6-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 Under
the Securities Exchange Act of 1934

For the month of February, 2010

(Commission file No. 1-14228)

Cameco Corporation

2121-11th Street West
Saskatoon, Saskatchewan, Canada S7M 1J3
(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F o       Form 40-F þ

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes o       No þ

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

TABLE OF CONTENTS

EX-1

Exhibit Index

Exhibit No.	Description	Page No.
1.	Press Release dated February 24, 2010

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 24, 2010	Cameco Corporation
	By:	/s/ “Gary M. S. Chad”
		Gary M. S. Chad
		Senior Vice-President, Governance, Law and Corporate Secretary

EX-1

EXHIBIT 1

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

2121 – 11^th Street West, Saskatoon, Saskatchewan, S7M 1J3 Canada
Tel: (306) 956-6200 Fax: (306) 956-6201

Cameco Reports Record Financial Performance for 2009

Saskatoon, Saskatchewan, Canada, February 24, 2010 . . . . . . . . . . . . . .

Cameco Corporation (TSX: CCO; NYSE: CCJ) today reported record net earnings of $1.1 billion ($2.82 per share diluted) for 2009, compared to $450 million ($1.28 per share diluted) in 2008. For the fourth quarter net earnings were $598 million ($1.52 per share diluted), compared to $31 million ($0.08 per share diluted) in the fourth quarter of 2008.

Our net earnings were significantly higher for the year and the fourth quarter, primarily as a result of selling our interest in Centerra Gold Inc. (Centerra) and recording an after-tax gain of $374 million. Net earnings for the full year were also favourably impacted by the recording of an after-tax profit of $179 million relating to mark-to-market gains on financial instruments, compared to a loss of $148 million in 2008.

Adjusted net earnings¹ for the full year were $582 million ($1.49 per share adjusted and diluted), compared to $589 million ($1.67 adjusted and diluted) in 2008. The 1% decrease in 2009 was attributable to:

• lower profits from our uranium business due to higher unit costs

• lower profits in gold resulting from lower sales volumes

• higher profits from our electricity business, relating to higher realized selling prices, which partially offset our uranium and gold results

Our 2009 fourth quarter adjusted net earnings¹ were $248 million ($0.63 per share adjusted and diluted), a 39% increase over $179 million earned for the same period in 2008. This resulted primarily from higher profits in gold, due to a higher realized selling price (averaging $1,129 (US) per ounce in 2009 compared to $806 (US) per ounce in 2008).

“With the sale of Centerra, we are now fully focused on the growing interest in nuclear energy,” said Jerry Grandey, Cameco’s President and Chief Executive Officer. “Operationally and financially, we are well positioned to meet our goal of doubling annual uranium production by 2018.”

¹ Net earnings for the quarters and years ended December 31, 2008 and 2009 have been adjusted to exclude a number of items. Our adjusted net earnings include our share of Centerra’s operating earnings for the periods presented. Adjusted net earnings is a non-GAAP measure. For a description see “Non-GAAP measures” in this document.

Note: All dollar amounts are expressed in Canadian dollars unless otherwise stated. The 2009 annual financial statements have been audited, however 2008 and 2009 fourth quarter financial information presented is unaudited. Our audited annual financial statements are available on our company’s website cameco.com, on SEDAR at sedar.com and on EDGAR at sec.gov/shtml.

Financial Highlights	Three months ended				Year ended				Change
December 31	December 31				December 31				from 2008
($ millions - except per share amounts)	20092		20082		20092		20082		to 2009
Revenue		659		640		2,315		2,183		6	%
Net earnings		598		31		1,099		450		144	%
- $  per common share (basic)		1.52		0.08		2.83		1.29		119	%
- $  per common share (diluted)		1.52		0.08		2.82		1.28		120	%
Adjusted net earnings1		248		179		582		589		(1	)%
- $  per common share (adjusted and diluted)		0.63		0.49		1.49		1.67		(11	)%
Cash provided by operations (from continuing operations)		188		224		690		530		30	%

1

Net earnings for the quarters and years ended December 31, 2008 and 2009 have been adjusted to exclude a number of items. Our adjusted net earnings include our share of Centerra’s operating earnings for the periods presented. Adjusted net earnings is a non-GAAP measure. For a description see “Non-GAAP measures” in this document.

