ENCANA CORPORATION Strategic Combination with Newfield Exploration Co. Creating a Leading Multi-Basin Company November 1, 2018

STRATEGIC COMBINATION WITH NEWFIELD EXPLORATION Transaction Creates Leading Multi-Basin Company Transaction Overview Core-of-the-Core Positions in 3 Top North American Plays – Consideration: All Stock—2.6719 shares of Encana for each share of Newfield – $7.7 billion transaction value (incl. Newfield net debt of $2.2B) Montney – Subject to approval by Encana and Newfield shareholders and regulatory 201 MBOE/d approval 22% liquids – Closing expected in Q1 2019 Duvernay 16 MBOE/d Immediately following closing expect to expand buyback to $1.5B* 43% liquids and increase dividend by 25%** Williston 21 MBOE/d • Core acreage in heart of STACK and SCOOP within Anadarko Basin 86% liquids – Large contiguous acreage position with stacked pay across multiple commercial and prospective zones Uinta – ~360,000 net acres with ~6,000 gross risked locations 19 MBOE/d 84% liquids STACK/SCOOP – World class resource—3.0 BBOE of net unrisked resource 144 MBOE/d – Ideal fit for application of cube development model 60% liquids Arkoma Significant growth underpinned by large, contiguous positions in 3 81 MMcf/d top North American Plays Eagle Ford Permian 50 MBOE/d – Assets in Eagle Ford, Williston, Duvernay and Uinta generate free operating 99 MBOE/d 82% liquids cash flowŦ 85% liquids *Post closing and subject to regulatory approval. Includes $250MM in shares purchased under existing NCIB program; **Post-closing and subject to Board approval ŦNon-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.

TRANSACTION EXPANDS SHAREHOLDER RETURNS Efficiency, Scale & Accretion Combined • Combined Company Overview Enterprise Value ($B)1 $13.3 $6.3 $19.6 Q3 2018 Last Twelve Months $2.2 $1.4 $3.6 – Large, high quality positions in 3 top North American Adjusted EBITDAŦ ($B) plays – Accretive multi-year growth in cash flow per share Q3 2018 Production2 (CFPS)Ŧ and free cash flow (FCF)Ŧ Oil & Condensate (Mbbls/d) 136 74 210 – >$250MM expected annual synergies derived from cube NGLs (Mbbls/d) 42 48 90 development and G&A savings Total Liquids (Mbbls/d) 178 122 300 – 64% increase in Adjusted EBITDAŦ, 54% increase in oil Liquids % 47% 61% 52% and condensate production, 85% increase in proved reserves Gas (MMcf/d) 1,197 462 1,659 – Further bolsters a strong balance sheet and credit profile Total Production (Mboe/d) 378 199 577 – Scale—2nd largest North American unconventional company 2017 YE Proved Reserves2 795 678 1,473 (MMBOE) 1As at Oct. 31, 2018, EV= Market Capitalization + Debt Net of Cash 2Newfield excludes China volumes ŦNon-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website. 3

ENCANA – A LEADING MULTI-BASIN COMPANY Delivering Quality Growth and Shareholder Returns Increasing Return of » Dividend increase of 25% expected in 2019* Capital to » Expand existing buyback to $1.5 billion post closing in 2019** Shareholders Accretive to CFPSŦ & » Accretive to anticipated 2019 CFPSŦ and multi-year FCFŦ Free Cash FlowŦ » Immediate increase in total liquids to > 50% total production » Core-of-the-core large scale positions in 3 top North American plays Asset Quality » Permian, STACK/SCOOP and Montney » $250 million in expected annual synergies from cube development and G&A Synergies and Scale » #2 N.A. unconventional E&P—Q3/18 pro forma ~575 MBOE/d, ~300 Mbbls/d liquids » Credit positive: return of capital to shareholders funded from FCFŦ and cash on hand *Post-closing and subject to Board approval. **Post closing and subject to regulatory approval. Includes $250 million in shares purchased under existing buyback program. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website. 4

