Q3 Results Conference Call

Transcription

1 ENCANA CORPORATION Q3 Results Conference Call November 12, 215

2 FOCUSED GROWTH Lowering Costs and Growing High Margin Production Execution in the core four assets on track Permian: top tier operator Eagle Ford: great asset continues to outperform Duvernay: delivering compelling returns Montney: capital efficiency and liquids growth Innovation and focus driving both efficiency and margins Continue to see costs dropping and productivity improving in each asset >9% of Q3 capital directed to core four assets Maintained Q2 upstream operating cash flow excluding hedging despite >$11/bbl drop in WTI Reducing corporate cost structures Annual interest and administrative costs down ~$3MM since 212 Proactively managing the balance sheet Divestiture proceeds being used to reduce debt, enhance financial flexibility & accelerate activity ~$2.8B billion in debt reduction expected by year-end* *Assuming that previously announced divestitures close by year-end 2

3 QUALITY GROWTH FROM HIGH MARGIN ASSETS Liquids Production Doubled Since Q1 214 (Mbbls/d) Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15F Total liquids up 1% from Q2 and up 35% Y-O-Y YTD liquids 78% oil and condensate* Core four assets driving liquids growth Contributing ~8% of total Q3 liquids production Margin expansion to continue in 216 Core Four Assets Other Liquids *Includes plant condensate 3

4 INNOVATION AT WORK Encana s R&D Lab Is In The Field Finding the right solutions to enhance returns today Well spacing in three dimensions in complex reservoirs Targeting the best pay with advanced reservoir characterization & geosteering Optimizing completions intensity Wolfcamp A Full life production management Logistics to drop costs and eliminate non-productive time WC_B $MM 2, 1,5 1, 5 215F Capital Wolfcamp B 36B-1 Core Four Assets Capital Other Assets Innovation Permian well spacing evaluation pad 4

5 PERMIAN Top Tier Operator Top tier cost performance D&C costs down $2MM/well since acquisition D&C costs of $6.4MM/well in Q3, down 9% from Q2 Top tier production performance Core of the core acreage position Production of 46 MBOE/d, up 28% from Q2 Innovation at work Well spacing evaluation in complex stacked pay Pivotal to understanding interaction between wells, fracs, and benches Enhancing the value of our 5, well inventory Executed oil gathering agreement, improving operating margins by up to $2/bbl 3% tied in and on track for 5% by year end Returns averaging >3% at strip pricing* *October 3, 215 strip pricing. **ITG review of EUR performance not tied to bookable reserves MBOE 1, Peer D&C Cost Performance $MM ECA Data compiled through peer second quarter conference call material. Peers include APA, CPE, EGN, FANG, LPI, OXY, PE, PXD, QEP, RSPP Peer EUR Performance** 1 ECA Data Source: ITG Energy Exploration and Production: ECA Is the Sleeping Giant About to Wake Up. Peers include AEPB, APA, AREX, CXO, EGN, EPE, FANG, LPI, PE, PXD-N, PXD-S, RSPP 5

6 EAGLE FORD A Great Asset Continues to Outperform Average Q3 D&C cost of $5.4MM/well Beating the $5.6MM well cost target* Completion days dropped 42% to 3.5 days New $5.2MM D&C cost target Q3 production of 54 MBOE/d Up 18% since Q2 Up over 25% since acquisition Successful ramp-up of Patton Trust South facility Innovation at work Refined cluster spacing improving Graben well productivity by 5% in the first 18 days Infill well results are meeting type curve expectations, strengthening our 6+ well inventory Returns averaging >3% at strip pricing** *Q2 target ** October 3, 215 strip pricing. Aggressive reductions in D&C Costs $MM $MM/ Q14 Avg 1Q15 Avg 2Q15 Avg 3Q15 Avg D&C* D&C/1,' Note: Normalized to 5, ft. lateral Reduced cluster spacing creating better wells BOE/d 1, Days On Production New Wells Historical Cluster Spacing Tight Cluster Spacing 6

