EX-99.3 4 o68633exv99w3.htm EX-99.3
EXHIBIT 99.3
Cameco Corporation
2010 Management’s Discussion and Analysis
February 14, 2011

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Management’s discussion and analysis
February 14, 2011

2010 Highlights |  |  | 4 |
About Cameco |  |  | 7 |
About the nuclear energy industry |  |  | 9 |
Our strategy |  |  | 15 |
Financial results |  |  | 28 |
Our operations and development projects |  |  | 53 |
Mineral reserves and resources |  |  | 84 |
Additional information |  |  | 90 |

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

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

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

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

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Examples of forward-looking information in this MD&A

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

Material risks

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

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Material assumptions

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

2010 Management’s discussion and analysis 3

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

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

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

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

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

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

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

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

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

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

2010 Management’s discussion and analysis 5

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

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

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About Cameco
Our head office is in Saskatoon, Saskatchewan. We are one of the world’s largest uranium producers, with uranium assets on three continents. Nuclear energy plants around the world use our uranium products to generate one of the cleanest sources of electricity available today.
Uranium
We are one of the world’s largest uranium producers, and in 2010 accounted for about 16% of the world’s production. We have controlling ownership of the world’s largest high-grade reserves, with ore grades up to 100 times the world average, and low-cost operations.
Product

• |  | uranium concentrates (U3O8)

Mineral reserves and resources
Mineral reserves

• |  | approximately 475 million pounds proven and probable

Mineral resources

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

Global exploration

• |  | focused on four continents

Operating properties

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

Development project

• |  | Cigar Lake, Saskatchewan

Projects under evaluation

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

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

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

Operations

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

We also have a 24% interest in GE-Hitachi Global Laser Enrichment LLC (GLE) in North Carolina, with General Electric (51%) and Hitachi Ltd. (25%). GLE is testing a third-generation technology that, if successful, will use lasers to commercially enrich uranium.
2010 Management’s discussion and analysis 7

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Electricity
We generate clean electricity through our 31.6% interest in the Bruce Power Limited Partnership (BPLP), which operates four nuclear reactors at the Bruce B generating station in southern Ontario.
Capacity

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

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

- |  | uranium concentrates
- |  | conversion services
- |  | fuel fabrication services

Global presence
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About the nuclear energy industry
According to the World Energy Outlook for 2010 (OECD/International Energy Agency), population growth and industrial development will lead to a near doubling of electricity consumption from 2008 to 2035. Most of this energy will be used by developing (non-OECD) countries as their populations and standards of living increase.
Nuclear power is a clean source of electricity, and generation capacity is growing
As the demand for energy increases, governments, media and consumers are becoming increasingly aware of the dangers and effects of air pollution and climate change, and the importance of low-emission sources of electricity. Increasingly, nuclear energy is recognized as a sustainable alternative to carbon-based electricity that provides energy diversity and security.
Nuclear power can generate electricity with no toxic air pollutants and very low carbon dioxide (CO2) or other greenhouse gas emissions. It has the capacity to produce enough electricity on a global scale to meet our growing needs, and while it isn’t the only solution, it is an affordable and sustainable source of clean, reliable energy. In a carbon-constrained world, nuclear energy will be an even more important part of the future energy mix.
2010 Management’s discussion and analysis 9

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At the start of 2011, there were 441 commercial nuclear power reactors operating in 30 countries. Countries around the world are increasing their capacity to generate nuclear power by refurbishing or uprating nuclear reactors and building new ones.
China is expected to lead the world in the construction of nuclear power plants as electricity demand continues its rapid growth. India is also moving forward with ambitious growth plans to diversify its sources of energy and obtain a secure source of electricity. As at January 1, 2011:

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

This year the government of Canada signed a civil nuclear co-operation agreement with India to export nuclear technology, equipment and uranium to support India’s growing nuclear energy industry. Canada is the eighth nation to sign such an agreement with India since the Nuclear Suppliers Group lifted a 34-year ban on nuclear co-operation with India in 2008. Licencing arrangements for these exports still have to be negotiated by the two governments and discussions are ongoing.
Russia and South Korea continue to expand their nuclear generating capacity. Several non-nuclear countries, like United Arab Emirates, Turkey, Vietnam and Italy, are laying the groundwork to proceed with nuclear power development.
In the UK, government commitment to the future of nuclear energy is strong, driven by the need to limit CO2 emissions, and by concerns about energy security as current reactors approach the end of their operating lives.
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The US continues to make progress toward new nuclear development with pre-construction activities for new reactors underway in two states and one reactor under construction in another.
We have long-term supply contracts in 12 of these countries, including China. We are in discussions with India to provide uranium for their growing reactor program.
Demand for uranium is growing
We forecast that world demand will be almost 2.3 billion pounds of U3O8 over the next 10 years. This estimate assumes utilities will build strategic inventories of about 160 million pounds of U3O8 to support their reactor programs.
China’s significant activity in the long-term market this year is a sign of the growing demand for uranium and one of the main drivers behind the recent increase in the uranium price. China has been relatively active in the spot market over the last few years, but in 2010, it advanced its reactor build program and started to secure uranium under long-
2010 Management’s discussion and analysis 11

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term contracts. We signed two long-term contracts with Chinese utilities this year, to supply more than 50 million pounds of uranium.
We expect 66% of global uranium supply over the next 10 years to come from existing primary production sources, production from mines that are currently in commercial operation.
We expect 16% to come from existing secondary supply sources. Most of these sources are finite and will not meet long-term needs. One of the largest current sources of secondary supply is uranium derived from Russian highly enriched uranium (HEU). All deliveries from this source are expected to be made by the end of 2013, when the Russian HEU commercial agreement expires. The US government also makes some of its inventories available to the market, although in much smaller quantities.
We expect the remaining 18% will come from new sources of supply.
In 2010, five producers of uranium concentrates marketed 70% of world production and there were only three commercial providers of UF6 conversion services in the western world. Barriers to entry for new competitors are high, and the lead time for new uranium production can be as long as 10 years or more, depending on the deposit type and location.
Given our extensive base of mineral reserves and resources, diversified sources of supply, global exploration program and vertical integration, we are well positioned to capitalize on the growing interest in nuclear energy.
Despite this growth, challenges remain
Many countries face major obstacles to new nuclear plant construction, including significant upfront capital costs, political opposition and uncertain regulatory environments. In some locations, nuclear energy may not be competitive with other sources of electricity. A country’s first new-generation nuclear plants will face significant business risks, including first-time costs, financing, licensing, schedule and construction costs.
While several countries are making progress on the management of used fuel and other radioactive waste from the nuclear fuel cycle, it is still a controversial issue. Many environmental groups continue to oppose the nuclear power industry. There are nuclear plant phase-out programs in a number of European countries, including Germany. However, Germany recently announced plans to extend the lifespan of its nuclear plants by an average of 12 years. Nuclear power still does not qualify internationally for greenhouse gas emission credits, even though it has been recognized as a non-emitting technology in US energy legislation. The lack of climate change legislation in the US makes nuclear energy less competitive than it is in some other countries.
The long-term outlook is positive
Over the long term, we expect that the benefits of nuclear energy will prevail over the challenges, and market fundamentals for uranium and fuel services will remain positive as:

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

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

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

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

2010 Management’s discussion and analysis 13

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

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

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

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

These are supported by annual objectives, which you’ll find starting on page 25.
2010 Management’s discussion and analysis 15

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Uranium: doubling production by 2018
We have a strategy and process in place to double our annual production to 40 million pounds by 2018, which we expect to come from three sources:

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

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

• |  | The McArthur River extension is expected to expand our existing mining area, which is part of the most prolific high-grade uranium system in the world.

• |  | Under a memorandum of understanding with our Inkai partner, National Atomic Company KazAtomProm Joint Stock Company (Kazatomprom), we are in discussions to increase annual production from blocks 1 and 2, which would result in our share increasing to 5.7 million pounds.

• |  | Inkai block 3, in Kazakhstan, has the potential to become a significant source of production.

• |  | Our acquisition in 2008 of a 70% interest in Kintyre, in Australia, adds potential for low-cost production and diversifies our production by geography and deposit type.

• |  | Millennium is a uranium deposit in northern Saskatchewan that we expect will take advantage of the mill at Key Lake.

