Integrated oil Building on our success

Transcription

1 Integrated oil Building on our success John Brannan Executive Vice-President and President, Integrated Oil Division Investor Day Calgary - June 17 New York - June 21 Integrated oil overview Foster Creek Up to 12 months acceleration of phase F ~235,000 bbls/d (gross) of planned development Christina Lake Up to 12 months acceleration of phase E ~258,000 bbls/d (gross) of planned development Overview of our industry leading performance Update Wood River CORE project Christina Lake Region Foster Creek Region ALBERTA Cenovus land at Dec. 31, Borger TEXAS Wood River ILLINOIS Oilsands leases P&NG leases Christina Lake proper Foster Creek proper Note: Timelines are subject to regulatory approvals. 1

2 Growth strategy Driven by bitumen resource Projects capable of supporting 20% CAGR through Bbbls best estimate for discovered BIIP 5.4 Bbbls best estimate for contingent resource Supported by downstream heavy oil processing 275,000 bbls/d post-core total heavy oil processing capacity Additional Opportunities Foster Creek & Christina Lake Current production Base growth plan Growth Long term plays Commerciality Cenovus SAGD operating experience Mbbls/d yr CAGR ( ) ~25% Q Foster Creek Christina Lake Production is shown before royalties and on a gross basis. 2

3 Foster Creek - leading the way Foster Creek current phases Pilot project began in 1996 Became the industry s first commercial SAGD project in ,000 bbls/d of productive capacity (phases A - E) Largest producing SAGD operation in Alberta Currently producing more than 100,000 bbls/d from 160 wells Pioneered use of wedge wells Achieved royalty payout in Feb 2010 Top tier performance SOR Leading capital efficiencies $ /bbl operating cost (2010F) C$/bbl/d 20,000 10,000 Capital efficiency 0 Volumes are shown on a 100% basis. A 20Mbbls/d B 10Mbbls/d C 30Mbbls/d D&E 60Mbbls/d 3

4 Foster Creek future development Total planned capacity of ~235,000 bbls/d Phases F, G & H Staged plant expansion west of phases A - E Each expansion adds 30,000 bbls/d of productive capacity Regulatory approval anticipated second half 2010 Up to 12 months acceleration of phase F Requires $76 million (gross) in 2010F Phase I now planned Timelines are subject to regulatory approvals. Volumes are shown on a 100% basis. Christina Lake - top tier reservoir 4

5 Christina Lake current phases Pilot project began in 2000 First production in ,000 bbls/d of productive capacity (phases A&B) Currently producing approximately 15,000 bbls/d from 17 wells Top tier performance SOR Leading capital efficiencies C$/bbl/d 30,000 20,000 Capital efficiency $ /bbl operating costs (2010F) 10,000 Volumes are shown on a 100% basis. 0 A&B 18Mbbls/d CD&E 120Mbbls/d Christina Lake future development Total planned capacity of ~258,000 bbls/d Phases C G Each expansion adds 40,000 bbls/d of productive capacity Regulatory approval in place for phases C & D Phase C construction ahead of schedule and on budget Phase D under construction Regulatory approval anticipated for phases E G in 2011 Up to 12 months acceleration of phase E Phase H now planned Timelines are subject to regulatory approvals. Volumes are shown on a 100% basis. 5

6 Project schedules Project phase Regulatory applications First production target Expected cumulative production capacity (bbls/d) Foster Creek A-E Q Q ,000 F Q F 150,000 G Q F 180,000 H Q F 210,000 I ~2014F ~2019F ~235,000 Christina Lake A-B Q Q ,000 C Q Q3 2011F 58,000 D Q Q2 2013F 98,000 E Q F 138,000 F Q F 178,000 G Q F 218,000 H ~2013F ~2019F ~258,000 On stream Under construction Submitted for regulatory approval* Planned no approvals* *Timelines are subject to regulatory approvals. SAGD development plans driving growth Mbbls/d Production capacity (year end rate) Emerging Opportunities Christina Lake (developing) Annualized production Foster Creek (developing) Christina Lake (existing) Foster Creek (existing) Annualized production F 2011F 2012F 2013F 2014F 2015F 2016F 2017F 2018F 2019F Volumes are shown before royalties and net to CVE (50% basis). 6

