rmanc

nce d driving ng r retur urns ns

  • 18 high intensity cube-style completions showing strong early

results at 6 – 8 well spacing with similar job size at reduced cost

  • Additi

Additional 2 24 le legacy w wells lls in in focus a area track acking typ ype curve ve

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11

Demonst strated ed P Permi mian an Basin L n Leader er

FY15 – FY18 Y18 >2.5x FY15 - Curre rrent ~32% CA CAGR GR Ach chieved a at a avg r rig co count o

  • f ~4.5

5 (1)

(1) Average ECA operated hz rig count from FY15 through 1H19. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

  • Gener

eratin ing f free u ee upstrea eam o

  • per

eratin ing c cash f flo low Ŧ & growing volumes

  • 38

38 net w wells o

  • n-st

stream i m in 2Q19

  • 2Q19 p

19 produc uction o n of 1 104 4 MBOE/d

  • Currently running at ~110 MBOE/d in July
  • Effi

ficien ent oper erator

  • r
  • Growing to >100 MBOE/d with 4 rig program

13% reduction in days

to total depth YoY

77 days 2Q19

spud to sales average

40% reduction in recycled

water costs since 2016

14% production

growth vs 1Q

Continue inued O Optim imiz izatio ion Cycle e Time L e Leader Operation

  • nal

al P Perfor

  • rma

mance Cost F Focused sed

Permian Production (MBOE/d)

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SLIDE 12

12

Permi mian

  • HNC 248 Cube: 14-wells

ls set recor ecord ~17 Mbbls ls/d /d a after 60 d days ys

  • ~1,400 BOE/d average rate per well after 90 days
  • Continued

ed g growth e expec ected ed i in 2 2H19

  • On track to meet full year 2019 expectations
  • Oil & condensate volumes +11% QoQ to 67.5 Mbbls/d in

2Q19

  • Leading P

Permi rmian B Basi sin o

  • perator
  • Best in class cycle time performance
  • Record pump efficiency: 25 days with >20hrs/d
  • Stro

rong re realized p prici cing

  • Preferred API blend
  • Market diversification creating value

(1) Normalized to 8,500’ lateral length.

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13

Mo Mont ntney

(1) Normalized to 7,215’ lateral length. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

  • Gener

eratin ing f free u ee upstrea eam o

  • per

eratin ing c cash flow

while le growin ing liquid ids volumes es

  • 32

32 net w wells o

  • n-st

stream i m in 2Q19

  • Increased completions scope resulting in 25% TC
  • utperformance
  • 2Q19 p

19 produc uction o n of 2 203 3 MBOE/d

  • Total liquids of 54 Mbbls/d (72% Oil & condensate)
  • Third party outages & planned maintenance impacted 2Q19

production by ~6.8 MBOE/d

  • Montney c

continues o s operational e excellence

  • Drilling cycle time savings of 9% 1Q19  2Q19
  • 50% increase in completion intensity over 2018 while holding

costs-per-lateral-foot flat

  • Rig and crew efficiencies – cycle time down 44% YoY
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SLIDE 14

14

Capit pital D l Disc isciplin ipline Fr Free Ca Cash h Fl Flow

Encana’s S Sustainable B e Busines ess R Roadma map

Liqu iquids ids Gr Growth Div ivide idend Gr Growth Bal alan ance S Sheet eet S Stren ength Mu Mult lti-Basin in Portfoli lio w wit ith S Scale le

Pr Profitable B Busi siness @ ss @ Compe pellin lling V Valuatio tion

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SLIDE 15

2Q19 Co Confe ference Cal Call

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16

FUTURE E ORIEN ENTED ED INFORMA MATION

  • meeting or exceeding Encana’s 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 and execution efficiency, operating, income and cash flow margin, and margin expansion, including expected timeframes

  • well performance, completions intensity, location, running room and scale of assets, including its

competitiveness and pace of growth against peers

  • number of potential drilling locations, 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

  • 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

  • anticipated efficiencies and synergies, including well costs, G&A, drilling and completion cycle times,
  • perating, corporate, transportation and processing, staffing, services and materials secured and supply

chain management

  • leading positions 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 return of capital model and priorities therein, management of balance sheet and credit rating,

access to liquidity, available cash, and return of capital including dividends and size and timing of share buyback

  • expected net debt, net debt to adjusted EBITDA, leverage, reductions to commercial paper outstanding,

financial capacity and other debt metrics

  • ptions to maximize shareholder returns and timing thereof
  • commodity price outlook
  • utcomes of risk management program, including exposure to commodity prices and foreign exchange,

amount of hedged production, market access, market diversification strategy and physical sales locations

  • environmental, health and safety performance
  • portfolio refinement and timing of closing thereof

