3Q19 3Q19 Confer Conference Call ence Call Octobe October 31, - - PowerPoint PPT Presentation
3Q19 3Q19 Confer Conference Call ence Call Octobe October 31, 2019 r 31, 2019 2 To Todays C Call 1 1 2 2 3 Strong St ng 3Q 3Q fi financia nancials and ls and U.S. Dom S. Domicil ile & Br & Brand 2020 Outlook
Octobe October 31, 2019 r 31, 2019
2
St Strong ng 3Q 3Q fi financia nancials and ls and YTD 2019 highl YTD 2019 highlights hts
to Anadarko basin performance
U.S. Dom
ile & Br & Brand
passive capital markets
2020 Outlook 2020 Outlook
competitive liquids growth
3
3 Q H H I G H L I G H T S G H L I G H T S
Net Earn Net Earnings ngs
$149 MM $149 MM
$0.11 / share
Cash Flo Cash Flow Ŧ
$817 MM $817 MM
$0.62 / share
Fr Free Cash Flo ee Cash Flow Ŧ
$251 MM $251 MM
Continued FCF generation in 4Q19
Bu Buyback
~197 MM ~197 MM
~13% of O/S shares
Div Divide dend nd
+25% YTD +25% YTD
Liquid idity ity Ŧ
~$3.4B ~$3.4B
~10-yr avg Bond Tenor, Investment Grade
Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website
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ised G&A synergy e nergy estim timate p te post acquisition sition for 3 3rd t time me
ised ‘19 p 9 production tion g guidance w ce while c ile capital u tal unchanged nged
Returned cash to shareh cash to sharehol
rs
~$230 MM of MM of YTD YTD free cash flow free cash flow Ŧ, exclu cludin ing a g acquisition sition & & restru structurin cturing c g costs
Complete ted d sale sale of non
core China & Arkoma China & Arkoma assets assets
Enhanced leade leadersh ship for long for long-term succes m succession and n and conti continuity ty
ced plans to e establish blish c corporate d
cile in the e United ed S Stat ates es t to unlock s k shareholder der v value
Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website Note: Transaction and restructuring costs of $167 MM. Free cash flow yield calculated using Non-GAAP free cash flow divided by market capitalization at end of period
50 100 150 200 250
2018 Full Year 2019 Q3 YTD
Pr Proven ven Fr Free Cas ee Cash Flo Flow Gener Generation
Addi Additional al FCF in 4Q19 FCF in 4Q19 2.5% 2.5% 4.2% 4.2% FCF Yield FCF excl. acquisition costs
$140 MM $140 MM ~$230 MM ~$230 MM
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Producti
MBOE/D
Strong Ho ng Howa ward County County r result sults
Continued oper erationa ional e l execution ecution
Permia Permian
Producti
MBOE/D
Williston
le Fo Ford: rd: Strong well performance and operational execution continues to drive free cash flow
Duvernay: Recent 2-well pad averaging 750 bbl/d of condensate per well over first 150 days
Producti
MBOE/D
$1.4 MM reducti duction n in in D&C costs D&C costs
Strong, cons ng, consiste istent well r nt well result sults gener s generati ting high r ng high returns turns
Producti
MBOE/D
Condensate conti te continues nues to to r real alize ~90% of e ~90% of WTI WTI
Shorter cycle times accelerati ting pr ng proj
ect payouts uts
Anadark Anadarko Base Assets Base Assets Montne Montney
Note: Base assets include Eagle Ford, Williston, Duvernay and Uinta
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A N A D A R K O A N A D A R K O
Current pr ent producti
162 MBOE/ MBOE/D
Premium B ium Black O ack Oil ac il acreage age an and l d leading e ading execution ution delivering livering t top t p tier r er returns turns
and >2X increase in pumped fluid volumes 3Q19 vs ’18
50 100 150 60 120 180 240 300 360
Mbbls (Oil) Producing Days
All 2019 STACK Wells (103 Gross Meramec) (1)
2019 STACK Production YTD STACK 2019 TC
35% Reducti 35% Reduction in YTD Cycle Times (da n in YTD Cycle Times (days)
Legacy NFX
Q1 Q2 Q3 145 145 112 112 91 91
(1) Normalized to 10,000’ lateral length
Fast Faster er cyc cycle time times = = lo lower wer co cost sts, acce accelerate lerated l d learn arnings, ngs, and h higher r er returns rns PR PROVING ING O OPER ERATION IONAL EX AL EXCELL CELLEN ENCE
1Q 2Q 3Q
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A N A D A R K O A N A D A R K O
Oil outpe tperfo formance driving r rmance driving returns turns
strong results at 6 – 8 wells per section with similar job size
Initial ECA Cube Style Completions (6 – 8 wells per section)
50 100 150 60 120 180 240 300 360
Mbbls (Oil)
Encana Cube Wells (40 Gross) 1
50 100 150 200 250 300 60 120 180 240 300 360
MBOE Producing Days
Encana Cube Wells (40 Gross) 1
Pre ECA (24 Wells) Cube Dev (40 Wells) STACK 2019 TC
(1) Normalized to 10,000’ lateral length
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ST STACK Day W K Day Webcast & bcast & Field Field T Tour ur
January 29 & 30, 2020 29 & 30, 2020
Additional dat data at ti at time of
vent MAR MARK Y YOUR UR CALE CALENDAR AR
Driving C ing Competitive itive r returns rns
Contiguous core acreage in heart of play Favorable royalty structure Industry leading D&C costs Advantaged marketing arrangements Efficient cost structure at scale
ST STACK r K returns compete with turns compete with Perm Permian: ian: >50% IRR (B >50% IRR (BTAX) X)
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Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website (1) Shareholder Q&A available on our website. Preliminary proxy statement / prospectus to be filed on EDGAR and SEDAR in early November 2019
