COSWF 2012 10K

We believe that strong companies such as COS can, and should, affect significant positive changes in the quality of life in our community. COS has a deep commitment to our community, and we believe in sharing the benefits of the oil sands with our neighbours. Since 2005, COS has directed about $19 million towards community investment programs. Whether it’s doing our part to address the root problems of poverty, helping youth to attain their greatest potential, or supporting emergency shelters, we focus on projects and organizations where we believe COS‘ investments can make a meaningful difference.

In 2012, COS launched Math Minds, an initiative aimed at strengthening numeracy among students in kindergarten to grade six. Math Minds is a collaborative effort between COS, academic institutions and social services agencies to drive real and lasting change in elementary numeracy by applying leading-edge educational principles rooted in extensive academic research.

We believe that any student can enjoy and excel at math. Our vision is that the confidence gained through students‘ success in math will empower them to make a positive difference for themselves and for the world.

For more information about COS and Math Minds, please visit www.cdnoilsands.com

Invested in a healthy, educated and compassionate community

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Resourceful2012 ANNUAL REPORT

All references to “dollars” or “C$” are in Canadian dollars and all references % to “US$” are in United States dollars 2012 2011 change

FINANCIAL ($ millions, except per share amounts) Sales, after crude oil purchases and transportation expense 3,566 3,934 – 9% Cash flow from operations1,4 1 ,581 1,897 – 17% Per share3 3.26 3.9 1 – 17%Net income 981 1, 144 – 14% Per share, basic and diluted 2.02 2.36 – 14%Dividends 654 533 23% Per share 1.35 1.10 23%

FINANCIAL RATIOS3 Net debt to cash flow from operations (times)1 0.2 0.2 Net debt to total net capitalization (%) 5 9 Return on average shareholders’ equity (%) 22.5 28.8 Return on average productive capital employed (%) 26.6 33.2

OPERATIONSSales volumes, net of crude oil purchases2

Total (mmbbls) 38.7 38.7 0% Daily average (bbls) 105,680 106,015 0%Operating expenses ($/bbl)3 39.06 38.80 1%Capital expenditures ($ millions) 1,086 643 69%Net realized selling price ($/bbl)3 91.90 101.2 – 9%Average West Texas Intermediate (US$/bbl) 94.1 5 95. 1 1 – 1%Average foreign exchange rate (US$/C$) 1.00 1.0 1 – 1%

SHARE INFORMATIONClosing price on December 31 ($/share) 20.1 7 23.25 – 13% Number of shares outstanding (in millions) 484.6 484.5 0% Total shareholder return3 (%) – 8 – 8 0%S&P/TSX Oil & Gas Index (%) – 1 1 – 18

Certain calculations displayed above are non-GAAP or additional GAAP financial measures. Please see the Management’s Discussion and Analysis section of this report for a discussion of non-GAAP and additional GAAP financial measures.

A five-year statistical summary is provided on page 76.

1 Cash flow from operations is calculated as cash from operating activities, as reported on the Consolidated Statements of Cash Flows, before changes in non-cash working capital.

2 The Corporation’s sales volumes differ from its production volumes due to changes in inventory, which are primarily in-transit pipeline volumes, and are after purchased crude oil volumes.

3 Non-GAAP measure(s).4 Additional GAAP measure.

2012 results reflected lower pricing for our product.

COS continues to demonstrate strong profitability.

F I N A N C I A L A N D O P E R AT I N G H I G H L I G H T S

2012 results

I N S I D E T H I S R E P O RT

02 President’s Message 08 Strategic Scorecard 10 Financial Review 1 1 Management’s Discussion and Analysis 4 1 Management’s Report 42 Independent Auditor’s Report 44 Consolidated Financial Statements 48 Notes to Consolidated Financial Statements 73 Advisory 75 Glossary and Abbreviations 76 Statistical Summary IBC Shareholder Information

S H A R E H O L D E R I N F O R M AT I O N

Board of Directors

DONALD J. LOWRY 2

Chairman of the Board President and Chief Executive Officer EPCOR Utilities Inc. Edmonton, Alberta

IAN A. BOURNE 1,2

Calgary, Alberta

MARCEL R. COUTUPresident and Chief Executive Officer Canadian Oil Sands Limited Calgary, Alberta

GERALD W. GRANDEY 1,2

Saskatoon, Saskatchewan

SARAH E. RAISS 1

Calgary, Alberta

JOHN K. READ 3

Calgary, Alberta

BRANT G. SANGSTER 3

Calgary, Alberta

C.E. (CHUCK) SHULTZ 3

Chairman Emeritus of the Board Chairman and Chief Executive Officer Dauntless Energy Inc. Calgary, Alberta

WESLEY R. TWISS 2,3

Calgary, Alberta

JOHN B. ZAOZIRNY, Q.C.1

Canaccord Financial Corporation Calgary, Alberta

1 Member of the Corporate Governance and Compensation Committee

2 Member of the Audit Committee3 Member of the Reserves, Marketing

Operations and Environmental, Health and Safety Committee

Officers

MARCEL R. COUTUPresident and Chief Executive Officer

RYAN M. KUBIKChief Financial Officer

TRUDY M. CURRANSenior Vice President, General Counsel and Corporate Secretary

DARREN K. HARDYSenior Vice President, Operations

ALLEN R. HAGERMAN, fca

Executive Vice President

ROBERT P. DAWSONVice President, Finance

PHILIP D. BIRKBYController

SIREN FISEKCIVice President, Investor and Corporate Relations

ADRIENNE NICKERSONVice President, Operations

DAVID J. SIRRSVice President, Marketing

SCOTT W. ARNOLDDirector, Sustainability and External Relations

Ticker Symbols

Toronto Stock Exchange: COSOTCQX: COSWF

Registrar and Transfer Agent

Computershare Trust Company of Canada, with offices in Vancouver, Calgary, Toronto and Montreal, is the registrar and Transfer Agent for Canadian Oil Sands Limited.

COMPUTERSHARE TRUST COMPANY OF CANADA600, 530 – 8th Avenue SW Calgary, Alberta T2P 3S8 Telephone: 1 (800) 564-6253 Fax: (403) 267-6598 E-mail: [email protected]

Auditors

PRICEWATERHOUSECOOPERS LLP CHARTERED ACCOUNTANTSCalgary, Alberta

Independent Qualified Reserves Evaluators

GLJ PETROLEUM CONSULTANTS LTD.Calgary, Alberta

Internal Auditors

DELOITTE & TOUCHE LLPCalgary, Alberta

Canadian Oil Sands Limited

2500 First Canadian Centre 350 – 7th Avenue S.W. Calgary, Alberta T2P 3N9 Telephone: (403) 218-6200 Fax: (403) 218-6201

Investor and Media Contacts


ALISON TROLLOPEManager, Investor Relations

Telephone: (403) 218-6220 Email: [email protected]

Notice of Meeting

Canadian Oil Sands’ 2013 Annual Special Meeting will be held in the Metropolitan Conference Centre, The Ballroom, 333 – 4th Avenue SW, Calgary, Alberta on Tuesday, April 30, 2013 at 2:30 pm (MST). All shareholders are invited to attend, and those unable to do so are requested to sign and return the form of proxy mailed with this report to ensure representation at the meeting. The meeting will be webcast on our website at www.cdnoilsands.com.D

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For additional information about Canadian Oil Sands, or for an on-line version of this report, please visit our website at www.cdnoilsands.com.

1211100908

CASH FLOW FROM OPERATIONS 1,4

(in millions)

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RETURN ON EQUITY3

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Resourceful Canadian Oil Sands (COS) is a pure investment opportunity in light, sweet crude oil. Through our 36.74 per cent interest in the Syncrude project, we offer a robust production stream of fully upgraded crude oil. With strategic resources that include a strong balance sheet, billions of barrels in reserves and resources on high-quality leases, and a management team committed to maximizing the value of our Syncrude asset, COS is well positioned to deliver long-term value to shareholders.

I M P O RTA N T: Please read the Advisories regarding forward-looking information on page 73 and non-GAAP and additional GAAP financial measures on page 74.

COVER: Over 5,000 employees work at Syncrude, which is consistently recognized as one of Alberta’s top employers and best places to work.

THIS PAGE: Syncrude is a fully integrated facility that upgrades low-value bitumen to produce a stream of 100 per cent synthetic crude oil.

SYNCRUDE’S PRODUCT IS A HIGH-QUALITY, LIGHT SWEET SYNTHETIC CRUDE OIL.

02 | CANA D IA N O I L SA NDS L I M I T ED

These results were achieved despite several challenges. At Syncrude, production fell short of our objectives. There remain cost pressures in the oil sands sector and, industry-wide, Canadian producers are experiencing a lack of pipeline capacity for crude oil transport. These factors have weighed on our stock price as well as those of our peers.

Amid a dynamic industry landscape, our core value remains unchanged. We are a pure-play, long-term investment in crude oil. We are focused on efficient cash management, which means reinvesting in our business for continued economic returns, returning excess cash to shareholders in the form of dividends and maintaining a strong balance sheet. This strategy has delivered strong returns to shareholders over the long term. COS remains well positioned with strong financial resources to weather volatility, even as we continue to advance our major multi- year capital investment program. All of our capital projects are aimed at long-term benefits encompassing more stable and long-life production, operational efficiencies and improved environmental performance.

Major projects on track

We have four major projects underway, two mine train projects and two tailings reclamation projects. Across all four projects, we are confident in the cost estimates and schedules based on progress to date. By the end of 2013, with two projects scheduled to be largely complete, only about one-third of the total cost of our major projects will remain.

The largest of our investments is the construction of two new mine trains at our Mildred Lake mine with a projected total cost of $1.6 billion (net to COS). This project was about 35 per cent complete at the end of 2012 and has an anticipated in-service date of Q4 2014. Each of the mine trains will incorporate novel wet crushing technology and feature greater productive capacity than our existing mine trains. These improvements are expected to add flexibility to our mining operations, increase bitumen recovery and lower maintenance requirements. Our second major project will relocate two mine trains at our Aurora North Mine at an expected cost of $400 million (net to COS) and an anticipated in-service date of Q1 2014. Once both mine train projects are complete, Syncrude’s current mines will be poised to operate for decades.

P R E S I D E N T ’ S M E S S A G E

Marcel R. CoutuPresident and Chief Executive Officer

Canadian Oil Sands’ performance in 2012 reflected both progress and challenge. We made good progress on our major projects at Syncrude, which are expected to sustain decades of production as well as improve environmental performance. We generated one of the highest yields among Canadian energy producers with an increase in our dividend that returned a total of $1.35 per share to investors. That was possible through solid cash flow from operations of $1.6 billion, the support of one of the strongest balance sheets in our industry, and a clear line-of-sight on capital expenditures.

Fellow shareholders,

2012 AN N UAL REPORT | 03

In 2012, we started construction on a full-scale centrifuge plant that is expected to begin operating in 2015. This technology produces a soft, clay-rich material that can be used as the landform foundation in oil sands reclamation areas.

Two other major projects involve tailings reclamation as part of our commitment to meet the Alberta government’s stringent tailings regulations. The first is the construction of a $300 million (net to COS) Composite Tails (or CT) plant at Aurora North, where fluid fine tails (or FFT) are mixed with coarse tailings sand and some gypsum to transform the FFT into solid material suitable for reclamation. A similar plant has been operating at the Mildred Lake mine for over a decade. We have now accumulated sufficient FFT at Aurora North after 10 years of operations to start up a CT plant. Construction is expected to be largely complete by the end of this year.

We also are investing $700 million (net to COS) in a centrifuge plant at the Mildred Lake mine. The system is designed to accelerate the reclamation of tailings by extracting water from the FFT to allow for the restoration of a solid surface. Syncrude has successfully demonstrated this technology with a commercial-scale plant operating on-site. Construction on this centrifuge project began late last year and is scheduled for completion in the first half of 2015.

Focused on enhancing production

Last year Syncrude produced 104.9 million barrels of synthetic crude oil (SCO), essentially equal to the 105.3 million barrels produced in 2011 but seven per cent lower than our target of 113 million barrels.

While we have not yet seen the expected increases in production at Syncrude, production has been stable over the last six years, and we continue to believe there are gradual and steady gains to be achieved. In 2012, we experienced fewer slurry system failures and bitumen furnace tube leaks, which are key performance indicators for reliability. We have also made unit modifications to reduce solids content in the feed going to the upgrader. These abrasive solids were causing unplanned downtime and contributed to significant loss in production over the last few years. Two of our three cokers have achieved optimal 36-month run lengths, up from an average of 28 months. Also, Syncrude is focused on implementing reliability improvement plans for each business area of the facility based on Imperial Oil and ExxonMobil’s best-in-class systems.

Our goal is to gradually and safely achieve industry-leading utilization rates by drawing on the strengths of ExxonMobil’s Global Reliability Management System and Syncrude’s experienced operations team. With largely fixed operating costs, achieving organic growth from our current facilities is highly economic and therefore a priority at Syncrude.

01 | Superior Quality

Our light, sweet synthetic crude is a desirable refinery feedstock for conversion into valuable products such as diesel and jet fuel. Having secured its leases early in the development of the oil sands industry, Syncrude possesses premium bitumen-rich deposits with sufficient reserves to produce at current rates for the next 40 years with the potential for future growth through undeveloped resources. Further, COS is the only oil sands company whose assets are undiluted with lower-value heavy oil or natural gas products.

FIVE REASONS TO INVEST IN COS

SYNCRUDE’S MAJOR PROJECTS REMAIN ON TIME AND ON BUDGET.

SYNCRUDEOIL SANDSLEASES

Aurora South

Aurora North Mine

Mildred LakeMine

Upgrader

CNRL Horizon

SuncorFort Hills

Shell

ShellJackpine Phase 2

CNRLShell

Jackpine Phase 1

Imperial

SuncorSuncor

Suncor

She

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Athabasca River

TotalJoslyn

CNRL

Fort McMurray40 km


1110090807

PRODUCTION SINCE LAST EXPANSION(barrels per day, gross to Syncrude)

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While production has been stable over the past several years, Syncrude is actively focused on optimizing operations and gradually increasing production rates.

Managing costs key to strong profit margins

One aspect of our business that is not fully appreciated is our profit margin. Syncrude’s operating expenses are competitive with other oil sands producers, yet 100 per cent of Syncrude’s production is a high-quality, light sweet crude oil blend, for which we have historically received a higher price. Other oil sands producers’ operating expenses reflect the cost to produce a slate of products, which include lower quality products that fetch a lower price than SCO. Our internal analysis indicates that Syncrude, on average, is the lowest cost producer of light sweet synthetic crude oil from the oil sands. This results in a significantly higher margin per barrel for our product, illustrating that our upgrading facility provides a significant competitive advantage.

That said, cost inflation continues to be a challenge for the oil sands industry. As I noted, our operating costs are relatively fixed, so spreading these costs over more barrels as a result of higher production is a key objective. We recognize that we must be vigilant in controlling costs to preserve Syncrude’s profit margins, and we have a system-wide process underway to pursue opportunities for cost efficiencies.

Pipeline access critical

An increasingly important factor in the success of our business is market access. The entire industry is experiencing a lack of pipeline transportation to markets across North America, and this is having a significant impact on the price producers receive for their crude oil, including our SCO. Historically, our product has traded at a slight premium or discount to West Texas Intermediate (WTI). At the same time, WTI generally tracked closely to Brent and other world oil prices. But recently, both trends have changed.

First, we have seen the difference – or “differential” – between the price of SCO and WTI become more volatile. In 2011, our SCO averaged a $7 per barrel premium to WTI, and in 2012 it sold at an average discount of $2.50 per barrel. A lack of market access has also changed the historical trend between WTI and Brent oil prices. The two began to diverge in late 2010 and WTI averaged a discount to Brent of $18 per barrel in 2012.

We expect the volatility in the differential of SCO to WTI to continue at least over the next few years, reflecting North American supply and demand fundamentals for crude oil. On the supply side, increasing production of synthetic oil and bitumen from the oil sands, as well as light crude oil from tight oil formations such as the Bakken, have reduced space available on pipelines and driven down pricing of crude from Western Canada. Meanwhile, modifications at some U.S. refineries to process heavier crude oil will ultimately push light crude sales, including SCO, to more distant refineries, which increases transportation costs.

At present, various pipeline projects are proposed that will expand our reach to North American markets, including refineries in eastern Canada. The completion of these projects should help to reduce pricing volatility between SCO and WTI.

02 | Essential

Global demand for crude oil is expected to remain strong for decades, and Canada’s oil sands are a significant, growing and secure source of supply. More broadly, Canada’s oil sands deposits represent 55 per cent of all available crude oil reserves accessible for private sector investment. COS represents a unique opportunity for upside exposure to rising oil prices as an independent, pure-play oil sands company marketing a high-quality product.



SOURCE: International Energy Agency, 2012.

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PROJECTED WORLD OIL DEMAND(millions of barrels/day)


03 | Responsible

Syncrude was formed nearly 50 years ago with a focus on researching the most sustainable means of developing the oil sands. Since then, Syncrude has continuously applied innovative thinking to its relentless pursuit of responsible oil sands development. Achievements to date include:

• Reclamationofapproximately3,200 hectares of mined lands and another 1,200 hectares are ready for revegetation.

• Plantingofnearlysevenmilliontrees and shrubs.

• Useof85percentrecycledwater in our operations.


GIVEN THE ECONOMIC CHALLENGES IN BUILDING AN UPGRADER IN ALBERTA TODAY, OUR EXISTING INTEGRATED FACILITY IS A SIGNIFICANT COMPETITIVE ADVANTAGE.

In the meantime, we are working to identify new opportunities to ship our product. We are taking a portfolio approach to securing pipeline access, meaning that we are pursuing committed capacity on multiple routes to enhance our marketing flexibility.

Expanding our markets

I am often asked if rising U.S. oil production from tight formations, which have only been unlocked in the last few years with technological advances, will displace Canadian synthetic oil products. According to the U.S. Energy Information Administration, the U.S. will still require crude imports even under optimistic forecasts for North American supply. We see Canadian exports remaining strong and increasingly displacing crude oil from places such as the Middle East, Mexico and Venezuela.

A far more significant factor is affecting Canadian crude oil producers – a lack of access to international markets and the world’s strongest growth economies. As discussed earlier, Canadian oil producers are receiving an excessive price discount to world oil price benchmarks such as Brent. This gap is primarily due to a lack of available shipping routes for Canadian crude oil to reach coastal refineries and international customers. We expect the gap between WTI and Brent to be reduced in the near-term with new capacity to the U.S. Gulf Coast being brought on with the reversal of the Seaway pipeline, the construction of the Keystone XL Southern Leg expected to be completed by the end of 2013, and the twinning of the Seaway pipeline anticipated in mid-2014.

COS offers compelling value compared to new projects in our industry. COS’ market value at year-end 2012 was $10 billion, which equatestoabout$80,000perflowingbarrel of production capacity. New oil sands mining infrastructure is expected to come on-stream in 2013 at a cost of about $115,000 per flowingbarreloflower-valuebitumenproduction capacity. In addition to our high-value production stream of light sweet crude oil, COS offers substantial reserves and resources and an attractive dividend.


Syncrude continues to make significant advances in reducing air emissions and water use, as well as in the development of reclamation technologies to return disturbed land to a productive state that is capable of supporting biologically self-sustaining communities of plants and animals.

The International Energy Administration projects moderate growth in global demand for oil of about 14 per cent between now and 2035. Almost all of this incremental demand is anticipated to come from the world’s emerging economies. This underscores the need for pipeline infrastructure to reach tidewater ports and the ability to ship our crude oil to markets such as China and India.

Access to markets impacts Canadians

The lack of available pipeline space and the discount for Canadian oil is important not just to our industry, but to all Canadians. Last year, research by the Canadian Imperial Bank of Commerce suggested that the Canadian oil discount equates to about $18 billion annually, or $50 million per day – and the differentials for heavy oil to world oil prices have risen significantly since then.

The beneficiaries of this discount are primarily U.S. refineries, which are taking advantage of cheap feedstock that we, as Canadians, are subsidizing. When Canadian producers don’t receive a globally competitive price for their oil, hundreds of millions of tax and royalty dollars are lost – funds that could build schools, hospitals and other infrastructure as well as provide transfer payments to other provinces. Given these factors, there is a need for a balanced national discussion on how to move these pipelines forward, quickly, safely and responsibly, enabling Canadians to benefit from the fair value of our nation’s valuable natural resources.

Syncrude: A leader in sustainable development

Syncrude recently published an extensive report on their sustainability efforts that asked: Are the oil sands being responsibly developed? This is an important question, and I personally believe that the answer is “yes.” When Syncrude was incorporated in 1964, an environmental group was established to study regional baseline metrics for land, air and water quality before construction even began. Since operations started, we have followed a path of continuous improvement to mitigate the impacts

04 | Dependable

COS has a strong production stream of high-quality crude oil and long-life resources for future development. The value of this significant asset base translates into a strong return on equity and dividends. In 2012, COS returned to investors $1.35 per share, which at the end of the year equated to a 7 per cent yield. Over the past 11 years, COS has paid over $6 billion in dividends to investors.



COS HAS BEEN INCLUDED IN THE DOW JONES SUSTAINABILITY INDEX SINCE 2010.

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121110090807

CUMULATIVE DIVIDEND PAYMENTS($ billions)

For more information about Syncrude sustainability, visit www.syncrudesustainability.ca


of industrial development on the environment. New processes have been introduced to reduce water and energy consumption, reclaim the land faster and to minimize air emissions.

While proud of what has been accomplished, we are determined to improve our performance. COS has joined forces with other oil sands producers to accelerate innovation in environmental performance under the Canadian Oil Sands Innovation Alliance (COSIA). COSIA brings together thought leaders in industry, government, academia and the broader public to improve measurement, accountability and environmental performance. Today, Syncrude alone invests more than $60 million in research and development every year as a means to achieve environmental and operating excellence. These efforts continue to bear fruit, as reflected by COS’ inclusion in the Dow Jones Sustainability Index North America since 2010.

Outlook for dividends

As we look to the upcoming year, we have significant financial resources to support our capital program as well as our dividend. Based on the assumptions provided in our Outlook, we expect to maintain a quarterly dividend of $0.35 per share. At year-end 2012, this level of dividend generated one of the highest yields among Canadian energy producers.

Our core strategy remains to provide our investors with long-term oil price exposure and to pay a healthy dividend based on our cash flow over time. Because we do not hedge our oil production, changes in oil prices could have a material impact on our plans. That said, we take a longer-term view of our finance plan to avoid short-term adjustments to the dividend. Assuming continued strength in world oil prices, after 2014 we see the potential for expanded free cash flow (cash flow from operations less capital expenditures), when our major project spending tapers off.

Well-positioned for the future

The theme for this year’s annual report is “resourceful”, a word that I think describes COS very well.

In a literal sense, the word “resourceful” describes our established and stable operations and significant production of about 105,000 barrels per day net to COS. Investments previously made in our upgrading capacity are also an important resource, as we continue to benefit from premium pricing for our product relative to heavy oil producers. What’s more, we have sufficient reserves and resources to produce for decades to come.

COS benefits from a highly experienced and committed Board of Directors. In 2012, Board member Chuck Shultz was one of only four individuals recognized for his leadership in corporate governance with the prestigious Fellowship award from the Institute of Corporate Directors.

In closing, I’d like to recognize the resourceful people with whom I have the privilege of working. There are only about 30 of us in total, with approximately one third of the team marketing our product, and most of the rest providing the operations insight and accounting, legal and finance support that is required to run a publicly traded oil company. We are focused on maintaining our low administrative cost base, thereby allowing investors the opportunity to benefit from a high-quality, pure-play oil sands investment. I would like to thank all of our investors for their support.

(signed)

Marcel R. Coutu President and Chief Executive Officer February 21, 2013

05 | Track Record

An oil sands pioneer, Syncrude has produced more than two billion barrels of high-quality crude oil to date. Leveraging its significant technical and operating experience gained over several decades, Syncrude is actively working to identify and develop new ways to achieve operational efficiencies and minimize our impact on the environment. Syncrude’s expertise is further enhanced by ExxonMobil/Imperial Oil, which contribute global best- in-class operating systems and procedures as a foundation for strong, stable production.



2012 Progress

Accomplishments and objectives

MAXIMIZING THE VALUE OF YOUR COS INVESTMENT

OPTIMIZING OPERATIONS DEVELOPING THE CAPACITY FOR LONG-TERM GROWTH

In 2012, we achieved most of our goals. Importantly, we reached some important milestones in our commitment to responsible development of the oil sands. We were able to deliver a higher dividend and a stronger balance sheet by year-end than originallyexpected.Thiswasbalancedbyessentiallyflatyear-over-yearproduction and mid-tier total shareholder returns.

• Weexceededourcommitmentto pay a minimum of $0.30 in quarterly dividends per share to investors and raised it to $0.35 per share for a total of $1.35 in dividends per share in 2012.

• With$1.6billionincashatyear-end,we maintained a strong balance sheet while remaining unhedged in our production, allowing investors full exposure to crude oil prices.

• Wefellshortofourgoaltoachieveatop-quartile total shareholder return (dividends plus capital appreciation) with results that placed us in the middle of our peer group.

• Productionwasflatyear-over-year,and less than our growth target of 113 million barrels. We successfully achieved our goal of a 36-month run-timeforCoker8-3;however,wehadunplanneddowntimeonCoker8-1 and in our mining operations.

• Weachievedsimilartotaloperatingexpenses year-over-year. Due to lower production, however, per barrel operating expenses were higher than expected.

• Asplanned,wecompleteddetailedengineering and announced total expected cost of mine train relocations and replacements, and began construction of these projects.

• ContinuedimplementationoftheManagement Services Agreement (MSA) with ExxonMobil.

• In2012,wecontinuedtoassesstheeconomics for execution of the Aurora South project in the next decade.

• WeannouncedtheproposedMildredLake mine extension (MLX) project, which is expected to provide a low-cost source of new bitumen production into the 2030s.

• Weevaluatedoilsands-related assets but did not identify an attractive opportunity to add value for our shareholders. We are very disciplined in our approach to acquisitions and careful to not dilute the value of our Syncrude asset.

S T R AT E G I C S C O R E C A R D


Looking ahead to 2013

BEING A RESPONSIBLE PRODUCER

OUR GOAL IS TO DELIVER THE FULL VALUE OF THE SYNCRUDE ASSET BY OPTIMIZING THE RESOURCE POTENTIAL AT SYNCRUDE, PROFITABLY AND RESPONSIBLY GROWING PRODUCTION, AND MAXIMIZING CAPITAL EFFICIENCY.

In 2013, we expect to significantly advance our major projects. We anticipate gradual production growth, which should bring our per barrel operating costs down. We will continue to invest significantly in research and development, about half of which is dedicated to environmental projects. And, we plan to achieve these goals while maintaining a strong balance sheet and delivering a healthy dividend.

• Invested$0.4billionnettoCOS ($1.1 billion to Syncrude) in

environmental projects.• COSstrengthenedourparticipationin

Syncrude’s Safety, Health and Corporate Sustainability Committee to enable enhanced oversight of Syncrude’s environmental performance.

• Commissionedtheindustry’sfirstcommercial-scale demonstration of anend-pitlake;Syncruderesearchintothistechnologysincethe1980shasshown these lakes can support healthy communities of aquatic ecosystems.

• Completedplantingofvegetationforfenwetlandresearchproject;activeresearch will now begin on hydrology, wetland and terrestrial plant response, and climate conditions.