2

Under Canadian GAAP, we are required to report the results of discontinued operations separately from continuing operations. We have included our operating earnings from Centerra, and the financial impact of our disposition of Centerra shares, in discontinued operations. We recast our consolidated financial results for 2008 to conform to accounting standards for discontinued operations (Centerra). The change affected a number of financial measures, including revenue. See note 25 to the annual audited financial statements for more information.

Highlights

• record revenue of $2.3 billion, up 6% over 2008

• uranium production 20.8 million pounds, up 20% from 2008

• cash from continuing operations increased by 30% to $690 million

• sold our interest in Centerra in the fourth quarter, netting cash of $871 million

• completed dewatering the underground workings at Cigar Lake in February 2010 and expect initial production in mid-2013, based on current information

For more information regarding our 2009 results, please see our annual management’s discussion and analysis (MD&A).

Outlook for the year 2010

Over the next several years, we expect to make significant investments to expand production at our existing mines and advance projects as we pursue our growth strategy. The projects are at various stages of development, from exploration and evaluation to construction.

We expect our existing cash balances and our operating cash flows, based on current uranium spot prices, will meet our anticipated requirements over the next several years, without the need for significant additional funding. Our cash balances will gradually decline as we use the funds to pursue our growth plans. We will consider other uranium production opportunities as they arise.

Our outlook for 2010 reflects the growth expenditures necessary to help us achieve our strategy.

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Below is a table summarizing our 2010 consolidated outlook as well as the outlook for each of our business segments. Following the table is a more detailed discussion of our:

• consolidated outlook

• outlook for each of our business segments including our uranium price sensitivity table and production forecast by site for the years 2010 to 2014

• planned capital expenditures for 2010 and actual expenditures in 2009

• sensitivity analysis for consolidated earnings to changes in the exchange rate, uranium spot price and electricity spot price

2010 Financial outlook¹

	Consolidated		Uranium		Fuel services		Electricity
Production		—	21.5 million lbs		14 to 16 million kgU			—
Sales volume		—	31 to 33 million lbs		Increase 15% to 20%			—
Capacity factor		—		—		—	About 90%
Revenue compared to 2009	Decrease 5% to 10%		Decrease 5% to 10%2		Increase 5% to 10%		Decrease 5% to 10%
Unit cost of product sold (including DDR)		—	Decrease 5% to 10%3			—	Increase 10% to 15%
Direct administration costs compared to 20094	Increase 25% to 30%			—		—		—
Exploration costs compared to 2009		—	Increase 80% to 90%			—		—
Tax rate	Less than 5%			—		—		—
Capital expenditures	$552 million5			—		—	$41 million

1	We only provide outlook for the select items shown in the table. For all other items listed in the table, no outlook is provided.
2	Based on a uranium spot price of $41.75 (US) per pound (the Ux spot price as of February 22, 2010) and an exchange rate of $1.00 (US) for $1.05 (Cdn).
3	Assumes the unit cost of sale for produced material will decline by 2% to 5%, and the unit cost of sale for purchased material will decline by 15% to 20%.
4	Direct administration costs do not include stock-based compensation expenses.
5	Does not include our share of capital expenditures at Bruce Power Limited Partnership (BPLP).

Consolidated outlook

For 2010, we expect consolidated revenue to be 5% to 10% lower, as:

• We expect lower trading volumes in uranium, so uranium sales volumes are likely to be lower by 5% to 10%.

• We expect realized prices for electricity to be lower, so revenue from our electricity business is likely to decline.

We expect administration costs (not including stock-based compensation) to be 25% to 30% higher than they were in 2009 due to planned higher spending in support of our growth strategy.

We expect exploration expenses to be 80% to 90% higher than they were in 2009. We plan to invest approximately $90 million to $95 million on uranium exploration in 2010 as part of our long-term strategy. This includes approximately $40 million for exploration at Kintyre and Inkai block 3 in Kazakhstan. Our policy is to expense costs for properties that do not have established reserves or operating history.

