EX-1 2 d298854dex1.htm EXHIBIT 1

Exhibit 1

TSX: CCO NYSE: CCJ |  |  |  | website: cameco.com currency: Cdn (unless noted)

2121 – 11th Street West, Saskatoon, Saskatchewan, S7M 1J3 Canada

Tel: (306) 956-6200 Fax: (306) 956-6201

Cameco reports fourth quarter and 2011 financial results

| • |  | delivered a strong fourth quarter—record revenue and gross profit from our nuclear business

| • |  | record annual revenue and gross profit from our nuclear business, and record revenue and realized prices in our uranium segment

| • |  | uranium production 3% higher than plan—on track with our Double U strategy

| • |  | matched our 2010 production record at McArthur River/Key Lake

| • |  | continued progress at Cigar Lake—broke through on the 480 metre level, putting it on the path to become another source of high-grade, low-cost production

Saskatoon, Saskatchewan, Canada, February 9, 2012

Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the fourth quarter ended December 31, 2011 and for the year.

“2011 was a challenging year for the nuclear industry,” said CEO Tim Gitzel. “However, it was business as usual for us, and in some ways, even better than usual. We achieved a number of financial records including record revenue and gross profit from our nuclear business and record realized prices for uranium. At our operations we delivered on a number of key milestones in a safe and responsible manner.

“Looking forward, we remain confident in the long-term fundamentals of the nuclear industry. With our extraordinary assets, contract portfolio, employee expertise, industry knowledge and financial strength, we are well positioned to meet the growing demand for uranium and add value for our shareholders.”

Highlights ($ millions except per share amounts) |  | Three months ended December 31 |  |  | change |  |  | Year ended December 31 |  |  | change |
| 2011 |  |  | 2010 |  |  |  | 2011 |  |  | 2010 |  |
Revenue |  |  | 977 |  |  |  | 673 |  |  |  | 45 | % |  |  | 2,384 |  |  |  | 2,124 |  |  |  | 12 | %
Gross profit |  |  | 353 |  |  |  | 252 |  |  |  | 40 | % |  |  | 776 |  |  |  | 771 |  |  |  | 1 | %
Net earnings 1 |  |  | 265 |  |  |  | 206 |  |  |  | 29 | % |  |  | 450 |  |  |  | 516 |  |  |  | (13 | )%
$ per common share (basic and diluted) |  |  | 0.67 |  |  |  | 0.52 |  |  |  | 29 | % |  |  | 1.14 |  |  |  | 1.31 |  |  |  | (13 | )%
Adjusted net earnings (non-IFRS, see page 9) |  |  | 249 |  |  |  | 190 |  |  |  | 31 | % |  |  | 509 |  |  |  | 497 |  |  |  | 2 | %
$ per common share (adjusted and diluted) |  |  | 0.63 |  |  |  | 0.48 |  |  |  | 31 | % |  |  | 1.29 |  |  |  | 1.26 |  |  |  | 2 | %
Cash provided by operations (after working capital changes) |  |  | 255 |  |  |  | 109 |  |  |  | 134 | % |  |  | 732 |  |  |  | 521 |  |  |  | 40 | %

1 | Net earnings attributable to our shareholders.

The 2011 annual financial statements have been audited; however, the 2010 and 2011 fourth quarter financial information presented is unaudited. You can find a copy of our 2011 audited financial statements on our website at cameco.com. Our 2011 annual management’s discussion and analysis (MD&A) will be posted on our website on Thursday, February 9, 2012.

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Transition to IFRS

On January 1, 2011, we adopted International Financial Reporting Standards (IFRS) for Canadian publicly accountable enterprises. Our financial statements have been prepared using IFRS. Amounts relating to the year ended December 31, 2010 in this document and our related financial statements have been revised using IFRS for comparative purposes. Amounts for periods prior to January 1, 2010 are presented in accordance with Canadian GAAP in effect prior to January 1, 2011.

Full year

Net earnings attributable to our shareholders (net earnings) for the year were $450 million ($1.14 per share diluted) compared to $516 million ($1.31 per share diluted) in 2010. In addition to the items noted below, our net earnings were impacted by losses on foreign exchange derivatives compared to gains in 2010.

On an adjusted basis, our earnings for the year were $509 million ($1.29 per share adjusted and diluted) compared to $497 million ($1.26 per share adjusted and diluted) (non-IFRS, see page 9). The 2% increase resulted from:

| • |  | higher earnings from our uranium business due to higher realized prices, and an increase in sales volumes partially offset by:

| • |  | an increase in the cost of sales

| • |  | lower earnings from our electricity business due to higher costs, lower realized prices and lower sales volumes

| • |  | lower earnings from our fuel services business resulting from higher costs, partially offset by higher sales volumes

| • |  | higher income taxes due to an increase in the provision related to our transfer pricing dispute with the Canadian Revenue Agency (CRA)

See 2011 Financial results by segment on page 10 for more detailed discussion.

Fourth quarter

In the fourth quarter of 2011, our net earnings were $265 million ($0.67 per share diluted), an increase of $59 million compared to $206 million ($0.52 per share diluted) in 2010. Uranium revenues were up significantly due to an increase in sales volumes and an increase in the average realized selling price, partially offset by lower results in the electricity business due to lower sales volumes and a lower realized price.

On an adjusted basis, our earnings this quarter were $249 million ($0.63 per share diluted) compared to $190 million ($0.48 per share diluted) (non-IFRS, see page 9) in the fourth quarter of 2010. The 31% increase in adjusted net earnings in the quarter followed the same trend as our net earnings, due to our positive results in the uranium business partially offset by our results in the electricity business.

See 2011 Financial results by segment on page 10 for more detailed discussion.

The nuclear energy industry today

The nuclear energy industry addressed significant challenges in 2011 related to events at the Fukushima-Daiichi nuclear power plant in Japan. As a result, the outlook for the industry remains uncertain for the near to medium term. In the long term, however, we continue to see a very strong and promising growth profile for the nuclear industry.

On March 11, an earthquake and tsunami in Japan caused cooling systems at the Fukushima-Daiichi nuclear power station to fail, and radioactive materials were released. This reduced public confidence in nuclear power in some countries, most notably Germany, which represents 5% of world nuclear generating capacity. It decided to revert to its previous phase-out policy, shutting down eight of its reactors, and plans to shut down the remaining nine reactors by 2022.

