Exhibit 99.2

EX-99.2 3 d253986dex992.htm EXHIBIT 99.2 Exhibit 99.2

Exhibit 99.2

LOGO

Management’s discussion and analysis

for the quarter ended September 30, 2011


Third quarter update			4

Financial results			9

Our operations and development projects			23

Qualified persons			28

Additional information			28

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

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 condensed consolidated interim financial statements and notes for the quarter ended September 30, 2011 (interim financial statements). The information is based on what we knew as of November 4, 2011 and updates our first and second quarter MD&A and annual MD&A included in our 2010 annual financial report.

As you review the MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2010 and annual MD&A of the audited consolidated 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 an investment decision about our securities.

Effective January 1, 2011, we adopted International Financial Reporting Standards (IFRS) for Canadian publicly accountable enterprises. Our interim financial statements for the first, second and third quarters of 2011 have been prepared using IFRS. Amounts relating to the year ended December 31, 2010 in this MD&A and our interim financial statements have been recast to reflect our adoption of IFRS. Amounts for periods prior to January 1, 2010 are presented in accordance with Canadian Generally Accepted Accounting Principles (Canadian GAAP).

Financial information provided in this MD&A and our interim financial statements has been prepared using IFRS standards and interpretations currently issued and expected to be effective at the end of our first annual IFRS reporting period, which will be December 31, 2011. However, certain accounting policies may not be adopted or the application of such policies to certain transactions or circumstances may be modified. As a result, financial information contained in this MD&A and our interim financial statements is subject to change.

Presentation and terminology used in our interim financial statements and this MD&A differ from that used in previous years. Details of the more significant accounting differences can be found in note 3 to our interim financial statements.

To help you distinguish and understand the impact of the transition to IFRS on our interim financial statements, where we refer to “Canadian GAAP” in this MD&A, we mean Canadian GAAP before the adoption of IFRS.

Unless we have specified otherwise, all dollar amounts are in Canadian dollars.

2011 THIRD QUARTER REPORT 1

Caution about forward-looking information

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

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

•

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

•

It represents our current views, and can change significantly.

•

It is based on a number of material assumptions, including those we have listed on page 3, 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 on page 3. 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.

Examples of forward-looking information in this MD&A

•

our expectations about 2011 and future global uranium supply, consumption, demand and number of operating reactors, including the discussion on the expected impact resulting from the March 2011 nuclear incident in Japan

•

our strategy for doubling annual production by 2018 to 40 million pounds is on track and our expectation that existing cash balances and operating cash flows will meet anticipated requirements without the need for any significant additional funding

•

our expectation that uranium demand in the near term will remain discretionary

•

the outlook for each of our operating segments for 2011, and our consolidated outlook for the year

•

our expectation that fourth quarter deliveries will account for over one-third of 2011 sales volumes

•

our expectation that we will invest significantly in expanding production at existing mines and advancing projects as we pursue our growth strategy

•

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

•

our expectation that we will have a solid revenue stream for years to come, even in the event of declining uranium market prices

•

our expectation that our operating and investment activities for the remainder of 2011 will not be constrained by the financial covenants in our unsecured revolving credit facility

•

our uranium price sensitivity analysis

•

forecast production at our uranium operations from 2011 to 2015

•

our future plans for each of our uranium operating properties, development projects and projects under evaluation, and fuel services operating sites

•

our mid-2013 target for initial production from Cigar Lake

2 CAMECO CORPORATION

Material risks

•

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

•

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

•

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

•

our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate

•

we are unable to enforce our legal rights under our existing agreements, permits or licences, or are subject to litigation or arbitration that has an adverse outcome

•

there are defects in, or challenges to, title to our properties

•

our mineral reserve and resource estimates are inaccurate, or we face unexpected or challenging geological, hydrological or mining conditions

•

we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays

•

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

•

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

•

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

•

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

•

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

•

our uranium and conversion suppliers fail to fulfil delivery commitments

•

we are delayed or do not succeed in remediating and developing Cigar Lake

•

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

•

our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, tailings dam failures, and other development and operating risks

Material assumptions

•

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

•

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

•

our expected production costs

•

our expectations regarding spot prices and realized prices for uranium, and other factors discussed on page 18 & 19, Price sensitivity analysis: uranium

•

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

•

our decommissioning and reclamation expenses

•

our mineral reserve and resource estimates

•

the geological, hydrological and other conditions at our mines

•

our Cigar Lake remediation, development and production plans succeed

•

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

•

our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals

•

our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, tailings dam failure, lack of tailings capacity, or other development or operating risks

2011 THIRD QUARTER REPORT 3

Our strategy

Our strategy to double annual uranium production to 40 million pounds by 2018 is on track. We are preparing our assets to ensure we have the flexibility to respond appropriately to evolving market conditions. We remain confident in the long-term fundamentals of the nuclear industry, despite near- to medium-term uncertainty. World demand for safe, clean, reliable and affordable energy continues to grow and the need for nuclear as part of the world’s energy mix remains as compelling as ever.

We continue to focus on cost-competitiveness and operational efficiency, including in our fuel services business. We are exploring options to extend the operating life of the four B units at Bruce Power.

Our extraordinary assets, extensive portfolio of long-term sales contracts, employee expertise and comprehensive industry knowledge provide us with the confidence and financial stability to pursue our corporate growth strategy.

Third quarter update

Our performance


Highlights ($ millions except where indicated)			Three months ended September 30								Nine months ended September 30
Highlights ($ millions except where indicated)			2011		2010			change			2011		2010		change
Revenue				527		419			26	%		1,407		1,450		(3	)%
Gross profit				179		156			15	%		423		519		(18	)%
Net earnings				39		98			(60	)%		186		311		(40	)%
$ per common share (diluted)				0.10		0.25			(60	)%		0.47		0.79		(41	)%
Adjusted net earnings (non-IFRS/GAAP measure, see pages 10 & 11)				104		80			30	%		259		307		(16	)%
$ per common share (adjusted and diluted)				0.26		0.20			30	%		0.66		0.78		(15	)%
Cash provided by operations (after working capital changes)				190		(5	)		3900	%		477		412		16	%
Average realized prices	Uranium	$US/lb		47.33		40.63			16	%		47.06		41.46		14	%
		$Cdn/lb		45.97		43.01			7	%		46.36		43.90		6	%
	Fuel services	$Cdn/kgU		17.42		16.32			7	%		18.05		18.19		(1	)%
	Electricity	$Cdn/MWh		54.00		57.00			(5	)%		54.00		58.00		(7	)%

Third quarter

Net earnings attributable to our shareholders (net earnings) this quarter were $39 million ($0.10 per share diluted) compared to $98 million ($0.25 per share diluted) in the third quarter of 2010. Net earnings were down this quarter primarily as a result of losses on foreign exchange derivatives compared to gains in 2010, partially offset by lower income taxes and the item noted below. The Canadian dollar weakened in the third quarter of 2011 relative to the US dollar, while it strengthened in the third quarter of 2010.

On an adjusted basis, our earnings this quarter were $104 million ($0.26 per share diluted) compared to $80 million ($0.20 per share diluted) (non-IFRS/GAAP measure, see pages 10 and 11) in the third quarter of 2010 mainly due to:

•

higher earnings from our uranium business based on higher sales volumes and higher realized prices, partially offset by an increase in the average cost of product sold

See Financial results by segment for more detailed discussion.