TOP POSITIONS IN THE MOST ECONOMIC RESOURCE PLAYS Encana’s Core-of-the-Core Multi-Basin Portfolio 80 ~90% of pro forma production from large /bbl) 70 scale, low cost basins ( $ en 60 breakev 50 WTI 40 cycle 30 -Half 20 10 0 Source: RSEG as of July 2018; Includes onshore unconventional resource plays with over 250 MBOE/d of total production per RSEG; Assumes 20:1 WTI:Henry Hub ratio, C$2.00/GJ AECO, and 1.30 C$/US$ FX. Permian based on the average of the Midland, Delaware, CBP, and NW Shelf as disclosed by RSEG. STACK/SCOOP based on the average of STACK and SCOOP as disclosed by RSEG; *Based on the Encana Montney breakeven from RSEG’s July 2018 Montney map; adjusted because of the differences in economics across various positions in the Montney 5

WORLD CLASS STACK/SCOOP POSITION Enhancing Our Multi-Basin Portfolio • World class resource—3.0BBOE of net un-risked resource • Acreage represents the core of the play • Large contiguous acreage position with stacked pay across multiple commercial and prospective zones – ~360,000 net acres – ~6,000 gross risked locations – 144 MBOE/d Q3 2018 production, >60% liquids • Core-of-the-core STACK position in SW Kingfisher county • Cube development is the next phase of commercial development 6

HIGH QUALITY RESOURCE POTENTIAL The Right Rocks • Thick, porous, laterally extensive reservoir – Fits cube development model with 2-4 target benches – Oil saturated across a wide oil window • Pressure increases deliverability – Over-pressured reservoir, targets >7,500’ TVD – High pressure wells produce 1,000-3,000 bbls/d; competes with North America’s best plays N NW Extension STACK MERGE SCOOP S N Springer NW Extension Anadarko Basin Meramec STACK Osage MERGE na WDFD SCOOP WDFD SCOOP S 200 Ft 7

2ND LARGEST UNCONVENTIONAL PRODUCER IN NORTH AMERICA Strategic Combination Creates Immediate Scale MBOE/d 700 600 Pro forma Q3/18 production ~575 MBOE/d 500 400 300 200 100 0 Peer #1 Peer #2 Peer #3 Peer #4 Peer #5 Peer #6 Peer #7 Peer #8 Peer #9 Peer #10 Peer #11 Source: Company disclosure and FactSet; Peers include: EOG, APA, DVN, APC, RRC, OXY, PXD, MRO, CLR, CXO, XEC 8 Note: Q2 production shown on an “as reported” basis, excluding the impact of acquisitions and divestitures. Peer set excludes companies with <30% liquids. Data bars exclude offshore, oil sands and international production.

SYNERGY SUMMARY Scale and Cube Development Driving Material Synergies • Cube development ideal for commercial development in STACK/SCOOP • Cube development synergies of ~$1MM/well or ~$125MM/year – Rapid transfer of initiatives currently employed in Permian and Montney Cubes – Improved cycle time – multi-well pad drilling improvement – Supply management savings – self sourcing raw materials, scale, multi-basin market knowledge – Pad efficiencies – facilities, construction, cycle time – Completions – pumping efficiency and high intensity completion design • G&A synergies capture significant savings ($125MM/year) • Total of ~$250MM of expected annual synergies; >$1B over 4 years • Expect to hit run-rate synergies in 2H 2019 9

SYNERGY SUMMARY High Confidence Synergies Annualized G&A Costs ($MM/yr) Cube Development Synergies in STACK/SCOOP $1MM/well savings x 125 net wells = ~$125MM/year Current Well Cycle Time Pad Supply Completions Well Cost Cost Efficiencies Management Post Synergies ~ $125MM/year in annual G&A synergies for the ~$125MM/year well cost synergies combined business (costs down by at least $1MM/well) 10

