Cenovus Energy
Annual Report 2010

Plain-text annual report

the cenovus equation 20 10 ann ual report t h e C e n o v u s e Q u a t i o n 2 0 1 0 a n n u a l r e p o r t . w w w c e n o v u s . c o m Brian Ferguson talks about Cenovus, our operations and how we’re doing things differently. Want to see the video? Download a free Qr code reader on your mobile browser. Front cover: Staff from our Christina Lake site Cenovus energy inC . 421 – 7 avenue sW po Box 766 Calgary, alberta, Canada t2p 0M5 printed in Canada. We aRe a canaDian oiL coMP anY aPPLYinG FResh, PRoGRessive thinKinG: to safely and responsibly unlock energy resources the world needs – that’s our promise. to increase total shareholder return – that’s our goal. pictured here is Foster Creek, our largest steam-assisted gravity drainage (sagD) project, situated on the Cold lake air Weapons range in northern alberta. Corporate Information e xeCutive oFFiCers Brian C. Ferguson president & Chief executive officer John K. Brannan executive vice-president & Chief operating officer harbir s. Chhina executive vice-president, oil sands Kerry D. Dyte executive vice-president, general Counsel & Corporate secretary Judy a. Fairburn executive vice-president, environment & strategic planning sheila M. Mcintosh executive vice-president, Communications & stakeholder relations ivor M. ruste executive vice-president & Chief Financial officer Donald t. swystun executive vice-president, refining, Marketing, transportation & Development hayward J. Walls executive vice-president, organization & Workplace Development BoarD oF DireCtors Michael a. grandin(1)(4)(8) Chair, Calgary, alberta ralph s. Cunningham(1)(3)(4)(6) houston, texas patrick D. Daniel(1)(2)(3)(4) Calgary, alberta ian W. Delaney(1)(3)(4)(6) toronto, ontario Brian C. Ferguson(7) Calgary, alberta valerie a. a. nielsen(1)(2)(4)(5) Calgary, alberta Charles M. rampacek(4)(5)(6) Dallas, texas Colin taylor (2)(3)(4) toronto, ontario Wayne g. thomson(1)(4)(5)(6) Calgary, alberta (1) Former director of encana. (2) Member of the audit committee. (3) Member of the human Resources and compensation committee. (4) Member of the nominating and corporate Governance committee. (5) Member of the Reserves committee. (6) Member of the safety, environment and Responsibility committee. (7) as an officer and a non-independent director, Mr. Ferguson is not a member of any of the committees of our Board. (8) ex-officio non-voting member of all other committees of our Board. Cenovus he aD & registereD oFFiCe cenovus energy inc. 421 – 7 avenue s.W. Po Box 766 calgary, alberta, canada t2P 0M5 Phone: 403-766-2000 www.cenovus.com Shareholder Information annual Meeting shareholders are invited to attend the annual meeting being held on Wednesday, april 27, 2011 at 2 p.m. (calgary time) at the teLus convention centre, exhibition hall e, 2nd Floor, north Building, 136 – 8 avenue s.e., calgary, alberta. Please see our management proxy circular mailed to shareholders and posted on our website, www.cenovus.com, for additional information. transFer a gents & registrar in canada, ciBc Mellon trust company in calgary, Montreal & toronto. in the united states, BnY Mellon in Jersey city, new Jersey. shareholders are encouraged to contact ciBc Mellon trust company for information regarding their security holdings. they can be reached throughout north america by phoning 1-866-332-8898 (english & French) and outside north america by phone at 1-416-643-5850 or by facsimile at 1-416-643-5501. Canadian stock transfer Company CiBC Mellon trust Company Po Box 7010 adelaide street Postal station toronto, ontario, canada M5c 2W9 www.cibcmellon.com canadian stock transfer company inc. recently purchased the transfer agency business from ciBc Mellon. canadian stock transfer company inc. is operating the transfer agency business in the name of ciBc Mellon trust company for a transition period. shareholDer aCCount Matters to change your address, transfer shares, eliminate duplicate mailings, deposit dividends directly into accounts at financial institutions in canada that provide electronic fund-transfer services, etc., please contact ciBc Mellon trust company. stoCK e xChanges common shares (cve) trade on the toronto stock exchange (tsX) and the new York stock exchange (nYse). annual inForMation ForM / ForM 40-F our annual information Form is filed with the canadian securities administrators in canada on seDaR at www.sedar.com and with the u.s. securities and exchange commission under the Multi- Jurisdictional Disclosure system as Form 40-F on eDGaR at www.sec.gov. nyse s tat eMent oF DiFFerenCes as a canadian company listed on the new York stock exchange (nYse), we are not required to comply with most of the nYse corporate governance standards and instead may comply with canadian corporate governance requirements. We are, however, required to disclose the significant differences between our corporate governance practices and those required to be followed by u.s. domestic companies under the nYse corporate governance standards. except as summarized on our website, www.cenovus.com, we are in compliance with the nYse corporate governance standards in all significant respects. investor rel ations Please visit the Invest In Us section of www.cenovus.com for investor information. investor inquiries should be directed to: 403-766-7711 investor.relations@cenovus.com or susan grey Director, investor Relations 403-766-4751 susan.grey@cenovus.com Media inquiries should be directed to: 403-766-7751 media.relations@cenovus.com or rhona DelFrari Manager, Media Relations 403-766-4740 rhona.delfrari@cenovus.com 133 · c oRPoRate anD sh aRehoLDeR inFoRMat i on · ce n ov us 20 10 a nn u aL RePoR t . c n i e v i t a e r c y r d n u o F y b d e c u d o r p d n a d e n g i s e D see how we add up OUR ABILITY TO ACHIEVE OUR PROMISE AND OUR GOAL REQUIRES A GREAT ASSET BASE AND THE RIGHT PEOPLE DOING THE RIGHT THINGS. WE HAVE BOTH. THE CENOVUS EQUATION SHOWS HOW WE ADD UP. This page We grow our oil sands projects in phases. Construction is currently underway for phases C and D at Christina Lake. phase C, a 40,000 barrel-per-day expansion is expected to be completed in 2011. FaCing page The majority of Cenovus’s natural gas production comes from our shallow gas operations in southern alberta. pictured here is a drilling rig near Brooks. to results OUR GREAT ASSETS PROVIDE THE fOUNDATION fOR YEARS Of ENERGY DEVELOPMENT . We have an industry-leading portfolio of oil sands assets, two high-quality refining assets, a strong balance sheet, and low-cost conventional oil and natural gas operations that generate substantial operating cash flow. This page (CLoCkWise) a pumpjack at our Weyburn facility in saskatchewan / a natural gas wellhead near Brooks, alberta / The Wood River Refinery in Roxanna, illinois jointly owned with Conocophillips. FaCing page We’re always looking for ways to improve how we get our resources out of the ground. pictured here is equipment used for the solvent aided process (sap) at Christina Lake. sap is a technology we’re piloting. it helps maximize the amount of oil recovered using sagD while reducing the environmental impact. QUALITY RESOURCES + fINANCIAL STRENGTH = great assets WE TAKE OUR COMMITMENT TO SMART RESOURCE DEVELOPMENT SERIOUSLY. WE AIM TO MAXIMIZE VALUE fOR OUR SHAREHOLDERS WHILE SEEKING TO BALANCE ECONOMIC, SOCIAL AND ENVIRONMENTAL PERfORMANCE. This commitment guides the way we conduct our operations and is the foundation of our 10-year business plan. This page (CLoCkWise) speaking with a landowner / a Cenovus employee taking water samples / oil storage pipe racks coated with fire proofing leaving our module fabrication yard in nisku for our Christina Lake facility. FaCing page our environmental specialists inspect and analyze the land we’ll be using for our drilling activities before any operations begin. They then develop a plan that will reclaim the land once a well is depleted. pictured here is new growth in the forest near our Foster Creek project. STRONG EXECUTION + RESPONSIBLE OPERATIONS = smart resource development WE HAVE A CULTURE THAT fOSTERS NEW IDEAS AND NEW APPROACHES IN ALL ASPECTS Of OUR BUSINESS. In our operations, technology plays a key role in extracting the resources – enhancing the amount recovered and improving the methods we use to get the oil and natural gas out of the ground. An ongoing objective is to advance innovative technologies that reduce the amount of land, water and energy we use. This page (CLoCkWise) Foster Creek control room / Building a culture of knowledge sharing through staff information sessions / solar panels in some of our operations provide power to remote instruments, allowing for data communication back to our main facility / staff at our Weyburn facility. FaCing page The plants at our oil sands facilities are largely water plants that require a complex system of pipes to transport steam and fluids used in the sagD process. pictured here is our Christina Lake facility.  INNOVATION + CONTINUOUS IMPROVEMENT = leading technology WE HAVE YEARS Of EXPERIENCE IMPROVING WHAT WE DO. A TRACK RECORD Of DELIVERING GREAT PERfORMANCE. A PASSION fOR RESULTS. The people at Cenovus are dedicated and enthusiastic about improving every aspect of our business. Experienced in turning ideas into action, and committed to doing right by the environment and our communities. We are proud to have the right people doing the right things to provide the energy resources the world needs and relies on every day. This page (CLoCkWise) adjusting a bolt on a pumpjack in Langevin / Cenovus staff in a meeting / operators at Christina Lake. FaCing page at Cenovus it’s important our equipment is operating at an optimal level. our employees are always looking for ways to improve equipment reliability and performance. pictured here is a mechanic at our Weyburn facility completing preventative maintenance on mechanical components. KNOWLEDGE + DEDICATION = the right people our people bring energy, focus and dedication to their work. pictured here is an operator at Christina Lake. CENOVUS 201 0 A NNUA L REPO RT · S E CTI ON TI TL E · 12 As a company we are: Rigorous. Respectful. Ready. We have the resource, the strategy and a track record of strong results. As a team, we have the passion for operational excellence, the commitment to finding better ways of doing things and respect for the environment and the communities where we live and work. That’s how we add up to results. 13 · SECTION TITLE · CENOVUS 2 01 0 ANNUAL REPO RT great assets sMart resOUrCe DeVeLOPMeNt LeaDiNg teChNOLOgythe right PeOPLecenovusOperating adjustments may be required to ensure our treated oil meets pipeline sales specifications before it’s shipped to market. Pictured here is an operator conducting oil sampling at foster Creek. TaBLe oF C onTenT s Strategy snapshot ........................................................................................................................................................................................................................................................................................ 16 Meet our Executive Team ........................................................................................................................................................................................................................................................................ 19 Message from our President & Chief Executive Officer ............................................................................................................................................................................................................ 21 Q&A with our Chief Operating Officer ..............................................................................................................................................................................................................................................23 2010 year in review ...................................................................................................................................................................................................................................................................................... 25 Meet our employees .................................................................................................................................................................................................................................................................................. 29 Meet our Board of Directors ................................................................................................................................................................................................................................................................... 31 Message from our Board Chair ...............................................................................................................................................................................................................................................................32 Operating and financial highlights ........................................................................................................................................................................................................................................................33 Management’s discussion and analysis .............................................................................................................................................................................................................................................. 34 Consolidated financial statements ...................................................................................................................................................................................................................................................... 78 Notes to consolidated financial statements .................................................................................................................................................................................................................................. 85 Supplemental information .................................................................................................................................................................................................................................................................... 120 Reserves data and other oil and gas information ........................................................................................................................................................................................................................126 Corporate and shareholder information ......................................................................................................................................................................................................................................... 133 Fccl/wrB partnership our business venture with Conocophillips provides integration of oil sands and refining operations. This venture provides Cenovus with a 50 percent interest in the Wood River (illinois) and Borger (Texas) refineries; in return Conocophillips has a 50 percent interest in certain Cenovus oil sands properties, notably Foster Creek, Christina Lake and narrows Lake. For additional information, see our MD&a. Forward-looking information Our Annual Report contains forward-looking information about our strategy, milestones, goals, targets and future expectations. This forward-looking information is based non-gaap measures Our Annual Report contains references to certain financial measures which do not have a standardized meaning as prescribed by GAAP. A description of each non-GAAP on certain factors and assumptions and is subject to risks and uncertainties, some of which are specific measure, including a definition and reconciliation with GAAP measures, is included in our MD&A. to Cenovus and others that apply to the industry generally. for details about these factors, assumptions, risks and uncertainties, please refer to the Advisory section in our MD&A. All estimated timelines are subject to regulatory and/or partner approval. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied. for an overview of our risk management, see the Risk Management section of our MD&A. oil and gas information Our Annual Report contains information about our reserves and our bitumen resources. for additional information about our reserves, contingent and prospective resources, see the Oil and Gas Reserves and Resources section of our MD&A and the Advisory section of our MD&A. for additional information about our total and discovered bitumen initially-in-place, see the Additional Advisory on page 132. 15 · TABLE Of CONTENTS · CENOVUS 201 0 ANNUAL REP ORT sTRa TegY snapsho T Increasing total return to our shareholders is the cornerstone of our 10-year business plan. With our high-quality oil opportunities, our track record of strong execution and our financial strength, we plan to achieve increased shareholder return in two ways: naV is a comprehensive measure well suited to the long-term nature of oil sands development. doublE NAV * by 2015 & pAy A stroNg ANd sustAiNAblE diVidENd iNcrEAsE oil sANds productioN from 60thousANd bbls/d† iN 2010 to 300thousANd bbls/d† iN 2019 We plan to maintain financial flexibility and optimize cash flow to grow our business and provide an income stream to shareholders. mAiNtAiN stroNg pErformANcE from coNVENtioNAl oil ANd NAturAl gAs AssEts * NAV: Net asset value (total value of assets minus total value of liabilities) † Net to Cenovus CENOVUS 201 0 A NNUA L REPO RT · S TRATE GY S NA PSHOT · 16 sTRa Teg Y snapsho T We plan to double net asset value and pay a strong and sustainable dividend by leveraging these three strategic advantages: oil opportunities track record of performance financial strength bArrEls of discoVErEd biip* 56 billioN AmouNt dEfiNEd through drilliNg 14 yEArs oil sANds opErAtiNg history iNtErNAlly fuNdEd growth through stroNg cAsh flow ANd bAlANcE shEEt Vast majority of our total proved + probable reserves are bitumen, conventional oil and ngLs** – 88% of 2.4 billion barrels of oil equivalent. growth driVEr: oil Track record of being a low-cost operator who delivers strong financial results. We have best-in- class capital efficiencies, low soRs*** and a manufacturing approach to our business. increasing contribution to upstream operating cash flow from oil and ngLs. 2010: 63% 2019F: 80% goal: increase oil sands production five-fold by the end of 2019 by: • converting resources into reserves • continuing development of our high-quality, low-cost, oil sands projects • advancing regulatory approvals • advancing emerging oil sands projects projEct ApproVAls 400 to 500 thousANd bbls/d† by 2015 tEchNology iNNoVAtioN soR is the amount of steam needed to produce a barrel of oil, a key measure of efficiency for operations using sagD technology. a low soR means you’re more energy efficient, have lower costs and have a smaller environmental impact. We continue to be committed to improving our recovery rates and reducing our impact on the environment. our investment grade credit ratings reflect our quality assets, solid capital structure, financial flexibility and significant liquidity. our established base of conventional oil and natural gas assets generates operating cash flow to fund our oil sands growth. our hedging program manages commodity price exposure and locks in cash flow. *BIIP: bitumen initially-in-place; see Additional Advisory on page 132 **NGLs: natural gas liquids ***SOR: steam to oil ratio † Net to Cenovus 17 · STRATEGY SNAPSHOT · CENOVU S 20 10 ANNUA L REPORT sTRa TegY snapsho T – MiLes Tones Delivering on our business plan: We have set specific milestones to measure our achievements as we grow our business and build NAV. 2010 2011f 2012f achieved milesto ne s mile stones se t so F ar mile stones se t so F ar shaped our teams, systems and culture; developed our policies and practices; and set the strategic direction for our company announced plan to increase oil sands production to 300,000 bbls/d net by end of 2019 assessed oil sands resources, disclosed bitumen initially-in-place and provided more details about how we will grow our oil sands projects grew reserves and contingent resources submitted regulatory application for narrows Lake (one of our emerging oil sands projects) Received regulatory approval and initiated sanctioning process for Foster Creek phases F, g & h Received regulatory approval for grand Rapids sagD pilot project and began first steam Restructured our internal organization to better align with our business plan Delivered excellent operating and financial results Divested non-core assets established long-term agreement with Conklin community grow reserves and contingent resources grow reserves and contingent resources execute stratigraphic well program (drill 450 wells) and assess results initiate sanctioning process for narrows Lake phases a, B & C advance environment key performance indicators and long-term impact forecasting Drill 400 to 500 stratigraphic wells and assess results sanction Foster Creek phases F, g & h implement at least one new commercial technology from Cenovus’s R&D program achieve first production at Christina Lake phase C start gas cap air injection for thermal oil recovery pilot at Clearwater anticipate receipt of regulatory approval for Christina Lake phases e, F & g and commence sanctioning process for e increase production from pelican Lake Wabiskaw expand the polymer flood and drill additional infill wells at pelican Lake, which is expected to result in higher production submit grand Rapids regulatory application for a commercial operation start up coker as part of Wood River CoRe project implement the Cenovus operations Management system (CoMs) implement at least one new commercial technology from Cenovus’s R&D program integrate the six commitment areas of our Corporate Responsibility policy into the company’s business strategy in order to create value for both our business and the communities where we live and work CENOVUS 201 0 A NNUA L REPO RT · S TRATE GY S NA PSHOT – M IL ESTON ES · 18 MeeT ouR e xeCuTiVe Te aM The Cenovus Executive Team members bring expertise and energy to their roles. Collectively, they inspire our teams and steer the success of our business. BROAD KNOWLEDGE + COLLABORATIVE APPROACH = strong leadership (Pictured left to right) iVoR M. Rus Te executive Vice-president & Chief Financial officer JuDY a . FaiRBuRn executive Vice-president, environment & strategic planning keRRY D . DYTe executive Vice-president, general Counsel & Corporate secretary haR BiR s . Chhin a ha YWaRD J. WaLLs executive Vice-president, oil sands J ohn k . BRannan executive Vice-president & Chief operating officer BRian C . FeR guso n executive Vice-president, organization & Workplace Development sheiL a M. MC inT os h executive Vice-president, Communications & stakeholder Relations president & Chief executive officer Do n T . sWY sTun executive Vice-president, Refining, Marketing, Transportation & Development 19 · MEET OU R E XECUTIVE TE AM · CENOVU S 20 10 ANNUAL REPORT MeeT ouR e xeCuTiVe Te aM Everything we do is about increasing the value of the company. Our goal is to double our net asset value by 2015. BRian FeR guson Engaging with our various stakeholders and telling the Cenovus story is critical to our success. We have a great story to tell. We’re building a vibrant and healthy organization that differentiates Cenovus. We have the financial strength and flexibility to enable our ambitious plans. iVoR Rus Te Our commitment to safety, new ideas and improved technologies is strong. The status quo is unacceptable at Cenovus. Innovation unlocked the oil sands. That kind of ingenuity will tackle the environmental challenges. JuDY FaiRBuRn haYWaRD W aLLs We strive to be industry leading in our operations – from our approach to our results. John BRannan Our approach to governance provides a strong framework for achieving our plans. Our downstream integration gives us less volatility and balances our commodity exposure. sheiL a MCinT osh haRBiR Chhina keRRY D YTe Don sWY sTun CENOVUS 201 0 A NNUA L REPO RT · M EE T OUR E XE CUT IVE TE A M · 20 Message FR oM ouR pResiDenT & ChieF e xeCuTiVe oF FiCeR “ You can count on Cenovus’s commitment to develop our resources safely and responsibly, and to always strive to be better at how we do it.” CLEAR VISION + SMART EXECUTION = an exciting Future By the end of 2010, our efforts throughout the year resulted in an independent evaluation determining that our proved bitumen reserves had increased by 33 percent over 2009 to nearly 1.2 billion barrels. A particular highlight was that our foster Creek and Christina Lake facilities increased production by 33 percent in 2010 compared with 2009, for a combined production of over 59,000 barrels per day net to Cenovus. At the same time, our operating costs at these facilities decreased 10 percent in 2010 compared to 2009, to an average and focusing on increasing production from our high-quality oil sands assets. As part of our 10-year plan, we have set clear milestones to measure our success, which are outlined on page 18. The nature of oil sands means we are in a long-term business – so it’s important that you know our milestones and can track our progress. I am pleased to report that we met or exceeded all the key milestones we set for 2010. In everything we do, our aim is to increase value for you, our shareholders. We are targeting to double our net asset value by 2015, and boost our oil sands production five-fold to 300,000 barrels per day net to Cenovus by the end of 2019. We also expect to provide you with a strong and sustainable dividend. 2 010 – seTTing The s Tag e FoR FuTuRe VaLue CRe a Tio n Early in 2010, we undertook a third-party assessment to fully understand our oil sands resource. The evaluation, using some of the most rigorous standards in the industry, identified best estimate total bitumen initially-in-place on Cenovus lands of 137 billion barrels, of which 56 billion barrels are considered discovered. We created our long-term plan to take advantage of these tremendous assets by focusing on bringing this high-quality resource into production. BRI A N C . fERGUSO N PRESI DENT & CHI Ef E XECUTIVE OffICER With our first full year as an independent oil company behind us, I am proud of what we have accomplished at Cenovus in such a short time. It gives me great pleasure to report our accomplishments to you in this, our first annual report to shareholders. 2010 was a year of strong operational results, exceptional reserves growth and solid financial performance. One where we shaped our teams, our systems and our culture. Most importantly, it was one where we positioned Cenovus for future success by setting the strategic direction for our company. We did this by assessing our vast resource to better understand our growth opportunities, developing a 10-year business plan, 21 · MESSAGE fROM OUR PRESIDENT & CHIEf E XECUTIVE OffICER · CENOVUS 2010 A NNU AL REPORT Our proposed SAGD development in the oil sands is driving our growthOil sands production Mbbls/d (net to Cenovus)20102019F30050100150200250of $11.28 per barrel – all while we were operating with even more emphasis on working safely. To the credit of our entire operations team, their focus on safety resulted in fewer total incidents during the year. We furthered our expansions at both foster Creek and Christina Lake in 2010 and advanced development plans at two of our emerging projects, Narrows Lake and Grand Rapids. As well, our established oil and natural gas properties in Alberta and Saskatchewan continued to demonstrate strong cash-generating abilities, providing approximately $1.3 billion of operating cash flow in excess of their capital expenditures in 2010. The cash generated from our conventional oil and natural gas properties funds our continued oil sands growth, and the natural gas also fuels our oil sands and refining operations. In our refining operations, we continued to concentrate on increasing capacity through a coker and refinery expansion (CORE) project at our Wood River Refinery in Illinois. Upon anticipated start up of the coker in the fourth quarter of 2011, we expect improved profitability from this part of our business. Managing our business with a continued focus on value creation and cost control resulted in Cenovus having an even stronger financial position at the end of 2010 than at the start of the year. We have a healthy balance sheet, closing 2010 with a debt to capitalization ratio of 26 percent and debt to adjusted EBITDA ratio of 1.2 times. Total cash flow was strong at $3.21 per share for the year, while our capital investment in 2010 was $2.1 billion. At Cenovus, we take a responsible and careful approach to our financial strategy. We are committed to continuing to provide our shareholders with regular dividend payments as part of this disciplined approach. You can read more about our accomplishments in the 2010 Year in review section on pages 25 to 28 of this report. Another significant action we undertook in 2010 was to organize ourselves internally to maximize efficiencies and better align our structure with our plan. We accomplished this by eliminating our operating divisions and creating a centralized operations team under the leadership of John Brannan, who assumed the new position of Executive Vice-President & Chief Operating Officer. John brings more than 30 years of oil and natural gas experience to this new role, and his leadership will drive continued achievements in our operations. “2010 was a year of strong operational results, exceptional reserves growth and solid financial performance. One where we shaped our teams, our systems and our culture. Most importantly... we positioned Cenovus for future success by setting the strategic direction for our company.” 2 011 – B uiLDing on o uR 20 10 MoMe nTuM With the foundation of our company in place, 2011 will be focused on building on the momentum we achieved in 2010, by pursuing regulatory approvals, advancing construction of the expansion phases at foster Creek and Christina Lake, and pursuing opportunities for production growth in the Greater Pelican Region. The milestones we have set for 2011 align with our 10-year business plan and our goal of growing net asset value. They include executing our largest- ever stratigraphic well program to evaluate our undeveloped land, expand our contingent resource and advance projects into the regulatory queue. As well, we are focused on delivering on our upstream operational targets and keeping our projects on schedule and on budget, so we can continue to crystallize the value our great assets provide for our company and our shareholders. Cenovus shares outperformed the market in 2010 Total shareholder return (TSX) Percentage 30 15 0 CE N OVUS ENERGY S&P/TSX COMPOSITE INDEX S & P/TSX ENERGY INDEX THE VALUE Of A CENOVUS HOLDING WAS UP 29 PERCENT ON THE BA SI S Of ALL DIVIDEND PAYMENTS BEING RE IN VE STE D COMPARED WITH AN 18 PERCENT IN CRE AS E IN THE S &P/ TSX C OMPOSITE INDE X AND 13 PE RC EN T fOR THE S &P/ TSX ENERGY INDE X . The Cen oVus eq ua Tio n – o uR keY s TRen gThs What sets Cenovus apart is the combination of our great financial and operating assets, our commitment to responsible operations, our ability to advance technology to improve our results, and the 3,500 dedicated people who make it all happen. People who bring decades of experience, knowledge and enthusiasm to their work. Thanks to them, we are able to develop new ideas, new technologies and better approaches. I am proud of our achievements in bringing Cenovus to this point, and would like to acknowledge and thank our Board of Directors, our Executive Team, and our employees and contractors for demonstrating such dedication to Cenovus’s success. We have an air of excitement, a can-do attitude and a driving passion to make Cenovus the best it can be. In a year of change, we maintained focus on building our company, we delivered on our targets, and we had excellent operating and financial results. We are building a company that, at its core, believes in doing right by the environment and the communities where we live and work. We are focused on doing the right things to help provide the energy resources the world needs and relies on every day. With demand for energy growing, you can count on Cenovus’s commitment to develop our resources safely and responsibly, and to always strive to be better at how we do it. It’s at the heart of the Cenovus equation. And it’s our promise to you. We have set ambitious goals for ourselves, but I believe we are in a strong position to realize our tremendous future. Our Executive Team and I look forward to the exciting possibilities that lie ahead. CENOVUS 201 0 A NNUA L REPO RT · M ESS AGE fRO M OUR P RE S I DE NT & C HIEf E XECU TIVE OffICER · 22 q& a WiTh ouR ChieF opeRa Ting oFFiCeR “As a unified operations team we will be better positioned to continue our focus on maintaining our operating momentum, delivering on our business plan and being a safe, responsible operator.” GREAT TRACK RECORD + fRESH THINKING = operational excellence the way we work and take advantage of knowledge sharing and technology improvements across our business. Additionally, the unified operating team is supported by a central organization for regulatory, drilling, procurement, continuous improvement, land functions, process improvement, and health and safety. Most importantly, as a unified operations team we will be better positioned to continue our focus on maintaining our operating momentum, delivering on our business plan and being a safe, responsible operator. Cenovus believes it’s important to be a low-cost operator. How do you achieve that? We’re recognized in the industry as being a low- cost operator with leading capital efficiencies and we’re proud of our track record. Our low costs are the result of a number of factors. While it’s true that our low steam to oil ratios and high- quality reservoirs allow us to keep costs down, it’s also due to the manufacturing approach we take in the design, construction and operation of our facilities. Our teams build our projects in manageable phases using repeatable designs. We design the process flow diagrams, equipment, and operating processes to be similar at all our SAGD facilities. Our teams then apply their experience and learnings to each new phase and implement advancements in technology once they’ve become proven – all with the goal of improving efficiency and reducing costs, without sacrificing our commitment to high-quality facilities, safe operations and minimal environmental impact. How do you manage cost inflation in your business? We have a philosophy at Cenovus that holds everyone accountable for spending our money wisely regardless of the economic environment. So having that kind of overall attentiveness gives us an advantage when dealing with inflation. One way we manage inflation is through our approach to development. for example, by using in-house construction management teams, we take control of our costs and reduce potential for overruns by having Cenovus staff accountable for capital spending. Another way we manage inflation is through our module fabrication yard in Nisku, Alberta, located just outside of Edmonton. Having an established module yard allows us to control costs and maintain schedules and greatly reduces the amount of rework needed in the field. As an example, out of the 145 modules required for the Christina Lake phase C expansion, only two modules required minor modifications during installation – obviously a significant cost and time savings and a substantial increase in the efficiency of our construction teams. 23 · Q& A WITH OUR CHIEf OPERATING OffICER · CENOVUS 2010 ANNUA L REPO RT JOHN K . BRA NN AN E XE CU TIVE VI C E-PRESI DE N T & C HI Ef OP ERATIN G Of fICE R Late in 2010 you were named Cenovus’s Chief Operating Officer. How does this new role change Cenovus’s approach to operations? Let me start by saying I’m really pleased to be working closely with all the areas of our operations – our oil sands, conventional oil and natural gas teams, as well as our refining and marketing teams. Everyone has been doing great work. Having one operating team rather than separate operating divisions allows us to optimize The location of our projects also helps us control inflation. We’re fortunate to be located near Bonnyville, Cold Lake and Lac La Biche, which experienced lower inflation than areas such as fort McMurray during the last upswing in oil sands activity. Lastly, where we can, we train and hire locally and use businesses and services in the areas around our operations. It’s important to us that we work with local communities and stakeholders to establish a win-win scenario for all. Cenovus talks a lot about steam to oil ratio. What is it and why is it such an important measure? Steam to oil ratio, or SOR, is the amount of steam required to produce one barrel of oil. It’s a reflection of the quality of the reservoir and the approach used to develop the resource. It’s also the single most important factor that influences the economics of a SAGD project, the lower the SOR, the better. Approximately 60 to 70 percent of a SAGD plant’s function is dedicated to water handling for steam production. We currently have some of the lowest reported SORs in the industry. In 2010, our demonstrated SORs at foster Creek and Christina Lake were about 2.2 combined. A low SOR means we need less steam to produce oil so, on a per barrel basis, it means better capital efficiency indicated by our lower capital costs. Our most significant operating cost stems from burning natural gas to turn water into steam. Our low SOR keeps our operating costs at a minimum. It also leads to other benefits such as a smaller surface footprint, lower emissions and reduced water use, which help us meet our environmental objectives as well as our financial objectives. I’m extremely proud of the work we’ve done to successfully lower our SOR. Cenovus has made a commitment to implement at least one new commercial technology per year. Why is research and development so critical to the company’s success? Research and development is a huge focus for Cenovus. Historically, we’ve been able to implement at least one new technology in our operations each year and believe we can continue that trend. Take the development of SAGD for example. We believe that this technology, which has only been commercially applied for about a decade, still has opportunities for improvement with respect to developing and optimizing our recovery schemes. We plan to continue to lead the industry in implementing new approaches to how we’re able to extract the oil out of the ground. Our recent use of wedge wells is a great example of that. It’s a Cenovus technology that’s already changing the way we develop our assets, and we haven’t even begun to fully utilize it in our operations. At year end 2010, about 13 percent of foster Creek’s total production came from wedge wells, which cost only about half the amount required to drill a SAGD well pair. At the end of 2010 we had drilled 51 wedge wells at foster Creek with 33 producing, and had one producing wedge well at Christina Lake. Building on this success, we’re planning to drill 10 more wedge wells at foster Creek in 2011. We believe research and development is critical to the longevity of our business, which is why our ability to advance technology is an important part of who we are as a company. It’s how we’ve increased efficiency, recovery and project returns. It’s also reduced our costs and our overall environmental intensity. And it’s how we’re going to continue to improve our operations in the future. W EDGE WELL TECH NOLOGY This simplified diagram shows the ‘wedge’ of oil between two well pairs that was previously inaccessible. P E E D m 0 5 4 X O R P P A WEDGE WELL WEDGE WELL RECOVE RY ARE A INJECTOR WELL PRODUCER WELL WEDGE WE LL S ARE SINGLE HORIZONTAL WELLS DRILLED BETWEEN TWO SAGD WELL PAIRS TO CAPTURE P REVIOUS LY I NACCESSIBLE OIL IN TH E R ESERVOIR THEY REQ UIRE LITTLE OR NO STE AM TO E XTR ACT THE REM AIN ING OIL , MAKING IT POSSIB LE TO INCREASE OIL RECOVERY WHILE REDUCING OPERATING COSTS , WATE R USE AND ENERGY USE PER BARREL . . If oil sands are your growth driver, what role do your other resources play? We have a great balance of growth and financial assets. We think of our conventional oil and natural gas properties as financial assets. They are low-cost, high-return assets that, with modest capital investment, will generate substantial operating cash flow and will experience a fairly shallow decline. Our natural gas business also acts as an economic hedge against price fluctuations, because natural gas fuels our oil sands and refining operations. Our oil operations include Weyburn and other properties in southern Alberta and Saskatchewan while our natural gas properties are in Alberta. On the growth front, in addition to the CENOVUS 201 0 A NNUA L REPO RT · Q & A WI TH OUR CH I Ef OP E RATIN G OffICER · 24 growth from our oil sands, we expect to double heavy oil production at Pelican Lake as a result of our multi-year infill drilling program. When will the Coker and Refinery Expansion (CORE) project at Wood River be complete? The CORE project is a large-scale expansion that started in September 2008 at our Wood River Refinery in Illinois, which is designed to process 306,000 barrels per day of crude oil. Construction is expected to be substantially complete in the third quarter of 2011, with start up of the coker expected in the fourth quarter. Once complete, Wood River will join our Borger Refinery in Texas as one of the more complex refineries in the United States. The increased complexity is a result of adding a new coker, associated processing units and other upgrades to the existing refinery. Together, they will provide the refinery with the flexibility to take advantage of lower cost feedstocks and improve overall refining capacity and yields. The refinery modifications will increase Wood River’s crude capacity by 50,000 barrels per day and heavy crude oil capacity will more than double to 240,000 barrels per day. These downstream assets protect us against wide light/ heavy differentials and enable us to extract value across the entire chain from bitumen all the way to transportation fuels. Safety is a core value at Cenovus. How do you ensure that value translates into action and results in a good safety record? The health and safety of our workforce is of paramount importance at Cenovus. But it’s not just about saying it. It’s about living it every day. We have eight safety commitments that guide how we conduct our business. All eight are critical to reinforcing the behaviour and attitude we want to see in our staff, but the first one best illustrates our commitment to safety. It states, ‘Our work is never so urgent or important that we cannot take the time to do it safely.’ While these commitments are the foundation of our goal to have an injury-free workplace, they are put into practice through awareness, education and empowerment of our employees and contractors. Most gratifying of all is that our increased focus on safety has resulted in a significant reduction of on-the-job injuries over the past three years. And that’s what’s really important. Because working at Cenovus really does mean working safely. 2010 Ye aR in ReVi eW In our first full year as an independent company, we achieved a number of milestones and delivered on our commitment to develop energy resources safely and responsibly. We met production targets while maintaining safe, disciplined operations. We accelerated expansions at our core oil sands operations, foster Creek and Christina Lake. Cenovus is well positioned for future success. KEY MILESTONES ACHIEVED + STRONG RESULTS = a year to Be proud oF sTRong 2010 Res uLT s enterprise value: $28.5 billion (1) shares outstanding: 752.7 million (1) oil & ngLs production: 129 Mbbls/d natural gas production: 737 MMcf/d proved & probable reserves: 2.4 billion BOE(1) Total acreage: 7.2 million net acres(1) Bitumen acreage: 1.4 million net acres (1)(2) Refining capacity: 226 Mbbls/d All numbers shown are net to Cenovus on a before royalties basis. (1) As at December 31, 2010. (2) Includes exclusive rights to lease 0.6 million net acres on our behalf and/or our assignee’s behalf. DeVeL opeD ouR 10- Ye aR Bus ine ss pL an Approved June 2010 by our Board of Directors. See the Strategy snapshot on page 16. ChangeD ouR oR g an izaTio naL sTRuCTuRe We replaced our operating divisions with a centralized operations team. It took effect December 1, 2010. Co nFiRMeD ouR V asT oiL s anD s poTenTi aL An independent evaluation was completed in the spring of 2010 that confirmed 5.4 billion barrels of best estimate bitumen economic contingent resources on Cenovus’s lands. A subsequent independent evaluation was completed at the end of 2010 that confirmed 6.1 billion barrels of best estimate bitumen economic contingent resources – an increase of 13 percent. The information from these independent evaluations is supported by a great deal of data, including thousands of kilometres of seismic data and a high number of well penetrations. Our proved bitumen reserves, also based on independent evaluations, grew from 866 million barrels at year-end 2009 to 1,154 million barrels at year-end 2010, an increase of 33 percent. totAl 2010 diVidENd: 80¢ pEr commoN shArE These numbers – both proved reserves and contingent resources – reflect the high quality of our assets and the great work being done by our teams. for the company as a whole, the increase in our reserves, combined with highly competitive proved finding and development costs* for 2010 of $3.65 per barrel of oil equivalent confirms the wealth of opportunity we have on our lands. CoMMiTTeD T o TeChnoL ogY DeVeL o pMenT As part of our business plan, we have committed to implement at least one new commercial innovation each year. We have more than 50 research and development projects underway at any given time – about three-quarters of which should result in environmental improvements. pR o gResseD o uR enViR o nMenT aL op poRTuniTY FunD We committed to invest in three new opportunities in 2010, bringing the number of current environmental investments to seven. The fund invests in companies and external research groups developing emerging or early- stage technologies that focus on water treatment and management, energy efficiency, alternative energy, emissions reduction, environmental remediation and land disturbance mitigation. Information about how to apply is on our website. *Without changes in future development costs. See our Additional Advisory on page 132. 