Oil sands key to building value

Transcription

1 Oil sands key to building value Harbir Chhina Executive Vice-President, Oil Sands Investor Day Calgary December 7, 211 Oil sands key to building value Maximizing value at producing properties improving cost, schedule & production Recognizing value at emerging properties proving up resource & advancing development Adding value through innovation developing technology & enhancing processes ALBERTA ALBERTA Borealis Greater Pelican Region Borealis Region Christina Lake Region Foster Creek Cenovus land at Dec. 31, 29. Region Cenovus land at Dec. 31, 21 SASKTACHEWAN 1

2 Why we re successful Top quality reservoirs Manufacturing approach & project execution Operational excellence Experienced team Technological innovations Stakeholder relationships & environmental track record Sustainable, predictable development 1 Pre development Initial development Expansion phases Full field development Net asset value Land Exploration/piloting Delineation Prepare/file application Application approval Engineering, procurement & construction Production CL - E FC - FGH CL - D FC-A-E, CL-A-C years 5 years 5 7 years 3+ years Winifred Lake East McMurray Steepbank Narrows Lake Grand Rapids Telephone Lake Foster Creek Christina Lake Pelican Lake Wabiskaw More than half of our oil sands leases have zero wells per section 2

3 Building NAV by converting resources Discovered BIIP 56 Bbbls 1P 2P Undiscovered BIIP* 82 Bbbls 2C 6.1 Bbbls 137 Bbbls 7.8 Bbbls *Undiscovered BIIP is unrisked. Volumes are shown before royalties and on a net basis. Foster Creek improving on a top tier reservoir Milestones Performance Phase F, G & H expansion Technology development 211 Produced at 95% of nameplate Completed turnaround Progressed phase F (3% complete) Commercialized blowdown boiler Tested liner design 212 Exceed nameplate production Conduct May turnaround Ramp up to full construction Test secondary pay Expand Wedge WellTM technology use Convert first well pairs to blowdown Pilot CO 2 co-injection 3

4 Operational excellence Foster Creek Mbbls/d Record production 122 Mbbls/d July 1, Turnaround Dec-1 1-Mar-11 1-Jun-11 1-Sep-11 1-Dec-11 Volumes are shown on a 1% basis. Technology increases capacity at Foster Creek Overall production capacity increased by 2, bbls/d resulting from: success of Wedge WellTM technology plant optimization Project phase Foster Creek A - E First production target Expected production capacity (bbls/d) gross Prior New 12, F 214F 35, 45, G 215F 35, 4, H 216F 35, 4, Future phases 217F+ 45, 65, Total capacity 27, 29, 29, 31, 4

5 Technology improved performance Mbbls/d 12 ISOR Wedge WellTM technology reduced SOR: 2.5 to Jan-9 Jul-9 Jan-1 Jul-1 Jan-11 Jul Total production Wedge Well TM production ISOR Christina Lake top tier reservoir Milestones Phase C expansion Phase D & E expansion Technology development 211 Achieved first production Improved schedule & cost Accelerated project timing Tested improved startup technique Implemented Wedge WellTM technology 212 Ramp to full capacity (Q2) Achieve first oil at phase D (Q4) Pilot CondenSAP Drill downspacing wells 5

6 Operational excellence Christina Lake Mbbls/d 5 Record production 45 Mbbls/d Nov. 27, Turnaround 1-Dec-1 1-Mar-11 1-Jun-11 1-Sep-11 1-Dec-11 Volumes are shown on a 1% basis. Advancing timing at Christina Lake Strong execution drives improved schedule for Christina Lake phases D & E Project phase Regulatory application filings First production target Expected production capacity (bbls/d) gross Christina Lake A - C D E F G H Q3-27 Q4-29 Q4-29 Q F Prior Q1-213F 214F 216F 217F 219F New Q4-212F Q4-213F 58, 4, 4, 4, 4, 4, Total capacity 258, 6

7 Leading capital efficiency Foster Creek Christina Lake $/bbl/d $/bbl/d 3, 3, Actual costs Projected costs Actual costs Projected costs 2, 2, 1, 1, A 2Mbbls/d B 1Mbbls/d C 3Mbbls/d D&E 6Mbbls/d FG&H* 125Mbbls/d A&B 18Mbbls/d CD&E 12Mbbls/d FG&H 12 Mbbls/d Capital efficiency is calculated based on production design capacity for each phase. *Foster Creek F,G&H expectations reflect greenfield expansion and design enhancement initiatives. Pelican Lake our lowest risk growth opportunity Milestones Performance Expansion Technology development 211 Maintained production Commenced infill drilling with 2 rigs, added a 3 rd in July Expanded polymer flood Drilled 7 infill wells 212 Achieve production growth Add 4 th drilling rig Q1 Commence new battery construction Continue to expand polymer flood Begin field pipeline upgrade 7

