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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 condensed consolidated interim financial statements and notes for the quarter ended June 30, 2011 (interim financial statements). The information is based on what we knew as of August 3, 2011 and updates our first 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 and second 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 SECOND 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 situation at the Fukushima nuclear power plant in Japan

•		our goal for doubling annual production by 2018 to 40 million pounds and our expectation that existing cash balances and operating cash flows will meet anticipated 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 about 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 gradually as we use the funds in our business and pursue our growth plans

•		our expectation that our operating and investment activities in 2011 will not be constrained by the financial covenants in our general credit facilities

•		our uranium price sensitivity analysis

•		forecast production at our uranium operations from 2011 to 2015

•		our expectation that Inkai will receive all the necessary approvals and permits to meet its 2011 and future annual production targets

•		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 19 & 20, 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 and development plans succeed

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

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

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

2011 SECOND QUARTER REPORT 3

Second quarter update

As a pure-play nuclear energy investment, we are well positioned as the world continues to require nuclear to meet the growing demand for safe, clean, reliable and affordable energy. We are among the world’s largest uranium producers, with world class assets and strong fundamentals, operating 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 have long-term objectives for each of our three business segments:

•		uranium — double our annual production to 40 million pounds by 2018 from existing assets

•		fuel services — invest in our fuel services business to support our overall growth in the nuclear business

•		electricity — maintain steady cash flow while looking at options to extend the operating life of the four Bruce B units

You can read more about our strategy in our 2010 annual MD&A.

Management update

On July 1, 2011, Tim Gitzel assumed the role of president and chief executive officer (CEO). Tim joined the company in 2007 as senior vice-president and chief operating officer and was promoted to president in May of 2010. Prior to joining Cameco, he was executive vice-president, mining business unit for AREVA based in Paris, France with responsibility for uranium, gold, exploration and decommissioning operations in 11 countries around the world.

Tim replaces Jerry Grandey as CEO. Jerry retired after more than eight years as CEO and 18 years with Cameco.

Tim’s transition to CEO was well planned and seamlessly executed.

In addition, on July 15, 2011, Grant Isaac was appointed senior vice-president and chief financial officer (CFO) and Alice Wong was appointed senior vice-president, corporate services. Both will report to the president and CEO, Tim Gitzel.

Grant Isaac, previously senior vice-president, corporate services, replaces Kim Goheen as CFO. Kim has retired after 14 years with Cameco. Alice Wong, previously vice-president, safety, health, environment, quality and regulatory relations, replaces Grant Isaac as senior vice-president, corporate services.

Under Tim’s direction, the management team remains committed to the strategy, vision and values that have helped us become a global leader in the nuclear industry.

4 CAMECO CORPORATION

Our performance


			Three months							Six months
Highlights			ended June 30							ended June 30
($ millions except where indicated)			2011		2010		change			2011		2010		change

Revenue				426		546		(22	)%		880		1,031		(15	)%

Gross profit				108		180		(40	)%		244		363		(33	)%

Net earnings				54		70		(23	)%		145		213		(32	)%

$ per common share (diluted)				0.14		0.18		(22	)%		0.37		0.54		(31	)%

Adjusted net earnings (non-IFRS/GAAP measure, see pages 11 and 12)				70		116		(40	)%		154		228		(32	)%

$ per common share (adjusted and diluted)				0.18		0.29		(38	)%		0.39		0.58		(33	)%

Cash provided by operations (after working capital changes)				20		271		(93	)%		286		417		(31	)%

Average realized prices		$US/lb		45.65		41.31		11	%		46.89		41.76		12	%
	Uranium	$Cdn/lb		44.48		43.00		3	%		46.60		44.23		5	%

	Fuel services	$Cdn/kgU		17.24		15.98		8	%		18.50		19.28		(4	)%

	Electricity	$Cdn/MWh		55.00		58.00		(5	)%		54.00		58.00		(7	)%

Second quarter

As anticipated, our results for the second quarter and the first six months of 2011 were impacted by lower uranium sales volumes. We continue to expect sales to be heavily weighted toward the second half of the year. Net earnings attributable to our shareholders (net earnings) this quarter were $54 million ($0.14 per share diluted) compared to $70 million ($0.18 per share diluted) in the second quarter of 2010. Net earnings were down this quarter due to the items noted below, partially offset by higher gains on foreign exchange derivatives. The Canadian dollar strengthened in the second quarter of 2011 whereas it weakened relative to the US dollar in the second quarter of 2010.