25 · 2010 YE AR IN REVIEW · CENOVUS 2010 ANNUAL REPORT Re aCheD R oYaLTY pa YouT a T Fos TeR CReek oiL is o uR gR oW Th DRiVeR In february 2010, our foster Creek project became Alberta’s largest producing SAGD project to reach payout for royalty purposes, which means higher royalties are now paid to the government. This milestone reflects foster Creek’s strong financial and operational performance. foster Creek started as a pilot project in 1996 and, in 2001, became the first commercial SAGD project in the industry. aCCeLeRa TeD e xpansions a T ouR MaJoR sagD oiL sanD s pR oJeCT s Foster Creek In September 2010, we received regulatory approval to build three new expansion phases (f, G & H) at foster Creek. Current gross production capacity at foster Creek is 120,000 barrels per day, and each one of the three phases is expected to add 30,000 gross barrels per day, bringing total production capacity up to 210,000 gross barrels per day. Work on phase f is underway. Christina Lake We’re advancing expansion phases C and D at Christina Lake, which received regulatory approval in 2008. We continued construction of phase C in 2010 and began constructing phase D. Phase C will add about 40,000 barrels per day of gross production capacity with first production expected in Q3 of 2011. Phase D will also add about 40,000 gross barrels per day of production capacity with first production expected in 2013. We expect to bring these phases on stream at an industry-leading capital efficiency of about $22,000 per flowing barrel. These two expansions will bring the production capacity to 98,000 barrels per day on a gross basis from its current 18,000 barrels per day. We’re currently awaiting regulatory approval for three more expansion phases (E, f & G), which would add an additional 120,000 barrels per day of gross production capacity. BR ou ghT T W o eMeR ging oiL s anD s pR oJeCT s CL oseR T o DeVeL opMe nT narrows Lake In June 2010, we applied for regulatory approval of a project at Narrows Lake, located northwest of our Christina Lake project. As part of that application, we have consulted with the communities located near the project to explain our plans. Narrows Lake will be developed in phases up to a gross production capacity of about 130,000 barrels per day. The application is the first commercial project to include the option to use SAP, a solvent aided process that increases oil recovery. grand Rapids We’re taking steps to develop a future oil sands project in the Greater Pelican Region, about 300 kilometres north of Edmonton. In December 2010, we received regulatory approval for a SAGD pilot in the Grand Rapids formation. Drilling of the SAGD well pair is complete, and in late 2010 we began injecting steam into the formation. If the pilot is successful, we plan to file a regulatory application for a 180,000 barrels-per-day commercial operation. Bor e alis region includes Telephone Lake and other emerging projects Technology used: sagD(1) northern alberta gre at er pelican region includes pelican Lake Wabiskaw as well as grand Rapids and other emerging projects Technology used: polymer flood and sagD northern alberta chr istina l ake region includes Christina Lake* as well as narrows Lake* and other emerging projects Technology used: sagD and sap(2) northern alberta Foster creek region includes Foster Creek* as well as emerging projects Technology used: sagD northern alberta weyBu rn Technology used: enhanced oil recovery using Co2 sequestration Weyburn, saskatchewan We also have natural gas and conventional oil properties across Alberta and southern Saskatchewan. wood river reFin ery* Roxanna, illinois Borger reFinery* Borger, Texas *joint owner with Conocophillips (1) steam-assisted gravity drainage (2) solvent aided process “We’re excited about the way we’re able to transfer knowledge from one area to another. We’re applying horizontal drilling and completion techniques from our Saskatchewan, Lower Shaunavon and Bakken developments to our Drumheller, Brooks North and Langevin oil development programs.” KEVI N KEL LY TE A M LE A D , DR UMHELLER /BOYER D eVeL op eD MuLTi- Ye aR gR oW Th pL an FoR peLiCa n L ak e WaBi ska W We have plans for significant growth of our existing Pelican Lake Wabiskaw production as we expand our polymer enhanced oil recovery project. Our multi-year growth plan involves more than doubling existing production to 40,000 to 50,000 barrels per day. Mai nT ai neD a s TRo ng Fin a nCi aL posiTi on Both our debt to capitalization ratio of 26 percent and debt to adjusted EBITDA ratio of 1.2 times were at or below the low end of our target ranges. Our cash flow was strong in 2010 at $2.4 billion and aligned with our expectations. The majority of the cash required to fund our oil sands growth is generated by our conventional oil and gas properties. In 2010, these properties contributed about $1.3 billion of operating cash flow in excess of the capital spent on them. e xpL oReD shaun a Vo n anD Bakk en FoR n eW op poRTun iTi es Our Lower Shaunavon and Bakken medium and light oil assets in Saskatchewan are early stage development opportunities for Cenovus. We had 25 wells producing at year-end 2010 with plans to drill an additional 36 horizontal wells in the area in 2011. We anticipate production at the end of 2011 could reach 5,700 barrels per day. opTiMi zeD CoaL BeD MeThane (C B M) pR oDuC Ti o n FR oM e s TaBLi sheD shaLL oW gas o peRa Tio ns In 2010, we undertook a 900 well recompletion program in our shallow gas operation to further assess CBM potential on our lands. Total CBM production from our Brooks and Langevin properties was approximately 30 MMcf/d from about 1,400 recompleted shallow gas wells. The long-range plan calls for over 6,500 CBM recompletions in existing shallow gas wellbores. grEw oil sANds productioN by 33% oVEr 2009 CENOVUS 201 0 A NNUA L REPO RT · 2 01 0 Y E A R I N RE VI EW · 26 “We’re a company that follows through on our commitments.” ADRI AN MI TCHE LL RE SERVOIR A NA LYST D iVe s TeD no n-C oRe ass eT s In 2010, we sold some non-core assets in southeastern Alberta and southwestern Saskatchewan for net proceeds of $156 million. Our total divestitures for the year were $307 million. As part of maximizing shareholder value, we continually look to improve our asset base and sell non-core assets as long as market conditions are favourable. We believe it’s good business practice to sell assets that aren’t part of our core business and use those funds to invest in assets that are in our area of focus. our commitmENts: rigorous rEspEctful rEAdy “I’m really proud of the focus we have on developing technologies that will reduce the impact our operations have on the environment even further.” SUB ODH GUPTA TE CHNOLOGY ENHANCEMENT ADVISOR OP ERATO R ADJUSTI NG VALVES AT T HE W EYBU RN f AC I LI TY CeLeBRa TeD TenTh an n iVeRsaRY oF ouR WeYBuRn C o 2 pR oJeC T In September 2010, we celebrated the tenth anniversary of our Weyburn carbon dioxide (CO2) enhanced oil recovery project, which uses technology to improve both oil recovery and our environmental performance. Since CO2 was first injected into the reservoir in 2000, more than 16 million tonnes of CO2 have been stored at Weyburn, which otherwise would have been vented into the atmosphere. The Weyburn oil field is located in southern Saskatchewan. ToL D ouR s ToRY Presenting to investors and government officials, doing media interviews, meeting with community leaders, groups and landowners, working with Aboriginal communities, and communicating with our employees – we remain committed to telling our story to all our stakeholders to help them understand our company, the quality of our asset base, the strength and expertise of our teams, our solid financial position and our commitment to operating safely and responsibly. WED GE WELLS AT fOSTER CREEK AS PART Of TELLIN G O UR STORY , WE C RE ATE D ADS IN THE f A LL Of 20 1 0, fOC USE D ON THE VAL UE O IL AND N ATURAL GA S B RI NG TO OUR LI VE S SET Of ADS , WHI C H L A UN CHED I N E ARLY 20 11 , IL LU STRATE W HAT A SAGD O PERAT IO N LO OK S L IK E TH E A DS C AN BE V I EWED O N OUR WE BS I TE . A SE CON D . . 27 · 2010 YE AR IN REVIEW · CENOVUS 2010 ANNUAL REPORT es TaB Lis heD L o ng-TeRM agReeMenT WiTh Co nkLin C oM MuniTY We signed a long-term agreement with the Aboriginal community of Conklin, which is located less than 20 kilometres from our Christina Lake project in northern Alberta. The agreement will provide mutual benefits for as many as 40 years and outlines our commitment to working and engaging with the Conklin community on the following matters: > providing benefits such as employment, community investment, business development, education and training > determining how we’ll engage with the community as our projects grow and how we’ll work together to address any issues that arise > protecting the environment and protecting Christina Lake > providing financial and other resources that will help Conklin residents adapt to change in their area CENOVUS VICE-PRESIDEN TS JO IN T HE C ON KL IN RESOURCE DEVELO PM EN T ADVI SORY C OM M ITTEE TO SIGN A LONG- TERM AG REEME NT WITH THE COMMUN ITY Of C ON KLI N. aDV anCeD C oRpoRa Te Resp on siBiLiTY a T Ceno Vus: neW poLiCY, neW Me as uRe s MaDe a DiF FeRenCe in The C oM MuniTie s WheRe We LiVe anD W oRk At Cenovus, corporate responsibility (CR) is integrated into the way we do business. In 2010, we created a policy that reflects our company and our commitment to CR. It sets out our guiding principles relating to leadership, corporate governance and business practices, people, environmental performance, stakeholder and Aboriginal engagement, and community involvement and investment. Additionally, in July 2010, we released our first set of CR performance measures. These measures set a firm foundation for future public reporting on our company’s non-financial performance. In developing these measures we used the Global Reporting Initiative guidelines as a framework for reporting and have begun to align our performance metrics with the standards set out by the Canadian Association of Petroleum Producers’ Responsible Canadian Energy program. Company giving In 2010 Cenovus worked with 427 organizations, providing both monetary and in-kind assistance in the communities where we live and work. We also became an Imagine Canada Caring company, which means we give one percent of our pre-tax profits to charitable or non-profit organizations. In 2010 that resulted in $13.5 million in donations. employee giving Our employees contributed more than $3.2 million (including the company match) through our annual giving campaign, matching gifts and volunteer programs. The money benefited nearly 700 charitable organizations across Canada. During the annual campaign, which runs every October, employees designate their donation amount to charities of choice, with Cenovus matching donations dollar for dollar. “It was great to have the Executive Team visit us in the field.” ART L AURI N PRODUCT ION COO RDI NATOR THE E X ECU TIVE TE AM VI SI TS O UR P E L IC AN L A K E SI TE CENOVUS 201 0 A NNUA L REPO RT · 2 01 0 Y E A R I N RE VI EW · 28 AT CENOVUS WE BELIEVE IN BEING A PART Of THE . IT ’S COMMUNITIES WHERE WE LIVE AND WOR K ABOUT BEING INVOLVED AND MAKING A POSITI VE DIffERENCE INCLUDING COMING TOGETHER IN THE SPIRIT Of GIVING TO DONATE GIf AND TEENS DURING THE HOLIDAYS . TS fOR CHILDREN Ce noVus n aMeD T o DoW Jo nes sus Tain aBiLiTY inDe x (DJs i) anD CaRBo n Dis CLos uRe Le aDeRs hip inDe x The DJSI North America Index recognizes companies from Canada and the United States for their sustainability performance. Companies are selected based on an annual assessment of economic, social, environmental and corporate governance performance. The Carbon Disclosure Leadership Index recognizes companies for their leadership in the reporting of greenhouse gas emissions. totAl rEcordAblE iNjury frEquENcy lowErEd by 15% es TaBLi sheD L o ng-TeRM agRe eMenT WiTh Con kLin C oMMun iTY MeeT ouR eMpL oYees The people of this company embody the spirit of Cenovus. Rigorous in their commitment to smart resource development. Respectful in their commitment to doing right by the environment and communities where Cenovus operates. Ready in their commitment to embracing fresh thinking and new ideas. KNOWLEDGE + DEDICATION = the right people Cenovus is an excellent place to work. I get the opportunity to work with great people on innovative projects. naThan hYLT on I don’t know what the next year will bring but here’s hoping that year two will be as positive and successful. It’s really great to work at a company that values innovation and embraces new ideas as part of our everyday approach to doing business. nasseR aW aDa It’s exciting to be part of a company with both an established history and track record and yet a totally new identity, new culture, new way of doing things. It’s been a rewarding experience introducing our local stakeholders to our company and our plans. TReV oR BoRs CaM kopanskY It’s important to me to work for a company that takes safety so seriously. I come to work every day knowing that people rely on us for the oil and natural gas we produce. ChRis oLiVeR Helping to build a new company has been an exciting experience. Jason sWiTzeR There’s such a strong spirit of camaraderie at Cenovus. kiM Yee CoLe BR osT Liz Young 29 · MEET OUR EMPLOYEES · CENOVUS 20 10 ANNUAL REP ORT MeeT ouR eMpL oYees Trevor Aadland / Ali Abbassi / Jason Abbate / Yasmin Abdul / Phillip Abraham / Phil Abrey / Nicole Abs / Michalene Adair / Aaron Adam / Jennifer Adams / Stewart Adams / Jamie Agnew / Annie Agustin / Rhonda Aiello / Abayomi Akande / Jennifer Alaric / Sheila Albon / Gary Alden / Everett Alderdice / Neil Aldridge / Jim Aleman / Michael Alessio / Renee Alessio / Andell Alexander / faisal Alimohd / Travis Alkier / Courtney Allan / Denise Allan / Michael Allan / Dale Allen / Roberto Allende-Garcia / Douglas Allin / Cindy Alpaugh / Brett Altwasser / Vernon Alvis / Jason Aman / Jon Amerl / Kim Amirault / Giuseppe Ammirati / Arthur Amyotte / Ligen An / Andrea Anderson / Brent Anderson / David Anderson / Gary Anderson / Judy Anderson / Michael Anderson / Richard Anderson / Timothy Anderson / Todd Anderson / Ken Andres / Edith Andrew / Mark Andrews / Tamer Antar / Gwenda Anweiler / Kimberly Appleby / John Arcovio / Lesley Arnett / Caroline Arnieri / Royce Arnott / Aaron Arsenault / Julian Arsenault / Joel Arthurs / Michael Arychuk / Abbas Arzpeyma-Nemati / Shane Ashby / Marijane Ashforth / Derrick Ashworth / Andrew Asplund / Karen Asselstine / Theodore Assie / Laverne Atkinson / Tony Atwood / Lawrence Auger / Lenny Auger / David Austin / Mark Austin / Nasser Awada / Brett Aylwin / Karmyn Ayn / Cole Babey / Wade Bachur / Erica Back / Tracy Bader / Mohammad Bagheri / Mohammad Bahadori / Robert Baillargeon / Brian Bain / Arnold Baker / David Baker / Evan Baker / Nadia Baker / Rawleen Baker / Robert Baker / William Baker / Colin Ball / Dale Ball / Susan Ballendine / Christopher Ballesteros / Wayne Bamber / Peter Bandola / Chad Barber / Brenda Bardell-Resch / Jason Bardick / Ryan Bardick / Paul Barker / Sandra Barker / Debra Barnett / Arnold Baron / Robert Baron / Courtney Barr / Marc Barrette / Dallas Barrie / Stuart Barrie / Shirley Barron / Bradley Barrow / Darcy Barry / Jamie Barsness / Connie Barteaux / Lori Barth / Michele Barth / Ronald Bartlett / Isabella Baslios / Barbara Bateman / Keith Bateman / Wayne Bateman / Darwin Bateyko / Kelly Bauman / Kelvin Bauman / Vincent Bax / Susan Bayly / Elizabeth Bayrak / Richard Beale / Leslie Beard / Dale Beaton / Aime Beaulac / Lori Beaulieu / Theran Beaulieu / Javier Becaria / Jessica Beck / Robert Beckett / Jeffrey Beckford / Jacqueline Beckie / Niel Beckie / Kenneth Beierbach / Jeremy Belair / Catherine Belanger / Dale Belbin / Lloyd Belcourt / Matthew Belitsky / Carrie Bell / Diane Bell / Kelly Bell / Scot Bell / Irene Belthazar / Marisol Ben / Corey Beniuk / Jason Beniuk / Jeffery Beniuk / David Benn / Greg Benzon / Corey Berg / Grant Bergos / Alan Berkiw / Maria Bermudez / Stephen Bernard / Mark Berrett / Tanya Berry / Leona Bertagnolli / Shawna Bertin / Julie Bertram / Mark Bertrand / Edward Bertschi / CherylLyn Best / Monica Betancourt / Tracy Bialowas / Ovidiu Bibic / Cody Biech / Alice Bienia / Dean Bierkos / Jo-Ann Biggs / Mark Bilozir / Mark Bilyk / Paul Binassi / Brandi Biollo / Chad Biollo / Lori Birdsell / Jillian Birnie / Bradley Bischoff / Amanda Bishop / Cassandra Bishop / Tyler Bishop / Tom Bissell / Darin Bitz / Christopher Blackwood / Ryan Blais / Trevor Blake / Deborah Bland / Connie Blatch / Adam Blazenko / Brenda Blazenko / Michael Bleackley / Blake Bloor / Brenda Bloski / Phil Blower / Glen Blythe / Leslie Boc / Scott Bodnar / Kerry Bohnet / Denis Boivin / Blaine Bolen / Kenneth Bolstad / Kevin Bolton / Glen Bonogofski / Kyle Boon / Rupam Bora / Bryan Boratynec / Albert Bordeleau / Gail Bordeniuk / Robert Borgen / Joseph Borras / Trevor Bors / Anna Bortolotto / Deborah Bosse / Moira Botham / Roger Boucher / Elisa Bourget / Crystal Bowen / James Bowman / Matthew Bowman / Michael Bown / Wayne Boylan / Rosana Bracho / Ian Braconnier / Darcy Bradley / Hugh Bradley / Leanne Bradley / Kim Brady / Sean Brady / John Brannan / Chad Branvold / Darlean Brasic / Gilles Brazeau / Jessica Brears / William Brears / Edmond Breland / Ryan Bremer / Michael Brennan / Lynda Briand / Carol Briceno / Stephen Brink / Claudine Brinston / Debora Brisson / Danielle Broadwell / Glenn Bromley / Pierre Brosseau / Cole Brost / Benjamin Brown / David Brown / Diane Brown / Gary Brown / Kevin Brown / Mary Brown / Terry Brown / Wade Brown / Jason Browne / Jamie Bruinsma / Jessica Bruneau / Edlyn Bruni / Donald Bryan / Nickole Bryan-Johnson / James Bryden / Daniel Bryson / Rodney Buchan / Christopher Buchanan / Brad Buckingham / Kent Buckingham / Dean Buckosky / Joseph Bueckert / Brent Bull / Stjepan Bulmer / Michael Bumstead / Candace Bundus / Tara Bunes / Jamie Bunka / Alfred Burk / Dean Burkart / Deborah Burke / Thanh Burns / Geoffrey Burrowes / Janet Burton / Cindy Busch / Randi Busenius / Heather Bush / Chad Buteau / Cayley Butt / David Butterwick / Brian Bylo / Jennifer Byrnes / Amanda Cabaj / Bernadette Cadden / Rex Cagas / Jerry Callaghan / Jenni Calvert / Cremilde Camara / Cambridge / Anna Cameron / Lauressa Cameron / Michael Cameron / Earl Campbell / James Campbell / Patrick Campbell / Ryan Campbell / Sandra Campbell / Christian Canas / Patricia Cancade / Carissa Caouette / Matt Cardall / Lance Cardinal / Donna Carey / Andrew Carleton / David Carley / Ercidio Carli / Linda Carr / John Carson / Nancy Carson / Paul Cary / Janne Cash / Teresa Cassetta / Miguel Castillo / Nory Cayago / Brian Celaire / Dan Cesario / Renee Chabeniuk / Daniel Chambers / Andy Chan / Betty Chan / Chong Chan / Edward Chan / Tammy Chan / Wai Chan / Steven Chang / Giselle Chao / Colin Chapman / franklyn Charles / Dawn Chau-Lam / Brady Cheek / Qiaozhi Chen / Zhen Chen / Ryan Cherniwchan / Stacy Chessall / Daniel Cheung / Joseph Cheung / Winifred Chew-Semple / Michelle Cheyne / Harbir Chhina / Hicham Chibl / Katharine Chidley / Alberta Chikmoroff / Julie Chim / Leonie Chin / Tom Chin / frank Chinski / 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Brian Stevens / Jeffery Stevens / Sandra Stevens / Nicole Stewart / Raegan Stewart / Sydnee-Leigh Stewart / James Stirling / Shawn Stobbart / Dean Stobo / Linda Stock / Darryll Stone / William Stoneman / Jeremy Stork / Kevin Stoski / Andrew Straile / Darcy Strate / Gregory Stratychuk / Brenda Streight / Lionel Stuber / Joshua Studer / Krystle Suchan / Jennifer Suen / Vitali Sukhetsky / Arjan Sulejmani / Jeffery Sullivan / Justin Sullivan / Sarah Sullivan / Colette Summers / Susan Sun / Rudy Sundermann / Judy Sutton / Benjamin Svoboda / Colyn Swanson / Darren Swaren / Tara Sweet / Joseph Swiech / Elizabeth Swift / Ken Switala / Jason Switzer / Donald Swystun / Ryan Sych / Mark Sykes / Jared Sylvestre / Pierre Sylvestre / Michael Taillon / Carla Tait / Neil Talbot / David Tam / Jennifer Tamura / Vernny Tang / Cody Taranko / Evan Tardif / Debra Tario / John Tarnasky / Landon Tarnasky / Ross Tarrant / Cameron Taylor / Scott Taylor / Sheila Taylor / Gary Tebb / Shane Tebb / Brittany Tebbenham / Paul Teha / Robert Templeton / Darwin Terlson / Mitchell Thew / Sharon Thiara / Bradley Thiessen / Tyler Thiessen / Wayne Thomas / Christopher Thompson / Cody Thompson / Joel Thompson / Linda Thompson / Marion Thompson / Ryan Thompson / Scott Thompson / Melanie Thomson / Evelyn Thorkelson / Brenda Thorne / Nishi Thusoo / Bryan Tiessen / Robbie Tinis / James Todd / Matthew Toews / Scott Toews / Scott Toews / Steven Tofan / Jillian Tofer / Dubravka Tomic / Shannon Tompkins / Henry Tong / Alfredo Torres / Gabriel Toth / Donnie Tradewell / Jennifer Tran / Kim Tran / Lisa Trang / Nathaniel Tredger / Leslie Tremblay / Russell Tremblay / Richard Trost / Sharon Trottier / Johanne Trudel / Colin True / Warren Trumpour / Hoa Tsukishima / Carla Tucker / Lana Tucker / Catherine Tully / Gurpartap Tumber / Jean Turcotte / Dean Turner / Julia Turner / Ryan Turtle / John Turuk / Chandip Twana / Alister Twarzynski / Kerri Twemlow / Barney Twidale / Keith Urlacher / Luis Urzua / Gordon Uswak / Tamara Utsch / Teresa Utsunomiya / Mora Uyesugi / Stephen Uzelman / Petrica Vaitus / Paul Valcourt / Jason Van Buskirk / Shane Van Buskirk / Mark Van de Veen / Brent Van Ham / Jeffrey Van Ham / Charlotte Van Pelt / Kerry Van Son / Angela Van Unen / Kimberly Van Unen / Cheryl VanBastelaar / Arthur Vander Hoek / Paul Vander Valk / Kelly Vandesype / Tony Vandeweyer / Justin VanMaarion / Tyson Vany / Theresa Varalta / Erika Vargas / Adam Varley / John Varsek / Greg Vatcher / Cody Vaughan / Haig Vejprava / Bernadette Velasco / Lazar Velev / Darren Venne / Natasha Verdon / Jerrod Verhaest / Michael Vermeersch / Mike Verrier / Wilhelmina Versloot / Brian Verville / Jillian Viccars / Sheldon Vigoren / Leonidas Villegas / Ryan Vinck / Shaireen Virani / Phonesavanh Viravong / Lori Virtue / John Visser / Raymond Von Niessen / Cindy Wachtler / Sean Wade / Lee Wagner / Steven Wagner / Heather Wagstaff / Vivian Wahby / Duane Walkeden / Twila Walkeden / Kirstin Walker / Rennick Walker / Taura Walker / Sheldon Wall / Steven Wall / Steve Wallace / Tarnia Wallace / Hayward Walls / Ryan Walper / Andrew Walsh / Andrew Walsh / Tieshan Wang / Corwin Wanuch / Darcey Ward / Michelle Ward / Kathleen Ware / Allison Warkentin / Anthony Warren / Darryl Warren / Scott Waschuk / Kitty Wasslen / Michael Wasylyk / Michele Waters / Jayson Watier / Jeff Watier / Catherine Watson / Robert Watson / Robert Watson / Rick Watters / Katherine Wattie / Arlette Watwood / Richard Wawrykowych / Evan Way / Loy Webb / David Webber / Pamela Weber / Paul Weber / Colin Webster / Dale Webster / Pamela Webster / Rodney Webster / Richard Wegerhoff / Heather Weighill / Betty Weightman / Ryan Weimer / Simon Weintz / Shawna Weir-Murphy / Lyle Weiss / Lyle Weiss / Neil Wenman / Michael Wenner / Sara Wentz / Gregory Wenzel / Trevor Weppler / Nigel Werenka / Margaret Werezak / Scott Werre / Barry Weseen / Dann Weselosky / Jeff West / Patricia Westman / Trevor Westman / Bradley Wheeler / Deanne Wheeler-felstad / Colleen Whelehan / Charles Whitaker / Curtis White / Mergitte White / Vanessa White / William White / Lorna Whiteway / Albert Whitford / Jack Whittaker / Phoinyx Whittingham / Carol Whorms / Carol Whorms / Jeneane Whyte / Russell Wickes / Catherine Widdoes / Michael Wiebe / Trevor Wiebe / Linda Wiegand / Ralph Wieler / Brett Wiens / Lane Wieteska / Becky Wigemyr / Lori Wilhelm-Einsporn / Candise Wilkins / frederick Wilkinson / Jessica Wilkinson / Karen Will / Adam Willcott / Cory Williams / Larry Williams / Tyler Williams / Darryl Williamson / John Williamson / Caroline Wilson Mussbacher / Carrie Wilson / Cedric Wilson / frances Wilson / Jeffrey Wilson / Micheal Wilson / Robert Wilson / Russell Wilson / Shauna Wilson / Cory Winder / Henry Winnicki / Allan Winquist / Nathan Winter / Riley Winter / Gary Witiw / Dean Wolansky / Cindy Wolfe / Murray Wolfe / William Wolfe / John-Paul Wolff / Dale Woloshen / Benjamin Wong / Jim Wong / Lucia Wong / Deanna Woo / Kevin Woo / Blake Wood / Nicole Woodland / Mary Woods / Troy Woods / Garfield Woodward / Caroline Worobo / Rachelle Woroniuk / Leonard Wourms / Darin Wright / Stan Wright / John Wrobel / Xinjie Wu / Kerry Wycislik / Brent Wyness / James Yaholnitsky / Daniel Yake / Robert Yanke / Robert Yanke / Jessica Yarnell / Kim Yee / Larry Yee / Tony Yee / Sung Youn / Darla Young / Elizabeth Young / Ian Young / Janet Young / John Young / Rodney Young / William Young / Alice Yu / Carolyn Yu / David Yu / Tze Yu / Luningning Yue / Nicole Yuen / Arthur Yukim / Trenton Zacharias / James Zakariasen / Maliha Zaman / Roger Zavagnin / Mohamud Zaver / Sandra Zdunich / Khalil Zeidani / Remo Zelantini / Jason Zelinski / Amy Zhang / Weimin Zhang / Yi Zhang / Ian Ziebart / Russ Ziegler / Drew Zieglgansberger / Oral Zihove / Melissa Zimmerman / James Zinger / Ronald Zittel / Lynette Zyznomirski CENOVUS 201 0 A NNUA L REPO RT · M EE T OUR EM P LOY E ES · 3 0 AS AT DECEMBER 31, 2010 MeeT ouR BoaRD oF DiReCT oRs The members of the Cenovus Board of Directors have years of experience. Their breadth of skills guides our decisions and actions. DIVERSE EXPERTISE + QUALITY DISCUSSION = insightFul guidance (Pictured left to right) ChaRLes M. RaMpa Ce k paTRiCk D. DanieL R aLph s . Cun ni nghaM ian W. DeL aneY MiChaeL a . g RanDi n (Board Chair ) VaLeRie a . a . nieLse n BRi an C . FeR guso n WaYne g. ThoMso n CoLin Ta YLoR 31 · MEET OUR BOARD Of DIRECTORS · CENOVUS 2010 A NNUAL REPORT M essage FR oM ouR BoaRD ChaiR “Your Executive Team and your Board are off to a strong start in realizing the great potential that is Cenovus.” GOOD GOVERNANCE + STRATEGIC DECISIONS = a company to Believe in “After reading this annual report, I think you will agree that Cenovus’s first year performance couldn’t have been much better.” from a governance perspective, we believe that the Board got off to a great start as well. The management proxy circular describes, in some detail, your Directors’ qualifications and your Board’s actions with respect to regulatory compliance, self-regulation, executive compensation and other important Board and Committee matters. However, I thought a few comments here might give you a better understanding of how your Board is operating. We have a nine-member Board with a good mix of skills. The smaller size is intended to encourage open and inclusive discussion. The mix of skills captures experience in both upstream and downstream oil and gas operations and transportation, as well as in accounting, finance and general business and board operations. This combination leads to good quality debate and questioning based on knowledge of the business, all with a view to helping the Executive Team make high-quality decisions. During the year, we focused much of our attention on strategy and risk management. We worked with the Executive Team to ensure that Cenovus’s initial strategy built on the rationale for the company’s creation and took full advantage of its physical asset base, the technical expertise of its people and its financial capacity. At the same time, and also with the Executive Team, we made sure all the risks that we could foresee were included in Cenovus’s well-developed risk monitoring and mitigation system. for reasons such as these we believe your company, your Executive Team and your Board are off to a strong start in realizing the great potential that is Cenovus. Respectfully submitted on behalf of the Board. MICHAEL A . GRA N DIN BOARD CHAI R WhaT a gRe a T s TaRT FoR Ce n o Vus! Cenovus began with an excellent portfolio of assets. It has vast and largely undeveloped oil sands resources to provide for growth well into the future. It has established oil and natural gas assets to fund this growth. It has the technical know- how to effectively recover its resources and the project management expertise to do so efficiently. Perhaps most importantly, it has a highly engaged and enthusiastic workforce, motivated by attractive opportunities, whose members are eager to convert potential value into present value. After reading this annual report, I think you will agree that Cenovus’s first year performance couldn’t have been much better. CENOVUS 201 0 A NNUA L REPO RT · M ESS AGE fRO M OUR BOA RD C H AIR · 32 opeRa Ting anD FinanCi aL highLighT s o p eR aT i n g h i g h L i g h T s B E f O R E R OYA LT I E S production Crude Oil and Natural Gas Liquids (bbls/d) Oil Sands – Heavy Oil foster Creek Christina Lake Total Pelican Lake Senlac Conventional Liquids Heavy Oil Light and Medium Oil Natural Gas Liquids Total Crude Oil and Natural Gas Liquids (bbls/d) Natural Gas (MMcf/d) Refinery operations(1) Crude Oil Capacity (Mbbls/d) Crude Oil Runs (Mbbls/d) Crude Utilization (%) proved reserves(2) (3) Total Reserves (MMBOE) Year-end Bitumen Reserves (MMbbls) Total Production Replacement (%) Recycle Ratio(4) Proved finding & Development Costs ($/BOE)(5) Reserve Life Index (years) 2010 2009 % change 51,147 7,898 59,045 22,966 – 82,011 16,659 29,346 1,171 129,187 737 452 386 86 1,666 1,154 398 7.8 3.65 18 37,725 6,698 44,423 24,870 3,057 72,350 17,888 30,394 1,206 121,838 837 452 394 87 1,398 866 205 5.1 5.39 15 36 18 33 (8) – 13 (7) (3) (3) 6 (12) – (2) (1) 19 33 94 53 (32) 20 (1) Represents 100% of the Wood River and Borger refinery operations. (2) Natural gas is converted using a 6:1 oil equivalent. See the Advisory section of the MD&A. (3) 2009 estimates prepared in accordance with U.S. disclosure requirements using constant prices and costs. 2010 estimates prepared in accordance with Canadian disclosure requirements using forecast prices and costs. See the Oil and Gas Reserves and Resources section of the MD&A for more information. (4) for additional information regarding our Recycle Ratio, see our 2011 Management Proxy Circular, available at www.cenovus.com. (5) finding and Development Costs presented do not include changes in future development costs. for a description of the calculations used, refer to our Additional Advisory on page 132. finding and Development Costs calculated with changes in future development costs, for proved reserves and for proved plus probable reserves, are disclosed in the Additional Advisory on page 132. F i n a n C i aL h i g h Li g h T s $ M I L L I O N S , E XC E P T P E R S H A R E A N D OT H E R A M O U N T S A S N OT E D 2010 2009 % change Gross Revenues Net Revenues Cash flow (1) Per Share – Diluted Net Earnings Per Share – Diluted Operating Earnings (1) Per Share – Diluted Capital Investment Net Acquisition and Divestiture Activity Net Capital Investment Dividends Per Common Share ($/share)(2) Dividend Yield (%) (3) Debt to Capitalization (%)(1) Debt to Adjusted EBITDA (times) (1) 14 13 (15) 21 (48) (2) (2) 13,422 12,973 2,415 3.21 993 1.32 794 1.06 2,122 (221) 1,901 11,790 11,517 2,845 3.79 818 1.09 1,522 2.03 2,162 (219) 1,943 c$0.80 2.40 US$0.20 3.17 26 1.2 28 1.1 (1) Non-GAAP measures as referenced in the Advisory section of the MD&A. (2) fourth quarter dividend paid in December 2009 reflects an amount determined in connection with the Arrangement (defined on page 36) based on carve-out earnings and cash flows. (3) 2010 based on TSX closing share price at year end. 2009 based on NYSE closing share price at year end and using annualized dividend. 33 · OPERATING AND fINANCIAL HIGHLIGHTS · CENOVUS 201 0 ANNUAL REPORT m anagement ’s discussi on and ana lys i s Introduction and Overview of Cenovus Energy ...........................................................................................................................................................................................................................35 Overview of 2010 ......................................................................................................................................................................................................................................................................................... 37 Financial Information ................................................................................................................................................................................................................................................................................. 41 results of Operations ................................................................................................................................................................................................................................................................................47 Operating Segments .................................................................................................................................................................................................................................................................................. 49 Upstream ................................................................................................................................................................................................................................................................................................... 49 Oil sands .............................................................................................................................................................................................................................................................................................. 49 Conventional ......................................................................................................................................................................................................................................................................................52 refining and Marketing ........................................................................................................................................................................................................................................................................56 Corporate and Eliminations ....................................................................................................................................................................................................................................................................58 Quarterly Financial Data ..........................................................................................................................................................................................................................................................................60 Oil and Gas reserves and resources .................................................................................................................................................................................................................................................. 61 liquidity and Capital resources .......................................................................................................................................................................................................................................................... 64 risk Management .........................................................................................................................................................................................................................................................................................67 accounting policies and Estimates .......................................................................................................................................................................................................................................................71 Outlook ............................................................................................................................................................................................................................................................................................................75 advisory ............................................................................................................................................................................................................................................................................................................76 abbreviations ...........................................................................................................................................................................................................................................................................................77 For the Year Ended December 31, 2010 (Canadian Dollars) this Management’s Discussion and analysis (“MD&a”) for Cenovus Energy Inc., dated February 18, 2011, should be read with our audited Consolidated Financial Statements for the year ended December 31, 2010 (“Consolidated Financial Statements”). this MD&a contains forward-looking information about our current expectations, estimates and projections. For information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information, as well as definitions used in this document, see the advisory at the end of this MD&a. Management is responsible for preparing the MD&a, while the audit Committee of the Cenovus Board of Directors (the “Board”) reviews the MD&a and recommends its approval by the Board. this MD&a and the Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with Canadian Generally accepted accounting principles (“Gaap”). production and reserve volumes are presented on a before royalties basis. Certain amounts in prior years have been reclassified to conform to the current year’s presentation. CENOVUS 201 0 aNNUal rEpOrt · MaNa GEM E Nt ’S DISCUSSION aND aNal YSIS · 34 Introduction and Overview of Cenovus Energy Cenovus is a Canadian oil company headquartered in Calgary, Alberta, with a market capitalization of approximately $25 billion on December 31, 2010. In 2010, we had total crude oil, natural gas and NGL production in excess of 250,000 barrels of oil equivalent per day. Our operations include oil sands projects in northern Alberta, including Foster Creek and Christina Lake. These two properties are located in the Athabasca region and use steam-assisted gravity drainage (“SAGD”) to extract crude oil. Also located within the Athabasca region is our pelican Lake property, where we have an enhanced oil recovery project using polymer flood technology, as well as our emerging Grand rapids project. In southern Saskatchewan, we inject carbon dioxide to enhance oil recovery at our Weyburn operation. We also have established conventional crude oil and natural gas production in Alberta and Saskatchewan. In addition to our upstream assets, we have 50 percent ownership in two refineries in Illinois and Texas, U.S.A., enabling us to partially integrate our operations from crude oil production through to refined products such as gasoline, diesel and jet fuel to reduce volatility associated with commodity price movements. Our operational focus over the next five years will be to increase production, predominantly from Foster Creek and Christina Lake as well as pelican Lake and to continue assessment of our emerging resource base. We have proven our expertise and low cost oil sands development approach and our conventional crude oil and natural gas production base is expected to generate reliable production and cash flows which will enable further development of our oil sands assets. In all of our operations, whether crude oil or natural gas, technology plays a key role in improving the way we extract the resources, increasing the amount recovered and reducing costs. Cenovus has a knowledgeable, experienced team committed to continuous innovation. One of our most significant ongoing objectives is to advance technologies that reduce the amount of water, steam, natural gas and electricity consumed in our operations and to minimize surface land disturbance. Our future lies in developing the land position that we hold in the Athabasca region in northeast Alberta. In addition to our Foster Creek and Christina Lake oil sands projects, we currently have three emerging projects in this area: Narrows Lake (1) Grand rapids Telephone Lake (1) Approximate ownership interest Ownership Interest 50 percent 100 percent 100 percent At our Narrows Lake property, located within the Christina Lake region, we have submitted a joint application and environmental impact assessment (“EIA”). This project is expected to begin producing in 2016, and is expected to have a gross production capacity of 130,000 bbls/d. At our Grand rapids property, which is located within the Greater pelican region, a pilot project is underway. If this pilot is determined to be successful, we expect to file a regulatory application for a commercial operation with gross production capacity of 180,000 bbls/d. Our Telephone Lake property is located within the Borealis region. We have submitted a regulatory application for the development of this property, including the construction of a facility with gross production capacity of 35,000 bbls/d. We have a number of opportunities to deliver shareholder value, predominantly through production growth from our resource position in the oil sands, most of which is undeveloped. Our 10 year business plan is to grow our net oil sands production from approximately 60,000 bbls/d in 2010 to 300,000 bbls/d by the end of 2019. Growth is expected to be primarily internally funded through cash flow generated from our established crude oil and natural gas production base where we also have opportunities to add production through new technologies. Our natural gas production provides an economic hedge for the natural gas required as a fuel source at both our upstream and refining operations. Our refineries, which are operated by Conocophillips, an unrelated U.S. public company, enable us to moderate commodity price cycles by processing heavy oil, thus economically integrating our oil sands production. A key milestone in this regard is the planned 2011 coker startup of the Coker and refinery Expansion (“COrE”) project at the Wood river refinery. We also employ commodity hedging to enhance cash flow certainty. In addition to our strategy of growing net asset value, we expect to continue to pay meaningful dividends to deliver strong total shareholder return over the long term. 35 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Our BusInEss struCturE Our operating and reportable segments are as follows: 2009 FinanCial inFORMatiOn Cenovus began independent operations on December 1, 2009, as a result of the plan of arrangement (“Arrangement”) involving Encana Corporation (“Encana”) whereby Encana was split into two independent energy companies, one a natural gas company, Encana and the other an oil company, Cenovus. The results for the year ended December 31, 2010 and the one month period from December 1 to December 31, 2009 represent the Company’s operations, cash flow, and financial position as a stand-alone entity. The results for the periods prior to the Arrangement, being January 1 to November 30, 2009 and January 1 to December 31, 2008 have been prepared on a “carve-out” accounting basis whereby results have been derived from the accounting records of Encana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus. Further information on the carve-out assumptions can be found in the notes to the Consolidated Financial Statements. • Upstream, which includes Cenovus’s development and production of crude oil, natural gas and NGLs in Canada, is organized into two reportable operations: – Oil Sands, which consists of Cenovus’s producing bitumen assets at Foster Creek and Christina Lake, heavy oil assets at pelican Lake, new resource play assets such as Narrows Lake, Grand rapids and Telephone Lake, and the Athabasca natural gas assets. Certain of the Company’s oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with Conocophillips and operated by Cenovus. – Conventional, which includes the development and production of conventional crude oil, natural gas and NGLs in western Canada. • Refining and Marketing, which is focused on the refining of crude oil products into petroleum and chemical products at two refineries located in the U.S. The refineries are jointly owned with and operated by Conocophillips. This segment also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. • Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory. The operating and reportable segments shown above were changed from those presented in prior periods to better align with our long range business plan. All prior periods have been restated to reflect this presentation. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 36 Overview of 2010 2010 marked our first full year operating as an independent company, and we delivered very strong performance overall. Excellent operating performance reflected strong oil sands production growth, with very good operating and capital cost controls to maintain our position as a low cost producer. Despite diminished realized natural gas prices, which resulted from the large oversupply of natural gas markets and crude oil pipeline disruptions, both of which impacted our operating cash flows, we achieved our 2010 cash flow guidance and generated net earnings of $993 million which exceeded 2009 by 21 percent. In addition, managing our business with a continual focus on value creation, cost control and updated credit facilities resulted in Cenovus having an even stronger financial position at the end of 2010 than at the start of the year. Specific highlights for 2010 include: • Operating cash flow from refining and Marketing decreasing by $293 million mainly due to planned turnarounds at both refineries, higher average crude costs and refinery optimization activities due primarily to weaker diesel and gasoline prices primarily in the first half of 2010. partially offsetting these decreases were lower operating expenses and a strengthening of the Canadian dollar; • Net earnings increasing $175 million mainly due to unrealized foreign exchange gains, unrealized mark-to-market hedging gains and lower income taxes, partially offset by lower operating cash flows; • Our debt metrics improving with debt to capitalization decreasing to 26 percent and debt to adjusted EBITDA being 1.2x; and • Substantial growth in our bitumen proved reserves (year-over-year increase • Declaring and paying dividends of $601 million ($0.20 per share per of 288 MMbbls), resulting in very low finding and development costs; • production from our Foster Creek and Christina Lake oil sands projects quarter) in 2010 compared to US$150 million in 2009 paid in connection with the Arrangement. increasing by 33 percent; reserves and resources • receiving regulatory approval for Foster Creek expansion phases F, G and H; • Capital spending on the Foster Creek and Christina Lake expansions increasing significantly, consistent with our strategy to move these projects forward; and • Our Conventional crude oil and natural gas business generating more than $1.2 billion in operating cash flow in excess of the related capital spent to fund the development of our oil sands projects. Additional operating and financial highlights for 2010 compared to 2009 include: • Total capital spending being relatively unchanged year over year, however, spending on our oil sands projects increased 38 percent to $867 million while spending on our refineries decreased 37 percent to $655 million. In our Conventional upstream business, our spending focus on oil increased to 68 percent of spending ($358 million) in 2010 compared to 48 percent ($223 million) in 2009; • proceeds from the divestiture of property, plant and equipment totaled $307 million (2009 - $222 million); • Net revenues increasing 13 percent mainly due to improved crude oil and refined product prices despite pipeline transportation disruptions of crude oil from Alberta to mid-west U.S. refineries in the second half of 2010 and higher royalties as a result of Foster Creek achieving payout status for royalty purposes; • As expected, based on realized natural gas prices declining 34 percent and natural gas volumes declining 12 percent (including the impact of divestitures) we had a decrease in our Upstream operating cash flow of $921 million. The lower natural gas prices and lower operating cash flow from refining and Marketing resulted in decreases to our cash flow of $430 million and operating earnings of $728 million. The natural gas decreases were partially offset by higher crude oil volumes and realized prices; The receipt of Alberta Energy resources Conservation Board (“ErCB”) regulatory approval for expansion phases F, G and H at Foster Creek, including expansion of the development area, combined with an overall increased recovery factor in the area, has resulted in a significant increase to our proved bitumen reserves in 2010. In 2010, we also issued two news releases highlighting detailed information related to our bitumen initially-in-place, contingent resources and prospective resources, which enable investors to more fully understand our inventory of oil sands assets. We also provided further information about our resources and development plans at our Investor Day presentations in June 2010 and at the end of 2010 the estimates of bitumen contingent and prospective resources were updated. Our best estimate bitumen contingent resources at December 31, 2010 were approximately 6.1 billion barrels and our best estimate bitumen prospective resources were approximately 12.3 billion barrels. Foster Creek Our Foster Creek property achieved project payout for royalty purposes in February 2010. project payout is achieved when the cumulative project revenue exceeds the cumulative project allowable costs. As a result, Foster Creek’s royalties increased from $19 million and an effective royalty rate of 2.7 percent in 2009 to $165 million and an effective royalty rate of 16.2 percent in 2010, which includes pre-payout royalties for one month. As noted above, we received regulatory approval from the ErCB for the next three expansion phases at Foster Creek, F, G and H. When all three phases are complete, Foster Creek’s gross production capacity is expected to increase from the current 120,000 bbls/d to 210,000 bbls/d. The next step for these expansions is to receive final partner approval, which is expected in 2011. Engineering and preliminary ground work on phase F is already underway. First production for phase F is expected to be accelerated by 12 months to 2014 compared to our original plan. production from the other two phases is expected in 2016-2017. 37 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Christina Lake Net Capital Investment The construction of the Christina Lake expansion is progressing with phases C and D each expected to add an additional 40,000 bbls/d of gross production capacity. Start up of phase C is expected to begin with steam injection in the second quarter of 2011 and production commencing in the second half of 2011. production from phase D has been advanced from its original planned start by approximately six months and is now targeted to begin in 2013. These expansion phases are expected to bring Christina Lake’s gross production capacity to 98,000 bbls/d in 2013. New resource plays We have announced our intention to move ahead with the development of Narrows Lake, which may use a combination of SAGD and Solvent Aided process (“SAp”) to recover the bitumen. SAp is a technological improvement applied to our SAGD operations that helps maximize the amount of bitumen recovered and requires less steam and water usage. SAp takes the benefit of injecting steam in the SAGD process and combines it with solvents, such as butane, to help bring the bitumen to the surface. In the first quarter of 2010, we initiated the regulatory approval process by filing proposed terms of reference for an EIA and began public consultation for the project. In the second quarter of 2010, final terms of reference were issued by Alberta Environment and a joint application and EIA was filed. In 2010, we received approval from the ErCB and Alberta Environment to begin a pilot project at our Grand rapids project. The drilling of a SAGD well pair and construction of associated facilities is complete and steam injection commenced in December 2010. As part of our efforts to progress these emerging projects, in 2010, we significantly increased our spending to $124 million in new resource play areas including the drilling of over 150 gross stratigraphic wells and commencing our Grand rapids pilot project. In addition, we continued our research and development efforts that we expect will continue to reduce our land footprint, water use and air emissions intensity. refining COrE project At the end of 2010, the COrE project progressed to approximately 91 percent complete from 71 percent at the beginning of the year. Commissioning of several of the process units has been completed with an expected coker start up in the fourth quarter of 2011. At the time of coker start up, we expect that COrE expenditures will reach approximately US$3.7 billion (US$1.85 billion net to Cenovus). The total estimated cost of the COrE project is expected to be approximately US$3.9 billion (US$1.95 billion net to Cenovus), or about 10 percent higher than originally forecast. Unusual weather patterns across our operating areas throughout the year, including a very wet summer, restricted access to our properties and with continued low commodity prices we chose to reduce spending, which has resulted in our upstream capital investment program being lower than originally planned in some of our operating areas. Although upstream capital spending is lower than expected, production levels have remained at expected levels. Our refining capital spending was also lower than expected as unusually high water levels on the Mississippi river delayed deliveries of various COrE modules, deferring some 2010 spending to 2011. As part of our ongoing portfolio management strategy, we divested of certain non-core oil and gas assets for proceeds of $221 million, which reduced our 2010 crude oil and NGLs production by approximately 975 bbls/d (one percent) and natural gas production by approximately 33 MMcf/d (four percent). In total, our 2010 property, plant and equipment divestitures resulted in proceeds of $307 million. Net revenues During the second half of 2010, pipeline disruptions and apportionment challenges restricted the access of Alberta crude oil to U.S. markets. As a result, there were higher inventory levels of WCS and a widening of the WTI- WCS price differential in the second half of 2010. The widened WTI-WCS differential had a negative impact on our upstream revenue; however our refining operations benefitted somewhat due to a lower cost for purchased product. While the effects of pipeline apportionment did not significantly affect our production, it did result in lower sales volumes in the second half of 2010 as we added volumes to storage at the end of 2010. With respect to commodity prices, our strategy is to use financial instruments to protect and provide certainty on a portion of our cash flows and therefore commodity price hedging activity continues to be an important element of our business model. This activity reflects our objective of locking in prices on a portion of our natural gas and crude oil production such that we protect a significant portion of the subsequent years’ cash flows. realized after-tax hedging gains of $199 million during 2010 (2009–gains of $804 million) reflect the benefits of locking in commodity prices in excess of the current period benchmark prices. These realized hedging gains are significantly less than those of 2009 since they effectively reflect the significant over supply and deterioration of natural gas markets and prices over the last two years. Our hedging strategy continues to be sound and allowed us to put in place natural gas hedges for 2010 at approximately $6.00 per Mcf as compared to hedges for 2009 put in place at approximately $9.00 per Mcf when future prices were higher in 2008. For more information on our realized hedging prices, refer to the Operating Netbacks in the results of Operations section of this MD&A. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 38 O u r B u s I n E s s E n v I r O n m E n t Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows select market benchmark prices and foreign exchange rates to assist in understanding our financial results. S E l E C t E d B E n C h M a R k P R i C E S ( 1 ) 2010 Q4 Q3 Q2 Q1 2009 Q4 Q3 Q2 Q1 2008 Crude Oil Prices (US$/bbl) West Texas Intermediate Average End of period spot price Western Canada Select Average End of period spot price Average price – Differential WTI-WCS Condensate (C5 @ Edmonton) Average price – Differential WTI-Condensate (premium)/discount refining margin 3-2-1 Crack spread(2) (US$/bbl) Chicago Midwest Combined (Group 3) natural Gas Prices AECO ($/GJ) NYMEX (US$/MMBtu) Basis Differential NYMEX-AECO (US$/MMBtu) Foreign Exchange 79.61 85.24 76.21 78.05 78.88 62.09 76.13 68.24 59.79 43.31 91.38 91.38 79.97 75.63 83.45 79.36 79.36 70.46 69.82 49.64 65.38 67.12 60.56 63.96 69.84 52.43 64.01 58.06 52.37 34.38 72.87 72.87 64.97 61.38 70.25 71.84 71.84 59.76 59.12 42.69 99.75 44.60 79.70 35.40 14.23 18.12 15.65 14.09 9.04 9.66 12.12 10.18 7.42 8.93 20.05 81.91 85.24 74.53 82.87 84.98 61.35 74.42 65.76 58.07 46.26 106.22 (2.30) – 1.68 (4.82) (6.10) 0.74 1.71 2.48 1.72 (2.95) (6.47) 9.33 9.48 9.25 10.34 11.60 6.11 9.12 10.60 11.38 6.82 8.54 8.09 5.00 8.48 10.95 5.52 8.06 9.16 9.75 9.62 3.91 3.39 4.39 3.80 0.40 0.28 3.52 4.38 0.78 3.66 5.08 4.09 0.32 5.30 0.19 3.92 3.99 0.40 4.01 4.17 0.19 2.87 3.39 0.67 3.47 3.50 0.39 5.34 4.89 0.35 11.22 11.03 7.71 9.04 1.23 Average US/Canadian dollar exchange rate 0.971 0.987 0.962 0.973 0.961 0.876 0.947 0.911 0.857 0.803 0.938 (1) These benchmark prices do not include the impacts of our hedging program or reflect our sales prices. For our realized sales prices, refer to the Operating Netbacks in the results of Operations section of this MD&A. (2) 3-2-1 Crack Spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of ultra low sulphur diesel. 39 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T The global economic recovery that began in the second half of 2009 continued throughout 2010 resulting in increased crude oil demand, mainly from China, other Asian countries and the United States, and was reflected in higher WTI benchmark prices. The closing price of WTI at the end of 2010 increased 15 percent from the 2009 closing price and was more than double the 2008 closing price. While crude oil demand increased compared to 2009 and global production levels from both OpEC and non-OpEC countries has increased, significant spare OpEC production capacity still remained at the end of 2010. Further increases in OpEC production could result in a lowering of crude oil prices. WTI is an important benchmark as it is also used as the basis for determining royalties for a number of our crude oil properties. WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. This blended heavy oil is usually traded at a discount to the light oil benchmark, WTI. The widening of the WTI- WCS differential in 2010 was partially the result of pipeline transportation disruptions of crude oil from Alberta to mid-west U.S. refineries as well as refinery downtime in certain regions of the U.S. in the second half of 2010. While overall the price of WCS increased in 2010 compared to 2009, pipeline disruptions resulted in increased WCS inventory which negatively impacted its market price. At the same time, the price of WTI increased substantially in 2010 resulting in the differential widening to as much as US$31.00 per bbl during the year. The end of 2010 saw the differential narrowing to approximately US$18.51 per bbl. Blending condensate with bitumen enables our bitumen and heavy oil production to be transported. The WTI-condensate differential is the benchmark price of condensate relative to the price of WTI. As purchased condensate is sold as part of the crude oil blend, the cost of condensate purchases impacts both our revenues and transportation and blending costs. The differentials for WTI-WCS and WTI-Condensate are independent of one another and tend not to move in tandem. Benchmark refining margin crack spreads for 2010 improved from 2009 due, in part, to an increase in consumer demand for refined products partly due to the improved economy in the U.S., resulting in increased gasoline and distillate consumption. However, most of the improvement can be attributed to weaker WTI prices relative to other global crude and product prices as a result of pipeline congestion in inland U.S. markets. In 2010, benchmark NYMEX natural gas prices showed marginal improvement primarily due to increased consumption for electric power generation due to record summer heat as well as natural gas prices becoming more economical than certain coal as a fuel source for power generation. 2010 also saw natural gas demand increase for use in the industrial sector of the U.S. While NYMEX natural gas prices were higher in 2010 compared to 2009, throughout 2010 the NYMEX price has been generally on a downward trend. The main cause of the declining natural gas prices in 2010 was natural gas supply. Industry wide natural gas drilling activity, primarily from shale gas, remained strong in 2010 which resulted in higher levels of North American natural gas production as well as volumes in storage increasing to record high levels despite declining market prices. During 2010, the Canadian dollar strengthened relative to the U.S. dollar, primarily since the economic recovery in Canada moved at a greater pace than in the U.S. An increase in the value of the Canadian dollar compared to the U.S. dollar has a negative impact on our revenues as the sale prices of our crude oil and refined products are determined by reference to U.S. benchmarks. Similarly, our refining results are in U.S. dollars and therefore a strengthened Canadian dollar reduces this segment’s reported results. Our risk mitigation strategy has helped reduce our exposure to commodity price volatility. realized hedging gains, after-tax, in 2010 were $199 million (2009–gains of $804 million; 2008–losses of $196 million). Further information regarding our hedging program can be found in the notes to the Consolidated Financial Statements. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 40 Financial Information In our financial reporting to shareholders for the year ended December 31, 2009, we used U.S. dollars as our reporting currency and reported production on an after royalties basis. Effective January 1, 2010, we changed our reporting currency to Canadian dollars and our reporting of production to a before royalties basis. This change in reporting currency and protocol was made to better reflect our business, and allows for increased comparability to our peers. With the change in reporting currency and protocol, all comparative information has been restated from U.S. dollars to Canadian dollars and production from after royalties to before royalties. s E L E C t E D C O n s O L I DAt E D F I n A n C I A L r E s u Lt s ( $ m i lli o n s , e x c e p t p e r s h a r e a m o u n t s) Net revenues Operating Cash Flow (1) Cash Flow (1) - per share – diluted (2) Operating Earnings (1) - per share – diluted (2) Net Earnings - per share – basic (2) - per share – diluted (2) Total Assets Total Long-Term Debt Other Long-Term Obligations Capital Investment Free Cash Flow (1) Cash Dividends (3) - per share (3) (1) Non-GAAp measure defined within this MD&A. 2010 12,973 2,975 2,415 3.21 794 1.06 993 1.32 1.32 22,095 3,432 6,156 2,122 293 601 0.80 2010 vs 2009 13% -29% -15% -48% 21% 2% -6% -5% -2% -57% 2009 11,517 4,189 2,845 3.79 1,522 2.03 818 1.09 1.09 21,755 3,656 6,507 2,162 683 159 US$0.20 2009 vs 2008 -34% 7% -9% -6% -68% -4% -2% -11% -2% -25% 2008 17,570 3,933 3,115 4.14 1,620 2.15 2,526 3.37 3.36 22,614 3,719 7,308 2,204 911 n/a n/a (2) Any per share amounts prior to December 1, 2009 have been calculated using Encana’s common share balances based on the terms of the Arrangement, wherein Encana shareholders received one common share of Cenovus and one common share of the new Encana. (3) The 2009 dividend reflected an amount determined in connection with the Arrangement based on carve-out earnings and cash flow. 41 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T n E t r E v E n u E s v A r I A n C E ( $ m i lli o n s) Net revenues for the Year Ended December 31, 2009 $ 11,517 Increase (decrease) due to: Upstream prices realized hedging Volume royalties Condensate and Other (1) refining and Marketing Corporate and Eliminations Unrealized hedging Other net revenues for the Year Ended December 31, 2010 $ 238 (882) (43) (176) 299 $ 728 (14) (564) 1,306 714 $ 12,973 (1) revenue dollars reported include the value of condensate sold as bitumen or heavy oil blend. Condensate costs are recorded in transportation and blending expense. The increase in net revenues for 2010 is comprised of two main items. Our Upstream net revenues decreased in 2010 primarily due to the decrease in our realized natural gas prices and natural gas production, as well as higher crude oil royalties. partially offsetting these decreases were increases in the realized price and production of crude oil as well as increased prices and volumes of condensate blended with heavy oil consistent with increases in our production. Our refining and Marketing net revenues for 2010 increased primarily because of higher refined product prices and higher prices and volumes related to operational third party sales undertaken by the marketing group, partially offset by reduced refined products volumes from planned turnarounds, a power outage and refinery optimization activities. Also increasing net revenues in 2010, were unrealized hedging gains on natural gas. Further information and explanations regarding our net revenues can be found in the Operating Segments and Corporate and Eliminations sections of this MD&A. O P E r At I n G C A s H F L OW ( $ m i lli o n s) Crude Oil and NGLs Oil Sands Conventional Crude Oil and NGLs Natural Gas Other Upstream Operations refining and Marketing Operating Cash Flow 2010 2009 2008 $ 1,052 $ 1,002 $ 751 1,081 16 2,900 75 753 2,061 5 3,821 368 1,019 1,033 2,227 13 4,292 (359) $ 2,975 $ 4,189 $ 3,933 CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 42 Operating cash flow is a non-GAAp measure defined as net revenues less production and mineral taxes, transportation and blending, operating and purchased product expenses. It is used to provide a consistent measure of the cash generating performance of our assets and improves the comparability of our underlying financial performance between years. Operating cash flow includes realized hedging gains and losses but excludes unrealized hedging gains and losses which are included in the Corporate and Eliminations segment. Operating cash flow decreased by $1,214 million in 2010 primarily because of a $980 million reduction related to natural gas as a result of a 34 percent decrease in realized prices along with lower production volumes. Crude Oil and NGLs operating cash flow increased $48 million in 2010 as higher production and realized prices were partially offset by higher operating expenses consistent with increased production and higher royalties, mainly due to Foster Creek achieving payout status for royalty purposes in 2010. Operating cash flow for refining and Marketing decreased $293 million due to increased crude oil purchased product costs and reduced crude utilization as a result of planned turnarounds, a power outage and refinery optimization activities related to weaker diesel and gasoline prices primarily in the first half of 2010. Details of the components that explain the decrease in operating cash flow can be found in the Operating Segments section of this MD&A. C A s H F L OW Cash flow is a non-GAAp measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Cash flow is commonly used in the oil and gas industry to assist in measuring the ability to finance capital programs and meet financial obligations. ( $ m i lli o n s) Cash From Operating Activities (Add back) deduct: Net change in other assets and liabilities Net change in non-cash working capital Cash Flow Operating cash flow 2010 ($ millions) 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 4,189 50 (2) (980) 11 (293) 2,975 9 0 0 2 , 1 3 R E B M E C E D S L G N D N A L I O E D U R C S D N A S L I O S L G N D N A L I O E D U R C I L A N O T N E V N O C S A G L A R U T A N I S N O T A R E P O M A E R T S P U R E H T O Y E A R E N D I N C R E A S E S D E C R E A S E S I G N T E K R A M D N A G N N I F E R I 0 1 0 2 , 1 3 R E B M E C E D 2010 2009 2008 $ 2,594 $ 3,039 $ 3,225 (55) 234 (26) 220 (92) 202 $ 2,415 $ 2,845 $ 3,115 43 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Cash flow 2010 ($ millions) 3,500 3,000 2,500 2,000 1,500 1,000 500 0 315 (754) 2,845 (136) (181) (170) (293) 852 (63) 2,415 S E C I R P D E Z I L A E R S A G L A R U T A N S L G N D N A L I O E D U R C S E M U L O V D N A S E C I R P 9 0 0 2 , 1 3 R E B M E C E D S E M U L O V S A G L A R U T A N S L G N D N A L I O E D U R C S E I T L A Y O R S E S N E P X E M A E R T S P U I G N T E K R A M D N A G N N I F E R I W O L F H S A C G N T A R E P O I E M O C N I T N E R R U C E S N E P X E X A T R E H T O 0 1 0 2 , 1 3 R E B M E C E D Y E A R E N D I N C R E A S E S D E C R E A S E S • An increase in general and administrative and net interest expense of $75 million; • Higher crude oil and NGLs operating expenses consistent with the increase in production; and • realized foreign exchange losses of $18 million in 2010 compared to gains of $23 million in 2009. The decreases in our 2010 cash flow were partially offset by: • A $852 million decrease in current income tax expense as a result of 2009 including acceleration of current income tax along with 2010 including the utilization of claims from tax pools that we received as a result of the Arrangement, as well as lower realized hedging gains in 2010; • A seven percent increase in our average realized liquids price to $62.60 per bbl compared to $58.24 per bbl; and • A six percent increase in our crude oil and NGLs production volumes. In 2009, our cash flow decreased $270 million compared to 2008 as a result of: • Current income tax expense increased $565 million primarily due to accelerated income tax as a result of the dissolution of a partnership as part of the Arrangement; • A decrease in the realized average liquids selling price, including the impact In 2010 our cash flow decreased $430 million from 2009 primarily due to: of hedges, of $14.25 per bbl to $58.24 per bbl; • A 34 percent decrease in the average realized natural gas price to • Natural gas production declined 12 percent; and $5.16 per Mcf compared to $7.78 per Mcf; • A decrease in operating cash flow from refining and Marketing of $293 million mainly due to planned turnarounds at both refineries, higher crude costs and refinery optimization activities due primarily to weak diesel and gasoline prices in the first half of 2010. partially offsetting these decreases to operating cash flow was a strengthening of the Canadian dollar; • An increase in crude oil and NGLs royalties of $181 million primarily as a result of Foster Creek achieving project payout status for royalty purposes as well as higher WTI prices partially offset by a strengthened average Canadian dollar used for calculating royalties; • Natural gas production in total declining 12 percent as a result of the divestiture of certain non-core properties, which made up four percent of the total annual decrease, as well as reduced capital expenditures; O P E r At I nG E A r n I nGs ( $ m i lli o n s) Net Earnings (Add back) deduct: Unrealized mark-to-market accounting gains (losses), after-tax (1) Non-operating foreign exchange gains (losses), after-tax (2) Gain on bargain purchase, after-tax Operating Earnings • A decrease in the realized average natural gas price, including the impact of hedges, to $7.78 per Mcf compared to $7.93 per Mcf. The 2009 cash flow decreases above were partially offset by: • An improvement in our operating cash flow from refining and Marketing of $727 million; • A decrease in royalties of $260 million resulting from decreased commodity sales prices; • An eight percent increase in our crude oil and NGLs production volumes; and • realized foreign exchange gains of $23 million in 2009 compared to losses of $9 million in 2008. 2010 2009 2008 $ 993 $ 818 $ 2,526 34 153 12 (494) (210) – 636 270 – $ 794 $ 1,522 $ 1,620 (1) The unrealized mark-to-market accounting gains (losses), after-tax includes the reversal of unrealized gains (losses) recognized in prior periods. (2) After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the partnership contribution receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions and future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 44 Operating earnings is a non-GAAp measure defined as net earnings excluding the after-tax gain (loss) on discontinuance; after-tax gain on bargain purchase; after-tax effect of unrealized mark-to-market accounting gains (losses) on derivative instruments; after-tax gains (losses) on non-operating foreign exchange and the effect of changes in statutory income tax rates. We believe that these non-operating items reduce the comparability of our underlying financial performance between periods. The above reconciliation of operating earnings has been prepared to provide information that is more comparable between periods. The items identified above that affected our cash flow and identified below that affected our net earnings also impacted our operating earnings. The decline in operating earnings for 2010 is consistent with the decreases to our operating cash flow and cash flow, details of which can be found above, partially offset by a decrease in depreciation, depletion and amortization (“DD&A”) expense. n E t E A r n I n G s v A r I A n C E ( $ m i lli o n s) Net Earnings for the Year Ended December 31, 2009 $ 818 Increase (decrease) due to: Operating Segments Upstream net revenues Upstream expenses (1) Upstream operating cash flow refining and Marketing operating cash flow Corporate and Eliminations Unrealized hedging gains (losses), net of tax Unrealized foreign exchange gains (losses) Expenses (2) Depreciation, depletion and amortization Income taxes, excluding income taxes on unrealized hedging gains (losses) $ (564) (357) (921) (293) 528 396 (142) 217 390 net Earnings for the Year Ended December 31, 2010 $ 993 (1) Includes production and mineral tax, transportation and blending and operating expenses. (2) Includes general and administrative, net interest, accretion of asset retirement obligations, realized foreign exchange (gains) losses, gain (loss) on divestiture of assets, other (income) loss, net and Corporate operating and purchased product expenses excluding unrealized hedging. In 2010, net earnings increased by $175 million. The items identified above that reduced our cash flow in 2010 also reduced our net earnings. Other significant factors that impacted 2010 net earnings include: • Unrealized mark-to-market hedging gains, after-tax, of $34 million, compared to losses of $494 million, after-tax, in 2009; • Unrealized foreign exchange gains of $69 million in 2010 compared to • DD&A expense increasing by $130 million; • Unrealized foreign exchange losses of $327 million for 2009 compared to gains of $317 million in 2008; and • Future income tax recovery, excluding the impact of the unrealized financial hedging gains and losses, of $386 million, compared to future income tax expense of $142 million in 2008. losses of $327 million in 2009; • A decrease of $217 million in DD&A; and • Future income tax expense, excluding the impact of the unrealized financial hedging gains, in 2010 of $76 million, compared to a recovery of $386 million in 2009. In 2009, net earnings decreased $1,708 million compared to 2008. The items previously discussed that reduced our cash flow in 2009 also reduced our net earnings. Other significant factors that impacted our 2009 net earnings include: • Unrealized mark-to-market hedging losses, after-tax, of $494 million compared to gains, after-tax of $636 million in 2008; h E d g i n g i M P aC t O n n E t E a R n i n g S As a means of managing the volatility of commodity prices, we enter into various financial instrument agreements. Our strategy is to use financial instruments to protect and provide certainty on a portion of our cash flows. Changes in mark-to-market gains or losses on these agreements affect our net earnings and are the result of volatility in the forward commodity prices and changes in the balance of unsettled contracts. 45 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T ( $ m i lli o n s) Unrealized Mark-to-Market Hedging Gains (Losses), after-tax (1) realized Hedging Gains (Losses), after-tax (2) Hedging Impacts in Net Earnings 2010 2009 2008 $ $ 34 199 233 $ $ (494) 804 310 $ $ 636 (196) 440 (1) Included in Corporate and Eliminations financial results. Further detail on unrealized mark-to-market gains (losses) can be found in the Corporate and Eliminations section of this MD&A. (2) Included in the Operating Segment financial results and included in operating cash flow and cash flow. n E t C A P I tA L I n v E s t m E n t ( $ m i lli o n s) Upstream Oil Sands Conventional refining and Marketing Corporate Capital Investment Acquisitions Divestitures Net Capital Investment 2010 2009 2008 $ $ 867 523 1,390 656 76 2,122 86 (307) 629 466 1,095 1,033 34 2,162 3 (222) $ 758 848 1,606 539 59 2,204 – (48) $ 1,901 $ 1,943 $ 2,156 Upstream capital investment in 2010 was primarily focused on continued development of our oil sands projects and conventional oil properties, including the drilling of stratigraphic wells to support the next phases of our expansion activities. refining and Marketing capital investment was primarily focused on the COrE project at the Wood river refinery. Capital investment was funded by cash flow. Further information regarding our capital investment can be found in the Operating Segments section of this MD&A. aC q U i S i t i O n S a n d d i v E S t i t U R E S Our planned program to divest of non-core oil and gas assets in 2010 resulted in proceeds of $307 million. These divestitures included certain non-core conventional crude oil and natural gas producing properties as well as the sale of certain lands at the Narrows Lake property to the FCCL partnership. Our 2010 acquisitions included the purchase of an interest in three sections of undeveloped land at Narrows Lake as well as certain producing conventional oil properties. In the fourth quarter of 2010 under the terms of an agreement with an unrelated Canadian company, we acquired certain marine terminal facilities in Kitimat, British Columbia for $38 million. F r E E C A s H F L OW In order to determine the funds available for financing and investing activities, including dividend payments, we use a non-GAAp measure of free cash flow, which is defined as cash flow in excess of capital investment, which excludes acquisitions and divestitures. Cash flow is a non-GAAp measure and is defined under the cash flow section of this MD&A. ( $ m i lli o n s) Cash Flow Capital Investment Free Cash Flow 2010 2,415 2,122 293 $ $ 2009 2,845 2,162 2008 $ 3,115 2,204 683 $ 911 $ $ CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 46 results of Operations C R U d E O i l a n d n g l S P R O d U C t i O n vO l U M E S ( b b l s /d ) Oil Sands – Heavy Oil Foster Creek Christina Lake pelican Lake Senlac Conventional Liquids Heavy Oil Light and Medium Oil NGLs (1) (1) NGLs include condensate volumes. 2010 51,147 7,898 22,966 – 16,659 29,346 1,171 129,187 2010 vs 2009 36% 18% -8% – -7% -3% -3% 6% 2009 37,725 6,698 24,870 3,057 17,888 30,394 1,206 121,838 2009 vs 2008 44% 57% -9% -5% -6% -3% –% 8% 2008 26,220 4,279 27,324 3,223 19,062 31,492 1,203 112,803 Overall, our crude oil and NGLs production increased six percent in 2010. Increases in production volumes at Foster Creek and Christina Lake were partially offset by expected natural declines at our other properties. We also sold certain non-core Conventional properties in 2010 which decreased our total annual crude oil production by 975 bbls/d or one percent. In 2009, we also sold our Senlac property. Further detail on the changes in our production can be found in the Operating Segments section of this MD&A. n at U R a l g a S P R O d U C t i O n vO l U M E S ( M M c f/d ) Conventional Oil Sands 2010 694 43 737 2010 vs 2009 -11% -19% -12% 2009 784 53 837 2009 vs 2008 -9% -40% -12% 2008 866 88 954 47 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T During 2009 and 2010, we chose to restrict capital spending on natural gas drilling, completion and tie-in activity in favour of increasing investment in crude oil projects. In 2010, we divested of certain non-core natural gas properties which decreased annual production by approximately 33 MMcf/d, or four percent. Weather related delays experienced throughout 2010 also negatively impacted our natural gas production. On a barrel of oil equivalent basis, excluding the divestitures, production remained consistent in 2010 compared to 2009. Further details on the changes in our production can be found in the Operating Segments section of this MD&A. O P E R at i n g n E t B aC k S 2010 2009 2008 Liquids natural Gas ($/mcf) ($/bbl) Liquids ($/bbl) Natural Gas ($/Mcf) Liquids ($/bbl) Natural Gas ($/Mcf) price (1) royalties production and mineral taxes Transportation and blending (1) Operating expenses Netback excluding realized Financial Hedging realized Financial Hedging Gains (Losses) $ 62.96 $ 9.33 0.62 1.88 11.78 39.35 (0.36) 4.09 0.07 0.02 0.17 0.96 2.87 1.07 $ 57.14 5.62 0.65 1.60 10.67 38.60 1.10 $ 4.15 0.08 0.05 0.15 0.86 3.01 3.63 $ 77.84 $ 9.32 1.01 1.62 10.90 54.99 (5.35) 8.17 0.42 0.11 0.24 0.84 6.56 (0.24) Netback including realized Financial Hedging $ 38.99 $ 3.94 $ 39.70 $ 6.64 $ 49.64 $ 6.32 (1) Operating netbacks for liquids exclude the value of condensate sold as bitumen blend and condensate costs recorded in transportation and blending expense. In 2010, our average netback for liquids, excluding realized financial hedging, increased by $0.75 per bbl primarily due to an increase in prices partially offset by higher royalties and operating expenses. Our average netback for natural gas, excluding realized financial hedges, decreased by $0.14 per Mcf primarily as a result of lower sales prices and increased operating expenses per Mcf as natural gas production decreased while operating expenses were relatively consistent. Further discussions of operating results are contained in the Operating Segments section of this MD&A. As part of ongoing efforts to maintain financial resilience and flexibility, we reduced our price risk through a commodity price hedging program. Our strategy is to protect a significant portion of the subsequent years’ cash flows through the use of various financial instruments. Further information regarding this program can be found in the notes to the Consolidated Financial Statements. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 48 Operating segments Our Upstream Segment has two reportable operations: Oil Sands and Conventional. Oil Sands consists of our producing bitumen assets at Foster Creek and Christina Lake, heavy oil assets at pelican Lake, the new resource play assets such as our Narrows Lake, Grand rapids and Telephone Lake properties as well as the Athabasca natural gas assets. Conventional includes the development and production of crude oil, natural gas and NGLs in western Canada. The refining and Marketing segment includes our ownership interest in the Wood river and Borger refineries and the marketing of our crude oil and natural gas, as well as third-party purchases and sales of product. u P s t rE A m O i l S a n d S In northeast Alberta, we are a 50 percent partner in the Foster Creek and Christina Lake oil sands projects and also produce heavy oil from our pelican Lake operations. prior to its divestiture in the fourth quarter of 2009, we also owned 100 percent of the Senlac property. We also have several new resource plays in the early stages of assessment, including Narrows Lake, Grand rapids and Telephone Lake. The Oil Sands assets also include the Athabasca natural gas property from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations. Oil Sands highlights in 2010 include: • Foster Creek achieving project payout status for royalty purposes in 2010; • receiving regulatory approval for the next three phases of expansion (F, G and H) at Foster Creek; • Significant increases in production at Foster Creek and Christina Lake; • Filing a joint application and EIA for our Narrows Lake project; • receiving approval for and commencing a pilot project at our Grand rapids property; and • Completing a large stratigraphic well program in 2010 and commencing a winter stratigraphic well program targeting to drill approximately 450 wells in 2011. O i l S a n d S – C R U d E O i l Financial results ( $ m i lli o n s) revenues Deduct (add) realized financial hedging (gains) losses royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating Operating Cash Flow Capital Investment 2010 2009 2008 $ 2,611 $ 2,008 $ 2,337 8 276 2,327 – 934 341 1,052 867 (48) 129 75 178 1,927 2,084 1 626 298 1,002 629 373 2 784 279 1,019 758 261 $ Operating Cash Flow in Excess of related Capital $ 185 $ 49 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T production Volumes C r u d e o i l ( b b l s /d ) Foster Creek Christina Lake Total pelican Lake Senlac 2010 51,147 7,898 59,045 22,966 – 82,011 2010 vs 2009 36% 18% 33% -8% – 13% 2009 37,725 6,698 44,423 24,870 3,057 72,350 2009 vs 2008 44% 57% 46% -9% -5% 19% 2008 26,220 4,279 30,499 27,324 3,223 61,046 Foster Creek and Christina Lake Production Volumes by Quarter (bbls/d) F O ST E R C R E E K C H R I ST I N A L A K E 65,000 60,000 55,000 50,000 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Q4 2008 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2009 2010 Net revenues Variance ( $ m i lli o n s) Crude Oil 2009 Net revenues Net revenues Variances in: price (1) Volume royalties Condensate(2) 2010 net revenues $ 1,927 80 178 (147) 289 $ 2,327 (1) Includes the impact of realized financial hedging. (2) revenue dollars reported include the value of condensate sold as bitumen blend. Condensate costs are recorded in transportation and blending expense. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 50 In 2010 our average crude oil sales price, excluding realized financial hedges, increased eight percent to $59.76 per bbl compared to 2009 consistent with the WCS benchmark increasing year over year. Financial hedging activities for 2010 resulted in realized losses of $8 million ($0.26 per bbl) compared to gains of $48 million ($1.87 per bbl) in 2009 (2008–losses of $75 million; $3.37 per bbl). Foster Creek production increased 36 percent primarily as a result of the phase D and E expansions, which commenced production late in the first quarter of 2009, as well as increased production from wedge wells. The 18 percent increase in production at Christina Lake was a result of increased production from the phase B expansion, well optimizations and production from the first wedge well at Christina Lake. At pelican Lake, the decrease in production was the result of expected natural production declines. In the fourth quarter of 2009, we sold our Senlac heavy oil assets which had annual production of 3,057 bbls/d in 2009. pipeline apportionments in the second half of 2010 did not significantly affect our production but did result in lower sales volumes and higher volumes in storage at the end of 2010. royalties increased by $147 million in 2010 compared to 2009 due to Foster Creek achieving project payout status for royalty purposes in the first quarter of 2010, along with an increased WTI price partially offset by a strengthened Canadian dollar used for calculating royalties, resulting in higher royalty rates. For 2010, the effective royalty rate for Foster Creek was 16.2 percent (2009–2.7 percent; 2008–1.1 percent) and for Christina Lake was 3.9 percent (2009–2.3 percent; 2008–1.0 percent). pelican Lake royalties remained consistent as the increase in royalty rates due to higher prices was offset O i l S a n d S – C a P i ta l i n v E S t M E n t by lower volumes, which resulted in an effective royalty rate of 21.1 percent (2009–20.1 percent; 2008–20.2 percent). Transportation and condensate blending costs increased by $308 million in 2010. The increase in condensate blending costs of $289 million was primarily related to the volume of condensate required increasing due to higher production at Foster Creek and Christina Lake as well as an increase in the average cost of condensate, while blending costs at pelican Lake were consistent with 2009. Transportation costs increased $19 million primarily due to the higher production volumes. Operating costs increased by $43 million due to higher repairs and maintenance, increased field personnel in relation to phased expansions, higher chemical costs and purchased fuel volumes in relation to production increases. The increase in operating costs at Foster Creek and Christina Lake is due to a 33 percent increase in production volumes. At pelican Lake, the increase in operating costs is attributable to polymer chemical costs and increased maintenance and workover expenses. O i l S a n d S – n at U R a l g a S Oil Sands also includes our 100 percent owned natural gas operations in Athabasca. primarily as a result of natural declines, our natural gas production decreased to 43 MMcf/d (2009–53 MMcf/d; 2008–88 MMcf/d). As a result of lower production as well as lower natural gas prices, operating cash flow declined $104 million in 2010 to $77 million (2009–$181 million; 2008–$160 million). ( $ m i lli o n s) Foster Creek Christina Lake Total pelican Lake New resource plays Other (1) (1) Includes Athabasca and Senlac. 2010 2009 2008 $ $ 278 346 624 104 124 15 $ 262 224 486 72 17 54 356 235 591 62 53 52 $ 867 $ 629 $ 758 51 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Our Oil Sands capital investment in 2010 was primarily focused on the continued development of the next expansion phases of the Foster Creek and Christina Lake projects, as well as activities related to our pelican Lake polymer flood. Our current plan is to increase gross production capacity at Foster Creek and Christina Lake to approximately 218,000 bbls/d of bitumen with the expected completion of Christina Lake phase C in 2011 and phase D in 2013. Foster Creek capital investment in 2010 was higher as we received regulatory approval for the next phases of expansion (F, G and H). The majority of Foster Creek spending was related to drilling stratigraphic test wells, debottlenecking portions of the plant and preparation for the next phases of expansion including engineering and design, site preparation and camp construction. We are planning to accelerate the completion of Foster Creek phase F by up to 12 months which would result in production beginning in 2014. At Christina Lake, capital investment was higher in 2010 due to construction and well pad drilling related to the phase C expansion, detailed design, procurement and construction for the phase D expansion and the drilling of stratigraphic test wells. We have chosen to accelerate completion of Christina Lake phase D by approximately six months and expect production to begin in 2013. Our current plan is to increase gross production capacity to approximately 98,000 bbls/d of bitumen with the expected completion of phase C in 2011 and phase D in 2013. Capital investment for pelican Lake was primarily related to capital maintenance, facility additions for polymer flooding and infill drilling opportunities. Capital investment in new resource plays in 2010 was mainly related to the drilling of stratigraphic test wells, as shown in the following table, regulatory advancement and the Grand rapids pilot project including the drilling of a SAGD well pair and facility construction. Gross Stratigraphic Wells The stratigraphic test wells drilled at Foster Creek and Christina Lake are to support the next phases of expansion while the stratigraphic test wells drilled at Narrows Lake, Grand rapids, Telephone Lake and other emerging projects have been drilled to assess the quality of our projects and to support regulatory applications for project approval. Foster Creek Christina Lake Total Narrows Lake Grand rapids Telephone Lake Other C O n v E n t i O n a l 2010 2009 2008 82 24 106 39 71 26 17 259 65 28 93 – 17 – – 110 144 113 257 – 8 5 5 275 Our Conventional operations include the development and production of crude oil, natural gas and NGLs in Alberta and Saskatchewan. These conventional crude oil and natural gas assets generate reliable production and cash flows. Conventional highlights in 2010 include: • Generating operating cash flow in excess of capital investment of more than $1.2 billion; • recompleted 1,194 Alberta natural gas wells adding low cost production; • Weyburn production increasing as a result of our well optimization program, which partially offset natural declines; • The continued development of the Bakken and Shaunavon plays where we more than doubled average production to about 2,000 bbls/d from less than 1,000 bbls/d in 2009; and • Divesting of certain non-core properties for proceeds of $221 million, which reduced our annual crude oil and NGLs production volume two percent and our annual natural gas production volume four percent. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 52 C R U d E O i l a n d n g l S Financial results ( $ m i lli o n s) revenues Deduct (add) realized financial hedging (gains) losses royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating Operating Cash Flow Capital Investment 2010 2009 2008 $ 1,229 $ 1,161 $ 1,752 9 153 – 119 1,067 1,042 28 86 202 751 358 393 $ 28 87 174 753 223 530 $ 146 208 1,398 40 154 171 1,033 359 674 Operating Cash Flow in Excess of related Capital $ production Volumes ( b b l s /d ) Heavy Oil Alberta Light and Medium Oil Alberta Saskatchewan NGLs 2010 16,659 10,854 18,492 1,171 47,176 2010 vs 2009 2009 2009 vs 2008 2008 -7% -9% –% -3% -5% 17,888 -6% 19,062 11,959 18,435 1,206 49,488 -14% 5% –% -4% 13,941 17,551 1,203 51,757 53 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Net revenues Variance Net Revenues Variance ($ millions) 1,500 1,000 1,042 500 0 9 0 0 2 , 1 3 R E B M E C E D 133 (76) (34) 2 1,067 ) 1 ( E C I R P E M U L O V S E I T L A Y O R ) 2 ( E T A S N E D N O C 0 1 0 2 , 1 3 R E B M E C E D Y E A R E N D I N C R E A S E S D E C R E A S E S (1) Includes the impact of realized financial hedging. (2) revenue dollars reported include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. For 2010 the average crude oil and NGLs sales price, excluding realized hedging, increased 14 percent to $68.45 per bbl, consistent with the increases in benchmark prices. During 2010, realized financial hedging losses were $9 million ($0.54 per bbl) compared to gains of less than $1 million ($0.02 per bbl) in 2009 (2008–losses of $146 million; $7.67 per bbl). n at U R a l g a S Financial results ( $ m i lli o n s) revenues Deduct (add) realized financial hedging (gains) losses royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating Operating Cash Flow Capital Investment production in 2010 was lower than 2009 due to expected natural declines, the divestiture of non-core producing properties in the first half of 2010 (which had an annual average production of approximately 1,000 bbls/d), production downtime due to weather and operational challenges in Alberta and Saskatchewan. pipeline apportionments in the second half of 2010 did not significantly affect our production but did result in lower heavy oil sales prices as well as lower sales volumes and higher volumes in storage at the end of 2010. partially offsetting these reductions was increased production from well optimizations at Weyburn and new wells in Alberta and Saskatchewan, including increased production at Bakken and Shaunavon. royalties for 2010 were $34 million higher as a result of higher commodity prices, as well as higher royalty rates arising from the higher commodity prices, which resulted in an effective royalty rate of 13.3 percent for 2010 (2009–11.4 percent; 2008–13.0 percent). The higher royalty rate was partially offset by lower volumes. production and mineral taxes were consistent in 2010 as higher commodity prices were offset by a prior period adjustment that had increased expenses in 2009. Transportation and blending costs were consistent in 2010 as increases in the average cost of condensate were offset by decreased volumes of condensate required for blending with heavy oil. Operating costs increased $28 million in 2010 primarily from increased workover activity mainly at Weyburn, higher repair and maintenance activity in all areas, higher trucking costs related to new production in Saskatchewan and higher indirect costs. Our Conventional crude oil and NGLs operations generated $393 million of operating cash flow in excess of capital investment, a decrease of $137 million from 2009 mainly due to increased capital investment in 2010. 2010 2009 2008 $ 1,042 $ 1,189 $ 2,588 (264) 17 1,289 6 44 235 1,004 165 839 (1,007) 19 2,177 15 45 237 1,880 243 76 79 2,433 38 76 252 2,067 489 $ 1,637 $ 1,578 Operating Cash Flow in Excess of related Capital $ CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 54 Net revenues Variance Net Revenues Variance ($ millions) 2,500 2,000 1,500 1,000 500 0 2,177 (754) (136) 2 1,289 9 0 0 2 , 1 3 R E B M E C E D ) 1 ( E C I R P E M U L O V S E I T L A Y O R 0 1 0 2 , 1 3 R E B M E C E D Y E A R E N D I N C R E A S E S D E C R E A S E S (1) Includes the impact of realized financial hedging. Our natural gas revenue and operating cash flow is down significantly due to lower realized prices. While our average natural gas price, excluding realized financial hedges, decreased slightly compared to 2009 and was consistent with the change in benchmark AECO price, the most significant decline in our revenue is a $743 million decline related to our realized financial hedging C O n v E n t i O n a l – C a P i ta l i n v E S t M E n t ( $ m i lli o n s) Alberta Saskatchewan gains in 2010, which were $264 million ($1.04 per Mcf), compared to gains of $1,007 million ($3.52 per Mcf) in 2009 (2008–losses of $76 million; $0.24 per Mcf) as a result of our settled fixed price contracts being approximately $3.00 per Mcf lower than the same period in 2009 due to the oversupply of natural gas and weaker market prices. For details of the specific pricing on our hedging program, see the notes to our Consolidated Financial Statements. The cumulative impact of restricted natural gas capital spending in 2009 and 2010 as well as divestitures of non-core properties and natural production declines reduced our natural gas production volumes by 11 percent to 694 MMcf/d in 2010 (2009–784 MMcf/d; 2008–866 MMcf/d). The divestitures reduced our 2010 annual natural gas production by approximately 33 MMcf/d. royalties were slightly lower in 2010 as a result of adjustments related to prior years’ production partially offset by lower volumes. The average royalty rate for 2010 was 1.7 percent (2009–1.6 percent; 2008–3.1 percent). production and mineral taxes in 2010 were $9 million lower than 2009 mainly due to lower prices and volumes in 2010. Costs related to transportation decreased slightly in 2010 due to lower volumes. Operating expenses for 2010 decreased slightly as a result of reduced operations due to divestitures and lower production volumes. These declines were specifically related to lower property tax, repairs and maintenance, lower field staff and salaries as well as lower chemical costs, were offset with increased electricity prices and higher indirect costs. Our Conventional natural gas operations generated $839 million of operating cash flow in excess of capital investment, a decrease of $798 million from 2009 mainly due to lower realized prices in 2010. 2010 2009 2008 $ $ 303 220 523 $ $ 340 126 466 $ $ 598 250 848 For 2010, approximately 68 percent or $358 million of our capital investment was on our crude oil properties (2009–48 percent or $223 million; 2008– 42 percent or $359 million). Capital investment in Alberta was focused on our oil program, our shallow gas projects and our liquids rich deep gas projects. Our capital investment in Saskatchewan continued to focus on drilling and facility work at Weyburn as well as appraisal projects at Lower Shaunavon and Bakken. In 2010, we drilled 36 wells in the Shaunavon and Bakken areas, 22 of which were on production at the end of 2010. The following table details our Conventional drilling activity. Fewer natural gas wells were drilled in 2010 as our drilling program shifted towards oil wells from shallow gas wells. Well recompletions are mostly related to CBM development. (n e t w e ll s) Crude oil Natural gas recompletions Stratigraphic test wells 2010 180 495 1,194 9 2009 2008 105 502 855 5 93 1,375 1,017 13 55 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T r E F I n I n G A n D m A r k E t I n G This operating segment includes the results of our refining operations in the U.S. that are jointly owned with and operated by Conocophillips. This segment’s results also include the marketing group’s third party purchases and sales of product, undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification. refining and Marketing highlights in 2010 include: • The progression of the COrE project to approximately 91 percent complete from 71 percent at the beginning of the year; and • Operating cash flow increasing in the fourth quarter by $112 million due to higher market crack spreads and increased utilization compared to the fourth quarter of 2009. Financial results ( $ m i lli o n s) revenues purchased product Gross margin Operating expenses Operating Cash Flow Capital Investment 2010 $ 8,228 $ 7,664 564 489 75 656 2009 6,922 6,020 902 534 368 1,033 2008 $ 10,684 10,500 184 543 (359) 539 Capital Investment in Excess of Operating Cash Flow $ (581) $ (665) $ (898) refining and Marketing revenues in 2010 increased 19 percent primarily due to higher prices for refined products and crude oil, as well as higher marketing volumes related to operational third-party sales. times between the purchases of a portion of our Canadian heavy oil and the processing at the refinery and resulted in the product purchased in the third quarter of 2010 to be processed in the fourth quarter of 2010. purchased product costs, which are determined on a first-in, first-out inventory valuation basis, increased 27 percent in 2010 due mainly to higher crude costs and operational third-party marketing volumes. Operating costs, consisting mainly of labour, utilities and supplies, decreased eight percent in 2010 due to lower maintenance and decreased prices for utilities consumed at the refineries and a strengthened Canadian dollar. Our refining operations benefitted in the fourth quarter of 2010 from the wider light-heavy crude oil price differentials that occurred in the third quarter of 2010 as a result of pipeline disruptions. In addition, the initial start up phase of the Keystone pipeline in 2010 resulted in lengthy transportation 2010 operating cash flow decreased by $293 million mainly due to planned turnarounds at both refineries, higher average crude costs as well as refinery optimization activities due primarily to weaker diesel and gasoline prices in the first half of 2010. partially offsetting these decreases to operating cash flow was a strengthening of the Canadian dollar. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 56 R E F i n E Ry O P E R at iO n S ( 1 ) Crude oil capacity (Mbbls/d) Crude oil runs (Mbbls/d) Crude utilization (%) refined products (Mbbls/d) 2010 2009 2008 452 386 86 405 452 394 87 417 452 423 93 448 (1) represents 100% of the Wood river and Borger refinery operations. On a 100 percent basis, our refineries have a current capacity of approximately 452,000 bbls/d of crude oil and 45,000 bbls/d of NGLs, including processing capability to refine up to 145,000 bbls/d of blended heavy crude oil. Upon completion of the Wood river COrE project we expect to be able to refine approximately 275,000 bbls/d (on a 100 percent basis) of heavy crude oil (approximately 150,000 bbls/d of bitumen equivalent) primarily into motor fuels. Our crude utilization was slightly lower in 2010 primarily due to a planned turnaround at the Wood river refinery, an extended turnaround at the Borger refinery, a power outage at Wood river, unplanned maintenance and refinery optimization activities. C a P i ta l i n v E S t M E n t ( $ m i lli o n s) Wood river refinery Borger refinery Marketing 2010 2009 2008 $ 568 $ 944 $ 87 1 88 1 $ 656 $ 1,033 $ 477 45 17 539 Our refining capital investment in 2010 continued to focus on the COrE project at the Wood river refinery. For 2010, of the $568 million capital expenditures at the Wood river refinery, $473 million were related to the COrE project. At December 31, 2010, the COrE project is approximately 91 percent complete. Unanticipated high water levels on the Mississippi river caused delays in the delivery schedule of various modules, which resulted in a shift to the timeline for this project. Commissioning of several of the process units has been completed with an expected coker start up in the fourth quarter of 2011. At the time of coker start up, we expect that COrE expenditures will reach approximately US$3.7 billion (US$1.85 billion net to Cenovus). The total estimated cost of the COrE project is expected to be approximately US$3.9 billion (US$1.95 billion net to Cenovus), or about 10 percent higher than originally forecast. The balance of the Wood river and Borger refineries 2010 capital investment was related to refining reliability and maintenance projects, clean fuels and other emission reduction environmental initiatives. 57 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Corporate and Eliminations Financial results ( $ m i lli o n s) revenues Expenses (add) deduct Operating purchased product 2010 2009 2008 $ (64) $ (778) $ 731 3 (115) 30 (110) $ 48 $ (698) $ (13) (159) 903 The Corporate and Eliminations segment includes revenues that represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices. The segment also includes inter-segment eliminations that relate to transactions that have been recorded at transfer prices based on current market prices as well as unrealized intersegment profits in inventory. Operating expenses primarily relate to unrealized mark-to-market gains and losses on long-term power purchase contracts. The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative and financing activities made up of the following: ( $ m i lli o n s) General and administrative Interest, net Accretion of asset retirement obligation Foreign exchange (gain) loss, net (Gain) loss on divestiture of assets and other 2010 2009 2008 $ $ $ 251 279 75 (51) (4) 211 244 45 304 (2) $ 550 $ 802 $ 171 233 40 (308) 3 139 General and administrative expenses were $40 million higher in 2010 primarily due to higher salaries and benefits as we move to implement our 10 year strategic plan and complete the transition to a new independent company as well as higher long-term incentive expense due to an increase in our share price. Net interest in 2010 was $35 million higher than 2009 primarily as a result of a full year of standby fees incurred on our committed credit facility in 2010 as well as a full year of amortization on financing costs related to the setup of debt financing programs. Additionally, interest on long-term debt was slightly higher in 2010 as a result of a higher average interest rate and higher outstanding debt in 2010 compared to the proportionate share of Encana’s debt allocated to Cenovus for the majority of 2009. The weighted average interest rate on outstanding debt for the year ended December 31, 2010 was 5.8 percent (2009–5.5 percent; 2008–5.5 percent). In 2010 we reported foreign exchange gains of $51 million (2009–losses of $304 million; 2008–gains of $308 million), the majority of which were unrealized. The strengthening of the Canadian dollar during 2010 led to unrealized gains on our U.S. dollar debt, which was partially offset by unrealized losses on our U.S. dollar partnership contribution receivable. The 2010 gain on divestiture of assets and other includes a gain of $12 million related to the acquisition of certain marine terminal facilities in Kitimat, British Columbia in the fourth quarter of 2010. Summary of Unrealized Mark-To-Market Gains (Losses) The volatility of commodity prices has a significant impact on our net earnings, and as a means of managing this volatility, we enter into various financial instrument agreements. Our strategy is to use financial instruments to protect and provide certainty on a portion of our cash flows. The financial instrument agreements were recorded at the date of the financial statements based on mark-to-market accounting. Changes in the mark-to-market gains or losses reflected in corporate revenues are the result of volatility between periods in the forward commodity prices and changes in the balance of unsettled contracts. The table below provides a summary of the unrealized mark-to-market gains and losses recognized for each period. Additional information regarding financial instruments can be found in the notes to the Consolidated Financial Statements. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 58 ( $ m i lli o n s) revenues Crude Oil Natural Gas Expenses Income Tax Expense (recovery) Unrealized Mark-to-Market Gains (Losses), after-tax d E P R E C i at i O n , d E P l E t i O n a n d a M O R t i Z at i O n ( $ m i lli o n s) Upstream refining and Marketing Corporate and Eliminations 2010 2009 2008 $ $ $ (92) 152 60 14 46 12 34 $ (102) (566) (668) 30 (698) (204) $ (494) $ 260 630 890 (9) 899 263 636 2010 2009 2008 $ 1,039 $ 1,250 $ 239 32 232 45 1,179 205 13 $ 1,310 $ 1,527 $ 1,397 We use full cost accounting for our upstream oil and gas activities and calculate DD&A on a country-by-country cost centre basis. Upstream DD&A decreased in 2010 primarily as a result of a reduced DD&A rate with the addition of proved reserves at Christina Lake phase D at the end of 2009. refining and Marketing DD&A in 2010 includes an impairment loss of $37 million related to a processing unit determined to be a redundant asset and which would not be used in future operations at the Borger refinery. Offsetting this was lower DD&A on the refineries primarily related to a strengthening of the average U.S./Canadian dollar exchange rate in 2010. Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, office furniture and leasehold improvements. i n C O M E t a x ( $ m i lli o n s) Current income tax expense Future income tax expense (recovery) Total Income taxes When comparing 2010 to 2009, our current tax expense declined and our future tax expense increased. Our current income tax expense in 2009 included the acceleration of income tax incurred as a result of certain corporate restructuring transactions which were required to give effect to the Arrangement and was offset by a recovery of future income tax in 2009. Our future income tax expense in 2010 includes a tax benefit of $107 million from the recognition of net capital losses expected to be realized against future taxable capital gains. These capital losses are attributable to an internal restructuring undertaken in 2010. Our effective tax rate for 2010 was 14.6 percent compared to 29.6 percent in 2009 (2008–23.5 percent). The decrease in 2010 is primarily due to the recognition of the future tax benefits arising from net capital losses and from operating losses in our U.S. entities in 2010 compared to earnings in 2009. It should be noted that our 2009 income tax expense was calculated as if Cenovus and its subsidiaries had been separate tax paying legal entities, each filing a separate tax return in its local jurisdiction, and that the calculation 2010 2009 2008 $ $ 82 88 170 $ $ 934 (590) 344 $ $ 369 405 774 was based on a number of assumptions, allocations and estimates consistent with the historical carve-out consolidated financial statements. Our effective tax rate in any year is a function of the relationship between total tax expense and the amount of earnings before income taxes for the year. The effective tax rate differs from the statutory tax rate as it takes into consideration permanent differences, adjustments for changes in tax rates and other tax legislation, variation in the estimate of reserves and the differences between the provision and the actual amounts subsequently reported on the tax returns. permanent differences include: • The non-taxable portion of Canadian capital gains and losses; • Multi-jurisdictional financing; • Non-deductible stock-based compensation; and • Taxable foreign exchange gains not included in net earnings. Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. We believe that our provision for taxes is adequate. 59 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Quarterly Financial Data ( $ m i lli o n s , e x c e p t p e r s h a r e a m o u n t s) Net revenues Operating Cash Flow (1) Cash Flow (1) - per share – diluted (2) Operating Earnings (1) - per share – diluted (2) Net Earnings - per share – basic (2) - per share – diluted (2) Capital Investment Free Cash Flow (1) Cash Dividends (3) - per share (3) Q4 2010 Q3 2010 Q2 2010 Q1 2010 Q4 2009 Q3 2009 Q2 2009 Q1 2009 3,172 3,115 3,195 3,491 3,005 3,001 2,818 2,693 812 648 660 509 0.86 0.68 140 0.19 73 0.10 0.10 706 (58) 151 159 0.21 223 0.30 0.30 480 29 150 665 537 0.71 142 0.19 172 0.23 0.23 443 94 150 838 721 0.96 353 0.47 525 0.70 0.70 493 228 150 954 235 0.31 169 0.23 42 0.06 0.06 507 (272) 159 0.20 0.20 0.20 0.20 US$0.20 1,134 1,173 924 1.23 427 945 1.26 512 0.57 0.68 101 0.13 0.13 515 409 n/a n/a 160 0.21 0.21 488 457 n/a n/a 928 741 0.99 414 0.55 515 0.69 0.69 652 89 n/a n/a Q4 2008 3,946 121 (209) (0.28) (159) (0.21) 490 0.65 0.65 760 (969) n/a n/a (1) Non-GAAp measure defined within this MD&A. (2) Any per share amounts prior to December 1, 2009 have been calculated using Encana’s common share balances based on the terms of the Arrangement, wherein Encana shareholders received one common share of Cenovus and one common share of the new Encana. (3) The fourth quarter 2009 dividend reflected an amount determined in connection with the Arrangement based on carve-out earnings and cash flow. In the fourth quarter of 2010 cash flow increased $413 million compared to the fourth quarter of 2009 primarily due to: • A $526 million decrease in current income tax expense as a result of 2009 including acceleration of current income tax along with 2010 including the utilization of claims from tax pools that we received as a result of the Arrangement, as well as lower realized hedging gains in 2010; and • A $112 million increase in operating cash flow from refining and Marketing primarily due to higher market crack spreads and increased utilization compared to the fourth quarter of 2009. The increases in our fourth quarter 2010 cash flow were partially offset by: • A 22 percent decrease in the average realized natural gas price to $5.05 per Mcf from $6.44 per Mcf; • A 14 percent decrease in natural gas production primarily due to the disposition of certain non-core properties and reduced natural gas capital expenditures; • A five percent decrease in our average realized liquids price to • Higher crude oil and NGLs operating costs consistent with the increase in production; • An increase in general and administrative and net interest expense of $13 million; and • An increase in royalties of $10 million primarily as a result of Foster Creek achieving royalty payout as well as higher WTI prices partially offset by a strengthened average Canadian dollar used for calculating royalties. Our net earnings in the fourth quarter of 2010 were $31 million higher than 2009. The factors that increased our cash flow in the fourth quarter also increased net earnings. Other significant factors that impacted our fourth quarter 2010 net earnings include: • Future income tax expense, excluding the impact of the unrealized financial hedging gains, in 2010 of $37 million, compared to a recovery of $351 million in 2009; • Unrealized mark-to-market losses, after-tax, of $197 million, compared to losses of $92 million, after-tax, in 2009; $61.46 per bbl compared to $64.74 per bbl; • Unrealized foreign exchange gains of $30 million in 2010 compared to • A decrease in crude oil and NGLs volumes sold due to pipeline apportionments in the fourth quarter of 2010; losses of $86 million in 2009; and • A decrease of $28 million in DD&A. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 60 Oil and Gas reserves and resources As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). prior to the year ended December 31, 2010, we presented our reserves estimates in accordance with certain U.S. disclosure requirements pursuant to an exemption from certain of the NI 51-101 requirements. Year over year comparisons are in reference to the previously disclosed December 31, 2009 estimates prepared by independent qualified reserves evaluators (“IQrEs”) and determined using 2009 12 month average constant prices and costs, as prescribed by the U.S. Securities and Exchange Commission (“SEC”). We retain two IQrEs, McDaniel & Associates Consultants Ltd. (“McDaniel”) and GLJ petroleum Consultants Ltd., to evaluate and prepare reports on 100 percent of our reserves. McDaniel also evaluated 100 percent of our bitumen contingent and prospective resources. The reserves Committee of the Board, composed of independent directors, annually reviews the qualifications and selection of the IQrEs, the procedures relating to the disclosure of information with respect to oil and gas activities and the procedures for providing information to the IQrEs. The reserves Committee meets with management and each IQrE to determine whether any restrictions affect the ability of the IQrE to report on the reserves data without reservation, to review the reserves data and the report of the IQrE thereon, and to recommend approval of the reserves and resources disclosure to the Board. Highlights in 2010 include: • Improved recovery factor and expansion of development area at Foster Creek led to substantial growth in our proved bitumen reserves by 288 MMbbls, a 33 percent increase from 2009; • Conventional oil and NGLs proved reserves grew one percent; and • An overall nine percent decline in natural gas and CBM proved reserves due to extensions and improved recoveries as well as technical revisions not enough to offset production and dispositions. The reserves data presented summarizes our bitumen, heavy oil, light and medium oil plus NGLs, and natural gas plus CBM reserves using McDaniel’s January 1, 2011 forecast prices and costs. We hold significant freehold title rights which generate production for our account from third parties leasing those lands. The before royalty volumes presented below do not include reserves associated with this production. Information with respect to pricing as well as additional reserves information is contained in our Annual Information Form (“AIF”) for the year ended December 31, 2010, available at www.sedar.com and on our website at www.cenovus.com. r E s E rv E s A t D E C E m B E r 3 1 B e fo r e r oy a l t i e s proved probable proved plus probable Bitumen (MMbbls) Heavy Oil (MMbbls) Light & Medium Oil & NGLs (MMbbls) Natural Gas & CBM (Bcf) 2010 (1) 2009 (2) 2010 (1) 2009 (2) 2010 (1) 2009 (2) 2010 (1) 2009 (2) 1,154 523 866 479 1,677 1,345 169 97 266 165 104 269 111 49 160 112 53 165 1,390 410 1,800 1,529 436 1,965 (1) refers to 2010 estimates prepared by the IQrEs using McDaniel January 1, 2011 forecast prices and costs. (2) refers to previously disclosed estimates prepared by the IQrEs using 2009 constant prices and costs. 61 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T r E C O n C I L I At I O n O F P r Ov E D r E s E rv E s B e fo r e r oy a l t i e s December 31, 2009 (SEC) (1) Transition to NI 51-101 Standards (2) December 31, 2009 (NI 51-101) (3) Extensions and Improved recovery Technical revisions Economic Factors Dispositions production December 31, 2010 Year over year change Bitumen (MMbbls) Light & Medium Oil & NGLs (MMbbls) Heavy Oil (MMbbls) Natural Gas & CBM (Bcf) 866 – 866 270 40 – – (22) 1,154 288 33% 165 (1) 164 9 15 – (5) (14) 169 4 2% 112 (3) 109 11 1 – – (10) 111 (1) (1%) 1,529 128 1,657 45 60 (18) (87) (267) 1,390 (139) (9%) (1) refers to previously disclosed estimates prepared by the IQrEs using 2009 constant prices and costs. (2) The change in reserves disclosed in the transition from SEC to NI 51-101 is a result of (i) the forecast prices and costs used under NI 51-101 were higher than the SEC prescribed constant prices and costs, restoring previously uneconomic gas reserves, and (ii) the removal of royalty interest reserves from the before royalties reserves totals. See Oil and Gas Information in the Advisory section of this MD&A. (3) Determined using McDaniel January 1, 2010 forecast prices and costs. r E C O n C I L I At I O n O F P r O B A B L E r E s E rv E s B e fo r e r oy a l t i e s December 31, 2009 (SEC) (1) Transition to NI 51-101 Standards (2) December 31, 2009 (NI 51-101) (3) Extensions and Improved recovery Technical revisions Economic Factors Dispositions December 31, 2010 Year over year change Bitumen (MMbbls) Light & Medium Oil & NGLs (MMbbls) Heavy Oil (MMbbls) Natural Gas & CBM (Bcf) 479 – 479 132 (88) – – 523 44 9% 104 (1) 103 5 (10) – (1) 97 (7) (7%) 53 (2) 51 (1) (1) – – 49 (4) (8%) 436 52 488 12 (82) 7 (15) 410 (26) (6%) (1) refers to previously disclosed estimates prepared by the IQrEs using 2009 constant prices and costs. (2) The change in reserves disclosed in the transition from SEC to NI 51-101 is a result of (i) the forecast prices and costs used under NI 51-101 were higher than the SEC prescribed constant prices and costs, restoring previously uneconomic gas reserves, and (ii) the removal of royalty interest reserves from the before royalties reserves totals. See Oil and Gas Information in the Advisory section of this MD&A. (3) Determined using McDaniel January 1, 2010 forecast prices and costs. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 62 In 2010, proved and proved plus probable bitumen reserves increased by approximately 33 and 25 percent respectively. This was primarily a result of receiving regulatory approval to expand the development area at Foster Creek and from improvements to overall recovery based on operating performance. Incremental recovery from wedge wells, drilled between existing producers, and improved recovery resulting from better than expected drainage from existing wells also contributed to the increase. In 2010, proved heavy oil reserves increased by approximately two percent primarily as a result of expanding polymer flood areas and their successful performance at pelican Lake. probable heavy oil reserves decreased by approximately seven percent as a result of transfers to proved reserves. proved plus probable reserves decreased by approximately one percent. In 2010, proved light and medium oil and NGLs reserves decreased by approximately one percent, primarily as a result of expanding waterflood and carbon dioxide flood areas and their successful performance at Weyburn being offset by current year production. probable light and medium oil and NGLs reserves decreased by eight percent as a result of transfers to proved reserves. proved plus probable reserves decreased by approximately three percent. In 2010, proved natural gas reserves declined by approximately nine percent as extensions and technical revisions did not offset production and the divestiture of some of our natural gas assets. probable natural gas reserves and proved plus probable reserves declined by approximately six percent and eight percent respectively. r E s O u r C E s A t D E C E m B E r 3 1 B e fo r e r oy a l t i e s Economic contingent resources (3) Low Estimate Best Estimate High Estimate prospective resources (4) Low Estimate Best Estimate High Estimate Bitumen (billions of barrels) 2010 (1) 2009 (2) 4.4 6.1 8.0 7.3 12.3 21.7 3.9 5.4 7.3 7.8 12.6 21.4 (1) refers to estimates prepared by McDaniel, using McDaniel January 1, 2011 forecast prices and costs. (2) refers to previously disclosed estimates prepared by McDaniel, using 2009 constant prices and costs. (3) See Oil and Gas Information in the Advisory section of this MD&A for definitions of contingent resources, economic contingent resources and low, best and high estimate. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. (4) There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. prospective resources are not screened for economic viability. Best estimate economic contingent resources increased 0.7 billion barrels or 13 percent relative to 2009. This increase is primarily as a result of significant stratigraphic well drilling converting prospective resources to contingent resources, and positive technical revisions to volumetric estimates and recovery factor estimates. Best estimate prospective resources declined 0.3 billion barrels or two percent relative to 2009, primarily as a result of the reclassification of prospective resources to contingent resources resulting from stratigraphic drilling. The contingencies which must be overcome to enable the bitumen economic contingent resources to be classified as reserves include submission of regulatory applications with no major issues raised, access to markets, and intent to proceed by the operator and partners as evidenced by a development plan with major capital expenditures planned within five years. Additional reserves and other oil and gas information, including the risks and uncertainties associated with reserves and resource estimates, is contained in our AIF, available at www.sedar.com and on our website at www.cenovus.com. 63 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Liquidity and Capital resources ( $ m i lli o n s) Net cash from (used in) Operating activities Investing activities 2010 2009 2008 $ 2,594 $ 3,039 $ 3,225 (1,796) (2,063) (2,109) 1,116 (1,227) 1 $ (110) Net cash provided (used) before Financing activities Financing activities Foreign exchange gains (losses) on cash and cash equivalents held in foreign currency 798 (631) (22) Increase (decrease) in cash and cash equivalents $ 145 $ 976 (977) (32) (33) O P E r AtI n G AC tI v I tI E s Net cash from operating activities decreased $445 million in 2010 compared to 2009 mainly because of lower cash flow. Cash flow was $2,415 million during 2010 (2009–$2,845 million; 2008–$3,115 million). reasons for this change are discussed in the Cash Flow section of this MD&A. Cash from operating activities was also impacted by the net change in other assets and liabilities and the net change in non-cash working capital. Excluding the impact of risk management assets and liabilities, we had working capital of $290 million at December 31, 2010 compared to working capital of $479 million at December 31, 2009. We anticipate that we will continue to meet the payment terms of our suppliers. I n v E s tI n G AC tI v I tI E s Net cash used for investing activities in 2010 decreased to $1,796 million from $2,063 million in 2009 (2008–$2,109 million). Capital expenditures increased in 2010 to $2,208 million compared to $2,165 million in 2009 (2008–$2,204 million). Total divestiture proceeds increased in 2010 to $309 million compared to $222 million in 2009 (2008–$48 million). The changes to our capital expenditures are discussed under the Net Capital Investment and Operating Segment sections of this MD&A. Also decreasing the cash used in investing was the net change in non-cash working capital, which increased cash and cash equivalents by $99 million in 2010 compared to a $95 million decrease in 2009 (2008–increase of $96 million). F I nAn C I n G AC t Iv I t I E s Cenovus has a committed credit facility and a commercial paper program that are used to manage our short term cash requirements. In 2010, we re-negotiated our $2.5 billion credit facility by combining the two existing tranches into a single tranche and extending the maturity to November 30, 2014. At December 31, 2010, no amounts were drawn on the committed credit facility. In 2010, we filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. The Canadian shelf prospectus allows for the issue of medium term notes in Canadian dollars or other foreign currencies from time to time in one or more offerings. The terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates, will be determined at the date of issue. At December 31, 2010, no medium term notes have been issued under this Canadian shelf prospectus. The Canadian shelf prospectus expires in July 2012. In 2010, we filed a U.S. base shelf prospectus for unsecured notes in the amount of US$1.5 billion. The U.S. shelf prospectus allows for the issuance of debt securities in U.S. dollars or other foreign currencies from time to time in one or more offerings. The terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates, will be determined at the date of issue. At December 31, 2010, no notes have been issued under this U.S. shelf prospectus. The U.S. shelf prospectus expires in August 2012. In 2010, we declared and paid quarterly dividends of $0.20 per share (2009– U.S.$0.20 per share in the fourth quarter). Dividend payments for 2010 totaled $601 million (2009–$159 million). The declaration of dividends is at the sole discretion of the Board and considered quarterly. Net cash used in financing activities for 2010 was $631 million (2009–$977 million; 2008–$1,227 million). The 2010 decrease in net cash used in financing was a result of net financing transactions with Encana in 2009 related to the Arrangement. In 2009, we completed a private offering of senior unsecured notes for net proceeds of $3,718 million (U.S.$3,468 million) as well as the repayment of the $3.7 billion (U.S.$3.5 billion) demand promissory note to Encana. In 2010, substantially all of these notes were exchanged for notes registered under the Securities Act of 1933 with the same terms and conditions as the original issued notes. Our debt was $3,432 million as at December 31, 2010 and does not require any payments of principal until 2014. As at December 31, 2010, we are in compliance with all of the terms of our debt agreements. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 64 F I nAn C I A L m E t r I C s Debt to Capitalization Debt to Adjusted EBITDA (times) Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAp financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. Capitalization is a non- GAAp measure defined as long-term debt including current portion plus Shareholders’ Equity. Trailing 12-month Adjusted EBITDA is a non-GAAp measure defined as adjusted earnings before interest, income taxes, DD&A, accretion of asset retirement obligations, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss). Debt is defined as the current and long-term portions of long-term debt excluding any amounts with respect to the partnership Contribution payable or receivable. These metrics are used to steward our overall debt position as measures of our overall financial strength. We target a Debt to Capitalization ratio of between 30 to 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times. Additional information regarding our capital structure can be found in the notes to the Consolidated Financial Statements. O u t s tA n D I n G s H A r E D AtA Cenovus is authorized to issue an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. As at December 31, 2010 there were 752.7 million (2009– 751.3 million) common shares outstanding and no preferred shares outstanding. In 2010, the Board approved a dividend reinvestment plan (“DrIp”), which permits holders of common shares to automatically reinvest all or any portion of the cash dividends paid on their common shares in additional common shares. At the discretion of Cenovus, the additional common shares may be issued from treasury or purchased on the market. For the year ended December 31, 2010, common shares were purchased on the market to meet our DrIp requirements. The Cenovus Employee Stock Option plan (“ESOp”) permits our Board, from time to time, to grant to employees of Cenovus and its subsidiaries stock options to purchase our common shares. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted under the ESOp are exercisable at 30 percent of 2010 26% 1.2x 2009 28% 1.1x 2008 28% 0.8x the initial grant after one year, an additional 30 percent of the initial grant after two years and are fully exercisable after three years and expire five to seven years after the date granted. Options granted have an associated tandem share appreciation right (“TSAr”), which gives employees the right to elect to receive a cash payment equal to the excess of the market price of our common shares over the exercise price of their option in exchange for surrendering their option. A portion of the options have an additional vesting condition which is subject to the Company attaining prescribed performance relative to key pre-determined measures. The performance-based options that do not vest when eligible are forfeited. The exercise of an option as a TSAr for a cash payment does not result in the issuance of any additional common shares, thus having no dilutive effect. In accordance with the Arrangement, each Cenovus and Encana employee holding Encana options prior to the Arrangement received one Cenovus replacement option and one Encana replacement option for each original Encana option held. The terms and conditions of the Cenovus replacement options are similar to the terms and conditions of the original Encana options, which are also similar to the terms and conditions of Cenovus options. The original exercise price of the Encana options was apportioned to the Cenovus and Encana replacement options based on the one-day weighted average trading price of Cenovus’s common share price relative to that of Encana’s common share price on the Toronto Stock Exchange on December 2, 2009. At December 31, 2010, Cenovus employees held approximately 19.1 million options, of which 7.7 million were exercisable. At December 31, 2010, Encana employees held approximately 17.2 million Cenovus replacement options, of which 10.8 million were exercisable. No further Cenovus replacement options will be granted to Encana employees. Encana is required to reimburse Cenovus in respect of cash payments made to Encana employees for Cenovus replacement options exercised as TSArs. Cenovus is required to reimburse Encana in respect of cash payments made to Cenovus employees for Encana replacement options exercised as TSArs. No further Encana replacement options will be granted to Cenovus employees. 65 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T C O n t r AC t uA L O B L I G At I O n s A n D C O m m I t m E n t s ( $ m i lli o n s) Long-term Debt (1) partnership Contribution payable (1) Asset retirement Obligation pipeline Transportation purchases of Goods and Services product purchases Operating Leases (2) Capital Commitments Other Long-term Commitments Total payments product Sales partnership Contribution receivable (1) 2011 – 343 100 107 157 23 33 91 4 858 50 346 $ $ $ $ 2012 – 364 2 93 23 18 87 71 2 660 52 364 $ $ $ $ $ $ $ $ (1) principal component only. See notes to the Consolidated Financial Statements. (2) Operating leases consist of building leases. $ 2,685 $ Expected payment Date 2013 2014 2015 2016+ – 386 2 167 12 18 88 4 1 678 54 384 $ $ $ $ 796 410 2 167 10 18 85 4 1 1,493 56 405 $ $ $ $ – 435 2 166 7 18 78 4 – 710 57 427 581 6,012 953 23 7 1,553 14 1 11,829 63 565 $ $ $ Total 3,481 2,519 6,120 1,653 232 102 1,924 188 9 $ $ $ 16,228 332 2,491 Cenovus has entered into various commitments in the normal course of operations primarily related to debt, future demand charges on firm transportation agreements (which include amounts for projects awaiting regulatory approval), building leases, capital commitments and marketing agreements. In addition, we have commitments related to our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. For further information please see the notes to the Consolidated Financial Statements. As at December 31, 2010, Cenovus remained a party to long-term, fixed price, physical contracts for natural gas with a current delivery of approximately 33 MMcf/d, with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 73 Bcf of natural gas at a weighted average price of US$4.54 per Mcf. In the normal course of business, we also lease office space for personnel who support field operations and for corporate purposes. L E G A L P r O C E E D I n G s We are involved in various legal claims associated with the normal course of operations and we believe we have made adequate provisions for such claims. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 66 risk management Our business, prospects, financial condition, results of operations and cash flows, and in some cases our reputation, are impacted by risks that are categorized as follows: • Financial risks including market risk (fluctuations in commodity prices, foreign exchange rates and interest rates), credit and liquidity risk; • Operational risks including capital, operating and reserves replacement risks; and • Safety, environmental and regulatory risks including regulatory process and approval risks, stakeholder and partner support for activities and growth plans and changes to royalty and income tax legislation. We are committed to identifying and managing these risks in the near-term, as well as on a strategic and longer term basis at all levels in the organization in accordance with our Board-approved Market risk Mitigation policy, Enterprise risk Management policy, Credit policy and risk management programs. Issues affecting, or with the potential to affect, our assets, operations and/or reputation, are generally of a strategic nature or are emerging issues that can be identified early and then managed, but occasionally include unforeseen issues that arise unexpectedly and must be managed on an urgent basis. We take a proactive approach to the identification and management of issues that can affect our assets, operations and/or reputation and have established consistent and clear policies, procedures, guidelines and responsibilities for issue identification and management. Further information regarding the risk factors affecting Cenovus can be found in the Advisory section of this MD&A and in the risk Factors section of our AIF for the year ended December 31, 2010. F I nAn C I A L r I s k s Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on our business. We continue to implement our business model which focuses on developing low-risk and low-cost long-life resource properties. Management monitors our operational and financial risk strategies to proactively respond to the changing economic conditions and to eliminate, mitigate or reduce the risk. Cost containment and reduction strategies are in place to help ensure our controllable costs are efficiently managed. Counterparty and credit risks are closely monitored as is our liquidity to ensure access to cost effective credit. Sufficient cash resources are maintained to fund capital expenditures. We partially mitigate our exposure to financial risks through the use of various financial instruments and physical contracts governed by our Market risk Mitigation policy which contains prescribed hedging protocols and limits. We have entered into various financial instrument agreements to mitigate exposure to commodity price risk volatility. The details of these instruments, including any unrealized gains or losses, as of December 31, 2010, are disclosed in the notes to the Consolidated Financial Statements and discussed in this MD&A. The financial instruments used are primarily swaps which are entered into with major financial institutions, integrated energy companies or commodities trading institutions and exchanges. C O M M O d i t y P R i C E R i S k Commodity price risk is the exposure to fluctuations in future market prices that results from the sales of various commodities in our operations. We seek to reduce our exposure to commodity price risk through an integrated business strategy whereby a portion of operating supplies and feedstock is provided from internal operations. To further mitigate commodity price risk, we use derivative instruments in various operational markets to optimize our supply or production chain. We have partially mitigated our exposure to the crude oil commodity price risk on our crude oil sales with fixed price WTI swaps. We have partially mitigated our exposure to the natural gas commodity price risk on our natural gas sales with fixed price NYMEX and AECO swaps. We have partially mitigated our exposure to widening crude oil and natural gas price differentials with fixed price differential and basis swaps between our production areas and various sales points. We have mitigated some of our exposure to electricity consumption costs, with two derivative contracts which expire on January 1, 2018. C R E d i t R i S k Credit risk is the potential for loss if a counterparty in a transaction fails to meet its obligations in accordance with agreed terms. A substantial portion of our accounts receivable is with customers in the oil and gas industry. This credit exposure is mitigated through the use of our Board-approved credit policies governing our credit portfolio and with credit practices that limit transactions according to counterparties’ credit quality. All financial derivative agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. l i q U i d i t y R i Sk Liquidity risk is the risk we will not be able to meet all our financial obligations as they come due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. We manage our liquidity risk through the active management of cash and debt by ensuring that we have access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facilities, commercial paper and availability under our shelf prospectuses. At December 31, 2010, no amounts were drawn on our committed credit facility. In addition, we had $1.5 billion in unused capacity under our Canadian shelf prospectus and US$1.5 billion in unused capacity under our U.S. shelf prospectus, the availability of which are dependent on market conditions. F O R E i g n E xC h a n g E R i S k Foreign exchange risk is the exposure to fluctuations in foreign currency exchange rates in our operations. As our commodity sales are generally priced in U.S. dollars and our capital expenditures and expenses are paid in both U.S. and Canadian dollars, fluctuations in the exchange rate between the U.S. and Canadian dollar can have a significant effect on our financial results which are reported in Canadian dollars. 