8 Pelican Lake tremendous growth opportunity Mbbls/d Grand Rapids + hot water flood Polymer/infill Waterflood Primary Opportunity to apply technology to grow production F 214F 216F 218F 22F Volumes are shown before royalties. 211F based on commodity price assumptions as outlined in the October 27, 211 guidance document. 212F based on midpoints of December 7, 211 guidance document. 213F through 22F based on future price assumptions as noted in the advisory. Advancing our emerging projects Narrows Lake Regulatory approval Construction Steam & production Production capacity bbls/d net 65, Grand Rapids 18, Telephone Lake* 9, , Forecast *Timeline subject to change; production not currently included in 1-year plan. Steam and production includes ~6 months initial steaming with no production followed by month production ramp up. Timing subject to regulatory approval and project sanction. 8

9 Adding value through innovation Successfully developing technology through: culture of innovation portfolio of projects to minimize risk financial capacity to support field testing (6/4 rule) emphasis on pilot testing collaboration opportunities Protecting our intellectual property rights Status quo is unacceptable Harbir Chhina Blowdown boiler commercialized in 211 Utilizes boiler water (blowdown) as feed water for second boiler Generates more steam from the same water Improves heat recovery Lowers operating costs & emissions Improves steam quality from ~77% to ~92% OTSG Blowdown 23% Blowdown boiler SAGD steam 77% SAGD steam 15% BFW 1 st BD 2 nd BD Blowdown 8% 9

10 Commercializing one technology per year Solvent processes ESP (phase 1) Wedge WellTM technology Accelerated start-up Chemical Looping Combustion Blowdown boiler Confidential project Confidential project Warm Lime Sof t ening Confidential project Confidential project Confidential project Combustion (AIDROH) New drilling method ESP (phase 2) Develop Pilot Commercial demonstration * *Commercial demonstration may take up to 4 years to become part of mainstream process. Developing technology to build value Value Blowdown boiler 3 SAP 4 5 Wedge WellTM technology 2 CondenSAP 58% 32% 1% ESP (phase 2) 1 Develop Pilot Commercial Stage 1. ESP (phase 2) early stage enhancement of pump technology 2. CondenSAP a condensate based Solvent Aided Process 3. SAP butane based, being piloted at Christina Lake, commercial plans for Narrows Lake 4. Blowdown boiler part of all future template designs, makes more steam per mcf of gas used 5. Wedge WellTM technology commercialized at Foster Creek 1

11 Oil sands a key to building value Maximizing value at producing properties improving cost, schedule and production Recognizing value at emerging properties proving up resource and advancing development Adding value through innovation developing technology and enhancing processes ALBERTA ALBERTA Borealis Greater Pelican Region Borealis Region Christina Lake Region Foster Creek Cenovus land at Dec. 31, 29. Region Cenovus land at Dec. 31, 21 SASKTACHEWAN Supplemental information 11

12 Oil sands project comparison Foster Creek Christina Lake Narrows Lake Grand Rapids Telephone Lake Working interest 5% 5% 5% 1% 1% Potential size (Mbbls/d gross) Design SOR SAGD 1.6 SAP Contingent resource (best estimate) Supply cost (US$/bbl WTI) Core area well density (wps) Land position (net acres) 7,72 12,48 12,96 52,48 36,48 Wedge WellTM technology Well producer Technology details: <.1 average SOR first year production rate of 6 8 bbls/d at Foster Creek, current average of 4 bbls/d; 3 4 bbls/d at Christina Lake acceleration of production 1 15% potential increase in recovery factor Foster Creek wells 38 producing, 13 coming on, 1 planned for 211F Christina Lake wells 4 producing Wedge Standard SAGD well pair and steam chambers coalesce 12

13 Wedge WellTM technology growth Well count 25 2 Wedge Well TM production Wedge Well TM Well pair count count bbls/d 25, 2, 15 15, 1 1, 5 5, Jan-9 Jul-9 Jan-1 Jul-1 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Cenovus s Solvent Aided Process (SAP) SAP versus SAGD metrics 3% production rate improvement 15% incremental total oil recovery 3% reduction in annual fuel gas usage.5 bbls solvent (butane) purchased per bbl bitumen 3% increase to initial capital 1% decrease in annual sustaining capital 5 1% reduction in non-fuel operating cost ~$1./bbl netback uplift Environmental benefits lower SOR & emission intensity lower water usage & footprint Steam only (SAGD) Steam & solvent (SAP) Milestones 2 21 Senlac SAP pilot Christina Lake SAP pilot F Christina Lake isolated test 21 Q2 SAP & SAGD Narrows Lake 13

