EX-99.5 6 o61001exv99w5.htm EX-99.5
Exhibit 99.5
Focused on
Cameco
2009 Annual Report

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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, our expectation that Cigar Lake will begin production mid 2013, 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 “About forward-looking information”.

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URANIUM

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 surface mining economical. Tunnels and shafts provide access to the ore.
| • |  | In situ recovery (ISR) does not require 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 ground rock and other solid waste (tailings) is placed in an engineered tailings facility.

FUEL SERVICES

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.

ELECTRICITY

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, Japanese and Russian reactors.

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Message from the Chair
Dear Shareholder,
There has never been a better time to invest in Cameco. The company’s fundamentals are strong, world demand for electricity continues to grow and there is a ready and growing market for uranium as more and more countries recognize the benefits of nuclear power as a source of clean electricity.
Your board of directors is charged with overseeing management to ensure the company stays on course to achieve its strategy and deliver value to you, the shareholder. Our primary responsibility is ensuring sound governance, strictly adhering to our high standards of integrity and ethics, and being steadfast in our compliance with corporate governance standards as a publicly listed company in both Canada and the U.S.
The board is actively engaged in monitoring the key risks Cameco faces. This is especially important as the company focuses on achieving growth by doubling production by 2018 and tapping the full potential of the nuclear fuel cycle. Cameco’s enterprise risk management system helps management identify, assess, manage, and report on risks in a systematic way, following principles that help identify and mitigate any uncertainties that could have a negative impact on its business activities. And while the company faces many kinds of risk — financial, operational, environmental, compensation, reputational — the board is well aware of the growing world attention on executive compensation. The human resources and compensation committee continued its review of compensation risk as part of our ongoing focus on sound governance.
Board renewal is an important aspect of our ability to effectively carry out our duties on behalf of shareholders.
This year we welcomed James Gowans and Donald Deranger to the board. As chief operating officer and chief technical officer of DeBeers SA, president and CEO of DeBeers Canada Inc., chair of the Mining Association of Canada, and past president of the Canadian Institute on Mining Metallurgy and Petroleum for 2008-2009, Mr. Gowans brings considerable mining expertise to the board. Mr. Deranger is a northern Saskatchewan aboriginal leader and Athabasca vice-chief of the Prince Albert Grand Council, and has won a number of awards for his initiatives in employment, training and economic development for members of the Athabasca sector of northern Saskatchewan. On behalf of the board, I would also like to thank George Dembroski and Robert Peterson for their contributions and dedication. Both have reached our retirement age for directors and will be leaving the board as of the annual meeting of shareholders in May.
Also this year, the board revised our skills matrix to align it more closely with our strategic focus, and reviewed the diversity of the board to ensure an effective mix of directors. We will use the new matrix to enhance the skills of the current board and to recruit new directors in the future.
We are proud of Cameco’s accomplishments in 2009 and we look forward to 2010.
Victor J. Zaleschuk
Chair of the Board
February 23, 2010

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Message from the President and CEO
Dear Shareholder,
Cameco is a unique company with a very bright future.
We are among the world’s largest players in a market where demand is growing and it is clear there will be a shortage of supply. We have a world-class body of assets to draw from, and the financial strength, expertise and discipline we need to grow. We believe strongly in our values, and apply them consistently in our operations and business dealings. We have planted our flag from one end of the nuclear fuel cycle to the other, and are recognized around the world as a reliable supplier and business partner, strong community supporter, international problem solver and employer of choice.
2009: a year of successes
This year, we sold our interest in Centerra under very favourable terms. This put us in an excellent financial position, and turned us into pure-play nuclear energy investment with enormous potential.
We delivered the highest net earnings ever, at $1.1 billion (an increase of 144% over last year), increased cash from continuing operations by 30%, and ended the year with $1.3 billion in cash on hand. We increased production in our uranium segment by 20%, and accomplished a mining first, reaching a new mining zone at McArthur River/Key Lake through the water-saturated Athabasca sandstone, largely because of our innovative freezewall design. We completed dewatering the underground development at Cigar Lake in February 2010, and based on current information, expect production to begin in mid-2013. We resumed UF6 production at Port Hope and operations returned to normal. And our share of earnings before taxes from our electricity segment increased by 59% to $224 million.
A growing market
According to the OECD, population growth and industrial development will lead to a near doubling of electricity consumption by 2030. At the same time, governments, media and consumers are becoming more aware of the dangers and effects of air pollution and climate change, and the importance of low-emission sources of electricity.
Customers need electricity regardless of world economic conditions, and nuclear power is an affordable and sustainable source of clean, renewable energy. The demand for uranium is expected to continue to grow, and along with it, the need for new supply to meet future customer requirements. Turn to page 10 to read more about the nuclear energy industry and our expectations for demand and supply.
A clear view ahead
Our strategy is to double uranium production to 40 million pounds by 2018, which we plan to accomplish with our existing operating and development properties, and projects we are currently evaluating. Our fuel services segment is helping to support this growth by broadening our business relationships and expanding our uranium market share. And our investment in the Bruce Power Limited Partnership is an excellent source of cash flow and a logical fit with our other businesses. Turn to page 15 to read more about our growth plans.
While doubling production is an ambitious target, we believe we have the assets, expertise and focus to achieve it. Our strong financial position, developed over many years, combined with a commitment to operational excellence, position us well to deliver on our strategy. We have clearly defined objectives and a reward system designed to support them within our tolerance for risk. Disciplined processes are in place to manage our portfolio, control risk, improve operations and reduce costs. And we have an unwavering commitment to safety, sustainable development and building supportive communities. You’ll learn more about what makes our company strong starting on page 18.

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A long-term approach
We believe that sustainability means thinking about the long-term viability of the work we do, and not just meeting minimum standards.
It means being innovative about making our impact on the environment as small and as temporary as we can. And it means promoting safety and providing benefits to the communities we operate in no matter where they are, so future generations can advance and prosper in the way we have. For example, in 2009, over half of the employees at our mines in northern Saskatchewan were from local communities, and about $220 million in mine spending went to northern businesses.
Actions like these build shareholder value and ensure we retain our social licence to deliver the significant benefits of nuclear energy to people around the world. They are, in fact, an investment in the future of our industry.
A strong culture
Corporations really are a group of people working to accomplish objectives they all agree on. Our company is filled with people of strong character and solid individual values for doing good. They have established an equally strong corporate culture with well defined values. They are committed to advancing our strategies following our principles of sustainable development. And this year I’m happy to say that they told us they’re satisfied with their work: Cameco was included in the Financial Post’s 10 Best Companies to Work For in Canada for 2010, for our employee policies, programs and role in the community, and in November 2009, Mediacorp named us one of Canada’s Top 100 Employers.
I’m proud to have such a capable, creative and committed team, and look forward to the many accomplishments ahead.
Jerry Grandey
President & CEO
February 23, 2010

Management’s discussion and analysis |  |  |  |
2009 Highlights |  |  | 6 |
About Cameco |  |  | 8 |
About the nuclear energy industry |  |  | 10 |
Our strategy |  |  | 15 |
Financial results |  |  | 24 |
Our operations and development projects |  |  | 49 |
Reserves and resources |  |  | 77 |
Additional information |  |  | 81 |
2009 consolidated financial statements |  |  |  |
Report of management’s accountability |  |  | 87 |
Auditor’s report |  |  | 88 |
Consolidated financial statements |  |  | 89 |
Notes to consolidated financial statements |  |  | 94 |
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, 2009. The information is based on what we knew as of February 23, 2010.
We encourage you to read our audited consolidated financial statements as you review the 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 a decision to invest in 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 prepare a reconciliation of our annual financial statements to US GAAP, which is 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 78.
About forward-looking information
Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans and 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: anticipate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples on page 5).
• |  | 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, because of 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 it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

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Examples of forward-looking information in this MD&A

• |  | our expectations about future worldwide uranium supply and demand
• |  | production at our uranium operations from 2010 to 2014 and our target for doubling annual production by 2018
• |  | our ability to maintain expected annual production at McArthur River and Key Lake within the time frames we have set, to complete remediation and begin production at Cigar Lake within the time frames we have set and at the estimated cost, and to achieve our annual production targets at Inkai
• |  | our expectations that our existing cash balances and operating cash flows will be sufficient to meet our anticipated requirements over the next several years without the need for any significant additional financing
• |  | future production at our fuel services operations
• |  | the likely terms and volumes to be covered by long-term delivery contracts that we enter into in 2010 and future years
• |  | future royalty and tax payments and rates
• |  | our long-term uranium price sensitivity analysis
• |  | our 2010 objectives
• |  | the outlook for each of our operating segments for 2010, and our consolidated outlook for the year

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, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate
• |  | we are unable to enforce our legal rights, or are subject to litigation or arbitration that has an adverse outcome
• |  | there are defects in title to our properties
• |  | our 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
• |  | 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 (like Kazakhstan)
• |  | we are affected by terrorism, sabotage, 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
• |  | we are affected by natural phenomena, including inclement weather, fire, flood, underground floods, earthquakes, pitwall failure and cave-ins
• |  | 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, labour relations issues, strikes or lockouts and other developments and operating risks

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 39, Long-term price sensitivity analysis: uranium
• |  | tax rates, foreign currency exchange rates and interest rates
• |  | decommissioning and reclamation expenses
• |  | reserve and resource estimates
• |  | the geological, hydrological and other conditions at our mines, including the accuracy of our expectations about the condition of underground workings at Cigar Lake
• |  | 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, natural disasters, governmental or political actions, litigation or arbitration proceedings, labour relations issues, or other development or operating risks

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2009 Highlights
Cameco is 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.
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 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

We made significant progress this year both financially and at our operations.
Strong financial performance
2009 was a record financial year for us.
We delivered the highest net earnings ever, at $1.1 billion (144% higher than last year) and increased cash from continuing operations by 30%, to $690 million. Cash on hand increased to $1.3 billion at year end. We intend to use these funds to advance our growth strategy.

Highlights |  |  |  |  |  |  |  |  |  |  |  |  |
December 31 ($ millions except where indicated) |  |  |  |  |  | 2009 |  |  | 2008 |  |  | change |
Revenue |  |  | 2,315 |  |  |  | 2,183 |  |  |  | 6 | %
Gross profit |  |  | 750 |  |  |  | 829 |  |  |  | (10 | )%
Net earnings |  |  | 1,099 |  |  |  | 450 |  |  |  | 144 | %
$ per common share (diluted) |  |  | 2.82 |  |  |  | 1.28 |  |  |  | 120 | %
Adjusted net earnings (non-GAAP, see page 27) |  |  | 582 |  |  |  | 589 |  |  |  | (1 | )%
$ per common share (adjusted and diluted) |  |  | 1.49 |  |  |  | 1.67 |  |  |  | (11 | )%
Cash provided by continuing operations |  |  | 690 |  |  |  | 530 |  |  |  | 30 | %
Average realized prices |  | $US/lb |  |  | 38.25 |  |  |  | 39.52 |  |  |  | (3 | )%
Uranium |  | $Cdn/lb |  |  | 45.12 |  |  |  | 43.91 |  |  |  | 3 | %
Fuel services |  | $Cdn/kgU |  |  | 17.84 |  |  |  | 15.85 |  |  |  | 13 | %
Electricity |  | $Cdn/MWh |  |  | 64 |  |  |  | 57 |  |  |  | 12 | %

Shares and stock options outstanding
At February 22, 2010, we had:

• |  | 392,853,733 common shares and one Class B share outstanding
• |  | 7,939,833 stock options outstanding, with exercise prices ranging from $5.75 to $55.00

Dividend policy
Our board of directors has established a policy of paying a quarterly dividend of $0.07 ($0.28 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 at our operations
In our uranium segment this year we increased production by 20%. Key highlights:

• |  | Successfully moved to a new mining zone at McArthur River/Key Lake, through the water-saturated Athabasca sandstone — a mining first, and largely as a result of our innovative freezewall design. We also reduced the amount of molybdenum and selenium released to the environment.
• |  | Extended Rabbit Lake’s expected production life by two years to 2015.
• |  | Commissioned Inkai’s main processing plant, and started commissioning the first satellite plant.
• |  | Completed dewatering the underground development at Cigar Lake in February 2010, and based on current information, expect initial production in mid-2013.

In our fuel services segment, we resumed UF6 production at Port Hope and operations returned to normal.
In our electricity segment, BPLP generated 24.6 million terawatt hours (TWh) of electricity, at a capacity factor of 87%. Our share of earnings before taxes went up by 59% to $224 million.
We continued to invest in our exploration activities, spending $23 million in six brownfield and advanced exploration projects, including $11 million for delineation drilling at Kintyre, plus about $31 million in regional exploration programs. Saskatchewan was the largest single region, followed by Australia, northern Canada and the rest of the global program.

Highlights |  |  |  |  |  | 2009 |  |  | 2008 |  |  | change |
Uranium |  | Production volume (million lbs) |  |  | 20.8 |  |  |  | 17.3 |  |  |  | 20 | %
|  | Revenue ($millions) |  |  | 1,551 |  |  |  | 1,512 |  |  |  | 3 | %
Fuel services |  | Production volume (million kgU) |  |  | 12.3 |  |  |  | 8.3 |  |  |  | 48 | %
|  | Revenue ($millions) |  |  | 276 |  |  |  | 252 |  |  |  | 10 | %
Electricity |  | Output (100%) (TWh) |  |  | 24.6 |  |  |  | 24.7 |  |  |  | — |
|  | Revenue (100%) |  |  | 1,640 |  |  |  | 1,409 |  |  |  | 16 | %
|  | Our share of earnings before taxes |  |  | 224 |  |  |  | 141 |  |  |  | 59 | %

Key market facts
Demand for electricity is expected to nearly double by 2030, driven mainly by growth in the developing world as it seeks to diversify sources of energy and provide supply security.

• |  | The world is increasingly recognizing the benefits of nuclear energy as it searches for alternatives to carbon-based electricity generation and security of supply.
• |  | There are 436 commercial nuclear power reactors operating in 30 countries, providing about 15% of the world’s electricity.
• |  | There are 53 reactors currently under construction and, by 2019, 91 new reactors (net) are forecast 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 is expected to grow by an average of 3% per year.
• |  | To meet global demand over the next 10 years, we expect that about 67% of uranium supply will come from mines that are currently in operation, 21% from finite sources of secondary supply (mainly government inventories and limited recycling), and 12% will have to come from new sources of primary production.
• |  | Cameco – 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 – is ideally positioned to benefit from the world’s growing need for clean, reliable energy.

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About Cameco
Cameco, with its head office in Saskatoon, Saskatchewan, is 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 2009 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)

Reserves and resources
Reserves

• |  | approximately 480 million pounds proven and probable

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 expansion, 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 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)
• |  | 10-year 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 and manages the overall site 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 2009 (OECD/International Energy Agency), population growth and industrial development will lead to a near doubling of electricity consumption by 2030. Most of this energy will be used by developing (non-OECD) countries as their populations increase and gross domestic products grow.
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.
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, renewable energy. In a carbon-constrained world, nuclear energy will be an even more important part of the future energy mix.
There are 436 commercial nuclear power reactors operating in 30 countries. Sixteen of these countries use nuclear energy for most of their electricity. Countries around the world are increasing their capacity to generate nuclear power by refurbishing or upgrading 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:

• |  | China is currently operating 11 reactors, building 20 and planning more. We expect it to have a net increase of 42 reactors by 2019.
• |  | India is currently operating 18 reactors and has several under construction. We expect it to have a net increase of 13 reactors by 2019.

The US government announced in January 2010 that the success of a leading global economy is tied to a clean energy economy, and that building a new generation of safe, clean nuclear power plants is an integral component. It is considering tripling its initial commitment of $18.5 billion (US) in loan guarantees to $54 billion (US), and is providing other incentives to revitalize its nuclear industry after three decades of stagnation. It also plans to pass a

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comprehensive energy and climate bill with incentives to make clean energy profitable. However, it may be a few more years before significant orders for new nuclear power plants are placed.
In the UK, government commitment to the future of nuclear energy is strong as a result of the need to limit CO2 emissions, and because of concerns about energy security as current reactors approach the end of their operating lives.
Several non-nuclear countries, like Italy, Vietnam and United Arab Emirates, are also laying the groundwork to proceed with nuclear power development.
Demand for uranium is growing
We forecast that the world will consume just over 2 billion pounds of U3O8 over the next 10 years.
During this period, we expect about 67% of uranium supply to come from existing primary production sources — production from mines that are currently in commercial operation.

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We expect about 21% 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 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 that the remaining 12% will come from new sources of primary production.
In 2009, seven producers of uranium concentrates marketed 83% 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 uranium production can be as long as 10 years or more, depending on the deposit type and location.
Given our extensive base of 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 plants, 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, however Belgium and Spain are reconsidering. And 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 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 are finite
• |  | primary production needs to increase to meet future reactor requirements

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 of nuclear plants accelerates.

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The industry in 2009
World consumption and production
Consumption in 2009 was 7% lower than our forecast due to the delayed startup of three reactors. Capacity factors were also lower, mainly due to the lower demand for electricity resulting from the global economic crisis.
We expect consumption to increase to about 180 million pounds in 2010, and production to be between 140 million and 145 million pounds. Secondary supplies should continue to bridge the gap. By 2019, we expect world uranium consumption to be 233 million pounds per year, an average annual growth rate of about 3%.
We expect world demand for UF6 and natural UO2 conversion services to increase by about 5% in 2010.
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 very discretionary. Spot prices in 2010 are expected to be volatile.

|  | 2009 |  |  | 2008 |  |  | change
Uranium ($US/lb U3O8) 1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  | 46.06 |  |  |  | 61.58 |  |  |  | (25 | )%
Average long-term price |  |  | 65.50 |  |  |  | 82.50 |  |  |  | (21 | )%
Fuel services |  |  |  |  |  |  |  |  |  |  |  |
($US/kgU UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  |  |  |  |  |  |  |  |  |  |
• North America |  |  | 7.16 |  |  |  | 9.03 |  |  |  | (21 | )%
• Europe |  |  | 8.82 |  |  |  | 10.28 |  |  |  | (14 | )%
Average long-term price |  |  |  |  |  |  |  |  |  |  |  |
• North America |  |  | 11.91 |  |  |  | 12.25 |  |  |  | (3 | )%
• Europe |  |  | 13.20 |  |  |  | 13.22 |  |  |  | — |
Note: the industry does not publish UO2 prices. |  |  |  |  |  |  |  |  |  |  |  |
Electricity ($/MWh) |  |  |  |  |  |  |  |  |  |  |  |
Average Ontario electricity spot price |  |  | 30 |  |  |  | 49 |  |  |  | (39 | )%

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

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Contract volumes
In 2009, spot market sales were at a record high, with utilities responsible for 55% of the purchases. China accounted for more than 20%, or about 12 million pounds. Most of these purchases were opportunistic as utilities and others took advantage of price volatility.
We expect long-term contracting volumes in 2010 to be similar to 2009, 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:

• |  | a large portfolio of low-cost mining operations and geographically diverse uranium assets
• |  | controlling interests in the world’s largest high-grade uranium reserves
• |  | multiple sources of conversion and the ability to increase production
• |  | excellent growth potential from existing assets, combined with a global exploration program
• |  | a strong customer base and a worldwide marketing presence
• |  | an extensive portfolio of long-term sales contracts
• |  | 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

Over the past four years, we’ve made significant progress in becoming a more vertically integrated business, adding conversion capacity, buying fuel manufacturing facilities and investing in the development of a third-generation enrichment process.
The focus of our growth strategy is on our uranium segment. We plan to concentrate on increasing production to meet rising demand, while 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 22.
Uranium: doubling production by 2018
We have a strategy and process in place to double our annual production by 2018, which we expect to come from three sources:

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

Our strategy is flexible enough to respond to both positive and negative developments in the nuclear industry.
Operating properties
Our existing 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 will also be 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 reserves, we expect Rabbit Lake to produce until 2015, although work is ongoing to extend its mine life even further.
Development projects

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Cigar Lake is our main 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. Based on current information, 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 expansion is an extension of our existing mining area, which is part of the most prolific high-grade uranium system in the world.
• |  | Under the terms of a memorandum of understanding with our Inkai partner, National Atomic Company Kazatomprom Joint Stock Company (Kazatomprom), we are in discussions to increase our share of annual production from blocks 1 and 2 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 by investing in environmental studies, reserve delineation and feasibility studies to build a pipeline of projects ready for a production decision.
Growth beyond 2018
Our active global exploration program, combined with our disciplined acquisition strategy, will add to our pipeline of future production sources, replacing our reserves and resources and helping to ensure 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. We now have direct interests in almost 70 active exploration projects in six countries, over 100 experienced professionals who are searching for the next generation of deposits, and ownership interests in approximately 4.2 million hectares (10.4 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.
We also partner, through strategic alliances and equity holdings, with smaller companies holding properties that meet our investment criteria. Our leadership position and industry expertise in exploration make us a partner of choice. In return for our investment, we usually have the right to own a majority stake in a successful discovery.
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.

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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 page 5, and specifically on the assumptions and risks listed here.
Assumptions
Our statements about doubling annual production by 2018 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.
Material risks that could prevent us from reaching our target

• |  | we may not be able to locate additional reserves and identify appropriate methods of mining to maintain production levels at McArthur River
• |  | we may not be able to increase production to the expected level at Inkai if we can’t add reserves at block 3, the feasibility study isn’t favourable or we can’t secure regulatory approval
• |  | if our partner or the Kazakh government does not support an increase in production to the expected level at Inkai, remediation and development at Cigar Lake is not completed on schedule, or we don’t reach full production levels as quickly as we expect
• |  | development of Kintyre is delayed due to political, regulatory or aboriginal issues
• |  | we cannot obtain a favourable feasibility study for the Kintyre or Millennium project, or we cannot reach agreement with our project partners to move ahead with production
• |  | 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 consideration 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
• |  | disruption in production or development due to natural phenomena, labour disputes, political risks or other development and operation risks

Fuel services: capturing synergies
We made a strategic decision to invest in infrastructure in our fuel services business, and now have a world-class facility. We are one of only three commercial suppliers of UF6 in the western world.
Our fuel services segment helps support the growth of the uranium segment by allowing us to offer a range of products and services to customers. This helps us broaden our business relationships and expand our uranium market share.
We’re focused on capturing synergies where we can, servicing our customers more effectively, improving cost-competitiveness and operational efficiency, and expanding into innovative areas like laser enrichment technology to broaden our services.
Electricity: capturing added value
Our investment in the Bruce Power Limited Partnership 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, looking at options to extend the operating life of the four Bruce B units, and gaining exposure to new generation opportunities.

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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
Uncertainty in the global financial markets has prevented many companies from ready access to capital markets. We are in a strong financial position to proceed with our growth plans.
Disciplined portfolio management
We have a disciplined portfolio management process that incorporates all capital projects into a single capital plan. 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.
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.
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 Cameco.
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 delivery 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 generally 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 at the time of delivery, often include floor prices adjusted for inflation and, recently, some have begun to include ceiling prices in excess of $100 (US) per pound.
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 customers. This strategy has allowed us to add increasingly favourable contracts to our portfolio that will enable us to benefit from higher market prices in the future.
Our contracts generally include a supply interruption clause that gives us the right to reduce, on a prorata 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.

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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 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. In addition to being a source of profit, this activity can provide 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 2009, labour, production supplies and contracted services made up 88% of the production costs at our uranium mines. Labour (34%) was the largest component. Production supplies (28%) included fuels, reagents and other items. Contracted services (26%) included mining and maintenance contractors, air charters, security and ground freight.
Operating costs in our fuel services segment are mainly fixed. In 2009, labour accounted for about 57% of the total. The largest variable operating cost is for anhydrous hydrogen fluoride, followed by energy (natural gas and electricity).
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.
A safe, healthy and rewarding workplace
We strive to foster a safe, healthy and rewarding workplace at all of our facilities, and measure our progress against key indicators, such as employee sentiment toward the company, conventional and radiation safety statistics 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 10 Best Companies to Work For in Canada for 2010, for our employee policies, programs and role in the community, and in November 2009, Mediacorp named us one of Canada’s Top 100 Employers.

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A clean environment
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.
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 many 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.
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 2009:

• |  | 50% of the employees at our mines were local residents
• |  | 71% of services to our northern minesites — approximately $220 million — went to northern businesses
• |  | we engaged in project discussions with communities near Cigar Lake, Millennium and Key Lake, visited 11 communities throughout the north, and met with communities where we’re exploring to give them information and garner grassroots support early in the process
• |  | we donated over $1 million to northern and aboriginal initiatives for youth, education, culture and recreation

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.