On an adjusted basis, our earnings this quarter were $70 million ($0.18 per share diluted) compared to $116 million ($0.29 per share diluted) (non-IFRS/GAAP measure, see pages 11 and 12) in the second quarter of 2010. The decline was due to:

•		lower earnings from our uranium business due to lower sales and an increase in the average cost of product sold, partially offset by an increase in the realized price

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

•		higher income taxes

See Financial results by segment for more detailed discussion.

First six months

Net earnings in the first six months of the year were $145 million ($0.37 per share diluted) compared to $213 million ($0.54 per share diluted) in the first six months of 2010. Net earnings were lower than in 2010 due to the items noted below, partially offset by higher gains on foreign exchange derivatives.

On an adjusted basis, our earnings for the first six months of this year were $154 million ($0.39 per share diluted) compared to $228 million ($0.58 per share diluted) (non-IFRS/GAAP measure, see pages 11 and 12). The decline was due to:

•

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

•

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

2011 SECOND QUARTER REPORT 5

•		lower earnings from our fuel services business due to lower average realized prices and an increase in the average cost of product sold

•		higher income taxes

See Financial results by segment for more detailed discussion.

Operations update


		Three months							Six months
		ended June 30							ended June 30
Highlights		2011		2010		change			2011		2010		change

Uranium	Production volume (million lbs)		5.7		4.9		16	%		10.5		10.9		(4	)%

	Sales volume (million lbs)		5.8		8.4		(31	)%		11.9		14.9		(20	)%

	Revenue ($ millions)		256		359		(29	)%		554		661		(16	)%

Fuel services	Production volume (million kgU)		4.5		4.5		—			8.8		9.3		(5	)%

	Sales volume (million kgU)		4.0		4.6		(13	)%		6.4		6.8		(6	)%

	Revenue ($ millions)		70		73		(4	)%		119		131		(9	)%

Electricity	Output (100%) (TWh)		5.6		6.2		(10	)%		12.0		13.0		(8	)%

	Revenue (100%) ($ millions)		314		359		(13	)%		654		753		(13	)%

	Our share of earnings before taxes ($ millions)		10		32		(69	)%		40		87		(54	)%

Production in our uranium segment this quarter was up 16% compared to the second quarter of 2010 mainly due to a change in the production schedule at McArthur River/Key Lake. To optimize production for the year, we rescheduled the maintenance outage at the Key Lake mill from the second quarter to the first quarter. Due to planned variations in mill production at Rabbit Lake, production was 4% lower for the first six months of the year. Production remains on track for the year. See Uranium 2011 Q2 Updates for more information.

Key highlight:

•

at Cigar Lake, we resumed the sinking of shaft 2 and also received regulatory approval of our mine plan

Production in our fuel services segment was the same this quarter as it was in the second quarter of 2010. Production for the first six months of the year decreased by 5%, largely due to operational issues in the first quarter and a planned shutdown in the second quarter to reduce inventory. We continue to expect production to be between 15 million and 16 million kgU this year.

In our electricity segment, BPLP’s generation was 10% lower for the quarter and 8% lower for the first six months of the year, compared to the same periods last year. The capacity factor this quarter was 78% and 85% for the first six months of the year.

Uranium market update

It has been almost five months since the Fukushima-Daiichi nuclear power plant was damaged by the devastating earthquake and tsunami in Japan. As Japan continues to manage the effects of these events on its nuclear reactor fleet, the future role of nuclear energy in that country is also being discussed. While there are reports of strong support for nuclear from various industry groups in Japan, public sentiment is reportedly more cautious.