67 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T We reduce our exposure to foreign exchange risk through an integrated business strategy with a mix of U.S. and Canadian operations that creates a partial hedge to foreign exchange exposure. To further mitigate foreign exchange risk, we may enter into foreign exchange contracts or hedge our commodity exposures in Canadian dollars. We also have the flexibility to maintain a mix of both U.S. dollar and Canadian dollar debt, which helps to offset the exposure to the fluctuations in the U.S./Canadian dollar exchange rate. In addition to direct issuance of U.S. dollar denominated debt, we may enter into cross currency swaps on a portion of our debt as a means of managing the U.S./Canadian dollar debt mix. We utilize a peer review process to ensure that capital projects are appropriately risked and that knowledge is shared across our company. peer reviews are undertaken primarily for early stage properties, although they may occur for any type of project. When making operating and investing decisions, our business model allows flexibility in capital allocation to optimize investments focused on strategic fit, project returns, long-term value creation, and risk mitigation. We also mitigate operational risks through a number of other policies, systems and processes as well as by maintaining a comprehensive insurance program in respect of our assets and operations. in tE R E S t R atE R i Sk s A F E t Y, E n v I r O n m E n tA L A n D r E G u L At O rY r I s k s Interest rate risk is the impact of changing interest rates on earnings, cash flows and valuations. Although all of our debt portfolio was fixed rate debt at December 31, 2010, we have the flexibility to partially mitigate our exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt through the use of our commercial paper program and credit facilities. We may also enter into interest rate swap transactions from time to time as an additional means of managing the fixed/floating rate debt portfolio mix. O P E r At I O n A L r I s k s Operational risk is the risk of loss or lost opportunity resulting from operating and capital activities that, by their nature, could have an impact on our ability to achieve our objectives. Our ability to operate, generate cash flows, complete projects and value reserves is dependent on financial risks, including commodity prices mentioned above, continued market demand for our products and other risk factors outside of our control, which include: general business and market conditions; economic recessions and financial market turmoil; the ability to secure and maintain cost effective financing for our commitments; the ability to obtain necessary approvals; environmental and regulatory matters; unexpected cost increases; royalties; taxes; the availability of drilling and other equipment; the ability to access lands; weather; the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of diluents to transport crude oil; technology failures; accidents; the availability of skilled labour; and reservoir quality. If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels and, therefore, our cash flows are highly dependent upon successfully producing current reserves and acquiring, discovering or developing additional reserves. To mitigate these risks, as part of the capital approval process, we evaluate projects on a fully risked basis, including geological risk and engineering risk. In addition, our asset teams undertake a process called Lookback and Learning. In this process, each asset team undertakes a thorough review of its previous capital program to identify key learnings, which often include operational issues that positively and negatively impacted the project’s results. Mitigation plans are developed for the operational issues that had a negative impact on results. These mitigation plans are then incorporated into the current year plan for the project. On an annual basis, these Lookback and Learning results are analyzed in relation to our capital program with the results and identified learnings shared across our company. We are engaged in the relatively high risk activities of crude oil and natural gas development and production and refining. We are committed to safety in our operations and with high regard for the environment and stakeholders. These risks are managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, we maintain a system, in respect of our assets and operations, that identifies, assesses and controls safety, security and environmental risk and requires regular reporting to both senior management and our Board. The Safety, Environment and responsibility Committee of our Board reviews and recommends policies pertaining to corporate responsibility, including the environment, for approval by our Board and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Contingency plans are in place for a timely response to an environmental event and remediation/reclamation strategies are utilized to restore the environment. In addition, security risks are managed through a security program designed to protect our personnel and assets. We have an Investigations Committee whose mandate is to address potential violations of policies and practices and an Integrity Helpline that can be used to raise any concerns regarding operations, accounting or internal control matters. Our operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact our existing and planned projects as well as impose a cost of compliance. regulatory and legal risks are identified by our operating and corporate groups, and our compliance with the required laws and regulations is monitored by our legal group in respect of our assets and operations. Our legal and environmental policy groups stay abreast of new developments and changes in laws and regulations to ensure that we continue to comply with prescribed laws and regulations. Of note in this regard, our approach to changes in regulations relating to climate change, royalty and regulatory frameworks is discussed below. To partially mitigate resource access risks, keep abreast of regulatory developments and be a responsible operator, we maintain relationships with key stakeholders and conduct other mitigation initiatives mentioned herein. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 68 E n v i R O n M E n ta l R E g U l at i O n a n d R i S k Environmental regulation impacts many aspects of our business. regulatory regimes apply to all companies active in the energy industry. We are required to obtain regulatory approvals, licenses and permits in order to operate and we must comply with standards and requirements for the exploration, development and production of crude oil and natural gas and the refining, distribution and marketing of petroleum products. regulatory assessment, review and approval are generally required before initiating, advancing or changing operations projects. Further information regarding the status of each project can be found in the Operating Segments section of this MD&A. tracking, attention to fuel consumption and a focus on minimizing our steam to oil ratio help to support and drive our focus on cost reduction. (2) respond to price Signals As regulatory regimes for GHGs develop in the jurisdictions where we work, inevitably price signals begin to emerge. We have initiated an Energy Efficiency Initiative in an effort to improve the energy efficiency of our operations. The price of potential carbon reductions plays a role in the economics of the projects that are implemented. In response to the anticipated price of carbon reduction, we are also attempting, where appropriate, to realize associated value of our reduction projects. C l i M at E C h a n g E (3) Anticipate Future Carbon Constrained Scenarios Various federal, provincial and state governments have announced intentions to regulate greenhouse gas (“GHG”) emissions and other air pollutants and a number of legislative and regulatory measures to address GHG emissions are in various phases of review, discussion or implementation in the U.S. and Canada. Adverse impacts to our business if comprehensive GHG regulation is enacted in any jurisdiction in which we operate may include, among other things, increased compliance costs, permitting delays, substantial costs to generate or purchase emission credits or allowances which may add costs to the products we produce and reduce demand for crude oil and certain refined products. Beyond existing legal requirements, the extent and magnitude of any adverse impacts of any of these additional programs cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance. We intend to continue our activity to use scenario planning to anticipate future impacts, reduce our emissions intensity and improve our energy efficiency. We will also continue to work with governments to develop an approach to deal with climate change issues that protects the industry’s competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector. The Government of Alberta has set targets for GHG emissions reductions. regulations require facilities that emit more than 100,000 tonnes of GHG emissions per year to reduce their emissions intensity by 12 percent from a regulated baseline. To comply, companies can make operating improvements, purchase carbon offsets (or emission performance credits) or make a $15 per tonne contribution to an Alberta Climate Change and Emissions Management Fund. Cenovus currently has three facilities subject to this regulation. For the 2010 compliance year, we do not anticipate material costs in this regard. Our efforts with respect to emissions management are founded in our industry leadership in carbon dioxide sequestration, a focus on energy efficiency and the development of technology to reduce GHG emissions. In particular, our low steam to oil ratios at Foster Creek and Christina Lake translates directly into lower emissions intensity. Given the uncertainty in North American carbon legislation, our strategy for addressing the implications of emerging carbon regulations is proactive and is composed of three principal elements: (1) Manage Existing Costs When regulations are implemented, a cost is placed on our emissions (or a portion thereof) and while these are not material at this stage, they are being actively managed to ensure compliance. Factors such as effective emissions We continue to work with governments, academics and industry leaders to develop and respond to emerging GHG regulations. By continuing to stay engaged in the debate on the most appropriate means to regulate these emissions, we gain useful knowledge that allows us to explore different strategies for managing our emissions and costs. These scenarios assist with our long range planning and our analyses on the implications of regulatory trends. We incorporate the potential costs of carbon into future planning. Management and the Board review the impact of a variety of carbon constrained scenarios on our strategy, with a current price range from $15 to $65 per tonne of emissions applied to a range of emissions coverage levels. A major benefit of applying a range of carbon prices at the strategic level is that it can provide direct guidance to the capital allocation process. We also examine the impact of carbon regulation on our major projects. Although uncertainty remains regarding potential future emissions regulation, our plan is to continue to assess and evaluate the cost of carbon relative to our investments across a range of scenarios. We recognize that there is a cost associated with carbon emissions. We believe that GHG regulations and the cost of carbon at various price levels have been adequately taken into consideration as part of our business planning and scenarios analysis. We believe that our development strategy, use of technology and focus on continuous improvement is an effective way to develop the resource, generate shareholder returns and coordinate overall environmental objectives with respect to carbon, air emissions, water and land. We are committed to transparency with our stakeholders and will keep them apprised of how these issues affect our operations. A L B E r tA’ s r OYA L t Y F r A m E WO r k In 2010, the Government of Alberta outlined changes to the royalty structure in the province. The updates to conventional crude oil and natural gas royalty structure released in the first quarter of 2010 included: • A five percent maximum royalty rate on new gas and conventional oil wells for a period of 12 months or 0.5 billion cubic feet equivalent for gas wells or 50,000 barrels of oil equivalent for oil wells, whichever comes first. The five percent royalty rate was originally created with the New Well Incentive under the Energy Incentive program that was released on March 3, 2009 and was set to expire on March 31, 2011, but is now permanently in place; • The maximum royalty rate for conventional oil will decrease to 40 percent from 50 percent and the maximum natural gas royalty rate will decrease to 36 percent from 50 percent; and 69 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T • Effective January 1, 2011 no additional wells will be allowed under the Transitional royalty program (“Trp”) that went into effect on January 1, 2009. The Trp allows for a one time option of selecting transitional royalty rates on new natural gas or conventional oil wells drilled between 1,000 to 3,500 metres in depth. Any wells that are elected under the Trp can continue to use this program until December 31, 2013. Updates released in the second quarter of 2010 were primarily focused on supporting deep basin gas drilling and improving the economics of unconventional gas plays, as well as horizontal oil and gas drilling. These updates included: • A maximum royalty rate of five percent for all products produced from horizontal oil or horizontal non-oil sands wells, with volume and production month limits set according to the depth of the well. Horizontal oil and non-oil sands wells are defined by the ErCB; • Wells defined as horizontal natural gas wells by the ErCB will have a maximum five percent royalty rate on all production for a period of 18 producing months or 500 MMcf of gas equivalent production; • CBM wells that produce exclusively from areas defined by the ErCB as coal will have a maximum royalty rate of five percent on all products produced in the first 36 months with a production limit of 750 MMcf of gas equivalent; and • The Natural Gas Deep Drilling program was made permanent and was modified and simplified. Modifications include the reduction of the minimum well depth to 2,000 metres; elimination of well target, spacing and pool boundary restrictions; all lateral wells qualify for credits; increased credits between 3,500 and 5,000 metres; and removal of maximum well depth. Also included as part of the royalty structure changes released in the second quarter were updates to the royalty curves for conventional oil and natural gas. The effective date of the new curves is January 1, 2011. For Cenovus, the main impact of these royalty changes is expected to be a positive improvement to the economics of our oil drilling program for certain properties in our Conventional operating segment and any future shale oil developments in Alberta. A L B E r tA’ s r E G u L At O rY F r A m E WO r k As part of the Government of Alberta’s competitiveness review, a comprehensive review of Alberta’s regulatory system called the regulatory Enhancement project (the “project”) was initiated in March 2010. The project’s goal is to create an effective regulatory system that will contribute to Alberta’s overall competitiveness while protecting the environment, ensuring public safety and conservation of resources. The project involved engagement with a broad range of stakeholders, including industry, and led to a recommendation to the Minister of Energy for adoption of a coordinated policy framework and an integrated regulatory system for the upstream oil and gas sector. The Government of Alberta has accepted the projects team’s recommendations and is expected to begin implementing those recommendations in the first half of 2011. Alberta’s Land-use Framework, which is to be implemented under the Alberta Land Stewardship Act (“ALSA”), sets out the Government of Alberta’s approach to managing Alberta’s land and natural resources to achieve long-term economic, environmental and social goals. ALSA contemplates the amendment or extinguishment of previously issued consents such as regulatory permits, licenses, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan. The Government of Alberta is expected to develop a regional plan for each of seven regions in the province and has identified the Lower Athabasca regional plan (“LArp”) as a priority. The LArp is intended to identify and set resource and environmental management outcomes for air, land, water and biodiversity, and guide future resource decisions while considering social and economic impacts. In August 2010, the Lower Athabasca regional Advisory Council (“rAC”) provided its vision document to the Government of Alberta regarding the LArp. Cenovus is actively participating in the feedback process as a stakeholder with significant activities in the region and will continue to monitor developments going forward. The Government of Alberta is expected to respond to the rAC advice with its own LArp recommendations. It is possible that the rAC vision, if adopted in its current form by the Government of Alberta, may negatively impact Cenovus’s access to certain resource properties or limit the pace of development due to environmental limits and thresholds. t r A n s PA r E n C Y A n D C O r P O r At E r E s P O n s I B I L I t Y We are committed to operating in a responsible manner and to integrating our corporate responsibility principles into the way we conduct our business. We recognize the importance of reporting to stakeholders in a transparent and accountable manner. We disclose not only the information we are required to disclose by legislation or regulatory authorities, but also information that more broadly describes our activities, policies, opportunities and risks. Our Corporate responsibility (“Cr”) policy has been updated to ensure that it continues to drive our commitments, strategy and reporting, and also enables alignment with our business objectives and processes. Our future Cr reporting activities will be guided by this policy and will focus on improving performance by continuing to track, measure and monitor our Cr performance indicators. This policy was released on December 1, 2010 and is available on our website at www.cenovus.com. In 2010, we released our “Corporate responsibility performance Highlights” fact sheet and launched the Cr section of our website. The two-page fact sheet introduced Cenovus to our stakeholders and provided a snapshot of our 2009 Cr performance. It was distributed to all of our staff, including contractors and staff in the field and to over 1,000 of our external contacts. We also created a more detailed “Corporate responsibility 2009 performance Measures report” to complement the fact sheet. The performance Measures report organizes all 2009 Cr metrics into one document and is available on our website at www.cenovus.com. As our Cr reporting process matures, indicators will be developed that better reflect Cenovus’s operations and challenges. These indicators will be integrated into our Cr reporting and will expand our online presence through our website. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 70 Accounting Policies and Estimates Management is required to make judgments, assumptions and estimates in the application of GAAp that have a significant impact on our financial results. Actual results may differ from those estimates, and those differences may be material. The basis of presentation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements. C r I t I C A L A C C O u n t I n G P O L I C I E s A n D E s t I m At E s The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to understanding our financial results. B a S i S O F P R E S E n tat i O n Our results for the year ended December 31, 2010 and the one month period from December 1 to December 31, 2009 represent our operations, cash flows and financial position as a stand-alone entity. Our results for the periods prior to the Arrangement, being January 1 to November 30, 2009 and January 1 to December 31, 2008, have been prepared on a “carve-out” accounting basis, whereby the results have been derived from the accounting records of Encana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus. The historical consolidated financial statements include allocations of certain Encana expenses, assets and liabilities. In the opinion of management, the consolidated and the historical carve-out consolidated financial statements reflect all adjustments necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with GAAp. Management believes that the assumptions underlying the historical consolidated financial statements are reasonable. However, as we operated as part of Encana and were not a stand-alone company prior to November 30, 2009, the historical consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented. O i l a n d g a S R E S E Rv E S All of our oil and gas reserves are evaluated and reported to Cenovus by the IQrEs. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. reserves estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts. These revisions can have a significant impact on our future earnings because they will directly impact our DD&A rates, asset impairment calculations, accounting for business combinations and asset retirement obligations. P R O P E R t y, P l a n t a n d E q U i P M E n t – d d & a Crude oil and natural gas properties are accounted for in accordance with the Canadian Institute of Chartered Accountants (“CICA”) guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, exploration for, and the development of crude oil and natural gas reserves, are capitalized on a country-by-country cost centre basis and costs associated with production are expensed. The capitalized costs, plus estimated future development costs, are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves. reserves estimates can have a significant impact on earnings, as they are a key component in the calculation of DD&A. A downward revision in our estimate of reserve quantities could result in a higher DD&A charge to earnings. a S S E t i M Pa iR M E n t S Under GAAp, the carrying amount of crude oil and natural gas properties in each cost centre may not exceed their recoverable amount. The recoverable amount is calculated as the total undiscounted cash flow using proved reserves and estimated future prices and costs. If the carrying amount of a cost centre exceeds its recoverable amount, the impairment loss is limited to an amount by which the carrying amount exceeds the sum of: i) the fair value of proved and probable reserves; and ii) the costs of unproved properties that have been subject to a separate impairment test. We also perform an annual impairment test on goodwill, whereby the fair value of each reporting unit is determined and compared to the book value of the reporting unit. A reporting unit has all assets, including goodwill, and liabilities allocated to the country cost centre level. For the above impairment tests, fair value is calculated as the cash flows from oil and gas properties using proved and probable reserves and estimated future prices and costs, discounted at a risk-free interest rate. In order to estimate future cash flows, we are required to make a number of assumptions and estimates, including quantities of reserves, future commodity prices as well as development and operating costs. Changes in any of the assumptions, such as a downward revision in reserves, a decrease in commodity prices or an increase in costs, could result in an impairment of an asset’s carrying value. An impairment loss is recognized on refining property, plant and equipment when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from expected use and eventual disposition. If the carrying amount is not recoverable, an impairment loss is measured as the amount by which the carrying amount exceeds the fair value. 71 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T B U S i n E S S C O M B i n at i O n S The purchase price of business combinations and asset acquisitions is allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the use of assumptions and estimates regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation will have a direct impact on our future net earnings, largely due to the impact on the calculation of DD&A rates or asset impairment tests. a S S E t R E t i R E M E n t O B l i g at i O n S We are required to recognize an asset retirement obligation (“ArO”) liability for the future abandonment and reclamation costs associated with our property, plant and equipment. ArO is only recognized to the extent there is a legal obligation associated with the retirement of a tangible long-lived asset that we are required to settle as a result of an existing or enacted law. Our calculation of ArO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal and regulatory requirements, contracts and current technologies. There are many assumptions used in the estimate of the ArO liability which can be subject to change based on experience. These assumptions include: the estimated cost of reclaiming producing well sites, crude oil and natural gas processing plants and refining facilities; inflation rates; credit-adjusted risk free rates; and the timing of retirement of assets. At the end of each year, we review our assumptions and estimates and any changes to the ArO liability are discounted to present value using a credit-adjusted risk-free discount rate. C O M P E n S at i O n P l a n S We have obligations for payments to our employees related to our stock option and incentive plans. The obligations provide for a range of payouts based on key predetermined performance measures and the cost of these plans is expensed based on expected payouts. The amounts to be paid, if any, may vary from the current estimate. We also have obligations for payments to our employees related to stock option plans of Encana. The financial liability for these obligations is accrued using the fair value method, and therefore fluctuations in the fair value will affect the accrued compensation expense that is recognized. The fair value of the obligation fluctuates, as it is based on assumptions for the risk-free discount rate, dividend yield, as well as the volatility of Encana’s share price. R i S k M a n ag E M E n t aC t i v i t i E S We use various derivative financial instruments to manage our commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. The estimated fair value of derivative financial instruments is determined using appropriate valuation models and methodologies. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows and discount rates. In determining these assumptions, we rely primarily on external readily observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange rates. The resulting fair value estimates may not necessarily be indicative of the amounts that may be realized or settled in a current market transaction and these differences may be material. i n C O M E t a x E S We follow the liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences between the carrying value of assets and liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted as of the consolidated balance sheet date. Accounting for income taxes is a complex process that requires the interpretation of changing laws and regulations, for example changing income tax rates, and making certain judgments with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. These interpretations and judgments have a significant impact on our provision for current and future income tax, and will have a direct impact on our future net earnings. n E W A C C O u n t I n G s tA n DA r D s A D O P t E D On January 1, 2010, Cenovus early adopted CICA Handbook Section 1582, “Business Combinations”, which replaces CICA Handbook Section 1581 of the same name. The new standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the Statement of Earnings. This accounting policy was applied to the November 1, 2010 purchase of the marine terminal facilities. In conjunction with the early adoption of CICA Handbook Section 1582, the Company was also required to early adopt CICA Handbook Sections 1601, “Consolidated Financial Statements” and 1602, “Non-controlling Interests” effective January 1, 2010. These sections replace the former consolidated financial statement standard, CICA Handbook Section 1600, “Consolidated Financial Statements”. Section 1601 establishes the requirements for the preparation of the consolidated financial statements and Section 1602 establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. Section 1602 requires a non-controlling interest to be classified as a separate component of equity. In addition, net earnings, and components of other comprehensive income are attributed to both the parent and non-controlling interest. The early adoption of these standards did not have a material impact on the Company’s Consolidated Financial Statements for the year ended December 31, 2010. These standards are converged with International Financial reporting Standards (“IFrS”). CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 72 r E C E n t AC C O u n t I n G P r O n O u n C E m E n t s U P S t R E a M P P & E There are no pending GAAp accounting pronouncements, other than the requirement to adopt IFrS in 2011, as discussed below. I n t E r nA t I O nA L F I nAn C I A L r E P O r t I n G s tAn DAr D s We are required to report our results in accordance with IFrS beginning with the three month period ending March 31, 2011. We have a detailed changeover plan, which includes the preparation of required comparative information for 2010. We continue to be on schedule with our plan, and expect that the adoption of IFrS will not have a significant impact or influence on our business, operations or strategies. The information below summarizes our accounting policies and opening balance sheet information, which were disclosed in our MD&A for previous periods. It also includes additional information on the estimated IFrS impacts on our financial results for the year ended December 31, 2010. Our IFrS financial results have not yet been finalized because: • The results remain subject to further review by management; • We are continuing to monitor any new or amended IFrS issued by the International Accounting Standards Board that could affect our choice of accounting policies; • Our IFrS financial statements for the year ending December 31, 2011 must use the standards that are in effect on December 31, 2011, and therefore our IFrS accounting policies will only be finalized when our first annual IFrS financial statements are prepared for the year ending December 31, 2011; and • The results are unaudited and are subject to additional audit work by our external auditors. S i g n i F i C a n t i M P aC t S O F i F R S The following areas are the most significantly affected by the adoption of IFrS: • Upstream property, plant and Equipment (“pp&E”), including: – Exploration and Evaluation costs – Asset retirement obligation – Transition on date of adoption of IFrS – DD&A – Gains and losses on divestitures • refining Assets • Impairment testing • Stock-based compensation • Income taxes Exploration and Evaluation costs During the exploration and evaluation (“E&E”) phase, we capitalized costs incurred for these projects under GAAp. While this capitalization policy has not changed under IFrS, these costs will be reported separately as E&E assets, rather than being included in pp&E. Asset retirement Obligation Under GAAp, the discount rates used to estimate the ArO liability were not updated to current market discount rates, while under IFrS, the discount rate is updated each reporting period. This difference in accounting policy did not have a significant impact on either our opening balance sheet or our net earnings for the year ended December 31, 2010. However, our ArO liability as of December 31, 2010 was higher under IFrS as a result of changes to the discount rate used to estimate the liability. The impact is expected to be less than $200 million. Transition adjustments on date of adoption of IFrS – January 1, 2010 Under GAAp, we follow full cost accounting, while IFrS has no equivalent treatment. IFrS 1 (“First-time Adoption of IFrS”) permits full cost accounting companies to allocate their existing upstream pp&E net book value (full cost pool) to the unit of account level upon transition to IFrS using reserve information. Using this exemption, we reclassified the cost of our unproved properties from Upstream pp&E to the new E&E asset category, and allocated the remainder of our Upstream full cost pool to our IFrS areas based on the relative fair value of each area. Fair value was calculated using the estimated future net cash flows from proved reserves, discounted at 10 percent, since this was considered to be an appropriate estimate of the relative fair value of each of our IFrS areas. This approach was also consistent with the allocation method which was required to be used in the formation of Cenovus. The allocation process did not affect the net book value of our Upstream pp&E as no IFrS impairments were recognized. DD&A Under GAAp, we calculated our DD&A rate at the country cost centre level. Under IFrS, this rate is calculated at a lower unit of account level, which resulted in our Upstream DD&A for the year ended December 31, 2010 increasing by less than $150 million. The increase in DD&A is primarily due to separating the long life reserves associated with the Foster Creek and Christina Lake properties from the rest of the full cost pool. Gains and losses on divestitures Full cost accounting under GAAp required that gains or losses on divestitures of pp&E only be recognized when the disposal would affect our DD&A rate by 20 percent or more. Under IFrS, we are required to recognize all gains and losses on upstream property divestitures. For the year ended December 31, 2010, we recognized gains on divestiture of oil and gas properties of about $125 million. Under GAAp, these gains were credited to the full cost pool, and would have resulted in a lower GAAp DD&A rate in future years compared to our IFrS DD&A rates. 73 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T R E F i n i n g a S S E t S S U M M a Ry O F i F R S i M PaC t S t O d E C E M B E R 3 1 , 2 0 1 0 In our IFrS opening balance sheet, we elected to re-measure the carrying value of our refineries to their fair value, which permanently reduced their carrying value by approximately $2.6 billion ($1.6 billion, after-tax). In addition, having revalued the refineries to their fair values, it was also determined that the refining deferred asset, which had a carrying value of $121 million at January 1, 2010, was fully impaired under IFrS. The impairment loss on a refining process unit recognized under GAAp was reduced under IFrS due to the January 1, 2010 fair value election. The impact of these three IFrS adjustments was a decrease in our refining and Marketing DD&A of less than $150 million for the year ended December 31, 2010. i M Pa iR M E n t t E S t i n g In the first step for all of our GAAp impairment tests (Upstream, refining and Goodwill), future cash flows are not discounted. Under IFrS, the future cash flows are discounted. In addition, for Upstream pp&E, impairment testing was performed at the country cost centre level, while under IFrS, it is performed at the lower cash-generating unit level. There was no impact on our Upstream pp&E, refining pp&E or goodwill with this change in accounting policy. S tO C k- B a S Ed C O M P En S at iO n Under GAAp, obligations for cash payments under stock-based compensation plans were accrued using the intrinsic method, while under IFrS these obligations are accounted for using the fair value method. While the carrying value in each reporting period will be different under IFrS compared to GAAp, the cumulative expense recognized over the life of the instrument under both methods will not be different. This difference in policy did not have a significant impact on either our IFrS opening balance sheet or our net earnings for the year ended December 31, 2010. i n C O M E t a x E S The carrying amounts of our tax balances have been directly impacted by the tax effects resulting from changes in our accounting policies. The future income tax liability on our IFrS opening balance sheet was reduced by approximately $1 billion, primarily due to the fair value election on our refineries. For the year ended December 31, 2010, our income tax expense increased primarily related to the tax effects on the recognition of gains on our pp&E divestitures. The net effect of the significant adjustments above is an increase to our net earnings mainly due to the gain on divestiture of oil and gas properties. All of the other IFrS adjustments are not significant. In total, we estimate an increase to our net earnings under IFrS for the year ended December 31, 2010 of less than $120 million. The most significant impacts on our December 31, 2010 balance sheet are as follows: • Decrease in pp&E of approximately $2.2 billion; • re-classification of approximately $0.7 billion of Upstream pp&E to E&E assets; • Decrease in Other assets of approximately $0.1 billion; • Increase in Asset retirement Obligation of approximately $0.2 billion; • Decrease in Future Income Taxes of approximately $0.9 billion; and • Decrease in Shareholders’ Equity of approximately $1.6 billion. These balance sheet changes increased our Debt to Capitalization ratio at December 31, 2010, from 26 percent to 29 percent, which is below our target range of 30 percent to 40 percent. In terms of our cash flow statement for the year ended December 31, 2010, the IFrS adjustments did not have a significant impact on cash from operating activities, cash used in investing activities, or cash from financing activities. Furthermore, the IFrS adjustments did not have a significant impact on cash flow, which is our non-GAAp measure defined earlier in this MD&A. i n t E R n a l C O n t R O l S Ov E R F i n a n C i a l R E P O R t i n g & d i S C lO S U R E C O n t R O l S a n d P R O C E d U R E S During the fourth quarter of 2010, we have updated our internal controls documentation related to external financial reporting processes, including disclosure controls and procedures. We do not expect that the adoption of IFrS will have a significant impact on any of our internal control processes. F i n a n C i a l R E P O R t i n g E x P E R t i S E In terms of financial literacy, we held additional internal IFrS education sessions in the fourth quarter of 2010. These education sessions will continue during 2011 across all of our finance teams to ensure that there is a strong level of knowledge of IFrS throughout the organization. We will also continue to educate our external stakeholders, primarily by disclosing and explaining the significant adjustments from GAAp to IFrS. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 74 Outlook Our long term objective is to focus on building net asset value and generating an attractive total shareholder return through the following strategies: • Material growth in oil sands production, primarily through expansions at our Foster Creek and Christina Lake properties, and heavy oil production at pelican Lake. We also have an extensive inventory of new resource play assets such as Narrows Lake, Grand rapids and Telephone Lake, and have a 100 percent working interest in many of these assets; • Continue the development of our resources in multiple phases using a low cost manufacturing-like approach; • Leadership in low cost oil sands development enabled by technology, innovation and continued respect for the health and safety of our employees, emphasis on industry leading environmental performance and meaningful dialogue with our stakeholders; • To primarily fund growth internally through free cash flow generation mainly from our established conventional crude oil and natural gas assets along with sufficient capacity on our debt facilities for additional cash requirements, as well as proceeds generated from our ongoing portfolio management strategy to divest of non-core oil and gas assets; • Maintaining a lower risk profile through natural gas and refining integration as well as a consistent hedging strategy; and • Maintaining a meaningful dividend. We expect that global oil demand will continue to increase which should allow for continued strength in WTI prices. We are expecting the light-heavy differential, represented by WCS crude oil prices, to remain close to historical trends due to pipeline disruptions and Canadian heavy crude supply growing in advance of new coking capacity and pipeline access to the Gulf of Mexico. Once the new refinery and pipeline capacity is in place there should be strengthening in WCS. If the pipeline disruptions and apportionment that occurred in the second half of 2010 persist, we expect widened light-heavy oil differentials to continue in 2011, which should benefit our refining financial results. Offsetting this is a relatively weak price outlook for natural gas and refining margins although refining margins will benefit from any near term congestion in inland markets. The key challenges that need to be effectively managed to enable our growth are commodity price volatility, timely regulatory and partner approvals, environmental regulations and competitive pressures within our industry. Additional detail regarding the impact of these factors on our 2010 results is discussed in the risk Management section of this MD&A and in our AIF for the year ended December 31, 2010. We expect our 2011 capital investment program to be primarily internally funded through cash flow with sufficient capacity on our debt facilities for additional cash requirements. We also plan to divest of certain non-core assets in 2011 for proceeds of $300 to $500 million. Our conventional crude oil and natural gas assets in Alberta and Saskatchewan are key to providing free cash flow to enable oil sands growth. Our 10 year business plan outlines how Cenovus expects to reach net oil sands production of 300,000 bbls/d by the end of 2019. We are planning continued expansions at Foster Creek and Christina Lake, as well as new projects at Narrows Lake, Grand rapids and Telephone Lake in order to achieve this objective. As part of ongoing efforts to maintain financial resilience and flexibility, Cenovus has taken steps to reduce pricing risk through a commodity hedging program. While we have historically benefitted from this strategy, there is no certainty that we will continue to derive such benefits in the future. We will continue to develop our strategy with respect to capital investment and returns to shareholders. Future dividends will be at the sole discretion of the Board and considered quarterly. 75 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T Advisory F Or WA r D - L O Ok I n G I n F Or m At I On This MD&A contains 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. Forward-looking information in this MD&A is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast”, or “F”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “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 and prospective 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. 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 www.cenovus.com; 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 debt to cash flow ratio; 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. readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our material risk factors, see “risk Factors” in our Annual Information Form/Form 40-F for the year ended December 31, 2010, available at www.sedar.com, www.sec.gov and www.cenovus.com. O I L A n D G A s I n F O r m At I O n The bitumen contingent and prospective resources estimates were prepared effective December 31, 2010 by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator. The estimates were based on the Canadian Oil and Gas Evaluation Handbook and comply with the requirements of National Instrument 51-101. • Contingent resources are those quantities of petroleum 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. The estimate of contingent resources has not been adjusted for risk based on the chance of development. CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 76 • Economic Contingent resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. In Cenovus’s case, contingent resources were evaluated using the same commodity price assumptions that were used for the 2010 reserves evaluation, which comply with NI 51-101 requirements. • prospective resources are those quantities of petroleum 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. The estimate of prospective resources has not been adjusted for risk based on the chance of discovery or the chance of development. • 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 percent confidence level that the actual quantities recovered will equal or exceed the estimate. • Low Estimate is considered to be a conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources at the low end of the estimate range have the highest degree of certainty – a 90 percent confidence level – that the actual quantities recovered will equal or exceed the estimate. • High Estimate is considered to be an optimistic estimate of the quantity of resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those resources at the high end of the estimate range have a lower degree of certainty – a 10 percent confidence level – that the actual quantities recovered will equal or exceed the estimate. The economic contingent resources were estimated on a project level. The high and low estimates are arithmetic sums of multiple estimates which statistical principles indicate may be misleading as to volumes that may actually be recovered. The aggregated low estimate results shown may have a higher level of confidence than the individual projects, and the aggregated high estimate results shown may have a lower level of confidence than the individual projects. Additional information relating to our oil and gas reserves and resources is presented in our AIF for the year ended December 31, 2010, available at www.sedar.com and on our website at www.cenovus.com. C r u D E O I L , n G L s A n D n A t u r A L G A s C O n v E r s I O n s In this document, certain natural gas volumes have been converted to barrels of oil equivalent (“BOE”) on the basis of six Mcf to one bbl. 