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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.

|  |  |  | 2010 objectives
|  |  |  | This is forward-looking information.
2009 objectives |  | results |  | See page 4 for more information.
Outstanding financial performance
Produce 20.1 million pounds of U3O8 and 8 to 12 million kgU from fuel services. |  | Exceeded • Our share of U3O8 production was 20.8 million pounds, or 103% of plan. • We produced 12.3 million kgU at fuel services. |  | Production • Produce 21.5 million pounds of U3O8 and between 14 million and 16 million kgU from fuel services. Financial measures Corporate performance • Achieve budgeted net earnings and cash flow from operations (before working capital changes). Costs Strive for unit costs below budget. Growth Cigar Lake • Access and secure underground workings and continue with remediation work on schedule. Reinitiate Shaft 2 development • Update the technical report. 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. Kintyre • Advance project evaluation to allow a production decision as soon as possible. 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 expansion 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. Management • Continue integrating portfolio management into our management, planning and budgeting processes. • Deliver planned capital projects within 10% of budget.
Achieve combined unit-operating costs within budget. |  | Exceeded • Unit costs were 10% below budget. |
Pursue future additional tailings capacity at Rabbit Lake and Key Lake by submitting to regulators a project description, completing prefeasibility study work, conducting environmental baseline studies and community consultations, and initiating the environmental assessment process. |  | Partially achieved Key Lake: • Completed all planned activities except the project description for the environmental assessment, which was filed later than planned. Rabbit Lake • Completed some early work, including the initial draft prefeasibility study and preliminary community consultations, but decided to refocus resources on Key Lake. |
Advance Cigar Lake mine remediation, including sealing of the August 2008 water inflow area. |  | Achieved • Dewatering resumed in the fourth quarter and is complete. |
Advance development of Kintyre by initiating environmental baseline work and conducting confirmatory drilling. |  | Achieved • Drilling began in late September. • Work on the environmental study began in October. |
Achieve an average mineral reserve and resource replacement rate through brownfield or greenfield exploration programs, joint ventures and acquisitions that is, over the last three years, at least equal to total annual U3O8 production from all facilities. |  | Exceeded Our additions to reserves and resources exceeded production by an average of 15 million pounds per year in each of the last three years (2007 to 2009). |
Identify, develop and evaluate opportunities for economic growth in uranium supply within the three- to eight-year time frame. |  | Achieved • We identified and evaluated several opportunities. • We acquired 10.6% of UFP Investments, LLC, which is developing uranium-from-phosphate technology. |

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2009 objectives |  | results |  | 2010 objectives
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 the combined (employee and contractor) injury frequency and severity, and radiation doses. |  | Exceeded • Overall, strong safety performance demonstrated in 2009. • Lost-time incident frequency for employees and contractors was 0.4 per 200,000 hours worked compared to a target of 0.8 — the best performance in Cameco’s history. Medical aid frequency and severity were also better than target. |  | • 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.
Implement Cameco’s systematic approach to training by the end of 2009. |  | Achieved • All operations met or exceeded their 2009 implementation milestones. |  |
Clean environment
Strive to achieve zero reportable environmental incidents in all jurisdictions where we operate. Reduce the frequency of environmental incidents and incur no significant incidents at all Cameco-operated sites. |  | Partially achieved • There were 27 environmental incidents, which is a small improvement over 2008 (29 incidents), but is above our long-term average of 22. 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.
With the goal of reducing energy consumption at all Cameco business locations, develop and begin to implement energy management action plans at all Canadian mining and milling operations, and complete energy assessments at all remaining North American operations. |  | Achieved • We completed energy assessments and developed energy management plans for all but one of our operations. • We completed a study on renewable energy opportunities at McArthur River/Key Lake, led by the Pembina Institute. • We implemented almost all of the energy reduction actions at our operations in northern Saskatchewan. |  |
Supportive communities
Build awareness and support for Cameco in the communities impacted by our company through community investment, business development and public relations, and improve levels of support in these jurisdictions. |  | 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. |  | • Build awareness and support for Cameco through community investment, business development programs and public relations. • Advance our projects by securing support from indigenous communities affected by our operations.
Finalize and begin implementation of an enhanced northern Saskatchewan strategy focused on workforce development, business development, community relations, and government and regulatory affairs. |  | Achieved • We completed the Northern Saskatchewan Strategy Review in June and, by the end of the year, had made significant headway in all four categories. • We visited every impact community in the north, invested over $1 million in community programs, developed our relationships with local suppliers and met our target for local employees. |  |

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

2009 consolidated financial results |  |  | 24 |
Outlook for 2010 |  |  | 31 |
Liquidity and capital resources |  |  | 32 |
2009 financial results by segment |  |  | 38 |
Uranium |  |  | 38 |
Fuel services |  |  | 41 |
Electricity |  |  | 42 |
Fourth quarter results |  |  | 44 |
Fourth quarter consolidated results |  |  | 44 |
Quarterly trends |  |  | 45 |
Fourth quarter results by segment |  |  | 46 |

2009 consolidated financial results
In 2009, we sold all of our shares of Centerra Gold Inc. (Centerra), the gold segment of our business.
Under Canadian GAAP, we are required to report the results of discontinued operations separately from continuing operations. We have included our operating earnings from Centerra, and the financial impact of our disposition of Centerra shares, in discontinued operations.
We recast our consolidated financial results for 2008 and 2007 for comparison purposes to show the impact of Centerra as a discontinued operation. The change affected a number of financial measures, including revenue, gross profit, administration costs and income tax expense. See note 25 to the financial statements for more information.

Highlights |  |  |  |  |  |  |  |  |  |  |  |  |  | change from |
December 31 ($ millions except per share amounts) |  | 2009 |  |  | 2008 |  |  | 2007 |  |  | 2008 to 2009 |
Revenue |  |  | 2,315 |  |  |  | 2,183 |  |  |  | 1,905 |  |  |  | 6 | %
Gross profit |  |  | 750 |  |  |  | 829 |  |  |  | 765 |  |  |  | (10 | )%
Net earnings |  |  | 1,099 |  |  |  | 450 |  |  |  | 416 |  |  |  | 144 | %
$ per common share (basic) |  |  | 2.83 |  |  |  | 1.29 |  |  |  | 1.18 |  |  |  | 119 | %
$ per common share (diluted) |  |  | 2.82 |  |  |  | 1.28 |  |  |  | 1.13 |  |  |  | 120 | %
Adjusted net earnings (non-GAAP, see page 27) |  |  | 582 |  |  |  | 589 |  |  |  | 572 |  |  |  | (1 | )%
$ per common share (adjusted and diluted) |  |  | 1.49 |  |  |  | 1.67 |  |  |  | 1.54 |  |  |  | (11 | )%
Cash provided by operations (from continuing operations) |  |  | 690 |  |  |  | 530 |  |  |  | 756 |  |  |  | 30 | %

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Revenue 6% higher

($ millions) |  |  |  |
Revenue — 2008 |  |  | 2,183 |
Changes: |  |  |  |
Uranium business — higher realized prices |  |  | 39 |
Fuel services business — higher realized prices |  |  | 25 |
Electricity business — higher realized prices |  |  | 73 |
Other |  |  | (5 | )
Revenue — 2009 |  |  | 2,315 |

See 2009 financial results by segment for more information.
Three-year trend
Revenue has risen by 22% over the past three years, to a record $2.3 billion in 2009, mainly due to higher realized selling prices for uranium. Our average realized price for uranium was $45.12/lb in 2009, compared to $41.68/lb in 2007. Electricity revenue in 2009 was $100 million higher than 2007 as a result of higher realized prices, which increased from $52/MWh to $64/MWh.
Average realized prices

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | change from |
|  |  |  |  |  | 2009 |  |  | 2008 |  |  | 2007 |  |  | 2008 to 2009 |
Uranium |  | $US/lb |  |  | 38.25 |  |  |  | 39.52 |  |  |  | 37.47 |  |  |  | (3 | )%
|  | $Cdn/lb |  |  | 45.12 |  |  |  | 43.91 |  |  |  | 41.68 |  |  |  | 3 | %
Fuel services |  | $Cdn/kgU |  |  | 17.84 |  |  |  | 15.85 |  |  |  | 14.04 |  |  |  | 13 | %
Electricity |  | $Cdn/MWh |  |  | 64 |  |  |  | 57 |  |  |  | 52 |  |  |  | 12 | %

Outlook for 2010
We expect consolidated revenue to be 5% to 10% lower in 2010 as:

• |  | We expect lower trading volumes in uranium, so uranium sales volumes are likely to decline by 5% to 10%.
• |  | We expect realized prices for electricity to be lower, so revenue from our electricity business is likely to decline.

Our customers have the discretion to choose when in the year to receive deliveries of our uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. For 2010, the trend in delivery patterns is expected to be similar to 2009 with deliveries being more heavily weighted to the second and fourth quarters.

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Gross profit down 10%
We calculate gross profit by deducting the cost of products and services sold, and depreciation, depletion and reclamation (DDR), from revenue.

($ millions) |  |  |  |
Gross profit — 2008 |  |  | 829 |
Changes: |  |  |  |
Uranium business — higher costs for purchased uranium; higher royalties |  |  | (177 | )
Fuel services business — higher realized prices; higher production |  |  | 42 |
Electricity business — higher realized prices |  |  | 65 |
Other |  |  | (9 | )
Gross profit — 2009 |  |  | 750 |

See 2009 financial results by segment for more detailed discussion.
Three-year trend
After increasing in 2008 due primarily to higher realized prices in the uranium and fuel services businesses, our gross profit declined in 2009 mainly due to an increase in the cost of product sold for uranium. This increase was largely related to more purchases at near-market prices, which pushed our average cost of uranium higher. These purchases were made to take advantage of trading opportunities in current and future years and, while profitable, are at margins much lower than our average.
Net earnings up 144%
Our net earnings were $649 million higher than last year primarily as a result of:

• |  | selling our interest in Centerra and recording an after tax gain of $374 million
• |  | recording an after-tax profit of $179 million relating to mark-to-market gains on financial instruments, compared to a loss of $148 million in 2008

Three-year trend
Our net earnings normally trend with revenue, but in recent years have been significantly influenced by unusual items.
In 2007, we recorded charges of $153 million after tax for the restructuring of Centerra, $65 million after tax for a cash settlement feature for the stock option plan, and a $25 million recovery of future income taxes due to changes in tax legislation.
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.

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Adjusted net earnings down 1%
(non-GAAP, see below)

($ millions) |  |  |  |
Adjusted net earnings — 2008 |  |  | 589 |
Changes: |  |  |  |
Uranium business — higher costs for purchased uranium; higher royalties |  |  | (177 | )
Fuel services business — higher realized prices; higher production |  |  | 42 |
Electricity business — higher realized prices |  |  | 65 |
Gold business — lower output and higher costs |  |  | (12 | )
Realized gains on financial instruments |  |  | 63 |
Income tax expense |  |  | 32 |
All other |  |  | (20 | )
Adjusted net earnings — 2009 |  |  | 582 |

Three-year trend
Our adjusted net earnings have been relatively stable over the past three years.
The 3% increase in 2008 was largely the result of stronger results in gold.
The 1% decrease in 2009 resulted from:

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

A note about non-GAAP measures
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 one-time costs, writedowns, gains and unrealized mark-to-market losses on our financial instruments, which we believe do not reflect underlying performance.
Adjusted net earnings is non-standard supplemental information, and not a substitute for financial information prepared according to GAAP. Other companies may calculate this measure differently. The table below reconciles adjusted net earnings with our net earnings.

($ millions) |  | 2009 |  |  | 2008 |
Net earnings (GAAP measure) |  |  | 1,099 |  |  |  | 450 |
Adjustments (after tax) |  |  |  |  |  |  |  |
Restructuring the gold business |  |  | 46 |  |  |  | (20 | )
Gain on sale of Centerra |  |  | (374 | ) |  |  | — |
Unrealized losses (gains) on financial instruments |  |  | (189 | ) |  |  | 166 |
Stock option expense (recovery) |  |  | — |  |  |  | (33 | )
Investment writedowns |  |  | — |  |  |  | 26 |
Adjusted net earnings1 (non-GAAP measure) |  |  | 582 |  |  |  | 589 |

1 |  | Adjusted net earnings includes our share of Centerra’s operating earnings for the periods presented.

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Discontinued operations
On December 30, 2009, we disposed of our entire interest in Centerra in two steps:

• |  | We sold 88,618,472 common shares of Centerra through a public offering, at a price of $10.25 per share, for net proceeds of approximately $871 million.
• |  | We transferred another 25,300,000 common shares of Centerra to Kyrgyzaltyn JSC (Kyrgyzaltyn), under our April 24, 2009 agreement with them and the Government of the Kyrgyz Republic.

The table below includes our share of Centerra’s operating results, the net gain on the disposition and the restructuring charges related to the agreement with Kyrgyzaltyn. See note 25 to the financial statements for more information.

($ millions) |  | 2009 |  |  | 2008 |  |  | change |
Results from operations |  |  | 54 |  |  |  | 64 |  |  |  | (10 | )
Agreement with Kyrgyzaltyn |  |  | (46 | ) |  |  | 20 |  |  |  | (66 | )
Gain on disposal of interest |  |  | 374 |  |  |  | — |  |  |  | 374 |
Earnings from discontinued operations |  |  | 382 |  |  |  | 84 |  |  |  | 298 |

Corporate expenses
Administration

($ millions) |  | 2009 |  |  | 2008 |  |  | change |
Direct administration |  |  | 122 |  |  |  | 147 |  |  |  | (17 | )%
Stock-based compensation |  |  | 14 |  |  |  | (61 | ) |  |  | 123 | %
Total administration |  |  | 136 |  |  |  | 86 |  |  |  | 58 | %

Direct administration costs in 2009 were lower than 2008 as we curtailed certain activities in response to the global financial crisis, and spent less on enhancing system technology and recruitment. The rate of growth in the workforce has slowed since the third quarter of 2008.
We recorded $14 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 a recovery of $61 million in 2008. See note 22 to the financial statements.
Outlook for 2010
We expect administration costs (not including stock-based compensation) to be about 25% to 30% higher than they were in 2009 due to planned higher spending in support of our growth strategy.
Exploration
In 2009, uranium exploration expenses were $49 million compared to $53 million in 2008. The decline in 2009 reflects $6 million in recoveries under investment tax credit programs. Our exploration efforts in 2009 focused on Canada, the United States, Mongolia, Kazakhstan, Australia and South America.
Outlook for 2010
We expect exploration expenses to be about 80% to 90% higher than they were in 2009 due to evaluation activities at Kintyre and Inkai block 3. Our policy is to expense costs for properties that do not have established reserves or operating history. See Our operations — Uranium exploration for more information.

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Interest and other charges
Interest and other charges were $106 million lower than last year mainly as a result of recording $21 million in foreign exchange gains compared to losses of $83 million in 2008. Gross interest charges this year were $13 million lower than last year attributable to our lower average debt level. See note 11 to the financial statements.
Gains and losses on derivatives
In 2009, we recorded $244 million in mark-to-market gains on our financial instruments compared to losses of $203 million in 2008. Unrealized gains on financial instruments were much higher in 2009 than 2008 due to the significant increase in the value of the Canadian dollar against the US dollar. 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 27 to the financial statements.
Income taxes
We recorded an income tax expense of $53 million in 2009 compared to a recovery of $24 million in 2008. This was mainly due to a $425 million increase in pretax earnings in 2009, which was largely attributable to the recognition of $244 million in gains on derivatives, compared to $203 million in losses in 2008.
On an adjusted net earnings basis, our effective tax rate in 2009 was 3%, or 4% lower than 2008 as:

• |  | A higher proportion of taxable income was earned in jurisdictions with favourable tax rates.
• |  | Certain future tax liabilities recognized in prior years were reduced.
• |  | 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 $18 million in 2009, compared to $50 million in 2008.
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 and 2004 tax returns. We believe it is likely that CRA will reassess our tax returns for 2005 through 2009 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. However, to reflect the uncertainties of CRA’s appeals process and litigation, we increased our reserve for uncertain tax positions by $9 million in 2009. 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 2009 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 2010
We expect our effective tax rate for 2010 to be less than 5%.
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.

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At December 31, 2009:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.05 (Cdn), down from $1.00 (US) for $1.22 (Cdn) at December 31, 2008. The exchange rate averaged $1.00 (US) for $1.14 (Cdn) over the year.
• |  | Our effective exchange rate for the year, after allowing for hedging, was about $1.18, compared to $1.11 in 2008.
• |  | We had foreign currency contracts of $1.5 billion (US) and EUR 34 million at December 31, 2009. The US currency contracts had an average exchange rate of $1.00 (US) for $1.09 (Cdn).
• |  | The mark-to-market gain on all foreign exchange contracts was $67 million compared to a $105 million loss at December 31, 2008.

Timing differences between the maturity dates and designation dates on previously closed hedge contracts can result in deferred gains or charges. At December 31, 2009, we had net deferred gains of $39 million. The table below shows when these will be recognized in earnings.

$ millions (Cdn) |  | 2010 |  |  | 2011 |
Deferred gains (charges) |  |  | 34 |  |  |  | 5 |

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2009, all counterparties to foreign exchange hedging contracts had a Standard & Poor’s credit rating of A or better.
Sensitivity analysis
At December 31, 2009, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2010 net earnings by about $10 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.05 (Cdn).

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Outlook for 2010
Over the next several years, we expect to make significant investments to expand production at existing mines and to advance 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, based on current uranium spot prices, will meet our anticipated requirements over the next several years, without the need for significant additional funding. Our cash balances will gradually decline as we use the funds to pursue our growth plans.
Our outlook for 2010 reflects the growth expenditures necessary to help us achieve our strategy. Please note that we do not include an outlook for the items in the table that are marked with a dash.
See 2009 financial results by segment for details.

|  | Consolidated |  | Uranium |  | Fuel services |  | Electricity
Production |  | — |  | 21.5 million lbs |  | 14 to 16 million kgU |  | —
Sales volume |  | — |  | 31 to 33 million lbs |  | Increase 15% to 20% |  | —
Capacity factor |  | — |  | — |  | — |  | About 90%
Revenue compared to 2009 |  | Decrease |  | Decrease |  | Increase |  | Decrease
|  | 5% to 10% |  | 5% to 10%1 |  | 5% to 10% |  | 5% to 10%
Unit cost of product sold (including DDR) |  | — |  | Decrease |  | — |  | Increase
|  |  |  | 5% to 10%2 |  |  |  | 10% to 15%
Direct administration costs compared to 20093 |  | Increase |  | — |  | — |  | —
|  | 25% to 30% |  |  |  |  |  |
Exploration costs compared to 2009 |  | — |  | Increase |  | — |  | —
|  |  |  | 80% to 90% |  |  |  |
Tax rate |  | Less than 5% |  | — |  | — |  | —
Capital expenditures |  | $552 million4 |  | — |  | — |  | $41 million

1 |  | Based on a uranium spot price of $41.75 (US) per pound (the Ux spot price as of February 22, 2010) and an exchange rate of $1.00 (US) for $1.05 (Cdn).
2 |  | Assumes the unit cost of sale for produced material will decline by 2% to 5% and the unit cost of sale for purchased material will decline by 15% to 20%.
3 |  | Direct administration costs do not include stock-based compensation expenses.
4 |  | Does not include our share of capital expenditures at BPLP.

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Liquidity and capital resources
At the end of 2009, 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 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.
Continued uncertainty in the global financial markets has prevented many companies from ready access to capital markets. Our strong financial position enables us to rely on operating cash flows and existing bank credit facilities to provide liquidity. This 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

|  | 2009 |  |  | 2008 |
Cash position ($ millions) (cash, cash equivalents, short-term investments) |  |  | 1,304 |  |  |  | 64 |
Cash provided by operations ($ millions) (net cash flow generated by our operating activities after changes in working capital) |  |  | 690 |  |  |  | 530 |
Cash provided by operations/net debt (net debt is total consolidated debt, less cash and cash equivalents) |  |  | n/a |  |  |  | 42 | %
Net debt/total capitalization (total capitalization is total long-term debt and equity) |  |  | n/a |  |  |  | 26 | %

Credit ratings
Third-party ratings for our commercial paper and senior debt as of December 31, 2009:

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) |  | 2009 |  |  | 2008 |
Cash and cash equivalents at beginning of year |  |  | 64 |  |  |  | 28 |
Cash from operations |  |  | 690 |  |  |  | 530 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (393 | ) |  |  | (531 | )
Dispositions |  |  | 871 |  |  |  | — |
Acquisitions |  |  | — |  |  |  | (503 | )
Other investing activities |  |  | (36 | ) |  |  | (13 | )
Financing activities |  |  |  |  |  |  |  |
Change in debt |  |  | (231 | ) |  |  | 629 |
Issue of shares |  |  | 442 |  |  |  | 1 |
Dividends |  |  | (93 | ) |  |  | (81 | )
Exchange rate changes on foreign currency cash balances |  |  | (10 | ) |  |  | 4 |
Cash and short-term investments at end of year |  |  | 1,304 |  |  |  | 64 |

Cash from operations
Cash from operations was 30% higher than in 2008 as cash margins were higher in the electricity and fuel services businesses, mainly due to higher realized prices. Working capital requirements, primarily an increase in product inventories, used $84 million in cash in 2009. In 2008, working capital consumed $91 million as a result of an increase in trade receivables during the year. See note 19 to the financial statements.
Investing activities
Cash used in investing includes acquisitions and capital spending.
Acquisitions and divestitures
In December 2009, we sold our interest in Centerra for net proceeds of $871 million. We concluded no significant acquisitions in the year. In 2008, we spent $503 million to acquire an interest in Kintyre ($351 million), GLE ($124 million) and GoviEx Uranium Inc. ($28 million). In addition to the cash invested in GLE, we issued a promissory note in the amount of $73 million (US) in support of future development of the business.

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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 |  |  | 2009 actual |  |  | 2009 plan |
Growth capital |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 111 |  |  |  | 42 |  |  |  | 48 |
Inkai |  |  | 4 |  |  |  | 10 |  |  |  | 9 |
Total growth capital |  |  | 115 |  |  |  | 52 |  |  |  | 57 |
Sustaining capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 220 |  |  |  | 115 |  |  |  | 106 |
US ISR |  |  | 53 |  |  |  | 32 |  |  |  | 54 |
Rabbit Lake |  |  | 56 |  |  |  | 43 |  |  |  | 38 |
Inkai |  |  | 18 |  |  |  | 17 |  |  |  | 18 |
Fuel services |  |  | 29 |  |  |  | 18 |  |  |  | 23 |
Other |  |  | 9 |  |  |  | 20 |  |  |  | 21 |
Total sustaining capital |  |  | 385 |  |  |  | 245 |  |  |  | 260 |
Capitalized interest |  |  | 52 |  |  |  | 37 |  |  |  | 50 |
Total uranium & fuel services |  |  | 552 |  |  |  | 334 |  |  |  | 367 |
Electricity (our 31.6% share of BPLP) |  |  | 41 |  |  |  | 39 |  |  |  | 38 |

Capital expenditures were 8% below our plan for 2009 mainly as a result of reduced activity at our US ISR uranium operations, where poor weather and regulatory issues delayed wellfield construction. We do not expect future production to be affected by these delays.
Outlook for investing activities
We expect total capital expenditures for uranium and fuel services to be 65% higher in 2010, as a result of higher spending for:

• |  | growth capital at Cigar Lake
• |  | sustaining capital at Key Lake and McArthur River

Major sustaining expenditures in 2010 include:

• |  | McArthur River/Key Lake — At McArthur River, the largest component is mine development at about $47 million. Other projects include installing freezing and distribution systems, and work on dewatering equipment and mine ventilation. At Key Lake, construction of a new acid plant is the largest project at approximately $87 million.
• |  | US in situ recovery (ISR) — Wellfield construction and well installation is the largest project at approximately $28 million. We also plan to work on the Reynolds Ranch satellite operation and infrastructure.
• |  | Rabbit Lake — Mine development at Eagle Point is the largest project at about $17 million. Other projects include dewatering systems, continued work on mine ventilation expansion and replacement of components of the acid plant.

In 2010, we expect to fund our capital expenditures with cash on hand and cash generated by our operating activities.

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Financing activities
Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance.
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:

• |  | In the first quarter, we issued approximately 26.7 million common shares, netting $440 million, and put in place or renewed $600 million in revolving lines of credit.
• |  | In the third quarter, 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.
• |  | In the fourth quarter, we renewed a $100 million revolving credit facility until February 2011, and sold our interest in Centerra, netting $871 million.

We used the net proceeds from these transactions to strengthen our cash balances and repay short-term debt. Our intention as we move ahead is to use this cash to advance our growth strategy and for general corporate purposes.
Long-term contractual obligations

December 31, 2009 |  |  |  |  |  | 2011 |  |  | 2013 |  |  | 2015 and |  |  |  |
($ millions) |  | 2010 |  |  | and 2012 |  |  | and 2014 |  |  | beyond |  |  | Total |
Long-term debt |  |  | 12 |  |  |  | 28 |  |  |  | 34 |  |  |  | 890 |  |  |  | 964 |
Interest on long-term debt |  |  | 54 |  |  |  | 107 |  |  |  | 102 |  |  |  | 162 |  |  |  | 425 |
Reclamation costs |  |  | 14 |  |  |  | 16 |  |  |  | 16 |  |  |  | 449 |  |  |  | 495 |
Other liabilities |  |  | — |  |  |  | 1 |  |  |  | — |  |  |  | 248 |  |  |  | 249 |
Total |  |  | 80 |  |  |  | 152 |  |  |  | 152 |  |  |  | 1,749 |  |  |  | 2,133 |

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. On mutual agreement between the lenders and Cameco, the facility can be extended for an additional year on the 2010 and 2011 anniversary dates. 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, 2009, 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, 2011. This facility can be extended for one additional 364-day term on mutual agreement with the lender. At December 31, 2009, 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, 2009, we had approximately $592 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. In 2010, GLE expects to have enough data from the test loop phase to be able to decide whether to proceed to commercial feasibility. We do not expect any amounts to be drawn on this note until 2011.