4 CAMECO CORPORATION

First nine months

Net earnings in the first nine months of the year were $186 million ($0.47 per share diluted) compared to $311 million ($0.79 per share diluted) in the first nine months of 2010. Net earnings were lower than in 2010 mainly as a result of the items noted below along with losses on foreign exchange derivatives compared to gains in 2010, partially offset by lower income taxes.

On an adjusted basis, our earnings for the first nine months of this year were $259 million ($0.66 per share diluted) compared to $307 million ($0.78 per share diluted) (non-IFRS/GAAP measure, see pages 10 and 11) mainly due to:

•

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

•

lower earnings from our uranium business based on an increase in the average cost of product sold and lower sales volumes, partially offset by an increase in the realized price

•

lower earnings from our fuel services business as a result of an increase in the average cost of product sold and lower realized prices

See Financial results by segment for more detailed discussion.

Operations update


Highlights		Three months ended September 30							Nine months ended September 30
Highlights		2011		2010		change			2011		2010		change
Uranium	Production volume (million lbs)		5.3		5.6		(5	)%		15.8		16.5		(4	)%
	Sales volume (million lbs)		7.2		5.6		29	%		19.1		20.5		(7	)%
	Revenue ($ millions)		332		240		38	%		885		901		(2	)%
Fuel services	Production volume (million kgU)		2.8		2.3		22	%		11.6		11.7		(1	)%
	Sales volume (million kgU)		4.6		3.9		18	%		11.1		10.7		4	%
	Revenue ($ millions)		81		64		27	%		199		195		2	%
Electricity	Output (100%) (TWh)		6.7		6.3		6	%		18.7		19.3		(3	)%
	Revenue (100%) ($ millions)		362		363		—			1,016		1,116		(9	)%
	Our share of earnings before taxes ($ millions)		35		36		(3	)%		75		123		(39	)%

Production in our uranium segment this quarter was down 5% compared to the third quarter of 2010 mainly due to lower production from Smith Ranch-Highland and Inkai. In the first nine months of the year uranium production was down 4% compared to 2010. We have revised our production outlook down 1% for the year due to lower expected production at our US and Inkai operations, partially offset by higher expected production at McArthur River/Key Lake. See Uranium 2011 Q3 updates for more information.

Key highlights:

•

signed a non-binding memorandum of understanding (MOU) to process all Cigar Lake ore at McClean Lake mill, which is expected to result in a significant reduction in the operating cost of the project. See page 26 for more information.

•

signed a memorandum of agreement (MOA) to increase production at Inkai from 3.9 to 5.2 million pounds (100% basis). See page 26 for more information.

Production in our fuel services segment was 22% higher this quarter than it was in the third quarter of 2010 due to the planned maintenance shutdown of the Port Hope UF₆ plant in 2010. Production for the first nine months of the year was 11.6 million kgU compared to 11.7 million kgU in 2010. Due to current unfavourable market conditions for UF₆ conversion, we are reducing production for this year. We now expect fuel services to produce between 14 million and 15 million kgU this year (previously 15 million to 16 million kgU).

2011 THIRD QUARTER REPORT 5

In our electricity segment, BPLP’s generation was 6% higher for the quarter and 3% lower for the first nine months of the year, compared to the same periods last year. The capacity factor this quarter was 93% and 87% for the first nine months of the year.

Also of note this quarter:

On August 30, 2011, we made an all-cash offer to acquire all the outstanding shares of Hathor Exploration Limited (Hathor) for a price of $3.75 per share in a transaction which values the fully diluted share capital of Hathor at approximately $520 million.¹

On October 19, 2011, Hathor announced that it had entered into an agreement with Rio Tinto pursuant to which Rio Tinto will make an offer for all of the common shares of Hathor. Rio Tinto subsequently made its offer.

We are reviewing the Hathor announcement and Rio Tinto offer. On October 31, 2011, we announced the extension of the expiry date of our offer to November 14, 2011.

Uranium market update

The uranium market during the third quarter can be characterized as uncertain. We expect this uncertainty to continue in the near to medium term as the industry continues to determine the extent to which short- to medium-term demand has been impacted by the March nuclear incident in Japan. The biggest drivers of uncertainty are concerns about excess German and Japanese uranium inventories and the extent to which deferrals and/or cancellations under sales contracts will introduce additional volumes into the market.

Germany, which has 17 nuclear reactors and represents 5% of the global generating capacity, has decided to revert to its previous phase out policy. Currently, eight of its reactors (about 2% of global generating capacity) are shutdown; we do not expect these reactors to restart. Germany has indicated it plans to shut down the remaining nine reactors by 2022.

In Japan, 11 of its 54 nuclear reactors are currently operating. Many of the reactors currently off-line were unaffected by the March earthquake and tsunami; however, they require regulatory and political approvals before they can restart (four of the Fukushima-Daiichi units are permanently shut down). There is concern that these approvals may be delayed due to decreased public support for nuclear in Japan. However, there has been some progress. In August, the local government approved the restart of the first nuclear reactor since March—Hokkaido’s Tomari 3 reactor. Japan’s 54 reactors represent 12% of global nuclear generating capacity.

Despite the near- to medium-term uncertainty, in the long term we continue to see a very strong and promising growth profile for the nuclear industry. Countries around the world, with very few exceptions, have reconfirmed their commitment to nuclear energy. China, India, France, Russia, South Korea, the United Kingdom, Canada, the United States, and almost every other country with a nuclear program are maintaining nuclear as a part of their energy mix.

Other previously non-nuclear countries are either moving ahead with their reactor construction programs or considering adding nuclear to their energy programs in the future. For example, the United Arab Emirates is proceeding with its plans to have 5.6 gigawatts of nuclear capacity in place by 2020 and is beginning the process to secure fuel for those reactors. In Saudi Arabia, where power demand has been increasing by 7% to 8% annually, plans to build 16 reactors by 2030 have been announced.

We are in the enviable position of being heavily committed under long-term sales contracts until 2016. With more than 300 million pounds of uranium under contract, we expect to have a solid revenue stream for years to come, even in the event of declining uranium market prices. With a target of 40% fixed-price contracts and 60% market-related, our portfolio is designed to give us increasing leverage when uranium prices increase, and to protect us when prices decline.

¹	Estimated fully diluted share capital of approximately 139 million shares, based on Hathor’s public disclosure.

6 CAMECO CORPORATION

Caution about forward-looking information relating to the March 2011 Japanese nuclear incident

This discussion of the expected impact of the March 2011 nuclear incident in Japan, including its potential impact on future global uranium demand and the number of operating reactors, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2.

Industry prices


	Sep 30 2011		Jun 30 2011		Mar 31 2011		Sept 30 2010		Jun 30 2010		Mar 31 2010
Uranium ($US/lb U₃O₈)¹
Average spot market price		52.25		52.88		60.50		46.63		41.75		41.88
Average long-term price		63.50		68.00		70.00		61.00		59.00		59.00
Fuel services ($US/kgU UF₆)¹
Average spot market price
• North America		9.50		11.00		12.00		13.00		7.00		5.63
• Europe		9.50		11.00		12.00		12.50		7.88		7.50
Average long-term price
• North America		16.50		16.00		15.75		13.13		11.25		11.00
• Europe		17.00		16.25		16.00		13.50		12.75		12.75
Note: the industry does not publish UO₂prices.
Electricity ($/MWh)
Average Ontario electricity spot price		33.00		28.00		32.00		43.00		34.00		34.00

¹	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 2011 was about 11.8 million pounds. This compares to about 13.3 million pounds in the third quarter of 2010. For the first nine months of the year, spot purchases totalled 40.1 million pounds compared to 36 million pounds for the same period in 2010.