Our strategy is to advance these projects through a stage gate process that includes several defined decision points in the assessment and development stages. At each point, we re-evaluate the project based on current competitive, economic, social, legal, political and environmental considerations. If it continues to meet our criteria, we proceed to the next stage. This process allows us to build a pipeline of projects ready for a production decision.
2010 management’s discussion and analysis 17

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

• |  | we cannot locate additional reserves and identify appropriate methods of mining to maintain and increase production levels at McArthur River
• |  | our partner or the Kazakh government does not support an increase in production to the expected level at Inkai, blocks 1 and 2, or we don’t reach the full production level as quickly as we expect
• |  | we cannot bring block 3 into production at Inkai if the feasibility study is not favourable or we cannot secure partner or government approval
• |  | remediation and development at Cigar Lake is not completed on schedule, or we do not reach the full production level as quickly as we expect
• |  | development of Kintyre is delayed due to political, regulatory or indigenous people issues
• |  | we cannot obtain a favourable feasibility study for Kintyre or the Millennium project, or we cannot reach agreement with our project partners to move ahead with production at Kintyre or Millennium

• |  | the Key Lake mill does not have enough capacity to handle anticipated production increases, and we aren’t able to expand its capacity or to identify alternative milling arrangements
• |  | the projects under evaluation do not proceed or, if they do, are not completed on schedule or don’t reach full production levels as quickly as we expect
• |  | uranium prices and development and operating costs make it uneconomical to develop projects under consideration
• |  | we cannot obtain or maintain necessary permits or approvals from government authorities
• |  | disruption in production or development due to natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, lack of tailings capacity, or other development and operation risks

Fuel services: capturing synergies
Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and expand our uranium market share.
We are one of three commercial suppliers of UF6 in the western world. Our focus is on cost-competitiveness and operational efficiency as we gradually increase production at our world-class conversion facility to support the growing demand. We’re also expanding into innovative areas like laser enrichment technology to broaden our fuel cycle participation and help us serve our customers more effectively.
Electricity: capturing added value
Our investment in BPLP is an excellent source of cash flow and a logical fit with our other businesses. Our focus is on maintaining steady cash flow, building synergies with our other segments and looking at the option to extend the operating life of the four Bruce B units.
2010 management’s discussion and analysis 19

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Building on our strengths
World-class assets
We have a large portfolio of low-cost mining operations and geographically diverse uranium assets, and controlling interests in the world’s largest high-grade uranium reserves.
Strong customer relationships
We have large, reliable customers that need uranium regardless of world economic conditions, and we expect the uranium contract portfolio we’ve built to provide a solid revenue stream for years to come.
Uranium price leverage
Our plans to increase our production of uranium, combined with our contracting strategy, are designed to give us increasing leverage when uranium prices go up, and to protect us when prices decline.
Financial strength
We are in a strong financial position to proceed with our growth plans, and the stability of our revenue stream allowed us to announce plans to increase annual dividends again this year, to $0.40 per share starting in 2011.
Disciplined portfolio management
We have a disciplined portfolio management process that incorporates all capital projects into a single capital plan and uses a stage gate decision process (see page 17). This ensures our capital projects are aligned with our strategic objectives, and that business benefits are measurable and attainable.
Focused risk management
We have a formal enterprise-wide risk management process that we apply consistently and systematically across our organization. Risk management is a core element of our strategy and our objectives, and we use it to continuously improve our organization. It will underpin decisions we make as we move ahead with our growth strategy.
Innovation
We are always looking for ways to improve processes, to increase safety and environmental performance, and reduce costs. We are currently working on projects in all aspects of operations, including upgrading the Key Lake and Rabbit Lake mills.
Reputation
We believe strongly in our values and apply them consistently in our operations and business dealings. We are recognized as a reliable supplier and business partner, strong community supporter, international problem solver and employer of choice.
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Managing our growth
Our ability to grow is a function of our people, processes, assets and reputation, and the ability to enhance and leverage these strengths to add value and build competitive advantage.
We use four categories to define what we are committed to deliver, and how we will measure our results:

• |  | outstanding financial performance
• |  | a safe, healthy and rewarding workplace
• |  | a clean environment
• |  | supportive communities

We introduced these measures of success in 2002, to proactively address the financial, social and environmental aspects of our business. We believe that each is integral to the company’s overall success and that, together, they will ensure our long-term sustainability.
Focus on long-term sustainability
Companies are under growing scrutiny for the way they conduct their businesses, and there has been a significant increase in stakeholder expectations for environmentally and socially responsible business practices.
Rather than viewing sustainable development as an ‘add-on’ to traditional business activity, we see it as integral to the way we do business, and have made it a strategic priority, integrating it into our objectives and compensation policies.
You can find out more in our sustainable development report and annual information form, which are on our website (cameco.com).
Outstanding financial performance
Our financial results depend heavily on the prices we realize in our uranium and fuel services segments, on the cost of supply, and on sales and production volumes.
Managing contracts
We sell uranium and fuel services directly to nuclear utilities around the world, as uranium concentrates, UO2, UF6, conversion services or fuel fabrication.
Uranium is not traded in meaningful quantities on a commodity exchange. Utilities buy the majority of their uranium and fuel services products under long-term contracts with suppliers, and meet the rest of their needs on the spot market.
Our extensive portfolio of long-term sales contracts — and the long-term, trusting relationships we have with our customers — are core strengths for us.
Because we sell large volumes of uranium every year, our net earnings and operating cash flows are affected by changes in the uranium price. Our contracting strategy is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that maximizes our realized price. Market prices are influenced by the fundamentals of supply and demand, geopolitical events, disruptions in planned supply and other market factors. Contract terms usually reflect market conditions at the time the contract is accepted, with deliveries beginning several years in the future.
Our current uranium contracting strategy is to sign contracts with terms of 10 years or more that include mechanisms to protect us when market prices decline, and allow us to benefit when market prices go up. Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Fixed-price contracts are typically based on the industry long-term price indicator at the time the contract is accepted, adjusted for inflation to the time of delivery. Market-related contracts may be based on either the spot price or the long-term price as quoted at the time of delivery, and often include floor prices adjusted for inflation and some include ceiling prices also adjusted for inflation.
This is a balanced approach that reduces the volatility of our future earnings and cash flow, and that we believe delivers the best value to shareholders over the long term. It is also consistent with the contracting strategy of our
2010 management’s discussion and analysis 21

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customers. This strategy has allowed us to add increasingly favourable contracts to our portfolio that will enable us to benefit from any increases in market prices in the future.
The majority of our contracts include a supply interruption clause that gives us the right to reduce, on a pro rata basis, defer or cancel deliveries if there is a shortfall in planned production or in deliveries under the Russian HEU commercial agreement.
We are heavily committed under long-term uranium contracts until 2016, so we are becoming increasingly selective when considering new commitments.
The majority of our fuel services contracts are at a fixed price per kgU, adjusted for inflation, and reflect the market at the time the contract is accepted.
Managing our supply
We sell more uranium than we produce every year. We meet our delivery commitments using uranium we obtain:

• |  | from our own production

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

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

We participate in the uranium spot market from time to time, including making spot purchases to take advantage of opportunities to place the material into higher priced contracts. We determine the appropriate extent of our spot market activity based on the current spot price and various factors relating to our business. In addition to being a source of profit, this activity provides insight into the underlying market fundamentals and supports our sales activities.
Managing our costs
Like all mining companies, our uranium segment is affected by the rising price of inputs like labour and fuel. In 2010, labour, production supplies and contracted services made up 85% of the production costs at our uranium mines. Labour (35%) was the largest component. Production supplies (25%) included fuels, reagents and other items. Contracted services (25%) included mining and maintenance contractors, air charters, security and ground freight.
Operating costs in our fuel services segment are mainly fixed. In 2010, labour accounted for about 50% of the total. The largest variable operating cost is for energy (natural gas and electricity), followed by zirconium and anhydrous hydrogen fluoride.
Our costs are also affected by the mix of products we produce and those we buy. We have long-term contracts to buy uranium and conversion services at fixed prices that are lower than the current published spot and long-term prices. As noted above, we also buy on the spot market, which, while profitable, can be at prices that are much higher than our other sources of supply.
To help us operate efficiently and cost-effectively as we grow, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology and business process improvements.
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A safe, healthy and rewarding workplace
We strive to foster a safe, healthy and rewarding workplace at all of our facilities, and measure progress against key indicators, such as conventional and radiation safety statistics, employee sentiment toward the company and employment creation.
To achieve our growth objectives, we need to build an engaged, qualified and diverse organization capable of leading and implementing our strategies. Our challenge is to retain our current workforce and compete for the limited number of people available, both to replace retiring employees and to support our growth. Our long-term people strategy includes identifying critical segments and planning our workforce to meet this challenge.
Our approach seems to be working: we were included in the Financial Post’s Top 10 Best Companies to Work For in Canada for 2010 for our employee policies, programs and role in the community, and Mediacorp named us one of Canada’s Top 100 Employers for both 2010 and 2011. You can find out more about our awards on our website.
A clean environment
We are committed to operating our business with respect and care for the local and global environment. We strive to be a leader in environmental practices and performance by complying with and moving beyond legal and other requirements.
We are committed to integrating environmental leadership into everything we do. In 2005, we launched a formal environmental leadership initiative, and set objectives and performance indicators to measure our progress in protecting the air, water and land near our operations, and in reducing the amount of waste we generate and energy we use.
Reducing our impact
We have been working to reduce the impact we have on the environment. This includes monitoring and reducing our effect on air, water and land, reducing the greenhouse gases we produce and the amount of energy we consume, and managing the effects of waste.
We are investing in management systems and safety initiatives to achieve operational excellence, and this is improving our safety and environmental performance and operating efficiency.
We have developed new water treatment technologies that have improved the quality of the water released from our Saskatchewan uranium milling operations, and are working on other projects to reduce waste, improve the reclamation process and manage waste rock more effectively.
We have also completed an energy assessment at each of our North American operations, and developed management plans for reducing our energy intensity and greenhouse gas emissions.
We are maximizing the lifespan of our operating sites to limit the environmental impact of operations, and revitalizing the Key Lake mill (in operation for 28 years) and Rabbit Lake mill (in operation for 36 years).
Like other large industrial organizations, we use chemicals in our operations that could be hazardous to our health and the environment if they are not handled correctly. We train our employees in the proper use of hazardous substances and in emergency response techniques.
We meet with communities who are affected by our activities to tell them what we’re doing and to receive feedback and further input. For example, in Saskatchewan, we participate in the Athabasca Working Group and Northern Saskatchewan Environmental Quality Committee. In Ontario, we liaise with our communities by regularly holding educational and environment-focused activities.
2010 management’s discussion and analysis 23

