EX-99.5 6 o69465exv99w5.htm EX-99.5
Exhibit 99.5

Cameco 2010 Annual Financial Review KEEPING PACE WITH GLOBAL URANIUM DEMAND 2010 Annual Financial Review

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Cameco’s vision is to be a dominant nuclear energy company producing uranium fuel and generating clean electricity. Our goal is to be the supplier, partner, investment and employer of choice. We are making statements and providing information about our expectations for the future which are considered to be forward-looking information or forward-looking statements under Canadian and United States securities laws. These include statements about our aim to double our annual uranium production to 40 million pounds by 2018 and how we expect to achieve that goal, and our expectation that demand for uranium will grow and there will a shortage of uranium supply. We are presenting this information to help you understand management’s current views of our future prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws. This information is based on a number of material assumptions, and is subject to a number of material risks, which are discussed in our annual MD&A contained in this document, including under the heading “Caution about forward-looking information”.

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The nuclear fuel cycle Candu Cycle Light Water Cycle Cameco ’s operations and investments span from exploration to electricity generation . 1 Mining There are three ways to mine uranium, depending on the depth of the orebody and the deposit’s geological characteristics: • Open pit mining is used if the ore is near the surface. The ore is usually mined using drilling and blasting. • Underground mining is used if the ore is too deep to make open pit mining economical. Tunnels and shafts provide access to the ore. • In situ recovery (ISR) does not require large scale excavation. Instead, holes are drilled into the ore and a solution is used to dissolve the uranium. The solution is pumped to the surface where the uranium is recovered. 1 Milling Ore from open pit and underground mines is processed to extract the uranium and package it as a powder typically referred to as uranium concentrate (U3O8) or yellowcake. The leftover processed rock and other solid waste (tailings) is placed in an engineered tailings facility. 2 Refining Refining removes the impurities from the uranium concentrate and changes its chemical form to uranium trioxide (UO3). 3 Conversion For light water reactors, the UO3 is converted to uranium hexafluoride (UF6) gas to prepare it for the next stage of processing. For heavy water reactors like the Candu reactor, the UO3 is converted into powdered uranium dioxide (UO2). 4 Enrichment Uranium is made up of two main isotopes: U-238 and U-235. Only U-235 atoms, which make up 0.7% of natural uranium, are involved in the nuclear reaction (fission). The enrichment process increases the concentration of U-235 to between 3% and 5% by separating U-235 atoms from the U-238. Enriched UF6 gas is then converted to powdered UO2. 5 Fuel manufacturing Natural or enriched UO2 is pressed into pellets, which are baked at a high temperature. These are packed into zircaloy or stainless steel tubes, sealed and then assembled into fuel bundles. 6 Generation Nuclear reactors are used to generate electricity. Fission of U-235 atoms in the reactor fuel creates heat that generates steam to drive turbines. The fuel bundles in the reactor need to be replaced as the U-235 atoms are depleted, typically after one or two years depending upon the reactor type. The used – or spent – fuel is stored or reprocessed. Spent fuel management The majority of spent fuel is safely stored at the reactor site. A small amount of spent fuel is reprocessed. The reprocessed fuel is used in some European and Japanese reactors.

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2010 Awards Fuelling A Culture of Excellence Governance Gavel Awards (Canadian Coalition for Good Governance) Best Disclosure of Board Governance Practices and Director Qualifications PAR (Progressive Aboriginal Relations) Program (Canadian Council for Aboriginal Business) Part of the program since 2001, Cameco retains Gold Level certification for “innovative programs and engagement of Aboriginal people that have made an enduring impact on the business, Aboriginal communities, and demonstrate best practice for those companies beginning their journey”. 24th Annual ARC Awards International (MerComm, Inc.) Online Annual Report, Mining Ferrous & Non-Ferrous category: Bronze Investor Relations Global Rankings Top 5 Investor Relations Website, North America 42nd Annual Emergency Response/Mine Rescue Skills competition, Proficiency Skills category (Saskatchewan Mining Association) 30-minute written exam, bench test and practical demonstration of gas testing techniques: First place, McArthur River; Runner-up, Rabbit Lake Award in Honour of World Day for Safety and Health at Work, April 28 (South Kazakhstan Oblast) High performance in improving safety and health along with compliance with labour law requirements among the enterprises of the atomic industry: JV Inkai 2009 Peak Performance Award (Nebraska Safety Council) In recognition of safety performance: Crow Butte operation Canadian Institute of Mining, Metallurgy and Petroleum Awards John T. Ryan Trophy Best safety record, metal mines: Cameco McArthur River Special Safety Award Certificate Outstanding safety record in 2009: Cameco Cigar Lake Excellence in Environmental Business Award (Port Hope and District Chamber of Commerce) Environmental performance including production of nuclear fuel used to generate clean, carbon-free electricity; company core value to protect the environment; and support for the new Ganaraska Forest Centre: Cameco Port Hope Canada’s Best Diversity Employers (Mediacorp Canada Inc.) Employers across Canada that have exceptional workplace diversity and inclusiveness programs Financial Post’s Top 10 Best Companies to Work For (Mediacorp Canada Inc.) Fast-growing companies in Canada that offer tremendous career advancement opportunities together with leading-edge employee perks and benefits Saskatchewan’s Top 20 Best Employers (Mediacorp Canada Inc.) Saskatchewan employers that lead their industries in offering exceptional places to work Canada’s Top 100 Employers (Mediacorp Canada Inc. Exceptional workplaces by: (1) Physical Workplace; (2) Work Atmosphere & Social; (3) Health, Financial & Family Benefits; (4) Vacation & Time Off; (5) Employee Communications; (6) Performance Management; (7) Training & Skills Development; and (8) Community Involvement

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Message from the Chair
Dear Shareholder,
2010 marked another successful year for Cameco. The tragic events in Japan have caused short-term challenges in the nuclear industry, but the long-term fundamentals for nuclear energy are very positive. The company is in a strong financial position, our growth strategy is taking hold, and a number of new markets are welcoming nuclear power as a source of clean energy.
The board is responsible for overseeing management and Cameco’s affairs, and ensuring that our core values are reflected in everything we do. Nowhere is this more important than working with management to develop Cameco’s strategic direction to ensure long-term success.
Management is charged with a strategy of doubling uranium production by 2018, to achieve its vision to be a dominant nuclear energy company. While it is still early days, management met all of its operating targets this year. The board is very pleased with the progress to date and confident in management’s strategy to achieve its goals.
Opportunity is not without its risks, however. The board and its committees have also been devoting more time and attention to risk oversight. The board works with management to identify the company’s principal risks, and to ensure we have a robust system for managing them across the organization, reporting regularly and mitigating risk as much as possible. It has also been devoting more attention to priority areas like compensation risk and the transition to International Financial Reporting Standards (IFRS), as well as operating and financial risks, among others.
Strong leadership and effective succession planning are also critical to our long-term success. The board has had ongoing discussions about succession planning and approved some key changes this year, as outlined in Jerry Grandey’s letter to shareholders on the next page. Briefly, Tim Gitzel was appointed president, and will succeed Jerry Grandey as chief executive officer on July 1, 2011 as Jerry retires as CEO and member of the board at the end of June 2011. Bob Steane replaced Tim as senior vice-president and chief operating officer, and Ken Seitz became senior vice-president, marketing and business development on George Assie’s retirement.
As CEO since 2003, Jerry led considerable growth in the company and developed a solid management team with great abilities and experience. I wish to thank him and wish him much success. Tim Gitzel joined Cameco in January 2007, as senior vice-president and chief operating officer and was appointed president last May. He brings extensive experience in Canadian and international uranium mining activities to his role as president and CEO through 17 years of senior management experience. He will be also nominated to the board at the 2011 annual meeting.
In December the board approved a planned increase in the annual dividend from $0.28 to $0.40 per share starting in 2011 — our seventh increase in nine years, and a sign of our confidence in the predictability of Cameco’s revenue stream.
Our ability to create shareholder value is rooted in a strong culture founded on core values of safety and environment, people, integrity and excellence in everything we do. The board adopted value statements in 2010 that embody our current practices in these areas. The code of conduct and ethics has been revised to reinforce our standards of ethical conduct and make the code more user friendly, and a new shareholder engagement statement in our governance guidelines highlights the board’s commitment to open and honest dialogue with shareholders.
I would like to thank George Ivany who is retiring from the board at the 2011 annual meeting. During his 12 years on the board, George served on all five committees and made valuable contributions with his broad experience in education and science. After an extensive search, the nominating, corporate governance and risk committee has nominated Daniel Camus to be elected to our board. Mr. Camus brings extensive international experience to the board, including his experience as a senior executive of a major European energy operator with significant transactional experience in China and India.
On behalf of the board, I would like to thank Jerry and his team for a successful 2010.
I look forward to many exciting developments in 2011.
Victor J. Zaleschuk
Chair of the board
March 14, 2011

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Message from the CEO
Dear Shareholder,
Cameco is well positioned to catch the value in the market as we double annual production by 2018.
In 2010, we began to see the growth we’ve been anticipating become reality, as the demand for nuclear power and uranium fuel continued to build around the world.
We acknowledge the tragic events in Japan and the short-term challenges that the nuclear industry will face, but the long-term fundamentals remain the same. In emerging markets, China is the leader by far, with over a third of all reactors under construction in the world today. India, Brazil and the United Arab Emirates are also growing. Turkey has chosen two sites for new plants, and Vietnam and Jordan are interested in building their first facilities. Russia and South Korea, among others, are continuing to expand their nuclear programs. And the United States, our largest customer, is returning to nuclear power after a 30-year absence from new reactor construction. It’s planning to build between four and eight new reactors over the next decade. Overall, we’re expecting about 100 (net) new nuclear reactors to be built by 2020. You can read more about this on page 11.
2010 also saw these nuclear growth programs impact the market. For example, China began to secure longer-term uranium supplies, and we signed two key agreements for a total of 52 million pounds. These agreements are laying the groundwork for long-term uranium supply arrangements, with considerable potential for us to expand our relationships in this important region.
But as demand grows, uranium supply is not being replenished at a sufficient pace. That pushed prices up in 2010, and increased the need for new sources. It’s also presenting an excellent opportunity for uranium suppliers who are poised to benefit.
Already one of the largest suppliers of uranium and fuel services in the world, Cameco has a geologically and geographically diverse reserve and resource base, low-cost mines, a strategy to double our production and the financial flexibility to get us there. These factors, combined with an experienced and dedicated team, means we’re well positioned to take full advantage of the growth in nuclear energy.
2010: another great year
This year, we met all of our major targets, and our revenue was in line with the guidance we provided throughout the year. Our cash from operations remained strong at $507 million and we ended the year with $1.3 billion in cash on hand. We increased production by 2 million pounds — exceeding our goal for this year and our results in 2009 — and reduced our unit costs for the second consecutive year. Cigar Lake is back on track, and production at Inkai and McArthur River/Key Lake are well above last year. Our US operations continue to perform well and at Rabbit Lake we added another two years of reserves, extending the estimated mine life to 2017.
This was also our first full year up and running at Port Hope since 2007, and although there were a few operational issues, we made great progress in revitalizing and eventually returning harbour access to the community.
On track to double production
Our strategy is to double our uranium production to 40 million pounds by 2018 — all from existing assets. Approximately half of this production is from mines that are already operating. The other half is from projects that are under development or in the feasibility stage.
Our planning process is disciplined and well defined. We have a clear development plan for each project, and measurable milestones designed to move us toward our goal. We’re constantly evaluating each project’s feasibility in the context of changing business conditions, which gives us the ability to respond to both positive and negative developments in the industry. You can read about our pipeline of projects on page 16.

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Financial flexibility
Achieving our goal of doubling production will require sustained investment and we expect to meet this requirement without the need for significant additional funding. Our reported earnings and cash flows will be impacted as many costs associated with our growth initiatives will be expensed as we go. This is an inevitable consequence of growth.
Cameco is in a very strong financial position, which gives us considerable financial flexibility. The uranium contract portfolio we’ve built over the past 23 years, and our discipline and expertise in managing our operations efficiently and cost-effectively, gives us a steady revenue stream that we can rely on as we grow.
At the same time, we’re providing healthy dividends to shareholders. We’ve increased our annual dividend seven times in the last nine years, including a planned 43% increase from $0.28 to $0.40 per share in 2011.
Growing responsibly
All of our success is built on a record of increasing operational excellence.
Companies are under growing scrutiny for the way they conduct their businesses, and there has been a significant increase in stakeholder expectations for environmentally and socially responsible business practices. Rather than viewing sustainable development as an ‘add-on’ to traditional business activity, we see it as integral to the way we do business, and have made it a strategic priority, integrating it into our values, objectives and compensation.
Since 2002, we’ve been using four categories to define what we are committed to deliver, and how we measure our results: outstanding financial performance, a safe, healthy and rewarding workplace, a clean environment and supportive communities. Every year we’re making strides in each of these areas — all of which build shareholder value.
Take some time to review our sustainability report on our website for more information about our progress in these areas.
Developing our leadership
It’s important for every company to have a succession strategy, and this year we made some important changes to position our leadership team for the long term:

• |  | Tim Gitzel was appointed president. Tim joined Cameco in 2007 as senior vice-president and chief operating officer, and it’s under his guidance that we’ve become as operationally strong as we are today.
• |  | Bob Steane, a 30-year Cameco veteran, moved into Tim’s role, bringing years of invaluable expertise to this position.
• |  | Ken Seitz, who has been with Cameco since 2004, was promoted to senior vice-president, marketing and business development, replacing George Assie, who retired on December 31. George will continue to share his knowledge and expertise with Cameco by serving on some of our subsidiary boards.

Supporting this team is a strong and dedicated group of employees working together to achieve our goals. In addition to being among the top 100 employers in Canada again this year, we were recognized as one of Canada’s Best Diversity Employers.
Gerald W. Grandey
CEO

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This is particularly significant, given our goal to reach 67% northern (or RSN) employment at our northern Saskatchewan operations, and something that speaks well for us as we move ahead at Kintyre in Australia.
On February 22, 2011, the board and I announced my retirement at the end of June 2011 with Tim Gitzel being our new CEO effective July 1, following our succession plan. Cameco will be in good hands with very strong and capable leadership going forward. I would like to extend my gratitude to our many friends and stakeholders. Without their long-term support, Cameco would not be the success it is today.
The long term is now
The nuclear business is a long-term story: there’s no predicting the ups and downs of the commodity cycle. But nuclear energy is in demand, and that demand is growing. Cameco is uniquely positioned to grow and be successful, and to build value for our shareholders.
We’re very excited about the years ahead.
Gerald W. Grandey
CEO
March 14, 2011

Management’s discussion and analysis |  |  |  |
2010 Highlights |  |  | 4 |
About Cameco |  |  | 7 |
About the nuclear energy industry |  |  | 9 |
Our strategy |  |  | 15 |
Financial results |  |  | 28 |
Our operations and development projects |  |  | 53 |
Mineral reserves and resources |  |  | 84 |
Additional information |  |  | 90 |
2010 Consolidated financial statements |  |  |  |
Report of management’s accountability |  |  | 100 |
Auditor’s report |  |  | 101 |
Consolidated financial statements |  |  | 102 |
Notes to consolidated financial statements |  |  | 107 |
Investor information |  | inside back cover

Throughout this document, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries.

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Management’s discussion and analysis
This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements and notes for the year ended December 31, 2010. The information is based on what we knew as of February 11, 2011.
We encourage you to read our audited consolidated financial statements and notes as you review this MD&A. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.
Unless we have specified otherwise, all dollar amounts are in Canadian dollars. The financial information in this MD&A and in our financial statements and notes are prepared according to Canadian generally accepted accounting principles (Canadian GAAP), unless otherwise indicated. We also prepared a reconciliation of our annual financial statements to US GAAP, which has been filed with securities regulatory authorities. We present our mineral reserve and resource estimates as required by Canadian securities law. See Important information for US investors on page 85.
Caution about forward-looking information
Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans, future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A as forward-looking information.
Key things to understand about the forward-looking information in this MD&A:

• |  | It typically includes words and phrases about the future, such as: believe, estimate, anticipate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples on page 2).
• |  | It represents our current views, and can change significantly.
• |  | It is based on a number of material assumptions, including those we’ve listed below, which may prove to be incorrect.
• |  | Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review our annual information form, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

Forward-looking information is designed to help you understand management’s current views of our near and longer term prospects, and may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.
2010 Annual financial review 1

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Examples of forward-looking information in this MD&A

• |  | our expectations about future worldwide uranium supply and demand
• |  | spot prices in 2011 are expected to be volatile
• |  | our goal for doubling annual production by 2018 to 40 million pounds and our expectation that existing cash balances and operating cash flows will meet anticipated capital requirements without the need for any significant additional financing to reach this goal
• |  | our 2011 objectives
• |  | the outlook for each of our operating segments for 2011, and our consolidated outlook for the year
• |  | our expectation that we will invest significantly in expanding production at our existing mines and advancing projects as we pursue our growth strategy
• |  | our expectation that cash balances will decline gradually as we use the funds in our business and to pursue our growth plans
• |  | our expectation that for the next several years our capital expenditures will be similar to 2011
• |  | our expectation that our operating and investment activities in 2011 will not be constrained by the financial covenants in our general credit facilities
• |  | our uranium price sensitivity analysis
• |  | forecast production at our uranium operations from 2011 to 2015
• |  | our expectation that Inkai will receive all the necessary approvals and permits to meet its 2011 and future annual production targets
• |  | the likely terms and volumes to be covered by long-term delivery contracts that we enter into in 2011 and in future years
• |  | future production at our fuel services operations
• |  | future royalty and tax payments and rates
• |  | our future plans for each of our uranium operating properties, development projects and projects under evaluation, and fuel services operating sites
• |  | our mid-2013 target for initial production from Cigar Lake, the expected benefits of our surface freeze strategy and our 2011 Cigar Lake plans
• |  | our mineral reserve and resource estimates
• |  | the discussion of the expected impact of International Financial Reporting Standards (IFRS) on our financial statements, internal control over financial reporting and disclosure controls and procedures, our business activities in general, and our estimate of IFRS opening statement of financial position and interim period financial results

Material risks

• |  | actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor
• |  | we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates
• |  | production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms
• |  | our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate
• |  | we are unable to enforce our legal rights under our existing agreements, permits or licences, or are subject to litigation or arbitration that has an adverse outcome
• |  | there are defects in, or challenges to, title to our properties
• |  | our mineral reserve and resource estimates are inaccurate, or we face unexpected or challenging geological, hydrological or mining conditions
• |  | we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays
• |  | we cannot obtain or maintain necessary permits or approvals from government authorities
• |  | we are affected by political risks in a developing country where we operate
• |  | we are affected by terrorism, sabotage, blockades, accident or a deterioration in political support for, or demand for, nuclear energy
• |  | there are changes to government regulations or policies, including tax and trade laws and policies
• |  | our uranium and conversion suppliers fail to fulfil delivery commitments
• |  | delay or lack of success in remediating and developing Cigar Lake
• |  | we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes
• |  | our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, tailings dam failures, and other development and operating risks
• |  | new IFRS standards or changes in the standards or their interpretation

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Material assumptions

• |  | sales and purchase volumes and prices for uranium, fuel services and electricity
• |  | expected production costs
• |  | expected spot prices and realized prices for uranium, and other factors discussed on page 43, Price sensitivity analysis: uranium
• |  | tax rates, foreign currency exchange rates and interest rates
• |  | decommissioning and reclamation expenses
• |  | mineral reserve and resource estimates
• |  | the geological, hydrological and other conditions at our mines
• |  | our Cigar Lake remediation and development plans succeed
• |  | our ability to continue to supply our products and services in the expected quantities and at the expected times
• |  | our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals
• |  | our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, tailings dam failure, lack of tailings capacity, or other development or operating risks
• |  | our IFRS related forecasts are not significantly impacted by new IFRS standards or changes in the standards or their interpretation or changes in our policy choices

2010 Annual financial review 3

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2010 Highlights
Cameco is well positioned as the world becomes increasingly focused on nuclear as a source of clean, reliable and affordable energy. We are among the world’s largest uranium producers, in a market where demand is growing, and a pure-play nuclear energy investment.
Our vision is to be a dominant nuclear energy company producing uranium fuel and generating clean electricity.
We have long-term objectives for each of our three business segments:

• |  | uranium — double our annual production to 40 million pounds by 2018 from existing assets
• |  | fuel services — invest in our fuel services business to support our overall growth in the nuclear business
• |  | electricity — maintain steady cash flow while looking at options to extend the operating life of the four Bruce B units

We made excellent progress this year at our operations and on our projects.
Strong financial performance
Net earnings in 2010 were $515 million. Last year, net earnings were higher by $584 million, due mainly to the one time gain on the sale of our interest in Centerra Gold Inc. (Centerra) and higher unrealized gains on financial instruments. Revenue was in line with our guidance, and uranium unit costs were 7% lower than in 2009. We ended the year with $1.3 billion cash on hand. We intend to use these funds to advance our growth strategy.

Highlights |  |  |  |  |  |  |  |  |  |  |  |  |
December 31 |  |  |  |  |  |  |  |  |  |  |  |  |
($ millions except where indicated) |  |  |  |  |  | 2010 |  |  | 2009 |  |  | change |
Revenue |  |  |  |  |  |  | 2,124 |  |  |  | 2,315 |  |  |  | (8 | )%
Gross profit |  |  |  |  |  |  | 744 |  |  |  | 750 |  |  |  | (1 | )%
Net earnings |  |  |  |  |  |  | 515 |  |  |  | 1,099 |  |  |  | (53 | )%
$ per common share (diluted) |  |  |  |  |  |  | 1.30 |  |  |  | 2.82 |  |  |  | (54 | )%
Adjusted net earnings (non-GAAP, see page 29) |  |  |  |  |  |  | 496 |  |  |  | 528 |  |  |  | (6 | )%
$ per common share (adjusted and diluted) |  |  |  |  |  |  | 1.25 |  |  |  | 1.35 |  |  |  | (7 | )%
Cash provided by operations (after working capital changes) |  |  |  |  |  |  | 507 |  |  |  | 690 |  |  |  | (27 | )%
Average realized prices |  | $US/lb |  |  | 43.63 |  |  |  | 38.25 |  |  |  | 14 | %
Uranium |  | $Cdn/lb |  |  | 45.81 |  |  |  | 45.12 |  |  |  | 2 | %
Fuel services |  | $Cdn/kgU |  |  | 16.86 |  |  |  | 17.84 |  |  |  | (5 | )%
Electricity |  | $Cdn/MWh |  |  | 58 |  |  |  | 64 |  |  |  | (9 | )%

Shares and stock options outstanding
At February 10, 2011, we had:

• |  | 394,435,383 common shares and one Class B share outstanding
• |  | 7,432,998 stock options outstanding, with exercise prices ranging from $5.88 to $46.88

Dividend policy
Our board of directors has established a policy of paying a quarterly dividend of $0.10 ($0.40 per year) per common share. This policy will be reviewed from time to time based on our cash flow, earnings, financial position, strategy and other relevant factors.
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Excellent progress this year
In our uranium segment this year, production was 10% higher than 2009 and 6% higher than our plan at the beginning of 2010. We had a number of successes at our mining operations. Key highlights:

• |  | Achieved the best safety performance in our history, exceeding 2009’s award winning performance.
• |  | Received approval for production flexibility at McArthur River, which allowed us to exceed our production target by 6%.
• |  | Extended Rabbit Lake’s expected mine life by two years to 2017.
• |  | Continued to ramp up production at Inkai and exceeded 2009 production by 136%.
• |  | Finished dewatering the underground development at Cigar Lake, substantially completed securing the underground development areas and began implementing a surface freeze strategy we expect will provide a number of benefits. You can read more about this on page 73.

In our fuel services segment, production was 25% higher than 2009 due to the routine operation of the Port Hope UF6 plant. In 2009, the plant was shut down for the first five months of the year.
In our electricity segment, Bruce Power Limited Partnership (BPLP) generated 25.9 terawatt hours (TWh) of electricity, at a capacity factor of 91%. Our share of earnings before taxes was $166 million.
Our investment in GE-Hitachi Global Laser Enrichment LLC (GLE) continues to progress. GLE successfully completed initial testing of its enrichment technology, which met key performance criteria. GLE is continuing its testing, and has begun engineering design work for a commercial facility. In addition, we have continued to work with GLE on potential customer contracts for the facility. The US Nuclear Regulatory Commission is assessing GLE’s application for a commercial facility construction and operating licence.
We continued to advance our exploration activities, spending $11 million at five brownfield exploration projects, and $48 million for resource delineation at Kintyre and Inkai block 3. We spent about $37 million on regional exploration programs. Saskatchewan saw the most expenditures, followed by Australia, northern Canada, Asia, the US and South America.

Highlights |  |  |  | 2010 |  |  | 2009 |  |  | change |
Uranium |  | Production volume (million lbs) |  |  | 22.8 |  |  |  | 20.8 |  |  |  | 10 | %
|  | Sales volume (million lbs) |  |  | 29.6 |  |  |  | 33.9 |  |  |  | (13 | )%
|  | Revenue ($ millions) |  |  | 1,374 |  |  |  | 1,551 |  |  |  | (11 | )%
Fuel services |  | Production volume (million kgU) |  |  | 15.4 |  |  |  | 12.3 |  |  |  | 25 | %
|  | Sales volume (million kgU) |  |  | 17.0 |  |  |  | 14.9 |  |  |  | 14 | %
|  | Revenue ($ millions) |  |  | 301 |  |  |  | 276 |  |  |  | 9 | %
Electricity |  | Output (100%) (TWh) |  |  | 25.9 |  |  |  | 24.6 |  |  |  | 5 | %
|  | Revenue (100%) |  |  | 1,509 |  |  |  | 1,640 |  |  |  | (8 | )%
|  | Our share of earnings before taxes ($ millions) |  |  | 166 |  |  |  | 224 |  |  |  | (26 | )%

2010 Annual financial review 5

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Key market facts
Demand for electricity is expected to nearly double from 2008 to 2035, driven mainly by growth in the developing world as it seeks to diversify sources of energy and provide security of supply.

• |  | The world is increasingly recognizing the benefits of nuclear energy as it searches for alternatives to carbon-based electricity generation, and for energy diversification and security.
• |  | At the start of 2011, there were 441 commercial nuclear power reactors operating in 30 countries, providing about 14% of the world’s electricity.
• |  | At the start of 2011, there were 65 reactors under construction and, by 2020, we estimate 104 new reactors (net) to come on line.
• |  | Most of this new build is being driven by rapidly developing countries like China and India, which have severe energy deficits and want clean sources of electricity to improve their environment and sustain economic growth.
• |  | Over the next decade, demand for uranium to fuel existing and new reactors, and build strategic inventories is expected to grow by an average of 2.5% per year.
• |  | To meet global demand over the next 10 years, we expect 66% of uranium supply will come from mines that are currently in operation, 16% from finite sources of secondary supply (mainly Russian highly enriched uranium (HEU), government inventories and limited recycling), and 18% will have to come from new sources of supply.
• |  | With uranium assets on three continents, including high-grade reserves and low-cost mining operations in Canada, and investments that cover the nuclear fuel cycle – we are ideally positioned to benefit from the world’s growing need for clean, reliable energy.

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About Cameco
Our head office is in Saskatoon, Saskatchewan. We are one of the world’s largest uranium producers, with uranium assets on three continents. Nuclear energy plants around the world use our uranium products to generate one of the cleanest sources of electricity available today.

Uranium
We are one of the world’s largest uranium producers, and in 2010 accounted for about 16% of the world’s production. We have controlling ownership of the world’s largest high-grade reserves, with ore grades up to 100 times the world average, and low-cost operations.
Product

• |  | uranium concentrates (U3O8)

Mineral reserves and resources
Mineral reserves

• |  | approximately 475 million pounds proven and probable

Mineral resources

• |  | approximately 140 million pounds measured and indicated and 355 million pounds inferred

Global exploration

• |  | focused on four continents

Operating properties

• |  | McArthur River and Key Lake, Saskatchewan
• |  | Rabbit Lake, Saskatchewan
• |  | Smith Ranch-Highland, Wyoming
• |  | Crow Butte, Nebraska
• |  | Inkai, Kazakhstan

Development project

• |  | Cigar Lake, Saskatchewan

Projects under evaluation

• |  | Inkai blocks 1 and 2 production increase, Kazakhstan
• |  | Inkai block 3, Kazakhstan
• |  | McArthur River extension, Saskatchewan
• |  | Kintyre, Australia
• |  | Millennium, Saskatchewan

Fuel services
We are an integrated uranium fuel supplier, offering refining, conversion and fuel manufacturing services.
Products

• |  | uranium trioxide (UO3)
• |  | uranium hexafluoride (UF6) (control about 35% of western world capacity)
• |  | uranium dioxide (UO2) (the world’s only commercial producer of natural UO2)
• |  | fuel bundles, reactor components and monitoring equipment used by Candu reactors

Operations

• |  | Blind River refinery, Ontario (refines U3O8 to UO3)
• |  | Port Hope conversion facility, Ontario (converts UO3 to UF6 or UO2)
• |  | Cameco Fuel Manufacturing Inc., Ontario (manufactures fuel bundles and reactor components)
• |  | a toll conversion agreement with Springfields Fuels Ltd. (SFL), Lancashire, United Kingdom (UK) (to convert UO3 to UF6 — expires in 2016)

We also have a 24% interest in GE-Hitachi Global Laser Enrichment LLC (GLE) in North Carolina, with General Electric (51%) and Hitachi Ltd. (25%). GLE is testing a third-generation technology that, if successful, will use lasers to commercially enrich uranium.
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Electricity
We generate clean electricity through our 31.6% interest in the Bruce Power Limited Partnership (BPLP), which operates four nuclear reactors at the Bruce B generating station in southern Ontario.
Capacity

• |  | 3,260 megawatts (MW) (100% basis) (about 15% of Ontario’s electricity)

We also have agreements to manage the procurement of fuel and fuel services for BPLP, including:

• |  | uranium concentrates
• |  | conversion services
• |  | fuel fabrication services

Global presence
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About the nuclear energy industry
According to the World Energy Outlook for 2010 (OECD/International Energy Agency), population growth and industrial development will lead to a near doubling of electricity consumption from 2008 to 2035. Most of this energy will be used by developing (non-OECD) countries as their populations and standards of living increase.
Nuclear power is a clean source of electricity, and generation capacity is growing
As the demand for energy increases, governments, media and consumers are becoming increasingly aware of the dangers and effects of air pollution and climate change, and the importance of low-emission sources of electricity. Increasingly, nuclear energy is recognized as a sustainable alternative to carbon-based electricity that provides energy diversity and security.
Nuclear power can generate electricity with no toxic air pollutants and very low carbon dioxide (CO2) or other greenhouse gas emissions. It has the capacity to produce enough electricity on a global scale to meet our growing needs, and while it isn’t the only solution, it is an affordable and sustainable source of clean, reliable energy. In a carbon-constrained world, nuclear energy will be an even more important part of the future energy mix.
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At the start of 2011, there were 441 commercial nuclear power reactors operating in 30 countries. Countries around the world are increasing their capacity to generate nuclear power by refurbishing or uprating nuclear reactors and building new ones.
China is expected to lead the world in the construction of nuclear power plants as electricity demand continues its rapid growth. India is also moving forward with ambitious growth plans to diversify its sources of energy and obtain a secure source of electricity. As at January 1, 2011:

• |  | China was operating 13 reactors, building between 25 and 30 and planning more. We expect a net increase of 54 reactors by 2020.
• |  | India was operating 19 reactors and had several under construction. We expect a net increase of 13 reactors by 2020.

This year the government of Canada signed a civil nuclear co-operation agreement with India to export nuclear technology, equipment and uranium to support India’s growing nuclear energy industry. Canada is the eighth nation to sign such an agreement with India since the Nuclear Suppliers Group lifted a 34-year ban on nuclear co-operation with India in 2008. Licencing arrangements for these exports still have to be negotiated by the two governments and discussions are ongoing.
Russia and South Korea continue to expand their nuclear generating capacity. Several non-nuclear countries, like United Arab Emirates, Turkey, Vietnam and Italy, are laying the groundwork to proceed with nuclear power development.
In the UK, government commitment to the future of nuclear energy is strong, driven by the need to limit CO2 emissions, and by concerns about energy security as current reactors approach the end of their operating lives.
The US continues to make progress toward new nuclear development with pre-construction activities for new reactors underway in two states and one reactor under construction in another.
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We have long-term supply contracts in 12 of these countries, including China. We are in discussions with India to provide uranium for their growing reactor program.
Demand for uranium is growing
We forecast that world demand will be almost 2.3 billion pounds of U3O8 over the next 10 years. This estimate assumes utilities will build strategic inventories of about 160 million pounds of U3O8 to support their reactor programs.
China’s significant activity in the long-term market this year is a sign of the growing demand for uranium and one of the main drivers behind the recent increase in the uranium price. China has been relatively active in the spot market over the last few years, but in 2010, it advanced its reactor build program and started to secure uranium under long-term contracts. We signed two long-term contracts with Chinese utilities this year, to supply more than 50 million pounds of uranium.
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We expect 66% of global uranium supply over the next 10 years to come from existing primary production sources, production from mines that are currently in commercial operation.
We expect 16% to come from existing secondary supply sources. Most of these sources are finite and will not meet long-term needs. One of the largest current sources of secondary supply is uranium derived from Russian highly enriched uranium (HEU). All deliveries from this source are expected to be made by the end of 2013, when the Russian HEU commercial agreement expires. The US government also makes some of its inventories available to the market, although in much smaller quantities.
We expect the remaining 18% will come from new sources of supply.
In 2010, five producers of uranium concentrates marketed 70% of world production and there were only three commercial providers of UF6 conversion services in the western world. Barriers to entry for new competitors are high, and the lead time for new uranium production can be as long as 10 years or more, depending on the deposit type and location.
Given our extensive base of mineral reserves and resources, diversified sources of supply, global exploration program and vertical integration, we are well positioned to capitalize on the growing interest in nuclear energy.
Despite this growth, challenges remain
Many countries face major obstacles to new nuclear plant construction, including significant upfront capital costs, political opposition and uncertain regulatory environments. In some locations, nuclear energy may not be competitive with other sources of electricity. A country’s first new-generation nuclear plants will face significant business risks, including first-time costs, financing, licensing, schedule and construction costs.
While several countries are making progress on the management of used fuel and other radioactive waste from the nuclear fuel cycle, it is still a controversial issue. Many environmental groups continue to oppose the nuclear power industry. There are nuclear plant phase-out programs in a number of European countries, including Germany. However, Germany recently announced plans to extend the lifespan of its nuclear plants by an average of 12 years. Nuclear power still does not qualify internationally for greenhouse gas emission credits, even though it has been recognized as a non-emitting technology in US energy legislation. The lack of climate change legislation in the US makes nuclear energy less competitive than it is in some other countries.
The long-term outlook is positive
Over the long term, we expect that the benefits of nuclear energy will prevail over the challenges, and market fundamentals for uranium and fuel services will remain positive as:

• |  | we expect demand to continue to exceed worldwide production
• |  | secondary supplies currently filling the shortfall are finite
• |  | primary production needs to increase to meet future demand

Over the next 10 years, we anticipate demand for uranium and conversion services to increase moderately, with potential for more rapid growth toward the end of the period, as the construction and completion of nuclear plants accelerates.
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The industry in 2010
World consumption and production
We estimate global uranium consumption in 2010 was about 180 million pounds and production was 140 million pounds.
We expect global uranium consumption to increase to about 195 million pounds in 2011, and production to be approximately 150 million pounds. Secondary supplies should continue to bridge the gap. By 2020, we expect world uranium consumption to be about 230 million pounds per year, an average annual growth rate of about 2%.
We expect world consumption for UF6 and natural UO2 conversion services to increase by about 7% in 2011.
Industry prices
Utilities are well covered under existing contracts and have been building up inventory levels of U3O8 since 2004, so we expect uranium demand in the near term to be discretionary. Spot prices in 2011 are expected to be volatile.

|  | 2010 |  | 2009 |  | change |
Uranium ($US/lb U3O8) 1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  | 46.83 |  |  | 46.06 |  |  | 2 | %
Average long-term price |  |  | 60.92 |  |  | 65.50 |  |  | (7 | )%
Fuel services |  |  |  |  |  |  |  |  |  |  |  |
($US/kgU UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  |  |  |  |  |  |  |  |  |  |
• North America |  |  | 9.11 |  |  | 7.16 |  |  | 27 | %
• Europe |  |  | 9.83 |  |  | 8.82 |  |  | 11 | %
Average long-term price |  |  |  |  |  |  |  |  |  |  |  |
• North America |  |  | 12.21 |  |  | 11.91 |  |  | 3 | %
• Europe |  |  | 13.27 |  |  | 13.20 |  |  | 1 | %
Note: the industry does not publish UO2 prices. |  |  |  |  |  |  |  |  |  |  |  |
Electricity ($/MWh) |  |  |  |  |  |  |  |  |  |  |  |
Average Ontario electricity spot price |  |  | 36 |  |  | 30 |  |  | 20 | %

1 |  | Average of prices reported by TradeTech and Ux Consulting (Ux)

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Contract volumes
The Ux estimate for 2010 spot market sales is about 50 million pounds, 7% below the record high of 54 million pounds in 2009. Utilities were responsible for 39% of the purchases. With spot price volatility throughout the year, utilities and others took advantage of periods of lower spot prices to make opportunistic purchases.
We expected long-term contracting volumes in 2010 to be similar to 2009, but they ended significantly higher. Industry estimates are that China agreed to purchase about 170 million pounds under long-term contracts, accounting for about 70% of all long-term purchase volumes. We estimate long-term contracting volumes in 2011 will be between 150 and 200 million pounds, depending on supply, market expectations, and market prices.
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Our strategy
Our vision is to be a dominant nuclear energy company producing uranium fuel and generating clean electricity. Our goal is to be the supplier, partner, investment and employer of choice in the nuclear industry.
We are a pure-play nuclear investment with a proven track record and the strengths to take advantage of the world’s rising demand for clean, safe and reliable energy. Our core strengths make us unique:

• |  | a large portfolio of low-cost mining operations and geographically diverse uranium assets
• |  | controlling interests in the world’s largest high-grade uranium reserves
• |  | extensive mineral reserves and resources to support our growth strategy
• |  | excellent growth potential from existing assets, combined with an advanced global exploration program
• |  | multiple sources of conversion and the ability to increase production
• |  | a strong customer base and a worldwide marketing presence
• |  | an extensive portfolio of long-term sales contracts supported by long-life assets
• |  | innovative technology and experience operating in technically challenging environments
• |  | an enterprise-wide risk management system tied directly to our strategy and objectives
• |  | conservative financial management and the financial strength to support our growth
• |  | among the first to build relationships in emerging markets

The focus of our growth strategy continues to be on our uranium segment. With the significant increase in nuclear reactor construction around the world, utilities and countries are building up their strategic inventories. In 2010, this resulted in increased long-term contracting and drove uranium spot prices significantly higher.
Our extraordinary assets, contract portfolio, employee expertise and comprehensive industry knowledge give us the ability to capitalize on any increase in uranium demand and prices, increasing shareholder value.
At the same time, we are managing our fuel services segment to better service our customers and expand our market share.
We plan to use the cash we have available to sustain and increase our production from existing assets. We will consider other uranium production opportunities as they arise.
We have long-term objectives for each of our three business segments:

• |  | uranium — double our annual production to 40 million pounds by 2018 from existing assets
• |  | fuel services — invest in our fuel services business to support our overall growth in the nuclear business
• |  | electricity — maintain steady cash flow while gaining exposure to new opportunities

These are supported by annual objectives, which you’ll find starting on page 25.
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Uranium: doubling production by 2018
We have a strategy and process in place to double our annual production to 40 million pounds by 2018, which we expect to come from three sources:

• |  | operating properties
• |  | development projects
• |  | projects under evaluation

This chart below shows how we expect each of these sources to progress towards achieving our 2018 production goal.
About half of the total expected 2018 annual production is from mines that are already operating. The other half is from projects that are in development or under evaluation. To reach our goal, we expect existing cash balances and operating cash flows will meet anticipated capital requirements without the need for significant additional funding.
We expect to spend, on average, between $20 million and $25 million per year for the next three years to assess the feasibility of projects under evaluation. These amounts will be expensed as incurred.
This is not a complete list of all the projects we are currently evaluating. Many projects are early stage. As we evaluate them, the mix of projects to reach our 2018 goal may change. Our evaluation process is designed to provide flexibility in development decisions. You can read about our stage gate process on page 17.
Operating properties
Our sources of production are McArthur River/Key Lake, Rabbit Lake, Smith Ranch-Highland, Crow Butte and Inkai.
We plan to maintain the base of our current production at these operations, and to expand production where we can by developing new mining zones. We are upgrading the mills at Key Lake and Rabbit Lake to support our growing production.
Inkai blocks 1 and 2, in Kazakhstan, have the potential to significantly increase production. Based on current mineral reserves, we expect Rabbit Lake to produce until 2017, although work is ongoing to extend its mine life even further.
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Development project
Cigar Lake is our project in development. It is a superior, world-class deposit that we expect to generate 9 million pounds of uranium per year for Cameco (18 million pounds per year in total) after we finish remediation and construction, and ramp up to full production. We are targeting initial production in mid-2013.
Projects under evaluation
We are evaluating several potential sources of production, including expanding McArthur River, increasing production at Inkai blocks 1 and 2, and advancing Inkai block 3, Kintyre and Millennium.

• |  | The McArthur River extension is expected to expand our existing mining area, which is part of the most prolific high-grade uranium system in the world.
• |  | Under a memorandum of understanding with our Inkai partner, National Atomic Company KazAtomProm Joint Stock Company (Kazatomprom), we are in discussions to increase annual production from blocks 1 and 2, which would result in our share increasing to 5.7 million pounds.
• |  | Inkai block 3, in Kazakhstan, has the potential to become a significant source of production.
• |  | Our acquisition in 2008 of a 70% interest in Kintyre, in Australia, adds potential for low-cost production and diversifies our production by geography and deposit type.
• |  | Millennium is a uranium deposit in northern Saskatchewan that we expect will take advantage of the mill at Key Lake.