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 wellhead. A B Br E v I At I O n s The following is a summary of the abbreviations that have been used in this document: O i l a n d n at U R a l g a S l i q U i d S bbl barrel bbls/d barrels per day Mbbls/d thousand barrels per day MMbbls million barrels ngls BOE Natural gas liquids barrel of oil equivalent BOE/d barrel of oil equivalent per day Wti WCS West Texas Intermediate Western Canada Select n at U R a l g a S Mcf thousand cubic feet MMcf million cubic feet MMcf/d million cubic feet per day Bcf billion cubic feet MMBtu million British thermal units gJ Gigajoule CBM Coal Bed Methane The Arrangement refers to the commencement of independent operations on December 1, 2009 following an agreement with Encana creating two independent publicly traded energy companies. n O n - G A A P m E A s u r E s Certain financial measures in this document do not have a standardized meaning as prescribed by GAAp such as cash flow, operating cash flow, free cash flow, operating earnings, adjusted EBITDA, debt and capitalization and therefore are considered non-GAAp measures. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding our liquidity and our ability to generate funds to finance our operations. The additional information should not be considered in isolation or as a substitute for measures prepared in accordance with GAAp. The definition and reconciliation of each non-GAAp measure, is presented in this MD&A. A D D I t I On A L I n F Or m At I On For convenience, references in this document to “the Company”, “Cenovus”, “we”, “us”, “our” and “its” may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships (“subsidiaries”) of Cenovus, and the assets, activities and initiatives of such subsidiaries. Additional information relating to Cenovus Energy Inc., including our AIF for the year ended December 31, 2010, is available on SEDAr at www.sedar.com and on our website at www.cenovus.com. 77 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T COnSOlidatEd Fin anCial S tatEMEnt S report of management m A n AG E m E n t ’ s r E s P O n s I B I L I t Y F O r t H E C O n s O L I DAt E D F I n A n C I A L s tAt E m E n t s The accompanying Consolidated Financial Statements of Cenovus Energy Inc. (“Cenovus”) are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with Canadian generally accepted accounting principles and include certain estimates that reflect Management’s best judgments. The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of three independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes-Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent auditors at least on a quarterly basis to review and approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors. m A n AG E m E n t ’ s A s s E s s m E n t O F I n t E r n A L C O n t r O L O v E r F I n A n C I A L r E P O r t I n G Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements. Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2010. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control–Integrated Framework to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at that date. pricewaterhouseCoopers LLp, an independent firm of Chartered Accountants, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2010 as stated in their Auditors’ report. pricewaterhouseCoopers LLp has provided such opinions. Brian C. Ferguson president & Chief Executive Officer Cenovus Energy Inc. February 18, 2011 CENOVUS 201 0 A NNUA L rEpOr T · rEpOr T OF MA NAGEM E NT · 78 ivor M. Ruste Executive Vice-president & Chief Financial Officer Cenovus Energy Inc. Independent Auditor’s report t O t H E s H A r E H O L D E r s O F C E n Ov u s E n E r G Y I n C . We have completed integrated audits of Cenovus Energy Inc.’s 2010, 2009 and 2008 consolidated financial statements and its internal control over financial reporting as at December 31, 2010. Our opinions, based on our audits, are presented below. R E P O R t O n t h E C O n S O l i dat E d F i n a n C i a l S tat E M E n t S We have audited the accompanying consolidated financial statements of Cenovus Energy Inc., which comprise the consolidated balance sheets at December 31, 2010 and December 31, 2009 and the consolidated statements of earnings and comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2010, and the related notes including a summary of significant accounting policies. M a n ag E M E n t ’ S R E S P O n S i B i l i t y F O R t h E C O n S O l i dat E d F i n a n C i a l S tat E M E n t S Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. aU d i tO R ’ S R E S P O n Si B i l i t y Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards require that we comply with ethical requirements. An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements. OP i n i On In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Cenovus Energy Inc. as at December 31, 2010 and December 31, 2009 and the results of its operations and cash flows for each of the three years in the period ended December 31, 2010 in accordance with Canadian generally accepted accounting principles. R E P O R t O n i n t E R n a l C O n t R O l O v E R F i n a n C i a l R E P O R t i n g We have also audited Cenovus Energy Inc.’s internal control over financial reporting as at December 31, 2010, based on criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 79 · INDEpENDENT AUDITOr’ S rEpOr T · CENOVUS 2010 ANNUAL rEpOr T M a n ag E M E n t ’ S R E S P O n S i B i l i t y F O R i n t E R n a l C O n t R O l O v E R d E F i n i t i O n O F i n t E R n a l C O n t R O l O v E R F i n a n C i a l R E P O R t i n g F i n a n C i a l R E P O R t i n g The company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Controls over Financial reporting. aU d i tO R ’ S R E S P O n Si B i l i t y Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion on the company’s internal control over financial reporting. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with Canadian generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. i n h E R En t l iM i tat iO n S Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. OP i n i On In our opinion, Cenovus Energy Inc. maintained, in all material respects, effective internal control over financial reporting as at December 31, 2010 based on criteria established in Internal Control — Integrated Framework issued by COSO. PricewaterhouseCoopers llP Chartered Accountants Calgary, Alberta, Canada February 18, 2011 CENOVUS 201 0 A NNUA L rEpOr T · IN DEpE N DE N T AUD ITOr’ S rEpOr T · 80 C O n s O L I DAt E D s tAt E m E n t s O F E A r n I n G s A n D C O m P r E H E n s I v E I n C O m E For the years ended December 31, ($ millions, except per share amounts) Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating purchased product Depreciation, depletion and amortization General and administrative Interest, net Accretion of asset retirement obligation Foreign exchange (gain) loss, net (Gain) loss on divestiture of assets Other (income) loss, net Earnings Before Income Tax Income tax expense Net Earnings Other Comprehensive Income (Loss), Net of Tax Foreign currency translation adjustment Comprehensive Income Net Earnings per Common Share Basic Diluted See accompanying Notes to Consolidated Financial Statements. (Note 1) (Note 1) (Note 1) (Note 8) (Note 16) (Note 9) (Note 6) (Note 10) (Note 22) 2010 13,422 449 12,973 34 1,065 1,302 7,549 1,310 251 279 75 (51) 9 (13) 11,810 1,163 170 993 (13) 980 1.32 1.32 2009 11,790 273 11,517 44 760 1,312 5,910 1,527 211 244 45 304 – (2) 10,355 1,162 344 818 (238) 580 1.09 1.09 2008 18,103 533 17,570 80 1,021 1,292 10,341 1,397 171 233 40 (308) – 3 14,270 3,300 774 2,526 347 2,873 3.37 3.36 81 · C ONSOLIDATED S TATEMENTS OF E ArNINGS AND C OMprEHENSIVE INCOME · CENOVUS 201 0 ANNUAL rEpOr T C O n s O L I DAt E D B A L A n C E s H E E t s As at December 31, ($ millions) Assets Current Assets Cash and cash equivalents Accounts receivable and accrued revenues Income tax receivable Current portion of partnership Contribution receivable risk management Inventories Assets Held for Sale property, plant and Equipment, net partnership Contribution receivable risk Management Other Assets Goodwill Liabilities and shareholders’ Equity Current Liabilities Accounts payable and accrued liabilities Income tax payable Current portion of partnership Contribution payable risk management Liabilities related to Assets Held for Sale Long-Term Debt partnership Contribution payable risk Management Asset retirement Obligation Other Liabilities Future Income Taxes Commitments and Contingencies Shareholders’ Equity See accompanying Notes to Consolidated Financial Statements. Approved by the Board 2010 2009 300 1,055 31 346 163 880 2,775 65 – 15,530 2,145 43 1 391 1,146 22,095 1,825 154 – 343 163 2,485 7 – 3,432 2,176 10 4 1,213 346 2,404 12,073 10,022 22,095 155 978 40 345 60 875 2,453 15,214 2,621 320 1,146 21,755 1,574 340 70 1,984 3,656 2,650 1,147 239 2,467 12,147 9,608 21,755 (Note 11) (Note 21) (Note 12) (Note 6) (Notes 1, 13) (Note 11) (Note 21) (Note 14) (Note 1) (Note 11) (Note 21) (Note 6) (Note 15) (Note 11) (Note 21) (Note 16) (Note 17) (Note 10) (Note 23) (Note 18) Michael a. grandin Director Cenovus Energy Inc. Colin taylor Director Cenovus Energy Inc. CENOVUS 201 0 A NNUA L rEpOr T · CON SOLIDATED BA L A NCE SH E E TS · 8 2 Share Capital (Note 18) paid in Surplus (Note 18) retained Earnings Owner’s Net Investment (Note 18) AOCI* C O n s O L I DAt E D s tAt E m E n t s O F s H A r E H O L D E r s ’ E Q u I t Y ($ millions) Balance as at December 31, 2007 Net earnings Net distribution to owner Other comprehensive income (loss) Balance as at December 31, 2008 Net earnings Net distribution to owner Other comprehensive income (loss) Owner’s net Investment at Arrangement date – november 30, 2009 Issuance of common stock in connection with the Arrangement reclassification of owner’s net investment to paid in surplus in connection with the Arrangement Net earnings – December 1 to December 31 Dividends on common shares Common shares issued under option plans Other comprehensive income (loss) Balance as at December 31, 2009 Net earnings Common shares issued under option plans Dividends on common shares Other comprehensive income (loss) – – – – – – – – – 3,680 – – – 1 – – – – – – – – – – – 6,055 – (159) – – 3,681 5,896 – 35 – – – – – – Balance as at December 31, 2010 3,716 5,896 * Accumulated Other Comprehensive Income See accompanying Notes to Consolidated Financial Statements. – – – – – – – – – – – 45 – – – 45 993 – (601) – 437 (123) – – 347 224 – – (212) 12 – – – – – (26) (14) – – – (13) (27) Total 7,912 2,526 (1,297) 347 9,488 773 (302) (212) 8,035 2,526 (1,297) – 9,264 773 (302) – 9,735 9,747 (3,680) (6,055) – – – – – – – – – – – – 45 (159) 1 (26) 9,608 993 35 (601) (13) 10,022 83 · C ONSOLIDATED S TATEMENTS OF SHArEH OLDErS ’ EQUITY · CENOVUS 2010 ANNUAL rEpOr T C O n s O L I DAt E D s tAt E m E n t s O F C A s H F L OW s For the years ended December 31, ($ millions) Operating Activities Net earnings Depreciation, depletion and amortization Future income taxes (recovery) Unrealized (gain) loss on risk management Unrealized foreign exchange (gain) loss Accretion of asset retirement obligation (Gain) loss on divestiture of assets Other Net change in other assets and liabilities Net change in non-cash working capital Cash From Operating Activities Investing Activities Capital expenditures proceeds from divestitures Net change in other assets Net change in non-cash working capital Cash (Used in) Investing Activities Net Cash provided before Financing Activities Financing Activities Net issuance (repayment) of revolving long-term debt Issuance of long-term debt repayment of long-term debt Issuance of U.S. Unsecured Notes payment of note payable to Encana payment of transition account payable to Encana Net financing transactions with Encana Issuance of common shares Dividends on common shares Other Cash (Used in) Financing Activities Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents, Beginning of Year Cash and Cash Equivalents, End of Year Supplemental Cash Flow Information See accompanying Notes to Consolidated Financial Statements. 2010 2009 2008 993 1,310 88 (46) (69) 75 9 55 (55) 234 818 1,527 (590) 698 327 45 – 20 (26) 220 2,594 3,039 2,526 1,397 405 (899) (317) 40 – (37) (92) 202 3,225 (2,208) 309 4 99 (1,796) 798 (58) – – – – – – 28 (601) – (631) (22) 145 155 300 (2,165) (2,204) 222 (25) (95) (2,063) 976 (342) 204 (97) 3,718 (3,701) (264) (302) 1 (159) (35) (977) (32) (33) 188 155 48 (49) 96 (2,109) 1,116 41 276 (247) – – – (1,297) – – – (1,227) 1 (110) 298 188 (Note 10) (Note 21) (Note 9) (Note 16) (Note 1) (Note 7) (Note 15) (Note 15) (Note 22) CENOVUS 201 0 A NNUA L rEpOr T · CON SOLIDATED STATEM E NTS O F C AS H FLOWS · 84 nO tES t O COnSOlidatEd FinanCial S tatEMEn t S All amounts in $ millions, unless otherwise indicated. For the year ended December 31, 2010 1. DEs CrIPtIOn OF BusInEss AnD sE GmEn tE D D Is CLOsurEs Cenovus Energy Inc. (“Cenovus” or the “Company”) is in the business of the development, production and marketing of crude oil, natural gas and natural gas liquids (“NGLs”) in Canada with refining operations in the United States (“U.S.”). The Company is headquartered in Calgary, Alberta and its Common Shares are listed on the Toronto and New York stock exchanges. Information on the Company’s background and the basis of presentation for these financial statements are found in Note 2. The Company’s operating and reportable segments are as follows: • Upstream, which includes Cenovus’s development and production of crude oil, natural gas and NGLs in Canada, is organized into two reportable operations: – Oil Sands, which consists of Cenovus’s producing bitumen assets at Foster Creek and Christina Lake, heavy oil assets at pelican Lake, new resource play assets such as Narrows Lake, Grand rapids and Telephone Lake, and the Athabasca natural gas assets. Certain of the Company’s oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with Conocophillips, an unrelated U.S. public company and operated by Cenovus. – Conventional, which includes the development and production of conventional crude oil, natural gas and NGLs in western Canada. • Refining and Marketing, which is focused on the refining of crude oil products into petroleum and chemical products at two refineries located in the U.S. The refineries are jointly owned with and operated by Conocophillips. This segment also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. • Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory. The operating and reportable segments shown above have been changed from those presented in prior periods to match Cenovus’s new operating structure. All prior periods have been restated to reflect this presentation. The tabular financial information which follows presents the segmented information first by segment, then by product and geographic location. Capital expenditures, goodwill, sales information and information relating to Cenovus’s major customers are summarized at the end of the note. 85 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T R E S U lt S O F O P E R at i O n S – S E g M E n t a n d O P E R at i O n a l i n F O R M at i O n For the years ended December 31, 2010 2009 2008 2010 2009 2008 2010 2009 2008 Oil Sands Conventional Total Upstream Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating purchased product Depreciation, depletion and amortization Segment Income (Loss) Balances as at December 31, property, plant & Equipment Goodwill Total Assets 2,719 279 2,440 – 935 369 – 1,136 2,277 135 2,142 1 628 332 – 1,181 2,558 246 2,312 2 791 335 – 2,539 170 2,369 34 130 441 – 3,369 138 3,231 43 132 416 – 4,130 287 3,843 78 230 427 – 1,184 1,764 2,640 3,108 5,258 449 4,809 34 1,065 810 – 2,900 1,039 1,861 5,646 273 5,373 44 760 748 – 3,821 1,250 2,571 6,688 533 6,155 80 1,021 762 – 4,292 1,179 3,113 10,196 10,095 9,949 1,146 1,146 1,146 14,543 14,921 15,466 For the years ended December 31, 2010 2009 2008 2010 2009 2008 2010 2009 2008 refining and Marketing Corporate and Eliminations Consolidated Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating purchased product Depreciation, depletion and amortization Segment Income (Loss) General and Administrative Interest, net Accretion of asset retirement obligation Foreign exchange (gain) loss, net (Gain) loss on divestiture of assets Other (income) loss, net Earnings Before Income Tax Income tax expense Net Earnings Balances as at December 31, property, plant & Equipment Goodwill Total Assets 8,228 – 8,228 – – 489 7,664 75 239 (164) 6,922 – 6,922 – – 534 6,020 368 232 136 10,684 – 10,684 – – 543 10,500 (359) 205 (564) 5,188 5,003 4,967 – – – 6,714 6,404 5,964 (64) – (64) – – 3 (115) 48 32 16 251 279 75 (51) 9 (13) 550 146 – 838 (778) – (778) – – 30 (110) (698) 45 (743) 211 244 45 304 – (2) 802 731 – 731 – – (13) (159) 903 13 890 171 233 40 (308) – 3 139 13,422 449 12,973 34 1,065 1,302 7,549 3,023 1,310 1,713 251 279 75 (51) 9 (13) 550 1,163 170 993 11,790 273 11,517 44 760 1,312 5,910 3,491 1,527 1,964 211 244 45 304 – (2) 802 1,162 344 818 18,103 533 17,570 80 1,021 1,292 10,341 4,836 1,397 3,439 171 233 40 (308) – 3 139 3,300 774 2,526 116 – 98 – 15,530 15,214 15,014 1,146 1,146 1,146 430 1,184 22,095 21,755 22,614 CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 86 U P S t R E a M P R O d U C t a n d O P E R at i O n a l i n F O R M at i O n For the years ended December 31, 2010 2009 2008 2010 2009 2008 2010 2009 2008 Oil Sands Crude Oil & NGLs Conventional Total Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating Operating Cash Flow 2,603 276 2,327 – 934 341 2,056 129 1,927 1 626 298 2,262 178 2,084 2 784 279 1,052 1,002 1,019 1,220 153 1,067 28 86 202 751 1,161 119 1,042 28 87 174 753 1,606 208 1,398 40 154 171 1,033 3,823 429 3,394 28 1,020 543 1,803 3,217 248 2,969 29 713 472 3,868 386 3,482 42 938 450 1,755 2,052 Oil Sands Natural Gas Conventional Total For the years ended December 31, 2010 2009 2008 2010 2009 2008 2010 2009 2008 Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating Operating Cash Flow 102 1 101 – 1 23 77 214 6 208 – 2 25 181 278 68 210 – 7 43 160 1,306 17 1,289 6 44 235 2,196 19 2,177 15 45 237 2,512 79 2,433 38 76 252 1,408 18 1,390 6 45 258 2,410 25 2,385 15 47 262 2,790 147 2,643 38 83 295 1,004 1,880 2,067 1,081 2,061 2,227 Oil Sands Other Conventional Total For the years ended December 31, 2010 2009 2008 2010 2009 2008 2010 2009 2008 Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating Operating Cash Flow 14 2 12 – – 5 7 7 – 7 – – 9 (2) 18 – 18 – – 13 5 13 – 13 – – 4 9 12 – 12 – – 5 7 12 – 12 – – 4 9 8 Oil Sands Total Conventional 30 – 30 – – 17 13 27 2 25 – – 16 19 – 19 – – 14 5 Total For the years ended December 31, 2010 2009 2008 2010 2009 2008 2010 2009 2008 Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating Operating Cash Flow 2,719 279 2,440 – 935 369 1,136 2,277 135 2,142 1 628 332 1,181 2,558 246 2,312 2 791 335 1,184 2,539 170 2,369 34 130 441 3,369 138 3,231 43 132 416 4,130 287 3,843 78 230 427 5,258 449 4,809 34 1,065 810 5,646 273 5,373 44 760 748 6,688 533 6,155 80 1,021 762 1,764 2,640 3,108 2,900 3,821 4,292 87 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T g E O g R a P h i C i n F O R M at i On The refining and Marketing segment operates in both Canada and the United States. Both of Cenovus’s refining facilities are located and carry on business in the United States. The marketing of Cenovus’s crude oil and natural gas produced in Canada, as well as the third party purchases and sales of product is undertaken in Canada. physical product sales that settle in the United States are considered to be export sales undertaken by a Canadian business. Canada (Marketing) United States (refining) Total refining and Marketing For the years ended December 31, 2010 2009 2008 2010 2009 2008 2010 2009 2008 Gross revenues Less: royalties Net revenues Expenses Operating purchased product Operating Cash Flow Depreciation, depletion and amortization Segment Income (Loss) 1,604 – 1,604 17 1,579 8 10 (2) 965 – 965 17 938 10 12 (2) 1,211 – 1,211 20 1,184 7 4 3 6,624 5,957 9,473 8,228 6,922 10,684 – – – – – – 6,624 5,957 9,473 8,228 6,922 10,684 472 517 6,085 5,082 67 229 (162) 358 220 138 523 9,316 (366) 201 (567) 489 534 543 7,664 6,020 10,500 75 239 (164) 368 232 136 (359) 205 (564) C a P i ta l E x P E n d i t U R E S For the years ended December 31, Capital Oil Sands Conventional Upstream refining and Marketing Corporate Acquisition Capital Oil Sands Conventional refining and Marketing Total 2010 2009 2008 867 523 1,390 656 76 2,122 25 23 38 629 466 1,095 1,033 34 2,162 – 3 – 758 848 1,606 539 59 2,204 – – – 2,208 2,165 2,204 In addition to the above, in 2009 Cenovus acquired strategic bitumen lands in exchange for certain non-core holdings. g O Od W i l l a d d i t i On S There were no additions to goodwill during 2010, 2009 or 2008. E x P O R t S a l E S Sales of crude oil, natural gas and NGLs produced or purchased in Canada delivered to customers outside of Canada were $646 million (2009–$618 million; 2008–$1,388 million). M a J O R C U S tO M E R S In connection with the marketing and sale of Cenovus’s own and purchased crude oil, natural gas and refined products for the year ended December 31, 2010, Cenovus had two customers (2009–two; 2008–two) which individually accounted for more than 10 percent of its consolidated gross revenues. Sales to these customers, major international integrated energy companies with an investment grade credit rating, were approximately $7,671 million (2009– $6,389 million; 2008–$9,619 million). CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 88 2 . BACk Gr OunD & BAsIs OF PrEsEn t AtIOn In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. The Company’s functional currency is Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars. Cenovus began independent operations on December 1, 2009, as a result of the plan of arrangement (“Arrangement”) involving Encana Corporation (“Encana”) whereby Encana was split into two independent energy companies, one a natural gas company, Encana and the other an oil company, Cenovus. In connection with the Arrangement, Encana common shareholders received one share in each of the new Encana and Cenovus in exchange for each Encana share held. Common shares of Cenovus began trading on a “when issued” basis on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges on November 2, 2009. regular trading of the Cenovus shares began on the TSX on December 3, 2009 and on the NYSE on December 9, 2009. Up until the completion of the Arrangement, Encana was considered a related party due to its parent-subsidiary relationship with the Cenovus entities. However, subsequent to the Arrangement, Encana is no longer a related party as defined by the CICA Handbook Section 3840 – related party Transactions. B a S i S O F P R E S E n tat i O n /C a Rv E- O U t F i n a n C i a l i n F O R M at i O n The results for the year ended December 31, 2010 and the one month period from December 1 to December 31, 2009 represent the Company’s operations, cash flow and financial position as a stand-alone entity. The results for the periods prior to the Arrangement, being from January 1 to November 30, 2009 and January 1 to December 31, 2008 have been prepared on a “carve-out” accounting basis whereby the results have been derived from the accounting records of Encana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus. As the Company operated as part of Encana and was not a stand-alone entity prior to November 30, 2009, the historical Consolidated Financial Statements include allocations of certain Encana revenues, expenses, assets and liabilities, including the items described below. The operating results of Cenovus were specifically identified based on Encana’s divisional organization. Certain other expenses presented in the Consolidated Statements of Earnings and Comprehensive Income represent allocations and estimates of the cost of services incurred by Encana. These allocations and estimates include unrealized mark-to-market gains and losses, general and administrative costs, net interest, foreign exchange gains and losses and income tax expenses. The majority of the assets and liabilities of Cenovus were identified based on the divisional structure, with the most significant exceptions being property, plant and equipment (“pp&E”), income taxes payable and long-term debt. refining, crude oil and natural gas marketing and corporate depreciation, depletion and amortization were specifically identified based on Encana’s divisional structure where possible. Depletion related to upstream properties was allocated to Cenovus based on the related production volumes utilizing the depletion rate calculated for Encana’s consolidated Canadian cost centre. Mark-to-market gains and losses resulting from derivative financial instruments entered into by Encana were allocated to Cenovus based on the related product volumes. Salaries, benefits, pension, long-term incentives and other post-employment benefits costs, assets and liabilities were allocated to Cenovus based on Management’s best estimate of how services were historically provided by existing employees. Costs, assets and liabilities associated with retired employees remained with Encana. Net interest expense was calculated primarily using the debt balance allocated to Cenovus. Income taxes were recorded as if Cenovus and its subsidiaries had been separate tax paying legal entities, each filing a separate tax return in its local jurisdiction. The calculation of income taxes is based on a number of assumptions, allocations and estimates, including those used to prepare the Cenovus Carve-out Consolidated Financial Statements. prior to the Arrangement, Cenovus’s tax pools were allocated for the Canadian cost centre based on the same allocation method used to determine pp&E for carve-out purposes. pp&E related to upstream oil and gas activities are accounted for by Cenovus using the full cost method of accounting. pp&E related to upstream oil and gas activities was determined based on an allocation process which used the ratio of future net revenue, discounted at 10 percent, of the respective divisions of Encana to the future net revenue, discounted at 10 percent, of all proved properties in Canada at December 31, 2008. Future net revenue was the estimated net amount to be received with respect to development and production of crude oil and natural gas reserves. Goodwill was allocated to Cenovus based on the properties associated with the former business combinations on which it arose. For the purpose of preparing the Carve-out Consolidated Financial Statements, it was determined that Cenovus should maintain approximately the same Debt to Capitalization ratio as consolidated Encana based on U.S. dollar amounts. As a result, prior to the Arrangement, debt was allocated to Cenovus based on this ratio, which was calculated using U.S. dollars. Debt is defined as the current and long-term portions of Long-term Debt. Capitalization is not a term that has a prescribed meaning under generally accepted accounting principles (“non-GAAp”) and is a measure defined as Debt plus Shareholders’ Equity. Management believes the assumptions underlying the Cenovus Carve-out Consolidated Financial Statements are reasonable. However, the Cenovus Consolidated Financial Statements herein may not reflect Cenovus’s financial position, results of operations, and cash flows had Cenovus been a stand-alone company during the periods presented or what Cenovus’s operations, financial position, and cash flows will be in the future. Encana’s direct investment in 89 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T Cenovus is shown as Net Investment in place of Shareholders’ Equity because a direct ownership by shareholders in Cenovus did not exist prior to November 30, 2009. Encana’s investment includes the accumulated net earnings, other comprehensive income and net cash distributions to Encana. In the opinion of Management, the Consolidated and the historical Carve-out Consolidated Financial Statements reflect all adjustments (including normal recurring adjustments) necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with Canadian generally accepted accounting principles (“Canadian GAAp”). 3. CHAnGE In rEPOrtInG Cu r rEnC Y As a result of the Arrangement, Cenovus reported its results in U.S. dollars for the preparation of its December 31, 2009 consolidated financial statements as this was the reporting currency used by Encana. Effective January 1, 2010, the Company changed its reporting currency to Canadian dollars. The change in reporting currency is to better reflect the business of Cenovus, and it allows for increased comparability to the Company’s peers. In implementing this change, the Company has followed the requirements of the Canadian Institute of Chartered Accountants (“CICA”) Emerging Issues Committee (“EIC”) Abstract 130 (“EIC-130”), “Translation Method When the reporting Currency Differs from the Measurement Currency or there is a Change in the reporting Currency.” With the change in reporting currency, all comparative financial information has been restated from U.S. dollars to Canadian dollars to reflect the Company’s consolidated financial statements as if they had been historically reported in Canadian dollars. 4. summAr Y OF sIGnIFICAnt ACCOuntInG PO L I CI Es A) principles of Consolidation The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries and are presented in accordance with Canadian GAAp. Information prepared in accordance with GAAp in the United States is included in Note 24. Investments in jointly controlled partnerships and unincorporated joint ventures carry on certain of Cenovus’s development, production and crude oil refining businesses and are accounted for using the proportionate consolidation method, whereby Cenovus’s proportionate share of revenues, expenses, assets and liabilities are included in the accounts. B) Foreign Currency Translation The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at period end exchange rates, while revenues and expenses are translated using average rates over the period. Translation gains and losses relating to the self- sustaining operations are included in Accumulated Other Comprehensive Income (“AOCI”) as a separate component of Shareholders’ Equity. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings. C) Measurement Uncertainty and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Amounts recorded for depreciation, depletion and amortization, asset retirement costs and obligations and amounts used for ceiling test and impairment calculations are based on estimates of crude oil and natural gas reserves, future costs required to develop those reserves and future cash flows. By their nature, these estimates of reserves, including the estimates of future prices and costs, and the related future cash flows are subject to measurement uncertainty, and the impact in the Consolidated Financial Statements of future periods could be material. The values of pension assets and obligations and the amount of pension costs charged to net earnings depend on certain actuarial and economic assumptions which, by their nature, are subject to measurement uncertainty. The amount of compensation expense accrued for long-term performance- based compensation arrangements is subject to Management’s best estimate of whether or not the performance criteria will be met and what the ultimate payout will be. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. The timely preparation of the Consolidated Financial Statements in conformity with Canadian GAAp requires that Management make estimates and assumptions and use judgment regarding the reported amounts of assets Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. As such, income taxes are subject to measurement uncertainty. CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 90 D) revenue recognition H) Income Taxes revenues associated with the sales of Cenovus’s crude oil, natural gas, NGLs and petroleum and refined products are recognized when title passes from the Company to its customer. realized gains and losses from crude oil and natural gas commodity price risk management activities are recorded in revenue when the product is sold. revenues and purchased product are recorded on a gross basis when the title to product passes and the risks and rewards of ownership have been transferred. purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. revenues associated with the services provided as agent are recorded as the services are provided. Unrealized gains and losses from natural gas and crude oil commodity price risk management activities are recorded as revenue based on the related mark-to-market calculations at the end of the respective period. E) production and Mineral Taxes Costs paid to non-mineral interest owners based on production of crude oil, natural gas and NGLs are recognized when the product is produced. F) Transportation and Blending Costs The costs associated with the transportation of crude oil, natural gas and NGLs, including the cost of diluent used in blending, are recognized when the product is delivered and the services provided. G) Employee Benefit plans Accruals for obligations under the employee benefit plans and the related costs are recorded net of plan assets. The cost of pensions and other post-employment benefits is actuarially determined using the projected benefit method based on length of service, and reflects Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on the fair value of those assets. The accrued benefit obligation is discounted using the market interest rate on high quality corporate debt instruments as at the measurement date. pension expense for the defined benefit pension plan includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. Amortization is calculated on a straight-line basis over a period covering the expected average remaining service lives of employees covered by the plans. pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plans. Cenovus follows the liability method of accounting for income taxes, where future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs. I) Earnings per Share Amounts Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share amounts are calculated giving effect to the potential dilution that would occur if stock options, without tandem stock appreciation rights attached, were exercised or other contracts expected to result in the issuance of common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options without tandem share appreciation rights attached and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the- money stock options without tandem stock appreciation rights attached are used to repurchase common shares at the average market price. J) Cash and Cash Equivalents Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased. K) Inventories product inventories, including petroleum and refined products, are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. L) property, plant and Equipment Upstream Crude oil and natural gas properties are accounted for in accordance with the CICA guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, the exploration for, and the development of bitumen, crude oil and natural gas reserves, are capitalized on a country- by-country cost centre basis. Costs accumulated within each cost centre are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves determined using estimated future prices and costs. For purposes of this calculation, natural gas is converted to oil on an energy equivalent basis. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. proceeds from the divestiture of 91 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depreciation, depletion and amortization of 20 percent or greater, in which case a gain or loss is recorded. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded, on a cost centre basis, from the costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment has occurred. Costs that have been impaired are included in the costs subject to depreciation, depletion and amortization. An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of: i. the fair value of proved and probable reserves; and ii. the costs of unproved properties that have been subject to a separate impairment test. Refining The initial acquisition costs of refining property, plant and equipment are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use and the associated asset retirement costs. Capitalized costs are not subject to depreciation until the asset is put into use, after which they are depreciated on a straight-line basis over the estimated service lives of each component of the refining facilities. An impairment loss is recognized on refining property, plant and equipment when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from expected use and eventual disposition. If the carrying amount is not recoverable, an impairment loss is measured as the amount by which the carrying amount exceeds the fair value. Other Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 25 years. Assets under construction are not subject to depreciation until put into use. M) Capitalization of Costs Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. N) Amortization of Other Assets Items included in Other Assets are amortized, where applicable, on a straight- line basis over the estimated useful lives of the assets. O) Goodwill Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually. Goodwill and all other assets and liabilities have been allocated to the country cost centre level, referred to as a reporting unit. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount. p) Asset retirement Obligation The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheets when incurred and a reasonable estimate of fair value can be made. Asset retirement obligations include those legal obligations where Cenovus will be required to retire tangible long-lived assets such as producing well sites, crude oil and natural gas processing plants, and refining facilities. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost. Amortization of asset retirement costs are included in depreciation, depletion and amortization in the Consolidated Statements of Earnings. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statements of Earnings. Actual expenditures incurred are charged against the accumulated obligation. Q) Stock-Based Compensation Obligations for payments, cash or common shares, under Cenovus’s stock option, performance share unit and deferred share unit plans are accrued using the intrinsic method as compensation cost over the vesting period. Fluctuations in the price of Cenovus’s common shares change the accrued compensation cost and are recognized when they occur. Encana replacement stock options with tandem stock appreciation rights attached held by Cenovus employees are accrued using the fair value method. The fair value is recognized as compensation cost over the vesting period. Fluctuations in the fair value of the rights change the accrued compensation cost and are recognized when they occur. r) Financial Instruments Financial instruments are measured at fair value on initial recognition of the instrument. Measurement in subsequent periods depends on whether the financial instrument has been classified as “held-for-trading”, “available-for- sale”, “held-to-maturity”, “loans and receivables”, or “other financial liabilities”. CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 92 Financial assets and financial liabilities “held-for-trading” are measured at fair value with changes in those fair values recognized in net earnings. Financial assets “available-for-sale” are measured at fair value, with changes in those fair values recognized in Other Comprehensive Income (“OCI”). Financial assets “held-to-maturity”, “loans and receivables” and “other financial liabilities” are measured at amortized cost using the effective interest method of amortization. Cash and cash equivalents are designated as “held-for-trading” and are measured at fair value. Accounts receivable and accrued revenues and the partnership Contribution receivable and partner loans receivable are designated as “loans and receivables”. Accounts payable and accrued liabilities, the partnership Contribution payable and partner loans payable and long-term debt are designated as “other financial liabilities”. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt and amortized using the effective interest method. rates and interest rates. Derivative financial instruments are not used for speculative purposes. policies and procedures are in place with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use, in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated from budgeted capital programs, and in other cases to the mitigation of market price risks for specific assets and obligations. When applicable, the Company identifies relationships between financial instruments and anticipated transactions, as well as its risk management objective and the strategy for undertaking the economic hedge transaction. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction. derivative Financial instruments S) reclassification risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings. realized gains or losses from financial derivatives related to crude oil and natural gas commodity prices are recognized in crude oil and natural gas revenues as the related sales occur. realized gains or losses from financial derivatives related to power commodity prices are recognized in operating costs as the related power costs are incurred. Unrealized gains and losses are recognized at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts. Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange In addition to the restatement required due to the changes in operating segments (see Note 1), certain information provided for prior years has been reclassified to conform to the presentation adopted in 2010. T) recent Accounting pronouncements Beginning with the three month period ending March 31, 2011, Cenovus is required to report its results in accordance with International Financial reporting Standards (“IFrS”). Cenovus has developed a detailed changeover plan to complete the transition to IFrS. The plan includes the preparation of required comparative information for 2010, given that the IFrS date of transition was January 1, 2010. The Company is on schedule with its plan and is continuing to assess the potential impact of the adoption of IFrS on its Consolidated Financial Statements. 5. CHAnGEs In ACCOu n tInG PO LI C IEs AnD PrACtI CEs B U S i n E S S C O M B i n at i O n S On January 1, 2010, Cenovus early adopted CICA Handbook Section 1582, “Business Combinations,” which replaces CICA Handbook Section 1581 of the same name. The new standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the Statement of Earnings. This accounting policy was applied to the November 1, 2010 purchase of the marine terminal facilities disclosed in Note 6. C O n S O l i dat E d F i n a n C i a l S tat E M E n t S a n d n O n - C O n tR O l l i n g in tE R E S t S In conjunction with the early adoption of CICA Handbook Section 1582, the Company was also required to early adopt CICA Handbook Sections 1601, “Consolidated Financial Statements” and 1602, “Non-controlling Interests” effective January 1, 2010. These sections replace the former consolidated financial statement standard, CICA Handbook Section 1600, “Consolidated Financial Statements.” Section 1601 establishes the requirements for the preparation of the consolidated financial statements and Section 1602 establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. Section 1602 requires a non-controlling interest to be classified as a separate component of equity. In addition, net earnings, and components of other comprehensive income are attributed to both the parent and non-controlling interest. The early adoption of these standards did not have a material impact on the Company’s Consolidated Financial Statements for the year ended December 31, 2010. These standards along with CICA Handbook Section 1582 above are converged with IFrS (see Note 4). 93 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T 6. AssEts AnD LIABILItIEs HE LD FOr sA L E On November 1, 2010, under the terms of an agreement with a non-related Canadian company, Cenovus acquired certain marine terminal facilities in Kitimat, British Columbia for cash consideration of $38 million. Cenovus intends to sell the facilities as soon as practicable. As a result, the net assets acquired have been recorded at estimated fair value less costs to sell, and have been classified as held for sale. These assets are reported in the refining and Marketing segment. Cenovus recognized a bargain purchase gain of $12 million, resulting from the excess fair value of the net assets acquired over the cash consideration paid. The table below represents the purchase cost and the preliminary allocation to the assets and liabilities. The gain has been recorded in other income. Cash consideration Fair value of Liabilities assumed Asset retirement obligation Future income taxes Total purchase price and Liabilities Assumed Estimated Fair Value of Assets acquired property, plant and Equipment Bargain purchase Gain As at December 31, 2010 the assets and liabilities classified as held for sale consists of the following: Assets Held for Sale property, plant and equipment Liabilities related to Assets Held for Sale Asset retirement obligation Future income taxes 7. DIvEstIturEs For the years ended December 31, Oil Sands Conventional Corporate Cash proceeds 38 5 4 47 59 12 December 31, 2010 65 5 2 7 2010 2009 2008 81 221 7 309 89 130 3 222 8 40 – 48 CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 94 8. In tErEst , nEt For the years ended December 31, Interest Expense–Long-Term Debt Interest Expense–Other Interest Income 2010 2009 2008 227 196 (144) 279 211 220 (187) 244 205 228 (200) 233 Interest Expense–Other and Interest Income are primarily due to the partnership Contribution payable and receivable, respectively (See Note 11). 