Continued uncertainty put downward pressure on the spot price. At the end of the quarter, the average spot price was $52.25 (US) per pound. On October 31, 2011 Ux reported a spot price of $52.00 (US) per pound. Demand remains extremely discretionary and buyers are very price sensitive.

The long-term uranium price declined 7% 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 quoted near the time of delivery).

In general, utilities are well covered under existing contracts and have been building inventory levels of U₃O₈ since 2004, so we expect uranium demand in the near term to remain discretionary.

Spot market UF₆ conversion prices declined, while long-term UF₆conversion price indicators increased throughout the quarter.

2011 THIRD QUARTER REPORT 7

Long-term fundamentals are strong

Electricity is essential to maintaining and improving the standard of living for people throughout the world, and nuclear power continues to be seen as an affordable and sustainable source of safe, clean, reliable energy. The demand for uranium is expected to grow, and along with it, the need for new supply to meet future customer requirements.

Our long history of success comes from many years of hard work and discipline, developing and acquiring the expertise and assets we need to deliver on our strategy. We are well positioned to grow and be successful, and to build value for our shareholders.

Shares and stock options outstanding

At November 4, 2011, we had:

•

394,717,683 common shares and one Class B share outstanding

•

8,601,319 stock options outstanding, with exercise prices ranging from $10.51 to $46.88

Dividend policy

Our board of directors has established a policy of paying a quarterly dividend of $0.10 ($0.40 per year) per common share. This policy will be reviewed from time to time based on our cash flow, earnings, financial position, strategy and other relevant factors.

8 CAMECO CORPORATION

Financial results

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


2011 Q3 results
Consolidated financial results			9

Outlook for 2011			14
Liquidity and capital resources			15

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

Consolidated financial results

Effective January 1, 2011, we adopted IFRS for Canadian publicly accountable enterprises. Our interim financial statements have been prepared using IFRS. Amounts relating to the year ended December 31, 2010 in this MD&A and our related interim financial statements have been recast to reflect our adoption of IFRS. Amounts for periods prior to January 1, 2010 are presented in accordance with Canadian GAAP.


Highlights ($ millions except per share amounts)	Three months ended September 30								Nine months ended September 30
Highlights ($ millions except per share amounts)	2011		2010			change			2011		2010		change
Revenue		527		419			26	%		1,407		1,450		(3	)%
Net earnings		39		98			(60	)%		186		311		(40	)%
$ per common share (basic)		0.10		0.25			(60	)%		0.47		0.79		(41	)%
$ per common share (diluted)		0.10		0.25			(60	)%		0.47		0.79		(41	)%
Adjusted net earnings (non-IFRS/GAAP measure, see pages 10 & 11)		104		80			30	%		259		307		(16	)%
$ per common share (adjusted and diluted)		0.26		0.20			30	%		0.66		0.78		(15	)%
Cash provided by operations (after working capital changes)		190		(5	)		3900	%		477		412		16	%

Net earnings

Net earnings this quarter were $39 million ($0.10 per share diluted) compared to $98 million ($0.25 per share diluted) in the third quarter of 2010, primarily as a result of:

•

losses on foreign exchange derivatives, compared to gains in 2010

•

lower income taxes

•

higher earnings from our uranium business based on higher sales and higher realized prices, partially offset by an increase in the average cost of product sold

2011 THIRD QUARTER REPORT 9

Net earnings in the first nine months of the year were $186 million ($0.47 per share diluted) compared to $311 million ($0.79 per share diluted) in the first nine months of 2010 mainly due to:

•

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

•

lower earnings from our uranium business based on an increase in the cost of product sold and lower sales volumes, partially offset by an increase in the realized price

•

lower earnings from our fuel services business as a result of an increase in the average cost of product sold

•

losses on foreign exchange derivatives, compared to gains in 2010

•

lower income taxes

The following table shows the items that contribute to the difference between our Canadian GAAP and IFRS earnings for the three months and nine months ended September 30, 2010. For more information about these accounting differences see note 3 to our interim financial statements.


2010 changes in earnings ($ millions)	Three months ended September 30			Nine months ended September 30
Net earnings – Canadian GAAP		98			308

Accounting differences
Borrowing costs		(11	)		(32	)
Decommissioning provision		1			2
In-process research & development		3			9
BPLP – pension and maintenance costs		(2	)		6
Income taxes – tax effect on differences		1			4
Income taxes – IFRS accounting difference		8			14

Total accounting differences		—			3

Net earnings – IFRS		98			311

Adjusted net earnings (non-IFRS/GAAP measures)

Adjusted net earnings is a measure with no standardized meaning under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our net earnings adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period. We also used this measure prior to adoption of IFRS (non-GAAP measure).

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


($ millions)	Three months ended September 30					Nine months ended September 30
($ millions)	2011		2010			2011		2010
Net earnings		39		98			186		311
Adjustments on derivatives (after tax)¹		65		(18	)		73		(4	)
Adjusted net earnings		104		80			259		307

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

10 CAMECO CORPORATION

The table that follows describes what contributed to the changes in adjusted net earnings this quarter and for the first nine months of the year.


Change in adjusted net earnings ($ millions)		Three months ended September 30			Nine months ended September 30
Adjusted net earnings – 2010			80			307
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	Higher (lower) sales volumes		32			(24	)
	Higher realized prices ($US)		51			113
	Foreign exchange impact on realized prices		(30	)		(66	)
	Higher costs		(29	)		(47	)

	change – uranium		24			(24	)

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

	change – fuel services		(1	)		(23	)

Electricity	Higher (lower) sales volumes		2			(5	)
	Lower realized prices ($Cdn)		(7	)		(20	)
	Lower (higher) costs		5			(25	)

	change – electricity		—			(50	)

Other changes
Higher gains on derivatives & foreign exchange			1			48
Higher income taxes			(9	)		(12	)
Cigar Lake remediation			6			10
Miscellaneous			3			3

Adjusted net earnings – 2011			104			259

See Financial results by segment for more detailed discussion.

Average realized prices


		Three months ended September 30							Nine months ended September 30
		2011		2010		change			2011		2010		change
Uranium	$US/lb $Cdn/lb		47.33 45.97		40.63 43.01		16 7	% %		47.06 46.36		41.46 43.90		14 6	% %
Fuel services	$Cdn/kgU		17.42		16.32		7	%		18.05		18.19		(1	)%
Electricity	$Cdn/MWh		54.00		57.00		(5	)%		54.00		58.00		(7	)%

2011 THIRD QUARTER REPORT 11

Quarterly trends


Highlights ($ millions except per share amounts)	2011						2010									Canadian GAAP 2009
	Q3		Q2		Q1		Q4		Q3			Q2		Q1		Q4
Revenue		527		426		454		673		419			546		485		659
Net earnings		39		55		92		205		98			70		143		598
$ per common share (basic)		0.10		0.14		0.23		0.52		0.25			0.18		0.36		1.52
$ per common share (diluted)		0.10		0.14		0.23		0.51		0.25			0.18		0.36		1.52
Adjusted net earnings (non-IFRS/GAAP measures, see pages 10 & 11)		104		71		84		189		80			116		111		170
$ per share diluted		0.26		0.18		0.22		0.48		0.20			0.29		0.29		0.43
Earnings from continuing operations		39		55		92		205		98			70		143		174
$ per common share (basic)		0.10		0.14		0.23		0.52		0.25			0.18		0.36		0.44
$ per common share (diluted)		0.10		0.14		0.23		0.51		0.25			0.18		0.36		0.44
Cash provided by operations		190		20		267		109		(5	)		271		146		188

The table that follows presents the differences between net earnings and adjusted net earnings for the previous eight quarters.


