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Management’s discussion and analysis

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited consolidated financial statements and notes for the quarter ended September 30, 2010. The information is based on what we knew as of November 5, 2010 and updates our first and second quarter MD&A and annual MD&A included in our 2009 annual report.

As you review this MD&A, we encourage you to read our unaudited consolidated financial statements and notes for the period ended September 30, 2010 as well as our audited consolidated financial statements and notes for the year ended December 31, 2009 and annual MD&A of the audited financial statements. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making a decision to invest in our securities.

Unless we have specified otherwise, all dollar amounts are in Canadian dollars. The financial information in this MD&A and in our financial statements and notes are prepared according to Canadian generally accepted accounting principles (Canadian GAAP), unless otherwise indicated. We also prepared a reconciliation of our annual financial statements to US GAAP, which has been filed with securities regulatory authorities.

About forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans, future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A as forward-looking information.

Key things to understand about the forward-looking information in this MD&A:

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It typically includes words and phrases about the future, such as: anticipate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples on page 2).

•

It represents our current views, and can change significantly.

•

It is based on a number of material assumptions, including those we’ve listed below, which may prove to be incorrect.

•

Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review our annual information form and our 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.

2010 Third quarter report 1

Examples of forward-looking information in this MD&A

•

production at our uranium operations from 2010 to 2014 and our target for doubling annual production by 2018

•

our expectations about future worldwide uranium supply and demand

•

our expectation that delivery patterns for uranium and fuel services will be similar to 2009, with deliveries in the fourth quarter accounting for about a third of our 2010 sales volume

•

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 our existing cash balances and operating cash flows will meet our anticipated requirements over the next several years without the need for any significant additional financing

•

our expectation that our cash balances will decline gradually as we use the funds in our business and to pursue our growth plans

•

the outlook for each of our operating segments for 2010, and our consolidated outlook for the year

•

our expectation that our plans to double annual uranium production by 2018 will not be impacted by the reduction in our 2010 planned capital expenditures

•

our expectation that our operating and investment activities in 2010 will not be constrained by the financial covenants in our general credit facilities

•

our expectation that our unit costs will rise in the fourth quarter due to receipt of additional purchased material

•

our uranium price sensitivity analysis

•		our mid-2013 target for initial production from Cigar Lake and our 2010 Cigar Lake plans

•		the discussion of the expected impact of IFRS on our financial statements, internal control over financial reporting and disclosure controls and procedures, our business activities in general, and our estimate of IFRS opening balances and interim period financial results

Material risks

•

actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor

•

we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates

•

production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms

•

our estimates of production, purchases, 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 or delays in Australia, Canada, Kazakhstan or the US

•

we cannot obtain or maintain necessary permits or approvals from government authorities

•

we are affected by political risks in a developing country where we operate

•

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

•

there are changes to government regulations or policies, including tax and trade laws and policies

•

our suppliers of purchased uranium and conversion fail to fulfil contract delivery commitments

•

delay or lack of success in remediating and developing Cigar Lake

•

we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes

•

our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour relations issues, strikes or lockouts, underground floods, pitwall failure, cave-ins and other developments and operating risks

•

new IFRS standards or changes in the standards or their interpretation

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Material assumptions

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sales and purchase volumes and prices for uranium, fuel services and electricity

•

expected production costs

•

expected spot prices and realized prices for uranium, and other factors discussed on page 18, Price sensitivity analysis: uranium

•

tax rates, foreign currency exchange rates and interest rates

•

decommissioning and reclamation expenses

•

reserve and resource estimates

•

the geological, hydrological and other conditions at our mines, including the accuracy of our expectations about the condition of underground workings at Cigar Lake

•

our Cigar Lake remediation and development plans succeed

•

our ability to continue to supply our products and services in the expected quantities and at the expected times

•

our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals in Australia, Canada, Kazakhstan or the US

•		our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, labour relations issues, underground floods, or other development or operating risks

•		our IFRS related forecasts are not significantly impacted by new IFRS standards or changes in the standards or their interpretation or changes in our policy choices

2010 Third quarter report 3

Third quarter update

Cameco is well positioned as the world becomes increasingly focused on nuclear as a source of clean, reliable and affordable energy. We are among the world’s largest players in a market where demand is growing.

Our vision is to be a dominant nuclear energy company producing uranium fuel and generating clean electricity.

We are already one of the largest uranium producers in the world, and when we sold our gold segment late last year, became a pure-play nuclear energy investment.

Our strategy is to double annual uranium production to 40 million pounds by 2018, which we plan to accomplish with our existing operating and development properties, and other projects already in our portfolio. Our fuel services segment is helping to support this growth by broadening our business relationships and expanding our uranium market share. And our investment in the Bruce Power Limited Partnership is an excellent source of earnings and cash flow.

You can read more about our strategy in our 2009 annual MD&A.

We have the financial strength to advance our growth plans. In our 2009 annual MD&A we talked about our plans to increase expenditures, both capitalized and expensed, to achieve our growth strategy. We are steadfastly focused on the long-term, spending prudently today for greater benefit tomorrow.

Our performance

In 2009, we sold all of our shares of Centerra Gold Inc. (Centerra).

For comparison purposes, we have recast our consolidated financial results for 2008 and 2009 (presented in this document) to show the impact of Centerra as a discontinued operation, which is required under Canadian GAAP. The change affected a number of financial measures, including revenue, gross profit, administration costs and income tax expense. See note 12 to the financial statements for more information.


			Three months ended								Nine months ended
Highlights			September 30								September 30
($ millions except where indicated)			2010			2009		change			2010		2009		change

Revenue				419			518		(19	)%		1,450		1,656		(12	)%

Gross profit				152			149		2	%		499		544		(8	)%

Net earnings				98			172		(43	)%		308		501		(39	)%

$ per common share (diluted)				0.25			0.44		(43	)%		0.78		1.29		(40	)%

Adjusted net earnings (non-GAAP, see page 9)				80			94		(15	)%		305		358		(15	)%

$ per common share (adjusted and diluted)				0.20			0.24		(17	)%		0.77		0.92		(16	)%

Cash provided by operations (after working capital changes)				(18	)		175		(110	)%		387		502		(23	)%

Average realized prices		$US/lb		40.63			34.24		19	%		41.46		37.26		11	%
	Uranium	$Cdn/lb		43.01			39.18		10	%		43.90		45.80		(4	)%

	Fuel services	$Cdn/kgU		16.32			16.82		(3	)%		18.19		19.85		(8	)%

	Electricity	$Cdn/MWh		57.00			66.00		(14	)%		58.00		64.00		(9	)%

Third quarter

Net earnings this quarter were $98 million ($0.25 per share diluted) compared to $172 million ($0.44 per share diluted) in the third quarter of 2009. In addition to the items noted below, our net earnings were impacted by a stronger Canadian dollar. Our after-tax unrealized mark-to-market gains on financial instruments were $29 million compared to $94 million in the third quarter of 2009.

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On an adjusted basis, our earnings this quarter were $80 million ($0.20 per share diluted) compared to $94 million ($0.24 per share diluted) (non-GAAP, see page 9) in the third quarter of 2009. The decline was due to:

•

lower profits from our electricity businesses due to lower realized prices and higher costs

•

higher exploration expenditures

Partially offset by:

•

higher profits from our uranium business due to lower costs and higher $Cdn realized selling prices

•

higher profits from our fuel services business due to higher sales volumes and lower costs

See Financial results by segment for more detailed discussion.

First nine months

Net earnings in the first nine months of the year were $308 million ($0.78 per share diluted) compared to $501 million ($1.29 per share diluted) in the first nine months of 2009. In addition to the items noted below, our net earnings were impacted by lower after-tax unrealized mark-to-market gains on financial instruments, $16 million compared to $147 million in 2009. While the Canadian dollar strengthened slightly in the first nine months of 2010, it strengthened to a much greater extent in the same period of 2009.