Our strategy is to advance these projects through a stage gate process that includes several defined decision points in the assessment and development stages. At each point, we re-evaluate the project based on current competitive, economic, social, legal, political and environmental considerations. If it continues to meet our criteria, we proceed to the next stage. This process allows us to build a pipeline of projects ready for a production decision.
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Growth beyond 2018
Our active global exploration program, combined with our disciplined acquisition strategy, will add to our pipeline of future production sources. Our program is directed at replacing mineral reserves and resources as they are depleted by our production, and ensuring our growth beyond 2018.
Exploration
We have maintained an active exploration program throughout the uranium price cycle, which has helped us secure land with exploration and development prospects that are among the best in the world. In addition, our exploration efforts have increased uranium mineral reserves and resources at our operations. We have direct interests in almost 70 active exploration projects in six countries, over 100 experienced professionals searching for the next generation of deposits, and ownership interests in approximately 4.3 million hectares (10.6 million acres) of land mainly in Canada, Australia, Kazakhstan, the US, Mongolia and Peru. Many of these projects are advanced through joint ventures with both junior and major uranium companies.
For properties that meet our investment criteria, we will partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our leadership position and industry expertise in both exploration and corporate social responsibility make us a partner of choice.
Acquisition
We have a dedicated team looking for opportunities to acquire companies that are already producing or are nearing that stage. We will invest when an opportunity is available at the right time and the right price. Our acquisition strategy complements our exploration strategy, and together they are building a development pipeline of prospective uranium projects.
This discussion of our strategy, our process to double our annual uranium production by 2018, and our growth beyond that date is forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on the assumptions and risks listed here.
Assumptions
Our statements about doubling annual production by 2018 to 40 million pounds reflect our current production target for 2018. Although we are confident in our efforts to reach that target, we cannot guarantee that we will. We have made assumptions about 2018 production levels at each of our existing operating mines, except those that we do not expect will still be operating then. We have also made assumptions about the development of mines that are not operating yet and their 2018 production levels. We believe these assumptions are reasonable, individually and together, but if an assumption about one or more mines proves to be incorrect, we will not reach our 2018 target production level unless the shortfall can be made up by additional production at another mine.
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Material risks that could prevent us from reaching our target

• |  | we cannot locate additional reserves and identify appropriate methods of mining to maintain and increase production levels at McArthur River
• |  | our partner or the Kazakh government does not support an increase in production to the expected level at Inkai, blocks 1 and 2, or we don’t reach the full production level as quickly as we expect
• |  | we cannot bring block 3 into production at Inkai if the feasibility study is not favourable or we cannot secure partner or government approval
• |  | remediation and development at Cigar Lake is not completed on schedule, or we do not reach the full production level as quickly as we expect
• |  | development of Kintyre is delayed due to political, regulatory or indigenous people issues
• |  | we cannot obtain a favourable feasibility study for Kintyre or the Millennium project, or we cannot reach agreement with our project partners to move ahead with production at Kintyre or Millennium
• |  | the Key Lake mill does not have enough capacity to handle anticipated production increases, and we aren’t able to expand its capacity or to identify alternative milling arrangements
• |  | the projects under evaluation do not proceed or, if they do, are not completed on schedule or don’t reach full production levels as quickly as we expect
• |  | uranium prices and development and operating costs make it uneconomical to develop projects under consideration
• |  | we cannot obtain or maintain necessary permits or approvals from government authorities
• |  | disruption in production or development due to natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, lack of tailings capacity, or other development and operation risks

Fuel services: capturing synergies
Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and expand our uranium market share.
We are one of three commercial suppliers of UF6 in the western world. Our focus is on cost-competitiveness and operational efficiency as we gradually increase production at our world-class conversion facility to support the growing demand. We’re also expanding into innovative areas like laser enrichment technology to broaden our fuel cycle participation and help us serve our customers more effectively.
Electricity: capturing added value
Our investment in BPLP is an excellent source of cash flow and a logical fit with our other businesses. Our focus is on maintaining steady cash flow, building synergies with our other segments and looking at the option to extend the operating life of the four Bruce B units.
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Building on our strengths
World-class assets
We have a large portfolio of low-cost mining operations and geographically diverse uranium assets, and controlling interests in the world’s largest high-grade uranium reserves.
Strong customer relationships
We have large, reliable customers that need uranium regardless of world economic conditions, and we expect the uranium contract portfolio we’ve built to provide a solid revenue stream for years to come.
Uranium price leverage
Our plans to increase our production of uranium, combined with our contracting strategy, are designed to give us increasing leverage when uranium prices go up, and to protect us when prices decline.
Financial strength
We are in a strong financial position to proceed with our growth plans, and the stability of our revenue stream allowed us to announce plans to increase annual dividends again this year, to $0.40 per share starting in 2011.
Disciplined portfolio management
We have a disciplined portfolio management process that incorporates all capital projects into a single capital plan and uses a stage gate decision process (see page 17). This ensures our capital projects are aligned with our strategic objectives, and that business benefits are measurable and attainable.
Focused risk management
We have a formal enterprise-wide risk management process that we apply consistently and systematically across our organization. Risk management is a core element of our strategy and our objectives, and we use it to continuously improve our organization. It will underpin decisions we make as we move ahead with our growth strategy.
Innovation
We are always looking for ways to improve processes, to increase safety and environmental performance, and reduce costs. We are currently working on projects in all aspects of operations, including upgrading the Key Lake and Rabbit Lake mills.
Reputation
We believe strongly in our values and apply them consistently in our operations and business dealings. We are recognized as a reliable supplier and business partner, strong community supporter, international problem solver and employer of choice.
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Managing our growth
Our ability to grow is a function of our people, processes, assets and reputation, and the ability to enhance and leverage these strengths to add value and build competitive advantage.
We use four categories to define what we are committed to deliver, and how we will measure our results:

• |  | outstanding financial performance

• |  | a safe, healthy and rewarding workplace

• |  | a clean environment

• |  | supportive communities

We introduced these measures of success in 2002, to proactively address the financial, social and environmental aspects of our business. We believe that each is integral to the company’s overall success and that, together, they will ensure our long-term sustainability.
Focus on long-term sustainability
Companies are under growing scrutiny for the way they conduct their businesses, and there has been a significant increase in stakeholder expectations for environmentally and socially responsible business practices.
Rather than viewing sustainable development as an ‘add-on’ to traditional business activity, we see it as integral to the way we do business, and have made it a strategic priority, integrating it into our objectives and compensation policies.
You can find out more in our sustainable development report and annual information form, which are on our website (cameco.com).
Outstanding financial performance
Our financial results depend heavily on the prices we realize in our uranium and fuel services segments, on the cost of supply, and on sales and production volumes.
Managing contracts
We sell uranium and fuel services directly to nuclear utilities around the world, as uranium concentrates, UO2, UF6, conversion services or fuel fabrication.
Uranium is not traded in meaningful quantities on a commodity exchange. Utilities buy the majority of their uranium and fuel services products under long-term contracts with suppliers, and meet the rest of their needs on the spot market.
Our extensive portfolio of long-term sales contracts — and the long-term, trusting relationships we have with our customers — are core strengths for us.
Because we sell large volumes of uranium every year, our net earnings and operating cash flows are affected by changes in the uranium price. Our contracting strategy is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that maximizes our realized price. Market prices are influenced by the fundamentals of supply and demand, geopolitical events, disruptions in planned supply and other market factors. Contract terms usually reflect market conditions at the time the contract is accepted, with deliveries beginning several years in the future.
Our current uranium contracting strategy is to sign contracts with terms of 10 years or more that include mechanisms to protect us when market prices decline, and allow us to benefit when market prices go up. Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Fixed-price contracts are typically based on the industry long-term price indicator at the time the contract is accepted, adjusted for inflation to the time of delivery. Market-related contracts may be based on either the spot price or the long-term price as quoted at the time of delivery, and often include floor prices adjusted for inflation and some include ceiling prices also adjusted for inflation.
This is a balanced approach that reduces the volatility of our future earnings and cash flow, and that we believe delivers the best value to shareholders over the long term. It is also consistent with the contracting strategy of our
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customers. This strategy has allowed us to add increasingly favourable contracts to our portfolio that will enable us to benefit from any increases in market prices in the future.
The majority of our contracts include a supply interruption clause that gives us the right to reduce, on a pro rata basis, defer or cancel deliveries if there is a shortfall in planned production or in deliveries under the Russian HEU commercial agreement.
We are heavily committed under long-term uranium contracts until 2016, so we are becoming increasingly selective when considering new commitments.
The majority of our fuel services contracts are at a fixed price per kgU, adjusted for inflation, and reflect the market at the time the contract is accepted.
Managing our supply
We sell more uranium than we produce every year. We meet our delivery commitments using uranium we obtain:

• |  | from our own production

• |  | by purchasing uranium under both spot and long-term purchase agreements — mostly under the Russian HEU commercial agreement

• |  | from our existing inventory — we target inventories of about six months of forward sales of uranium concentrates and UF6

We participate in the uranium spot market from time to time, including making spot purchases to take advantage of opportunities to place the material into higher priced contracts. We determine the appropriate extent of our spot market activity based on the current spot price and various factors relating to our business. In addition to being a source of profit, this activity provides insight into the underlying market fundamentals and supports our sales activities.
Managing our costs
Like all mining companies, our uranium segment is affected by the rising price of inputs like labour and fuel. In 2010, labour, production supplies and contracted services made up 85% of the production costs at our uranium mines. Labour (35%) was the largest component. Production supplies (25%) included fuels, reagents and other items. Contracted services (25%) included mining and maintenance contractors, air charters, security and ground freight.
Operating costs in our fuel services segment are mainly fixed. In 2010, labour accounted for about 50% of the total. The largest variable operating cost is for energy (natural gas and electricity), followed by zirconium and anhydrous hydrogen fluoride.
Our costs are also affected by the mix of products we produce and those we buy. We have long-term contracts to buy uranium and conversion services at fixed prices that are lower than the current published spot and long-term prices. As noted above, we also buy on the spot market, which, while profitable, can be at prices that are much higher than our other sources of supply.
To help us operate efficiently and cost-effectively as we grow, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology and business process improvements.
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A safe, healthy and rewarding workplace
We strive to foster a safe, healthy and rewarding workplace at all of our facilities, and measure progress against key indicators, such as conventional and radiation safety statistics, employee sentiment toward the company and employment creation.
To achieve our growth objectives, we need to build an engaged, qualified and diverse organization capable of leading and implementing our strategies. Our challenge is to retain our current workforce and compete for the limited number of people available, both to replace retiring employees and to support our growth. Our long-term people strategy includes identifying critical segments and planning our workforce to meet this challenge.
Our approach seems to be working: we were included in the Financial Post’s Top 10 Best Companies to Work For in Canada for 2010 for our employee policies, programs and role in the community, and Mediacorp named us one of Canada’s Top 100 Employers for both 2010 and 2011. You can find out more about our awards on our website.
A clean environment
We are committed to operating our business with respect and care for the local and global environment. We strive to be a leader in environmental practices and performance by complying with and moving beyond legal and other requirements.
We are committed to integrating environmental leadership into everything we do. In 2005, we launched a formal environmental leadership initiative, and set objectives and performance indicators to measure our progress in protecting the air, water and land near our operations, and in reducing the amount of waste we generate and energy we use.
Reducing our impact
We have been working to reduce the impact we have on the environment. This includes monitoring and reducing our effect on air, water and land, reducing the greenhouse gases we produce and the amount of energy we consume, and managing the effects of waste.
We are investing in management systems and safety initiatives to achieve operational excellence, and this is improving our safety and environmental performance and operating efficiency.
We have developed new water treatment technologies that have improved the quality of the water released from our Saskatchewan uranium milling operations, and are working on other projects to reduce waste, improve the reclamation process and manage waste rock more effectively.
We have also completed an energy assessment at each of our North American operations, and developed management plans for reducing our energy intensity and greenhouse gas emissions.
We are maximizing the lifespan of our operating sites to limit the environmental impact of operations, and revitalizing the Key Lake mill (in operation for 28 years) and Rabbit Lake mill (in operation for 36 years).
Like other large industrial organizations, we use chemicals in our operations that could be hazardous to our health and the environment if they are not handled correctly. We train our employees in the proper use of hazardous substances and in emergency response techniques.
We meet with communities who are affected by our activities to tell them what we’re doing and to receive feedback and further input. For example, in Saskatchewan, we participate in the Athabasca Working Group and Northern Saskatchewan Environmental Quality Committee. In Ontario, we liaise with our communities by regularly holding educational and environment-focused activities.
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Supportive communities
To maintain public support for our operations (our social licence to operate) and our global reputation, we need the respect and support of communities, indigenous people, governments and regulators affected by our operations.
We build and sustain the trust of local communities by being a leader in corporate social responsibility (CSR). Through our CSR initiatives, we educate, engage, employ and invest in the people in the regions where we operate.
For example, in northern Saskatchewan in 2010:

• |  | 50% of the employees at our mines were local residents

• |  | 78% of services to our northern minesites — approximately $295 million — went to northern businesses

• |  | we engaged in project discussions with communities impacted by our operations and exploration activities, making 120 community visits to give them information and garner grassroots support early in the process

• |  | we donated over $2.5 million to northern and aboriginal initiatives for youth, health and wellness, education and literacy, and culture and recreation

• |  | provided $100,000 in scholarships to post-secondary students

Our operations are closely regulated to give the public comfort that we are operating in a safe and environmentally responsible way. Regulators approve the construction, startup, continued operation and any significant changes to our operations. Our operations are also subject to laws and regulations related to safety and the environment, including the management of hazardous wastes and materials.
Our objectives are consistent with those of our regulators — to keep people safe and to protect the environment. We pursue these goals through open and co-operative relationships with all of our regulators. We work to earn their trust and that of other stakeholders by continually striving to protect people and the environment.
24 cameco corporation

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Measuring our results
We set corporate, business unit and departmental objectives every year under our four measures of success, and these become the foundation for a portion of annual employee compensation.

|  |  |  | 2011 objectives
|  |  |  | This is forward-looking information.
2010 objectives |  | Results |  | See page 1 for more information.
Outstanding financial performance |  |  |  |
Production |  | Exceeded |  | Production
• Produce 21.5 million pounds of U3O8 and between 14 million and 16 million kgU from fuel services. |  | • Our share of U3O8 production was 22.8 million pounds, or 106% of plan. • We produced 15.4 million kgU at fuel services. |  | • Produce 21.9 million pounds of U3O8 and between 15 million and 16 million kgU from fuel services.
Financial measures |  |  |  |
Corporate performance |  | Exceeded |  | Corporate performance
• Achieve budgeted net earnings and cash flow from operations (before working capital changes). Costs • Strive for unit costs below budget. |  | • Net earnings were higher than budget. • Cash flow from operations before working capital changes was higher than budget. • Unit costs for uranium production and fuel services were below budget. |  | • Achieve budgeted net earnings and cash flow from operations (before working capital changes). Costs • Strive for unit costs below budget.
Growth |  |  |  |
Cigar Lake |  | Exceeded |  | Cigar Lake
• Access and secure underground workings and continue with remediation work on schedule. Reinitiate shaft 2 development. • Update the technical report. |  | • Successfully dewatered and re-entered the mine using innovative technology. • Resumed shaft 2 development. • Issued technical report. |  | • Advance the project towards mid-2013 startup by completing remediation of all underground workings and advancing shaft 2 sinking.
Inkai |  | Partially achieved |  | Inkai
• Advance Inkai block 3 delineation and begin a feasibility study. Initiate a feasibility study to increase production at Inkai blocks 1 and 2, and secure necessary regulatory approvals. |  | • Block 3 delineation was advanced and supported initiation of a 5-year resource appraisal work plan and test leach facility required by the Kazakh authorities. Approval in principle to operate blocks 1 and 2 at 3.9 million pounds per annum (100% basis) was received, but not for design capacity of 5.2 million pounds per annum. |  | • Advance block 3 mineral resource delineation and the engineering design of a test leach facility. Advance construction of site infrastructure. • Receive approval to increase annual production from blocks 1 and 2 to design capacity of 5.2 million pounds per annum (100% basis). Pursue our longer term objective of receiving approval to double annual production from blocks 1 and 2 by advancing the conversion joint venture project with Kazatomprom.

2010 Annual financial review 25

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2010 objectives |  | Results |  | 2011 objectives
Outstanding financial performance |  |  |  |
Growth (continued) |  |  |  |
Kintyre |  | Achieved |  | Kintyre
• Advance project evaluation to allow a production decision as soon as possible. |  | • Completed delineation drilling and core logging. • Made progress on environmental baseline studies, supporting submission of an environmental scoping document to the Australian regulator. |  | • Continue to advance project evaluation to allow a production decision as soon as possible.
Exploration and innovation |  | Exceeded |  | Exploration and innovation
• Replace mineral reserves and resources at the rate of annual U3O8 production based on a three-year rolling average. • Continue to advance extension of McArthur River and the Millennium project to provide future sources of production. • Support production growth and improved operating efficiencies through targeted research, development and technological innovation. |  | • Additions to reserves and resources exceeded production by an average of 8 million pounds per year in each of the last three years (2008 to 2010). • The McArthur River extension project and the Millennium project were advanced through the stage gate process. • Cameco’s Research Centre advanced a number of projects aimed at improving our environmental performance and process efficiencies at our operations. |  | • Replace mineral reserves and resources at the rate of annual U3O8 production based on a three-year rolling average. • Support production growth and improved operating efficiencies through targeted research, development and technological innovation. McArthur River extension • Advance the underground exploration drifts to the north of current mining areas and initiate a feasibility study. Millennium • Continue to advance the Millennium project toward a project decision.
Management |  | Achieved |  | Management
• Continue integrating portfolio management into our management, planning and budgeting processes. • Deliver planned capital projects within 10% of budget. |  | • Portfolio management is now fully integrated into the planning and budgeting process. • Capital projects were delivered within 10% of budget. |  | • Sustain and grow production in accordance with our strategy to double uranium production by 2018 by advancing pipeline uranium projects through the stage gate process. • Deliver planned capital projects within 10% of budget.
Safe, healthy and rewarding workplace |  |  |  |
• Strive for no lost-time injuries at all Cameco-operated sites and, at a minimum, maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses. • Develop a formal implementation plan for the risk standard and begin implementation. |  | Exceeded • Overall, exceptionally strong safety performance in 2010. • Lost-time incident frequency for employees and contractors was 0.24 per 200,000 hours worked compared to a target of 0.5 — the best performance in Cameco’s history. Medical aid frequency and severity were also significantly better than target. Achieved • All operations met or exceeded their 2010 implementation milestones. |  | • Strive for no lost-time injuries at all Cameco-operated sites and, at a minimum, maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses. • Complete implementation of the risk standard and integrate it into our quality management system. Adopt a risk policy and implement improvements to the risk governance structure at the management and board level.

26 cameco corporation

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2010 objectives |  | Results |  | 2011 objectives
Clean environment |  |  |  |
• Strive for zero reportable environmental incidents, reduce the frequency of incidents and have no significant incidents at Cameco-operated sites. |  | Achieved • There were 22 reportable environmental incidents, an improvement over 2009 (28 incidents), and below our long-term average of 30. There were no significant environmental incidents. |  | • Strive for zero reportable environmental incidents, reduce the frequency of incidents and have no significant incidents at Cameco-operated sites. • Improve year-over-year performance in corporate environmental leadership indicators.
• Improve year-over-year performance in corporate environmental leadership indicators. |  | Achieved • Five out of eight key performance indicators showed an improvement relative to 2009. |  |
Supportive communities |  |  |  |
• Build awareness and support for Cameco through community investment, business development programs and public relations. |  | Achieved • We received positive feedback from our annual polls in Port Hope and Saskatchewan. • We were named one of Canada’s Top 100 employers, and one of the top 10 companies to work for in Canada. |  | • Develop long-term relationships by engaging with stakeholders important to our sustainability. • Ensure support from our employees, impacted communities, investors, governments and the general public through communications, community investment and business development.
• Advance our projects by securing support from indigenous communities affected by our operations. |  | Achieved • Established and maintained positive relationships with groups impacted by our various operating activities. |  |

2010 Annual financial review 27

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Financial results
This section of our MD&A discusses our performance, financial condition and outlook for the future.

2010 consolidated financial results |  |  | 29 |
Outlook for 2011 |  |  | 35 |
Liquidity and capital resources |  |  | 36 |
2010 financial results by segment |  |  | 42 |
Uranium |  |  | 42 |
Fuel services |  |  | 45 |
Electricity |  |  | 46 |
Fourth quarter results |  |  | 48 |
Fourth quarter consolidated results |  |  | 48 |
Quarterly trends |  |  | 49 |
Fourth quarter results by segment |  |  | 50 |

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2010 consolidated financial results
In 2009, we sold all of our shares of Centerra.
We have recast our consolidated financial results for 2008 and 2009 for comparison to show the impact of Centerra as a discontinued operation, as required under Canadian GAAP. The change affected a number of financial measures, including revenue, gross profit, administration costs and income tax expense. See note 24 to the financial statements for more information.

Highlights |  |  |  |  |  |  |  |  |  |  |  |  |  | change from |
December 31 ($ millions except per share amounts) |  | 2010 |  |  | 2009 |  |  | 2008 |  |  | 2009 to 2010 |
Revenue |  |  | 2,124 |  |  |  | 2,315 |  |  |  | 2,183 |  |  |  | (8 | )%
Gross profit |  |  | 744 |  |  |  | 750 |  |  |  | 829 |  |  |  | (1 | )%
Net earnings |  |  | 515 |  |  |  | 1,099 |  |  |  | 450 |  |  |  | (53 | )%
$ per common share (basic) |  |  | 1.31 |  |  |  | 2.83 |  |  |  | 1.29 |  |  |  | (54 | )%
$ per common share (diluted) |  |  | 1.30 |  |  |  | 2.82 |  |  |  | 1.28 |  |  |  | (54 | )%
Adjusted net earnings (non-GAAP, see below) |  |  | 496 |  |  |  | 528 |  |  |  | 525 |  |  |  | (6 | )%
$ per common share (adjusted and diluted) |  |  | 1.25 |  |  |  | 1.35 |  |  |  | 1.49 |  |  |  | (7 | )%
Cash provided by operations (after working capital changes) |  |  | 507 |  |  |  | 690 |  |  |  | 530 |  |  |  | (27 | )%

Net earnings
Our net earnings were $584 million lower than last year primarily as a result of:

• |  | selling our interest in Centerra and recording an after tax gain of $374 million in 2009
• |  | recording an after tax profit of $19 million relating to unrealized mark-to-market gains on financial instruments, compared to a gain of $189 million in 2009
• |  | lower earnings in our electricity business due to a decline in realized prices
• |  | higher exploration expenses, which rose by $47 million mainly due to evaluation activities at Kintyre and Inkai block 3

Three-year trend
Our net earnings normally trend with revenue, but in recent years have been significantly influenced by unusual items.
In 2008, we stopped applying hedge accounting to our portfolio of foreign exchange contracts and, due to the decline in the Canadian dollar relative to the US dollar, recorded $148 million in unrealized mark-to-market losses. We also recorded $30 million in charges to reduce the carrying value of certain investments.
In 2009, we sold our interest in Centerra and recorded a net gain of $374 million. We also recorded $244 million in unrealized mark-to-market pretax gains on our foreign exchange contracts.
Adjusted net earnings (non-GAAP measure)
We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our GAAP-based net earnings, adjusted for earnings from discontinued operations and unrealized mark-to-market gains and losses on our financial instruments, which we believe do not reflect underlying performance.
2010 Annual financial review 29

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Adjusted net earnings is non-standard supplemental information, and not a substitute for financial information prepared in accordance with GAAP. Other companies may calculate this measure differently. The table below reconciles adjusted net earnings with our net earnings.

($ millions) |  | 2010 |  |  | 2009 |  |  | 2008 |
Net earnings (GAAP measure) |  |  | 515 |  |  |  | 1,099 |  |  |  | 450 |
Adjustments (after tax) |  |  |  |  |  |  |  |  |  |  |  |
Earnings from discontinued operations |  |  | — |  |  |  | (382 | )1 |  |  | (84 | )1
Unrealized gains on financial instruments |  |  | (19 | ) |  |  | (189 | ) |  |  | 166 |
Stock option expense (recovery) |  |  | — |  |  |  | — |  |  |  | (33 | )
Investment writedowns |  |  | — |  |  |  | — |  |  |  | 26 |
Adjusted net earnings (non-GAAP measure) |  |  | 496 |  |  |  | 528 |  |  |  | 525 |

1 |  | We have changed our method for determining adjusted earnings to exclude all amounts related to our investment in Centerra. Previously, we had included our share of operating income from Centerra in our adjusted earnings measure.

The table below shows what contributed to the change in adjusted net earnings for 2010.

($ millions) |  |  |  |  |
Adjusted net earnings — 2009 |  |  | 528 |
Change in gross profit by segment (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation, depletion and reclamation (DDR)) |  |  |  |
Uranium |  | Lower sales volume |  |  | (62 | )
|  |  |  | Higher realized prices ($US) |  |  | 188 |
|  |  |  | Foreign exchange impact on realized prices |  |  | (168 | )
|  |  |  | Lower costs |  |  | 57 |
|  |  |  | change — uranium |  |  | 15 |
Fuel services | Higher sales volume |  |  | 7 |
|  |  |  | Lower realized prices ($Cdn) |  |  | (17 | )
|  |  |  | Lower costs |  |  | 20 |
|  |  |  | change — fuel services |  |  | 10 |
Electricity | Higher sales volume |  |  | 13 |
|  |  |  | Lower realized prices ($Cdn) |  |  | (70 | )
|  |  |  | Lower costs |  |  | 16 |
|  |  |  | change — electricity |  |  | (41 | )
Other changes |  |  |  |
Exploration expense |  |  | (47 | )
Administration expense |  |  | (20 | )
Realized gains on derivatives & foreign exchange |  |  | 33 |
Reduced losses from associated companies |  |  | 26 |
Interest expense |  |  | 13 |
Income taxes |  |  | (35 | )
Miscellaneous |  |  | 14 |
Adjusted net earnings — 2010 |  |  | 496 |

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Three-year trend
Our adjusted net earnings have been relatively stable over the past three years.
The 1% increase from 2008 to 2009 resulted from:

• |  | higher profits from our electricity business, relating to a higher realized selling price
• |  | partially offset by lower profits in our uranium business, which were impacted by higher unit costs

The 6% decrease from 2009 to 2010 resulted from:

• |  | lower profits from our electricity business, relating to a lower realized selling price
• |  | higher exploration expenses
• |  | higher income taxes
• |  | partially offset by improved profits in the uranium business, relating to the lower cost of sales

Revenue
The table below shows what contributed to the change in revenue this year.

($ millions) |  |  |  |
Revenue — 2009 |  |  | 2,315 |
Uranium |  |  |  |
Lower sales volume |  |  | (191 | )
Higher realized prices ($Cdn) |  |  | 20 |
Fuel services |  |  |  |
Higher sales volume |  |  | 38 |
Lower realized prices ($Cdn) |  |  | (17 | )
Electricity |  |  |  |
Higher sales volume |  |  | 29 |
Lower realized prices ($Cdn) |  |  | (70 | )
Revenue — 2010 |  |  | 2,124 |

See Financial results by segment for more detailed discussion.
Three-year trend
In 2009, revenue rose by $0.1 billion to a record $2.3 billion, due to higher realized prices in all business segments. The most significant increase was in the electricity business, where the price rose to $64/MWh from $57/MWh in 2008.
In 2010, revenue declined by 8% to $2.1 billion due largely to reduced sales volumes in the uranium business and a lower realized price in electricity. The decline in sales volumes was matched with an increase in inventories.
Average realized prices

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | change from |
|  |  |  |  |  | 2010 |  |  | 2009 |  |  | 2008 |  |  | 2009 to 2010 |
Uranium1 |  | $US/lb |  |  | 43.63 |  |  |  | 38.25 |  |  |  | 39.52 |  |  |  | 14 | %
|  | $Cdn/lb |  |  | 45.81 |  |  |  | 45.12 |  |  |  | 43.91 |  |  |  | 2 | %
Fuel services |  | $Cdn/kgU |  |  | 16.86 |  |  |  | 17.84 |  |  |  | 15.85 |  |  |  | (5 | )%
Electricity |  | $Cdn/MWh |  |  | 58 |  |  |  | 64 |  |  |  | 57 |  |  |  | (9 | )%

1 |  | Average realized foreign exchange rate ($US/$Cdn): 2010 — $1.05, 2009 — $1.18 and 2008 — $1.11.

2010 Annual financial review 31

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Outlook for 2011
We expect consolidated revenue to be 10% to 15% higher in 2011 due to:

• |  | higher sales volumes in the uranium and fuel services businesses
• |  | increases in realized prices in the uranium and fuel services businesses
• |  | partially offset by lower realized prices for electricity

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. We expect the trend in delivery patterns in 2011 to be somewhat different than in 2010, with deliveries heavily weighted to the second half of the year. We expect the fourth quarter to account for about one-third of our 2011 sales volumes.
Corporate expenses
Administration

($ millions) |  | 2010 |  |  | 2009 |  |  | change |
Direct administration |  |  | 141 |  |  |  | 122 |  |  |  | 16 | %
Stock-based compensation |  |  | 15 |  |  |  | 14 |  |  |  | 7 | %
Total administration |  |  | 156 |  |  |  | 136 |  |  |  | 15 | %

Direct administration costs in 2010 were $19 million (16%) higher than in 2009 as we continued to pursue and evaluate growth opportunities. The increase is largely related to increased hiring and analysis of business opportunities to achieve our growth plans. These costs were lower than we forecast as we narrowed the scope of some business development activities during the year.
We recorded $15 million in stock-based compensation expenses this year under our stock option, deferred share unit, performance share unit and phantom stock option plans, compared to $14 million in 2009. See note 22 to the financial statements.
Outlook for 2011
We expect administration costs (not including stock-based compensation) to be about 15% to 20% higher than in 2010 due to planned higher spending in support of our growth strategy.
Exploration
In 2010, uranium exploration expenses were $96 million compared to $49 million in 2009. The increase in 2010 largely reflects the increase in evaluation activities at the Kintyre and Inkai block 3 projects in Australia and Kazakhstan. Our exploration efforts in 2010 focused on Canada, the United States, Mongolia, Kazakhstan, Australia and South America.
Outlook for 2011
We expect exploration expenses to be about 5% to 10% lower than they were in 2010 due to a reduction in evaluation activities at the Kintyre project as we near the completion of the prefeasibility stage. See Our operations —Uranium exploration for more information.
Interest and other charges
Interest and other charges were $16 million higher than last year mainly as a result of recording $7 million in foreign exchange losses compared to gains of $21 million in 2009, partially offset by a $7 million increase in interest income attributable to higher cash balances. Gross interest charges this year were $10 million higher than last year attributable to our higher average debt level. See note 15 to the financial statements.
32 cameco corporation

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Gains and losses on derivatives
In 2010, we recorded $75 million in mark-to-market gains on our financial instruments compared to gains of $244 million in 2009. Unrealized gains on financial instruments were lower in 2010 than 2009 as the Canadian dollar continued to strengthen against the US dollar, but to a lesser degree. We voluntarily removed the hedging designation on our foreign currency forward sales contracts effective August 1, 2008, and have since recognized unrealized mark-to-market gains and losses in earnings. See note 26 to the financial statements.
Income taxes
We recorded an income tax expense of $27 million in 2010 compared to $53 million in 2009. This was mainly due to a $235 million decrease in pretax earnings in 2010, which was largely attributable to the decline of $169 million in gains on derivatives.
On an adjusted net earnings basis, our effective tax rate in 2010 was 4%, or 7% higher than 2009 as:

• |  | A higher proportion of taxable income was earned in jurisdictions with higher tax rates.
• |  | In 2009, certain future tax liabilities recognized in prior years were reduced.
• |  | In 2009, the statutory income tax rate in Canada was reduced, allowing us to reduce our provision for future income taxes.

On an adjusted net earnings basis, our tax expense was $20 million in 2010, compared to a recovery of $15 million in 2009.
Since 2008, Canada Revenue Agency (CRA) has disputed the transfer pricing methodology we used for certain uranium sale and purchase agreements and issued notices of reassessment for our 2003, 2004 and 2005 tax returns. We believe it is likely that CRA will reassess our tax returns for 2006 through 2010 on a similar basis. Our view is that CRA is incorrect, and we are contesting its position. In July 2009, we filed a Notice of Appeal relating to the 2003 reassessment with the Tax Court of Canada. In November 2010, we filed a Notice of Appeal relating to the 2004 reassessment with the Tax Court of Canada. We intend to object to the 2005 reassessment and pursue our appeal rights under the Income Tax Act. However, to reflect the uncertainties of CRA’s appeals process and litigation, we have provided $27 million for uncertain tax positions for the years 2003 through 2010. We believe that the ultimate resolution of this matter will not be material to our financial position, results of operations or liquidity over the period. However, an unfavourable outcome for the years 2003 to 2010 could be material to our financial position, results of operations or cash flows in the year(s) of resolution. See note 18 to the financial statements.
Outlook for 2011
On an adjusted net earnings basis, we expect our effective income tax rate will reflect a recovery of 0% to 5% as taxable income in Canada is expected to decline.
Foreign exchange
The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments.
Sales of uranium and fuel services are routinely denominated in US dollars while production costs are largely denominated in Canadian dollars. We use planned hedging to try to protect net inflows (total uranium and fuel services sales less US dollar cash expenses and product purchases) from the uranium and fuel services segments against declines in the US dollar in the shorter term. Our strategy is to hedge net inflows over a rolling 60-month period. Our target for the first 12 months is to hedge 35% to 100% of net inflows. The target range declines every year until it reaches 0% to 10% of our net inflows (from 48 and 60 months).
We also have a natural hedge against US currency fluctuations as a portion of our annual cash outlays, including purchases of uranium and fuel services, is denominated in US dollars. The earnings impact of this natural hedge is more difficult to identify because inventory includes material added over more than one fiscal period.
2010 Annual financial review 33

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At December 31, 2010:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $0.99 (Cdn), down from $1.00 (US) for $1.05 (Cdn) at December 31, 2009. The exchange rate averaged $1.00 (US) for $1.03 (Cdn) over the year.
• |  | Our effective exchange rate for the year, after allowing for hedging, was about $1.00 (US) for $1.05 (Cdn), compared to $1.00 (US) for $1.18 (Cdn) in 2009.
• |  | We had foreign currency contracts of $1.3 billion (US) and EUR 93 million at December 31, 2010. The US currency contracts had an average exchange rate of $1.00 (US) for $1.03 (Cdn).
• |  | The mark-to-market gain on all foreign exchange contracts was $47 million compared to a $67 million gain at December 31, 2009.

Timing differences between the maturity dates and designation dates on previously closed hedge contracts can result in deferred gains or charges. At December 31, 2010, we had net deferred gains of $6 million which will be recognized in earnings in 2011.
We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2010, all counterparties to foreign exchange hedging contracts had a Standard & Poor’s (S&P) credit rating of A or better.
Sensitivity analysis
At December 31, 2010, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2010 net earnings by about $9 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $0.99 (Cdn).
34 cameco corporation

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Outlook for 2011
Over the next several years, we expect to invest significantly in expanding production at existing mines and advancing projects as we pursue our growth strategy. The projects are at various stages of development, from exploration and evaluation to construction.
We expect our existing cash balances and operating cash flows will meet our anticipated capital requirements without the need for significant additional funding. Cash balances will decline gradually as we use the funds in our business and pursue our growth plans.
Our outlook for 2011 reflects the growth expenditures necessary to help us achieve our strategy. We do not provide an outlook for the items in the table that are marked with a dash.
See Financial results by segment for details.
2011 Financial outlook1

|  | Consolidated |  | Uranium |  | Fuel services |  | Electricity
Production |  | — |  | 21.9 million lbs |  | 15 to 16 million kgU |  | — |
Sales volume |  | — |  | 31 to 33 million lbs |  | Increase 10% to 15% |  | — |
Capacity factor |  | — |  | — |  | — |  | 89%
Revenue compared to 2010 |  | Increase 10% to 15% |  | Increase 15% to 20%2 |  | Increase 5% to 10% |  | Decrease 10% to 15%
Unit cost of product sold (including DDR) |  | — |  | Increase 0% to 5%3 |  | Increase 2% to 5% |  | Increase 10% to 15%
Direct administration costs compared to 20104 |  | Increase 15% to 20% |  | — |  | — |  | — |
Exploration costs compared to 2010 |  | — |  | Decrease 5% to 10% |  | — |  | — |
Tax rate |  | Recovery of 0% to 5% |  | — |  | — |  | — |
Capital expenditures |  | $575 million5 |  | — |  | — |  | $80 million

1 |  | Commencing January 1, 2011, we will be reporting our financial results in accordance with IFRS. The information in our 2011 financial outlook has been prepared in accordance with IFRS and our policy choices thereunder to date. A discussion about our transition to IFRS begins on page 91.
2 |  | Based on a uranium spot price of $73.00 (US) per pound (the Ux spot price as of February 7, 2011), a long-term price indicator of $73.00 (US) per pound (the Ux long-term indicator on January 31, 2011) and an exchange rate of $1.00 (US) for $1.00 (Cdn).
3 |  | This increase is based on the unit cost of sale for produced material. If we decide to make discretionary purchases in 2011 then we expect the overall unit cost of product sold to increase further.
4 |  | Direct administration costs do not include stock-based compensation expenses. See page 32 for more information.
5 |  | Does not include our share of capital expenditures at BPLP.

Sensitivity analysis
For 2011:

• |  | a change of $5 (US) per pound in each of the Ux spot price ($73.00 (US) per pound on February 7, 2011) and the Ux long-term price indicator ($73.00 (US) per pound on January 31, 2011) would change revenue by $34 million and net earnings by $26 million.
• |  | a change of $5 in the electricity spot price would change our 2011 net earnings by $2 million, based on the assumption that the spot price will remain below the floor price provided for under BPLP’s agreement with the Ontario Power Authority (OPA).

2010 Annual financial review 35

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Liquidity and capital resources
At the end of 2010, we had cash and short-term investments of $1.3 billion in a mix of short-term deposits and treasury bills, while our total debt amounted to $1 billion. We were in a similar position at the end of 2009.
We have large, reliable customers that need uranium regardless of world economic conditions, and we expect the uranium contract portfolio we’ve built to provide a solid revenue stream for years to come.
Our financial objective is to make sure we have the cash and debt capacity to fund our operating activities, investments, and growth. We have several alternatives to fund future capital needs, including our significant cash position, credit facilities, future operating cash flow and debt or equity financing, and are continually evaluating these options to make sure we have the best mix of capital resources to meet our needs.
Our strong financial position gives us the flexibility to fund longer term requirements until the balance accumulates to the point where it makes sense to refinance in the capital markets.
Financial condition

|  | 2010 |  |  | 2009 |
Cash position ($ millions) (cash, cash equivalents, short-term investments) |  |  | 1,260 |  |  |  | 1,304 |
Cash provided by operations ($ millions) (net cash flow generated by our operating activities after changes in working capital) |  |  | 507 |  |  |  | 690 |
Cash provided by operations/net debt (net debt is total consolidated debt, less cash and cash equivalents) |  |  | n/a |  |  |  | n/a |
Net debt/total capitalization (total capitalization is total long-term debt and equity) |  |  | n/a |  |  |  | n/a |

Credit ratings
Third-party ratings for our commercial paper and senior debt as of December 31, 2010:

Security |  | DBRS |  |  | S&P |
Commercial paper |  | R-1 (low) |  | A-1 (low)1
Senior unsecured debentures |  | A (low) |  | BBB+

1 |  | Canadian National Scale Rating. The Global Scale Rating is A-2.

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Liquidity

($ millions) |  | 2010 |  |  | 2009 |
Cash and cash equivalents at beginning of year |  |  | 1,304 |  |  |  | 64 |
Cash from operations |  |  | 507 |  |  |  | 690 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (470 | ) |  |  | (393 | )
Dispositions |  |  | — |  |  |  | 871 |
Acquisitions |  |  | — |  |  |  | — |
Other investing activities |  |  | 11 |  |  |  | (36 | )
Financing activities |  |  |  |  |  |  |  |
Change in debt |  |  | (10 | ) |  |  | (231 | )
Issue of shares |  |  | 18 |  |  |  | 442 |
Dividends |  |  | (106 | ) |  |  | (93 | )
Other financing activities |  |  | 10 |  |  |  | — |
Exchange rate on changes on foreign currency cash balances |  |  | (4 | ) |  |  | (10 | )
Cash and short-term investments at end of year |  |  | 1,260 |  |  |  | 1,304 |

Cash from operations
Cash from operations was 27% lower than in 2009 mainly due to higher working capital requirements relating to increased inventory levels and a reduction in accounts payable. Not including working capital requirements, our operating cash flows in the year were up $2 million. See note 19 to the financial statements.
Investing activities
Cash used in investing includes acquisitions and capital spending.
Acquisitions and divestitures
In 2010, we concluded no significant acquisitions or divestitures. In 2009, we sold our interest in Centerra for net proceeds of $871 million. We concluded no significant acquisitions in 2009.
Talvivaara Agreement
On February 7, 2011, we signed two agreements with Talvivaara Mining Company Plc (Talvivaara) to buy uranium produced at the Sotkamo nickel-zinc mine in eastern Finland. Under the first agreement with Talvivaara, we will provide an up-front payment, to a maximum of $60 million (US), to cover certain construction costs. This amount will be repaid through the initial deliveries of uranium concentrates. Once the full amount has repaid, we will continue to purchase the uranium concentrates produced at the Sotkamo mine through a second agreement, which provides for the purchase of uranium using a pricing formula that references market prices at the time of delivery. The second agreement expires on December 31, 2027.
2010 Annual financial review 37

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Capital spending
We classify capital spending as growth or sustaining. Growth capital is money we invest to generate incremental production, and for business development. Sustaining capital is the money we spend to keep our operations at current production levels.