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Uranium outlook

We expect to produce 21.5 million pounds of U₃O₈, or 3% more than 2009. The increase is driven by our plan to double production at Inkai.

Based on the contracts we have in place, we expect to sell between 31 million and 33 million pounds U₃O₈ in 2010. We expect the unit cost of sale for produced material to be 2% to 5% lower than in 2009 due to higher production, and the unit cost of sale for purchased material to be 15% to 20% lower, as we expect to make fewer purchases on the spot market.

Based on current spot prices, revenue should be about 5% to 10% lower than it was in 2009 as a result of lower expected sales volumes in 2010.

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

Long-term price sensitivity analysis: uranium

The table below is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table.

The table is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2009 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2009, and none of the assumptions we list below change.

Expected Realized Uranium Price Sensitivity Under Various Spot Price Assumptions (Rounded to the nearest $1.00) $US/lb U3O8
Spot prices	$	20	$	40	$	60	$	80	$	100	$	120	$	140
2010		33		39		47		53		60		67		74
2011		33		38		47		54		63		71		79
2012		36		39		49		58		68		77		86
2013		43		45		55		65		75		85		94
2014		42		46		56		66		76		87		96

In the table, our average realized price increases over time under all spot price scenarios. This illustrates the mix of long-term contracts in our December 31, 2009 portfolio, and is consistent with our contracting strategy.

Our contracts usually include a mix of fixed-price and market-price components, which we target at a 40:60 ratio. We signed many of our current contracts in 2003 to 2005, when market prices were low ($11 to $31 (US)). Those that are fixed at lower prices or have low ceilings will yield prices that are lower than current market prices. These older contracts are beginning to expire, and we are starting to deliver into contracts signed since 2004 (when market prices began to increase).

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

Sales

• sales volume of 32 million pounds in 2010 (the mid-point of our outlook for the year)

• sales volume of 30 million pounds for 2011 and every year following

Deliveries

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

• we defer a portion of deliveries under existing contracts for 2010, 2011 and 2012

Prices

• the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only)

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

Inflation

• is 2.0% per year

Cameco’s share of production — annual forecast to 2014

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

Based on current information, we expect Cigar Lake to begin production in mid-2013. We will update our production outlook for Cigar Lake in the technical report, which we plan to file at the end of the first quarter of 2010.

By 2011, Inkai is expected to reach production of 5.2 million pounds of U₃O₈ per year (our share 3.1 million pounds). Inkai has regulatory approval to produce 2.6 million pounds (100% basis) and, in 2005, applied for regulatory approval to increase production to 5.2 million pounds per year (100% basis). We require regulatory approval to increase production to the level necessary to achieve our annual production forecast, and expect to receive it in 2010.

This production forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed under the heading “Caution Regarding Forward-looking Information and Statements”, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.

Assumptions

• we achieve our forecast production for each operation, which requires, among other things, that our mining plans succeed, processing plants function and our reserve estimates are accurate

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

• our production is not disrupted or reduced due to natural phenomena, labour disputes, political risks, shortage or lack of supplies critical to production, equipment failures or other development and operation risks

Material risks that could cause actual results to differ materially

• we do not achieve forecast production levels for each operation due to a change in our mining plans, processing plant availability, lack of tailings capacity or for other reasons

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

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

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Fuel services outlook

We expect to produce 14 million to 16 million kgU in our fuel services business in 2010, a significant improvement over 2009 largely due to stronger anticipated performance at the Port Hope UF₆ conversion plant.

We expect the average realized selling price for our fuel services products to decline by 5% to 10%, sales volumes to increase by 15% to 20%, and revenue to be 5% to 10% higher.

Electricity outlook

We expect the average capacity factor of the four Bruce B reactors to be approximately 90% in 2010, and actual output to be about 4% higher than it was in 2009. The 2010 realized price for electricity is projected to be about 5% to 10% lower than 2009, as BPLP has fewer financial contracts in place for 2010. At December 31, 2009, BPLP had about 6.5 TWh under financial contracts, which is equivalent to about 25% of Bruce B generation at its planned capacity factor. We expect that revenue will be lower by a corresponding 5% to 10% as a result.