STRONG INVESTMENT GRADE COMPANY Credit Positive Transaction • Consistent with ECA mid-cycle leverage targets — 2019F net debt to Adjusted EBITDAŦ at target of ~1.5x Encana Newfield Combined • Dividend and share repurchases funded from free cash flowŦ and cash on hand Debt Outstanding $4,211MM $2,450MM $6,661MM • Combination of two strong balance sheets Annual Debt enhances credit profile $267MM $137MM $404MM Interest — Enhanced scale and production metrics Weighted average 6.34% 5.59% 6.06% — Multi-basin asset profile mitigates single basin risk coupon • Encana stand alone liquidity of $4B on existing Weighted average undrawn credit facilities 13 Years 5 Years 10 Years term • Well-dispersed debt maturity profile S&P / BBB- / BB+ / • Cost savings from elimination of Newfield credit Fitch / Moody’s BBB-/ Ba1 BBB- / Ba1 facility Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website 11

FURTHER UPSIDE ACROSS CORE PILLARS OF OUR STRATEGY Levers of Additional Value TOP TIER MARKET • Top tier resource RESOURCE FUNDAMENTALS – High quality multi-basin portfolio provides investment options – Best rocks continue to get better – adds scale, inventory depth and upside • Operational excellence – Optimized completion design from multi-basin experience • Market fundamentals BALANCE SHEET STRENGTH – Marketing upside from enhancing realized price and reducing risk • Capital allocation – Multi-basin portfolio benefits – Optimization of non-op acreage in STACK/SCOOP • Balance sheet strength – Further strengthens balance sheet and reduces cost of capital OPERATIONAL CAPITAL EXCELLENCE ALLOCATION 12

ENCANA Q3 RESULTS Delivering Efficient Growth in 2018 with Free Cash FlowŦ • Expect to meet or beat 2018 targets and generate free cash flowŦ – Liquids growth driving higher margins and free cash flowŦ – Permian production expected to exceed 100 MBOE/d in Q4, revised target of 40% annualized production growth – Montney liquids currently ~55 Mbbls/d, on track to deliver target of 55-65 Mbbls/d in Q4 – Pipestone liquids hub on-stream late Q3 • Generated $66MM of free cash flowŦ in Q3 and expect full year free cash flowŦ – 2018F cash flow marginŦ expected to be >$16/BOE • Marketing strategy ensures market access and maximizes realized price – Permian oil price realizations at 101% of WTI in Q3 – Canadian gas price realizations at 86% of NYMEX or 240% of AECO in Q3 • Strong operational and financial performance across the portfolio – Per BOE operating costs and T&P down significantly – Balance sheet strength – expect to be at target of ~1.5x net debt to adjusted EBITDAŦ by year end Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website. 13

STRONG FINANCIAL PERFORMANCE Q3 Highlights Q3 2018 • FCFŦ positive in Q3 – Generated $66MM of FCFŦ Net Earnings ($MM) 39 – Expect full year positive FCFŦ Operating EarningsŦ ($MM) 163 – Cash flow marginŦ of $16.93/BOE in Q3 and expect >$16/BOE Cash FlowŦ ($MM) 589 for 2018 - $ per share, diluted 0.62 – Core assets each generating positive free operating cash flowŦ Capital Investment ($MM) 523 in 2018 Free Cash FlowŦ 66 • Shareholder returns ongoing Upstream Operating Cash FlowŦ, Incl. Hedge 691 – Completed $250MM of share repurchases YTD ($MM) • Balance sheet strength Cash and cash equivalents ($MM) 615 – Substantial reduction in net debt to EBITDA quarter over quarter Net Debt to Adjusted EBITDAŦ 1.6x – Expect leverage to be at target of ~1.5x at year end 2018 Weighted Avg. Shares Outstanding, millions 955.1 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website. 14