(Cameco’s share in $ millions) |  | 2010 plan |  |  | 2010 actual |  |  | 2011 plan |
Growth capital |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 111 |  |  |  | 90 |  |  |  | 176 |
Inkai |  |  | 4 |  |  |  | 5 |  |  |  | 9 |
McArthur River |  |  | — |  |  |  | — |  |  |  | 14 |
Millennium |  |  | — |  |  |  | — |  |  |  | 6 |
US ISR |  |  | — |  |  |  | — |  |  |  | 13 |
Total growth capital |  |  | 115 |  |  |  | 95 |  |  |  | 218 |
Sustaining capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 220 |  |  |  | 165 |  |  |  | 169 |
US ISR |  |  | 53 |  |  |  | 45 |  |  |  | 38 |
Rabbit Lake |  |  | 56 |  |  |  | 49 |  |  |  | 85 |
Inkai |  |  | 18 |  |  |  | 5 |  |  |  | 19 |
Fuel services |  |  | 29 |  |  |  | 20 |  |  |  | 32 |
Other |  |  | 9 |  |  |  | 8 |  |  |  | 14 |
Total sustaining capital |  |  | 385 |  |  |  | 292 |  |  |  | 357 |
Capitalized interest |  |  | 52 |  |  |  | 48 |  |  |  | — |
Total uranium & fuel services |  |  | 552 | 1 |  |  | 435 |  |  |  | 575 |
Electricity (our 31.6% share of BPLP) |  |  | 41 |  |  |  | 35 |  |  |  | 80 |

1 |  | We updated our 2010 capital cost estimate in the Q2 MD&A to $510 million and in the Q3 MD&A to $475 million.

Capital expenditures were 21% below our 2010 plan mainly as a result of reduced activity at our Saskatchewan uranium operations. We do not expect this reduction in capital expenditures in 2010 will impact our plans to double annual uranium production by 2018. The variance at Cigar Lake was due mainly to the cleanup and remediation of the underground workings taking longer than originally expected and the revision to project schedules as a result of the decision to proceed with surface freezing. The variance at McArthur River was due mainly to a change in the mine development plans and postponement of some capital projects that were not critical to production. The variance at Key Lake was mainly a result of delays in the construction of the acid and oxygen plants and deferring some of the other Key Lake revitalization projects.
Outlook for investing activities
We expect total capital expenditures for uranium and fuel services to be 32% higher in 2011, as a result of higher spending for:

• |  | growth capital at Cigar Lake
• |  | sustaining capital at Rabbit Lake

Major sustaining expenditures in 2011 include:

• |  | McArthur River/Key Lake — At McArthur River, the largest component is mine development at about $50 million. Other projects include site facility expansion and equipment purchases. At Key Lake, construction of the new acid, steam and oxygen plants continues at an estimated cost of $30 million. Additional work to revitalize the mill will also be undertaken, as well as work on the tailings facilities.
• |  | US in situ recovery (ISR) — Wellfield construction and well installation is the largest project at approximately $25 million. We also plan to work on the development of the Gas Hills and North Butte projects.

38 cameco corporation

#####

• |  | Rabbit Lake — At Eagle Point, the largest project includes mine development at about $20 million. Other projects include dewatering systems, continued work on mine ventilation expansion and replacement of components of the acid plant estimated at $24 million.

For the next several years, we expect our capital expenditures will be similar to 2011.
Financing activities
Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance. In the fourth quarter, we renewed a $100 million revolving credit facility until February 2012.
As a result of our significant cash balance, there was little in the way of financing activities in 2010.
2009 was a very active year for us. We carried out six separate transactions to build on our already strong financial position, and to support our corporate strategy:

• |  | We issued approximately 26.7 million common shares, netting $440 million, and put in place or renewed $600 million in revolving lines of credit.

• |  | We issued 10-year debentures bearing interest at a rate of 5.67%, netting $495 million. At the same time, we cancelled a $500 million revolving credit facility that was to mature in June 2010.

• |  | We renewed a $100 million revolving credit facility until February 2011, and sold our interest in Centerra, netting $871 million.

Long-term contractual obligations

December 31, 2010 |  |  |  |  |  | 2012 |  |  | 2014 |  |  |  |  |  |  |
($ millions) |  | 2011 |  |  | and 2013 |  |  | and 2015 |  |  | 2016 and beyond |  |  | Total |
Long-term debt |  |  | 13 |  |  |  | 31 |  |  |  | 337 |  |  |  | 572 |  |  |  | 953 |
Interest on long-term debt |  |  | 53 |  |  |  | 105 |  |  |  | 96 |  |  |  | 113 |  |  |  | 367 |
Provision for reclamation |  |  | 14 |  |  |  | 23 |  |  |  | 22 |  |  |  | 406 |  |  |  | 465 |
Provision for waste disposal |  |  | 1 |  |  |  | 2 |  |  |  | 2 |  |  |  | 33 |  |  |  | 38 |
Other liabilities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 374 |  |  |  | 374 |
Total |  |  | 81 |  |  |  | 161 |  |  |  | 457 |  |  |  | 1,498 |  |  |  | 2,197 |

We now have unsecured lines of credit of about $1.2 billion, which include the following:

• |  | A $500 million, unsecured revolving credit facility that matures November 30, 2012. In addition to borrowing directly from this facility, we can use up to $100 million of it to issue letters of credit, and we keep up to $400 million available to provide liquidity for our commercial paper program, as necessary. The facility ranks equally with all of our other senior debt. At December 31, 2010, there was nothing outstanding under this credit facility, and nothing outstanding under our commercial paper program.

• |  | A $100 million, unsecured revolving credit facility that matures on February 4, 2012. At December 31, 2010, there was nothing outstanding under this credit facility.

• |  | Approximately $600 million in short-term borrowing and letters of credit provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, and as overdraft protection. At December 31, 2010, we had approximately $550 million outstanding in letters of credit.

We have $800 million in senior unsecured debentures:

• |  | $300 million bearing interest at 4.7% per year, maturing on September 16, 2015

• |  | $500 million bearing interest at 5.67% per year, maturing on September 2, 2019

We have issued a $73 million (US) promissory note to GLE to support future development of its business. We do not expect any amounts to be drawn on this note until 2012.
2010 Annual financial review 39

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Debt covenants
Our revolving credit facilities include the following financial covenants:

• |  | our funded debt to tangible net worth ratio must be 1:1 or less

• |  | our tangible net worth must be more than $1.25 billion

• |  | other customary covenants and events of default

Funded debt is total consolidated debt less the following: non-recourse debt, $100 million in letters of credit, cash and short-term investments.
Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facilities. At December 31, 2010, we complied with all covenants, and we expect to continue to comply in 2011.
Off-balance sheet arrangements
We had two kinds of off-balance sheet arrangements at the end of 2010:

• |  | purchase commitments

• |  | financial assurances

Purchase commitments

December 31, 2010 |  |  |  |  |  | 2012 |  |  | 2014 |  |  |  |  |  |  |
($ millions) |  | 2011 |  |  | and 2013 |  |  | and 2015 |  |  | 2016 and beyond |  |  | Total |
Purchase commitments1 |  |  | 266 |  |  |  | 620 |  |  |  | 173 |  |  |  | 6 |  |  |  | 1,065 |

1 |  | Denominated in US dollars, converted to Canadian dollars as of December 31, 2010 at the rate of $0.99.

Most of these are commitments to buy uranium and fuel services products under long-term, fixed-price arrangements.
At the end of 2010, we had committed to $1.1 billion (Cdn) for the following:

• |  | About 27 million pounds U3O8 equivalent from 2011 to 2014. Of these, about 23 million pounds are from our agreement with Techsnabexport Joint Stock Company (Tenex) to buy uranium from dismantled Russian weapons (the Russian HEU commercial agreement) through 2013.

• |  | Over 36 million kgU as UF6 in conversion services from 2011 to 2016 primarily under our agreements with Springfields Fuels Ltd. (SFL) and Tenex.

• |  | Almost 1.1 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-western supplier.

Non-delivery by Tenex or SFL under their agreements could have a material adverse effect on our financial condition, liquidity and results of operations.
Tenex, SFL and the SWU supplier do not have the right to terminate their agreements other than pursuant to customary event of default provisions.
40 cameco corporation

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Financial assurances

December 31 |  |  |  |  |  |  |  |  |
($ millions) |  | 2010 |  |  | 2009 |  |  | change |
Standby letters of credit |  |  | 550 |  |  |  | 592 |  |  |  | (7 | )%
BPLP guarantees |  |  | 82 |  |  |  | 87 |  |  |  | (6 | )%
Total |  |  | 632 |  |  |  | 679 |  |  |  | (7 | )%

Standby letters of credit mainly provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities. We are required to provide letters of credit to various regulatory agencies until decommissioning and reclamation activities are complete. Letters of credit are issued by financial institutions for a one-year term.
Our total commitment for financial guarantees on behalf of BPLP was an estimated $94 million at the end of the year. See note 25 to the financial statements.
Balance sheet

December 31 |  |  |  |  |  |  |  |  |  |  |  |  |  | change from |
($ millions except per share amounts) |  | 2010 |  |  | 2009 |  |  | 2008 |  |  | 2009 to 2010 |
Inventory |  |  | 543 |  |  |  | 453 |  |  |  | 398 |  |  |  | 20 | %
Total assets |  |  | 7,671 |  |  |  | 7,394 |  |  |  | 7,011 |  |  |  | 4 | %
Long-term financial liabilities |  |  | 1,465 |  |  |  | 1,471 |  |  |  | 1,800 |  |  |  | (1 | )%
Dividends per common share |  |  | 0.28 |  |  |  | 0.24 |  |  |  | 0.24 |  |  |  | 17 | %

Total product inventories increased by 20% to $543 million this year due to higher levels of inventory for uranium, where the quantities produced and purchased exceeded sales for the year. The average cost of uranium was lower as a result of fewer purchases at near-market prices.
At the end of 2010, our total assets amounted to $7.7 billion, an increase of $0.3 billion compared to 2009 due primarily to a higher rate of investment in property, plant and equipment. In 2009, the total asset balance increased by $0.4 billion, largely attributable to a higher cash balance.
The major components of long-term financial liabilities are long-term debt, future income taxes and the provision for reclamation. In 2010, our balance was similar to that of the prior year. In 2009, our balance declined by $0.3 billion primarily due to the repayment of debt during the year.
2010 Annual financial review 41

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2010 financial results by segment
Uranium

Highlights |  | 2010 |  |  | 2009 |  |  | change |
Production volume (million lbs) |  |  | 22.8 |  |  |  | 20.8 |  |  |  | 10 | %
Sales volume (million lbs) |  |  | 29.6 |  |  |  | 33.9 |  |  |  | (13 | )%
Average spot price ($US/lb) |  |  | 46.83 |  |  |  | 46.06 |  |  |  | 2 | %
Average realized price |  |  |  |  |  |  |  |  |  |  |  |
($US/lb) |  |  | 43.63 |  |  |  | 38.25 |  |  |  | 14 | %
($Cdn/lb) |  |  | 45.81 |  |  |  | 45.12 |  |  |  | 2 | %
Average unit cost of sales ($Cdn/lb U3O8) (including DDR) |  |  | 28.40 |  |  |  | 30.59 |  |  |  | (7 | )%
Revenue ($ millions) |  |  | 1,374 |  |  |  | 1,551 |  |  |  | (11 | )%
Gross profit ($ millions) |  |  | 503 |  |  |  | 488 |  |  |  | 3 | %
Gross profit (%) |  |  | 37 |  |  |  | 31 |  |  |  | 19 | %

Production volumes in 2010 were 10% higher than 2009 due to higher production at McArthur River/Key Lake and the continued rampup of production at Inkai.
Uranium revenues this year were down 11% compared to 2009, due to a 13% decline in sales volumes.
Sales volumes in 2010 were 13% lower than 2009 due to some customers deferring deliveries under contracts until 2011. In addition, given the discretionary nature of spot market demand and the low level of spot market prices during the first three quarters of 2010, we intentionally reduced our spot market sales for the year.
Our realized prices this year in US dollars were 14% higher than 2009 mainly due to higher prices under fixed-price sales contracts. Our Canadian dollar selling price, however, was only slightly higher than 2009 as it was impacted by a less favourable exchange rate. Our exchange rate averaged $1.05 compared to $1.18 in 2009.
Total cash cost of sales (excluding DDR) decreased by 23% this year, to $699 million ($23.32 per pound U3O8). This was mainly the result of the following:

• |  | the 13% decline in sales volumes

• |  | average unit costs for produced uranium were 6% lower

• |  | average unit costs for purchased uranium were 17% lower due to fewer purchases at spot prices

• |  | a lower proportion of sales of purchased uranium, which carries a higher cash cost

The net effect was a $15 million increase in gross profit for the year.
The following table shows our cash cost of sales per unit (excluding DDR) for produced and purchased material, including royalty charges on produced material, and the quantity of produced and purchased uranium sold.

|  | Unit cash cost of sale |  |  |  |  |  |  | Quantity sold |
|  | ($Cdn/lb U3O8) |  |  |  |  |  |  | (million lbs) |
|  | 2010 |  |  | 2009 |  |  | change |  |  | 2010 |  |  | 2009 |  |  | change |
Produced |  |  | 22.45 |  |  |  | 23.86 |  |  |  | (1.41 | ) |  |  | 20.0 |  |  |  | 20.9 |  |  |  | (0.9 | )
Purchased |  |  | 25.11 |  |  |  | 30.22 |  |  |  | (5.11 | ) |  |  | 9.6 |  |  |  | 13.0 |  |  |  | (3.4 | )
Total |  |  | 23.32 |  |  |  | 26.33 |  |  |  | (3.01 | ) |  |  | 29.6 |  |  |  | 33.9 |  |  |  | (4.3 | )

42 cameco corporation

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Outlook for 2011
We expect to produce 21.9 million pounds of U3O8 in 2011.
Based on the contracts we have in place, we expect to sell between 31 million and 33 million pounds of U3O8 in 2011. We expect the unit cost of sales to be 0% to 5% higher than in 2010. This increase is based on the unit cost of sale for produced material. If we decide to make discretionary purchases in 2011 then we expect the overall unit cost of product sold to increase further.
Based on current spot prices, revenue should be about 15% to 20% higher than it was in 2010 as a result of increases in expected realized prices and sales volumes in 2011.
Price sensitivity analysis: uranium
The table below is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table.
It is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2010 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2010, and none of the assumptions we list below change.
Expected realized uranium price sensitivity under various spot price assumptions
(rounded to the nearest $1.00)

($US/lb U3O8) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Spot prices |  | $20 |  |  | $40 |  |  | $60 |  |  | $80 |  |  | $100 |  |  | $120 |  |  | $140 |
2011 |  |  | 38 |  |  |  | 41 |  |  |  | 47 |  |  |  | 52 |  |  |  | 57 |  |  |  | 63 |  |  |  | 68 |
2012 |  |  | 36 |  |  |  | 40 |  |  |  | 50 |  |  |  | 58 |  |  |  | 68 |  |  |  | 77 |  |  |  | 86 |
2013 |  |  | 43 |  |  |  | 45 |  |  |  | 54 |  |  |  | 63 |  |  |  | 73 |  |  |  | 82 |  |  |  | 90 |
2014 |  |  | 44 |  |  |  | 47 |  |  |  | 55 |  |  |  | 64 |  |  |  | 74 |  |  |  | 83 |  |  |  | 91 |
2015 |  |  | 40 |  |  |  | 45 |  |  |  | 55 |  |  |  | 65 |  |  |  | 75 |  |  |  | 85 |  |  |  | 94 |

The table illustrates the mix of long-term contracts in our December 31, 2010 portfolio, and is consistent with our contracting strategy. It has been updated to reflect deliveries made and contracts entered into up to December 31, 2010.
Our portfolio includes a mix of fixed-price and market-price contracts, which we target at a 40:60 ratio. We signed many of our current contracts in 2003 to 2005, when market prices were low ($11 to $31 (US)). Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices. These older contracts are beginning to expire, and we are starting to deliver into more favourably priced contracts.
Our portfolio is affected by more than just the spot price. We made the following assumptions (which are not forecasts) to create the table:
Sales

• |  | sales volumes on average of 32 million pounds per year

Deliveries

• |  | customers take the maximum quantity allowed under each contract (unless they have already provided a delivery notice indicating they will take less)

• |  | we defer a portion of deliveries under existing contracts for 2011 and 2012

Prices

• |  | the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 13% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table will be higher.

• |  | we deliver all volumes that we don’t have contracts for at the spot price for each scenario

Inflation

• |  | is 2.0% per year

2010 Annual financial review 43

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Tiered royalties
As sales of material we produce at our Saskatchewan properties increase, so do the tiered royalties we pay. The table below indicates what we would pay in tiered royalties at various realized prices. We record tiered royalties as a cost of sales.
This table assumes that we sell 100,000 pounds U3O8 and that there is no capital allowance available to reduce royalties, and is based on 2010 rates. The index value to calculate rates for 2011 is not available until April 2011.

Realized |  | Tier 1 royalty |  |  | Tier 2 royalty |  |  | Tier 3 royalty |  |  |  |
price |  | 6% x |  |  | 4% x |  |  | 5% x |  |  |  |
($Cdn) | (sales price - $17.51) |  |  | (sales price - $26.27) |  |  | (sales price - $35.03) |  |  | Total royalties |
25 |  |  | 44,940 |  |  |  | — |  |  |  | — |  |  |  | 44,940 |
35 |  |  | 104,940 |  |  |  | 34,920 |  |  |  | — |  |  |  | 139,860 |
45 |  |  | 164,940 |  |  |  | 74,920 |  |  |  | 49,850 |  |  |  | 289,710 |
55 |  |  | 224,940 |  |  |  | 114,920 |  |  |  | 99,850 |  |  |  | 439,710 |
65 |  |  | 284,940 |  |  |  | 154,920 |  |  |  | 149,850 |  |  |  | 589,710 |
75 |  |  | 344,940 |  |  |  | 194,920 |  |  |  | 199,850 |  |  |  | 739,710 |
85 |  |  | 404,940 |  |  |  | 234,920 |  |  |  | 249,850 |  |  |  | 889,710 |

44 cameco corporation

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Fuel services
(includes results for UF6, UO2 and fuel fabrication)

Highlights |  | 2010 |  |  | 2009 |  |  | change |
Production volume (million kgU) |  |  | 15.4 |  |  |  | 12.3 |  |  |  | 25 | %
Sales volume (million kgU) |  |  | 17.0 |  |  |  | 14.9 |  |  |  | 14 | %
Realized price ($Cdn/kgU) |  |  | 16.86 |  |  |  | 17.84 |  |  |  | (5 | )%
Average unit cost of sales ($Cdn/kgU) (including DDR) |  |  | 13.39 |  |  |  | 14.47 |  |  |  | (7 | )%
Revenue ($ millions) |  |  | 301 |  |  |  | 276 |  |  |  | 9 | %
Gross profit ($ millions) |  |  | 60 |  |  |  | 50 |  |  |  | 20 | %
Gross profit (%) |  |  | 20 |  |  |  | 18 |  |  |  | 11 | %

The Port Hope UF6 conversion plant operated for a full year in 2010, increasing production volumes by 25% over 2009. In 2009, the facility was shut down for the first five months of the year.
Total revenue increased by 9% due to a 14% increase in sales volumes.
Our Canadian dollar realized price for UF6 was affected by a less favourable exchange rate. Our exchange rate averaged $1.05 in 2010 compared to $1.18 in 2009.
The total cost of products and services sold (including DDR) increased by 6% ($241 million compared to $226 million in 2009) due to the increase in sales volumes. The average unit cost of sales was 7% lower due to lower costs for purchased material and the return to operational status of the UF6 facility.
The net effect was a $10 million increase in gross profit.
Outlook for 2011
We expect production in 2011 to be similar to 2010, in the range of 15 million to 16 million kgU.
We expect the average realized price for our fuel services products to decline by 2% to 5%, sales volumes to increase by 10% to 15% and revenue to be 5% to 10% higher.
2010 Annual financial review 45

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Electricity
BPLP
(100% — not prorated to reflect our 31.6% interest)

Highlights |  |  |  |  |  |  |  |  |
($ millions except where indicated) |  | 2010 |  |  | 2009 |  |  | change |
Output — terawatt hours (TWh) |  |  | 25.9 |  |  |  | 24.6 |  |  |  | 5 | %
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing) |  |  | 91 | % |  |  | 87 | % |  |  | 5 | %
Realized price ($/MWh) |  |  | 58 |  |  |  | 64 | 1 |  |  | (9 | )%
Average Ontario electricity spot price ($/MWh) |  |  | 36 |  |  |  | 30 |  |  |  | 20 | %
Revenue |  |  | 1,509 |  |  |  | 1,640 |  |  |  | (8 | )%
Operating costs (net of cost recoveries) |  |  | 930 |  |  |  | 905 |  |  |  | 3 | %
Cash costs |  |  | 785 |  |  |  | 770 |  |  |  | 2 | %
Non-cash costs |  |  | 145 |  |  |  | 135 |  |  |  | 7 | %
Income before interest and finance charges |  |  | 579 |  |  |  | 735 |  |  |  | (21 | )%
Interest and finance charges |  |  | 36 |  |  |  | 4 |  |  |  | 800 | %
Cash from operations |  |  | 643 |  |  |  | 754 |  |  |  | (15 | )%
Capital expenditures |  |  | 111 |  |  |  | 123 |  |  |  | (10 | )%
Distributions |  |  | 525 |  |  |  | 610 |  |  |  | (14 | )%
Operating costs ($/MWh) |  |  | 36 |  |  |  | 35 | 1 |  |  | 3 | %

1 |  | Based on actual generation of 24.6 TWh plus deemed generation of 1.2 TWh. Deemed generation in 2010 was insignificant.

Our earnings from BPLP

Highlights |  |  |  |  |  |  |  |  |
($ millions except where indicated) |  | 2010 |  |  | 2009 |  |  | change |
BPLP’s earnings before taxes (100%) |  |  | 543 |  |  |  | 731 |  |  |  | (26 | )%
Cameco’s share of pretax earnings before adjustments (31.6%) |  |  | 172 |  |  |  | 231 |  |  |  | (26 | )%
Proprietary adjustments |  |  | (6 | ) |  |  | (7 | ) |  |  | (14 | )%
Earnings before taxes from BPLP |  |  | 166 |  |  |  | 224 |  |  |  | (26 | )%

BPLP’s results in 2010 are largely the result of lower revenues, which were 8% lower than 2009 due to a 9% decrease in realized electricity prices. BPLP’s average realized price reflects spot sales, revenue recognized under BPLP’s agreement with the Ontario Power Authority (OPA) and revenue from financial contracts.
BPLP has an agreement with the OPA under which output from each B reactor is supported by a floor price (currently $48.96/MWh) that is adjusted annually for inflation. The floor price mechanism and any associated payments to BPLP for the output from each individual B reactor will expire on a date specified in the agreement. The expiry dates are December 31, 2015 for unit B6, December 31, 2016 for unit B5, December 31, 2017 for unit B7 and December 31, 2019 for unit B8. Revenue is recognized monthly, based on the positive difference between the floor price and the spot price. BPLP does not have to repay the revenue from the agreement with the OPA to the extent that the floor price for the particular year exceeds the average spot price for that year.
The agreement also provides for payment if the Independent Electricity System Operator reduces BPLP’s generation because Ontario baseload generation is higher than required. The amount of the reduction is considered ‘deemed
46 cameco corporation

#####

generation’, and BPLP is paid either the spot price or the floor price — whichever is higher. Deemed generation was insignificant in 2010.
During 2010, BPLP recognized revenue of $339 million under the agreement with the OPA, compared to $514 million in 2009.
BPLP also has financial contracts in place that reflect market conditions at the time they were signed. Contracts signed in 2006 to 2008, when the spot price was higher than the floor price, reflected the strong forward market at the time. BPLP receives or pays the difference between the contract price and the spot price. Since the electricity market in Ontario has weakened, BPLP has been putting fewer contracts in place.
BPLP sold the equivalent of about 42% of its output under financial contracts in 2010, compared to 57% in 2009.
BPLP’s operating costs were $930 million this year compared to $905 million in 2009.
The net effect was a decrease in our share of earnings before taxes of 26%.
BPLP distributed $525 million to the partners in 2010. Our share was $166 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.
BPLP’s capacity factor was 91% in 2010.
Outlook for 2011
We expect the average capacity factor for the four Bruce B reactors to be 89% in 2011, and actual output to be about 2% lower than it was in 2010. The 2011 realized price for electricity is projected to be about 5% to 10% lower than 2010 as BPLP has fewer financial contracts in place for 2011. At December 31, 2010, BPLP had about 7.5 TWh under financial contracts, which is equivalent to about 30% of Bruce B generation at its planned capacity factor. We expect that revenue will decline by 10% to 15% as a result.
We expect the average unit cost (net of cost recoveries) to be 10% to 15% higher in 2011, and total operating costs to rise by about 5% to 10%, mainly due to higher costs for planned outages and maintaining the workforce.
2010 Annual financial review 47

#####

Fourth quarter results
Fourth quarter consolidated results

|  | Three months ended |  |  |  |
Highlights |  | December 31 |  |  |  |
($ millions except per share amounts) |  | 2010 |  |  | 2009 |  |  | change |
Revenue |  |  | 673 |  |  |  | 659 |  |  |  | 2 | %
Gross profit |  |  | 245 |  |  |  | 206 |  |  |  | 19 | %
Net earnings |  |  | 207 |  |  |  | 598 |  |  |  | (65 | )%
$ per common share (basic) |  |  | 0.52 |  |  |  | 1.52 |  |  |  | (66 | )%
$ per common share (diluted) |  |  | 0.52 |  |  |  | 1.52 |  |  |  | (66 | )%
Adjusted net earnings (non-GAAP, see page 29) |  |  | 191 |  |  |  | 170 |  |  |  | 12 | %
$ per common share (adjusted and diluted) |  |  | 0.48 |  |  |  | 0.43 |  |  |  | 12 | %
Cash provided by operations (after working capital changes) |  |  | 120 |  |  |  | 188 |  |  |  | (36 | )%

In the fourth quarter of 2010, our net earnings were $207 million ($0.52 per share diluted), a decrease of $391 million compared to $598 million ($1.52 per share diluted) in 2009. We had a $374 million net gain in the fourth quarter of 2009 related to the sale of our interest in Centerra.
The 12% increase in adjusted net earnings in the quarter was from higher profits in our uranium segment relating to a higher average realized selling price and a lower unit cost of sales, partially offset by lower profits in the electricity business due to a lower realized price.
We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our financial performance from period to period. See page 29 for more information. The table below reconciles adjusted net earnings with our net earnings.

|  | Three months ended |
|  | December 31 |
($ millions) |  | 2010 |  |  | 2009 |
Net earnings (GAAP measure) |  |  | 207 |  |  |  | 598 |
Adjustments (after tax) |  |  |  |  |  |  |  |
Earnings from discontinued operations |  |  | — |  |  |  | (424 | )1
Unrealized gains on financial instruments |  |  | (16 | ) |  |  | (4 | )
Adjusted net earnings (non-GAAP measure) |  |  | 191 |  |  |  | 170 |

1 |  | We have changed our calculation of adjusted earnings to exclude amounts related to our investment in Centerra. In previous years, this calculation included our share of earnings from Centerra.

We recorded an income tax expense of $7 million this quarter, based on adjusted net earnings, compared to a $3 million expense in 2009.
48 cameco corporation

#####

Direct administration costs were $47 million in the quarter, $8 million higher than the same period last year. Stock-based compensation expenses were $8 million in the quarter, compared to $3 million in the fourth quarter of 2009 due to a 41% increase in our share price during the fourth quarter of 2010. See note 22 to the financial statements.

|  | Three months ended |
|  | December 31 |
($ millions) |  | 2010 |  |  | 2009 |
Direct administration |  |  | 47 |  |  |  | 39 |
Stock-based compensation |  |  | 8 |  |  |  | 3 |
Total administration |  |  | 55 |  |  |  | 42 |

Quarterly trends

Highlights |  |  |  |  |  |  |  |  |  |  |  |  |  | 2010 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2009 |
($ millions except per share amounts) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 673 |  |  |  | 419 |  |  |  | 546 |  |  |  | 486 |  |  |  | 659 |  |  |  | 518 |  |  |  | 645 |  |  |  | 493 |
Net earnings |  |  | 207 |  |  |  | 98 |  |  |  | 68 |  |  |  | 142 |  |  |  | 598 |  |  |  | 172 |  |  |  | 247 |  |  |  | 82 |
$ per common share (basic) |  |  | 0.52 |  |  |  | 0.25 |  |  |  | 0.17 |  |  |  | 0.37 |  |  |  | 1.52 |  |  |  | 0.44 |  |  |  | 0.64 |  |  |  | 0.23 |
$ per common share (diluted) |  |  | 0.52 |  |  |  | 0.25 |  |  |  | 0.17 |  |  |  | 0.36 |  |  |  | 1.52 |  |  |  | 0.44 |  |  |  | 0.64 |  |  |  | 0.22 |
Adjusted net earnings (non-GAAP, see page 29) |  |  | 191 |  |  |  | 80 |  |  |  | 114 |  |  |  | 111 |  |  |  | 170 |  |  |  | 94 |  |  |  | 161 |  |  |  | 103 |
$ per share diluted |  |  | 0.48 |  |  |  | 0.20 |  |  |  | 0.29 |  |  |  | 0.28 |  |  |  | 0.43 |  |  |  | 0.24 |  |  |  | 0.41 |  |  |  | 0.27 |
Earnings from continuing operations |  |  | 207 |  |  |  | 98 |  |  |  | 68 |  |  |  | 142 |  |  |  | 174 |  |  |  | 195 |  |  |  | 269 |  |  |  | 79 |
$ per common share (basic) |  |  | 0.52 |  |  |  | 0.25 |  |  |  | 0.17 |  |  |  | 0.37 |  |  |  | 0.44 |  |  |  | 0.49 |  |  |  | 0.68 |  |  |  | 0.23 |
$ per common share (diluted) |  |  | 0.52 |  |  |  | 0.25 |  |  |  | 0.17 |  |  |  | 0.36 |  |  |  | 0.44 |  |  |  | 0.49 |  |  |  | 0.68 |  |  |  | 0.23 |
Cash provided by operations |  |  | 120 |  |  |  | (18 | ) |  |  | 272 |  |  |  | 133 |  |  |  | 188 |  |  |  | 175 |  |  |  | 147 |  |  |  | 180 |

Key things to note:

• |  | Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 68% of consolidated revenues in the fourth quarter of 2010.
• |  | The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments.
• |  | Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our results from period to period (see page 29 for more information).
• |  | Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments.
• |  | Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

2010 Annual financial review 49

#####

Fourth quarter results by segment
Uranium

|  | Three months ended |  |  |  |
|  | December 31 |  |  |  |
Highlights |  | 2010 |  |  | 2009 |  |  | change |
Production volume (million lbs) |  |  | 6.4 |  |  |  | 6.7 |  |  |  | (4 | )%
Sales volume (million lbs) |  |  | 9.1 |  |  |  | 10.0 |  |  |  | (9 | )%
Average spot price ($US/lb) |  |  | 58.29 |  |  |  | 45.96 |  |  |  | 27 | %
Average realized price |  |  |  |  |  |  |  |  |  |  |  |
($US/lb) |  |  | 48.50 |  |  |  | 40.64 |  |  |  | 19 | %
($Cdn/lb) |  |  | 50.10 |  |  |  | 43.51 |  |  |  | 15 | %
Average unit cost of sales ($Cdn/lb U3O8) (including DDR) |  |  | 29.89 |  |  |  | 30.29 |  |  |  | (1 | )%
Revenue ($ millions) |  |  | 461 |  |  |  | 443 |  |  |  | 4 | %
Gross profit ($ millions) |  |  | 181 |  |  |  | 132 |  |  |  | 37 | %
Gross profit (%) |  |  | 39 |  |  |  | 30 |  |  |  | 30 | %

Production volumes were 4% lower due to lower output at Rabbit Lake.
Uranium revenues were up 4% due to a 15% increase in the realized selling price, partially offset by a 9% decline in sales volumes.
Realized prices were higher due to higher prices under market-related and fixed-price sales contracts.
Total cash cost of sales (excluding DDR) decreased by 12% to $233 million ($25.30 per pound U3O8). This was mainly the result of the following:

• |  | the 9% decline in sales volumes
• |  | average unit costs for produced uranium were 26% higher
• |  | average unit costs for purchased uranium were 14% lower due to fewer purchases at spot prices

The net effect was a $49 million increase in gross profit for the quarter.
The following table shows our cash cost of sales per unit (excluding DDR) for produced and purchased material, including royalty charges on produced material, and the quantity of produced and purchased uranium sold.

|  | Unit cash cost of sale |  |  | Quantity sold |
Three months |  | ($Cdn/lb U3O8) |  |  | (million lbs) |
ended December 31 |  | 2010 |  |  | 2009 |  |  | change |  |  | 2010 |  |  | 2009 |  |  | change |
Produced |  |  | 22.30 |  |  |  | 17.73 |  |  |  | 4.57 |  |  |  | 5.5 |  |  |  | 5.1 |  |  |  | 0.4 |
Purchased |  |  | 29.93 |  |  |  | 34.72 |  |  |  | (4.79 | ) |  |  | 3.6 |  |  |  | 4.9 |  |  |  | (1.3 | )
Total |  |  | 25.30 |  |  |  | 26.19 |  |  |  | (0.89 | ) |  |  | 9.1 |  |  |  | 10.0 |  |  |  | (0.9 | )

50 cameco corporation

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Fuel services
(includes results for UF6, UO2 and fuel fabrication)

|  | Three months ended |  |  |  |
|  | December 31 |  |  |  |
Highlights |  | 2010 |  |  | 2009 |  |  | change |
Production volume (million kgU) |  |  | 3.9 |  |  |  | 3.9 |  |  |  | — |
Sales volume (million kgU) |  |  | 6.3 |  |  |  | 6.0 |  |  |  | 5 | %
Realized price ($Cdn/kgU) |  |  | 14.59 |  |  |  | 14.89 |  |  |  | (2 | )%
Average unit cost of sales ($Cdn/kgU) (including DDR) |  |  | 12.87 |  |  |  | 12.43 |  |  |  | 4 | %
Revenue ($ millions) |  |  | 93 |  |  |  | 91 |  |  |  | 2 | %
Gross profit ($ millions) |  |  | 11 |  |  |  | 13 |  |  |  | (15 | )%
Gross profit (%) |  |  | 12 |  |  |  | 14 |  |  |  | (14 | )%

Total revenue increased by 2% due to a 5% increase in sales volumes.
Our Canadian dollar realized price for UF6 was similar to the prior year but was affected by a less favourable exchange rate. Our exchange rate averaged $1.03 in the fourth quarter compared to $1.07 in 2009.
The total cost of products and services sold (including DDR) increased by 5% ($82 million compared to $78 million in the fourth quarter of 2009) due to the increase in sales volumes. The average unit cost of sales was 4% higher due to increased sales of fuel fabrication, which carries a higher unit cost than other fuel services products.
The net effect was a $2 million decrease in gross profit.
2010 Annual financial review 51

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Electricity
BPLP
(100% — not prorated to reflect our 31.6% interest)

|  | Three months ended |  |  |  |
Highlights |  | December 31 |  |  |  |
($ millions except where indicated) |  | 2010 |  |  | 2009 |  |  | change |
Output — terawatt hours (TWh) |  |  | 6.6 |  |  |  | 6.4 |  |  |  | 3 | %
Capacity factor |  |  | 91 | % |  |  | 89 | % |  |  | 2 | %
(the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing) |  |  |  |  |  |  |  |  |  |  |  |
Realized price ($/MWh) |  |  | 60 |  |  |  | 62 | 1 |  |  | (3 | )%
Average Ontario electricity spot price ($/MWh) |  |  | 32 |  |  |  | 30 |  |  |  | 7 | %
Revenue |  |  | 393 |  |  |  | 422 |  |  |  | (7 | )%
Operating costs (net of cost recoveries) |  |  | 221 |  |  |  | 218 |  |  |  | 1 | %
Cash costs |  |  | 184 |  |  |  | 183 |  |  |  | 1 | %
Non-cash costs |  |  | 37 |  |  |  | 35 |  |  |  | 6 | %
Income before interest and finance charges |  |  | 172 |  |  |  | 204 |  |  |  | (16 | )%
Interest and finance charges |  |  | 7 |  |  |  | 1 |  |  |  | 600 | %
Cash from operations |  |  | 146 |  |  |  | 229 |  |  |  | (36 | )%
Capital expenditures |  |  | 37 |  |  |  | 40 |  |  |  | (3 | )%
Distributions |  |  | 120 |  |  |  | 220 |  |  |  | (45 | )%
Operating costs ($/MWh) |  |  | 33 |  |  |  | 32 | 1 |  |  | 3 | %

1 |  | Based on actual generation of 6.4 TWh plus deemed generation of 0.4 TWh in the fourth quarter.

Our earnings from BPLP

|  | Three months ended |  |  |  |
Highlights |  | December 31 |  |  |  |
($ millions except where indicated) |  | 2010 |  |  | 2009 |  |  | change |
BPLP’s earnings before taxes (100%) |  |  | 165 |  |  |  | 203 |  |  |  | (19 | )%
Cameco’s share of pretax earnings before adjustments (31.6%) |  |  | 52 |  |  |  | 64 |  |  |  | (19 | )%
Proprietary adjustments |  |  | (1 | ) |  |  | (2 | ) |  |  | (50 | )%
Earnings before taxes from BPLP |  |  | 51 |  |  |  | 62 |  |  |  | (18 | )%

Total electricity revenue decreased 7% as higher actual output was offset by a lower realized price. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $114 million this quarter under its agreement with the OPA, compared to $137 million in the fourth quarter of 2009. The equivalent of about 45% of BPLP’s output was sold under financial contracts this quarter, compared to 54% in the fourth quarter of 2009.
The capacity factor was 91% this quarter, up from 89% in the fourth quarter of 2009. Operating costs were $221 million compared to $218 million in 2009.
The result was an 18% decrease in our share of earnings before taxes.
BPLP distributed $120 million to the partners in the fourth quarter. Our share was $38 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.
52 cameco corporation

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Our operations and development projects
This section of our MD&A is an overview of each of our operations, what we accomplished this year, our plans for the future and how we manage risk.

Uranium |  |  |  |
Operating properties |  |  |  |
McArthur River and Key Lake |  |  | 58 |
Rabbit Lake |  |  | 63 |
Smith Ranch-Highland |  |  | 65 |
Crow Butte |  |  | 67 |
Inkai |  |  | 69 |
Development project |  |  |  |
Cigar Lake |  |  | 72 |
Projects under evaluation |  |  |  |
Inkai blocks 1 and 2 |  |  |  |
production increase (see Inkai, above) |  |  | 69 |
Inkai block 3 (see Inkai, above) |  |  | 69 |
McArthur River extension |  |  |  |
(see McArthur River, above) |  |  | 58 |
Kintyre |  |  | 77 |
Millennium |  |  | 78 |
Exploration |  |  | 79 |
Fuel services |  |  |  |
Refining |  |  |  |
Blind River refinery |  |  | 80 |
Conversion and fuel manufacturing |  |  |  |
Port Hope conversion services |  |  | 81 |
Fuel Manufacturing |  |  | 81 |
Springfields Fuels |  |  | 81 |
Electricity |  |  |  |
Bruce Power Limited Partnership |  |  | 83 |

2010 Annual financial review 53

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Managing the risks
The nature of our operations means we face many potential risks and hazards that could have a significant impact on our business. We have comprehensive systems and procedures in place to manage them, but there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause.
Below we list the regulatory, environmental and operational risks that generally apply to all of our operations, development projects, and projects under evaluation. We also talk about how we manage specific risks in each operation or project update. These risks could have a material impact on our business in the near term.
We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.
Regulatory risks
A significant part of our economic value depends on our ability to:

• |  | obtain and renew the licences and other approvals we need to operate, to increase production at our mines and to develop new mines. If we do not receive the regulatory approvals we need, or do not receive them at the right time, then we may have to delay, modify or cancel a project, which could increase our costs and delay or prevent us from generating revenue from the project. Regulatory review, including the review of environmental matters, is a long and complex process.
• |  | comply with the conditions in these licences and approvals. In a number of instances, our right to continue operating facilities, increase production at our mines and develop new mines depends on our compliance with these conditions.
• |  | comply with the extensive laws and regulations that govern our activities, including our growth plans. Environmental legislation imposes very strict standards and controls on almost every aspect of our operations and the mines we plan to develop, and are becoming more stringent in Canada and the US. Examples of these controls include that:

| • |  | we must complete an environmental assessment before we can begin developing a new mine or make any significant change to a plan that has already been approved
| • |  | we increasingly need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an environmental assessment or an extensive review of supporting information. The complexity of this process can be further compounded when regulatory approvals are required from multiple agencies.