On an adjusted basis, our earnings for the first nine months of this year were $305 million ($0.77 per share diluted) compared to $358 million ($0.92 per share diluted) (non-GAAP, see page 9). The decline was due to:

•

lower earnings from our uranium business due to lower sales volumes and lower $Cdn realized prices. Despite an 11% increase in our $US realized uranium prices, the stronger Canadian dollar year-over-year led to a 4% decline in $Cdn realized prices. Our exchange rate averaged $1.06 compared to $1.23 a year ago.

•

lower profits in our electricity business due to lower realized prices

•

higher exploration expenditures, particularly in Australia and Kazakhstan

Partially offset by:

•

higher profits from our fuel services business due to higher sales volumes and lower costs

See Financial results by segment for more detailed discussion.

Operations update


		Three months ended							Nine months ended
Highlights		September 30							September 30
September 30		2010		2009		change			2010		2009		change

Uranium	Production volume (million lbs)		5.6		5.6		—			16.5		14.1		17	%

	Sales volume (million lbs)		5.6		8.3		(33	)%		20.5		23.9		(14	)%

	Revenue ($ millions)		244		329		(26	)%		912		1,108		(18	)%

Fuel services	Production volume (million kgU)		2.3		4.1		(44	)%		11.7		8.4		39	%

	Sales volume (million lbs)		3.9		2.8		39	%		10.7		8.9		20	%

	Revenue ($ millions)		69		50		38	%		208		186		12	%

Electricity	Output (100%) (TWh)		6.3		6.2		2	%		19.3		18.2		6	%

	Revenue (100%)		363		458		(21	)%		1,116		1,218		(8	)%

	Our share of earnings before taxes ($ millions)		37		78		(53	)%		115		162		(29	)%

Production in our uranium segment this quarter was the same as in the third quarter of 2009 and 17% higher for the first nine months of this year.

2010 third quarter report 5

We expect uranium production will be 22 million pounds this year compared to our previous estimate of 21.5 million pounds, with increased production at Rabbit Lake and Inkai. See Uranium — production overview for details.

As announced on November 1, 2010, unionized employees at McArthur River and Key Lake agreed to a new four-year collective agreement that expires on December 31, 2013. The new contract includes a 14.75% wage increase over the term of the agreement.

At Cigar Lake, we have decided to implement a surface freeze strategy we expect will:

•

shorten the ramp up period for the project by bringing forward uranium production (up to 10 million pounds) into the early years

•

improve mining costs and project economics

Production in our fuel services segment decreased by 44% this quarter compared to 2009 primarily due to the planned annual maintenance shutdown of the Port Hope UF₆ plant, which operated throughout the third quarter of 2009. Production for the first nine months of the year increased by 39%, largely due to the routine operation of the Port Hope UF₆ plant, which did not operate for most of the first half of 2009.

In our electricity segment, BPLP’s generation was 2% higher for the quarter and 6% higher for the first nine months, compared to the same periods last year. The capacity factor this quarter was 88%, and 90% for the first nine months of the year.

Uranium market update

Of note this quarter:

The United States Enrichment Corporation (USEC) sold approximately 0.6 million pounds U₃O₈ equivalent at the end of September. The United States Department of Energy (DOE) made the material available to USEC in return for the accelerated cleanup work at the Portsmouth gaseous diffusion plant. This was the fourth sale in 2010 and brings the total DOE material provided to the market this year to about 2.4 million pounds U₃O₈ equivalent.

Industry prices


	Sept 30		June 30		Mar 31		Sept 30		June 30		Mar 31
	2010		2010		2010		2009		2009		2009

Uranium ($US/lb U₃O₈)¹
Average spot market price		46.63		41.75		41.88		42.88		51.50		42.00
Average long-term price		61.00		59.00		59.00		64.50		65.00		69.50


Fuel services ($US/kgU UF₆)¹

Average spot market price
• North America		13.00		7.00		5.63		6.25		7.00		8.50
• Europe		12.50		7.88		7.50		8.25		8.50		9.75

Average long-term price
• North America		13.13		11.25		11.00		11.75		12.25		12.25
• Europe		13.50		12.75		12.75		13.13		13.38		13.38

Note: the industry does not publish UO₂prices.

Electricity ($/MWh)
Average Ontario electricity spot price		43.00		34.00		34.00		22.00		23.00		43.00

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

On the spot market, where purchases call for delivery within one year, the volume reported for the third quarter of 2010 was about 13.3 million pounds U₃O₈. This is ahead of the 11.2 million pounds purchased in the third quarter of

6 cameco corporation

2009. For the first nine months of the year, spot purchases totalled 36 million pounds compared to 43.5 million pounds for the same period in 2009.

Spot uranium prices trended up during the quarter. Since the end of July, the spot price has followed a pattern of increases followed by moderate decreases. This resulted in an overall higher price as market activity picked up and sellers looked for higher prices. Demand in the spot market continues to be discretionary.

Long-term uranium prices rose to $61.00 (US) per pound during the quarter. Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices adjusted by inflation indices, and market referenced prices (spot and long-term indicators).

Utilities are well covered under existing contracts and have been building inventory levels of U₃O₈ since 2004. We expect uranium demand in the near term to be somewhat discretionary.

Spot market UF₆ conversion prices increased significantly this quarter. The increase is being attributed to the loss of production caused by a labour dispute at a uranium conversion facility in the US. Long-term UF₆ conversion prices also increased this quarter due to increased demand for UF₆ conversion.

Long-term fundamentals are strong

People need electricity regardless of world economic conditions, and nuclear power is an affordable and sustainable source of clean, reliable energy. The demand for uranium is expected to continue to grow, and along with it, the need for new supply to meet future customer requirements.

Cameco’s long history of success comes from many years of hard work and discipline, developing and acquiring the expertise and assets that position us well to deliver on our strategy. As the momentum behind nuclear energy grows, so will our success.

Shares and stock options outstanding

At November 5, 2010, we had:

•

393,493,749 common shares and one Class B share outstanding

•

8,474,864 stock options outstanding, with exercise prices ranging from $5.75 to $55.00

Dividend policy

Our board of directors has established a policy of paying a quarterly dividend of $0.07 ($0.28 per year) per common share. This policy will be reviewed from time to time based on our cash flow, earnings, financial position, strategy and other relevant factors.

2010 third quarter report 7

Financial results

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


2010 Q3 results
Consolidated financial results			8
Outlook for 2010			14
Liquidity and capital resources			15

Financial results by segment			17
Uranium			17
Fuel services			20
Electricity			21

Consolidated financial results

In 2009, we sold all of our shares of Centerra Gold Inc. (Centerra).


	Three months ended								Nine months ended
Highlights	September 30								September 30
($ millions except per share amounts)	2010			2009		change			2010		2009		change

Revenue		419			518		(19	)%		1,450		1,656		(12	)%

Net earnings		98			172		(43	)%		308		501		(39	)%

$ per common share (basic)		0.25			0.44		(43	)%		0.78		1.30		(40	)%

$ per common share (diluted)		0.25			0.44		(43	)%		0.78		1.29		(40	)%

Adjusted net earnings (non-GAAP, see page 9)		80			94		(15	)%		305		358		(15	)%

$ per common share (adjusted and diluted)		0.20			0.24		(17	)%		0.77		0.92		(16	)%

Cash provided by operations (after working capital changes)		(18	)		175		(110	)%		387		502		(23	)%

Net earnings

Net earnings this quarter were $98 million ($0.25 per share diluted) compared to $172 million ($0.44 per share diluted) in the third quarter of 2009 due to:

•

lower after-tax unrealized mark-to-market gains on financial instruments, $29 million compared to $94 million in the third quarter of 2009 due to a stronger Canadian dollar

•

lower earnings from our electricity business due to a decline in realized prices and higher costs

•

higher exploration expenditures

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Net earnings in the first nine months of the year were $308 million ($0.78 per share diluted) compared to $501 million ($1.29 per share diluted) in the first nine months of 2009 due to:

•

lower after-tax unrealized mark-to-market gains on financial instruments, $16 million compared to $147 million in 2009. While the Canadian dollar strengthened slightly in the first nine months of 2010, it strengthened to a much greater extent in the same period of 2009.