Other countries around the world have now had time to do a preliminary review of their nuclear programs. With very few exceptions, we see these countries continuing their commitment to nuclear energy. India, China, 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.

There are a few exceptions, Germany being the most notable. Germany, which has 17 nuclear reactors, representing 5% of the global generating capacity, has decided to revert to its previous phase out policy. Currently, eight of its

6 CAMECO CORPORATION

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.

Despite these changes, the nuclear industry is growing. Other previously non-nuclear countries are considering adding nuclear to their energy programs in the future. Saudi Arabia, for example, recently announced its plan to build 16 reactors by 2030. Its plan includes building the first two reactors over the next 10 years and adding two new reactors every year thereafter. The Saudis are targeting nuclear power to provide 20% of their electricity needs in the future. Saudi Arabia has signed nuclear co-operation agreements with France and Argentina, and has announced plans to sign agreements with China and South Korea in the near future. We have not incorporated this announcement from Saudi Arabia into our supply and demand outlook below.

We have reviewed our supply and demand outlook from the first quarter and revised our estimates to reflect Germany’s decision to move away from nuclear and the current status of Japan’s nuclear fleet. As a result, we expect:

•		over the next 10 years, world uranium demand to decline to about 2.1 billion pounds, compared to our previous estimate of 2.2 billion pounds (about a 3% decline)

•		in 2020, annual world consumption to decrease to about 225 million pounds, about a 5 million pound reduction from our previous estimate. This represents an average annual growth rate of about 3%.

•		about 85 net new reactors by 2020 compared to our previous estimate of about 90

•		global uranium consumption in 2011 to decrease to about 175 million pounds, a 3% reduction from our previous estimate of about 180 million pounds

•		global uranium production to be about 145 million pounds in 2011, unchanged from our previous estimate

•		world consumption of UF₆ and UO₂ conversion services to decrease to about 65 million kgU in 2011 compared to our previous estimate of about 70 million kgU

Despite the expected decreases in our estimates noted above, we continue to expect annual global consumption to exceed annual global mine production by a significant margin over the next 10 years, a situation that has existed since about 1986. We expect the new supply required to meet global uranium demand to be about 270 million pounds over the next 10 years (our previous estimate was 320 million pounds).

About 70% of global uranium supply over the next 10 years is expected to come from mines currently in commercial operation, less than 20% is expected to come from existing secondary supply sources and the remainder is expected to come from new sources of supply (unchanged from our previous estimate).

With our extensive portfolio of long-term sales contracts, we are in the enviable position of being heavily committed until 2016. As a result, we expect the impact of changes in the global supply and demand outlook on us to be significantly less.

We will continue to monitor announcements and developments in the nuclear industry. When we believe we have adequate information, we will report the expected impact on our uranium supply and demand outlook.

Our industry continues to respond in a responsible manner to the events in Japan. We, and others in our industry, are reviewing the lessons learned from this event and, where applicable, incorporating them to ensure the health and safety of employees, communities and the environment. Governments, regulators and the general public are looking for assurances that every segment of the industry has learned and applied the lessons resulting from Fukushima. Our industry is applying the lessons learned and will continue to take every possible step to identify and mitigate risks.

Caution about forward-looking information relating to Fukushima

This discussion of the expected impact of the situation at the Fukushima nuclear power plant 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.

2011 SECOND QUARTER REPORT 7

More specifically, it is based on the assumptions that:

•		we have accurately assessed the effect that the events which have already taken place will have on the regulation and public perception of the safety of nuclear power plants and the resulting impact on the demand for uranium

•		there will not be any significant adverse changes in conditions at Fukushima

It is subject to the risks that:

•		the situation could have a more significant adverse impact on the demand for uranium than we now expect based on currently available information

•		subsequent developments in the situation could result in a further reduction in uranium demand

Industry prices


	Jun 30		Mar 31		Jun 30		Mar 31
	2011		2011		2010		2010

Uranium ($US/lb U₃O₈)¹
Average spot market price		52.88		60.50		41.75		41.88
Average long-term price		68.00		70.00		59.00		59.00

Fuel services
($US/kgU UF₆)¹
Average spot market price
• North America		11.00		12.00		7.00		5.63
• Europe		11.00		12.00		7.88		7.50
Average long-term price
• North America		16.00		15.75		11.25		11.00
• Europe		16.25		16.00		12.75		12.75
Note: the industry does not publish UO₂prices.