Why Why? Highlights ighlights
Shareholder friendly providing additional liquidity & capital market access
Aligns Encana with U.S. domiciled peers
Leading unconv. oil and condensate company
Reflects transformation to the “New E&P”
Low cost opportunity to unlock value 1
SHAREHOLDE SHAREHOLDER V VOTE EARL TE EARLY 2020 Y 2020
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CAN U.S.
Note: Public Filings and FactSet market data as of June 30, 2019 (1) Morningstar market data as of September 30, 2019. Reflects U.S. and Canadian Exchange Traded Fund assets as a proxy for equity market size comparison (2) Represents average passive fund ownership of U.S. Peers. U.S. Peers consist of APA, CLR, COG, CXO, DVN, EOG, MRO, NBL, PXD
Equit Equity Mark Market et Size Size 1 Shar Shareh eholder Frien r Friendly ly
ases e equity l ty liquidity & idity & capital m tal mark rket a et access
indices
Leve vels pl playing fie g field wit d with compa comparable peer peers
enables access to larger passive investment capital markets
dual l listed o
NYSE & & TSX
No change to operations or str ns or strate tegy gy
Sharehol holder vote earl er vote early 2020 2020
~30% ~30%
Passive Peer Passive Peer Owners Ownershi hip 2
<10% <10%
ECA ECA U.S. Peers .S. Peers
U.S. Peers benefit from larger passive ownership U.S. domicile provides additional access to a substantially larger U.S. equity market
+20% +20%
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* Completion of the name change (including ticker), share consolidation and U.S. domestication subject to shareholder, stock exchange and court approvals; expected in early 2020
Capital Discipline Agile and Adaptive Innovation and Technology Socially Responsible Sustainable Business Model Culture of Excellence
To mak make modern life possible modern life possible for all. for all.
NYSE: OVV* TSX: OVV*
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2013 3Q19 2013 Adj '13 2Q+3Q
Scale ale & & capital d pital discipline ipline p providing r iding recurring f rring free cash f flow Ŧ gener generation Liqui Liquids focus e s focus expandi xpanding cash flo g cash flow mar margin in Ŧ (~55% liqu % liquids pr ids produc
tion) Commi Commitmen ent to r t to retu turn of
cash – – $1.25B $1.25B bu buyback & k & +25% di +25% divi vidend YTD YTD Str Strong balanc balance sheet e sheet and de-le and de-lever eragi aging pr g prof
ile (Inv e (Investment estment Gr Grade & ade & $3.4B of $3.4B of liqui liquidit ity)
Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website (1) Non-GAAP reconciliations provided on Company’s website and in Annual Filing. “2013 at current prices” is illustrative and reflects adjusted cash flow using reported FY2013 Gas and Liquids production volumes at 2Q19 and 3Q19 average benchmark prices of ~$58 / BBL WTI and ~$2.44 / MMBTU HHUB. This illustrative metric reflects what ECA directionally could have looked like with its 2013 commodity mix and cost structure in today’s price environment
Str Strong Bal ng Balance Sheet & nce Sheet & Cash Fl Cash Flow Subst Substantial SEC l SEC Pr Proved ed Reserv Reserves es
85 85% Gas Gas
2013 2013 Today day
55 55% Liquid Liquids ~1.5 BBOE ~2.0 BBOE
Oil & l & Condens ndensate Gr te Growth th Cash Flo Cash Flow 1,
1,Ŧ
Debt Debt / / Adj Adj Cap Cap Ŧ
$2.6B $2.6B $3.4B $3.4B
2013 3Q19
2013 2013 3Q19
36% 36% 28% 28% ~$0.8B ~$0.8B 1
2013 at current prices 2Q + 3Q19 Annualized
237 237 35 35
Mbbls/d
13
2020 Outlook 2020 Outlook
Gener Generate free cash te free cash flow and flow and modes modest liquids liquids gro growth at th at mid- mid- cycl cycle prices e prices
A
Sustainabl Sustainable divi divide dend nd growth growth 1 De- De-leveragi aging g the balance sheet the balance sheet Improv Improving returns ing returns through capital efficiency through capital efficiency Continued capital Continued capital discipline and discipline and efficient efficient operations
Prior Prioriti tize free cash free cash flow flow over
growth if growth if price prices soften soften
B
(1) All dividend declarations are subject to Board approval
202 2020 Fr Free Cash Flo ee Cash Flow is top prio is top priority
2020: Fr 2020: Free Cash Fl ee Cash Flow to to Bal Balance Sheet nce Sheet Funda Fundamenta tal Princ Principl ples es
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Profitable Business at a Compelling Valuation
Fr Free Cash ee Cash Flo Flow Capital Disciplin Capital Discipline Balanc Balance Sheet Str e Sheet Strengt ngth Divid Dividend nd Gr Growth Multi- i-Bas Basin P n Portf rtfolio w lio with S th Scale ale Liqu Liquids Gr s Growth
Octobe October 31, 2019 r 31, 2019