7 DUVERNAY Delivering Compelling Returns Q3 production of 9.3 MBOE/d Up 59% since Q2 New cost benchmark realized on pad Completion cost of $6.4 MM/well Water hub reduced costs by $1.2 MM/well Innovation at work Reducing 8 well pad cycle times to ~ 6 months Dual drilling rigs, dual frac crews Targeting and completions design efforts delivering top percentile wells in North America Returns averaging >3% at strip pricing* (excluding JV carry capital) Duvernay D&C costs offset by higher productivity and a competitive fiscal regime to deliver equivalent returns * October 3, 215 strip pricing. Duvernay and Eagle Ford well comparison $MM (Gross) D&C Cost BOE/d (GBR) 2, 1,6 1,2 8 4 ECA Duvernay Karnes Eagle Ford IP3 ECA Duvernay Karnes Eagle Ford 7

8 MONTNEY Capital Efficiency & Liquids Growth Four new Mid-Montney condensate wells completed in Tower All wells flowing >5 bbls/d within first 3 days 13 Mid-Montney Tower wells in inventory Expecting 5, bbls/d of liquids by end of 218 Liquids growth outpaces gas > 1,5 oil and condensate Montney wells in inventory Innovation at work Refining cluster spacing and frac intensity has improved productivity per well by up to two times Returns averaging >6% at strip pricing* (excluding third party capital) Challenges with third party restrictions TCPL restrictions reduced available flow capacity by ~4 MMcf/d in Q3 Maintained liquids production and curtailed dry gas only Impacts are continuing to date in Q4 * October 3, 215 strip pricing. Mbbls/d Bcf/d Total Capital $MM Production Efficiency $/BOE/d $1, $1,5 9,5 1, Liquids Gas 8

9 BUILDING MOMENTUM IN 2H 215 Q3 Highlights 35% y-o-y increase in total liquids volumes 1% sequential quarterly growth Core four asset production up 12% vs. Q2 Combined T&P and op cost down $1.7/BOE Q3 cash flow up $19 million versus Q2 >9% Q3 capex focused on core four assets $2.8 billion completed & announced divestitures DD&A rate updated 215F: $9.3 $9.55/BOE Upstream Operating Cash Flow* Excluding Hedging ($MM) Upstream Operating Cash Flow* Including Hedging ($MM) Q3 215 Q2 215 YTD , ,712 Transportation & Processing ($/BOE) Operating ($/BOE) Total Cash Flow ($MM) ,47 - $ per share, diluted Operating Earnings (Loss) ($MM) (24) (167) (172) - $ per share, diluted (.3) (.2) (.21) Weighted avg. shares O/S - diluted (MM) Capital Investment ($MM) ,952 Remainder of guidance unchanged 216 fixed hedges and three-way costless collars** 56 Mbbls/d WTI 395 MMcf/d NYMEX Net Acquisitions & (Divestitures) ($MM) (99) (14) (1,77) Natural Gas (MMcf/d) 1,547 1,568 1,656 Total Liquids (Mbbls/d) Total Production (MBOE/d) Core Four Production (MBOE/d) *Upstream operating cash flow is defined as revenues, net of royalties, less production and mineral taxes, transportation and processing and operating expenses for each of the respective Canadian and USA operations. ** Excludes swaptions 9

10 DRIVING CASH FLOW WITH STRATEGIC INVESTMENT Higher Margin Production Offsetting Lower Q3 Oil Price $MM $35 $28 $21 $14 $7 Q2 vs. Q3 Upstream Operating Cash Flow Excluding Hedging Upstream operating cash flow excluding hedging unchanged in Q3 vs. Q2 Higher margin liquids-rich production from core four assets and lower costs offset the >$11 drop in oil price and lower non-core asset production Exceeding 215 cost efficiency target 215 savings now expected to be >$4MM $ Q2 Operating CF Q2 Average WTI $57.94/bbl Lower Q3 Price Impact Lower Non- Core Asset Production Higher Core Four Asset Production Lower Operating + T&P Expenses Other Q3 Operating CF Q3 Average WTI $46.43/bbl 1