Electricity ($/MWh)
Average Ontario electricity spot price		28.00		32.00		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 second quarter of 2011 was about 9.2 million pounds U₃O₈. This compares to about 9.6 million pounds in the second quarter of 2010. For the first half of the year, spot purchases totalled 28.3 million pounds compared to 22.7 million pounds for the same period in 2010.

Continued uncertainty coupled with Germany, Switzerland and Italy deciding to cancel their nuclear programs put downward pressure on the spot price. At the end of the quarter, the average spot price was $52.88 (US) per pound and has continued to drift down with Ux reporting $52.25 (US) per pound on August 1, 2011. Demand remains extremely discretionary and buyers are very price sensitive.

The long-term uranium price declined slightly 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 dropped at the beginning of the quarter, then levelled off in May and June. Long-term UF₆conversion price indicators increased throughout the quarter.

8 CAMECO CORPORATION

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 August 2, 2011, we had:

•		394,712,003 common shares and one Class B share outstanding

•		8,703,696 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.

2011 SECOND QUARTER REPORT 9

Financial results

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

2011 Q2 results


Consolidated financial results			10
Outlook for 2011			15
Liquidity and capital resources			16
Financial results by segment			18
Uranium			18
Fuel services			21
Electricity			22

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	Three months ended June 30							Six months ended June 30
($ millions except per share amounts)	2011		2010		change			2011		2010		change

Revenue		426		546		(22	)%		880		1,031		(15	)%

Net earnings		54		70		(23	)%		145		213		(32	)%

$ per common share (basic)		0.14		0.18		(22	)%		0.37		0.54		(31	)%

$ per common share (diluted)		0.14		0.18		(22	)%		0.37		0.54		(31	)%

Adjusted net earnings (non-IFRS/GAAP measure, see page 4)		70		116		(40	)%		154		228		(32	)%

$ per common share (adjusted and diluted)		0.18		0.29		(38	)%		0.39		0.58		(33	)%

Cash provided by operations (after working capital changes)		20		271		(93	)%		286		417		(31	)%

Net earnings

Net earnings this quarter were $54 million ($0.14 per share diluted) compared to $70 million ($0.18 per share diluted) in the second quarter of 2010 due to:

•

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

•

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

•

higher income taxes

•

partially offset by higher gains on foreign exchange derivatives

10 CAMECO CORPORATION

Net earnings in the first six months of the year were $145 million ($0.37 per share diluted) compared to $213 million ($0.54 per share diluted) in the first six months of 2010 due to:

•

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

•

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

•

lower earnings from our fuel services business due to lower average realized prices and an increase in the average cost of product sold

•

higher income taxes

•

partially offset by higher gains on foreign exchange derivatives

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


2010 changes in earnings	Three months ended			Six months ended
($ millions)	June 30			June 30

Net earnings — Canadian GAAP		68			210

Accounting differences
Borrowing costs		(11	)		(21	)
Decommissioning provision		2			1
In-process research & development		3			6
BPLP — pension and maintenance costs		8			8
Income taxes — tax effect on differences		—			2
Income taxes — IFRS accounting difference		—			6
All other		—			1

Total accounting differences		2			3

Net earnings — IFRS		70			213

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 for unrealized gains and losses on our financial instruments 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. 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.


	Three months				Six months
	ended June 30				ended June 30
($ millions)	2011		2010		2011		2010

Net earnings		54		70		145		213

Adjustments on derivatives (after tax)¹		16		46		9		15

Adjusted net earnings		70		116		154		228


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 we continued to apply hedge accounting.