We expect the average unit cost (net of cost recoveries) to be 10% to 15% higher in 2010, and total operating costs to rise by about 10% to 15%, mainly due to higher costs for planned outages and maintaining the workforce.

Capital spending (Cameco’s share in $ millions)	2010 Plan		2009 Actual		2009 Plan
Growth capital
Cigar Lake		111		42		48
Inkai		4		10		9
Total growth capital		115		52		57
Sustaining capital
McArthur River/Key Lake		220		115		106
US ISR		53		32		54
Rabbit Lake		56		43		38
Inkai		18		17		18
Fuel services		29		18		23
Other		9		20		21
Total sustaining capital		385		245		260
Capitalized interest		52		37		50
Total uranium & fuel services		552		334		367
Electricity (our 31.6% share of BPLP)		41		39		38

We expect total capital expenditures for uranium and fuel services to be 65% higher in 2010, as a result of higher spending for:

• growth capital at Cigar Lake

• sustaining capital at Key Lake and McArthur River

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Sensitivity analysis

At December 31, 2009, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2010 net earnings by about $10 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.05 (Cdn).

For 2010:

• a change of $5 US from the Ux spot price on February 22, 2010 ($41.75 (US) per pound) would change revenue by $64 million and net earnings by $39 million

• a change of $1 in the electricity spot price would change our 2010 net earnings by $3 million, based on the assumption that the spot price will remain below the floor price provided for under BPLP’s agreement with the Ontario Power Authority (OPA)

2009 financial results by segment

Uranium results

Highlights

	Three months ended				Year ended				Change %
	December 31				December 31				from 2008
	2009		2008		2009		2008		to 2009
Production volume (million lbs)		6.7		5.5		20.8		17.3		20	%
Sales volume (million lbs)		10.0		10.5		33.9		34.1		(1	)%
Average spot price ($US/lb)		45.96		51.00		46.06		61.58		(25	)%
Average realized price:
($US/lb)		40.64		35.31		38.25		39.52		(3	)%
($Cdn/lb)		43.51		42.77		45.12		43.91		3	%
Cost of sales ($Cdn/lb U3O8) (including DDR)		30.29		24.16		30.59		24.27		26	%
Revenue ($ millions)		443		450		1,551		1,512		3	%
Gross profit ($ millions)1		132		193		488		665		(27	)%
Gross profit (%)		30		43		31		44		(30	)%

¹ Gross profit equals revenue less cost of products and services sold and DDR.

Fourth quarter

Uranium revenues for the quarter were down 2% compared to 2008, as a 5% decline in sales volumes was partially offset by a 2% increase in our realized price. The Canadian dollar was much stronger, with our exchange rate averaging $1.07 compared to $1.21 a year ago. Our results fell slightly short of forecast due to logistical issues during the quarter that delayed delivery of approximately 1 million pounds of uranium until the first quarter of 2010.

The total cost of products and services sold, including depreciation, depletion and reclamation (DDR) was 21% higher than 2008 ($311 million compared to $257 million in 2008) mainly due to higher unit costs for purchased uranium. The average unit cost of product and services sold was $30.29/lb, or 25% higher than it was in the fourth quarter of 2008 as we purchased uranium at near-market prices during the year. These purchases were made to take advantage of trading opportunities in current and future years and, while profitable, are at margins much lower than our average.

The net effect was a 32% decrease in gross profit for the quarter.

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Full year

For 2009, the primary reason for a 3% increase in total revenues was a weaker Canadian dollar resulting in a 3% higher realized price. Sales volumes were slightly lower than in 2008.

Our total cash cost of sales (excluding DDR) increased by 27% to $901 million ($26.33 per pound U₃O₈) in 2009. This was mainly the result of:

• our unit cost for purchased uranium being significantly higher as we bought more uranium at near-market prices to take advantage of profitable trading opportunities

• we recorded royalty expenses of $117 million (compared to $82 million in 2008) due to higher realized prices and royalty adjustments

The net effect was a 27% decrease in gross profit for the year.