It remains unclear what level of nuclear power Japan itself—which represents 12% of global nuclear generating capacity—will depend on in the future. As of February 8, 2012, Japan had three reactors operating. These three reactors are scheduled to enter regular maintenance shutdowns between late February and the end of April, at which time we expect all of Japan’s nuclear reactors will be offline. Many are unaffected by the events in March 2011 but are offline for both planned and unplanned maintenance outages, and diminished public support has prevented utilities from gaining the regulatory and political approvals necessary to restart them. The Japanese government has

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ordered stress tests to be conducted on all reactors before allowing them to restart, and is implementing reforms to its existing nuclear regulatory framework and energy policy. Stress tests are progressing, but the government has not made any final decisions about restarting the reactors. Local government approval will also likely be required to allow reactors to restart.

The current operating status of reactors in Germany and Japan has caused concern that, in the near to medium term, additional volumes could be introduced to the market from deferrals and/or cancellations of deliveries under sales contracts. This has caused market participants to be discretionary in their purchases. We believe that utilities will continue to work with producers to manage these materials and minimize the impact on the market.

Industry taking action

At the same time, the industry has taken action. Countries with nuclear programs are reviewing regulatory standards, assessing the safety of existing facilities and the design of reactors under construction or in the planning stage. Third party organizations such as the International Atomic Energy Association, Nuclear Energy Institute, World Association of Nuclear Operators, Institute of Nuclear Power Operators, and the World Nuclear Association are lending their support and technical expertise to governments and operators, and providing an accurate source of information for the public.

Preliminary safety reviews are now complete and lessons are being applied that we expect will make the industry even safer. Most countries with nuclear generation capacity have reconfirmed their commitment to the technology and to the future of nuclear energy.

Long-term outlook is positive

Electricity is essential to maintaining and improving the standard of living for people around the world. Demand for safe, clean, reliable, affordable energy continues to grow and the need for nuclear as part of the world’s energy mix remains compelling. We expect demand for uranium to grow, and along with it the need for new supply to meet future customer requirements. You can read more about our outlook on future supply and demand in our annual MD&A.

Cameco well positioned

During this period of uncertainty, we are in the enviable position of being heavily committed under long-term sales contracts through 2016. As well, we have commitments to supply a total of about 290 million pounds of uranium under all of our long-term contracts, many of which extend beyond 2016. Therefore, we expect to have a solid revenue stream for years to come, even in the event of declining uranium market prices.

Outlook for 2012

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 as we use the funds in our business and pursue our growth plans.

Our outlook for 2012 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 2011 Financial results by segment on page 10 for details.

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2012 Financial outlook

|  | Consolidated |  | Uranium |  | Fuel services |  | Electricity
Production |  | — |  | 21.7 million lbs |  | 13 to 14 million kgU |  | —
Sales volume |  | — |  | 31 to 33 million lbs |  | Decrease 10% to 15% |  | —
Capacity factor |  | — |  | — |  | — |  | 95%
Revenue compared to 2011 |  | Decrease 0% to 5% |  | Decrease 0% to 5%1 |  | Decrease 10% to 15% |  | Increase 5% to 10%
Average unit cost of sales (including D&A) |  | — |  | Increase 0% to 5%2 |  | Increase 10% to 15% |  | Decrease 5% to 10%
Direct administration costs compared to 2011 3 |  | Increase 10% to 15% |  | — |  | — |  | —
Exploration costs compared to 2011 |  | — |  | Increase 15% to 20% |  | — |  | —
Tax rate |  | Recovery of 0% to 5% |  | — |  | — |  | —
Capital expenditures |  | $620 million 4 |  | — |  | — |  | $80 million

1 | Based on a uranium spot price of $52.00 (US) per pound (the Ux Consulting spot price as of February 6, 2012), a long-term price indicator of $61.00 (US) per pound (the Ux long-term indicator on January 30, 2012) and an exchange rate of $1.00 (US) for $1.00 (Cdn).

2 | This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we decide to make discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

3 | Direct administration costs do not include stock-based compensation expenses.

4 | Does not include our share of capital expenditures at BPLP.

Consolidated outlook

We expect consolidated revenue to be 0% to 5% lower in 2012 due to:

| • |  | lower sales volumes in the fuel services business

| • |  | lower realized prices in the uranium business

| • |  | partially offset by higher volumes in the electricity business

We expect administration costs (not including stock-based compensation) to be about 10% to 15% higher than in 2011 due to planned higher spending in support of our growth strategy.

We expect exploration expenses to be about 15% to 20% higher than they were in 2011 due to an increase in evaluation activities at Kintyre and Inkai block 3. We will also continue to focus efforts in Canada.

Uranium outlook

We expect to produce 21.7 million pounds in 2012. In addition, we have commitments under long-term contracts to purchase about 8 million pounds.

Based on the contracts we have in place, we expect to sell between 31 million and 33 million pounds of U 3 O 8 in 2012. We expect the average unit cost of sales to be 0% to 5% higher than in 2011. The increase is due primarily to higher costs for produced material. If we decide to make additional discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

Based on current spot prices, revenue should be about 0% to 5% lower than it was in 2011 as a result of an expected decrease in the realized price.

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. In 2012, we expect that deliveries will be evenly distributed across the quarters. However, not all delivery notices have been received to date, which could alter the delivery pattern.

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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, 2011 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, 2011, and none of the assumptions we list below change.

We intend to update this table each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio each quarter. As a result we expect the table to change from quarter to quarter.