• Startedconstructionofourcentrifugetailings management project, a new technology to accelerate tailings reclamation.

• Increaseproductionbyaboutfive per cent, equivalent to five million barrels gross to Syncrude, over 2012 production.

• Improveperbarreloperatingexpensesin 2013 over 2012.

• CompletetheAuroraNorthTailingsManagement project.

• Achieve90percentcompletionon the Aurora mine train relocations.

• Achieve75percentcompletiononthe Mildred Lake mine train replacements.

• Invest$25million($70milliongross to Syncrude) in research and development, directed at reducing operating expenses, improving reliability, enhancing environmental performance and realizing potential cost savings in environmental initiatives.

• Aimtomaintainaquarterlydividendof $0.35 per share in 2013, based on the assumptions outlined in the 2013 guidance.

• Maintainastrongbalancesheetwhileremaining unhedged on oil prices, thereby providing investors with the full potential of this commodity.

10 | CANA DIA N O I L SA NDS L I M I T ED

C O N T E N T S

1 1 Management’s Discussion and Analysis 1 1 Forward-Looking Information Advisory 12 Non-GAAP and Additional GAAP Financial Measures 13 Business Description 14 Overview 15 Review of Financial Results 22 Summary of Quarterly Results 23 Capital Expenditures 24 Contractual Obligations and Commitments 24 Dividends 25 Liquidity and Capital Resources 26 Shareholders’ Capital and Trading Activity 27 Critical Accounting Estimates and Judgements 29 Changes in Accounting Policies 29 Accounting Pronouncements Not Yet Adopted 30 Financial Instruments 30 Risk Management 36 2012 Actual Results Compared to Outlook 37 2013 Outlook 41 Management’s Report 42 Independent Auditor’s Report 44 Consolidated Statements of Income and Comprehensive Income 45 Consolidated Statements of Shareholders’ Equity 46 Consolidated Balance Sheets 47 Consolidated Statements of Cash Flows 48 Notes to Consolidated Financial Statements 73 Advisory 75 Glossary and Abbreviations 76 Statistical Summary IBC Shareholder Information

F I N A N C I A L R E V I E W

Measuring performance


M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S

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Management’s Discussion and Analysis

The following Management’s Discussion and Analysis (“MD&A”) was prepared as of February 21, 2013 and should be read in conjunction with the audited consolidated financial statements and notes thereto of Canadian Oil Sands Limited (the “Corporation”) for the years ended December 31, 2012 and December 31, 2011 and the Corporation’s Annual Information Form (“AIF”) dated February 21, 2013. Additional information on the Corporation, including its AIF, is available on SEDAR at www.sedar.com or on the Corporation’s website at www.cdnoilsands.com. References to “Canadian Oil Sands”, “COS”, or “we” include the Corporation, its subsidiaries and partnerships. The financial results of Canadian Oil Sands have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”) and are reported in Canadian dollars, unless stated otherwise.

Forward-Looking Information Advisory

In the interest of providing the Corporation’s shareholders and potential investors with information regarding the Corporation, including management’s assessment of the Corporation’s future production and cost estimates, plans and operations, certain statements throughout this MD&A contain “forward-looking information” under applicable securities law. Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “believe”, “plan”, “intend” or similar words suggesting future outcomes.

Forward-looking statements in this MD&A include, but are not limited to, statements with respect to: the expectations regarding the 2013 annual Syncrude forecasted production range of 105 million barrels to 115 million barrels and the single-point Syncrude productionestimate of 110 million barrels (40.4 million barrels net to the Corporation); the timing of the Coker 8-1 turnaround; the intention to maintain a quarterly dividend of $0.35 per Share in 2013 based on the assumptions in our 2013 Outlook; future dividends and any increase or decrease from current payment amounts; the establishment of future dividend levels with the intent of absorbing short-term market volatility over several quarters; the level of natural gas consumption and production in 2013 and beyond; the expected sales, operating expenses, development expenses, Crown royalties, capital expenditures and cash flow from operations for 2013; the anticipated amount of current taxes in 2013; expectations regarding current taxes beyond 2013; the expectation that proceeds from the March 2012 Senior Note offering will be used to repay U.S. $300 million of Senior Notes which mature on August 15, 2013, to fund major capital projects over the next few years and for general corporate purposes; expectations regarding the Corporation’s cash levels for 2013 and 2014; the expected price for crude oil and natural gas in 2013; the expected foreign exchange rates in 2013; the expected realized selling price, which includes the anticipated differential to West Texas Intermediate (“WTI”) to be received in 2013 for the Corporation’s product; the expectations regarding net debt; the anticipated impact of increases or decreases in oil prices, production, operating expenses, foreign exchange rates and natural gas prices on the Corporation’s cash flow from operations; the expectation that regular maintenance capital costs will average approximately $10 per barrel for years after 2013; the expected amount of total major project costs, anticipated target in-service dates and estimated completion percentages for the Mildred Lake mine train replacements, the Aurora North mine train relocations, the composite tails plant at the Aurora North mine and the centrifuge plant at the Mildred Lake mine; the expectation that the Corporation will finance the major projects primarily with existing cash balances and cash flow from operations; the cost estimates for 2013 to 2015 major project spending; the expectation that the volatility in WTI and the Synthetic Crude Oil (“SCO”) to WTI differential is likely to persist for several years until additional planned pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing,Oklahoma, the U.S. Gulf Coast or the Canadian East or West Coasts; the views regarding the reinstatement of the Corporation’s premium dividend, dividend reinstatement and optional share purchase plan; plans regarding crude oil hedges in the future; the belief that the mine train relocations/replacements will not impact production; the expectations regarding inflation and labour in the Wood Buffalo Region; the expectations regarding refining demand for SCO; the expectations regarding where SCO will be consumed in the future; the expectationsregarding pipeline apportionment and capacity; the impacts of increased supplies of crude oil, refining demand for SCO, pipeline and rail access and capacity; and market access and price differentials on the realized selling price the Corporation receives for its SCO.

You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, knownand unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Corporation believes that the expectations represented by such forward-looking statements are reasonable and reflect the current views of the Corporation with respect to future events, there can be no assurance that such assumptions and expectations will prove to be correct.

The factors or assumptions on which the forward-looking information is based include, but are not limited to: the assumptions outlined in the Corporation’s guidance document as posted on the Corporation’s website at www.cdnoilsands.com as of January 31, 2013 and as subsequently amended or replaced from time to time, including without limitation, the assumptions as to production, operating expenses and oil prices; the successful and timely implementation of capital projects; Syncrude’s major project spending plans; the ability to obtain regulatory and Syncrude joint venture owner approval; our ability to either generate sufficient cash flow from operations to meet our current and future obligations or obtain external sources of debt and equity capital; the continuation of assumed tax, royalty and regulatory regimes and the accuracy of the estimates of our reserves and resources volumes.

12 | CA NA DIA N O I L SA NDS L I M I T ED


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Some of the risks and other factors which could cause actual results or events to differ materially from current expectations expressed in the forward-looking statements contained in this MD&A include, but are not limited to: the impacts of legislative or regulatory changes especially as such relate to royalties, taxation, the environment and tailings; the impact of technology on operations and processes and how new complex technology may not perform as expected; skilled labour shortages and the productivity achieved from labour in the Fort McMurray area; the supply and demand metrics for oil and natural gas; the impact that pipeline capacity and refinery demand have on prices for our SCO; the unanimous joint venture owner approval for major expansions and changes in product types; the variances of stock market activities generally; global economic conditions/volatility; normal risks associated with litigation, general economic, business and market conditions; the impact of Syncrude being unable to meet the conditions of its approval for its tailings management plan under Directive 074; volatility of crude oil prices; volatility of the SCO to WTI price differential; unsuccessful or untimely implementation of capital or maintenance projects and such other risks and uncertainties described in the Corporation’s AIF dated February 21, 2013 and in the reports and filings made with securities regulatory authorities from time to time by the Corporation which are available on the Corporation’s profile on SEDAR at www.sedar.com and on the Corporation’s website at www.cdnoilsands.com.

You are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this MD&A are made as of February 21, 2013, and unless required by law, the Corporation does not undertake any obligation to updatepublicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

Non-GAAP and Additional GAAP Financial Measures

In this MD&A and the related press release, we refer to financial measures that do not have any standardized meaning as prescribed by Canadian GAAP. These financial measures include additional GAAP financial measures, which are line items, headings or subtotals in addition to those required under Canadian GAAP, and non-GAAP financial measures. Additional GAAP and non-GAAP financial measuresprovide information that we believe is meaningful regarding the Corporation’s operational performance, its liquidity and its capacity to fund dividends, capital expenditures and other investing activities. Users are cautioned that additional GAAP and non-GAAP financial measures presented by the Corporation may not be comparable with measures provided by other entities.

We refer to one additional GAAP financial measure: cash flow from operations, which is calculated as cash from operating activities, as reported on the Consolidated Statements of Cash Flows, before changes in non-cash working capital. We believe cash flow from operations, which is not impacted by fluctuations in non-cash working capital balances, is more indicative of operational performance. The majority of our non-cash working capital is liquid and typically settles within 30 days.

Cash flow from operations is reconciled to cash from operating activities as follows:

($ millions) 2012 2011

Cash flow from operations $ 1,581 $ 1,897 Change in non-cash working capital1 283 61 Cash from operating activities1 $ 1,864 $ 1,958 1 As reported in the Consolidated Statements of Cash Flows.

Non-GAAP financial measures include cash flow from operations per Share, which is calculated as cash flow from operations divided by the weighted-average number of Shares outstanding in the period; net debt; total debt; total net capitalization; total capitalization; net debt-to-total net capitalization; and total debt-to-total capitalization. In addition, the Corporation refers to various per barrel figures, such as net realized selling prices, operating expenses and Crown royalties, which also are considered non-GAAP measures. We derive per barrel figures by dividing the relevant sales or cost figure by our sales volumes, which are net of purchased crude oil volumes in a period.


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Business Description

Canadian Oil Sands is the largest joint venture owner of the Syncrude Joint Venture (“Syncrude”), a major producer of high quality, low sulphur, light, synthetic crude oil (“SCO”). Canadian Oil Sands’ only producing asset is a 36.74 per cent working interest in Syncrude, generating revenue from its share of production, and represents the only public opportunity for undiversified investment directly in Syncrude.

The Syncrude Project is located near Fort McMurray, Alberta and is comprised of oil sands mines, utilities plants, bitumen extraction plants and an upgrading complex that processes bitumen into SCO. Syncrude Canada Ltd. (“Syncrude Canada”) operates Syncrude on behalf of the Syncrude owners and is responsible for selecting, compensating, directing and controllingSyncrude’s employees, and for administering all related employment benefits and obligations. Each joint venture owner has an undivided interest in the assets of Syncrude, takes its production in kind, and funds its proportionate share of Syncrude’s operating, development and capital expenditures on a daily basis. Oversight of Syncrude Canada is provided by a Syncrude Management Committee and various management sub-committees as well as Syncrude Canada’s Board of Directors and Board committees, all of which are staffed by representatives of the Syncrude owners. In particular, the Syncrude Management Committee oversees and approves significant Syncrude expenditures and long-term strategies.

Syncrude’s leases are located in the Athabasca oil sands deposit. Syncrudes reserves and resources are all considered to be recoverable through surface mining, meaning that the layers of oil sands are found beneath a relatively shallow overburden layer. Based on evaluations performed in accordance with the COGE Handbook by our qualified independent petroleum reserve evaluators effective December 31, 2012, Canadian Oil Sands estimates Syncrude’s proved plus probable reserves at 4.6 billion barrels (1.7 billion barrels net to the Corporation), best estimate contingent resources at 5.2 billion barrels (1.9 billion barrels net to the Corporation) and best estimate prospective resources at 1.6 billion barrels(0.6 billion barrels net to the Corporation) of SCO. Based on the current annual production outlook for 2013 of 110 million barrels, or 40.4 million barrels net to Canadian Oil Sands, Syncrude’s estimated proved plus probable reserve life is approximately 42 years. More information regarding Canadian Oil Sands’ reserves and resources can be found in the “Reserves Data and Other Information” section in our 2012 AIF at www.sedar.com or on our website at www.cdnoilsands.com.

Syncrude produces SCO from the Athabasca oil sands deposits by open-pit mining the oil sands, extracting the bitumen from the sands, upgrading the recovered bitumen into lighter oil fractions and combining those component fractions into a single SCO product. Using proven open-pit mining technologies to access the oil sands deposits results in a recovery rate of 90 per cent or more of the bitumen in place. As a large, integrated facility, production volumes reflect the capacity of thefacility and the reliability of Syncrude’s operations. Reliability is a critical success factor for Syncrude because the operatingcosts are largely fixed. The aim is to maximize throughput and utilization of the various operating units in a safe and sustainable manner in order to increase production volumes and reduce per-barrel costs, thereby enhancing the economics of the Syncrude project. While regular maintenance of operating units is required, unplanned outages of units can occur, and these outages usually result in additional maintenance or repair costs and reduced production volumes, which consequently impacts revenues and operating expenses. Over the past six years, Syncrude’s production has been fairly stable, averaging about 290,000 barrels per day. Syncrude’s operations are subject to a number of risks that are discussed in further detail in the “Risk Management” section of this MD&A.

Canadian Oil Sands’ cash flow from operations and net income are dependent on the selling price received for SCO, sales volumes, operating and other expenses, including Crown royalties. The dividends paid to Shareholders are likewise dependent on these factors and on the amount and timing of capital expenditures. The price we receive for our SCO, net of crude oil purchases and transportation expense, reflects the realized selling price at the Syncrude plant gate. Historically, our selling price has correlated closely with the West Texas Intermediate (“WTI”) benchmark oil price and has been impacted by movements in United States/Canadian (“U.S./Cdn”) currency exchange rates. However, supply and demand fundamentals are creating volatility in crude oil prices and are impacting the weighted-average price differential of our SCO product relative to Canadian dollar WTI as well as WTI prices relative to other crude oil benchmarks. These price differentials can change quickly, reflecting changes in the short-term supply and demand in the market and pipeline availability for transporting crude oil. Canadian Oil Sands prefers to remain unhedged on crude oil prices; however, during



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periods of significant capital spending and financing requirements, the Corporation may hedge prices to reduce cash flow volatility.

Overview

Canadian Oil Sands recorded cash flow from operations of approximately $1.6 billion, or $3.26 per Share, in 2012, despite a business climate characterized by global economic concerns and crude oil pipeline capacity constraints in North America, both of which contributed to oil price volatility.

In 2012, WTI crude oil prices averaged U.S. $94 per barrel, U.S. $18 per barrel below European Brent prices, reflecting an over-supply of crude oil and limited pipeline capacity in inland North American markets. The realized selling price of our SCO averaged $92 per barrel, a $2.50 per barrel discount to WTI. Syncrude’s upgrader helped Canadian Oil Sands avoid the deeper discounts suffered by Western Canadian heavy oil producers.

Syncrude production in 2012 was seven per cent lower than our original 2012 outlook, and totalled 104.9 million barrels, or 286,500 barrels per day. This compares with 105.3 million barrels, or 288,400 barrels per day, in 2011. Volumes in 2012 reflect maintenance on Coker 8-1, planned turnarounds of Coker 8-3 and the Vacuum Distillation Unit, and unplanned outages in mine trains. Volumes in 2011 reflect the planned Coker 8-2 turnaround and unplanned outages of Coker 8-1 and a hydrogen unit.

Syncrude’s operating expenses in 2012 were similar to 2011, reflecting the start-up of a pilot centrifuge plant to treat tailings, cost escalation, and higher maintenance costs in 2012, offset by lower purchased energy costs, due primarily to lower natural gas prices and diesel volumes, relative to 2011.

Capital expenditures in 2012 increased over 2011 as Syncrude made significant progress on multi-year capital projects to replace or relocate mine trains and support tailings management plans. Total cost, progress and in-service date estimates for these projects, which remain on schedule and on budget, are as follows:

Total Cost Total Cost Estimated % Target Estimate Estimate Complete at In-Service ($ billions) Accuracy (%) Dec 31, 20122 Date

Mildred Lake Mine Train Replacement $ 1.6 +15%/-15% 35% Q4 2014

Aurora North Mine Train Relocation $ 0.4 +15%/-15% 55% Q1 2014

Aurora North Tailings Management $ 0.3 +15%/-15% 70% Q4 2013

Centrifuge Tailings Management $ 0.7 +15%/-15% 10% H1 2015

- Costs include capital expenditures, excluding capitalized interest, and certain development expenses.

Crown royalties decreased in 2012 from 2011, reflecting an increase in deductible capital expenditures, primarily due to spending on the major capital projects.

In 2012, Canadian Oil Sands issued U.S. $700 million of long-term debt, providing increased liquidity to fund the major capital projects and the U.S. $300 million debt maturity in 2013. With cash of $1.6 billion and net debt, comprised of total debt less cash and cash equivalents, of $0.2 billion at December 31, 2012, we are well-positioned to manage risks associated with the capital program, even under an uncertain outlook for oil prices. We intend to fund our share of Syncrude’s upcoming capital expenditures with existing cash balances and cash flow from operations, which remains strong at prevailing oil prices.

During 2012, the Corporation paid dividends to Shareholders totalling $654 million, or $1.35 per Share. We are targeting a quarterly dividend of $0.35 per Share in 2013.


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In 2013, we are estimating annual Syncrude production of 110 million barrels, a five per cent increase over 2012 levels. Total operating expenses in 2013 are forecast at $1.5 billion, similar to 2012. However, because of the relatively fixed-cost nature of the Syncrude operation, per barrel operating expenses in 2013 are forecast to decrease by six per cent with the higher production estimate. Total 2013 capital expenditures are estimated at $1.3 billion. We are forecasting continued progress on our major projects in 2013, with capital expenditures on those projects estimated at $0.8 billion.

Review of Financial Results

Canadian Oil Sands’ unaudited fourth quarter 2012 results were discussed and analyzed in our MD&A released on January 31, 2013 and filed with the Corporation’s January 31, 2013 press release, which is available on our website at www.cdnoilsands.com or at www.sedar.com.

Highlights ($ millions, except per Share and volume amounts) 2012 2011 2010

Cash flow from operations1 $ 1,581 $ 1,897 $ 1,232 Per Share1 $ 3.26 $ 3.91 $ 2.55

Net income $ 981 $ 1,144 $ 1,189 Per Share, Basic and Diluted $ 2.02 $ 2.36 $ 2.46

Sales, after crude oil purchases and transportation expense $ 3,566 $ 3,934 $ 3,180

Sales volumes2

Total (mmbbls) 38.7 38.7 39.2 Daily average (bbls) 105,680 106,015 107,280

Realized SCO selling price ($/bbl)3 $ 91.90 $ 101.20 $ 80.53

West Texas Intermediate (“WTI”) (average $US/bbl) $ 94.15 $ 95.11 $ 79.61

Operating expenses ($/bbl)3 $ 39.06 $ 38.80 $ 35.42

Capital expenditures $ 1,086 $ 643 $ 582

Dividends $ 654 $ 533 $ 896 Per Share $ 1.35 $ 1.10 $ 1.85

Total assets $ 10,171 $ 8,620 $ 7,132

Net debt4 $ 241 $ 414 $ 1,171

Total other long-term liabilities5 $ 1,509 $ 1,488 $ 780 1 Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined in the “Non-GAAP and Additional GAAP Financial Measures” section of this MD&A.2 The Corporation’s sales volumes differ from its production volumes due to changes in inventory, which are primarily in-transit pipeline volumes.

Sales volumes are net of purchases.3 These per barrel measures have been derived by dividing the relevant item by sales volume in the period.4 Current and non-current portions of long-term debt less cash and cash equivalents. Net debt is a non-GAAP measure.5 Includes non-current portions of employee future benefits and the asset retirement obligation, as well as other liabilities.



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Cash Flow from Operations

2012 vs 2011 2011 vs 2010 ($ millions) ($ millions)

The decrease in cash flow from operations to $1,581 million, or $3.26 per Share, in 2012 from $1,897 million, or $3.91 per share, in 2011, reflects a lower realized selling price, partially offset by lower Crown royalties.

The increase in cash flow from operations to $1,897 million, or $3.91 per Share, in 2011 from $1,232 million, or $2.55 per Share, in 2010 reflects a higher realized selling price partially offset by higher operating expenses.

Net Income Net income decreased to $981 million, or $2.02 per Share, in 2012 from $1,144 million, or $2.36 per Share, in 2011, reflecting a lower realized selling price partially offset by lower Crown royalties, due to higher deductible capital expenditures, lower taxes, and a foreign exchange gain (as opposed to a foreign exchange loss in 2011).

Net income decreased to $1,144 million, or $2.36 per Share, in 2011 from $1,189 million, or $2.46 per Share, in 2010. A higher realized selling price in 2011 was partially offset by higher operating expenses and a foreign exchange loss (as opposed to a gain in 2010). In addition, the large income tax recovery recorded in 2010, due to re-measuring the deferred tax liability upon conversion to a corporation, also served to increase net income in that year.

The following table shows the components of net income per barrel of SCO:

($ per barrel)1 2012 2011 2010

Sales after crude oil purchases and transportation expense $ 92.21 $ 101.66 $ 81.21 Operating expenses (39.06) (38.80) (35.42) Crown royalties (5.21) (7.93) (7.80)

$ 47.94 $ 54.93 $ 37.99 Development expenses2 (2.62) (2.93) (2.68) Administration and insurance (0.95) (0.85) (0.80) Depreciation and depletion (10.41) (9.84) (10.96) Net finance expense (1.01) (1.19) (2.09) Foreign exchange gain (loss) 0.65 (0.57) 1.54 Tax (expense) recovery (8.23) (10.00) 7.36

(22.57) (25.38) (7.63) Net income per barrel $ 25.37 $ 29.55 $ 30.36 Sales volumes (mmbbls)3 38.7 38.7 39.2 1 Unless otherwise specified, the per barrel measures in this MD&A have been derived by dividing the relevant item by sales volumes in the period.2 Previously referred to as non-production expenses.3 Sales volumes, net of purchased crude oil volumes.

$1,400

$1,500

$1,600

$1,700

$1,800

$1,900

$2,000

$1,897

2011

($366)

Selling Price

$105

Crown Royalties

($55)

Other

$1,581

2012

$900

$1,100

$1,300

$1,500

$1,700

$1,900

$2,100

$1,232

2010

$791

Selling Price

($114)

Operating Expenses

($12)

Other

$1,897

2011


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Sales Net of Crude Oil Purchases and Transportation Expense

Changes ($ millions, except where otherwise noted) 2012 2011 2010 2012 vs 2011 2011 vs 2010

Sales1 $ 3,905 $ 4,182 $ 3,460 $ (277) $ 722 Crude oil purchases (295) (221) (254) (74) 33 Transportation expense (44) (27) (26) (17) (1)

$ 3,566 $ 3,934 $ 3,180 $ (368) $ 754 Sales volumes2 Total (mmbbls) 38.7 38.7 39.2 – (0.5) Daily average (bbls) 105,680 106,015 107,280 (335) (1,265)

Realized SCO selling price3 $ 91.90 $ 101.20 $ 80.53 $ (9.30) $ 20.67 (average $Cdn/bbl)

West Texas Intermediate (“WTI”) $ 94.15 $ 95.11 $ 79.61 $ (0.96) $ 15.50 (average $US/bbl)

SCO premium (discount) to WTI $ (2.52) $ 7.32 $ (1.61) $ (9.84) $ 8.93 (weighted average $Cdn/bbl)

Average foreign exchange rate $ 1.00 $ 1.01 $ 0.97 $ (0.01) $ 0.04 ($US/$Cdn) 1 Sales include sales of purchased crude oil and sulphur.2 Sales volumes, net of purchased crude oil volumes.3 SCO sales net of crude oil purchases and transportation expense divided by sales volumes, net of purchased crude oil volumes.

The $368 million decrease in sales, net of crude oil purchases and transportation expense, from 2011 to 2012 reflects a $91.90 per barrel average realized SCO selling price in 2012, compared with $101.20 per barrel in 2011. The 2012 realized selling price reflects a U.S. $94 per barrel WTI price and a $2.52 per barrel weighted-average SCO discount to WTI, compared with a U.S. $95 per barrel WTI price and a $7.32 per barrel SCO premium in 2011.

The $754 million increase in sales, net of crude oil purchases and transportation expense, from 2010 to 2011 reflects a $20.67 increase in the realized SCO selling price partially offset by lower sales volumes in 2011. The increase in the realizedselling price reflects a U.S. $15.50 per barrel increase in WTI oil prices and an $8.93 improvement in the SCO differential to WTI, partially offset by a stronger Canadian dollar in 2011. Sales volumes decreased from 2010 to 2011, reflecting the Coker 8-1 and hydrogen unit outages in 2011.

Both WTI and the SCO to WTI differential reflect supply/demand fundamentals for inland North American light crude oil. Increasing North American production of light crude oil, and refinery modifications that enable processing of heavier crude oils, can push light crude sales, including SCO, to more distant refineries, thereby increasing transportation costs and exposing Canadian Oil Sands to supply/demand factors in different markets. A number of pipelines in both Canada and the United States are at, or near, capacity and any pipeline apportionments can exacerbate this situation by restricting the ability of WTI, SCO and other crude oils to reach preferred markets. However, strong demand from customers and increases in rail shipments of inland crude to coastal refineries can offset these forces. These supply and demand dynamics create price volatility that is likely to persist for several years until additional planned pipeline or other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast, or the Canadian East or West Coasts.

The Corporation purchases crude oil from third parties to fulfill sales commitments with customers when there are shortfalls in Syncrude’s production and to facilitate certain transportation arrangements. Sales include the sale of purchased crude oil while the cost of these purchases is included in crude oil purchases and transportation expense. Crude oil purchases were higher in 2012 than in 2011, reflecting additional purchased volumes in 2012 to support transportation arrangements. Crude oil purchases were lower in 2011 than in 2010, reflecting additional purchased volumes in 2010 to support transportation arrangements and unanticipated production shortfalls, partially offset by higher crude oil prices in 2011.



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Crown Royalties Crown royalties decreased to $202 million, or $5.21 per barrel, in 2012 from $307 million, or $7.93 per barrel, in 2011 due primarily to increases in deductible capital expenditures. The higher deductible capital expenditures reflect increased spending on capital projects to replace or relocate Syncrude mine trains and to support tailings management plans.

Crown royalties in 2011 of $307 million were similar to 2010 as bitumen prices were largely unchanged year over year, despite increases in realized SCO prices. Lower bitumen production volumes and higher allowed costs in 2011 were largely offset by revisions to the estimated quality and transportation deductions used to calculate Crown royalties for 2009 and 2010.

From 2009 through 2015, Syncrude’s Crown royalties are determined pursuant to the Syncrude Royalty Amending Agreement (“Syncrude RAA”) and the Syncrude Bitumen Royalty Option Agreement.

Under the Syncrude RAA, the Syncrude owners pay the greater of 25 per cent of net deemed bitumen revenues, or one per cent of gross deemed bitumen revenues, plus a transition royalty of up to $975 million ($358 million net to the Corporation) for the period January 1, 2010 to December 31, 2015. The transition royalty of $975 million is reduced proportionally if bitumen production is less than 345,000 barrels per day over the period. The $975 million ($358 million net to the Corporation) is scheduled over six annual installments as follows:

($ millions) 2010 2011 2012 2013 2014 2015 Total

Syncrude $ 75 $ 75 $ 100 $ 150 $ 225 $ 350 $ 975 Canadian Oil Sands’ share $ 27 $ 27 $ 37 $ 55 $ 83 $ 129 $ 358

Under the Syncrude Bitumen Royalty Option Agreement, costs related to capital expenditures that were deducted in computing Crown royalties on SCO prior to 2009, and are no longer associated with the royalty base, are recaptured by the Crown. These recapture amounts vary based on Government of Canada long-term bond rates and result in approximately $25 million of additional Crown royalties per year, net to the Corporation, over a 25-year period.