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Supportive communities
To maintain public support for our operations (our social licence to operate) and our global reputation, we need the respect and support of communities, indigenous people, governments and regulators affected by our operations.
We build and sustain the trust of local communities by being a leader in corporate social responsibility (CSR). Through our CSR initiatives, we educate, engage, employ and invest in the people in the regions where we operate.
For example, in northern Saskatchewan in 2010:

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

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

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

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

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

Our operations are closely regulated to give the public comfort that we are operating in a safe and environmentally responsible way. Regulators approve the construction, startup, continued operation and any significant changes to our operations. Our operations are also subject to laws and regulations related to safety and the environment, including the management of hazardous wastes and materials.
Our objectives are consistent with those of our regulators — to keep people safe and to protect the environment. We pursue these goals through open and co-operative relationships with all of our regulators. We work to earn their trust and that of other stakeholders by continually striving to protect people and the environment.
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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 |  | Results |  | 2011 objectives
|  |  |  |  |  |  |  | This is forward-looking information. See page 1 for more information.
Outstanding financial performance |  |  |  |  |  |  |  |
Production |  | Exceeded |  | Production
• |  | Produce 21.5 million pounds of U3O8 and between 14 million and 16 million kgU from fuel services. |  | • |  | Our share of U3O8 production was 22.8 million pounds, or 106% of plan. |  | • |  | Produce 21.9 million pounds of U3O8 and between 15 million and 16 million kgU from fuel services.
|  |  | • |  | We produced 15.4 million kgU at fuel services. |  |  |
Financial measures |  |  |  |  |  |  |  |
Corporate performance |  | Exceeded |  | Corporate performance
• |  | Achieve budgeted net earnings and cash flow from operations (before working capital changes). |  | • • |  | Net earnings were higher than budget. Cash flow from operations before working capital changes was higher than budget. |  | • |  | Achieve budgeted net earnings and cash flow from operations (before working capital changes).
Costs |  |  |  |  | Costs
• |  | Strive for unit costs below budget. |  | • |  | Unit costs for uranium production and fuel services were below budget. |  | • |  | Strive for unit costs below budget.
Growth |  |  |  |  |  |  |  |
Cigar Lake |  | Exceeded |  | Cigar Lake
• • |  | Access and secure underground workings and continue with remediation work on schedule. Reinitiate shaft 2 development. Update the technical report. |  | • • • |  | Successfully dewatered and re-entered the mine using innovative technology. Resumed shaft 2 development. Issued technical report. |  | • |  | Advance the project towards mid-2013 startup by completing remediation of all underground workings and advancing shaft 2 sinking.
Inkai |  | Partially achieved |  | Inkai
• • |  | Advance Inkai block 3 delineation and begin a feasibility study. Initiate a feasibility study to increase production at Inkai blocks 1 and 2, and secure necessary regulatory approvals. |  | • • |  | Block 3 delineation was advanced and supported initiation of a 5-year resource appraisal work plan and test leach facility required by the Kazakh authorities. Approval in principle to operate blocks 1 and 2 at 3.9 million pounds per annum (100% basis) was received, but not for design capacity of 5.2 million pounds per annum. |  | • • • |  | Advance block 3 mineral resource delineation and the engineering design of a test leach facility. Advance construction of site infrastructure. Receive approval to increase annual production from blocks 1 and 2 to design capacity of 5.2 million pounds per annum (100% basis). Pursue our longer term objective of receiving approval to double annual production from blocks 1 and 2 by advancing the conversion joint venture project with Kazatomprom.

2010 management’s discussion and analysis 25

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

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

2010 management’s discussion and analysis 27

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

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

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

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

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

• |  | selling our interest in Centerra and recording an after tax gain of $374 million in 2009

• |  | recording an after tax profit of $19 million relating to unrealized mark-to-market gains on financial instruments, compared to a gain of $189 million in 2009

• |  | lower earnings in our electricity business due to a decline in realized prices

• |  | higher exploration expenses, which rose by $47 million mainly due to evaluation activities at Kintyre and Inkai block 3

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

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

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

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

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

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

30 cameco corporation

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

• |  | higher profits from our electricity business, relating to a higher realized selling price

• |  | partially offset by lower profits in our uranium business, which were impacted by higher unit costs

The 6% decrease from 2009 to 2010 resulted from:

• |  | lower profits from our electricity business, relating to a lower realized selling price

• |  | higher exploration expenses

• |  | higher income taxes

• |  | partially offset by improved profits in the uranium business, relating to the lower cost of sales

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

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

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

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

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

2010 Management’s discussion and analysis 31

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

• |  | higher sales volumes in the uranium and fuel services businesses

• |  | increases in realized prices in the uranium and fuel services businesses

• |  | partially offset by lower realized prices for electricity

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

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

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

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

• |  | A higher proportion of taxable income was earned in jurisdictions with higher tax rates.

• |  | In 2009, certain future tax liabilities recognized in prior years were reduced.

• |  | In 2009, the statutory income tax rate in Canada was reduced, allowing us to reduce our provision for future income taxes.

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

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At December 31, 2010:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $0.99 (Cdn), down from $1.00 (US) for $1.05 (Cdn) at December 31, 2009. The exchange rate averaged $1.00 (US) for $1.03 (Cdn) over the year.

• |  | Our effective exchange rate for the year, after allowing for hedging, was about $1.00 (US) for $1.05 (Cdn), compared to $1.00 (US) for $1.18 (Cdn) in 2009.

• |  | We had foreign currency contracts of $1.3 billion (US) and EUR 93 million at December 31, 2010. The US currency contracts had an average exchange rate of $1.00 (US) for $1.03 (Cdn).

• |  | The mark-to-market gain on all foreign exchange contracts was $47 million compared to a $67 million gain at December 31, 2009.

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

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

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

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

Sensitivity analysis
For 2011:

• |  | a change of $5 (US) per pound in each of the Ux spot price ($73.00 (US) per pound on February 7, 2011) and the Ux long-term price indicator ($73.00 (US) per pound on January 31, 2011) would change revenue by $34 million and net earnings by $26 million.

• |  | a change of $5 in the electricity spot price would change our 2011 net earnings by $2 million, based on the assumption that the spot price will remain below the floor price provided for under BPLP’s agreement with the Ontario Power Authority (OPA).

2010 Management’s discussion and analysis 35

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

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

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

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

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

36 cameco corporation

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Liquidity

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

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

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

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

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

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

• |  | growth capital at Cigar Lake

• |  | sustaining capital at Rabbit Lake

Major sustaining expenditures in 2011 include:

• |  | McArthur River/Key Lake — At McArthur River, the largest component is mine development at about $50 million. Other projects include site facility expansion and equipment purchases. At Key Lake, construction of the new acid, steam and oxygen plants continues at an estimated cost of $30 million. Additional work to revitalize the mill will also be undertaken, as well as work on the tailings facilities.

38 cameco corporation

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• |  | US in situ recovery (ISR) — Wellfield construction and well installation is the largest project at approximately $25 million. We also plan to work on the development of the Gas Hills and North Butte projects.