($ millions)	2011							2010											Canadian GAAP 2009
	Q3		Q2		Q1			Q4			Q3			Q2		Q1			Q4
Net earnings		39		55		92			205			98			70		143			598
Adjustments (net of tax)
Adjustments on derivatives		65		16		(8	)		(16	)		(18	)		46		(32	)		(4	)
Loss (earnings) from discontinued operations		—		—		—			—			—			—		—			(424	)
Adjusted net earnings (non-IFRS/GAAP measures, see pages 10 & 11)		104		71		84			189			80			116		111			170

Key things to note:

•

Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 63% of consolidated revenues in the third quarter of 2011.

•

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-IFRS/GAAP measure, as a more meaningful way to compare our results from period to period.

•

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.

12 CAMECO CORPORATION

Administration


	Three months ended September 30							Nine months ended September 30
($ millions)	2011		2010		change			2011		2010		change
Direct administration		37		34		9	%		101		93		9	%
Stock-based compensation		1		6		(83	)%		5		7		(29	)%
Total administration		38		40		(5	)%		106		100		6	%

Direct administration costs were $37 million this quarter, or $3 million higher than the same period last year. Through the first nine months of 2011, our direct administration costs were 9% higher than in 2010. These increases reflect the costs necessary for evaluating and pursuing growth opportunities including:

•

increased hiring

•

studies and analyses of various opportunities

Exploration

Uranium exploration expenses were $36 million this quarter, or $1 million higher compared to the same quarter in 2010. Exploration expenses in the first nine months of the year increased to $71 million from $68 million in 2010. Exploration in 2011 is focused on Canada, Australia, Kazakhstan and the United States.

Gains and losses on derivatives

We recorded $76 million in losses on our derivatives this quarter, compared to gains of $39 million in the third quarter of 2010. In the first nine months of the year, we recorded $40 million in losses on our derivatives compared to gains of $22 million in 2010. These losses reflect the weakening of the Canadian dollar in 2011.

Income taxes

In the third quarter of 2011, we recorded an income tax recovery of $22 million compared to $1 million in the third quarter of 2010. The increase in recoveries was mainly due to higher losses being incurred in Canada compared to 2010, which was largely attributable to the losses we recorded on our derivatives. See note 12 to our interim financial statements for more detail.

On an adjusted basis, our income tax expense this quarter was $2 million compared to a recovery of $8 million in the third quarter of 2010. Our effective tax rate this quarter on an adjusted net earnings basis was 1% compared to a recovery of 11% for the third quarter of 2010.

In the first nine months of 2011, we recorded an income tax recovery of $19 million compared to a recovery of $3 million in 2010. The increase in recoveries was mainly due to higher losses being incurred in Canada compared to 2010, which was largely attributable to the losses we recorded on our derivatives. See note 12 to our interim financial statements for more detail.

On an adjusted basis, we recorded an income tax expense of $8 million in the first nine months of 2011 compared to income tax recovery of $4 million in 2010. Our effective tax rate for the first nine months of 2011, on an adjusted net earnings basis, reflects an expense of 3% compared to a recovery of 1% in 2010.

Foreign exchange

At September 30, 2011:

•

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.04 (Cdn), up from $1.00 (US) for $0.96 (Cdn) at June 30, 2011. The exchange rate averaged $1.00 (US) for $0.98 (Cdn) over the quarter.

•

We had foreign currency contracts of $1.4 billion (US) and EUR 46 million. The US currency contracts had an average exchange rate of $1.00 (US) for $1.00 (Cdn).

2011 THIRD QUARTER REPORT 13

•

The mark-to-market loss on all foreign exchange contracts was $57 million compared to a $37 million gain at June 30, 2011. We received cash of $14 million this quarter and $59 million for the first nine months of the year related to the settlement of foreign exchange contracts.

Outlook for 2011

Over the next several years, we expect to invest significantly in expanding production at existing mines and advancing projects as we pursue our growth strategy. The projects are at various stages of development, from exploration and evaluation to construction.

We expect our existing cash balances and operating cash flows will meet our anticipated requirements over the next several years, without the need for significant additional funding. Cash balances will decline as we use the funds in our business and pursue our growth plans.

Our outlook for 2011 reflects the expenditures necessary to help us achieve our strategy. Our outlook for uranium production, exploration, fuel services production, direct administration costs and capital expenditures has changed from the outlook included in our second quarter MD&A. We explain the changes below. All other items in the table are unchanged. We do not include an 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		—			21.7 million lbs			14 to 15 million kgU			—
Sales volume		—			31 to 33 million lbs			Increase 10% to 15%			—
Capacity factor		—			—			—			87	%
Revenue compared to 2010		Increase 5% to 10	%		Increase 10 % to 15	%¹		Increase 5% to 10	%		Decrease 10% to 15	%
Unit cost of produced product sold (including DDR)		—			Increase 0% to 5	%²		Increase 5% to 10	%		Increase 10% to 15	%
Direct administration costs compared to 2010³		Increase 10 % to 15	%		—			—			—
Exploration costs compared to 2010		—			Increase 0% to 5	%		—			—
Tax rate		Recovery of 0% to 5	%		—			—			—
Capital expenditures	$	575 million	⁴		—			—		$	80 million

¹	Based on a uranium spot price of $52.00 (US) per pound (the Ux spot price as of October 31, 2011), a long-term price indicator of $63.00 (US) per pound (the Ux long-term indicator on October 31, 2011) and an exchange rate of $1.00 (US) for $1.00 (Cdn).

²	This increase is based on the unit cost of sale for produced material. Any additional discretionary purchases in 2011 may cause the overall unit cost of product sold to increase further.

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

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

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. A delivery that was expected in the third quarter was moved into the fourth quarter. We now expect deliveries in the fourth quarter to account for over one-third of our 2011 sales volumes.

We now expect uranium production to be 21.7 million pounds this year compared to our previous forecast of 21.9 million pounds. The decrease is due to lower expected production at our US and Inkai operations, partially offset by higher expected production at McArthur River/Key Lake. Please see our Uranium production outlook for more information.

Exploration costs are now expected to increase 0% to 5% over 2010 (previously a 5% to 10% decrease) based on increased evaluation activities at Kintyre.

14 CAMECO CORPORATION

Due to current unfavourable market conditions for UF₆ conversion, we are reducing production for this year. We now expect fuel services to produce between 14 million and 15 million kgU this year (previously 15 million to 16 million kgU).

We have narrowed the scope of some of our business development activities and now expect our direct administration costs to increase 10% to 15% over 2010 (previously a 15% to 20% increase).

We expect capital expenditures to be about $575 million in 2011 compared to our previous estimate of $590 million due to changes in the scheduling of some projects. We do not expect this reduction in capital expenditures in 2011 will impact our plans to double annual uranium production to 40 million pounds by 2018.