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Product loan facilities
We have a standby product loan facility with one of our customers. The facility, which became effective April 1, 2008, allows us to borrow up to 2.4 million pounds U3O8 equivalent from April 1, 2008, to December 31, 2011, and to repay it from 2012 to 2014. We pay standby fees of 2.0% of the U3O8 long-term market value at the time the facility was signed, and 5.0% interest on any amounts we draw. Borrowings must be repaid in kind. As at December 31, 2009, there was nothing outstanding under this facility. Revenue from deliveries to this customer, up to the limit of the loan facility, will be deferred until the loan facility has been terminated or, if drawn upon, when the loans are repaid. Revenues deferred to date have not had a material impact on our revenues or earnings.
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, 2009, we complied with all covenants, and we expect to continue to comply in 2010.
Off-balance sheet arrangements
We had two kinds of off-balance sheet arrangements at the end of 2009:

• |  | purchase commitments
• |  | financial assurances

Purchase commitments

December 31, 2009 |  |  |  |  |  | 2011 |  |  | 2013 |  |  | 2015 and |  |  |  |
($ millions) |  | 2010 |  |  | and 2012 |  |  | and 2014 |  |  | beyond |  |  | Total |
Purchase commitments1 |  |  | 140 |  |  |  | 334 |  |  |  | 370 |  |  |  | 35 |  |  |  | 879 |

1 |  | Denominated in US dollars, converted to Canadian dollars as of December 31, 2009 at the rate of $1.0466.

Nearly all of these are commitments to buy uranium and fuel services products under long-term, fixed-price arrangements.
At the end of 2009, we had committed to $840 million (US) for the following:

• |  | About 31 million pounds U3O8 equivalent from 2010 to 2013. Of these, an average of 7 million pounds a year until 2013 are from our agreement with Techsnabexport Joint Stock Company (Tenex) to buy uranium from dismantled Russian weapons (the Russian HEU commercial agreement).
• |  | Almost 43 million kgU as UF6 in conversion services from 2010 to 2016 under our agreements with Springfields Fuels Ltd. (SFL) and Tenex.

Non-delivery by a supplier under these two agreements could have a material adverse effect on our financial condition, liquidity and results of operations.
These two suppliers do not have the right to terminate their agreements other than pursuant to customary event of default provisions.

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Financial assurances

December 31 |  |  |  |  |  |  |  |  |
($ millions) |  | 2009 |  |  | 2008 |  |  | change |
Standby letters of credit |  |  | 592 |  |  |  | 429 |  |  |  | 38 | %
BPLP guarantees |  |  | 87 |  |  |  | 82 |  |  |  | 6 | %
Total |  |  | 679 |  |  |  | 511 |  |  |  | 33 | %

Standby letters of credit mainly provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities. We are required to provide the 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 $87 million at the end of the year. See note 26 to the financial statements.
Balance sheet

December 31 |  |  |  |  |  |  |  |  |  |  |  |  |  | change from |
($ millions except per share amounts) |  | 2009 |  |  | 2008 |  |  | 2007 |  |  | 2008 to 2009 |
Inventory |  |  | 453 |  |  |  | 398 |  |  |  | 393 |  |  |  | 14 | %
Total assets |  |  | 7,342 |  |  |  | 7,011 |  |  |  | 4,582 |  |  |  | 5 | %
Long-term financial liabilities |  |  | 1,583 |  |  |  | 1,800 |  |  |  | 1,512 |  |  |  | (12 | )%
Dividends per common share |  | $ | 0.24 |  |  | $ | 0.24 |  |  | $ | 0.20 |  |  |  | 0 | %

Total product inventories increased by 14% to $453 million this year due to the higher average carrying cost for uranium and higher fuel services inventory. The average cost of uranium was higher as a result of increased purchasing at near-market prices.
At the end of 2009, our total assets amounted to $7.3 billion, an increase of $2.8 billion compared to 2007. In 2008, the total asset balance increased by $2.4 billion as a result of acquisitions and a temporary increase in accounts receivable. In 2009, the increase was 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 2009, our balance declined by $217 million primarily due to the repayment of debt during the year. In 2008, the balance increased by $288 million as a result of higher debt levels and increased provision for reclamation resulting from higher estimates for reclamation costs.

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2009 financial results by segment
Uranium

Highlights |  | 2009 |  |  | 2008 |  |  | change |
Production volume (million lbs) |  |  | 20.8 |  |  |  | 17.3 |  |  |  | 20 | %
Sales volume (million lbs) |  |  | 33.9 |  |  |  | 34.1 |  |  |  | (1 | )%
Average spot price ($US/lb) |  |  | 46.06 |  |  |  | 61.58 |  |  |  | (25 | )%
Average realized price |  |  |  |  |  |  |  |  |  |  |  |
($US/lb) |  |  | 38.25 |  |  |  | 39.52 |  |  |  | (3 | )%
($Cdn/lb) |  |  | 45.12 |  |  |  | 43.91 |  |  |  | 3 | %
Cost of sales ($Cdn/lb U3O8) (including DDR) |  |  | 30.59 |  |  |  | 24.27 |  |  |  | 26 | %
Revenue ($ millions) |  |  | 1,551 |  |  |  | 1,512 |  |  |  | 3 | %
Gross profit ($ millions) |  |  | 488 |  |  |  | 665 |  |  |  | (27 | )%
Gross profit (%) |  |  | 31 |  |  |  | 44 |  |  |  | (30 | )%

Production volume in 2009 was 20% higher than 2008 due to higher production at McArthur River, Rabbit Lake, Smith Ranch-Highland, and the rampup of production at Inkai.
Our average realized selling price in $US was 3% lower than 2008 due to lower spot prices. In $Cdn, our realized price was 3% higher as a result of a weaker Canadian dollar in 2009. This was the primary reason for a 3% increase in total revenues as sales volumes were slightly lower than in 2008.
Our total cash cost of sales (excluding DDR) increased by 27% to $901 million ($26.33 per pound U3O8) in 2009. This was mainly the result of the following:

• |  | Our unit cost for purchased uranium was significantly higher due to higher purchases at near-market prices to take advantage of profitable trading opportunities.
• |  | We recorded royalty expenses of $117 million (compared to $82 million in 2008) due to higher realized prices and royalty adjustments.

For produced material, our cash cost of sales per unit rose by $4.44 per pound in 2009. Higher royalty costs represented 38% of the increase (higher realized prices resulted in a $1.30 per pound increase in royalties), and incremental production from Inkai added $0.83 per pound (19%). During the rampup stage, Inkai`s cash costs will be significantly higher than our overall average.
The following table shows our cash cost of sales per unit for produced and purchased material, including royalty charges on produced material, as well as the amounts of produced and purchased uranium sold.

|  | Unit cost of sale |  |  | Quantity sold |
|  | ($Cdn/lb U3O8) |  |  | (million lbs) |
|  | 2009 |  |  | 2008 |  |  | change |  |  | 2009 |  |  | 2008 |  |  | change |
Produced |  |  | 23.86 |  |  |  | 19.42 |  |  |  | 4.44 |  |  |  | 20.9 |  |  |  | 23.2 |  |  |  | (2.3 | )
Purchased |  |  | 30.22 |  |  |  | 24.57 |  |  |  | 5.65 |  |  |  | 13.0 |  |  |  | 10.9 |  |  |  | 2.1 |
Total |  |  | 26.33 |  |  |  | 20.67 |  |  |  | 5.66 |  |  |  | 33.9 |  |  |  | 34.1 |  |  |  | (0.2 | )

The net effect was a 27% decrease in gross profit.
In the third quarter of 2009, we forecast a 5% to 10% increase in uranium revenues and expected sales volumes in the range of 34 million to 36 million pounds. Our actual results for 2009 fell slightly short of forecast due to logistical issues that delayed delivery of approximately 1 million pounds of uranium until the first quarter of 2010.

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Outlook for 2010
We expect to produce 21.5 million pounds of U3O8, or 3% more than 2009. This increase is driven by our plan to double production at Inkai.
Based on the contracts we have in place, we expect to sell between 31 million and 33 million pounds U3O8 in 2010. We expect the unit cost of sale for produced material to be 2% to 5% lower than 2009 due to higher production, and the unit cost of sale for purchased material to be 15% to 20% lower as we expect to make fewer purchases on the spot market.
Based on current spot prices, revenue should be about 5% to 10% lower than it was in 2009 as a result of lower expected sales volumes.
Sensitivity analysis
For 2010, a change of $5 (US) from the Ux spot price on February 22, 2010 ($41.75 (US) per pound) would change revenue by $64 million and net earnings by $39 million.
Long-term 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.
The table is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2009 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, 2009, 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 |
2010 |  |  | 33 |  |  |  | 39 |  |  |  | 47 |  |  |  | 53 |  |  |  | 60 |  |  |  | 67 |  |  |  | 74 |
2011 |  |  | 33 |  |  |  | 38 |  |  |  | 47 |  |  |  | 54 |  |  |  | 63 |  |  |  | 71 |  |  |  | 79 |
2012 |  |  | 36 |  |  |  | 39 |  |  |  | 49 |  |  |  | 58 |  |  |  | 68 |  |  |  | 77 |  |  |  | 86 |
2013 |  |  | 43 |  |  |  | 45 |  |  |  | 55 |  |  |  | 65 |  |  |  | 75 |  |  |  | 85 |  |  |  | 94 |
2014 |  |  | 42 |  |  |  | 46 |  |  |  | 56 |  |  |  | 66 |  |  |  | 76 |  |  |  | 87 |  |  |  | 96 |

In the table, our average realized price increases over time under all spot price scenarios. This illustrates the mix of long-term contracts in our December 31, 2009 portfolio, and is consistent with our contracting strategy.
Our contracts usually include a mix of fixed-price and market-price components, 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 ceilings will yield prices that are lower than current market prices. These older contracts are beginning to expire, and we are starting to deliver into contracts signed since 2004 (when market prices began to increase).
See page 19 for more information about our contracting strategy.

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Our portfolio is affected by more than just the spot price. We made the following assumptions to create the table:
Sales

• |  | sales volume of 32 million pounds in 2010 (the midpoint of our outlook for the year)
• |  | sales volume of 30 million pounds for 2011 and every year following

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 2010, 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)
• |  | we deliver all volumes that we don’t have contracts for at the spot price for each scenario

Inflation

• |  | is 2.0% per year

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 2009 rates. The index value to calculate rates for 2010 is not available until April 2010.

|  | Tier 1 royalty |  |  | Tier 2 royalty |  |  | Tier 3 royalty |  |  |  |
Realized price |  | 6% x |  |  | 4% x |  |  | 5% x |  |  |  |
($Cdn) |  | (sales price - $17.82) |  |  | (sales price - $26.74) |  |  | (sales price - $35.65) |  |  | Total royalties |
25 |  |  | 43,080 |  |  |  | — |  |  |  | — |  |  |  | 43,080 |
35 |  |  | 103,080 |  |  |  | 33,040 |  |  |  | — |  |  |  | 136,120 |
45 |  |  | 163,080 |  |  |  | 73,040 |  |  |  | 46,750 |  |  |  | 282,870 |
55 |  |  | 223,080 |  |  |  | 113,040 |  |  |  | 96,750 |  |  |  | 432,870 |
65 |  |  | 283,080 |  |  |  | 153,040 |  |  |  | 146,750 |  |  |  | 582,870 |
75 |  |  | 343,080 |  |  |  | 193,040 |  |  |  | 196,750 |  |  |  | 732,870 |
85 |  |  | 403,080 |  |  |  | 233,040 |  |  |  | 246,750 |  |  |  | 882,870 |

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

Highlights |  | 2009 |  |  | 2008 |  |  | change |
Production volume (million kgU) |  |  | 12.3 |  |  |  | 8.3 |  |  |  | 48 | %
Sales volume (million kgU) |  |  | 14.9 |  |  |  | 14.8 |  |  |  | 1 | %
Realized price ($Cdn/kgU) |  |  | 17.84 |  |  |  | 15.85 |  |  |  | 13 | %
Cost of sales ($Cdn/kgU) (including DDR) |  |  | 14.47 |  |  |  | 15.46 |  |  |  | (6 | )%
Revenue ($ millions) |  |  | 276 |  |  |  | 252 |  |  |  | 10 | %
Gross profit ($ millions) |  |  | 50 |  |  |  | 8 |  |  |  | 525 | %
Gross profit (%) |  |  | 18 |  |  |  | 3 |  |  |  | 500 | %

The shutdown of the Port Hope UF6 conversion plant reduced production in our fuel services division in 2009 and 2008. The UF6 plant resumed operations in June, reducing the impact in 2009, and resulting in a 48% increase in total production.
Revenue rose by 10% as a result of a 13% increase in the average realized selling price for fuel service products, reflecting improved prices under UF6 sales contracts.
The unit cost of products and services sold (including DDR) was 6% lower this year, mainly due to higher production volumes and allocating operating costs to inventory rather than expensing them directly. In 2009, we expensed $18 million in standby charges compared to $43 million in 2008.
The net effect was a $42 million increase in gross profit.
Outlook for 2010
We expect to produce 14 million to 16 million kgU in our fuel services business in 2010, a significant improvement over 2009 due largely to stronger anticipated performance at the Port Hope UF6 conversion plant.
We expect the average realized selling price for our fuel services products to decline by 5% to 10%, sales volumes to increase by 15% to 20%, and revenue to be 5% to 10% higher.

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

Highlights |  |  |  |  |  |  |  |  |
($ millions except where indicated) |  | 2009 |  |  | 2008 |  |  | change |
Output — terawatt hours (TWh) |  |  | 24.6 |  |  |  | 24.7 |  |  |  | — |
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing) |  |  | 87 | % |  |  | 87 | % |  |  | — |
Realized price ($/MWh) |  |  | 64 | 1 |  |  | 57 |  |  |  | 12 | %
Average Ontario electricity spot price ($/MWh) |  |  | 30 |  |  |  | 49 |  |  |  | (39 | )%
Revenue |  |  | 1,640 |  |  |  | 1,409 |  |  |  | 16 | %
Operating costs (net of cost recoveries) |  |  | 905 |  |  |  | 900 |  |  |  | 1 | %
Cash costs |  |  | 770 |  |  |  | 779 |  |  |  | (1 | )%
Non-cash costs |  |  | 135 |  |  |  | 121 |  |  |  | 12 | %
Income before interest and finance charges |  |  | 735 |  |  |  | 509 |  |  |  | 44 | %
Interest and finance charges |  |  | 4 |  |  |  | 41 |  |  |  | (90 | )%
Cash from operations |  |  | 754 |  |  |  | 547 |  |  |  | 38 | %
Capital expenditures |  |  | 123 |  |  |  | 85 |  |  |  | 45 | %
Distributions2 |  |  | 610 |  |  |  | 329 |  |  |  | 85 | %
Operating costs ($/MWh) |  |  | 35 | 1 |  |  | 36 |  |  |  | (3 | )%

1 |  | Based on actual generation of 24.6 TWh plus deemed generation of 1.2 TWh.
2 |  | Does not include the full repayment of the partner loans of $225 million in 2008 (our share was $75 million).

Our earnings from BPLP

($ millions) |  | 2009 |  |  | 2008 |  |  | change |
BPLP’s earnings before taxes (100%) |  |  | 731 |  |  |  | 468 |  |  |  | 56 | %
Cameco’s share of pretax earnings before adjustments (31.6%) |  |  | 231 |  |  |  | 148 |  |  |  | 56 | %
Proprietary adjustments |  |  | (7 | ) |  |  | (7 | ) |  |  | — |
Earnings before taxes from BPLP |  |  | 224 |  |  |  | 141 |  |  |  | 59 | %

BPLP’s improved results in 2009 are largely the result of higher revenues, which were 16% higher than 2008 due to a 12% increase in realized 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 that extends to 2019. Under the agreement, output from the B reactors is supported by a floor price (currently $48.76/MWh) that is adjusted annually for inflation. 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 to the extent that the floor price exceeds the average spot price for the 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 generation’, and BPLP is paid either the spot price or the floor price — whichever is higher.
During 2009, BPLP recognized revenue of $514 million under the agreement with the OPA.
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

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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 57% of its output under financial contracts in 2009, compared to 67% in 2008.
BPLP’s operating costs were $905 million this year compared to $900 million in 2008.
The net effect was an increase in our share of earnings before taxes of 59%.
BPLP distributed $610 million to the partners in 2009. Our share was $193 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.
BPLP’s adjusted capacity factor was 91% in 2009 (including actual generation of 24.6 TWh and deemed generation of 1.2 TWh). Excluding deemed generation, the capacity factor was 87% — unchanged from 2008.
Outlook for 2010
We expect the average capacity factor for the four Bruce B reactors to be approximately 90% in 2010, and actual output to be about 4% higher than it was in 2009. The 2010 realized price for electricity is projected to be about 5% to 10% lower than 2009 as BPLP has fewer financial contracts in place for 2010. At December 31, 2009, BPLP had about 6.5 TWh under financial contracts, which is equivalent to about 25% of Bruce B generation at its planned capacity factor. We expect that revenue will decline by a corresponding 5% to 10% as a result.
We expect the average unit cost (net of cost recoveries) to be 10% to 15% higher in 2010, and total operating costs to rise by about 10% to 15%, mainly due to higher costs for planned outages and maintaining the workforce.
Sensitivity analysis
A change of $1 in the electricity spot price in 2010 would change our 2010 net earnings by $3 million, based on the assumption that the spot price will remain below the floor price provided for under BPLP’s agreement with the OPA.

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Fourth quarter results
Fourth quarter consolidated results

|  | Three months ended |  |  |  |
Highlights |  | December 31 |  |  |  |
($ millions except per share amounts) |  | 2009 |  |  | 2008 |  |  | change |
Revenue |  |  | 659 |  |  |  | 640 |  |  |  | 3 | %
Net earnings |  |  | 598 |  |  |  | 31 |  |  |  | 1,829 | %
$ per common share (basic) |  |  | 1.52 |  |  |  | 0.08 |  |  |  | 1,800 | %
$ per common share (diluted) |  |  | 1.52 |  |  |  | 0.08 |  |  |  | 1,800 | %
Adjusted net earnings (non-GAAP, see page 27) |  |  | 248 |  |  |  | 179 |  |  |  | 39 | %
$ per common share (adjusted and diluted) |  |  | 0.63 |  |  |  | 0.49 |  |  |  | 29 | %
Cash provided by operations (after working capital changes) |  |  | 188 |  |  |  | 224 |  |  |  | (16 | )%

In the fourth quarter of 2009, our net earnings were $598 million ($1.52 per share diluted), an increase of $567 million compared to $31 million ($0.08 per share diluted) in 2008. The results for 2009 reflect a $374 million net gain related to the sale of our interest in Centerra. In 2008, we recorded an unrealized after tax loss of $148 million on financial instruments.
The 39% increase in adjusted net earnings in the quarter was from higher profits in gold relating to a higher realized selling price, averaging $1,129 (US) per ounce in 2009 compared to $806 (US) in 2008.
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 27 for more information. The table below reconciles adjusted net earnings with our net earnings.

|  | Three months ended |
|  | December 31 |
($ millions) |  | 2009 |  |  | 2008 |
Net earnings (GAAP measure) |  |  | 598 |  |  |  | 31 |
Adjustments (after tax) |  |  |  |  |  |  |  |
Restructuring the gold business |  |  | 28 |  |  |  | 10 |
Gain on sale of Centerra |  |  | (374 | ) |  |  | — |
Unrealized losses (gains) on financial instruments |  |  | (4 | ) |  |  | 130 |
Stock option expense (recovery) |  |  | — |  |  |  | 2 |
Investment write downs |  |  | — |  |  |  | 6 |
Adjusted net earnings1 (non-GAAP measure) |  |  | 248 |  |  |  | 179 |

1 |  | Adjusted net earnings includes our share of Centerra’s operating earnings for the periods presented.

We recorded an income tax expense of $20 million this quarter, based on adjusted earnings, compared to a $31 million expense in 2008. Our effective income tax rate was 6% in the fourth quarter of 2009 compared to 13% in 2008.

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Direct administration costs were $39 million in the quarter, or $18 million lower than the same period last year. The decrease reflects lower costs for BPLP business development activities as well as reduced spending on system technology. Stock-based compensation expenses were $3 million in the quarter, compared to a recovery of $10 million in the fourth quarter of 2008. The 2008 amount reflects recoveries recorded before we amended our stock option plan in November 2008. See note 22 to the financial statements.

|  | Three months ended December 31 |
($ millions) |  | 2009 |  |  | 2008 |
Direct administration |  |  | 39 |  |  |  | 57 |
Stock-based compensation |  |  | 3 |  |  |  | (10 | )
Total administration |  |  | 42 |  |  |  | 47 |

Quarterly trends

Highlights |  |  |  |  |  |
($ millions except per share amounts) |  | 2009 |  |  | 2008 |
|  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 659 |  |  |  | 518 |  |  |  | 645 |  |  |  | 493 |  |  |  | 640 |  |  |  | 329 |  |  |  | 620 |  |  |  | 594 |
Net earnings |  |  | 598 |  |  |  | 172 |  |  |  | 247 |  |  |  | 82 |  |  |  | 31 |  |  |  | 136 |  |  |  | 150 |  |  |  | 133 |
$ per common share (basic) |  |  | 1.52 |  |  |  | 0.44 |  |  |  | 0.64 |  |  |  | 0.23 |  |  |  | 0.08 |  |  |  | 0.39 |  |  |  | 0.44 |  |  |  | 0.38 |
$ per common share (diluted) |  |  | 1.52 |  |  |  | 0.44 |  |  |  | 0.64 |  |  |  | 0.22 |  |  |  | 0.08 |  |  |  | 0.39 |  |  |  | 0.43 |  |  |  | 0.38 |
Adjusted net earnings (non-GAAP, see page 44) |  |  | 248 |  |  |  | 104 |  |  |  | 140 |  |  |  | 90 |  |  |  | 179 |  |  |  | 128 |  |  |  | 139 |  |  |  | 143 |
$ per share diluted |  |  | 0.63 |  |  |  | 0.26 |  |  |  | 0.36 |  |  |  | 0.24 |  |  |  | 0.49 |  |  |  | 0.37 |  |  |  | 0.39 |  |  |  | 0.42 |
Earnings from continuing operations |  |  | 174 |  |  |  | 195 |  |  |  | 269 |  |  |  | 79 |  |  |  | 5 |  |  |  | 124 |  |  |  | 108 |  |  |  | 129 |
$ per common share (basic) |  |  | 0.44 |  |  |  | 0.49 |  |  |  | 0.68 |  |  |  | 0.23 |  |  |  | 0.01 |  |  |  | 0.37 |  |  |  | 0.31 |  |  |  | 0.36 |
$ per common share (diluted) |  |  | 0.44 |  |  |  | 0.49 |  |  |  | 0.68 |  |  |  | 0.23 |  |  |  | 0.01 |  |  |  | 0.37 |  |  |  | 0.30 |  |  |  | 0.36 |
Cash provided by operations |  |  | 188 |  |  |  | 175 |  |  |  | 161 |  |  |  | 166 |  |  |  | 224 |  |  |  | 87 |  |  |  | 100 |  |  |  | 119 |

Key things to note:

• |  | Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 66% of annual consolidated revenues in 2009.
• |  | The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments. In 2009, uranium sales volumes were most heavily weighted to the second and fourth quarters — similar to 2008.
• |  | 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 44 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 (see page 33 for more information).
• |  | Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

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Fourth quarter results by segment
Uranium

|  | Three months ended |  |  |  |
|  | December 31 |  |  |  |
Highlights |  | 2009 |  |  | 2008 |  |  | change |
Production volume (million lbs) |  |  | 6.7 |  |  |  | 5.5 |  |  |  | 22 | %
Sales volume (million lbs) |  |  | 10.0 |  |  |  | 10.5 |  |  |  | (5 | )%
Average spot price ($US/lb) |  |  | 45.96 |  |  |  | 51.00 |  |  |  | (10 | )%
Average realized price: |  |  |  |  |  |  |  |  |  |  |  |
($US/lb) |  |  | 40.64 |  |  |  | 35.31 |  |  |  | 15 | %
($Cdn/lb) |  |  | 43.51 |  |  |  | 42.77 |  |  |  | 2 | %
Cost of sales ($Cdn/lb U3O8) (including DDR) |  |  | 30.29 |  |  |  | 24.16 |  |  |  | 25 | %
Revenue ($ millions) |  |  | 443 |  |  |  | 450 |  |  |  | (2 | )%
Gross profit ($ millions) |  |  | 132 |  |  |  | 193 |  |  |  | (32 | )%
Gross profit (%) |  |  | 30 |  |  |  | 43 |  |  |  | (30 | )%

Production volumes were 22% higher in the fourth quarter of 2009 compared to the fourth quarter of 2008, as a result of higher production at McArthur River/Key Lake, Smith-Ranch Highland and Inkai.
Uranium revenues for the quarter were down 2% compared to 2008, as a 5% decline in sales volumes was partially offset by a 2% increase in our $Cdn realized price. In $US, our realized price for the quarter was 15% higher than in 2008 mainly due to stronger prices under fixed-price sales contracts. The Canadian dollar was much stronger in the fourth quarter of 2009, with our exchange rate averaging $1.07 compared to $1.21 a year ago.
The total cost of products and services sold, including DDR, was 21% higher than 2008 ($311 million compared to $257 million in 2008) mainly related to higher unit costs for purchased uranium. The average unit cost of product and services sold was $30.29/lb, or 25% higher than it was in the fourth quarter of 2008 as we purchased uranium at near-market prices during the year.
The net effect was a 32% decrease in gross profit.