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

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

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

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

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

Long-term contractual obligations

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

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

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

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

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

We have $800 million in senior unsecured debentures:

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

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

2010 Management’s discussion and analysis 39

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We have issued a $73 million (US) promissory note to GLE to support future development of its business. We do not expect any amounts to be drawn on this note until 2012.
Debt covenants
Our revolving credit facilities include the following financial covenants:

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

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

• |  | other customary covenants and events of default

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

• |  | purchase commitments

• |  | financial assurances

Purchase commitments

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

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

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

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

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

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

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

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Financial assurances

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

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

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

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

#####

2010 financial results by segment
Uranium

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

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

• |  | the 13% decline in sales volumes

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

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

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

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

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

42 cameco corporation

#####

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

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

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

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

Deliveries

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

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

Prices

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

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

Inflation

• |  | is 2.0% per year

2010 Management’s discussion and analysis 43

#####

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

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

44 cameco corporation

#####

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

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

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

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

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

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

Our earnings from BPLP

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

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

#####

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

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Fourth quarter results
Fourth quarter consolidated results

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

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

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

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

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

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

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

Quarterly trends

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

Key things to note:

• |  | Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 68% of consolidated revenues in the fourth quarter of 2010.

• |  | The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments.

• |  | Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our results from period to period (see page 29 for more information).

• |  | Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments.

• |  | Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

2010 Management’s discussion and analysis 49

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Fourth quarter results by segment
Uranium

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

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

• |  | the 9% decline in sales volumes

• |  | average unit costs for produced uranium were 26% higher

• |  | average unit costs for purchased uranium were 14% lower due to fewer purchases at spot prices

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

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

50 cameco corporation

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

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

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

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

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

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

Our earnings from BPLP

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

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

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

2010 Management’s discussion and analysis 53

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

• |  | obtain and renew the licences and other approvals we need to operate, to increase production at our mines and to develop new mines. If we do not receive the regulatory approvals we need, or do not receive them at the right time, then we may have to delay, modify or cancel a project, which could increase our costs and delay or prevent us from generating revenue from the project. Regulatory review, including the review of environmental matters, is a long and complex process.

• |  | comply with the conditions in these licences and approvals. In a number of instances, our right to continue operating facilities, increase production at our mines and develop new mines depends on our compliance with these conditions.

• |  | comply with the extensive laws and regulations that govern our activities, including our growth plans. Environmental legislation imposes very strict standards and controls on almost every aspect of our operations and the mines we plan to develop, and are becoming more stringent in Canada and the US. Examples of these controls include that:

|  | • we must complete an environmental assessment before we can begin developing a new mine or make any significant change to a plan that has already been approved

|  | • we increasingly need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an environmental assessment or an extensive review of supporting information. The complexity of this process can be further compounded when regulatory approvals are required from multiple agencies.

We use significant management and financial resources to manage our regulatory risks.
Environmental risks
We have the safety, health and environmental risks associated with any mining and chemical processing company. All three of our business segments face unique risks associated with radiation.
Laws to protect the environment are becoming more stringent for members of the nuclear energy industry and have inter-jurisdictional aspects (both federal and provincial/state regimes are applicable). Once we have permanently stopped mining and processing activities, we are required to decommission the operating site to the satisfaction of the regulator. We have developed conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. As the site approaches or goes into decommissioning, regulators review our detailed decommissioning plan, and this can result in additional regulatory process, requirements, costs and financial assurances.
At the end of 2010, our estimate of total decommissioning and reclamation costs was $465 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $280 million at the end of 2010 (the present value of the $465 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.
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We provide financial assurances for decommissioning and reclamation as letters of credit to regulatory authorities, as required. We had a total of $549 million in letters of credit supporting our reclamation liabilities at the end of 2010. Since 2001, all of our North American operations have had letters of credit in place that provide financial assurance in line with our preliminary plans for decommissioning for the sites.
Some of the sites we own or operate have been under ongoing investigation and/or remediation and planning as a result of historic soil and groundwater conditions. For example, we are addressing issues related to historic soil and groundwater contamination at Port Hope and Rabbit Lake.
We use significant management and financial resources to manage our environmental risks.
We manage environmental risks through our safety, health, environment and quality (SHEQ) management system. Our SHEQ management system is centralized and managed at the corporate level, and we implement it corporately and at our operations level. Our chief executive officer is responsible for ensuring that our SHEQ management system is implemented. Our board’s safety, health and environment committee also oversees how we manage our environmental risks.
In 2010, we invested:

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

• |  | $34 million in health and safety programs, unchanged compared to 2009.

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

• |  | environmental damage

• |  | industrial and transportation accidents

• |  | labour shortages, disputes or strikes

• |  | cost increases for contracted or purchased materials, supplies and services

• |  | shortages of required materials and supplies

• |  | transportation disruptions

• |  | electrical power interruptions

• |  | equipment failures

• |  | non-compliance with laws and licences

• |  | catastrophic accidents

• |  | fires

• |  | blockades or other acts of social or political activism

• |  | natural phenomena, such as inclement weather conditions, floods and earthquakes

• |  | unusual, unexpected or adverse mining or geological conditions

• |  | underground floods

• |  | ground movement or cave ins

• |  | tailings pipeline or dam failures

• |  | technological failure of mining methods

We have insurance to cover some of these risks and hazards, but not all of them, and not to the full amount of losses or liabilities that could potentially arise.
2010 Management’s discussion and analysis 55

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

• |  | We increased production by 5% over 2009.

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

At Rabbit Lake:

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

At Inkai:

• |  | We continued to ramp up production and exceeded our 2009 production by 136%.

• |  | Production was 13% higher than our plan at the beginning of the year due to the completion of the processing facilities and a stable acid supply.

Uranium production

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

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

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

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

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

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

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

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

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

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.

Assumptions

• |  | we achieve our forecast production for each operation, which requires, among other things, that our mining plans succeed, processing plants are available and function as designed, we have sufficient tailings capacity and our reserve estimates are accurate

• |  | we obtain or maintain the necessary permits and approvals from government authorities

• |  | our production is not disrupted or reduced as a result of natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks

Material risks that could cause actual results to differ materially

• |  | we do not achieve forecast production levels for each operation because of a change in our mining plans, processing plants are not available or do not function as designed, lack of tailings capacity or for other reasons

• |  | we cannot obtain or maintain necessary permits or government approvals

• |  | natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks disrupt or reduce our production

2010 Management’s discussion and analysis 57

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

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

1 For more information on the average grade, please see the 2010 update that follows in this section — Change in Average Reserve Grades
58 cameco corporation

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

• |  | drilling a series of overlapping holes through the ore zone from a raisebore chamber in waste rock above the ore

• |  | collecting the broken ore at the bottom of the raises using line-of-sight remote-controlled scoop trams, and transporting it to a grinding circuit

• |  | filling each raisebore hole with concrete once it is complete

• |  | removing the equipment and filling the entire chamber with concrete when all the rows of raises in a chamber are complete

• |  | starting the process again with the next raisebore chamber

We have successfully used the raisebore mining method to extract about 190 million pounds (100% basis) since we began mining in 1999.
McArthur River currently has four zones with delineated mineral reserves (zones 1 to 4). Zones A and B are categorized as inferred mineral resources. Parts of zones 1, 2, 3 and 4 also have mineral resources.
Until this year, we have mined only zone 2 since the mine started production. Zone 2 is divided into four panels (panels 1, 2, 3 and 5). Until late 2009, all mine production was from panels 1, 2 and 3, and there are still limited
2010 Management’s discussion and analysis 59

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

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

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

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

• |  | building the acid, steam and oxygen processing plants

• |  | securing our existing tailings capacity

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

• |  | allow continued processing of ore from the McArthur River mine and other potential mine developments

• |  | increase long-term capacity of the Deilmann tailings management facility by allowing us to deposit tailings to a higher elevation