THE STRATEGY IS WORKING Liquids Growth + Margin Growth = Cash FlowŦ Growth • Focused liquids growth Q3 Q2 â^† – 23 Mbbls/d increase in liquids in the quarter (15% increase) 2018 2018 – >75% of liquids growth from oil and condensate Liquids Production (Mbbls/d) 179 155 15% – Liquids mix continues to increase, now at 47% Total Production (MBOE/d) 378 338 12% • Midstream and marketing program increases Liquids Mix (%) 47% 46% 1% realized prices, reduces risk Realized Price, ex Hedge ($/BOE) 33.30 31.93 4% – Sales market diversification Upstream Operating Expense • Cost control 3.07 3.40 (10%) ($/BOE)* – Relentless focus on efficiency and greater scale is driving per Transportation & Processing ($/BOE) 7.05 7.73 (9%) BOE costs lower – upstream opex* and T&P down 10% and 9%, respectively Operating MarginŦ, ex Hedge ($/BOE) 21.72 19.21 13% – Higher realized pricing goes directly to margin Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website; 15 *Excludes long-term incentives

2018 GUIDANCE UPDATE Free Cash FlowŦ Positive in 2018 • On track to deliver liquids growth 2018F Updated Guidance • 2018F cash flow marginŦ >$16/BOE ($14/BOE original) Capital Investment ($ billion) 2.0 – Driven by high value liquids growth Total Liquids (Mbbls/d) 165 – 175 Cost structure in excellent shape Natural Gas (MMcf/d) 1,150 – 1,250 – T&P expected to be ~$25 million lower than original guidance – Operating costs and admin expenses within guidance ranges Total Production (MBOE/d) 360 – 380 Capital investment of $2 billion Upstream Operating Expense* ($/BOE) 3.00 – 3.30 – $55 million of capital associated with divested assets (San Juan, Transportation & Processing ($/BOE) 7.20 – 7.40 Pipestone Liquids Hub) returned through disposition proceeds – Minor cost increase from diesel, steel tariffs and delayed local sand Administrative Expense* ($/BOE) 1.25 – 1.50 Production, Mineral & Other Taxes 3.25 – 3.75% % of Revenue** Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website; *Excludes long-term incentives; **Upstream revenue excluding risk management activities 16

ENCANA – A LEADING MULTI-BASIN COMPANY Delivering Quality Corporate Returns Core-of-the-Core Positions in 3 Top North American Plays • Strategic combination with Newfield to create a leading North American unconventional company • Increasing return of capital to shareholders Montney — Expand buyback to $1.5 billion* Duvernay — 25% dividend increase** • Generating quality growth Williston • Track record of efficient operations • Core-of-the-core large scale positions in 3 top North American plays Uinta • Accretive to Encana’s 5 year plan STACK/SCOOP Arkoma Permian Eagle Ford • *Post closing and subject to regulatory approval. Includes $250 million in shares purchased under existing NCIB program. • **Post-closing and subject to Board approval.