We use significant management and financial resources to manage our regulatory risks.
Environmental risks
We have the safety, health and environmental risks associated with any mining and chemical processing company. All three of our business segments face unique risks associated with radiation.
Laws to protect the environment are becoming more stringent for members of the nuclear energy industry and have inter-jurisdictional aspects (both federal and provincial/state regimes are applicable). Once we have permanently stopped mining and processing activities, we are required to decommission the operating site to the satisfaction of the regulator. We have developed conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. As the site approaches or goes into decommissioning, regulators review our detailed decommissioning plan, and this can result in additional regulatory process, requirements, costs and financial assurances.
At the end of 2010, our estimate of total decommissioning and reclamation costs was $465 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $280 million at the end of 2010 (the present value of the $465 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.
54 cameco corporation

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We provide financial assurances for decommissioning and reclamation as letters of credit to regulatory authorities, as required. We had a total of $549 million in letters of credit supporting our reclamation liabilities at the end of 2010. Since 2001, all of our North American operations have had letters of credit in place that provide financial assurance in line with our preliminary plans for decommissioning for the sites.
Some of the sites we own or operate have been under ongoing investigation and/or remediation and planning as a result of historic soil and groundwater conditions. For example, we are addressing issues related to historic soil and groundwater contamination at Port Hope and Rabbit Lake.
We use significant management and financial resources to manage our environmental risks.
We manage environmental risks through our safety, health, environment and quality (SHEQ) management system. Our SHEQ management system is centralized and managed at the corporate level, and we implement it corporately and at our operations level. Our chief executive officer is responsible for ensuring that our SHEQ management system is implemented. Our board’s safety, health and environment committee also oversees how we manage our environmental risks.
In 2010, we invested:

• |  | $76 million in environmental protection, monitoring and assessment programs, a decrease of 17% compared to 2009.
• |  | $34 million in health and safety programs, unchanged compared to 2009

In 2011, spending for these programs is expected to be similar to 2010.
Operational risks
Other operational risks and hazards include:

• |  | environmental damage
• |  | industrial and transportation accidents
• |  | labour shortages, disputes or strikes
• |  | cost increases for contracted or purchased materials, supplies and services
• |  | shortages of required materials and supplies
• |  | transportation disruptions
• |  | electrical power interruptions
• |  | equipment failures
• |  | non-compliance with laws and licences
• |  | catastrophic accidents
• |  | fires
• |  | blockades or other acts of social or political activism
• |  | natural phenomena, such as inclement weather conditions, floods and earthquakes
• |  | unusual, unexpected or adverse mining or geological conditions
• |  | underground floods
• |  | ground movement or cave ins
• |  | tailings pipeline or dam failures
• |  | technological failure of mining methods

We have insurance to cover some of these risks and hazards, but not all of them, and not to the full amount of losses or liabilities that could potentially arise.
2010 Annual financial review 55

#####

Uranium — production overview
Our production was 10% higher this year than it was in 2009 and 6% higher than our plan at the beginning of 2010. We had a number of successes at our mining operations in 2010.
At McArthur River/Key Lake:

• |  | We increased production by 5% over 2009.
• |  | We obtained approval for production flexibility, which allowed us to exceed our production target by 6%.

At Rabbit Lake:

• |  | We added mineral reserves, extending the estimated mine life by two years to 2017.

At Inkai:

• |  | We continued to ramp up production and exceeded our 2009 production by 136%.
• |  | Production was 13% higher than our plan at the beginning of the year due to the completion of the processing facilities and a stable acid supply.

Uranium production

|  | Three months ended |  |  | Year ended |  |  |  |
Cameco’s share |  | December 31 |  |  | December 31 |  |  |  |
(million lbs U3O8) |  | 2010 |  |  | 2009 |  |  | 2010 |  |  | 2009 |  |  | 2010 plan |
McArthur River/Key Lake |  |  | 4.0 |  |  |  | 4.0 |  |  |  | 13.9 |  |  |  | 13.3 |  |  |  | 13.1 |
Rabbit Lake |  |  | 1.3 |  |  |  | 1.4 |  |  |  | 3.8 |  |  |  | 3.8 |  |  |  | 3.6 |
Smith Ranch-Highland |  |  | 0.4 |  |  |  | 0.5 |  |  |  | 1.8 |  |  |  | 1.8 |  |  |  | 1.8 |
Crow Butte |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.7 |  |  |  | 0.8 |  |  |  | 0.7 |
Inkai |  |  | 0.5 |  |  |  | 0.6 |  |  |  | 2.6 |  |  |  | 1.1 |  |  |  | 2.3 |
Total |  |  | 6.4 |  |  |  | 6.7 |  |  |  | 22.8 |  |  |  | 20.8 |  |  |  | 21.5 | 1

1 |  | We updated our 2010 plan in our Q3 MD&A to 22 million pounds.

Outlook
We have geographically diversified sources of production. We expect to produce about 125 million pounds of U3O8 over the next five years from the properties listed below. Our strategy is to double our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and projects under evaluation. These sources are discussed in the following section.
Cameco’s share of production — annual forecast to 2015

Current forecast |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
(million lbs U3O8) |  | 2011 |  |  | 2012 |  |  | 2013 |  |  | 2014 |  |  | 2015 |
McArthur River/Key Lake |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |
Rabbit Lake |  |  | 3.6 |  |  |  | 3.6 |  |  |  | 3.6 |  |  |  | 3.6 |  |  |  | 3.6 |
US ISR |  |  | 2.5 |  |  |  | 3.1 |  |  |  | 3.1 |  |  |  | 3.7 |  |  |  | 3.8 |
Inkai |  |  | 2.7 |  |  |  | 3.1 |  |  |  | 3.1 |  |  |  | 3.1 |  |  |  | 3.1 |
Cigar Lake |  |  | — |  |  |  | — |  |  |  | 1.0 |  |  |  | 2.0 |  |  |  | 5.6 |
Total |  |  | 21.9 |  |  |  | 22.9 |  |  |  | 23.9 |  |  |  | 25.5 |  |  |  | 29.2 |

In 2013, production at McArthur River may be lower as we transition to mining upper zone 4.
In 2010, Inkai received approval in principle to produce at 3.9 million pounds per year (100% basis) and is seeking final approval through an amendment to the resource use contract.
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Our 2011 and future annual production targets assume Inkai receives the government approvals and support of our partner, Kazatomprom. More specifically, it must:

• |  | obtain final approval to produce at an annual rate of 3.9 million pounds (our share 2.3 million pounds)
• |  | obtain the necessary permits and approvals to produce at an annual rate of 5.2 million pounds (our share 3.1 million pounds)
• |  | ramp up production to an annual rate of 5.2 million pounds this year

We expect Inkai to receive all of the necessary permits and approvals to meet its 2011 and future annual production targets and we anticipate it will be able to ramp up production as noted above.
There is no certainty, however, that Inkai will receive these permits or approvals or that it will be able to ramp up production this year. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2011 and future annual production targets.
This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.
Assumptions

• |  | we achieve our forecast production for each operation, which requires, among other things, that our mining plans succeed, processing plants are available and function as designed, we have sufficient tailings capacity and our reserve estimates are accurate
• |  | we obtain or maintain the necessary permits and approvals from government authorities
• |  | our production is not disrupted or reduced as a result of natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks

Material risks that could cause actual results to differ materially

• |  | we do not achieve forecast production levels for each operation because of a change in our mining plans, processing plants are not available or do not function as designed, lack of tailings capacity or for other reasons
• |  | we cannot obtain or maintain necessary permits or government approvals
• |  | natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks disrupt or reduce our production

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Uranium — operating properties
McArthur River/Key Lake
McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the largest uranium mill in the world.
Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator.
McArthur River is one of our three material uranium properties.

Location |  | Saskatchewan, Canada
Ownership |  | 69.805% — McArthur River
|  | 83.33% — Key Lake
End product |  | U3O8
ISO certification |  | ISO 14001 certified
Deposit type |  | underground
Estimated reserves |  | 234.2 million pounds — proven and probable
(our share) |  |
Average reserve grade |  | U3O8 — 15.24%1
Estimated resources |  | 11.8 million pounds (measured and indicated)
(our share) |  | 104.8 million pounds (inferred)
Mining methods |  | currently: raiseboring
|  | under development: boxhole boring
Licensed capacity |  | mine and mill: 18.7 million pounds per year
|  | (can be exceeded — see Licensing below)
Total production 2000 to 2010 |  | 191.1 million pounds (McArthur River/Key Lake) (100% basis)
1983 to 2002 |  | 209.8 million pounds (Key Lake) (100% basis)
2010 production |  | 13.9 million pounds (our share)
2011 forecast production |  | 13.1 million pounds (our share)
Estimated decommissioning cost |  | $36.1 million — McArthur River
|  | $120.7 million — Key Lake

1 For more information on the average grade, please see the 2010 update that follows in this section — Change in Average Reserve Grades
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Background
We use a number of innovative methods and techniques to mine the McArthur River deposit:
Ground freezing
The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We use ground freezing to form an impermeable wall around the area being mined. This prevents water from entering the mine, and helps stabilize weak rock formations.
In 2009, we developed an innovative, cathedral-shaped freezewall around zone 2, panel 5, allowing us to develop tunnels above and below the orebody. We expect this innovation will allow us to continue using raisebore mining as the main mining method at McArthur River and improve production efficiencies as we transition to other areas of the mine (see Planning for the future — Zone 4 below).
Raisebore mining
Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River. It involves:

• |  | drilling a series of overlapping holes through the ore zone from a raisebore chamber in waste rock above the ore
• |  | collecting the broken ore at the bottom of the raises using line-of-sight remote-controlled scoop trams, and transporting it to a grinding circuit
• |  | filling each raisebore hole with concrete once it is complete
• |  | removing the equipment and filling the entire chamber with concrete when all the rows of raises in a chamber are complete
• |  | starting the process again with the next raisebore chamber

We have successfully used the raisebore mining method to extract about 190 million pounds (100% basis) since we began mining in 1999.
McArthur River currently has four zones with delineated mineral reserves (zones 1 to 4). Zones A and B are categorized as inferred mineral resources. Parts of zones 1, 2, 3 and 4 also have mineral resources.
Until this year, we have mined only zone 2 since the mine started production. Zone 2 is divided into four panels (panels 1, 2, 3 and 5). Until late 2009, all mine production was from panels 1, 2 and 3, and there are still limited
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reserves that we will extract from these panels in the next few years. Panel 5 represents the upper portion of zone 2, overlying a portion of the other panels.
We successfully transitioned to panel 5 last year, the first time development has been accomplished through the unconformity into the Athabasca sandstone.
We brought the lower mining area of zone 4 into production in the fourth quarter of 2010.
Boxhole boring
Given our success with the cathedral-shaped freezewall around zone 2, panel 5, the use of boxhole boring in our mine plan has been significantly narrowed in scope. We expect to be able to continue using raisebore mining as our main mining method for McArthur River.
Boxhole boring is similar to the raisebore method, but the drilling machine is located below the orebody, so development is not required above the orebody. This method is currently being used at only a few mines around the world, but has not been used for uranium mining.
Boxhole boring poses some technical challenges. We will continue to test this method in 2011; however, we expect it will only be used as a secondary method in areas where we determine raiseboring is not feasible. We may use it on a limited basis in 2013 to meet our production target.
2010 update
Production
Our share of production was 6% higher than our target of 13.1 million pounds U3O8, and a 5% increase over 2009. In 2009, we also exceeded our production target.
Our strong performance at both McArthur River and Key Lake allowed us to realize benefits under the production flexibility amendments to the McArthur River and Key Lake operating licences (see Licensing below).
New mining areas
Zone 2, panel 5 — We developed a second raisebore chamber. This is expected to improve production efficiency in the future.
Lower zone 4 — We completed the transition to this zone and began production during the fourth quarter.
Change in Average Reserve Grades
At McArthur River, average grade for our mineral reserves changed as follows:

• |  | for our proven reserves: in 2010 the average grade is 17.29%, up from 15.72% in 2009
• |  | for our probable reserves: in 2010 the average grade is 13.49%, down from 26.33% in 2009

As a consequence, the average grade for our proven and probable reserves in 2010 is 15.24%, down from 19.53% in 2009.
The addition of 260 thousand tonnes of ore to probable reserves resulted in the average grade decreasing in 2010. This increase of tonnes is due mostly to successful underground drilling and conversion of lower grade inferred resources to probable reserves. Our plan to use conventional blast-hole stoping in some areas also enabled us to convert lower grade resources to reserves. We do not expect this reduction in grade to have a material effect on operating costs. Please see our mineral reserves and resources section on page 84 for more information.
Mill revitalization
The Key Lake mill began operating in 1983. We are revitalizing the mill to ensure sustained reliable production and increase our uranium production capability. This year we focused on:

• |  | building the acid, steam and oxygen processing plants
• |  | securing our existing tailings capacity

Operational upgrades
The Key Lake revitalization plan includes upgrading circuits with new technology to simplify operations and improving environmental performance. As part of this plan, we are replacing the acid, steam and oxygen plants.
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This year we installed all structural steel and winterized the buildings. We installed all major equipment for the acid and steam plants, and are installing mechanical piping.
We expect to complete and commission all three plants in 2011.
Tailings capacity
We submitted a project description, the Key Lake extension project, to regulators to extend the lifespan of the Key Lake operation.
The project proposes to:

• |  | allow continued processing of ore from the McArthur River mine and other potential mine developments
• |  | increase long-term capacity of the Deilmann tailings management facility by allowing us to deposit tailings to a higher elevation
• |  | increase annual mill production capacity to 25 million pounds U3O8

Licensing
The CNSC approved an amendment to our operating licence for McArthur River, giving us flexibility in the annual licensed production limit, similar to that received at Key Lake last year. The McArthur River mine can produce up to 20.7 million pounds U3O8 (100% basis) per year as long as average annual production does not exceed 18.7 million pounds. If production is lower than 18.7 million pounds in any year, we can produce more in future years until we recover the shortfall. After taking advantage of this provision in 2009 and this year, we still have the opportunity to recover about 4 million pounds (100% basis) in past production shortfalls.
After the mill is revitalized, annual production will depend mainly on mine production. We are continuing to plan for annual production of 18.7 million pounds (100% basis) for the next few years.
Exploration
We initiated a multi-year project, the McArthur River extension, to advance the underground exploration drifts to the north and to the south of the current mining operations. We expect this work to further delineate zones A and B inferred mineral resources to the north, and mineral resources to the south.
We received regulatory approval to continue developing the north exploration drift towards zone A and zone B. Over the next two years, we will carry out underground exploration from this drift to expand our knowledge of the size and grade of the ore in this area.
The surface lease has been reinstated to its original size, which will allow us to optimize the location for future mine workings for ongoing approved activities. We expect a fourth shaft will be necessary for ventilation of ongoing operations and for the eventual development of zones to the north of current mining areas.
Labour relations
We reached a new four-year collective agreement with unionized employees at McArthur River and Key Lake. The agreement expires on December 31, 2013.
Planning for the future
Production
We expect our share of production to be 13.1 million pounds U3O8 in 2011 and will look for opportunities to take advantage of the production flexibility provision in our licences.
New mining zones
Zone 2, panel 5 — In 2011, we expect to develop a third raisebore chamber.
Zone 4 — In 2011, we will begin work to install the freezewall required to bring the upper mining area of zone 4 into production.
Our initial plan was to mine upper zone 4 using boxhole boring. We now expect, however, to use raisebore mining in this area by applying the ground freezing experience we gained in zone 2, panel 5. By using raisebore mining, we expect to significantly improve production efficiencies compared to boxhole boring.
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Tailings capacity
In 2011, we expect to:

• |  | complete the detailed design for the stabilization of the Deilmann tailings management facility pitwalls
• |  | start to relocate the infrastructure necessary to allow us to flatten the slope of the pitwalls
• |  | advance work on the environmental assessment for the Key Lake extension project

Exploration
In 2011, we will continue work on the McArthur River extension project, to advance the underground exploration drift to the north of the current mining areas. We will carry out further surface exploration drilling of zone B. We will begin work on a feasibility study for the zones north of our current mining areas.
Managing ongoing risks
Production at McArthur River/Key Lake poses many challenges: control of groundwater, weak rock formations, radiation protection, water inflow, mining method uncertainty and changes to productivity, mine transitioning, regulatory approvals, tailings capacity, reliability of facilities at Key Lake, surface and underground fires. Operational experience gained since the start of production has resulted in a significant reduction in risk.
Water inflow risk
The greatest risk is production interruption from water inflows. A 2003 water inflow resulted in a three-month suspension of production. We also had a small water inflow in 2008 that did not impact production.
The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs and a loss of mineral reserves.
We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

• |  | Ground freezing — Before mining, we drill freezeholes and freeze the ground to form an impermeable freezewall around the area being mined. Ground freezing reduces but does not eliminate the risk of water inflows.
• |  | Mine development — We carry out extensive grouting and careful placement of mine development away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk, and apply extensive additional technical and operating controls for all higher risk development.
• |  | Pumping capacity and treatment limits — Our standard for this project is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before beginning work on any new zone.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow.
Key Lake tailings capacity risk
Tailings from processing McArthur River ore are deposited in the Deilmann tailings management facility. At current production rates, the capacity of the Deilmann tailings management facility is five to six years, assuming we experience only minor losses in storage capacity due to sloughing from the pitwalls. Significant sloughing may constrain McArthur River production.
Sloughing of material from the pitwalls has occurred in the past and resulted in the loss of capacity. Technical studies show that stabilizing and reducing water levels in the pit enhances the stability of the pitwalls, thereby reducing the risk of pitwall sloughing. We doubled our dewatering treatment capacity, allowing us to stabilize the water level in the pit. The water level has been gradually reduced over the past two years.
In 2009, regulators approved our plan for the long-term stabilization of the Deilmann tailings management facility pitwalls. We are implementing the plan, and expect it will take approximately four years to complete the work.
We have also assessed options for long-term storage of tailings at Key Lake. We are proceeding with the environmental assessment to support an application for regulatory approval to deposit tailings in the Deilmann tailings management facility to a much higher level. This would provide us with enough tailings capacity to support many more years of mill production at Key Lake (see Tailings capacity above).
We also manage the risks listed on pages 54 and 55.
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Uranium — operating properties
Rabbit Lake
The Rabbit Lake operation, which opened in 1975, is the longest operating uranium production facility in North America, and the second largest uranium mill in the world.

Location |  | Saskatchewan, Canada
Ownership |  | 100%
End product |  | U3O8
ISO certification |  | ISO 14001 certified
Deposit type |  | underground
Estimated reserves |  | 25.5 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 0.76%
Estimated resources |  | 4.0 million pounds (indicated)
|  | 10.2 million pounds (inferred)
Mining method |  | vertical blast-hole stoping
Licensed capacity |  | mill: maximum 16.9 million pounds per year; currently 11 million
Total production 1975 to 2010 |  | 182.5 million pounds
2010 production |  | 3.8 million pounds
2011 forecast production |  | 3.6 million pounds
Estimated decommissioning cost |  | $105.2 million

2010 update
Production
Production this year was the same as in 2009.
Continued to upgrade the mill
We completed the first phase of upgrades at the acid plant, replacing the convertor and heat recovery equipment.
Worked to extend the mine life
We added mineral reserves, extending the estimated mine life by two years to 2017. We have completed surface exploration drilling near the mine and have found new mineralization referred to as the Powell zone. In 2012, we are planning to start an underground drilling program to further evaluate this mineralization.
We installed and commissioned a new exhaust air raise at the Eagle Point mine to support future activities in the northern part of the mine.
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Planning for the future
Production
We expect to produce 3.6 million pounds in 2011.
Milling
We expect to have sufficient tailings capacity to support milling of Eagle Point ore and a portion of the uranium solution from milling of Cigar Lake ore until mid-2016. We are planning to expand the existing tailings management facility to increase the tailings capacity by mid-2016 to support the extension of Rabbit Lake’s mine life, accommodate tailings from processing Cigar Lake uranium solution and provide a modest amount of additional tailings capacity for future processing opportunities. We need regulatory approval to proceed with any increase in capacity.
Exploration
We have extended our underground drilling reserve replacement program into 2011. We plan to test and evaluate areas east and northeast of the mine where we have had good results. Drilling will also continue on other parts of the property.
Reclamation
As part of our multi-year site-wide reclamation plan, we expect to spend $5.7 million in 2011 to reclaim facilities that are no longer in use.
Managing our risks
We manage the risks listed on pages 54 and 55.
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Uranium — operating properties
Smith Ranch-Highland
We operate Smith Ranch and Highland as a combined operation. Each has its own processing facility, but the Smith Ranch mill processes all the uranium. The Highland mill is currently idle.
Together, they form the largest uranium production facility in the United States.

Location |  | Wyoming, US
Ownership |  | 100%
End product |  | U3O8
ISO certification |  | ISO 14001 certified
Estimated reserves |  | 8.0 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 0.09%
Estimated resources |  | 22.5 million pounds (measured and indicated)
|  | 6.6 million pounds (inferred)
Mining method |  | in situ recovery (ISR)
Licensed capacity |  | mine: 2 million pounds per year
|  | mill: 4 million pounds per year including Highland mill
Total production 2002 to 2010 |  | 13.6 million pounds
2010 production |  | 1.8 million pounds
2011 forecast production |  | 1.8 million pounds
Estimated decommissioning cost |  | $111.5 million (US)

2010 update
Production
We met our production target for the year.
Upgrades
We finished building five deep disposal wells, and received authorization to operate four of the five wells. We expect to receive authorization to operate the fifth well in 2011. These are expected to help us operate and restore groundwater more efficiently.
Licensing
We submitted the licence renewal application to the regulators. We expect production to continue throughout the licence renewal process.
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Planning for the future
Production
We expect to produce 1.8 million pounds in 2011.
Reynolds Ranch expansion
We are seeking regulatory approval to proceed with our Reynolds Ranch expansion. The regulators have indicated they have a large volume of permits to process, therefore approval of our expansion is not expected to occur until late in 2011. We do not expect this delay to impact production.
Reserves and resources for Reynolds Ranch and Northwest Unit have been included in the totals for Smith Ranch-Highland reserves and resources. Both properties are adjacent to Smith Ranch-Highland.
Exploration
Additional exploration is underway with the objective of extending the mine life.
Managing our risks
The operating environment is becoming more complex as public interest and regulatory oversight increase. This may have a negative impact on our plans to increase production. We also manage the risks listed on pages 54 and 55.
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Uranium — operating properties
Crow Butte
Crow Butte was discovered in 1980 and began production in 1991. It is the first uranium mine in Nebraska, and is a significant contributor to the economy of northwest Nebraska.

Location |  | Nebraska, US
Ownership |  | 100%
End product |  | U3O8
ISO certification |  | ISO 14001 certified
Estimated reserves |  | 3.1 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 0.12%
Estimated resources |  | 11.2 million pounds (measured and indicated)
|  | 5.6 million pounds (inferred)
Mining method |  | in situ recovery (ISR)
Licensed capacity (mine and mill) |  | 1 million pounds per year
Total production 2002 to 2010 |  | 6.8 million pounds
2010 production |  | 0.7 million pounds
2011 forecast production |  | 0.7 million pounds
Estimated decommissioning cost |  | $35.2 million (US)

2010 update
Production
Production was in line with our forecast.
Licensing
The regulators continued their review of our applications to expand and re-license Crow Butte. They are planning public hearings in 2011 to consider our application. We expect production to continue throughout this licence renewal process.
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Planning for the future
Production
In 2011, we expect to produce 0.7 million pounds.
Managing our risks
The operating environment is becoming more complex as public interest and regulatory oversight increase. This may have a negative impact on our plans to increase production. We also manage the risks listed on pages 54 and 55.
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Uranium — operating properties
Inkai
Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is Joint Venture Inkai Limited Liability Partnership, which we jointly own (60%) with Kazatomprom (40%).
Inkai is one of our three material uranium properties.

Location |  | Central Kazakhstan
Ownership |  | 60%
End product |  | U3O8
ISO certification |  | BSI OHSAS 18001
|  | ISO 14001 certified
Estimated reserves (our share) |  | 72.9 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 0.07%
Estimated resources (Our share) |  | 18.3 million pounds (measured and indicated)
|  | 153.0 million pounds (inferred)
Mining method |  | in situ recovery (ISR)
Licensed capacity (mine and mill) |  | approved in principle: 3.9 million pounds per year
|  | (our share 2.3 million pounds per year)
|  | application: expect to submit for 5.2 million pounds per year
|  | (our share 3.1 million pounds per year)
2010 production |  | 2.6 million pounds (our share)
2011 forecast production |  | 2.7 million pounds (our share)
Estimated decommissioning cost |  | $7 million (US)

2010 update
Production
Our share of production this year was significantly higher due to successful wellfield performance and the processing of uranium in inventory at the end of 2009. Production was 13% higher than our plan at the beginning of the year due to the completion of the processing facilities and a stable acid supply.
Operations
Inkai received state commissioning approval for the main processing plant, allowing full processing of uranium concentrate on site. The plant operated at production rates very close to design capacity for several months due to strong wellfield performance.
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Project funding
We have a loan agreement with Inkai. As of December 31, 2010, there was:

• |  | $314 million (US) of principal outstanding on the loan.

• |  | a nominal amount of accrued interest and financing fees on the loan. In 2010, Inkai paid $49 million (US) in accrued interest and financing fees.

Inkai uses 100% of the cash available for distribution each year to pay accrued interest and financing fees. After those amounts are paid, Inkai then uses 80% of cash available for distribution each year to repay principal outstanding on the loan until it is repaid in full. The remaining 20% of cash available for distribution is paid to the owners.
We have also agreed to advance funds for Inkai’s work on block 3 until the feasibility study is complete.
Licensing
Inkai received approval in principle to:

• |  | increase annual production from blocks 1 and 2 to 3.9 million pounds of U3O8 (100% basis)

• |  | amend the block 3 licence to provide for a five-year appraisal period to carry out delineation drilling, mineral resource estimation, construction and operation of a test leach facility, and to complete a feasibility study

Inkai is in the process of finalizing the approval process with an amendment to its resource use contract.
Block 3 exploration
Inkai continued delineation drilling throughout the year and began planning for engineering and construction of a test leach facility.
Profits from block 3 production are to be shared on a 50:50 basis with our partner, instead of based on our ownership interests.
Uranium conversion project
Under the guidance of the memorandum of understanding signed in 2007 (see Doubling production below), we continued to work with our partner Kazatomprom to evaluate joint UF6 conversion opportunities. This work includes examining the feasibility of a number of options and locations based on strategic and economic considerations.
Planning for the future
Production
We expect our share of production to be 2.7 million pounds in 2011.
Block 3 exploration
In 2011 we expect to:

• |  | continue delineation drilling
• |  | begin developing infrastructure and engineering for the test leach facility

Doubling production
As part of our strategy to double production by 2018, we are working with our partner, Kazatomprom, to implement our 2007 non-binding memorandum of understanding. The memorandum:

• |  | targets future annual production capacity at 10.4 million pounds (our share 5.7 million pounds). While the existing project ownership would not change, our share of the additional capacity under the memorandum would be 50%.
• |  | contemplates studying the feasibility of constructing a uranium conversion facility as well as other potential collaborations in uranium conversion

To implement the increase, we need a binding agreement to finalize the terms of the memorandum, and various approvals from our partner and the government. We expect our ability to double annual uranium production at Inkai will be closely tied to the success of the uranium conversion project.
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Managing our risks
Regulatory approvals
In 2010, Inkai received approval in principle to produce 3.9 million pounds per year (100% basis) and is seeking final approval with an amendment to the resource use contract.
Our 2011 and future annual production targets and mineral reserve estimates assume Inkai receives the necessary government approvals and the support of our partner, Kazatomprom. More specifically, Inkai must:

• |  | obtain final approval to produce at an annual rate of 3.9 million pounds (our share 2.3 million pounds)

• |  | obtain the necessary permits and approvals to produce at an annual rate of 5.2 million pounds (our share 3.1 million pounds)

• |  | ramp up production to an annual rate of 5.2 million pounds this year

We expect Inkai to receive all of the necessary permits and approvals to meet its 2011 and future annual production targets and we anticipate it will be able to ramp up production as noted above.
There is no certainty, however, Inkai will receive these permits or approvals or that it will be able to ramp up production this year. If Inkai does not, or if the permits and approvals are delayed, then Inkai may be unable to achieve its 2011 and future annual production targets and we may have to recategorize some of Inkai’s mineral reserves as resources.
Taxes
A new tax code became law in Kazakhstan on January 1, 2009, and the resource use contract was amended to adopt it. We do not expect the new tax code to have a material impact at this time, but the elimination of tax stabilization under the new tax code could be material in the future. Under the new tax code, Inkai’s corporate income tax rate is 20% and the rate used to calculate the mineral extraction tax on uranium is 22%. See our annual information form for an overview of the changes brought about by the new tax code.
Supply of sulphuric acid
The supply of sulphuric acid has not been an issue for Inkai this year. However, given the importance of sulphuric acid to Inkai’s mining operations, we continue to closely monitor its availability. Our production may be less than forecast if there is a shortage.
Political risk
Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our Inkai investment, and our plans to increase production, are subject to the risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal, and fiscal instability. Kazakh laws and regulations are still developing and their application can be difficult to predict. To maintain and increase Inkai production, we need ongoing support, agreement and co-operation from our partner and the government.
The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Subsoil Use Law dated June 24, 2010. It replaces the Law on the Subsoil and Subsoil Use, dated January 27, 1996.
In general, Inkai’s licences are governed by the version of the subsoil law that was in effect when the licences were issued in April 1999, and new legislation applies to Inkai only if it does not worsen Inkai’s position. Changes to legislation related to national security, among other criteria, however, are exempt from the stabilization clause in the resource use contract. The Kazakh government interprets the national security exemption broadly.
With the new subsoil law, the government continues to weaken its stabilization guarantee. The government is broadly applying the national security exception to encompass security over strategic national resources.
The resource use contract contains significantly broader stabilization provisions than the new subsoil law, and these contract provisions currently apply to us.
To date, the new subsoil law has not had a significant impact on Inkai. We continue to assess the impact. See our annual information form for an overview of this change in law.
We also manage the risks listed on pages 54 and 55.
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Uranium — development project
Cigar Lake
Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner, and the mine operator, and expect the operation to use available capacity at our Rabbit Lake mill.
Cigar Lake, which is being developed, is one of our three material uranium properties.

Location |  | Saskatchewan, Canada
Ownership |  | 50.025%
End product |  | U3O8
Deposit type |  | underground
Estimated reserves (our share) |  | 104.7 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 17.04%
Estimated resources (our share) |  | 0.6 million pounds (measured and indicated)
|  | 66.8 million pounds (inferred)
Mining method |  | jet boring
Target production date |  | mid-2013
Target annual production (our share) |  | 9 million pounds after rampup
Estimated decommissioning cost |  | $27.7 million (to the end of construction)

Background
Development
We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows (two in 2006 and one in 2008). The first inflow flooded shaft 2, while it was under construction. The second inflow flooded the underground development and we began remediation late in 2006. In 2008, another inflow interrupted the dewatering of the underground development. We sealed the inflows and completed dewatering of shafts 1 and 2. In 2010, we continued remediation of the underground.
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Mining method
We will use a number of innovative methods and techniques to mine the Cigar Lake deposit:

• |  | Bulk freezing — The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We will freeze the ore zone and surrounding rock in the area to be mined, to prevent water from entering the mine and to help stabilize weak rock formations.
|  | In the past, bulk freezing has been done from underground. In 2010, however, we tested and began to implement an innovative surface freeze strategy, which we expect will provide the following benefits:

| • |  | reduce risk to the production schedule by advancing the availability of frozen ground and simplifying construction activities underground by moving some of the freezing infrastructure to surface
| • |  | move up to 10 million pounds forward in the production schedule
| • |  | improve mining costs and economics of the project

|  | We expect the capital cost for surface freezing will be $80 to $85 million (100% basis). Our plan is to use a hybrid freezing approach. We will use surface freezing to shorten the rampup period and utilize underground freezing for the longer term development of the mine.
• |  | Jet boring — After many years of test mining, we selected jet boring, a non-entry mining method, which we have developed and adapted specifically for this deposit. This method is new to the uranium mining industry. Overall, our initial test program was a success and met all initial objectives. This method, however, has not been proven at full production. As we ramp up production, there may be some technical challenges, which could affect our production plans.

We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.
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Milling
For approximately two years after mining begins, we expect all Cigar Lake ore to be processed at Areva’s McClean Lake JEB mill. After production ramps up to planned full capacity, the JEB mill is expected to ship a portion of the uranium solution from milling of Cigar Lake ore to the Rabbit Lake mill for processing.
2010 update
During the year, we:

• |  | completed dewatering the underground development
• |  | substantially completed cleanup, inspection, assessment and securing of the underground development areas
• |  | we prepared the ground around shaft 2 for freezing in preparation to resume shaft sinking
• |  | began implementing a surface freeze strategy we expect will shorten the rampup period for the project by bringing forward uranium production into the early years and improve mining costs and project economics
• |  | increased installed pumping capacity
• |  | completed backfilling of the 420 and 465 metre levels
• |  | resumed underground development in the south end of the mine
• |  | completed the 2010 surface drilling program

Costs
As of December 31, 2010, we had:

• |  | invested $492 million for our share of the construction costs to develop Cigar Lake
• |  | invested $262 million related to test mining and infrastructure development (prior to our 2005 development decision)
• |  | expensed $81 million in remediation expenses, including about $17 million in 2010

Exploration
We initiated a surface drilling program, which we expect will further delineate mineral resources to the east and west of current reserves.
Planning for the future
In 2011, we expect to:

• |  | finish restoring all remaining underground mine systems, infrastructure and underground development areas
• |  | complete the work to secure the mine
• |  | resume underground construction
• |  | complete the sinking of shaft 2
• |  | complete the surface ore loadout facilities
• |  | procure additional equipment for the jet boring system
• |  | work to obtain regulatory approval of the environmental assessment that will allow the release of treated water directly to Seru Bay of Waterbury Lake
• |  | work to obtain regulatory approval for the Cigar Lake mine plan

Technical report
In the technical report filed in 2010, we reported $912 million (100% basis) as our expected share of the total capital costs to complete the Cigar Lake project. This included completion of the underground development and surface construction, and completion of modifications at the Rabbit Lake and McClean Lake mills.
Later in 2011, we plan to issue a new technical report for Cigar Lake to reflect developments during 2010, including our decision to proceed with the surface freeze strategy. In the report, we will update our estimates including our capital cost estimate and production rampup schedule.
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Production
We are targeting initial production to begin in mid-2013.
The costs to complete Cigar Lake and our target dates for securing the mine and for initial production are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on the assumptions and risks listed here.
Assumptions

• |  | natural phenomena, an equipment failure or other causes do not result in a material delay or disruption in our plans
• |  | there are no additional water inflows
• |  | the seals or plugs used for previous water inflows do not fail
• |  | there are no labour disputes or shortages
• |  | we obtain contractors, equipment, operating parts, supplies, and regulatory permits and approvals when we need them
• |  | our mine plans are achieved, our processing plants are available and function as designed, sufficient tailings capacity is available and our mineral reserve estimates are accurate

Material risks

• |  | an unexpected geological, hydrological or underground condition, such as an additional water inflow, further delays our progress
• |  | we cannot obtain or maintain the necessary regulatory permits or approvals
• |  | natural phenomena, labour disputes, equipment failure, delay in obtaining the required contractors, equipment, operating parts or supplies, or other reasons cause a material delay or disruption in our plans
• |  | our mining plans change or do not succeed, our processing plants are not available or do not function as designed, sufficient tailings capacity is not available and our mineral reserve estimates are not accurate

Managing our risks
Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, water inflow, mining method uncertainty, regulatory approvals, tailings capacity, surface and underground fires and other mining-related challenges. To reduce this risk, we are applying our operational experience and the lessons we have learned about water inflows at McArthur River and Cigar Lake.
The greatest risk to development and production is from water inflows. The 2006 and 2008 water inflows were significant setbacks.
The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant delay in Cigar Lake’s remediation, development or production, a material increase in costs and a loss of mineral reserves. Although we are taking the following steps to mitigate the risks of water inflow, there can be no guarantee that these will be successful:
Bulk freezing
Two of the primary challenges in mining the deposit are control of groundwater and ground support. Bulk freezing reduces but does not eliminate the risk of water inflows.
Mine development
Our approach is to carry out extensive grouting and careful placement of mine development away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk, and apply extensive additional technical and operating controls for all higher risk development.
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Pumping capacity and treatment limits
We increased our pumping capacity this year to meet our standard for this project, which is to secure pumping capacity of at least one and a half times the estimated maximum inflow.
We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum inflow.
We also manage the risks listed on pages 54 and 55.
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Uranium — projects under evaluation
Kintyre
Kintyre, which we acquired with a partner in 2008, adds potential for low-cost production and diversifies our geographic reach and deposit types. We are the operator.

Location |  | Western Australia
Ownership |  | 70%
End product |  | U3O8
Deposit type |  | open pit

Background
In August 2008, we paid $346 million (US) to acquire a 70% interest in Kintyre.
2010 update
This year we:

• |  | began the process for negotiating a mine development agreement with the Martu, the native land title holders for this property

• |  | built a construction camp to support the prefeasibility assessment of the project

• |  | completed a delineation drilling program

• |  | carried out metallurgical testing to define the milling process

• |  | initiated mining and infrastructure studies for the prefeasibility study

• |  | initiated a hydrogeological drilling program to confirm process water supply

• |  | carried out environmental baseline studies

• |  | submitted the environmental referral document to initiate the environmental assessment process and submitted the environmental scoping document

• |  | trained and hired a significant number of Martu people

Planning for the future
Our plan for 2011 is to keep moving the project towards a production decision. We expect to:

• |  | generate a National Instrument 43-101 mineral resource estimate

• |  | complete a memorandum of understanding for a mine development agreement with the Martu

• |  | carry out further exploration drilling to test potential extensions of the deposit

• |  | submit an environmental review and management program

• |  | complete the prefeasibility study and decide whether to proceed to the feasibility stage

Managing the risks
To successfully develop this project, we need a positive feasibility study, regulatory approval and an agreement with the Martu. We also manage the risks listed on pages 54 and 55.

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Uranium — projects under evaluation
Millennium
Millennium is a uranium deposit in northern Saskatchewan that we expect will use the mill at Key Lake. We are the operator.

Location |  | Saskatchewan, Canada
Ownership |  | 42%
End product |  | U3O8
Deposit type |  | underground
Estimated resources |  | 21.4 million pounds (indicated)
(our share) |  | 4.3 million pounds (inferred)

Background
The Millennium deposit was discovered in 2000. The deposit was delineated through geophysical survey and drilling work between 2000 and 2007.
2010 update
This year we:

• |  | completed our mine design with positive results achieved

• |  | continued work on the environmental assessment, preparing us to submit the environmental impact statement late in 2011 or early 2012

Planning for the future
Our plan for 2011 is to keep moving the project towards a production decision. We expect to:

• |  | complete the environmental assessment work and submit the environmental impact study to the regulators late in 2011 or early 2012

• |  | undertake additional studies and design work required to advance the project

Managing the risks
The English River First Nation (ERFN) has selected surface lands covering the Millennium deposit in a claim for Treaty Land Entitlement (TLE). The Saskatchewan government has rejected the selection, but the ERFN has challenged the government’s decision in the courts. The TLE process does not affect our mineral rights, but it could have an impact on the surface rights and benefits we ultimately negotiate as part of the development of this deposit.
We also manage the risks listed on pages 54 and 55.

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Uranium — exploration
Exploration is key to ensuring our long-term growth, and since 2002 we have more than tripled our annual investment.
2010 update
Brownfield exploration
Brownfield exploration is uranium exploration near our existing operations, and includes expenses for advanced exploration projects where uranium mineralization is being defined.
We spent $11 million in five brownfield exploration projects, and $48 million for resource delineation at Kintyre and Inkai block 3.
Regional exploration
We spent about $37 million in regional exploration programs (including support costs). Saskatchewan was the largest region, followed by Australia, northern Canada, Asia, and South America.
We own a 30% interest in the Phoenix deposit, part of the Wheeler River joint venture in Saskatchewan, operated by 60% owner Denison Mines. In 2010, an initial estimate of 36 million pounds indicated mineral resources (100%) for zone A, the largest of four known mineralized zones of the deposit, was announced.
Plans for 2011
We plan to spend approximately $90 million on uranium exploration in 2011 as part of our long-term strategy. This includes activities at our projects under evaluation.
Brownfield exploration
About $9 million will be spent on five brownfield exploration projects in the Athabasca Basin and Australia. Our expenditures on projects under evaluation are expected to total $22 million, with the largest amounts spent on Kintyre and on further delineation of the Inkai block 3 resource.
Regional exploration
We expect to spend about $60 million on 54 projects worldwide, the majority of which are at drill target stage. Among the larger expenditures planned are $8 million on two adjacent projects in Nunavut, $5 million directed towards new targets in South Australia and Argentina, and a $4 million expenditure on the Wellington Range project in Northern Territory, Australia.

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Fuel services — refining
Blind River refinery
Blind River is the world’s largest commercial uranium refinery, refining U3O8 from mines around the world into UO3.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | UO3
ISO certification |  | ISO 14001 certified
Licensed capacity |  | approved: 18 million kgU as UO3 per year
|  | application: 24 million kgU as UO3 per year
Estimated decommissioning cost |  | $36 million

2010 update
Production
Our Blind River refinery produced 12.4 million kgU of UO3, in line with our forecast. This ensured that SFL maintained its contractual inventories and Port Hope met its production requirements.
Managing our risks
We manage the risks listed on pages 54 and 55.

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Fuel services — conversion and fuel manufacturing
We control about 35% of western world UF6 capacity.
Port Hope conversion services
Port Hope is the only uranium conversion facility in Canada, and one of only four in the western world. It is the only commercial supplier of UO2 for Canadian-made Candu reactors.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | UF6, UO2
ISO certification |  | ISO 14001 certified
Licensed capacity |  | 12.5 million kgU as UF6 per year
|  | 2.8 million kgU as UO2 per year
Estimated decommissioning cost |  | $96 million

Cameco Fuel Manufacturing Inc. (CFM)
CFM produces fuel bundles and reactor components for Candu reactors.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | Candu fuel bundles and components
ISO certification |  | ISO 9001 certified
Licensed capacity |  | 1.2 million kgU as UO2 as finished bundles
Estimated decommissioning cost |  | $18 million

Springfields Fuels Ltd. (SFL)
SFL is the newest conversion facility in the world. We contract almost all of its capacity through a toll-processing agreement to 2016.