FLS involve assumptions, risks and uncertainties that may cause such statements not to occur or results to differ materially. These assumptions include: future commodity prices and differentials; foreign exchange rates; assumptions contained 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 that counterparties will fulfill their obligations; access to transportation and processing facilities; assumed tax, royalty and regulatory regimes; and expectations and projections made in light of Encana's historical experience and its perception of historical trends. Risks and uncertainties include: integration of Encana and Newfield and the ability to recognize the anticipated benefits; ability to generate sufficient cash flow to meet obligations; commodity price volatility; ability to secure adequate transportation and potential pipeline curtailments; variability and discretion to declare and pay dividends, if any; amount and timing of share repurchases; timing and costs of well, facilities and pipeline construction; business interruption, property and casualty losses or unexpected technical difficulties; counterparty and credit risk; 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 in marketing operations; risks associated with technology; changes in or interpretation of laws

  • r regulations; risks associated with existing and potential lawsuits and regulatory actions; impact of disputes arising with partners, including suspension 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 estimates of recoverable quantities and future net revenue; 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, as described in Encana’s most recent Annual Report on Form 10-K and Quarterly 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. 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 or revise any FLS. 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

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

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17

ADVISORY Y REGARDING G OIL & GAS INFORMATION

All reserves estimates 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 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. Detailed Canadian and U.S. protocol disclosure 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 estimates are contained in the Form 51-101F1. For additional 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 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. Encana uses the terms play and resource play. 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. As used by Encana, estimated ultimate recovery (“EUR”) has the meaning set out jointly by the Society of Petroleum Engineers and World Petroleum Congress in the year 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 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

  • f 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, EUR 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 EUR. Estimates of Encana potential gross inventory locations, including premium return well inventory, include proved undeveloped reserves, probable undeveloped reserves, un-risked 2C contingent resources and unbooked inventory locations. As of December 31, 2018, on a proforma basis, 2,012 proved undeveloped 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) have been categorized as either reserves or contingent resources. Unbooked locations have not been classified as either reserves or resources and are internal estimates that have been identified by management as an estimation of Encana's multi-year potential drilling activities based on evaluation of applicable geologic, seismic, engineering, production, resource and acreage information. There is no certainty that Encana 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 may 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

  • ne 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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SLIDE 18

18

NO NON-GAA GAAP MEASU ASURES

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, including reconciliations, see the Company’s website and Encana’s most recent Annual Report as filed on SEDAR and EDGAR. Non-GAAP measures include:

  • Non
  • n-GA

GAAP Cash sh Fl Flow, Non

  • n-GAA

AAP Cash sh Flow

  • w Pe

Per Sh Share (CFPS), Non

  • n-GAA

AAP Fre ree Cash sh Flow

  • w, Non
  • n-GAA

AAP Fre ree Cash sh Flow

  • w Yi

Yield an and Non

  • n-GAAP

AAP Cash sh Fl Flow Margi rgin – Non-GAAP Cash Flow (or Cash Flow) is defined as cash from (used in) operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and current tax on sale of assets. Non-GAAP CFPS is Non-GAAP Cash Flow divided by the weighted average number of common shares outstanding. Non-GAAP Free Cash Flow (or Free Cash Flow) is Non-GAAP Cash Flow in excess of capital expenditures, excluding net acquisitions and divestitures. Non-GAAP Free Cash Flow Yield is annualized Non-GAAP Free Cash Flow compared to current market capitalization. Non-GAAP Cash Flow Margin is Non-GAAP Cash Flow per BOE of production. 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.

  • To

Tota tal Cost sts per er BO BOE is defined as the summation of production, mineral and other taxes, upstream transportation and processing expense, upstream operating expense and administrative expense, excluding the impact of long-term incentive and restructuring costs, per BOE of production. Management believes this measure is useful to the company and its investors as a measure of operational efficiency across periods.

  • Non
  • n-GA

GAAP Ope perati ting Earn rnings gs (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 U.S. tax reform, and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.

  • Net

et Debt, bt, Adjusted EBITD TDA, A, Net et Deb ebt to to Adjusted EBITDA DA an and Annu nnualized Lever everage – 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. Annualized leverage is defined as net debt to adjusted EBITDA based on Adjusted EBITDA generated in the period on an annualized basis.

  • Ope

perati ting Margin in/Ope peratin ting Cash sh Flo low/Ope peratin ting Netback ack – Product revenues less costs associated with delivering the product to market, including production, mineral and other taxes, transportation and processing and

  • perating

expenses. When presented

  • n

a per BOE basis, Operating Margin/Operating Cash Flow/Operating Netback is defined as indicated divided by average barrels

  • f
  • il

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).

  • Fre

ree Ope peratin ting Cash sh Fl Flow – Operating Cash Flow in excess of capital investment, excluding net acquisitions and divestitures.

  • Up

Upstre ream Ope perati ting Cash sh Fl Flow – Upstream Operating Cash Flow is a measure that adjusts the Canadian, USA and China Operations revenues for production, mineral and other taxes, transportation and processing expense, and operating expense. Management monitors Upstream Operating Cash Flow as it reflects operating performance and measures the amount of cash generated from the company’s upstream operations.

  • Up

Upstre ream Ope peratin ting Fre ree Cash sh Flow

  • w – is defined as Upstream Operating Cash Flow in excess of capital

investment, excluding net acquisitions and divestitures.

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