• |  | increase annual mill production capacity to 25 million pounds U3O8

Licensing
The CNSC approved an amendment to our operating licence for McArthur River, giving us flexibility in the annual licensed production limit, similar to that received at Key Lake last year. The McArthur River mine can produce up to 20.7 million pounds U3O8 (100% basis) per year as long as average annual production does not exceed 18.7 million pounds. If production is lower than 18.7 million pounds in any year, we can produce more in future years until we recover the shortfall. After taking advantage of this provision in 2009 and this year, we still have the opportunity to recover about 4 million pounds (100% basis) in past production shortfalls.
After the mill is revitalized, annual production will depend mainly on mine production. We are continuing to plan for annual production of 18.7 million pounds (100% basis) for the next few years.
Exploration
We initiated a multi-year project, the McArthur River extension, to advance the underground exploration drifts to the north and to the south of the current mining operations. We expect this work to further delineate zones A and B inferred mineral resources to the north, and mineral resources to the south.
We received regulatory approval to continue developing the north exploration drift towards zone A and zone B. Over the next two years, we will carry out underground exploration from this drift to expand our knowledge of the size and grade of the ore in this area.
The surface lease has been reinstated to its original size, which will allow us to optimize the location for future mine workings for ongoing approved activities. We expect a fourth shaft will be necessary for ventilation of ongoing operations and for the eventual development of zones to the north of current mining areas.
Labour relations
We reached a new four-year collective agreement with unionized employees at McArthur River and Key Lake. The agreement expires on December 31, 2013.
Planning for the future
Production
We expect our share of production to be 13.1 million pounds U3O8 in 2011 and will look for opportunities to take advantage of the production flexibility provision in our licences.
New mining zones
Zone 2, panel 5 — In 2011, we expect to develop a third raisebore chamber.
Zone 4 — In 2011, we will begin work to install the freezewall required to bring the upper mining area of zone 4 into production.
Our initial plan was to mine upper zone 4 using boxhole boring. We now expect, however, to use raisebore mining in this area by applying the ground freezing experience we gained in zone 2, panel 5. By using raisebore mining, we expect to significantly improve production efficiencies compared to boxhole boring.
2010 Management’s discussion and analysis 61

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Tailings capacity
In 2011, we expect to:

• |  | complete the detailed design for the stabilization of the Deilmann tailings management facility pitwalls

• |  | start to relocate the infrastructure necessary to allow us to flatten the slope of the pitwalls

• |  | advance work on the environmental assessment for the Key Lake extension project

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

• |  | Ground freezing — Before mining, we drill freezeholes and freeze the ground to form an impermeable freezewall around the area being mined. Ground freezing reduces but does not eliminate the risk of water inflows.

• |  | Mine development — We carry out extensive grouting and careful placement of mine development away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk, and apply extensive additional technical and operating controls for all higher risk development.

• |  | Pumping capacity and treatment limits — Our standard for this project is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before beginning work on any new zone.

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

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

2010 update
Production
Production this year was the same as in 2009.
Continued to upgrade the mill
We completed the first phase of upgrades at the acid plant, replacing the convertor and heat recovery equipment.
Worked to extend the mine life
We added mineral reserves, extending the estimated mine life by two years to 2017. We have completed surface exploration drilling near the mine and have found new mineralization referred to as the Powell zone. In 2012, we are planning to start an underground drilling program to further evaluate this mineralization.
We installed and commissioned a new exhaust air raise at the Eagle Point mine to support future activities in the northern part of the mine.
2010 Management’s discussion and analysis 63

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Planning for the future
Production
We expect to produce 3.6 million pounds in 2011.
Milling
We expect to have sufficient tailings capacity to support milling of Eagle Point ore and a portion of the uranium solution from milling of Cigar Lake ore until mid-2016. We are planning to expand the existing tailings management facility to increase the tailings capacity by mid-2016 to support the extension of Rabbit Lake’s mine life, accommodate tailings from processing Cigar Lake uranium solution and provide a modest amount of additional tailings capacity for future processing opportunities. We need regulatory approval to proceed with any increase in capacity.
Exploration
We have extended our underground drilling reserve replacement program into 2011. We plan to test and evaluate areas east and northeast of the mine where we have had good results. Drilling will also continue on other parts of the property.
Reclamation
As part of our multi-year site-wide reclamation plan, we expect to spend $5.7 million in 2011 to reclaim facilities that are no longer in use.
Managing our risks
We manage the risks listed on pages 54 and 55.
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Uranium — operating properties
Smith Ranch-Highland
We operate Smith Ranch and Highland as a combined operation. Each has its own processing facility, but the Smith Ranch mill processes all the uranium. The Highland mill is currently idle.
Together, they form the largest uranium production facility in the United States.

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

2010 update
Production
We met our production target for the year.
Upgrades
We finished building five deep disposal wells, and received authorization to operate four of the five wells. We expect to receive authorization to operate the fifth well in 2011. These are expected to help us operate and restore groundwater more efficiently.
Licensing
We submitted the licence renewal application to the regulators. We expect production to continue throughout the licence renewal process.
2010 Management’s discussion and analysis 65

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Planning for the future
Production
We expect to produce 1.8 million pounds in 2011.
Reynolds Ranch expansion
We are seeking regulatory approval to proceed with our Reynolds Ranch expansion. The regulators have indicated they have a large volume of permits to process, therefore approval of our expansion is not expected to occur until late in 2011. We do not expect this delay to impact production.
Reserves and resources for Reynolds Ranch and Northwest Unit have been included in the totals for Smith Ranch-Highland reserves and resources. Both properties are adjacent to Smith Ranch-Highland.
Exploration
Additional exploration is underway with the objective of extending the mine life.
Managing our risks
The operating environment is becoming more complex as public interest and regulatory oversight increase. This may have a negative impact on our plans to increase production. We also manage the risks listed on pages 54 and 55.
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Uranium — operating properties
Crow Butte
Crow Butte was discovered in 1980 and began production in 1991. It is the first uranium mine in Nebraska, and is a significant contributor to the economy of northwest Nebraska.

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

2010 update
Production
Production was in line with our forecast.
Licensing
The regulators continued their review of our applications to expand and re-license Crow Butte. They are planning public hearings in 2011 to consider our application. We expect production to continue throughout this licence renewal process.
2010 Management’s discussion and analysis 67

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Planning for the future
Production
In 2011, we expect to produce 0.7 million pounds.
Managing our risks
The operating environment is becoming more complex as public interest and regulatory oversight increase. This may have a negative impact on our plans to increase production. We also manage the risks listed on pages 54 and 55.
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Uranium — operating properties
Inkai
Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is Joint Venture Inkai Limited Liability Partnership, which we jointly own (60%) with Kazatomprom (40%).
Inkai is one of our three material uranium properties.

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

2010 update
Production
Our share of production this year was significantly higher due to successful wellfield performance and the processing of uranium in inventory at the end of 2009. Production was 13% higher than our plan at the beginning of the year due to the completion of the processing facilities and a stable acid supply.
Operations
Inkai received state commissioning approval for the main processing plant, allowing full processing of uranium concentrate on site. The plant operated at production rates very close to design capacity for several months due to strong wellfield performance.
2010 Management’s discussion and analysis 69

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Project funding
We have a loan agreement with Inkai. As of December 31, 2010, there was:

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

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

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

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

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

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

• |  | continue delineation drilling

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

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

• |  | targets future annual production capacity at 10.4 million pounds (our share 5.7 million pounds). While the existing project ownership would not change, our share of the additional capacity under the memorandum would be 50%.

• |  | contemplates studying the feasibility of constructing a uranium conversion facility as well as other potential collaborations in uranium conversion

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

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

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

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

We expect Inkai to receive all of the necessary permits and approvals to meet its 2011 and future annual production targets and we anticipate it will be able to ramp up production as noted above.
There is no certainty, however, Inkai will receive these permits or approvals or that it will be able to ramp up production this year. If Inkai does not, or if the permits and approvals are delayed, then Inkai may be unable to achieve its 2011 and future annual production targets and we may have to recategorize some of Inkai’s mineral reserves as resources.
Taxes
A new tax code became law in Kazakhstan on January 1, 2009, and the resource use contract was amended to adopt it. We do not expect the new tax code to have a material impact at this time, but the elimination of tax stabilization under the new tax code could be material in the future. Under the new tax code, Inkai’s corporate income tax rate is 20% and the rate used to calculate the mineral extraction tax on uranium is 22%. See our annual information form for an overview of the changes brought about by the new tax code.
Supply of sulphuric acid
The supply of sulphuric acid has not been an issue for Inkai this year. However, given the importance of sulphuric acid to Inkai’s mining operations, we continue to closely monitor its availability. Our production may be less than forecast if there is a shortage.
Political risk
Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our Inkai investment, and our plans to increase production, are subject to the risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal, and fiscal instability. Kazakh laws and regulations are still developing and their application can be difficult to predict. To maintain and increase Inkai production, we need ongoing support, agreement and co-operation from our partner and the government.
The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Subsoil Use Law dated June 24, 2010. It replaces the Law on the Subsoil and Subsoil Use, dated January 27, 1996.
In general, Inkai’s licences are governed by the version of the subsoil law that was in effect when the licences were issued in April 1999, and new legislation applies to Inkai only if it does not worsen Inkai’s position. Changes to legislation related to national security, among other criteria, however, are exempt from the stabilization clause in the resource use contract. The Kazakh government interprets the national security exemption broadly.
With the new subsoil law, the government continues to weaken its stabilization guarantee. The government is broadly applying the national security exception to encompass security over strategic national resources.
The resource use contract contains significantly broader stabilization provisions than the new subsoil law, and these contract provisions currently apply to us.
To date, the new subsoil law has not had a significant impact on Inkai. We continue to assess the impact. See our annual information form for an overview of this change in law.
We also manage the risks listed on pages 54 and 55.
2010 Management’s discussion and analysis 71

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Uranium — development project
Cigar Lake
Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner, and the mine operator, and expect the operation to use available capacity at our Rabbit Lake mill.
Cigar Lake, which is being developed, is one of our three material uranium properties.