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This communication is not intended to and does not constitute an offer to sell, buy or exchange or the solicitation of an offer to sell, buy or exchange any securities or the solicitation of any vote or approval in any jurisdiction, nor shall there be any sale, purchase, or exchange of securities or solicitation of any vote or approval in any jurisdiction in contravention of applicable law. In connection with the proposed corporate reorganization that includes, among other things, the redomicile, Encana will cause its subsidiary 1847432 Alberta ULC, a predecessor to Ovintiv Inc. (“Ovintiv”), to file a registration statement on Form S-4, which will include Ovintiv’s prospectus as well as Encana’s proxy statement (the “Proxy Statement/Prospectus”), with the U.S. Securities and Exchange Commission (the “SEC”) and Canadian securities regulatory authorities. Encana plans to mail the definitive Proxy Statement/Prospectus to its shareholders and holders of its equity incentives in connection with the proposed corporate reorganization. INVESTORS AND SECURITYHOLDERS OF ENCANA ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC AND CANADIAN SECURITIES REGULATORY AUTHORITIES CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT ENCANA, NEWCO, THE CORPORATE REORGANIZATION AND RELATED MATTERS. Investors and securityholders will be able to obtain free copies of the Proxy Statement/Prospectus (when available) and other documents filed with the SEC by Encana or Ovintiv through the website maintained by the SEC at www.sec.gov. Investors and securityholders will also be able to
maintained by the Canadian Securities Administrators at www.sedar.com. In addition, investors and securityholders 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. Pa Part rticipant ipants in the Solicit
ion Encana and certain of its directors, executive officers and employees may be considered participants in the solicitation of proxies in connection with the proposed corporate
with the corporate reorganization, including a description of their respective direct or indirect interests, by security holdings or otherwise, will be included in the 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 2019 Proxy Statement, which was filed with the SEC and Canadian securities regulatory authorities on March 14, 2019. This document is available free of charge as described above.
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level of capital productivity, expected return and source of funding
profit, net present value, rates of return, recovery, return on capital employed, production and execution efficiency, operating, income and cash flow margin, and margin growth, including expected timeframes
performance, completions intensity, location, running room and scale
assets, including its competitiveness and pace of growth against peers, and costs within assets
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
and operating, corporate, transportation and processing activities
flexibility of commercial arrangements and costs and timing of certain infrastructure being operational
available free cash flow, returns, dividend growth, deleveraging, and focus on capital and efficient operations
and U.S. domestication) and the benefits thereof, including opportunity to enhance long-term value for shareholders, liquidity and capital market access, exposure to larger pools of investment, comparability with U.S. peers, increase in passive and index ownership and benefits of the new brand and logo
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
uncertainties include: ability to achieve anticipated benefits of the corporate reorganization; receipt of shareholder, stock exchange and court approvals and satisfaction of other conditions; risks relating to the new company following the reorganization, including triggering provisions in certain agreements; negative publicity resulting from the reorganization and impacts to the company’s business and share price; 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; 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; risks that the description of transactions in external communications may not properly reflect the underlying legal and tax principles of the corporate reorganization; changes in or interpretation of laws or 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-
“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 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. 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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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
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
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 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
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 one
particularly if used in isolation.
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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:
Cash Flow Yield and Non-GAAP Cash Flow Margin – 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
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.
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.
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.
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.
the product to market, including production, mineral and other taxes, transportation and processing and operating
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).
divestitures.