•

lower earnings from our uranium business due to lower sales volumes and lower $Cdn realized prices. Despite a 11% increase in our $US realized uranium prices, the stronger Canadian dollar year-over-year led to a 4% decline in $Cdn realized prices. Our exchange rate averaged $1.06 compared to $1.23 a year ago.

•

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

•

higher exploration expenditures, particularly in Australia and Kazakhstan

Adjusted net earnings (non-GAAP measure)

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

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						Nine months ended
	September 30						September 30
($ millions)	2010			2009			2010			2009

Net earnings (GAAP measure)		98			172			308			501

Adjustments (after tax)

Losses from discontinued operations		—			23			—			42

Unrealized gains on financial instruments		(18	)		(101	)		(3	)		(185	)

Adjusted net earnings (non-GAAP measure)		80			94			305			358

2010 third quarter report 9

The tables that follow describe what contributed to the changes in adjusted net earnings and revenue this quarter and for the first nine months of the year.


Change in adjusted net earnings		Three months ended			Nine months ended
($ millions)		September 30			September 30

Adjusted net earnings — 2009			94			358

Change in gross profit by segment (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation, depletion and reclamation (DDR))

Uranium	Lower sales volumes		(23	)		(51	)
	Higher (lower) realized prices ($Cdn)		21			(39	)
	Lower costs		34			56

	change — uranium		32			(34	)

Fuel services	Higher sales volumes		2			8
	Lower realized prices ($Cdn)		(2	)		(18	)
	Lower costs		5			23

	change — fuel services		5			13

Electricity	Higher sales volumes		2			10
	Lower realized prices ($Cdn)		(33	)		(56	)
	Lower (higher) costs		(3	)		13

	change — electricity		(34	)		(33	)

Other changes
Exploration expense			(25	)		(35	)
Realized gains on derivatives & foreign exchange			24			45
Reduced losses from associated companies			—			14
Income taxes			(10	)		(32	)
Miscellaneous			(6	)		9

Adjusted net earnings — 2010			80			305

Revenue


Change in revenue	Three months ended			Nine months ended
($ millions)	September 30			September 30

Revenue — 2009		518			1,656

Uranium

Lower sales volumes		(106	)		(157	)

Higher (lower) realized prices ($Cdn)		21			(39	)

Fuel services

Higher sales volumes		18			40

Lower realized prices ($Cdn)		(2	)		(18	)

Electricity

Higher sales volumes		2			20

Lower realized prices ($Cdn)		(32	)		(52	)

Revenue — 2010		419			1,450

See Financial results by segment for more detailed discussion.

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Average realized prices


		Three months ended							Nine months ended
		September 30							September 30
		2010		2009		change			2010		2009		change

	$US/lb		40.63		34.24		19	%		41.46		37.26		11	%

Uranium	$Cdn/lb		43.01		39.18		10	%		43.90		45.80		(4	)%

Fuel services	$Cdn/kgU		16.32		16.82		(3	)%		18.19		19.85		(8	)%


Electricity	$Cdn/MWh		57.00		66.00		(14	)%		58.00		64.00		(9	)%

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. We expect the trend in delivery patterns in 2010 to be similar to 2009, with deliveries in the fourth quarter accounting for about a third of our 2010 sales volume.

Quarterly trends


Highlights						2010								2009		2008
($ millions except per share amounts)	Q3			Q2		Q1		Q4		Q3		Q2		Q1		Q4

Revenue		419			546		485		659		518		646		493		640

Net earnings		98			68		142		598		172		247		82		31

$ per common share (basic)		0.25			0.17		0.36		1.52		0.44		0.63		0.22		0.08

$ per common share (diluted)		0.25			0.17		0.36		1.52		0.44		0.63		0.22		0.08

Adjusted net earnings (non-GAAP, see page 9)		80			114		111		169		94		162		103		179

$ per share diluted		0.20			0.29		0.28		0.43		0.24		0.41		0.27		0.49

Earnings from continuing operations		98			68		142		174		195		269		78		5

$ per common share (basic)		0.25			0.17		0.36		0.44		0.49		0.69		0.21		0.01

$ per common share (diluted)		0.25			0.17		0.36		0.44		0.49		0.69		0.21		0.01

Cash provided by operations		(18	)		272		133		188		175		147		180		224

Key things to note:

•

Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 58% of consolidated revenues in the third quarter of 2010.

•

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

•

Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our results from period to period (see page 9 for more information).

•

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

•

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

2010 third quarter report 11

Administration


	Three months ended				Nine months ended
	September 30				September 30
($ millions)	2010		2009		2010		2009

Direct administration		35		31		94		83

Stock-based compensation		5		2		7		11

Total administration		40		33		101		94

Direct administration costs were $35 million this quarter, or $4 million higher than the same period last year. Through the first nine months of 2010, our direct administration costs were 13% higher than in 2009. These increases are in line with our previous guidance and reflect the costs necessary for evaluating and pursuing growth opportunities including:

•

increased hiring

•

studies and analysis of various opportunities

Exploration

Uranium exploration expenses were $35 million this quarter compared to $11 million in the same quarter in 2009, as activity in Canada, Kazakhstan and at the Kintyre project in Australia increased. Exploration expenses in the first nine months of the year increased to $68 million from $33 million in 2009. Exploration in 2010 is focused on Canada, the United States, Mongolia, Kazakhstan, Australia and South America.

Gains and losses on derivatives

We recorded $39 million in mark-to-market gains on our financial instruments this quarter, compared to gains of $129 million in the third quarter of 2009. In the first nine months of the year, we recorded $22 million in mark-to-market gains on our financial instruments compared to $201 million in 2009. While the Canadian dollar strengthened slightly in the first nine months of 2010, it strengthened significantly in the first nine months of 2009.

Income taxes

In the third quarter of 2010, we recorded an income tax expense of $8 million compared to $28 million in the third quarter of 2009. The decline this quarter was mainly due to a $121 million decrease in pretax earnings, which was largely attributable to the decline in gains we recorded on derivatives compared to 2009.

On an adjusted basis, we recorded an income tax expense of $1 million this quarter compared to a net recovery of $9 million in the third quarter of 2009. During the third quarter of 2009, we obtained reasonable assurance that certain qualifying expenditures under investment tax credit programs would ultimately be realized and accordingly, we began to recognize the expected benefits in our financial results.

Our effective tax rate in this quarter on an adjusted net earnings basis was 1% compared to a recovery of 11% for the third quarter of 2009.

In the first nine months of 2010, we recorded an income tax expense of $15 million compared to $50 million in 2009. The decline in 2010 was mainly due to a $276 million decrease in pretax earnings, which was largely attributable to the decline in gains we recorded on derivatives compared to 2009. Lower earnings from the uranium and electricity businesses also contributed to the decline in income tax expense.

On an adjusted basis, we recorded a net income tax expense of $13 million in the first nine months of 2010 compared to a net recovery of $18 million in 2009. The increase in expense this year was mainly due to a change in the distribution of our taxable income. We earned a higher proportion of taxable income in jurisdictions with higher tax rates in the first nine months of this year.

Our effective tax rate on an adjusted earnings basis was 4% compared to a recovery of 5% in 2009.

12 cameco corporation

Foreign exchange

At September 30, 2010:

•

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.03 (Cdn), down from $1.00 (US) for $1.06 (Cdn) at June 30, 2010. The exchange rate averaged $1.00 (US) for $1.04 (Cdn) over the quarter.

•

We had foreign currency contracts of $1.6 billion (US) and EUR 98 million at September 30, 2010. The US currency contracts had an average exchange rate of $1.00 (US) for $1.04 (Cdn).