Sensitivity analysis

For the rest of 2011:

•

a change of $5 (US) per pound in both the Ux spot price ($52.00 (US) per pound on October 31, 2011) and the Ux long-term price indicator ($63.00 (US) per pound on October 31, 2011) would change revenue by $13 million and net earnings by $9 million

•

a change of $5/MWh in the electricity spot price would not change our 2011 net earnings as gains under BPLP’s financial contracts have been fully locked in for 2011 and based on the assumption that the spot price will remain below the floor price of $50.18/MWh provided for under BPLP’s agreement with the Ontario Power Authority (OPA)

•

a one-cent change in the value of the Canadian dollar versus the US dollar would change revenue by $7 million and adjusted net earnings by $3 million. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

Liquidity and capital resources

Cash from operations

Cash from operations was $195 million higher this quarter than in 2010 due largely to lower working capital requirements in 2011. Working capital changes were $130 million less in 2011. In 2010, working capital required $149 million in cash as a result of increases in accounts receivable and product inventories. Not including working capital requirements, our operating cash flows this quarter were higher by $65 million, based on higher profits in the uranium business. See Financial results by segment for details.

Cash from operations was $65 million higher for the first nine months of 2011 primarily due to a decrease in working capital requirements, partially offset by lower profits. Working capital changes were $146 million less in 2011. In 2010, working capital changes required $124 million due to decreases in accounts payable and increases in product inventories, partially offset by decreases in accounts receivable. Not including working capital requirements, our operating cash flows in the first nine months were down by $81 million, as a result of lower profits in the uranium, fuel services, and electricity businesses. See Financial results by segment for details.

On transition to IFRS, we elected to classify interest payments as a financing activity rather than an operating activity in our statement of cash flows. This change will increase our reported cash flows from operating activities with a corresponding decrease in cash flows from financing activities. There is no net impact on consolidated cash flows as a result of this change in presentation. Prior period amounts have been recast to reflect this classification.

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, 2011, the same as at June 30, 2011. At September 30, 2011, we had approximately $606 million outstanding in letters of credit.

2011 THIRD QUARTER REPORT 15

On November 1, 2011:

•

we cancelled our $100 million unsecured revolving credit facility that was maturing February 4, 2012

•

we amended, and extended the term of our $500 million unsecured revolving credit facility that was maturing November 30, 2012. This credit facility was increased to $1.25 billion and now matures November 1, 2016. Each year on the anniversary date, and upon mutual agreement, the facility can be extended for an additional year. In addition to borrowing directly from this facility, we can use up to $100 million of it to issue letters of credit and we may use it to provide liquidity for our commercial paper program, as necessary. From time to time we may increase the revolving credit facility above $1.25 billion, by no less than increments of $50 million, up to a total of $1.75 billion. The facility ranks equally with all of our other senior debt. As of November 4, 2011, there was nothing outstanding under this facility.

With these changes, our unsecured lines of credit total about $1.9 billion as of November 4, 2011.

Debt covenants

As at September 30, 2011, we met the financial related covenants in our unsecured revolving credit facilities.

As noted under Debt, we cancelled one of our unsecured revolving credit facilities and amended and extended the other. We are bound by certain covenants in the remaining $1.25 billion unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at November 4, 2011, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2011 to be constrained by them.

Long-term contractual obligations and off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at September 30, 2011:

•

purchase commitments

•

financial assurances

There have been no material changes to our long-term contractual obligations, purchase commitments and financial assurances since December 31, 2010, 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)	Sep 30, 2011		Dec 31, 2010		change
Cash and short-term investments		1,194		1,260		(5	)%
Total debt		1,036		1,039		—
Other liabilities		667		459		45	%
Inventory		690		533		29	%

Total cash and short-term investments at September 30, 2011 were $1,194 million, or 5% lower than at December 31, 2010, exceeding our total debt by $158 million.

Total debt decreased by $3 million to $1,036 million at September 30, 2011. Of this total, $105 million was classified as current, up $6 million compared to December 31, 2010. See notes 10 and 11 of our audited annual financial statements for more detail.

Other liabilities increased by 45% to $667 million at September 30, 2011. The increase was mainly the result of updating the actuarial valuation for our pension plans to reflect current market conditions.

Total product inventories increased by 29% to $690 million. This was the result of higher uranium and fuel services inventories, as sales were lower than production and purchases in the first nine months of the year. In addition, the average carrying cost for uranium increased due to material purchased at near-market prices and higher costs for produced uranium.

16 CAMECO CORPORATION

Financial results by segment

Uranium


Highlights	Three months ended September 30							Nine months ended September 30
Highlights	2011		2010		change			2011		2010		change
Production volume (million lbs)		5.3		5.6		(5	)%		15.8		16.5		(4	)%
Sales volume (million lbs)		7.2		5.6		29	%		19.1		20.5		(7	)%
Average spot price ($US/lb)		51.04		45.83		11	%		57.89		43.01		35	%
Average realized price
($US/lb)		47.33		40.63		16	%		47.06		41.46		14	%
($Cdn/lb)		45.97		43.01		7	%		46.36		43.90		6	%
Cost of sales ($Cdn/lb) (including DDR)		27.59		23.61		17	%		29.68		27.20		9	%
Revenue ($ millions)		332		240		38	%		885		901		(2	)%
Gross profit ($ millions)		133		108		23	%		319		343		(7	)%
Gross profit (%)		40		45		(11	)%		36		38		(5	)%

Third quarter

Production volumes this quarter were 5% lower compared to the third quarter of 2010 primarily due to lower production from Smith Ranch-Highland and Inkai. See Operating properties for more information.

Uranium revenues this quarter were up 38% compared to 2010, due to a 29% increase in sales volumes and a 7% increase in the $Cdn realized selling price.

Our realized prices this quarter were higher than the third quarter of 2010 mainly due to higher $US prices under market-related contracts, partially offset by a less favourable exchange rate. In the third quarter of 2011, our realized foreign exchange rate was $0.97 compared to $1.06 in the prior year.

Total cash cost of sales (excluding DDR) increased by 68% ($165 million compared to $98 million in 2010). This was mainly the result of the following:

•

the 29% increase in sales volumes

•

average unit costs for produced uranium were 32% higher largely due to standby costs paid to AREVA relating to the McClean Lake mill. As well, royalty charges in 2011 were higher due to higher deliveries of produced material and higher realized prices.

•

average unit costs for purchased uranium were 21% higher due to increased purchases at spot prices

The net effect was a $25 million increase in gross profit for the quarter.

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


Three months ended September 30	Unit cash cost of sale ($Cdn/lb)							Quantity sold (million lbs)
Three months ended September 30	2011		2010		change			2011		2010		change
Produced		23.63		17.85		32	%		5.3		3.5		51	%
Purchased		20.57		17.05		21	%		1.9		2.1		(10	)%
Total		22.84		17.55		30	%		7.2		5.6		29	%

2011 THIRD QUARTER REPORT 17

First nine months

Production volumes for the first nine months of the year were 4% lower than in the previous year mainly due to lower production from Smith Ranch-Highland and Inkai. See Operating properties for more information.

For the first nine months of 2011, uranium revenues were down 2% compared to 2010, due to a 7% decline in sales volumes partially offset by a 6% increase in the $Cdn realized selling price.

Our realized prices were higher than the first nine months of 2010 mainly due to higher $US prices under market-related contracts, partially offset by a less favourable exchange rate. In the first nine months of 2011, our realized foreign exchange rate was $0.99 compared to $1.06 in the prior year.

Total cash cost of sales (excluding DDR) increased by 6% ($487 million compared to $460 million in 2010). This was mainly the result of the following:

•

average unit costs for produced uranium were 10% higher due to increased unit production costs relating to the lower production during the first nine months

•

standby costs paid to AREVA relating to the McClean Lake mill

•

average unit costs for purchased uranium were 22% higher due to increased purchases at spot prices

The net effect was a $24 million decrease in gross profit for the first nine months.