The Syncrude RAA requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil reference price further adjusted to reflect quality and location differences between Syncrude’s bitumen and the Canadian reference price bitumen. In addition, the agreement provides that a minimum bitumen value, or “floor price”, may be imposed in circumstances where Canadian heavy oil prices are temporarily suppressed relative to North American heavy oil prices.

Canadian Oil Sands’ share of the royalties recognized for the period from January 1, 2009 to December 31, 2012 reflect management’s best estimate of both reasonable quality and transportation deductions and adjustments to reflect the “floor price”. However, the Syncrude owners and the Alberta government are disputing the basis for the quality, transportation and “floor price” adjustments. Under alternate assumptions, Crown royalties for this period could be as much as $55 million (on an after-tax basis) more than the amounts recognized.

The Syncrude owners and the Alberta government continue to discuss these matters, but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. The cumulative impact, if any, of such discussions or judicial determination, as applicable, would impact both net income and cash flow from operations accordingly.


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Operating Expenses The following table breaks down operating expenses into their major components:

2012 2011 2010 $ millions $ per bbl $ millions $ per bbl $ millions $ per bbl

Production1 $ 1,242 $ 32.12 $ 1,163 $ 30.08 $ 1,103 $ 28.16 Natural gas and diesel purchases2 125 3.22 194 5.01 168 4.29 Pension and incentive compensation 103 2.67 100 2.58 88 2.24 Other3 41 1.05 44 1.13 28 0.73 Total operating expenses $ 1,511 $ 39.06 $ 1,501 $ 38.80 $ 1,387 $ 35.42 1 Includes maintenance (planned and unplanned) as well as non-major turnaround costs. Major turnaround costs are capitalized as property, plant and

equipment.2 Includes costs to purchase natural gas used to produce energy and hydrogen and diesel consumed as fuel.3 Includes fees for management services provided by Imperial Oil Resources, insurance premiums, and greenhouse gas emissions levies.

On a total dollar basis, operating expenses in 2012 were similar to 2011, reflecting higher 2012 production costs largely offset by lower natural gas and diesel purchases. The increase in production costs was due primarily to:

• the start-up of a pilot centrifuge plant to treat tailings; • cost escalation; and • higher maintenance costs, reflecting the Coker 8-1 shutdown in the first quarter of the year.

The lower natural gas and diesel purchases reflect lower natural gas prices and diesel volumes relative to 2011.

On a total dollar basis, operating expenses increased about eight per cent from 2010 to 2011, reflecting: • higher maintenance costs in 2011, primarily in tailings management and extraction; and • increased diesel costs in 2011. Low-sulphur regulations that went into effect in mid-2010 have reduced the amount

of diesel that Syncrude can produce internally, resulting in increased diesel purchases. In addition, diesel prices were 30 per cent higher in 2011 relative to 2010.

Operating expenses on a per barrel basis are affected by the Corporation’s sales volumes, which were lower in 2012 and 2011 than in 2010.

The following table shows operating expenses per barrel of bitumen and SCO. The information allocates costs to bitumen production and upgrading on the basis used to determine Crown royalties.

2012 20113 20103

($ per barrel) Bitumen SCO Bitumen SCO Bitumen SCO Bitumen production $ 25.70 $ 29.73 $ 24.43 $ 29.07 $ 22.68 $ 26.76 Internal fuel allocation1 2.11 2.44 2.40 2.85 2.49 2.94 Total bitumen production expenses $ 27.81 $ 32.17 $ 26.83 $ 31.92 $ 25.17 $ 29.70

Upgrading2 $ 9.33 $ 9.73 $ 8.66 Less: internal fuel allocation1 (2.44) (2.85) (2.94)Total upgrading expenses $ 6.89 $ 6.88 $ 5.72

Total operating expenses $ 39.06 $ 38.80 $ 35.42

(thousands of barrels per day)Syncrude production volumes 331 287 343 288 346 293 Canadian Oil Sands sales volumes 106 106 107 1 Reflects energy generated by the upgrader that is used in the bitumen production process and is valued by reference to natural gas and diesel prices.

Natural gas prices averaged $2.34 per GJ in 2012, $3.48 per GJ in 2011, and $3.87 per GJ in 2010. Diesel prices averaged $0.90 per litre in 2012, $0.94 per litre 2011, and $0.72 per litre 2010.2 Upgrading expenses include the operating expenses associated with processing and upgrading bitumen to SCO.3 Certain comparative years’ amounts have been restated to conform to the current year presentation.



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Development Expenses Development expenses, which were previously referred to as non-production expenses, totalled $101 million in 2012, $113 million in 2011, and $105 million in 2010. Development expenses consist primarily of expenditures relating to capital programs, which are expensed, such as pre-feasibility engineering, technical and support services, research, evaluation drilling and regulatory and stakeholder consultation expenditures. Development expenses can vary from period to period depending on the number of projects underway and the development stage of the projects.

Net Finance Expense

($ millions) 2012 2011 2010

Interest costs1 $ 105 $ 87 $ 91 Less capitalized interest (92) (57) (30) Interest expense $ 13 $ 30 $ 61 Accretion of asset retirement obligation 26 16 21 Net finance expense $ 39 $ 46 $ 82 1 Interest costs are net of interest income of $12 million, $4 million and $1 million in 2012, 2011, and 2010, respectively

Interest costs in 2012 were higher than 2011 and 2010 as a result of the U.S. $700 million debt issued on March 29, 2012. However, interest expense fell each year to 2012 because a higher portion of interest costs were capitalized as cumulative capital expenditures on qualifying assets rose.

The increase in accretion of the asset retirement obligation from 2011 to 2012 reflects the increase in the estimated asset retirement obligation recognized in the fourth quarter of 2011.

Depreciation and Depletion Expense Depreciation and depletion expense totalled $403 million in 2012, $381 million in 2011, and $429 million in 2010, reflecting changes made to the estimated useful lives of certain assets.

Foreign Exchange (Gain) Loss

($ millions) 2012 2011 2010

Foreign exchange (gain) loss – long-term debt $ (28) $ 25 $ (58) Foreign exchange (gain) loss – other 3 (3) (2) Total foreign exchange (gain) loss $ (25) $ 22 $ (60)

Foreign exchange gains/losses are primarily the result of revaluations of our U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates.

The foreign exchange gain in 2012 was the result of a strengthening Canadian dollar from U.S. $0.98 at December 31, 2011 to U.S. $1.01 at December 31, 2012. The foreign exchange loss in 2011 was the result of a weakening Canadian dollar from U.S. $1.01 at December 31, 2010 to U.S. $0.98 at December 31, 2011, and the foreign exchange gain in 2010 was the result of a strengthening Canadian dollar from U.S. $0.96 at December 31, 2009 to U.S. $1.01 at December 31, 2010.

The foreign exchange gain in 2012 also reflects higher outstanding debt levels relative to 2011 and 2010, as a result of the U.S. $700 million debt issued on March 29, 2012.


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Tax Expense

($ millions) 2012 2011 2010

Current tax expense $ 40 $ – $ – Deferred tax expense (recovery) 278 387 (289) Total tax expense (recovery) $ 318 $ 387 $ (289)

The decrease in total tax expense from 2011 to 2012 reflects lower before-tax earnings in 2012. The increase in total tax expense from 2010 to 2011 is primarily the result of the following:

• Prior to Canadian Oil Sands’ conversion from an income trust to a corporate structure on December 31, 2010, tax expense was reduced by the payment of distributions to trust unitholders.

• The Corporation’s deferred tax liability was re-measured at a lower tax rate upon conversion to a corporation on December 31, 2010, resulting in a $269 million deferred tax recovery.

Asset Retirement Obligation

($ millions) 2012 2011

Asset retirement obligation, beginning of year $ 1,037 $ 501 Change in risk-free interest rate 68 98 Change in estimated liability 25 471 Accretion expense 26 16 Reclamation spending (54) (49) Asset retirement obligation, end of year $ 1,102 $ 1,037 Less current portion (44) (29) Non-current portion $ 1,058 $ 1,008

Canadian Oil Sands increased its estimated asset retirement obligation in 2012 from $1,037 million at December 31, 2011 to $1,102 million at December 31, 2012. The increase reflects:

• a decrease in the risk-free interest rate used to discount future reclamation and closure expenditures; and • an acceleration in the estimated timing of certain future reclamation and closure expenditures;

partially offset by: • reclamation spending during 2012.

Canadian Oil Sands increased its estimated asset retirement obligation in 2011 from $501 million at December 31, 2010 to $1,037 million at December 31, 2011. The increase reflects:

• additional fluid fine tailings treatment costs required to meet Alberta Energy Resources Conservation Board regulations;

• costs of additional surface water drainage features required for final closure; • higher estimated material handling costs; and • a decrease in the risk-free interest rate used to discount future reclamation and closure expenditures;

partially offset by: • reclamation spending during 2011.

Pension and Other Post-Employment Benefit Plans The liability for the Corporation’s share of Syncrude Canada’s pension and other post-employment benefit plans decreased from $465 million at December 31, 2011 to $438 million at December 31, 2012, reflecting contributions to the plans and higher than estimated returns on plan assets, partially offset by a decrease in the interest rate used to discount future pension costs.

The liability for the Corporation’s share of the plans increased from $327 million at December 31, 2010 to $465 million at December 31, 2011, reflecting a decrease in the interest rate used to discount estimated future pension costs and lower than estimated returns on the pension plan assets, partially offset by contributions to the plans.



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Summary of Quarterly Results

2012 2011 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Sales1 ($ millions) $ 929 $ 941 $ 740 $ 956 $ 884 $ 989 $ 1,045 $ 1,016

Net income ($ millions) $ 221 $ 338 $ 101 $ 321 $ 232 $ 242 $ 346 $ 324 Per Share, Basic & Diluted $ 0.46 $ 0.70 $ 0.21 $ 0.66 $ 0.48 $ 0.50 $ 0.71 $ 0.67

Cash flow from operations2 ($ millions) $ 418 $ 470 $ 245 $ 454 $ 363 $ 512 $ 544 $ 478 Per Share2 $ 0.86 $ 0.97 $ 0.51 $ 0.94 $ 0.75 $ 1.06 $ 1.12 $ 0.99

Dividends ($ millions) $ 169 $ 170 $ 170 $ 145 $ 146 $ 145 $ 145 $ 97 Per Share $ 0.35 $ 0.35 $ 0.35 $ 0.30 $ 0.30 $ 0.30 $ 0.30 $ 0.20

Daily average sales volumes3 (bbls) 111,669 113,331 89,597 108,108 91,259 109,260 102,938 120,894

Realized SCO selling price ($/bbl) $ 89.99 $ 89.89 $ 90.45 $ 97.07 $ 104.78 $ 97.89 $ 111.00 $ 93.04

Operating expenses4 ($/bbl) $ 38.85 $ 36.71 $ 50.66 $ 32.68 $ 46.88 $ 37.19 $ 37.07 $ 35.53

Purchased natural gas price ($/GJ) $ 3.02 $ 2.00 $ 1.79 $ 2.23 $ 3.19 $ 3.51 $ 3.62 $ 3.59

WTI5 (average $US/bbl) $ 88.23 $ 92.20 $ 93.35 $ 103.03 $ 94.06 $ 89.54 $ 102.34 $ 94.60

Foreign exchange rates ($US/$Cdn) Average $ 1.01 $ 1.00 $ 0.99 $ 1.00 $ 0.98 $ 1.02 $ 1.03 $ 1.02 Quarter-end $ 1.01 $ 1.02 $ 0.98 $ 1.00 $ 0.98 $ 0.96 $ 1.04 $ 1.03 1 Sales after crude oil purchases and transportation expense.2 Cash flow from operations and cash flow from operations per Share are additional GAAP and non-GAAP measures, respectively, and are defined in the

“Non-GAAP and Additional GAAP Financial Measures” section of this MD&A. 3 Daily average sales volumes net of crude oil purchases.4 Derived from operating expenses, as reported on the Consolidated Statements of Income and Comprehensive Income, divided by sales volumes

during the period. 5 Pricing obtained from Bloomberg.

During the last eight quarters, the following items have had a significant impact on the Corporation’s financial results: • fluctuations in realized selling prices have affected the Corporation’s sales and Crown royalties. Monthly average

WTI prices have ranged from U.S. $82 per barrel to U.S. $110 per barrel, and the monthly average differentials between our realized selling price and Canadian dollar WTI prices have ranged from a $14 per barrel premium to a $17 per barrel discount;

• U.S. to Canadian dollar exchange rate fluctuations have resulted in foreign exchange gains and losses on the revaluation of U.S. dollar-denominated debt and have impacted realized selling prices;

• planned and unplanned maintenance activities have reduced quarterly production volumes and revenues and increased operating expenses;

• fluctuations in natural gas prices have affected the Corporation’s operating expenses and Crown royalties; and • increased spending on capital projects to replace or relocate Syncrude mining trains and to support tailings

management plans has reduced Crown royalties.

Quarterly variances in net income and cash flow from operations are caused mainly by fluctuations in realized selling prices, production and sales volumes, operating expenses and natural gas prices. Net income is also impacted by foreign exchange gains and losses, depreciation and depletion, and tax expense. The dividends paid to Shareholders are likewise dependent on the factors impacting cash flow from operations as well as the amount and timing of capital expenditures.

While the supply/demand balance for crude oil affects selling prices, the impact of this relationship has not displayed significant seasonality. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is influenced by weather conditions and North American natural gas inventory levels. Technological developments in North American natural gas production have significantly increased production levels and reduced natural gas prices. These conditions may persist for the next several years.


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Syncrude production levels generally do not display seasonal patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit outages cannot always be precisely scheduled and unplanned outages may occur. The costs of major turnarounds are capitalized as property, plant and equipment and depreciated over the period until the next scheduled turnaround. The costs of all other turnarounds and maintenance activities are expensed in the period incurred, which can result in volatility in quarterly operating expenses. Allturnarounds and maintenance activities impact per barrel operating expenses because sales volumes are lower in the periods when this work is occurring.

Capital Expenditures

($ millions) 2012 2011 2010

Major Projects

Mildred Lake Mine Train Replacement $ 362 $ 139 $ 57 Reconstruct crushers, surge facilities, and slurry prep facilities to support tailings storage requirements

Aurora North Mine Train Relocation 98 27 16 Relocate crushers, surge facilities, and slurry prep facilities to support tailings storage requirements

Aurora North Tailings Management 123 40 19 Construct a composite tails (CT) plant at the Aurora North mine to process tailings

Centrifuge Tailings Management 69 39 – Construct a centrifuge plant at the Mildred Lake mine to process tailings

Syncrude Emissions Reduction (SER) 21 110 113 Retrofit technology into Syncrude’s original two cokers to reduce total sulphur dioxide and other emissions

Capital expenditures on major projects $ 673 $ 355 $ 205

Regular maintenance Capitalized turnaround costs $ 76 $ 44 $ 46 Other1 245 187 301 Capital expenditures on regular maintenance $ 321 $ 231 $ 347

Capitalized interest $ 92 $ 57 $ 30 Total capital expenditures $ 1,086 $ 643 $ 582 1 Other regular maintenance capital includes expenditures on relocation of tailings facilities and other infrastructure projects.

Capital expenditures increased to $1,086 million in 2012 from $643 million in 2011 and $582 million in 2010, reflecting increased spending on the major capital projects. More information on these major projects is provided in the “Outlook” section of this MD&A.

Capitalized turnaround costs were higher in 2012 than in 2011 and 2010, reflecting the planned turnarounds of Coker 8-3 and the Vacuum Distillation Unit. By comparison, 2011 capitalized turnaround costs reflect the Coker 8-2 turnaround and 2010 costs reflect the Coker 8-1 and LC Finer turnarounds.

The increasing capitalized interest costs from 2010 to 2012 reflect higher cumulative capital expenditures on qualifying assets.



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Contractual Obligations and Commitments

The following table outlines the significant contractual obligations and commitments that were assumed in the normal course of operations and were known as of February 21, 2013. These obligations and commitments represent future cash payments that the Corporation is required to make under existing contractual agreements that it has entered into either directly, or as a 36.74 per cent owner in Syncrude. The principal payments and accrued interest due on total debt and the asset retirement obligation are recognized as liabilities in the Corporation’s consolidated financial statements. The other contractual obligations and commitments are not recognized as liabilities.

Cash Outflow By Period ($ millions) Total 2013 2014 to 2015 2016 to 2017 After 2017

Total debt1 $ 3,016 $ 409 $ 200 $ 200 $ 2,207 Pipeline and storage commitments2 2,536 46 163 231 2,096 Asset retirement obligation3 2,104 44 88 40 1,932 Pension plan solvency deficiency payments4 357 72 121 67 97 Other obligations5 316 141 92 22 61 Capital expenditure commitments6 246 223 23 – – Natural gas purchase commitments7 94 56 38 – –

$ 8,669 $ 991 $ 725 $ 560 $ 6,393 1 Total debt is a non-GAAP measure and includes current and non-current portions of long-term debt. Actual payments differ from the carrying value

of total debt as the amounts in this table include both principal and interest payments.2 Reflects Canadian Oil Sands’ take-or-pay commitments for transportation and storage of crude oil in support of the Corporation’s strategy to secure

access to markets and enhance marketing flexibility.3 Reflects Canadian Oil Sands’ 36.74 per cent share of the undiscounted estimated future cash flows required to settle Syncrude’s obligation to reclaim and close each of its mine sites and decommission its utilities plants, bitumen extraction plants, and upgrading complex.4 Canadian Oil Sands is responsible for funding its 36.74 per cent share of Syncrude Canada’s registered pension plan solvency deficiency, which was confirmed in the December 31, 2011 actuarial valuation completed in 2012.5 These obligations include, but are not limited to, Canadian Oil Sands’ 36.74 per cent share of Syncrude Canada’s non-cancellable annual fixed fees

under a management services agreement with Imperial Oil Resources, amounts due under Syncrude Canada’s employee retention program, and Synrude’s commitment to purchase tires. 6 Comprised of Canadian Oil Sands’ 36.74 per cent share of Syncrude’s funding commitments primarily related to the major capital projects: the Mildred

Lake Mine Train Replacement, Aurora North Mine Train Relocation, Aurora North Tailings Management and Centrifuge Tailings Management projects. Amounts are due in 2013 and 2014.

7 Reflects Canadian Oil Sands’ 36.74 per cent share of Syncrude’s commitments for natural gas purchases at floating market prices.

During 2012, Canadian Oil Sands entered into new contractual obligations totalling approximately $1.3 billion for the transportation and storage of crude oil in support of the Corporation’s strategy to secure access to markets and enhance marketing flexibility. The Corporation also assumed $250 million in new funding commitments primarily related to the major capital projects, increased its funding commitment by $110 million in respect of Syncrude Canada’s registered pension plan, and assumed $70 million in new commitments related to Syncrude Canada’s employee retention program.

Dividends

On January 31, 2013, the Corporation declared a quarterly dividend of $0.35 per Share for a total dividend of approximately $170 million. The dividend will be paid on February 28, 2013 to Shareholders of record on February 22, 2013. During 2012, the Corporation paid dividends to shareholders totalling $654 million, or $1.35 per Share.

Dividend payments are set quarterly by the Board of Directors in the context of current and expected crude oil prices, economic conditions, Syncrude’s operating performance, and the Corporation’s capacity to finance operating and investing obligations. Dividend levels are established with the intent of absorbing short-term market volatility over several quarters. Dividend levels also recognize our intention to fund the current major projects primarily with cash flow from operations and existing cash balances, while maintaining a strong balance sheet to reduce exposure to potential oil price declines, capital cost increases or major operational upsets.


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Liquidity and Capital Resources

December 31 December 31 December 31 As at ($ millions, except % amounts) 2012 2011 2010

Total debt1,2 $ 1,794 $ 1,132 $ 1,251 Cash and cash equivalents (1,553) (718) (80) Net debt1,3 $ 241 $ 414 $ 1,171

Shareholders’ equity $ 4,515 $ 4,210 $ 3,726

Total net capitalization1,4 $ 4,756 $ 4,624 $ 4,897

Total capitalization1,5 $ 6,309 $ 5,342 $ 4,977

Net debt-to-total net capitalization1,6 (%) 5 9 24

Total debt-to-total capitalization1,7 (%) 28 21 25 1 Non-GAAP measure.2 Includes current and non-current portions of long-term debt.3 Total debt less cash and cash equivalents.4 Net debt plus Shareholders’ equity.5 Total debt plus Shareholders’ equity.6 Net debt divided by total net capitalization.7 Total debt divided by total capitalization.

Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, decreased in 2012 to $0.2 billion at December 31, 2012 from $0.4 billion at December 31, 2011. As a result, net debt-to-total net capitalization fell to five per cent at December 31, 2012 from nine per cent at December 31, 2011. While $1,581 million of cash flow from operations in 2012 fell short of capital expenditures and dividend payments of $1,086 million and $654 million, respectively, a reduction in non-cash working capital more than offset this difference. Shareholders’ equity increased in 2012 to $4.5 billion at December 31, 2012 from $4.2 billion at December 31, 2011, as net income exceeded dividends.

Net debt decreased in 2011 to $0.4 billion at December 31, 2011 from $1.2 billion at December 31, 2010, as Canadian Oil Sands generated approximately $1.9 billion in cash flow from operations, which exceeded capital expenditures and dividend payments of approximately $0.6 billion and $0.5 billion, respectively. Shareholders’ equity increased in 2011 to approximately $4.2 billion at December 31, 2011 from approximately $3.7 billion at December 31, 2010, as net income exceeded dividends.

In June 2012, the Corporation extended the terms of its credit facilities by one year. The term of the $1,500 million operating credit facility was extended to June 1, 2016 and the $40 million extendible revolving term credit facility to June 30, 2014. No amounts were drawn against these facilities at December 31, 2012.

In March 2012, Canadian Oil Sands issued U.S. $400 million of 4.5 per cent unsecured Senior Notes due April 1, 2022 and U.S. $300 million of 6.0 per cent unsecured Senior Notes due April 1, 2042. Interest on the notes is payable semi-annually on April 1 and October 1. Proceeds from the issues will be used to repay U.S. $300 million of Senior Notes, which mature on August 15, 2013, to fund major capital projects over the next few years and for general corporate purposes. As a result of these debt issues, total debt-to-total capitalization rose to 28 per cent at December 31, 2012 from 21 per cent and 25 per cent at December 31, 2011 and 2010, respectively.

The decrease in total debt-to-total capitalization from 25 per cent at December 31, 2010 to 21 per cent at December 31, 2011 reflects the repayment of $145 million drawn against the Corporation’s operating credit facility.

The Senior Notes indentures and credit facility agreements contain certain covenants that restrict Canadian Oil Sands’ ability to sell all or substantially all of its assets or change the nature of its business, and limit total debt-to-total capitalization to 55 per cent. Canadian Oil Sands is in compliance with its debt covenants and, with a total debt-to-total capitalization of 28 per cent at December 31, 2012, a significant increase in debt or decrease in equity would be required to negatively impact the Corporation’s financial flexibility.



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The Corporation’s liquidity position has improved in 2012 as a result of our growing cash position and the issuance of the Senior Notes. Canadian Oil Sands intentionally built cash balances in 2011 and 2012 in order to increase liquidity for funding the major capital projects in 2013 and 2014 and the debt maturity in 2013. We expect cash levels to decrease significantly over the next two years as we fund the major capital projects and repay the 2013 debt maturity. As a result, and based on the assumptions in our 2013 Outlook, net debt levels are expected to rise to $1 billion to $2 billion by the end of 2014, coincident with reduced capital expenditure risk from the completion of our major capital projects.

Shareholders’ Capital and Trading Activity

Canadian Oil Sands issues options, performance units (“PSUs”), and restricted share units (“RSUs”) under its long-term incentive plans for employees, and deferred share units (“DSUs”) as a component of non-executive directors’ compensation.

Options are share-based compensation awards which provide the holder with the right to purchase a Share at an exercise price determined at the date of grant. For options granted prior to 2011, exercise prices are reduced by dividends over a threshold amount. Subject to certain exemptions relating to retirement, death or termination, the options vest by one-third following the date of grant in each of the first three years and expire seven years after the date of grant. At December 31, 2012, there were 2,200,923 options outstanding with a weighted-average exercise price of $26.72 per option. In January and February, 2013, 162,185 options expired and 962,173 options were granted.

PSUs are share-based compensation awards with a settlement value based on the Corporation’s Share price at the end of a three-year vesting period and the total Shareholder return generated by the Corporation relative to a comparator group, comprised of other industry peers and the S&P/TSX oil and gas E&P index, over that three-year period. PSUs are settled in cash, in Shares purchased in the secondary market, or in Shares issued from treasury. At December 31, 2012, there were 240,102 PSUs outstanding with an accrued value of approximately $3.7 million. In February, 2013, 69,796 PSUs matured and 118,833 PSUs were granted.

RSUs are share-based compensation awards with a settlement value based on the Corporation’s Share price at the end of a three-year vesting period. RSUs are settled in cash, in Shares purchased in the secondary market or in Shares issued from treasury. At December 31, 2012, there were 19,541 RSUs outstanding with an accrued value of approximately $0.2 million. In February, 2013, another 12,439 RSUs were granted.

DSUs are share-based compensation awards with a settlement value based on the Corporation’s Share price. DSUs vest immediately upon grant and settle when a director’s service ceases. The settlement value is based on the Corporation’s Share price on that date. DSUs are awarded and settled in cash, in Shares purchased in the secondary market or in Shares issued from treasury. At December 31, 2012 and February 21, 2013, there were 50,352 DSUs outstanding with an accrued value of approximately $1.0 million.

The share-based compensation awards outstanding at February 21, 2013 represent less than one per cent of total Shares outstanding on a Share-equivalent basis.

More detail on the Corporation’s options, PSUs, RSUs and DSUs can be found in the Corporation’s Management Proxy Circular dated March 20, 2012, which is available on our website at www.cdnoilsands.com or at www.sedar.com.


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The Corporation’s shares trade on the Toronto Stock Exchange under the symbol COS. On December 31, 2012, the Corporation had a market capitalization of approximately $9.8 billion with 484.6 million shares outstanding and a closing price of $20.17 per Share. A table summarizing the Shares issued in 2012 is included in Note 14 to the audited consolidated financial statements. The following table summarizes the trading activity for 2012.

Canadian Oil Sands Limited – Trading Activity

Fourth Third Second First Total Quarter Quarter Quarter Quarter 2012 2012 2012 2012 2012

Share price High $ 25.19 $ 21.69 $ 22.34 $ 23.32 $ 25.19 Low $ 18.21 $ 19.10 $ 18.74 $ 18.21 $ 21.01 Close $ 20.17 $ 20.17 $ 21.05 $ 19.72 $ 21.04 Volume of Shares traded (millions) 402.2 81.9 91.7 100.6 128.0 Weighted average Shares outstanding (millions) 484.5 484.6 484.5 484.5 484.5

Premium Dividend, Dividend Reinvestment and Optional Share Purchase Plan On December 31, 2010, upon conversion from an income trust to a corporate structure, the Trust’s Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan (“Trust DRIP”) was replaced by the Corporation’s Premium Dividend, Dividend Reinvestment and Optional Share Purchase Plan (“Corporate DRIP”) with substantially the same terms and conditions as the Trust DRIP. The Corporate DRIP allows eligible Shareholders to direct their dividends to the purchase of additional Shares or receive a premium dividend amount. The Corporate DRIP has been suspended but could be reinstated in the future to help preserve balance sheet equity.