For produced material, our cash cost of sales per unit rose by $4.44 per pound in 2009. Higher royalty costs represented 38% of the increase (higher realized prices resulted in $1.30 per pound increase in royalties) and production from Inkai added $0.83 per pound (19%). During the rampup stage, Inkai’s cash costs will be significantly higher than our overall average.

The following table shows our cash cost of sales per unit for produced and purchased material, including royalty charges on produced material, as well as the amounts of produced and purchased uranium sold.

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

Uranium — 2009 production overview

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

Production volumes were 22% higher in the fourth quarter of 2009 compared to the fourth quarter of 2008, as a result of higher production at McArthur River/Key Lake, Smith Ranch-Highland and Inkai.

Annual production also climbed 20% over 2008 levels due to higher production at McArthur River/Key Lake, Rabbit Lake and Smith Ranch-Highland, and the continued rampup of production at Inkai. Production in 2008 was lower than planned as a result of operating challenges at the Key Lake mill.

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Fuel services results

(includes results for UF₆, UO₂ and fuel fabrication)

Highlights

	Three months ended				Year ended				Change %
	December 31				December 31				from 2008
	2009		2008		2009		2008		to 2009
Production volume (million kgU)		3.9		2.6		12.3		8.3		48	%
Sales volume (million kgU)		6.0		4.6		14.9		14.8		1	%
Realized price ($Cdn/kgU)		14.89		13.81		17.84		15.85		13	%
Cost of sales ($Cdn/kgU) (including DDR)		12.92		11.26		14.47		15.46		(6	)%
Revenue ($ millions)		91		70		276		252		10	%
Gross profit ($ millions)1		13		14		50		8		525	%
Gross profit (%)		14		20		18		3		500	%

¹ Gross profit equals revenue less cost of products and services sold and DDR.

Fourth quarter

For the fourth quarter of 2009, total revenue rose by 30%. The unit cost of products and services sold (including DDR) was 15% higher, mainly due to a labour strike at our fuel manufacturing facility. Our cost of sales for the quarter included $9 million in standby costs incurred during the strike.

The net effect was a 7% decrease in gross profit for the quarter.

Full year

In 2009, revenue rose by 10% as a result of a 13% increase in the average realized selling price for fuel service products, reflecting improved prices under UF₆ sales contracts.

The unit cost of products and services sold (including DDR) was 6% lower this year, mainly due to higher production volumes and allocating operating costs to inventory rather than expensing them directly. In 2009, we expensed $18 million in standby charges compared to $43 million in 2008.

The shutdown of the Port Hope UF₆ conversion plant reduced production in our fuel services division in 2009 and 2008. The UF₆ plant resumed operations in June, reducing the impact in 2009, and resulting in a 48% increase in total production.

The net effect was a $42 million increase in gross profit for the year.

Electricity results

Fourth quarter

During the fourth quarter, our earnings before taxes from BPLP were $62 million, up from $55 million in 2008. The increase was mainly due to higher realized prices.

BPLP’s average realized price reflects spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. During the fourth quarter of 2009, BPLP recognized revenue of $137 million under its agreement with the OPA. For more information on the OPA agreement, please see our 2009 annual MD&A.

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BPLP 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.

The equivalent of about 54% of BPLP’s output was sold under financial contracts in the fourth quarter of 2009 compared to 76% in the fourth quarter of 2008.

BPLP’s adjusted capacity factor was 95% in the fourth quarter of 2009 (includes actual generation of 6.4 TWh and deemed generation of 0.4 TWh). The deemed generation resulted from the B units having their power output reduced in response to dispatch orders from the market operator during periods of excess baseload generation in Ontario. Excluding deemed generation, the capacity factor was 89%, down from 97% in the fourth quarter of 2008.

BPLP distributed $220 million to the partners in the fourth quarter. Our share was $70 million.

Full year

For the year, our earnings before taxes from BPLP were $224 million, up 59% from $141 million in 2008.

BPLP’s improved results in 2009 are largely the result of higher revenues, which were 16% higher than 2008 due to a 12% increase in realized prices.