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

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

• |  | Bulk freezing — The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We will freeze the ore zone and surrounding rock in the area to be mined, to prevent water from entering the mine and to help stabilize weak rock formations.

|  | In the past, bulk freezing has been done from underground. In 2010, however, we tested and began to implement an innovative surface freeze strategy, which we expect will provide the following benefits:

• |  | reduce risk to the production schedule by advancing the availability of frozen ground and simplifying construction activities underground by moving some of the freezing infrastructure to surface

• |  | move up to 10 million pounds forward in the production schedule

• |  | improve mining costs and economics of the project

|  | We expect the capital cost for surface freezing will be $80 to $85 million (100% basis). Our plan is to use a hybrid freezing approach. We will use surface freezing to shorten the rampup period and utilize underground freezing for the longer term development of the mine.

• |  | Jet boring — After many years of test mining, we selected jet boring, a non-entry mining method, which we have developed and adapted specifically for this deposit. This method is new to the uranium mining industry. Overall, our initial test program was a success and met all initial objectives. This method, however, has not been proven at full production. As we ramp up production, there may be some technical challenges, which could affect our production plans.

We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.
2010 Management’s discussion and analysis 73

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Milling
For approximately two years after mining begins, we expect all Cigar Lake ore to be processed at Areva’s McClean Lake JEB mill. After production ramps up to planned full capacity, the JEB mill is expected to ship a portion of the uranium solution from milling of Cigar Lake ore to the Rabbit Lake mill for processing.
2010 update
During the year, we:

• |  | completed dewatering the underground development

• |  | substantially completed cleanup, inspection, assessment and securing of the underground development areas

• |  | we prepared the ground around shaft 2 for freezing in preparation to resume shaft sinking

• |  | began implementing a surface freeze strategy we expect will shorten the rampup period for the project by bringing forward uranium production into the early years and improve mining costs and project economics

• |  | increased installed pumping capacity

• |  | completed backfilling of the 420 and 465 metre levels

• |  | resumed underground development in the south end of the mine

• |  | completed the 2010 surface drilling program

Costs
As of December 31, 2010, we had:

• |  | invested $492 million for our share of the construction costs to develop Cigar Lake

• |  | invested $262 million related to test mining and infrastructure development (prior to our 2005 development decision)

• |  | expensed $81 million in remediation expenses, including about $17 million in 2010

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

• |  | finish restoring all remaining underground mine systems, infrastructure and underground development areas

• |  | complete the work to secure the mine

• |  | resume underground construction

• |  | complete the sinking of shaft 2

• |  | complete the surface ore loadout facilities

• |  | procure additional equipment for the jet boring system

• |  | work to obtain regulatory approval of the environmental assessment that will allow the release of treated water directly to Seru Bay of Waterbury Lake

• |  | work to obtain regulatory approval for the Cigar Lake mine plan

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

• |  | natural phenomena, an equipment failure or other causes do not result in a material delay or disruption in our plans

• |  | there are no additional water inflows

• |  | the seals or plugs used for previous water inflows do not fail

• |  | there are no labour disputes or shortages

• |  | we obtain contractors, equipment, operating parts, supplies, and regulatory permits and approvals when we need them

• |  | our mine plans are achieved, our processing plants are available and function as designed, sufficient tailings capacity is available and our mineral reserve estimates are accurate

Material risks

• |  | an unexpected geological, hydrological or underground condition, such as an additional water inflow, further delays our progress

• |  | we cannot obtain or maintain the necessary regulatory permits or approvals

• |  | natural phenomena, labour disputes, equipment failure, delay in obtaining the required contractors, equipment, operating parts or supplies, or other reasons cause a material delay or disruption in our plans

• |  | our mining plans change or do not succeed, our processing plants are not available or do not function as designed, sufficient tailings capacity is not available and our mineral reserve estimates are not accurate

Managing our risks
Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, water inflow, mining method uncertainty, regulatory approvals, tailings capacity, surface and underground fires and other mining-related challenges. To reduce this risk, we are applying our operational experience and the lessons we have learned about water inflows at McArthur River and Cigar Lake.
The greatest risk to development and production is from water inflows. The 2006 and 2008 water inflows were significant setbacks.
The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant delay in Cigar Lake’s remediation, development or production, a material increase in costs and a loss of mineral reserves. Although we are taking the following steps to mitigate the risks of water inflow, there can be no guarantee that these will be successful:
Bulk freezing
Two of the primary challenges in mining the deposit are control of groundwater and ground support. Bulk freezing reduces but does not eliminate the risk of water inflows.
Mine development
Our approach is to carry out extensive grouting and careful placement of mine development away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk, and apply extensive additional technical and operating controls for all higher risk development.
2010 Management’s discussion and analysis 75

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Pumping capacity and treatment limits
We increased our pumping capacity this year to meet our standard for this project, which is to secure pumping capacity of at least one and a half times the estimated maximum inflow.
We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum inflow.
We also manage the risks listed on pages 54 and 55.
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Uranium — projects under evaluation
Kintyre
Kintyre, which we acquired with a partner in 2008, adds potential for low-cost production and diversifies our geographic reach and deposit types. We are the operator.

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

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

• |  | began the process for negotiating a mine development agreement with the Martu, the native land title holders for this property
• |  | built a construction camp to support the prefeasibility assessment of the project
• |  | completed a delineation drilling program
• |  | carried out metallurgical testing to define the milling process
• |  | initiated mining and infrastructure studies for the prefeasibility study
• |  | initiated a hydrogeological drilling program to confirm process water supply
• |  | carried out environmental baseline studies
• |  | submitted the environmental referral document to initiate the environmental assessment process and submitted the environmental scoping document
• |  | trained and hired a significant number of Martu people

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

• |  | generate a National Instrument 43-101 mineral resource estimate
• |  | complete a memorandum of understanding for a mine development agreement with the Martu
• |  | carry out further exploration drilling to test potential extensions of the deposit
• |  | submit an environmental review and management program
• |  | complete the prefeasibility study and decide whether to proceed to the feasibility stage

Managing the risks
To successfully develop this project, we need a positive feasibility study, regulatory approval and an agreement with the Martu. We also manage the risks listed on pages 54 and 55.
2010 Management’s discussion and analysis 77

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

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

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

• |  | completed our mine design with positive results achieved
• |  | continued work on the environmental assessment, preparing us to submit the environmental impact statement late in 2011 or early 2012

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

• |  | complete the environmental assessment work and submit the environmental impact study to the regulators late in 2011 or early 2012
• |  | undertake additional studies and design work required to advance the project

Managing the risks
The English River First Nation (ERFN) has selected surface lands covering the Millennium deposit in a claim for Treaty Land Entitlement (TLE). The Saskatchewan government has rejected the selection, but the ERFN has challenged the government’s decision in the courts. The TLE process does not affect our mineral rights, but it could have an impact on the surface rights and benefits we ultimately negotiate as part of the development of this deposit.
We also manage the risks listed on pages 54 and 55.
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Uranium — exploration
Exploration is key to ensuring our long-term growth, and since 2002 we have more than tripled our annual investment.
2010 update
Brownfield exploration
Brownfield exploration is uranium exploration near our existing operations, and includes expenses for advanced exploration projects where uranium mineralization is being defined.
We spent $11 million in five brownfield exploration projects, and $48 million for resource delineation at Kintyre and Inkai block 3.
Regional exploration
We spent about $37 million in regional exploration programs (including support costs). Saskatchewan was the largest region, followed by Australia, northern Canada, Asia, and South America.
We own a 30% interest in the Phoenix deposit, part of the Wheeler River joint venture in Saskatchewan, operated by 60% owner Denison Mines. In 2010, an initial estimate of 36 million pounds indicated mineral resources (100%) for zone A, the largest of four known mineralized zones of the deposit, was announced.
Plans for 2011
We plan to spend approximately $90 million on uranium exploration in 2011 as part of our long-term strategy. This includes activities at our projects under evaluation.
Brownfield exploration
About $9 million will be spent on five brownfield exploration projects in the Athabasca Basin and Australia. Our expenditures on projects under evaluation are expected to total $22 million, with the largest amounts spent on Kintyre and on further delineation of the Inkai block 3 resource.
Regional exploration
We expect to spend about $60 million on 54 projects worldwide, the majority of which are at drill target stage. Among the larger expenditures planned are $8 million on two adjacent projects in Nunavut, $5 million directed towards new targets in South Australia and Argentina, and a $4 million expenditure on the Wellington Range project in Northern Territory, Australia.
2010 Management’s discussion and analysis 79

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

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

2010 update
Production
Our Blind River refinery produced 12.4 million kgU of UO3, in line with our forecast. This ensured that SFL maintained its contractual inventories and Port Hope met its production requirements.
Managing our risks
We manage the risks listed on pages 54 and 55.
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Fuel services — conversion and fuel manufacturing
We control about 35% of western world UF6 capacity.
Port Hope conversion services
Port Hope is the only uranium conversion facility in Canada, and one of only four in the western world. It is the only commercial supplier of UO2 for Canadian-made Candu reactors.