2011 SECOND QUARTER REPORT 11

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


Change in adjusted net earnings		Three months			Six months ended
($ millions)		ended June 30			June 30

Adjusted net earnings — 2010			116			228

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		(39	)		(48	)
	Higher realized prices ($US)		26			64
	Foreign exchange impact on realized prices		(17	)		(36	)
	Higher costs		(11	)		(28	)

	change — uranium		(41	)		(48	)

Fuel services	Lower sales volumes		(2	)		(2	)
	Higher (lower) realized prices ($Cdn)		5			(5	)
	Higher costs		(9	)		(14	)

	change — fuel services		(6	)		(21	)

Electricity	Lower sales volumes		(4	)		(7	)
	Lower realized prices ($Cdn)		(3	)		(13	)
	Higher costs		(18	)		(30	)

	change — electricity		(25	)		(50	)
Other changes
Higher realized gains on derivatives & foreign exchange			30			45
Higher income taxes			(7	)		(3	)
Cigar Lake remediation			4			3
Miscellaneous			(1	)		—

Adjusted net earnings — 2011			70			154

See Financial results by segment for more detailed discussion.

Average realized prices


		Three months ended							Six months ended
		June 30							June 30
		2011		2010		change			2011		2010		change

	$US/lb		45.65		41.31		11	%		46.89		41.76		12	%
Uranium	$Cdn/lb		44.48		43.00		3	%		46.60		44.23		5	%

Fuel services	$Cdn/kgU		17.24		15.98		8	%		18.50		19.28		(4	)%

Electricity	$Cdn/MWh		55.00		58.00		(5	)%		54.00		58.00		(7	)%

12 CAMECO CORPORATION

Quarterly trends


														Canadian
Highlights			2011										2010		GAAP 2009
($ millions except per share amounts)	Q2		Q1		Q4		Q3			Q2		Q1		Q4		Q3

Revenue		426		454		673		419			546		485		659		518

Net earnings		54		91		205		98			70		143		598		172

$ per common share (basic)		0.14		0.23		0.52		0.25			0.18		0.36		1.52		0.44

$ per common share (diluted)		0.14		0.23		0.51		0.25			0.18		0.36		1.52		0.44

Adjusted net earnings (non-IFRS/GAAP measures, see pages 11 & 12)		70		84		189		80			116		112		170		94

$ per share diluted		0.18		0.21		0.48		0.21			0.29		0.28		0.43		0.24

Earnings from continuing operations		54		91		205		98			70		143		174		195

$ per common share (basic)		0.14		0.23		0.52		0.25			0.18		0.36		0.44		0.49

$ per common share (diluted)		0.14		0.23		0.51		0.25			0.18		0.36		0.44		0.49

Cash provided by operations		20		266		109		(5	)		271		146		188		175

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


																	Canadian
	2011													2010			GAAP 2009
($ millions)	Q2		Q1			Q4			Q3			Q2		Q1			Q4			Q3

Net earnings		54		91			205			98			70		143			598			172

Adjustments (net of tax)

Unrealized losses (gains) on financial instruments		16		(7	)		(16	)		(18	)		46		(31	)		(4	)		(101	)

Loss (earnings) from discontinued operations		—		—			—			—			—		—			(424	)		23

Adjusted net earnings (non-IFRS/GAAP measures, see pages 11 & 12)		70		84			189			80			116		112			170			94

Key things to note:

•

Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 60% of consolidated revenues in the second 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.

2011 SECOND QUARTER REPORT 13

Administration


	Three months ended								Six months ended
	June 30								June 30
($ millions)	2011		2010			change			2011		2010		change

Direct administration		33		30			10	%		64		59		8	%

Stock-based compensation		1		(1	)		200	%		4		1		300	%

Total administration		34		29			17	%		68		60		13	%

Direct administration costs were $33 million this quarter, or $3 million higher than the same period last year. Through the first six months of 2011, our direct administration costs were 8% 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 $17 million this quarter down $1 million compared to the same quarter in 2010. Exploration expenses in the first six months of the year increased to $35 million from $33 million in 2010. Exploration in 2011 is focused on Canada, Australia, Kazakhstan and the United States.