7 Timeline - illustrative SAGD phase Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Prepare application Regulatory approval (1) Engineering Procurement Construction (2) Commissioning Steam Production Initial capital (1) Receipt of regulatory approval is variable. Assumes construction starts when approval is received. (2) Construction time is variable depending on several factors. Commissioning, steam and production would be timed accordingly. Capital profile - illustrative SAGD phase Percent of total initial capital 50% 40% 30% 20% 10% 0% Engineering and procurement Construction Percent of peak production 100% 0% Years Initial capital Sustaining capital Well capital Maintenance capital Plant capital % peak production Capital efficiency based on initial capital ~ month construction timeline - starts after regulatory approval Sustaining capital varies from year to year and may be affected by technological innovations 7

8 Why we re successful how we do it Top quality reservoirs Manufacturing approach & project execution Operational excellence Technological innovations Top quality people Top quality reservoirs Steam-to-oil ratio (bbl/bbl) Low SOR means Lower capital cost Lower operating cost Smaller surface footprint Lower energy usage Lower emissions Less water usage 2 0 Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer CVE FC Peers include: CNQ, COP, CLL, DVN, HSE, IMO, JACOS, MEG, NXY, RDS, SU. Source: ERCB public domain data, April, 2009 March, Peer CVE CL 8

9 Manufacturing approach to development Increasing efficiency is reducing execution timeline Manufacturing process Staged development Dedicated in-house construction management teams Multiple small contractors Standard designs Assembly line drilling & completions Module yard Enhanced safety Minimize rework and cost over-runs Cost savings and schedule certainty Accessible labor Nisku module yard 9

10 Pipe module Christina Lake site construction 10

11 Operational excellence - Foster Creek Mbbls/d 120 Record production 113 Mbbls/d March 1, Jun-09 1-Sep-09 1-Dec-09 1-Mar-10 1-Jun-10 Volumes are shown on a 100% basis. Operational excellence - Christina Lake Mbbls/d 20 Record production 18 Mbbls/d May 20, Turnaround 0 1-Jun-09 1-Sep-09 1-Dec-09 1-Mar-10 1-Jun-10 Volumes are shown on a 100% basis. 11

12 Electric Submersible Pumps (ESP) ESPs reduce SOR through use of lower operating pressures ~20% improvement in run life Cumulative Meantime to Failure (MTTF) increased from 10.5 to 12.7 months Down time for a pump change 75% reduction 24 hour service rig operations Effect of reducing pump change time 15 days: More than 1,000,000 bbls/yr* ESP run life cumulative MTTF in months 9 Dec-08 Mar-09 Jun-09 Sep-09 Dec Days down on pump change *Based on plant production of 100 Mbbls/d and 1 pump change per well per year Technology improving recovery Wedge wells < 0.1 average SOR bbls/d average production rate at Foster Creek Acceleration of production 10% potential increase in recovered oil Foster Creek 36 wells drilled Christina Lake evaluating pilot Steam chambers coalesce Wedge well producer Standard SAGD well pair 12

13 Increased recovery with wedge wells Percent recovery* 80% 60% Illustrative well performance Accelerated recovery with wedge wells Incremental recovery with wedge wells 40% Percent recovery without wedge wells 20% 0% Year *Percent recovery of exploitable bitumen in place. Technology - improving efficiencies Electric drilling rigs 3 rigs at Foster Creek & Christina Lake In use since 2005 Improves efficiency, reduces operating costs Lower emissions Greater than 65% reduction in CO 2 vs. a typical diesel powered rig Blowdown boiler Blowdown water from one boiler used as feed water for second boiler Generates more steam from the same water Less waste water disposal Improved heat recovery lowers operating costs and emissions 13