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

|  | Three months ended |  |  |  |
|  | December 31 |  |  |  |
Highlights |  | 2009 |  |  | 2008 |  |  | change |
Production volume (million kgU) |  |  | 3.9 |  |  |  | 2.6 |  |  |  | 50 | %
Sales volume (million kgU) |  |  | 6.0 |  |  |  | 4.6 |  |  |  | 30 | %
Realized price ($Cdn/kgU) |  |  | 14.89 |  |  |  | 13.81 |  |  |  | 8 | %
Cost of sales ($Cdn/kgU) (including DDR) |  |  | 12.92 |  |  |  | 11.26 |  |  |  | 15 | %
Revenue ($ millions) |  |  | 91 |  |  |  | 70 |  |  |  | 30 | %
Gross profit ($ millions) |  |  | 13 |  |  |  | 14 |  |  |  | (7 | )%
Gross profit (%) |  |  | 14 |  |  |  | 20 |  |  |  | (30 | )%

Our results in the fourth quarter of 2009 were adversely affected by a labour strike at our fuel manufacturing facility. In addition, delivery dates are at the discretion of customers, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly.
Total revenue rose by 30% and the cost of products and services sold (including DDR) went up by 38% ($78 million compared to $56 million in the fourth quarter of 2008). The increases are a result of sales volumes being 30% higher than in the fourth quarter of 2008. Our cost of sales per unit was 15% higher, mainly due to the labour strike. Our cost of sales for the quarter included $9 million in standby costs incurred during the strike.
The net effect was a 7% decrease in gross profit.

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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) |  | 2009 |  |  | 2008 |  |  | change |
Output — terawatt hours (TWh) |  |  | 6.4 |  |  |  | 7.0 |  |  |  | (9 | )%
Capacity factor |  |  | 89 | % |  |  | 97 | % |  |  | (8 | )%
Realized price ($/MWh) |  |  | 62 | 1 |  |  | 57 |  |  |  | 9 | %
Average Ontario electricity spot price ($/Mwh) |  |  | 30 |  |  |  | 49 |  |  |  | (39 | )%
Revenue |  |  | 422 |  |  |  | 399 |  |  |  | 6 | %
Operating costs (net of cost recoveries) |  |  | 218 |  |  |  | 207 |  |  |  | 5 | %
Cash costs |  |  | 183 |  |  |  | 176 |  |  |  | 4 | %
Non-cash costs |  |  | 35 |  |  |  | 31 |  |  |  | 13 | %
Income before interest and finance charges |  |  | 204 |  |  |  | 192 |  |  |  | 6 | %
Interest and finance charges |  |  | 1 |  |  |  | 11 |  |  |  | (91 | )%
Cash from operations |  |  | 229 |  |  |  | 176 |  |  |  | 30 | %
Capital expenditures |  |  | 40 |  |  |  | 19 |  |  |  | 111 | %
Distributions |  |  | 220 |  |  |  | 205 |  |  |  | 7 | %
Operating costs ($/MWh) |  |  | 33 | 1 |  |  | 30 |  |  |  | 10 | %

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

Our earnings from BPLP

($ millions) |  | 2009 |  |  | 2008 |  |  | change |
BPLP’s earnings before taxes (100%) |  |  | 203 |  |  |  | 181 |  |  |  | 12 | %
Cameco’s share of pretax earnings before adjustments (31.6%) |  |  | 64 |  |  |  | 57 |  |  |  | 12 | %
Proprietary adjustments |  |  | (2 | ) |  |  | (2 | ) |  |  | — |
Earnings before taxes from BPLP |  |  | 62 |  |  |  | 55 |  |  |  | 13 | %

Total electricity revenue increased by 6%. BPLP’s results this quarter are higher mainly due to higher realized prices. BPLP’s average realized price reflects spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. During the fourth quarter of 2009, BPLP recognized revenue of $137 million under the agreement with the OPA.
BPLP’s adjusted capacity factor was 95% in the fourth quarter of 2009 (includes actual generation of 6.4 TWh and deemed generation of 0.4 TWh). Excluding deemed generation, the capacity factor was 89%, down from 97% in the fourth quarter of 2008.
The equivalent of about 54% of BPLP’s output was sold under financial contracts in the fourth quarter of 2009 compared to 76% in the fourth quarter of 2008.
The net effect was a 13% increase in our share of earnings before taxes.
BPLP distributed $220 million to the partners in the fourth quarter. Our share was $70 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

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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 Production overview |  |  | 51 |
Operating properties |  |  |  |
McArthur River and Key Lake |  |  | 53 |
Rabbit Lake |  |  | 58 |
Smith Ranch-Highland |  |  | 60 |
Crow Butte |  |  | 62 |
Inkai |  |  | 63 |
Development project |  |  |  |
Cigar Lake |  |  | 66 |
Projects under evaluation |  |  |  |
Inkai blocks 1 and 2 production increase (see Inkai, above) |  |  | 63 |
Inkai block 3 (see Inkai, above) |  |  | 63 |
McArthur River expansion (see McArthur River, above) |  |  | 53 |
Kintyre |  |  | 70 |
Millennium |  |  | 71 |
Exploration |  |  | 72 |
Fuel services |  |  |  |
Refining |  |  |  |
Blind River refinery |  |  | 73 |
Conversion and fuel manufacturing |  |  |  |
Port Hope conversion services |  |  | 74 |
Fuel Manufacturing |  |  | 74 |
Springfields Fuels |  |  | 74 |
Electricity |  |  |  |
Bruce Power Limited Partnership |  |  | 76 |

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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.
This page lists 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. If we do not receive the regulatory approvals we need, or do not receive them at the right time, we may have to delay or modify a project, which could increase our costs and delay or prevent us from generating revenue from the project.
Environmental regulations also impose very strict standards and controls on almost every aspect of our operations, and are becoming more stringent in Canada and the US. For example, making changes to our operational processes increasingly requires regulatory approval.
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.
Environmental risks
We have the health, safety and environmental risks associated with any mining and chemical processing company. All three segments face unique risks associated with radiation.
Operational risks
Other operational risks and hazards include:

• |  | environmental incidents and pollution
• |  | accidents
• |  | social or political activism, including blockades
• |  | non-compliance with laws and licences
• |  | fire
• |  | natural phenomena, including underground floods, cave-ins and pitwall failures
• |  | unusual, unexpected or adverse mining or geological conditions
• |  | technological failure of mining methods
• |  | risks from the transportation of our products and chemicals

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.

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Uranium — production overview
We had a number of successes at our mining operations in 2009.
At McArthur River/Key Lake:

• |  | We accomplished a mining first by successfully developing through the unconformity into the Athabasca sandstone, and exceeded our production target by 2%.
• |  | We successfully reduced the release of both molybdenum and selenium to the environment.

At Rabbit Lake:

• |  | We added mineral reserves, extending the expected life of reserves by two years to 2015 and exceeded our production target by 6%.

At Inkai:

• |  | We commissioned Inkai’s main processing plant and started commissioning the first satellite plant, and exceeded our production target by 22%.

Uranium production

|  | Three months ended |  |  | Year ended |  |  |  |
Cameco’s share |  | December 31 |  |  | December 31 |  |  |  |
(million lbs U3O8) |  | 2009 |  |  | 2008 |  |  | 2009 |  |  | 2008 |  |  | 2009 plan |
McArthur River/Key Lake |  |  | 4.0 |  |  |  | 3.1 |  |  |  | 13.3 |  |  |  | 11.6 |  |  |  | 13.1 |
Rabbit Lake |  |  | 1.4 |  |  |  | 1.8 |  |  |  | 3.8 |  |  |  | 3.6 |  |  |  | 3.6 |
Smith Ranch-Highland |  |  | 0.5 |  |  |  | 0.3 |  |  |  | 1.8 |  |  |  | 1.2 |  |  |  | 1.8 |
Crow Butte |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.8 |  |  |  | 0.6 |  |  |  | 0.8 |
Inkai |  |  | 0.6 |  |  |  | 0.1 |  |  |  | 1.1 |  |  |  | 0.3 |  |  |  | 0.9 |
Total |  |  | 6.7 |  |  |  | 5.5 |  |  |  | 20.8 |  |  |  | 17.3 |  |  |  | 20.2 |

Outlook
We have geographically diversified sources of production. Based on our mines currently in production, we expect to produce 112.9 million pounds of U3O8 over the next five years. 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 2014

Current forecast |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
(million lbs U3O8) |  | 2010 |  |  | 2011 |  |  | 2012 |  |  | 2013 |  |  | 2014 |
McArthur River/Key Lake |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |
Rabbit Lake |  |  | 3.6 |  |  |  | 3.6 |  |  |  | 3.6 |  |  |  | 3.6 |  |  |  | 3.0 |
US ISR |  |  | 2.5 |  |  |  | 2.6 |  |  |  | 3.0 |  |  |  | 3.4 |  |  |  | 3.8 |
Inkai |  |  | 2.3 |  |  |  | 3.1 |  |  |  | 3.1 |  |  |  | 3.1 |  |  |  | 3.1 |
Total |  |  | 21.5 |  |  |  | 22.4 |  |  |  | 22.8 |  |  |  | 23.2 |  |  |  | 23.0 |

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We expect Cigar Lake to begin production in mid-2013, based on current information, and will update our production outlook for Cigar Lake in the technical report, which we plan to file at the end of the first quarter of 2010.
By 2011, Inkai is expected to reach production of 5.2 million pounds of U3O8 per year (our share 3.1 million pounds). Inkai has regulatory approval to produce 2.6 million pounds (100% basis) and, in 2005, applied for regulatory approval to increase production to 5.2 million pounds per year (100% basis). We need regulatory approval to increase production to the level necessary to achieve our annual production forecast, and expect to receive it in 2010.
This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on page 5, 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 function 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, 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 plant availability, lack of tailings capacity or for other reasons
• |  | we cannot obtain or maintain necessary permits or government approvals
• |  | natural phenomena, labour disputes, political risks, 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.

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 (Cameco’s share) |  | 234 million pounds — proven and probable
Average reserve grade |  | U3O8 — 19.5%
Estimated resources |  | 21.1 million pounds (measured and indicated) (Cameco’s share) 111.3 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 Licencing below)
Total production |  | 2000 to 2009 |  | 171.2 million pounds (McArthur River/Key Lake)
|  | 1983 to 2002 |  | 209.8 million pounds (Key Lake)
2009 production |  | 13.3 million pounds (Cameco’s share)
2010 forecast production |  | 13.1 million pounds (Cameco’s share)

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Background
Mining of the McArthur River deposit poses a number of challenges including control of groundwater, stabilizing weak rock formations, and radiation protection from very high grade uranium ores. To address these challenges we use a number of innovative methods and techniques:
Ground freezing
The sandstones that overlay the deposit and basement rocks are water-bearing, with large volumes of water under significant pressure. We use ground freezing to form an impermeable freezewall. This prevents water from entering the mine, and helps stabilize weak rock formations.
Raisebore mining
Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River. From a raisebore chamber in waste rock above the ore, we drill a series of overlapping holes through the ore zone and collect the ore using remote-controlled scoop trams at the bottom of the raises. Once each raisebore hole is complete, we fill it with concrete. We have successfully used the raisebore mining method to extract more than 170 million pounds 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.
We have mined only zone 2 since the mine started production. To sustain our production levels, we need to move to new mining areas.
Zone 2 is divided into four panels (panels 1, 2, 3 and 5). Panel 5 represents the upper portion of zone 2, overlying a portion of the other panels. Until late 2009, all mine production was from panels 1, 2 and 3, and there are still limited reserves that we will extract from these panels in the next few years. We expect to mine a total of approximately 85 million pounds of uranium from panel 5.
As mining of zone 2 progresses, we are also bringing the lower mining area of zone 4 into production later in 2010.

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2009 update
Production on target
Our share of production in 2009 was 13.3 million pounds U3O8 compared to our target of 13.1 million pounds U3O8, and a 15% increase over 2008. Production in 2008 was lower than planned due to operating challenges at the Key Lake mill.
We exceeded our target as a result of strong results at both McArthur River and Key Lake, and the amendment to the Key Lake operating licence (see Licensing below).
New mining areas
Zone 2, panel 5 — We completed a new freezewall around this area, developed the initial raisebore chamber and began production in the fourth quarter. This is the first time development has been accomplished through the unconformity into the Athabasca sandstone.
Lower zone 4 — We completed the raisebore chamber on the 530 metre level, completed all freezehole drilling and began freezing the ground.
Mill revitalization
The Key Lake mill began operating in 1983. We are renewing the mill to help maintain and increase our uranium production capability, and this year focused on three areas:

• |  | operational upgrades
• |  | treatment of effluent
• |  | tailings capacity

Operational upgrades
The Key Lake revitalization plan includes upgrading circuits with new technology to simplify operations, increasing annual production capacity and improving environmental performance. As part of this plan, we are replacing the acid, steam and oxygen plants. We received regulatory approval to proceed with these projects and have begun work.
Treatment of effluent
Our operating licence includes a condition that the Key Lake mill reduce the levels of molybdenum and selenium discharged to the environment. Based on work this year, release of both metals to the environment is now controlled at reduced concentrations.
Tailings capacity
The Key Lake mill deposits the milling tailings in the Deilmann tailings management facility (TMF). This year we received regulatory approval to increase the capacity of the Deilmann TMF. This now gives us approximately six years of capacity at current production rates.
Licensing
The CNSC approved an amendment to our operating licence for Key Lake, giving us flexibility in the annual licensed production limit.
Under certain conditions, the Key Lake mill can produce up to 20.4 million pounds U3O8 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 (up to 20.4 million pounds) until we recover the shortfall. The amendment allows us to recover shortfalls going back to 2003.
We have applied for regulatory approval for similar production flexibility at the McArthur River mine.
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.

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Exploration
We continued our underground exploration drilling and development this year, focusing on evaluating mineral resources at the south of the mine. We successfully converted 14 million pounds of measured resources in zone 4 to mineral reserves.
Surface drilling on zone B increased inferred mineral resources by 14 million pounds.
Reserves grade
The estimated average ore grade of the mineral reserves at McArthur River has declined from 21% U3O8 to 19.5% as a result of new reserves in zone 4 that average 10.3% U3O8. We do not expect to be producing from this area for a number of years.
Planning for the future
Production
We expect our share of production to be 13.1 million pounds U3O8 in 2010.
New mining zones
Zone 2, panel 5 — In 2010, we expect to develop two additional raisebore chambers. This area is planned to account for approximately two-thirds of McArthur River mine production in 2010.
Lower zone 4
We began freezing in January 2010. Once the freezewall is in place and development complete, we expect initial production will begin late in 2010.
Exploration
In 2010, we plan to initiate a multi-year project, the McArthur River expansion, to advance the underground exploration drifts on the 530 metre level to the north and to the south of the existing mine. This work is expected to further delineate zone A and B inferred resources to the north as well as resources to the south. As part of the project, we will also initiate a preliminary assessment to determine the potential options and feasibility for mining these resources.
Surface exploration will focus on historically known but under tested targets south of the mine.
Managing near-term risks
Labour relations
The collective agreement covering unionized employees at the McArthur River and Key Lake operations expired on December 31, 2009. Negotiations are in progress. There is risk to production if we are unable to reach an agreement and employees go on strike.
Transition to new mining areas
Portions of the new production raises for zone 2, panel 5 will intersect with the freezewall originally developed for zone 2, panels 1, 2 and 3. This original freezewall is now redundant. The steel freezepipes from this freezewall are being removed. Timely removal represents the largest remaining schedule risk that could impact production rates.
Managing ongoing risks
Production at McArthur River/Key Lake poses many challenges: control of groundwater, weak ground 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 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:

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• |  | Ground freezing — Before mining an ore zone, we drill freeze holes and freeze the ground to form an impermeable freezewall around the ore zone. 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 — The total installed pumping capacity from the McArthur River mine is currently more than 1,850 m3/hr. On the surface, we have water treatment capacity of 1,500 m3/hr and approximately 50,000 m3 of surface storage. We have regulatory approval to treat and release 1,500 m3/hr in non-routine circumstances. In our view, this is sufficient capacity to handle an estimated maximum inflow. We review our dewatering system and requirements at least once a year and before beginning work on any new zone.

Key Lake tailings capacity risk
Tailings from processing McArthur River ore are deposited in the Deilmann TMF. At current production rates, the capacity of the Deilmann TMF is six years, assuming only minor storage capacity losses due to sloughing from pitwalls. Significant sloughing would 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. In recent years, we doubled dewatering treatment capacity, allowing us to stabilize the water level in the pit, and have recently begun to reduce this water level.
In 2009, we completed and received regulatory approval for an action plan for the long-term stabilization of the Deilmann TMF pitwalls. We are now carrying out engineering required to implement this action plan. We expect it will take approximately five years to complete the work.
We also completed prefeasibility work to assess options for long-term storage of tailings at Key Lake. We are proceeding with technical studies and environmental assessment work to support an application for regulatory approval to deposit tailings in the Deilmann TMF to a significantly higher elevation. This would provide enough tailings capacity for many years of mill production at Key Lake.
We also manage the risks listed on page 50.

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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 |  | not certified
Deposit type |  | underground
Estimated reserves |  | 21.3 million pounds (proven and probable)
Average reserve grade |  | U3O8 - 0.88%
Estimated resources |  | 10.4 million pounds (measured and indicated) 0.9 million pounds (inferred)
Mining method |  | vertical blast-hole stoping
Licensed capacity |  | mill: 16 million pounds per year
Total production 1975 to 2009 |  | 178.7 million pounds
2009 production |  | 3.8 million pounds
2010 forecast production |  | 3.6 million pounds

2009 update
Production on target
Rabbit Lake’s production this year was 3.8 million pounds U3O8, just over our target, and 6% higher than 2008. Higher tonnage made up for grades that were lower than expected.
Continued to upgrade the mill and expand the tailings facility
We replaced selected plant equipment and process vessels, and commissioned and began operating the new circuit to reduce concentrations of molybdenum in mill effluent.
We completed the tailings management facility expansion in 2009.
Advanced reclamation planning
The CNSC approved our multi-year site-wide reclamation plan. It will serve as the foundation for future reclamation activities, with area-specific plans to be approved on a case-by-case basis.

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Worked to extend the mine life
We added mineral reserves, extending the expected production life by two years to 2015. We are conducting exploration drilling near the mine and have found new mineralization.
Planning for the future
Production
We expect to produce 3.6 million pounds in 2010.
Milling
We expect the mill to have the capacity to handle tailings from milling ore from Rabbit Lake until 2015 (based upon expected ore grades and milling rates). After production at Cigar Lake ramps up to full capacity, we expect to ship a portion of the uranium solution from milling of Cigar Lake ore to the Rabbit Lake mill for processing. To support this level of production, we will be replacing major components of the acid plant and working to increase tailings capacity.
Exploration
We have extended our underground drilling reserve replacement program into 2010. 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 million in 2010 to reclaim facilities that are no longer in use.
Managing our risks
We manage the risks listed on page 50.

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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; however, 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 |  | 5.9 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 0.10%
Estimated resources |  | 23.0 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 2009 |  | 11.8 million pounds
2009 production |  | 1.8 million pounds
2010 forecast production |  | 1.8 million pounds

2009 update
Production on target
We produced 1.8 million pounds at Smith Ranch-Highland in 2009, meeting our target for the year.
Upgrades
We built and began operating a selenium removal plant. We also started construction on five deep disposal wells. Construction will continue through 2010. These upgrades will allow us to operate and restore groundwater more efficiently.
Planning for the future
Production
We expect to produce 1.8 million pounds in 2010.
Reynolds Ranch expansion
We are seeking regulatory approval to proceed with our Reynolds Ranch expansion, which is expected in the second half of 2010. Reynolds Ranch is adjacent to the Smith Ranch-Highland property.

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Reserves and resources for Reynolds Ranch and Northwest Unit have been included in the totals for Smith Ranch-Highland reserves and resources.
Exploration
Additional exploration is under way 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 page 50.

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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 |  | 4.1 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 0.13%
Estimated resources |  | 10.4 million pounds (measured and indicated) 6.7 million pounds (inferred)
Mining method |  | in situ recovery (ISR)
Licensed capacity (mine and mill) |  | 1 million pounds per year
Total production 2002 to 2009 |  | 6.1 million pounds
2009 production |  | 0.8 million pounds
2010 forecast production |  | 0.7 million pounds

2009 update
Production on target
2009 production was 0.8 million pounds, in line with our forecast.
Licensing
The regulators continued their review of our applications to expand and re-license Crow Butte. There will be public hearings once the reviews are completed.
Planning for the future
Production
In 2010, 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 page 50.

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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%).

Location |  | central Kazakhstan
Ownership |  | 60%
End product |  | U3O8
ISO certification |  | BSI OHSAS 18001 ISO 14001 certified
Estimated reserves (Cameco’s share) |  | 80.9 million pounds (proven and probable)
Average reserve grade |  | U3O8 - 0.07%
Estimated resources (Cameco’s share) |  | 13.1 million pounds (measured and indicated) 153.0 million pounds (inferred)
Mining method |  | In situ recovery (ISR)
Licensed capacity (mine and mill) |  | Approved: 2.6 million pounds per year (Cameco’s share 1.6 million pounds per year)
|  | Application: 5.2 million pounds per year (Cameco’s share 3.1 million pounds per year)
2009 production |  | 1.1 million pounds (Cameco’s share)
2010 forecast production |  | 2.3 million pounds (Cameco’s share)

2009 update
Production
Our share of production this year was 1.1 million pounds U3O8 or 22% higher than our forecast of 0.9 million pounds.
Operations
We completed commissioning of the main processing plant and began commissioning the first satellite plant in 2009.
Supply of sulphuric acid
Inkai has increased the number of suppliers of sulphuric acid from two to four, but the shortage of sulphuric acid has delayed production in the past and its future availability remains a concern.
Project funding
We have agreed with Kazatomprom, a state-owned entity of the Kazakhstan government, to provide funding, by way of a loan, of up to $370 million (US) for project development. Further funding may be required. As of December 31, 2009, the amount outstanding under the loan, including accrued interest, was $337 million (US). Of the cash available for distribution each year, 80% is used to repay the loan until it is repaid in full.

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We have agreed with our partner to provide all funds required by Inkai in connection with work on block 3 until completion of a feasibility study.
We have also invested approximately $4 million (US) over the past several years on sustainable development activities.
Taxes
A new tax code became law on January 1, 2009, and our 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. We are also not certain how the Kazakh government will interpret and apply the new code.
Licensing and Resource Use Contract amendments
We received final approval for the block 2 mining licence after the Resource Use Contract was amended. The mining licence for block 1 expires in 2024 and for block 2 expires in 2030.
Block 3 exploration
Regulators extended the term of the block 3 exploration licence to the end of July 2010 after the Resource Use Contract was amended. Under Kazakh law, we have to achieve a commercial discovery to extend our licence beyond July 2010. We spent $3 million (US) (our share) on exploration drilling at block 3 in 2009.
Profits from block 3 production are to be shared on a 50:50 basis with our partner, instead of based on our ownership interests.
Planning for the future
Production
We expect our share of production to be 2.3 million pounds in 2010.
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.

Both partners approved the production increase at a board meeting in 2008. To implement the increase, we need a binding agreement to finalize the terms of the memorandum, and various government approvals. We are currently in discussions with Kazatomprom regarding these initiatives.
Block 3 exploration
To support a commercial discovery, we are:

• |  | spending $19 million (US) (our share) on exploration drilling in 2010
• |  | preparing an application to file with regulators in the first half of 2010, declaring that we have made a commercial discovery

Technical report
We plan to file our first technical report for this property by the end of the first quarter of 2010.

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Managing our risks
Regulatory approvals
Our 2010 production forecast and reserve estimates assume that we will receive regulatory approval to produce 5.2 million pounds per year (our share: 3.1 million pounds). We believe it is reasonably likely we will receive this approval but, if we do not, we will be unable to meet our 2010 production target and will have to recategorize half of Inkai’s mineral reserves as resources. We also need the regulators to approve our application to declare a commercial discovery in order to extend the term of the block 3 exploration licence beyond July 2010.
Supply of sulphuric acid
Although we have increased our sources of supply, availability of sulphuric acid remains a concern and 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.
Amendments to the subsoil law in 2007 allow the government to reopen subsoil use agreements in certain circumstances. This may increase its ability to expropriate our properties under certain circumstances. In 2009, we amended the Resource Use Contract to adopt a new tax code, at the request of the Kazakh government, even though the government had agreed to the tax stabilization provisions in the original contract. A new subsoil use law has also been proposed. We do not know if the new law will be adopted or what it will contain. It is premature to make any assessment, but further changes to the subsoil law could increase our risk. These developments are illustrative of increased political risk in Kazakhstan.
We also manage the risks listed on page 50.

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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.

Location |  | Saskatchewan, Canada
Ownership |  | 50.025%
End product |  | U3O8
Deposit type |  | underground
Estimated reserves (Cameco’s share) |  | 104.7 million pounds (proven and probable)
Average reserve grade |  | U3O8 — 17.0%
Estimated resources (Cameco’s share) |  | 0.6 million pounds (measured and indicated) 66.8 million pounds (inferred)
Mining method |  | jet boring
Target production date |  | mid-2013 (based on current information)
Target annual production (Cameco’s share) |  | 9 million pounds after rampup

Background
Development
We began developing the Cigar Lake underground mine in 2005, but development has been 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 source of that inflow in 2009, and continued remediation and dewatering shafts 1 and 2. In February 2010, we completed dewatering the underground development, and we expect work to secure the underground to be complete before October 2010, depending on the condition of the mine.
Mining method
Mining the Cigar Lake deposit poses a number of challenges, including groundwater control, weak rock formations, and protection from radiation from very high-grade uranium ores. Cigar Lake’s mining plan uses several innovative techniques to mitigate these challenges, including bulk freezing and jet boring:

• |  | Bulk freezing — The sandstones that overlay the deposit and basement rocks are water-bearing, with large volumes of water under significant pressure. We will freeze the orebody and surrounding rock to prevent water from entering the mine, and to help stabilize weak rock formations.