Critical Accounting Estimates and Judgements

In order to provide timely financial information to users, the Corporation makes estimates and uses judgement when determining the assets, liabilities, revenues, expenses, commitments and contingencies reported in the consolidated financial statements and notes. The following estimates and judgements are considered critical because actual results could differ materially from reported results if different assumptions underlying these estimates and judgements were used:

Critical Accounting Estimates

a) Crown Royalties When calculating deemed bitumen revenues on which Crown royalties are based, Canadian Oil Sands must estimate a deemed bitumen value and deductible costs. The deemed bitumen value is based on a Canadian heavy oil reference price adjusted to reflect quality and location differences between Syncrude’s bitumen and the Canadian reference price bitumen. Canadian Oil Sands must estimate these quality and transportation adjustments and, if the assumptions under which these estimates are based change, actual Crown royalties could vary greatly from estimated amounts. Additional information is provided in the “Crown royalties” section of this MD&A.

b) Asset Retirement Obligation In determining the estimated value of the asset retirement obligation, Canadian Oil Sands must estimate the timingand amount of future reclamation and closure expenditures. Given the long reserve life of Syncrude’s leases, the expenditures will be made over approximately the next 70 years and it is difficult to estimate the precise timing and amount of these expenditures. Any changes in the anticipated timing or amount of the expenditures results in a change to the asset retirement obligation, corresponding property, plant and equipment (“PP&E”) asset, accretion expense (within net finance expense), and depreciation and depletion expense.



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c) Employee Future Benefits Canadian Oil Sands accrues its obligations for Syncrude Canada’s post-employment benefits using actuarial and other assumptions to estimate the accrued benefit obligation, the return on plan assets and the expense related to the current period. Changes in these assumptions, or differences between actual and estimated benefit payments and plan asset returns, give rise to actuarial gains and losses. A one per cent decrease in the interest rate used to discount future benefit payments would result in a $205 million increase in Canadian Oil Sands’ share of Syncrude Canada’s accrued benefit obligation and a $10 million decrease in annual interest costs, while a one per cent increase in the interest rate would result in a $160 million decrease in Canadian Oil Sands’ share of the accrued benefit obligation and a $7 million increase in annual interest costs.

d) Impairment In determining the recoverable amount of assets subject to impairment testing, Canadian Oil Sands must estimate the reserves it expects to recover and the related future net revenues expected to be generated from producing those reserves. Reserves and future net revenues are evaluated and reported in a reserve report prepared by independent petroleum reserve evaluators who determine these evaluations using various factors and assumptions, such as: forecasts of mining and extraction recovery and upgrading yield based on geological and engineering data, projected future rates of production, projected operating costs, Crown royalties and taxes, projected crude oil prices, oil price differentials, and timing and amounts of future capital expenditures and other development costs, all of which are estimates. The factors and assumptions used in the estimates are assessed for reasonableness based on the information available at the time the estimates are prepared. As circumstances change and new information becomes available, the estimates could change. Actual results could vary from estimates, which could cause changes to the asset impairment tests.

e) Depreciation and Depletion Canadian Oil Sands calculates depreciation expense for the majority of its assets on a straight-line basis and must estimate the useful lives of these assets accordingly. While these useful life estimates are reviewed on a regular basis and depreciation calculations are revised accordingly, actual lives may differ from the estimates. Canadian Oil Sands calculates depletion expense for asset retirement and mine development costs on a unit-of-production basis and must estimate reserves, which are used as a component of the depletion calculations to allocate capital costs over their estimated useful lives. As circumstances change and new information becomes available, estimated reserves and the resultant depletion calculations could change.

Critical Accounting Judgements

a) Crown Royalties When calculating deemed bitumen revenues on which Crown royalties are based, Canadian Oil Sands must determine a deemed bitumen value and deductible costs. This requires the use of judgement in the application of the governing royalty agreement. The determination of the appropriate application of the royalty agreement may remain uncertain for several years. The final outcome of such determination could result in amounts different from those initially recorded and would impact Crown royalties in the period in which a determination is made. Additional information is provided in the “Crown royalties” section of this MD&A.

b) Asset Retirement Obligation Canadian Oil Sands applies judgement in determining that the risk-free interest rate is the appropriate rate to discount the asset retirement obligation. Alternatively, a credit-adjusted rate could be used which would yield a smaller asset retirement obligation and corresponding PP&E asset, lower depreciation and depletion expense and a higher accretion expense, which is presented within net finance expense.


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c) Taxes In determining its current and deferred tax provisions, Canadian Oil Sands must apply judgement when interpreting and applying complex and changing tax laws and regulations. The determination of the appropriate application of these laws and regulations by tax authorities may remain uncertain for several years. The final outcome of such determination could result in amounts different from those initially recorded and would impact current or deferred tax expense in the period in which a determination is made.

Changes in Accounting Policies

There were no new accounting policies adopted, nor any changes to accounting policies, in 2012.

Accounting Pronouncements Not Yet Adopted

Employee Future Benefits In June 2011, the International Accounting Standards Board (“IASB”) amended IAS 19, Employee Benefits, addressing the recognition and measurement of defined benefit pension expense and termination benefits, and disclosures for all employee benefits. The amendments are effective for years beginning on or after January 1, 2013 with earlier application permitted. The amendments must be applied retrospectively.

The key amendments are as follows: • Actuarial gains and losses, which will be referred to as re-measurements, are to be recognized immediately in

“other comprehensive income” (“OCI”), eliminating the choice between immediate recognition through net income or OCI, or deferral using the corridor approach. This change will not impact Canadian Oil Sands as the Corporation currently recognizes actuarial gains and losses immediately through OCI.

• An expected rate of return on assets will no longer be calculated. Instead, the interest cost component of the pension expense, which previously represented accretion of the discounted accrued benefit obligation, will now represent accretion of the net accrued benefit liability (the accrued benefit obligation net of the fair value of plan assets). The rate, based on a market rate of interest for high-quality corporate debt instruments with cash flows that match the timing and amount of expected benefit payments, will be the same rate previously used to accrete the discounted accrued benefit obligation.

• Lastly, the interest cost component of pension expense will now be presented within net finance expense.

Canadian Oil Sands has chosen to apply the amendments effective January 1, 2013. The 2012 comparative year amounts reported in the Corporation’s Consolidated Statements of Income and Comprehensive Income in 2013 will be adjusted as follows:

Adjusted To Reflect Amended

($ millions) As Reported Standard Adjustments

Operating expenses $ 1,511 $ 1,504 $ (7) Net finance expense $ 39 $ 60 $ 21 Tax expense $ 318 $ 314 $ (4) Net income $ 981 $ 971 $ (10) Other comprehensive loss, net of taxes $ (21) $ (11) $ 10

Consolidation In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements; IFRS 11, Joint Arrangements, to replace International Accounting Standard (“IAS”) 31, Interests in Joint Ventures; IFRS 12, Disclosure of Interests in Other Entities;and amendments to IAS 27, Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures. These



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new standards and amendments are effective for years beginning on or after January 1, 2013 with earlier application permitted if all five standards are collectively adopted.

IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements. IFRS 11 eliminates the accounting policy choice between proportionate consolidation and equity method accounting for joint ventures available under IAS 31 and, instead, mandates one of these two methodologies based on the economic substance of the joint arrangement. IFRS 12 requires entities to disclose information about the nature of their interests in joint ventures. Canadian Oil Sands does not anticipate that any of these standards will result in significant accounting or disclosure changes.

Fair Value Measurement In May 2011, the IASB issued IFRS 13, Fair Value Measurements, which establishes a single source of guidance for fair value measurements and related disclosures. The new standard is effective for years beginning on or after January 1, 2013 with earlier application permitted. Canadian Oil Sands does not anticipate that this standard will result in significant accounting or disclosure changes.

Financial Instruments: Disclosures In December 2011, the IASB issued amendments to IFRS 7, Financial Instruments: Disclosures, effective for years beginning on or after January 1, 2013 with retrospective application for all comparative periods. The amendments require entities to disclose information about the effect, or potential effect, of netting arrangements on an entity’s financial position.Canadian Oil Sands will be adding these disclosures when the standard becomes effective in 2013; however, we do not expect that this will result in significant changes to disclosures.

Production Stripping Costs In October 2011, the IASB issued International Financial Reporting Interpretations Committee (“IFRIC”) Interpretation 20, Stripping Costs in the Production Phase of a Surface Mine, which clarifies the accounting for costs associated with waste removal in surface mining during the production phase of a mine. The standard is effective for years beginning on or after January 1, 2013 with earlier application permitted. Canadian Oil Sands does not anticipate that this standard will resultin significant accounting or disclosure changes.

Financial Instruments

The Corporation’s financial instruments include cash and cash equivalents, accounts receivable, investments held in a reclamation trust, accounts payable and accrued liabilities, and current and non-current portions of long-term debt. The carrying values and fair values of the Corporation’s financial instruments are disclosed in Note 20 to the audited consolidated financial statements. The risks associated with these instruments and the Corporation’s management of these risks is disclosed in the “Financial Market Risks” portion of the “Risk Management” section of this MD&A.

Risk Management

Canadian Oil Sands approaches the management of risk systematically through a process designed to identify, categorize and assess risks. Syncrude Canada, as operator of Syncrude, identifies and assesses the operational and environmental, health, and safety (“EH&S”) risks that may impact its operations. The Corporation then augments Syncrude Canada’s analysis with further consideration of risks specific to Canadian Oil Sands. Risks are categorized based on their probability of occurrence and their potential impact on Canadian Oil Sands’ future cash flow from operations, net income, corporate reputation and EH&S performance. Syncrude and Canadian Oil Sands take a number of actions once the risks have been identified and categorized, including avoidance, mitigation, risk transfer and acceptance. In addition to ongoing monitoring and review, the Board of Directors of Canadian Oil Sands Limited is presented at least annually, and with quarterly updates where relevant, with a summary of management’s assessment of the risks and strategies for managing such risks. The Board of Directors reviews the assessment and recommendations, and provides oversight of this risk management process.


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There are a number of risks that could impact Canadian Oil Sands’ cash flow from operations and net income and, therefore, the dividends ultimately paid to Shareholders. Cash flow from operations is sensitive to a number of factors including: Syncrude production; sales volumes; oil and natural gas prices; oil price differentials; foreign currency exchange rates; operating, development, administration and financing expenses; Crown royalties; taxes; and regulatory and environmental risks. Dividends may also be impacted by Canadian Oil Sands’ financing requirements for capital expenditures. Sensitivities to the most significant items affecting cash flow from operations are provided in the “2013 Outlook” section of this MD&A.

The following discusses the significant risks that impact Canadian Oil Sands’ cash flow from operations, net income, corporate reputation and EH&S performance. More information regarding Canadian Oil Sands’ risks is available in its AIF dated February 21, 2013, which is available on our website at www.cdnoilsands.com or at www.sedar.com.

Crude Oil Price Risk The financial condition, operating results and future growth of Canadian Oil Sands are substantially dependent on prevailing and expected prices of oil. Prices for oil are subject to large fluctuations in response to changes in the supply of and demandfor oil, market uncertainty and a variety of additional factors, including access to markets and sufficient transportation capacity, all of which are beyond the control of Canadian Oil Sands. Prices are influenced by global and regional supply and demand factors. These factors include: the condition of the Canadian, United States and global economies; access to markets and sufficient pipeline and rail capacity; weather conditions in Canada and the United States; the actions of the Organization of Petroleum Exporting Countries; governmental regulation; political stability in the Middle East and elsewhere; war, or the threatof war, in oil producing regions; the foreign supply of oil and refined products; the price of foreign imports of crude oil andrefined products and the availability and price of alternate fuel sources. All of these factors are beyond our control and can result in a high degree of price volatility not only in crude oil prices, but also fluctuating price differentials between heavy and light grades of crude oil and price differentials between SCO and light crude oil benchmarks such as WTI and European Brent, all of which can impact prices for SCO. During the past two years, WTI monthly average prices have fluctuated from U.S. $82 per barrel to U.S. $110 per barrel. As a result of increasing Canadian and United States crude oil supply coupled with logistical constraints, this monthly average WTI benchmark traded at an average U.S. $17 per barrel discount to monthly European Brent prices over the same period. Canadian Oil Sands’ realized SCO to WTI monthly average price differential has ranged from a $14 per barrel premium to a $17 per barrel discount over the last two years.

A prolonged period of low crude oil prices could affect the value of our interest in Syncrude and the level of spending on growth projects and could result in curtailment of production. Any substantial and extended decline in the benchmark price of oil or anextended worsening of the differential for SCO compared to either WTI or European Brent would have an adverse effect on the revenues, profitability and cash flow from operations of Canadian Oil Sands and likely affect the ability of Canadian Oil Sandsto pay dividends and to repay its debt obligations.

While the Syncrude Project has not been shut down for non-operational reasons by the joint venture owners since production commenced in 1978, a prolonged period of very low oil prices could result in the owners deciding to suspend production. Any such suspension of production could expose Canadian Oil Sands to significant additional expense and would negatively impact its ability to pay dividends and to repay its debt obligations.

Canadian Oil Sands prefers to remain unhedged on crude oil prices; however, during periods of significant capital spending and financing requirements, management may hedge prices to reduce cash flow volatility. Canadian Oil Sands did not have any crude oil price hedges in place during 2012 or 2011; instead, a strong balance sheet was used to mitigate the risk around crude oil price movements. As at February 21, 2013, the Corporation remains unhedged on its crude oil price exposure.

Marketing and Transportation of Synthetic Crude Oil Risk All of our Syncrude production is transported through the Alberta Oil Sands Pipeline (“AOSPL”) system, which delivers SCO to Edmonton, Alberta. Disruptions in service on this system could adversely affect our crude oil sales and production and cash flow from operations. The AOSPL system feeds into various other crude oil pipelines that are used to deliver SCO to refinery customers within Canada and the United States. Interruptions in the availability or apportionment of volumes on these pipeline systems may limit the ability to deliver production volumes and could adversely impact sales volumes or the prices received for SCO. These interruptions may be caused by the inability of the pipeline to operate, or they can be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity.



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Apportionment on certain export pipelines has resulted from crude oil supply growth and pressure restrictions. To date, apportionment has not affected our sales volumes but has restricted our ability to reach preferred markets as well as our price realizations. Pipeline apportionment is impacted by crude oil supply and demand factors, transportation alternatives, such as rail, logistical improvements, and changes in pipeline capacity. A number of projects to add or expand and extend existing pipelines are currently planned with significant new capacity projected to be available around 2015. There can be no certainty, however, that investments will be made or that regulatory approvals will be received to provide this capacity or that current capacity will not encounter continuing operational incidents. In addition, planned or unplanned shutdowns, reduced processing rates or closures of our refinery customers may limit our ability to deliver SCO.

A significant volume of SCO is sold to customers beyond Edmonton, Alberta to Eastern Canada and the United States. As such, pipeline and rail access and capacity, transportation tariffs, market access and price differentials with competing products are all factors that can affect sales volumes and the realized selling price for SCO. As crude oil production rises andtraditional light crude oil refineries execute projects to refine heavy and sour crudes, we anticipate SCO will be consumed at more distant delivery points. Pipeline transportation costs will rise, and Canadian Oil Sands’ price realization will be impacted by those costs as well as supply and demand factors in those extended markets. As a result, there can be no assurance that the selling price realized for SCO by Canadian Oil Sands will not be negatively impacted in the future.

SCO is carried on pipelines and potentially in the future on railways that cross environmentally sensitive areas. Any spill of SCO into such environmentally sensitive areas could have a negative impact on the environment, our reputation and our ability to transport SCO and potentially expose Canadian Oil Sands to clean up costs.

Operational Risk Our investment in Syncrude is our only producing asset and therefore the results of the Corporation depend on Syncrude’s operations. The Syncrude Project is a 24-hour per day, 365-day per year operation with complex, inter-dependent facilities. The shutdown of any part of Syncrude’s operation could significantly impact the production of SCO. Causes of production shortfalls and/or interruptions may include, but are not limited to: equipment failures; design errors; operator errors; weather-related shutdowns; or catastrophic events such as fire, earthquake, storms, explosions or dam failures.

Productivity of the mining or extraction operations may be such that internally produced bitumen may not be sufficient to supply enough feed for the upgrading facility to meet its production capacity. While Syncrude has the ability to import purchased bitumen, there are physical restrictions on the amount of bitumen that can be transported into Syncrude’s facilities and there is a risk that sufficient quantities of bitumen may not be available or economical. Partially offsetting this risk is the opportunity at periods in time, such as during coker turnarounds, for the mining and extraction operations to produce more bitumen than is required by the upgrading facility, which results in Syncrude building bitumen inventory for later use; however, Syncrude’s capacity to store bitumen is limited to about 2.5 million barrels.

The Syncrude Project incorporates operational risk management programs as well as support from Imperial Oil/ExxonMobil through a Management Services Agreement. These organizations apply robust engineering and design standards and utilize maintenance and inspection procedures to mitigate operational risk. Sustained, safe and reliable operations are critical to achieving targets for production and operating expenses.

In addition, we are exposed to risks associated with major projects, including the possibility that projects will not be completed on time and/or will not achieve their design objectives.

If the mine train relocation and replacement projects, currently in progress, are not executed timely and effectively, production could be adversely impacted. At the Aurora North mine, Syncrude has three mine trains but only operates two at any given time. To mitigate production risk at that location, the plan is to relocate mine trains one at a time, while the other two trains continue to operate. In addition, the mine train relocations will be scheduled during planned upgrader outages when demand for bitumen is lower. To mitigate the risk at the Mildred Lake mine, the plan is to have the replacement mine trains operating before the old mine trains are decommissioned. The mine train relocations and replacements are necessary to vacate depleted pits to allow tailings placement. If the mine trains are not removed on time, there is a risk that Syncrude will not be able to place tailings in these pits, and therefore produce planned levels of bitumen, for some period.


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Complications could arise when major construction projects are commissioned and become operational, as new systems are integrated with existing systems and facilities. The SER project is currently in commissioning and start-up. SER is designed to significantly reduce sulphur emissions and is expected to allow Syncrude to comply with regulated emissions targets over a three-year period following SER’s start-up.

Canadian Oil Sands reduces exposure to some operational risks by maintaining appropriate levels of insurance, primarily business interruption (“BI”) and property insurance. The Corporation has purchased total coverage of approximately U.S. $1.2 billion of BI and property insurance, net to Canadian Oil Sands, in case Syncrude experiences an event causing a loss or interruption of production, such as a fire or explosion at the operating facilities. The BI insurance is subject to an approximate average 90-day self-retention period. While such insurance mitigates the impact of certain operational upsets, insurance is unlikely to fully protect against catastrophic events or prolonged shutdowns.

Canadian Oil Sands also faces risks associated with competition amongst other oil sands producers for limited resources, in particular skilled labour, in the Fort McMurray area where Syncrude and other oil sands producers operate. The demand for these resources creates cost pressure on products and services to operate Syncrude’s facilities.

In addition, limitations on the availability of an experienced workforce, including high attrition rates in oil sands operations,increase the risk of design or operator error. To mitigate this risk, Syncrude Canada is focused on attracting and retaining experienced and skilled labour. Syncrude Canada offers competitive industry compensation to employees and contract staff, has a very strong record for safety performance and is an innovative and socially responsible company committed to the environment and dedicated to its employees, the Aboriginal Peoples, and the communities of northern Alberta. Additionally, Syncrude Canada has employee retention and housing programs to deal with the increased demands on local infrastructure.

There may also be increased activity in global industries, such as mining or refining, which are competing for constrained supplies and labour. While we do not expect any specific shortage to impact our current 2013 production outlook, the ability to achieve higher levels of production in the future may be limited by unexpected supply or labour constraints.

Capital Expenditure Risk Inherent in the mining of oil sands and production of SCO is a need to make substantial capital expenditures. The demand for skilled labour and other limited resources impacting operating expenses is having a similar effect on capital expenditures. There is also a risk that capital maintenance at Syncrude will be required more often than currently planned, or that significant capital projects could arise that were not previously anticipated.

In addition to potential capital cost increases, we are exposed to financing risks associated with funding our share of Syncrude’s capital program. We have historically minimized this risk by diversifying our funding sources, which include credit facilities and cash flow from operations. In addition, we believe that the Corporation has the ability to access public debt and equity markets, given our asset base and current credit ratings; however, maintaining such market access may be impacted by sustained low production and low commodity prices. For further discussion, see the “Liquidity Risk” disclosure within the “Financial Market Risk” section of this MD&A.

Financial Market Risks Canadian Oil Sands is subject to financial market risk as a result of fluctuations in foreign currency exchange rates, interestrates, liquidity, and credit.

Foreign Currency Risk Canadian Oil Sands’ results are affected by fluctuations in the U.S./Cdn currency exchange rates, as sales generated are based on a WTI benchmark price in U.S. dollars while operating expenses and capital expenditures are denominated primarily in Canadian dollars. Our sales exposure is partially offset by U.S. dollar obligations, such as interest costs on U.S.dollar-denominated long-term debt and our share of Syncrude’s U.S. dollar vendor payments. In addition, when our U.S. dollar Senior Notes mature, we have exposure to U.S. dollar exchange rates on the principal repayment of the notes. This repayment of U.S. dollar debt acts as a partial economic hedge against the U.S. dollar-denominated sales receipts we collect from our customers.



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In the past, the Corporation has hedged foreign currency exchange rates by entering into fixed rate currency contracts. The Corporation did not have any foreign currency hedges in place during 2012 or 2011, and does not currently intend to enter into any new currency hedge positions. The Corporation may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.

As at December 31, 2012, portions of Canadian Oil Sands’ cash and cash equivalents, accounts receivable, accounts payable and long-term debt were denominated in U.S. dollars. Based on these U.S. dollar financial instrument closing balances, 2012 net income and other comprehensive income would have increased/decreased by approximately $14 million for every $0.01 decrease/increase in the value of the U.S./Cdn currency exchange rate.

Interest Rate Risk Canadian Oil Sands’ financial results are impacted by U.S. and Canadian interest rate changes because our credit facilities and investments are exposed to floating interest rates. In addition, we are exposed to the refinancing of maturing long-term debt at prevailing interest rates. As at December 31, 2012, there were no amounts drawn on the credit facilities (no amounts drawn on the credit facilities at December 31, 2011) and the U.S. $300 million of Senior Notes, which mature in August 2013, were refinanced with our 2012 senior note issuance. Canadian Oil Sands did not have a significant exposure to interest rate risk due to the short-term nature of its investments and having no outstanding floating rate debt during the year.

Liquidity Risk Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they come due. Canadian Oil Sands actively manages its liquidity through cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through bank credit facilities, estimating future cash flow from operations based on reasonable production and pricing assumptions, understanding operating commitments and future capital expenditure requirements, analysing economic hedging opportunities, and complying with debt covenants. In addition, over the long-term, Canadian Oil Sands spreads out the maturities of its various debt tranches and maintains a prudent capital structure.

Of the total debt outstanding of U.S $1.8 billion, U.S. $1.5 billion is not due until 2019 or later and the $1.5 billion creditfacility does not expire until June 2016. The U.S. $300 million of Senior Notes, which mature in August 2013, were refinanced with our 2012 senior note issuance. Canadian Oil Sands held cash balances totaling $1.6 billion at December 31, 2012, and was in compliance with its debt covenants throughout 2012, collectively resulting in relatively low liquidity risk.

More information regarding the available credit facilities and contractual maturities of Canadian Oil Sands’ long-term debt can be found in Notes 10 and 11, respectively, to the consolidated financial statements.

Credit Risk Canadian Oil Sands is exposed to credit risk primarily through customer receivable balances, financial counterparties with whom the Corporation has invested its cash and cash equivalents, and with its insurance providers in the event of an outstanding claim. The maximum exposure to any one customer or financial counterparty is managed through a credit policy that limits exposure based on credit ratings. The policy also specifically limits the exposure to customers with a credit rating below investment grade to a maximum of 25 per cent of Canadian Oil Sands’ consolidated accounts receivable. This credit risk concentration is monitored on a regular basis. Risk is further mitigated as accounts receivable with customers typically are settled in the month following the sale, and investments with financial counterparties are typically short-term in nature and are placed with institutions that have a credit rating of “R-1 (low)” or better, as defined by the Dominion Bond Rating Service (“DBRS”).

Canadian Oil Sands carries credit insurance on some counterparties to help mitigate a portion of the impact should a loss occur and continues to transact primarily with investment grade customers. The Corporation’s maximum credit exposure related to customer receivables was $311 million at December 31, 2012 ($376 million at December 31, 2011). Substantially all accounts receivable at December 31, 2012 were due from investment grade energy producers, financial institutions, and refinery-based customers, and our cash and cash equivalents were invested in deposits and bankers’ acceptances with


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high-quality senior banks as well as investment grade commercial paper. At present, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.

Syncrude Joint Venture Ownership Risk Syncrude is a joint venture currently owned by seven participants. Each participant is entitled to one vote. Operating decisionsand those relating to debottlenecking matters require a 51 per cent majority with at least three participants’ approving while major growth decisions outside of the original scope of the operations as well as producing multiple products rather than a single product require unanimous approval. Canadian Oil Sands has a representative who chairs Syncrude’s Management Committee, which is a committee of the participants that determines the oversight of Syncrude. Syncrude’s future plans will depend on such agreement and may depend on the financial strength and views of the other participants at the time such decisions are made.

Environmental Risks Canadian Oil Sands is committed to ensuring that Syncrude develops its oil sands resources in a responsible way. We are subject to laws and regulations governing the impact Syncrude and other oil sands operations have on the environment. Additionally, we are subject to reputational risk regarding such environmental impacts. The following highlights the key environmental risks at this time.

Tailings Management Syncrude produces a significant volume of fluid fine tailings, which are presently held in settling basins. Syncrude’s reclamation and closure plan and its Alberta Energy Resources Conservation Board (“ERCB”) approval depends on the use of composite tails, centrifuge and end pit lakes technology to manage tailings fluids and solids associated with bitumen production. There is an inherent risk that such technologies used by Syncrude and most other oil sands producers may not be as effective as desired or perform as required in order to meet the approved reclamation and closure plan. Current initiatives undertaken by Syncrude include the development of the Base Mine Lake demonstration project, implementation of composite tails at Aurora North, implementation of fluid fine tailings centrifugation technology at Mildred Lake, and other sustaining projects such as in-pit containment construction and mine facilities relocations within the mining/tailings footprints.

The Directive 074 legislation, which provides tailings performance criteria and requirements for the oil sands mining industry, allows the ERCB to take enforcement action against companies that fail to meet industry-wide tailings management criteria. Enforcement actions range from non-compliance fees to increased inspections and suspension or cancellation of approvals. It is noteworthy that Directive 074 is performance-based, and gives companies the flexibility to select the technology most applicable to their operation in order to achieve the performance criteria.