China Operations revenues for production, mineral and other taxes, transportation and processing expense, and
measures the amount of cash generated from the company’s upstream operations.
excluding net acquisitions and divestitures.
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2013 C 13 Cash Fl sh Flow
sensi nsitiv tivity: ty:
price of $3.57/mcf for an estimated revenue impact of $1.2 billion on 2013 volumes of 2,777 MMcf/d
price of $67.30/bbl for an estimated revenue impact of ~$0.5 billion on 2013 volumes of 54 Mbbls/d
2013 N 13 Non-GA n-GAAP C Cash Fl sh Flow
Sensiti nsitivity ty 2013 A 13 As Report Reported Impa pact o ct of Gas Gas Realized alized Pr Price Ch Change Impa pact o ct of Li Liquids s Realized alized Pr Price Ch Change 2013 a 13 at curre rrent pr prices Cash from Operating Activities 2,289 (1,205) (538) 546 (Add back) Deduct: Net Change in Other Assets and Liabilities (80) (80) Net Change in non-cash Working capital (179) (179) Cash Tax on Sale of assets (33) (33) Non-GAAP Cash Flow 2,581 (1,205) (538) 838 2019 Y 19 YTD Q Q3 Fr Free ee Cas Cash Flo Flow Exc Excluding g Re Rest stru ruct cturi uring a and Acqu cquistion
Costs sts 2019 Q 19 Q3 YT YTD As As Report Reported Re Rest stru ruct cturi uring Cos Costs Acquis isiti ition n Cos Costs Ad Adjusted Cash from Operating Activities 2,191 134 33 2,358 (Add back) Deduct: Net Change in Other Assets and Liabilities (55) (55) Net Change in non- cash Working capital 130 130 Non-GAAP Cash Flow 2,116 134 33 2,283 Capital Investment 2,052 2,052 Non-GAAP Free Cash Flow 64 134 33 231 2019 Fr 19 Free Ca Cash sh Flow Flow E Excl cluding r restru ructuri cturing a g and a d acquisi isition ion c costs
2
3Q 3Q19 19
$ M Milli illions $ P Per S Share
NET EARNINGS 149 0.11 NON-GAAPOPERATING EARNINGSŦ 195 0.15 CASH FROM OPERATING ACTIVITIES 756 NON-GAAPCASH 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
YT YTD19 Up Upstr tream Operati ting FCF Ŧ By Asse sset
>$600 M MM (2)
2)
Free Cash Flo Flow Ŧ
performance
& restructuring costs
un-rate annualized ed lev ever erage e of 1.8x Ŧ,(1)
d of pr production (54% liquids ds)
(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 2 2019 Bu Buyback p program $1.25B / B / 1 197 M MM shs (~13% o
3
* 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 $2,225 MM is upstream proforma capital. Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website
Guid idance*
3Q YTD Reportable 3Q YTD Proforma FY19 Proforma (New) w) FY19 Midpoint (Previous) CAPITAL INVESTMENT ($ MILLION) 2,052 2,225(3) 2,800 2,800 TOTAL LIQUIDS (MBBLS/D) 295 315 312 312 – 316 16 310 NATURAL GAS (MMCF/D) 1,562 1,635 1,615 – 1,630 1,600 TOTAL PRODUCTION (MBOE/D) 556 588 580 580 – 590 90 580 TOTAL COSTS PER BOE 2,Ŧ
UPSTREAM OPERATING AND T&P, PRODUCTION AND MINERAL TAXES PLUS ADMINISTRATIVE
12.66 n/a 12. 12.60 – 12.90 13.00
ised FY FY19 productio ion guid idance
ng A Ana nadarko B Basin v n volum umes d driving ng
~1 Mbbls/d of liquids for Arkoma & China (~5 Mboe/d) 1
iterated FY FY19 capex mid idpoin int
Tot
/ BOE low
eased G&A syner ergies es
New F FY19 G Guida dance
Produc uction n Out utperformanc nce (Mboe/d /d) +5 +5 Raised FY19 guidance midpoint (585 vs 580) +5 +5 Outperformance offsetting YTD dispositions 1 +10 +10 Effective Outperformance
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Reconcilia liatio ion of F Full ll Year Guid idance to Reportable le
2 0 1 9 G U I D A N C E
Reportable: ECA plus Newfield post close February 13, 2019 Impact of Newfield Jan 1 – Feb 13, 2019: Newfield activity January 1, 2019 – February 13, 2019 Full year proforma: Results of ECA + Newfield combined for all of 2019
2019 Guidance: Reportable Versus F Full Ye Year Proforma
2019 Reportable Guidance Impact of Newfield Jan 1 - Feb 13, 2019 FY19 Profor
CAPITAL INVESTMENT ($ BILLION) 2.55 – 2.65 0.2 2.8 .8 TOTAL LIQUIDS (MBBLS/d) 297 – 301 15 312 312 – 316 16 NATURAL GAS (MMCF/d) 1,560 – 1,575 55 1,615 – 1,630 TOTAL PRODUCTION (MBOE/d) 556 – 566 24 580 580 – 590 90 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 costs Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website
incurred in 2019 at $167 million
4.00 6.00 8.00 10.00 12.00 14.00 2018PF 2019F
$/BOE
G&A Excl. LTI and Restr. Costs PMOT Upstream T&P Upstream Opex
5