•

The mark-to-market gain on all foreign exchange contracts was $4 million compared to a $26 million loss at June 30, 2010. We received cash of $7 million this quarter and $86 million for the first nine months of the year related to the settlement of foreign exchange contracts.

Sensitivity analysis

At September 30, 2010, every one-cent change in the value of the Canadian dollar versus the US dollar would change our net earnings by about $12 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.03 (Cdn).

2010 third quarter report 13

Outlook for 2010

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, 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 decline gradually as we use the funds in our business and to pursue our growth plans.

Our outlook for 2010 reflects the growth expenditures necessary to help us achieve our strategy. Our outlook for uranium production, fuel services production, consolidated capital expenditures and capital expenditures for electricity has changed from the outlook in our second quarter MD&A. We explain the material changes below. All other items in the table are unchanged. We do not provide outlook for the items in the table that are marked with a dash.

See Financial results by segment for details.


	Consolidated	Uranium	Fuel services	Electricity

Production	—	22 million lbs	15 to 16 million kgU	—

Sales volume	—	30 million lbs	Increase 15% to 20%	—

Capacity factor	—	—	—	About 90%

Revenue compared to 2009	Decrease 5% to 10%	Decrease 10% to 15%¹	Increase 5% to 10%	Decrease 5% to 10%

Unit cost of product sold (including DDR)	—	Decrease 5% to 10%²	—	Increase less than 5%

Direct administration costs compared to 2009³	Increase 20% to 25%	—	—	—

Exploration costs compared to 2009	—	Increase 90% to 100%	—	—

Tax rate	Less than 5%	—	—	—

Capital expenditures	$475 million⁴	—	—	$36 million


¹		Based on a uranium spot price of $53.50 (US) per pound (the Ux spot price as of November 1, 2010) and an exchange rate of $1.00 (US) for $1.01 (Cdn).

²		Assumes the unit cost of sale for produced material will decline by 5% to 10% relative to 2009 and the unit cost of sale for purchased material will decline by 10% to 15%.

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

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

We expect uranium production to be 22 million pounds this year, compared to our previous estimate of 21.5 million pounds, with increased production at Rabbit Lake and Inkai. See Uranium 2010 Q3 Updates — Operating properties for details.

We expect capital expenditures to be about $475 million in 2010, compared to our previous estimate of $510 million due to changes in the scheduling of some projects. We do not expect this reduction in capital expenditures in 2010 will impact our plans to double annual uranium production by 2018.

14 cameco corporation

Sensitivity analysis

For the rest of 2010:

•

a change of $5 (US) from the Ux spot price on November 1, 2010 ($53.50 (US) per pound) would change revenue by $13 million and net earnings by $10 million

•

a change of $1 in the electricity spot price would change our 2010 net earnings by $1 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)

Liquidity and capital resources

Cash from operations

Cash from operations was $193 million lower this quarter than in 2009 due to much higher working capital requirements. Working capital changes required $142 million, primarily from an increase in accounts receivable and uranium inventories during the quarter. In 2009, working capital consumed $23 million in cash largely due to increases in accounts receivable and product inventories. Not including working capital requirements, our operating cash flows this quarter were down by $74 million, largely due to lower uranium sales volumes and a lower realized price for electricity. See Financial results by segment for details.

Cash from operations was $115 million lower for the first nine months of 2010 than for the same period in 2009 mainly due to higher working capital requirements relating to increased inventory levels and a reduction in accounts payable. Not including working capital requirements, our operating cash flows in the first nine months of this year were down by $12 million.

Debt

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1.2 billion at September 30, 2010, compared to $1.1 billion at June 30, 2010. Our short-term borrowing and letters of credit facilities increased by about $19 million this quarter. At September 30, 2010, we had approximately $548 million outstanding in letters of credit.

Credit ratings

Third-party ratings for our commercial paper and senior debt as of September 30, 2010:


Security	DBRS	S&P

Commercial paper	R-1 (low)	A-1 (low)¹

Senior unsecured debentures	A (low)	BBB+


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

Debt covenants

We are bound by certain covenants in our general credit facilities. The financially related covenants place restrictions on total debt, including guarantees, and set minimum levels of net worth. As at September 30, 2010, we met these financial covenants and do not expect our operating and investment activities in 2010 to be constrained by them.

2010 third quarter report 15

Long-term contractual obligations and off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at September 30, 2010:

•

purchase commitments

•

financial assurances

There have been no material changes to our long-term contractual obligations, purchase commitments and financial assurances since December 31, 2009, including payments due for the next five years and thereafter. Our long-term contractual obligations do not include our sales commitments. Please see our annual MD&A for more information.

Balance sheet


($ millions except per share amounts)	Sept 30, 2010		Dec 31, 2009		change

Cash and short-term investments		1,270		1,304		(3	)%

Total debt		1,032		1,041		(1	)%

Inventory		514		453		13	%

Total cash and short-term investments at September 30, 2010 were $1,270 million, or 3% lower than at December 31, 2009, exceeding our total debt by $238 million.

Total debt declined by $9 million to $1,032 million at September 30, 2010. Of this total, $88 million was classified as current, unchanged compared to December 31, 2009. See notes 10 and 11 of our audited annual financial statements for more detail.

Total product inventories increased by 13% to $514 million. This is the result of higher uranium inventory, as sales were lower than production and purchases in the first nine months of the year.

16 cameco corporation

Financial results by segment

Uranium


	Three months ended							Nine months ended
	September 30							September 30
Highlights	2010		2009		change			2010		2009		change

Production volume (million lbs)		5.6		5.6		—			16.5		14.1		17	%

Sales volume (million lbs)		5.6		8.3		(33	)%		20.5		23.9		(14	)%

Average spot price ($US/lb)		45.83		45.29		1	%		43.01		46.10		(7	)%
Average realized price
($US/lb)		40.63		34.24		19	%		41.46		37.26		11	%
($Cdn/lb)		43.01		39.18		10	%		43.90		45.80		(4	)%

Average unit cost of sales ($Cdn/lb U₃O₈) (including DDR)		24.36		30.67		(21	)%		27.74		30.72		(10	)%

Revenue ($ millions)		244		329		(26	)%		912		1,108		(18	)%

Gross profit ($ millions)		101		69		46	%		322		356		(10	)%

Gross profit (%)		41		21		95	%		35		32		9	%

Third quarter

Production volumes this quarter were the same as in the third quarter in 2009.

Uranium revenues this quarter were down 26% compared to 2009, due to a 33% decline in sales volumes.

Our realized prices this quarter were higher than the third quarter of 2009 mainly due to higher prices under fixed-price sales contracts.

Total cash cost of sales (excluding DDR) decreased by 53% this quarter, to $100 million ($17.55 per pound U₃O₈). This was mainly the result of the following:

•

the 33% decline in sales volume

•

average unit costs for produced uranium were 31% lower

•

average unit costs for purchased uranium were 29% lower due to fewer purchases at spot prices

•

royalty charges were lower due to lower deliveries of produced material

The net effect was a $32 million increase in gross profit for the quarter.

Our average unit cost of sales for uranium was much lower in the third quarter than in the first six months of 2010. We expect that the average unit cost will rise in the fourth quarter due to receipt of additional purchased material. Our average unit cost reflects purchases once the material is received. We calculate our total cost of sales based on the average cost of all purchased and produced uranium.

First nine months

Production volumes for the first nine months of the year were 17% higher than in the previous year due to higher production at almost all our sites. See Operating properties for more information.

For the first nine months of 2010, uranium revenues were down 18% compared to 2009, due to a 14% decline in sales volumes and a 4% decrease in our $Cdn realized price. Our exchange rate averaged $1.06 compared to $1.23 a year ago. In $US, our realized price was 11% higher than in 2009 mainly due to the mix of contracts into which we delivered uranium. So far this year, deliveries have been more heavily weighted toward market related contracts, which yielded higher prices than our fixed price contracts.