11 DISCIPLINED FOCUS ON REDUCING COST STRUCTURE Enhancing Total Corporate Returns 25 $MM Quarterly G&A and interest expense down >$85 million since prior to launch of strategy in Q3 G&A expense down 5% vs. 212 average Q3 interest expense down 35% vs. 212 average Committed to maintaining investment grade credit rating 1 5 Mid-BBB ratings from Moody s, S&P and DBRS Actively managing balance sheet By year end, expect to have reduced debt by ~ $2.8B*** 212 Avg 213 Avg 214 Avg 1Q15 2Q15 3Q15 No long-term debt maturities until 219 G&A* Interest Expense** * Excluding restructuring and long-term incentive costs. ** Excluding one time payments. ***Assuming announced divestitures close by year-end. 11

12 THE STRATEGY IS WORKING Execution in the core four assets on track Innovation and focus driving both efficiency and margins Reducing corporate costs Proactively managing the balance sheet One. Agile. Driven. A culture of success

13 FUTURE ORIENTED INFORMATION This presentation contains certain forward-looking statements or information (collectively, forward-looking statements ) within the meaning of applicable securities legislation. Forward-looking statements include, but are not limited to: expected 215 capital investment, including increased capital investment in the Permian expected production, number of wells (including additional wells in the Permian) and potential to grow well anticipated cash flow inventory continued operational and capital cost efficiencies, including reductions in drilling and completion costs lowering costs, improving well performance and production rates expected G&A and interest expense, and their sustainability in a high commodity price environment anticipated hedging and outcomes of risk management program anticipated capital plans managing the balance sheet and maintaining an investment grade credit rating, including expectation to continued innovation to drive efficiency and margins reduce debt and associated interest expense savings expected rates of return and improved operating margins the expectation of meeting the targets in the Company s 215 corporate guidance expected rig count and rig release metrics anticipated reserves and resources and stacked resource potential projected liquids growth, capital and production efficiency through to 218 development of midstream and marketing solutions, including increased capacity anticipated compound annual growth rate through to 218 expected impact of third-party transportation restrictions expected proceeds from announced divestitures, use of proceeds therefrom and timing of closing Readers are cautioned upon unduly relying on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, these statements involve numerous assumptions, known and unknown risks and uncertainties and other factors, which can contribute to the possibility that such statements will not occur or which may cause the actual performance and financial results of the Company to differ materially from those expressed or implied by such statements. These assumptions include, but are not limited to: achieving average production for 215 of between 1.6 Bcf/d and 1.7 Bcf/d of natural gas and 13 Mbbls/d to 15 Mbbls/d of liquids commodity prices contained in the Company s 215 corporate guidance or in this presentation U.S./Canadian dollar exchange rate of.8 effectiveness of the Company s resource play hub model to drive productivity and efficiencies results from innovations data contained in key modeling statistics the expectation that counterparties will successfully fulfill their obligations under gathering and midstream commitments availability of attractive hedge contracts and enforceability of the risk management program 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, the benefits achieved and general industry expectation Risks and uncertainties that may affect the operations and development of our business include, but are not limited to: risks inherent to closing announced divestitures and adjustments that may reduce the expected proceeds and value to Encana; the ability to generate sufficient cash flow to meet the Company's obligations; commodity price volatility; ability to secure adequate product transportation and potential pipeline curtailments; variability of dividends to be paid; timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk associated with hedging contracts; risk and effect of a downgrade in credit rating, including access to capital markets; fluctuations in currency and interest rates; assumptions based on the Company s 215 corporate guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; the Company's ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from resource 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 divestitures of certain assets or other transactions or receive 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 from time to time in its most recent MD&A, financial statements, Annual Information Form and Form 4-F, as filed on SEDAR and EDGAR. Although Encana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. The forward-looking statements contained in this document are made as of the date of this document and, except as required by law, Encana undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by these cautionary statements. Certain future oriented financial information or financial outlook information is included in this presentation to communicate Encana s current expectations as to its performance in 215. Readers are cautioned that it may not be appropriate for other purposes. This presentation may contain references to non-gaap measures, which do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. These measures have been described and presented in order to provide shareholders and potential investors with additional information regarding Encana s liquidity and its ability to generate funds to finance its operations. In particular, rates of return for a particular play 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, the Company s field operating expenses and certain type curve assumptions. 13