Location |  | Lancashire, UK
Toll-processing agreement |  | annual conversion of 5 million kgU as UO3 to UF6
Licensed capacity |  | 6.0 million kgU as UF6 per year

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2010 update
Production
Fuel services production was 15.4 million kgU in 2010, in line with our target of 15 million to 16 million kgU. Production was 25% higher than in 2009 due to the routine operation of the Port Hope UF6 plant, which did not operate for most of the first half of 2009.
Port Hope conversion facility cleanup and modernization (Vision 2010)
We submitted the draft environmental impact statement for review by the regulators in December.
Collective agreement
Unionized employees at the Port Hope conversion facility voted to accept a new, three-year collective agreement. The agreement expires June 30, 2013.
Community outreach
We continued to strengthen our community outreach program in Port Hope by:

• |  | holding a series of community forums

• |  | making presentations to municipal council

• |  | reaching out using community newsletters, newspaper advertising, public displays, open houses and a website dedicated to the Port Hope community

Public opinion research shows we have a strong level of local support.
Planning for the future
Production
We expect total production to be between 15 million and 16 million kgU in 2011.
Port Hope conversion facility cleanup and modernization (Vision 2010)
In 2011, we expect to:

• |  | continue with the environmental assessment process for this project

• |  | finalize the environmental impact statement

Managing our risks
We manage the risks listed on pages 54 and 55.

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Electricity
Bruce Power Limited Partnership (BPLP)
BPLP leases and operates four Candu nuclear reactors that have the capacity to provide about 15% of Ontario’s electricity.

Location |  | Ontario, Canada
Ownership |  | 31.6%
ISO certification |  | ISO 14001 certified
Expected reactor life |  | 2018 to 2021
Term of lease |  | 2018 — right to extend for up to 25 years
Generation capacity |  | 3,260 MW

Background
We are the fuel procurement manager for BPLP’s four nuclear reactors and for Bruce A Limited Partnership’s (BALP) two operating reactors.
We provide 100% of BPLP’s uranium concentrates and have agreed to supply BALP with the majority of its future uranium concentrates. Sales to BPLP and BALP are also a substantial portion of our fuel manufacturing business and an important part of our UO2 business.
2010 update
Output
BPLP’s capacity factor was 91%.
Collective agreements
The collective agreements with the Power Workers’ Union and the Society of Energy Professionals expired in December. BPLP has reached a tentative agreement with the Power Workers’ Union and discussions with the Society are underway.
Planning for the future
Output
We expect the capacity factor to be 89% in 2011 and actual output to be about 2% lower than 2010.
Managing our risks
BPLP manages the unique risks associated with operating Candu reactors. The amount of electricity generated, and the cost of that generation, could vary materially from forecast if planned outages are significantly longer than planned, or there are many unplanned outages, either for maintenance, regulatory requirements, equipment malfunction or due to other causes.
BPLP also manages the risks listed on pages 54 and 55.

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Mineral reserves and resources
Our mineral reserves and resources are the foundation of our company and fundamental to our success.
We have interests in a number of uranium properties. The tables in this section show our estimates of the reserves, measured and indicated resources and inferred resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River and Inkai, which are being mined, and Cigar Lake, which is being developed.
We estimate and disclose mineral reserves and resources in five categories, using the definitions adopted by the Canadian Institute of Mining, Metallurgy and Petroleum, and in compliance with Canadian National Instrument 43-101 — Standards of Disclosure for Mineral Projects (NI 43-101), developed by the Canadian Securities Administrators. You can find out more about these categories at www.cim.org.
About mineral resources
Mineral resources do not have demonstrated economic viability, but have reasonable prospects for economic extraction. They fall into three categories: measured, indicated and inferred. Our reported mineral resources are exclusive of mineral reserves.

• |  | Measured and indicated mineral resources are sufficiently well defined that we can estimate them with enough confidence to apply technical and economic parameters and evaluate the economic viability of the deposit.

• |  | measured resources: we can confirm geological and grade continuity to carry out production planning.

• |  | indicated resources: we can reasonably assume geological and grade continuity to carry out mine planning.

• |  | Inferred mineral resources are estimated using limited information. We do not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource as a result of continued exploration.

About mineral reserves
Mineral reserves are measured and indicated mineral resources that can be mined economically at the time of reporting. They fall into two categories:

• |  | proven reserves: economic extraction of measured resources is demonstrated by at least a preliminary feasibility study

• |  | probable reserves: economic extraction of measured and/or indicated resources is demonstrated by at least a preliminary feasibility study

We use current geological models, an average uranium price of $56.50 (US) per pound U3O8, and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.
Changes this year
Our share of proven and probable mineral reserves went from 479 million pounds U3O8 at the end of 2009 to 476 million pounds at the end of 2010. The change was mostly the result of:

• |  | mining and milling activities, which used 24 million pounds

• |  | conversion of mineral resources to reserves from drilling and mine design updates at McArthur River, Rabbit Lake and Smith Ranch-Highland

• |  | conversion of mineral reserves to resources at Inkai due to the production ramp up schedule and increased leaching recovery applied to a limited annual production rate

Measured and indicated mineral resources increased from 140 million pounds U3O8 at the end of 2009 to 142 million pounds at the end of 2010. The change was mostly the result of:

• |  | addition of mineral resources at the new Phoenix deposit

• |  | conversion of mineral resources to reserves at McArthur River and Rabbit Lake

• |  | conversion of mineral reserves to resources at Inkai

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At the end of 2010, our share of inferred mineral resources was nearly 357 million pounds U3O8 — a net gain of 3 million pounds, which came mostly from the new Powell zone at Rabbit Lake and drilling and new mining plans at McArthur River zone 4 south.
Qualified persons
The technical and scientific information discussed in this MD&A, including mineral reserve and resource estimates, for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) were prepared by, or under the supervision of, individuals who are qualified persons for the purposes of NI 43-101:
McArthur River/Key Lake
• Alain G. Mainville, director, mineral resources management, Cameco
• David Bronkhorst, vice-president, Saskatchewan mining south, Cameco
• Greg Murdock, technical superintendent, McArthur River, Cameco
• Les Yesnik, general manager, Key Lake, Cameco
• Lorne D. Schwartz, chief metallurgist, major projects —technical services, Cameco
Cigar Lake

• |  | Alain G. Mainville, director, mineral resources management, Cameco
• |  | C. Scott Bishop, principal mine engineer, major projects — technical services, Cameco
• |  | Grant J.H. Goddard, vice-president, Saskatchewan mining north, Cameco
• |  | Lorne D. Schwartz, chief metallurgist, major projects — technical services, Cameco

Inkai

• |  | Alain G. Mainville, director, mineral resources management, Cameco
• |  | Charles J. Foldenauer, operations director, JV Inkai

Important information about mineral reserve and resource estimates
Although we have carefully prepared and verified the mineral reserve and resource figures in this document, the figures are estimates, based in part on forward-looking information.
Estimates are based on our knowledge, mining experience, analysis of drilling results, the quality of available data and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions including:

• |  | geological interpretation

• |  | extraction plans

• |  | commodity prices

• |  | recovery rates

• |  | operating and capital costs

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 1 for information about forward-looking information.
Please see our mineral reserves and resources section of our annual information form for the specific assumptions, parameters and methods used for McArthur River, Inkai and Cigar Lake mineral reserve and resource estimates.
Important information for US investors
While the terms measured, indicated and inferred mineral resources are recognized and required by Canadian securities regulatory authorities, the US Securities and Exchange Commission (SEC) does not recognize them. Under US standards, mineralization may not be classified as a ‘reserve’ unless it has been determined at the time of reporting that the mineralization could be economically and legally produced or extracted. US investors should not assume that:

• |  | any or all of a measured or indicated mineral resource will ever be converted into proven or probable mineral reserves

• |  | any or all of an inferred mineral resource exists or is economically or legally mineable, or will ever be upgraded to a higher category. Under Canadian securities regulations, estimates of inferred resources may not form the basis of

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feasibility or prefeasibility studies. Inferred resources have a great amount of uncertainty as to their existence and economic and legal feasibility.
The requirements of Canadian securities regulators for identification of ‘reserves’ are also not the same as those of the SEC, and mineral reserves reported by us in accordance with Canadian requirements may not qualify as reserves under SEC standards.
Other information concerning descriptions of mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for US domestic mining companies, including Industry Guide 7.

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Mineral reserves
As at December 31, 2010 (100% basis — only the second last column shows Cameco’s share)
Proven and probable (tonnes in thousands; pounds in millions)

|  |  |  |  |  |  |  | Proven |  |  |  |  |  |  |  |  |  |  | Probable |  |  |  |  |  |  |  |  |  |  | Total mineral reserves |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Cameco’s |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | share of |  |  | Estimated |
|  |  |  |  |  |  |  | Grade |  |  | Content |  |  |  |  |  |  | Grade |  |  | Content |  |  |  |  |  |  | Grade |  |  | Content |  |  | content |  |  | metallurgical |
Property |  | Mining method |  | Tonnes |  |  | %U3O8 |  |  | (lbs U3O8) |  |  | Tonnes |  |  | %U3O8 |  |  | (lbs U3O8) |  |  | Tonnes |  |  | %U3O8 |  |  | (lbs U3O8) |  |  | (lbs U3O8) |  |  | recovery (%) |
McArthur River |  | underground |  |  | 458.5 |  |  |  | 17.29 |  |  |  | 174.8 |  |  |  | 540.2 |  |  |  | 13.49 |  |  |  | 160.7 |  |  |  | 998.7 |  |  |  | 15.24 |  |  |  | 335.5 |  |  |  | 234.2 |  |  |  | 98.7 |
Cigar Lake |  | underground |  |  | 130.5 |  |  |  | 25.62 |  |  |  | 73.7 |  |  |  | 426.8 |  |  |  | 14.41 |  |  |  | 135.6 |  |  |  | 557.3 |  |  |  | 17.04 |  |  |  | 209.3 |  |  |  | 104.7 |  |  |  | 98.5 |
Rabbit Lake |  | underground |  |  | 39.6 |  |  |  | 0.62 |  |  |  | 0.5 |  |  |  | 1,478.1 |  |  |  | 0.77 |  |  |  | 25.0 |  |  |  | 1,517.7 |  |  |  | 0.76 |  |  |  | 25.5 |  |  |  | 25.5 |  |  |  | 96.7 |
Key Lake |  | open pit |  |  | 61.9 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 61.9 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 98.7 |
Inkai |  | ISR |  |  | 4,817.2 |  |  |  | 0.08 |  |  |  | 8.9 |  |  |  | 75,810.0 |  |  |  | 0.07 |  |  |  | 112.7 |  |  |  | 80,627.2 |  |  |  | 0.07 |  |  |  | 121.6 |  |  |  | 72.9 |  |  |  | 85.0 |
Gas Hills-Peach |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 6,403.8 |  |  |  | 0.13 |  |  |  | 19.0 |  |  |  | 6,403.8 |  |  |  | 0.13 |  |  |  | 19.0 |  |  |  | 19.0 |  |  |  | 72.0 |
North Butte-Brown Ranch |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,803.2 |  |  |  | 0.10 |  |  |  | 8.2 |  |  |  | 3,803.2 |  |  |  | 0.10 |  |  |  | 8.2 |  |  |  | 8.2 |  |  |  | 80.0 |
Smith Ranch-Highland |  | ISR |  |  | 1,243.4 |  |  |  | 0.11 |  |  |  | 3.1 |  |  |  | 2,707.7 |  |  |  | 0.08 |  |  |  | 4.9 |  |  |  | 3,951.1 |  |  |  | 0.09 |  |  |  | 8.0 |  |  |  | 8.0 |  |  |  | 80.0 |
Crow Butte |  | ISR |  |  | 922.2 |  |  |  | 0.11 |  |  |  | 2.3 |  |  |  | 282.2 |  |  |  | 0.13 |  |  |  | 0.8 |  |  |  | 1,204.4 |  |  |  | 0.12 |  |  |  | 3.1 |  |  |  | 3.1 |  |  |  | 85.0 |
Total |  |  |  |  | 7,673.3 |  |  |  | — |  |  |  | 264.0 |  |  |  | 91,452.0 |  |  |  | — |  |  |  | 466.9 |  |  |  | 99,125.3 |  |  |  | — |  |  |  | 730.9 |  |  |  | 476.2 |  |  |  |  |

Notes
See page 60 for a discussion of the change in the average ore grade for mineral reserves at McArthur River.
ISR — in situ recovery
Estimates in the table above:

• |  | use an average uranium price of $56.50 (US)/lb U3O8

• |  | are based on the average exchange rate at December 31, 2010 ($1.00 US=$0.99 Cdn)

Totals may not add up due to rounding.
Except for the possible Inkai permitting issue referred to below, we do not expect these mineral reserve estimates to be materially affected by environmental, permitting, legal, taxation, socio-economic, political or marketing issues.
Metallurgical recovery
We report mineral reserves as the quantity of contained ore supporting our mining plans, and include an estimate of the metallurgical recovery for each uranium property. Metallurgical recovery is an estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process, and is calculated by multiplying quantity of contained metal (content) by the estimated metallurgical recovery percentage. Our share of uranium in the table above is before accounting for estimated metallurgical recovery.
Estimates for Inkai
In 2010, Inkai received approval in principle to produce 3.9 million pounds per year (100% basis) and is seeking final approval with an amendment to the resource use contract.
Our 2011 and future annual production targets and mineral reserve estimates assume Inkai receives the necessary government approvals and the support of our partner, Kazatomprom. More specifically, Inkai must:

• |  | obtain final approval to produce at an annual rate of 3.9 million pounds (our share 2.3 million pounds)

• |  | obtain the necessary permits and approvals to produce at an annual rate of 5.2 million pounds (our share 3.1 million pounds)

• |  | ramp up production to an annual rate of 5.2 million pounds this year

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We expect Inkai to receive all of the necessary permits and approvals to meet its 2011 and future annual production targets and we anticipate it will be able to ramp up production as noted above.
There is no certainty, however, Inkai will receive these permits or approvals or that it will be able to ramp up production this year. If Inkai does not, or if the permits and approvals are delayed, then Inkai may be unable to achieve its 2011 and future annual production targets and we may have to re-categorize some of Inkai’s mineral reserves as resources.

88 cameco corporation |  |

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Mineral resources
As at December 31, 2010 (100% — only the last column shows Cameco’s share)
Measured and indicated (tonnes in thousands; pounds in millions)

|  |  |  | Measured |  |  | Indicated |  |  | Total measured and indicated |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Cameco’s |
|  | Mining |  |  |  |  |  | Grade |  |  | Content |  |  |  |  |  |  | Grade |  |  | Content |  |  |  |  |  |  | Grade |  |  | Content |  |  | share |
Property |  | method |  | Tonnes |  |  | % U3O8 |  |  | (lbs U3O8) |  |  | Tonnes |  |  | % U3O8 |  |  | (lbs U3O8) |  |  | Tonnes |  |  | % U3O8 |  |  | (lbs U3O8) |  |  | (lbs U3O8) |
McArthur River |  | underground |  |  | 85.9 |  |  |  | 6.28 |  |  |  | 11.9 |  |  |  | 22.2 |  |  |  | 10.23 |  |  |  | 5.0 |  |  |  | 108.1 |  |  |  | 7.09 |  |  |  | 16.9 |  |  |  | 11.8 |
Cigar Lake |  | underground |  |  | 8.4 |  |  |  | 2.07 |  |  |  | 0.4 |  |  |  | 15.6 |  |  |  | 2.35 |  |  |  | 0.8 |  |  |  | 24.0 |  |  |  | 2.27 |  |  |  | 1.2 |  |  |  | 0.6 |
Rabbit Lake |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 348.0 |  |  |  | 0.52 |  |  |  | 4.0 |  |  |  | 348.0 |  |  |  | 0.52 |  |  |  | 4.0 |  |  |  | 4.0 |
Dawn Lake |  | open pit, underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 347.0 |  |  |  | 1.69 |  |  |  | 12.9 |  |  |  | 347.0 |  |  |  | 1.69 |  |  |  | 12.9 |  |  |  | 7.4 |
Millennium |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 507.8 |  |  |  | 4.55 |  |  |  | 50.9 |  |  |  | 507.8 |  |  |  | 4.55 |  |  |  | 50.9 |  |  |  | 21.4 |
Phoenix |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 89.9 |  |  |  | 17.98 |  |  |  | 35.6 |  |  |  | 89.9 |  |  |  | 17.98 |  |  |  | 35.6 |  |  |  | 10.7 |
Tamarack |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 10.3 |
Inkai |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 18,386.3 |  |  |  | 0.08 |  |  |  | 30.5 |  |  |  | 18,386.3 |  |  |  | 0.08 |  |  |  | 30.5 |  |  |  | 18.3 |
Gas Hills-Peach |  | ISR |  |  | 1,964.2 |  |  |  | 0.08 |  |  |  | 3.4 |  |  |  | 1,418.2 |  |  |  | 0.07 |  |  |  | 2.3 |  |  |  | 3,382.4 |  |  |  | 0.08 |  |  |  | 5.7 |  |  |  | 5.7 |
North Butte-Brown Ranch |  | ISR |  |  | 762.1 |  |  |  | 0.08 |  |  |  | 1.4 |  |  |  | 4,012.0 |  |  |  | 0.07 |  |  |  | 6.0 |  |  |  | 4,774.1 |  |  |  | 0.07 |  |  |  | 7.4 |  |  |  | 7.4 |
Smith Ranch-Highland |  | ISR |  |  | 2,079.1 |  |  |  | 0.11 |  |  |  | 4.9 |  |  |  | 13,906.5 |  |  |  | 0.06 |  |  |  | 17.6 |  |  |  | 15,985.6 |  |  |  | 0.06 |  |  |  | 22.5 |  |  |  | 22.5 |
Crow Butte |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2,466.2 |  |  |  | 0.21 |  |  |  | 11.2 |  |  |  | 2,466.2 |  |  |  | 0.21 |  |  |  | 11.2 |  |  |  | 11.2 |
Ruby Ranch |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 4.1 |
Ruth |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,080.5 |  |  |  | 0.09 |  |  |  | 2.1 |  |  |  | 1,080.5 |  |  |  | 0.09 |  |  |  | 2.1 |  |  |  | 2.1 |
Shirley Basin |  | ISR |  |  | 89.2 |  |  |  | 0.16 |  |  |  | 0.3 |  |  |  | 1,638.2 |  |  |  | 0.11 |  |  |  | 4.1 |  |  |  | 1,727.4 |  |  |  | 0.12 |  |  |  | 4.4 |  |  |  | 4.4 |
Total |  |  |  |  | 4,988.9 |  |  |  | — |  |  |  | 22.3 |  |  |  | 46,637.5 |  |  |  | — |  |  |  | 205.0 |  |  |  | 51,626.4 |  |  |  | — |  |  |  | 227.3 |  |  |  | 141.9 |

Inferred (tonnes in thousands; pounds in millions)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Cameco’s |
|  | Mining |  |  |  |  |  | Grade |  |  | Content |  |  | share |
Property |  | method |  | Tonnes |  |  | % U3O8 |  |  | (lbs U3O8) |  |  | (lbs U3O8) |
McArthur River |  | underground |  |  | 506.1 |  |  |  | 13.46 |  |  |  | 150.2 |  |  |  | 104.8 |
Cigar Lake |  | underground |  |  | 480.4 |  |  |  | 12.61 |  |  |  | 133.5 |  |  |  | 66.8 |
Rabbit Lake |  | underground |  |  | 369.4 |  |  |  | 1.26 |  |  |  | 10.2 |  |  |  | 10.2 |
Millennium |  | underground |  |  | 217.8 |  |  |  | 2.12 |  |  |  | 10.2 |  |  |  | 4.3 |
Phoenix |  | underground |  |  | 23.8 |  |  |  | 7.27 |  |  |  | 3.8 |  |  |  | 1.1 |
Tamarack |  | underground |  |  | 45.6 |  |  |  | 1.02 |  |  |  | 1.0 |  |  |  | 0.6 |
Inkai |  | ISR |  |  | 254,696.0 |  |  |  | 0.05 |  |  |  | 255.1 |  |  |  | 153.0 |
Gas Hills-Peach |  | ISR |  |  | 861.5 |  |  |  | 0.07 |  |  |  | 1.3 |  |  |  | 1.3 |
North Butte-Brown Ranch |  | ISR |  |  | 640.6 |  |  |  | 0.06 |  |  |  | 0.9 |  |  |  | 0.9 |
Smith Ranch-Highland |  | ISR |  |  | 6,370.1 |  |  |  | 0.05 |  |  |  | 6.6 |  |  |  | 6.6 |
Crow Butte |  | ISR |  |  | 2,349.4 |  |  |  | 0.11 |  |  |  | 5.6 |  |  |  | 5.6 |
Ruby Ranch |  | ISR |  |  | 56.2 |  |  |  | 0.14 |  |  |  | 0.2 |  |  |  | 0.2 |
Ruth |  | ISR |  |  | 210.9 |  |  |  | 0.08 |  |  |  | 0.4 |  |  |  | 0.4 |
Shirley Basin |  | ISR |  |  | 508.0 |  |  |  | 0.10 |  |  |  | 1.1 |  |  |  | 1.1 |
Total |  |  |  |  | 267,335.8 |  |  |  | — |  |  |  | 580.1 |  |  |  | 356.9 |

Notes
ISR — in situ recovery
Mineral resources do not include amounts that have been identified as mineral reserves.
Mineral resources do not have demonstrated economic viability. Totals may not add up due to rounding.
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Additional information
Related party transactions
We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In 2010, we paid PACL $38 million for construction and contracting services (2009 — $30 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.
Critical accounting estimates
Because of the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report.
We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable. We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements.
Decommissioning and reclamation
We are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position.
Property, plant and equipment
We depreciate property, plant and equipment primarily using the unit of production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.
We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.
Taxes
When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation allowances, changes in tax laws and our expectations for future results.
We base our estimates of future income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record future income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.
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Controls and procedures
We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2010, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.
Management, including our chief executive officer and our chief financial officer, supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Management, including our chief executive officer and our chief financial officer, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2010. We have not made any change to our internal control over financial reporting during the 2010 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
New accounting pronouncements
International Financial Reporting Standards (IFRS)
The Accounting Standards Board requires Canadian publicly accountable enterprises to adopt IFRS effective January 1, 2011. Although IFRS has a conceptual framework that is similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosure.
We have developed a three-phase implementation plan in order to ensure compliance and a smooth transition.
Senior management and the board’s audit committee are actively involved in the process. A major public accounting firm has been engaged to provide technical accounting advice and project management guidance.
Phase 1: Preliminary study and diagnostic — complete
During this phase, we:

• |  | completed a high-level impact assessment
• |  | prioritized areas to evaluate in phase 2
• |  | developed a detailed plan for convergence and implementation
• |  | determined which information technology systems need to be modified to meet IFRS reporting requirements. We tested and implemented systems modifications by June 30, 2009.

Phase 2: Detailed component evaluation — complete
During this phase, we:

• |  | assessed the impact of the adoption of IFRS on our results of operations, financial position and financial statement disclosures
• |  | developed a detailed, systematic gap analysis of accounting and disclosure differences between Canadian GAAP and IFRS, which will help us make final decisions about accounting policies and our overall conversion strategy
• |  | specified all changes we needed to make to existing business processes

Phase 3: Embedding — in progress
During this final phase, we will:

• |  | carry out the changes to our business processes
• |  | receive the audit committee’s approval of our accounting policy changes
• |  | complete the training process for our audit committee, board members and staff

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• |  | communicate the impact of the IFRS transition to external stakeholders
• |  | collect the financial information we need to create our 2010 and 2011 financial statements under IFRS
• |  | receive the board’s approval of the new statements

Progress update
We evaluated key accounting policy alternatives and implementation throughout the year and have completed our analysis of the accounting effects of adopting IFRS. We have quantified the items in our January 1, 2010 opening balances and earnings for the three-month periods ended March 31, 2010, June 30, 2010 and September 30, 2010 under IFRS, subject to changes in IFRS standards or their interpretation. See Opening statement of financial position and interim period financial results under IFRS for more information about the most significant differences expected between our Canadian GAAP and IFRS balances.
Senior management and the audit committee have approved our IFRS accounting policies, but IFRS standards are evolving and are subject to change going forward. The International Accounting Standards Board (IASB) has several projects underway that could affect the differences between Canadian GAAP and IFRS. For example, we expect that the standards for consolidation, liabilities, discontinued operations, financial instruments, employee benefits and joint ventures could change in the near term, and that IFRS for income taxes may change at a later date. It is also possible that new guidance regarding accounting for borrowing costs may be issued. We have been monitoring and evaluating these changes and will continue to do so.
In the fourth quarter of 2010, we changed our choice in accounting policy relating to joint ventures. Previously, we had planned to use the equity method to account for our interests in jointly controlled enterprises. This choice was made based on the expectation that a new accounting standard requiring the use of the equity method for such joint venture interests would take effect in the near term. However, the anticipated standard has not been issued and we have opted to continue to proportionately account for all joint venture interests.
We currently expect IFRS will affect our consolidated financial statements in the following key areas:
Asset impairment
We use a two-step approach to test for impairment under Canadian GAAP:

• |  | We compare the carrying value of the asset with undiscounted future cash flows to see whether there is an impairment.
• |  | If there is an impairment, we measure it by comparing the carrying value of the asset with its fair value.

International Accounting Standard (IAS) 36, Impairment of Assets, takes a one-step approach:

• |  | Compare the carrying value of the asset with the higher of its fair value less costs to sell or its value in use.

The difference in accounting for asset impairment could lead to greater volatility in reported earnings in future periods. The value-in-use test under IFRS uses discounted future cash flows, increasing the likelihood of asset impairment compared to the test under Canadian GAAP, which uses undiscounted cash flow. IFRS also requires companies to reverse impairment losses (for everything except goodwill) if an impairment is reduced due to a change in circumstances. Canadian GAAP does not allow companies to reverse impairment losses. As at January 1, 2011, we have not recorded any impairment charges under Canadian GAAP. We have, however, under IFRS reversed portions of impairment charges previously recorded under Canadian GAAP. See Opening statement of financial position and interim period financial results under IFRS for more information.
Employee benefits
We amortize past service costs on a straight-line basis over the expected average remaining service life of the plan participants under Canadian GAAP.
IAS 19, Employee Benefits, requires companies to expense the past service cost component of defined benefit plans on an accelerated basis. Vested past service costs must be expensed immediately. Unvested past service costs must be recognized on a straight-line basis until the benefits vest. Companies will also recognize actuarial gains and losses directly in equity rather than through profit or loss.
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IFRS 1, First-Time Adoption of International Financial Reporting Standards, also allows companies to recognize all cumulative actuarial gains and losses in retained earnings at the transition date and we have done so.
Share-based payments
We measure cash-settled, share-based payments to employees based on the intrinsic value of the award under Canadian GAAP. IFRS 2, Share-Based Payments, requires companies to measure payments at the award’s fair value, both initially and at each reporting date.
We expect no material impact on our financial results due to this difference.
Provisions (including asset retirement obligations)
IAS 37, Provisions, Contingent Liabilities and Contingent Assets, requires companies to recognize a provision when:

• |  | there is a present obligation due to a past transaction or event
• |  | it is probable (i.e. more likely than not) that an outflow of resources will be required to settle the obligation, and
• |  | the obligation can be reliably estimated

Canadian GAAP uses the term ‘likely’ in its recognition criteria, which is a higher threshold than ‘probable’, so some contingent liabilities may be recognized under IFRS that were not recognized under Canadian GAAP.
IFRS also measures provisions differently. For example:

• |  | When there is a range of equally possible outcomes, IFRS uses the midpoint of the range as the best estimate, while Canadian GAAP uses the low end of the range.
• |  | Under IFRS, material provisions are discounted to their present value.

Joint ventures
We proportionately account for interests in jointly controlled enterprises, such as our interest in BPLP, under Canadian GAAP. The IASB has indicated that it expects to issue a new standard in 2011 that will replace IAS 31, Interests in Joint Ventures. It is considering Exposure Draft 9, Joint Arrangements (ED 9), which proposes that an entity recognize its interest in a joint controlled enterprise using the equity method. It is uncertain when the new standard will become effective. Until then, we have elected under the current IFRS standard to continue to use the proportionate consolidation method to account for our interests in jointly controlled enterprises.
Income taxes
Under Canadian GAAP, we cannot recognize deferred tax for a temporary difference that arises from intercompany transactions. We record the taxes we pay or recover in these transactions as an asset or liability, and then recognize them as a tax expense when the asset leaves the group or is otherwise used. IAS 12 requires entities to recognize deferred taxes for temporary differences that arise from intercompany transactions, and to recognize taxes paid or recovered in these transactions in the period incurred.
The IASB may address these differences in a fundamental review of income tax accounting at some time in the future, but this review is not likely to be soon.
Convertible debentures
Under Canadian GAAP, our convertible debentures, issued in 2003 and redeemed in 2008, were treated as a compound instrument with a debt and equity component. We measured the debt component at amortized cost using the effective interest rate method, and the equity component at the issue date using the residual method which does not recognize future changes in value.
We have concluded that under IFRS we cannot account for the convertible debentures as compound instruments under IAS 32. This does not change our accounting for the debt component, but we have concluded that the conversion feature is to be accounted for as a derivative. We are required to measure derivatives at fair value at each reporting date, recording changes in value in earnings. For purposes of our transition to IFRS, we have measured the fair value of the conversion feature as at the redemption date, and recorded an increase in share capital offset by a corresponding decrease in retained earnings.
Given the significant increase in value of the conversion option as a result of increases in the stock price of Cameco between the date of issuance and the date of redemption, we have recorded a $297 million reclassification between retained earnings and share capital.
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Exploration expenses
Under Canadian GAAP, we charge expenditures for geological exploration programs to earnings as incurred. We begin capitalizing exploration and development expenditures related to the project once the decision has been made to proceed to development.
IFRS 6, Exploration for and Evaluation of Mineral Resources, requires companies to either capitalize or expense costs incurred during the exploration and evaluation phase. Geological activities are considered exploration and evaluation between the time of obtaining the legal rights to explore a specific area and the completion of a commercially viable technical feasibility study. IFRS 6 requires entities to choose which expenditures are capitalized and which are expensed, and to apply the approach consistently.
On transition to IFRS, we will maintain our current accounting policy of expensing all costs relating to exploration and evaluation as they are incurred. As we do under Canadian GAAP, we will capitalize costs once we have determined that a property has economically recoverable reserves. No adjustments are required on transition to IFRS.
First-time adoption of IFRS
IFRS 1 generally requires an entity to apply IFRS retrospectively at the end of its first IFRS reporting period, but there are some mandatory exceptions and some optional exemptions.
We have analyzed the options available to us and have used the exemptions described in the table below. This is a summary of the most significant decisions relating to the transition to IFRS and IFRS 1 elections — it is not a complete list of decisions we were required or elected to make. We have completed our analysis and have made decisions about the accounting policies that are available. We have quantified the impacts of these differences on our consolidated financial statements under IFRS.

Business combinations |  | There is an option to apply IFRS 3, Business Combinations, retrospectively or prospectively.
|  | We have elected to apply IFRS 3 prospectively to all business combinations that occurred before the transition date, except as required under IFRS 1.
Fair value as deemed cost |  | There is an option to choose to use the fair value of an item of property, plant and equipment as deemed cost at the transition date or a previous revaluation under Canadian GAAP as deemed cost under IFRS.
|  | We have elected not to use fair value as deemed cost on transition. Instead, these items are reported at cost as determined under IFRS.
Share-based payments |  | There is an option to apply IFRS 2, Share-Based Payments, to all equity instruments granted on or before November 7, 2002, and to those granted after November 7, 2002 only if they had not vested by the transition date.
|  | We have elected to apply IFRS 2 to all equity instruments granted after November 7, 2002 that had not vested as of January 1, 2010, and to all liabilities arising from share-based payment transactions that existed at January 1, 2010.
Borrowing costs |  | There is an option to apply IAS 23, Borrowing Costs, retrospectively, using a date we specify, or to capitalize borrowing costs for all qualifying assets when capitalization begins on or after January 1, 2010.
|  | We have elected to apply IAS 23 prospectively. For all qualifying assets, we will expense the borrowing costs we were capitalizing before January 1, 2010, and capitalize the borrowing costs that take effect on or after that date.
Employee benefits |  | IAS 19, Employee Benefits, requires entities to defer or amortize certain actuarial gains and losses, subject to certain provisions (corridor approach), or to immediately recognize them in equity.
|  | We have elected to recognize cumulative actuarial gains and losses on benefit plans in retained earnings at the transition date.

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Differences in currency translation |  | IAS 21, The Effects of Changes in Foreign Exchange Rates, requires the retrospective calculation of currency translation differences from the date a subsidiary or associate was formed or acquired.
|  | IFRS 1 provides the option of resetting cumulative translation gains and losses to zero at the transition date.
|  | We have elected to reset all cumulative translation gains and losses to zero in retained earnings at the transition date.
Decommissioning liabilities |  | There is an option to apply International Financial Reporting Interpretations Committee 1 (IFRIC 1), Changes in Existing Decommissioning, Restoration and Similar Liabilities, retrospectively or prospectively.
|  | IFRIC 1 will require us to add or deduct a change in our obligations to dismantle, remove and restore items of property, plant and equipment from the cost of the asset it relates to. The adjusted amount is then depreciated prospectively over the asset’s remaining useful life.
|  | We have elected to adopt IFRIC 1 prospectively at the transition date.

Opening statement of financial position and interim period financial results under IFRS
The following tables include our statement of financial position under IFRS as at January 1, 2010 and our estimates of the most significant differences between our Canadian GAAP and IFRS earnings for the three-month periods ended March 31, 2010, June 30, 2010 and September 30, 2010. This information is based on our current views, assumptions and expectations. However, circumstances may arise, such as changes in IFRS standards or interpretations of existing IFRS standards, which could alter the information presented below.
The notes referenced in the tables are explained by the corresponding notes at the end of the tables.
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Opening statement of financial position

|  |  |  |  |  | Jan 1, 2010 |  |  |  |
|  |  |  |  |  | effect of |  |  |  |
($ millions) |  | Cdn GAAP |  |  | transition |  |  | IFRS |
Assets |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  |  | 1,101 |  |  |  | — |  |  |  | 1,101 |
Short-term investments |  |  | 203 |  |  |  | — |  |  |  | 203 |
Accounts receivable |  |  | 447 |  |  |  | 2 |  |  |  | 449 |
Inventories |  |  | 453 |  |  |  | (8 | ) |  |  | 445 |
Supplies and prepaid expenses |  |  | 169 |  |  |  | — |  |  |  | 169 |
Current portion of long-term receivables, investments and other |  |  | 155 |  |  |  | — |  |  |  | 155 |
|  |  | 2,528 |  |  |  | (6 | ) |  |  | 2,522 |
Property, plant and equipment (1, 2, 3, 10) |  |  | 4,068 |  |  |  | (351 | ) |  |  | 3,717 |
Intangible assets |  |  | 98 |  |  |  | — |  |  |  | 98 |
Long-term receivables, investments and other (4, 5, 6) |  |  | 667 |  |  |  | (291 | ) |  |  | 376 |
Investments in equity-accounted investees (4) |  |  | — |  |  |  | 222 |  |  |  | 222 |
Deferred tax assets (9) |  |  | 33 |  |  |  | (9 | ) |  |  | 24 |
Total assets |  |  | 7,394 |  |  |  | (435 | ) |  |  | 6,959 |
Liabilities and shareholders’ equity |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  |  | 503 |  |  |  | 2 |  |  |  | 505 |
Current tax liabilities |  |  | 31 |  |  |  | — |  |  |  | 31 |
Short-term debt |  |  | 77 |  |  |  | — |  |  |  | 77 |
Dividends payable |  |  | 24 |  |  |  | — |  |  |  | 24 |
Current portion of long-term debt |  |  | 12 |  |  |  | — |  |  |  | 12 |
Current portion of other liabilities |  |  | 29 |  |  |  | — |  |  |  | 29 |
Deferred tax liabilities (9) |  |  | 87 |  |  |  | (1 | ) |  |  | 86 |
|  |  | 763 |  |  |  | 1 |  |  |  | 764 |
Long-term debt |  |  | 953 |  |  |  | — |  |  |  | 953 |
Provision for reclamation |  |  | 258 |  |  |  | (258 | ) |  |  | — |
Provisions (2) |  |  | — |  |  |  | 315 |  |  |  | 315 |
Other liabilities (5, 6, 10) |  |  | 245 |  |  |  | 72 |  |  |  | 317 |
Deferred tax liabilities (9) |  |  | 167 |  |  |  | (146 | ) |  |  | 21 |
|  |  | 2,386 |  |  |  | (16 | ) |  |  | 2,370 |
Minority interest |  |  | 164 |  |  |  | (164 | ) |  |  | — |
Shareholders’ equity |  |  |  |  |  |  |  |  |  |  |  |
Share capital (8) |  |  | 1,512 |  |  |  | 297 |  |  |  | 1,809 |
Contributed surplus |  |  | 132 |  |  |  | — |  |  |  | 132 |
Retained earnings |  |  | 3,159 |  |  |  | (767 | ) |  |  | 2,392 |
Other components of equity (7) |  |  | 41 |  |  |  | 51 |  |  |  | 92 |
Total shareholders’ equity attributable to equity holders |  |  | 4,844 |  |  |  | (419 | ) |  |  | 4,425 |
Non-controlling interest |  |  | — |  |  |  | 164 |  |  |  | 164 |
Total shareholders’ equity |  |  | 4,844 |  |  |  | (255 | ) |  |  | 4,589 |
Total liabilities and shareholders’ equity |  |  | 7,394 |  |  |  | (435 | ) |  |  | 6,959 |

96 cameco corporation

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Interim period financial results

2010 changes in earnings |  | Three months ended |
($ millions) |  | March 31 |  |  | June 30 |  |  | Sept 30 |
Net earnings — Canadian GAAP |  |  | 142 |  |  |  | 68 |  |  |  | 98 |
Accounting differences |  |  |  |  |  |  |  |  |  |  |  |
Borrowing costs1 |  |  | (10 | ) |  |  | (11 | ) |  |  | (11 | )
Decommissioning provision2 |  |  | (2 | ) |  |  | (1 | ) |  |  | 2 |
In-process research & development4 |  |  | 3 |  |  |  | 3 |  |  |  | 3 |
BPLP — pension and maintenance costs10 |  |  | — |  |  |  | 8 |  |  |  | (2 | )
Income taxes — tax effect on differences9 |  |  | 3 |  |  |  | — |  |  |  | 1 |
Income taxes — IFRS accounting difference9 |  |  | 6 |  |  |  | — |  |  |  | 8 |
All other |  |  | 1 |  |  |  | — |  |  |  | — |
Total accounting differences |  |  | 1 |  |  |  | 1 |  |  |  | 1 |
Net earnings — IFRS |  |  | 143 |  |  |  | 69 |  |  |  | 99 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |
Unrealized losses (gains) on financial instruments |  |  | (31 | ) |  |  | 46 |  |  |  | (18 | )
Adjusted net earnings (non-GAAP measure) |  |  | 112 |  |  |  | 115 |  |  |  | 81 |

1 |  | We have elected under IFRS 1 not to apply IAS 23, Borrowing Costs, retrospectively to borrowing costs incurred on the construction of qualifying assets that commenced prior to January 1, 2010. Accordingly, we have expensed all borrowing costs that had been previously capitalized under Canadian GAAP. New guidance from the IASB is pending and it is possible that our accounting may change as a result. At January 1, 2010, the effect was a $330 million decrease in property, plant and equipment and a corresponding decrease in retained earnings.
2 |  | We have elected under IFRS 1 to apply IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities, prospectively to changes in decommissioning liabilities that occurred prior to January 1, 2010. There are no new liabilities recognized as a result of the transition to IFRS. However, the measurement of existing liabilities according to the IFRS standards provides a different result. At January 1, 2010, the effect was a $55 million increase in provisions, a $55 million decrease in property, plant and equipment and a $110 million decrease in retained earnings.
|  | Canadian GAAP requires the unwinding of the discount (accretion) to be recorded as an operating cost and allocated to inventory whereas IFRS requires accretion to be reflected as a financing cost. The net result in the interim periods was an increase in reported expenses with a corresponding decrease in product inventories.
3 |  | IFRS requires the reversal of any previously recorded impairment losses where circumstances have changed such that the impairments have been reduced. We reviewed our previously recorded impairment losses and reversed a portion of the charges relating to certain of our in situ recovery mine assets located in the United States. At January 1, 2010, the effect was a $35 million increase in property, plant and equipment with a corresponding increase in retained earnings.
4 |  | Under IFRS, in-process research and development (IPR&D) that meets the definition of an intangible asset is capitalized with amortization commencing when the asset is ready for use (i.e. when development is complete). Under Canadian GAAP, we have been amortizing IPR&D related to the acquisition of our interest in GE-Hitachi Global Laser Enrichment LLC, a development stage entity. At January 1, 2010, the effect was a $20 million increase to investments in equity accounted investees and a corresponding increase in retained earnings.
|  | For the interim periods, we reversed the full amount amortized under Canadian GAAP.
5 |  | We have elected under IFRS 1 to reclassify all cumulative actuarial gains and losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date. At January 1, 2010, the effect was a $15 million

2010 Annual Financial review 97

#####

|  | decrease in long-term receivables, investments and other, other liabilities and a corresponding decrease in retained earnings.
6 |  | As a result of BPLP also transitioning to IFRS, we have recorded our share of BPLP’s transition adjustments. The most significant of BPLP’s IFRS transition adjustments results from cumulative actuarial losses. BPLP reclassified cumulative actuarial gains and losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date. The effect was a $137 million decrease in long-term receivables, investments and other, other liabilities and a corresponding decrease in retained earnings.
7 |  | We have elected under IFRS 1 to deem all foreign currency translation differences that exist at the date of transition to IFRS to be zero at the date of transition. At January 1, 2010, the effect was a $50 million adjustment to the cumulative translation adjustment account and a corresponding decrease in retained earnings.
8 |  | Under IFRS, we have concluded that our convertible debentures issued in 2003 and settled in 2008 will be treated as a hybrid instrument with a debt component and a conversion feature to be accounted for as a derivative. A derivative is required to be measured at fair value at each reporting date with changes in value being recorded in earnings. For purposes of our IFRS transition, we have measured the fair value of the conversion feature as at the redemption date and recorded a $297 million increase in share capital offset by a corresponding decrease in retained earnings.
9 |  | As a result of the changes in our opening balances on transition to IFRS, we have reduced our deferred tax liabilities by $138 million.
|  | For the interim periods, the adjustments relating to income tax expense reflect the tax effects of other adjustments as well as an IFRS accounting difference related to intra-group transactions. Under IFRS, deferred tax assets and liabilities are recognized for intra-group transactions whereas Canadian GAAP allows for the recognition of deferred tax assets and liabilities only when the transaction is with a third party.
10 |  | On transition to IFRS all actuarial losses were reclassified to retained earnings. Under IFRS, future actuarial gains and losses will be recognized through other comprehensive income to equity. Under Canadian GAAP, we have been amortizing the actuarial losses related to our interest in BPLP. As well, under IFRS, the costs of major inspections are capitalized and amortized over the period to the next inspection. Under Canadian GAAP, we have been expensing the inspection costs related to our interest in BPLP.