2016 2018
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 P Party E ESG A Assessm ssmen ent
5th
th Cons
nsecut utive S e Safes est Yea ear E Ever er Proven n Safet ety Res esults
peers in the US
peers in Canada
Env nvironmen ental P Per erformanc nce
July 2019 score
rd
O&G companie ies Top quartile ile vs peer companies
Score >25% above peer average
Methane I Intensity 2018 W Water U Use
% of Total Water Tons CH4 / MBOE Number of Recordable Injuries x 200,000 divided by exposure hours
~45% ~45%
Fresh Alternative TR TRIF
0. 0.44 44 0. 0.34 34 0. 0.30 30 0. 0.30 30 0. 0.28 28
2014 2015 2016 2017 2018
0. 0.43 43 0. 0.22 22
6
ES ESG Impac act Mat atrix Safety ty
Socia ial
Governance
activism
En Environmental al
ask Force on Climat ate-rela lated Financia ial l Disclo losures
performance
ility Reportin ing and Programs
us on n Climate Cha hang nge and nd Air Qua uality
– Electrifying production equipment and facilities – Top Tier LDAR program utilizing Optical Gas Imaging for >10-years
unding member of The he Env nvironm nment ntal Partnership
ESG i iss ssues d s deemed m most st i impact ctful t to o
strategy
7
(1) Insufficient 2016 data
Category Metr tric Measurem emen ent 2018 018 2017 017 2016 016
Emissi ssions
GHG I Inte tensity ty metric tons CO2e/gross annual production 17.33 25.05 27.12 Meth thane I Inte tensity ty metric tons CH4/gross annual production 0.22 0.38 0.43 Indirect G GHG E Emiss ssions s metric tons CO2e 199,028 242,582 –1 Direct G GHG E Emissi sions metric tons CO2e 3,312,645 3,571,514 3,612,528 Methane E Emissi sions metric tons CH4 41,686 54,602 57,679
Water & Spill ills
Water er I Inten ensity Cubic meters/gross annual production 75.7 99.5 67.2 Fresh W Water I Intensity Cubic meters/gross annual production 43.1 74.1 47.1 Reportable le S Spil ills ls Regulatory reportable spills 49 59 65 Total al Wat ater U Use MMbbls 91 89 56 Alter ernative W e Water er % 43% 26% 30%
Safe fety
Total R l Recordable le I Inju jury Freq equen ency ( (TRIF) Number of Recordable Injuries x 200,000 divided by exposure hours 0.28 0.30 0.30 Recordable le I Inju juries Workforce 63 64 54
8
Permian Anadarko Montney Base & Other
M U L T I - B A S I N P O R T F OL I O W I T H S C A LE
ASSET ET NET A ACRES 2018 P PRODUCTION LIQUIDS DS % %
CORE RE
PERMIAN 115,000 92 MBOE/d 85% ANADARKO 361,000 135 MBOE/d 60% MONTNEY 793,000 191 MBOE/d 22%
BASE
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 B BBOE o
Proforma P Proved R Res eserves*
e positions ns in thr hree ee of the t top plays i in n North Ameri rica
BBOE of proforma ma h high h quality p proved ed r reserves es*
* 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
>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 2019F** C Capital $2 $2.75-2. 2.85B 85B Continue nued L Liqui uids G 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.
100 200 300 2016 2017 2018 2019F* Liquids Production (Mbbls/d) Permian Montney Anadarko
10
Prio iorit ity # #3 - Sus ustain n Bus usine ness Maintain cash flowŦ and liquids production in core areas Prio iorit ity # #2 – Div ivid idends* Sustain current dividend Prio iorit ity # #1 - Fin inancia ial S l Strength Manage leverage at mid-cycle prices to ~1.5x net debt to adjusted EBITDAŦ Maintain strong liquidity Investment grade credit ratings
* Declaration and payment of future dividends subject to board approval Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website
Prio iorit ity # #5 – Excess Free Cash FlowŦ Prio iorit ity # #4 – Div ivid idend G Growth Dividend increase as sustainable free cash flowŦ grows
C A P I T A L D I S C IP L I N E
Growth investment that generates strong full-cycle returns and expands free cash flowŦ Opportunistic share buybacks Deleverage balance sheet Reduce debt
11
$0.0 $0.5 $1.0 $1.5 $2.0 2018 2019F Distributions to Shareholders ($B) Dividends Buyback
R E T U R N O F C A P I T A L
>$13 b billion of assets since 201 2013
natural gas
shareholders
ng liquidi dity a and nd lower ered ed lev ever erage e to main intain fle lexibil ilit ity t to fund in investor init itia iativ ives
mitme ment nt to r ret etur urn cash to shareho holder ers*
2019
* Declaration and payment of future dividends is subject to Board approval. Year to date share buyback as at September 30, 2019.