14 Canadian & US crude oil pipeline proposals Kinder Morgan TMX Northern Leg 400 Mbbls/d Enbridge Gateway 500 Mbbls/d TBD TransCanada Keystone Enbridge Alberta Clipper Cushing Extension Southern Access Expansion Heartland Extension Southern Access Extension 435 Mbbls/d June 155 Mbbls/d Mbbls/d July Mbbls/d TBD 400+ Mbbls/d TBD 600 Mbbls/d Kinder Morgan TMX2 Expansion 80 Mbbls/d TMX3 Expansion Enbridge Ohio Access 320 Mbbls/d Mbbls/d TBD Enbridge Line 9 Reversal (Trailbreaker) 215 Mbbls/d TBD Portland Pipeline Reversal 200 Mbbls/d TBD TransCanada Keystone XL 700 Mbbls/d 2013 Sunoco Buffalo to Philadelphia New Line BP/Enbridge GAP reversal Flanagan-Cushing 400 Mbbls/d TBD Marysville to Toledo Expansion Mbbls/d Mbbls/d TBD Muskeg Expansion 38 Mbbls/d TBD ExxonMobil/Enbridge Pegasus Expansion 30 Mbbls/d June 2009 Texas Access New Line 445 Mbbls/d TBD Sunoco to USGC 300 Mbbls/d TBD TransCanada Louisiana Access Scope TBD Source: CAPP Downstream overview Top quality refinery assets Wood River (Post-CORE) 356 Mbbls/d crude throughput 240 Mbbls/d heavy crude capacity ~89% clean product yield Borger 146 Mbbls/d crude throughput 35 Mbbls/d heavy crude capacity ~89% clean product yield Integration strategy Capture full value chain - bitumen to transportation fuels Minimize risk - reduce exposure to light / heavy differential Continue to optimize Wood River and Borger to increase heavy processing capacity Volumes are shown on a 100% basis. 14

15 Bitumen value chain net margin Share of bitumen value chain margin 100% History of margin sharing 0% Total net margin available for one bbl of bitumen refined into transportation fuels. Downstream margin based on Purvin & Gertz PADD II heavy refining margin. Upstream margin based on Purvin & Gertz bitumen field price and average SAGD opex assuming a 2.5 SOR. Source: Purvin & Gertz, CVE Downstream net margin Upstream net margin Bitumen integration strategy Mbbls/d Downstream bitumen equivalent processing capacity Annualized bitumen production Post 2012 long bitumen F 2011F 2012F 2013F 2014F 2015F 2016F 2017F 2018F 2019F Volumes are shown before royalties and net to CVE (50% basis). 15

16 Wood River CORE project Increases overall capacity 50 Mbbls/d of increased crude throughput 130 Mbbls/d of increased heavy crude capacity - lowers crude input costs ~10% increase in clean product yield ~$4.00/bbl margin improvement Completion mid-2011 (Coker) 9 of 21 scope areas already complete Final cost forecast to be within 10% of budget Volumes are shown on a 100% basis. Offloading modules 16

17 CORE project - new units area High quality refinery assets US refining infrastructure 35 Baker O Brien complexity index Borger Wood River post-core CORE Project Wood River pre-core

18 Building value Top quality assets Foster Creek and Christina Lake are recognized as best in industry Significant growth opportunity Potential for greater than 245,000 bbls/d (net) of production capacity at Foster Creek and Christina Lake Experienced SAGD operator A proven track record Low cost capital and operating structures Technology leader Full value chain integration Natural gas - heavy oil production - refining CORE on-stream mid-2011 Supplemental information 18

19 Foster Creek summary F Production (bbls/d) 37,725 46,000 50,000 Net wells drilled (1) Capital ($ MM) Operating cash flow (2) ($ MM) Operating costs ($/bbl) Acreage (year end, net acres) Proper/Core area 36,000 Average royalty (%) SOR Supply cost US$/bbl (3) (1) Includes well pairs and wedge wells, excludes strat wells. (2) Operating cash flow is a non-gaap measure. Numbers shown include hedges. (3) Average WTI or NYMEX price required for an after-tax cost of capital return of 9%. Foster Creek overview Producing formation: McMurray Multiple stacked channels ~450 m reservoir depth Up to 40 m+ net pay (average 25 m) High permeability (5-10 Darcies) High oil saturation (~80%) 9 11 API bitumen No significant gas caps or formation water ALBERTA Cenovus land at Dec. 31, Mbbls/d Net before royalties Oilsands leases P&NG leases Foster Creek proper F 2011F 2012F 2013F 2014F 19