Other updates
As we proceed with our transition, we are also assessing the impact on our internal controls over financial reporting, and on our disclosure controls and procedures. Changes in accounting policies or business processes require additional controls or procedures to ensure the integrity of our financial disclosures. We have substantially completed the design and implementation of the new controls and are testing them. The transition to IFRS has not, however, required any significant changes in our internal control over financial reporting or our disclosure controls and procedures.
We conducted several educational and training sessions for our audit committee and the board of directors in 2009 and 2010. During these sessions, management and external advisors provided the board with detailed background information on IFRS accounting standards (including IFRS 1 elections), the implications of policy choices on our financial reporting, and a preliminary view of the expected format and content of our financial statements and notes upon transition. Management gives the audit committee quarterly project status updates and presentations.
We began training management and accounting staff in 2008. Training is being delivered mainly by external advisors, and focusing on the accounting issues most relevant to us. Sessions will continue into 2011. As a result, we are confident there is sufficient expertise within the organization to allow us to effectively transition to IFRS.
Our transition plan includes the need to inform key external stakeholders about the anticipated impact of the IFRS transition on our financial reporting. In 2009, we provided an information update as part of our investor day presentations. In December of 2010, we hosted a special session with the investment community dedicated to addressing IFRS-related accounting changes specific to Cameco.
98 cameco corporation

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We have also evaluated the impact of IFRS on our business activities in general. As a result, we believe the adoption of IFRS will not have a material effect on our risk management practices, hedging activities, capital requirements, compensation arrangements, compliance with debt covenants or other contractual commitments.
2010 Annual financial review 99

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REPORT OF MANAGEMENT’S ACCOUNTABILITY
The accompanying consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. Management is responsible for ensuring that these statements, which include amounts based upon estimates and judgment, are consistent with other information and operating data contained in the annual financial review and reflect the corporation’s business transactions and financial position.
Management is also responsible for the information disclosed in the management’s discussion and analysis including responsibility for the existence of appropriate information systems, procedures and controls to ensure that the information used internally by management and disclosed externally is complete and reliable in all material respects.
In addition, management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. The internal control system includes an internal audit function and a code of conduct and ethics, which is communicated to all levels in the organization and requires all employees to maintain high standards in their conduct of the corporation’s affairs. Such systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the company’s assets are appropriately accounted for and adequately safeguarded. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the company’s system of internal control over financial reporting was effective as at December 31, 2010.
KPMG LLP has audited the consolidated financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States).
The board of directors annually appoints an audit committee comprised of directors who are not employees of the corporation. This committee meets regularly with management, the internal auditor and the shareholders’ auditors to review significant accounting, reporting and internal control matters. Both the internal and shareholders’ auditors have unrestricted access to the audit committee. The audit committee reviews the financial statements, the report of the shareholders’ auditors, and management’s discussion and analysis and submits its report to the board of directors for formal approval.

Original signed by Gerald W. Grandey |  | Original signed by O. Kim Goheen
Chief Executive Officer |  | Senior Vice-President and Chief Financial Officer
February 11, 2011 |  | February 11, 2011

100 cameco corporation

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INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Cameco Corporation
We have audited the accompanying consolidated financial statements of Cameco Corporation (“the Corporation”), which comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of earnings, shareholders’ equity, comprehensive income, accumulated other comprehensive income and cash flows for the years then ended, and notes, comprising 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 Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
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. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence 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, we consider internal control relevant to the Corporation’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Corporation’s internal control. An audit also includes evaluating the appropriateness of accounting 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.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Cameco Corporation as at December 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.
Original signed by KPMG LLP
Chartered Accountants
Saskatoon, Canada
February 11, 2011
2010 Annual Financial review 101

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Consolidated Balance Sheets

As at December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2010 |  |  | 2009 |
Assets |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 376,621 |  |  | $ | 1,101,229 |
Short-term investments [note 5] |  |  | 883,032 |  |  |  | 202,836 |
Accounts receivable |  |  | 447,404 |  |  |  | 446,722 |
Income taxes receivable |  |  | 42,190 |  |  |  | — |
Inventories [note 6] |  |  | 542,526 |  |  |  | 453,224 |
Supplies and prepaid expenses |  |  | 190,079 |  |  |  | 169,005 |
Current portion of long-term receivables, investments and other [note 9] |  |  | 91,447 |  |  |  | 154,725 |
|  |  | 2,573,299 |  |  |  | 2,527,741 |
Property, plant and equipment [note 7] |  |  | 4,337,809 |  |  |  | 4,068,103 |
Intangible assets [note 8] |  |  | 94,270 |  |  |  | 97,713 |
Long-term receivables, investments and other [note 9] |  |  | 628,824 |  |  |  | 667,287 |
Future income tax assets [note 18] |  |  | 37,166 |  |  |  | 33,017 |
Total assets |  | $ | 7,671,368 |  |  | $ | 7,393,861 |
Liabilities and Shareholders’ Equity |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | $ | 399,035 |  |  | $ | 503,521 |
Income taxes payable |  |  | 35,042 |  |  |  | 31,143 |
Short-term debt [notes 10] |  |  | 72,948 |  |  |  | 76,762 |
Dividends payable |  |  | 27,605 |  |  |  | 23,570 |
Current portion of long-term debt [note 11] |  |  | 13,177 |  |  |  | 11,629 |
Current portion of other liabilities [note 13] |  |  | 28,228 |  |  |  | 29,297 |
Future income taxes [note 18] |  |  | 28,674 |  |  |  | 87,135 |
|  |  | 604,709 |  |  |  | 763,057 |
Long-term debt [note 11] |  |  | 940,317 |  |  |  | 952,853 |
Provision for reclamation [note 12] |  |  | 279,653 |  |  |  | 258,277 |
Other liabilities [note 13] |  |  | 244,179 |  |  |  | 244,433 |
Future income taxes [note 18] |  |  | 208,044 |  |  |  | 167,373 |
|  |  | 2,276,902 |  |  |  | 2,385,993 |
Minority interest |  |  | 178,139 |  |  |  | 164,040 |
Shareholders’ equity |  |  |  |  |  |  |  |
Share capital [note 14] |  |  | 1,535,857 |  |  |  | 1,512,461 |
Contributed surplus |  |  | 142,376 |  |  |  | 131,577 |
Retained earnings |  |  | 3,563,089 |  |  |  | 3,158,506 |
Accumulated other comprehensive income |  |  | (24,995 | ) |  |  | 41,284 |
|  |  | 5,216,327 |  |  |  | 4,843,828 |
Total liabilities and shareholders’ equity |  | $ | 7,671,368 |  |  | $ | 7,393,861 |

Commitments and contingencies [notes 12,18,25]
Subsequent event [note 29]
See accompanying notes to consolidated financial statements.
Approved by the board of directors
Original signed by Gerald W. Grandey and John H. Clappison
102 cameco corporation

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Consolidated Statements of Earnings

For the years ended December 31 |  |  |  |  |  |
($Cdn thousands, except per share amounts) |  | 2010 |  |  | 2009 |
Revenue from |  |  |  |  |  |  |  |
Products and services |  | $ | 2,123,655 |  |  | $ | 2,314,985 |
Expenses |  |  |  |  |  |  |  |
Products and services sold |  |  | 1,127,879 |  |  |  | 1,324,278 |
Depreciation, depletion and reclamation |  |  | 251,547 |  |  |  | 240,643 |
Administration |  |  | 155,810 |  |  |  | 135,558 |
Exploration |  |  | 95,796 |  |  |  | 49,061 |
Research and development |  |  | 4,794 |  |  |  | 630 |
Interest and other [note 15] |  |  | 3,474 |  |  |  | (12,470 | )
Gains on derivatives [note 26] |  |  | (75,183 | ) |  |  | (243,804 | )
Cigar Lake remediation |  |  | 16,633 |  |  |  | 17,884 |
Loss (gain) on sale of assets [note 16] |  |  | 107 |  |  |  | (566 | )
|  |  | 1,580,857 |  |  |  | 1,511,214 |
Earnings from continuing operations |  |  | 542,798 |  |  |  | 803,771 |
Other expense [note 17] |  |  | (11,150 | ) |  |  | (36,912 | )
Earnings before income taxes and minority interest |  |  | 531,648 |  |  |  | 766,859 |
Income tax expense [note 18] |  |  | 27,251 |  |  |  | 52,897 |
Minority interest |  |  | (10,352 | ) |  |  | (3,035 | )
Earnings from continuing operations |  | $ | 514,749 |  |  | $ | 716,997 |
Earnings from discontinued operations [note 24] |  |  | — |  |  |  | 382,425 |
Net earnings |  | $ | 514,749 |  |  | $ | 1,099,422 |
Net earnings per share [note 27] |  |  |  |  |  |  |  |
Basic |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.31 |  |  | $ | 1.84 |
Discontinued operations |  |  | — |  |  |  | 0.99 |
Total basic earnings per share |  | $ | 1.31 |  |  | $ | 2.83 |
Diluted |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.30 |  |  | $ | 1.84 |
Discontinued operations |  |  | — |  |  |  | 0.98 |
Total diluted earnings per share |  | $ | 1.30 |  |  | $ | 2.82 |

See accompanying notes to consolidated financial statements.
2010 Annual Financial review 103

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Consolidated Statements of Shareholders’ Equity

For the years ended December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2010 |  |  | 2009 |
Share capital |  |  |  |  |  |  |  |
Balance at beginning of year |  | $ | 1,512,461 |  |  | $ | 1,062,714 |
Stock option plan |  |  | 23,396 |  |  |  | 4,215 |
Equity issuance [note 14] |  |  | — |  |  |  | 445,532 |
Balance at end of year |  |  | 1,535,857 |  |  |  | 1,512,461 |
Contributed surplus |  |  |  |  |  |  |  |
Balance at beginning of year |  |  | 131,577 |  |  |  | 131,858 |
Stock-based compensation |  |  | 16,086 |  |  |  | 641 |
Options exercised |  |  | (5,287 | ) |  |  | (922 | )
Balance at end of year |  |  | 142,376 |  |  |  | 131,577 |
Retained earnings |  |  |  |  |  |  |  |
Balance at beginning of year |  |  | 3,158,506 |  |  |  | 2,153,315 |
Net earnings |  |  | 514,749 |  |  |  | 1,099,422 |
Dividends on common shares |  |  | (110,166 | ) |  |  | (94,231 | )
Balance at end of year |  |  | 3,563,089 |  |  |  | 3,158,506 |
Accumulated other comprehensive income (loss) |  |  |  |  |  |  |  |
Balance at beginning of year |  |  | 41,284 |  |  |  | 165,736 |
Other comprehensive loss |  |  | (66,279 | ) |  |  | (124,452 | )
Balance at end of year |  |  | (24,995 | ) |  |  | 41,284 |
Total retained earnings and accumulated other comprehensive income (loss) |  |  | 3,538,094 |  |  |  | 3,199,790 |
Shareholders’ equity at end of year |  | $ | 5,216,327 |  |  | $ | 4,843,828 |

See accompanying notes to consolidated financial statements.
104 cameco corporation

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Consolidated Statements of Comprehensive Income

For the years ended December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2010 |  |  | 2009 |
Net earnings |  | $ | 514,749 |  |  | $ | 1,099,422 |
Other comprehensive income (loss), net of taxes [note 18] |  |  |  |  |  |  |  |
Unrealized foreign currency translation losses |  |  | (6,696 | ) |  |  | (115,739 | )
Gains on derivatives designated as cash flow hedges |  |  | 12,035 |  |  |  | 101,162 |
Gains on derivatives designated as cash flow hedges transferred to net earnings |  |  | (71,186 | ) |  |  | (113,360 | )
Unrealized gains on available-for-sale securities |  |  | 2,125 |  |  |  | 3,011 |
(Gains) losses on available-for-sale securities transferred to net earnings |  |  | (2,557 | ) |  |  | 474 |
Other comprehensive loss |  |  | (66,279 | ) |  |  | (124,452 | )
Total comprehensive income |  | $ | 448,470 |  |  | $ | 974,970 |

Consolidated Statement of Accumulated Other Comprehensive Income (Loss)

|  | Currency |  |  |  |  |  |  |  |  |  |
|  | Translation |  |  | Cash Flow |  |  | Available-For- |  |  |  |
($Cdn thousands)(net of related income taxes)[note 18] |  | Adjustment |  |  | Hedges |  |  | Sale Assets |  |  | Total |
Balance at December 31, 2008 |  | $ | 65,342 |  |  | $ | 101,654 |  |  | $ | (1,260 | ) |  | $ | 165,736 |
Unrealized foreign currency translation losses |  |  | (115,739 | ) |  |  | — |  |  |  | — |  |  |  | (115,739 | )
Gains on derivatives designated as cash flow hedges |  |  | — |  |  |  | 101,162 |  |  |  | — |  |  |  | 101,162 |
Gains on derivatives designated as cash flow hedges transferred to net earnings |  |  | — |  |  |  | (113,360 | ) |  |  | — |  |  |  | (113,360 | )
Unrealized gains on available-for-sale securities |  |  | — |  |  |  | — |  |  |  | 3,011 |  |  |  | 3,011 |
Losses on available-for-sale securities transferred to net earnings |  |  | — |  |  |  | — |  |  |  | 474 |  |  |  | 474 |
Balance at December 31, 2009 |  | $ | (50,397 | ) |  | $ | 89,456 |  |  | $ | 2,225 |  |  | $ | 41,284 |
Unrealized foreign currency translation losses |  |  | (6,696 | ) |  |  | — |  |  |  | — |  |  |  | (6,696 | )
Gains on derivatives designated as cash flow hedges |  |  | — |  |  |  | 12,035 |  |  |  | — |  |  |  | 12,035 |
Gains on derivatives designated as cash flow hedges transferred to net earnings |  |  | — |  |  |  | (71,186 | ) |  |  | — |  |  |  | (71,186 | )
Unrealized gains on available-for-sale securities |  |  | — |  |  |  | — |  |  |  | 2,125 |  |  |  | 2,125 |
Gains on available-for-sale securities transferred to net earnings |  |  | — |  |  |  | — |  |  |  | (2,557 | ) |  |  | (2,557 | )
Balance at December 31, 2010 |  | $ | (57,093 | ) |  | $ | 30,305 |  |  | $ | 1,793 |  |  | $ | (24,995 | )

See accompanying notes to consolidated financial statements.
2010 Annual Financial review 105

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Consolidated Statements of Cash Flows

For the years ended December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2010 |  |  | 2009 |
Operating activities |  |  |  |  |  |  |  |
Net earnings |  | $ | 514,749 |  |  | $ | 1,099,422 |
Items not requiring (providing) cash: |  |  |  |  |  |  |  |
Depreciation, depletion and reclamation |  |  | 251,547 |  |  |  | 240,643 |
Provision for future taxes [note 18] |  |  | 612 |  |  |  | 2,237 |
Deferred gains |  |  | (33,369 | ) |  |  | (41,254 | )
Unrealized (gains) losses on derivatives |  |  | 25,561 |  |  |  | (180,260 | )
Stock-based compensation [note 22] |  |  | 16,086 |  |  |  | 2,772 |
Loss (gain) on sale of assets [note 16] |  |  | 107 |  |  |  | (566 | )
Equity in loss from associated companies [note 17] |  |  | 16,413 |  |  |  | 29,811 |
Other expense (income) [note 17] |  |  | (5,263 | ) |  |  | 7,101 |
Discontinued operations [note 24] |  |  | — |  |  |  | (382,425 | )
Minority interest |  |  | (10,352 | ) |  |  | (3,035 | )
Other operating items [note 19] |  |  | (268,993 | ) |  |  | (84,333 | )
Cash provided by operations |  |  | 507,098 |  |  |  | 690,113 |
Investing activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (470,277 | ) |  |  | (392,719 | )
Purchase of short-term investments [note 5] |  |  | (680,346 | ) |  |  | (202,850 | )
Decrease (increase) in long-term receivables, investments and other |  |  | 9,453 |  |  |  | (40,258 | )
Proceeds on sale of property, plant and equipment |  |  | 1,437 |  |  |  | 3,647 |
Cash used in investing (continuing operations) |  |  | (1,139,733 | ) |  |  | (632,180 | )
Cash provided by investing (discontinued operations) [note 24] |  |  | — |  |  |  | 871,300 |
Cash provided by (used in) investing |  |  | (1,139,733 | ) |  |  | 239,120 |
Financing activities |  |  |  |  |  |  |  |
Decrease in debt |  |  | (11,629 | ) |  |  | (726,460 | )
Increase in debt |  |  | 1,896 |  |  |  | — |
Issue of debentures, net of issue costs [note 11] |  |  | — |  |  |  | 495,272 |
Issue of shares, net of issue costs [note 14] |  |  | — |  |  |  | 440,150 |
Contributions from minority interests |  |  | 9,811 |  |  |  | — |
Issue of shares, stock option plan |  |  | 18,109 |  |  |  | 1,292 |
Dividends |  |  | (106,132 | ) |  |  | (92,603 | )
Cash provided by (used in) financing |  |  | (87,945 | ) |  |  | 117,651 |
Increase (decrease) in cash during the year |  |  | (720,580 | ) |  |  | 1,046,884 |
Exchange rate changes on foreign currency cash balances |  |  | (4,028 | ) |  |  | (9,877 | )
Cash and cash equivalents at beginning of year |  |  | 1,101,229 |  |  |  | 64,222 |
Cash and cash equivalents at end of year |  | $ | 376,621 |  |  | $ | 1,101,229 |
Cash and cash equivalents comprised of: |  |  |  |  |  |  |  |
Cash |  | $ | 100,752 |  |  | $ | 56,009 |
Cash equivalents |  |  | 275,869 |  |  |  | 1,045,220 |
|  | $ | 376,621 |  |  | $ | 1,101,229 |
Supplemental cash flow disclosure |  |  |  |  |  |  |  |
Interest paid |  | $ | 53,859 |  |  | $ | 35,267 |
Income taxes paid |  | $ | 63,226 |  |  | $ | 57,093 |

See accompanying notes to consolidated financial statements.
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Notes to Consolidated Financial Statements
For the years ended December 31, 2010 and 2009
($Cdn thousands, except per share amounts and as noted)

1. |  | Cameco Corporation

|  | Cameco Corporation is incorporated under the Canada Business Corporations Act. Cameco Corporation and its subsidiaries (collectively, Cameco or the company) are primarily engaged in the exploration for and the development, mining, refining, conversion and fabrication of uranium for sale as fuel for generating electricity in nuclear power reactors in Canada and other countries. The company has a 31.6% interest in Bruce Power L.P. (BPLP), which operates the four Bruce B nuclear reactors in Ontario.

2. |  | Significant Accounting Policies

| (a) |  | Consolidation Principles
|  |  | The consolidated financial statements include the accounts of Cameco and its subsidiaries. Interests in joint ventures are accounted for by the proportionate consolidation method. Under this method, Cameco includes in its accounts its proportionate share of assets, liabilities, revenues and expenses.
|  |  | The consolidated financial statements are prepared by management in accordance with Canadian generally accepted accounting principles. Management makes various estimates and assumptions in determining the reported amounts of assets and liabilities, revenues and expenses for each year presented, and in the disclosure of commitments and contingencies. The most significant estimates are related to the lives and recoverability of mineral properties, provisions for decommissioning and reclamation of assets, future income taxes, financial instruments and mineral reserves. Actual results could differ from these estimates. This summary of significant accounting policies is a description of the accounting methods and practices that have been used in the preparation of these consolidated financial statements and is presented to assist the reader in interpreting the statements contained herein.
| (b) |  | Cash and Cash Equivalents
|  |  | Cash and cash equivalents consist of balances with financial institutions and investments in money market instruments, which have a term to maturity of three months or less at time of purchase.
| (c) |  | Short-Term Investments
|  |  | Short-term investments consist of short-term money market instruments with terms to maturity at the date of acquisition of between three and 12 months. The short-term investments are classified as available-for-sale and are carried at fair value in the consolidated balance sheets with unrealized gains and losses reported in other comprehensive income (OCI). Realized gains and losses, as well as other-than-temporary declines in value, are recorded in the consolidated statements of earnings.
| (d) |  | Inventories
|  |  | Inventories of broken ore, uranium concentrates and refined and converted products are valued at the lower of average cost and net realizable value. Average cost includes direct materials, direct labour, operational overhead expenses and depreciation, depletion and reclamation. Net realizable value for finished products is considered to be the estimated selling price in the ordinary course of business, less the estimated costs of completion and selling expenses.
| (e) |  | Supplies
|  |  | Consumable supplies and spares are valued at the lower of cost or replacement value.
| (f) |  | Investments
|  |  | Investments in associated companies over which Cameco has the ability to exercise significant influence are accounted for by the equity method. Under this method, Cameco includes in earnings its share of earnings or losses of the associated company. Portfolio investments are classified as available-for-sale and are carried at fair value in the consolidated balance sheets with unrealized gains and losses reported in OCI. Realized gains and losses, as well as other-than-temporary declines in value, are recorded in the consolidated statements of earnings.

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| (g) |  | Property, Plant and Equipment
|  |  | Assets are carried at cost. Costs of additions and improvements are capitalized. When assets are retired or sold, the resulting gains or losses are reflected in current earnings. Maintenance and repair expenditures are charged to cost of production.
|  |  | The decision to develop a mine property within a project area is based on an assessment of the commercial viability of the property, the availability of financing and the existence of markets for the product. Once the decision to proceed to development is made, development and other expenditures relating to the project area are deferred and carried at cost with the intention that these costs will be depleted over the proven and probable reserves using the units-of-production method. No depreciation or depletion is charged against the property until commercial production commences. After a mine property has been brought into commercial production, costs of any additional work on that property are expensed as incurred, except for large development programs, which will be deferred and depleted over the remaining lives of the related assets.
|  |  | The carrying values of non-producing properties are periodically assessed by management and if management determines that the carrying values cannot be recovered, the unrecoverable amounts are written off against current earnings.
|  |  | Cameco reviews the carrying values of its property, plant and equipment when changes in circumstances indicate that those carrying values may not be recoverable. Estimated future net cash flows are calculated using estimated recoverable reserves, estimated future commodity prices and the expected future operating and capital costs. An impairment loss is recognized when the carrying value of an asset held for use exceeds the sum of undiscounted future net cash flows. An impairment loss is measured as the amount by which the asset’s carrying amount exceeds its fair value.
|  |  | Interest is capitalized on expenditures related to development projects actively being prepared for their intended use. Capitalization is discontinued when the asset enters commercial operation or development ceases.
|  |  | Fuel services assets, mine buildings, equipment and mineral properties are depreciated or depleted according to the units-of-production method. This method allocates the costs of these assets to each accounting period. For fuel services, the amount of depreciation is measured by the portion of the facilities’ total estimated lifetime production that is produced in that period. For mining, the amount of depreciation or depletion is measured by the portion of the mines’ proven and probable reserves which are recovered during the period.
|  |  | Nuclear generating plants are depreciated according to the straight-line method based on the lower of useful life and remaining lease term.
|  |  | Other assets are depreciated according to the straight-line method based on estimated useful lives, which generally range from three to 10 years.
| (h) |  | Intangible Assets
|  |  | Intangible assets acquired in a business combination are recorded at their fair values. Finite-lived intangible assets are amortized over the estimated production profile of the business unit to which they relate. The carrying values of intangible assets are periodically assessed by management and if management determines that the carrying values cannot be recovered, the unrecoverable amount is charged to earnings in the current period.
| (i) |  | Future Income Taxes
|  |  | Future income taxes are recognized for the future income tax consequences attributable to differences between the carrying values of assets and liabilities and their respective income tax bases. Future income tax assets and liabilities are measured using enacted or substantively enacted income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities of a change in rates is included in earnings in the period, which includes the enactment date. Future income tax assets are recorded in the financial statements and a valuation allowance is provided, if necessary, to reduce the future income tax asset to an amount that is more likely than not to be realized. Accrued interest and penalties for uncertain tax positions are recognized in the period in which uncertainties are identified.

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| (j) |  | Research and Development and Exploration Costs
|  |  | Expenditures for research and technology related to the products and processes are charged against earnings as incurred. Exploration expenditures including drilling and related costs are charged against earnings as incurred up until the point at which it is determined that the costs are economically recoverable. Any further exploration expenditures are capitalized once economic recoverability has been established.
| (k) |  | Environmental Protection and Asset Retirement Obligations
|  |  | The fair value of the liability for an asset retirement obligation is recognized in the period incurred. The fair value, discounted using the company’s credit adjusted risk-free rate, is added to the carrying amount of the associated asset and depreciated over the asset’s useful life. The liability is accreted over time, using the company’s credit adjusted risk-free rate, through periodic charges to earnings, and it is reduced by actual costs of decommissioning and reclamation. Cameco’s estimates of reclamation costs could change as a result of changes in regulatory requirements, reclamation plans, cost estimates and timing of estimated expenditures. Costs related to ongoing environmental programs are charged against earnings as incurred.
| (l) |  | Employee Future Benefits
|  |  | Cameco accrues its obligations under employee benefit plans. The cost of pensions and other retirement benefits earned by employees is actuarially determined using the projected benefit method pro-rated on service and management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. For the purpose of calculating the expected return on plan assets, those assets are measured at fair value. Cameco measures the plan assets and the accrued benefit obligations on December 31 each year.
|  |  | On both the Cameco-specific and BPLP-specific defined benefit pension plans, past service costs arising from plan amendments are amortized on a straight-line basis over the expected average remaining service life of the plan participants. Net actuarial gains, which exceed 10% of the greater of the accrued benefit obligation and the fair value of plan assets, are amortized on a straight-line basis over the expected average remaining service life of the plan participants.
|  |  | On the Cameco-specific retirement benefit plans that do not vest or accumulate, past service costs arising from plan amendments, and net actuarial gains and losses, are recognized in the period they arise. Conversely, the BPLP-specific amounts are amortized on a straight-line basis over the expected average remaining service life of the plan participants.
| (m) |  | Stock-Based Compensation
|  |  | Cameco has five stock-based compensation plans that are described in note 22. These encompass a stock option plan, an employee share ownership plan, a performance share unit plan, a deferred share unit plan and a phantom stock option plan. In calculating compensation expense, Cameco includes an estimate for forfeitures that is based on historic trends.
|  |  | Options granted under the stock option and performance share unit plans for which the holder cannot elect cash settlement are accounted for using the fair value method. Under this method, the compensation cost of options granted is measured at estimated fair value at the grant date and recognized over the shorter of the period to eligible retirement or the vesting period. Options that may be settled in cash are accounted for as liabilities and are carried at their intrinsic value. The intrinsic value of the liability is marked-to-market each period and is amortized to expense over the shorter of the period to eligible retirement or the vesting period.
|  |  | Deferred share units and phantom stock options are amortized over the shorter of the period to eligible retirement or the vesting period and re-measured at each reporting period, until settlement, using the quoted market value. Cameco’s contributions under the employee share ownership plan are expensed during the year of contribution. Shares purchased with company contributions and with dividends paid on such shares become unrestricted on January 1 of the second plan year following the date on which such shares were purchased.

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| (n) |  | Revenue Recognition
|  |  | Cameco supplies uranium concentrates and uranium conversion services to utility customers.
|  |  | Cameco recognizes revenue on the sale of its nuclear products when evidenced by a contract that indicates the product, pricing and delivery terms, when delivery occurs, the related revenue is fixed or determinable and collection is reasonably assured.
|  |  | Cameco has three types of sales arrangements with its customers in its uranium and fuel services businesses. These arrangements include uranium supply, toll conversion services and conversion supply (converted uranium), which is a combination of uranium supply and toll conversion services.
|  |  | Uranium Supply
|  |  | In a uranium supply arrangement, Cameco is contractually obligated to provide uranium concentrates to its customers. Cameco-owned uranium is physically delivered to conversion facilities (Converters) where the Converter will credit Cameco’s account for the volume of accepted uranium. Based on delivery terms in a sales contract with its customer, Cameco instructs the Converter to transfer title of a contractually specified quantity of uranium to the customer’s account at the Converter’s facility. At this point, Cameco invoices the customer and recognizes revenue for the uranium supply.
|  |  | Toll Conversion Services
|  |  | In a toll conversion arrangement, Cameco is contractually obligated to convert customer-owned uranium to a chemical state suitable for enrichment. The customer delivers uranium to Cameco’s conversion facilities. Once conversion is complete, Cameco physically delivers converted uranium to enrichment facilities (Enrichers) where the Enricher will credit Cameco’s account for the volume of accepted processed uranium. Based on delivery terms in a sales contract with its customer, Cameco instructs the Enricher to transfer title of a contractually specified quantity of converted uranium to the customer’s account at the Enricher’s facility. At this point, Cameco invoices the customer and recognizes revenue for the toll conversion services.
|  |  | Conversion Supply
|  |  | In a conversion supply arrangement, Cameco is contractually obligated to provide uranium concentrates and conversion services to its customers. Cameco-owned uranium is converted and physically delivered to an Enricher as described in the toll conversion services arrangement. Based on delivery terms in a sales contract with its customer, Cameco instructs the Enricher to transfer title of a contractually specified quantity of converted uranium to the customer’s account at the Enricher’s facility. At this point, Cameco invoices the customer and recognizes revenue for both the uranium supplied and the conversion service provided. It is rare for Cameco to enter into back-to-back arrangements for uranium supply and toll conversion services. However, in the event that a customer requires such an arrangement, revenue from uranium supply is deferred until the toll conversion service has been rendered.
|  |  | Revenue from deliveries to counterparties with whom Cameco has arranged a standby product loan facility (up to the limit of the loan facilities) and the related cost of sales are deferred until the loan arrangements have been terminated, or if drawn upon, when the loans are repaid and that portion of the facility is terminated.
|  |  | Electricity sales are recognized at the time of generation, and delivery to the purchasing utility is metered at the point of interconnection with the transmission system. Revenues are recognized on an accrual basis, which includes an estimate of the value of electricity produced during the period but not yet billed.
| (o) |  | Amortization of Financing Costs
|  |  | For financial instruments that are measured at amortized cost, the effective interest method of amortization is used for any debt discounts and issue expenses. Unamortized costs are classified with their related financial liability.
| (p) |  | Foreign Currency Translation
|  |  | Monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars at year-end rates of exchange. Revenue and expense transactions denominated in foreign currencies are translated into Canadian dollars at rates in effect at the time of the transactions. The applicable exchange gains and losses arising on these transactions are reflected in earnings.
|  |  | The United States (US) dollar is considered the functional currency of most of Cameco’s operations outside of Canada. The financial statements of these operations are translated into Canadian dollars using the current rate method whereby all assets and liabilities are translated at the year-end rate of exchange, and all revenue and

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|  |  | expense items are translated at the average rate of exchange prevailing during the year. Exchange gains and losses arising from this translation, representing the net unrealized foreign currency translation gain (loss) on Cameco’s net investment in these foreign operations, are recorded in the foreign currency translation adjustments component of accumulated other comprehensive income (AOCI). Exchange gains or losses arising from the translation of foreign debt designated as hedges of a net investment in foreign operations are also recorded in the foreign currency translation adjustments component of AOCI. These adjustments are not included in earnings until realized through a reduction in Cameco’s net investment in such operations.
| (q) |  | Derivative Financial Instruments and Hedging Transactions
|  |  | Financial Assets and Financial Liabilities
|  |  | All financial assets and liabilities are carried at fair value in the consolidated balance sheets, except for items classified in the following categories, which are carried at amortized cost: loans and receivables, held-to-maturity securities and financial liabilities not held-for-trading. Realized and unrealized gains and losses on financial assets and liabilities that are held-for-trading are recorded in the consolidated statements of earnings. Unrealized gains and losses on financial assets that are available-for-sale are reported in OCI until realized, at which time they are recorded in the consolidated statements of earnings.
|  |  | Hedge Accounting and Derivatives
|  |  | Derivative financial and commodity instruments are employed by Cameco to reduce exposure to fluctuations in foreign currency exchange rates, interest rates and commodity prices. All derivative instruments are recorded at fair value in the consolidated balance sheets, except for those designated as hedging instruments.
|  |  | The purpose of hedging transactions is to modify Cameco’s exposure to one or more risks by creating an offset between changes in the fair value of, or the cash inflows attributable to, the hedged item and the hedging item. Hedge accounting ensures that the offsetting gains, losses, revenues and expenses are recognized to net earnings in the same period or periods. When hedge accounting is appropriate, the hedging relationship is designated as a fair value hedge, a cash flow hedge, or a foreign currency risk hedge related to a net investment in a self-sustaining foreign operation.
|  |  | At the inception of a hedging relationship, Cameco formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. The process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. Cameco also formally assesses, both at the inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.
|  |  | For fair value hedges, changes in the fair value of the derivatives and corresponding changes in fair value of the hedged items attributed to the risk being hedged are recognized in the consolidated statements of earnings. For cash flow hedges, the effective portion of the changes in the fair values of the derivative instruments are recorded in OCI until the hedged items are recognized in the consolidated statements of earnings. Derivative instruments that do not qualify for hedge accounting, or are not designated as hedging instruments, are marked-to-market and the resulting net gains or losses are recognized on the consolidated statements of earnings.
|  |  | Derivatives may be embedded in other financial instruments (the “host instrument”). Embedded derivatives are treated as separate derivatives when their economic characteristics and risks are not clearly and closely related to those of the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative, and the combined contract is not held-for-trading or designated at fair value. These embedded derivatives are measured at fair value with subsequent changes recognized in gains or losses on derivatives on the consolidated statements of earnings.
| (r) |  | Earnings Per Share
|  |  | Earnings per share are calculated using the weighted average number of common shares outstanding.
|  |  | The calculation of diluted earnings per share assumes that outstanding options and warrants which are dilutive to earnings per share are exercised and the proceeds are used to repurchase shares of the company at the average market price of the shares for the period. The effect is to increase the number of shares used to calculate diluted earnings per share.

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3. |  | Accounting Standards

| (a) |  | Future Changes in Accounting Policies
|  |  | International Financial Reporting Standards (IFRS)
|  |  | In February 2008, the Accounting Standards Board announced that Canadian publicly accountable enterprises will be required to adopt IFRS effective January 1, 2011. As a result, Cameco will publish its first consolidated financial statements, prepared in accordance with IFRS, for the quarter ending March 31, 2011. We will also provide comparative data on an IFRS basis, including an opening balance sheet as at January 1, 2010.

4. |  | Financial Risk Management
|  | This note presents information about various risks that Cameco is exposed to from its use of financial instruments, its objectives, policies and processes for measuring and managing risk, and the company’s management of capital. Further quantitative disclosures are included throughout these consolidated financial statements.
|  | Risk Management Overview
|  | Cameco is exposed in varying degrees to a variety of financial instrument related risks. Management and the board of directors, both separately and together, discuss the principal risks of our businesses. The board sets policies for the implementation of systems to manage, monitor and mitigate identifiable risks. Cameco’s risk management objective in relation to these instruments is to protect and minimize volatility in cash flow.
|  | Market Risk
|  | Cameco engages in various business activities which expose the company to market risk from changes in commodity prices and foreign currency exchange rates. As part of its overall risk management strategy, Cameco uses derivatives to manage some of its exposures to market risk that result from these activities.
|  | Derivative instruments may include financial and physical forward contracts. Such contracts may be used to establish a fixed price for a commodity, an interest-bearing obligation or a cash flow denominated in a foreign currency. Market risks are monitored regularly against defined risk limits and tolerances.
|  | Cameco’s actual exposure to these market risks is constantly changing as the company’s portfolios of foreign currency and commodity contracts change. Changes in fair value or cash flows based on market variable fluctuations cannot be extrapolated as the relationship between the change in the market variable and the change in fair value or cash flow may not be linear.
|  | The types of risk exposure and the way in which such exposure is managed are as follows:

| (a) |  | Commodity Price Risk
|  |  | As a significant producer and supplier of uranium, nuclear fuel processing and electricity, Cameco bears significant exposure to changes in prices for these products. A substantial change in prices will affect the company’s net earnings and operating cash flows. Prices for Cameco’s products are volatile and are influenced by numerous factors beyond the company’s control, such as supply and demand fundamentals, geopolitical events and, in the case of electricity prices, weather.
|  |  | Cameco’s sales contracting strategy focuses on reducing the volatility in future earnings and cash flow, while providing both protection against decreases in market price and retention of exposure to future market price increases. To mitigate the risks associated with the fluctuations in the market price for uranium products, Cameco seeks to maintain a portfolio of uranium product sales contracts with a variety of delivery dates and pricing mechanisms that provide a degree of protection from pricing volatility. To mitigate risks associated with fluctuations in the market price for electricity, BPLP enters into various energy and sales related contracts that qualify as cash flow hedges. At December 31, 2010, the effect of a $1/MWh increase in the market price for electricity would be a decrease of $175,000 in net earnings, and a decrease in other comprehensive income of $850,000 for 2010.

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| (b) |  | Foreign Exchange Risk
|  |  | The relationship between the Canadian and US dollars affects financial results of the uranium business as well as the fuel services business.
|  |  | Sales of uranium and fuel services are routinely denominated in US dollars while production costs are largely denominated in Canadian dollars. Cameco attempts to provide some protection against exchange rate fluctuations by planned hedging activity designed to smooth volatility. Cameco also has a natural hedge against US currency fluctuations because a portion of its annual cash outlays, including purchases of uranium and fuel services, is denominated in US dollars. At December 31, 2010, the effect of a $0.01 increase in the US to Canadian dollar exchange rate on our portfolio of currency hedges and other US denominated exposures would have been a decrease of $9,200,000 in net earnings for 2010.
| (c) |  | Counterparty Credit Risk
|  |  | Cameco’s sales of uranium product, conversion and fuel manufacturing services expose the company to the risk of non-payment. Counterparty credit risk is associated with the ability of counterparties to satisfy their contractual obligations to Cameco, including both payment and performance.
|  |  | Cameco manages this risk by monitoring the credit worthiness of our customers and seeking pre-payment or other forms of payment security from customers with an unacceptable level of credit risk.
|  |  | Cameco’s maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amount of financial assets such as accounts receivable and short-term investments. At December 31, 2010, there were no significant concentrations of credit risk and no amounts were held as collateral.
| (d) |  | Liquidity Risk
|  |  | Financial liquidity represents Cameco’s ability to fund future operating activities and investments. Cameco ensures that there is sufficient capital in order to meet short-term business requirements, after taking into account cash flows from operations and the company’s holdings of cash and cash equivalents. The company believes that these sources will be sufficient to cover the likely short-term and long-term cash requirements.
|  |  | The tables below outline the maturity dates for Cameco’s non-derivative financial liabilities including, principal and interest, as at December 31, 2010:

|  |  |  |  |  | Due in less |  |  | Due in |  |  | Due in |  |  | Due after |
(Millions) |  | Total |  |  | than 1 year |  |  | 1-3 years |  |  | 3-5 years |  |  | 5 years |
Long-term debt |  | $ | 794 |  |  | $ | — |  |  | $ | — |  |  | $ | 298 |  |  | $ | 496 |
BPLP lease |  |  | 159 |  |  |  | 13 |  |  |  | 31 |  |  |  | 39 |  |  |  | 76 |
Short-term debt |  |  | 73 |  |  |  | 73 |  |  |  | — |  |  |  | — |  |  |  | — |
Total contractual repayments |  | $ | 1,026 |  |  | $ | 86 |  |  | $ | 31 |  |  | $ | 337 |  |  | $ | 572 |

|  |  |  |  |  | Due in less |  |  | Due in |  |  | Due in |  |  | Due after |
(Millions) |  | Total |  |  | than 1 year |  |  | 1-3 years |  |  | 3-5 years |  |  | 5 years |
Interest on long-term debt |  | $ | 312 |  |  | $ | 42 |  |  | $ | 85 |  |  | $ | 81 |  |  | $ | 104 |
Interest on BPLP lease |  |  | 55 |  |  |  | 11 |  |  |  | 20 |  |  |  | 15 |  |  |  | 9 |
Interest on short-term debt |  |  | 2 |  |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | — |
Total interest payments |  | $ | 369 |  |  | $ | 55 |  |  | $ | 105 |  |  | $ | 96 |  |  | $ | 113 |

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| (e) |  | Interest Rate Risk
|  |  | During the year, Cameco entered into interest rate swap arrangements whereby fixed rate payments in relation to part of the $300,000,000 Series C debenture were swapped for variable rate payments. The notional amount under the swap arrangements is $135,000,000. Concurrently, Cameco has entered into interest rate cap arrangements at a notional amount of $135,000,000 million that are effective March 18, 2013 and terminate on March 16, 2015. These interest rate cap arrangements, when effective, will limit Cameco’s interest rate exposure to 5% plus an average margin of 1.81%.
|  |  | At December 31, 2010, the effect of a 1% increase in the three-month bankers acceptance rate would be a decrease in net earnings of $3,570,000.

|  | Capital Management

|  | Cameco’s capital structure reflects our vision and the environment in which we operate. We seek growth through development and expansion of existing assets and by acquisition. Our capital resources are managed to support achievement of our goals. The overall objectives for managing capital remained unchanged in 2010 from the prior comparative period.

|  | Cameco’s management considers its capital structure to consist of long-term debt, short-term debt (net of cash and cash equivalents), minority interest and shareholders’ equity.

|  | The capital structure at December 31, 2010 was as follows:

(Thousands) |  | 2010 |  |  | 2009 |
Long-term debt |  | $ | 953,494 |  |  | $ | 964,482 |
Short-term debt |  |  | 72,948 |  |  |  | 76,762 |
Cash and cash equivalents |  |  | (376,621 | ) |  |  | (1,101,229 | )
Short-term investments |  |  | (883,032 | ) |  |  | (202,836 | )
Net debt |  |  | (233,211 | ) |  |  | (262,821 | )
Minority interest |  |  | 178,139 |  |  |  | 164,040 |
Shareholders’ equity |  |  | 5,216,327 |  |  |  | 4,843,828 |
Total equity |  |  | 5,394,466 |  |  |  | 5,007,868 |
Total capital |  | $ | 5,161,255 |  |  | $ | 4,745,047 |

|  | Cameco is bound by certain covenants in its general credit facilities. These covenants place restrictions on total debt, including guarantees, and set minimum levels for net worth. As of December 31, 2010, Cameco met these requirements.