Nine months ended September 30	Unit cash cost of sale ($Cdn/lb)							Quantity sold (million lbs)
Nine months ended September 30	2011		2010		change			2011		2010		change
Produced		24.78		22.54		10	%		12.8		14.5		(12	)%
Purchased		27.11		22.22		22	%		6.3		6.0		5	%
Total		25.54		22.45		14	%		19.1		20.5		(7	)%

Price sensitivity analysis: uranium

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

It is designed to indicate how the portfolio of long-term contracts we had in place on September 30, 2011 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on September 30, 2011, 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
2011		46		47		49		51		53		55		57
2012		36		40		50		59		69		78		87
2013		43		46		54		63		72		81		88
2014		45		48		56		65		74		83		91
2015		43		47		56		66		77		87		97

*	The table with this heading which appeared on page 19 of our second quarter MD&A has been corrected. See Note regarding our uranium price sensitivity analysis on page 30 for more information.

18 CAMECO CORPORATION

The table illustrates the mix of long-term contracts in our September 30, 2011 portfolio, and is consistent with our contracting strategy. The table has been updated to September 30, 2011 to reflect:

•

deliveries made and contracts entered into during the quarter

•

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

•

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

These changes do not impact our outlook for 2011 sales.

Our portfolio includes a mix of fixed-price and market-price contracts, which we target at a 40:60 ratio. We signed many of our current contracts in 2003 to 2005, when market prices were low ($11 to $31 (US)). Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices. These older contracts are beginning to expire, and we are starting to deliver into more favourably priced contracts.

Our portfolio is affected by more than just the spot price. We made the following assumptions (which are not forecasts) to create the table:

Sales

•

sales volumes on average of 32 million pounds per year

Deliveries

•

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

•

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

Prices

•

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

•

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

Inflation

•

is 3.5% per year for Canada and 2.5% per year for the United States and the United Kingdom (our prior inflation assumption was 2% per year)

2011 THIRD QUARTER REPORT 19

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)


Highlights	Three months ended September 30							Nine months ended September 30
Highlights	2011		2010		change			2011		2010		change
Production volume (million kgU)		2.8		2.3		22	%		11.6		11.7		(1	)%
Sales volume (million kgU)		4.6		3.9		18	%		11.1		10.7		4	%
Realized price ($Cdn/kgU)		17.42		16.32		7	%		18.05		18.19		(1	)%
Cost of sales ($Cdn/kgU) (including DDR)		15.34		13.55		13	%		15.42		13.38		15	%
Revenue ($ millions)		81		64		27	%		199		195		2	%
Gross profit ($ millions)		10		11		(9	)%		29		52		(44	)%
Gross profit (%)		12		17		(29	)%		15		27		(44	)%

Third quarter

Total revenue was $17 million higher than in 2010 due to a 7% increase in the average realized price for our fuel services products along with an 18% increase in sales volumes.

Our $Cdn realized price for fuel services was affected by a 5% increase in our realized price for UF₆ as well as the mix of products delivered in the quarter. In 2011, a higher proportion of fuel services sales were for fuel fabrication, which typically yields a much higher price than the other fuel services products.

The total cost of products and services sold (including DDR) increased by 34% ($71 million compared to $53 million in the third quarter of 2010) due to the increase in sales volumes along with the mix of products delivered in the quarter. As a result of the product mix, the average unit cost of sales was 13% higher for the quarter.

The net effect was a $1 million decrease in gross profit.

First nine months

In the first nine months of the year, total revenue increased by 2% due to a 4% increase in sales volumes, partially offset by a 1% decline in the realized selling price.

The total cost of products and services sold (including DDR) increased by 18% ($170 million compared to $144 million in 2010) due to the increase in the unit cost of product sold. The average unit cost of sales was 15% higher due to the mix of products delivered in the year and the recognition of higher cost recoveries in 2010.

The net effect was a $23 million decrease in gross profit.

20 CAMECO CORPORATION

Electricity

BPLP

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


Highlights ($ millions except where indicated)	Three months ended September 30									Nine months ended September 30
Highlights ($ millions except where indicated)	2011			2010			change			2011			2010			change
Output - terawatt hours (TWh)		6.7			6.3			6	%		18.7			19.3			(3	)%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		93	%		88	%		6	%		87	%		90	%		(3	)%
Realized price ($/MWh)		54			57			(5	)%		54	¹		58			(7	)%
Average Ontario electricity spot price ($/MWh)		33			43			(23	)%		31			38			(18	)%
Revenue		362			363			—			1,016			1,116			(9	)%
Operating costs (net of cost recoveries)		232			229			1	%		735			685			7	%
Cash costs		182			184			(1	)%		592			557			6	%
Non-cash costs		50			45			11	%		143			128			12	%
Income before interest and finance charges		130			134			(3	)%		281			431			(35	)%
Interest and finance charges		14			16			(13	)%		30			30			—
Cash from operations		137			131			5	%		377			522			(28	)%
Capital expenditures		61			25			144	%		158			98			61	%
Distributions		80			100			(20	)%		205			405			(49	)%
Operating costs ($/MWh)		35			36			(3	)%		39	¹		35			11	%

¹	Nine months ended September 30, 2011 are based on actual generation of 18.7 TWh plus deemed generation of 0.2 TWh

Our earnings from BPLP


Highlights ($ millions except where indicated)	Three months ended September 30									Nine months ended September 30
Highlights ($ millions except where indicated)	2011			2010			change			2011			2010			change
BPLP’s earnings before taxes (100%)		116			118			(2	)%		251			401			(37	)%
Cameco’s share of pretax earnings before adjustments (31.6%)		37			37			—			79			127			(38	)%
Proprietary adjustments		(2	)		(1	)		(100	)%		(4	)		(4	)		—
Earnings before taxes from BPLP		35			36			(3	)%		75			123			(39	)%

Third quarter

Total electricity revenue decreased slightly this quarter compared to the third quarter of 2010 due to lower realized prices which were almost completely offset by increased output. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. BPLP recognized revenue of $119 million this quarter under its agreement with the OPA, compared to $41 million in the third quarter of 2010. About 53% of BPLP’s output was sold under financial contracts this quarter, compared to 46% in the third quarter of 2010. Pricing under these contracts was lower than in 2010. From time to time BPLP enters the market to lock in the gains under these contracts.

The capacity factor was 93% this quarter, up from 88% in the third quarter of 2010 due to a lower volume of planned and unplanned outage days when compared to last year. Operating costs were similar at $232 million compared to $229 million in 2010.

2011 THIRD QUARTER REPORT 21

The result was a 3% decrease in our share of earnings before taxes.

BPLP distributed $80 million to the partners in the third quarter. Our share was $25 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

During the fourth quarter, there is a planned maintenance outage at one unit.

First nine months

Total electricity revenue for the first nine months decreased 9% compared to 2010 due to lower output and 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 $351 million in the first nine months of 2011 under its agreement with the OPA, compared to $224 million in the first nine months of 2010. The equivalent of about 49% of BPLP’s output was sold under financial contracts in the first nine months of this year, compared to 41% in 2010. Pricing under these contracts was lower than in 2010. From time to time BPLP enters the market to lock in the gains under these contracts.

The capacity factor was 87% for the first nine months of this year, down from 90% in 2010 due to a higher volume of outage days during this year’s planned outage compared to last year’s planned outage. Operating costs were $735 million compared to $685 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

The result was a 39% decrease in our share of earnings before taxes.