IMPORTANT INFORMATION FOR INVESTORS AND SHAREHOLDERS This communication is not intended to and does not constitute an offer to sell or the solicitation of an offer to subscribe for or buy or an invitation to purchase or subscribe for any securities or the solicitation of any vote or approval in any jurisdiction, nor shall there be any sale, issuance or transfer of securities in any jurisdiction in contravention of applicable law. In connection with the proposed transaction between Encana and Newfield, Encana will file with the U.S. Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4 that is expected to include a Joint Proxy Statement of Encana and Newfield that will also constitute a Prospectus of Encana (the “Joint Proxy Statement/Prospectus”). Encana and Newfield plan to mail to their respective shareholders the definitive Joint Proxy Statement/Prospectus in connection with the transaction. INVESTORS AND SECURITY HOLDERS OF ENCANA AND NEWFIELD ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT ENCANA, NEWFIELD, THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain free copies of the Joint Proxy Statement/Prospectus (when available) and other documents filed with the SEC by Encana and Newfield through the website maintained by the SEC at www.sec.gov. Investors will also be able to obtain free copies of the Joint Proxy Statement/Prospectus (when available) and other documents filed with Canadian securities regulatory authorities by Encana, through the website maintained by the Canadian Securities Administrators at www.sedar.com. In addition, investors and security holders will be able to obtain free copies of the documents filed with the SEC and Canadian securities regulatory authorities on Encana’s website at www.encana.com or by contacting Encana’s Corporate Secretary. Copies of the documents filed with the SEC by Newfield will be available free of charge on Newfield’s website at www.newfield.com. PARTICIPANTS IN MERGER SOLICITATION Encana, Newfield and certain of their respective directors, executive officers and employees may be considered participants in the solicitation of proxies in connection with the proposed transaction. Information regarding the persons who may, under the rules of the SEC, be deemed participants in the solicitation of the shareholders of Encana and the stockholders of Newfield in connection with the transaction, including a description of their respective direct or indirect interests, by security holdings or otherwise, will be included in the Joint Proxy Statement/Prospectus described above when it is filed with the SEC and Canadian securities regulatory authorities. Additional information regarding Encana’s directors and executive officers is also included in Encana’s Notice of Annual Meeting of Shareholders and 2018 Proxy Statement, which was filed with the SEC and Canadian securities regulatory authorities on March 23, 2018, and information regarding Newfield’s directors and executive officers is also included in Newfield’s 2018 Proxy Statement, which was filed with the SEC on March 29, 2018. These documents are available free of charge as described above. All amounts in this presentation are in U.S. dollars unless otherwise specified. 18

FUTURE ORIENTED INFORMATION 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: • timing of closing of the transaction • expected transportation and processing capacity, commitments, curtailments and restrictions, including flexibility of • the expectation that the closing conditions, including shareholder approvals and regulatory approvals, will be satisfied commercial arrangements and costs and timing of certain infrastructure being operational • anticipated benefits from the transaction • anticipated reserves and resources, including product types and stacked resource potential • anticipated production and commodity mix as a result of the transaction • anticipated third-party incremental and joint venture carry capital • anticipated synergies from the transaction • ability to manage costs and efficiencies, including drilling and completion, operating, corporate, transportation and • expectation that the transaction is accretive to certain metrics in Encana’s five year plan processing, staffing, services and materials secured and supply chain management • anticipated capital program, including focus of development and allocation thereof, number of wells on stream, level of • expected net debt, net debt to adjusted EBITDA, target leverage, financial capacity and other debt metrics capital productivity, expected return and source of funding • growth in long-term shareholder value, options to maximize shareholder returns and timing thereof • well performance, completions intensity, location of acreage and costs relative to peers and within assets • commodity price outlook • anticipated production, including growth from core assets, cash flow, free cash flow, capital coverage, payout, profit, net • outcomes of risk management program, including exposure to commodity prices and foreign exchange, amount of present value, rates of return, recovery, return on capital employed, production and execution efficiency, operating, hedged production, market access, market diversification strategy and physical sales locations income and cash flow margin, and margin expansion, including expected timeframes • management of balance sheet and credit rating, including access to sources of liquidity and available cash • number of potential drilling locations (including premium return inventory and ability to add to or consume such • execution of strategy and future outlook in five-year plan, including expected growth, returns, free cash flow, projections inventory), well spacing, number of wells per pad, decline rate, rig count, rig release metrics, focus and timing of drilling, based on commodity prices and use of cash therefrom anticipated vertical and horizontal drilling, cycle times, commodity composition, gas-oil ratios and operating performance • environmental, health and safety performance compared to type curves • advantages of a multi-basin portfolio • running room and scale of assets, including its competitiveness and pace of growth against peers • anticipated dividends or changes thereto following closing • pacesetting metrics being indicative of future well performance and costs, and sustainability thereof • impact of changes in laws and regulations, including recent U.S. tax reform • timing, success and benefits from innovation, cube development approach, advanced completions design, scale of • anticipated size of share repurchase program, including amount and number of shares, anticipated timeframe and development, high-intensity completions and precision targeting, and transferability of ideas benefits of program Readers are cautioned against unduly relying on FLS which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: ability to satisfy closing conditions, regulatory and shareholder approvals, enforceability of transaction agreements, 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: integration of Encana and Newfield and the ability to recognize the anticipated benefits from the combination of Encana and Newfield, ability to obtain required shareholder and regulatory approvals for the transaction, timing thereof and risk that such regulatory approvals may result in the imposition of conditions that could adversely affect the expected benefits of the transaction, risk that the conditions to the transaction are not satisfied on a timely basis or at all and the failure of the transaction to close for any other reason; risks relating to the value of the Encana common shares to be issued in connection with the transaction; disruption to Encana’s and Newfield’s respective businesses that could result from the announcement of the transaction, 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 and timing of purchases, if any, pursuant to the share repurchase program; 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 a credit rating, including to refinance debt required to be repaid because of a downgrade, 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. References in this presentation to “Newfield’ refer to Newfield Exploration Company may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships of Newfield Exploration Company, and the assets, activities and initiatives of such subsidiaries. 19