14 ADVISORY REGARDING RESERVES DATA & OTHER OIL & GAS INFORMATION National Instrument ( NI ) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies such as Encana engaged in oil and gas activities. Encana complies with the NI annual disclosure requirements in its annual information form, most recently dated March 3, 215 ( AIF ). The Canadian protocol disclosure is contained in Appendix A and under Narrative Description of the Business in the AIF. Encana has obtained an exemption dated January 4, 211 from certain requirements of NI to permit it to provide certain disclosure prepared in accordance with U.S. disclosure requirements, in addition to the Canadian protocol disclosure. That disclosure is primarily set forth in Appendix D of the AIF. Further, Encana obtained an exemption dated January 21, 215 (the 215 Exemption Order ) from certain requirements of NI 51-11, to permit it to use the definition of product type contained in the amendments to NI that came into force on July 1, 215, as it relates to its Canadian protocol disclosure contained in Appendix A of the AIF. 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. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. The estimates of economic contingent resources contained in this presentation are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook ( COGEH ). Contingent resources do not constitute, and should not be confused with, reserves. Contingent resources are defined as those quantities of petroleum estimated, on 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. Economic contingent resources are those contingent resources that are currently economically recoverable. In examining economic viability, the same fiscal conditions have been applied as in the estimation of reserves. There is a range of uncertainty of estimated recoverable volumes. A low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate, which under probabilistic methodology reflects a 9 percent confidence level. A best estimate is considered to be a realistic estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, which under probabilistic methodology reflects a 5 percent confidence level. A high estimate is considered to be an optimistic estimate. It is unlikely that the actual remaining quantities recovered will exceed the high estimate, which under probabilistic methodology reflects a 1 percent confidence level. There is no certainty that it will be commercially viable to produce any portion of the volumes currently classified as economic contingent resources. The primary contingencies which currently prevent the classification of Encana's disclosed economic contingent resources as reserves include the lack of a reasonable expectation that all internal and external approvals will be forthcoming and the lack of a documented intent to develop the resources within a reasonable time frame. Other commercial considerations that may preclude the classification of contingent resources as reserves include factors such as legal, environmental, political and regulatory matters or a lack of markets. The estimates of various classes of reserves (proved, probable, possible) and of contingent resources (low, best, high) in this presentation represent arithmetic sums of multiple estimates of such classes for different properties, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of reserves and contingent resources and appreciate the differing probabilities of recovery associated with each class. 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 resources ). 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 ) has the meaning set out jointly by the Society of Petroleum Engineers and World Petroleum Congress in the year 2, 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. In this presentation, Encana has provided information with respect to certain of its plays and emerging opportunities which is analogous information as defined in NI This analogous information includes estimates of PIIP, NGIP, COIP or EUR, all as defined in the COGEH or by the SPE-PRMS, 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. Some of this data may not have been prepared by qualified reserves evaluators or auditors, may have been prepared based on internal estimates (including PIIP and EUR), 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 document, 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. Further, disclosure regarding drilling locations is based on internal estimates, may include proved, probable and unbooked locations, and assume a number of wells that can be drilled per section based on industry practice and internal review. The drilling locations which Encana will actually drill will ultimately depend upon the availability of capital, regulatory and partner approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. 3-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. A 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 BOEs may be misleading, particularly if used in isolation. 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. 14