2010 third quarter report 17

Total cash cost of sales (excluding DDR) decreased by 27% in the first nine months of the year, to $466 million ($22.45 per pound U₃O₈). This was mainly the result of the following:

•

average unit costs for produced uranium were 13% lower due to higher production levels

•

average unit costs for purchased uranium were 19% lower due to fewer purchases at spot prices

•

sales volumes were 14% lower

•

lower royalty charges

The net effect was a $34 million decrease in gross profit for the first nine months.

The following table shows our cash cost of sales per unit (excluding DDR) for produced and purchased material, including royalty charges on produced material, and the quantity of produced and purchased uranium sold.


	Unit cash cost of sale							Quantity sold
Three months ended	($Cdn/lb U₃O₈)							(million lbs)
September 30	2010		2009		change			2010		2009		change

Produced		17.85		25.85		(8.00	)		3.5		6.2		(2.7	)

Purchased		17.05		23.87		(6.82	)		2.1		2.1		—

Total		17.55		25.36		(7.81	)		5.6		8.3		(2.7	)


Nine months ended
September 30	2010		2009		change			2010		2009		change

Produced		22.54		25.84		(3.30	)		14.5		15.8		(1.3	)

Purchased		22.22		27.50		(5.28	)		6.0		8.1		(2.1	)

Total		22.45		26.39		(3.94	)		20.5		23.9		(3.4	)

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 has been updated to reflect deliveries made and contracts entered into up to September 30, 2010. It is designed to indicate how the portfolio of long-term contracts we had in place on September 30, 2010 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on September 30, 2010, and none of the assumptions listed on the following page 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		41		42		44		46		48		51		53

2011		34		39		47		53		61		68		75

2012		35		38		47		56		65		73		82

2013		42		45		54		64		74		84		92

2014		43		46		56		65		75		85		93

The table illustrates the mix of long-term contracts in our September 30, 2010 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 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.

18 cameco corporation

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)


	Three months ended							Nine months ended
	September 30							September 30
Highlights	2010		2009		change			2010		2009		change

Production volume (million kgU)		2.3		4.1		(44	)%		11.7		8.4		39	%

Sales volume (million kgU)		3.9		2.8		39	%		10.7		8.9		20	%

Realized price ($Cdn/kgU)		16.32		16.82		(3	)%		18.19		19.85		(8	)%

Average unit cost of sales ($Cdn/kgU) (including DDR)		13.84		15.43		(10	)%		13.70		15.86		(14	)%

Revenue ($ millions)		69		50		38	%		208		186		12	%

Gross profit ($ millions)		9		4		125	%		49		36		36	%

Gross profit (%)		13		7		86	%		24		20		20	%

Third quarter

Total revenue increased by 38% due to a 39% increase in sales volumes.

Our $Cdn realized price for UF₆ was affected by a less favourable exchange rate. Our exchange rate averaged $1.06 in the third quarter compared to $1.14 in 2009.

The total cost of products and services sold (including DDR) increased by 28% ($60 million compared to $47 million in the third quarter of 2009) due to the increase in sales volume. The average unit cost of sales was 10% lower due largely to lower costs for purchased material.

The net effect was a $5 million increase in gross profit.

First nine months

In the first nine months of the year, total revenue increased by 12% due to a 20% increase in sales volumes.

Our $Cdn realized price for UF₆ was affected by a less favourable exchange rate. Our exchange rate averaged $1.06 compared to $1.23 last year at this time.

The total cost of products and services sold (including DDR) increased by 7% ($159 million compared to $149 million in 2009) as the impact of the increase in sales volume was largely offset by a lower cost per unit sold. The average unit cost of sales was 14% lower as we allocated costs related to the UF₆ plant to inventory during the first nine months of this year. In 2009, we expensed the majority of these costs, due to the plant having been shut down throughout most of the first half.

The net effect was a $13 million increase in gross profit.

20 cameco corporation

Electricity

BPLP

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


	Three months ended								Nine months ended
Highlights	September 30								September 30
($ millions except where indicated)	2010		2009			change			2010		2009		change

Output — terawatt hours (TWh)		6.3		6.2			2	%		19.3		18.2		6	%

Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		88		86			2	%		90		86		5	%

Realized price ($/MWh)		57		66			(14	)%		58		64		(9	)%

Average Ontario electricity spot price ($/MWh)		43		22			95	%		38		29		31	%

Revenue		363		458			(21	)%		1,116		1,218		(8	)%

Operating costs(net of cost recoveries)		224		210			7	%		709		687		3	%

Cash costs		187		176			6	%		601		587		2	%
Non-cash costs		37		34			9	%		108		100		8	%

Income before interest and finance charges		139		248			(44	)%		407		531		(23	)%

Interest and finance charges		16		(4	)		n/a			30		3		n/a

Cash from operations		130		206			(37	)%		497		525		(5	)%

Capital expenditures		24		34			(29	)%		72		83		(13	)%

Distributions		100		120			(17	)%		405		390		4	%

Operating costs ($/MWh)		36		30			20	%		37		36		3	%

Our earnings from BPLP


	Three months ended									Nine months ended
Highlights	September 30									September 30
($ millions except where indicated)	2010			2009			change			2010			2009			change

BPLP’s earnings before taxes (100%)		123			252			(51	)%		377			528			(29	)%

Cameco’s share of pretax earnings before adjustments (31.6%)		39			80			(51	)%		119			167			(29	)%

Proprietary adjustments		(2	)		(2	)		—			(4	)		(5	)		20	%

Earnings before taxes from BPLP		37			78			(53	)%		115			162			(29	)%

Third quarter

Total electricity revenue decreased 21% this quarter compared to the third quarter of 2009 as higher output was more than offset by lower realized prices. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $41 million this quarter under its agreement with the OPA, compared to $205 million in the third quarter of 2009. The equivalent of about 46% of BPLP’s output was sold under financial contracts this quarter, compared to 51% in the third quarter of 2009.

The capacity factor was 88% this quarter, up from 86% in the third quarter of 2009 due to fewer planned and unplanned outage days. Operating costs were $224 million compared to $210 million in 2009.

The result was a 53% decrease in our share of earnings before taxes.

2010 third quarter report 21

BPLP distributed $100 million to the partners in the third quarter. Our share was $32 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

First nine months

Total electricity revenue for the first nine months of the year decreased 8% compared to 2009, as higher output was more than offset by lower realized prices. BPLP recognized revenue of $224 million under its agreement with the OPA in the first nine months of 2010, compared to $377 million for the same period in 2009. The equivalent of about 41% of BPLP’s output was sold under financial contracts in the first nine months of this year, compared to 58% in 2009.

The capacity factor was 90% for the first nine months of this year, up from 86% in 2009 due to fewer planned and unplanned outage days. Operating costs were $709 million compared to $687 million in 2009.

The result was a 29% decrease in our share of earnings before taxes.

BPLP distributed $405 million to the partners in the nine months of this year. Our share was $128 million.

22 cameco corporation

Our operations and development projects

Uranium — production overview

Production this quarter was the same as in the third quarter of 2009 and 17% higher for the first nine months of the year.

Uranium production


	Three months ended							Nine months ended
Cameco’s share	September 30							September 30
(million lbs U₃O₈)	2010		2009		change			2010		2009		change

McArthur River/Key Lake		3.7		3.8		(3	)%		9.9		9.3		6	%

Rabbit Lake		0.5		0.9		(44	)%		2.5		2.4		4	%

Smith Ranch-Highland		0.4		0.4		—			1.4		1.3		8	%

Crow Butte		0.2		0.2		—			0.6		0.6		—

Inkai		0.8		0.3		167	%		2.1		0.5		320	%

Total		5.6		5.6		—			16.5		14.1		17	%

See Uranium 2010 Q3 updates — Operating properties for details.

Outlook

Our sources of production are diversified both geographically and geologically. As outlined below, we expect production to total 116 million pounds of U₃O₈ over the next five years. Our strategy is to double our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and other projects already in our portfolio.