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 |
2012 |  |  | 38 |  |  |  | 42 |  |  |  | 50 |  |  |  | 57 |  |  |  | 66 |  |  |  | 74 |  |  |  | 81 |
2013 |  |  | 43 |  |  |  | 46 |  |  |  | 54 |  |  |  | 62 |  |  |  | 71 |  |  |  | 80 |  |  |  | 88 |
2014 |  |  | 45 |  |  |  | 48 |  |  |  | 56 |  |  |  | 65 |  |  |  | 74 |  |  |  | 83 |  |  |  | 91 |
2015 |  |  | 43 |  |  |  | 47 |  |  |  | 56 |  |  |  | 66 |  |  |  | 77 |  |  |  | 87 |  |  |  | 97 |
2016 |  |  | 45 |  |  |  | 50 |  |  |  | 58 |  |  |  | 68 |  |  |  | 78 |  |  |  | 88 |  |  |  | 97 |

The table illustrates the mix of long-term contracts in our December 31, 2011 portfolio, and is consistent with our contracting strategy. The table has been updated to December 31, 2011 to reflect:

| • |  | deliveries made and contracts entered into up to December 31, 2011

| • |  | changes to deliveries under some sales contracts to assist our customers who were directly impacted by the March nuclear incident in Japan

| • |  | changes to deliveries under some contracts where deliveries are tied to reactor requirements

Our portfolio includes a mix of fixed-price and market-related 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 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 14% 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 do not have contracts for at the spot price for each scenario

Inflation

| • |  | is 3% per year

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Cameco’s share of production — annual forecast to 2016

We have geographically diverse sources of production. We are on track with our strategy to increase our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and projects under evaluation.

Current forecast (million lbs) |  | 2012 |  |  | 2013 |  |  | 2014 |  |  | 2015 |  |  | 2016 |
McArthur River/Key Lake |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |  |  |  | 13.1 |
Rabbit Lake |  |  | 3.7 |  |  |  | 3.7 |  |  |  | 3.7 |  |  |  | 3.7 |  |  |  | 3.4 |
US ISR |  |  | 2.4 |  |  |  | 3.0 |  |  |  | 3.1 |  |  |  | 3.7 |  |  |  | 3.8 |
Inkai 1 |  |  | 2.5 |  |  |  | 2.9 |  |  |  | 2.9 |  |  |  | 2.9 |  |  |  | 2.9 |
Cigar Lake |  |  | — |  |  |  | 0.3 |  |  |  | 1.9 |  |  |  | 5.5 |  |  |  | 7.9 |
Total share of production |  |  | 21.7 |  |  |  | 23.0 |  |  |  | 24.7 |  |  |  | 28.9 |  |  |  | 31.1 |
Cameco’s share of Inkai’s production on which profits are generated2 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Inkai 1 |  |  | 2.6 |  |  |  | 3.0 |  |  |  | 3.0 |  |  |  | 3.0 |  |  |  | 3.0 |
Total2 |  |  | 21.8 |  |  |  | 23.1 |  |  |  | 24.8 |  |  |  | 29.0 |  |  |  | 31.2 |

1 | We have signed a memorandum of agreement (MOA) with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). Once implemented, we will receive the right to purchase 2.9 million pounds of Inkai’s annual production and receive profits on 3.0 million pounds. See page 15 for more information.

2 | We have adjusted the production table to reflect the share of Inkai’s production we will use to calculate our profits under the MOA. See page 15 for more information.

In 2013, production at McArthur River may be lower as we transition to mining upper zone 4.

Our 2012 and future annual production targets for Inkai assume, and we expect:

| • |  | Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract

| • |  | we reach a binding agreement with Kazatomprom to finalize the terms of the MOA

| • |  | Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis)

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to recatagorize some of Inkai’s mineral reserves as resources.

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 18 and 19 and specifically on the assumptions and risks noted above and listed on the following page. Actual production may be significantly different from this forecast.

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Assumptions

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

| • |  | 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 or equipment 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 approvals from government authorities

| • |  | 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

Fuel services outlook

Due to current unfavourable market conditions for UF 6 conversion, we are decreasing our production in 2012. We plan to produce between 13 million and 14 million kgU, and expect sales volumes in 2012 to be 10% to 15% lower than in 2011.

We are changing our fuel services product mix in 2012, producing and selling less UF 6 than in 2011. We will also realize fewer 2012 cost recoveries in UF 6 conversion. Therefore, in fuel services we expect:

| • |  | the average realized price for our fuel services products to increase by 0% to 5%

| • |  | revenue to decrease by 10% to 15%

| • |  | average unit cost of sales (including depreciation and amortization (D&A)) to increase by 10% to 15%

Electricity outlook

Bruce Power estimates the average capacity factor for the four Bruce B reactors to be 95% in 2012, and actual output to be about 9% higher than it was in 2011 due to fewer planned outage days in 2012. The 2012 realized price for electricity is projected to be about the same as 2011. As a result, we expect that revenue will increase by 5% to 10%.

We expect the average unit cost of sales (net of cost recoveries) to be 5% to 10% lower in 2012 and total operating costs to decrease by about 0% to 5%, mainly due to fewer planned outages resulting in lower costs.

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Capital spending

(Cameco’s share in $ millions) |  | 2011 plan |  |  | 2011 actual |  |  | 2012 plan |
Growth capital |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 176 |  |  |  | 172 |  |  |  | 215 |
Inkai |  |  | 9 |  |  |  | 1 |  |  |  | 10 |
McArthur River |  |  | 14 |  |  |  | 24 |  |  |  | 35 |
Millennium |  |  | 6 |  |  |  | 4 |  |  |  | 5 |
US ISR |  |  | 13 |  |  |  | 15 |  |  |  | 30 |
Total growth capital |  |  | 218 |  |  |  | 216 |  |  |  | 295 |
Sustaining capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 169 |  |  |  | 168 |  |  |  | 145 |
US ISR |  |  | 38 |  |  |  | 39 |  |  |  | 50 |
Rabbit Lake |  |  | 85 |  |  |  | 77 |  |  |  | 75 |
Inkai |  |  | 19 |  |  |  | 15 |  |  |  | 30 |
Fuel services |  |  | 32 |  |  |  | 18 |  |  |  | 20 |
Other |  |  | 14 |  |  |  | 20 |  |  |  | 5 |
Total sustaining capital |  |  | 357 |  |  |  | 337 |  |  |  | 325 |
Total uranium & fuel services |  |  | 575 | 1 |  |  | 553 |  |  |  | 620 |
Electricity (our 31.6% share of BPLP) |  |  | 80 |  |  |  | 77 |  |  |  | 80 |

1 | We updated our 2011 capital cost estimate in the Q1 MD&A to $620 million, in the Q2 MD&A to $590 million and in the Q3 MD&A to $575 million.