20 Christina Lake summary F Production (bbls/d) 6,698 7,200 7,700 Net wells drilled (1) 0 25 Capital ($ MM) Operating cash flow (2) ($ MM) Operating costs ($/bbl) Acreage (year end, net acres) Proper/Core area 12,000 Average royalty (%) SOR Supply cost US$/bbl (3) (1) Includes well pairs plus wedge wells, excludes strat wells. (2) Operating cash flow is a non-gaap measure. Numbers shown include hedges. (3) Average WTI or NYMEX price required for an after-tax cost of capital return of 9%. Christina Lake overview Producing formation: McMurray Multiple stacked channels Reservoir depth ~375 m Up to 47 m+ net pay (average m) High permeability (5-10 Darcies) High oil saturation (~80%) API bitumen Gas cap and bottom water present ALBERTA Cenovus land at Dec. 31, Mbbls/d Net before royalties Oilsands leases P&NG leases Christina Lake proper F 2011F 2012F 2013F 2014F 20

21 Western Canadian Sedimentary Basin pipelines Mbbl/d Existing and Planned Pipeline Project Capacity (Unrisked) Proposed projects 6,500 6,000 5,500 5,000 4,500 CAPP supply forecast (June 2009) 200 6, Alberta Clipper Expansion TMX Northern Leg (Kitimat) Enbridge Northern Gateway Keystone XL (Expansion) Existing and approved projects 4,000 3,500 3,000 2,500 2,000 1,500 2, ,935 1,870 1,870 1,870 1,870 1,870 1,870 1,870 1,870 1,870 1,870 TMX-2 & 3 (Vancouver) Keystone XL (Base) Keystone Legacy & Expansion Enbridge Alberta Clipper (Base) Enbridge (Base) 1,000 TMPL (Land) Express Pipeline Proposed projects illustrate number of pipelines competing for next expansion WRB refinery statistics Crude throughput, Mbbls/d Coking capacity, Mbbls/d Bitumen processing equivalent, Mbbls/d Heavy crude processing Mbbls/d Baker O Brien complexity Wood River pre-core Wood River post-core Borger Figures represent 100% of the Wood River and Borger refinery operations. 21

22 Representative crude slates & yields Refinery inputs - % crude slate Refinery output - % yield 100% 75% 50% 25% 0% WR current WR post-core Borger WR current WR post-core Borger Heavy Medium sour Light sweet Other products Distillates * Other clean products Motor fuels** *Distillates include diesel and jet fuel. **Motor fuels includes all blends of gasoline. Downstream margin sensitivity Net margin ($/bbl) $4 Wood River (pre-core) and Borger crack spread ($/bbl) Base +$1 +$2 $3 $2 $1 $- $0 +$1 +$2 +$3 +$4 WCS differential ($/bbl) 22