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		3.7		3.6		3.6		3.6		3.0

US ISR		2.5		2.5		3.1		3.1		3.7

Inkai		2.7		3.1		3.1		3.1		3.1

Cigar Lake		—		—		—		1.0		2.0

Total		22.0		22.3		22.9		23.9		24.9

Inkai requires government approval and the support of our partner, Kazatomprom, in order to produce at the forecast annual rate of 5.2 million pounds of U₃O₈ (our share 3.1 million pounds). We believe that it is reasonably likely that Inkai will receive these confirmations.

2010 Third quarter report 23

________________________

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on page 2, 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, Cigar Lake remediation and development plans succeed, processing plants function and our mineral reserve estimates are accurate

•

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

•

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

Material risks that could cause actual results to differ materially

•

we do not achieve forecast production levels for each operation due to a change in our mining plans, delay or lack of success in remediating and developing Cigar Lake, processing plant availability, lack of tailings capacity or for other reasons

•

we cannot obtain or maintain necessary permits or government approvals

•

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

24 cameco corporation

Uranium 2010 Q3 updates

Operating properties

McArthur River/Key Lake

Production update

Production increased for the first nine months of the year largely as a result of a shorter maintenance shut-down and improved startup at the Key Lake mill in the second quarter compared to 2009 and strong ore supply from McArthur River. We are beginning to see the benefits from our focus on reliability and maintenance over the last few years.

Operations update

At Key Lake, the mill continues to operate well.

Construction is on schedule for the acid and oxygen plants. We finished installing structural steel and plan to winterize the buildings in the fourth quarter. We installed all major equipment in the acid plant and are in the process of installing mechanical piping.

We received regulatory approval for development of a second raisebore chamber in zone 2, panel 5 and an extraction chamber in the lower mining area of zone 4. We continue to expect first production from the lower mining area of zone 4 in 2010.

Rabbit Lake

Production update

Production this quarter was 44% below the same quarter in 2009. As planned, the mill operated for a shorter period than in the third quarter of 2009 resulting in lower production. Production in the first nine months was slightly higher than last year. We expect to see large variations in mill production from quarter to quarter as we manage ore supply to ensure efficient operation of the mill. We expect production for the year will be 3% higher than our previous estimate of 3.6 million pounds.

Operations update

We completed the scheduled mill maintenance shutdown this quarter, and the mill returned to normal operations on September 1, 2010. We repaired and replaced equipment and infrastructure throughout the mill. At the Eagle Point mine, we installed and commissioned a new exhaust air raise, which will support future activities in the northern part of the mine.

2010 Third quarter report 25

Smith Ranch-Highland and Crow Butte

Production update

Production remains on schedule.

Operations update

At Smith Ranch-Highland, we no longer expect regulatory approval for the Reynolds Ranch expansion in the second half of 2010. The regulators have indicated they have a large volume of permits to process, therefore approval of our expansion is not expected to occur until late in 2011. We do not expect this delay to impact production.

Inkai

Production update

Completion of the processing facilities and a stable acid supply resulted in higher production for both the quarter and first nine months of the year compared to the same periods in 2009.

We have increased our 2010 production forecast by 17%, from our previous estimate of 2.3 million pounds. The increase reflects strong wellfield performance in the first nine months of the year and 2009 uranium inventories at Inkai being processed this year.

Operations update

In mid-June Inkai received approval in principle to increase annual production from blocks 1 and 2 to 3.9 million pounds U₃O₈ (100% basis), which is in line with Inkai’s production target for 2010. An amendment to the subsoil use contract to implement this is progressing through the Kazakh government approval process.

We continue to work with Kazatomprom to evaluate opportunities aimed at cooperating on UF₆ conversion.

Development project

Cigar Lake

This quarter we:

•

substantially completed clean up, inspection, assessment and securing of the underground development areas

•

completed freeze drilling and outfitting of the freeze holes at shaft 2, as part of our preparations to resume shaft sinking

•

progressed remediation of the underground brine handling system to support freezing of the orebody and shaft 2

•

increased pumping capacity to 2,500 m³/hr

•

began backfilling of the 465 metre level

Our activities for the remainder of 2010 will focus on carrying out our plans and implementing the strategies we have identified to move Cigar Lake towards production. Our plans include:

•

continuing to restore the underground mine systems, infrastructure and underground development areas so we can resume construction

•

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

•

beginning to freeze the ground around shaft 2 in preparation to resume shaft sinking

•

implementing a surface freeze strategy we expect will shorten the ramp up period for the project by bringing forward uranium production (up to 10 million pounds) into the early years and improve mining costs and project economics

•

continuing the surface drilling program designed to upgrade mineral resources

26 cameco corporation

We continue to target initial production in mid-2013.

Cigar Lake is a key part of our plan to double annual uranium production to 40 million pounds by 2018, and we are committed to bringing this valuable asset safely into production.

Projects under evaluation

We continue to advance the Kintyre and Millennium projects toward development decisions.

Fuel services 2010 Q3 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc. (CFM)

Springfields Fuels Ltd. (SFL)

Fuel services production totalled 2.3 million kgU this quarter, compared to 4.1 million kgU in the third quarter of 2009. Lower production was primarily due to the planned annual maintenance shutdown of the Port Hope UF₆ plant, which operated throughout the third quarter of 2009.

Production for the first nine months of the year was 11.7 million kgU compared to 8.4 million kgU in the first nine months of 2009. Higher production is largely due to the routine operation of the Port Hope UF₆ plant, which did not operate for most of the first half of 2009.

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) was prepared under the supervision of the following individuals who are qualified persons for the purposes of NI 43-101.

McArthur River/Key Lake

•

David Bronkhorst, vice-president, Saskatchewan mining south, Cameco

•

Les Yesnik, general manager, Key Lake, Cameco

Inkai

•

Charles Foldenauer, general manager operations and development, Inkai

Cigar Lake

•

Grant Goddard, vice-president, Saskatchewan mining north, Cameco

2010 Third quarter report 27

Additional information

Related party transactions

We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In the first nine months of 2010, we paid PACL $19.0 million for construction and contracting services (2009 — $21.6 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

Controls and procedures

As of September 30, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of September 30, 2010, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New accounting pronouncements

International financial reporting standards (IFRS)

The Accounting Standards Board requires Canadian publicly accountable enterprises to adopt IFRS effective January 1, 2011. Although IFRS has a conceptual framework that is similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosure.

We have developed a three-phase implementation plan that will ensure compliance and a smooth transition.

Senior management and the board’s audit committee are actively involved in the process. A major public accounting firm has been engaged to provide technical accounting advice and project management guidance.

Phase 1: Preliminary study and diagnostic — complete

During this phase, we:

•

completed a high-level impact assessment

•

prioritized areas to evaluate in phase 2

•

developed a detailed plan for convergence and implementation

•

determined which information technology systems need to be modified to meet IFRS reporting requirements.

We tested and implemented systems modifications by June 30, 2009.

28 cameco corporation

Phase 2: Detailed component evaluation — complete

During this phase, we:

•

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

•

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

•

specified all changes we needed to make to existing business processes

Phase 3: Embedding — in progress

During this final phase, we will:

•

carry out the changes to our business processes

•

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

•

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

•

communicate the impact of the IFRS transition to external stakeholders

•

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

•

receive the board’s approval of the new statements

Progress update

During the quarter, we continued to evaluate key accounting policy alternatives and implementation decisions, but have not yet fully completed our analysis of all accounting effects of adopting IFRS. We have quantified the majority of items in our January 1, 2010 opening balances and earnings for the three month periods ended March 31, 2010 and June 30, 2010 under IFRS subject to changes in IFRS standards or their interpretation. See Opening balances and interim period financial results under IFRS for more information about the most significant differences expected between our Canadian GAAP and IFRS balances.