Capital expenditures were 4% below the updated guidance we provided in our third quarter MD&A, mainly due to variances at Inkai and in the fuel services division. We do not expect this reduction in capital expenditures in 2011 will impact our plans to increase annual uranium production by 2018. The variance at fuel services was mainly due to cancellation of certain projects and revisions to project schedules. The variance at Inkai was mainly due to the deferral of upgrades to infrastructure and slower than expected progress on approvals for block 3.

We expect total capital expenditures for uranium and fuel services to be about 12% higher in 2012 as a result of higher spending for:

| • |  | growth capital at Cigar Lake

| • |  | growth and sustaining capital at US ISR

| • |  | sustaining capital at Inkai

In addition, we expect capital expenditures for 2013 and 2014 to be as follows:

($ millions) |  | 2013 |  |  | 2014 |
Growth capital |  |  | 325 – 350 |  |  |  | 250 – 275 |
Sustaining capital |  |  | 325 – 350 |  |  |  | 350 – 375 |
Total uranium & fuel services |  |  | 650 – 700 |  |  |  | 600 – 650 |

These growth capital expenditures are related to our Double U strategy. Many of these are early stage projects, however, and the mix of projects and their underlying capital estimates could change significantly. This is a preliminary estimate that we expect to fund using existing cash balances and operating cash flows.

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This information regarding currently expected capital expenditures for future periods is forward-looking information, and is based upon the assumptions and subject to the material factors discussed on pages 18 and 19. Our actual capital expenditures for future periods may be significantly different.

Sensitivity analysis

At December 31, 2011, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2011 net earnings by about $10 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.02 (Cdn).

For 2012:

| • |  | a change of $5 (US) per pound in each of the Ux spot price ($52.00 (US) per pound on February 6, 2012) and the Ux long-term price indicator ($61.00 (US) per pound on January 30, 2012) would change revenue by $68 million and net earnings by $55 million.

| • |  | a change of $5/MWh in the electricity spot price would change our 2012 net earnings by $4 million based on the assumption that the spot price will remain below the floor price of $50.18/MWh provided for under BPLP’s agreement with the Ontario Power Authority (OPA).

Non-IFRS measures

Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period and adjusted for earnings from discontinued operations. We also used this measure prior to adoption of IFRS (non-GAAP measure).

Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the fourth quarters of 2011 and 2010 and the years ended 2011 and 2010 as reported in our financial statements.

|  | Three months ended December 31 |  |  | Year ended December 31 |
($ millions) |  | 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |
Net earnings |  |  | 265 |  |  |  | 206 |  |  |  | 450 |  |  |  | 516 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives 1 (pre-tax) |  |  | (22 | ) |  |  | (22 | ) |  |  | 80 |  |  |  | (26 | )
Income taxes on adjustments to derivatives |  |  | 6 |  |  |  | 6 |  |  |  | (21 | ) |  |  | 7 |
Adjusted net earnings |  |  | 249 |  |  |  | 190 |  |  |  | 509 |  |  |  | 497 |

1 | In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains and losses on derivatives as reported under IFRS to reflect what our earnings would have been had hedge accounting been applied.

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2011 financial results by segment

Uranium

|  | Three months ended December 31 |  |  |  |  |  | Year ended December 31 |  |  |  |
Highlights |  | 2011 |  |  | 2010 |  |  | change |  |  | 2011 |  |  | 2010 |  |  | change |
Production volume (million lbs) |  |  | 6.6 |  |  |  | 6.4 |  |  |  | 3 | % |  |  | 22.4 |  |  |  | 22.8 |  |  |  | (2 | )%
Sales volume (million lbs) |  |  | 13.8 |  |  |  | 9.1 |  |  |  | 52 | % |  |  | 32.9 |  |  |  | 29.6 |  |  |  | 11 | %
Average spot price ($US/lb) |  |  | 51.79 |  |  |  | 58.29 |  |  |  | (11 | )% |  |  | 56.36 |  |  |  | 46.83 |  |  |  | 20 | %
Average long-term price ($US/lb) |  |  | 62.50 |  |  |  | 64.33 |  |  |  | (3 | )% |  |  | 66.79 |  |  |  | 60.92 |  |  |  | 10 | %
Average realized price |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
($US/lb) |  |  | 52.09 |  |  |  | 48.51 |  |  |  | 7 | % |  |  | 49.17 |  |  |  | 43.63 |  |  |  | 13 | %
($Cdn/lb) |  |  | 53.08 |  |  |  | 50.10 |  |  |  | 6 | % |  |  | 49.18 |  |  |  | 45.81 |  |  |  | 7 | %
Average unit cost of sales ($Cdn/lb) (including D&A) |  |  | 30.29 |  |  |  | 29.38 |  |  |  | 3 | % |  |  | 29.94 |  |  |  | 27.87 |  |  |  | 7 | %
Revenue ($ millions) |  |  | 731 |  |  |  | 457 |  |  |  | 60 | % |  |  | 1,616 |  |  |  | 1,358 |  |  |  | 19 | %
Gross profit ($ millions) |  |  | 314 |  |  |  | 189 |  |  |  | 66 | % |  |  | 632 |  |  |  | 532 |  |  |  | 19 | %
Gross profit (%) |  |  | 43 |  |  |  | 41 |  |  |  | 5 | % |  |  | 39 |  |  |  | 39 |  |  |  | — |

Fourth quarter

Production volumes were 3% higher due to slightly higher output at Rabbit Lake and Inkai, partially offset by slightly lower output at McArthur River/Key Lake and Smith Ranch-Highland. See Operations and development project updates starting on page 14 for more information.

Uranium revenues were up 60% due to a 6% increase in the Canadian dollar average realized price, and a 52% increase in sales volumes.

Our realized prices this quarter were higher than the fourth quarter of 2010 mainly due to higher US dollar prices under market related contracts, partially offset by a less favourable exchange rate. In the fourth quarter of 2011, our realized foreign exchange rate was $1.02 compared to $1.03 in the prior year.