Gains and losses on derivatives

We recorded $12 million in mark-to-market gains on our financial instruments this quarter, compared to losses of $60 million in the second quarter of 2010. In the first six months of the year, we recorded $36 million in mark-to-market gains on our financial instruments compared to losses of $17 million in 2010. These gains reflect the strengthening of the Canadian dollar in 2011.

Income taxes

In the second quarter of 2011, we recorded an income tax recovery of $1 million compared to $19 million in the second quarter of 2010. The decline in recoveries this quarter was mainly due to a higher proportion of income being earned in Canada in 2011, which was largely attributable to the gains we recorded on our derivatives.

On an adjusted basis, we recorded an income tax expense of $5 million this quarter compared to a recovery of $2 million in the second quarter of 2010. Our effective tax rate this quarter on an adjusted net earnings basis reflects an expense of 7% compared to a recovery of 2% for the second quarter of 2010.

In the first six months of 2011, we recorded an income tax expense of $3 million compared to a recovery of $2 million in 2010. In spite of a decline in pre-tax income in 2011, our net tax expense increased compared to 2010 due to higher earnings in jurisdictions with relatively higher tax rates.

On an adjusted basis, we recorded an income tax expense of $6 million in the first six months of 2011 compared to $3 million in 2010. Our effective tax rate for the first six months of 2011, on an adjusted net earnings basis, reflects an expense of 4% compared to 1% in 2010.

Foreign exchange

At June 30, 2011:

•

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $0.96 (Cdn), down from $1.00 (US) for $0.97 (Cdn) at March 31, 2011. The exchange rate averaged $1.00 (US) for $0.97 (Cdn) over the quarter.

•

We had foreign currency contracts of $1.2 billion (US) and EUR 92 million. The US currency contracts had an average exchange rate of $1.00 (US) for $1.00 (Cdn).

•

The mark-to-market gain on all foreign exchange contracts was $37 million compared to a $54 million gain at March 31, 2011. We received cash of $27 million this quarter and $44 million for the first six months of the year related to the settlement of foreign exchange contracts.

14 CAMECO CORPORATION

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 gradually 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 fuel services unit cost of produced product sold, electricity capacity and capital expenditures has changed from the outlook included in our first 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	—	21.9 million lbs	15 to 16 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 15% to 20%	—	—	—

Exploration costs compared to 2010	—	Decrease 5% to 10%	—	—

Tax rate	Recovery of 0% to 5%	—	—	—

Capital expenditures	$590 million⁴	—	—	$80 million


¹		Based on a uranium spot price of $52.25 (US) per pound (the Ux spot price as of August 1, 2011), a long-term price indicator of $68.00 (US) per pound (the Ux long-term indicator on July 25, 2011) and an exchange rate of $1.00 (US) for $0.95 (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. This year, we expect deliveries will be heavily weighted to the second half of the year. We expect deliveries in the fourth quarter to account for about one-third of our 2011 sales volumes.

We now expect unit cost of produced product sold for fuel services to increase by 5% to 10% over 2010 (previously a 2% to 5% increase) primarily due to increased sales in the fuel manufacturing division.

Electricity capacity factor in 2011 is expected to decrease to 87% compared to 89% as previously reported. The change in outlook is largely the result of increased planned outage days when compared to 2010.

We expect capital expenditures to be about $590 million in 2011 compared to our previous estimate of $620 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 by 2018.

2011 SECOND QUARTER REPORT 15

Sensitivity analysis

For the rest of 2011:

•

a change of $5 (US) per pound in both the Ux spot price ($52.25 (US) per pound on August 1, 2011) and the Ux long-term price indicator ($68.00 (US) per pound on July 25, 2011) would change revenue by $22 million and net earnings by $16 million

•

a change of $5 in the electricity spot price would change our 2011 net earnings by $1 million, based on the assumption that the spot price will remain below the floor price of $50.18 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 $10 million and adjusted net earnings by $3 million. This sensitivity is based on an exchange rate of $1.00 (US) for $0.95 (Cdn).