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• |  | Jet boring— The jet boring mining method is new to the uranium mining industry. We have conducted an initial test mine program and, overall, the program was a success and met all initial objectives. As we ramp up production, however, there may be some technical challenges.

We are confident we will be able to solve challenges that may arise as we ramp up production, but failure to do so would have a significant impact on our business.
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.
2009 update
We remediated the 2008 inflow that forced us to temporarily suspend dewatering of the mine. We remotely placed an inflatable seal between the shaft and the source of the inflow then backfilled and sealed the entire area with concrete and grout.
Dewatering and mine re-entry
We completed dewatering shaft 2 in April and remediation of the shaft in May. We resumed dewatering shaft 1 in October and crews entered the shaft in November. Work focused on refurbishing shaft 1 — installing the ladderway, replacing mechanical and electrical components and extending the in-shaft pumping system.
In February 2010, we completed dewatering the underground development. Crews re-entered the main working level of the mine 480 metres below the surface. Safe access to the 480 metre level has been established and work to inspect, assess and secure the underground development has begun. This work will be followed by restoration of underground mine systems and infrastructure in preparation for resumed construction activities.
Licensing
Cigar Lake’s construction licence was amended effective January 1, 2010, to extend the term for four years and to cover dewatering, remediation and construction activities, including completion of shaft 2 and surface construction.
Costs
As of December 31, 2009, we had:

• |  | invested $470 million in capital to develop Cigar Lake
• |  | expensed $64 million in remediation expenses, including $18 million in 2009

Planning for the future
In 2010, we expect to:

• |  | complete work to secure the underground before October 2010, depending on the condition of the mine
• |  | determine if additional remedial work is needed
• |  | file an updated technical report for the Cigar Lake project by the end of the first quarter
• |  | begin to restore the underground mine systems and infrastructure to prepare to resume construction

Cost update
The preliminary estimate of our share of the total capital costs to complete the Cigar Lake project is between $450 million and $550 million. This includes completing underground development and surface construction, and completing modifications at Rabbit Lake and McClean Lake mills.
Taking into account the $470 million that had been spent as at December 31, 2009, and assuming our estimate does not change, our share of total capital costs for Cigar Lake is between $920 million and $1.0 billion. Our capital cost estimate has increased primarily as a result of the longer period over which remediation and development will occur, additional costs for inflow abatement, increases in surface capital costs and improvements to the mine plan and water management systems. The technical report we plan to file at the end of the first quarter of 2010 will include our updated capital cost estimate.
Remediation
In addition to capital costs, our share of the remaining remediation expenses is now expected to be $29 million. In 2010, we expect to spend $25 million on remediation expenses.

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Production
We are now targeting initial production to begin in mid-2013, based on current information.
Reserves and resources
We updated our reserve and resource estimates in 2009 as required by industry standards based on information gathered to the end of the year.

Cameco’s share |  |  |  |  |  |  |  |  |
(million lbs) |  | 2009 |  |  | 2008 |  |  | change |
Proven reserves |  |  | 36.9 |  |  |  | 113.2 |  |  |  | (76.3 | )
Probable reserves |  |  | 67.8 |  |  |  | — |  |  |  | 67.8 |
Total |  |  | 104.7 |  |  |  | 113.2 |  |  |  | (8.5 | )
Measured resources |  |  | 0.2 |  |  |  | — |  |  |  | 0.2 |
Indicated resources |  |  | 0.4 |  |  |  | 3.3 |  |  |  | (2.9 | )
Total |  |  | 0.6 |  |  |  | 3.3 |  |  |  | (2.7 | )
Inferred resources |  |  | 66.8 |  |  |  | 59.1 |  |  |  | 7.7 |

The changes are mainly from:

• |  | re-interpretation of the mineralized envelopes on the east end of the deposit
• |  | block modelling in 3D (we used a 2D model in 2007)
• |  | revised mine layout and dilution assumptions
• |  | recategorization of the resources and reserves

These factors contributed to the decreases in total contained pounds of U3O8 in the reserves and in the estimated average grade.
Our share of reserves went from 113 million pounds in 2008 to 105 million pounds, due to a 12% increase in tonnes of diluted ore and an 18% reduction in average grades. Our review of the mineral resource and reserve classification resulted in 35% of reserves being classified as proven, compared to 100% previously. The classification is based on drill hole spacing, geological continuity, grade continuity, estimation confidence and the anticipated ability to successfully recover all of the ore.

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The costs to complete Cigar Lake and our target dates for securing the underground and for initial production are forward-looking information. They are based on the assumptions and subject to the material risks discussed on page 5, and specifically on the assumptions and risks listed here.
Assumptions

• |  | natural phenomena or an equipment failure do not cause a material delay or disrupt our plans
• |  | there are no additional water inflows
• |  | the seals used for previous water inflows do not fail
• |  | there are no labour disputes
• |  | we obtain contractors, equipment, operating parts and supplies, and regulatory permits and approvals when we need them

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

Managing our risks
Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak ground 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’ve learned about water inflows from 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 take 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.
Pumping capacity and treatment limits
The total installed pumping capacity from the Cigar Lake mine is currently 1,550 m3/hr. On the surface, we have water treatment capacity of 2,550 m3/hr and approximately 100,000 m3 of surface storage. We have regulatory approval to release 1,100 m3/hr of treated water in non-routine circumstances. In our view, we have sufficient capacity to handle an estimated maximum inflow, and we intend to install additional capacity to assure the long-term success of the project.
In addition to the above, our main risks in 2010 include:

• |  | uncertainty about the condition of the underground development, which we will know once the crews have assessed the underground
• |  | delay or lack of success in implementing our remediation plan

We also manage the risks listed on page 50.

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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. Mitsubishi Development Pty Ltd. owns the remaining 30%.
2009 update
This year we:

• |  | opened an office in Perth to manage the project through the evaluation and prefeasibility stages
• |  | received permits and established a camp to support ongoing diamond drilling
• |  | continued to hire professional and support staff
• |  | began environmental studies and confirmatory drilling
• |  | continued our dialogue with the Martu, the native land title holders for this property

Planning for the future
Our plan for 2010 is to keep moving the project towards a production decision. We expect to:

• |  | negotiate a mine development agreement with the Martu
• |  | complete delineation drilling of the deposit
• |  | estimate a resource
• |  | conduct metallurgical testing to define the milling process
• |  | continue the environmental assessment for the environmental impact statement we plan to submit to regulators in 2011
• |  | begin a prefeasibility study
• |  | build a temporary construction camp

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 page 50.

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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 |  | 19.6 million pounds (indicated)
(Cameco’s share) |  | 4.1 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.
2009 update
We submitted our project description for an environmental assessment and we continued consultation activities. The environmental assessment and feasibility study are under way.
Planning for the future
Our plan for 2010 is to keep moving the project towards a production decision. We expect to:

• |  | complete the feasibility study
• |  | continue our environmental assessment process
• |  | continue with our community consultation

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 page 50.

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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.
2009 update
Brownfield exploration
Brownfield exploration is uranium exploration near our existing operations and on advanced exploration projects where uranium mineralization is being defined.
In 2009, we invested $23 million in six brownfield and advanced exploration projects. The largest investment ($11.2 million) was at Kintyre for delineation drilling. We also carried out significant programs at McArthur River, Rabbit Lake, and the Millennium deposit.
Regional exploration
In 2009, we invested about $31 million in regional exploration programs (including support costs). Saskatchewan was the largest single region, followed by Australia, northern Canada and the rest of the global program.
Plans for 2010
We plan to invest approximately $90 million to $95 million on uranium exploration in 2010 as part of our long-term strategy. This includes approximately $40 million for exploration at Kintyre and Inkai block 3 in Kazakhstan.
Brownfield exploration
Approximately 20% of the uranium exploration budget, about $11 million, will be invested in six brownfield exploration projects in the Athabasca Basin and Australia.
Regional exploration
We expect to allocate the rest of the exploration budget among 48 projects worldwide, the majority of which are at drill target stage. Among the larger investments planned are $5 million on two adjacent projects in Nunavut, a $2 million program on the Dawn Lake project in Saskatchewan, and a $3 million investment 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

2009 update
Production
Our Blind River refinery produced 12.9 million kgU of UO3, which is 29% higher than our forecast. This ensured that SFL maintained its contractual inventories and Port Hope met its production requirements.
Planning for the future
We expect production in 2010 to be between 11 million and 13 million kgU as UO3.
Once we receive regulatory approval to produce at 24 million kgU, construction to increase capacity will begin.
Managing our risks
We manage the risks listed on page 50.

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Fuel services — conversion and fuel manufacturing
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. We control 35% of western world UF6 capacity.

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

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

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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2009 update
Production
Fuel services production was 12.3 million kgU in 2009, in line with our target of 11 million to 13 million kgU.
Production at the UO2 plant began in mid-January 2009, after it had been shut down for an extended planned maintenance period. We upgraded the floors and in-floor structures, and they now meet the standards of the UF6 plant.
Production at the UF6 plant began on June 17, 2009 after being suspended in December 2008 as hydrofluoric acid (HF) was not available on acceptable terms.
HF is a primary feed material for the production of UF6. We have signed an agreement with our original supplier, and with two additional suppliers, broadening our sources of supply.
Fuel manufacturing
BPLP sales represent a substantial portion of our fuel manufacturing business.
We have an agreement with Bruce Power A Limited Partnership (BALP) to supply fuel bundles that contain slightly enriched uranium (SEU). We received regulatory approval and began construction to modify the plant to produce SEU. At BALP’s request, construction has been suspended. BALP is considering its alternatives.
Port Hope conversion facility cleanup and modernization (Vision 2010)
The federal Minister of the Environment approved the environmental assessment guidelines, and work on the environmental assessment continues.
Collective agreements
Following a strike at CFM, unionized employees ratified a new three-year collective agreement that expires on June 1, 2012.
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 14 million and 16 million kgU in 2010.
Port Hope conversion facility cleanup and modernization (Vision 2010)
We expect to file the environmental assessment for this project in 2010.
Managing our risks
The main risk in 2010 is a potential strike by unionized employees at the Port Hope conversion facility, which would impact production. The collective agreement expires on June 30, 2010.
We also manage the risks listed on page 50.

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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 |  | 2017 to 2020
Term of lease |  | 2018 — right to extend for 25 years
Generation capacity |  | 3,260 MW
Average annual fuel |  | 1.2 million pounds of U3O8
supplied by Cameco |  | 600 tonnes UO2 conversion and fuel fabrication

Background
We are the fuel procurement manager for BPLP’s four nuclear reactors and for BALP’s 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.
2009 update
Output
BPLP’s adjusted capacity factor was 91% this year, which included 24.6 TWh of actual generation and 1.2 TWh of deemed generation (the market operator reduced power output from the B units during a period of excess baseload generation in Ontario).
Licensing
The operating licence for the four B reactors has been extended to October 31, 2014.
Planning for the future
Output
We expect the capacity factor to be approximately 90% in 2010 and actual output to be about 4% higher than in 2009.
Managing our risks
The collective agreements for the two main unions at Bruce Power will expire in December 2010. Bruce Power is working actively towards new agreements with its union partners.
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 page 50.

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Reserves and resources
Our uranium reserves and resources are the foundation of our company and are fundamental to our success.
We estimate and disclose them in five categories (proven and probable reserves, and measured, indicated and inferred resources) following established industry practices and in compliance with National Instrument 43-101 (NI 43-101). We use current geological models, current or projected operating costs and mine plans to estimate our reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.
Changes this year
Cameco’s share of proven and probable reserves went from 495 million pounds at the end of 2008 to 478.7 million pounds at the end of 2009. The change was mostly the result of:

• |  | mining and milling activities, which used 22 million pounds
• |  | identifying additional reserves — 14 million pounds at McArthur River, and 8 million pounds at Rabbit Lake
• |  | reclassifying reserves to resources — 8 million pounds at Cigar Lake and 6 million pounds at Ruby Ranch and Ruth

Measured and indicated resources increased from 127.9 million pounds at the end of 2008 to 139.6 million pounds at the end of 2009. The change was mostly the result of:

• |  | adding 20 million pounds of resources at Tamarack, Rabbit Lake and Crow Butte
• |  | upgrading 14 million pounds of resources to reserves at McArthur River, zone 4
• |  | downgrading 6 million pounds of reserves to resources at Ruby Ranch and Ruth

At the end of 2009, our share of inferred resources was nearly 354 million pounds — a net gain of 18 million pounds, which came mostly from the addition of 14 million pounds from surface drilling on McArthur River zone B.
Qualified persons
The technical and scientific information discussed in this MD&A, including the reserve and resource estimates for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) 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, general manager, McArthur River, Cameco
• |  | Greg Murdock, technical superintendent, McArthur River, Cameco
• |  | Lorne D. Schwartz, chief metallurgist, mining technical services, Cameco
• |  | Les Yesnik, general manager, Key Lake, Cameco

Inkai

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

Cigar Lake

• |  | Alain G. Mainville, director, mineral resources management, Cameco
• |  | Grant J.H. Goddard, general manager, Cigar Lake, Cameco
• |  | C. Scott Bishop, chief mine engineer, Cigar Lake, Cameco
• |  | Lorne D. Schwartz, chief metallurgist, mining technical services, Cameco

Alain G. Mainville, director, mineral resources management, oversees and co-ordinates the estimation of mineral reserves and resources by Cameco’s qualified persons, and reports to management and the board’s reserves oversight committee.
Estimates are based on our knowledge, mining experience, analysis of drilling results and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions, including:

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• |  | geological interpretation
• |  | extraction plans
• |  | commodity prices
• |  | operating and capital costs.

Important information for US investors
While the terms measured, indicated and inferred 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 resource will ever be converted into proven or probable mineral reserves.
• |  | Any or all of an inferred 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 feasibility or prefeasibility studies.

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, 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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Reserves
As at December 31, 2009 (100% — only the second last column shows Cameco’s share)
Proven and probable (tonnes in thousands; pounds in millions)

|  |  |  |  |  | Proven |  |  | Probable |  |  | Total 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 |  |  | 498.5 |  |  |  | 15.72 |  |  |  | 172.7 |  |  |  | 280.0 |  |  |  | 26.33 |  |  |  | 162.5 |  |  |  | 778.5 |  |  |  | 19.53 |  |  |  | 335.2 |  |  |  | 234.0 |  |  |  | 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 |  |  | 37.4 |  |  |  | 0.75 |  |  |  | 0.6 |  |  |  | 1,059.0 |  |  |  | 0.89 |  |  |  | 20.7 |  |  |  | 1,096.4 |  |  |  | 0.88 |  |  |  | 21.3 |  |  |  | 21.3 |  |  |  | 96.7 |
Key Lake |  | open pit |  |  | 61.9 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 61.9 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 98.7 |
Inkai |  | ISR |  |  | 6,043.0 |  |  |  | 0.08 |  |  |  | 11.1 |  |  |  | 83,434.0 |  |  |  | 0.07 |  |  |  | 123.6 |  |  |  | 89,477.0 |  |  |  | 0.07 |  |  |  | 134.7 |  |  |  | 80.9 |  |  |  | 80.0 |
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 |  |  | 771.9 |  |  |  | 0.12 |  |  |  | 2.0 |  |  |  | 1,931.1 |  |  |  | 0.09 |  |  |  | 3.9 |  |  |  | 2,703.0 |  |  |  | 0.10 |  |  |  | 5.9 |  |  |  | 5.9 |  |  |  | 80.0 |
Crow Butte |  | ISR |  |  | 968.7 |  |  |  | 0.11 |  |  |  | 2.3 |  |  |  | 493.1 |  |  |  | 0.17 |  |  |  | 1.8 |  |  |  | 1,461.8 |  |  |  | 0.13 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 85.0 |
Total |  |  |  |  |  |  | 8,511.9 |  |  |  | — |  |  |  | 263.1 |  |  |  | 97,831.0 |  |  |  | — |  |  |  | 475.3 |  |  |  | 106,342.9 |  |  |  | — |  |  |  | 738.4 |  |  |  | 478.7 |  |  |  |  |

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 material that can be physically recovered by the metallurgical extraction process, and is calculated by multiplying content by the estimated metallurgical recovery percentage. Our share of uranium in the table above is before accounting for estimated metallurgical recovery.
Estimates of Inkai
Our mineral reserve estimates of Inkai assume annual production of 5.2 million pounds of U3O8. Inkai has regulatory approval to produce 2.6 million pounds, and applied for approval to increase production to 5.2 million pounds per year in 2005. We expect to receive all permits and approvals required for the construction and operation of the new ISR mine at Inkai in 2010, including approval to increase annual production to 5.2 million pounds. There can be no certainty, however, that we will receive these permits or approvals. If Inkai does not receive approval to increase production, we will re-categorize half of its mineral reserves as mineral resources.
Notes
Estimates in the table:

• |  | are based on the exchange rate at December 31, 2009 ($1.00 US=$1.05 Cdn)
• |  | use an average uranium price of $54 (US)/lb U3O8

Totals may not add up due to rounding.
We do not expect these estimates to be materially affected by environmental, permitting, legal, title, taxation, socio-economic, political or marketing issues.

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Resources
As at December 31, 2009 (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 |  |  | 162.9 |  |  |  | 6.39 |  |  |  | 22.9 |  |  |  | 39.9 |  |  |  | 8.37 |  |  |  | 7.4 |  |  |  | 202.8 |  |  |  | 6.78 |  |  |  | 30.3 |  |  |  | 21.1 |
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 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 792.5 |  |  |  | 0.59 |  |  |  | 10.4 |  |  |  | 792.5 |  |  |  | 0.59 |  |  |  | 10.4 |  |  |  | 10.4 |
Dawn Lake |  | open pit, underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 347.0 |  |  |  | 1.69 |  |  |  | 12.9 |  |  |  | 347.0 |  |  |  | 1.69 |  |  |  | 12.9 |  |  |  | 7.4 |
Millennium |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 468.9 |  |  |  | 4.53 |  |  |  | 46.8 |  |  |  | 468.9 |  |  |  | 4.53 |  |  |  | 46.8 |  |  |  | 19.6 |
Tamarack |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 10.3 |
Inkai |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 13,291.0 |  |  |  | 0.07 |  |  |  | 21.9 |  |  |  | 13,291.0 |  |  |  | 0.07 |  |  |  | 21.9 |  |  |  | 13.1 |
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 |  |  | 2,834.9 |  |  |  | 0.10 |  |  |  | 6.0 |  |  |  | 13,170.9 |  |  |  | 0.06 |  |  |  | 17.0 |  |  |  | 16,005.8 |  |  |  | 0.07 |  |  |  | 23.0 |  |  |  | 23.0 |
Crow Butte |  | ISR |  |  | 64.3 |  |  |  | 0.23 |  |  |  | 0.3 |  |  |  | 2,322.2 |  |  |  | 0.20 |  |  |  | 10.1 |  |  |  | 2,386.5 |  |  |  | 0.20 |  |  |  | 10.4 |  |  |  | 10.4 |
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 |  |  |  |  | 5,886.0 |  |  |  | — |  |  |  | 34.7 |  |  |  | 40,996.0 |  |  |  | — |  |  |  | 163.8 |  |  |  | 46,882.0 |  |  |  | — |  |  |  | 198.5 |  |  |  | 139.6 |

Inferred (tonnes in thousands; pounds in millions)

|  | Mining |  |  |  |  |  | Grade |  |  | Content |  |  | Cameco’s share |
Property |  | method |  | Tonnes |  |  | % U3O8 |  |  | (lbs U3O8) |  |  | (lbs U3O8) |
McArthur River |  | underground |  |  | 604.2 |  |  |  | 11.97 |  |  |  | 159.4 |  |  |  | 111.3 |
Cigar Lake |  | underground |  |  | 480.4 |  |  |  | 12.61 |  |  |  | 133.5 |  |  |  | 66.8 |
Rabbit Lake |  | underground |  |  | 119.8 |  |  |  | 0.36 |  |  |  | 0.9 |  |  |  | 0.9 |
Millennium |  | underground |  |  | 214.3 |  |  |  | 2.06 |  |  |  | 9.7 |  |  |  | 4.1 |
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 |  |  | 2,843.7 |  |  |  | 0.11 |  |  |  | 6.7 |  |  |  | 6.7 |
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 |  |  |  |  | 267,651.3 |  |  |  | — |  |  |  | 576.8 |  |  |  | 353.9 |

Notes
Resources do not include amounts that have been identified as reserves. 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 2009, we paid PACL $30.8 million for construction and contracting services (2008 — $38.5 million). These transactions were conducted 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, 2009, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.
Management, including our president and 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 president and 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, 2009. We have not made any change to our internal control over financial reporting during the 2009 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 that will 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 — completed in June 2008
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. Necessary systems modifications have been tested and implemented as of June 30, 2009

Phase 2: Detailed component evaluation — in progress
During this phase, we are:

• |  | assessing the impact of the adoption of IFRS on our results of operations, financial position and financial statement disclosures
• |  | developing 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
• |  | specifying all changes we need to make to existing business processes

See the detailed status below.
Phase 3: Embedding — in progress
During this final phase, we will:

• |  | carry out the changes to our business processes

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• |  | receive the audit committee’s approval of our accounting policy changes
• |  | complete the training process for our audit committee, board members and staff
• |  | 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 are still evaluating some key accounting policy alternatives and implementation decisions, and have not yet determined the full accounting effects of adopting IFRS. We do not, however, expect that adopting IFRS will have a material impact on our consolidated financial statements.
Senior management and the audit committee have approved our IFRS accounting policies, but IFRS standards are evolving and may be different at the time of transition. 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 before we adopt IFRS, and that IFRS for income taxes may change at a later date. We have been monitoring and evaluating these changes, and our analysis incorporates the standards we expect to be in effect at the time of transition.
We currently expect IFRS to 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 either its fair value less costs to sell or its value in use — whichever is higher.

Value in use uses discounted future cash flows, and could result in more writedowns, but the effect of this could be lower because IAS 36 allows companies to reverse impairment losses (for everything except goodwill) if an impairment is reduced because circumstances have changed. Canadian GAAP does not allow companies to reverse impairment losses.
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.
IFRS 1, First-Time Adoption of International Financial Reporting Standards (IFRS 1), also allows companies to recognize all cumulative actuarial gains and losses in retained earnings at the transition date.

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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 this difference to affect how we account for our phantom stock option plan.
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 because of 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.

Joint ventures
We proportionately account for interests in jointly controlled enterprises under Canadian GAAP. The IASB has indicated that it expects to issue a new standard in 2010 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.
We expect to use the equity method to account for our joint venture interests when we transition to IFRS.
Income taxes
Under Canadian GAAP, we credit (or charge) income tax directly to equity only when it relates to items that we are crediting (or charging) directly to equity in the same period. IAS 12, Income Taxes, requires companies to credit (or charge) income tax directly to equity whether or not the related item is credited (or charged) directly to equity in the same period. That means we may have to recognize some income tax effects directly in equity rather than through net income or loss.
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 from GAAP in a fundamental review of income tax accounting at some time in the future, but this review is not likely to be soon.
First-time adoption of IFRS
IFRS 1 generally requires an entity to apply the new standards retrospectively at the end of its first IFRS reporting period, but there are some mandatory exceptions and some optional exemptions.
We are analyzing the options available to us, and currently expect to use the exemptions in the table below. This is a summary of the changes we currently believe will be most significant when we transition to IFRS — it is not a complete list of changes we will be required to make. We are still working on our analysis and have not made decisions about the accounting policies that are available. At this stage, we cannot reliably quantify the expected impacts of these differences on our consolidated financial statements.

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Business combinations |  | We will have the option to apply IFRS 3, Business Combinations, retrospectively or prospectively.
|  | We plan 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 |  | We will be able to choose to use the fair value of property, plant and equipment as deemed cost at the transition date, or to use the value determined under GAAP.
|  | We plan to use the historical bases under Canadian GAAP as deemed cost at the transition date.
Share-based payments |  | We will be able 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 plan 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 |  | We will be able to choose to apply IAS 23 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 plan 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 will have the option of recognizing cumulative actuarial gains and losses on benefit plans in retained earnings at the transition date.
Differences in currency translation |  | IAS 21, The Effects of Changes in Foreign Exchange Rates, will require us to calculate currency translation differences retrospectively, from the date we formed or acquired a subsidiary or associate.
|  | IFRS 1 gives us the option of resetting cumulative translation gains and losses to zero at the transition date.
|  | We plan to reset all cumulative translation gains and losses to zero in retained earnings at the transition date.
Decommissioning liabilities |  | We will have the option of applying 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 plan to adopt IFRIC 1 prospectively at the transition date.

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 could require the implementation of additional controls or procedures to ensure the integrity of our financial disclosures. We plan to design and test the effectiveness of new controls in 2010.
We conducted several educational and training sessions for our audit committee and the board of directors in 2009. 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 Cameco. Sessions will continue throughout 2010.

