Financial strategy supports business plan

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1 Financial strategy supports business plan Ivor Ruste Executive Vice-President & Chief Financial Officer Investor Day Calgary December 7, 2011 Financial strategy supports business plan Support long-term objectives with 2012 budget Build flexibility into capital programs Maintain balance sheet strength to provide capacity Ensure continuous & cost effective access to capital Manage financial risk Maintain financial strength to support oil development & dividend growth strategy Focused on increasing total shareholder return 1

2 Well positioned in 2012 Enhancing financial capacity completed bank facility renewal & expansion in 2011 Maintaining consistency with 10-year business plan maintain operating & capital cost discipline manage natural gas as a financial asset manage risk through integrated approach Ensuring flexibility through conventional programs 40% of 2012 budget is discretionary Capital investment focused on oil growth 2012 capital budget: $3.1 - $3.4 B CVE wide 6% Natural gas 3% Refining 5% Foster Creek 21% Conventional oil 21% Christina Lake 15% New resource plays 12% Pelican Lake 17% 91% oil-directed* ~65% contributes to growth beyond 2012 ~$2.0 billion or 60% is committed capital *Oil-directed spending includes upstream oil and refining capital expenditures. 2

3 Integrated oil drives operating cash flow * 100% 80% 85% 60% 64% 80% Price Exposed 165 MMcf/d (25%) 40% 20% 0% F 2012F Foster Creek & Christina Lake Pelican Lake Conventional oil Refining & Marketing Natural gas *Operating cash flow is a non-gaap measure. See advisory. Building flexibility into capital programs $ billions 7 Discretionary capital Committed capital 6 Cash flow F 2012F 2013F 2014F 2015F Average (2016F F) 2011F based on the October 27, 2011 guidance document. 2012F based on the December 7, 2011 guidance document. 2013F through 2021F based on future price assumptions as noted in the advisory. 3

4 Balance sheet strength provides capacity Significant liquidity & long dated debt maturities US$3.5 billion in notes maturing in 2014, 2019 & 2039 $3.0 billion committed credit facility due November 30, 2015 $1.5 billion shelf prospectus in place in Canada US$1.5 billion shelf prospectus in place in U.S. Strong balance sheet supports credit ratings Debt to Capitalization* Debt to Adjusted EBITDA* Q % 1.1x Target range 30 40% x *Non-GAAP measures. See advisory. Balance sheet strength provides capacity Debt to Capitalization* Percent 40% Target range Debt to Adjusted EBITDA* Times 2.0 Target range 30% % % 0.5 0% F 2012F 2013F 2014F 2015F Average (2016F F) F 2012F 2013F 2014F 2015F Average (2016F F) 2011F based on commodity price assumptions as outlined in the October 27, 2011 guidance document. 2012F through 2021F based on future price assumptions as noted in the advisory. *Non-GAAP measure. See advisory. 4

5 Sensitivities to price changes Independent sensitivities WTI oil + US$10 -US$10 NYMEX natural gas + US$1 -US$1 Light-heavy oil differential widens: (WTI WCS) + US$5 tightens: (WTI WCS) - US$5 Impact on 2012F cash flow ($ millions) 185 (185) 60 (60) (15) 30 Sensitivities based on assumptions noted in 2012 guidance: WTI US$90.00/bbl; Light-heavy differentials US$15.00/bbl; Chicago crack spread US$14.50/bbl; NYMEX US$3.50/Mcf; and a foreign exchange rate of $0.975 US$/C$. Sensitivities include hedge positions as at September 30, Note: Cash flow is a non-gaap measure. See advisory. Managing financial risk is critical Use commodity price hedging for cash flow certainty Integrate upstream & refining cash flows Achieve economic hedge from internal natural gas consumption Apply prudent financial policies Monitor credit & procurement activities 5

6 Managing commodity price risk 2012 Oil hedge positions 2012 Natural gas hedge positions WTI NYMEX Fixed US$96.57/bbl 37 Mbbls/d (23%) Unhedged* 126 Mbbls/d (77%) Unhedged* 180 MMcf/d (30%) NYMEX Fixed Price Exposed 165 MMcf/d US$ 5.82/Mcf (25%) AECO/NYMEX 351 MMcf/d Fixed (53%)& internal use* US$5.05/Mcf** 408 MMcf/d (70%) Hedge positions as at September 30, *Unhedged production volumes and internal natural gas use are based on 2012 guidance midpoints. **Natural gas hedge price excludes internal use. Dividend contributes to total shareholder return Dividends provide good capital discipline Current dividend $0.20/share per quarter; ~$600 million annually Dividend growth requires strong financial health sustainable pace of development reliable, predictable cash flow Financial capacity allows the Board of Directors to consider a dividend increase in