Total cost of sales (including D&A) increased by 56% ($417 million compared to $268 million in 2010). This was mainly the result of the following:

| • |  | the 52% increase in sales volumes

| • |  | higher royalty charges due to higher deliveries of Saskatchewan-produced material and higher realized prices

| • |  | average unit costs for produced uranium were 2% higher

| • |  | partially offset by 33% lower average unit costs for purchased uranium due to fewer purchases at spot prices

The net effect was a $125 million increase in gross profit for the quarter.

Full year

Production volumes in 2011 were 2% lower than 2010 due to lower production from Smith Ranch-Highland and Inkai. See Operations and development project updates starting on page 14 for more information.

Uranium revenues this year were up 19% compared to 2010, due to an 11% increase in sales volumes and an increase of 7% in the Canadian dollar average realized price. Sales volumes in 2011 were higher than 2010 due to some customers deferring 2010 deliveries under contracts until 2011. The 19% increase was higher than the guidance we provided in the third quarter (increase 10% to 15%) as sales volumes for 2011 were at the top of the range provided (31 million pounds to 33 million pounds) at that time.

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Our realized prices this year in US dollars were 13% higher than 2010 mainly due to higher US dollar prices under market-related contracts. Our Canadian dollar selling price, however, was only 7% higher than 2010 as a result of a less favourable exchange rate when compared to 2010. Our exchange rate averaged $1.00 compared to $1.05 in 2010.

Total cost of sales (including D&A) increased by 19% this year ($983 million compared to $826 million in 2010). This was mainly the result of the following:

| • |  | the 11% increase in sales volumes

| • |  | average unit costs for produced uranium were 7% higher, although our average unit cost of sale for produced material was within the guidance we provided

| • |  | average unit costs for purchased uranium were 14% higher due to the increase in spot prices

| • |  | standby costs paid to AREVA relating to the McClean Lake mill

| • |  | higher royalty charges due to higher deliveries of Saskatchewan-produced material and higher realized prices. In 2011, total royalties rose to $124 million from $78 million in 2010.

The net effect was a $100 million increase in gross profit for the year.

The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures, see below). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

|  | Three months ended December 31 |  |  |  |  |  | Year ended December 31 |  |  |  |
($Cdn/lb) |  | 2011 |  |  | 2010 |  |  | change |  |  | 2011 |  |  | 2010 |  |  | change |
Produced |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 17.44 |  |  |  | 15.94 |  |  |  | 9 | % |  |  | 18.45 |  |  |  | 16.89 |  |  |  | 9 | %
Non-cash cost |  |  | 5.52 |  |  |  | 6.52 |  |  |  | (15 | )% |  |  | 6.50 |  |  |  | 6.32 |  |  |  | 3 | %
Total production cost |  |  | 22.96 |  |  |  | 22.46 |  |  |  | 2 | % |  |  | 24.95 |  |  |  | 23.21 |  |  |  | 7 | %
Quantity produced (million lbs) |  |  | 6.6 |  |  |  | 6.4 |  |  |  | 3 | % |  |  | 22.4 |  |  |  | 22.8 |  |  |  | (2 | )%
Purchased |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 18.86 |  |  |  | 28.14 |  |  |  | (33 | )% |  |  | 26.08 |  |  |  | 22.85 |  |  |  | 14 | %
Quantity purchased (million lbs) |  |  | 2.3 |  |  |  | 4.3 |  |  |  | (47 | )% |  |  | 9.6 |  |  |  | 10.6 |  |  |  | (9 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 21.90 |  |  |  | 24.74 |  |  |  | (11 | )% |  |  | 25.29 |  |  |  | 23.10 |  |  |  | 9 | %
Quantities produced and purchased (million lbs) |  |  | 8.9 |  |  |  | 10.7 |  |  |  | (17 | )% |  |  | 32.0 |  |  |  | 33.4 |  |  |  | (4 | )%

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.

These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the table below presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2011 and 2010 and the years ended 2011 and 2010 as reported in our financial statements.

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Cash and total cost per pound reconciliation

|  | Three months ended December 31 |  |  | Year ended December 31 |
($ millions) |  | 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |
Cost of product sold |  |  | 336.8 |  |  |  | 230.9 |  |  |  | 824.3 |  |  |  | 691.3 |
Add / (subtract) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Royalties |  |  | (61.3 | ) |  |  | (18.2 | ) |  |  | (123.6 | ) |  |  | (78.2 | )
Standby charges |  |  | (6.0 | ) |  |  | (6.4 | ) |  |  | (22.0 | ) |  |  | (12.0 | )
Other selling costs |  |  | (2.8 | ) |  |  | (7.9 | ) |  |  | (9.4 | ) |  |  | (13.4 | )
Change in inventories |  |  | (108.2 | ) |  |  | 24.6 |  |  |  | (5.7 | ) |  |  | 39.6 |
Cash operating costs (a) |  |  | 158.5 |  |  |  | 223.0 |  |  |  | 663.6 |  |  |  | 627.3 |
Add / (subtract) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 80.1 |  |  |  | 37.3 |  |  |  | 159.2 |  |  |  | 134.9 |
Change in inventories |  |  | (43.7 | ) |  |  | 4.4 |  |  |  | (13.6 | ) |  |  | 9.2 |
Total operating costs (b) |  |  | 194.9 |  |  |  | 264.7 |  |  |  | 809.2 |  |  |  | 771.4 |
Uranium produced and purchased (millions lbs) (c) |  |  | 8.9 |  |  |  | 10.7 |  |  |  | 32.0 |  |  |  | 33.4 |
Cash costs per pound (a ÷ c) |  |  | 17.81 |  |  |  | 20.84 |  |  |  | 20.74 |  |  |  | 18.78 |
Total costs per pound (b ÷ c) |  |  | 21.90 |  |  |  | 24.74 |  |  |  | 25.29 |  |  |  | 23.10 |

Fuel services results

(includes results for UF 6, UO 2 and fuel fabrication)