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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. We are planning further communications with the investment community in 2010.
We are also evaluating the impact of IFRS on our business activities in general. At this stage, we do not believe the adoption of IFRS will have a material effect on our risk management practices, hedging activities, capital requirements, compensation arrangements, compliance with debt covenants or other contractual commitments.
Business combinations
CICA Handbook Section 1582, Business Combinations, is effective for business combinations with an acquisition date after January 1, 2011. This standard specifies a number of changes, including: an expanded definition of a business, a requirement to measure all business acquisitions at fair value, a requirement to measure non-controlling interests at fair value and a requirement to recognize acquisition-related costs as expenses.
Consolidated financial statements
CICA Handbook Section 1601, Consolidated Financial Statements, which replaces the existing standard, is effective for periods beginning on or after January 1, 2011. This section establishes the standards for preparing consolidated financial statements.
Non-controlling interests in consolidated financial statements
CICA Handbook Section 1602, Non-controlling Interests in Consolidated Financial Statements, is effective for periods beginning on or after January 1, 2011. This section specifies that non-controlling interests be treated as a separate component of equity, not as a liability or other item outside of equity. Section 1602 will be applied prospectively to all non-controlling interests, including any that arose before the effective date.

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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, 2009.
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
President and Chief Executive Officer |  | Senior Vice-President and Chief Financial Officer
February 23, 2010 |  | February 23, 2010

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AUDITORS’ REPORT
To the Shareholders of Cameco Corporation
We have audited the consolidated balance sheets of Cameco Corporation (“the Corporation”) as at December 31, 2009 and 2008 and the consolidated statements of earnings, shareholders’ equity, comprehensive income, accumulated other comprehensive income and cash flows for each of the years then ended. These financial statements are the responsibility of the corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the corporation as at December 31, 2009 and 2008 and the results of its operations and its cash flows for each of the years then ended in accordance with Canadian generally accepted accounting principles.
Original signed by KPMGLLP
Chartered Accountants
Saskatoon, Canada
February 23, 2010

88

#####

Consolidated Balance Sheets

|  |  |  |  |  | (Recast |
note 25) |
As at December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2009 |  |  | 2008 |
Assets |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 1,101,229 |  |  | $ | 64,222 |
Short-term investments [note 5] |  |  | 202,836 |  |  |  | — |
Accounts receivable |  |  | 453,622 |  |  |  | 522,504 |
Inventories [note 6] |  |  | 453,224 |  |  |  | 398,110 |
Supplies and prepaid expenses |  |  | 162,105 |  |  |  | 143,020 |
Current portion of long-term receivables, investments and other [note 9] |  |  | 154,725 |  |  |  | 49,836 |
Assets of discontinued operations [note 25] |  |  | — |  |  |  | 1,176,056 |
|  |  | 2,527,741 |  |  |  | 2,353,748 |
Property, plant and equipment [note 7] |  |  | 4,068,103 |  |  |  | 3,932,658 |
Intangible assets [note 8] |  |  | 97,713 |  |  |  | 101,442 |
Long-term receivables, investments and other [note 9] |  |  | 648,545 |  |  |  | 622,753 |
Total assets |  | $ | 7,342,102 |  |  | $ | 7,010,601 |
Liabilities and Shareholders’ Equity |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | $ | 534,664 |  |  | $ | 514,710 |
Short-term debt [notes 10, 24] |  |  | 76,762 |  |  |  | 89,817 |
Dividends payable |  |  | 23,570 |  |  |  | 21,943 |
Current portion of long-term debt [note 11] |  |  | 11,629 |  |  |  | 10,175 |
Current portion of other liabilities [note 13] |  |  | 29,297 |  |  |  | 117,222 |
Future income taxes [note 18] |  |  | 87,135 |  |  |  | 68,857 |
Liabilities of discontinued operations [note 25] |  |  | — |  |  |  | 743,323 |
|  |  | 763,057 |  |  |  | 1,566,047 |
Long-term debt [note 11] |  |  | 952,853 |  |  |  | 1,212,982 |
Provision for reclamation [note 12] |  |  | 296,896 |  |  |  | 313,203 |
Other liabilities [note 13] |  |  | 187,072 |  |  |  | 179,880 |
Future income taxes [note 18] |  |  | 134,356 |  |  |  | 83,848 |
|  |  | 2,334,234 |  |  |  | 3,355,960 |
Minority interest |  |  | 164,040 |  |  |  | 141,018 |
Shareholders’ equity |  |  |  |  |  |  |  |
Share capital |  |  | 1,512,461 |  |  |  | 1,062,714 |
Contributed surplus |  |  | 131,577 |  |  |  | 131,858 |
Retained earnings |  |  | 3,158,506 |  |  |  | 2,153,315 |
Accumulated other comprehensive income |  |  | 41,284 |  |  |  | 165,736 |
|  |  | 4,843,828 |  |  |  | 3,513,623 |
Total liabilities and shareholders’ equity |  | $ | 7,342,102 |  |  | $ | 7,010,601 |

Commitments and contingencies [notes 12,18,26]
See accompanying notes to consolidated financial statements.
Approved by the board of directors
Original signed by Gerald W. Grandey and John H. Clappison

89

#####

Consolidated Statements of Earnings

|  |  |  |  |  | (Recast |
note 25) |
For the years ended December 31 |  |  |  |  |  |
($Cdn thousands, except per share amounts) |  | 2009 |  |  | 2008 |
Revenue from |  |  |  |  |  |  |  |
Products and services |  | $ | 2,314,985 |  |  | $ | 2,182,553 |
Expenses |  |  |  |  |  |  |  |
Products and services sold (i) |  |  | 1,324,278 |  |  |  | 1,146,462 |
Depreciation, depletion and reclamation |  |  | 240,643 |  |  |  | 207,453 |
Administration |  |  | 135,558 |  |  |  | 86,392 |
Exploration |  |  | 49,061 |  |  |  | 53,224 |
Research and development |  |  | 630 |  |  |  | 4,998 |
Interest and other [note 15] |  |  | (12,470 | ) |  |  | 93,281 |
(Gains) losses on derivatives [note 27] |  |  | (243,804 | ) |  |  | 202,651 |
Cigar Lake remediation |  |  | 17,884 |  |  |  | 11,369 |
Gain on sale of assets [note 16] |  |  | (566 | ) |  |  | (4,097 | )
|  |  | 1,511,214 |  |  |  | 1,801,733 |
Earnings from continuing operations |  |  | 803,771 |  |  |  | 380,820 |
Other expense [note 17] |  |  | (36,912 | ) |  |  | (39,273 | )
Earnings before income taxes and minority interest |  |  | 766,859 |  |  |  | 341,547 |
Income tax expense (recovery) [note 18] |  |  | 52,897 |  |  |  | (24,357 | )
Minority interest |  |  | (3,035 | ) |  |  | (245 | )
Earnings from continuing operations |  | $ | 716,997 |  |  | $ | 366,149 |
Earnings from discontinued operations [note 25] |  |  | 382,425 |  |  |  | 83,968 |
Net earnings |  | $ | 1,099,422 |  |  | $ | 450,117 |
Net earnings per share [note 28] |  |  |  |  |  |  |  |
Basic |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.84 |  |  | $ | 1.05 |
Discontinued operations |  |  | 0.99 |  |  |  | 0.24 |
Total basic earnings per share |  | $ | 2.83 |  |  | $ | 1.29 |
Diluted |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.84 |  |  | $ | 1.04 |
Discontinued operations |  |  | 0.98 |  |  |  | 0.24 |
Total diluted earnings per share |  | $ | 2.82 |  |  | $ | 1.28 |
(i) Excludes depreciation, depletion and reclamation expenses of: |  | $ | 228,317 |  |  | $ | 198,594 |

See accompanying notes to consolidated financial statements.

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#####

Consolidated Statements of Shareholders’ Equity

|  |  |  |  |  | (Recast |
|  |  |  |  |  | note 25) |
For the years ended December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2009 |  |  | 2008 |
Share capital |  |  |  |  |  |  |  |
Balance at beginning of year |  | $ | 1,062,714 |  |  | $ | 819,268 |
Stock option plan |  |  | 4,215 |  |  |  | 1,011 |
Debenture conversions [note 11] |  |  | — |  |  |  | 242,435 |
Equity issuance [note 14] |  |  | 445,532 |  |  |  | — |
Balance at end of year |  |  | 1,512,461 |  |  |  | 1,062,714 |
Contributed surplus |  |  |  |  |  |  |  |
Balance at beginning of year |  |  | 131,858 |  |  |  | 119,531 |
Stock option plan amendment [note 22] |  |  | — |  |  |  | 25,987 |
Stock-based compensation |  |  | 641 |  |  |  | 16,821 |
Options exercised |  |  | (922 | ) |  |  | (40 | )
Debenture conversions [note 11] |  |  | — |  |  |  | (30,441 | )
Balance at end of year |  |  | 131,577 |  |  |  | 131,858 |
Retained earnings |  |  |  |  |  |  |  |
Balance at beginning of year |  |  | 2,153,315 |  |  |  | 1,788,416 |
Net earnings |  |  | 1,099,422 |  |  |  | 450,117 |
Dividends on common shares |  |  | (94,231 | ) |  |  | (85,218 | )
Balance at end of year |  |  | 3,158,506 |  |  |  | 2,153,315 |
Accumulated other comprehensive income (loss) |  |  |  |  |  |  |  |
Balance at beginning of year |  |  | 165,736 |  |  |  | 104,021 |
Other comprehensive income |  |  | (124,452 | ) |  |  | 61,715 |
Balance at end of year |  |  | 41,284 |  |  |  | 165,736 |
Total retained earnings and accumulated other comprehensive income |  |  | 3,199,790 |  |  |  | 2,319,051 |
Shareholders’ equity at end of year |  | $ | 4,843,828 |  |  | $ | 3,513,623 |

See accompanying notes to consolidated financial statements.

91

#####

Consolidated Statements of Comprehensive Income

|  |  |  |  |  | (Recast |
|  |  |  |  |  | note 25) |
For the years ended December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2009 |  |  | 2008 |
Net earnings |  | $ | 1,099,422 |  |  | $ | 450,117 |
Other comprehensive income (loss), net of taxes [note 18] |  |  |  |  |  |  |  |
Unrealized foreign currency translation (losses) gains |  |  | (115,739 | ) |  |  | 137,689 |
Gains on derivatives designated as cash flow hedges |  |  | 101,162 |  |  |  | 23,976 |
Gains on derivatives designated as cash flow hedges transferred to net earnings |  |  | (113,360 | ) |  |  | (105,056 | )
Unrealized gains (losses) on available-for-sale securities |  |  | 3,011 |  |  |  | (14,271 | )
Losses on available-for-sale securities transferred to net earnings |  |  | 474 |  |  |  | 19,377 |
Other comprehensive income |  |  | (124,452 | ) |  |  | 61,715 |
Total comprehensive income |  | $ | 974,970 |  |  | $ | 511,832 |

Consolidated Statement of Accumulated Other Comprehensive Income

|  | Currency |  |  |  |  |  |
|  | Translation |  | Cash Flow |  | Available-For- |  |
($Cdn thousands)(net of related income taxes)[note 18] |  | Adjustment |  | Hedges |  | Sale Assets |  | Total
Balance at December 31, 2007 |  | $ | (72,347 | ) |  | $ | 182,734 |  |  | $ | (6,366 | ) |  | $ | 104,021 |
Unrealized foreign currency translation gains |  |  | 137,689 |  |  |  | — |  |  |  | — |  |  |  | 137,689 |
Gains on derivatives designated as cash flow hedges |  |  | — |  |  |  | 23,976 |  |  |  | — |  |  |  | 23,976 |
Gains on derivatives designated as cash flow hedges transferred to net earnings |  |  | — |  |  |  | (105,056 | ) |  |  | — |  |  |  | (105,056 | )
Unrealized losses on available-for-sale securities |  |  | — |  |  |  | — |  |  |  | (14,271 | ) |  |  | (14,271 | )
Losses on available-for-sale securities transferred to net earnings |  |  | — |  |  |  | — |  |  |  | 19,377 |  |  |  | 19,377 |
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 |

See accompanying notes to consolidated financial statements.

92

#####

Consolidated Statements of Cash Flows

|  |  |  |  |  | (Recast |
|  |  |  |  |  | note 25) |
For the years ended December 31 |  |  |  |  |  |
($Cdn thousands) |  | 2009 |  |  | 2008 |
Operating activities |  |  |  |  |  |  |  |
Net earnings |  | $ | 1,099,422 |  |  | $ | 450,117 |
Items not requiring (providing) cash: |  |  |  |  |  |  |  |
Depreciation, depletion and reclamation |  |  | 240,643 |  |  |  | 207,453 |
Provision for future taxes [note 18] |  |  | 2,237 |  |  |  | (117,461 | )
Deferred gains |  |  | (41,254 | ) |  |  | (112,361 | )
Unrealized (gains) losses on derivatives |  |  | (180,260 | ) |  |  | 156,098 |
Unrealized foreign exchange losses |  |  | — |  |  |  | 71,241 |
Stock-based compensation [note 22] |  |  | 2,772 |  |  |  | 14,574 |
Gain on sale of assets [note 16] |  |  | (566 | ) |  |  | (4,097 | )
Equity in loss from associated companies [note 17] |  |  | 29,811 |  |  |  | 9,706 |
Other expense (income) [note 17] |  |  | 7,101 |  |  |  | (425 | )
Writedown of investments [notes 9, 17] |  |  | — |  |  |  | 29,992 |
Discontinued operations [note 25] |  |  | (382,425 | ) |  |  | (83,968 | )
Minority interest |  |  | (3,035 | ) |  |  | (245 | )
Other operating items [note 19] |  |  | (84,333 | ) |  |  | (91,036 | )
Cash provided by operations |  |  | 690,113 |  |  |  | 529,588 |
Investing activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (392,719 | ) |  |  | (531,061 | )
Acquisitions, net of cash [note 24] |  |  | — |  |  |  | (503,157 | )
Purchase of short-term investments [note 5] |  |  | (202,850 | ) |  |  | — |
Increase in long-term receivables, investments and other |  |  | (40,258 | ) |  |  | (49,518 | )
Proceeds on sale of property, plant and equipment |  |  | 3,647 |  |  |  | 37,093 |
Cash used in investing (continuing operations) |  |  | (632,180 | ) |  |  | (1,046,643 | )
Cash provided by investing (discontinued operations) [note 25] |  |  | 871,300 |  |  |  | — |
Cash provided by (used in) investing |  |  | 239,120 |  |  |  | (1,046,643 | )
Financing activities |  |  |  |  |  |  |  |
Decrease in debt |  |  | (726,460 | ) |  |  | (10,712 | )
Increase in debt |  |  | — |  |  |  | 640,089 |
Issue of debentures, net of issue costs [note 11] |  |  | 495,272 |  |  |  | — |
Issue of shares, net of issue costs [note 14] |  |  | 440,150 |  |  |  | — |
Issue of shares, stock option plan |  |  | 1,292 |  |  |  | 972 |
Dividends |  |  | (92,603 | ) |  |  | (80,495 | )
Cash provided by financing |  |  | 117,651 |  |  |  | 549,854 |
Increase in cash during the year |  |  | 1,046,884 |  |  |  | 32,799 |
Exchange rate changes on foreign currency cash balances |  |  | (9,877 | ) |  |  | 3,737 |
Cash and cash equivalents at beginning of year |  |  | 64,222 |  |  |  | 27,686 |
Cash and cash equivalents at end of year |  | $ | 1,101,229 |  |  | $ | 64,222 |
Cash and cash equivalents comprised of: |  |  |  |  |  |  |  |
Cash |  | $ | 56,009 |  |  | $ | 61,429 |
Cash equivalents |  |  | 1,045,220 |  |  |  | 2,793 |
|  | $ | 1,101,229 |  |  | $ | 64,222 |
Supplemental cash flow disclosure |  |  |  |  |  |  |  |
Interest paid |  | $ | 35,267 |  |  | $ | 52,272 |
Income taxes paid |  | $ | 57,093 |  |  | $ | 117,788 |

See accompanying notes to consolidated financial statements.

93

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Notes to Consolidated Financial Statements
For the years ended December 31, 2009 and 2008
($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.

94

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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 will be depleted by charges against earnings from future mining operations. 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 unit-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.
| (j) |  | Research and Development and Exploration Costs
|  |  | Expenditures for research and technology related to the products, processes and expenditures for geological exploration programs are charged against earnings as incurred.

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| (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, 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 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

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|  |  | 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) |  | Changes in Accounting Policies

| (i) |  | Goodwill and Intangible Assets
|  |  | Effective January 1, 2009, Cameco adopted the new Canadian standard, Handbook Section 3064, Goodwill and Intangible Assets, which replaces Handbook Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The standard introduces guidance for the recognition, measurement and disclosure of goodwill and intangible assets, including internally generated intangible assets. The standard also harmonizes Canadian standards with IFRS and applies to annual and interim financial statements for fiscal years beginning on or after October 1, 2008. There was no material impact to previously reported financial statements as a result of the implementation of the new standard.
| (ii) |  | Financial Instruments — Disclosures
|  |  | Effective October 1, 2009, Cameco adopted the amendments to Handbook Section 3862, Financial Instruments — Disclosures. The amendments harmonize Canadian standards with IFRS and provide for enhanced disclosures on liquidity risk and require new disclosures on fair value measurements of financial instruments.

| (b) |  | Future Changes in Accounting Policy

| (i) |  | 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.
| (ii) |  | Business Combinations
|  |  | CICA Handbook Section 1582, Business Combinations is effective for business combinations with an acquisition date after January 1, 2011. This standard specifies a number of changes, including an expanded definition of a business, a requirement to measure all business acquisitions at fair value, a requirement to measure non-controlling interests at fair value and a requirement to recognize acquisition-related costs as expenses.
| (iii) |  | Consolidated Financial Statements
|  |  | CICA Handbook Section 1601, Consolidated Financial Statements, which replaces the existing standard, is effective for periods beginning on or after January 1, 2011. This section establishes the standards for preparing consolidated financial statements.
| (iv) |  | Non-controlling Interests in Consolidated Financial Statements
|  |  | CICA Handbook Section 1602, Non-controlling Interests in Consolidated Financial Statements is effective for periods beginning on or after January 1, 2011. This section specifies that non-controlling interests be treated as a separate component of equity, not as a liability or other item outside of equity. Section 1602 will be applied prospectively to all non-controlling interests, including any that arose before the effective date.

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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, 2009, the effect of a $1/MWh increase in the market price for electricity would be an increase of $778,000 in net earnings, and a decrease in other comprehensive income of $3,450,000 for 2009.
| (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, 2009, 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 $11,000,000 in net earnings for 2009.
| (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.

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|  |  | 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, 2009, 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, 2009:

|  |  |  |  |  | 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 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 794 |
BPLP lease |  |  | 171 |  |  |  | 12 |  |  |  | 28 |  |  |  | 35 |  |  |  | 96 |
Short-term debt |  |  | 77 |  |  |  | 77 |  |  |  | — |  |  |  | — |  |  |  | — |
Total contractual repayments |  | $ | 1,042 |  |  | $ | 89 |  |  | $ | 28 |  |  | $ | 35 |  |  | $ | 890 |

|  |  |  |  |  | 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 |  | $ | 358 |  |  | $ | 42 |  |  | $ | 85 |  |  | $ | 85 |  |  | $ | 146 |
Interest on BPLP lease |  |  | 67 |  |  |  | 12 |  |  |  | 22 |  |  |  | 17 |  |  |  | 16 |
Interest on short-term debt |  |  | 2 |  |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | — |
Total interest payments |  | $ | 427 |  |  | $ | 56 |  |  | $ | 107 |  |  | $ | 102 |  |  | $ | 162 |

|  | 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 2009 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, 2009 was as follows:

(Thousands) |  | 2009 |  |  | 2008 |
Long-term debt |  | $ | 964,482 |  |  | $ | 1,223,157 |
Short-term debt |  |  | 76,762 |  |  |  | 89,817 |
Cash and cash equivalents |  |  | (1,101,229 | ) |  |  | (64,222 | )
Short-term investments |  |  | (202,836 | ) |  |  | — |
Net debt |  |  | (262,821 | ) |  |  | 1,248,752 |
Minority interest |  |  | 164,040 |  |  |  | 141,018 |
Shareholders’ equity |  |  | 4,843,828 |  |  |  | 3,513,623 |
Total equity |  |  | 5,007,868 |  |  |  | 3,654,641 |
Total capital |  | $ | 4,745,047 |  |  | $ | 4,903,393 |

|  | 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, 2009, Cameco met these requirements.

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5. |  | Short-Term Investments
|  | In 2009, Cameco purchased money market instruments with terms to maturity between three and 12 months. The fair values of marketable securities held at December 31, 2009 were $202,836,000 (2008 — nil).
6. |  | Inventories

|  | 2009 |  |  | 2008 |
Uranium |  |  |  |  |  |  |  |
Concentrate |  | $ | 310,893 |  |  | $ | 287,079 |
Broken ore |  |  | 18,125 |  |  |  | 21,396 |
|  |  | 329,018 |  |  |  | 308,475 |
Fuel Services |  |  | 124,206 |  |  |  | 89,635 |
Total |  | $ | 453,224 |  |  | $ | 398,110 |

7. |  | Property, Plant and Equipment

|  |  |  |  |  | Accumulated |  |  |  |  |  |  |
|  |  |  |  |  | Depreciation |  |  |  |  |  |  |
|  | Cost |  |  | and Depletion |  |  | 2009 Net |  |  | 2008 Net |
Uranium |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mining |  | $ | 3,308,418 |  |  | $ | 1,507,039 |  |  | $ | 1,801,379 |  |  | $ | 1,799,885 |
Non-producing |  |  | 1,476,409 |  |  |  | — |  |  |  | 1,476,409 |  |  |  | 1,325,532 |
Fuel Services |  |  | 491,921 |  |  |  | 212,608 |  |  |  | 279,313 |  |  |  | 279,391 |
Electricity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets under capital lease |  |  | 164,288 |  |  |  | 80,422 |  |  |  | 83,866 |  |  |  | 93,220 |
Other |  |  | 586,368 |  |  |  | 224,991 |  |  |  | 361,377 |  |  |  | 367,004 |
Other |  |  | 117,897 |  |  |  | 52,138 |  |  |  | 65,759 |  |  |  | 67,626 |
Total |  | $ | 6,145,301 |  |  | $ | 2,077,198 |  |  | $ | 4,068,103 |  |  | $ | 3,932,658 |

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8. |  | Intangible Assets and Goodwill

|  |  |  |  |  | Accumulated |  |  |  |  |  |  |
|  | Cost |  |  | Depreciation |  |  | 2009 Net |  |  | 2008 Net |
Intangible assets |  | $ | 118,819 |  |  | $ | 21,106 |  |  | $ | 97,713 |  |  | $ | 101,442 |

|  | The intangible asset value relates to intellectual property associated with Cameco Fuel Manufacturing and is being amortized on a unit-of-production basis.
9. |  | Long-Term Receivables, Investments and Other

|  | 2009 |  |  | 2008 |
BPLP [note 21] |  |  |  |  |  |  |  |
Capital lease receivable from BPLP (i) |  | $ | 94,895 |  |  | $ | 97,044 |
Derivatives [note 27] |  |  | 141,949 |  |  |  | 75,994 |
Accrued pension benefit asset [note 23] |  |  | 36,613 |  |  |  | 6,061 |
Equity accounted investments |  |  |  |  |  |  |  |
Global Laser Enrichment LLC (privately held) [note 24] |  |  | 185,716 |  |  |  | 240,018 |
UNOR Inc. (market value $952) |  |  | 935 |  |  |  | 1,088 |
UEX Corporation (market value $45,909) |  |  | 6,052 |  |  |  | 6,714 |
Huron Wind (privately held) |  |  | 4,002 |  |  |  | 4,623 |
Minergia S.A.C. (privately held) |  |  | 4,551 |  |  |  | 534 |
UFP Investments Inc. (privately held) |  |  | 2,617 |  |  |  | — |
Available-for-sale securities |  |  |  |  |  |  |  |
Western Uranium Corporation (market value $4,637) |  |  | 4,637 |  |  |  | 3,296 |
GoviEx Uranium (privately held) [note 24] |  |  | 25,214 |  |  |  | 34,442 |
Derivatives [note 27] |  |  | 68,432 |  |  |  | 5,793 |
Deferred charges |  |  |  |  |  |  |  |
Cost of sales [note 13] |  |  | 14,415 |  |  |  | 6,414 |
Advances receivable from Inkai JV LLP (ii) |  |  | 141,149 |  |  |  | 126,130 |
Accrued pension benefit asset [note 23] |  |  | 7,773 |  |  |  | 4,815 |
Other |  |  | 64,320 |  |  |  | 59,623 |
|  |  | 803,270 |  |  |  | 672,589 |
Less current portion |  |  | (154,725 | ) |  |  | (49,836 | )
Net |  | $ | 648,545 |  |  | $ | 622,753 |

(i) |  | BPLP leases the Bruce A nuclear generating plants and other property, plant and equipment to Bruce A L.P. 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, 2009, $337,000,000 (US) of principal and interest was outstanding (2008 — $257,000,000 (US)), of which 40% represents the joint venture partner’s share. As management does not anticipate repayment in the next 12 months, it has classified this loan as long term.