2018 018 – 2019F P Planne nned R Retur urns ns*
12
P E R M I A N
development
* Includes plant and field condensate
FY19 P PLAN
ACREAGE (net acres) / AVERAGE WORKING INTEREST % 115,000 / 92% 2019 AVERAGE WORKING INTEREST (%) 96% AVERAGE ROYALTY RATE (%) 25% CAPITAL (net) ($MM) $920 – $950 NET WELLS DRILLED 110 – 120 NET WELLS ON STREAM 115 – 125 D&C COST ($MM/well) $6.1 AVERAGE LATERAL LENGTH (ft) 8,500
TOTAL P PROD ODUCTION ON S SPLIT IT
OIL/CONDENSATE* % 64% NGLs (C2 – C4) % 19% NATURAL GAS % 17%
13
P E R M I A N
jority o
il productio ion g gathered v via ia p pip ipeli line with a access t ss to m multiple p physi sical m markets s
gas g gathe hering ng a and nd p processing ng w with a h access to G Gul ulf C Coast a and nd M Mont nt Bel elvieu eu market ets
imal Waha ha basi sis r s risk sk
ed m market et a acces ess t to G Gulf C Coast refini ning ng/export m markets
Permian
Color
ty Midland Crane
Pip ipelin ines connect to t to Cushing a and Gulf C Coas ast
Proximity ty to to m market a and environ
respon
infrastructure d developm pment
(1) 4Q 2019 risk management positions as at September 30, 2019. Hedged volumes are converted to Mcf at a 1:1 ratio from MMBtu.
Permia ian (1)
1)
2019 019 2020 020
WTI/MIDLAND DIFFERENTIAL HEDGES SWAP PRICE (US$/bbl) 18 Mbbls/d $(1.44)/bbl 10 Mbbls/d $(1.20)/bbl FIRM OIL MARKET ACCESS 45 Mbbls/d 66 Mbbls/d WAHA BASIS HEDGES SWAP PRICE (US$/Mcf) 65 MMcf/d $(0.67)/Mcf 90 MMcf/d $(0.88)/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
A N A D A R K O
Counties
reduced well costs and improved capital efficiency
per well
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 (~$140MM) and expenses exclude amounts for this period.
FY19 P PLAN**
ACREAGE (net acres) / AVERAGE WORKING INTEREST % 363,000 / ~57% 2019 AVERAGE WORKING INTEREST (%) 70% AVERAGE ROYALTY RATE (%) 17 – 20% CAPITAL (net) ($MM) $825 - $875 NET WELLS DRILLED 75 – 85 NET WELLS ON STREAM 115 – 125 2018 AVERAGE D&C COST ($MM/well) $7.9 2019 D&C COST ($MM/well) $6.5 AVERAGE LATERAL LENGTH (ft) 10,000
TOTAL P PROD ODUCTION ON S SPLIT IT
OIL/CONDENSATE* % 36% NGLs (C2 – C4) % 26% NATURAL GAS % 38%
15
A N A D A R K O
Cushing
Anadarko
Oil il pipe c corrid idor Gas pipe c corridor
K growth a h area – high d h demand nd o
qua uality
flow risk
l dif ifferentia ial r ris isk f for o
il
gas g gathe hering ng a and nd p processing ng w with a h access t to S S.E. g gas and M Mont t Bel elvieu eu market ets
emen ental r res esidue g e gas i infrastructure e e expec ected ed 1 1H 2 2020 will e expan and m mar arket a access
Oil ga gathering g and pipel eline a e acces ess f for STACK g gro rowth a are rea Firm ma m market f for a a mate teria ial p l portio tion o
resi sidue g gas s
Bennington
To Perryville LA
Major
y of N NGL exposur ure a at Mont nt Belvie ieu
16
M O N T N E Y
partnership interest) and Pipestone (100% working interest)
consumed within Cutbank Ridge Partnership
FY19 P PLAN
ACREAGE (net acres) / AVERAGE WORKING INTEREST % 793,000 / 64%
89,000 / 100% 2019 AVERAGE WORKING INTEREST (%) 72% AVERAGE ROYALTY RATE (%) 5 – 10% CAPITAL (net) ($MM) $350 – $400 NET WELLS DRILLED 70 – 80 NET WELLS ON STREAM 75 – 85 D&C COST ($MM/well) $4.3 AVERAGE LATERAL LENGTH (ft) 7,900
TOTAL P PROD ODUCTION ON S SPLIT IT
OIL/CONDENSATE* % 18% NGLs (C2 – C4) % 7% NATURAL GAS % 75%
* Includes plant and field condensate
17
M O N T N E Y
To US Northwest To Dawn To Chicago Condensate Imports 100% f firm capacity ty o
Nova G Gas Transm smiss ssion Syst stem (NGTL) L) Conden ensate e sold ld in into premium m local ma market Natural Gas Pipeline Condensate Pipeline
(1) 4Q 2019 and full year 2020 risk management positions as at September 30, 2019 * Price stated is the differential versus NYMEX pricing. Hedged and transport volumes are converted to Mcf at a 1:1 ratio from MMBtu.