While Syncrude continues to develop tailings and fluid fine tailings reclamation technologies, there is a risk of increased costs to develop and implement various measures, the potential for tailings specific regulatory approval conditions to be attached to future regulatory applications and/or renewals, and a risk that Syncrude’s approvals could be suspended or cancelled if it cannot comply with the requirements of Directive 074, all of which could have a material adverse effect on Canadian Oil Sands’ business and financial condition.

Water Usage and Emissions As the Syncrude operations involve the use of water and the emission of sulphur dioxide and other pollutants and greenhouse gases such as carbon dioxide (CO2), legislation which significantly restricts or penalizes current production levels would have a material impact on our operations. While Syncrude is focused on reducing these emissions on a per barrel basis, no assurance can be given that existing or future environmental regulations will not adversely impact the abilityof the Syncrude Project to operate at present levels or increase production, or that such regulations will not result in higher unit costs of production.

Public Perception RiskDevelopment of Canada’s oil sands has received significant attention in political, media and activist commentary on the subject of climate change, greenhouse gas emissions, water usage, land reclamation, and impacts on local stakeholders. Public concerns regarding such issues may directly or indirectly have a negative impact on the profitability of Canadian Oil Sands by: (i) motivating extraordinary environmental and emissions regulation by governmental authorities, which could



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result in changes to Syncrude’s operating requirements, thereby potentially increasing the cost of operation and reclamation and closure; (ii) compelling legislation or policy that limits the purchase of crude oil produced from Canada’s oil sands by governments or other consumers, which, in turn, may limit the market for SCO and reduce its price; and (iii) resulting in proposed pipelines not being able to receive the necessary permits and approvals, which, in turn, may limit the transportation for SCO and reduce its price.

2012 Actual Results Compared to Outlook

In its 2011 annual MD&A, Canadian Oil Sands estimated 2012 Syncrude production volumes, cash flow from operations and capital expenditures (the “original estimate” or “original Outlook”). During 2012 the Corporation revised these estimates in quarterly reports and information releases to reflect actual results for each quarter and new significant information as it became available (the “revised estimate” or “revised Outlook”).

2012 Outlook (millions of Canadian dollars, except volume and per barrel amounts) 2012 Actual Original1 Revised2

Operating assumptions Syncrude production (mmbbls) 104.9 113.0 107.0 Canadian Oil Sands sales (mmbbls) 38.7 41.5 39.3 Sales, net of crude oil purchases and transportation $ 3,566 $ 3,813 $ 3,698 Realized SCO selling price ($/bbl) $ 91.90 $ 91.84 $ 94.00 Operating expenses $ 1,511 $ 1,516 $ 1,485 Operating expenses per barrel $ 39.06 $ 36.52 $ 37.77 Crown royalties $ 202 $ 253 $ 191 Cash flow from operations3 $ 1,581 $ 1,825 $ 1,746

Capital expenditure assumptions Major projects $ 673 $ 974 $ 701 Regular maintenance $ 321 $ 405 $ 325 Capitalized interest $ 92 $ 81 $ 88 Total capital expenditures $ 1,086 $ 1,460 $ 1,114

Business environment assumptions West Texas Intermediate (U.S.$/bbl) $ 94.15 $ 90.00 $ 95.00 Discount to average Cdn$ WTI prices (Cdn$/bbl) $ (2.52) $ – $ (1.00) Foreign exchange rate (U.S.$/Cdn$) $ 1.00 $ 0.98 $ 1.00 AECO natural gas (Cdn$/GJ) $ 2.34 $ 3.50 $ 2.25 1 Original 2012 Outlook as provided in the 2011 annual report dated February 23, 2012.2 Revised 2012 Outlook as provided in the third quarter 2012 quarterly report dated October 29, 2012.3 Cash flow from operations is an additional GAAP measure and is defined in the “Non GAAP and Additional GAAP Financial Measures” section of this

MD&A.

Syncrude actual 2012 production of 104.9 million barrels was lower than Canadian Oil Sands’ 113 million barrel original estimate, primarily due to the Coker 8-1 shutdown and unplanned mine train outages. In October 2012, we revised our estimate to 107 million barrels, based on the results achieved during the first nine months of the year.

Cash flow from operations in 2012 was $1,581 million, $244 million lower than the $1,825 million original estimate, and sales net of crude oil purchase and transportation were $3,566 million, $247 million lower than the $3,813 million original estimate, due primarily to lower-than-expected sales volumes.

The realized selling price in 2012 averaged $91.90 per barrel compared with $91.84 per barrel in the Original Outlook.

Total operating expenses of $1,511 million were similar to the $1,516 original estimate, reflecting higher-than-expected production costs, due to the Coker 8-1 shutdown, mine train outages, and reliability issues with trucks and other mobile equipment, offset by lower-than-expected natural gas prices. Lower-than-expected sales volumes resulted in actual per barrel operating expenses of $39.06, seven per cent higher than the $36.52 original estimate.


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Capital expenditures were $1,086 million, $374 million below the $1,460 million original estimate due primarily to adjustments to the expected timing of spending on major projects. The expected completion dates and cost estimates for these major projects are not affected by these adjustments.

2013 Outlook

As of February 21

(millions of Canadian dollars, except volume and per barrel amounts) 2013

Operating assumptions Syncrude production (mmbbls) 110 Canadian Oil Sands sales (mmbbls) 40.4 Sales, net of crude oil purchases and transportation $ 3,233 Realized SCO selling price ($/bbl) $ 80.00 Operating expenses $ 1,482 Operating expenses per barrel $ 36.67 Crown royalties $ 113 Current taxes $ 350 Cash flow from operations1 $ 1,045

Capital expenditure assumptions Major projects $ 836 Regular maintenance $ 393 Capitalized interest $ 97 Total capital expenditures $ 1,326

Business environment assumptions West Texas Intermediate (U.S.$/bbl) $ 85.00 Discount to average Cdn$ WTI prices (Cdn$/bbl) $ (5.00) Foreign exchange rate (U.S.$/Cdn$) $ 1.00 AECO natural gas (Cdn$/GJ) $ 3.50 1 Cash flow from operations is an additional GAAP measure and is defined in the “Non GAAP and Additional GAAP Financial Measures” section of this

MD&A.

The amounts in this 2013 Outlook dated February 21, 2013 are unchanged from the 2013 Outlook dated January 31, 2013, which was provided in the fourth quarter 2012 report.

Canadian Oil Sands continues to estimate annual Syncrude production of 105 to 115 million barrels for 2013. For the purposeof generating our 2013 Outlook, we have selected a single-point production estimate of 110 million barrels (301,400 barrels per day). Net to Canadian Oil Sands, the single-point estimate is equivalent to 40.4 million barrels (110,700 barrels per day).The production estimate incorporates a planned turnaround of Coker 8-1 in the second half of the year.

Sales, net of crude oil purchases and transportation expense, are estimated to be approximately $3.2 billion, reflecting our 40.4 million barrel production estimate and an $80 per barrel plant-gate realized selling price. The estimated selling price assumes a U.S. $85 per barrel WTI oil price, a foreign exchange rate of $1.00 U.S./Cdn, and a SCO discount to Cdn dollar WTI of $5.00 per barrel.

The WTI and SCO discount to WTI forecasts reflect our assessment of supply/demand fundamentals for inland North American light crude oil. Increasing North American production of light crude oil, and refinery modifications that enable processing of heavier crude oils, can push light crude sales, including SCO, to more distant refineries, thereby increasing transportation costs and exposing Canadian Oil Sands to supply/demand factors in different markets. A number of pipelines in both Canada and the United States are at, or near, capacity and any pipeline apportionments can exacerbate this situation by restricting the ability of WTI, SCO and other crude oils to reach preferred markets. However, strong demand from customers and increases in rail shipments of inland crude to coastal refineries can offset these forces. These supply and demand dynamics create price volatility that is likely to persist for several years until additional planned pipeline or



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other delivery capacity is available to deliver crude oil from Western Canada to Cushing, Oklahoma, the U.S. Gulf Coast, or the Canadian East or West Coasts.

We are estimating operating expenses of approximately $1.5 billion in 2013, comprised of approximately $1.3 billion in production costs and $0.2 billion in purchased energy costs. The purchased energy costs reflect a $3.50 per GJ natural gas price assumption and a consumption rate of about one GJ per barrel of SCO produced. Based on our production estimate, this translates to operating expenses of $36.67 per barrel.

Development expenses are estimated to rise by $55 million over 2012 to $156 million, reflecting development activity around higher capital spending in 2013.

Also, mainly as a result of higher 2013 capital expenditures, allowable deductible costs for royalty purposes in 2013 are anticipated to exceed deemed bitumen revenues. As a result, Canadian Oil Sands is estimating minimum royalties at one per cent of gross deemed bitumen revenues (instead of 25 per cent of net deemed bitumen revenues) in 2013. We will continue to expense the transition royalty and upgrader growth capital recapture.

Capital expenditures are estimated to total $1,326 million in 2013, comprised of $836 million of spending on major projects, $393 million in regular maintenance of the business and other projects, and $97 million in capitalized interest.

We estimate current taxes of approximately $350 million in 2013. We expect deductions for capital expenditures made in 2012 and 2013 will be available for deduction in 2014 and beyond, resulting in lower current taxes in subsequent years, under the assumptions outlined in the 2013 Outlook.

We estimate 2013 cash flow from operations of $1,045 million, or $2.16 per Share.

We expect cash levels to decrease significantly over the next two years as we fund major capital projects and repay the 2013 debt maturity. As a result, net debt levels are expected to rise to $1 billion to $2 billion by the end of 2014, resulting in a capital structure that provides financial flexibility.

Changes in certain factors and market conditions could potentially impact Canadian Oil Sands’ Outlook. The following table provides a sensitivity analysis of the key factors affecting the Corporation’s performance.

Outlook Sensitivity Analysis (February 21, 2013)

Cash Flow from Operations Increase

Variable Annual Sensitivity $ millions1,2 $ / Share1,2

Syncrude operating expense decrease Cdn$1.00/bbl $ 30 $ 0.06 Syncrude operating expense decrease Cdn$50 million $ 14 $ 0.03 WTI crude oil price increase U.S.$1.00/bbl $ 30 $ 0.06 Syncrude production increase 2 million bbls $ 44 $ 0.09 Canadian dollar weakening U.S.$0.01/Cdn$ $ 25 $ 0.05 AECO natural gas price decrease Cdn$0.50/GJ $ 16 $ 0.03 1 Canadian Oil Sands anticipates recording approximately $350 million in current taxes in 2013. These sensitivities are after the impact of taxes.2 These sensitivities assume Canadian Oil Sands remains in minimum royalty in 2013.

The 2013 Outlook contains forward-looking information and users are cautioned that the actual amounts may vary from the estimatesdisclosed. Please refer to the “Forward-Looking Information Advisory” section of this MD&A for the risks and assumptions underlying this forward-looking information.


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Major Projects The following tables provide cost and schedule estimates for Syncrude’s major projects. Regular maintenance capital costs for years after 2013 will be provided on an annual basis when we disclose the budgets for those years, and are currently estimated to average approximately $10 per barrel over the next few years.

Major Projects – Total Project Cost and Schedule Estimates1

Total Cost Total Cost Estimated % Target Estimate Estimate Complete at In-Service ($ billions) Accuracy (%) Dec 31, 20122 Date

Mildred Lake Mine Train Replacement Syncrude $ 4.2 +15%/-15% 35% Q4 2014 Reconstruct crushers, surge facilities, COS share 1.6 and slurry prep facilities to support tailings storage requirements Aurora North Mine Train Relocation Syncrude $ 1.0 +15%/-15% 55% Q1 2014 Relocate crushers, surge facilities, COS share 0.4 and slurry prep facilities to support tailings storage requirements

Aurora North Tailings Management Syncrude $ 0.8 +15%/-15% 70% Q4 2013 Construct a composite tails (CT) plant COS share 0.3 at the Aurora North mine to process tailings Centrifuge Tailings Management Syncrude $ 1.9 +15%/-15% 10% H1 2015 Construct a centrifuge plant at the COS share 0.7 Mildred Lake mine to process tailings

Major Projects – Annual Spending Profile1

Spent to ($ billions) Dec 31, 2012 2013 2014 2015 Total

Syncrude $ 2.6 $ 2.4 $ 2.3 $ 0.6 $ 7.9 Canadian Oil Sands share $ 1.0 $ 0.9 $ 0.9 $ 0.2 $ 3.0 1 Major projects costs include capital expenditures, excluding capitalized interest, and certain development expenses.2 The estimated percentage complete is based on hours spent as a percentage of total forecasted hours to project completion.

Canadian Oil Sands plans to finance these major projects primarily with existing cash balances and cash flow from operations.

The major projects tables contain forward-looking information and users of this information are cautioned that the actual yearly and total major project costs and the actual in-service dates for the major projects may vary from the plans disclosed. The major project cost estimates and major project target in-service dates are based on current spending plans. Please refer to the “Forward-Looking Information Advisory” section of this MD&A for the risks and assumptions underlying this forward-looking information. For a list of additional risk factors that could cause the actual amount of the major project costs and the major project target in-service dates to differ materially, please refer to the Corporation’s Annual Information Form dated February 21, 2013 which is available on the Corporation’s profile on SEDAR at www.sedar.com and on the Corporation’s website at www.cdnoilsands.com.



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Controls Environment Management is responsible for establishing and maintaining adequate internal control over financial reporting. We have established disclosure controls and procedures, internal control over financial reporting, and organization-wide policies to provide reasonable assurance that Canadian Oil Sands’ consolidated financial position, financial performance and cash flows are presented fairly. Our disclosure controls and procedures are designed to provide reasonable assurance of the timely disclosure and communication of all material information.

We periodically review and update our internal control systems to reflect changes in our business environment. We did not materially change any of our internal controls during 2012.

All internal control systems, no matter how well designed, have inherent limitations. These systems, therefore, provide reasonable but not absolute assurance that financial information is accurate and complete.

Canadian Oil Sands, under the supervision and participation of management, including the President and Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures and the design of our internal control over financial reporting pursuant to National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings as of December 31, 2012. In addition, management has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2012 using criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on these evaluations, Canadian Oil Sands’ management concluded that:

• Our disclosure controls and procedures were effective as of December 31, 2012 to provide reasonable assurance that material information is recorded, processed, summarized and reported within the time periods specified by the applicable Canadian securities regulators. Furthermore, our disclosure controls and procedures are designed to provide reasonable assurance that material information required to be disclosed under applicable Canadian securities regulation is communicated to our management, including our President and Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure; and

• Our internal control over financial reporting as of December 31, 2012 was designed and operated effectively to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Corporation’s financial statements for external purposes in accordance with GAAP.

PricewaterhouseCoopers LLP, our auditors, have expressed an unqualified opinion on the effectiveness of Canadian Oil Sands’ internal control over financial reporting as of December 31, 2012, as stated in their report which appears herein.


M A N A G E M E N T ’ S R E P O RT

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Management’s Report

Financial InformationManagement is responsible for the information contained in this annual report. The Consolidated Financial Statements have been prepared in accordance with Canadian generally accepted accounting principles, and include amounts based on management’s informed judgments and estimates. Where alternative accounting methods exist, management has chosen those that it deems to be the most appropriate based on Canadian Oil Sands’ operations. The financial and operating information included in this annual report is consistent with that contained in the Consolidated Financial Statements in all material respects.

To assist management in fulfilling its responsibilities, systems of accounting, internal controls and disclosure controls are maintained to provide reasonable, but not absolute, assurance that financial information is reliable and accurate and that assets are adequately safeguarded. In addition, Canadian Oil Sands has in place a Code of Business Conduct that applies to all of its employees and directors.

PricewaterhouseCoopers LLP, Chartered Accountants, appointed annually by the Shareholders to serve as Canadian Oil Sands’ external auditors, were engaged to conduct an examination of the Consolidated Financial Statements and internal controls in accordance with Canadian generally accepted auditing standards and in accordance with the standards of the Public Company Accounting Oversight Board (United States), and have expressed their opinion on these statements. Canadian Oil Sands also engages independent reserve evaluators to conduct independent evaluations of its crude oil reserves and resources. The external auditors and reserve evaluators have unrestricted access to the management of Canadian Oil Sands, the Audit Committee, the Reserves, Marketing Operations, and Environmental, Health and Safety Committee and the Board of Directors.

The Board of Directors has appointed a four-person Audit Committee, consisting of directors who are neither employees nor officers of Canadian Oil Sands and all of whom are independent. The Audit Committee meets regularly with management and external auditors to discuss controls over the financial reporting process, auditing and other financial reporting matters. In addition, it recommends the appointment of Canadian Oil Sands’ external auditors. The Audit Committee meets at least quarterly with management and the external auditors to review and approve interim financial statements prior to their release and recommends the audited annual financial statements to the Board of Directors for their approval. Annually, the Board of Directors reviews and approves Canadian Oil Sands’ annual financial statements, Management’s Discussion and Analysis, Annual Information Form, Management Proxy Circular, and annual reserves and resources estimates. The Board of Directors has approved the annual audited Consolidated Financial Statements and the Management’s Discussion and Analysis based on the recommendations of the Audit Committee.

Internal Control Over Financial Reporting Management is responsible for establishing and maintaining adequate internal control over financial reporting.

Management has assessed the effectiveness of Canadian Oil Sands’ internal control over financial reporting as of December 31, 2012 using criteria established in the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Canadian Oil Sands’ internal control over financial reporting was effective as of December 31, 2012.

PricewaterhouseCoopers LLP, our auditors, has audited the effectiveness of Canadian Oil Sands’ internal control over financial reporting as of December 31, 2012 as stated in their report which appears herein.

(signed) Marcel R. Coutu (signed) Ryan M. Kubik President and Chief Executive Officer Chief Financial Officer February 21, 2013 February 21, 2013


I N D E P E N D E N T A U D I T O R ’ S R E P O RT

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Independent Auditor’s Report

To the Shareholders of Canadian Oil Sands Limited

We have completed integrated audits of Canadian Oil Sands Limited’s 2012 and 2011 consolidated financial statements and its internal control over financial reporting as at December 31, 2012. Our opinions, based on our audits, are presented below.

Report on the consolidated financial statements We have audited the accompanying consolidated financial statements of Canadian Oil Sands Limited, which comprise the consolidated balance sheets as at December 31, 2012 and 2011 and the consolidated statements of income and comprehensive income, shareholders’ equity and cash flows for the years then ended, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

Management’s responsibility for the consolidated financial statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Boardand 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.

Auditor’s responsibility 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 the audit to obtain reasonableassurance about 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 auditor’s 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.

Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Canadian Oil Sands Limited as at December 31, 2012 and 2011 and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Report on internal control over financial reporting We have also audited Canadian Oil Sands Limited’s internal control over financial reporting as at December 31, 2012, based on criteria established in Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).


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Management’s responsibility for internal control over financial reporting 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 Report.

Auditor’s responsibility 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 reasonableassurance 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 audit opinion on the company’s internal control over financial reporting.

Definition of 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 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 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.

Inherent limitations 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.

Opinion In our opinion, Canadian Oil Sands Limited maintained, in all material respects, effective internal control over financial reporting as at December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by COSO.

(signed) PricewaterhouseCoopers LLPChartered AccountantsCalgary, Alberta February 21, 2013


C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S

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Consolidated Statements of Income and Comprehensive Income

For the years ended December 31 (millions of Canadian dollars, except per Share and Share volume amounts) 2012 2011

Sales $ 3,905 $ 4,182 Crown royalties (Note 16) (202) (307) Revenues 3,703 3,875

Expenses Operating 1,511 1,501 Development 101 113 Crude oil purchases and transportation 339 248 Administration 26 25 Insurance 10 8 Depreciation and depletion 403 381

2,390 2,276 Earnings from operating activities 1,313 1,599 Foreign exchange (gain) loss (Note 17) (25) 22 Net finance expense (Note 18) 39 46 Earnings before taxes 1,299 1,531 Tax expense (Note 13) 318 387 Net income 981 1,144 Other comprehensive loss, net of taxes

Actuarial loss on employee future benefit plans (Note 9) (21) (128) Reclassification of derivative gains to net income (3) (3) Comprehensive income $ 957 $ 1,013

Weighted average Shares (millions) 485 485 Shares, end of year (millions) 485 485

Net income per Share (Note 14) Basic and diluted $ 2.02 $ 2.36 See Notes to Consolidated Financial Statements


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Consolidated Statements of Shareholders’ Equity

For the years ended December 31 (millions of Canadian dollars) 2012 2011

Retained earnings Balance, beginning of year $ 1,517 $ 1,034 Net income 981 1,144 Actuarial loss on employee future benefit plans (21) (128) Dividends (654) (533) Balance, end of year 1,823 1,517 Accumulated other comprehensive income Balance, beginning of year 12 15 Reclassification of derivative gains to net income (3) (3) Balance, end of year 9 12 Shareholders’ capital Balance, beginning of year 2,673 2,671 Issuance of shares – 2 Balance, end of year 2,673 2,673 Contributed surplus Balance, beginning of year 8 6 Share-based compensation 2 2 Balance, end of year 10 8 Total Shareholders’ equity $ 4,515 $ 4,210

See Notes to Consolidated Financial Statements


C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S

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Consolidated Balance Sheets

As at December 31 (millions of Canadian dollars) 2012 2011

ASSETS Current assets Cash and cash equivalents $ 1,553 $ 718 Accounts receivable 311 376 Inventories (Note 5) 137 142 Prepaid expenses 9 10

2,010 1,246 Property, plant and equipment, net (Note 6) 8,003 7,227 Exploration and evaluation 89 89 Reclamation trust (Note 12) 69 58

$ 10,171 $ 8,620

LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Accounts payable and accrued liabilities (Note 7) $ 704 $ 479 Current tax (Note 13) 40 – Current portion of long-term debt (Note 11) 297 – Current portion of employee future benefits (Note 9) 76 47

1,117 526 Employee future benefits (Note 9) 362 418 Other liabilities (Note 8) 89 62 Long-term debt (Note 11) 1,497 1,132 Asset retirement obligation (Note 12) 1,058 1,008 Deferred tax (Note 13) 1,533 1,264

5,656 4,410 Shareholders’ equity (Note 14) 4,515 4,210

$ 10,171 $ 8,620

Commitments, Contingencies and Guarantees (Notes 22, 23 and 24, respectively)


Approved by the Board of Directors

(signed) Wesley R. Twiss (signed) Donald J. LowryDirector Director


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Consolidated Statements of Cash Flows

For the years ended December 31 (millions of Canadian dollars) 2012 2011

Cash from (used in) operating activities Net income $ 981 $ 1,144 Items not requiring an outlay of cash Depreciation and depletion 403 381 Accretion of asset retirement obligation (Note 12) 26 16 Foreign exchange (gain) loss on long-term debt (Note 17) (28) 25 Deferred tax expense (Note 13) 278 387 Share-based compensation 5 2 Reclamation expenditures (Note 12) (54) (49) Change in employee future benefits and other (30) (9) Cash flow from operations 1,581 1,897 Change in non-cash working capital (Note 25) 283 61 Cash from operating activities 1,864 1,958

Cash from (used in) financing activities Issuance of senior notes (Note 11) 689 – Repayment of bank credit facilities (Note 10) – (145) Issuance of shares (Note 14) – 2 Dividends (654) (533) Cash from (used in) financing activities 35 (676)

Cash from (used in) investing activities Capital expenditures (1,086) (643) Reclamation trust funding (10) (5) Change in non-cash working capital (Note 25) 34 4 Cash used in investing activities (1,062) (644)

Foreign exchange loss on cash and cash equivalents held in foreign currency (2) –

Increase in cash and cash equivalents 835 638 Cash and cash equivalents, beginning of year 718 80 Cash and cash equivalents, end of year $ 1,553 $ 718

Cash and cash equivalents consist of: Cash $ 607 $ 326 Short-term investments 946 392

$ 1,553 $ 718

Supplementary Information (Note 25)



N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S

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Notes to Consolidated Financial Statements(Tabular amounts expressed in millions of Canadian dollars, except where otherwise noted)

1) Nature of Operations

Canadian Oil Sands Limited (the “Corporation”) was incorporated in 2010 under the laws of the Province of Alberta, Canada pursuant to a plan of arrangement effecting the reorganization from an income trust into a corporate structure effective December 31, 2010.

The Corporation indirectly owns a 36.74 per cent interest (“Working Interest”) in the Syncrude Joint Venture (“Syncrude”). Syncrude is involved in the mining and upgrading of bitumen from oil sands near Fort McMurray in northern Alberta. The Syncrude Project is comprised of open-pit oil sands mines, utilities plants, bitumen extraction plants and an upgrading complex that processes bitumen into Synthetic Crude Oil (“SCO”). Each joint-venture owner, including the Corporation, takes its proportionate share of production in kind, and funds its proportionate share of Syncrude’s operating, development and capital costs on a daily basis. The Corporation also owns 36.74 per cent of the issued and outstanding shares of Syncrude Canada Ltd. (“Syncrude Canada”). Syncrude Canada operates Syncrude on behalf of the joint-venture owners and is responsible for selecting, compensating, directing and controlling Syncrude’s employees and for administering all related employment benefits and obligations. The Corporation’s investment in Syncrude and Syncrude Canada represents its only producing asset.

The Corporation’s office is located at the following address: 2500 First Canadian Centre, 350 – 7th Avenue S.W., Calgary, Alberta, Canada T2P 3N9.

2) Basis of Presentation

These audited consolidated financial statements are prepared and reported in Canadian dollars in accordance with Canadian generally accepted accounting principles as set out in the Handbook of the Canadian Institute of Chartered Accountants (“CICA Handbook”). The CICA Handbook incorporates International Financial Reporting Standards (“IFRS”) and publicly accountable enterprises, such as the Corporation, are required to apply such standards. These audited consolidated financial statements have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (“IASB”) and effective on February 21, 2013.

These audited consolidated financial statements were approved by the Corporation’s Board of Directors for issue on February 21, 2013.

3) Summary of Accounting Policies

Consolidation The consolidated financial statements include the accounts of the Corporation and its subsidiaries (collectively “Canadian Oil Sands”). Subsidiaries include incorporated and unincorporated entities, such as partnerships, for which the Corporation has the power to govern financial and operating policies. All intercompany transactions and balances are eliminated on consolidation. Activities of Syncrude are conducted jointly with others and, accordingly, these financial statements reflect only Canadian Oil Sands’ proportionate interest in such activities, which include SCO production, Crown royalties, operating and development expenses, as well as a proportionate interest in Syncrude’s property, plant and equipment, inventories, employee future benefits, other liabilities, asset retirement obligation, and associated accounts payable and receivable.

Cash and Cash Equivalents Cash and cash equivalents include cash in banks and short-term investments with maturities of less than 90 days at purchase.


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Inventories Inventories are comprised of product inventory and materials and supplies. Product inventory includes gas oils, in-transit batches of crude oil and pipeline linefill. All inventories are carried at the lower of average cost and net realizable value. Costs include direct and indirect expenditures incurred in bringing an item or product to its existing condition and location. The costs of product inventories are recognized as operating expenses or crude oil purchases and transportation expenses when sold. The costs of materials and supplies inventories are recognized as either operating expenses or property, plant and equipment when consumed.

Property, Plant and Equipment Property, plant and equipment (“PP&E”) are recorded at cost less accumulated depreciation and depletion. The cost of a PP&E asset includes its acquisition, development and construction costs, costs directly attributable to bringing the asset into operation, the cost of initial overburden removal and the estimate of any asset retirement costs. Major turnaround costs are capitalized, while non-major turnaround costs, repairs and maintenance and ongoing overburden removal on producing oil sands mines are expensed as operating expenses in the period incurred.