5. |  | Short-Term Investments

|  | In 2010, Cameco purchased money market instruments with terms to maturity between three and 12 months. The fair values of marketable securities held at December 31, 2010 were $883,032,000 (2009 — $202,836,000).

6. |  | Inventories

|  | 2010 |  |  | 2009 |
Uranium |  |  |  |  |  |  |  |
Concentrate |  | $ | 392,613 |  |  | $ | 310,893 |
Broken ore |  |  | 12,264 |  |  |  | 18,125 |
|  |  | 404,877 |  |  |  | 329,018 |
Fuel Services |  |  | 137,649 |  |  |  | 124,206 |
Total |  | $ | 542,526 |  |  | $ | 453,224 |

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7. |  | Property, Plant and Equipment

|  |  |  |  |  | Accumulated |  |  |  |  |  |  |
|  |  |  |  |  | Depreciation |  |  |  |  |  |  |
|  |  |  |  |  | and |  |  |  |  |  |  |
|  | Cost |  |  | Depletion |  |  | 2010 Net |  |  | 2009 Net |
Uranium |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mining |  | $ | 3,562,849 |  |  | $ | 1,657,227 |  |  | $ | 1,905,622 |  |  | $ | 1,801,379 |
Non-producing |  |  | 1,674,131 |  |  |  | — |  |  |  | 1,674,131 |  |  |  | 1,476,409 |
Fuel Services |  |  | 507,221 |  |  |  | 233,973 |  |  |  | 273,248 |  |  |  | 279,313 |
Electricity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets under capital lease |  |  | 164,288 |  |  |  | 89,744 |  |  |  | 74,544 |  |  |  | 83,866 |
Other |  |  | 610,826 |  |  |  | 257,945 |  |  |  | 352,881 |  |  |  | 361,377 |
Other |  |  | 125,178 |  |  |  | 67,795 |  |  |  | 57,383 |  |  |  | 65,759 |
Total |  | $ | 6,644,493 |  |  | $ | 2,306,684 |  |  | $ | 4,337,809 |  |  | $ | 4,068,103 |

| 8. |  | Intangible Assets

|  |  |  |  |  | Accumulated |  |  |  |  |  |  |
|  | Cost |  |  | Depreciation |  |  | 2010 Net |  |  | 2009 Net |
Intangible assets |  | $ | 118,819 |  |  | $ | 24,549 |  |  | $ | 94,270 |  |  | $ | 97,713 |

|  | The intangible asset value relates to intellectual property associated with Cameco Fuel Manufacturing and is being amortized on a units-of-production basis.

2010 Annual Financial review 115

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9. |  | Long-Term Receivables, Investments and Other

|  | 2010 |  |  | 2009 |
Bruce B L.P. (BPLP) [note 21] |  |  |  |  |  |  |  |
Capital lease receivable from Bruce A L.P. (BALP) (i) |  | $ | 91,608 |  |  | $ | 94,895 |
Derivatives [note 26] |  |  | 77,831 |  |  |  | 141,949 |
Accrued pension benefit asset [note 23] |  |  | 88,268 |  |  |  | 54,864 |
Equity accounted investments |  |  |  |  |  |  |  |
Global Laser Enrichment LLC (Cameco’s interest 24%) (privately held) |  |  | 162,718 |  |  |  | 185,716 |
UNOR Inc. |  |  | — |  |  |  | 935 |
UEX Corporation (market value $103,186) |  |  | 9,998 |  |  |  | 6,052 |
Huron Wind (privately held) |  |  | 3,913 |  |  |  | 4,002 |
Minergia S.A.C. (privately held) |  |  | 8,337 |  |  |  | 4,551 |
UFP Investments Inc. (privately held) |  |  | 6,784 |  |  |  | 2,617 |
Available-for-sale securities |  |  |  |  |  |  |  |
Western Uranium Corporation (market value $6,033) |  |  | 6,033 |  |  |  | 4,637 |
GoviEx Uranium (privately held) |  |  | 23,017 |  |  |  | 25,214 |
Derivatives [note 26] |  |  | 50,011 |  |  |  | 68,432 |
Deferred charges |  |  |  |  |  |  |  |
Cost of sales [note 13] |  |  | — |  |  |  | 14,415 |
Advances receivable from Inkai JV LLP (ii) |  |  | 125,072 |  |  |  | 141,149 |
Accrued pension benefit asset [note 23] |  |  | 6,142 |  |  |  | 8,264 |
Other |  |  | 60,539 |  |  |  | 64,320 |
|  |  | 720,271 |  |  |  | 822,012 |
Less current portion |  |  | (91,447 | ) |  |  | (154,725 | )
Net |  | $ | 628,824 |  |  | $ | 667,287 |

(i) |  | BPLP leases the Bruce A nuclear generating plants and other property, plant and equipment to BALP under a sublease agreement. Future minimum base rent sublease payments under the capital lease receivable are imputed using a 7.5% discount rate.
(ii) |  | Through an unsecured shareholder loan, Cameco has agreed to fund the development of the Inkai project. The limit of the loan facility is $370,000,000 (US) and advances under the facility bear interest at a rate of LIBOR plus 2%. At December 31, 2010, $314,000,000 (US) of principal and interest was outstanding (2009 - $337,000,000 (US)), of which 40% represents the joint venture partner’s share.

10. |  | Short-Term Debt

|  | In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GE-Hitachi Global Laser Enrichment LLC (GLE). The promissory note is payable on demand and bears interest at a market rate of 2.72%.

|  | In February 2009, Cameco concluded an arrangement for a $100,000,000 unsecured revolving credit facility. The original maturity date of the facility was February 5, 2010, however, in November 2010, upon mutual agreement with the lender, this facility was further extended to February 4, 2012. There are no longer any extensions available under this facility and there is no amount outstanding.

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11. Long-Term Debt

|  | 2010 |  |  | 2009 |
Debentures |  | $ | 794,483 |  |  | $ | 793,842 |
Capital lease obligation — BPLP |  |  | 159,011 |  |  |  | 170,640 |
|  |  | 953,494 |  |  |  | 964,482 |
Less current portion |  |  | (13,177 | ) |  |  | (11,629 | )
Net |  | $ | 940,317 |  |  | $ | 952,853 |

Cameco has $300,000,000 outstanding in senior unsecured debentures (Series C). These debentures bear interest at a rate of 4.7% per annum (effective interest rate of 4.79%) and mature September 16, 2015.
On September 2, 2009, Cameco issued debentures in the amount of $500,000,000. The debentures bear interest at 5.67% per annum (effective interest rate of 5.80%) and mature on September 2, 2019. The proceeds of the issue after deducting expenses were $495,300,000.
Cameco has a $500,000,000 unsecured revolving credit facility that is available until November 30, 2012. In addition to direct borrowings under the facility, up to $100,000,000 can be used for the issuance of letters of credit and, to the extent necessary, up to $400,000,000 may be allocated to provide liquidity support for the company’s commercial paper program. The facility ranks equally with all of Cameco’s other senior debt. At December 31, 2010, there were no amounts outstanding under this credit facility (2009 — nil). Cameco may also borrow directly in the commercial paper market. There was no commercial paper outstanding at December 31, 2010 (2009 — nil). These amounts, when drawn, are classified as long-term debt.
Cameco is bound by certain covenants in its revolving credit facilities. The significant financial covenants require a funded debt to tangible net worth ratio equal to or less than 1:1 and a tangible net worth greater than $1,250,000,000. Non-compliance with any of these covenants could result in accelerated payment and termination of the revolving credit facility. At December 31, 2010, Cameco was in compliance with covenants and does not expect its operating and investing activities in 2011 to be constrained by them.
Cameco has $554,934,000 ($400,882,000 and $154,889,000 (US)) in letter of credit facilities. The majority of the outstanding letters of credit at December 31, 2010 relate to future decommissioning and reclamation liabilities [note 12] and amounted to $549,533,000 ($395,818,000 and $153,987,000 (US)) (2009 — $592,215,000 ($396,427,000 and $187,071,000 (US)).
BPLP holds a long-term lease with OPG to operate the Bruce nuclear power facility. The term of the lease, which expires in 2018, is 18 years with an option to extend the lease for up to an additional 25 years. The interest rate associated with the lease is 7.5%.
BPLP has a $200,000,000 (Cameco’s share $63,200,000) revolving credit facility that is available until July 30, 2013, as well as $270,000,000 (Cameco’s share $83,320,000) in letter of credit facilities. As at December 31, 2010, BPLP had $45,000,000 (Cameco’s share $14,220,000) outstanding under the revolving credit facility (2009 — $35,000,000 (Cameco’s share $11,060,000)) and $270,000,000 (Cameco’s share $85,320,000) outstanding under the letter of credit facilities (2009 — $184,000,000 (Cameco’s share $58,144,000)).
2010 Annual Financial review 117

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The table below represents currently scheduled maturities of long-term debt and capital lease obligations over the next five years.

2011 |  | $ | 13,177 |
2012 |  |  | 14,852 |
2013 |  |  | 16,337 |
2014 |  |  | 18,233 |
2015 |  |  | 319,040 |
Thereafter |  |  | 571,855 |
Total |  | $ | 953,494 |

Standby Product Loan Facilities
Cameco had arranged for a standby product loan facility with one of its customers. The arrangement, which was finalized in 2008, allowed Cameco to borrow up to 2,400,000 pounds U3O8 equivalent over the period 2008 to 2011 with repayment during 2012 to 2014. Under the loan facility, standby fees of 2% were payable based on the market value of the facility, and interest was payable on the market value of any amounts drawn at a rate of 5%. Any borrowings were repayable in kind.
On September 13, 2010, Cameco gave notice of termination to the counterparty of the product loan agreement. The loan facility was terminated on October 15, 2010.
12. Provision for Reclamation
Cameco’s estimates of future asset retirement obligations are based on reclamation standards that satisfy regulatory requirements. Elements of uncertainty in estimating these amounts include potential changes in regulatory requirements, decommissioning and reclamation alternatives and amounts to be recovered from other parties.
Cameco estimates total future decommissioning and reclamation costs for its operating assets to be $465,709,000. These estimates are reviewed by Cameco technical personnel as required by regulatory agencies or more frequently as circumstances warrant. In connection with future decommissioning and reclamation costs, Cameco has provided financial assurances of $548,933,000 in the form of letters of credit to satisfy current regulatory requirements.
Under the BPLP lease agreement, OPG, as the owner of the Bruce nuclear plants, is responsible to decommission the Bruce facility and to provide funding and meet other requirements that the Canadian Nuclear Safety Commission (CNSC) may require of BPLP as licensed operator of the Bruce facility. OPG is also responsible to manage radioactive waste associated with decommissioning of the Bruce nuclear plants.
Following is a reconciliation of the total liability for asset retirement obligations:

|  | 2010 |  |  | 2009 |
Balance, beginning of year |  | $ | 258,277 |  |  | $ | 276,431 |
Changes in estimates |  |  | 20,201 |  |  |  | (17,125 | )
Liabilities settled |  |  | (12,542 | ) |  |  | (4,599 | )
Accretion expense |  |  | 17,208 |  |  |  | 17,828 |
Impact of foreign exchange |  |  | (3,491 | ) |  |  | (14,258 | )
Balance, end of year |  | $ | 279,653 |  |  | $ | 258,277 |

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| Following is a summary of the key assumptions on which the carrying amount of the asset retirement obligations is based:

| (i) |  | Total undiscounted amount of the estimated cash flows — $465,709,000.
| (ii) |  | Expected timing of payment of the cash flows — timing is based on life of mine plans. The majority of expenditures are expected to occur after 2016.
| (iii) |  | Discount rates — 5.00% to 7.50%.

The asset retirement obligations liability relates to the following segments:

|  | 2010 |  |  | 2009 |
Uranium |  | $ | 211,927 |  |  | $ | 192,544 |
Fuel Services |  |  | 67,726 |  |  |  | 65,733 |
Total |  | $ | 279,653 |  |  | $ | 258,277 |

13. Other Liabilities

|  | 2010 |  |  | 2009 |
Deferred sales [note 9] |  | $ | 17,004 |  |  | $ | 24,982 |
Derivatives [note 26] |  |  | 5,273 |  |  |  | 4,137 |
Accrued post-retirement benefit liability [note 23] |  |  | 13,355 |  |  |  | 12,019 |
Pensions [note 23] |  |  | 659 |  |  |  | 491 |
BPLP |  |  |  |  |  |  |  |
Accrued post-retirement benefit liability [note 23] |  |  | 138,533 |  |  |  | 125,402 |
Pensions [note 23] |  |  | 20,699 |  |  |  | 18,251 |
Derivatives [note 26] |  |  | 29,954 |  |  |  | 36,820 |
Provision for waste disposal |  |  | 37,660 |  |  |  | 38,619 |
Other |  |  | 9,270 |  |  |  | 13,009 |
|  |  | 272,407 |  |  |  | 273,730 |
Less current portion |  |  | (28,228 | ) |  |  | (29,297 | )
Net |  | $ | 244,179 |  |  | $ | 244,433 |

14. Share Capital
Authorized share capital:
Unlimited number of first preferred shares
Unlimited number of second preferred shares
Unlimited number of voting common shares, and
One Class B share
(a) Common Shares

Number Issued (Number of Shares) |  | 2010 |  |  | 2009 |
Beginning of year |  |  | 392,838,733 |  |  |  | 365,718,923 |
Issued: |  |  |  |  |  |  |  |
Equity issuance |  |  | — |  |  |  | 26,666,400 |
Stock option plan [note 22] |  |  | 1,512,310 |  |  |  | 453,410 |
Issued share capital |  |  | 394,351,043 |  |  |  | 392,838,733 |

(b) Class B Share
One Class B share issued during 1988 and assigned $1 of share capital entitles the shareholder to vote separately as a class in respect of any proposal to locate the head office of Cameco to a place not in the province of Saskatchewan.
2010 Annual financial Review 119

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(c) Share Issuance
On March 5, 2009, Cameco issued 26,666,400 common shares pursuant to a public offering for a total consideration of $459,995,000. The proceeds of the issue after deducting expenses were $445,532,000. Excluding the deferred tax recoveries, our net cash proceeds amounted to $440,150,000 in 2009.
15. Interest and Other

|  | 2010 |  |  | 2009 |
Interest on long-term debt |  | $ | 47,877 |  |  | $ | 38,377 |
Interest on short-term debt |  |  | 2,005 |  |  |  | 2,366 |
Foreign exchange (gains) losses |  |  | 6,626 |  |  |  | (21,086 | )
Other charges |  |  | 8,597 |  |  |  | 11,302 |
Interest income |  |  | (13,910 | ) |  |  | (6,614 | )
Capitalized interest |  |  | (47,721 | ) |  |  | (36,815 | )
Net |  | $ | 3,474 |  |  | $ | (12,470 | )

16. Loss (Gain) on Sale of Assets

|  |  |  |  |  | 2010 |  |  | 2009 |
Sale of geological data |  |  |  |  |  | $ | (1,107 | ) |  | $ | (3,674 | )
Other |  |  |  |  |  |  | 1,214 |  |  |  | 3,108 |
Net |  |  |  |  |  | $ | 107 |  |  | $ | (566 | )

17. Other Expense

|  | 2010 |  |  | 2009 |
Equity in loss of associated companies |  | $ | (16,413 | ) |  | $ | (29,811 | )
Other |  |  | 5,263 |  |  |  | (7,101 | )
Net |  | $ | (11,150 | ) |  | $ | (36,912 | )

In 2010, the equity in loss of associated companies includes a charge of $11,363,000 for the amortization of in-process research and development associated with the investment in GLE (2009 — $18,295,000).
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18. Income Taxes
The significant components of future income tax assets and liabilities at December 31 are as follows:

|  | 2010 |  |  | 2009 |
Assets |  |  |  |  |  |  |  |
Provision for reclamation |  | $ | 92,198 |  |  | $ | 89,996 |
Foreign exploration and development |  |  | 47,230 |  |  |  | 40,221 |
Income tax losses carried forward |  |  | 41,625 |  |  |  | 100,783 |
Other |  |  | 46,617 |  |  |  | 31,185 |
Future income tax assets before valuation allowance |  |  | 227,670 |  |  |  | 262,185 |
Valuation allowance |  |  | (63,843 | ) |  |  | (57,398 | )
Future income tax assets, net of valuation allowance |  | $ | 163,827 |  |  | $ | 204,787 |
Liabilities |  |  |  |  |  |  |  |
Property, plant and equipment |  | $ | 292,631 |  |  | $ | 338,645 |
Inventories |  |  | 24,264 |  |  |  | 5,618 |
Long-term investments and other |  |  | 46,484 |  |  |  | 82,015 |
Future income tax liabilities |  | $ | 363,379 |  |  | $ | 426,278 |
Net future income tax liabilities |  | $ | 199,552 |  |  | $ | 221,491 |

The provision for income taxes differs from the amount computed by applying the combined expected federal and provincial income tax rate to earnings before income taxes. The reasons for these differences are as follows:

|  | 2010 |  |  | 2009 |
Earnings before income taxes and minority interest |  | $ | 531,648 |  |  | $ | 766,859 |
Combined federal and provincial tax rate |  |  | 30.2 | % |  |  | 31.4 | %
Computed income tax expense |  |  | 160,558 |  |  |  | 240,794 |
Increase (decrease) in taxes resulting from: |  |  |  |  |  |  |  |
Reduction in income tax rates |  |  | (29,508 | ) |  |  | (10,983 | )
Manufacturing and processing deduction |  |  | (3,846 | ) |  |  | (3,211 | )
Difference between Canadian rate and rates applicable to subsidiaries in other countries |  |  | (126,222 | ) |  |  | (175,969 | )
Change in valuation allowance |  |  | 13,499 |  |  |  | 18,125 |
Capital and other taxes |  |  | 1,409 |  |  |  | 1,824 |
Stock-based compensation plans |  |  | 2,696 |  |  |  | 1,371 |
Other permanent differences |  |  | 8,665 |  |  |  | (19,054 | )
Income tax expense |  | $ | 27,251 |  |  | $ | 52,897 |

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In 2008, as part of the ongoing annual audits of Cameco’s Canadian tax returns, Canada Revenue Agency (CRA) disputed the transfer pricing methodology used by Cameco and its wholly owned Swiss subsidiary, Cameco Europe Ltd. (CEL), in respect of sale and purchase agreements for uranium products. In December 2008, CRA issued a notice of reassessment, which increased Cameco’s 2003 income for Canadian income tax purposes by approximately $43,000,000. Additional reassessments for 2003 were issued by CRA in 2009 and 2010, both to similar effect. In December 2009, CRA issued a notice of reassessment for the 2004 taxation year, which increased Cameco’s 2004 income by approximately $108,000,000. Another reassessment for 2004 was issued by CRA on May 13, 2010 to similar effect. In December 2010, CRA issued a notice of reassessment for the 2005 taxation year, which increased Cameco’s 2005 taxable income by approximately $197,000,000. No reassessment received to date has resulted in more than a nominal amount of cash taxes becoming payable due to the availability of elective deductions and tax loss carrybacks. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for the years 2006 through 2010 on a similar basis.
CRA’s Transfer Pricing Review Committee is scheduled to meet in late February, 2011, to decide whether to impose a penalty for 2005. Given that the Transfer Pricing Review Committee did not impose a transfer pricing penalty for 2003 or 2004, we do not expect that a penalty will be imposed for 2005.
Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect, and Cameco is contesting CRA’s position. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco has recorded a cumulative tax provision related to this matter for the years 2003 through 2010 in the amount of $27,000,000. No provisions for penalties or interest have been recorded. We do not expect more than a nominal amount of cash taxes to be payable due to availability of elective deductions and tax loss carryovers. While the resolution of this matter may result in liabilities that are higher or lower than the reserve, management believes that the ultimate resolution will not be material to Cameco’s financial position, results of operations or liquidity over the period. However, an unfavourable outcome for the years 2003 to 2010 could be material to Cameco’s financial position, results of operations or cash flows in the year(s) of resolution.
Further to Cameco’s decision to contest CRA’s reassessments, a Notice of Appeal for the 2003 taxation year was filed with the Tax Court of Canada on July 22, 2009, and amended on January 26, 2011, and the litigation process is proceeding. In connection with CRA’s 2004 reassessment, Cameco is contesting the reassessment and pursuing its appeal rights under the Income Tax Act. A Notice of Appeal for the 2004 taxation year was filed with the Tax Court of Canada on November 10, 2010. Cameco intends to object to the 2005 reassessment and pursue its appeal rights under the Income Tax Act.

|  | 2010 |  |  | 2009 |
Earnings (loss) before income taxes and minority interest |  |  |  |  |  |  |  |
Canada |  | $ | (27,641 | ) |  | $ | 109,534 |
Foreign |  |  | 559,289 |  |  |  | 657,325 |
|  | $ | 531,648 |  |  | $ | 766,859 |
Current income taxes (recovery) |  |  |  |  |  |  |  |
Canada |  | $ | (12,280 | ) |  | $ | 17,109 |
Foreign |  |  | 38,919 |  |  |  | 33,551 |
|  | $ | 26,639 |  |  | $ | 50,660 |
Future income taxes (recovery) |  |  |  |  |  |  |  |
Canada |  | $ | 7,105 |  |  | $ | 3,885 |
Foreign |  |  | (6,493 | ) |  |  | (1,648 | )
|  | $ | 612 |  |  | $ | 2,237 |
Income tax expense |  | $ | 27,251 |  |  | $ | 52,897 |

For 2010, earnings from discontinued operations [note 24] included a net income tax expense of nil, (2009 — recovery of $94,600,000).
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At December 31, 2010, loss carry forwards of $136,000,000 (2009 — $380,000,000) are available to reduce taxable income. These losses expire as follows:

Date of expiry |  | Canada |  |  | US |  |  | Other |  |  | Total |
2011 |  |  | — |  |  | $ | 158 |  |  |  | — |  |  | $ | 158 |
2013 |  |  | — |  |  |  | 1,722 |  |  |  | — |  |  |  | 1,722 |
2019 |  |  | — |  |  |  | — |  |  |  | 7,255 |  |  |  | 7,255 |
2029 |  |  | — |  |  |  | 17,463 |  |  |  | — |  |  |  | 17,463 |
2030 |  |  | 441 |  |  |  | 10,546 |  |  |  | — |  |  |  | 10,987 |
no expiry |  |  | — |  |  |  | — |  |  |  | 98,657 |  |  |  | 98,657 |
|  | $ | 441 |  |  | $ | 29,889 |  |  | $ | 105,912 |  |  | $ | 136,242 |

Included in the table above is $101,000,000 (2009 — $94,000,000) of temporary differences related to loss carry forwards where no future benefit is realized.
Other comprehensive income included on the consolidated statements of shareholders’ equity and the consolidated statements of comprehensive income is presented net of income taxes. The following income tax amounts are included in each component of other comprehensive income:

|  | 2010 |  |  | 2009 |
Gains on derivatives designated as cash flow hedges |  | $ | 2,977 |  |  | $ | 48,368 |
Gains on derivatives designated as cash flow hedges transferred to net earnings |  |  | (29,400 | ) |  |  | (48,121 | )
Unrealized gains on assets available-for-sale |  |  | 330 |  |  |  | 466 |
(Gains) losses on assets available-for-sale transferred to net earnings |  |  | (399 | ) |  |  | 80 |
Total income tax expense (recovery) included in OCI |  | $ | (26,492 | ) |  | $ | 793 |

Accumulated other comprehensive income included on the consolidated statements of shareholders’ equity and the consolidated statement of accumulated other comprehensive income is presented net of income taxes. The following income tax amounts are included in each component of accumulated other comprehensive income:

|  | 2010 |  |  | 2009 |
Gains on derivatives designated as cash flow hedges |  | $ | 10,564 |  |  | $ | 36,987 |
Gains on assets available-for-sale |  |  | 277 |  |  |  | 346 |
Total income tax expense included in AOCI |  | $ | 10,841 |  |  | $ | 37,333 |

2010 Annual financial review 123

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19. Statements of Cash Flows
Other Operating Items

|  | 2010 |  |  | 2009 |
Changes in non-cash working capital: |  |  |  |  |  |  |  |
Accounts receivable |  | $ | (1,566 | ) |  | $ | 34,556 |
Inventories |  |  | (74,899 | ) |  |  | (74,938 | )
Supplies and prepaid expenses |  |  | (21,229 | ) |  |  | (27,838 | )
Accounts payable and accrued liabilities |  |  | (141,748 | ) |  |  | 30,784 |
Other |  |  | (29,551 | ) |  |  | (46,897 | )
Total |  | $ | (268,993 | ) |  | $ | (84,333 | )

20. Uranium Joint Ventures
Cameco conducts a portion of its exploration, development, mining and milling activities through joint ventures. Cameco proportionately consolidates its ownership interest in these assets. The McArthur River, Key Lake and Cigar Lake joint ventures allocate uranium production to each joint venture participant and the joint venture participant derives revenue directly from the sale of such product. Mining and milling expenses incurred by the joint venture are included in the cost of inventory.
The participants in the Inkai joint venture purchase uranium from Inkai and, in turn, derive revenue directly from the sale of such product to third party customers. On proportionate consolidation of Inkai, Cameco eliminates revenues and cost of sales recorded by Inkai related to sales by Inkai directly to Cameco. After elimination of these related party sales for the period, there are no revenues and expenses resulting from proportionate consolidation of Inkai and accordingly, a statement showing revenues and expenses from Inkai has not been provided.
The following table outlines Cameco’s proportionate interest of the assets and liabilities of each joint venture:

|  | Ownership |  |  | 2010 |  |  | 2009 |
Total Assets |  |  |  |  |  |  |  |  |  |  |  |
McArthur River |  |  | 69.81 | % |  | $ | 963,510 |  |  | $ | 923,786 |
Key Lake |  |  | 83.33 | % |  |  | 469,156 |  |  |  | 401,604 |
Cigar Lake |  |  | 50.03 | % |  |  | 1,022,770 |  |  |  | 874,661 |
Inkai |  |  | 60.00 | % |  |  | 233,884 |  |  |  | 255,932 |
|  |  |  |  |  | $ | 2,689,320 |  |  | $ | 2,455,983 |
Total Liabilities |  |  |  |  |  |  |  |  |  |  |  |
McArthur River |  |  | 69.81 | % |  | $ | 31,960 |  |  | $ | 25,183 |
Key Lake |  |  | 83.33 | % |  |  | 73,345 |  |  |  | 65,706 |
Cigar Lake |  |  | 50.03 | % |  |  | 22,208 |  |  |  | 14,076 |
Inkai |  |  | 60.00 | % |  |  | 11,341 |  |  |  | 8,627 |
|  |  |  |  |  | $ | 138,854 |  |  | $ | 113,592 |

124 cameco corporation

#####

21. Investment in BPLP
Cameco holds a 31.6% interest in BPLP, which is governed by an agreement that provides for joint control of the strategic operating, investing and financing activities among the three major partners. Cameco proportionately consolidates its 31.6% interest in BPLP.
Fuel Supply Agreements
Cameco has entered into fuel supply agreements with BPLP for the procurement of fabricated fuel. Under these agreements, Cameco will supply uranium, conversion services and fabrication services. Contract terms are at market rates and on normal trade terms. During 2010, sales of uranium and conversion services to BPLP amounted to $80,211,000 (2009 — $84,909,000), approximately 3.8% (2009 — 3.7%) of Cameco’s total revenue. At December 31, 2010, amounts receivable under these agreements totaled $19,667,000 (2009 — $11,505,000).
The following schedules reflect Cameco’s 31.6% proportionate interest in the balance sheets, statements of earnings and statements of cash flows of BPLP.
Balance Sheets

(Millions) |  | 2010 |  |  | 2009 |
Current assets |  | $ | 207 |  |  | $ | 252 |
Property, plant and equipment |  |  | 373 |  |  |  | 390 |
Long-term receivables and investments |  |  | 213 |  |  |  | 207 |
|  | $ | 793 |  |  | $ | 849 |
Current liabilities |  | $ | 125 |  |  | $ | 129 |
Long-term liabilities |  |  | 314 |  |  |  | 320 |
|  |  | 439 |  |  |  | 449 |
Equity |  |  | 354 |  |  |  | 400 |
|  | $ | 793 |  |  | $ | 849 |

Statements of Earnings

(Millions) |  | 2010 |  |  | 2009 |
Revenue |  | $ | 477 |  |  | $ | 518 |
Operating costs |  |  | 294 |  |  |  | 286 |
Earnings before interest and taxes |  |  | 183 |  |  |  | 232 |
Interest |  |  | 11 |  |  |  | 1 |
Earnings before taxes |  | $ | 172 |  |  | $ | 231 |

Statements of Cash Flows

(Millions) |  | 2010 |  |  | 2009 |
Cash provided by operations |  | $ | 203 |  |  | $ | 238 |
Cash used in investing |  |  | (32 | ) |  |  | (36 | )
Cash used in financing |  |  | (172 | ) |  |  | (200 | )

2010 Annual financial review 125

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22. Stock-Based Compensation Plans
Stock Option Plan
Cameco has established a stock option plan under which options to purchase common shares may be granted to officers and other employees of Cameco. Options granted under the stock option plan have an exercise price of not less than the closing price quoted on the TSX for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options vest over three years and expire eight years from the date granted. Options have not been awarded to directors since 2003 and the plan has been amended to preclude the issue of options to directors.
The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed 43,017,198, of which 26,092,439 shares have been issued.
Stock option transactions for the respective years were as follows:

(Number of Options) |  | 2010 |  |  | 2009 |
Beginning of year |  |  | 7,939,833 |  |  |  | 7,120,555 |
Options granted |  |  | 1,515,945 |  |  |  | 1,381,039 |
Options exercised [note 14] |  |  | (1,512,310 | ) |  |  | (453,410 | )
Options forfeited |  |  | (391,089 | ) |  |  | (108,351 | )
End of year |  |  | 7,552,379 |  |  |  | 7,939,833 |
Exercisable |  |  | 4,814,761 |  |  |  | 5,550,148 |

Weighted average exercise prices were as follows:

|  | 2010 |  |  | 2009 |
Beginning of year |  | $ | 27.42 |  |  | $ | 27.98 |
Options granted |  |  | 28.90 |  |  |  | 19.41 |
Options exercised |  |  | 12.75 |  |  |  | 9.79 |
Options forfeited |  |  | 35.05 |  |  |  | 35.68 |
End of year |  | $ | 30.26 |  |  | $ | 27.42 |
Exercisable |  | $ | 32.02 |  |  | $ | 26.84 |

Total options outstanding and exercisable at December 31, 2010 were as follows:

2010 |  |  |  |  |  | Options Outstanding |  |  | Options Exercisable |
|  |  |  |  |  | Weighted |  |  | Weighted |  |  |  |  |  |  | Weighted |
|  |  |  |  |  | Average |  |  | Average |  |  |  |  |  |  | Average |
|  |  |  |  |  | Remaining |  |  | Exercisable |  |  |  |  |  |  | Exercisable |
Option Price Per Share |  | Number |  |  | Life |  |  | Price |  |  | Number |  |  | Price |
$5.75 — 13.49 |  |  | 788,200 |  |  |  | 2 |  |  | $ | 9.72 |  |  |  | 788,200 |  |  | $ | 9.72 |
13.50 — 32.99 |  |  | 3,755,092 |  |  |  | 6 |  |  |  | 25.33 |  |  |  | 1,381,999 |  |  |  | 25.25 |
33.00 — 55.00 |  |  | 3,009,087 |  |  |  | 5 |  |  |  | 41.78 |  |  |  | 2,644,562 |  |  |  | 42.19 |
|  |  | 7,552,379 |  |  |  |  |  |  |  |  |  |  |  | 4,814,761 |  |  |  |  |

126 cameco corporation

#####

Non-vested stock option transactions for the respective years were as follows:

(Number of Options) |  | 2010 |  |  | 2009 |
Beginning of year |  |  | 2,389,685 |  |  |  | 2,163,426 |
Options granted |  |  | 1,515,945 |  |  |  | 1,381,039 |
Options forfeited |  |  | (91,439 | ) |  |  | (75,039 | )
Options vested |  |  | (1,076,573 | ) |  |  | (1,079,741 | )
End of year |  |  | 2,737,618 |  |  |  | 2,389,685 |

For the year ended December 31, 2010, Cameco has recorded a net expense of $8,931,000 (2009 - $4,372,000), related to options that vested during the year.
The fair value of the options granted each year was determined using the Black-Scholes option-pricing model with the following weighted average assumptions:

|  | 2010 |  |  | 2009 |
Number of options granted |  |  | 1,515,945 |  |  |  | 1,381,039 |
Average strike price |  | $ | 28.90 |  |  | $ | 19.41 |
Expected dividend |  | $ | 0.28 |  |  | $ | 0.24 |
Expected volatility |  |  | 36 | % |  |  | 36 | %
Risk-free interest rate |  |  | 2.1 | % |  |  | 1.6 | %
Expected life of option |  | 4.0 years |  | 4.0 years
Expected forfeitures |  |  | 15 | % |  |  | 15 | %
Weighted average grant date fair values |  | $ | 8.46 |  |  | $ | 5.23 |

Executive Performance Share Unit (PSU), Deferred Share Unit (DSU), and Other Plans Commencing in 2005, Cameco provides each plan participant an annual grant of PSUs in an amount determined by the board. Each PSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash at the board’s discretion, at the end of each three-year period if certain performance and vesting criteria have been met. The final value of the PSUs will be based on the value of Cameco common shares at the end of the three-year period and the number of PSUs that ultimately vest. Vesting of PSUs at the end of the three-year period will be based on total shareholder return over the three years, Cameco’s ability to meet its annual cash flow from operations targets and whether the participating executive remains employed by Cameco at the end of the three-year vesting period. As of December 31, 2010, the total PSUs held by the participants was 395,360 (2009 — 233,710). In 2010, Cameco recognized an expense of $3,679,000 in relation to PSUs (2009 - $3,347,000).
Cameco offers a deferred share unit plan to non-employee directors. A DSU is a notional unit that reflects the market value of a single common share of Cameco. 60% of each director’s annual retainer is paid in DSUs. In addition, on an annual basis, directors can elect to receive 25%, 50%, 75% or 100% of the remaining 40% of their annual retainer and any additional fees in the form of DSUs. If a director meets their ownership requirements, the director may elect to take 25%, 50%, 75% or 100% of their annual retainer and any fees in cash, with the balance, if any, to be paid in DSUs. Each DSU fully vests upon award. The DSUs will be redeemed for cash upon a director leaving the board. The redemption amount will be based upon the weighted average of the closing prices of the common shares of Cameco on the TSX for the last 20 trading days prior to the redemption date multiplied by the number of DSUs held by the director. As of December 31, 2010, the total DSUs held by participating directors was 354,276 (2009 — 373,921).
2010 Annual financial review 127

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Cameco makes annual grants of bonuses to eligible non-North American employees in the form of phantom stock options. Employees receive the equivalent value of shares in cash when exercised. Options granted under the phantom stock option plan have an award value equal to the closing price quoted on the TSX for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options vest over three years and expire eight years from the date granted. As of December 31, 2010, the number of options held by participating employees was 242,051 (2009 —267,148) with exercise prices ranging from $5.88 to $46.88 per share (2009 - $5.88 to $46.88) and a weighted average exercise price of $30.00 (2009 — $30.61).
Commencing in 2007, Cameco created an employee share ownership plan whereby both employee and company contributions are used to purchase shares on the open market for employees. The company’s contributions are expensed during the year of contribution. Under the plan, all employees have the opportunity to participate in the program to a maximum of 6% of eligible earnings each year with Cameco matching the first 3% of employee-paid shares by 50%. Cameco contributes $1,000 of shares annually to each employee that is enrolled in the plan. At December 31, 2010, there were 3,496 participants in the plan (2009 — 3,306). The total number of shares purchased in 2010 on behalf of participants, including the company contribution, was 214,795 shares (2009 — 281,207). In 2010, the company’s contributions totaled $6,608,000 (2009 — $5,166,000).
Cameco has recognized the following expenses under these plans:

|  | 2010 |  |  | 2009 |
Deferred share units |  |  | 1,971 |  |  |  | 4,930 |
Phantom stock options |  |  | 979 |  |  |  | 1,531 |
Employee share ownership plan |  |  | 6,608 |  |  |  | 5,166 |

At December 31, 2010, a liability of $16,798,000 (2009 — $14,962,000) was included in the balance sheet to recognize accrued but unpaid expenses for these plans.
128 cameco corporation

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23. |  | Pension and Other Post-Retirement Benefits
|  | Cameco maintains both defined benefit and defined contribution plans providing pension and post-retirement benefits to substantially all of its employees.
|  | Under the defined pension benefit plans, Cameco provides benefits to retirees based on their length of service and final average earnings. The non-pension post-retirement plan covers such benefits as group life and supplemental health insurance to eligible employees and their dependants. The costs related to the non-pension post-retirement plans are charged to earnings in the period during which the employment services are rendered. However, these future obligations are not funded.
|  | The effective date for the most recent valuations for funding purposes on the pension benefit plans is January 1, 2009. The next planned effective date for valuation for funding purposes of the pension benefit plans is set to be January 1, 2012. The status of the defined plans is as follows:

| (a) |  | Accrued Benefit Obligation

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
|  | 2010 |  |  | 2009 |  |  | 2010 |  |  | 2009 |
Balance at beginning of year |  | $ | 30,840 |  |  | $ | 23,580 |  |  | $ | 12,019 |  |  | $ | 11,842 |
Current service cost |  |  | 1,330 |  |  |  | 915 |  |  |  | 553 |  |  |  | 435 |
Interest cost |  |  | 1,905 |  |  |  | 1,683 |  |  |  | 664 |  |  |  | 730 |
Actuarial loss (gain) |  |  | 3,535 |  |  |  | 5,647 |  |  |  | 720 |  |  |  | (442 | )
Foreign exchange |  |  | (81 | ) |  |  | (238 | ) |  |  | — |  |  |  | — |
Benefits paid |  |  | (2,011 | ) |  |  | (747 | ) |  |  | (601 | ) |  |  | (546 | )
|  | $ | 35,518 |  |  | $ | 30,840 |  |  | $ | 13,355 |  |  | $ | 12,019 |

| (b) |  | Plan Assets

|  | Pension Benefit Plans |
|  | 2010 |  |  | 2009 |
Fair value at beginning of year |  | $ | 24,209 |  |  | $ | 20,289 |
Actual return on plan assets |  |  | 3,739 |  |  |  | (708 | )
Employer contributions |  |  | 1,158 |  |  |  | 5,335 |
Benefits paid |  |  | (1,971 | ) |  |  | (707 | )
Fair value at end of year |  | $ | 27,135 |  |  | $ | 24,209 |

2010 Annual Financial Review 129

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|  | Plan assets consist of:

|  | Pension Benefit Plans |
|  | 2010 |  |  | 2009 |
Asset Category (i) |  |  |  |  |  |  |  |
Equity securities |  |  | 26 | % |  |  | 28 | %
Fixed income |  |  | 22 | % |  |  | 23 | %
Other (ii) |  |  | 52 | % |  |  | 49 | %
Total |  |  | 100 | % |  |  | 100 | %

(i) |  | The defined benefit plan assets contain no material amounts of related party assets at December 31, 2010 and 2009 respectively.
(ii) |  | Relates to the value of the refundable tax account held by the Canada Revenue Agency. The refundable total is approximately equal to half of the sum of the realized investment income plus employer contributions less half of the benefits paid by the plan.