During 2009, BPLP recognized revenue of $514 million under the agreement with the OPA.

BPLP sold the equivalent of about 57% of its output under financial contracts in 2009, compared to 67% in 2008.

BPLP’s adjusted capacity factor was 91% in 2009 (including actual generation of 24.6 TWh and deemed generation of 1.2 TWh). Excluding deemed generation, the capacity factor was 87% — unchanged from 2008.

BPLP distributed $610 million to the partners in 2009. Our share was $193 million.

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Non-GAAP measures

We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our GAAP-based net earnings, adjusted for one-time costs, writedowns, gains and unrealized mark-to-market losses on our financial instruments, which we believe do not reflect underlying performance.

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

	Three months ended					Year ended
	December 31					December 31
($ millions)	2009			2008		2009			2008
Net earnings (GAAP measure)		598			31		1,099			450
Adjustments (after tax)
Restructuring the gold business		28			10		46			(20	)
Gain on sale of Centerra		(374	)		—		(374	)		—
Unrealized losses (gains) on financial instruments		(4	)		130		(189	)		166
Stock option expense (recovery)		—			2		—			(33	)
Investment writedowns		—			6		—			26
Adjusted net earnings (non-GAAP measure)		248			179		582			589

Discontinued operations

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

• We sold 88,618,472 common shares of Centerra through a public offering, at a price of $10.25 per share, for net proceeds of approximately $871 million.

• We transferred another 25,300,000 common shares of Centerra to Kyrgyzaltyn JSC (Kyrgyzaltyn), under our April 24, 2009 agreement with them and the Government of the Kyrgyz Republic.

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

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

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COMPANY UPDATES

McArthur River/Key Lake

In 2009, we completed a new freeze wall around zone 2, panel 5, developed the initial raisebore chamber tunnel and began production in the fourth quarter. This is the first time development has been accomplished through the unconformity into the Athabasca sandstone.

In lower zone 4, we completed the raisebore chamber on the 530 metre level, completed all freezehole drilling and began freezing the ground.

Rabbit Lake

We added mineral reserves, extending the expected production life by two years to 2015.

Inkai

We successfully commissioned the main processing plant and started commissioning of the first satellite plant in 2009.

We received final approval for the block 2 mining licence after the Resource Use Contract was amended. The mining licence for block 1 expires in 2024 and for block 2 expires in 2030.

Regulators extended the term of the block 3 exploration licence to the end of July 2010 after the Resource Use Contract was amended. Under Kazakh law, we have to achieve a commercial discovery to extend our licence beyond July 2010.

Cigar Lake

We remediated the 2008 inflow that forced us to temporarily suspend dewatering of the mine. We remotely placed an inflatable seal between the shaft and the source of the inflow then backfilled and sealed the entire area with concrete and grout.

We completed dewatering shaft 2 in April and remediation of the shaft in May. We resumed dewatering shaft 1 in October and crews entered the shaft in November. Work focused on refurbishing shaft 1 — installing the ladderway, replacing mechanical and electrical components and extending the in-shaft pumping system.

In February 2010, we completed dewatering the underground development. Crews re-entered the main working level of the mine 480 metres below the surface. Safe access to the 480 metre level has been established and work to inspect, assess and secure the underground development has begun. This work will be followed by restoration of underground mine systems and infrastructure in preparation for resumed construction activities.

We expect to complete work to secure the underground before October 2010, depending on the condition of the mine.

Cigar Lake’s construction licence was amended effective January 1, 2010, to extend the term for four years and to cover dewatering, remediation and construction activities, including completion of shaft 2 and surface construction.

As of December 31, 2009, we had:

• invested $470 million in capital to develop Cigar Lake

• expensed $64 million in remediation expenses, including $18 million in 2009

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The preliminary estimate of our share of the total capital costs to complete the Cigar Lake project is between $450 million and $550 million. This includes completing underground development and surface construction, and completing modifications at Rabbit Lake and McClean Lake mills.