Highlights |  | Three months ended December 31 |  |  |  |  |  | Year ended December 31 |  |  |  |
| 2011 |  |  | 2010 |  |  | change |  |  | 2011 |  |  | 2010 |  |  | change |
Production volume (million kgU) |  |  | 3.1 |  |  |  | 3.9 |  |  |  | (21 | )% |  |  | 14.7 |  |  |  | 15.4 |  |  |  | (5 | )%
Sales volume (million kgU) |  |  | 7.2 |  |  |  | 6.3 |  |  |  | 14 | % |  |  | 18.3 |  |  |  | 17.0 |  |  |  | 8 | %
Realized price ($Cdn/kgU) |  |  | 14.66 |  |  |  | 14.59 |  |  |  | — |  |  |  | 16.71 |  |  |  | 16.86 |  |  |  | (1 | )%
Average unit cost of sales ($Cdn/kgU) (including D&A) |  |  | 11.18 |  |  |  | 12.49 |  |  |  | (10 | )% |  |  | 13.75 |  |  |  | 13.05 |  |  |  | 5 | %
Revenue ($ millions) |  |  | 106 |  |  |  | 91 |  |  |  | 16 | % |  |  | 305 |  |  |  | 287 |  |  |  | 6 | %
Gross profit ($ millions) |  |  | 25 |  |  |  | 13 |  |  |  | 92 | % |  |  | 54 |  |  |  | 65 |  |  |  | (17 | )%
Gross profit (%) |  |  | 24 |  |  |  | 14 |  |  |  | 71 | % |  |  | 18 |  |  |  | 23 |  |  |  | (22 | )%

Fourth quarter

Production volumes were 21% lower than in 2010 due to the decrease in production of UF 6. We reduced our production forecast in the third quarter as a result of unfavourable market conditions.

Total revenue increased by 16% due to a 14% increase in sales volumes and a slight increase in realized price.

The total cost of sales (including D&A) increased by 4% ($81 million compared to $78 million in the fourth quarter of 2010) due to the increase in sales volumes. When compared to 2010, the average unit cost of sales was 10% lower primarily due to higher cost recoveries in 2011.

The net effect was a $12 million increase in gross profit.

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Full year

Total revenue increased by 6% due to an 8% increase in sales volumes.

The total cost of sales (including D&A) increased by 13% ($251 million compared to $222 million in 2010) due to the increase in sales volumes. The average unit cost of sales was 5% higher due to higher unit costs for UF 6 relating to lower production.

The net effect was a $11 million decrease in gross profit.

Electricity results

Fourth quarter

Total electricity revenue decreased 14% due to lower output and 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 $147 million this quarter under its agreement with the OPA, compared to $114 million in the fourth quarter of 2010. The equivalent of about 66% of BPLP’s output was sold under financial contracts this quarter, compared to 45% in the fourth quarter of 2010. From time to time BPLP enters the market to lock in gains under these contracts.

The capacity factor was 86% this quarter, down from 91% in the fourth quarter of 2010 due to a higher volume of outage days during the year’s planned outages compared to last year’s planned outages.

Operating costs were $271 million compared to $225 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

The result was a 65% decrease in our share of earnings before taxes.

BPLP distributed $65 million to the partners in the fourth quarter. Our share was $21 million. BPLP capital calls to the partners in the fourth quarter were $10 million. Our share was $3 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

Full year

BPLP’s results in 2011 are largely the result of lower revenues, which were 10% lower than 2010 due to a 7% decrease in realized electricity prices. BPLP’s average realized price reflects spot sales, revenue recognized under BPLP’s agreement with the OPA and revenue from financial contracts.

During 2011, BPLP recognized revenue of $498 million under the agreement with the OPA, compared to $339 million in 2010.

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. BPLP sold the equivalent of about 54% of its output under financial contracts in 2011, compared to 42% in 2010. Pricing under these contracts was lower than in 2010. From time to time, BPLP enters the market to lock in gains under these contracts.

BPLP’s operating costs were $1.0 billion this year compared to $910 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

The net effect was a decrease in our share of earnings before taxes of 47%.

BPLP distributed $270 million to the partners in 2011. Our share was $85 million. BPLP capital calls to the partners in 2011 were $21 million. Our share was $7 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 87% in 2011, down from 91% in 2010 due to a higher volume of outage days during the year’s planned outages compared to last year’s planned outages.

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Operations and development project updates

Uranium – production overview

Cameco’s share (million lbs) |  | Three months ended December 31 |  |  | Year ended December 31 |  |  |  |
| 2011 |  |  | 2010 |  |  | 2011 |  |  | 2010 |  |  | 2011 plan |
McArthur River/Key Lake |  |  | 3.9 |  |  |  | 4.0 |  |  |  | 13.9 |  |  |  | 13.9 |  |  |  | 13.3 |
Rabbit Lake |  |  | 1.6 |  |  |  | 1.3 |  |  |  | 3.8 |  |  |  | 3.8 |  |  |  | 3.6 |
Smith Ranch-Highland |  |  | 0.2 |  |  |  | 0.4 |  |  |  | 1.4 |  |  |  | 1.8 |  |  |  | 1.6 |
Crow Butte |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.8 |  |  |  | 0.7 |  |  |  | 0.7 |
Inkai |  |  | 0.7 |  |  |  | 0.5 |  |  |  | 2.5 |  |  |  | 2.6 |  |  |  | 2.5 |
Total |  |  | 6.6 |  |  |  | 6.4 |  |  |  | 22.4 |  |  |  | 22.8 |  |  |  | 21.7 | 1

1 | We updated our 2011 plan in our Q3 MD&A to 21.7 million pounds from 21.9 million pounds at the beginning of 2011.

McArthur River/Key Lake

Our share of production in 2011 was 5% higher than our target of 13.3 million pounds, and the same as 2010.

At McArthur River and Key Lake we matched our production record set in 2010, realizing benefits under the production flexibility amendments to the McArthur River and Key Lake operating licences. Our revitalization program has improved the efficiency and reliability of equipment at the Key Lake mill, which had record monthly production in the latter part of the year.

We began drilling for the freezewall required to bring the upper mining area of zone 4 into production and in 2012, we will continue this drilling. We expect to start freezing upper zone 4 in 2013 and begin production from this area in 2014.

The Key Lake revitalization plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. After the mill is revitalized, annual production will depend mainly on mine production. As part of this plan, we replaced the acid, steam and oxygen plants.