BPLP distributed $205 million to the partners in the first nine months of 2011. Our share was $65 million.

22 CAMECO CORPORATION

Our operations and development projects

Uranium – production overview

Uranium production


Cameco’s share (million lbs U₃O₈)	Three months ended September 30							Nine months ended September 30
Cameco’s share (million lbs U₃O₈)	2011		2010		change			2011		2010		change
McArthur River/Key Lake		3.8		3.7		3	%		10.0		9.9		1	%
Rabbit Lake		0.5		0.5		—			2.2		2.5		(12	)%
Smith Ranch-Highland		0.3		0.4		(25	)%		1.2		1.4		(14	)%
Crow Butte		0.2		0.2		—			0.6		0.6		—
Inkai		0.5		0.8		(38	)%		1.8		2.1		(14	)%
Total		5.3		5.6		(5	)%		15.8		16.5		(4	)%

Outlook

We have geographically diverse sources of production. Our strategy is to double our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and projects under evaluation.

Cameco’s share of production — annual forecast to 2015


Current forecast (million lbs U₃O₈)	2011		2012		2013		2014		2015
McArthur River/Key Lake		13.3		13.1		13.1		13.1		13.1
Rabbit Lake		3.6		3.6		3.6		3.6		3.6
US ISR		2.3		2.4		3.0		3.1		3.7
Inkai¹		2.5		2.9		2.9		2.9		2.9
Cigar Lake		—		—		1.0		2.0		5.6

Total share of production		21.7		22.0		23.6		24.7		28.9

Cameco’s share of Inkai’s production on which profits are generated²
Inkai¹		2.5		3.0		3.0		3.0		3.0

Total²		21.7		22.1		23.7		24.8		29.0

We have signed an MOA with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). If implemented, the MOA will result in us receiving the right to purchase 2.9 million pounds of Inkai’s annual production and receive profits on 3.0 million pounds. See page 26 for more information.

²	We have adjusted the production table to reflect the share of Inkai’s production on which our profits will be calculated under the MOA. See page 26 for more detail.

2011 THIRD QUARTER REPORT 23

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

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

•

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

•

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

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom. If Inkai does not receive the permits and approvals it needs, if they are delayed, or if we do not reach a binding agreement with Kazatomprom, Inkai may be unable to achieve its future annual production targets.

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

Assumptions

•

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

•

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

•

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

Material risks that could cause actual results to differ materially

•

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

•

we cannot obtain or maintain necessary permits or government approvals

•

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

24 CAMECO CORPORATION

Uranium 2011 Q3 updates

Operating properties

McArthur River/Key Lake

Production update

At McArthur River/Key Lake, production was 3% higher in the third quarter and 1% higher for the first nine months of the year compared to the same periods last year. These increases were due to better recovery and improved equipment reliability at the mill. We expect the mill to operate through year end with no scheduled shutdown until 2012.

Operations update

At Key Lake, we continued work on the new oxygen, acid and steam plants. Commissioning of the steam plant commenced in the third quarter. We expect that the oxygen, acid and steam plants will all be operating by the end of the year.

Rabbit Lake

Production update

Production remains on track for the year. We expect to see large variations in mill production from quarter to quarter. We manage ore supply to ensure efficient operation of the mill.

Operations update

We completed the scheduled mill maintenance shutdown this quarter, and the mill returned to normal operations on August 31, 2011. During the shutdown we completed the next phase of upgrades at the acid plant which included successful replacement of the acid plant final towers.

As announced on October 5, 2011, we signed a non-binding MOU with our Cigar Lake joint venture partners, which contemplates a change in the milling arrangements for the ore from Cigar Lake. See Development project – Cigar Lake for more information.

Smith Ranch-Highland and Crow Butte

Production update

Production this quarter was 17% lower and 10% lower for the first nine months of the year compared to the same periods last year due to lower production from Smith Ranch-Highland. We have decreased our production forecast for the year by 8% to 2.3 million pounds. The review process to obtain regulatory approvals has lengthened at Smith Ranch-Highland, which has increased the timeline to bring new wellfields into production.

Operations update

We continue to seek regulatory approvals to proceed with expansions at our various satellite operations in Wyoming and Nebraska. However, we are experiencing some permitting delays. As a result, we do not expect to receive approval to expand Reynolds Ranch this year. We recognize the regulators have a large volume of permits to process. We are working with them to improve communications and ensure we understand and meet their needs.

2011 THIRD QUARTER REPORT 25

Inkai

Production update

Production for the quarter was 38% lower and 14% lower for the first nine months of the year compared to the same periods last year. For the quarter, lower production was primarily due to in-process uranium inventory changes. Prior to final commissioning of the processing facilities in 2010, the in-process uranium inventory had built up. A significant reduction of this inventory added to production in the third quarter of 2010 compared to 2011.

In addition, during 2010, the first year of full operation at Inkai, production benefited from the grade peak associated with multiple new wellfields. As our existing wellfields mature, the grades decrease. Average grades at in situ recovery operations typically stabilize at levels lower than initial years as uranium is recovered from a mix of wellfields of varying maturities. We are ramping up capacity at the Inkai operation in order to accommodate lower grades. We have lowered our production forecast to 2.5 million pounds, a 7% decrease from our initial estimate but in line with the currently approved production level.

Operations update

Inkai’s supply of sulphuric acid was consistent during the quarter. We experienced brief interruptions to supply during the first six months of the year. We do not anticipate any further interruptions to supply this year.

As announced on August 31, 2011, we signed an MOA with our partner, Kazatomprom, to increase production from blocks 1 and 2 to 5.2 million pounds of U₃O₈ (100% basis). Under the MOA, our share of Inkai’s annual production will be 2.9 million pounds with the processing plant at full capacity. We will also be entitled to receive profits on 3.0 million pounds.

We believe this is a fair and reasonable approach that allows both parties to benefit from changes in the uranium market that were not envisioned when the initial agreements were signed. To implement the increase, we need a binding agreement finalizing the terms of the MOA, government approval and an amendment to the resource use contract.

We continue to proceed with delineation drilling and the engineering of infrastructure and the test leach facility at block 3.

Development project

Cigar Lake

The sinking of shaft 2 continues as planned. We expect to reach the main mine workings on the 480 metre level before the end of the year. The final depth of the shaft will be 500 metres.

We also continued drilling freeze holes from surface during the quarter.

For the remainder of the year, we will focus on carrying out our plans and implementing the strategies we outlined in our annual MD&A.

As we noted under our Rabbit Lake update, we signed a non-binding MOU with our joint venture partners, which contemplates a change in the milling arrangements for the ore from Cigar Lake. Under the current toll milling agreements, both the McClean Lake mill and the Rabbit Lake mill would process uranium from Cigar Lake. Under the new arrangement, the McClean Lake mill would process and package all of the Cigar Lake uranium.

Rabbit Lake will continue to process ore mined on site and has the flexibility to process ore from other sources.

We expect the new milling arrangement will have a positive impact on the economics of the Cigar Lake project. To reflect the impact of this new milling arrangement and other developments (such as surface freezing) since the March 2010 Cigar Lake technical report, we are planning to file an updated Cigar Lake technical report with, or prior to, our February 2012 annual information form.

26 CAMECO CORPORATION

The most significant project developments since the March 2010 technical report are:

•

a decrease in the estimated average cash operating cost to about $18.60 per pound from $23.14 per pound. The reduction in the operating cost estimate is primarily due to the new milling arrangement.