Taking into account the $470 million that had been spent as at December 31, 2009, and assuming our estimate does not change, our share of the total capital cost estimate for Cigar Lake is between $920 million and $1.0 billion. Our capital cost estimate has increased primarily as a result of the longer period over which remediation and development will occur, additional costs for inflow abatement, increases in surface capital costs and improvements to the mine plan and water management systems. The technical report we plan to file at the end of the first quarter of 2010 will include our updated capital cost estimate.

In addition to capital costs, our share of the remaining remediation expenses is now expected to be $29 million. In 2010, we expect to spend $25 million on remediation expenses.

We are now targeting initial production to begin in mid-2013, based on current information.

We updated our reserve and resource estimates in 2009 as required by industry standards based on information gathered to the end of the year.

Cigar Lake reserves and resources

	2009						2008						Changes
	tonnes				lbs		tonnes				lbs		lbs
Cameco’s share	(thousand)		%U3O8		(million)		(thousand)		%U3O8		(million)		(million)
Proven reserves		65.25		25.6		36.9		248.50		20.7		113.2		(76.3	)
Probable reserves		213.40		14.4		67.8		—		—		—		67.8
Total P+P		278.65		17.0		104.7		248.50		20.7		113.2		(8.5	)
Measured resources		4.20		2.1		0.2		—		—		—		0.2
Indicated resources		7.80		2.4		0.4		30.60		4.9		3.3		(2.9	)
Total M+I		12.00		2.3		0.6		30.60		4.9		3.3		(2.7	)
Inferred resources		240.20		12.6		66.8		158.50		16.9		59.1		7.7

The changes are mainly from:

• re-interpretation of the mineralized envelopes on the east end of the deposit

• block modelling in 3D (we used a 2D model in 2007)

• revised mine layout and dilution assumptions

• recategorization of the resources and reserves

These factors contributed to the decreases in total contained pounds of U₃O₈ in the reserves and in the estimated average grade.

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Our share of reserves went from 113 million pounds in 2008 to 105 million pounds. Our review of the mineral resource and reserve classification resulted in 35% of reserves being classified as proven, compared to 100% previously. The classification is based on drill hole spacing, geological continuity, grade continuity, estimation confidence and the anticipated ability to successfully recover all of the ore.

The costs to complete Cigar Lake and our target dates for securing the underground and for initial production are forward-looking information. They are based on the assumptions and subject to the material risks discussed under the heading “Caution Regarding Forward-looking Information and Statements”, and specifically on the assumptions and risks listed here.

Assumptions

• natural phenomena or an equipment failure do not cause a material delay or disrupt our plans

• there are no additional water inflows

• the seals used for previous water inflows do not fail

• there are no labour disputes

• we obtain contractors, equipment, operating parts and supplies, and regulatory permits and approvals when required

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, the delay in obtaining the required contractors, equipment, operating parts or supplies, or other reasons cause a material delay or disruption in our plans

QUALIFIED PERSONS

The disclosure of scientific and technical information regarding the following Cameco properties in this news release were prepared by or under the supervision of the following qualified persons for the purpose of National Instrument 43-101:

	Qualified Persons	Properties
•	Alain G. Mainville, director, mineral resources management, Cameco	McArthurRiver/Key Lake
•	David Bronkhorst, general manager, Cameco
•	Greg Murdock, technical superintendent, Cameco
•	Lorne D. Schwartz, chief metallurgist, Cameco
•	Les Yesnik, general manager, Cameco
•	Alain G. Mainville, director, mineral resources management, Cameco	Inkai
•	Charles J. Foldenauer, deputy general director, operations, Inkai,
•	Alain G. Mainville, director, mineral resources management, Cameco	Cigar Lake
•	Grant J.H. Goddard, general manager, Cigar Lake, Cameco
•	C. Scott Bishop, chief mine engineer, Cigar Lake, Cameco
•	Lorne D. Schwartz, chief metallurgist, Cameco

Alain G. Mainville, director, mineral resources management, oversees and co-ordinates the estimation of mineral reserves and resources by Cameco’s qualified persons, and reports to management and the board’s reserve oversight committee.