14 Forward looking information The presentations and posters at Investor Day 211 contain certain forward-looking statements and other information (collectively forward-looking information ) about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forwardlooking information in this presentation is identified by words such as anticipate, believe, expect, plan, forecast or F, target, project, could, focus, vision, goal, milestone, proposed, scheduled, outlook, potential, may or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projected future value or net asset value, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, anticipated finding and development costs, expected reserves and contingent, prospective or in-place resources estimates, potential dividends and dividend growth strategy, anticipated timelines for future regulatory, partner or internal approvals, forecasted commodity prices, future use and development of technology and projected increasing shareholder value. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied. The assumptions on which our 211 guidance is based include actual prices for the first 9 months of 211 and September 3 strip pricing for the remainder of the year and an average number of shares outstanding of approximately 758 million. Approximate September 3 strip prices: WTI of US$79.4/bbl; Western Canada Select of US$69.25/bbl; NYMEX of US$3.8/MMBtu; AECO of $3.5/GJ; Chicago Crack Spread of US$31.95; and exchange rate of $.961 US$/C$. For the period 213 to 221 assumptions include WTI of US$85.-US$15./bbl; Western Canada Select of US$71.-US$85./bbl; NYMEX of US$4.-US$6./MMBtu; AECO of $3.3-$5.25/GJ; Chicago crack spread of US$9.; exchange rate of $.98-$1.7 US$/C$; and average number of shares outstanding of approximately 752 million. 212 guidance is based on an average diluted number of shares outstanding of approximately 759 million. It assumes WTI of US$9./bbl; Western Canada Select of US$75./bbl; NYMEX of US$3.5/MMBtu; AECO of $3.1/GJ; Chicago Crack Spread of US$14.5; and exchange rate of $.975 US$/C$. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include: assumptions inherent in our current guidance, available at our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects; our ability to generate sufficient cash flow from operations to meet our current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity prices, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; maintaining a desirable ratio of debt to adjusted EBITDA and debt to capitalization; our ability to access external sources of debt and equity capital; success of hedging strategies; accuracy of our reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate our integrated heavy oil business; reliability of our assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining of crude oil into petroleum and chemical products at two refineries; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in Alberta s regulatory framework, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us. The forward-looking information contained in the presentations and posters, including the underlying assumptions, risks and uncertainties, are made as of December 7, 211. For a full discussion of our material risk factors, see Risk Factors in our 21 Annual Information Form and Risk Management in our most recent Management s Discussion and Analysis, available at and Oil and gas information The company-wide bitumen contingent resources estimates and the Pelican Lake discovered petroleum initially-in-place estimates, effective December 31, 21, and the discovered bitumen initially-in-place estimates, effective December 31, 29, were prepared by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator, and are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook. For further discussion regarding our (i) bitumen contingent resources, see our 21 Annual Information Form (AIF) and (ii) our total bitumen initially-in-place and all subcategories thereof, see our June 16, 21 news release, available on SEDAR at and at Actual resources may be greater than or less than the estimates provided. As at December 31, 29, Discovered Bitumen Initially-in-Place (BIIP) company-wide, best estimate, is 56 Bbbls, including.1 Bbbls of cumulative production, 1.3 Bbbls of proved plus probable reserves, 5.4 Bbbls of economic contingent resources and 49 Bbbls of unrecoverable BIIP. As at December 31, 21, proved plus probable reserves were Bbbls and contingent resources were 6.1 Bbbls. As at December 31, 21, Discovered Petroleum Initially-In-Place (PIIP) for Pelican Lake, best estimate, is 1.6 Bbbls, including 95 MMbbls of production, 141 MMbbls of proved reserves, 86 MMbbls of probable reserves and 1,293 MMbbls of unrecoverable PIIP. Certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head. Additional information relating to our oil and gas reserves and resources is presented in our AIF, available at and on our website at NET ASSET VALUE With respect to the particular year being valued, the net asset value (NAV) disclosed herein is based on the number of issued and outstanding Cenovus shares as at December 31 as reported in our Annual Information Form and Form 4-F. We calculate NAV as an average of (i) our average trading price for the month of December, (ii) an average of net asset values published by external analysts in December following the announcement of our budget forecast, and (iii) an average of two net asset values based primarily on discounted cash flows of independently evaluated reserves, resources and downstream data and using internal corporate costs, with one based on constant prices and costs and one based on forecast prices and costs. NON-GAAP MEASURES The presentations and posters may contain references to non-gaap measures. These measures have been described and presented in order to provide shareholders and potential investors with additional information regarding Cenovus s liquidity and its ability to generate funds to finance its operations. Readers are encouraged to review our Third Quarter Report to Shareholders, available at for a full discussion of the use of each measure. TM is a trademark of Cenovus Energy Inc. 14