Interest costs attributable to the acquisition or construction of qualifying assets which require a substantial period of time to prepare for their intended use are capitalized as PP&E. All other interest costs are recognized as net finance expense in the period in which they are incurred.

PP&E is depreciated on a straight-line basis over the estimated useful lives of the assets, with the exception of mine development and asset retirement costs, which are depleted on a unit-of-production basis over the estimated proved and probable reserves of the producing mines. The following estimated useful lives of the assets depreciated on a straight-line basis are reviewed annually for any changes to those estimates:

Category Estimated Useful Life

Major turnarounds 2 to 3 years Vehicles and equipment 5 to 20 years Mining equipment Lesser of 25 years and the remaining life of the mine Upgrading and extraction 25 years Buildings 20 to 40 years

Construction in progress consists of assets that are not available for use and are therefore not depreciated. Once these assets are substantially complete and ready for their intended use, their costs, including applicable capitalized interest costs, are transferred to the appropriate category of PP&E and depreciated accordingly.

Exploration and Evaluation Exploration and evaluation (“E&E”) assets include the costs of acquiring undeveloped oil sands leases (“oil sands lease acquisition costs”) and interests in natural gas licenses located in the Arctic Islands in northern Canada (the “Arctic natural gas assets”). Certain expenditures relating to capital programs, such as pre-feasibility engineering, technical and support services, research, evaluation drilling and regulatory and stakeholder consultation expenditures are expensed as development expenses. E&E assets are transferred to PP&E once technical feasibility and commercial viability is determined. E&E assets are not available for use and are therefore not amortized.

Impairment The carrying amounts of PP&E and E&E assets are reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. E&E assets are also reviewed for impairment at the time they are transferred to PP&E.

For the purpose of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows (“cash generating units” or “CGUs”). An impairment loss is recognized for the amount by which the carrying amount of the CGU exceeds its recoverable amount. The recoverable amount is the higher of a CGU’s fair value less cost to sell (being the amount obtainable from the sale of a CGU in an arm’s length transaction, net of disposal costs) and its value in use (being the net present value of the CGU’s expected future cash flows).



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PP&E consists entirely of Canadian Oil Sands’ proportionate interest in Syncrude’s PP&E. PP&E is combined with the oil sands lease acquisition costs, within the E&E assets, to form one CGU for impairment testing purposes. The balance of the E&E assets, being the Arctic natural gas assets, form a second CGU which is tested for impairment separately from the oil sands assets. Impairments are reversed, net of imputed depreciation and depletion, if the reversal can be related objectively to an event occurring after the impairment charge was recognized. Impairment charges and reversals are recorded as depreciation and depletion.

Asset Retirement Obligation Canadian Oil Sands recognizes its proportionate share of Syncrude’s asset retirement obligation for the reclamation and closure of each mine site and the decommissioning of utilities plants, bitumen extraction plants, and the upgrading complex. The asset retirement obligation is measured at the present value of management’s best estimate of the future cash flows required to settle the obligation, discounted using the risk-free interest rate. The asset retirement obligation is recorded oninitial land disturbance and is added to the carrying amount of the associated PP&E asset and amortized over the asset’s remaining life. The asset retirement obligation is accreted over time through charges to net finance expense with actual expenditures charged against the obligation. Changes in the future cash flow estimates resulting from revisions to the estimated timing or amount of expenditures or changes in the risk-free interest rate are recognized as a change in the asset retirement obligation and related PP&E asset.

Revenue Recognition Revenue from sales of SCO, including both produced and purchased volumes, and other products is recorded when the significant risks and rewards of ownership transfer to the customer and collection is reasonably assured. Revenue is recorded net of Crown royalties.

Employee Future Benefits Canadian Oil Sands accrues its proportionate share of Syncrude Canada’s post-employment benefit obligations, which include defined benefit and defined contribution pension plans and a defined benefit plan for other post-employment benefits (“OPEB”).

The cost of the defined benefit pension and OPEB plans is actuarially determined using the projected unit credit method based on length of service and reflects Canadian Oil Sands’ best estimate of financial and demographic assumptions. The discount rate used to determine the accrued benefit obligation is based on a market rate of interest for high-quality corporate debt instruments with cash flows that match the timing and amount of expected benefit payments. The expected return on plan assets is the expected long-term rate of return on plan assets. Actuarial gains and losses, net of income taxes, are recognized immediately in other comprehensive income. The current service cost of the defined benefit plans is recognized in operating expenses as the service is rendered. Any past service costs arising from plan amendments are recognized immediately in operating expenses.

The cost of the defined contribution plans is recognized in operating expenses as the service is rendered and contributions become payable.

Taxes Deferred tax assets and liabilities are recognized based on the differences between the tax and accounting values of assets and liabilities and/or the timing differences arising when revenues or expenses are included in accounting income in one period and taxable income in a different period. These temporary differences are tax-effected using enacted or substantively enacted tax rates for the periods in which the temporary differences are expected to reverse. The effect of changes to the tax and accounting values or tax rates is recognized in net income, other comprehensive income or shareholders’ equity, consistent with the items to which they relate. Deferred tax assets are recognized only to the extent that it is probable that future taxable profits will be available against which the assets can be utilized.

Current taxes are estimated on taxable income for the current year at the statutory tax rates enacted or substantively enacted.


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Share-Based Compensation Canadian Oil Sands grants share-based awards to officers, select employees and non-executive directors and recognizes the associated share-based compensation expense in administration expenses.

The compensation cost for options granted to officers and select employees is based on the estimated fair values of the options at the time of grant. This cost is recognized in administration expenses over the vesting periods of the options and a corresponding increase to contributed surplus, within shareholders’ equity, is recognized at the time of grant. Upon exercise, both the consideration received and the amounts recorded as contributed surplus are recognized as shareholders’ capital.

The compensation cost for performance units (“PSUs”) awarded to officers, restricted share units (“RSUs”) awarded to select employees and deferred share units (“DSUs”) awarded to non-executive directors, is based on the fair values of these awards. This cost is recognized in administration expenses over the vesting periods of the awards with a corresponding liability recognized in accounts payable and accrued liabilities. Changes in the fair values of the PSUs, RSUs, and DSUs during the vesting periods are recognized as administration expenses in the period the change occurs. Upon settlement of these awards by cash, the outstanding liability is reduced. Upon settlement by the issuance of common shares, the outstanding liability is reclassified to shareholders’ capital.

As an owner in Syncrude, Canadian Oil Sands recognizes its 36.74 per cent share of Syncrude Canada’s share-based compensation awards. The compensation cost for these awards, which are comprised of restricted share units (“Syncrude RSUs”) and phantom share units (“Syncrude PSUs”) awarded to Syncrude Canada employees, is based on the fair values of these awards. This cost is recognized in operating expenses over the shorter of the normal vesting period and the period to eligible retirement if vesting is accelerated on retirement, with a corresponding liability recognized in accounts payable and accrued liabilities. Changes in the fair values of the Syncrude RSUs and Syncrude PSUs during the vesting periods are recognized as operating expenses in the period the change occurs. Upon settlement of these awards, which is always by cash, the outstanding liability is reduced.

Foreign Currency Translation The principal currency of the economic environment in which the Corporation and its subsidiaries and wholly owned partnership operate is the Canadian dollar. Monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars at exchange rates in effect at the end of the period, with the resulting gain or loss recognized in net income. Revenues and expenses are translated into Canadian dollars at average exchange rates. Translation gains and losses on U.S. dollar denominated long-term debt are unrealized until the debt obligations are repaid. All other translation gains and losses are classified as realized.

Net Income Per Share Basic net income per share is calculated by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per share is calculated by adjusting the weighted average number of common shares outstanding for dilutive common shares related to the Corporation's share-based compensation plans. The number of shares included is computed using the treasury stock method, which assumes that proceeds received from the exercise of in-the-money options are used to repurchase common shares at the average market price.

Dividends Dividends on common shares are recognized in the period in which the dividends are approved by the Corporation's Board of Directors.



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Financial InstrumentsAll financial instruments are initially measured at fair value. Subsequent measurement of financial instruments is based on their classification as follows:

Classification Measurement

Fair value through profit or loss Fair value with changes recognized in net incomeHeld to maturity Amortized cost using effective interest methodLoans and receivables Amortized cost using effective interest methodAvailable for sale Fair value with changes recognized in other comprehensive income Other liabilities Amortized cost using effective interest method

Transaction costs in respect of financial instruments measured at fair value are recognized immediately in net income. Transaction costs in respect of other financial instruments are included in the initial cost and amortized accordingly using the effective interest method.

The inputs to fair value measurements of financial instruments, including their classification within a hierarchy that prioritizes the inputs to fair value measurement, are as follows:

Level 1: Quoted prices in active markets for identical assets or liabilities; Level 2: Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly

or indirectly; and Level 3: Inputs for the asset or liability that are not based on observable market data.

4) Critical Accounting Estimates and Judgements

In order to provide timely financial information to users, the Corporation makes estimates and uses judgement when determining the assets, liabilities, revenues, expenses, commitments and contingencies reported in the consolidated financial statements and notes. The following estimates and judgements are considered critical because actual results could differ materially from reported results if different assumptions underlying these estimates and judgements were used:

Critical Accounting Estimates

a) Crown Royalties When calculating deemed bitumen revenues on which Crown royalties are based, Canadian Oil Sands must estimate a deemed bitumen value and deductible costs. The deemed bitumen value is based on a Canadian heavy oil reference price adjusted to reflect quality and location differences between Syncrude’s bitumen and the Canadian reference price bitumen. Canadian Oil Sands must estimate these quality and transportation adjustments and, if the assumptions under which these estimates are based change, actual Crown royalties could vary greatly from estimated amounts.

b) Asset Retirement Obligation In determining the estimated value of the asset retirement obligation, Canadian Oil Sands must estimate the timing and amount of future reclamation and closure expenditures. Given the long reserve life of Syncrude’s leases, the expenditures will be made over approximately the next 70 years and it is difficult to estimate the precise timing and amount of these expenditures. Any changes in the anticipated timing or amount of the expenditures results in a change to the asset retirement obligation, corresponding PP&E asset, accretion expense (within net finance expense), and depreciation and depletion expense.

c) Employee Future Benefits Canadian Oil Sands accrues its obligations for Syncrude Canada’s post-employment benefits using actuarial and other assumptions to estimate the accrued benefit obligation, the return on plan assets and the expense related to the current period. Changes in these assumptions, or differences between actual and estimated benefit payments and plan asset


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returns, give rise to actuarial gains and losses. A sensitivity analysis of the impacts of changes in the assumed interest rateused to discount the estimated accrued benefit obligation is provided in Note 9.

d) Impairment In determining the recoverable amount of PP&E and E&E assets subject to impairment testing, Canadian Oil Sands must estimate the reserves it expects to recover and the related future net revenues expected to be generated from producing those reserves. Reserves and future net revenues are evaluated and reported in a reserve report prepared by independent petroleum reserve evaluators who determine these evaluations using various factors and assumptions, such as: forecasts of mining and extraction recovery and upgrading yield based on geological and engineering data, projected future rates of production, projected operating costs, Crown royalties and taxes, projected crude oil prices and oil price differentials and timing and amounts of future capital expenditures and other development costs, all of which are estimates. The factors and assumptions used in the estimates are assessed for reasonableness based on the information available at the time the estimates are prepared. As circumstances change and new information becomes available, the estimates could change. Actual results could vary from estimates, which could cause changes to the asset impairment tests.

e) Depreciation and Depletion Canadian Oil Sands calculates depreciation expense for the majority of its assets on a straight-line basis and must estimate the useful lives of these assets accordingly. While these useful life estimates are reviewed on a regular basis and depreciation calculations are revised accordingly, actual lives may differ from the estimates. Canadian Oil Sands calculates depletion expense for asset retirement and mine development costs on a unit-of-production basis and must estimate reserves, which are used as a component of the depletion calculations to allocate capital costs over their estimated useful lives. As circumstances change and new information becomes available, estimated reserves and the resultant depletion calculations could change.

Critical Accounting Judgements

a) Crown Royalties When calculating deemed bitumen revenues on which Crown royalties are based, Canadian Oil sands must determine a deemed bitumen value and deductible costs. This requires the use of judgement in the application of the governing royalty agreement. The determination of the appropriate application of the royalty agreement may remain uncertain for several years. The final outcome of such determination could result in amounts different from those initially recorded and would impact Crown royalties in the period in which a determination is made.

b) Asset Retirement Obligation Canadian Oil Sands applies judgement in determining that the risk-free interest rate is the appropriate rate to discount the asset retirement obligation. Alternatively, a credit-adjusted rate could be used which would yield a smaller asset retirement obligation and corresponding PP&E asset, lower depreciation and depletion expense and a higher accretion expense, which is presented in net finance expense.

c) Taxes In determining its current and deferred tax provisions, Canadian Oil Sands must apply judgement when interpreting and applying complex and changing tax laws and regulations. The determination of the appropriate application of these laws and regulations by tax authorities may remain uncertain for several years. The final outcome of such determination could result in amounts different from those initially recorded and would impact current or deferred tax expense in the period in which a determination is made.



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5) Inventories

December 31 December 31 As at ($ millions) 2012 2011

1Materials and supplies $ 109 $ 108 Products 28 34 $ 137 $ 142

6) Property, Plant and Equipment, Net

Year Ended December 31, 2012

Upgrading Vehicles Asset Major

and Mining and retirement turnaround Construction Mine

($ millions) extracting equipment equipment Buildings costs costs in progress development Total

Cost Balance at January 1, 2012 $ 4,688 $ 1,417 $ 690 $ 310 $ 931 $ 114 $ 1,144 $ 393 $ 9,687 Additions – – 23 – – 76 987 – 1,086 Change in asset retirement costs – – – – 93 – – – 93 Retirements (3) (20) (27) (1) – (24) – (1) (76)Reclassifications1 615 - - 15 – – (630) – – Balance at December 31, 2012 $ 5,300 $ 1,397 $ 686 $ 324 $ 1,024 $ 166 $ 1,501 $ 392 $ 10,790

Accumulated depreciation Balance at January 1, 2012 $ 1,284 $ 480 $ 294 $ 100 $ 138 $ 53 $ – $ 111 $ 2,460 Depreciation 166 79 53 8 42 44 – 11 403 Retirements (3) (20) (27) (1) – (24) – (1) (76)Reclassifications1 – – – – – – – – – Balance at December 31, 2012 $ 1,447 $ 539 $ 320 $ 107 $ 180 $ 73 $ – $ 121 $ 2,787

Net book value at December 31, 2012 $ 3,853 $ 858 $ 366 $ 217 $ 844 $ 93 $ 1,501 $ 271 $ 8,003

Year Ended December 31, 2011

Upgrading Vehicles Asset Major

and Mining and retirement turnaround Construction Mine

($ millions) extracting equipment equipment Buildings costs costs in progress development Total

Cost Balance at January 1, 2011 $ 4,669 $ 1,381 $ 688 $ 304 $ 362 $ 103 $ 694 $ 345 $ 8,546 Additions – – – – – 43 600 – 643 Change in asset retirement costs – – – – 569 – – – 569 Retirements (6) (9) (22) (1) – (32) – (1) (71)Reclassifications1 25 45 24 7 – – (150) 49 – Balance at December 31, 2011 $ 4,688 $ 1,417 $ 690 $ 310 $ 931 $ 114 $ 1,144 $ 393 $ 9,687 Accumulated depreciation Balance at January 1, 2011 $ 1,092 $ 449 $ 264 $ 100 $ 103 $ 50 $ – $ 92 $ 2,150 Depreciation 169 92 54 7 14 35 – 10 381 Retirements (6) (9) (22) (1) – (32) – (1) (71)Reclassifications1 29 (52) (2) (6) 21 – – 10 – Balance at December 31, 2011 $ 1,284 $ 480 $ 294 $ 100 $ 138 $ 53 $ – $ 111 $ 2,460 Net book value at December 31, 2011 $ 3,404 $ 937 $ 396 $ 210 $ 793 $ 61 $ 1,144 $ 282 $ 7,227 1 Reclassifications are primarily transfers from construction in progress to other categories of property, plant and equipment when construction is completed and assets are available for use.


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In 2012, interest costs of $92 million were capitalized and included in property, plant and equipment (2011 – $57 million) based on a 6.7 per cent interest capitalization rate (2011 – 7.3 per cent).

7) Accounts Payable and Accrued Liabilities


Trade payables $ 498 $ 381 Accrued liabilities for Crown royalties 215 109 Current portion of asset retirement obligation (Note 12) 44 29 Interest payable 29 21

$ 786 $ 540 Less non-current portion of accrued liabilities for Crown royalties (82) (61) Accounts payable and accrued liabilities $ 704 $ 479

8) Other Liabilities


Accrued liabilities for Crown royalties $ 82 $ 61 Other 7 1 Other liabilities $ 89 $ 62

9) Employee Future Benefits


Employee future benefits $ 438 $ 465 Less current portion (76) (47)

$ 362 $ 418

Syncrude Canada has defined benefit pension and other post-employment benefit (“OPEB”) plans, and a defined contribution pension plan covering most of its employees. Other post-employment benefits include certain health care and life insurance benefits for retirees, their beneficiaries and covered dependants. The OPEB plan is not funded.

(a) Defined Benefit Plans The most recent actuarial valuation of the pension and OPEB plans for funding purposes was completed in 2012 and was as of December 31, 2011. The next actuarial valuation will be completed during 2013 and will be as of December 31, 2012.



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Canadian Oil Sands’ share of Syncrude Canada’s accrued benefit liability relating to the defined benefit plans is comprised of its share of Syncrude Canada’s accrued benefit obligation, partially offset by its share of Syncrude Canada’s plan assets as follows:

Other Post-Employment Pension Benefits Total ($ millions) 2012 2011 2012 2011 2012 2011 Accrued benefit obligation: Balance, beginning of year $ 902 $ 717 $ 60 $ 52 $ 962 $ 769 Current service cost 41 32 1 1 42 33 Interest cost 39 38 3 3 42 41 Employee contributions 7 4 – – 7 4 Benefits paid (35) (29) (2) (2) (37) (31) Actuarial loss 43 140 (2) 6 41 146 Balance, end of year $ 997 $ 902 $ 60 $ 60 $ 1,057 $ 962 Fair value of plan assets: Balance, beginning of year $ 497 $ 442 $ – $ – $ 497 $ 442 Actual return on plan assets 48 10 – – 48 10 Employer contributions 100 69 – – 100 69 Employee contributions 7 4 – – 7 4 Benefits paid (33) (28) – – (33) (28) Balance, end of year $ 619 $ 497 $ – $ – $ 619 $ 497 Accrued benefit liability $ (378) $ (405) $ (60) $ (60) $ (438) $ (465)

The accrued benefit obligation relates to both unfunded and partly funded plans as follows:

Other Post-Employment Pension Benefits Total As at December 31 ($ millions) 2012 2011 2012 2011 2012 2011

Accrued benefit obligation arising from: Unfunded plans $ 48 $ 40 $ 60 $ 60 $ 108 $ 100 Partly funded plans 949 862 – – 949 862

$ 997 $ 902 $ 60 $ 60 $ 1,057 $ 962

The asset allocation for Syncrude Canada’s defined benefit plan assets was as follows:

Percentage of Plan assets

As at December 31 2012 2011

Equity securities 60 60 Debt securities 40 40

100 100

Syncrude Canada’s plan assets are invested using a passive strategy with investments in indexed securities. Investments that are not traded in active markets are not significant.


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Elements of defined benefit costs recognized in the year:

Other Post-Employment Pension Benefits Total For the years ended December 31 ($ millions) 2012 2011 2012 2011 2012 2011

Current service cost $ 41 $ 32 $ 1 $ 1 $ 42 $ 33 Interest cost 39 38 3 3 42 41 Expected return on plan assets (35) (34) – – (35) (34) Recognized in operating expenses $ 45 $ 36 $ 4 $ 4 $ 49 $ 40 Actuarial loss (gain) Actuarial loss on accrued benefit obligation $ 43 $ 140 $ (2) $ 6 $ 41 $ 146 Difference between actual return and expected return on plan assets (13) 24 – – (13) 24 Recognized in other comprehensive income1 $ 30 $ 164 $ (2) $ 6 $ 28 $ 170 Total defined benefit cost $ 75 $ 200 $ 2 $ 10 $ 77 $ 210 1 Actuarial losses of $21 million (2011 - $128 million) are recognized in other comprehensive income, net of income taxes of $7 million (2011 - $42 million).

Select historical information about the defined benefit plans:

($ millions) 2012 2011 2010

Pension Accrued benefit liability at December 31 Accrued benefit obligation $ (997) $ (902) $ (717) Fair value of plan assets 619 497 442

$ (378) $ (405) $ (275)

Experience gain (loss) for the years ended December 311

Accrued benefit obligation $ (43) $ (136) $ (77) Plan assets $ 13 $ (24) $ 11

Other Post-Employment Benefits Accrued benefit liability at December 31 Accrued benefit obligation $ (60) $ (60) $ (52)

Experience gain (loss) for the years ended December 311

Accrued benefit obligation $ (2) $ (5) $ (5) 1 Experience gains (losses) represent actuarial gains (losses) excluding the impact of changes in actuarial assumptions, such as increases in the rate of compensation or changes in assumed health care costs.

Significant Assumptions The significant assumptions adopted in measuring the defined benefit plans are as follows:

Other Post-Employment Pension Benefits

As at December 31 2012 2011 2012 2011

Accrued benefit obligation Discount rate 4.00% 4.25% 4.00% 4.25% Rate of compensation increase 4.56% 4.50% 4.56% 4.50% Plan assets Expected rate of return on plan assets 6.50% 7.30% n/a n/a

A seven per cent annual rate of increase in the cost of supplemental health care benefits was assumed for 2012, 2013 and 2014 (2011 – eight per cent) decreasing by 0.5 per cent each year thereafter to a five per cent ultimate rate in 2018. In addition, an annual rate increase of four per cent in dental rates was used in 2012 and 2011.



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Sensitivity Analysis A one per cent decrease in the interest rate used to discount future benefit payments would result in a $205 million increase in Canadian Oil Sands’ share of Syncrude Canada’s accrued benefit obligation and a $10 million decrease in annual interest costs, while a one per cent increase in the interest rate would result in a $160 million decrease in Canadian Oil Sands’ share of the accrued benefit obligation and a $7 million increase in annual interest costs.

A one per cent increase in assumed health care cost trend rates would increase Canadian Oil Sands’ share of the accrued benefit obligation by $5 million, and a one per cent decrease would decrease Canadian Oil Sands’ share of the accrued benefit obligation by $4 million. A one per cent increase or decrease in the health care cost trend rates would have an insignificant impact on Canadian Oil Sands’ share of current service and interest costs.

(b) Defined Contribution Plans Canadian Oil Sands’ share of Syncrude Canada’s defined contribution pension plan expense was approximately $3 million in 2012 (2011 – $3 million).

(c) Total Cash Payments Canadian Oil Sands’ share of Syncrude’s total cash payments for employee future benefits for 2012 was $107 million (2011 – $75 million), consisting of cash contributed by Syncrude Canada to its defined benefit pension and OPEB plans and to its defined contribution pension plan, including contributions to fund benefit payments in excess of registered plan limits. Canadian Oil Sands’ share of Syncrude Canada’s estimated 2013 cash payments to fund the defined benefit plans is $101 million. The actuarial valuation completed in 2012 requires Syncrude Canada to fund a pension plan solvency deficiency. Canadian Oil Sands’ share of these funding requirements is $357 million over the next 13 years.

10) Bank Credit Facilities

December 31As at ($ millions) 2012

Operating credit facility (a) $ 1,500 Extendible revolving term facility (b) 40 Line of credit (c) 175

$ 1,715

The credit facilities of Canadian Oil Sands are unsecured. The credit facility agreements contain covenants restricting Canadian Oil Sands’ ability to sell all or substantially all of its assets or to change the nature of its business. The credit facility agreements also require Canadian Oil Sands to maintain its total debt-to-total capitalization at an amount less than 60 per cent, or 65 per cent in certain circumstances involving acquisitions.

a) Operating Credit Facility The $1,500 million credit facility expires on June 1, 2016. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers’ acceptances plus a credit spread. Any unused amounts are subject to standby fees. As at December 31, 2012, no amounts were drawn against this facility (no amounts were drawn against the facility at December 31, 2011).

b) Extendible Revolving Term Facility The $40 million extendible revolving term facility is a two year facility expiring June 30, 2014. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers’ acceptances plus a credit spread. Any unused amounts are subject to standby fees. At December 31, 2012, no amounts were drawn against this facility (no amounts were drawn against the facility at December 31, 2011).


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c) Line of Credit The $175 million line of credit is made up of one-year revolving letter of credit facilities. Letters of credit drawn on these facilities mature April 30th each year and are automatically renewed, unless notification to cancel is provided at least 60 days prior to expiry by either Canadian Oil Sands or the financial institution providing the facility. Letters of credit written on the facilities bear interest at a credit spread. Letters of credit of approximately $75 million have been written against the lineof credit as at December 31, 2012 (December 31, 2011 – $75 million).

11) Long-Term Debt


8.2% Senior Notes due April 1, 2027 (U.S. $73.95 million) (a) $ 72 $ 74 7.9% Senior Notes due September 1, 2021 (U.S. $250 million) (b) 245 250 5.8% Senior Notes due August 15, 2013 (U.S. $300 million) (c) 297 303 7.75% Senior Notes due May 15, 2019 (U.S. $500 million) (d) 494 505 4.5% Senior Notes due April 1, 2022 (U.S. $400 million) (e) 392 – 6.0% Senior Notes due April 1, 2042 (U.S. $300 million) (f) 294 –

$ 1,794 $ 1,132 Less current portion of long-term debt (297) –

$ 1,497 $ 1,132

Canadian Oil Sands’ Senior Notes are unsecured, rank pari passu with other senior unsecured debt of the Corporation, and contain certain covenants that place limitations on the sale of assets and the granting of liens or other security interests.

a) 8.2% Senior Notes On April 4, 1997, the Corporation issued U.S. $75 million of 8.2% Senior Notes, maturing April 1, 2027, and retired U.S. $1.05 million during 2000. Interest is payable on the notes semi-annually on April 1 and October 1.

b) 7.9% Senior Notes On August 24, 2001, the Corporation issued U.S. $250 million of 7.9% Senior Notes, maturing September 1, 2021. Interest is payable on the notes semi-annually on March 1 and September 1. The Corporation has agreed to maintain its debt-to-capitalization at an amount less than 55 per cent.

c) 5.8% Senior Notes On August 6, 2003, the Corporation issued U.S. $300 million of 5.8% Senior Notes, maturing August 15, 2013. Interest is payable on the notes semi-annually on February 15 and August 15.

d) 7.75% Senior Notes On May 11, 2009, the Corporation issued U.S. $500 million of 7.75% Senior Notes, maturing May 15, 2019. Interest is payable on the notes semi-annually on May 15 and November 15.

e) 4.5% Senior Notes On March 29, 2012, the Corporation issued U.S. $400 million of 4.5% Senior Notes, maturing April 1, 2022. Interest is payable on the notes semi-annually on April 1 and October 1.

f) 6.0% Senior Notes On March 29, 2012, the Corporation issued U.S. $300 million of 6.0% Senior Notes, maturing April 1, 2042. Interest is payable on the notes semi-annually on April 1 and October 1.