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CAUTION REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

This press release includes statements and information about our expectations for the future. When we discuss our strategy, plans and future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and United States securities laws. These statements typically include words and phrases about the future, such as: anticipate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook. They represent our current views, and can change significantly. We have based these statements on a number of material assumptions, including those we have listed below, which may prove to be incorrect. Actual results and events may be significantly different from what we currently expect, because of the risks associated with our business. We list a number of these material risks below. We recommend you also review our annual information form and 2009 annual MD&A, which include a discussion of other material risks that could cause actual results to differ significantly from our current expectations. Forward-looking information is designed to help you understand management’s current views of our near and longer-term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

Examples of forward-looking information in this press release include: production at our uranium operations from 2010 to 2014, and our target of doubling annual uranium production by 2018; our ability to reach expected annual production at McArthur River and Key Lake within the timeframes we have set, to complete remediation and begin production at Cigar Lake within the timeframes we have set and at the estimated cost, and to achieve our annual production targets at Inkai; our expectations that our existing cash balances and operating cash flows will be sufficient to meet our anticipated requirements over the next several years without the need for any significant additional financing; future production at our fuel services operations; future tax rates; our long-term uranium price sensitivity analysis; the outlook for each of our operating segments for 2010, and our consolidated outlook for the year.

The material risks that could cause actual results to vary include: actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor; we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates; production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms; our estimates of production, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate; we are unable to enforce our legal rights, or are subject to litigation or arbitration that has an adverse outcome; there are defects in title to our properties; our reserve and resource estimates are inaccurate, or we face unexpected or challenging geological, hydrological or mining conditions; we are affected by environmental, safety and regulatory risks, including increased regulatory burdens; we cannot obtain or maintain necessary permits or approvals from government authorities; we are affected by political risks in a developing country where we operate (like Kazakhstan); we are affected by terrorism, sabotage, accident or a deterioration in political support for, or demand for, nuclear energy; there are changes to government regulations or policies, including tax and trade laws and policies; our uranium and conversion suppliers fail to fulfill delivery commitments; we are affected by natural phenomena including inclement weather, fire, flood, underground floods, earthquakes, pitwall failure and cave-ins; our operations are disrupted because of problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour relations issues, strikes or lockouts and other developments and operating risks.

We have made material assumptions regarding: 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 in connection with our long-term price sensitivity analysis for uranium; tax rates, foreign currency exchange rates and interest rates; decommissioning and reclamation expenses; reserve and resource estimates; the geological, hydrological and other conditions at our mines, including the accuracy of our expectations about the condition of underground workings at Cigar Lake; our ability to continue to supply our products and services in the expected quantities and at the expected times; our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals; our operations are not significantly disrupted because of political instability, nationalization, terrorism, sabotage, natural disasters, governmental or political actions, litigation or arbitration proceedings, labour relations issues and other development or operating risks.

QUARTERLY DIVIDEND NOTICE

Cameco announced today that the company’s board of directors approved a quarterly dividend of $0.07 per share on the outstanding common shares of the corporation that is payable on April 15, 2010, to shareholders of record at the close of business on March 31, 2010.

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CONFERENCE CALL

We invite you to join our fourth quarter conference call on Thursday, February 25, 2010 at 9:30 a.m. Eastern.

The call will be open to all investors and the media. Management will discuss the financial results, the outlook for 2010 and company developments before opening the call to questions from investors and the media.

To join the call, please dial (416) 340-8018 or (866) 223-7781 (Canada and US). An operator will put your call through. A live audio feed of the conference call will be available from a link at cameco.com 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, Wednesday, March 24, 2010 by calling (416) 695-5800 or (800) 408-3053 (Passcode 1853874 #)

ADDITIONAL INFORMATION

A full copy of Cameco’s 2009 annual MD&A, annual audited financial statements and reconciliation to United States GAAP can be obtained on SEDAR at sedar.com, on EDGAR at sec.gov/edgar.shtml and the company’s website at cameco.com.

PROFILE

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

		- End -
Investor inquiries:	Bob Lillie	(306) 956-6639
Media inquiries:	Lyle Krahn	(306) 956-6316

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