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

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

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

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

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

2010 Management’s discussion and analysis 81

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

• |  | holding a series of community forums
• |  | making presentations to municipal council
• |  | reaching out using community newsletters, newspaper advertising, public displays, open houses and a website dedicated to the Port Hope community

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

• |  | continue with the environmental assessment process for this project
• |  | finalize the environmental impact statement

Managing our risks
We manage the risks listed on pages 54 and 55.
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Electricity
Bruce Power Limited Partnership (BPLP)
BPLP leases and operates four Candu nuclear reactors that have the capacity to provide about 15% of Ontario’s electricity.

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

Background
We are the fuel procurement manager for BPLP’s four nuclear reactors and for Bruce A Limited Partnership’s (BALP) two operating reactors.
We provide 100% of BPLP’s uranium concentrates and have agreed to supply BALP with the majority of its future uranium concentrates. Sales to BPLP and BALP are also a substantial portion of our fuel manufacturing business and an important part of our UO2 business.
2010 update
Output
BPLP’s capacity factor was 91%.
Collective agreements
The collective agreements with the Power Workers’ Union and the Society of Energy Professionals expired in December. BPLP has reached a tentative agreement with the Power Workers’ Union and discussions with the Society are underway.
Planning for the future
Output
We expect the capacity factor to be 89% in 2011 and actual output to be about 2% lower than 2010.
Managing our risks
BPLP manages the unique risks associated with operating Candu reactors. The amount of electricity generated, and the cost of that generation, could vary materially from forecast if planned outages are significantly longer than planned, or there are many unplanned outages, either for maintenance, regulatory requirements, equipment malfunction or due to other causes.
BPLP also manages the risks listed on pages 54 and 55.
2010 Management’s discussion and analysis 83

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

• |  | Measured and indicated mineral resources are sufficiently well defined that we can estimate them with enough confidence to apply technical and economic parameters and evaluate the economic viability of the deposit.
• |  | measured resources: we can confirm geological and grade continuity to carry out production planning.
• |  | indicated resources: we can reasonably assume geological and grade continuity to carry out mine planning.
• |  | Inferred mineral resources are estimated using limited information. We do not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource as a result of continued exploration.

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

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

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

• |  | mining and milling activities, which used 24 million pounds
• |  | conversion of mineral resources to reserves from drilling and mine design updates at McArthur River, Rabbit Lake and Smith Ranch-Highland
• |  | conversion of mineral reserves to resources at Inkai due to the production ramp up schedule and increased leaching recovery applied to a limited annual production rate

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

• |  | addition of mineral resources at the new Phoenix deposit
• |  | conversion of mineral resources to reserves at McArthur River and Rabbit Lake

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• |  | conversion of mineral reserves to resources at Inkai

At the end of 2010, our share of inferred mineral resources was nearly 357 million pounds U3O8 — a net gain of 3 million pounds, which came mostly from the new Powell zone at Rabbit Lake and drilling and new mining plans at McArthur River zone 4 south.
Qualified persons
The technical and scientific information discussed in this MD&A, including mineral reserve and resource estimates, for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) were prepared by, or under the supervision of, individuals who are qualified persons for the purposes of NI 43-101:

McArthur River/Key Lake |
• |  | Alain G. Mainville, director, mineral resources management, Cameco |
• |  | David Bronkhorst, vice-president, Saskatchewan mining south, Cameco |
• |  | Greg Murdock, technical superintendent, McArthur River, Cameco |
• |  | Les Yesnik, general manager, Key Lake, Cameco |
• |  | Lorne D. Schwartz, chief metallurgist, major projects —technical services, Cameco |
Cigar Lake |
• |  | Alain G. Mainville, director, mineral resources management, Cameco |
• |  | C. Scott Bishop, principal mine engineer, major projects — technical services,Cameco |
• |  | Grant J.H. Goddard, vice-president, Saskatchewan mining north, Cameco |
• |  | Lorne D. Schwartz, chief metallurgist, major projects — technical services, Cameco |
Inkai |
• |  | Alain G. Mainville, director, mineral resources management, Cameco |
• |  | Charles J. Foldenauer, operations director, JV Inkai |

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

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

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

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

2010 Management’s discussion and analysis 85

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• |  | any or all of an inferred mineral resource exists or is economically or legally mineable, or will ever be upgraded to a higher category. Under Canadian securities regulations, estimates of inferred resources may not form the basis of feasibility or prefeasibility studies. Inferred resources have a great amount of uncertainty as to their existence and economic and legal feasibility.

The requirements of Canadian securities regulators for identification of ‘reserves’ are also not the same as those of the SEC, and mineral reserves reported by us in accordance with Canadian requirements may not qualify as reserves under SEC standards.
Other information concerning descriptions of mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for US domestic mining companies, including Industry Guide 7.
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Mineral reserves
As at December 31, 2010 (100% basis — only the second last column shows Cameco’s share)
Proven and probable (tonnes in thousands; pounds in millions)

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

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

• |  | use an average uranium price of $56.50 (US)/lb U3O8
• |  | are based on the average exchange rate at December 31, 2010 ($1.00 US=$0.99 Cdn)

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

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

2010 Management’s discussion and analysis 87

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We expect Inkai to receive all of the necessary permits and approvals to meet its 2011 and future annual production targets and we anticipate it will be able to ramp up production as noted above.
There is no certainty, however, Inkai will receive these permits or approvals or that it will be able to ramp up production this year. If Inkai does not, or if the permits and approvals are delayed, then Inkai may be unable to achieve its 2011 and future annual production targets and we may have to re-categorize some of Inkai’s mineral reserves as resources.
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Mineral resources
As at December 31, 2010 (100% — only the last column shows Cameco’s share)
Measured and indicated (tonnes in thousands; pounds in millions)

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

Inferred (tonnes in thousands; pounds in millions)

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

Notes
ISR — in situ recovery
Mineral resources do not include amounts that have been identified as mineral reserves.
Mineral resources do not have demonstrated economic viability. Totals may not add up due to rounding.

2010 Management’s discussion and analysis 89

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Additional information
Related party transactions
We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In 2010, we paid PACL $38 million for construction and contracting services (2009 — $30 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.
Critical accounting estimates
Because of the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report.
We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable. We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements.
Decommissioning and reclamation
We are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position.
Property, plant and equipment
We depreciate property, plant and equipment primarily using the unit of production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.
We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.
Taxes
When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation allowances, changes in tax laws and our expectations for future results.
We base our estimates of future income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record future income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.

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Controls and procedures
We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2010, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.
Management, including our chief executive officer and our chief financial officer, supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Management, including our chief executive officer and our chief financial officer, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2010. We have not made any change to our internal control over financial reporting during the 2010 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
New accounting pronouncements
International Financial Reporting Standards (IFRS)
The Accounting Standards Board requires Canadian publicly accountable enterprises to adopt IFRS effective January 1, 2011. Although IFRS has a conceptual framework that is similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosure.
We have developed a three-phase implementation plan in order to ensure compliance and a smooth transition.
Senior management and the board’s audit committee are actively involved in the process. A major public accounting firm has been engaged to provide technical accounting advice and project management guidance.
Phase 1: Preliminary study and diagnostic — complete
During this phase, we:

• |  | completed a high-level impact assessment

• |  | prioritized areas to evaluate in phase 2

• |  | developed a detailed plan for convergence and implementation

• |  | determined which information technology systems need to be modified to meet IFRS reporting requirements. We tested and implemented systems modifications by June 30, 2009.