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g) Future Payments Future principal payments payable under long-term debt, including current and non-current portions, the total of which differs from the amortized cost balance recorded on the Consolidated Balance Sheets, are as follows:

($ millions)

2013 $ 298 After five years 1,516

$ 1,814

12) Asset Retirement Obligation and Reclamation Trust

Canadian Oil Sands and each of the other Syncrude owners are liable for their share of ongoing obligations related to the reclamation and closure of the Syncrude properties on abandonment. The Corporation estimates reclamation and closure expenditures will be made over approximately the next 70 years and has applied a risk-free interest rate of 2.25 per cent at December 31, 2012 (December 31, 2011 – 2.50 per cent) in deriving the asset retirement obligation.

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the Corporation’s share of the obligation associated with the retirement of the Syncrude properties:

($ millions) 2012 2011

Asset retirement obligation, beginning of year $ 1,037 $ 501 Change in estimated liability 25 471 Reclamation expenditures (54) (49) Accretion expense 26 16 Change in risk-free interest rate 68 98 Asset retirement obligation, end of year $ 1,102 $ 1,037 Less current portion (44) (29) Non-current portion $ 1,058 $ 1,008

The $25 million increase in the estimated liability was capitalized as property, plant and equipment. The $44 million current portion of the asset retirement obligation is included in accounts payable and accrued liabilities, while the $1,058 million non-current portion is presented separately as an asset retirement obligation on the December 31, 2012 Consolidated Balance Sheet. The total undiscounted estimated cash flows required to settle Canadian Oil Sand’s share of the asset retirement obligation were $2,104 million at December 31, 2012 (December 31, 2011 – $2,210 million).

The reclamation and closure expenditures will be funded from Canadian Oil Sands’ cash from operating activities and reclamation trust. In addition to annual funding for reclamation expenditures, Canadian Oil Sands is depositing $0.25 per barrel of production attributable to its working interest in Syncrude to a reclamation trust established for the purpose of funding its share of reclamation and closure obligations.

Additionally, Canadian Oil Sands has posted letters of credit with the Province of Alberta in the amount of $75 million (December 31, 2011 – $75 million) to secure its pro rata share of the reclamation and closure obligations of the Syncrude owners.


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13) Income Taxes

The income tax expense recorded on the Consolidated Statements of Income and Comprehensive Income differs from the amount computed by applying the combined Canadian federal and provincial statutory income tax rate to earnings before taxes as follows:

For the years ended December 31 ($ millions, except income tax rates) 2012 2011

Earnings before taxes $ 1,299 $ 1,531 Statutory income tax rates Canadian basic federal income tax rate 25.0% 26.5% Canadian federal abatement -10.0% -10.0% Alberta provincial income tax rate 10.0% 10.0%

25.0% 26.5% Expected taxes at statutory rate 325 406 Add (deduct) the tax effect of: Non-taxable portion of capital (gains) losses (4) 3 Other (3) 1 Difference between current year and future years tax rates – (23) Tax expense $ 318 $ 387

Tax expense is comprised of the following:

For the years ended December 31 ($ millions) 2012 2011 Current tax expense $ 40 $ – Deferred tax expense 278 387

$ 318 $ 387

The amounts shown on the Consolidated Balance Sheets as deferred taxes represent the differences between the accounting and tax values of assets and liabilities and/or the timing differences arising when revenues or expenses are included in accounting income in one period and taxable income in a different period. These temporary differences are tax-effected using enacted or substantively enacted tax rates expected to apply when the temporary differences reverse.

The deferred tax liability recorded on the Consolidated Balance Sheets is comprised of the following:

December 31 December 31 As at ($millions) 2012 2011

Deferred tax assets (liabilities): Property, plant and equipment in excess of tax value $ (1,596) $ (1,608) Partnership earnings1 (282) (200) Liabilities in excess of tax value2 345 351 Non-capital losses carried forward – 193 Net deferred tax liability $ (1,533) $ (1,264) 1 The Corporation’s taxable income was primarily generated through a partnership and the related taxes are payable in future periods.2 Liabilities in excess of tax value mainly consist of the asset retirement obligation and employee future benefits.

Included in the $282 million deferred tax liability for partnership earnings is $118 million related to temporary differences that are expected to reverse in 2013. The remaining temporary differences underlying the deferred tax liability for partnership earnings and all other deferred tax assets and liabilities are not expected to reverse before 2014.



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The following estimated balances are available for deduction against future taxable income: December 31

As at ($ millions) 2012

Undepreciated Capital Costs1 $ 1,677 Canadian Development Expenses 31 Tax credits and other 14

$ 1,722 Taxable income generated through a partnership on which taxes are payable in future periods2 (1,128) Estimated balances available for deduction against future taxable income $ 594 1 Approximately 27 per cent of Undepreciated Capital Costs are currently available for deduction at the declining balance rate of 25 per cent annually while the balance relates to multi-year capital projects and were not available for deduction at December 31, 2012. 2 The Corporation’s taxable income is primarily generated through a partnership.

14) Shareholders’ Equity

a) Shareholders’ Capital The Corporation is authorized to issue an unlimited number of Common Shares without nominal or par value, and a maximum of 10,000,000 preferred shares, issuable in series.

Number of Shares Proceeds (millions) ($ millions)

Shareholders’ capital, January 1, 2011 484.45 $ 2,671 Issued under share-based compensation plans 0.08 2 Shareholders’ capital, December 31, 2011 484.53 2,673

Issued under share-based compensation plans 0.03 – Shareholders’ capital, December 31, 2012 484.56 $ 2,673

b) Net Income Per Share The following table summarizes the Shares used in calculating net income per Share:

For the years ended December 31 (millions) 2012 2011

Weighted-average Shares outstanding, Basic 485 485 Effect of options – – Weighted-average Shares outstanding, Diluted 485 485

c) Dividends During the year, the Corporation paid dividends of $654 million (2011 – $533 million) or $1.35 per Share (2011 – $1.10 per Share). On January 31, 2013, the Corporation declared a quarterly dividend of $0.35 per Share for a total dividend of approximately $170 million. The dividend will be paid on February 28, 2013 to Shareholders of record on February 22, 2013.

15) Share-Based Compensation

Canadian Oil Sands issues options, PSUs and RSUs under its long-term incentive plans for employees and DSUs as a component of non-executive directors’ compensation. In addition, Syncrude Canada issues Syncrude RSUs and Syncrude PSUs for which Canadian Oil Sands records its 36.74 per cent ownership share.


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The following table illustrates the number of units outstanding and the amounts Canadian Oil Sands recorded in its consolidated financial statements related to share-based compensation awards in 2012 and 2011:

Syncrude Syncrude Options PSUs RSUs DSUs RSUs PSUs

($ millions, except unit amounts) (a) (b) (c) (d) (e) (f)

2012 Units outstanding at December 31 2,200,923 240,102 19,541 50,352 576,573 1,931,522 Expense recognized during the year $ 2 $ 2 $ – $ 1 $ 7 $ – Liability recognized at December 31 n/a $ 4 $ – $ 1 $ 8 $ 7

2011 Units outstanding at December 31 1,796,571 256,228 7,891 22,498 409,136 1,308,111 Expense (recovery) recognized during the year $ 2 $ 4 $ – $ – $ 5 $ (5) Liability recognized at December 31 n/a $ 5 $ – $ – $ 3 $ 7

a) OptionsCanadian Oil Sands’ options provide the holder with a right to purchase a Share at the exercise price determined at the grant date. For options granted prior to 2011, exercise prices are reduced by dividends over a threshold amount. For options granted during 2011 and 2012, exercise prices are not reduced by dividends. Subject to certain exceptions relating to retirement, death or termination, the options vest by one-third following the date of grant in each of the first three years and expire seven years after the date of grant.

b) PSUsCanadian Oil Sands’ PSUs are awarded and settled in cash, in Shares purchased in the secondary market, or in Shares issued from treasury, at the end of a three-year vesting period. The settlement value is based on the Corporation’s Share price at the vesting date and the total Shareholder return generated by the Corporation relative to a comparator group, comprised of other industry peers and the S&P/TSX oil and gas E&P index.

c) RSUsCanadian Oil Sands’ RSUs are awarded and settled in cash, in Shares purchased in the secondary market, or in Shares issued from treasury, at the end of a three-year vesting period. The settlement value is based on the Corporation’s Share price at the vesting date.

d) DSUsCanadian Oil Sands’ DSUs are awarded and settled in cash, in Shares purchased in the secondary market or in Shares issued from treasury. DSUs vest immediately upon grant and settle when a director’s service ceases. The settlement value is based on the Corporation’s Share price on that date.

e) Syncrude RSUsSyncrude Canada awards Syncrude RSUs to certain employees. Subject to certain exceptions relating to retirement, death or termination, Syncrude RSUs are settled in cash after a three-year vesting period. There are two types of Syncrude RSUs. The cash settlement for the first type is based on the weighted-average price of certain Syncrude owners’ shares and the total shareholder return of such owners’ shares over the vesting period relative to a peer group. The cash settlement for the second type is based purely on the weighted-average price of certain Syncrude owners’ shares, and is not contingent on shareholder return.

f) Syncrude PSUsSyncrude Canada awards Syncrude PSUs to certain employees. Subject to certain exceptions relating to retirement, death or termination, Syncrude PSUs awarded before 2005 have a term of seven years and are subject to a vesting schedule



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under which up to 50 per cent of the units are exercisable one year following the date of grant, an additional 25 per cent may be exercised after two years, and the remaining 25 per cent may be exercised after three years. Syncrude PSUs awarded after 2005 have a term of seven years and vest in equal amounts over a three-year period. Syncrude PSUs are settled in cash and have value if the weighted-average price of the shares of certain of Syncrude’s shareholders at the exercise date exceeds the exercise price.

16) Crown Royalties

From 2009 through 2015, Syncrude’s Crown royalties are determined pursuant to the Syncrude Royalty Amending Agreement (“Syncrude RAA”) and the Syncrude Bitumen Royalty Option Agreement.

Under the Syncrude RAA, the Syncrude owners pay the greater of 25 per cent of net deemed bitumen revenues, or one percent of gross deemed bitumen revenues, plus a transition royalty of up to $975 million ($358 million net to the Corporation) forthe period January 1, 2010 to December 31, 2015. The transition royalty of $975 million is reduced proportionally if bitumen production is less than 345,000 barrels per day over the period. The $975 million ($358 million net to the Corporation) becomes payable and is accrued as bitumen is produced. Payments are scheduled over six annual installments as follows:

($ millions) 2010 2011 2012 2013 2014 2015 Total

Syncrude $ 75 $ 75 $ 100 $ 150 $ 225 $ 350 $ 975 Canadian Oil Sands’ share $ 27 $ 27 $ 37 $ 55 $ 83 $ 129 $ 358

Under the Syncrude Bitumen Royalty Option Agreement, costs related to capital expenditures that were deducted in computing Crown royalties on SCO prior to 2009, and are no longer associated with the royalty base, are recaptured by the Crown. These recapture amounts vary based on Government of Canada long-term bond rates and result in approximately $25 million of additional Crown royalties per year, net to the Corporation, over a 25-year period.

The Syncrude RAA requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil reference price further adjusted to reflect quality and location differences between Syncrude’s bitumen and the Canadian reference price bitumen. In addition, the agreement provides that a minimum bitumen value, or “floor price”, may be imposed in circumstances where Canadian heavy oil prices are temporarily suppressed relative to North American heavy oil prices.

Canadian Oil Sands’ share of the royalties recognized for the period from January 1, 2009 to December 31, 2012 reflect management’s best estimate of both reasonable quality and transportation deductions and adjustments to reflect the “floor price”. However, the Syncrude owners and the Alberta government are disputing the basis for the quality, transportation and “floor price” adjustments. Under alternate assumptions, Crown royalties for this period could be as much as $55 million (on an after-tax basis) more than the amounts recognized.

The Syncrude owners and the Alberta government continue to discuss these matters, but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter. The cumulative impact, if any, of such discussions or judicial determination, as applicable, would be recognized and impact both net income and cash flow from operations accordingly.

17) Foreign Exchange

For the years ended December 31 ($ millions) 2012 2011

Foreign exchange (gain) loss – long-term debt $ (28) $ 25 Foreign exchange (gain) loss – other 3 (3) Total foreign exchange (gain) loss $ (25) $ 22


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18) Net Finance Expense


Interest costs 1 $ 105 $ 87 Less capitalized interest (92) (57) Interest expense 13 30 Accretion of asset retirement obligation 26 16 Net finance expense $ 39 $ 46 1 Interest costs are net of interest income of $12 million (2011 – $4 million).

19) Capital Management

The Corporation’s capital consists of cash and cash equivalents, debt and Shareholders’ equity. The balance of each of these items at December 31, 2012 and 2011 was as follows:

December 31 December 31 ($ millions, except % amounts) 2012 2011

Total debt1,2 $ 1,794 $ 1,132 Cash and cash equivalents (1,553) (718) Net debt1,3 $ 241 $ 414

Shareholders’ equity $ 4,515 $ 4,210

Total net capitalization1,4 $ 4,756 $ 4,624

Total capitalization1,5 $ 6,309 $ 5,342

Net debt-to-total net capitalization1,6 (%) 5 9

Total debt-to-total capitalization1,7 (%) 28 21 1 Non-GAAP measure.2 Includes current and non-current portions of long-term debt.3 Total debt less cash and cash equivalents.4 Net debt plus Shareholders’ equity.5 Total debt plus Shareholders’ equity.6 Net debt divided by total net capitalization.7 Total debt divided by total capitalization.

The Corporation’s objective for managing capital is to maximize long-term Shareholder value by: • ensuring financing capacity for Syncrude’s oil sands-related investing activities; • targeting an investment grade credit rating and financial flexibility to control risk and allow the Corporation to

maintain its crude oil price exposure; and • distributing to Shareholders any cash that is not required for financing Syncrude’s operations or capital investment.

Net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, decreased in 2012 to $0.2 billion at December 31, 2012 from $0.4 billion at December 31, 2011. As a result, net debt-to-total net capitalization fell to five per cent at December 31, 2012 from nine per cent at December 31, 2011. While $1,581 million of cash flow from operations in 2012 fell short of capital expenditures and dividend payments of $1,086 million and $654 million, respectively,a reduction in non-cash working capital more than offset this difference. Shareholders’ equity increased in 2012 to $4.5 billionat December 31, 2012 from $4.2 billion at December 31, 2011, as net income exceeded dividends.

In March 2012, Canadian Oil Sands issued U.S. $400 million of 4.5 per cent unsecured Senior Notes due April 1, 2022 and U.S. $300 million of 6.0 per cent unsecured Senior Notes due April 1, 2042. Interest on the notes is payable semi-annually on April 1 and October 1. Proceeds from the issues will be used to repay U.S. $300 million of Senior Notes, which mature on August 15, 2013, to fund major capital projects over the next few years and for general corporate purposes. As a result of these debt issues, total debt-to-total capitalization rose to 28 per cent at December 31, 2012 from 21 per cent at December 31, 2011.



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As disclosed in Notes 10 and 11, the Senior Notes indentures and credit facility agreements contain certain covenants that restrict Canadian Oil Sands’ ability to sell all or substantially all of its assets or change the nature of its business, and limittotal debt-to-total capitalization to 55 per cent. Canadian Oil Sands is in compliance with its debt covenants and, with a totaldebt-to-total capitalization of 28 per cent at December 31, 2012, a significant increase in debt or decrease in equity would be required to negatively impact the Corporation’s financial flexibility.

The Corporation’s liquidity position has improved in 2012 as a result of our growing cash position and the issuance of the Senior Notes. Canadian Oil Sands intentionally built cash balances in 2011 and 2012 in order to increase liquidity for funding the major capital projects in 2013 and 2014 and the debt maturity in 2013. We expect cash levels to decrease significantly over the next two years as we fund major capital projects and repay the 2013 debt maturity. As a result, and based on the assumptions in our Outlook, net debt levels are expected to rise to $1 billion to $2 billion by the end of 2014, coincident with reduced capital expenditure risk from the completion of our major capital projects.

20) Financial Instruments

The Corporation’s financial instruments include cash and cash equivalents, accounts receivable, investments held in a reclamation trust, accounts payable and accrued liabilities, and current and non-current portions of long-term debt. The carrying values of the Corporation’s financial instruments and their related categories at December 31, 2012 and 2011 were as follows:


Financial Assets Loans and receivables Cash and cash equivalents $ 1,553 $ 718 Accounts receivable 311 376 Reclamation trust 69 58

$ 1,933 $ 1,152

Financial Liabilities Other liabilities

Accounts payable and accrued liabilities1 $ 660 $ 450 Long-term debt2 1,794 1,132

$ 2,454 $ 1,582 1 Excludes current portion of asset retirement obligation.2 Includes current and non-current portions of long-term debt.

Fair Values The fair values of cash and cash equivalents, accounts receivable, reclamation trust investments and accounts payable and accrued liabilities approximate their carrying values due to the short-term nature of those instruments. The fair value of long-term debt, based on third-party market indications, is as follows:


8.2% Senior Notes due April 1, 2027 (U.S. $73.95 million) $ 104 $ 92 7.9% Senior Notes due September 1, 2021 (U.S. $250 million) 332 318 5.8% Senior Notes due August 15, 2013 (U.S. $300 million) 309 324 7.75% Senior Notes due May 15, 2019 (U.S. $500 million) 628 624 4.5% Senior Notes due April 1, 2022 (U.S. $400 million) 435 – 6.0% Senior Notes due April 1, 2042 (U.S. $300 million) 350 –

$ 2,158 $ 1,358


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Financial Risks

Foreign Currency Risk Canadian Oil Sands’ results are affected by fluctuations in the U.S./Cdn currency exchange rates, as sales generated are based on a WTI benchmark price in U.S. dollars while operating expenses and capital expenditures are denominated primarily in Canadian dollars. Our sales exposure is partially offset by U.S. dollar obligations, such as interest costs on U.S.dollar-denominated long-term debt and our share of Syncrude’s U.S. dollar vendor payments. In addition, when our U.S. dollar Senior Notes mature, we have exposure to U.S. dollar exchange rates on the principal repayment of the notes. This repayment of U.S. dollar debt acts as a partial economic hedge against the U.S. dollar-denominated sales receipts we collect from our customers.

In the past, the Corporation has hedged foreign currency exchange rates by entering into fixed rate currency contracts. The Corporation did not have any foreign currency hedges in place during 2012 or 2011, and does not currently intend to enter into any new currency hedge positions. The Corporation may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.

As at December 31, 2012, portions of Canadian Oil Sands’ cash and cash equivalents, accounts receivable, accounts payable and long-term debt were denominated in U.S. dollars. Based on these U.S. dollar financial instrument closing balances, 2012 net income and comprehensive income would have increased/decreased by approximately $14 million for every $0.01 decrease/increase in the value of the U.S./Cdn currency exchange rate.

Interest Rate Risk Canadian Oil Sands’ financial results are impacted by U.S. and Canadian interest rate changes because our credit facilities and investments are exposed to floating interest rates. In addition, we are exposed to the refinancing of maturing long-term debt at prevailing interest rates. As at December 31, 2012, there were no amounts drawn on the credit facilities (no amountsdrawn on the credit facilities at December 31, 2011) and the U.S. $300 million of Senior Notes, which mature in August 2013,were refinanced with our 2012 Senior Note issuance. Canadian Oil Sands did not have a significant exposure to interest rate risk due to the short-term nature of its investments and having no outstanding floating rate debt during the year.

Liquidity Risk Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they come due.CanadianOil Sands actively manages its liquidity through cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through bank credit facilities, estimating future cash flow from operations based on reasonable production and pricing assumptions, understanding operating commitments andfuture capital expenditure requirements, analyzing economic hedging opportunities, and complying with debt covenants. In addition, over the long-term, Canadian Oil Sands spreads out the maturities of its various debt tranches and maintains a prudent capital structure.

The long-term debt outstanding of U.S. $1.5 billion is not due until 2019 or later and the $1.5 billion credit facility does not expire until June 2016. The U.S. $300 million of Senior Notes, which mature in August 2013, were refinanced with our 2012 Senior Note issuance. Canadian Oil Sands held cash balances totaling $1.6 billion at December 31, 2012, and was in compliance with its debt covenants throughout 2012, collectively resulting in relatively low liquidity risk.

More information regarding the available credit facilities and contractual maturities of Canadian Oil Sands’ long-term debt can be found in Notes 10 and 11, respectively.



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The expected timing of cash flows related to financial liabilities is outlined below:

Cash Outflow By Period ($ millions) Total 2013 2014 to 2015 2016 to 2017 After 2017

Accounts payable and accrued liabilities1 $ 660 $ 660 $ – $ – $ – Long-term debt2 $ 3,016 $ 409 $ 200 $ 200 $ 2,207 1 Excludes current portion of asset retirement obligation.2 Includes current and non-current portions of long-term debt. Actual payments differ from the carrying value of the long-term debt as the amounts in this

table include both principal and interest payments.

Credit Risk Canadian Oil Sands is exposed to credit risk primarily through customer receivable balances, financial counterparties with whom the Corporation has invested its cash and cash equivalents, and with its insurance providers in the event of an outstanding claim. The maximum exposure to any one customer or financial counterparty is controlled through a credit policy that limits exposure based on credit ratings. The policy also specifically limits the exposure to customers with a creditrating below investment grade to a maximum of 25 per cent of Canadian Oil Sands’ consolidated accounts receivable. This credit risk concentration is monitored on a regular basis. Risk is further mitigated as accounts receivable with customers typically are settled in the month following the sale, and investments with financial counterparties are typically short-term in nature and are placed with institutions that have a credit rating of “R-1 (low)” or better, as defined by the Dominion Bond Rating Service (“DBRS”).

Canadian Oil Sands carries credit insurance on some counterparties to help mitigate a portion of the impact should a loss occur and continues to transact primarily with investment grade customers. The Corporation’s maximum credit exposure related to customer receivables was $311 million at December 31, 2012 ($376 million at December 31, 2011). The vast majority of accounts receivable at December 31, 2012 was due from investment grade energy producers, financial institutions,and refinery-based customers, and our cash and cash equivalents were invested in deposits and bankers’ acceptances with high-quality senior banks as well as investment grade commercial paper. At present, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.

21) Key Management Personnel Compensation

Key management personnel include the Corporation’s Board of Directors and certain members of senior management. Canadian Oil Sands recorded the following amounts in its financial statements relating to key management personnel compensation in 2012 and 2011:

($ millions) 2012 2011

Expense for the year Short-term benefits expense1 $ 5 $ 4 Share-based compensation expense 5 7

$ 10 $ 11 Liability recorded at December 312 $ 5 $ 7 1 Short-term benefits include salaries, annual incentive plan payments, the Corporation’s contributions to savings accounts on behalf of key management

personnel and fees paid to directors. 2 Liability owing to key management personnel for short-term benefits and share-based compensation.


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22) Commitments

Canadian Oil Sands is obligated to make future cash payments under contractual agreements that it has entered into either directly or as a 36.74 per cent owner in Syncrude. Cash from operating activities and existing cash balances are expected to be sufficient to fund the contractual obligations and commitments as they become due. The following table outlines the significant commitments that the Corporation will be required to fund which are not recorded as liabilities:

Cash Outflow By Period ($ millions) Total 2013 2014 to 2015 2016 to 2017 After 2017 Pipeline and storage (a) $ 2,536 $ 46 $ 163 $ 231 $ 2,096 Capital expenditures (b) 246 223 23 – – Natural gas purchases (c) 94 56 38 – – Other (d) 316 141 92 22 61

$ 3,192 $ 466 $ 316 $ 253 $ 2,157

a) Pipeline and Storage Canadian Oil Sands transports crude oil to customers and incurs transportation and storage costs as a result. To secure access to preferred markets and enhance marketing flexibility, the Corporation has committed to the use of certain pipelines and storage facilities which require Canadian Oil Sands to pay for services whether or not any volumes are shipped. Amounts are due under these commitments over the next 24 years.

b) Capital Expenditures Capital expenditure commitments are comprised of Canadian Oil Sands’ share of Syncrude’s funding commitments primarily related to the major projects: the Mildred Lake Mine Train Replacement, Aurora North Mine Train Relocation, Aurora North Tailings Management and Centrifuge Tailings Management projects. Amounts are due in 2013 and 2014.

c) Natural Gas Purchases Canadian Oil Sands is committed to its share of Syncrude’s purchase commitments for natural gas deliveries in 2013 and 2014 at floating market prices.

d) Other Other commitments include Canadian Oil Sands’ share of:

• Syncrude Canada’s employee retention program costs of $87 million for 2013 through 2015; • Syncrude’s commitment for tire purchases of $49 million for 2013 through 2024; and • Syncrude Canada’s non-cancellable annual fixed service fees totaling $34 million for 2013 and 2014, due under

a management services agreement with Imperial Oil Resources.

23) Contingencies

See Note 16 for a discussion of the contingent liability relating to the measurement of Crown royalties.

Various suits and claims arising in the ordinary course of business are pending against Syncrude Canada. While the ultimate effect of such actions cannot be ascertained at this time, in the opinion of the Corporation’s management and in consultation with its legal counsel, the possibility of an outflow of resources is remote. Syncrude Canada, as well as Canadian Oil Sands and the other Syncrude owners, also have claims pending against various parties, the outcomes of which are not yet determinable.



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24) Guarantees

Canadian Oil Sands has posted performance standby letters of credit with the Province of Alberta which are renewed annually. The letters of credit guarantee to the Province of Alberta the obligations of Canadian Oil Sands’ interest in future reclamation and closure of the Syncrude mines and plants (Note 12). The Province of Alberta can draw on the letters of credit if Syncrude fails to perform its reclamation and closure duties. The maximum potential amount of payments Canadian Oil Sands may be liable for pursuant to these letters of credit is $75 million.

25) Supplementary Information

a) Change in Non-Cash Working Capital


Operating activities: Accounts receivable (“AR”) $ 65 $ 4 Inventories 5 (13) Prepaid expenses 1 (4) Accounts payable and accrued liabilities (“AP”) 265 75 Less: AP and AR changes reclassified to investing and other (53) (1) Change in operating non-cash working capital $ 283 $ 61

Investing activities: Accounts payable and accrued liabilities $ 34 $ 4 Change in investing non-cash working capital $ 34 $ 4

Change in total non-cash working capital $ 317 $ 65

b) Income Taxes and Interest Paid


Income taxes paid $ – $ –

Interest paid $ 106 $ 95

Income taxes and interest payments are included within cash from operating activities on the Consolidated Statements of Cash Flows. The portion of interest costs that is capitalized as property, plant and equipment is included within cash used in investing activities on the Consolidated Statements of Cash Flows.

c) Major Customers In connection with the marketing and sale of Canadian Oil Sands’ own synthetic crude oil for the year ended December 31,2012, the Corporation had four customers (2011 – two) which individually accounted for more than 10 per cent of consolidated sales. Sales to these customers in 2012 were approximately $1,844 million (2011 – $1,173 million). Concentration of sales is monitored regularly and, in management’s assessment, the Corporation is not dependent upon these major customers.

d) Geographical Areas


Canada $ 3,422 $ 3,909 United States 483 273 Total Sales1 $ 3,905 $ 4,182 1 Sales are allocated to each country based on the location of the sale.


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26) Accounting Pronouncements Not Yet Adopted

Employee Future Benefits In June 2011, the International Accounting Standards Board (“IASB”) amended IAS 19, Employee Benefits, addressing the recognition and measurement of defined benefit pension expense and termination benefits, and disclosures for all employee benefits. The amendments are effective for years beginning on or after January 1, 2013 with earlier application permitted. The amendments must be applied retrospectively.