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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) [note 24]. The promissory note is payable on demand and bears interest at market rates.
|  | In February 2009, Cameco concluded an arrangement for a $100,000,000 unsecured revolving credit facility, maturing February 5, 2010. In December 2009, this facility was extended to February 4, 2011, and is extendable for one additional 364-day term upon mutual agreement with the lender. There is no amount outstanding under this facility.
11. |  | Long-Term Debt

|  | 2009 |  |  | 2008 |
Debentures |  | $ | 793,842 |  |  | $ | 298,177 |
Capital lease obligation — BPLP |  |  | 170,640 |  |  |  | 180,784 |
Commercial paper and bank debt |  |  | — |  |  |  | 744,196 |
|  |  | 964,482 |  |  |  | 1,223,157 |
Less current portion |  |  | (11,629 | ) |  |  | (10,175 | )
Net |  | $ | 952,853 |  |  | $ | 1,212,982 |

|  | On September 25, 2003, the company issued unsecured convertible debentures in the amount of $230,000,000. The debentures bore interest at 5% per annum, were to mature on October 1, 2013, and at the holder’s option were convertible into common shares of Cameco. The debentures were redeemable by the company beginning October 1, 2008, at a redemption price of par plus accrued and unpaid interest. The fair value of the conversion option associated with the convertible debentures on the date of issuance was $30,473,000, resulting in an effective interest rate of 7.21%. The amount was reflected as contributed surplus. The conversion price was $10.83 per share, a rate of approximately 92.3 common shares per $1,000 of convertible debentures. Interest was payable semi-annually in arrears on April 1 and October 1. On August 14, 2008, Cameco gave notice of its intention to redeem all of these debentures on October 1, 2008. As a result of debenture conversions and redemptions, 21,204,585 shares were issued during 2008 [note 14].
|  | 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. This facility can be extended for an additional year on the 2010 and 2011 anniversary dates, upon mutual agreement with the lenders. 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, 2009, there were no amounts outstanding under this credit facility (2008 — $149,800,000, bearing interest at an average rate of 1.7%). Cameco may also borrow directly in the commercial paper market. There was no commercial paper outstanding at December 31, 2009 (2008 — $152,800,000, bearing interest at an average rate of 2.7%). These amounts, when drawn, are classified as long-term debt.
|  | In 2008, Cameco arranged for a $470,000,000, 364-day unsecured revolving credit facility, extendable for up to two additional 364-day terms upon mutual agreement with the lenders. The facility ranks equally with all of Cameco’s other senior debt. At December 31, 2008, there was $29,885,000 (Cdn) and $336,200,000 (US) outstanding under this credit facility, bearing interest at 2.30% and 2.58%, respectively. Borrowings under this short-term facility were incurred to finance acquisitions [note 24]. In September 2009, this credit facility was terminated.
|  | 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, 2009, Cameco was in compliance with covenants and does not expect its operating and investing activities in 2010 to be constrained by them.

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|  | Cameco has $597,062,000 ($400,933,000 and $187,397,000 (US)) in letter of credit facilities. The majority of the outstanding letters of credit at December 31, 2009 relate to future decommissioning and reclamation liabilities [note 12] and amounted to $592,215,000 ($396,427,000 and $187,071,000 (US)) (2008 — $428,910,000 ($294,650,000 and $109,640,000 (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, 2011, as well as $184,000,000 (Cameco’s share $58,144,000) in letter of credit facilities. As at December 31, 2009, BPLP had $35,000,000 (Cameco’s share $11,060,000) outstanding under the revolving credit facility and $184,000,000 (Cameco’s share $58,144,000) outstanding under the letter of credit facilities.
|  | The table below represents currently scheduled maturities of long-term debt over the next five years.

2010 |  | $ | 11,629 |
2011 |  |  | 13,177 |
2012 |  |  | 14,852 |
2013 |  |  | 16,337 |
2014 |  |  | 18,233 |
Thereafter |  |  | 890,254 |
Total |  | $ | 964,482 |

|  | Standby Product Loan Facilities
|  | Cameco had arranged for a standby product loan facility with one of its customers. The arrangement, which was finalized in 2006, allowed Cameco to borrow up to 2,600,000 pounds U3O8 equivalent over the period 2006 to 2008 with repayment in 2008 and 2009. Of this material, up to 1,000,000 kilograms of uranium could have been borrowed in the form of UF6. Under the loan facility, standby fees of 2.25% 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 4.0%. Any borrowings would have been secured by letters of credit and payable in kind.
|  | On January 29, 2008, Cameco gave notice of termination to the counterparty of the product loan arrangement. The loan facility was terminated on April 1, 2008 and the associated letter of credit facilities were cancelled on January 31, 2008. Cameco recognized previously deferred revenues and costs in its earnings during 2008.
|  | On April 1, 2008, Cameco arranged for a standby product loan facility with one of its customers. The arrangement allows 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% are payable based on the market value of the facility, and interest is payable on the market value of any amounts drawn at a rate of 5%. Any borrowings are payable in kind. As at December 31, 2009, Cameco did not have any loan amounts outstanding under the facility.

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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 $495,112,000. 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 $591,548,000 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:

|  | 2009 |  |  | 2008 |
Balance, beginning of year |  | $ | 313,203 |  |  | $ | 264,055 |
Changes in estimates |  |  | (13,614 | ) |  |  | 26,308 |
Liabilities settled |  |  | (6,263 | ) |  |  | (4,663 | )
Accretion expense |  |  | 17,828 |  |  |  | 15,260 |
Impact of foreign exchange |  |  | (14,258 | ) |  |  | 12,243 |
Balance, end of year |  | $ | 296,896 |  |  | $ | 313,203 |

|  | 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 — $495,112,000.
| (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 — 5.25% to 7.50% for operations in North America and 9.00% for operations in Central Asia.

|  | The asset retirement obligations liability relates to the following segments:

|  | 2009 |  |  | 2008 |
Uranium |  | $ | 192,544 |  |  | $ | 213,559 |
Fuel Services |  |  | 104,352 |  |  |  | 99,644 |
Total |  | $ | 296,896 |  |  | $ | 313,203 |

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13. |  | Other Liabilities

|  | 2009 |  |  | 2008 |
Deferred sales [note 9] |  | $ | 24,982 |  |  | $ | 31,511 |
Derivatives [note 27] |  |  | 4,137 |  |  |  | 119,869 |
Accrued post-retirement benefit liability [note 23] |  |  | 12,019 |  |  |  | 11,842 |
Zircatec acquisition holdback |  |  | — |  |  |  | 2,000 |
BPLP |  |  |  |  |  |  |  |
Accrued post-retirement benefit liability [note 23] |  |  | 125,402 |  |  |  | 117,038 |
Derivatives [note 27] |  |  | 36,820 |  |  |  | 534 |
Other |  |  | 13,009 |  |  |  | 14,308 |
|  |  | 216,369 |  |  |  | 297,102 |
Less current portion |  |  | (29,297 | ) |  |  | (117,222 | )
Net |  | $ | 187,072 |  |  | $ | 179,880 |

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) |  | 2009 |  |  | 2008 |
Beginning of year |  |  | 365,718,923 |  |  |  | 344,398,698 |
Issued: |  |  |  |  |  |  |  |
Equity issuance |  |  | 26,666,400 |  |  |  | — |
Stock option plan [note 22] |  |  | 453,410 |  |  |  | 115,640 |
Debenture conversions [note 11] |  |  | — |  |  |  | 21,204,585 |
Issued share capital |  |  | 392,838,733 |  |  |  | 365,718,923 |

| (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.
| (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.

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15. |  | Interest and Other

|  | 2009 |  |  | 2008 |
Interest on long-term debt |  | $ | 38,377 |  |  | $ | 51,950 |
Interest on short-term debt |  |  | 2,366 |  |  |  | 1,377 |
Foreign exchange (gains) losses |  |  | (21,086 | ) |  |  | 83,006 |
Other charges |  |  | 11,302 |  |  |  | 12,498 |
Interest income |  |  | (6,614 | ) |  |  | (16,365 | )
Capitalized interest |  |  | (36,815 | ) |  |  | (39,185 | )
Net |  | $ | (12,470 | ) |  | $ | 93,281 |

16. |  | Gain on Sale of Assets

|  | 2009 |  |  | 2008 |
Sale of geological data |  | $ | (3,674 | ) |  | $ | (927 | )
Other |  |  | 3,108 |  |  |  | (3,170 | )
Net |  | $ | (566 | ) |  | $ | (4,097 | )

17. |  | Other Expense

|  | 2009 |  |  | 2008 |
Writedown of investments [note 9] |  | $ | — |  |  | $ | (29,992 | )
Equity in loss of associated companies |  |  | (29,811 | ) |  |  | (9,706 | )
Other |  |  | (7,101 | ) |  |  | 425 |
Net |  | $ | (36,912 | ) |  | $ | (39,273 | )

|  | In 2009, the equity in loss of associated companies includes a charge of $18,295,000 for the amortization of in-process research and development associated with the investment in GLE (2008 — $1,991,000). During 2008, the investments in Western Uranium Corporation, Cue Resources Ltd. and UNOR Inc. were determined to be impaired and charges of $17,092,000, $6,479,000 and $6,421,000 respectively, were recognized during the year [note 9].

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18. |  | Income Taxes
|  | The significant components of future income tax assets and liabilities at December 31 are as follows:

|  | 2009 |  |  | 2008 |
Assets |  |  |  |  |  |  |  |
Provision for reclamation |  | $ | 89,996 |  |  | $ | 92,345 |
Foreign exploration and development |  |  | 40,221 |  |  |  | 30,769 |
Income tax losses carried forward |  |  | 100,783 |  |  |  | 210,454 |
Other |  |  | 31,185 |  |  |  | 68,256 |
Future income tax assets before valuation allowance |  |  | 262,185 |  |  |  | 401,824 |
Valuation allowance |  |  | (57,398 | ) |  |  | (104,307 | )
Future income tax assets, net of valuation allowance |  | $ | 204,787 |  |  | $ | 297,517 |
Liabilities |  |  |  |  |  |  |  |
Property, plant and equipment |  | $ | 338,645 |  |  | $ | 339,549 |
Inventories |  |  | 5,618 |  |  |  | 30,567 |
Long-term investments and other |  |  | 82,015 |  |  |  | 80,106 |
Future income tax liabilities |  | $ | 426,278 |  |  | $ | 450,222 |
Net future income tax liabilities |  | $ | 221,491 |  |  | $ | 152,705 |
Less current portion |  |  | (87,135 | ) |  |  | (68,857 | )
|  | $ | 134,356 |  |  | $ | 83,848 |

|  | 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:

|  | 2009 |  |  | 2008 |
Earnings before income taxes and minority interest |  | $ | 766,859 |  |  | $ | 341,547 |
Combined federal and provincial tax rate |  |  | 31.4 | % |  |  | 32.3 | %
Computed income tax expense |  |  | 240,794 |  |  |  | 110,320 |
Increase (decrease) in taxes resulting from: |  |  |  |  |  |  |  |
Reduction in income tax rates |  |  | (10,983 | ) |  |  | — |
Provincial royalties and other taxes |  |  | — |  |  |  | 1,988 |
Manufacturing and processing deduction |  |  | (3,211 | ) |  |  | (771 | )
Difference between Canadian rate and rates applicable to subsidiaries in other countries |  |  | (175,969 | ) |  |  | (176,659 | )
Restructuring of gold business |  |  | — |  |  |  | (37,053 | )
Change in valuation allowance |  |  | 18,125 |  |  |  | 6,154 |
Capital and other taxes |  |  | 1,824 |  |  |  | — |
Stock-based compensation plans |  |  | 1,371 |  |  |  | 13,105 |
Other permanent differences |  |  | (19,054 | ) |  |  | 58,559 |
Income tax expense (recovery) |  | $ | 52,897 |  |  | $ | (24,357 | )

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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 Canadian taxable income by approximately $43,000,000 (this reassessment was superseded by a reassessment issued in February 2009 and neither reassessment resulted in more than a nominal amount of cash taxes becoming payable for that year). In December 2009, CRA issued a notice of reassessment for the 2004 tax return, which increased Cameco’s 2004 Canadian taxable income by approximately $108,000,000 (which, again, did not result in more than a nominal amount of cash taxes becoming payable for that year). Cameco believes it is likely that CRA will reassess Cameco’s tax returns for the years 2005 through 2009 on a similar basis.
|  | Late in 2009, CRA’s Transfer Pricing Review Committee decided not to impose a penalty for 2004 based on the documentation that had been submitted by Cameco. This followed the same decision by the Transfer Pricing Review Committee late in 2008 for the 2003 notice of reassessment.
|  | 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 decided to increase its reserve for uncertain tax positions and recognize an income tax expense of $9,000,000 in 2009, bringing the cumulative tax provision related to this matter for the years 2003 through 2009 to $24,000,000. No provisions for penalties or interest have been recorded. We do not expect any cash taxes to be payable due to availability of elective deductions and tax loss carryforwards. 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 2009 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 2003 reassessment, a Notice of Appeal was filed with the Tax Court of Canada on July 22, 2009 and the litigation process is proceeding. Cameco expects to file a Notice of Appeal for the 2004 reassessment in 2010.

|  | 2009 |  |  | 2008 |
Earnings before income taxes and minority interest |  |  |  |  |  |  |  |
Canada |  | $ | 109,534 |  |  | $ | (378,584 | )
Foreign |  |  | 657,325 |  |  |  | 720,131 |
|  | $ | 766,859 |  |  | $ | 341,547 |
Current income taxes |  |  |  |  |  |  |  |
Canada |  | $ | 17,109 |  |  | $ | 44,752 |
Foreign |  |  | 33,551 |  |  |  | 48,352 |
|  | $ | 50,660 |  |  | $ | 93,104 |
Future income taxes (recovery) |  |  |  |  |  |  |  |
Canada |  | $ | 3,885 |  |  | $ | (101,746 | )
Foreign |  |  | (1,648 | ) |  |  | (15,715 | )
|  | $ | 2,237 |  |  | $ | (117,461 | )
Income tax expense (recovery) |  | $ | 52,897 |  |  | $ | (24,357 | )

|  | For 2009, earnings from discontinued operations [note 25] included a net income tax expense of $94,600,000 (2008 — recovery of $400,000).

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|  | 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:

|  | 2009 |  |  | 2008 |
Gains (losses) on derivatives designated as cash flow hedges |  | $ | 48,368 |  |  | $ | (6,773 | )
Gains on derivatives designated as cash flow hedges transferred to net earnings |  |  | (48,121 | ) |  |  | (38,415 | )
Unrealized gains (losses) on assets available-for-sale |  |  | 466 |  |  |  | (2,072 | )
Losses on assets available-for-sale transferred to net earnings |  |  | 80 |  |  |  | 3,024 |
Total income tax expense (recovery) included in OCI |  | $ | 793 |  |  | $ | (44,236 | )

|  | 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:

|  | 2009 |  |  | 2008 |
Gains on derivatives designated as cash flow hedges |  | $ | 36,987 |  |  | $ | 36,740 |
Gains (losses) on assets available-for-sale |  |  | 346 |  |  |  | (200 | )
Total income tax expense included in AOCI |  | $ | 37,333 |  |  | $ | 36,540 |

19. |  | Statements of Cash Flows
|  | Other Operating Items

|  | 2009 |  |  | 2008 |
Changes in non-cash working capital: |  |  |  |  |  |  |  |
Accounts receivable |  | $ | 34,556 |  |  | $ | (122,239 | )
Inventories |  |  | (74,938 | ) |  |  | 21,694 |
Supplies and prepaid expenses |  |  | (27,838 | ) |  |  | (33,137 | )
Accounts payable and accrued liabilities |  |  | 30,784 |  |  |  | 10,393 |
Hedge position settlements |  |  | — |  |  |  | 52,152 |
Other |  |  | (46,897 | ) |  |  | (19,899 | )
Total |  | $ | (84,333 | ) |  | $ | (91,036 | )

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20. |  | Uranium Joint Ventures
|  | Cameco conducts a portion of its exploration, development, mining and milling activities through joint ventures. Cameco’s significant uranium joint venture interests are comprised of:

Producing: |  |  |  |
McArthur River |  |  | 69.81 | %
Key Lake |  |  | 83.33 | %
Inkai |  |  | 60.00 | %
Non-producing: |  |  |  |
Cigar Lake |  |  | 50.03 | %

|  | Uranium 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. At December 31, 2009, Cameco’s share of property, plant and equipment in these joint ventures amounted to $2,345,000,000 (2008 — $2,233,000,000) [note 7].
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 2009, sales of uranium and conversion services to BPLP amounted to $84,909,000 (2008 — $58,611,000), approximately 3.7% (2008 — 2.7%) of Cameco’s total revenue. At December 31, 2009, amounts receivable under these agreements totaled $11,505,000 (2008 — $11,131,000).
|  | 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) |  | 2009 |  |  | 2008 |
Current assets |  | $ | 252 |  |  | $ | 190 |
Property, plant and equipment |  |  | 390 |  |  |  | 403 |
Long-term receivables and investments |  |  | 207 |  |  |  | 156 |
|  | $ | 849 |  |  | $ | 749 |
Current liabilities |  | $ | 129 |  |  | $ | 110 |
Long-term liabilities |  |  | 320 |  |  |  | 304 |
|  |  | 449 |  |  |  | 414 |
Equity |  |  | 400 |  |  |  | 335 |
|  | $ | 849 |  |  | $ | 749 |

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|  | Statements of Earnings

(Millions) |  | 2009 |  |  | 2008 |
Revenue |  | $ | 518 |  |  | $ | 445 |
Operating costs |  |  | 286 |  |  |  | 285 |
Earnings before interest and taxes |  |  | 232 |  |  |  | 160 |
Interest |  |  | 1 |  |  |  | 13 |
Earnings before taxes |  | $ | 231 |  |  | $ | 147 |

|  | Statements of Cash Flows

(Millions) |  | 2009 |  |  | 2008 |
Cash provided by operations |  | $ | 238 |  |  | $ | 173 |
Cash (used in) provided by investing |  |  | (36 | ) |  |  | 4 |
Cash used in financing |  |  | (200 | ) |  |  | (178 | )

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 24,580,129 shares have been issued.
|  | Stock option transactions for the respective years were as follows:

(Number of Options) |  | 2009 |  |  | 2008 |
Beginning of year |  |  | 7,120,555 |  |  |  | 6,422,592 |
Options granted |  |  | 1,381,039 |  |  |  | 1,154,015 |
Options exercised [note 14] |  |  | (453,410 | ) |  |  | (330,852 | )
Options forfeited |  |  | (108,351 | ) |  |  | (125,200 | )
End of year |  |  | 7,939,833 |  |  |  | 7,120,555 |
Exercisable |  |  | 5,550,148 |  |  |  | 4,957,129 |

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|  | Weighted average exercise prices were as follows:

|  | 2009 |  |  | 2008 |
Beginning of year |  | $ | 27.98 |  |  | $ | 25.40 |
Options granted |  |  | 19.41 |  |  |  | 38.82 |
Options exercised |  |  | 9.79 |  |  |  | 11.62 |
Options forfeited |  |  | 35.68 |  |  |  | 38.77 |
End of year |  | $ | 27.42 |  |  | $ | 27.98 |
Exercisable |  | $ | 26.84 |  |  | $ | 22.08 |

|  | Total options outstanding and exercisable at December 31, 2009 were as follows:

2009 |  |  |  |  |  | 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 |  |  | 1,824,320 |  |  |  | 2 |  |  | $ | 8.28 |  |  |  | 1,824,320 |  |  | $ | 8.28 |
13.50 - 32.99 |  |  | 2,892,581 |  |  |  | 6 |  |  |  | 23.42 |  |  |  | 1,533,352 |  |  |  | 26.99 |
33.00 - 55.00 |  |  | 3,222,932 |  |  |  | 6 |  |  |  | 41.84 |  |  |  | 2,192,476 |  |  |  | 42.18 |
|  |  | 7,939,833 |  |  |  |  |  |  |  |  |  |  |  | 5,550,148 |  |  |  |  |

|  | The foregoing options have expiry dates ranging from February 25, 2010 to March 2, 2018.
|  | Non-vested stock option transactions for the respective years were as follows:

(Number of Options) |  | 2009 |  |  | 2008 |
Beginning of year |  |  | 2,163,426 |  |  |  | 2,726,113 |
Options granted |  |  | 1,381,039 |  |  |  | 1,154,015 |
Options forfeited |  |  | (75,039 | ) |  |  | (93,823 | )
Options vested |  |  | (1,079,741 | ) |  |  | (1,622,879 | )
End of year |  |  | 2,389,685 |  |  |  | 2,163,426 |

|  | On July 27, 2007, Cameco’s board of directors approved an amendment to the company’s stock option program introducing a cash settlement feature for the exercise of employee stock options. The cash settlement feature allowed option holders to elect to receive an amount in cash equal to the intrinsic value, being the excess market price of the common share over the exercise price of the option, instead of exercising the option and acquiring common shares. All outstanding stock options were subsequently classified as liabilities and carried at their intrinsic value. The intrinsic value of the liability was marked-to-market each period and amortized to expense over the shorter of the period to eligible retirement or the vesting period.
|  | Effective November 10, 2008, the stock option plan was amended to eliminate the alternative to settle in cash. As a result of the amendment, all outstanding options are classified as equity and the fair value determined using the Black-Scholes option-pricing model. The impact of the reclassification of the stock options at November 10, 2008, was a decrease in liabilities of $25,987,000 with a corresponding increase in contributed surplus.
|  | For the year ended December 31, 2009, Cameco has recorded a net expense of $4,372,000 (2008 recovery — $50,870,000), related to options that vested during the year.

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|  | The fair value of the options granted each year was determined using the Black-Scholes option-pricing model with the following weighted average assumptions:

|  | 2009 |  |  | 2008 |
Number of options granted |  |  | 1,381,039 |  |  |  | 1,154,015 |
Average strike price |  | $ | 19.41 |  |  | $ | 38.82 |
Expected dividend |  | $ | 0.24 |  |  | $ | 0.24 |
Expected volatility |  |  | 36 | % |  |  | 39 | %
Risk-free interest rate |  |  | 1.6 | % |  |  | 2.9 | %
Expected life of option |  |  | 4.0 | years |  |  | 3.5 | years
Expected forfeitures |  |  | 15 | % |  |  | 15 | %
Weighted average grant date fair values |  | $ | 5.23 |  |  | $ | 11.90 |

|  | 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, 2009, the total PSUs held by the participants was 233,710 (2008 — 179,810).
|  | 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 the remaining 40% of their annual retainer and any additional fees in the form of 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, 2009, the total DSUs held by participating directors was 373,921 (2008 — 380,890).
|  | 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, 2009, the number of options held by participating employees was 267,148 (2008 — 277,549) with exercise prices ranging from $5.88 to $46.88 per share (2008 — $4.81 to $46.88) and a weighted average exercise price of $30.61 (2008 — $29.97).
|  | 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, 2009, there were 3,306 participants in the plan (2008 — 3,067). The total number of shares purchased in 2009 on behalf of participants, including the company contribution, was 281,207 shares (2008 — 287,847). In 2009, the company’s contributions totaled $5,166,000 (2008 — $4,513,000).