At the end of 2011, construction of all three plants was complete. The steam plant was commissioned at year end and the oxygen plant was commissioned in early 2012. In 2012, we expect to:

| • |  | complete the commissioning of the new acid plant

| • |  | begin work for the construction of a new electrical substation and calciner

As part of the McArthur River extension, we advanced the exploration drifts to zones A and B, north of current mining operations, and were successful in upgrading the majority of the zone B inferred mineral resources to the indicated category based on surface drilling. This area continues to show promise. In addition to exploration work, we advanced feasibility work on the McArthur River extension project this year.

We are currently drafting the environmental impact study for the Key Lake extension project for submission to the regulator as part of the environmental assessment process. In 2011 we:

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

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

| • |  | continued our work on the environmental assessment

In 2012, for the Key Lake extension project, we expect to:

| • |  | begin to flatten the slope of the Deilmann tailings management facility pitwalls

| • |  | advance the environmental assessment for the Key Lake extension project. We expect to submit the draft environmental impact statement to the regulators by the end of the second quarter. Comments on the draft are expected before year end.

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In 2012, we plan to continue advancing the underground exploration drift to the south of the current mining areas. We also plan to test, from surface, along the entire length of the mineralized zone to identify additional mineral resources.

Inkai

Production this year was in line with the currently approved production level, but about 4% lower than production in 2010. Lower production was a result of in-process uranium inventory changes. Prior to final commissioning of the processing facilities in 2010, the in-process uranium inventory had built up. A significant reduction of this inventory added to production in 2010.

In addition, production in 2010, the first full year of operation, benefited from the higher grades associated with new wellfields. Average grades at in situ recovery operations typically stabilize at levels lower than initial years because uranium is recovered from a mix of wellfields of varying maturities and, as wellfields mature, the grades decrease. The processing plant has the capacity to produce at an annual rate of 5.2 million pounds per year (100% basis) depending on the grade of the production solution. Inkai is planning to expand the existing satellite plant capacity in order to support this production rate from lower grade solution. Regulatory approval is required to carry out production at the annual rate of 5.2 million pounds per year (100% basis).

An amendment to Inkai’s resource use contract was signed early in 2011, and Inkai received government approval to:

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

| • |  | carry out a five-year assessment program at block 3 that includes delineation drilling, uranium resource estimation, construction and operation of a test leach facility and completion of a feasibility study

We signed an MOA this year with our partner, Kazatomprom, to increase production from blocks 1 and 2 to 5.2 million pounds (100% basis). Under the MOA, our share of Inkai’s annual production will be 2.9 million pounds with the processing plant at full capacity. We will also be entitled to receive profits on 3.0 million pounds.

To implement the increase, we need a binding agreement finalizing the terms of the MOA, government approval and an amendment to the resource use contract.

Inkai continued delineation drilling, began infrastructure development and completed engineering for a test leach facility for the block 3 assessment program. Regulatory approval of the detailed delineation and test leach work programs is required.

Cigar Lake

During 2011, we:

| • |  | completed remediation of the underground

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

| • |  | completed the sinking of shaft 2 to the 480 metre level in early 2012

| • |  | substantially completed the ore loadout facility

| • |  | procured additional equipment for the jet boring system

| • |  | obtained regulatory approval to change the discharge location for the release of treated water to Seru Bay of Waterbury Lake

| • |  | obtained regulatory approval for the Cigar Lake mine plan

As of December 31, 2011, we had:

| • |  | invested about $675 million for our share of the construction costs to develop Cigar Lake

| • |  | expensed about $86 million in remediation expenses, including about $4 million in 2011

| • |  | expensed about $35 million in standby costs

We expect to spend an additional $484 million (our share) to complete this project, which requires us to:

| • |  | invest about $429 million for our share of the remaining capital costs, bringing our total share to about $1.1 billion

| • |  | expense about $55 million for our share of the remaining standby costs, bringing our total share to about $90 million

This would bring our total share of the cost for this project to about $1.3 billion since we began development in 2005.

- 15 -

We completed a surface drilling program this year, which increased the mineral reserves and average ore grade slightly, and extended the orebody further to the west. It also increased our confidence in the geology and the grade we can expect during the rampup period. We also initiated a drilling program to further delineate the west end of the mineralization.

In 2012, we expect to:

| • |  | complete the sinking of shaft 2 to its final depth of 500 metres

| • |  | begin installing shaft 2 infrastructure, including construction of a concrete ventilation partition, installation of electrical cable, water services, ore slurry pipes and hoist systems

| • |  | complete the surface ore loadout facility

| • |  | resume underground development in the north end of the mine

| • |  | move the jet boring system to site and begin testing underground

| • |  | develop two mining tunnels using the mine development system

| • |  | complete the Seru Bay pipeline

| • |  | complete all engineering designs and drawings for the project

| • |  | construct the clarifier

Cigar Lake continues to be a key part of our plan to increase our annual production to 40 million pounds by 2018 and we are pleased with the progress we are making to bring this valuable orebody into production. Over the year, we implemented a number of changes to the project, which have enhanced the overall economics of the project. These changes have put Cigar Lake on the path to becoming another high-grade, low-cost source of production, similar to our McArthur River operation.

We are updating the March 2010 Cigar Lake technical report to reflect these changes including the impact of the new milling arrangement, surface freezing and other developments. We plan to file the updated technical report with our February 2012 annual information form. The highlights of the technical report are:

| • |  | a decrease in the estimated average cash operating cost to about $18.60 per pound from about $23.10 per pound estimated in 2010. The reduction is primarily due to the new milling arrangement.

| • |  | an increase of about $190 million in our share of the total estimated capital cost at completion to $1.1 billion. The increase is mainly due to the implementation of the surface freeze strategy, general cost escalation, costs to upgrade and expand the McClean Lake mill and improvements to the mine plan.

| • |  | a change to the production profile, with slightly lower production expected in the first years of the project offset by higher production in the later years. We expect our share of production in 2013 to be about 0.3 million pounds. This compares to our previous estimate of 1 million pounds. This and the other revisions to our production schedule on page 6 represent an 8.7% decrease in our production forecast through 2016 and are a result of the extended period required for remediation and a better understanding of the geology and lower grades in the initial production panels.

| • |  | first commissioning in ore expected in mid-2013 and the first pounds expected to be packaged at the McClean Lake mill in the fourth quarter

| • |  | rampup to the full production rate expected by the end of 2017

| • |  | a 4% increase in our share of the mineral reserves estimate from 104.7 million pounds to 108.4 million pounds and an 8% increase in the estimated average ore grade

| • |  | an upgrade of probable mineral reserves to proven minerals reserves

Given the scale of this project and the challenging nature of the geology and mining method, we have made significant achievements since 2010. We will continue to develop this asset in a safe and deliberate manner to ensure we realize the economic benefits of this project.