| (c) |  | Funded Status Reconciliation

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
|  | 2010 |  |  | 2009 |  |  | 2010 |  |  | 2009 |
Fair value of plan assets |  | $ | 27,135 |  |  | $ | 24,209 |  |  | $ | — |  |  | $ | — |
Accrued benefit obligation |  |  | 35,518 |  |  |  | 30,840 |  |  |  | 13,355 |  |  |  | 12,019 |
Funded status of plans — deficit |  |  | (8,383 | ) |  |  | (6,631 | ) |  |  | (13,355 | ) |  |  | (12,019 | )
Unamortized net actuarial loss |  |  | 13,866 |  |  |  | 14,404 |  |  |  | — |  |  |  | — |
Accrued benefit asset (liability) |  | $ | 5,483 |  |  | $ | 7,773 |  |  | $ | (13,355 | ) |  | $ | (12,019 | )
Amounts included in: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term receivables, investments and |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
other [note 9] |  |  | 6,142 |  |  |  | 8,264 |  |  |  | — |  |  |  | — |
Other liabilities [note 13] |  |  | (659 | ) |  |  | (491 | ) |  |  | (13,355 | ) |  |  | (12,019 | )
Accrued benefit asset (liability) |  | $ | 5,483 |  |  | $ | 7,773 |  |  | $ | (13,355 | ) |  | $ | (12,019 | )

| (d) |  | Net Pension Expense

|  | 2010 |  |  | 2009 |
Current service cost |  | $ | 1,330 |  |  | $ | 915 |
Interest cost |  |  | 1,905 |  |  |  | 1,683 |
Actual return on plan assets |  |  | (3,739 | ) |  |  | 708 |
Actuarial loss |  |  | 3,535 |  |  |  | 5,647 |
Balance prior to adjustments to recognize the long-term nature of employee future benefit costs |  |  | 3,031 |  |  |  | 8,953 |
Difference between actual and expected return on plan assets |  |  | 2,961 |  |  |  | (1,494 | )
Difference between actuarial loss recognized for year and actual |  |  |  |  |  |  |  |
actuarial loss on accrued benefit obligation for year |  |  | (2,472 | ) |  |  | (4,974 | )
Defined benefit pension expense |  |  | 3,520 |  |  |  | 2,485 |
Defined contribution pension expense |  |  | 14,649 |  |  |  | 13,506 |
Net pension expense |  | $ | 18,169 |  |  | $ | 15,991 |

130 cameco corporation

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|  | 2010 |  |  | 2009 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 5.5 | % |  |  | 6.0 | %
Rate of compensation increase |  |  | 4.5 | % |  |  | 4.5 | %
Long-term rate of return on assets |  |  | 5.9 | % |  |  | 5.9 | %

| (e) |  | Other Post-Retirement Benefit Expense

|  | 2010 |  |  | 2009 |
Current service cost |  | $ | 553 |  |  | $ | 435 |
Interest cost |  |  | 664 |  |  |  | 730 |
Actuarial loss (gain) |  |  | 720 |  |  |  | (442 | )
Other post-retirement benefit expense |  | $ | 1,937 |  |  | $ | 723 |

|  | 2010 |  |  | 2009 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 5.5 | % |  |  | 6.0 | %
Health care cost trend rate |  |  | 9.0 | % |  |  | 9.0 | %

| (f) |  | Pension and Other Post-Retirement Benefits Cash Payments

|  | 2010 |  |  | 2009 |
Employer contributions to funded pension plans |  | $ | 1,158 |  |  | $ | 5,335 |
Benefits paid for unfunded benefit plans |  |  | 640 |  |  |  | 585 |
Cash contributions to defined contribution plans |  |  | 14,649 |  |  |  | 13,506 |
Total cash payments for employee future benefits |  | $ | 16,447 |  |  | $ | 19,426 |

|  |  | Benefits paid by the funded pension plan were $1,971,000 for 2010 (2009 — $707,000). Cameco’s expected contributions for the year ended December 31, 2011 are approximately $252,044 for the pension benefit plans.
|  |  | The following are estimated future benefit payments, which reflect expected future service:

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
2011 |  | $ | 8,376 |  |  | $ | 699 |
2012 |  |  | 1,421 |  |  |  | 736 |
2013 |  |  | 1,471 |  |  |  | 815 |
2014 |  |  | 1,546 |  |  |  | 822 |
2015 |  |  | 1,854 |  |  |  | 806 |
2016 to 2020 |  |  | 10,683 |  |  |  | 4,294 |

2010 Annual Financial review 131

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|  |  | BPLP
|  |  | BPLP has a funded registered pension plan and an unfunded supplemental pension plan. The funded plan is a contributory, defined benefit plan covering all employees up to the limits imposed by the Income Tax Act. The supplemental pension plan is a non-contributory, defined benefit plan covering all employees with respect to benefits that exceed the limits under the Income Tax Act. These plans are based on years of service and final average salary.
|  |  | BPLP also has other post-retirement benefit and other post-employment benefit plans that provide for group life insurance, health care and long-term disability benefits. These plans are non-contributory.
|  |  | The effective date for the most recent valuations for funding purposes on the pension benefit plans is January 1, 2010. The next planned effective date for valuation for funding purposes of the pension benefit plans is set to be January 1, 2011. The status of Cameco’s proportionate share (31.6%) of the defined plans is as follows:

| (a) |  | Accrued Benefit Obligation

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
|  | 2010 |  |  | 2009 |  |  | 2010 |  |  | 2009 |
Balance at beginning of year |  | $ | 711,636 |  |  | $ | 617,259 |  |  | $ | 151,826 |  |  | $ | 112,355 |
Current service cost |  |  | 18,329 |  |  |  | 14,944 |  |  |  | 7,422 |  |  |  | 4,910 |
Interest cost |  |  | 42,478 |  |  |  | 41,061 |  |  |  | 8,960 |  |  |  | 7,284 |
Actuarial loss |  |  | 139,143 |  |  |  | 65,018 |  |  |  | 17,291 |  |  |  | 31,127 |
Plan participants’ contributions |  |  | 6,630 |  |  |  | 6,244 |  |  |  | — |  |  |  | — |
Benefits paid |  |  | (30,797 | ) |  |  | (32,890 | ) |  |  | (4,488 | ) |  |  | (3,850 | )
|  | $ | 887,419 |  |  | $ | 711,636 |  |  | $ | 181,011 |  |  | $ | 151,826 |

| (b) |  | Plan Assets

|  | Pension Benefit Plans |
|  | 2010 |  |  | 2009 |
Fair value at beginning of year |  | $ | 635,293 |  |  | $ | 546,755 |
Actual return on plan assets |  |  | 55,288 |  |  |  | 65,486 |
Employer contributions |  |  | 50,906 |  |  |  | 49,698 |
Plan participants’ contributions |  |  | 6,630 |  |  |  | 6,244 |
Benefits paid |  |  | (30,797 | ) |  |  | (32,890 | )
Fair value at end of year |  | $ | 717,320 |  |  | $ | 635,293 |

|  |  | Plan assets consist of:

|  | Asset Allocation |  |  | Target Allocation |
|  | 2010 |  |  | 2009 |  |  | 2010 |  |  | 2009 |
Asset Category (i) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities |  |  | 59 | % |  |  | 60 | % |  |  | 60 | % |  |  | 60 | %
Fixed income |  |  | 39 | % |  |  | 38 | % |  |  | 40 | % |  |  | 40 | %
Cash |  |  | 2 | % |  |  | 2 | % |  |  | — |  |  |  | — |
Total |  |  | 100 | % |  |  | 100 | % |  |  | 100 | % |  |  | 100 | %

132 cameco corporation

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|  |  | The assets of the pension plan are managed on a going concern basis subject to legislative restrictions. The plan’s investment policy is to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plan participants. Rebalancing will take place on a monthly basis if outside of 3% of the target asset allocation.
|  |  | (i) The defined benefit plan assets contain no material amounts of related party assets at December 31, 2010.

| (c) |  | Funded Status Reconciliation

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
|  | 2010 |  |  | 2009 |  |  | 2010 |  |  | 2009 |
Fair value of plan assets |  | $ | 717,320 |  |  | $ | 635,293 |  |  | $ | — |  |  | $ | — |
Accrued benefit obligation |  |  | 887,419 |  |  |  | 711,636 |  |  |  | 181,011 |  |  |  | 151,826 |
Funded status of plans — deficit |  |  | (170,099 | ) |  |  | (76,343 | ) |  |  | (181,011 | ) |  |  | (151,826 | )
Unrecognized prior service cost |  |  | — |  |  |  | — |  |  |  | 1,981 |  |  |  | 2,431 |
Unamortized net actuarial loss |  |  | 237,668 |  |  |  | 112,956 |  |  |  | 40,497 |  |  |  | 23,993 |
Accrued benefit asset (liability) |  | $ | 67,569 |  |  | $ | 36,613 |  |  | $ | (138,533 | ) |  | $ | (125,402 | )
Amounts included in: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term receivables, investments and other [note 9] |  |  | 88,268 |  |  |  | 54,864 |  |  |  | — |  |  |  | — |
Other liabilities [note 13] |  |  | (20,699 | ) |  |  | (18,251 | ) |  |  | (138,533 | ) |  |  | (125,402 | )
Accrued benefit asset (liability) |  | $ | 67,569 |  |  | $ | 36,613 |  |  | $ | (138,533 | ) |  | $ | (125,402 | )

| (d) |  | Net Pension Expense

|  | 2010 |  |  | 2009 |
Current service cost |  | $ | 18,329 |  |  | $ | 14,944 |
Interest cost |  |  | 42,478 |  |  |  | 41,061 |
Actual return on plan assets |  |  | (55,288 | ) |  |  | (65,486 | )
Actuarial loss |  |  | 139,143 |  |  |  | 65,018 |
Balance prior to adjustments to recognize the long-term nature of employee future benefit costs |  |  | 144,662 |  |  |  | 55,537 |
Difference between actual and expected return on plan assets |  |  | 10,798 |  |  |  | 27,286 |
Difference between actuarial loss recognized and actual actuarial loss on accrued benefit obligation for year |  |  | (135,509 | ) |  |  | (63,678 | )
Net pension expense |  | $ | 19,951 |  |  | $ | 19,145 |

|  | 2010 |  |  | 2009 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 5.3 | % |  |  | 6.0 | %
Rate of compensation increase |  |  | 3.5 | % |  |  | 5.5 | %
Long-term rate of return on assets |  |  | 7.0 | % |  |  | 7.0 | %

2010 Annual Financial review 133

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| (e) |  | Other Benefit Plans Expense

|  | 2010 |  |  | 2009 |
Current service cost |  | $ | 7,422 |  |  | $ | 4,910 |
Interest cost |  |  | 8,960 |  |  |  | 7,284 |
Actuarial loss |  |  | 17,291 |  |  |  | 31,127 |
Balance prior to adjustments to recognize the long-term nature of employee future benefit costs |  |  | 33,673 |  |  |  | 43,321 |
Difference between amortization of past service costs and actual plan amendments for year |  |  | 450 |  |  |  | 450 |
Difference between actuarial loss (gain) recognized and actual actuarial |  |  |  |  |  |  |  |
loss on accrued benefit obligation for year |  |  | (16,504 | ) |  |  | (31,556 | )
Other benefit plans expense |  | $ | 17,619 |  |  | $ | 12,215 |

|  | 2010 |  |  | 2009 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 5.1 | % |  |  | 5.8 | %
Rate of compensation increase |  |  | 3.5 | % |  |  | 3.5 | %
Initial health care cost trend rate |  |  | 9.5 | % |  |  | 10.0 | %
Cost trend rate declines to |  |  | 5.0 | % |  |  | 5.0 | %
Year the rate reaches its final level |  |  | 2019 |  |  |  | 2019 |

|  | 2010 |  |  | 2009 |
Employer contributions to funded pension plans |  | $ | 49,938 |  |  | $ | 45,890 |
Benefits paid for unfunded benefit plans |  |  | 4,814 |  |  |  | 4,209 |
Total cash payments for employee future benefits |  | $ | 54,752 |  |  | $ | 50,099 |

| (f) |  | Pension and Other Post-Retirement Benefits Cash Payments
|  |  | Benefits paid by the funded pension plan were $30,472,000 for 2010 (2009 — $32,531,000). BPLP’s expected contributions for the year ended December 31, 2011 are approximately $86,148,000 for the pension benefit plans.
|  |  | The following are estimated future benefit payments, which reflect expected future service:

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
2011 |  | $ | 39,637 |  |  | $ | 5,473 |
2012 |  |  | 43,334 |  |  |  | 6,013 |
2013 |  |  | 47,201 |  |  |  | 6,575 |
2014 |  |  | 51,134 |  |  |  | 7,117 |
2015 |  |  | 54,858 |  |  |  | 7,613 |
2016 to 2020 |  |  | 330,163 |  |  |  | 46,407 |

134 cameco corporation

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24. |  | Restructuring of the Gold Business
|  | The assets and liabilities related to discontinued operations have been reclassified as assets or liabilities of discontinued operations on the consolidated balance sheets. Operating results related to the discontinued operations have been included in earnings from discontinued operations on the consolidated statements of earnings. Comparative period balances have been restated.

| (a) |  | Sale of Centerra Gold Inc. (Centerra)
|  |  | On December 30, 2009, Cameco completed a public offering of 88,618,472 common shares of Centerra for net proceeds of approximately $871,000,000 and recorded a net gain of $374,000,000. Concurrent with this offering, Cameco transferred an additional 25,300,000 common shares of Centerra to Kyrgyzaltyn pursuant to the agreement that Cameco entered into with the Government of the Kyrgyz Republic on April 24, 2009. As a result of the closing of the public offering, and the transfer of the Centerra common shares to Kyrgyzaltyn, Cameco has disposed of its entire interest in Centerra.
| (b) |  | Kyrgyz Share Transfer
|  |  | In 2007, the Parliament of the Kyrgyz Republic challenged the legal validity of Kumtor Gold Company (Kumtor) agreements with the Kyrgyz Republic. As a result, Cameco and Centerra entered into discussions with Kyrgyzaltyn, culminating in the signing of two agreements in August 2007 providing for the transfer of a certain number of Centerra shares to Kyrgyzaltyn, subject to certain conditions. These agreements, however, were never ratified by the Kyrgyz parliament.
|  |  | On April 24, 2009, Cameco, Centerra, the Kyrgyz government and other parties signed a new agreement to resolve all the issues related to the Kumtor mine. On April 30, 2009, the Kyrgyz parliament ratified the agreement and enacted legislation authorizing implementation of the agreement. On June 11, 2009, closing occurred and Centerra issued 18,232,615 treasury shares to Kyrgyzaltyn and Cameco transferred 25,300,000 shares of its 113,918,000 Centerra common shares to a custodian, to be held in escrow, for ultimate release to Kyrgyzaltyn, subject to certain conditions. Cameco retained its voting rights over these shares while they were held in escrow. As a result of the public offering concluded on December 30, 2009, Cameco released the shares held in escrow to Kyrgyzaltyn.
|  |  | The total amount of the after-tax loss related to this agreement is $179,000,000, of which an expense of $46,000,000 was recorded in 2009, a recovery of $20,000,000 in 2008 and an expense of $153,000,000 in 2007.
| (c) |  | Financial Results of Discontinued Operations
|  |  | The results of the operations of Centerra are presented under “discontinued operations” on the consolidated statements of earnings. The following table presents the components of the discontinued operations amounts, net of future income tax expenses [note 18]:

(Millions) |  | 2010 |  |  | 2009 |
Sale of Centerra |  |  | — |  |  | $ | 374.2 |
Kyrgyz share transfer |  |  | — |  |  |  | (45.9 | )
Operating earnings |  |  | — |  |  |  | 54.1 |
Earnings from discontinued operations |  | — |  |  | $ | 382.4 |

2010 Annual Financial review 135

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|  |  | The following table presents the components of the operating results of Centerra:

(Millions) |  | 2010 |  |  | 2009 |
Revenue |  |  | — |  |  | $ | 770.2 |
Expenses |  |  |  |  |  |  |  |
Products and services sold |  |  | — |  |  |  | 440.4 |
Depreciation, depletion and reclamation |  |  | — |  |  |  | 122.4 |
Exploration |  |  | — |  |  |  | 28.5 |
Other |  |  | — |  |  |  | 37.3 |
Earnings before income taxes and minority interest |  |  | — |  |  |  | 141.6 |
Income tax expense |  |  | — |  |  |  | 33.4 |
Minority interest |  |  | — |  |  |  | 54.1 |
Operating earnings |  |  | — |  |  | $ | 54.1 |

25. |  | Commitments and Contingencies

| (a) |  | On February 12, 2004, Cameco, Cameco Bruce Holdings II Inc., BPC Generation Infrastructure Trust and TransCanada Pipelines Limited (collectively, the “Consortium”) sent a notice of claim to British Energy Limited and British Energy International Holdings Limited (collectively, BE) requesting, amongst other things, indemnification for breach of a representation and warranty contained in the February 14, 2003, Amended and Restated Master Purchase Agreement. The alleged breach is that the Unit 8 steam generators were not “in good condition, repair and proper working order, having regard to their use and age.” This defect was discovered during a planned outage conducted just after closing. As a result of this defect, the planned outage had to be significantly extended. The Consortium has claimed damages in the amount of $64,558,200 being 79.8% of the $80,900,000 of damages actually incurred, plus an unspecified amount to take into account the reduced operating life of the steam generators. By agreement of the parties, an arbitrator has been appointed to arbitrate the claims and a schedule has been set for the next steps in the proceeding.
|  |  | The Consortium served its claim on October 21, 2008, and has amended it as required, most recently on August 7, 2009. BE served its answer and counter-statement on December 22, 2008, most recently amended on March 25, 2010, and the Consortium served its reply and answer to counter-statement on January 22, 2009, most recently amended on August 7, 2009.
|  |  | The Unit 8 steam generators require on-going monitoring and maintenance as a result of the defect. In addition to the $64,558,200 in damages sought in the notice of claim, the claim seeks an additional $4,900,000 spent on inspection, monitoring and maintenance of Unit 8, and $31,900,000 in costs for future monitoring and maintenance, as well as repair costs and lost revenue due to anticipated unplanned outages as a consequence of the defect in Unit 8. The initial claim had also sought damages for the early replacement of the Unit 8 steam generators due to the defect shortening their useful operating lives. However, recent inspection data and analysis of the condition of the Unit 8 steam generators now indicates that they will continue to function until the end of the Consortium’s lease of the Bruce Power facility in 2018, as was expected at the time the MPA was entered into. The claim for early replacement was thus abandoned via an amendment to the claim on August 7, 2009. The arbitration hearing was completed on November 23, 2010 and final oral arguments are scheduled for June 1, 2011.
|  |  | In anticipation of this claim, BE issued on February 10, 2006, and then served on Ontario Power Generation Inc. (OPG) and Bruce Power LP a Statement of Claim. This Statement of Claim seeks damages for any amounts that BE is found liable to pay to the Consortium in connection with the Unit 8 steam generator arbitration described above, damages in the amount of $500,000,000, costs and pre and post judgment interest amongst other things. Further proceedings in this action are on hold pending completion of the arbitration hearing.
| (b) |  | Annual supplemental rents of $30,000,000 (subject to CPI) per operating reactor are payable by BPLP to OPG. Should the hourly annual average price of electricity in Ontario fall below $30 per megawatt hour, the supplemental rent reduces to $12,000,000 per operating reactor. In accordance with the Sublease Agreement, Bruce A L.P. will participate in its share of any adjustments to the supplemental rent.

136 cameco corporation

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| (c) |  | Cameco, TransCanada and BPC have assumed the obligations to provide financial guarantees on behalf of BPLP. Cameco has provided the following financial assurances, with varying terms that range from 2011 to 2018:

| i) |  | Guarantees to customers under power sales agreements of up to $35,300,000. At December 31, 2010, Cameco’s actual exposure under these guarantees was $24,000,000.
| ii) |  | Termination payments to OPG pursuant to the lease agreement of $58,300,000. The fair value of these guarantees is nominal.

| (d) |  | Under a supply contract with the Ontario Power Authority (OPA), BPLP is entitled to receive payments from the OPA during periods when the market price for electricity in Ontario is lower than the floor price defined under the agreement during a calendar year. On July 6, 2009, BPLP and the OPA amended the supply contract such that beginning in 2009, the annual payments received will not be subject to repayment in future years. Previously, the payments received under the agreement were subject to repayment during the entire term of the contract, dependent on the spot price in future periods. BPLP’s entitlement to receive these payments remains in effect until December 31, 2019 but the generation that is subject to these payments starts to decrease in 2016, reflecting the original estimated lives for the Bruce B units. During 2010, BPLP recorded $339,000,000 under this agreement which was recognized as revenue with Cameco’s share being $107,000,000. Of the amount recorded, BPLP currently expects to repay $4,000,000.
| (e) |  | Cameco’s North American workforce includes about 3,300 employees, of which approximately 900 (27%) belong to three separate labour unions.
| (f) |  | At December 31, 2010, Cameco’s purchase commitments, the majority of which are fixed price uranium and conversion purchase arrangements, were as follows:

|  | (Millions (US)) |
2011 |  | $ | 267 |
2012 |  |  | 226 |
2013 |  |  | 397 |
2014 |  |  | 114 |
2015 |  |  | 60 |
Thereafter |  |  | 6 |
Total |  | $ | 1,070 |

26. |  | Financial Instruments
|  | The majority of revenues at Cameco are derived from the sale of uranium products, and electricity through its investment in BPLP. Cameco’s uranium product financial results are closely related to the long and short-term market price of uranium sales and conversion services. Prices fluctuate and can be affected by demand for nuclear power, worldwide production and uranium levels, and political and economic conditions in uranium producing and consuming countries. BPLP’s revenue from electricity is affected by changes in electricity prices associated with an open spot market for electricity in Ontario. Financial results for Cameco are also impacted by changes in foreign currency exchange rates and other operating risks. Finally, certain financial assets are subject to credit risks, including cash and securities, accounts receivable, and commodity and currency instruments.
|  | To mitigate risks associated with certain financial assets, Cameco will hold positions with a variety of large creditworthy institutions. Sales of uranium products, with short payment terms, are made to customers that management believes are creditworthy.
|  | To mitigate risks associated with foreign currency on its sale of uranium products, Cameco enters into forward sales contracts to establish a price for future delivery of the foreign currency.

2010 Annual Financial review 137

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|  | Cameco is exposed to interest rate risk through its interest rate swap contracts whereby fixed rate payments on a notional amount of $135,000,000 of the Series C senior unsecured debentures were swapped for variable rate payments. The swaps terminate on March 16, 2015. Under the terms of the swaps, Cameco makes interest payments based on three-month bankers acceptance rate plus an average margin of 1.81% and receives fixed interest payments of 4.7%. To mitigate this risk, Cameco entered into interest rate cap arrangements, effective March 18, 2013, whereby the three-month bankers acceptance rate was capped at 5.0% such that total variable payments will not exceed, on average 6.81%. At December 31, 2010, the mark-to-market gain on Cameco’s interest rate swaps and caps less premiums paid was $1,458,000.
|  | To mitigate risks associated with the fluctuations in the market price for uranium products, Cameco seeks to maintain a portfolio of uranium product sales contracts with a variety of delivery dates and pricing mechanisms that provide a degree of protection from price volatility. To mitigate risks associated with the fluctuations in the market price for electricity, BPLP enters into various energy and sales related contracts that qualify as cash flow hedges. These instruments have terms ranging from 2011 to 2016. At December 31, 2010, the mark-to-market gain on BPLP’s sales contracts was $29,000,000.
|  | All financial instruments measured at fair value are categorized into one of three hierarchy levels, described below, for disclosure purposes. Each level is based on the transparency of the inputs used to measure the fair values of assets and liabilities:

Level 1 — Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.
Level 2 — Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.
Level 3 — Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

|  | When the inputs used to measure fair value fall within more than one level of the hierarchy, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measure in its entirety.
|  | Except as otherwise disclosed, the fair market value of Cameco’s financial assets and liabilities approximates the carrying amount as a result of the short-term nature of the instruments, or the variable interest rate associated with the instruments, or the fixed interest rate of the instruments being similar to market rates.
|  | The fair values of Cameco’s privately held available-for-sale securities, as described in note 9, have not been disclosed because of the unavailability of a quoted market price in an active market. Cameco does not currently have plans to dispose of any of these investments.

138 cameco corporation

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|  | The following tables present Cameco’s fair value hierarchy for those assets and liabilities measured at fair value on a recurring basis.

As at December 31, 2010

Description |  | Total |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |
Derivative instrument assets |  | $ | 127,842 |  |  | $ | — |  |  | $ | 122,786 |  |  | $ | 5,056 |
Available-for-sale securities [notes 5, 9] |  |  | 889,065 |  |  |  | 889,065 |  |  |  | — |  |  |  | — |
Derivative instrument liabilities |  |  | (35,227 | ) |  |  | — |  |  |  | (35,227 | ) |  |  | — |
Net |  | $ | 981,680 |  |  | $ | 889,065 |  |  | $ | 87,559 |  |  | $ | 5,056 |

As at December 31, 2009

Description |  | Total |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |
Derivative instrument assets |  | $ | 210,381 |  |  | $ | — |  |  | $ | 197,381 |  |  | $ | 13,000 |
Available-for-sale securities [notes 5, 9] |  |  | 207,473 |  |  |  | 207,473 |  |  |  | — |  |  |  | — |
Derivative instrument liabilities |  |  | (40,957 | ) |  |  | — |  |  |  | (39,957 | ) |  |  | (1,000 | )
Net |  | $ | 376,897 |  |  | $ | 207,473 |  |  | $ | 157,424 |  |  | $ | 12,000 |

|  | The fair value of a financial instrument is the amount at which the financial instrument could be exchanged in an arm’s-length transaction between knowledgeable and willing parties under no compulsion to act. Fair values of identical instruments traded in active markets are determined by reference to last quoted prices, in the most advantageous active market for that instrument. In the absence of an active market, we determine fair values based on quoted prices for instruments with similar characteristics and risk profiles. Fair values of financial instruments determined using valuation models require the use of inputs. In determining those inputs, we look primarily to external, readily observable market inputs, when available, including factors such as interest rate yield curves, currency rates, and price and rate volatilities, as applicable. In some circumstances, we use input parameters that are not based on observable market data. In these cases, we may adjust model values to reflect the valuation uncertainty in order to determine what the fair value would be based on the assumptions that market participants would use in pricing the financial instrument. These adjustments are made in order to determine the fair value of the instruments.
|  | We make valuation adjustments for the credit risk of our derivative portfolios in order to arrive at their fair values. These adjustments take into account the creditworthiness of our counterparties.
|  | Equity-accounted investments and financial instruments classified as available-for-sale comprise actively traded debt and equity securities and are carried at fair value based on available quoted prices.
|  | There were no significant transfers between level 1 and level 2 of the fair value hierarchy. Transfers into level 3 are comprised of BPLP derivative financial instruments with contract terms extending beyond 36 months. Due to the decline in electricity prices as a result of the recession, the liquidity in the market has been significantly reduced, resulting in a lack of an active market and observable market inputs beyond 36 months.

2010 Annual Financial review 139

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|  | Derivatives
|  | The following tables summarize the fair value of derivatives and classification on the balance sheet:

As at December 31, 2010

|  | Cameco |  |  | BPLP |  |  | Total |
Non-hedge derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Embedded derivatives — sales contracts |  | $ | (3,864 | ) |  | $ | 18,877 |  |  | $ | 15,013 |
Foreign currency contracts |  |  | 47,144 |  |  |  | — |  |  |  | 47,144 |
Interest rate contracts |  |  | 1,458 |  |  |  | — |  |  |  | 1,458 |
Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |
Energy and sales contracts |  |  | — |  |  |  | 29,000 |  |  |  | 29,000 |
Net |  | $ | 44,738 |  |  | $ | 47,877 |  |  | $ | 92,615 |
Classification: |  |  |  |  |  |  |  |  |  |  |  |
Current portion of long-term receivables, investments and other [note 9] |  | $ | 46,629 |  |  | $ | 44,505 |  |  | $ | 91,134 |
Long-term receivables, investments and other [note 9] |  |  | 3,382 |  |  |  | 33,326 |  |  |  | 36,708 |
Current portion of other liabilities [note 13] |  |  | (377 | ) |  |  | (20,662 | ) |  |  | (21,039 | )
Other liabilities [note 13] |  |  | (4,896 | ) |  |  | (9,292 | ) |  |  | (14,188 | )
Net |  | $ | 44,738 |  |  | $ | 47,877 |  |  | $ | 92,615 |

As at December 31, 2009

|  | Cameco |  |  | BPLP |  |  | Total |
Non-hedge derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Embedded derivatives — sales contracts |  | $ | (2,736 | ) |  | $ | 9,082 |  |  | $ | 6,346 |
Foreign currency contracts |  |  | 67,031 |  |  |  | — |  |  |  | 67,031 |
Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |
Energy and sales contracts |  |  | — |  |  |  | 96,047 |  |  |  | 96,047 |
Net |  | $ | 64,295 |  |  | $ | 105,129 |  |  | $ | 169,424 |
Classification: |  |  |  |  |  |  |  |  |  |  |  |
Current portion of long-term receivables, investments and other [note 9] |  | $ | 66,972 |  |  | $ | 87,439 |  |  | $ | 154,411 |
Long-term receivables, investments and other [note 9] |  |  | 1,460 |  |  |  | 54,510 |  |  |  | 55,970 |
Current portion of other liabilities [note 13] |  |  | (445 | ) |  |  | (19,595 | ) |  |  | (20,040 | )
Other liabilities [note 13] |  |  | (3,692 | ) |  |  | (17,225 | ) |  |  | (20,917 | )
Net |  | $ | 64,295 |  |  | $ | 105,129 |  |  | $ | 169,424 |

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|  | The following tables summarize different components of the (gains) and losses on derivatives:

For the year ended December 31, 2010

|  | Cameco |  |  | BPLP |  |  | Total |
Non-hedge derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Embedded derivatives — sales contracts |  | $ | 1,623 |  |  | $ | 2,785 |  |  | $ | 4,408 |
Foreign currency contracts |  |  | (80,107 | ) |  |  | — |  |  |  | (80,107 | )
Interest rate contracts |  |  | (2,482 | ) |  |  | — |  |  |  | (2,482 | )
Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |
Energy and sales contracts |  |  | — |  |  |  | 2,998 |  |  |  | 2,998 |
Net |  | $ | (80,966 | ) |  | $ | 5,783 |  |  | $ | (75,183 | )

For the year ended December 31, 2009

|  | Cameco |  |  | BPLP |  |  | Total |
Non-hedge derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Embedded derivatives — sales contracts |  | $ | (4,764 | ) |  | $ | (4,737 | ) |  | $ | (9,501 | )
Foreign currency contracts |  |  | (234,066 | ) |  |  | — |  |  |  | (234,066 | )
Interest rate contracts |  |  | 401 |  |  |  | — |  |  |  | 401 |
Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |
Energy and sales contracts |  |  | — |  |  |  | (638 | ) |  |  | (638 | )
Net |  | $ | (238,429 | ) |  | $ | (5,375 | ) |  | $ | (243,804 | )

|  | Over the next 12 months, based on current exchange rates, Cameco expects an estimated $5,573,000 of pre-tax gains from the foreign currency cash flow hedges to be reclassified through other comprehensive income to net earnings. The maximum length of time Cameco hedges its exposure to the variability in future cash flows related to foreign currency on anticipated transactions is five years.
|  | Over the next 12 months, based on current prices, Cameco expects an estimated $18,012,000 of pre-tax gains from BPLP’s various energy and sales related cash flow hedges to be reclassified through other comprehensive income to net earnings. The maximum length of time BPLP is hedging its exposure to the variability in future cash flows related to electricity prices on anticipated transactions is six years.
|  | Currency
|  | At December 31, 2010, Cameco had $1,317,500,000 (US) in forward contracts at an average exchange rate of $1.03 and €93,000,000 at an average exchange rate of $1.35. The foreign currency contracts are scheduled for use as follows:

(Millions) |  | US |  |  | Rate |  |  | Cdn |  |  | Euro |  |  | Rate |  |  | US |
2011 |  | $ | 890 |  |  |  | 1.03 |  |  | $ | 917 |  |  | € | 45 |  |  |  | 1.35 |  |  | $ | 61 |
2012 |  |  | 363 |  |  |  | 1.04 |  |  |  | 378 |  |  |  | 46 |  |  |  | 1.35 |  |  |  | 62 |
2013 |  |  | 65 |  |  |  | 1.03 |  |  |  | 67 |  |  |  | — |  |  |  | — |  |  |  | — |
Thereafter |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2 |  |  |  | 1.34 |  |  |  | 3 |
Total |  | $ | 1,318 |  |  |  | 1.03 |  |  | $ | 1,362 |  |  | € | 93 |  |  |  | 1.35 |  |  | $ | 126 |

|  | These positions consist entirely of forward sales contracts. The average exchange rate reflects the current forward contract price. Of these amounts, $1,252,500,000 of the US-denominated contracts and $93,000,000 of the Euro-denominated contracts mature in 2011. The remaining $65,000,000 in US-denominated contracts matures in 2012.

2010 Annual Financial review 141

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27. |  | Per Share Amounts
|  | Per share amounts have been calculated based on the weighted average number of common shares outstanding during the year. The weighted average number of paid shares outstanding in 2010 was 393,168,523 (2009 — 387,955,503).

|  | 2010 |  |  | 2009 |
Basic earnings per share computation |  |  |  |  |  |  |  |
Net earnings |  | $ | 514,749 |  |  | $ | 1,099,422 |
Weighted average common shares outstanding |  |  | 393,169 |  |  |  | 387,956 |
Basic earnings per common share |  | $ | 1.31 |  |  | $ | 2.83 |
Diluted earnings per share computation |  |  |  |  |  |  |  |
Net earnings |  | $ | 514,749 |  |  | $ | 1,099,422 |
Weighted average common shares outstanding |  |  | 393,169 |  |  |  | 387,956 |
Dilutive effect of stock options |  |  | 1,850 |  |  |  | 1,977 |
Weighted average common shares outstanding, assuming dilution |  |  | 395,019 |  |  |  | 389,933 |
Diluted earnings per common share |  | $ | 1.30 |  |  | $ | 2.82 |

28. |  | Segmented Information
|  | Cameco has three reportable segments: uranium, fuel services and electricity. The uranium segment involves the exploration for, mining, milling, purchase and sale of uranium concentrate. The fuel services segment involves the refining, conversion and fabrication of uranium concentrate and the purchase and sale of conversion services. The electricity segment involves the generation and sale of electricity.
|  | Cameco’s reportable segments are strategic business units with different products, processes and marketing strategies.
|  | Accounting policies used in each segment are consistent with the policies outlined in the summary of significant accounting policies.

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(a) Business Segments
2010

|  |  |  |  |  | Fuel |  |  |  |  |  |  | Inter- |  |  |  |
(Millions) |  | Uranium |  |  | Services |  |  | Electricity |  |  | Segment |  |  | Total |
Revenue |  | $ | 1,373.7 |  |  | $ | 300.6 |  |  | $ | 476.7 |  |  | $ | (27.3 | ) |  | $ | 2,123.7 |
Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Products and services sold |  |  | 698.5 |  |  |  | 213.6 |  |  |  | 246.4 |  |  |  | (30.6 | ) |  |  | 1,127.9 |
Depreciation, depletion and reclamation |  |  | 171.8 |  |  |  | 26.9 |  |  |  | 52.5 |  |  |  | 0.3 |  |  |  | 251.5 |
Exploration |  |  | 95.8 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 95.8 |
Other |  |  | (2.8 | ) |  |  | 14.3 |  |  |  | — |  |  |  | — |  |  |  | 11.5 |
Cigar Lake remediation |  |  | 16.6 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 16.6 |
Loss on sale of assets |  |  | 0.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.1 |
Non-segmented expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 88.7 |
Earnings before income taxes and minority interest |  |  | 393.7 |  |  |  | 45.8 |  |  |  | 177.8 |  |  |  | 3.0 |  |  |  | 531.6 |
Income tax expense |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 27.3 |
Minority interest |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (10.4 | )
Net earnings |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 514.7 |
Assets |  | $ | 6,317.4 |  |  | $ | 395.9 |  |  | $ | 863.8 |  |  | $ | — |  |  | $ | 7,577.1 |
Intangibles |  | $ | — |  |  | $ | 94.3 |  |  | $ | — |  |  | $ | — |  |  | $ | 94.3 |
Capital expenditures for the year |  | $ | 415.2 |  |  | $ | 20.2 |  |  | $ | 34.9 |  |  | $ | — |  |  | $ | 470.3 |

2009

|  |  |  |  |  | Fuel |  |  |  |  |  |  | Inter- |  |  |  |
(Millions) |  | Uranium |  |  | Services |  |  | Electricity |  |  | Segment |  |  | Total |
Revenue |  | $ | 1,551.3 |  |  | $ | 276.3 |  |  | $ | 518.3 |  |  | $ | (30.9 | ) |  | $ | 2,315.0 |
Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Products and services sold |  |  | 901.4 |  |  |  | 203.9 |  |  |  | 243.5 |  |  |  | (24.5 | ) |  |  | 1,324.3 |
Depreciation, depletion and reclamation |  |  | 161.9 |  |  |  | 22.8 |  |  |  | 55.6 |  |  |  | 0.3 |  |  |  | 240.6 |
Exploration |  |  | 49.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 49.1 |
Other |  |  | 15.9 |  |  |  | 21.3 |  |  |  | — |  |  |  | — |  |  |  | 37.2 |
Cigar Lake remediation |  |  | 17.9 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 17.9 |
Gain on sale of assets |  |  | (0.6 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (0.6 | )
Non-segmented expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (120.4 | )
Earnings (loss) before income taxes and minority interest |  |  | 405.7 |  |  |  | 28.3 |  |  |  | 219.2 |  |  |  | (6.7 | ) |  |  | 766.9 |
Income tax expense |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 52.9 |
Minority interest |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (3.0 | )
Net earnings from continuing operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 717.0 |
Assets |  | $ | 5,989.7 |  |  | $ | 383.9 |  |  | $ | 922.6 |  |  | $ | — |  |  | $ | 7,296.2 |
Intangibles |  | $ | — |  |  | $ | 97.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 97.7 |
Capital expenditures for the year |  | $ | 333.3 |  |  | $ | 20.7 |  |  | $ | 38.7 |  |  | $ | — |  |  | $ | 392.7 |

2010 Annual Financial review 143

#####

(b) Geographic Segments

(Millions) |  | 2010 |  |  | 2009 |
Revenue from products and services |  |  |  |  |  |  |  |
Canada — domestic |  | $ | 689.0 |  |  | $ | 739.2 |
— export |  |  | 102.9 |  |  |  | 194.9 |
United States |  |  | 1,331.8 |  |  |  | 1,380.9 |
|  | $ | 2,123.7 |  |  | $ | 2,315.0 |
Assets |  |  |  |  |  |  |  |
Canada |  | $ | 5,819.8 |  |  | $ | 5,774.5 |
United States |  |  | 670.77 |  |  |  | 695.9 |
Australia |  |  | 607.9 |  |  |  | 553.1 |
Europe |  |  | 342.8 |  |  |  | 139.0 |
Kazakhstan |  |  | 230.1 |  |  |  | 231.4 |
|  | $ | 7,671.4 |  |  | $ | 7,393.9 |

| (c) |  | Major Customers
|  |  | Cameco relies on a small number of customers to purchase a significant portion of its uranium concentrates and uranium conversion services. During 2010, revenues from one customer of Cameco’s uranium and fuel services segments represented approximately $125,657,000 (2009 — $252,699,000), about 8% (2009 — 14%) of Cameco’s total revenues from these segments. As customers are relatively few in number, accounts receivable from any individual customer may periodically exceed 10% of accounts receivable depending on delivery schedules.
|  |  | During 2010, electricity revenues from one customer of BPLP represented approximately 7% (2009 — 5%) of BPLP’s total revenues.

| 29. |  | Talvivaara Agreement
|  |  | On February 7, 2011, Cameco signed two agreements with Talvivaara Mining Company Plc. to buy uranium produced at the Sotkamo nickel-zinc mine in Finland. Under the first agreement with Talvivaara, Cameco will provide an up-front payment, to a maximum of $60,000,000 (US) to cover certain construction costs. This amount will be repaid through deliveries of uranium concentrate. Once the full amount has been repaid, Cameco will continue to purchase the uranium concentrates produced at the Sotkamo mine through a second agreement which provides for the purchase of uranium using a pricing formula that references market prices at the time of delivery. The second agreement expires on December 31, 2027.
| 30. |  | Related Party Transactions
|  |  | Cameco purchases a significant amount of goods and services for its Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One such supplier is Points Athabasca Contracting Ltd. and the president of the company became a member of the board of directors of Cameco during 2009. In 2010, Cameco paid Points Athabasca Contracting Ltd. $38,000,000 (2009 — $30,800,000) for construction and contracting services. The transactions were conducted in the normal course of business and were accounted for at the exchange amount. Accounts payable include a balance of $2,290,000 (2009 — $230,000) resulting from these transactions.
| 31. |  | Comparative Figures
|  |  | Certain prior year balances have been reclassified to conform to the current financial statement presentation.

144 cameco corporation

#####

Common Shares
Toronto (CCO) | New York (CCJ)
Transfer Agents and Registrars
For information on common share holdings, dividend cheques,
lost share certificates and address changes, contact:

In Canada: |  | In the United States:
CIBC Mellon Trust Company |  | BNY Mellon Shareowner Services
P.O. Box 7010 |  | 480 Washington Blvd.
Adelaide Street Postal Station |  | Jersey City, New Jersey 07310
Toronto, Ontario M5C 2W9 |  | U.S.A.
Canada |  |

Telephone:
1-800-387-0825 (toll-free within Canada and the United States)
OR
1-416-643-5500 (from any country other than Canada
and the United States)
Fax:
1-416-643-5501 (all countries)
cibcmellon.com/investorinquiry
Annual Meeting
The annual meeting of shareholders of Cameco Corporation is scheduled
to be held on Tuesday, May 17, 2011 at 1:30 p.m. at Cameco’s head office
in Saskatoon, Saskatchewan.
Dividend Policy
The board of directors has established a policy of paying a quarterly dividend of
$0.10 ($0.40 per year) per common share for 2011. This policy will be reviewed
from time to time in light of the company’s cash flow, earnings, financial position
and other relevant factors.
Inquiries
Cameco Corporation
2121 — 11th Street West
Saskatoon, Saskatchewan S7M 1J3
Phone: 306-956-6200
Fax: 306-956-6201

#####

With 476 million pounds of proven and probable U3O3 reserves, Cameco has the potential to “Double U” by 20118.