Senior management and the audit committee have approved our IFRS accounting policies, but IFRS standards are evolving and may be different at the time of transition. The International Accounting Standards Board (IASB) has several projects underway that could affect the differences between Canadian GAAP and IFRS. For example, we expect that the standards for consolidation, liabilities, discontinued operations, financial instruments, employee benefits and joint ventures could change before we adopt IFRS, and that IFRS for income taxes may change at a later date. It is also possible that new guidance regarding accounting for borrowing costs may be issued and could impact our current accounting treatment on transition. We have been monitoring and evaluating these changes, and our analysis incorporates the standards we expect to be in effect at the time of transition.

We currently expect IFRS may affect our consolidated financial statements in the following key areas:

Asset impairment

We use a two-step approach to test for impairment under Canadian GAAP:

•

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

•

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

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

•

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

The difference in accounting for asset impairment could lead to greater volatility in our reported earnings in future periods. The value-in-use test uses discounted future cash flows, thereby increasing the likelihood of asset impairment relative to the undiscounted cash flow test applied under Canadian GAAP. Furthermore, IFRS requires companies to reverse impairment losses (for everything except goodwill) if an impairment is reduced due to a change in circumstances. Canadian GAAP does not allow companies to reverse impairment losses. Our analysis to date

2010 Third quarter report 29

indicates that we are unlikely to record significant impairment charges on transition to IFRS. We do, however, anticipate reversing portions of impairment charges previously recorded under Canadian GAAP. See Opening balances and interim period financial results under IFRS for more information.

Employee benefits

We amortize past service costs on a straight-line basis over the expected average remaining service life of the plan participants under Canadian GAAP.

IAS 19, Employee Benefits, requires companies to expense the past service cost component of defined benefit plans on an accelerated basis. Vested past service costs must be expensed immediately. Unvested past service costs must be recognized on a straight-line basis until the benefits vest. Companies will also recognize actuarial gains and losses directly in equity rather than through profit or loss.

IFRS 1, First-Time Adoption of International Financial Reporting Standards, also allows companies to recognize all cumulative actuarial gains and losses in retained earnings at the transition date.

Share-based payments

We measure cash-settled, share-based payments to employees based on the intrinsic value of the award under Canadian GAAP. IFRS 2, Share-Based Payments, requires companies to measure payments at the award’s fair value, both initially and at each reporting date.

We expect no material impact on our financial results due to this difference.

Provisions (Including asset retirement obligations)

IAS 37, Provisions, Contingent Liabilities and Contingent Assets, requires companies to recognize a provision when:

•

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

•

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

•

the obligation can be reliably estimated

Canadian GAAP uses the term “likely” in its recognition criteria, which is a higher threshold than “probable”, so some contingent liabilities may be recognized under IFRS that were not recognized under Canadian GAAP.

IFRS also measures provisions differently. For example:

•

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

•

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

Joint ventures

We proportionately account for interests in jointly controlled enterprises, such as our interest in BPLP, under Canadian GAAP. The IASB has indicated that it expects to issue a new standard in 2010 that will replace IAS 31 Interests in Joint Ventures. It is considering Exposure Draft 9, Joint Arrangements (ED 9), which proposes that an entity recognize its interest in a joint controlled enterprise using the equity method.

We expect to use the equity method to account for our joint venture interests when we transition to IFRS.

Income taxes

Under Canadian GAAP, we cannot recognize deferred tax for a temporary difference that arises from intercompany transactions. We record the taxes we pay or recover in these transactions as an asset or liability, and then recognize them as a tax expense when the asset leaves the group or is otherwise used. IAS 12 requires entities to recognize deferred taxes for temporary differences that arise from intercompany transactions, and to recognize taxes paid or recovered in these transactions in the period incurred.

The IASB may address these differences in a fundamental review of income tax accounting at some time in the future, but this review is not likely to be soon.

Convertible debentures

30 cameco corporation

Under Canadian GAAP, our convertible debentures, issued in 2003 and redeemed in 2008, were treated as a compound instrument with a debt and equity component. We measured the debt component at amortized cost using the effective interest rate method, while the equity component was measured at the issue date using the residual method with no future changes in value recognized.

Under IFRS, we have concluded that these convertible debentures cannot be accounted for as compound instruments under IAS 32. The accounting for the debt component is unchanged, but we have concluded that the conversion feature is to be accounted for as a derivative under IFRS. A derivative is required to be measured at fair value at each reporting date with changes in value being recorded in earnings. For purposes of our IFRS transition, we have measured the fair value of the conversion feature as at the redemption date and recorded an increase in share capital offset by a corresponding decrease in retained earnings.

Given the significant increase in value of the conversion option as a result of increases in the stock price of Cameco between the date of issuance and the date of redemption, a reclassification between retained earnings and share capital has been recorded in the amount of $297 million.

Exploration expenses

Under Canadian GAAP, we charge expenditures for geological exploration programs to earnings as incurred. Once the decision to proceed to development has been made, subsequent exploration and development expenditures related to the project are then capitalized.

IFRS 6, Exploration for and Evaluation of Mineral Resources, allows companies to either capitalize or expense costs incurred during the exploration and evaluation phase. Geological activities are considered to be classified as exploration and evaluation during the time between obtaining the legal rights to explore a specific area and the completion of a commercially viable technical feasibility study. IFRS 6 requires entities to select and consistently apply an accounting policy specifying which expenditures are capitalized and which are expensed.

On transition to IFRS, we plan to maintain our current accounting policy of expensing all costs relating to exploration and evaluation as they are incurred. As we do under Canadian GAAP, we will capitalize costs once we have determined that a property has economically recoverable reserves. No adjustments are required on transition to IFRS.

2010 Third quarter report 31

First-time adoption of IFRS

IFRS 1 generally requires an entity to apply IFRS retrospectively at the end of its first IFRS reporting period, but there are some mandatory exceptions and some optional exemptions.

We have analyzed the options available to us and currently expect to use the exemptions in the table below. This is a summary of the changes we currently believe will be most significant when we transition to IFRS — it is not a complete list of changes we will be required or may elect to make. We have completed our analyses on a preliminary basis but have not yet made final decisions about the accounting policies that are available. We have quantified the majority of the expected impacts of these differences on our consolidated financial statements.


Business combinations		We will have the option to apply IFRS 3, Business Combinations, retrospectively or prospectively. We plan to apply IFRS 3 prospectively to all business combinations that occurred before the transition date, except as required under IFRS 1.

Fair value as deemed cost		We will be able to choose to use the fair value of property, plant and equipment as deemed cost at the transition date, or to use the value determined under GAAP. We plan to use the historical bases under Canadian GAAP as deemed cost at the transition date.

Share-based payments		We will be able to apply IFRS 2, Share-Based Payments, to all equity instruments granted on or before November 7, 2002, and to those granted after November 7, 2002 only if they had not vested by the transition date. We plan to apply IFRS 2 to all equity instruments granted after November 7, 2002 that had not vested as of January 1, 2010, and to all liabilities arising from share-based payment transactions that existed at January 1, 2010.

Borrowing costs		We will be able to choose to apply IAS 23, Borrowing Costs retrospectively, using a date we specify, or to capitalize borrowing costs for all qualifying assets when capitalization begins on or after January 1, 2010. We plan to apply IAS 23 prospectively. For all qualifying assets, we will expense the borrowing costs we were capitalizing before January 1, 2010, and capitalize the borrowing costs that take effect on or after that date.

Employee benefits		IAS 19, Employee Benefits, requires entities to defer or amortize certain actuarial gains and losses, subject to certain provisions (corridor approach), or to immediately recognize them in equity. We plan to recognize cumulative actuarial gains and losses on benefit plans in retained earnings at the transition date.

Differences in currency translation		IAS 21, The Effects of Changes in Foreign Exchange Rates, will require us to calculate currency translation differences retrospectively, from the date we formed or acquired a subsidiary or associate. IFRS 1 gives us the option of resetting cumulative translation gains and losses to zero at the transition date. We plan to reset all cumulative translation gains and losses to zero in retained earnings at the transition date.