•

a $189 million increase in our share of the total capital cost at completion to $1.1 billion. The capital cost estimate has increased primarily as a result of the implementation of the surface freeze strategy, general cost escalation, costs to upgrade and expand the McClean Lake mill and improvements to the mine plan.

The projected production startup date remains mid-2013.

Binding agreements with the owners of the Cigar Lake project and McClean Lake mill are required to proceed with the new milling arrangements. We expect these to be complete before November 30, 2011.

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.

The intention to mill all Cigar Lake ore at the McClean Lake mill and the expected benefit of that arrangement, the estimated average cash operating cost and our expected share of the total capital cost at completion for Cigar Lake, and our projected production startup date of mid-2013 are forward-looking information. They are based on the assumptions and subject to the material risks discussed on page 3, and specifically on the assumptions and risks listed here.

Assumptions

•

we will reach binding agreements to implement the MOU

•

our expectation that the arrangement will result in the expected reduction in the operating cost

•

our Cigar Lake remediation, development and production plans succeed

•

there is no material delay or disruption in our plans as a result of additional water inflows, natural phenomena, equipment failure or other causes

Material Risks

•

we are unable to reach binding agreements to implement the new milling arrangements on expected terms

•

the new milling arrangement does not result in the expected cost savings or other benefits

•

our remediation, development or production plans for Cigar Lake are delayed or do not succeed for any reason

Projects under evaluation

In August, we hosted a group of Martu from Australia at our Saskatchewan mine sites. The experience was positive and we continue to work with the Martu to complete a memorandum of understanding for a mine development agreement at Kintyre.

We continue to work on the pre-feasibility study at Kintyre. We initially planned to complete the pre-feasibility study by the end of 2011. However, limited access to the site due to weather and changes in the scope of the study, including additional drilling and a comprehensive review of processing options, have delayed completion. We now expect to complete the pre-feasibility study by mid-2012.

We continue to advance the Kintyre and Millennium projects toward development decisions using our stage gate process. See our annual MD&A for more information regarding these projects.

2011 THIRD QUARTER REPORT 27

Fuel services 2011 Q3 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc.

Springfields Fuels Ltd. (SFL)

Production update

Fuel services production totalled 2.8 million kgU this quarter, compared to 2.3 million kgU in the third quarter of 2010. Production was 22% higher due to the planned maintenance shutdown of the Port Hope UF₆ plant in 2010.

Production for the first nine months of the year was 11.6 million kgU compared to 11.7 million kgU in the first nine months of 2010.

Based on the unfavourable market outlook for UF₆ conversion, we have discontinued discussions to extend our toll conversion contract with SFL beyond 2016. We remain fully committed to the current contract. Should market conditions improve over the next few years, we would consider resuming our discussions to extend the contract.

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by 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

•

Dave Neuburger, vice-president, international mining, Cameco

Cigar Lake

•

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

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 2011, we paid PACL $46.9 million for construction and contracting services (2010 - $19.0 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

Critical accounting estimates

In our 2010 annual MD&A, we have identified the critical accounting estimates that reflect the more significant judgments used in the preparation of our financial statements. These estimates have not changed as a result of our adoption of IFRS. Please refer to note 2 of our interim financial statements for a detailed description of our application of estimates and judgment in the preparation of our financial information.

28 CAMECO CORPORATION

Controls and procedures

As of September 30, 2011, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), 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, 2011, the CEO and CFO 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

•

such information is accumulated and communicated to our management, including our CEO and CFO, 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, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New accounting pronouncements

Financial instruments

In October 2010, the International Accounting Standards Board (“IASB”) issued IFRS 9, Financial Instruments (“IFRS 9”). This standard is effective for periods beginning on or after January 1, 2013 and is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement. IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. The guidance in IAS 39 on impairment of financial assets and hedge accounting continues to apply. We are assessing the impact of this new standard on our financial statements.

Consolidated financial statements

In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements (“IFRS 10”). This standard is effective for periods beginning on or after January 1, 2013 and establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 defines the principle of control and establishes control as the basis for determining which entities are consolidated in the consolidated financial statements. We are assessing the impact of this new standard on our financial statements.

Joint arrangements

In May 2011, the IASB issued IFRS 11, Joint Arrangements (“IFRS 11”). This standard is effective for periods beginning on or after January 1, 2013 and establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 requires a party to assess the rights and obligations arising from an arrangement in determining whether an arrangement is either a joint venture or a joint operation. Joint ventures are to be accounted for using the equity method while joint operations will continue to be accounted for using proportionate consolidation. We are assessing the impact of this new standard on our financial statements.

Disclosure of interests in other entities

In May 2011, the IASB issued IFRS 12, Disclosure of Interests in Other Entities (“IFRS 12”). This standard is effective for periods beginning on or after January 1, 2013 and applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 integrates and makes consistent the

2011 THIRD QUARTER REPORT 29

disclosure requirements for a reporting entity’s interest in other entities and presents those requirements in a single standard. We are assessing the impact of this new standard on our financial statements.

Fair value measurement

In May 2011, the IASB issued IFRS 13, Fair Value Measurement (“IFRS 13”). This standard is effective for periods beginning on or after January 1, 2013 and provides additional guidance where IFRS requires fair value to be used. IFRS 13 defines fair value, sets out in a single standard a framework for measuring fair value and establishes the required disclosures about fair value measurements. We are assessing the impact of this new standard on our financial statements.

Employee benefits

In June 2011, the IASB issued an amended version of IAS 19, Employee Benefits (“IAS 19”). This amendment is effective for periods beginning on or after January 1, 2013 and eliminates the ‘corridor method’ of accounting for defined benefit plans. Revised IAS 19 also streamlines the presentation of changes in assets and liabilities arising from defined benefit plans, and enhances the disclosure requirements for defined benefit plans. We are assessing the impact of this revised standard on our financial statements.

Presentation of other comprehensive income (OCI)

In June 2011, the IASB issued an amended version of IAS 1, Presentation of Financial Statements (“IAS 1”). This amendment is effective for periods beginning on or after January 1, 2012 and requires companies preparing financial statements in accordance with IFRS to group together items within OCI that may be reclassified to the profit or loss section of the statement of earnings. Revised IAS 1 also reaffirms existing requirements that items in OCI and profit or loss should be presented as either a single statement or two consecutive statements. We are assessing the impact of this revised standard on our financial statements.

International financial reporting standards (IFRS)

Our three-phase implementation plan, described in our annual MD&A, is substantially complete. Effective January 1, 2011, we adopted IFRS for Canadian publicly accountable enterprises. Our interim financial statements for the third quarter of 2011 have been prepared in accordance IFRS including comparative amounts for 2010. Details of the accounting differences can be found in note 3 to our interim financial statements.

Note regarding our uranium price sensitivity analysis

The table appearing on page 19 of our second quarter MD&A titled Expected realized uranium price sensitivity under various spot price assumptions was intended to indicate how the portfolio of long-term contracts we had in place on June 30, 2011 would respond to different spot prices and other stated assumptions. That table should have appeared as follows:

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)


($US/lb U₃O₈)
Spot prices	$20		$40		$60		$80		$100		$120		$140
2011		43		45		49		53		57		61		65
2012		35		40		49		57		66		75		83
2013		42		45		54		62		72		80		88
2014		45		48		56		65		74		83		91
2015		42		46		56		66		76		87		96

Although this table is now replaced by the more current table which appears on page 18 under the heading Price sensitivity analysis: uranium, we are providing the corrected version of the table published in our second quarter MD&A to facilitate comparison with the current table.

30 CAMECO CORPORATION