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|  | Cameco has recognized the following expenses (recoveries) under these plans:

|  | 2009 |  |  | 2008 |
Performance share units |  | $ | 3,347 |  |  | $ | (112 | )
Deferred share units |  |  | 4,930 |  |  |  | (6,252 | )
Phantom stock options |  |  | 1,531 |  |  |  | (2,390 | )
Employee share ownership plan |  |  | 5,166 |  |  |  | 4,513 |

|  | At December 31, 2009, a liability of $18,467,000 (2008 — $10,507,000) was included in the balance sheet to recognize accrued but unpaid expenses for these plans.
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 |
|  | 2009 |  |  | 2008 |  |  | 2009 |  |  | 2008 |
Balance at beginning of year |  | $ | 23,580 |  |  | $ | 28,441 |  |  | $ | 11,842 |  |  | $ | 13,143 |
Current service cost |  |  | 915 |  |  |  | 1,198 |  |  |  | 435 |  |  |  | 504 |
Interest cost |  |  | 1,683 |  |  |  | 1,569 |  |  |  | 730 |  |  |  | 629 |
Actuarial loss (gain) |  |  | 5,647 |  |  |  | (5,410 | ) |  |  | (442 | ) |  |  | (1,785 | )
Plan amendments |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 52 |
Foreign exchange |  |  | (238 | ) |  |  | 100 |  |  |  | — |  |  |  | — |
Benefits paid |  |  | (747 | ) |  |  | (2,318 | ) |  |  | (546 | ) |  |  | (701 | )
|  | $ | 30,840 |  |  | $ | 23,580 |  |  | $ | 12,019 |  |  | $ | 11,842 |

| (b) |  | Plan Assets

|  | Pension Benefit Plans |
|  | 2009 |  |  | 2008 |
Fair value at beginning of year |  | $ | 20,289 |  |  | $ | 23,864 |
Actual return on plan assets |  |  | (708 | ) |  |  | (3,039 | )
Employer contributions |  |  | 5,335 |  |  |  | 59 |
Benefits paid |  |  | (707 | ) |  |  | (595 | )
Fair value at end of year |  | $ | 24,209 |  |  | $ | 20,289 |

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|  | Plan assets consist of:

|  | Pension Benefit Plans |
|  | 2009 |  |  | 2008 |
Asset Category (i) |  |  |  |  |  |  |  |
Equity securities |  |  | 28 | % |  |  | 35 | %
Fixed income |  |  | 23 | % |  |  | 9 | %
Other (ii) |  |  | 49 | % |  |  | 56 | %
Total |  |  | 100 | % |  |  | 100 | %

(i) |  | The defined benefit plan assets contain no material amounts of related party assets at December 31, 2009 and 2008 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 |
|  | 2009 |  |  | 2008 |  |  | 2009 |  |  | 2008 |
Fair value of plan assets |  | $ | 24,209 |  |  | $ | 20,289 |  |  | $ | — |  |  | $ | — |
Accrued benefit obligation |  |  | 30,840 |  |  |  | 23,580 |  |  |  | 12,019 |  |  |  | 11,842 |
Funded status of plans — deficit |  |  | (6,631 | ) |  |  | (3,291 | ) |  |  | (12,019 | ) |  |  | (11,842 | )
Unamortized net actuarial loss |  |  | 14,404 |  |  |  | 8,106 |  |  |  | — |  |  |  | — |
Accrued benefit asset (liability) [notes 9, 13] |  | $ | 7,773 |  |  | $ | 4,815 |  |  | $ | (12,019 | ) |  | $ | (11,842 | )

| (d) |  | Net Pension Expense

|  | 2009 |  |  | 2008 |
Current service cost |  | $ | 915 |  |  | $ | 1,198 |
Interest cost |  |  | 1,683 |  |  |  | 1,569 |
Actual return on plan assets |  |  | 708 |  |  |  | 3,039 |
Actuarial loss (gain) |  |  | 5,647 |  |  |  | (5,410 | )
Balance prior to adjustments to recognize the long-term nature of employee future benefit costs |  |  | 8,953 |  |  |  | 396 |
Difference between actual and expected return on plan assets |  |  | (1,494 | ) |  |  | (3,859 | )
Difference between actuarial loss recognized for year and actual actuarial loss (gain) on accrued benefit obligation for year |  |  | (4,974 | ) |  |  | 6,258 |
Defined benefit pension expense |  |  | 2,485 |  |  |  | 2,795 |
Defined contribution pension expense |  |  | 13,506 |  |  |  | 13,005 |
Net pension expense |  | $ | 15,991 |  |  | $ | 15,800 |

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|  | 2009 |  |  | 2008 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 6.0 | % |  |  | 7.0 | %
Rate of compensation increase |  |  | 4.5 | % |  |  | 4.5 | %
Long-term rate of return on assets |  |  | 5.9 | % |  |  | 6.0 | %

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

|  | 2009 |  |  | 2008 |
Current service cost |  | $ | 435 |  |  | $ | 504 |
Interest cost |  |  | 730 |  |  |  | 629 |
Actuarial gain |  |  | (442 | ) |  |  | (1,785 | )
Plan amendment costs |  |  | — |  |  |  | 52 |
Other post-retirement benefit expense (recovery) |  | $ | 723 |  |  | $ | (600 | )

|  | 2009 |  |  | 2008 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 6.0 | % |  |  | 7.0 | %
Initial health care cost trend rate |  |  | 9.0 | % |  |  | 8.0 | %
Cost trend rate declines to |  |  | 6.0 | % |  |  | 6.0 | %
Year the rate reaches its final level |  |  | 2011 |  |  |  | 2011 |

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

|  | 2009 |  |  | 2008 |
Employer contributions to funded pension plans |  | $ | 5,335 |  |  | $ | 59 |
Benefits paid for unfunded benefit plans |  |  | 585 |  |  |  | 2,425 |
Cash contributions to defined contribution plans |  |  | 13,506 |  |  |  | 13,005 |
Total cash payments for employee future benefits |  | $ | 19,426 |  |  | $ | 15,489 |

|  | Benefits paid by the funded pension plan were $707,000 for 2009 (2008 — $595,000). Cameco’s expected contributions for the year ended December 31, 2010 are approximately $288,820 for the pension benefit plans.
|  | The following are estimated future benefit payments, which reflect expected future service:

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
2010 |  | $ | 809 |  |  | $ | 617 |
2011 |  |  | 1,357 |  |  |  | 710 |
2012 |  |  | 1,370 |  |  |  | 751 |
2013 |  |  | 1,457 |  |  |  | 841 |
2014 |  |  | 1,862 |  |  |  | 844 |
2015 to 2019 |  |  | 12,817 |  |  |  | 4,166 |

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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, 2009. The next planned effective date for valuation for funding purposes of the pension benefit plans is set to be January 1, 2010. The status of Cameco’s proportionate share (31.6%) of the defined plans is as follows:

| (a) |  | Funded Status Reconciliation

|  | Pension Benefit Plans |  |  | Other Benefit Plans |
|  | 2009 |  |  | 2008 |  |  | 2009 |  |  | 2008 |
Fair value of plan assets |  | $ | 635,293 |  |  | $ | 546,755 |  |  | $ | — |  |  | $ | — |
Accrued benefit obligation |  |  | 711,636 |  |  |  | 617,259 |  |  |  | 151,826 |  |  |  | 112,355 |
Funded status of plans — deficit |  |  | (76,343 | ) |  |  | (70,504 | ) |  |  | (151,826 | ) |  |  | (112,355 | )
Unrecognized prior service cost |  |  | — |  |  |  | — |  |  |  | 2,431 |  |  |  | 2,881 |
Unamortized net actuarial loss (gain) |  |  | 112,956 |  |  |  | 76,565 |  |  |  | 23,993 |  |  |  | (7,564 | )
Accrued benefit asset (liability) [notes 9, 13] |  | $ | 36,613 |  |  | $ | 6,061 |  |  | $ | (125,402 | ) |  | $ | (117,038 | )

| (b) |  | Pension Asset Categories

|  | Asset Allocation |  |  | Target Allocation |
|  | 2009 |  |  | 2008 |  |  | 2009 |  |  | 2008 |
Asset Category (i) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities |  |  | 60 | % |  |  | 56 | % |  |  | 60 | % |  |  | 60 | %
Fixed income |  |  | 38 | % |  |  | 42 | % |  |  | 40 | % |  |  | 40 | %
Cash |  |  | 2 | % |  |  | 2 | % |  |  | — |  |  |  | — |
Total |  |  | 100 | % |  |  | 100 | % |  |  | 100 | % |  |  | 100 | %

|  | 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, 2009.

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| (c) |  | Net Pension Expense

|  | 2009 |  |  | 2008 |
Current service cost |  | $ | 16,562 |  |  | $ | 27,599 |
Interest cost |  |  | 41,061 |  |  |  | 43,375 |
Actual return on plan assets |  |  | (65,486 | ) |  |  | 78,229 |
Actuarial loss (gain) |  |  | 65,018 |  |  |  | (238,037 | )
Balance prior to adjustments to recognize the long-term nature of employee future benefit costs |  |  | 57,155 |  |  |  | (88,834 | )
Difference between actual and expected return on plan assets |  |  | 27,286 |  |  |  | (121,493 | )
Difference between actuarial loss recognized and actual actuarial loss (gain) on accrued benefit obligation for year |  |  | (63,677 | ) |  |  | 249,271 |
Net pension expense |  | $ | 20,764 |  |  | $ | 38,944 |

|  | 2009 |  |  | 2008 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 6.0 | % |  |  | 6.8 | %
Rate of compensation increase |  |  | 5.5 | % |  |  | 6.0 | %
Long-term rate of return on assets |  |  | 7.0 | % |  |  | 7.0 | %

| (d) |  | Other Benefit Plans Expense

|  | 2009 |  |  | 2008 |
Current service cost |  | $ | 4,454 |  |  | $ | 7,007 |
Interest cost |  |  | 7,284 |  |  |  | 7,308 |
Actuarial loss (gain) |  |  | 31,127 |  |  |  | (36,228 | )
Balance prior to adjustments to recognize the long-term nature of employee future benefit costs |  |  | 42,865 |  |  |  | (21,913 | )
Difference between amortization of past service costs and actual plan amendments for year |  |  | 450 |  |  |  | 450 |
Difference between actuarial (gain) loss recognized and actual actuarial loss (gain) on accrued benefit obligation for year |  |  | (31,556 | ) |  |  | 37,608 |
Other benefit plans expense |  | $ | 11,759 |  |  | $ | 16,145 |

|  | 2009 |  |  | 2008 |
Significant assumptions at December 31 |  |  |  |  |  |  |  |
Discount rate |  |  | 5.8 | % |  |  | 6.4 | %
Rate of compensation increase |  |  | 3.5 | % |  |  | 3.5 | %
Initial health care cost trend rate |  |  | 10.0 | % |  |  | 9.5 | %
Cost trend rate declines to |  |  | 5.0 | % |  |  | 5.0 | %
Year the rate reaches its final level |  |  | 2019 |  |  |  | 2019 |

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

|  | 2009 |  |  | 2008 |
Employer contributions to funded pension plans |  | $ | 48,980 |  |  | $ | 37,604 |
Benefits paid for unfunded benefit plans |  |  | 4,209 |  |  |  | 3,815 |
Total cash payments for employee future benefits |  | $ | 53,189 |  |  | $ | 41,419 |

|  |  | Benefits paid by the funded pension plan were $32,531,000 for 2009 (2008 — $37,015,000). BPLP’s expected contributions for the year ended December 31, 2010 are approximately $56,771,000 for the pension benefit plans.
|  |  | The following are estimated future benefit payments, which reflect expected future service:

|  | Pension Benefit Plans |  | Other Benefit Plans
2010 |  | $ | 39,924 |  |  | $ | 4,989 |
2011 |  |  | 43,146 |  |  |  | 5,438 |
2012 |  |  | 46,583 |  |  |  | 5,965 |
2013 |  |  | 50,119 |  |  |  | 6,513 |
2014 |  |  | 53,682 |  |  |  | 7,078 |
2015 to 2019 |  |  | 317,914 |  |  |  | 43,343 |

24. |  | Acquisitions

| (a) |  | Acquisition of Interest in GE-Hitachi Global Laser Enrichment LLC (GLE)
|  |  | On June 19, 2008, Cameco, through a wholly owned subsidiary acquired a 24.0% interest in GLE at an initial cost of $123,848,000 (US). In addition, a promissory note in the amount of $73,344,000 (US) was issued in support of future development of the business. The remainder of GLE is owned indirectly by General Electric Company (51%) and Hitachi Ltd. (25%). GLE is in the process of developing uranium enrichment technology. The investment in GLE extends Cameco’s involvement in the front end of the nuclear fuel cycle. The promissory note is payable on demand and bears interest at market rates. The purchase price was financed with cash and debt. The equity method is being used to account for this investment.
|  |  | The purchase price allocation of Cameco’s 24.0% investment was as follows:

Cash |  | $ | 46,415 |
Notes receivable |  |  | 27,488 |
Property, plant & equipment |  |  | 8,289 |
Intangible assets |  |  | 115,485 |
Net liabilities |  |  | (603 | )
Equity interest acquired |  | $ | 197,074 |
Financed by: |  |  |  |
Bank debt |  | $ | 123,774 |
Promissory note |  |  | 73,300 |
|  | $ | 197,074 |

|  |  | The amount allocated to the investment in GLE includes an excess purchase price of approximately $110,517,000 over Cameco’s incremental share of the book value of the underlying net assets of the business. The values assigned to assets will be amortized to income over their estimated lives.

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| (b) |  | Acquisition of Interest in Kintyre Uranium Exploration Project (Kintyre)
|  |  | On August 11, 2008, a venture comprised of a wholly owned Cameco subsidiary (70%) and Mitsubishi Development Pty Ltd. (30%) acquired a 100% interest in the Kintyre uranium exploration project in the East Pilbara region of Western Australia from Rio Tinto for a total cost of $495,000,000 (US). Kintyre is an advanced exploration project located in Western Australia about 1,250 kilometres northeast of Perth.
|  |  | The values assigned to the net assets acquired were as follows:

Property, plant & equipment |  | $ | 501,287 |
Minority interest |  |  | (150,386 | )
Net assets acquired |  | $ | 350,901 |
Financed by: |  |  |  |
Bank debt |  | $ | 350,901 |

| (c) |  | Acquisition of Interest in GoviEx Uranium (GoviEx)
|  |  | On August 22, 2008, Cameco, through a wholly owned subsidiary, acquired a 12% interest in GoviEx at an initial cost of $28,125,000 (US). GoviEx is a closely held exploration company formed in 2006 with uranium exploration properties in Niger, Africa. The equity method was being used to account for this interest until June 2009.
|  |  | Cameco had an option to acquire an additional 10% interest in GoviEx for $31,250,000 (US) following completion of a due diligence review. Cameco elected not to proceed with the additional investment and it was determined in June 2009, that Cameco no longer had the ability to exert significant influence over the operations of GoviEx. The use of the equity method of accounting was discontinued and the investment in GoviEx is now accounted for as an available-for-sale security.

25. |  | 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.
|  |  | 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.

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| (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) |  | 2009 |  |  | 2008 |
Sale of Centerra |  | $ | 374.2 |  |  | $ | — |
Kyrgyz share transfer |  |  | (45.9 | ) |  |  | 19.9 |
Operating earnings |  |  | 54.1 |  |  |  | 64.1 |
Earnings from discontinued operations |  | $ | 382.4 |  |  | $ | 84.0 |

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

(Millions) |  | 2009 |  |  | 2008 |
Revenue |  | $ | 770.2 |  |  | $ | 676.6 |
Expenses |  |  |  |  |  |  |  |
Products and services sold |  |  | 440.4 |  |  |  | 371.3 |
Depreciation, depletion and reclamation |  |  | 122.4 |  |  |  | 85.9 |
Exploration |  |  | 28.5 |  |  |  | 25.0 |
Other |  |  | 37.3 |  |  |  | 33.9 |
Earnings before income taxes and minority interest |  |  | 141.6 |  |  |  | 160.5 |
Income tax expense |  |  | 33.4 |  |  |  | 36.6 |
Minority interest |  |  | 54.1 |  |  |  | 59.8 |
Operating earnings |  | $ | 54.1 |  |  | $ | 64.1 |

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26. |  | 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 July 8, 2009, 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 parties have completed oral discoveries and are currently in the process of completing answers to undertakings given during discoveries. The hearing is scheduled to take place in April and May 2010.
|  |  | 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. This action is in abeyance pending further developments on the Unit 8 steam generator arbitration.
| (b) |  | Annual supplemental rents of $26,000,000 (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 $13,000,000 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.
| (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 2004 to 2018:

| i) |  | Licensing assurances to Canadian Nuclear Safety Commission of up to $133,300,000. At December 31, 2009, Cameco’s actual exposure under these assurances was nil.
| ii) |  | Guarantees to customers under power sales agreements of up to $35,300,000. At December 31, 2009, Cameco’s actual exposure under these guarantees was $28,300,000.
| iii) |  | 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. The agreement remains in effect until the earlier of December 31, 2019 or one year after the shutdown of the BPLP units. During 2009, BPLP became entitled to $526,000,000 under this agreement and currently expects to repay $12,000,000. The remaining $514,000,000 was recognized as revenue with Cameco’s share being $162,000,000.

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| (e) |  | Cameco’s North American workforce includes about 3,000 employees, of which approximately 850 (28%) belong to three separate labour unions. A collective agreement for one of the three unions, representing about 250 employees, is set to expire in 2010.
| (f) |  | At December 31, 2009, Cameco’s purchase commitments, the majority of which are fixed price uranium and conversion purchase arrangements, were as follows:

|  | (Millions (US)) |
2010 |  | $ | 134 |
2011 |  |  | 150 |
2012 |  |  | 169 |
2013 |  |  | 326 |
2014 |  |  | 27 |
Thereafter |  |  | 34 |
Total |  | $ | 840 |

27. |  | 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.
|  | 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 2010 to 2015. At December 31, 2009, the marked-to-market gain on BPLP’s sales contracts was $96,000,000.
|  | 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.

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|  | 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.
|  | 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, 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 |

As at December 31, 2008

Description |  | Total |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |
Derivative instrument assets |  | $ | 81,787 |  |  | $ | — |  |  | $ | 81,787 |  |  | $ | — |
Available-for-sale securities [note 9] |  |  | 3,718 |  |  |  | 3,718 |  |  |  | — |  |  |  | — |
Derivative instrument liabilities |  |  | (120,403 | ) |  |  | — |  |  |  | (120,403 | ) |  |  | — |
Net |  | $ | (34,898 | ) |  | $ | 3,718 |  |  | $ | (38,616 | ) |  | $ | — |

|  | 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 from level 2 to level 3 are noted in the preceding tables. Transfers into level 3 are comprised of BPLP derivative financial instruments with contract terms extending beyond 36 months. Previously, all BPLP derivative financial instruments were classified as level 2, but given the recent decline in electricity prices as a result of the recession, the liquidity in the market was significantly reduced, resulting in a lack of an active market and observable market inputs beyond 36 months.

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

|  | As at December 31, 2008

|  | Cameco |  |  | BPLP |  |  | Total |
Non-hedge derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Embedded derivatives — sales contracts |  | $ | (8,951 | ) |  | $ | 4,344 |  |  | $ | (4,607 | )
Foreign currency contracts |  |  | (105,125 | ) |  |  | — |  |  |  | (105,125 | )
Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |
Energy and sales contracts |  |  | — |  |  |  | 71,116 |  |  |  | 71,116 |
Net |  | $ | (114,076 | ) |  | $ | 75,460 |  |  | $ | (38,616 | )
Classification: |  |  |  |  |  |  |  |  |  |  |  |
Current portion of long-term receivables, investments and other [note 9] |  | $ | 5,793 |  |  | $ | 43,654 |  |  | $ | 49,447 |
Long-term receivables, investments and other [note 9] |  |  | — |  |  |  | 32,340 |  |  |  | 32,340 |
Current portion of other liabilities [note 13] |  |  | (110,918 | ) |  |  | (73 | ) |  |  | (110,991 | )
Other liabilities [note 13] |  |  | (8,951 | ) |  |  | (461 | ) |  |  | (9,412 | )
Net |  | $ | (114,076 | ) |  | $ | 75,460 |  |  | $ | (38,616 | )

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

|  | For the year ended December 31, 2008

|  | Cameco |  |  | BPLP |  |  | Total |
Non-hedge derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Embedded derivatives — sales contracts |  | $ | 18,052 |  |  | $ | 2,841 |  |  | $ | 20,893 |
Foreign currency contracts |  |  | 179,673 |  |  |  | — |  |  |  | 179,673 |
Interest rate contracts |  |  | 906 |  |  |  | — |  |  |  | 906 |
Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |
Energy and sales contracts |  |  | — |  |  |  | (1,031 | ) |  |  | (1,031 | )
Ongoing hedge inefficiency |  |  | 2,210 |  |  |  | — |  |  |  | 2,210 |
Net |  | $ | 200,841 |  |  | $ | 1,810 |  |  | $ | 202,651 |

|  | Over the next 12 months, based on current exchange rates, Cameco expects an estimated $34,260,000 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 $63,876,000 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 five years.
|  | Currency
|  | At December 31, 2009, Cameco had $1,490,000,000 (US) in forward contracts at an average exchange rate of $1.09 and €34,200,000 at an average exchange rate of $1.46. The foreign currency contracts are scheduled for use as follows:

(Millions) |  | US |  |  | Rate |  |  | Cdn |  |  | Euro |  |  | Rate |  |  | US |
2010 |  | $ | 880 |  |  |  | 1.08 |  |  | $ | 950 |  |  | € | 13 |  |  |  | 1.45 |  |  | $ | 19 |
2011 |  |  | 475 |  |  |  | 1.12 |  |  |  | 532 |  |  |  | 16 |  |  |  | 1.47 |  |  |  | 24 |
2012 |  |  | 135 |  |  |  | 1.06 |  |  |  | 143 |  |  |  | 5 |  |  |  | 1.46 |  |  |  | 7 |
Total |  | $ | 1,490 |  |  |  | 1.09 |  |  | $ | 1,625 |  |  | € | 34 |  |  |  | 1.46 |  |  | $ | 50 |

|  | These positions consist entirely of forward sales contracts. The average exchange rate reflects the original spot prices at the time the contracts were entered into and includes forward points. The realized exchange rate will depend on the forward premium (discount) that is earned (paid) as contracts are utilized. Of these amounts, $1,325,000,000 of the US-denominated contracts and $34,000,000 of the Euro-denominated contracts mature in 2010. The remaining $165,000,000 in US-denominated contracts matures in 2011.

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28. |  | 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 2009 was 387,955,503 (2008 — 350,130,431).

|  | 2009 |  |  | 2008 |
Basic earnings per share computation |  |  |  |  |  |  |  |
Net earnings |  | $ | 1,099,422 |  |  | $ | 450,117 |
Weighted average common shares outstanding |  |  | 387,956 |  |  |  | 350,130 |
Basic earnings per common share |  | $ | 2.83 |  |  | $ | 1.29 |
Diluted earnings per share computation |  |  |  |  |  |  |  |
Net earnings |  | $ | 1,099,422 |  |  | $ | 450,117 |
Weighted average common shares outstanding |  |  | 387,956 |  |  |  | 350,130 |
Dilutive effect of stock options |  |  | 1,977 |  |  |  | 1,982 |
Weighted average common shares outstanding, assuming dilution |  |  | 389,933 |  |  |  | 352,112 |
Diluted earnings per common share |  | $ | 2.82 |  |  | $ | 1.28 |

29. |  | 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
|  |  | 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 |  | $ | 5,956.1 |  |  | $ | 383.9 |  |  | $ | 904.4 |  |  | $ | — |  |  | $ | 7,244.4 |
Intangibles |  | $ | — |  |  | $ | 97.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 97.7 |
Capital expenditures for the year |  | $ | 333.3 |  |  | $ | 20.7 |  |  | $ | 38.7 |  |  | $ | — |  |  | $ | 392.7 |

| 2008 |  | (Recast)

|  |  |  |  |  | Fuel |  |  |  |  |  | Inter- |  |
(Millions) |  | Uranium |  | Services |  | Electricity |  | Segment |  | Total
Revenue |  | $ | 1,512.4 |  |  | $ | 251.7 |  |  | $ | 445.3 |  |  | $ | (26.8 | ) |  | $ | 2,182.6 |
Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Products and services sold |  |  | 712.0 |  |  |  | 217.5 |  |  |  | 245.5 |  |  |  | (28.5 | ) |  |  | 1,146.5 |
Depreciation, depletion and reclamation |  |  | 135.9 |  |  |  | 26.6 |  |  |  | 46.0 |  |  |  | (1.0 | ) |  |  | 207.5 |
Exploration |  |  | 53.2 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 53.2 |
Other |  |  | 37.9 |  |  |  | 2.0 |  |  |  | — |  |  |  | — |  |  |  | 39.9 |
Cigar Lake remediation |  |  | 11.4 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 11.4 |
Gain on sale of assets |  |  | (4.1 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (4.1 | )
Non-segmented expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 386.7 |
Earnings before income taxes and minority interest |  |  | 566.1 |  |  |  | 5.6 |  |  |  | 153.8 |  |  |  | 2.7 |  |  |  | 341.5 |
Income tax recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (24.4 | )
Minority interest |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (0.2 | )
Net earnings from continuing operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 366.1 |
Assets |  | $ | 4,595.7 |  |  | $ | 311.3 |  |  | $ | 826.1 |  |  | $ | — |  |  | $ | 5,733.1 |
Intangibles |  | $ | — |  |  | $ | 101.4 |  |  | $ | — |  |  | $ | — |  |  | $ | 101.4 |
Capital expenditures for the year |  | $ | 421.1 |  |  | $ | 77.2 |  |  | $ | 32.8 |  |  | $ | — |  |  | $ | 531.1 |

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| (b) |  | Geographic Segments

(Millions) |  | 2009 |  |  | 2008 |
Revenue from products and services |  |  |  |  |  |  |  |
Canada — domestic |  | $ | 739.2 |  |  | $ | 589.7 |
— export |  |  | 194.9 |  |  |  | 291.3 |
United States |  |  | 1,380.9 |  |  |  | 1,301.6 |
|  | $ | 2,315.0 |  |  | $ | 2,182.6 |
Assets |  |  |  |  |  |  |  |
Canada |  | $ | 5,755.7 |  |  | $ | 4,121.9 |
United States |  |  | 662.9 |  |  |  | 798.2 |
Australia |  |  | 553.1 |  |  |  | 505.1 |
Europe |  |  | 139.0 |  |  |  | 194.9 |
Kazakhstan |  |  | 231.4 |  |  |  | 214.4 |
|  | $ | 7,342.1 |  |  | $ | 5,834.5 |

| (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 2009, revenues from one customer of Cameco’s uranium and fuel services segments represented approximately $252,699,000 (2008 — $106,799,000), about 14% (2008 — 6%) 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 2009, electricity revenues from one customer of BPLP represented approximately 5% (2008 — 4%) of BPLP’s total revenues.

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 2009, Cameco paid Points Athabasca Contracting Ltd. $30,800,000 (2008 — $38,500,000) 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 $230,000 (2008 — $940,000) resulting from these transactions.
31. |  | Comparative Figures
|  | Certain prior year balances have been reclassified to conform to the current financial statement presentation.

131

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INVESTOR INFORMATION
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 Wednesday, May 26, 2010, 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 $0.07 ($0.28 per year) per common share. 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

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Cameco has a plan for growth —
Fuelled from diverse sources.
With 479 million pounds of proven and probable U3O8
reserves, Cameco has the potential to “Double U” by 2018.
cameco.com