9. FOrEIGn E XCHAnGE (GAIn) LO ss , nEt For the years ended December 31, Unrealized Foreign Exchange (Gain) Loss on translation of: U.S. dollar debt issued from Canada U.S. dollar partnership Contribution receivable issued from Canada Other Unrealized Foreign Exchange (Gain) Loss realized Foreign Exchange (Gain) Loss 10. InCOmE t AXEs The provision for income taxes is as follows: For the years ended December 31, Current Canada United States Total Current Tax Future Tax 2010 2009 2008 (182) 91 22 (69) 18 (51) (381) 504 204 327 (23) 304 430 (744) (3) (317) 9 (308) 2010 2009 2008 82 – 82 88 170 979 (45) 934 (590) 344 393 (24) 369 405 774 Future income tax expense in 2010 includes a tax benefit of $107 million from the recognition of net capital losses expected to be realized against future capital gains. These net capital losses are attributable to an internal restructuring undertaken in 2010. Net capital losses of $415 million, attributable to the restructuring and to realized foreign exchange losses, are unrecognized at December 31, 2010. recognition is dependent on the level of future capital gains. Current income tax expense in 2009 includes the incremental tax incurred as a result of certain corporate restructuring transactions which were required to effect the Arrangement. 95 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: For the years ended December 31, Earnings Before Income Tax Canadian Statutory rate Expected Income Tax Effect on Taxes resulting from: Statutory and other rate differences Non-deductible stock-based compensation Multi-jurisdictional financing Foreign exchange gains not included in net earnings Non-taxable capital (gains) losses recognition of capital losses Other Effective Tax rate The net future income tax liability consists of: As at December 31, Future Tax Liabilities property, plant and equipment in excess of tax values Timing of partnership items Net foreign exchange gains risk management Other Future Tax Assets Unused tax losses risk management Other Net Future Income Tax Liability The approximate amounts of tax pools available are as follows: As at December 31, Canada United States 2010 1,163 28.2% 328 (33) 29 (93) 28 (9) (107) 27 170 14.6% 2009 1,162 29.2% 339 (1) – (134) 58 30 – 52 344 29.6% 2008 3,300 29.7% 980 (92) – (135) 71 (53) – 3 774 23.5% 2010 2009 2,534 2,654 125 127 55 55 (281) (45) 9 61 17 1 (242) (33) (166) – 2,404 2,467 2010 4,239 3,082 7,321 2009 3,754 2,637 6,391 Included in the above tax pools are $236 million (2009–$491 million) of Canadian non-capital losses which expire no earlier than 2026 and $607 million (2009– $232 million) of U.S. net operating losses which expire no earlier than 2029. Also included in the above tax pools are $983 million (2009–$51 million) of Canadian net capital losses, available for carry forward to reduce future capital gains. CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 96 11. PArtnErsHIP COn trIBu tIOn rE CE Iv A BL E AnD PAYAB LE In connection with the Arrangement with Encana, Cenovus acquired Encana’s assets which are jointly controlled with Conocophillips. On January 2, 2007, Encana became a 50 percent partner in an integrated, North American oil business with Conocophillips which consists of an upstream entity and a refining entity. The upstream entity contribution included assets from Encana, primarily the Foster Creek and Christina Lake properties, with a fair value of US$7.5 billion and a note receivable (partnership Contribution receivable) contributed from Conocophillips of an equal amount. For the refining entity, Conocophillips contributed its Wood river and Borger refineries, located in Illinois and Texas, respectively, for a fair value of US$7.5 billion and Encana contributed a note payable (partnership Contribution payable) of US$7.5 billion. In accordance with Canadian GAAp, these entities have been accounted for using the proportionate consolidation method with the results of operations included in the Upstream and refining and Marketing segments (See Note 1). Pa R t n E R Sh iP C O n tRiB Ut i O n R E C E i va B lE This note receivable is denominated in US$ and bears interest at a rate of 5.3 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term partnership Contribution receivable shown in the Consolidated Balance Sheets represent Cenovus’s 50 percent share of this promissory note, net of payments to date. M a n datO Ry R E C E i P t S partnership Contribution receivable–US$ partnership Contribution receivable–C$ equivalent Pa R t n E R Sh iP C O n tRiB Ut i O n Paya B lE 2011 348 346 2012 2013 2014 2015 Thereafter total 366 364 386 384 407 405 429 427 569 565 2,505 2,491 This note payable is denominated in US$ and bears interest at a rate of 6.0 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term partnership Contribution payable amounts shown in the Consolidated Balance Sheets represent Cenovus’s 50 percent share of this promissory note, net of payments to date. M a n datO Ry Pay M E n t S partnership Contribution payable–US$ partnership Contribution payable–C$ equivalent 2011 345 343 2012 366 364 2013 388 386 2014 2015 Thereafter total 412 410 437 435 584 581 2,532 2,519 In addition to the partnership Contribution receivable and payable, Other Assets and Other Liabilities include equal amounts for interest bearing partner loans, with no fixed repayment terms, related to the funding of refining operating and capital requirements. At December 31, 2010 these amounts were $274 million (December 31, 2009–$183 million). 97 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T 12 . InvEnt OrIEs As at December 31, product Upstream – Oil Sands refining and Marketing parts and Supplies 2010 2009 80 779 21 880 84 772 19 875 As a result of a significant decline in commodity prices in the latter half of 2008, Cenovus recorded a write-down of its product inventory by $186 million from cost to net realizable value at December 31, 2008. product turnover and the improvement in commodity prices has resulted in all of the 2008 write-down being reversed, $178 million in 2009 and $8 million in 2010. The total amount of inventories recognized as an expense during the year was $5,997 million (2009–$4,999 million; 2008–$9,322 million). 13. Pr OPErtY, PL Ant AnD E QuIPmEnt , nEt As at December 31, Upstream refining and Marketing Corporate and Eliminations * Depreciation, depletion and amortization 2010 Accumulated DD&A* (12,495) (695) (300) Cost 22,691 5,883 446 29,020 (13,490) net 10,196 5,188 146 15,530 2009 Accumulated DD&A* (11,455) (534) (274) (12,263) Cost 21,550 5,537 390 27,477 Net 10,095 5,003 116 15,214 Upstream property, plant and equipment includes internal costs directly related to exploration, development and construction activities of $102 million (2009–$117 million). Costs classified as general and administrative expenses have not been capitalized as part of the capital expenditures. Costs in respect of significant unproved properties and major development projects are excluded from the country cost centre’s depletable base. refining assets not put into use are excluded from depreciable costs. At the end of the year these costs were: As at December 31, Upstream refining and Marketing 2010 758 1,673 2,431 2009 644 1,366 2,010 2008 278 598 876 CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 98 The Canadian prices used in the ceiling test evaluation of Cenovus’s crude oil and natural gas reserves at December 31, 2010 were: WTI (US$/barrel) AECO ($/Mcf) Crude Oil ($/barrel) Natural Gas Liquids ($/barrel) Natural Gas ($/Mcf) 2011 85.00 4.25 64.75 62.19 4.05 2012 87.70 4.90 66.32 66.27 4.70 2013 90.50 5.40 65.08 68.94 5.20 2014 93.40 5.90 66.59 71.25 5.70 Average Annual % Change to 2022 2015 96.30 6.35 68.71 73.58 6.14 2% 4% 2% 2% 4% During the year ended December 31, 2010, it was determined that a processing unit at the Borger refinery was a redundant asset and would not be used in future operations at the refinery. The fair value of the unit was determined to be negligible based on market prices for refining assets of similar age and condition. Accordingly, the carrying amount of the unit was reduced to zero and an impairment loss of $37 million net to Cenovus, was recorded as additional depreciation, depletion and amortization in the Consolidated Statements of Earnings and Comprehensive Income within the refining and Marketing segment. 14. OtHEr AssEts As at December 31, partner Loans Deferred Asset–refining and Marketing Deferred pension plan and Savings plan Other 15. LOnG- tErm DEB t As at December 31, Canadian Dollar Denominated Debt revolving term debt* U.S. Dollar Denominated Debt revolving term debt* Unsecured notes Total Debt principal Debt Discounts and Transaction Costs Current portion of Long-Term Debt 2010 2009 274 99 11 7 391 183 121 9 7 320 Note 2010 2009 A A B C D – – 3,481 3,481 3,481 (49) – 32 26 3,663 3,689 3,721 (65) – 3,432 3,656 * revolving term debt includes commercial paper, bankers’ acceptances, LIBOr loans, prime rate loans and U.S. base rate loans. The weighted average interest rate on outstanding debt for the year ended December 31, 2010 was 5.8 percent (2009–5.5 percent). 99 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T A) revolving Term Debt At December 31, 2010, Cenovus had in place a committed credit facility in the amount of C$2,500 million or its equivalent amount in U.S. dollars. The committed credit facility matures on November 30, 2014 and is extendable from time to time for a period of up to four years at the option of Cenovus and upon agreement from the lenders. Borrowings are available by way of Bankers Acceptances, LIBOr based loans, prime rate loans or U.S. base rate loans. At December 31, 2010, no amounts were drawn on Cenovus’s committed bank credit facility (2009–$58 million). B) Unsecured Notes In conjunction with the Arrangement, on September 18, 2009 Cenovus completed a private offering of senior unsecured notes of an aggregate principal amount of US$3,500 million. The notes were disclosed on Cenovus’s Consolidated Balance Sheets as a long term liability, net of financing costs as at September 30, 2009. The net proceeds of $3,718 million were placed into an escrow account held by the escrow agent, The Bank of New York Mellon, pending the completion of the Arrangement. Cenovus placed an additional $162 million into the escrow account so that the total escrowed funds of $3,880 million would be sufficient to pay the special mandatory redemption price for the notes if the Arrangement did not proceed. Upon completion of the Arrangement, funds were released from escrow and the proceeds of the notes were used to pay the note payable to Encana of US$3,500 million as part of the Arrangement. On November 30, 2009 these notes became the direct, unsecured obligations of Cenovus. In 2010, substantially all of these notes were exchanged for notes registered under the Securities Act of 1933 with the same terms and conditions as the original issued notes. 4.50% due September 15, 2014 5.70% due October 15, 2019 6.75% due November 15, 2039 us$ Principal Amount 800 1,300 1,400 3,500 2010 796 1,293 1,392 3,481 2009 837 1,361 1,465 3,663 Cenovus has in place a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1,500 million. The Canadian shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other foreign currencies from time to time in one or more offerings. The terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates, will be determined at the date of issue. At December 31, 2010, no medium term notes have been issued under this Canadian prospectus. The shelf prospectus expires in July 2012. time in one or more offerings. The terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates, will be determined at the date of issue. At December 31, 2010, no notes have been issued under this U.S. prospectus. The shelf prospectus expires in August 2012. At December 31, 2010, the Company is in compliance with all of the terms of its debt agreements. C) Debt Discounts and Transaction Costs Cenovus has in place a U.S. base shelf prospectus for unsecured notes in the amount of US$1,500 million. The U.S. shelf prospectus allows for the issuance of debt securities in U.S. dollars or other foreign currencies from time to Long-term debt transaction costs and discounts are recorded within long-term debt and are being amortized using the effective interest method. During 2010, no transaction costs were recorded within long term debt (2009–$70 million). CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 100 D) Mandatory Debt payments 2011 2012 2013 2014 2015 Thereafter As at December 31, Asset retirement Obligation, Beginning of Year Liabilities Incurred Liabilities Settled Liabilities Divested Change in Estimated Future Cash Flows Accretion Expense Foreign Currency Translation Asset retirement Obligation, End of Year US$ principal Amount C$ principal Amount Total C$ Equivalent – – – 800 – 2,700 3,500 – – – – – – – – – – 796 – 2,685 3,481 2009 793 6 (38) (10) 357 45 (6) 2010 1,147 44 (33) (88) 69 75 (1) 1,213 1,147 16. AssEt rEtIrEmEn t OB L IGA tIOn The aggregate carrying amount of the obligation associated with the retirement of upstream oil and gas assets and refining facilities is as follows: The total undiscounted amount of estimated cash flows required to settle the obligation is $6,093 million (2009–$5,683 million), which has been discounted using a weighted average credit-adjusted risk free rate of 6.09 percent (2009–6.23 percent). Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general resources at that time. 17. OtHEr LIABILItIEs As at December 31, partner Loans Deferred revenue Other 2010 2009 274 37 35 346 183 40 16 239 101 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T 18. sHArE CAPIt AL aUt h O Ri Z E d Cenovus is authorized to issue an unlimited number of Common Shares, an unlimited number of First preferred Shares and an unlimited number of Second preferred Shares. i S S U E d a n d O U t S ta n d i n g As at December 31, Outstanding, Beginning of Year Common Shares Issued pursuant to the Arrangement Common Shares Issued under Stock Option plans Outstanding, End of Year To determine Cenovus’s share capital amount at the time of the Arrangement, Encana’s stated capital immediately prior to the Arrangement was split based on the relative fair market values of the Encana and Cenovus Common Shares at the time of the initial exchange. Cenovus’s share capital amount was deducted from Encana’s net investment with the remaining $6,055 million reclassified as paid in Surplus. At December 31, 2010, there were 26 million (2009–24 million) Common Shares available for future issuance under stock option plans. There were no preferred Shares outstanding as at December 31, 2010. The Company has a dividend reinvestment plan (“DrIp”). Under the DrIp, holders of Common Shares may reinvest all or a portion of the cash dividends payable on their Common Shares in additional Common Shares. At the discretion of the Company, the additional Common Shares may be issued from treasury or purchased on the market. n E t i n v E S t M E n t For periods prior to the Arrangement, Encana’s net investment in the operations of Cenovus is presented as total Net Investment in the Consolidated Financial Statements. Total Net Investment consists of Owner’s Net Investment and AOCI. 2010 2009 number of Common shares (thousands) Amount 751,309 3,681 – 1,366 – 35 752,675 3,716 Number of Common Shares (thousands) – 751,273 36 751,309 Amount – 3,680 1 3,681 S tO C k- B a S Ed C O M P En S at iO n A) Employee Stock Option plan Cenovus has an Employee Stock Option plan that provides employees with the opportunity to exercise an option to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, and are fully exercisable after three years. Options granted prior to February 17, 2010 expire after five years while options granted on February 17, 2010 or later expire after seven years. All options issued by the Company under the Employee Stock Option plan have associated tandem stock appreciation rights. In lieu of exercising the options, the tandem stock appreciation rights give the option holder the right to receive a cash payment equal to the excess of the market price of Cenovus’s Common Shares at the time of exercise over the exercise price of the right. The tandem stock appreciation rights vest and expire under the same terms and conditions as the underlying options. For the purpose of this note, options with associated tandem stock appreciation rights are referred to as “TSArs”. CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 102 In addition, certain of the TSArs are performance based (“performance TSArs”). The performance TSArs vest and expire under the same terms and service conditions as the underlying option, and have an additional vesting requirement whereby vesting is subject to achievement of prescribed performance relative to pre-determined key measures. performance TSArs that do not vest when eligible are forfeited. In accordance with the Arrangement described in Note 2, each Cenovus and Encana employee exchanged their original Encana TSAr for one Cenovus replacement TSAr and one Encana replacement TSAr. The terms and conditions of the Cenovus and Encana replacement TSArs are similar to the terms and conditions of the original Encana TSAr. The original exercise price of the Encana TSAr was apportioned to the Cenovus and Encana replacement TSArs based on the one day volume weighted average trading price of Cenovus’s Common Share price relative to that of Encana’s Common Share price on the TSX on December 2, 2009. Cenovus TSArs and Cenovus replacement TSArs are measured against the Cenovus Common Share price while Encana replacement TSArs are measured against the Encana Common Share price. The Cenovus replacement TSArs have similar vesting provisions as outlined above for the Employee Stock Option plan. The original Encana performance TSArs were also exchanged under the same terms as the original Encana TSArs. Unless otherwise indicated, all references to TSArs collectively refer to both the Cenovus issued TSArs and Cenovus replacement TSArs. TSArs Held by Cenovus Employees The following tables summarize the information related to the TSArs held by Cenovus employees as at December 31, 2010: As at December 31, 2010, (thousands of units) Outstanding, Beginning of Year Granted Exercised for cash payment Exercised as options for shares Forfeited Outstanding, End of Year Exercisable, End of Year Performance tsArs tsArs Weighted Average Exercise Price ($) total 8,402 6,087 (1,099) (948) (398) 12,044 4,154 8,053 – (77) (109) (794) 7,073 3,580 16,455 6,087 (1,176) (1,057) (1,192) 19,117 7,734 27.52 26.54 21.32 23.52 28.55 27.75 28.07 (thousands of units) Outstanding tsArs Exercisable tsArs range of Exercise price ($) 20.00 to 24.99 25.00 to 29.99 30.00 to 34.99 35.00 to 39.99 40.00 to 44.99 45.00 to 49.99 Weighted remaining Contractual total Life (Years) Average Weighted Average Exercise Price ($) Performance tsArs tsArs 1,198 8,925 1,733 119 67 2 – 4,694 2,379 – – – 1,198 13,619 4,112 119 67 2 12,044 7,073 19,117 0.25 3.99 2.19 2.44 2.45 2.39 3.35 22.96 26.47 32.87 37.22 43.23 45.56 27.75 Performance tsArs tsArs Weighted Average Exercise Price ($) total 1,172 1,818 1,051 72 40 1 – 2,351 1,229 – – – 1,172 4,169 2,280 72 40 1 4,154 3,580 7,734 22.94 26.59 32.86 37.22 43.23 45.56 28.07 103 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T Cenovus replacement TSArs Held by Encana Employees Encana is required to reimburse Cenovus in respect of cash payments made by Cenovus to Encana’s employees when these employees exercise a Cenovus replacement TSAr for cash. No compensation expense is recognized and no further Cenovus replacement TSArs will be granted to Encana employees. Cenovus has recorded a liability of $123 million (2009–$84 million) in the Consolidated Balance Sheets for Cenovus replacement TSArs held by Encana employees using the fair value method, with an offsetting accounts receivable from Encana. The fair value of each Cenovus replacement TSAr held by Encana employees was estimated using the Black-Scholes-Merton model with weighted average assumptions as follows: risk Free rate Dividend Yield Volatility Cenovus’s Common Share price The following tables summarize information related to the Cenovus replacement TSArs held by Encana employees as at December 31, 2010: 2010 1.70% 2.40% 23.99% $33.28 As at December 31, 2010, (thousands of units) Outstanding, Beginning of Year Exercised for cash payment Exercised as options for shares Forfeited Outstanding, End of Year Exercisable, End of Year Performance tsArs tsArs Weighted Average Exercise Price ($) total 12,482 (3,847) (105) (316) 8,214 5,977 10,463 22,945 (411) (1) (1,111) (4,258) (106) (1,427) 8,940 17,154 4,828 10,805 27.14 22.67 19.44 28.80 28.16 27.88 (thousands of units) Outstanding tsArs Exercisable tsArs range of Exercise price ($) 20.00 to 24.99 25.00 to 29.99 30.00 to 34.99 35.00 to 39.99 40.00 to 44.99 45.00 to 49.99 Performance tsArs tsArs Weighted remaining Contractual total Life (Years) Average Weighted Average Exercise Price ($) 1,658 4,116 2,271 90 77 2 – 6,107 2,833 – – – 1,658 10,223 5,104 90 77 2 8,214 8,940 17,154 0.17 2.19 2.09 2.44 2.44 2.39 1.97 22.95 26.49 32.83 37.24 42.81 45.56 28.16 Performance tsArs tsArs Weighted Average Exercise Price ($) total 1,650 2,711 1,515 54 46 1 – 3,368 1,460 – – – 1,650 6,079 2,975 54 46 1 5,977 4,828 10,805 22.95 26.63 32.74 37.24 42.81 45.56 27.88 CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 104 Encana replacement TSArs Held by Cenovus Employees Cenovus is required to reimburse Encana in respect of cash payments made by Encana to Cenovus employees when a Cenovus employee exercises an Encana replacement TSAr for cash. No further Encana replacement TSArs will be granted to Cenovus employees. The Company has recorded a liability of $24 million (2009–$70 million) in the Consolidated Balance Sheets for Encana replacement TSArs held by Cenovus’s employees using the fair value method. The fair value of each Encana replacement TSAr was estimated using the Black-Scholes-Merton model with weighted average assumptions as follows: risk Free rate Dividend Yield Volatility Encana’s Common Share price The following tables summarize information related to the Encana replacement TSArs held by Cenovus employees as at December 31, 2010: 2010 1.70% 2.74% 23.57% $29.09 As at December 31, 2010, (thousands of units) Outstanding, Beginning of Year Exercised for cash payment Exercised as options for Encana shares Forfeited Outstanding, End of Year Exercisable, End of Year Performance tsArs tsArs Weighted Average Exercise Price ($) total 8,305 (1,568) (94) (214) 6,429 4,461 8,052 (148) – 16,357 (1,716) (94) (806) (1,020) 7,098 3,605 13,527 8,066 30.46 24.43 21.47 31.98 31.17 30.85 (thousands of units) Outstanding tsArs Exercisable tsArs range of Exercise price ($) Performance tsArs tsArs Weighted remaining Contractual total Life (Years) Average Weighted Average Exercise Price ($) 20.00 to 24.99 25.00 to 29.99 30.00 to 34.99 35.00 to 39.99 40.00 to 44.99 45.00 to 49.99 50.00 to 54.99 7 4,371 312 1,597 74 66 2 – 4,718 – 2,380 – – – 7 9,089 312 3,977 74 66 2 6,429 7,098 13,527 2.75 2.04 1.75 2.13 2.49 2.46 2.39 2.06 23.04 28.59 32.61 36.47 42.28 47.86 50.39 31.17 Performance tsArs tsArs Weighted Average Exercise Price ($) total 4 3,127 274 971 45 39 1 – 2,376 – 1,229 – – – 4 5,503 274 2,200 45 39 1 4,461 3,605 8,066 23.06 28.30 32.71 36.47 42.28 47.86 50.39 30.85 105 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T B) performance Share Units The Company has granted performance Share Units (“pSUs”) to certain employees under its performance Share Unit plan for Employees. pSUs are whole share units and entitle employees to receive, upon vesting, either a Common Share of Cenovus or a cash payment equal to the value of a Cenovus Common Share. The number of pSUs eligible for payment is determined over three years based on the units granted multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three, multiplied by a performance multiplier for each year. The multiplier is based on the Company achieving key pre-determined performance measures. pSUs vest after three years. The following table summarizes information related to the pSUs held by Cenovus employees as at December 31, 2010: (thousands) Outstanding, Beginning of Year Granted Cancelled Units in Lieu of Dividends Outstanding, End of Year C) Deferred Share Units Outstanding Psus – 1,252 (35) 35 1,252 Under two Deferred Share Unit plans, Cenovus directors, officers and employees may receive Deferred Share Units (“DSUs”), which are equivalent in value to a Common Share of the Company. Employees have the option to convert either 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment. pursuant to the terms of the Arrangement, Encana DSUs credited to directors, officers and employees of Cenovus were exchanged for Cenovus DSUs. The fair value of the Cenovus DSUs credited to each holder was based on the fair market value of Cenovus Common Shares relative to Encana Common Shares prior to the effective date of the Arrangement. The following table summarizes information related to the DSUs held by Cenovus directors, officers and employees as at December 31, 2010: (thousands) Outstanding, Beginning of Year Granted Granted from Annual Bonus Awards Units in Lieu of Dividends Outstanding, End of Year D) Stock-Based Compensation Expense (recovery) Outstanding Dsus 768 65 81 26 940 The following table summarizes the stock-based compensation expense (recovery) recorded for all plans within operating and general and administrative expenses on the Consolidated Statements of Earnings and Comprehensive Income: TSArs held by Cenovus employees Encana replacement TSArs held by Cenovus employees performance Share Units Deferred Share Units Total stock-based compensation expense (recovery) * 2009 represents one month of compensation expense incurred under the Cenovus plan post Arrangement. CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 106 2010 2009* 2008 52 (23) 13 9 51 (2) 32 – – 30 – – – – – Included in the financial information prior to the Arrangement, the Company recorded compensation expense (recovery) for the following Encana plans: Encana TSArs Encana DSUs Total stock-based compensation expense (recovery) 2010 2009 2008 – – – 4 3 7 (5) 1 (4) 19. CAPIt AL struCtu rE Cenovus’s capital structure is comprised of Shareholders’ Equity plus Debt. Cenovus’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”). These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Debt is defined as the current and long-term portions of long-term debt excluding any amounts with respect to the partnership Contribution payable or receivable. Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAp financial metrics consisting of Debt to Cenovus targets a Debt to Capitalization ratio of between 30 and 40 percent. As at December 31, Debt Shareholders’ Equity Total Capitalization Debt to Capitalization ratio Cenovus targets a Debt to Adjusted EBITDA of between 1.0 and 2.0 times. As at December 31, Debt Net Earnings Add (deduct): Interest, net Income tax expense Depreciation, depletion and amortization Accretion of asset retirement obligation Foreign exchange (gain) loss, net (Gain) loss on divestiture of assets Other (income) loss, net Adjusted EBITDA Debt to Adjusted EBItDA 2010 3,432 10,022 13,454 26% 2009 3,656 818 244 344 1,527 45 304 – (2) 3,280 1.1x 2009 3,656 9,608 13,264 28% 2008 3,719 2,526 233 774 1,397 40 (308) – 3 4,665 0.8x 2010 3,432 993 279 170 1,310 75 (51) 9 (13) 2,772 1.2x 107 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T It is Cenovus’s intention to maintain an investment grade rating to ensure it has continuous access to capital and the financial flexibility to fund its capital programs, meet its financial obligations and finance potential acquisitions. Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity through all stages of the economic cycle. To manage the capital structure, Cenovus may adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt, draw down on its credit facilities or repay existing debt. Cenovus’s capital structure, objectives and targets have remained unchanged since Cenovus’s inception. At December 31, 2010, Cenovus is in compliance with all of the terms of its debt agreements. 20. PEnsIOns AnD O tHEr P O st- EmPLOYmEn t BEnEFIts The Company provides employees with a pension plan that includes defined contribution and defined benefit components, and other post-employment benefit plans (“OpEB”). Most of the employees participate in the defined contribution pension; the defined benefit pension component is closed to new entrants. The Company files an actuarial valuation of its pension plans with the provincial regulator at least every three years. The most recently filed valuation was dated November 30, 2009 and the next required actuarial valuation will be as at December 31, 2012. Information related to defined benefit pension and OpEB plans, based on actuarial estimations is as follows: As at December 31, Accrued Benefit Obligation, End of Year Fair Value of plan Assets, End of Year Funded Status–plan Assets (less) than Benefit Obligation Amounts Not recognized: Unamortized net actuarial (gain) loss Unamortized past service cost Accrued Benefit Asset (Liability) The weighted average assumptions used to determine benefit obligations are as follows: As at December 31, Discount rate rate of Compensation Increase Estimated future payment of pension and other benefits are as follows: 2011 2012 2013 2014 2015 2016 – 2020 Total pension Benefits OpEB 2010 2009 2010 2009 68 59 (9) 20 – 11 56 54 (2) 15 – 13 14 – (14) 1 – (13) 11 – (11) (1) 1 (11) pension Benefits 2010 2009 5.25% 4.05% 6.00% 4.05% OpEB 2010 5.25% 5.65% 2009 6.00% 5.77% pension Benefits OpEB 1 2 2 3 4 23 35 – – 1 1 1 9 12 CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 108 21. FInAnCIAL Instru mEn ts AnD rIsk mAnAGEmEn t Cenovus’s consolidated financial assets and liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, partnership Contribution receivable and payable and partner loans, risk management assets and liabilities, and long-term debt. risk management assets and liabilities arise from the use of derivative financial instruments. Fair values of financial assets and liabilities, summarized information related to risk management positions, and discussion of risks associated with financial assets and liabilities are presented as follows. risk management assets and liabilities are recorded at their estimated fair value based on mark-to-market accounting, using quoted market prices or, in their absence, third-party market indications and forecasts. Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on market information. At December 31, 2010, the carrying value of Cenovus’s long-term debt accounted for using amortized cost was $3,432 million and the fair value was $3,940 million (December 31, 2009–carrying value–$3,656 million, fair value–$3,964 million). A) Fair Value of Financial Assets and Liabilities B) risk Management Assets and Liabilities The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amount due to the short-term maturity of those instruments. The fair values of the partnership Contribution receivable and partnership Contribution payable and partner loans approximate their carrying amount due to the specific non-tradeable nature of these instruments. Under the terms of the Arrangement with Encana, the risk management positions at November 30, 2009 were allocated to Cenovus based upon Cenovus’s proportion of the related volumes covered by the contracts. To effect the allocation, Cenovus entered into a contract with Encana with the same terms and conditions as between Encana and the third parties to the existing contracts. All positions entered into after the Arrangement have been negotiated between Cenovus and third parties. Net risk Management position As at December 31, risk Management Current asset Long-term asset risk Management Current liability Long-term liability Net risk Management Asset (Liability) 2010 2009 163 43 206 163 10 173 33 60 1 61 70 4 74 (13) Of the $33 million net risk management asset balance at December 31, 2010, an asset of $41 million relates to the contract with Encana (2009–net liability of $15 million). Summary of Unrealized risk Management positions As at December 31, Commodity prices Crude Oil Natural Gas power Total Fair Value 2010 risk management 2009 risk Management Asset Liability net Asset Liability Net 4 202 – 206 159 – 14 173 (155) 202 (14) 33 8 53 – 61 66 – 8 74 (58) 53 (8) (13) 109 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T Net Fair Value Methodologies Used to Calculate Unrealized risk Management positions As at December 31, prices actively quoted prices sourced from observable data or market corroboration Total Fair Value 2010 2009 40 (7) 33 6 (19) (13) prices actively quoted refers to the fair value of contracts valued using quoted prices in an active market. prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Net Fair Value of Commodity price positions at December 31, 2010 As at December 31, 2010, Crude Oil Contracts Fixed price Contracts WTI NYMEX Fixed price WTI NYMEX Fixed price WTI NYMEX Fixed price WTI NYMEX Fixed price Other Fixed price Contracts * Other Financial positions ** Crude Oil Fair Value position natural Gas Contracts Fixed price Contracts NYMEX Fixed price NYMEX Fixed price AECO Fixed price Other Fixed price Contracts * Natural Gas Fair Value position Power Purchase Contracts power Fair Value position Notional Volumes Term Average price Fair value 28,600 bbls/d 29,200 bbls/d 5,000 bbls/d 3,000 bbls/d 2011 2011 2012 2012 2011 US$85.54/bbl C$88.32/bbl US$92.44/bbl C$93.82/bbl 379 MMcf/d 130 MMcf/d 80 MMcf/d 2011 2012 2012 US$5.70/Mcf US$5.96/Mcf C$4.49/Mcf 2011-2013 (85) (58) (3) (1) 4 (12) (155) 158 41 – 3 202 (14) * Cenovus has entered into fixed priced swaps to protect against widening price differentials between production areas in Canada and various sales points. ** Other financial positions are part of ongoing operations to market the Company’s production. CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 110 Earnings Impact of realized and Unrealized Gains (Losses) on risk Management positions For the years ended December 31, Gross revenues Less: royalties Net revenues Operating Expenses and Other Gain (Loss) on risk Management For the years ended December 31, Gross revenues Less: royalties Net revenues Operating Expenses and Other Gain (Loss) on risk Management reconciliation of Unrealized risk Management positions For the years ended December 31, Fair Value of Contracts, Beginning of Year Change in Fair Value of Contracts in place at Beginning of Year and Contracts Entered into During the Year Fair Value of Contracts realized During the Year Fair Value of Contracts, End of Year Commodity price Sensitivities – risk Management positions realized Gain (Loss) 2010 2009 2008 272 – 272 6 278 1,154 – 1,154 (38) 1,116 (305) – (305) 31 (274) Unrealized Gain (Loss) 2010 2009 2008 60 – 60 (14) 46 (668) – (668) (30) (698) 890 – 890 9 899 2010 total unrealized Gain (Loss) 2009 2008 Total Unrealized Gain (Loss) Total Unrealized Gain (Loss) 324 (278) 46 418 (1,116) (698) 625 274 899 Fair value (13) 324 (278) 33 The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. When assessing the potential impact of these commodity price changes, Management believes 10 percent volatility is a reasonable measure. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting earnings before income tax at December 31, 2010 as follows: Crude oil price Natural gas price power price 10% Price Increase 10% Price Decrease (227) (104) 6 227 104 (6) 111 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T C) risks Associated with Financial Assets and Liabilities Commodity Price Risk Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is not to use derivative financial instruments for speculative purposes. Crude Oil – The Company has partially mitigated its exposure to the commodity price risk on its crude oil sales and condensate supply used for blending with fixed price swaps. To help protect against widening crude oil price differentials in various production areas, Cenovus has entered into a limited number of swaps to manage the price differentials between these production areas and various sales points. Natural Gas – To partially mitigate the natural gas commodity price risk, the Company has entered into swaps, which fix the NYMEX and AECO prices. To help protect against widening natural gas price differentials in various production areas, Cenovus has entered into a limited number of swaps to manage the price differentials between these production areas and various sales points. power – The Company has in place two Canadian dollar denominated derivative contracts, which commenced January 1, 2007 for a period of 11 years, to manage its electricity consumption costs. Credit Risk Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company’s credit portfolio and with credit practices that limit transactions according to counterparties’ credit quality. Agreements are entered into with major financial institutions with investment grade credit ratings or with counterparties having investment grade credit ratings. A substantial portion of Cash outflows relating to financial liabilities are outlined in the table below: Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2010, over 92 percent (2009–98 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties. At December 31, 2010, Cenovus had two counterparties whose net settlement position individually account for more than 10 percent (2009– three counterparties, including Encana) of the fair value of the outstanding in-the-money net financial and physical contracts by counterparty. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets and the partnership Contribution receivable and the partner loans receivable is the total carrying value. The current concentration of this credit risk resides with A rated or higher counterparties. Cenovus’s exposure to its counterparties is acceptable and within Credit policy tolerances. liquidity Risk Liquidity risk is the risk that Cenovus will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt. As disclosed in Note 19, Cenovus targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times to manage the Company’s overall debt position. It is Cenovus’s intention to maintain investment grade credit ratings on its senior unsecured debt. Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facilities, commercial paper and availability under its shelf prospectuses. At December 31, 2010, Cenovus’s committed credit facility was fully available. In addition Cenovus had $1,500 million in unused capacity under its Canadian shelf prospectus and US$1,500 million in unused capacity under its U.S. shelf prospectus, the availability of which are dependent on market conditions. Accounts payable and Accrued Liabilities risk Management Liabilities Long-Term Debt (1) (2) partnership Contribution payable (1) partner Loans payable (1) principal and interest, including current portion (2) No principal repayment until 2014 and thereafter (see Note 15D) Less than 1 Year 1 - 3 Years 4 - 5 Years Thereafter 1,825 163 203 486 – – 10 407 972 274 – – 1,167 972 – – – 5,236 609 – total 1,825 173 7,013 3,039 274 CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 112 Foreign Exchange Risk Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollars can have a significant effect on reported results. Cenovus’s functional currency and reporting currency is Canadian dollars. All amounts are reported in Canadian dollars, unless otherwise indicated. As disclosed in Note 9, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada and the translation of the U.S. dollar partnership Contribution receivable issued from Canada. At December 31, 2010, Cenovus had US$3,500 million in U.S. dollar debt issued from Canada (US$3,525 million at December 31, 2009) and US$2,505 million related to the U.S. dollar partnership Contribution receivable (US$2,834 million at December 31, 2009). A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $10 million change in foreign exchange (gain) loss at December 31, 2010 (2009–$7 million). interest Rate Risk Interest rate risk arises from changes in market interest rates that may affect the earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. At December 31, 2010, one hundred percent of the Company’s debt was fixed- rate debt and as a result, had interest rates on floating rate debt changed by one percent there would be no impact on net earnings (December 31, 2009–$nil; 2008–$5 million). This assumes the amount of fixed and floating debt remains unchanged from December 31, 2010. 22 . s uPPLEmEnt Ar Y InFOr mA tIOn A) per Share Amounts For the years ended December 31, (millions) Weighted Average Common Shares Outstanding – Basic Effect of Stock Options and Other Dilutive Securities Weighted Average Common Shares Outstanding – Diluted 2010 751.9 0.8 752.7 2009 751.0 0.4 751.4 Since Cenovus’s shares were issued pursuant to the Arrangement, the per share amounts disclosed for 2009 and 2008 are based on the number of Encana’s Common Shares outstanding. B) Supplementary Cash Flow Information For the years ended December 31, Interest paid Income Taxes paid 2010 423 62 2009 426 1,284 Income taxes paid in 2009 includes amounts paid to Encana as a result of the dissolution of a partnership in connection with the Arrangement. 2008 750.1 1.7 751.8 2008 422 542 113 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T 23. COmmItmEnts AnD COn tInGEnC IEs A) Commitments As part of normal operations, the Company has committed to certain amounts over the next five years and thereafter as follows: 2011 2012 2013 2014 2015 Thereafter Total Operating Leases (Building Leases) pipeline Transportation (1) purchases of Goods and Services Capital Commitments product purchases Other Long-Term Commitments Total payments product Sales 33 107 157 91 23 4 415 50 (1) Certain transportation commitments included are subject to regulatory approval At December 31, 2010, there were outstanding letters of credit aggregating $23 million issued as security for performance under certain contracts (2009–$13 million). In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 21. B) Contingencies legal Proceedings Cenovus is involved in various legal claims associated with the normal course of operations. Cenovus believes it has made adequate provisions for such legal claims. 85 167 10 4 18 1 285 56 78 166 7 4 18 – 273 57 1,553 953 23 14 7 1 2,551 63 1,924 1,653 232 188 102 9 4,108 332 87 93 23 71 18 2 294 52 88 167 12 4 18 1 290 54 asset Retirement Cenovus is responsible for the retirement of long-lived assets related to its oil and gas properties, refining facilities and midstream facilities at the end of their useful lives. Cenovus has recognized a liability of $1,218 million, including $5 million that has been classified as Liabilities related to Assets Held for Sale, based on current legislation and estimated costs. Actual costs may differ from those estimated due to changes in legislation and changes in costs. income tax Matters The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate. 24. unItED st AtEs ACCOun tInG PrInCI PLEs AnD rE P OrtInG The Cenovus Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAp”) which, in most respects, conform to accounting principles generally accepted in the United States (“U.S. GAAp”). The significant differences between Canadian GAAp and U.S. GAAp applicable to Cenovus are described in this note. The most notable differences are: • full cost accounting; • pensions and other post-employment benefits; • liability-based stock compensation plans; • income taxes; • other comprehensive income; and • joint venture accounting. CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 114 R E C O n C i l i at i O n O F n E t E a R n i n g S U n d E R C a n a d i a n g a a P t O U . S . g a a P For the years ended December 31, Net Earnings–Canadian GAAp Increase (Decrease) in Net Earnings Under U.S. GAAp: Operating expense Depreciation, depletion and amortization expense General and administrative expense Stock-based compensation expense Income tax expense Net Earnings–U.S. GAAp Note 24 C ii) A, C ii) C ii) D C O n S O l i dat E d S tat E M E n t S O F E a R n i n g S a n d C O M P R E h E n S i v E i n C O M E – U . S . g a a P For the years ended December 31, Note 24 Gross revenues Less: royalties Net revenues Expenses production and mineral taxes Transportation and blending Operating purchased product Depreciation, depletion and amortization General and Administrative Interest, net Accretion of asset retirement obligation Foreign exchange (gain) loss, net Stock-based compensation–options (Gain) loss on divestiture of assets Other (income) loss, net Earnings Before Income Tax Income tax expense Net Earnings – U.S. GAAp Other Comprehensive Income (Loss), Net of Tax Foreign Currency Translation Adjustment Compensation plans Comprehensive Income C ii) A, C ii) C ii) D 2010 993 9 107 11 – (87) 1,033 2010 13,422 449 12,973 34 1,065 1,293 7,549 1,203 240 279 75 (51) – 9 (13) 11,683 1,290 257 1,033 (13) (7) 1,013 2009 818 4 239 9 – (199) 871 2009 11,790 273 11,517 44 760 1,308 5,910 1,288 202 244 45 304 – – (2) 10,103 1,414 543 871 (238) 32 665 2008 2,526 (13) 21 (17) 1 (138) 2,380 2008 18,103 533 17,570 80 1,021 1,305 10,341 1,376 188 233 40 (308) (1) – 3 14,278 3,292 912 2,380 347 (9) 2,718 115 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T C O n d E n S E d C O n S O l i dat E d B a l a n C E S h E E t S – U . S . g a a P As at December 31, Assets Current Assets Assets Held for Sale 2010 2009 Note 24 As reported u.s. GAAP As reported U.S. GAAp 2,775 65 2,775 65 2,453 – 2,453 – property, plant and Equipment A, B, C ii) (includes unproved properties and major development projects of $2,428 and $2,010 as of December 31, 2010 and 2009, respectively) Accumulated Depreciation, Depletion and Amortization property, plant and Equipment, net (Full Cost Method for Oil and Gas Activities) partnership Contribution receivable risk Management Other Assets Goodwill Liabilities and Shareholders’ Equity Current Liabilities Liabilities related to Assets Held for Sale Long-Term Debt partnership Contribution payable risk Management Asset retirement Obligation Other Liabilities Deferred Income Taxes Shareholders’ Equity 29,020 (13,490) 28,997 (14,045) 15,530 14,952 2,145 43 391 1,146 2,145 43 390 1,146 27,477 (12,263) 15,214 2,621 1 320 1,146 27,455 (12,925) 14,530 2,621 1 319 1,146 22,095 21,516 21,755 21,070 2,485 7 3,432 2,176 10 1,213 346 2,404 12,073 10,022 22,095 2,644 7 3,432 2,176 10 1,213 348 2,331 12,161 9,355 21,516 1,984 – 3,656 2,650 4 1,147 239 2,467 12,147 9,608 21,755 2,098 – 3,656 2,650 4 1,147 239 2,368 12,162 8,908 21,070 C i) C i), C ii), D C i), C ii) D E CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 116 C O n d E n S E d C O n S O l i dat E d S tat E M E n t S O F C a S h F lOW S – U . S . g a a P For the years ended December 31, Operating Activities Net earnings Depreciation, depletion and amortization Deferred income taxes Unrealized (gain) loss on risk management Unrealized foreign exchange (gain) loss Accretion of asset retirement obligation (Gain) loss on divestiture of assets Other (income) loss, net Net change in other assets and liabilities Net change in non-cash working capital Cash From Operating Activities Cash (Used in) Investing Activities Net Cash provided before Financing Activities Cash From (Used in) Financing Activities n Ot E S A) Full Cost Accounting Under U.S. GAAp, a ceiling test is applied to ensure the unamortized capitalized costs in a cost centre do not exceed the sum, net of applicable income taxes, of the present value, discounted at 10 percent, of the estimated future net revenues calculated on the basis of estimated value of future production from proved reserves using oil and gas prices at the balance sheet date, less related unescalated estimated future development and production costs, plus unimpaired unproved property costs. For 2010 and 2009, depletion charges under U.S. GAAp were also calculated by reference to proved reserves estimated using an average price for the prior 12-month period. For 2008, depletion charges under U.S. GAAp were calculated by reference to proved reserves estimated using oil and gas prices at the balance sheet date. Under Canadian GAAp, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecast pricing and future development and production costs to determine whether impairment exists. The impairment amount is measured using the fair value of proved and probable reserves. Depletion charges under Canadian GAAp are also calculated by reference to proved reserves estimated using estimated future prices and costs. At December 31, 2008, Cenovus’s capitalized costs of oil and gas properties in Canada exceeded the full cost ceiling resulting in a non-cash U.S. GAAp write-down of $73 million charged to DD&A. Additional depletion was also recorded in certain prior years, as a result of ceiling test differences between Canadian GAAp and U.S. GAAp. As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAp purposes. 