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

• |  | assessed the impact of the adoption of IFRS on our results of operations, financial position and financial statement disclosures

• |  | developed a detailed, systematic gap analysis of accounting and disclosure differences between Canadian GAAP and IFRS, which will help us make final decisions about accounting policies and our overall conversion strategy

• |  | specified all changes we needed to make to existing business processes

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

• |  | carry out the changes to our business processes

• |  | receive the audit committee’s approval of our accounting policy changes

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• |  | complete the training process for our audit committee, board members and staff

• |  | communicate the impact of the IFRS transition to external stakeholders

• |  | collect the financial information we need to create our 2010 and 2011 financial statements under IFRS

• |  | receive the board’s approval of the new statements

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

• |  | We compare the carrying value of the asset with undiscounted future cash flows to see whether there is an impairment.

• |  | If there is an impairment, we measure it by comparing the carrying value of the asset with its fair value.

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

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

The difference in accounting for asset impairment could lead to greater volatility in reported earnings in future periods. The value-in-use test under IFRS uses discounted future cash flows, increasing the likelihood of asset impairment compared to the test under Canadian GAAP, which uses undiscounted cash flow. IFRS also requires companies to reverse impairment losses (for everything except goodwill) if an impairment is reduced due to a change in circumstances. Canadian GAAP does not allow companies to reverse impairment losses. As at January 1, 2011, we have not recorded any impairment charges under Canadian GAAP. We have, however, under IFRS reversed portions of impairment charges previously recorded under Canadian GAAP. See Opening statement of financial position and interim period financial results under IFRS for more information.
Employee benefits
We amortize past service costs on a straight-line basis over the expected average remaining service life of the plan participants under Canadian GAAP.
IAS 19, Employee Benefits, requires companies to expense the past service cost component of defined benefit plans on an accelerated basis. Vested past service costs must be expensed immediately. Unvested past service costs must be recognized on a straight-line basis until the benefits vest. Companies will also recognize actuarial gains and losses directly in equity rather than through profit or loss.

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IFRS 1, First-Time Adoption of International Financial Reporting Standards, also allows companies to recognize all cumulative actuarial gains and losses in retained earnings at the transition date and we have done so.
Share-based payments
We measure cash-settled, share-based payments to employees based on the intrinsic value of the award under Canadian GAAP. IFRS 2, Share-Based Payments, requires companies to measure payments at the award’s fair value, both initially and at each reporting date.
We expect no material impact on our financial results due to this difference.
Provisions (including asset retirement obligations)
IAS 37, Provisions, Contingent Liabilities and Contingent Assets, requires companies to recognize a provision when:

• |  | there is a present obligation due to a past transaction or event

• |  | it is probable (i.e. more likely than not) that an outflow of resources will be required to settle the obligation, and

• |  | the obligation can be reliably estimated

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

• |  | When there is a range of equally possible outcomes, IFRS uses the midpoint of the range as the best estimate, while Canadian GAAP uses the low end of the range.

• |  | Under IFRS, material provisions are discounted to their present value.

Joint ventures
We proportionately account for interests in jointly controlled enterprises, such as our interest in BPLP, under Canadian GAAP. The IASB has indicated that it expects to issue a new standard in 2011 that will replace IAS 31, Interests in Joint Ventures. It is considering Exposure Draft 9, Joint Arrangements (ED 9), which proposes that an entity recognize its interest in a joint controlled enterprise using the equity method. It is uncertain when the new standard will become effective. Until then, we have elected under the current IFRS standard to continue to use the proportionate consolidation method to account for our interests in jointly controlled enterprises.
Income taxes
Under Canadian GAAP, we cannot recognize deferred tax for a temporary difference that arises from intercompany transactions. We record the taxes we pay or recover in these transactions as an asset or liability, and then recognize them as a tax expense when the asset leaves the group or is otherwise used. IAS 12 requires entities to recognize deferred taxes for temporary differences that arise from intercompany transactions, and to recognize taxes paid or recovered in these transactions in the period incurred.
The IASB may address these differences in a fundamental review of income tax accounting at some time in the future, but this review is not likely to be soon.
Convertible debentures
Under Canadian GAAP, our convertible debentures, issued in 2003 and redeemed in 2008, were treated as a compound instrument with a debt and equity component. We measured the debt component at amortized cost using the effective interest rate method, and the equity component at the issue date using the residual method which does not recognize future changes in value.
We have concluded that under IFRS we cannot account for the convertible debentures as compound instruments under IAS 32. This does not change our accounting for the debt component, but we have concluded that the conversion feature is to be accounted for as a derivative. We are required to measure derivatives at fair value at each reporting date, recording changes in value in earnings. For purposes of our transition to IFRS, we have measured the fair value of the conversion feature as at the redemption date, and recorded an increase in share capital offset by a corresponding decrease in retained earnings.
Given the significant increase in value of the conversion option as a result of increases in the stock price of Cameco between the date of issuance and the date of redemption, we have recorded a $297 million reclassification between retained earnings and share capital.

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Exploration expenses
Under Canadian GAAP, we charge expenditures for geological exploration programs to earnings as incurred. We begin capitalizing exploration and development expenditures related to the project once the decision has been made to proceed to development.
IFRS 6, Exploration for and Evaluation of Mineral Resources, requires companies to either capitalize or expense costs incurred during the exploration and evaluation phase. Geological activities are considered exploration and evaluation between the time of obtaining the legal rights to explore a specific area and the completion of a commercially viable technical feasibility study. IFRS 6 requires entities to choose which expenditures are capitalized and which are expensed, and to apply the approach consistently.
On transition to IFRS, we will maintain our current accounting policy of expensing all costs relating to exploration and evaluation as they are incurred. As we do under Canadian GAAP, we will capitalize costs once we have determined that a property has economically recoverable reserves. No adjustments are required on transition to IFRS.
First-time adoption of IFRS
IFRS 1 generally requires an entity to apply IFRS retrospectively at the end of its first IFRS reporting period, but there are some mandatory exceptions and some optional exemptions.
We have analyzed the options available to us and have used the exemptions described in the table below. This is a summary of the most significant decisions relating to the transition to IFRS and IFRS 1 elections — it is not a complete list of decisions we were required or elected to make. We have completed our analysis and have made decisions about the accounting policies that are available. We have quantified the impacts of these differences on our consolidated financial statements under IFRS.

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

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

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

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Opening statement of financial position

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

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Interim period financial results

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

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

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5 |  | We have elected under IFRS 1 to reclassify all cumulative actuarial gains and losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date. At January 1, 2010, the effect was a $15 million decrease in long-term receivables, investments and other, other liabilities and a corresponding decrease in retained earnings.
6 |  | As a result of BPLP also transitioning to IFRS, we have recorded our share of BPLP’s transition adjustments. The most significant of BPLP’s IFRS transition adjustments results from cumulative actuarial losses. BPLP reclassified cumulative actuarial gains and losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date. The effect was a $137 million decrease in long-term receivables, investments and other, other liabilities and a corresponding decrease in retained earnings.
7 |  | We have elected under IFRS 1 to deem all foreign currency translation differences that exist at the date of transition to IFRS to be zero at the date of transition. At January 1, 2010, the effect was a $50 million adjustment to the cumulative translation adjustment account and a corresponding decrease in retained earnings.
8 |  | Under IFRS, we have concluded that our convertible debentures issued in 2003 and settled in 2008 will be treated as a hybrid instrument with a debt component and a conversion feature to be accounted for as a derivative. A derivative is required to be measured at fair value at each reporting date with changes in value being recorded in earnings. For purposes of our IFRS transition, we have measured the fair value of the conversion feature as at the redemption date and recorded a $297 million increase in share capital offset by a corresponding decrease in retained earnings.
9 |  | As a result of the changes in our opening balances on transition to IFRS, we have reduced our deferred tax liabilities by $138 million. For the interim periods, the adjustments relating to income tax expense reflect the tax effects of other adjustments as well as an IFRS accounting difference related to intra-group transactions. Under IFRS, deferred tax assets and liabilities are recognized for intra-group transactions whereas Canadian GAAP allows for the recognition of deferred tax assets and liabilities only when the transaction is with a third party.
10 |  | On transition to IFRS all actuarial losses were reclassified to retained earnings. Under IFRS, future actuarial gains and losses will be recognized through other comprehensive income to equity. Under Canadian GAAP, we have been amortizing the actuarial losses related to our interest in BPLP. As well, under IFRS, the costs of major inspections are capitalized and amortized over the period to the next inspection. Under Canadian GAAP, we have been expensing the inspection costs related to our interest in BPLP.

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

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presentations. In December of 2010, we hosted a special session with the investment community dedicated to addressing IFRS-related accounting changes specific to Cameco.
We have also evaluated the impact of IFRS on our business activities in general. As a result, we believe the adoption of IFRS will not have a material effect on our risk management practices, hedging activities, capital requirements, compensation arrangements, compliance with debt covenants or other contractual commitments.

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