The key amendments are as follows: • Actuarial gains and losses, which will be referred to as re-measurements, are to be recognized immediately in

“other comprehensive income” (“OCI”), eliminating the choice between immediate recognition through net income or OCI, or deferral using the corridor approach. This change will not impact Canadian Oil Sands as the Corporation currently recognizes actuarial gains and losses immediately through OCI.

• An expected rate of return on assets will no longer be calculated. Instead, the interest cost component of the pension expense, which previously represented accretion of the discounted accrued benefit obligation, will now represent accretion of the net accrued benefit liability (the accrued benefit obligation net of the fair value of plan assets). The rate, based on a market rate of interest for high-quality corporate debt instruments with cash flows that match the timing and amount of expected benefit payments, will be the same rate previously used to accrete the discounted accrued benefit obligation.

• Lastly, the interest cost component of pension expense will now be presented within net finance expense.

Canadian Oil Sands has chosen to apply the amendments effective January 1, 2013. The 2012 comparative year amounts reported in the Corporation’s Consolidated Statements of Income and Comprehensive Income in 2013 will be adjusted as follows:

Adjusted To Reflect Amended

($ millions) As Reported Standard Adjustments

Operating expenses $ 1,511 $ 1,504 $ (7) Net finance expense $ 39 $ 60 $ 21 Tax expense $ 318 $ 314 $ (4) Net income $ 981 $ 971 $ (10) Other comprehensive loss, net of taxes $ (21) $ (11) $ 10

Consolidation In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements; IFRS 11, Joint Arrangements, to replaceInternational Accounting Standard (“IAS”) 31, Interests in Joint Ventures; IFRS 12, Disclosure of Interests in Other Entities; and amendments to IAS 27, Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures. These new standards and amendments are effective for years beginning on or after January 1, 2013 with earlier application permitted if all five standards are collectively adopted.

IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements. IFRS 11 eliminates theaccounting policy choice between proportionate consolidation and equity method accounting for joint ventures available underIAS 31 and, instead, mandates one of these two methodologies based on the economic substance of the joint arrangement. IFRS 12 requires entities to disclose information about the nature of their interests in joint ventures. Canadian Oil Sands doesnot anticipate that any of these standards will result in significant accounting or disclosure changes.

Fair Value Measurement In May 2011, the IASB issued IFRS 13, Fair Value Measurements, which establishes a single source of guidance for fair value measurements and related disclosures. The new standard is effective for years beginning on or after January 1, 2013 with earlier application permitted. Canadian Oil Sands does not anticipate that this standard will result in significant accounting or disclosure changes.



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Financial Instruments: Disclosures In December 2011, the IASB issued amendments to IFRS 7, Financial Instruments: Disclosures, effective for years beginning on or after January 1, 2013 with retrospective application for all comparative periods The amendments require entities to disclose information about the effect, or potential effect, of netting arrangements on an entity’s financial position.Canadian Oil Sands will be adding these disclosures when the standard becomes effective in 2013; however we do not expect that this will result in significant changes to disclosures.

Production Stripping Costs In October 2011, the IASB issued International Financial Reporting Interpretations Committee (“IFRIC”) Interpretation 20, Stripping Costs in the Production Phase of a Surface Mine, which clarifies the accounting for costs associated with waste removal in surface mining during the production phase of a mine. The standard is effective for years beginning on or after January 1, 2013 with earlier application permitted. Canadian Oil Sands does not anticipate that this standard will result in significant accounting or disclosure changes.

FORWARD-LOOKING INFORMATION

In the interest of providing shareholders and potential investors of Canadian Oil Sands Limited (the “Corporation” or “Canadian Oil Sands” or “we” or “our”) with information regarding the Corporation, including management’s assessment of the Corporation’s future production and cost estimates, plans and Syncrude operations, certain statements throughout this annual report contain “forward-looking information” under applicable securities law. Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “believe”, “plan”, “intend” or similar words suggesting future outcomes. Forward-looking statements in this annual report include, but are not limited to, statements with respect to: the estimated amount of total capital expenditures, estimated completion percentages and anticipated target in-service dates for the Mildred Lake mine train replacements, the Aurora North mine train relocations, the composite tails plant at the Aurora North mine and the centrifuge plant at the Mildred Lake mine; the expectation that the major projects at Syncrude should support production for decades as well as improve environmental performance; the estimated value and amount of reserves recoverable and the time frame to recover such reserves; the estimated resources; the ability of Syncrude’s reserves to produce at current rates for the next 40 years with the potential for future growth through undeveloped resources; the belief that Syncrude can gradually and safely achieve industry-leading utilization rates; the cost of the new oil sands mining infrastructure expected to come on stream in 2013; the quality of Syncrude’s leases; the expected benefits of wet crushing technology; the expected benefits of the management services agreement; the belief that there are gradual and steady production gains to be achieved at Syncrude; the expectation that the volatility of the Syncrude synthetic crude oil (“SCO”) to West Texas Intermediate (“WTI”) differential will continue at least for the next few years; the belief that modifications at some U.S. refineries to process heavier crude oil will ultimately push light crude sales, including SCO, to more distant refineries, which increases transportations costs; the expectation that the proposed pipeline projects will narrow the SCO to WTI differential; the belief that tight oil production in the U.S will not displace synthetic oil products and that the U.S. will still require crude oil imports; the belief that Canadian crude oil exports to the U.S. will increasingly displace crude oil from places such as the Middle East, Mexico and Venezuela; the expectation that the WTI to Brent differential will be reduced in the near term, with new capacity to the U.S. Gulf Coast being brought on with the reversal of the Seaway pipeline, the construction of the Keystone XL Southern Leg expected to be complete by the end of 2013 and the twinning of the Seaway pipeline anticipated in mid-2014; the expectations regarding future crude oil production growth and demand and the source of the future crude oil demand; intentions and expectations regarding future dividend levels, including our intention to pay a quarterly dividend of $0.35 per common share for 2013, based on the assumptions in our 2013 outlook; the view that, assuming continued strength in world oil prices, after 2014 we see the potential for expanded free cash flow (cash flow from operations less capital expenditures), when our major project spending tapers off; the anticipation that our major project spending will taper off after 2014; the estimation that the Mildred Lake mine extension project (the “MLX Project”) should provide a low-cost source of new bitumen production into the 2030s; the belief that per barrel operating costs should decrease in 2013; the plan to maintain a strong balance sheet in 2013; the plan to remain unhedged on oil prices in 2013; the plan to increase production by about five per cent in 2013 (110 million barrels gross to Syncrude and 40.4 million barrels net to Canadian Oil Sands in 2013); the belief that the Aurora North composite tails plant should be complete in 2013; the belief that the Aurora North mine train relocations should be 90 per cent complete after 2013; the belief that the Mildred Lake mine train replacements should be 75 per cent complete after 2013 and the estimation that Syncrude will invest $70 million ($25 million net to COS) in research and development in 2013.

You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, estimates, forecasts, projections and other forward-

looking statements will not occur. Although the Corporation believes that the expectations represented by such forward-looking statements are reasonable and reflect the current views of the Corporation, there can be no assurance that such expectations will prove to be correct.

The factors or assumptions on which the forward-looking information is based include, but are not limited to: the assumptions outlined in the Corporation’s guidance document as posted on the Corporation’s website at www.cdnoilsands.com as of the date hereof and as subsequently amended or replaced from time to time, including without limitation, the assumptions as to production, operating expenses and oil prices; the successful and timely implementation of capital projects; the Syncrude major project spending plans; the ability to obtain regulatory and Syncrude joint venture owner approval; our ability to either generate sufficient cash flow from operations to meet our current and future obligations or obtain external sources of debt and equity capital; the continuation of assumed tax, royalty and regulatory regimes and the accuracy of the estimates of our reserves and resources volumes.

Some of the risks and other factors that could cause results to differ materially from those expressed in the forward-looking statements contained in this annual report include, but are not limited to: the supply and demand metrics for oil and natural gas; general economic, business and market conditions and in particular, the impact of any downturn in the economy and the length of such economic recession; risks inherent to the operation of any large, complex refinery units, especially the integration between mining operations and an upgrader facility; regulatory changes which may impact the penalties on greenhouse gas emitters and operators with tailings ponds; labour shortages and the productivity achieved from labour in the Fort McMurray area; the impact of technology on operations and processes and how new complex technology may not perform as expected; currency and interest rate fluctuations; the availability of pipeline and rail transportation; global refining capacity; changes in business strategy; the availability and price of energy commodities; regulatory decisions; the effects of competition and pricing pressures; shifts in market demands; changes in laws and regulations including environmental and regulatory laws; potential increases in costs; the unanimous joint venture owner approval for major expansions and changes in product types; the impact of Syncrude not being able to meet the conditions of its approval for its tailings management plan under Directive 074; unsuccessful or untimely implementation of capital or maintenance projects; volatility of crude oil prices; volatility of the SCO to WTI differential; the availability of adequate levels of insurance; various events which could disrupt operations including fires, equipment failures and severe weather conditions; technological changes; management retention and development and such other risks and uncertainties described in the Corporation’s Annual Information Form dated February 21, 2013 and in the reports and filings made with the securities regulatory authorities from time to time by the Corporation, which are available on the Corporation’s profile on SEDAR at www.sedar.com and on the Corporation’s website at www.cdnoilsands.com.

You are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this annual report are made as of the date of this annual report and unless required by law, the Corporation does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this annual report are expressly qualified by this cautionary statement.

In any reference to contingent resources in this annual report, there is no certainty that it will be commercially viable to produce any portion of the resources.

In any reference to prospective resources in this annual report, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

The financial results of the Corporation have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) and are reported in Canadian dollars, unless otherwise stated.

A D V I S O RY



A D V I S O RY

NON-GAAP AND ADDITIONAL GAAP FINANCIAL MEASURES

In this annual report, we refer to financial measures that do not have any standardized meaning as prescribed by Canadian GAAP. These financial measures include additional GAAP financial measures (which are line items, headings or subtotals in addition to those required under Canadian GAAP) and non-GAAP financial measures. Additional GAAP and non-GAAP financial measures provide additional information that we believe is meaningful regarding the Corporation’s operational performance, its liquidity and its capacity to fund dividends, capital expenditures and other investing activities. Users are cautioned that additional GAAP and non-GAAP financial measures presented by the Corporation may not be comparable with measures provided by other entities.

We refer to one additional GAAP financial measure: cash flow from operations, which is calculated as cash from operating activities, as reported on the Consolidated Statements of Cash Flows, before changes in non-cash working capital. We believe cash flow from operations, which is not impacted by fluctuations in non-cash working capital balances, is more indicative of operational performance. The majority of our non-cash working capital is liquid and typically settles within 30 days.

Non-GAAP financial measures include cash flow from operations per share (which is calculated as cash flow from operations divided by the weighted-

average number of shares outstanding in the period); net debt to cash flow from operations (which is calculated as net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, divided by cash from operating activities less changes in non-cash working capital); net debt to total net capitalization (which is calculated as net debt, comprised of current and non-current portions of long-term debt less cash and cash equivalents, divided by net debt plus shareholders’ equity); return on average productive capital employed (which is calculated as net income before interest expense, deferred taxes and foreign exchange gains and losses, divided by average net debt plus shareholder’s equity, less capitalized costs related to major expansion projects not yet in use); return on average shareholders’ equity (which is calculated as net income divided by average shareholders’ equity outstanding during the year); and free cash flow (which is calculated as cash flow from operations less capital expenditures). In addition, the Corporation refers to various per barrel figures, such as net realized selling prices, operating expenses and Crown royalties, which also are considered non-GAAP financial measures. We derive per barrel figures by dividing the relevant sales or cost figure by our sales volumes, which are net of purchased crude oil volumes in a period.

For more information on non-GAAP and additional GAAP financial measures please refer to our 2012 annual MD&A.


G L O S S A RY A N D A B B R E V I AT I O N S

Alberta oil sand(s) deposits The four deposits, Athabasca, Peace River, Cold Lake and Wabasca, have total resources in place estimated at 1.7 trillion to 2.5 trillion barrels. The Athabasca Oil Sands deposit, Alberta’s largest and most accessible source of bitumen, contains more than one trillion barrels of bitumen over an area encompassing more than 30,000 square kilometres.

Bitumen A molasses-like substance that, in its raw state, is a heavy oil. It is a naturally occurring viscous mixture that requires upgrading or blending to make it transportable by pipeline and useable by conventional refineries.

Carbon dioxide (CO2) A non-toxic gas produced from decaying materials, respiration of plant and animal life, and combustion of organic matter, including fossil fuels; carbon dioxide is the most common greenhouse gas produced by human activities.

Centrifuge plant Proven technology that removes tailings into a soft, clay-rich soil that can be used in reclamation efforts.

Cokers Vessels in which bitumen is cracked into its fractions and from which coke is withdrawn in the process of converting bitumen to upgraded crude oil.

Composite tails plant Mixes mature fine tailings with gypsum and coarse tailings sand to transform the mature fine tailings into solid material suitable for reclamation.

Conventional oil Petroleum found in liquid form, flowing naturally, or capable of being pumped without further processing or dilution.

Feedstock(s) Raw material supplied to refinery, oil sands upgrader, or petrochemical plant.

Fluid coking A major part of the upgrading process whereby high temperatures in a coker break down the complex bitumen molecules, reject carbon and cause bitumen molecules to reformulate into lighter fractions that become the main ingredients in upgraded crude oil.

Mine train Modular units for crushing and mixing the oil sands with warm water to facilitate the extraction of bitumen from the oil sands.

Oil sand(s) A composition of sand, bitumen, mineral-rich clays and water.

Oil sand(s) lease A long-term agreement with the provincial government that permits the leaseholder to extract bitumen, other metals and minerals contained in the oil sands in the specified lease area.

Ore grade The percentage of bitumen by weight in the oil sands.

Reclamation The return of land used in oil sands operations to a productive state. Significant investments are being made by industry into advanced reclamation technology and techniques.

Synthetic crude oil A high-quality product resulting from the mining, extraction and upgrading of bitumen.

Tailings A combination of water, sand, silt, fine clay particles and residual hydrocarbon that is a by-product of removing bitumen from oil sand.

Tailings systems Separation of water from sand and clay to enable incorporation of solids into reclamation landscapes and recycling of water back into the operations.

Tight oil Light crude oil that is trapped in shale, limestone and sandstone formations and can only be produced economically using hydraulic fracturing, horizontal drilling, or other advanced techniques.

Total volume to bitumen in place (TV/BIP) The ratio of total ore plus overburden volume to total bitumen in place.

Turnaround A unit shutdown essential for good maintenance of the mining, producing and upgrading facilities. A turnaround reduces production but does not usually halt it entirely as the various operating units are often duplicated.

Upgrader A facility that upgrades bitumen (extra heavy oil) into synthetic crude oil.

Upgrading The conversion of heavy bitumen into a lighter crude oil by increasing the ratio of hydrogen to carbon, either by removing carbon (coking) or adding hydrogen (hydroprocessing).

RESERVES AND RESOURCES DEFINITIONS

Proved reserves Reserves that can be estimated with a high degree of certainty to be recoverable. NI 51-101 further identifies the certainty level for proved reserves as “at least a 90 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves”.

Proved plus probable reserves Additional reserves that are less certain to be recovered than proved reserves. NI 51-101 defines the certainty level as “at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.” Therefore, under NI 51-101, the proved plus probable reserves represent a “best estimate” or “expected reserves”.

Contingent resources 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.

Prospective resources 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.

Best estimate Term used to describe an uncertainty category for resources estimates referring to the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the “best estimate”. The best estimate of Contingent and Prospective Resources is prepared independent of the risks associated with achieving commercial production.

FINANCIAL METRICS

Cash flow from operations Cash from operating activities before changes in non-cash working capital.

Netback price Realized SCO selling price, less operating expenses and Crown royalties.

Net debt to cash flow from operations Net debt divided by cash flow from operations.

Net debt to total net capitalization Net debt divided by net debt plus shareholders’ equity.

Return on average shareholders’ equity Net income divided by average shareholders’ equity.

Return on average productive capital employed Net income before net interest expense, deferred taxes and foreign exchange gains and losses, divided by average net debt plus shareholders’ equity, less capitalized costs related to major expansion projects not yet in use.

Total shareholder return Change in share price over a period of time assuming all dividends are reinvested.

ABBREVIATIONS

barrel(s): bbl, bbls

barrel(s)/day: bbl/d, bbls/d, bpd

carbon dioxide: CO2

greenhouse gases: GHG(s)

millions of barrels: mmbbls

sulphur dioxide: SO2

Syncrude synthetic crude oil: SCO

thousands of barrels: mbbls

West Texas Intermediate: WTI


($ millions, except as indicated) 2012 2011 20101 2009 2008

FINANCIALSales, after crude oil purchases and transportation expense 3,566 3,934 3,1 80 2,615 4,1 69Operating expenses 1 ,5 1 1 1 ,50 1 1,387 1,328 1,368Development expenses6 10 1 1 1 3 105 14 1 78Crown royalties 202 307 306 228 599Administration 26 25 20 24 17Insurance 10 8 1 1 9 6Interest expense, net 13 30 61 93 68Depreciation and depletion 403 38 1 429 570 444 Goodwill impairment – – – 52 –Foreign exchange (gain) loss (25) 22 (60) (161 ) 159Tax (expense) recovery 318 387 (289) (101 ) (93)Net income 981 1 ,144 1 ,189 432 1,523 Per share ($) 2.02 2.36 2.46 0.89 3.17Cash flow from operations2,5 1,581 1,897 1,232 754 2,039 Per share ($)4 3.26 3.91 2.55 1.56 4.24Dividends 654 533 896 435 1,804 Per share ($) 1.35 1.10 1.85 0.90 3.75Capital expenditures 1,086 643 582 409 281

RESERVES (billions of SCO bbls, net to COS)

Proved reserves 0.8 0.8 0.9 1.0 1.0Proved plus probable reserves 1 .7 1 .8 1.8 1.9 1.8Contingent resources 1 .9 1 .9 2.0 1.8 2.0Prospective resources 0.6 0.6 0.6 0.7 0.8

OPERATING NETBACK ($/bbl)4

Realized SCO selling price 91.90 101 .20 80.53 69.47 1 07.47Operating expenses 39.06 38.80 35.42 35.29 35.26Crown royalties 5.2 1 7.93 7.80 6.06 15.44Netback price 47.63 54.47 37.3 1 28.1 2 56.77

FINANCIAL RATIOS4

Net debt to cash flow from operations (times)2 0.2 0.2 1.0 1.4 0.5Net debt to total net capitalization (%) 5.0 9.0 24.0 21.0 20.0Return on average productive capital employed (%) 26.6 33.2 1 9. 1 6.7 33.9Return on average shareholders’ equity (%) 22.5 28.8 33.0 11.0 37.7

TRADING DATA Share price high 25.19 33.94 33.05 39.89 55.25Share price low 18.21 1 8. 1 7 24.24 16.65 1 8.1 5Share price close 20.17 23.25 26.45 29.9 1 21 .10Trading volume (millions of shares) 402. 1 567. 1 4 1 2.7 4 1 6.0 463.6Number of shares outstanding (in millions) 484.6 484.5 484.4 484.4 481 .6

VOLUMES COS average daily sales (bbls/d)3 105,680 106,015 107,280 103,129 105,986COS total sales (mmbbls)3 38.7 38.7 39.2 37.6 38.8Syncrude average daily production (bbls/d) 286,505 288,372 293,288 279,926 289,129Syncrude total production (mmbbls) 104.9 105.3 107.0 102.2 105.8

1 Adjusted for International Financial Reporting Standards (“IFRS”). Note 26 to the 2011 annual audited consolidated financial statements discloses the impact of the transition to IFRS on the Corporation’s reported financial position, income and cash flows.


3 The Corporation’s sales volumes differ from its production volumes due to changes in inventory, which are primarily in-transit pipeline volumes. Sales volumes are net of purchases.4 Non-GAAP measures.5 Additional GAAP measure. 6 Previously referred to as non-production expenses.

Not adjusted for IFRS

S TAT I S T I C A L S U M M A RY

All references to “dollars” or “C$” are in Canadian dollars and all references % to “US$” are in United States dollars 2012 2011 change

FINANCIAL ($ millions, except per share amounts) Sales, after crude oil purchases and transportation expense 3,566 3,934 – 9% Cash flow from operations1,4 1 ,581 1,897 – 17% Per share3 3.26 3.9 1 – 17%Net income 981 1, 144 – 14% Per share, basic and diluted 2.02 2.36 – 14%Dividends 654 533 23% Per share 1.35 1.10 23%

FINANCIAL RATIOS3 Net debt to cash flow from operations (times)1 0.2 0.2 Net debt to total net capitalization (%) 5 9 Return on average shareholders’ equity (%) 22.5 28.8 Return on average productive capital employed (%) 26.6 33.2

OPERATIONSSales volumes, net of crude oil purchases2

Total (mmbbls) 38.7 38.7 0% Daily average (bbls) 105,680 106,015 0%Operating expenses ($/bbl)3 39.06 38.80 1%Capital expenditures ($ millions) 1,086 643 69%Net realized selling price ($/bbl)3 91.90 101.2 – 9%Average West Texas Intermediate (US$/bbl) 94.1 5 95. 1 1 – 1%Average foreign exchange rate (US$/C$) 1.00 1.0 1 – 1%

SHARE INFORMATIONClosing price on December 31 ($/share) 20.1 7 23.25 – 13% Number of shares outstanding (in millions) 484.6 484.5 0% Total shareholder return3 (%) – 8 – 8 0%S&P/TSX Oil & Gas Index (%) – 1 1 – 18

Certain calculations displayed above are non-GAAP or additional GAAP financial measures. Please see the Management’s Discussion and Analysis section of this report for a discussion of non-GAAP and additional GAAP financial measures.

A five-year statistical summary is provided on page 76.


2 The Corporation’s sales volumes differ from its production volumes due to changes in inventory, which are primarily in-transit pipeline volumes, and are after purchased crude oil volumes.

3 Non-GAAP measure(s).4 Additional GAAP measure.

2012 results reflected lower pricing for our product.

COS continues to demonstrate strong profitability on invested equity.

F I N A N C I A L A N D O P E R AT I N G H I G H L I G H T S

2012 results

I N S I D E T H I S R E P O RT

02 President’s Message 08 Strategic Scorecard 10 Financial Review 1 1 Management’s Discussion and Analysis 4 1 Management’s Report 42 Independent Auditor’s Report 44 Consolidated Financial Statements 48 Notes to Consolidated Financial Statements 73 Advisory 75 Glossary and Abbreviations 76 Statistical Summary IBC Shareholder Information

S H A R E H O L D E R I N F O R M AT I O N

Board of Directors

DONALD J. LOWRY 2

Chairman of the Board President and Chief Executive Officer EPCOR Utilities Inc. Edmonton, Alberta

IAN A. BOURNE 1,2

Calgary, Alberta

MARCEL R. COUTUPresident and Chief Executive Officer Canadian Oil Sands Limited Calgary, Alberta

GERALD W. GRANDEY 1,2

Saskatoon, Saskatchewan

SARAH E. RAISS 1

Calgary, Alberta

JOHN K. READ 3

Calgary, Alberta

BRANT G. SANGSTER 3

Calgary, Alberta

C.E. (CHUCK) SHULTZ 3

Chairman Emeritus of the Board Chairman and Chief Executive Officer Dauntless Energy Inc. Calgary, Alberta

WESLEY R. TWISS 2,3

Calgary, Alberta

JOHN B. ZAOZIRNY, Q.C.1

Canaccord Financial Corporation Calgary, Alberta

1 Member of the Corporate Governance and Compensation Committee

2 Member of the Audit Committee3 Member of the Reserves, Marketing

Operations and Environmental, Health and Safety Committee

Officers

MARCEL R. COUTUPresident and Chief Executive Officer

RYAN M. KUBIKChief Financial Officer

TRUDY M. CURRANSenior Vice President, General Counsel and Corporate Secretary

DARREN K. HARDYSenior Vice President, Operations

ALLEN R. HAGERMAN, fca

Executive Vice President

ROBERT P. DAWSONVice President, Finance

PHILIP D. BIRKBYController


ADRIENNE NICKERSONVice President, Operations

DAVID J. SIRRSVice President, Marketing

SCOTT W. ARNOLDDirector, Sustainability and External Relations

Ticker Symbols

Toronto Stock Exchange: COSOTCQX: COSWF

Registrar and Transfer Agent

Computershare Trust Company of Canada, with offices in Vancouver, Calgary, Toronto and Montreal, is the registrar and Transfer Agent for Canadian Oil Sands Limited.

COMPUTERSHARE TRUST COMPANY OF CANADA600, 530 – 8th Avenue SW Calgary, Alberta T2P 3S8 Telephone: 1 (800) 564-6253 Fax: (403) 267-6598 E-mail: [email protected]

Auditors

PRICEWATERHOUSECOOPERS LLP CHARTERED ACCOUNTANTSCalgary, Alberta

Independent Qualified Reserves Evaluators

GLJ PETROLEUM CONSULTANTS LTD.Calgary, Alberta

Internal Auditors

DELOITTE & TOUCHE LLPCalgary, Alberta

Canadian Oil Sands Limited

2500 First Canadian Centre 350 – 7th Avenue S.W. Calgary, Alberta T2P 3N9 Telephone: (403) 218-6200 Fax: (403) 218-6201

Investor and Media Contacts


ALISON TROLLOPEManager, Investor Relations

Telephone: (403) 218-6220 Email: [email protected]

Notice of Meeting

Canadian Oil Sands’ 2013 Annual Special Meeting will be held in the Metropolitan Conference Centre, The Ballroom, 333 – 4th Avenue SW, Calgary, Alberta on Tuesday, April 30, 2013 at 2:30 pm (MST). All shareholders are invited to attend, and those unable to do so are requested to sign and return the form of proxy mailed with this report to ensure representation at the meeting. The meeting will be webcast on our website at www.cdnoilsands.com.D

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For additional information about Canadian Oil Sands, or for an on-line version of this report, please visit our website at www.cdnoilsands.com.

1211100908

CASH FLOW FROM OPERATIONS 1,4

(in millions)

1,581

2,500

2,000

1,500

1,000

500

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1211100908

RETURN ON EQUITY3

(%)

22.5

40

30

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We believe that strong companies such as COS can, and should, affect significant positive changes in the quality of life in our community. COS has a deep commitment to our community, and we believe in sharing the benefits of the oil sands with our neighbours. Since 2005, COS has directed about $19 million towards community investment programs. Whether it’s doing our part to address the root problems of poverty, helping youth to attain their greatest potential, or supporting emergency shelters, we focus on projects and organizations where we believe COS‘ investments can make a meaningful difference.

In 2012, COS launched Math Minds, an initiative aimed at strengthening numeracy among students in kindergarten to grade six. Math Minds is a collaborative effort between COS, academic institutions and social services agencies to drive real and lasting change in elementary numeracy by applying leading-edge educational principles rooted in extensive academic research.

We believe that any student can enjoy and excel at math. Our vision is that the confidence gained through students‘ success in math will empower them to make a positive difference for themselves and for the world.

For more information about COS and Math Minds, please visit www.cdnoilsands.com

Invested in a healthy, educated and compassionate community

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Resourceful2012 ANNUAL REPORT

COSWF 2012 10K

Documents

Transcript of COSWF 2012 10K