7 Financial strategy supports business plan Support long-term objectives with 2012 budget Build flexibility into capital programs Maintain balance sheet strength to provide capacity Ensure continuous & cost effective access to capital Manage financial risk Maintain financial strength to support oil development & dividend growth strategy Focused on increasing total shareholder return Supplemental information 7

8 Key credit metrics & ratings Credit metrics Q Q Target range Debt to capitalization* 28% 29% 30 40% Debt to adjusted EBITDA* 1.1x 1.3x x Total debt* $3,617 $3,432 Credit ratings S&P (13-Oct-2011) Moody s (10-Aug-2011) DBRS (27-Jul-2011) Long-term BBB+ Stable Baa2 Stable A (low) Stable Short-term A-1 (Low) P-2 R-1 (Low) * Non-GAAP measures. See advisory. Managing commodity price risk 2012 Oil hedge positions 2012 Natural gas hedge positions Unhedged* 126 Mbbls/d (77%) Unhedged* 180 MMcf/d (30%) WTI NYMEX Fixed US$98.24/bbl 19 Mbbls/d (12%) WTI NYMEX Fixed $98.52/bbl 18 Mbbls/d (11%) NYMEX Fixed Price Exposed NYMEX Fixed 165 MMcf/d US$ 5.82/Mcf US$5.96/Mcf (25%) Internal use* 351 MMcf/d MMcf/d (53%) MMcf/d (22%) (20%) AECO Fixed $4.50/Mcf 127 MMcf/d (22%) Fixed Term Sales 33 MMcf/d US$4.30 MMBtu (6%) Hedge positions as at September 30, *Unhedged production volumes and internal natural gas use are based on 2012 guidance midpoints. 8

9 Capital spending ($ MM) F 2012F Oil sands Foster Creek Christina Lake New resource plays Pelican Lake Conventional oil & liquids Natural gas Refining Corporate Total 2,115 2,650 3, F and 2012F based on guidance midpoints. Note: Totals may not add due to rounding. Continuing A&D program core assets drive value Divestiture strategy target $100 - $150 MM in 2012 monetize non-core assets no need to sell assets at distressed prices Acquisition strategy minor tuck-in or swap opportunities No A&D activity included in 2012 guidance 9

10 Forward looking information The presentations and posters at Investor Day 2011 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 2011 guidance is based include actual prices for the first 9 months of 2011 and September 30 strip pricing for the remainder of the year and an average number of shares outstanding of approximately 758 million. Approximate September 30 strip prices: WTI of US$79.40/bbl; Western Canada Select of US$69.25/bbl; NYMEX of US$3.80/MMBtu; AECO of $3.50/GJ; Chicago Crack Spread of US$31.95; and exchange rate of $0.961 US$/C$. For the period 2013 to 2021 assumptions include WTI of US$85.00-US$105.00/bbl; Western Canada Select of US$71.00-US$85.00/bbl; NYMEX of US$4.00-US$6.00/MMBtu; AECO of $3.30-$5.25/GJ; Chicago crack spread of US$9.00; exchange rate of $0.98-$1.07 US$/C$; and average number of shares outstanding of approximately 752 million guidance is based on an average diluted number of shares outstanding of approximately 759 million. It assumes WTI of US$90.00/bbl; Western Canada Select of US$75.00/bbl; NYMEX of US$3.50/MMBtu; AECO of $3.10/GJ; Chicago Crack Spread of US$14.50; and exchange rate of $0.975 US$/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, For a full discussion of our material risk factors, see Risk Factors in our 2010 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, 2010, and the discovered bitumen initially-in-place estimates, effective December 31, 2009, 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 2010 Annual Information Form (AIF) and (ii) our total bitumen initially-in-place and all subcategories thereof, see our June 16, 2010 news release, available on SEDAR at and at Actual resources may be greater than or less than the estimates provided. As at December 31, 2009, Discovered Bitumen Initially-in-Place (BIIP) company-wide, best estimate, is 56 Bbbls, including 0.1 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, 2010, proved plus probable reserves were Bbbls and contingent resources were 6.1 Bbbls. As at December 31, 2010, 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 40-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. 10

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