- 16 -

Our expectations and plans regarding Cigar Lake, the expected benefit of milling Cigar Lake ore at the McClean Lake mill, the estimated average cash operating cost, our expected share of the total project and capital cost at completion for Cigar Lake and our mineral reserve estimate, are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 18 and 19.

Fuel services

Fuel services produced 14.7 million kgU in 2011, slightly lower than our plan at the beginning of the year and 5% lower than 2010. In the third quarter we reduced our production due to unfavourable market conditions for UF 6 conversion.

Based on the unfavourable market conditions for UF 6 conversion, we have discontinued discussions to extend our toll conversion contract with Springfields Fuels Limited beyond 2016. We remain fully committed to the current contract. If market conditions improve over the next few years, we would consider resuming our discussions to extend the contract.

Qualified persons

The technical and scientific information discussed in this document, including mineral reserve and resource estimates, for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) were approved by the following individuals who are qualified persons for the purposes of NI 43-101:

McArthur River/Key Lake |  | Cigar 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 |  | • Alain G. Mainville, director, mineral resources management, Cameco • Eric Paulsen, interim chief metallurgist, technology & innovation, Cameco • Grant Goddard, vice-president, Saskatchewan mining north, Cameco • Scott Bishop, principal mine engineer, technology & innovation, Cameco
Inkai |  |
• Alain G. Mainville, director, mineral resources management, Cameco • Dave Neuburger, vice-president, international mining, Cameco • Lawrence Reimann, manager, technical services, Cameco Resources |  |

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Caution about forward-looking information

This document 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 document as forward-looking information.

Key things to understand about the forward-looking information in this document:

| • |  | 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 below).

| • |  | It represents our current views, and can change significantly.

| • |  | It is based on a number of material assumptions, including those we have listed on page 19, 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 starting on page 18. 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.

Examples of forward-looking information in this document

| • |  | our outlook for the nuclear energy industry, including the discussion on the expected impact resulting from the March 2011 nuclear incident in Japan and how Cameco is well positioned

| • |  | the outlook for each of our operating segments for 2012, 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 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 expectation that cash balances will decline as we use the funds in our business and pursue our growth plans

| • |  | our uranium price sensitivity analysis

| • |  | forecast production at our uranium operations from 2012 to 2016

| • |  | our statements regarding our target to increase annual uranium production to 40 million pounds by 2018

| • |  | our expectations for 2012, 2013 and 2014 capital expenditures

| • |  | our expectations and plans for our McArthur River/Key Lake, Inkai and Cigar Lake uranium properties

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

| • |  | our 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 not reliable, 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

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| • |  | we are affected by terrorism, sabotage, blockades, civil unrest, accident or a deterioration in political support for, or demand for, nuclear energy

| • |  | we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium

| • |  | there are changes to government regulations or policies that adversely affect us, including tax and trade laws and policies

| • |  | our uranium and conversion suppliers fail to fulfil delivery commitments

| • |  | our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties encountered with the jet

|  | boring mining method or our inability to acquire any of the required jet boring equipment

| • |  | the new arrangement for milling Cigar Lake ore does not result in the expected cost savings or other benefits

| • |  | 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, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

Material assumptions

| • |  | our expectations regarding sales and purchase volumes and prices for uranium, fuel services and electricity

| • |  | our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being adversely affected by changes in regulation or in the public perception of the safety of nuclear power plants

| • |  | our expected production level and production costs

| • |  | our expectations regarding spot prices and realized prices for uranium, and other factors discussed on page 5, Price sensitivity analysis: uranium

| • |  | our expectations regarding tax rates, foreign currency exchange rates and interest rates

| • |  | our decommissioning and reclamation expenses

| • |  | our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable

| • |  | the geological, hydrological and other conditions at our mines

| • |  | our Cigar Lake development, mining and production plans succeed, including the success of the jet boring mining method at Cigar Lake and that we will be able to obtain the additional jet boring system units we require on schedule

| • |  | the new arrangement for milling Cigar Lake ore will result in the expected reduction in the operating cost

| • |  | 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, civil unrest, 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, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

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Conference call

We invite you to join our fourth quarter conference call on Friday, February 10, 2012 at 11:00 a.m. Eastern.

The call will be open to all investors and the media. To join the call, please dial (800) 355-4959 (Canada and US) or (416) 695-7848. An operator will put your call through. A live audio feed of the conference call will be available from a link at cameco.com. See the link on our home page on the day of the call.

A recorded version of the proceedings will be available:

| • |  | on our website, cameco.com, shortly after the call

| • |  | on post view until midnight, Eastern, March 10, 2012 by calling (800) 408-3053 (Canada and US) or (905) 694-9451 (Passcode 7817583 #)

Additional information

Our 2011 annual management’s discussion and analysis and annual audited financial statements will be available shortly on SEDAR at sedar.com, on EDGAR at sec.gov/edgar.shtml and on our website at cameco.com. Our February 2012 annual information form, along with our Cigar Lake technical report are expected to be available next week.

Profile

We are one of the world’s largest uranium producers, a significant supplier of conversion services and one of two Candu fuel manufacturers in Canada. Our competitive position is based on our controlling ownership of the world’s largest high-grade reserves and low-cost operations. Our uranium products are used to generate clean electricity in nuclear power plants around the world, including Ontario where we are a limited partner in North America’s largest nuclear electricity generating facility. We also explore for uranium in the Americas, Australia and Asia. Our shares trade on the Toronto and New York stock exchanges. Our head office is in Saskatoon, Saskatchewan.

As used in this news release, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries and affiliates unless stated otherwise.

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Investor inquiries: Rachelle Girard (306) 956-6403

Media inquiries: Gord Struthers (306) 956-6593

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