23 Downstream margin sensitivity Net margin ($/bbl) $4 Wood River (post-core) and Borger crack spread ($/bbl) Base +$1 +$2 $3 $2 $1 $- $0 +$1 +$2 +$3 +$4 WCS differential ($/bbl) Oil & gas information The resources estimates were prepared effective December 31, 2009 by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator (IQRE), and other than as disclosed herein are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook (COGEH). For further discussion regarding our economic contingent resources and our total bitumen initially-in-place and all subcategories thereof, see our April 22, 2010 news release and our June 16, 2010 news release, respectively, available at Actual resources may be greater than or less than the estimates provided. Total Bitumen Initially-In-Place (BIIP) (equivalent to total resources ) is that quantity of bitumen that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of bitumen 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. BIIP estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered. Discovered Bitumen Initially-In-Place (equivalent to discovered resources ) is that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered bitumen initially-in-place includes production, reserves, and contingent resources; the remainder is categorized as unrecoverable. There is no certainty that it will be commercially viable to produce any portion of the estimate. Undiscovered Bitumen Initially-In- Place (equivalent to undiscovered resources ) is that quantity of bitumen that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered bitumen initially-in-place is referred to as prospective resources, the remainder as unrecoverable. There is no certainty that any portion of the estimate will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Exploitable Bitumen Initially-In-Place is the estimated volume of bitumen, before any production has been removed, which is contained in a subsurface stratigraphic interval that meets or exceeds certain reservoir characteristics considered necessary for the commercial application of known recovery technologies. Examples of such reservoir characteristics include continuous net pay, porosity, and mass bitumen content. This definition was derived from and is consistent with current draft proposed COGEH terminology. Contingent resources those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. For Cenovus, the contingencies which must be overcome to enable the classification of bitumen contingent resources as reserves include regulatory application submission with no major issues raised, access to markets and intent to proceed by the operator and partners as evidenced by major capital expenditures planned within five years. The estimate of contingent resources has not been adjusted for risk based on the chance of development. There is no certainty that it will be commercially viable to produce any portion of the resources. Economic contingent resources those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The IQRE used the same commodity price assumptions that were used for the 2009 reserves evaluation, which were determined in accordance with U.S. Securities and Exchange Commission requirements. Prospective resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. Unrecoverable is that portion of discovered or undiscovered BIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. Proved reserves are those quantities of bitumen, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. Probable reserves are those additional reserves of bitumen that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered. Our disclosure of annual reserves data is made in accordance with U.S. disclosure requirements pursuant to an exemption received from the Canadian Securities Administrators. Accordingly, the proved plus probable reserves data may differ from corresponding information prepared in accordance with NI See Note Regarding Reserves Data and Other Oil and Gas Information in Cenovus s 2009 Annual Information Form (AIF). 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. 23

24 Forward-looking information This presentation contains certain forward-looking statements and information about our current expectations, estimates and projections about the future, based on certain assumptions made by the Company in light of its experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Forward-looking statements are typically identified by words such as anticipate, believe, expect, plan, intend, forecast or F, target, project, objective, could, focus, goal, proposed, scheduled, outlook, potential, may or similar expressions suggesting future outcomes or statements regarding an outlook, including statements about our strategy, our projected future value or net asset value, schedules, land positions, production, including, without limitation, the stability or growth thereof, reserves and resources estimates, material properties, uses and development of our technology, risk mitigation efforts, commodity prices, shareholder value, cash flow, funding alternatives, costs and expected impact of future commitments in respect of our ongoing operations generally and with respect to certain properties and interests held by Cenovus. Readers are cautioned not to place undue reliance on forward-looking statements and information as our actual results may differ materially from those expressed or implied. Forward-looking statements involve a number of assumptions, risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The risk factors and uncertainties that could cause actual results to differ materially, and the factors or assumptions on which the forward-looking information is based, include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions inherent in our current guidance; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; the effect 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, 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; success of hedging strategies; maintaining a desirable debt to cash flow ratio; accuracy of our reserves, resources and future production estimates; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; 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 the North American integrated heavy oil business and to obtain necessary regulatory approvals; the successful and timely implementation of capital projects; reliability of our assets; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; 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 synthetic crude oil; risks associated with technology and its application to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or the interpretations of such laws or 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 us, 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, hostilities, civil insurrection and instability affecting countries in which we operate; risks associated with existing and potential future lawsuits and regulatory actions made against us; our financing plans and initiatives; the historical financial information pertaining to our assets as operated by Encana prior to November 30, 2009 may not be representative of our results as an independent entity; our limited operating history as a separate entity and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. The forward-looking statements and information contained in this presentation, including the assumptions, risks and uncertainties underlying such statements, are made as of the date of this presentation. Many of these risk factors are discussed in further detail in our 2010 First Quarter Report to Shareholders, our 2009 AIF/Form 40-F and our MD&A for the year ended December 31, 2009, each as filed at and and available at The Cenovus 2010 Corporate Guidance, including the assumptions on which it is based, is available at Non-GAAP measures (Operating Earnings, Operating Cash Flow, Cash flow, Free Cash Flow, Capitalization and Adjusted EBITDA) 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. Please see our 2010 First Quarter Report to Shareholders for a full discussion of the use of each measure. 24