bination o
firm e expo port c capa pacity a and b d basis h hedg dges t to manag age A AEC ECO g gas as p price* r risk
2019
Q4 after hedge
firm c capa pacity s secured o d on N NGTL f for e expe pected d produc uction g n growth h – lim limited c curtailm lment r ris isk
ensate s e sold i into l local m market et a at c close t e to W WTI p prices es
Western Can anad ada a (1) 2019 2019 2020 2020
AECO BASIS HEDGES SWAP PRICE US$/Mcf* 405 MMcf/d $(0.88)/Mcf 495 MMcf/d $(0.88)/Mcf TRANSPORT TO DAWN 316 MMcf/d 316 MMcf/d TRANSPORT TO SUMAS / MALIN 132 MMcf/d 132 MMcf/d TRANSPORT TO CHICAGO 88 MMcf/d 108 MMcf/d
18 25 50 75 100 125 2018 2019F MBOE/d
Optimizing Free Cash FlowŦ
Duvernay Uinta Williston Eagle Ford
O P T I M I Z I N G F R E E C A S H F L O W
FY 2 2019 P PLAN* EAG EAGLE F E FORD WILLISTO TON DUVERNAY UI UINTA
ACREAGE (net acres) / AVERAGE WORKING INTEREST (%) 42,000 / 96% 81,000 / 59% 264,000 / 51% 222,000 / 80% 2019 AVG WORKING INTEREST (%) 92% 70% 51% 70% AVERAGE ROYALTY RATE (%) 20 – 25% 17 – 20% 5 – 10% 17 – 20% CAPITAL (net) ($MM) $250 – 270 $140 – 160 $100 – 120 $60 – 70
TOTAL P PROD ODUCTION ON S SPLIT IT*
OIL/CONDENSATE** % 67% 69% 38% 83% NGLs (C2 – C4) % 15% 13% 6% 3% NATURAL GAS % 18% 18% 56% 13%
and non-well capital requirements
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
C 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
>30% l lower o
a p per B BOE1
1 bas
asis
$75 million versus original estimate
rterl rly G G&A r run r rate f for r r remainder o r of y year: r: ~ ~$75 M MM
the BOW lease costs, previously classified in interest expense and corporate segment operating costs
through sub-lease revenues
run-rate G&A costs are down from $65 MM previous estimate to ~$50 MM
t opti timizati tion s segment l t loss o
~$40 M MM p per q quarte ter
erest ex expense o e on d deb ebt o
~$100 M MM p per er q quarter er
(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 costsQ3 ’19 year to date.
1.00 1.50 2.00 2.50 150 300 450 600 2018 2019F $/BOE $MM Bow Related Costs G&A Excl. LTI G&A per BOE
Lower Total G&A2
20
P R O J E C T E D C O M PO S I T I O N O F T O T A L P R O D U C T IO 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 da US US
2019F (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 da US US
2019F(1) (MMcf/d) 2019F Pricing (% NYMEX) 2019F(1) (MMcf/d) 2019F Pricing (% NYMEX)
Natural Gas 975 – 1,055 75% 550 – 650 78%
21
M 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 MMBtu Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.