ADVISORY REGARDING OIL & GAS INFORMATION All Encana reserves and economic contingent resources estimates in this presentation 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. 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. Information relating to Newfield locations and resources is based on Newfield public disclosure. 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 Encana potential gross inventory locations (not including locations of Newfield Exploration Company), including premium return well inventory, include proved undeveloped reserves, probable undeveloped reserves, un-risked 2C contingent resources and unbooked inventory locations. Approximately 40 percent of such locations are booked as of December 31, 2017 and are in respect of gross locations that have been categorized as either reserves or contingent resources, including 744 proved undeveloped locations, 1,399 probable undeveloped locations and 6,857 un-risked 2C contingent resource locations (in the development pending, development on-hold or development unclarified project maturity sub-classes). 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 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. 20

NON-GAAP MEASURES Certain measures in this presentation do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other companies. These measures have been provided for meaningful comparisons between current results and other periods and should not be viewed as a substitute for measures reported under U.S. GAAP. For additional information regarding non-GAAP measures, 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-GAAP Cash Flow, Non-GAAP Cash Flow Per Share (CFPS), Free Cash Flow and Non-GAAP Cash Flow Margin – Non-GAAP Cash • Upstream Operating Cash Flow, including Risk Management – Upstream Operating Cash Flow, including Risk Management is a measure 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- that adjusts the Canadian and USA Operations revenues for production, mineral and other taxes, transportation and processing expense, 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 operating expense and includes the impacts of realized risk management activities. Management monitors Upstream Operating Cash Flow, common shares outstanding. Free Cash Flow is Non-GAAP Cash Flow in excess of capital expenditures, excluding net acquisitions and including Risk Management as it reflects operating performance and measures the amount of cash generated from the company’s upstream divestitures. Non-GAAP Cash Flow Margin is Non-GAAP Cash Flow per BOE of production. Management believes these measures are useful to operations including risk management activities. the company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, • Non-GAAP Operating Earnings (Loss) – is defined as Net Earnings (Loss) excluding non-recurring or non-cash items that management and are an indication of the company’s ability to generate cash to finance capital programs, to service debt and to meet other financial believes reduces the comparability of the company’s financial performance between periods. These items may include, but are not limited to, obligations. These measures may be used, along with other measures, in the calculation of certain performance targets for the company’s unrealized gains/losses on risk management, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on management and employees. divestitures and gains on debt retirement. Income taxes may include valuation allowances and the provision related to the pre-tax items listed, • Forward looking Non-GAAP Cash Flow, Free Cash Flow and Cash Flow Margin: 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 ~$16.00/BOE Cash Flow Margin (2018) estimated annual effective income tax rate. • 2018 Cash From Operating Activities is expected to be approximately $2.0B with approximately $150M 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 $2.15B. This amount divided by the mid-point of the 2018 production guidance of 370 MBOE/d equals the expected Cash Flow Margin of ~$16.00/BOE • 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. • 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 Margin/Operating Cash Flow/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. 21