Decommissioning liabilities		We will have the option of applying International Financial Reporting Interpretations Committee 1 (IFRIC 1), Changes in Existing Decommissioning, Restoration and Similar Liabilities, retrospectively or prospectively. IFRIC 1 will require us to add or deduct a change in our obligations to dismantle, remove and restore items of property, plant and equipment, from the cost of the asset it relates to. The adjusted amount is then depreciated prospectively over the asset’s remaining useful life. We plan to adopt IFRIC 1 prospectively at the transition date.

32 cameco corporation

Opening balances and interim period financial results under IFRS

The following tables present our current estimates of the most significant differences in our IFRS balances as at January 1, 2010 and between our Canadian GAAP and IFRS earnings for the three month periods ended March 31, 2010 and June 30, 2010. This information reflects our most recent views, assumptions and expectations. However, circumstances may arise, such as changes in IFRS standards or interpretations of existing IFRS standards, which could alter the information presented below.

This is a summary of the changes we currently believe will be most significant when we transition to IFRS — it is not a complete list of changes we will be required or may elect to make.

The notes referenced in the tables are explained by the corresponding notes at the end of the tables.

Opening balances


Accounting	Balance sheet	Change
difference	category	($ millions)
Impairment reversal¹	Property, plant & equipment		35

Decommissioning liabilities²	Provisions		55
	Property, plant & equipment		(55	)

Borrowing costs³	Property, plant & equipment		(330	)

Cumulative translation adjustment⁴	Cumulative translation adjustment		(50	)

Employee benefits⁵	Long-term investments, receivables & other		(15	)

Joint venture accounting⁶	Property, plant & equipment		(450	)
	Long-term debt		(170	)
	Other liabilities		(145	)

In-process research & development (IPR&D)⁷	Investments in equity-accounted investees		20

Convertible debentures⁸	Share capital		297

Income taxes⁹	Deferred tax liabilities		(135	)

Amounts closed to retained earnings¹⁰	Retained earnings		(740	)

Net change in shareholders’ equity¹¹	Shareholders’ equity		(390	)

2010 Third quarter report 33

Interim period financial results


Changes in earnings	Three months ended			Three months ended
($ millions)	March 31, 2010			June 30, 2010
Net earnings — Canadian GAAP		143			68


Accounting differences
Borrowing costs³		(10	)		(10	)
Decommissioning provision²		(3	)		(3	)
In-process research & development⁷		3			3
Maintenance costs — BPLP¹²		—			8
Income taxes — tax effect on differences⁹		3			1
Income taxes — IFRS accounting difference⁹		6			—
All other		1			2

Total accounting differences		—			1

Net earnings — IFRS		143			69

Adjustments
Unrealized losses (gains) on financial instruments		(31	)		46

Adjusted net earnings (non-GAAP measure)		112			115


¹		IFRS requires the reversal of any previously recorded impairment losses where circumstances have changed such that the impairments have been reduced. We reviewed our previously recorded impairment losses and reversed a portion of the charges relating to certain of our in situ recovery mine assets located in the United States.

²		We plan to elect under IFRS 1 to apply IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities prospectively to changes in decommissioning liabilities that occurred prior to January 1, 2010. There are no new liabilities recognized as a result of the transition to IFRS. However, the measurement of existing liabilities according to the IFRS standards will provide a different result. At January 1, 2010, the effect would be a $55 million increase in provisions, a $55 million decrease in property, plant and equipment and a $110 million decrease in retained earnings.

		Canadian GAAP requires the unwinding of the discount (accretion) to be recorded as an operating cost and allocated to inventory whereas IFRS requires accretion to be reflected as a financing cost. The net result in the interim periods was an increase in reported expenses with a corresponding decrease in product inventories.

³		We plan to elect under IFRS 1 not to apply IAS 23, Borrowing Costs retrospectively to borrowing costs incurred on the construction of qualifying assets that commenced prior to January 1, 2010. Accordingly, we plan to expense all borrowing costs that had been previously capitalized under Canadian GAAP. New guidance from the IASB is pending and it is possible that our accounting may change as a result.

⁴		We plan to elect under IFRS 1 to deem all foreign currency translation differences that exist at the date of transition to IFRS to be zero at the date of transition.

⁵		We plan to elect under IFRS 1 to reclassify all cumulative actuarial gains and losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date.

⁶		Under IFRS, we expect to account for our interests in joint ventures that are constituted as a legal entity using the equity method. Under Canadian GAAP, Cameco’s 31.6% interest in BPLP was accounted for using proportionate consolidation. This change to the equity method has a significant impact on certain of our balance sheet categories.

⁷		Under IFRS, IPR&D that meets the definition of an intangible asset is capitalized with amortization commencing when the asset is ready for use (i.e. when development is complete). Under Canadian GAAP, we have been

34 cameco corporation


		amortizing IPR&D related to the acquisition of our interest in Global Laser Enrichment LLC, a development stage entity.

		For the interim periods, we reversed the full amount amortized under Canadian GAAP.

⁸		Under IFRS, we have concluded that our convertible debentures issued in 2003 and settled in 2008 will be treated as a hybrid instrument with a debt component and a conversion feature to be accounted for as a derivative. A derivative is required to be measured at fair value at each reporting date with changes in value being recorded in earnings. For purposes of our IFRS transition, we have measured the fair value of the conversion feature as at the redemption date and recorded a $297 million increase in share capital offset by a corresponding decrease in retained earnings.

⁹		As a result of the changes in our opening balances on transition to IFRS, we expect to reduce our deferred tax liabilities by approximately $135 million.

		For the interim periods, the adjustments relating to income tax expense reflect the tax effects of other adjustments as well as an IFRS accounting difference related to intra-group transactions. Under IFRS, deferred tax assets and liabilities are recognized for intra-group transactions whereas Canadian GAAP allows for the recognition of deferred tax assets and liabilities only when the transaction is with a third party.

¹⁰		Many of the foregoing changes are closed to retained earnings. We currently expect to reduce our retained earnings amount by approximately $740 million on transition to IFRS. This reduction is largely attributable to the changes to borrowing costs and convertible debentures.

¹¹		Certain adjustments to retained earnings are the result of changes in other components of shareholders’ equity. Thus, the net change in total shareholders’ equity is expected to be significantly lower than the change in retained earnings.

¹²		Under IFRS the costs of major inspections are capitalized and amortized over the period to the next inspection. Under Canadian GAAP, we have been expensing the inspection costs related to our interest in BPLP.

Other updates

As we proceed with our transition, we are also assessing the impact on our internal controls over financial reporting, and on our disclosure controls and procedures. Changes in accounting policies or business processes require the implementation of additional controls or procedures to ensure the integrity of our financial disclosures. We have substantially completed the design of the necessary new controls and testing is ongoing. We do not, however, anticipate any significant changes to be required in our internal control over financial reporting or our disclosure controls and procedures as a result of the transition to IFRS.

We conducted several educational and training sessions for our audit committee and the board of directors in 2009 and 2010. During these sessions, management and external advisors provided the board with detailed background information on IFRS accounting standards (including IFRS 1 elections), the implications of policy choices on our financial reporting, and a preliminary view of the expected format and content of our financial statements and notes upon transition. Management gives the audit committee quarterly project status updates and presentations.

We began training management and accounting staff in 2008. Training is being delivered mainly by external advisors, and focusing on the accounting issues most relevant to Cameco. Sessions will continue throughout 2010. As a result, we are confident there is sufficient expertise within the organization to allow us to effectively transition to IFRS.

Our transition plan includes the need to inform key external stakeholders about the anticipated impact of the IFRS transition on our financial reporting. In 2009, we provided an information update as part of our investor day presentations. We are planning further communications with the investment community in the fourth quarter of 2010.

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

2010 third quarter report 35


Third quarter update			4

Financial results			8

Our operations and development projects			23

Qualified persons			27

Additional information			28