2010 2009 2008 1,033 1,203 116 (46) (69) 75 9 35 (55) 293 2,594 (1,796) 798 (631) 871 1,288 (396) 698 327 45 – 7 (26) 225 3,039 (2,063) 976 (977) 2,380 1,376 554 (899) (317) 40 – (20) (92) 202 3,224 (2,109) 1,115 (1,226) The U.S. GAAp adjustment for the difference in depletion calculations resulted in a decrease to DD&A of $107 million (2009–$237 million; 2008–$98 million). B) property, plant and Equipment Allocation For periods prior to the Arrangement, net property, plant and equipment related to Canadian upstream oil and gas activities have been allocated for U.S. GAAp carve-out purposes using the same methodology as the carve-out allocation for Canadian GAAp purposes. The balances related to Canadian upstream operations have been allocated between Cenovus and Encana in accordance with the CICA Handbook Accounting Guideline AcG-16, based on the ratio of future net revenue, discounted at 10 percent, of the properties carved out to the discounted future net revenue of all proved properties in Canada using the reserve reports dated December 31, 2008. Future net revenue is the estimated net amount to be received with respect to development and production of crude oil and natural gas reserves, the value of which has been determined by independent qualified reserve evaluators. C) Compensation plans i) pensions and Other post-Employment Benefits Under U.S. GAAp, ASC 715-30, “Compensation – retirement Benefits”, requires Cenovus to recognize the over-funded or under-funded status of defined benefit and post-employment plans on the balance sheet as an asset or liability and to recognize changes in the funded status through Other Comprehensive Income. Canadian GAAp does not require the recognition of the funded status of these plans on its balance sheet. 117 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T ii) Liability-Based Stock Compensation plans D) Income Taxes Under Canadian GAAp, obligations for liability-based stock compensation plans are recorded using the intrinsic-value method of accounting. For U.S. GAAp purposes, Cenovus adopted ASC 718, “Compensation – Stock Compensation” for the year ended December 31, 2006 using the modified- prospective approach. Under ASC 718, liability-based stock compensation plans, including tandem share appreciation rights, performance tandem share appreciation rights, share appreciation rights and performance share appreciation rights, are required to be re-measured at fair value at each reporting period up until the settlement date. To the extent compensation cost relates to employees directly involved in crude oil and natural gas development activities, certain amounts are capitalized to property, plant and equipment. Amounts not capitalized are recognized as administrative expenses or operating expenses. The current period adjustments have the following impact: • Net property, plant and equipment decreased by $1 million (2009– $25 million decrease) • Current liabilities decreased by $14 million (2009–$41 million decrease) • Other liabilities decreased by $7 million (2009–$1 million increase) • Operating expenses decreased by $9 million (2009–$4 million decrease) • Administrative expenses decreased by $11 million (2009–$9 million decrease) • No adjustment was made to depreciation, depletion and amortization expenses (2009–$2 million decrease) U.S. GAAp uses enacted tax rates and legislative changes to calculate current and deferred income taxes, whereas Canadian GAAp uses substantively enacted tax rates and legislative changes. In 2009, Cenovus incurred losses in one of its subsidiary companies which were recognized and included in calculating future income taxes for Canadian GAAp purposes on the basis that the tax legislative changes were substantially enacted. For U.S. GAAp, these losses were not recognized as the tax legislative changes were not enacted by December 31, 2009 nor December 31, 2010. There was no additional impact to income tax expense in 2010 (2009–$131 million, 2008– nil). In 2010 some of these losses were claimed to reduce the current taxes payable under Canadian GAAp. For U.S. GAAp the losses were not available and the current tax payable increased by $59 million offset by a decrease to the deferred income tax payable with no impact on total tax expense. The remaining differences resulted from the deferred income tax adjustments included in the reconciliation of Net Earnings under Canadian GAAp to U.S. GAAp and the Condensed Consolidated Balance Sheet include the effect of such rate differences, if any, as well as the tax effect of the other reconciling items noted. The following table provides a reconciliation of the statutory rate to the actual tax rate: For the years ended December 31, Earnings Before Income Tax–U.S. GAAp Canadian Statutory rate Expected Income Tax Effect on Taxes resulting from: Statutory and other rate differences Non-deductible stock-based compensation Multi-jurisdictional financing Foreign exchange gains not included in net earnings Non-taxable capital (gains) losses recognition of capital losses Unrecognized non-capital losses Other Income Tax–U.S. GAAp Effective Tax rate 2010 1,290 28.2% 364 (36) 32 (93) 28 (9) (107) – 78 257 19.9% 2009 1,414 29.2% 413 (7) – (134) 58 30 – 131 52 543 38.4% 2008 3,292 29.7% 977 (88) – (135) 71 (53) – – 140 912 27.7% CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 118 The net deferred income tax liability consists of: As at December 31, Deferred Tax Liabilities property, plant and equipment in excess of tax values Timing of partnership items Net foreign exchange gains risk management Other Deferred Tax Assets Unused tax losses risk management Other Net Deferred Income Tax Liability E) Other Comprehensive Income 2010 2009 2,390 2,407 125 127 55 55 (209) (45) (167) 2,331 9 – 17 79 (111) (33) – 2,368 ASC 715-30 requires a change in the funded status of defined benefit and post-employment plans to be recognized on the balance sheet and changes in the funded status through other comprehensive income. In 2010, a loss of $7 million, net of tax was recognized in other comprehensive income (2009– gain of $32 million) as noted in D i). On adoption of ASC 715-30, as required, the transitional amount of $24 million, net of tax was booked directly to Accumulated Other Comprehensive Income. F) Joint Venture with Conocophillips Under Canadian GAAp, the refining operations that are jointly controlled are proportionately consolidated. U.S. GAAp requires the refining operations be accounted for using the equity method. However, under an accommodation of the U.S. Securities and Exchange Commission, accounting for jointly controlled investments does not require reconciliation from Canadian to U.S. GAAp if the joint venture is jointly controlled by all parties having an equity interest in the entity, which is the case for the refining operations. Equity accounting for the refining operations would have no impact on Cenovus’s net earnings or retained earnings. As required, the following disclosures are provided for the refining operations of the joint venture. C O n S O l i dat E d S tat E M E n t S O F E a R n i n g S For the years ended December 31, Operating Cash Flow (See Note 1) Depreciation, depletion and amortization Other Net Earnings (Loss) C O n S O l i dat E d B a l a n C E S h E E t S As at December 31, Current Assets Long-term Assets Current Liabilities Long-term Liabilities C O n S O l i dat E d S tat E M E n t S O F C a S h F lOW S For the years ended December 31, Cash From (Used in) Operating Activities Cash From (Used in) Investing Activities 2010 2009 67 (229) (12) (174) 2010 951 5,275 559 327 2010 117 (657) 358 (220) (12) 126 2009 808 5,104 511 410 2009 (62) (1,034) 119 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T SUP PlEMEntal inFORMatiOn (UnaUd i tEd) For the period ended December 31, 2010 Canadian Dollars/Canadian protocol F I nAn C I A L s tAt I s t I C s (C$ millions, except per share amounts) Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 2010 2009 Gross revenues Less: royalties Net revenues Operating Cash Flow Crude Oil and Natural Gas Liquids Foster Creek and Christina Lake pelican Lake Conventional Natural Gas Other Upstream Operations refining and Marketing Operating Cash Flow Cash Flow Information Cash from Operating Activities Deduct (Add back): Net change in other assets and liabilities Net change in non-cash working capital Cash Flow (1) per share – Basic – Diluted Operating Earnings (2) per share – Diluted Net Earnings per share – Basic – Diluted Effective Tax rates using Net Earnings Operating Earnings, excluding divestitures Canadian Statutory rate Foreign Exchange rates (US$ per C$1) Average period end 13,422 449 3,280 108 3,222 107 3,318 123 3,602 111 11,790 273 3,103 98 3,080 79 2,871 53 2,736 43 12,973 3,172 3,115 3,195 3,491 11,517 3,005 3,001 2,818 2,693 765 287 751 1,081 16 2,900 75 2,975 195 58 175 253 6 687 125 812 179 71 191 246 – 687 (27) 660 176 71 163 268 7 685 (20) 665 215 87 222 314 3 841 (3) 838 663 302 753 2,061 42 3,821 368 4,189 232 84 203 412 10 941 13 954 198 98 218 500 22 1,036 98 162 75 199 555 4 995 178 1,134 1,173 71 45 133 594 6 849 79 928 2,594 658 645 471 820 3,039 150 1,414 793 682 (14) 24 (13) 149 (13) (53) (15) 114 648 0.86 0.86 140 0.19 73 0.10 0.10 509 0.68 0.68 159 0.21 223 0.30 0.30 537 0.71 0.71 142 0.19 172 0.23 0.23 721 0.96 0.96 353 0.47 525 0.70 0.70 (55) 234 2,415 3.21 3.21 794 1.06 993 1.32 1.32 14.6% 21.7% 28.2% (26) 220 2,845 3.79 3.79 1,522 2.03 818 1.09 1.09 29.6% 25.0% 29.2% (14) (71) 235 0.31 0.31 169 0.23 42 0.06 0.06 (3) 493 924 1.23 1.23 427 0.57 101 0.13 0.13 (6) (146) 945 1.26 1.26 512 0.68 160 0.21 0.21 (3) (56) 741 0.99 0.99 414 0.55 515 0.69 0.69 0.971 1.005 0.987 1.005 0.962 0.971 0.973 0.943 0.961 0.985 0.876 0.956 0.947 0.956 0.911 0.933 0.857 0.860 0.803 0.794 (1) Cash Flow is a non-GAAp measure defined as Cash from Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows. (2) Operating Earnings is a non-GAAp measure defined as Net Earnings excluding after tax gain/loss on discontinuance, after-tax gain on bargain purchase, after-tax effect of unrealized mark-to-market accounting gains/losses on derivative instruments, after-tax gains/losses on translation of U.S. dollar denominated Notes issued from Canada, after-tax foreign exchange gains/losses on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates. CENOVUS 201 0 A NNUA L rEpOr T · S Up pL EM E NTA L I N FOrMATI ON ( UN AUDITED) · 120 F I n A n C I A L s tAt I s t I C s ( C O n t I n u E D ) Financial metrics (non-GAAP measures) Debt to Capitalization (1) (2) Debt to Adjusted EBITDA (2) (3) return on Capital Employed (4) return on Common Equity (5) 2010 2009 26% 1.2x 9% 10% 28% 1.1x 8% 8% (1) Capitalization is a non-GAAp measure defined as long-term debt including current portion plus Shareholders’ Equity. (2) Debt is defined as the current and long-term portions of long-term debt. (3) Adjusted EBITDA is a non-GAAp measure defined as adjusted earnings before interest, income taxes, DD&A, accretion of asset retirement obligations, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss). (4) Calculated, on a trailing twelve-month basis, as net earnings before after tax interest divided by average shareholder’s equity plus average debt, including current portion. (5) Calculated, on a trailing twelve-month basis, as net earnings divided by average shareholder’s equity. Common Share Information Common Shares Outstanding (millions) (1) period end Average – Basic Average – Diluted price range ($ per share) TSX – C$ High Low Close NYSE – US$ High Low Close Dividends paid ($ per share) (2) Share Volume Traded (millions) Year Q4 2010 Q3 Q2 Q1 December 2009 752.7 751.9 752.7 752.7 752.2 752.7 752.0 751.9 752.0 751.8 751.7 751.8 751.7 751.5 751.7 33.40 24.26 33.28 33.40 28.31 33.28 31.00 26.19 29.59 30.63 25.83 27.40 27.84 24.26 26.53 33.37 27.78 33.24 33.37 22.87 33.24 26.79 30.12 22.87 24.61 26.21 28.77 C$0.80 C$0.20 C$0.20 C$0.20 C$0.20 204.5 188.0 30.66 23.84 25.79 787.7 241.9 153.3 751.3 751.0 751.4 27.18 24.68 26.50 25.70 23.37 25.20 US$0.20 83.5 (1) Cenovus Common Shares were issued under the terms of the plan of arrangement with Encana Corporation (“Arrangement”) on November 30, 2009 and began trading on December 3, 2009 (TSX) and December 9, 2009 (NYSE). (2) Dividend paid in December 2009 reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flows. 121 · SUppLEMENTAL INFOrMATION (UNAUDITED) · CENOVU S 2010 A NNU AL rEpOr T F I n A n C I A L s tAt I s t I C s ( C O n t I n u E D ) Net Capital Investment (C$ millions) Capital Investment Upstream Foster Creek Christina Lake Total pelican Lake Other Oil Sands Conventional refining and Marketing Corporate Capital Investment Acquisitions Divestitures Net Acquisition and Divestiture Activity 2010 2009 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 278 346 624 104 139 523 1,390 656 76 2,122 86 (307) (221) 110 106 216 37 60 216 529 139 38 706 48 5 53 59 93 152 17 17 136 322 147 11 480 4 (168) (164) 52 84 136 28 19 68 251 166 26 443 34 (72) (38) 57 63 120 22 43 103 288 204 1 493 – (72) (72) 421 262 224 486 72 71 466 1,095 1,033 34 2,162 148 (367) 76 66 142 13 5 97 257 229 21 507 146 (366) (219) (220) 62 53 115 12 5 91 223 291 1 515 1 2 3 59 49 108 16 15 83 222 264 2 488 1 (3) (2) 65 56 121 31 46 195 393 249 10 652 – – – 1,943 287 518 486 652 Net Capital Investment 1,901 759 316 405 O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s Upstream production Volumes Crude Oil and Natural Gas Liquids (bbls/d) (1) Oil Sands – Heavy Foster Creek Christina Lake Total pelican Lake Other (including Senlac) Conventional Liquids Heavy Oil Light and Medium Oil Natural Gas Liquids (2) 2010 2009 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 51,147 7,898 52,183 8,606 50,269 7,838 59,045 60,789 21,738 22,966 – – 58,107 23,259 – 51,010 7,716 58,726 23,319 – 51,126 7,420 58,546 23,565 – 37,725 6,698 44,423 24,870 3,057 47,017 7,319 40,367 6,305 54,336 23,804 2,221 46,672 25,671 5,080 34,729 6,530 41,259 23,989 2,574 28,554 6,635 35,189 26,029 2,334 82,011 82,527 81,366 82,045 82,111 72,350 80,361 77,423 67,822 63,552 16,659 29,346 1,171 16,553 29,323 1,190 16,921 28,608 1,172 16,205 29,150 1,166 16,962 30,320 1,156 17,888 30,394 1,206 17,127 30,644 1,183 18,073 29,749 1,242 18,074 30,189 1,184 18,290 31,004 1,213 Total Crude Oil and Natural Gas Liquids 129,187 129,593 128,067 128,566 130,549 121,838 129,315 126,487 117,269 114,059 Natural Gas (MMcf/d) Oil Sands Conventional Total Natural Gas production 43 694 737 39 649 688 44 694 738 46 705 751 45 730 775 53 784 837 47 750 797 55 775 830 57 799 856 52 814 866 (1) Certain volumes for prior periods have been reclassified to conform to current liquids classification. (2) Natural gas liquids include condensate volumes. CENOVUS 201 0 A NNUA L rEpOr T · S Up pL EM E NTA L I N FOrMATI ON ( UN AUDITED) · 122 O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s ( C O n t I n u E D ) Average royalty rates (excluding impact of realized financial hedging) Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 2010 2009 Oil sands Foster Creek Christina Lake pelican Lake Conventional Weyburn Other Natural Gas Liquids natural Gas refining refinery Operations (1) Crude oil capacity (Mbbls/d) Crude oil runs (Mbbls/d) Crude utilization (%) refined products (Mbbls/d) (1) represents 100% of the Wood river and Borger refinery operations. Selected Average Benchmark prices Crude Oil Prices (US$/bbl) West Texas Intermediate (“WTI”) Western Canada Select (“WCS”) Differential – WTI/WCS Condensate – (C5 @ Edmonton) Differential – WTI/Condensate (premium)/discount refining margins 3-2-1 Crack spreads (1) (US$/bbl) Chicago Midwest Combined (Group 3) natural Gas Prices AECO ($/GJ) NYMEX (US$/MMBtu) Differential – NYMEX/AECO (US$/MMBtu) 16.2% 3.9% 21.1% 20.4% 3.6% 21.2% 17.9% 3.9% 18.5% 19.0% 4.4% 23.3% 9.7% 4.0% 21.4% 2.7% 2.3% 20.1% 3.9% 3.6% 19.3% 3.0% 2.9% 20.0% 1.5% 1.6% 19.9% 22.2% 8.2% 1.9% 18.8% 7.2% 1.0% 23.2% 7.1% 2.4% 23.3% 9.1% 2.0% 23.3% 9.1% 2.1% 19.7% 7.2% 1.6% 27.8% 8.4% 1.6% 19.9% 9.1% 2.1% 17.2% 6.6% 1.9% 1.4% 1.0% 21.7% 10.3% 2.4% 1.0% 1.6% 1.7% 2.4% 1.7% 2.8% 1.5% 3.9% 0.5% –0.9% 2.8% 2010 2009 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 452 386 86% 405 452 410 91% 434 452 401 89% 409 452 379 84% 398 452 355 79% 377 452 394 87% 417 452 348 77% 370 452 425 94% 451 452 404 89% 428 452 398 88% 421 2010 2009 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 79.61 65.38 14.23 81.91 85.24 67.12 18.12 85.24 76.21 60.56 15.65 74.53 78.05 63.96 14.09 82.87 78.88 69.84 9.04 84.98 62.09 52.43 9.66 61.35 76.13 64.01 12.12 74.42 68.24 58.06 10.18 65.76 59.79 52.37 7.42 58.07 43.31 34.38 8.93 46.26 (2.30) – 1.68 (4.82) (6.10) 0.74 1.71 2.48 1.72 (2.95) 9.33 9.48 9.25 9.12 10.34 10.60 11.60 11.38 3.91 4.39 0.40 3.39 3.80 0.28 3.52 4.38 0.78 3.66 4.09 0.32 6.11 6.82 5.08 5.30 0.19 8.54 8.09 5.00 5.52 8.48 8.06 10.95 9.16 3.92 3.99 0.40 4.01 4.17 0.19 2.87 3.39 0.67 3.47 3.50 0.39 9.75 9.62 5.34 4.89 0.35 (1) 3-2-1- Crack Spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of ultra low sulphur diesel. 123 · SUppLEMENTAL INFOrMATION (UNAUDITED) · CENOVU S 2010 A NNU AL rEpOr T O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s ( C O n t I n u E D ) per-unit results (C$, excluding impact of realized financial hedging) 2010 2009 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 Heavy Oil – Foster Creek ($/bbl) (1) price royalties Transportation and blending Operating 58.76 9.08 2.42 10.44 58.76 11.41 2.54 10.00 58.51 9.56 2.40 10.35 54.75 9.38 2.40 10.36 63.33 5.76 2.33 11.11 55.55 1.42 2.51 11.87 63.60 2.31 1.71 10.43 62.20 1.85 2.50 10.85 54.43 0.66 3.45 11.81 33.44 0.22 2.69 15.91 Netback 36.82 34.81 36.20 32.61 44.13 39.75 49.15 47.00 38.51 14.62 Heavy Oil – Christina Lake ($/bbl) (2) price royalties Transportation and blending Operating 57.96 2.14 3.54 16.56 58.42 2.05 1.54 17.40 56.45 2.04 3.69 15.94 54.99 2.19 4.52 16.50 62.27 2.28 4.47 16.41 53.45 1.24 3.09 16.31 57.07 2.04 0.96 18.06 64.85 1.72 5.36 15.31 57.32 0.83 2.83 13.69 32.44 0.23 3.38 18.21 Netback 35.72 37.43 34.78 31.78 39.11 32.81 36.01 42.46 39.97 10.62 Heavy Oil – pelican Lake ($/bbl) (3) price royalties Transportation and blending Operating 62.65 12.96 1.42 12.76 61.38 12.76 1.04 13.37 58.93 10.62 1.77 13.26 62.05 14.06 1.52 13.29 68.04 14.34 1.30 11.23 54.77 10.98 0.30 9.59 62.73 12.08 (0.02) 11.64 61.87 12.27 0.67 7.03 55.39 10.93 0.06 9.74 38.66 8.57 0.45 10.15 Netback 35.51 34.21 33.28 33.18 41.17 33.90 39.03 41.90 34.66 19.49 Heavy Oil – Oil Sands ($/bbl) (1) (2) (3) price royalties production and mineral taxes Transportation and blending Operating 59.76 9.53 – 2.25 11.70 59.35 10.79 – 2.08 11.54 58.41 9.30 – 2.35 11.83 56.83 10.03 – 2.35 11.81 64.61 7.94 – 2.23 11.65 55.09 4.98 0.04 1.81 11.49 62.75 5.37 0.02 1.14 11.41 62.23 5.66 0.07 2.15 9.69 55.18 4.86 0.06 2.16 11.53 35.47 3.69 – 1.85 13.89 Netback 36.28 34.94 34.93 32.64 42.79 36.77 44.81 44.66 36.57 16.04 Heavy Oil – Conventional ($/bbl) (4) price royalties production and mineral taxes Transportation and blending Operating Netback Total Heavy Oil ($/bbl) (5) price royalties production and mineral taxes Transportation and blending Operating Netback 63.18 9.01 0.19 0.56 12.08 60.45 8.01 0.05 0.45 12.47 59.40 7.29 0.17 0.60 11.52 61.35 9.65 0.10 0.60 12.95 71.16 10.99 0.44 0.59 11.45 55.29 5.47 0.14 1.91 9.47 62.09 8.61 0.13 1.59 12.06 64.62 8.39 (0.04) 1.22 9.31 56.00 4.13 0.44 2.75 9.72 37.71 0.61 0.02 2.11 6.91 41.34 39.47 39.82 38.05 47.69 38.30 39.70 45.74 38.96 28.06 60.33 9.44 0.03 1.97 11.77 59.53 10.36 0.01 1.83 11.68 58.59 8.95 0.03 2.04 11.77 57.57 9.97 0.02 2.06 11.99 65.76 8.48 0.08 1.94 11.61 55.14 5.08 0.06 1.83 11.07 62.63 5.95 0.04 1.22 11.52 62.72 6.22 0.04 1.96 9.61 55.36 4.70 0.14 2.28 11.13 35.99 2.98 - 1.91 12.27 37.12 35.65 35.80 33.53 43.65 37.10 43.90 44.89 37.11 18.83 CENOVUS 201 0 A NNUA L rEpOr T · S Up pL EM E NTA L I N FOrMATI ON ( UN AUDITED) · 124 O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s ( C O n t I n u E D ) Light and Medium Oil ($/bbl) price royalties production and mineral taxes Transportation and blending Operating Netback Total Crude Oil ($/bbl) price royalties production and mineral taxes Transportation and blending Operating Netback Natural Gas Liquids ($/bbl) price royalties Netback Total Liquids ($/bbl) price royalties production and mineral taxes Transportation and blending Operating Netback Total Natural Gas ($/Mcf) price royalties production and mineral taxes Transportation and blending Operating Netback Total ($/BOE) price royalties production and mineral taxes Transportation and blending Operating (6) Netback 2010 2009 Year Q4 Q3 Q2 Q1 Year Q4 Q3 Q2 Q1 71.63 9.30 2.55 1.66 12.27 45.85 62.98 9.41 0.62 1.90 11.89 39.16 72.98 7.69 2.45 1.89 12.99 47.96 62.75 9.72 0.59 1.84 11.99 38.61 68.37 9.32 2.44 1.81 12.02 66.14 10.17 3.08 1.51 12.84 42.78 38.54 60.86 9.03 0.59 1.99 11.83 59.51 10.01 0.71 1.94 12.19 78.78 10.05 2.25 1.45 11.25 53.78 68.87 8.85 0.59 1.83 11.52 37.42 34.66 46.08 61.00 1.12 63.60 0.75 59.88 62.85 62.96 9.33 0.62 1.88 11.78 62.75 9.63 0.59 1.82 11.84 54.43 1.29 53.14 60.80 8.96 0.59 1.97 11.72 58.71 1.16 57.55 59.50 9.93 0.71 1.94 12.08 67.42 1.39 66.03 68.85 8.78 0.59 1.83 11.42 63.34 7.39 2.40 0.98 9.93 71.82 11.72 1.70 0.70 9.53 68.15 8.09 2.57 0.83 10.00 65.28 6.56 1.98 1.18 9.53 42.64 48.17 46.66 46.03 57.22 5.67 0.65 1.61 10.78 38.51 49.08 0.81 48.27 57.14 5.62 0.65 1.60 10.67 64.85 7.34 0.44 1.10 11.04 44.93 59.06 0.96 58.10 64.79 7.28 0.44 1.09 10.94 64.00 6.66 0.64 1.69 9.70 45.31 57.95 5.18 0.62 2.00 10.72 39.43 49.17 1.00 44.65 0.82 48.17 43.83 63.85 6.60 0.63 1.67 9.61 57.81 5.14 0.61 1.98 10.61 39.35 38.87 37.56 34.84 46.23 38.60 45.04 45.34 39.47 4.09 0.07 0.02 0.17 0.96 2.87 44.01 4.93 0.37 1.45 8.81 28.45 3.55 (0.04) 0.02 0.16 1.02 2.39 42.82 4.90 0.35 1.40 9.08 27.09 3.68 0.08 0.03 0.15 0.94 2.48 41.49 4.73 0.38 1.42 8.70 3.78 0.07 (0.04) 0.15 0.94 2.66 41.46 5.26 0.24 1.43 8.93 5.27 0.14 0.07 0.21 0.94 3.91 50.16 4.81 0.52 1.53 8.53 26.26 25.60 34.77 4.15 0.08 0.05 0.15 0.86 3.01 39.88 2.87 0.46 1.24 7.71 27.60 4.17 0.16 0.03 0.12 0.81 3.05 44.54 4.05 0.30 0.91 7.85 3.14 0.02 0.04 0.16 0.84 2.08 40.43 3.22 0.43 1.29 7.24 3.80 0.01 0.07 0.16 0.83 2.73 38.65 2.35 0.52 1.41 7.52 31.43 28.25 26.85 48.09 3.14 3.37 1.21 10.67 29.70 39.40 3.03 0.95 1.71 11.82 21.89 43.42 0.46 42.96 39.45 3.00 0.94 1.69 11.69 22.13 5.47 0.15 0.05 0.18 0.94 4.15 35.71 1.81 0.58 1.34 8.27 23.71 (1) The Foster Creek 2010 YTD heavy oil price and transportation and blending costs exclude the costs of condensate purchases ($35.43/bbl) which are blended with the heavy oil. (2) The Christina Lake 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($36.66/bbl) which are blended with the heavy oil. (3) The pelican Lake 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($14.69/bbl) which are blended with the heavy oil. (4) The Conventional 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($11.08/bbl) which are blended with the heavy oil. (5) The total 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($26.88/bbl) which are blended with the heavy oil. (6) 2010 YTD operating costs include costs related to long-term incentives of $0.15/BOE (2009 – $0.09/BOE). Impact of realized Financial Hedging Liquids ($/bbl) Natural Gas ($/Mcf) Total ($/BOE) (0.36) 1.07 2.99 (1.29) 1.50 3.65 1.01 1.09 3.77 (0.40) 1.22 3.37 (0.78) 0.53 1.20 1.10 3.63 12.16 (0.05) 2.27 6.92 (0.01) 4.41 13.77 1.54 4.33 14.91 3.29 3.43 13.06 125 · SUppLEMENTAL INFOrMATION (UNAUDITED) · CENOVU S 2010 A NNU AL rEpOr T R ESE RvES data and O thER Oil and gaS i nFORMatiOn r E s E rv E s DA tA A n D O t H E r O I L A n D G A s I n F O r m At I O n For information in relation to the presentation of our reserves data and other oil and gas information, see the Oil and Gas reserves and resources section of our MD&A. We hold significant freehold title rights which generate production for our account from third parties leasing those lands. The Before royalty volumes presented do not include reserves associated with this royalty Interest production. The After royalty volumes presented include our royalty Interest reserves. For definitions of the terms used in our oil and gas disclosure, please refer to the Additional Advisory on page 132. s u m m A rY O F O I L A n D G A s r E s E rv E s A t D E C E m B E r 3 1 , 2 0 1 0 ( F O r E C A s t P r I C E s A n D C O s t s ) C O M Pa n y i n t E R E S t B E F O R E R Oya lt i E S ( 1 ) Classifications of reserves as proved or probable are only attempts to define the degree of certainty associated with the estimates. There are numerous uncertainties inherent in estimating quantities of bitumen, oil and natural gas reserves. it should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. For additional information on our pricing assumptions, reserves data and other oil and gas information, readers should review “reserves Data and Other Oil and Gas Information” and “risk Factors – Uncertainty of reserves, resources and Future Net revenue Estimates”, each within our AIF for the year ended December 31, 2010, available at www.sedar.com and at www.cenovus.com. Bitumen (MMbbls) Light & Medium Oil & NGLs (MMbbls) Heavy Oil (MMbbls) Natural Gas & CBM (Bcf) 126 20 1,008 1,154 523 1,677 111 13 45 169 97 266 79 5 27 111 49 160 1,292 62 36 1,390 410 1,800 Bitumen (MMbbls) Light & Medium Oil & NGLs (MMbbls) Heavy Oil (MMbbls) Natural Gas & CBM (Bcf) 96 14 760 870 404 1,274 92 10 36 138 72 210 67 4 21 92 39 131 1,292 61 36 1,389 391 1,780 reserves Category Proved reserves Developed producing Developed Non-producing Undeveloped total Proved reserves Probable reserves total Proved plus Probable reserves note: (1) Does not include royalty Interest reserves associated with royalty Interest production received by Cenovus. C O M Pa n y i n t E R E S t a F t E R R Oya lt i E S ( 1 ) reserves Category Proved reserves Developed producing Developed Non-producing Undeveloped total Proved reserves Probable reserves total Proved plus Probable reserves note: (1) Includes royalty Interest reserves associated with royalty Interest production received by Cenovus. CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 126 s u m m A rY O F n E t P r E s E n t vA L u E O F F u t u r E n E t r E v E n u E A t D E C E m B E r 3 1 , 2 0 1 0 ( F O r E C A s t P r I C E s A n D C O s t s ) Before Income Taxes Discounted at %/year ($ millions) Unit Value Before Income Tax Discounted at 10% (1) 0% 5% 10% 15% 20% $/BOE 16,118 1,423 36,936 54,477 21,163 12,796 888 13,789 27,473 12,192 10,619 604 6,302 17,525 6,879 9,102 435 3,300 12,837 4,031 7,986 325 1,872 10,183 2,466 75,640 39,665 24,404 16,868 12,649 22.60 15.53 7.66 13.16 11.84 12.76 After Income Taxes (1) Discounted at %/year ($ millions) 0% 5% 10% 15% 20% 12,683 1,070 27,637 10,153 666 10,359 8,480 454 4,720 7,308 328 2,442 6,443 245 1,349 41,390 21,178 13,654 10,078 8,037 15,783 9,073 5,076 2,923 1,737 57,173 30,251 18,730 13,001 9,774 reserves Category Proved reserves Developed producing Developed Non-producing Undeveloped total Proved reserves Probable reserves total Proved plus Probable reserves note: (1) Unit values have been calculated using the Company Interest After royalties reserves reserves Category Proved reserves Developed producing Developed Non-producing Undeveloped total Proved reserves Probable reserves total Proved plus Probable reserves note: (1) After income tax values are calculated by considering the Company’s existing tax pools the estimates of future net revenue presented do not represent fair market value. 127 · rESEr VES DATA AND OTHEr OIL AND GAS INFOrMATION · CENOVU S 2010 A NNU AL rEpOr T r E s E rv E s r E C O n C I L I At I O n The following tables provide a reconciliation of our company interest reserves Before royalties for bitumen, heavy oil, light and medium oil and NGLs, and natural gas for the year ended December 31, 2010, presented using forecast prices and costs. All reserves are located in Canada. r E s E rv E s r E C O n C I L I At I O n BY P r I n C I PA L P r O D u C t t Y P E A n D r E s E rv E s C At E G O rY ( F O r E C A s t P r I C E s A n D C O s t s ) C O M Pa n y i n t E R E S t P R Ov E d – B E F O R E R Oya lt i E S December 31, 2009 (sEC) (1) Transition to NI 51-101 Standards (2) December 31, 2009 (nI 51-101) Extensions and Improved recovery Discoveries Technical revisions Economic Factors Acquisitions Dispositions production (3) December 31, 2010 C O M Pa n y i n t E R E S t P R O B a B l E – B E F O R E R Oya lt i E S December 31, 2009 (sEC) (1) Transition to NI 51-101 Standards (2) December 31, 2009 (nI 51-101) Extensions and Improved recovery Discoveries Technical revisions Economic Factors Acquisitions Dispositions production December 31, 2010 Bitumen (MMbbls) Light & Medium Oil & NGLs (MMbbls) Heavy Oil (MMbbls) Natural Gas & CBM (Bcf) 866 – 866 270 – 40 – – – (22) 1,154 165 (1) 164 9 – 15 – – (5) (14) 169 112 (3) 109 11 – 1 – – – (10) 111 1,529 128 1,657 45 – 60 (18) – (87) (267) 1,390 Bitumen (MMbbls) Light & Medium Oil & NGLs (MMbbls) Heavy Oil (MMbbls) Natural Gas & CBM (Bcf) 479 – 479 132 – (88) – – – – 523 104 (1) 103 5 – (10) – – (1) – 97 53 (2) 51 (1) – (1) – – – – 49 436 52 488 12 – (82) 7 – (15) – 410 CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 128 C O M Pa n y i n t E R E S t P R Ov E d P l U S P R O B a B l E – B E F O R E R Oya lt i E S December 31, 2009 (sEC) (1) Transition to NI 51-101 Standards (2) December 31, 2009 (nI 51-101) Extensions and Improved recovery Discoveries Technical revisions Economic Factors Acquisitions Dispositions production (3) December 31, 2010 Bitumen (MMbbls) Light & Medium Oil & NGLs (MMbbls) Heavy Oil (MMbbls) Natural Gas & CBM (Bcf) 1,345 – 1,345 402 – (48) – – – (22) 1,677 269 (2) 267 14 – 5 – – (6) (14) 266 165 (5) 160 10 – – – – – (10) 160 1,965 180 2,145 57 – (22) (11) – (102) (267) 1,800 notes: (1) references in the tables to December 31, 2009 (SEC) numbers are to the previously disclosed estimates as of that date prepared by the IQrEs in accordance with U.S. disclosure requirements using constant prices and costs as prescribed by the SEC. (2) The change in reserves disclosed in the transition from SEC to NI 51-101 is a result of (i) the forecast prices and costs used under NI 51-101 were higher than the SEC prescribed constant prices and costs, restoring previously uneconomic gas reserves, and (ii) the removal of royalty Interest reserves from the Before royalties reserves totals. (3) production used for the reserves reconciliation differs from reported production. Company Interest Before royalties production for reserves includes Cenovus’s share of gas volumes provided to Cenovus’s share of the FCCL partnership for steam generation, but does not include royalty interest production, as prescribed by NI 51-101. E C O n O M i C C O n t i n g E n t a n d P R O S P E C t i v E R E S O U R C E S Company Interest Before r oyalties, Billions of barrels, Bitumen Economic Contingent resources (3) Low Estimate Best Estimate High Estimate Prospective resources (4) Low Estimate Best Estimate High Estimate December 31, 2010 (1) December 31, 2009 (2) 4.4 6.1 8.0 7.3 12.3 21.7 3.9 5.4 7.3 7.8 12.6 21.4 notes: (1) refers to estimates prepared by McDaniel using the same forecast prices and costs as used in the 2010 reserves estimates, McDaniel January 1, 2011 forecast prices and costs. (2) refers to previously disclosed estimates prepared by McDaniel, using 2009 constant prices and costs. (3) There is no certainty that it will be commercially viable to produce any portion of the contingent resources. (4) There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. prospective resources are not screened for economic viability. 129 · rESEr VES DATA AND OTHEr OIL AND GAS INFOrMATION · CENOVU S 2010 A NNU AL rEpOr T E X P L O r At I O n A n D D E v E L O P m E n t AC t I v I t Y The following tables summarize our gross participation and net interest in wells drilled for the periods indicated. E x P lO R at i O n W E l l S d Ri l lE d 2010: Oil Sands Conventional Total Canada 2009: Oil Sands Conventional Total Canada 2008: Oil Sands Conventional Total Canada d E v E lO P M E n t W E l l S d Ri l lE d 2010: Oil Sands Conventional Total Canada 2009: Oil Sands Conventional Total Canada 2008: Oil Sands Conventional Total Canada Oil Gas Dry & Abandoned Total Working Interest royalty Total Gross Net Gross Net Gross Net Gross Net Gross Gross Net – 26 26 – 4 4 – 1 1 – 26 26 – 4 4 – 1 1 – – – – – – – 5 5 – – – – – – – 3 3 – 1 1 – – – – 2 2 – 1 1 – – – – 1 1 – 27 27 – 4 4 – 8 8 – 27 27 – 4 4 – 5 5 – 21 21 – 8 8 – 34 34 – 48 48 – 12 12 – 42 42 – 27 27 – 4 4 – 5 5 Oil Gas Dry & Abandoned Total Working Interest royalty Total Gross Net Gross Net Gross Net Gross Net Gross Gross Net 82 160 47 154 – 499 – 495 242 201 499 495 50 102 29 101 8 555 8 502 – – – 8 2 – – – 8 2 82 659 47 649 741 696 66 659 45 605 152 130 563 510 10 10 725 650 41 105 146 21 92 113 13 1,489 13 1,372 1,502 1,385 4 7 11 4 7 11 58 1,601 38 1,471 1,659 1,509 8 204 212 10 261 271 41 503 544 90 863 47 649 953 696 76 920 45 605 996 650 99 2,104 38 1,471 2,203 1,509 In addition to the disclosure above, we drilled stratigraphic test wells during the year ended December 31, 2010, with Oil Sands having drilled 259 gross wells (178 net wells) and Conventional having drilled 11 gross wells (9 net wells). In addition to the disclosure above, we drilled service wells during the year ended December 31, 2010, with Oil Sands having drilled 68 gross wells (44 net wells) and Conventional having drilled 30 gross wells (20 net wells). CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 130 I n t E r E s t I n m A t E r I A L P r O P E r t I E s The following table summarizes our developed, undeveloped and total landholdings at December 31, 2010. ( t h o u s a n d s o f a c r e s) Alberta: Oil Sands – Crown (3) Conventional – Fee (4) – Crown (3) – Freehold (5) Total Alberta saskatchewan: Conventional – Fee (4) – Crown (3) – Freehold (5) Total Saskatchewan manitoba: Conventional – Fee (4) Total Manitoba total Developed Undeveloped (1) Total (2) Gross Net Gross Net Gross Net 696 1,913 1,571 51 4,231 69 47 13 129 3 3 597 1,913 1,463 42 4,015 69 34 9 112 3 3 1,845 440 372 35 2,692 437 162 28 627 261 261 1,455 440 306 32 2,233 437 141 25 603 261 261 4,363 4,130 3,580 3,097 2,541 2,353 1,943 86 6,923 506 209 41 756 264 264 7,943 2,052 2,353 1,769 74 6,248 506 175 34 715 264 264 7,227 notes: (1) Undeveloped includes land that has not yet been drilled, as well as land with wells that have never produced hydrocarbons or that do not currently allow for the production of hydrocarbons. (2) This table excludes approximately 2.4 million gross acres under lease or sublease, reserving to us, royalties or other interests. (3) Crown/Federal lands are those lands owned by the federal or provincial government or the First Nations, in which we have purchased a working interest lease. (4) Fee lands are those lands in which we have a fee simple interest in the mineral rights and have either: (i) not leased out all of the mineral zones; or (ii) retained a working interest. The current fee lands summary now includes all fee titles owned by us, that have one or more zones that remain unleased or available for development. (5) Freehold lands are those lands owned by individuals (other than a government or Cenovus) in which Cenovus holds a working interest lease. 131 · rESEr VES DATA AND OTHEr OIL AND GAS INFOrMATION · CENOVU S 2010 A NNU AL rEpOr T A D D I t I O nA L A D v I s O rY O i l a n d g a S i n F O R M at i O n F i n d i n g a n d d E v E lO P M E n t C O S t S Finding and development costs disclosed on pages 25 and 33 of this Annual report do not include changes in estimated future development costs and exclude the effects of acquisitions and dispositions. Cenovus uses finding and development costs without changes in estimated future development costs as an indicator of relative performance to be consistent with the methodology accepted within the oil and gas industry. Finding and development costs excluding the effects of acquisitions and dispositions and without changes in future development costs is equal to finding and development capital investment divided by finding and development reserves additions. Finding and development reserves additions are calculated by summing revisions, improved recovery, extensions and discoveries. Finding and development costs for proved reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $10.55/BOE for the year ended December 31, 2010, $16.01/BOE for the year ended December 31, 2009 and averaged $16.95/BOE for the three years ended December 31, 2010. Finding and development costs for proved plus probable reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $9.78/BOE for the year ended December 31, 2010, $81.70/BOE for the year ended December 31, 2009 and averaged $24.43/BOE for the three years ended December 31, 2010. These finding and development costs were calculated by dividing the sum of exploration costs, development costs and changes in future development costs in the particular year by the reserves additions (the sum of discoveries, extensions and improved recovery and technical revisions) in that year. The aggregate of the exploration and development costs incurred in a particular year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. For additional information about our finding and development costs, capital investment and reserves additions, please see our February 18, 2011 news release available at www.sedar.com and www.cenovus.com. The following definitions are applicable to our oil and gas disclosure in this Annual report. For definitions related to our contingent and prospective resources disclosure, see “Oil and Gas Information” in the Advisory section of our MD&A. For additional definitions that are not included here, please see “reserves Data and Other Oil and Gas Information” within our AIF for the year ended December 31, 2010, available at www.sedar.com and at www.cenovus.com. after Royalties means volumes after deduction of royalties and including any royalty interests. Before Royalties means volumes before deduction of royalties and excluding any royalty interests. Bitumen initially-in-place discovered bitumen initially-in-place (56 Bbbls) is the quantity of bitumen estimated, as at December 31, 2009 by an independent qualified reserves evaluator, 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. total bitumen initially-in-place (BIIp) (137 Bbbls) is the quantity of bitumen estimated, as at December 31, 2009 by an independent qualified reserves evaluator, to exist originally in naturally occurring accumulations. It includes Discovered BIIp (56 Bbbls) plus Undiscovered BIIp (82 Bbbls) which includes those estimated quantities, as at December 31, 2009, in accumulations yet to be discovered. 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 estimate. Bitumen initially-in-place estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered. For further information regarding these estimates and all subcategories thereof, please see our June 16, 2010 news release, available at www.sedar.com and www.cenovus.com. Company interest means, in relation to production, reserves, resources and property, the interest (operating or non-operating) held by Cenovus. Royalty interest means: (a) in relation to reserves, those reserves related to our royalty entitlement on lands to which we hold freehold title which have been leased to third parties, or reserves related to other royalty interests, such as overriding royalties to which we are entitled. (b) in relation to production, the production generated for Cenovus’s account pursuant to leasing agreements of our freehold title lands, and other royalty entitlement agreements. CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 132 We aRe a canaDian oiL coMP anY aPPLYinG FResh, PRoGRessive thinKinG: to safely and responsibly unlock energy resources the world needs – that’s our promise. to increase total shareholder return – that’s our goal. pictured here is Foster Creek, our largest steam-assisted gravity drainage (sagD) project, situated on the Cold lake air Weapons range in northern alberta. Corporate Information e xeCutive oFFiCers Brian C. Ferguson president & Chief executive officer John K. Brannan executive vice-president & Chief operating officer harbir s. Chhina executive vice-president, oil sands Kerry D. Dyte executive vice-president, general Counsel & Corporate secretary Judy a. Fairburn executive vice-president, environment & strategic planning sheila M. Mcintosh executive vice-president, Communications & stakeholder relations ivor M. ruste executive vice-president & Chief Financial officer Donald t. swystun executive vice-president, refining, Marketing, transportation & Development hayward J. Walls executive vice-president, organization & Workplace Development BoarD oF DireCtors Michael a. grandin(1)(4)(8) Chair, Calgary, alberta ralph s. Cunningham(1)(3)(4)(6) houston, texas patrick D. Daniel(1)(2)(3)(4) Calgary, alberta ian W. Delaney(1)(3)(4)(6) toronto, ontario Brian C. Ferguson(7) Calgary, alberta valerie a. a. nielsen(1)(2)(4)(5) Calgary, alberta Charles M. rampacek(4)(5)(6) Dallas, texas Colin taylor (2)(3)(4) toronto, ontario Wayne g. thomson(1)(4)(5)(6) Calgary, alberta (1) Former director of encana. (2) Member of the audit committee. (3) Member of the human Resources and compensation committee. (4) Member of the nominating and corporate Governance committee. (5) Member of the Reserves committee. (6) Member of the safety, environment and Responsibility committee. (7) as an officer and a non-independent director, Mr. Ferguson is not a member of any of the committees of our Board. (8) ex-officio non-voting member of all other committees of our Board. Cenovus he aD & registereD oFFiCe cenovus energy inc. 421 – 7 avenue s.W. Po Box 766 calgary, alberta, canada t2P 0M5 Phone: 403-766-2000 www.cenovus.com Shareholder Information annual Meeting shareholders are invited to attend the annual meeting being held on Wednesday, april 27, 2011 at 2 p.m. (calgary time) at the teLus convention centre, exhibition hall e, 2nd Floor, north Building, 136 – 8 avenue s.e., calgary, alberta. Please see our management proxy circular mailed to shareholders and posted on our website, www.cenovus.com, for additional information. transFer a gents & registrar in canada, ciBc Mellon trust company in calgary, Montreal & toronto. in the united states, BnY Mellon in Jersey city, new Jersey. shareholders are encouraged to contact ciBc Mellon trust company for information regarding their security holdings. they can be reached throughout north america by phoning 1-866-332-8898 (english & French) and outside north america by phone at 1-416-643-5850 or by facsimile at 1-416-643-5501. Canadian stock transfer Company CiBC Mellon trust Company Po Box 7010 adelaide street Postal station toronto, ontario, canada M5c 2W9 www.cibcmellon.com canadian stock transfer company inc. recently purchased the transfer agency business from ciBc Mellon. canadian stock transfer company inc. is operating the transfer agency business in the name of ciBc Mellon trust company for a transition period. shareholDer aCCount Matters to change your address, transfer shares, eliminate duplicate mailings, deposit dividends directly into accounts at financial institutions in canada that provide electronic fund-transfer services, etc., please contact ciBc Mellon trust company. stoCK e xChanges common shares (cve) trade on the toronto stock exchange (tsX) and the new York stock exchange (nYse). annual inForMation ForM / ForM 40-F our annual information Form is filed with the canadian securities administrators in canada on seDaR at www.sedar.com and with the u.s. securities and exchange commission under the Multi- Jurisdictional Disclosure system as Form 40-F on eDGaR at www.sec.gov. nyse s tat eMent oF DiFFerenCes as a canadian company listed on the new York stock exchange (nYse), we are not required to comply with most of the nYse corporate governance standards and instead may comply with canadian corporate governance requirements. We are, however, required to disclose the significant differences between our corporate governance practices and those required to be followed by u.s. domestic companies under the nYse corporate governance standards. except as summarized on our website, www.cenovus.com, we are in compliance with the nYse corporate governance standards in all significant respects. investor rel ations Please visit the Invest In Us section of www.cenovus.com for investor information. investor inquiries should be directed to: 403-766-7711 investor.relations@cenovus.com or susan grey Director, investor Relations 403-766-4751 susan.grey@cenovus.com Media inquiries should be directed to: 403-766-7751 media.relations@cenovus.com or rhona DelFrari Manager, Media Relations 403-766-4740 rhona.delfrari@cenovus.com 133 · c oRPoRate anD sh aRehoLDeR inFoRMat i on · ce n ov us 20 10 a nn u aL RePoR t . c n i e v i t a e r c y r d n u o F y b d e c u d o r p d n a d e n g i s e D the cenovus equation 20 10 ann ual report t h e C e n o v u s e Q u a t i o n 2 0 1 0 a n n u a l r e p o r t . w w w c e n o v u s . c o m Brian Ferguson talks about Cenovus, our operations and how we’re doing things differently. Want to see the video? Download a free Qr code reader on your mobile browser. Front cover: Staff from our Christina Lake site Cenovus energy inC . 421 – 7 avenue sW po Box 766 Calgary, alberta, Canada t2p 0M5 printed in Canada. 

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