educe c cash f flow risk and bui uild on market d diversifi fication effo fforts
I Oil
allows for upside capture to ~$67.00/bbl
EX Gas as
eign n Exchang nge
after hedge
HEDGE GE SUM UMMARY (1)
1)
2019 2019 2020 2020
Oil a and C d Condensate WTI HEDGES 176 Mbbls/d 119 Mbbls/d Natural al G Gas as NYMEX NATURAL GAS (2) 864 MMcf/d 1,038 MMcf/d Foreign E Exchange Notional US$ Currency Swaps Average Exchange Rate US$ to C$1 US$250 MM US$0.7516 US$425 MM US$0.7483
22
I Oil
2019 Q4 cash flowŦ after hedge (1)
2019 Q4 cash flowŦ after hedge (1)
structures allows for upside capture to ~$67.00/bbl
dland differ eren ential hed hedges es compleme ement nt firm o m oil m market access t to mult ltip iple le physic ical l markets
KEY H HED EDGES ES (2
(2)
201 2019 202 2020
Oil a and Condensate WTI FIXED PRICE SWAP SWAP PRICE (US$/bbl) 45 Mbbls/d $60.24/bbl 24 Mbbls/d $60.05/bbl WTI 3-WAY OPTION SHORT PUT (US$/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 $61.68/bbl WTI COSTLESS COLLAR LONG PUT (US$/bbl) SHORT CALL (US$/bbl) 43 Mbbls/d $56.28/bbl $66.57/bbl 15 Mbbls/d $50.00/bbl $68.71/bbl WTI/MIDLAND DIFFERENTIAL HEDGES SWAP PRICE (US$/bbl) 18 Mbbls/d $(1.44)/bbl 10 Mbbls/d $(1.20)/bbl
(1) Q4 2019 sensitivity based on mid-point of guidance volumes (2) Risk management positions as at September 30, 2019 Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.
23
nchm hmark
Q4 cash flowŦ after hedge (1)
O basis
flow (1)Ŧ in 2019 Q3-Q4 after hedge (1)
NATUR URAL GA GAS H HEDGE GES (2
(2) (3 ) (3)
201 2019 202 2020
Natural G Gas B Ben enchmark H Hed edges es NYMEX FIXED PRICE SWAP SWAP PRICE US$/Mcf 687 MMcf/d $2.72/Mcf 653 MMcf/d $2.69/Mcf NYMEX 3-WAY OPTION SHORT PUT (US$/mcf) LONG PUT (US$/mcf) SHORT CALL (US$/mcf) 330 MMcf/d $2.25/Mcf $2.60/Mcf $2.72/Mcf NYMEX COSTLESS COLLAR LONG PUT (US$/Mcf) SHORT CALL (US$/Mcf) 177 MMcf/d $2.89/Mcf $3.05/Mcf 55 MMcf/d $2.50/Mcf $2.88/Mcf Natural G Gas B Basis D Differ eren ential Hed edges es AECO BASIS HEDGES SWAP PRICE US$/Mcf 405 MMcf/d $(0.88)/Mcf 495 MMcf/d $(0.88)/Mcf WAHA BASIS HEDGES SWAP PRICE (US$/Mcf) 65 MMcf/d $(0.67)/Mcf 90 MMcf/d $(0.88)/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 MMBtu Ŧ Non-GAAP measures defined in advisories. For additional information regarding non-GAAP measures see the Company’s website.
24
FUTURE O E ORIEN ENTED I INFOR ORMATION ON
stream, level of capital productivity, expected return and source of funding
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 growth, including expected timeframes
competitiveness and pace of growth against peers, and costs within assets
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
scale of development, high-intensity completions and precision targeting, and transferability of ideas
management, and operating, corporate, transportation and processing activities
flexibility of commercial arrangements and costs and timing of certain infrastructure being operational
liquidity, available free cash flow, returns, dividend growth, deleveraging, and focus on capital and efficient
dividends
amount of hedged production, market access, market diversification strategy and physical sales locations
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 f acilities; 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: 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; 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 or 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
and best completions performance wells in the current quarter in such asset and are presented for comparison purposes. Drilling and completions costs have been normaliz ed 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:
25
ADVISOR ORY R REGARDING O OIL & L & G GAS I INFOR ORMATION ON
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
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
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 f actors. 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
misleading, particularly if used in isolation.
26
NO NON-GAAP AAP M MEAS 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 beviewed as a substitute for measures reported under U.S. GAAP. For additional information regarding non-GAAP measures, including reconciliations,see the Company’swebsite and Encana’smostrecentAnnual Reportas filed on SEDAR and EDGAR. Non-GAAPmeasuresinclude:
Cash Flow Yield and Non-GAAP Cash Flow Margin – 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
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.
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.
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 reti rement. 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.
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.
the product to market, including production, mineral and other taxes, transportation and processing and operating
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).
divestitures.
China Operations revenues for production, mineral and other taxes, transportation and processing expense, and
measures the amount of cash generated from the company’s upstream operations.
excluding net acquisitions and divestitures.
Conta tact I t Investo tor R Relati tions: 403.645.3550 | | 2 281.210.5110 | | i investor.relations@encana.com