Liquidity and capital resources

Cash from operations

Cash from operations was $251 million lower this quarter than in 2010 due largely to higher working capital requirements. Working capital changes required $179 million in 2011, primarily due to an increase in uranium inventories during the quarter. In 2010, working capital provided $73 million in cash largely due to decreases in accounts receivable and product inventories. Not including working capital requirements, our operating cash flows this quarter were down by $71 million, largely due to lower uranium sales volumes and lower profits in the electricity business. See Financial results by segment for details.

Cash from operations was $131 million lower for the first six months of 2011 than for the same period in 2010 mainly due to lower profits from the electricity business and lower uranium sales volumes. Not including working capital requirements, our operating cash flows in the first six months were down by $148 million.

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 June 30, 2011, the same as at March 31, 2011. At June 30, 2011, we had approximately $545 million outstanding in letters of credit.

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 June 30, 2011, we met these financial covenants and do not expect our operating and investment activities in 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 June 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.

16 CAMECO CORPORATION

Balance sheet


($ millions)	Jun 30, 2011		Dec 31, 2010		change

Cash and short-term investments		1,219		1,260		(3	)%

Total debt		1,026		1,039		(1	)%

Inventory		669		533		26	%

Total cash and short-term investments at June 30, 2011 were $1,219 million, or 3% lower than at December 31, 2010, exceeding our total debt by $193 million.

Total debt declined by $13 million to $1,026 million at June 30, 2011. Of this total, $93 million was classified as current, down $6 million compared to December 31, 2010. See notes 10 and 11 of our audited annual financial statements for more detail.

Total product inventories increased by 26% to $669 million. This was the result of higher uranium and fuel services inventories, as sales were lower than production and purchases in the first six 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.

2011 SECOND QUARTER REPORT 17

Financial results by segment

Uranium


	Three months ended							Six months ended
	June 30							June 30
Highlights	2011		2010		change			2011		2010		change

Production volume (million lbs)		5.7		4.9		16	%		10.5		10.9		(4	)%

Sales volume (million lbs)		5.8		8.4		(31	)%		11.9		14.9		(20	)%

Average spot price ($US/lb)		55.04		41.42		33	%		61.31		41.60		47	%
Average realized price
($US/lb)		45.65		41.31		11	%		46.89		41.76		12	%
($Cdn/lb)		44.48		43.00		3	%		46.60		44.23		5	%

Cost of sales ($Cdn/lb U₃O₈) (including DDR)		29.61		27.79		7	%		30.95		28.54		8	%

Revenue ($ millions)		256		359		(29	)%		554		661		(16	)%

Gross profit ($ millions)		86		127		(32	)%		186		234		(21	)%

Gross profit (%)		34		35		(3	)%		34		35		(3	)%

Second quarter

Production volumes this quarter were 16% higher compared to the second quarter of 2010 primarily due to higher production at McArthur River/Key Lake. See Operating properties for more information.

Uranium revenues this quarter were down 29% compared to 2010, due to a 31% decline in sales volumes partially offset by a 3% increase in the $Cdn realized selling price.

Our realized prices this quarter were higher than the second quarter of 2010 mainly due to higher $US prices under market-related contracts, partially offset by a less favourable exchange rate. In the second quarter of 2011, our realized foreign exchange rate was $0.97 compared to $1.04 in the prior year.

Total cash cost of sales (excluding DDR) decreased by 25% ($148 million compared to $197 million in 2010). This was mainly the result of the following:

•

the 31% decline in sales volumes

•

average unit costs for produced uranium were 5% higher largely due to standby costs paid to AREVA relating to the McClean Lake JEB mill

•

average unit costs for purchased uranium were 18% higher due to increased purchases at spot prices

The net effect was a $41 million decrease in gross profit for the quarter.

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


	Unit cash cost of sale									Quantity sold
Three months	($Cdn/lb U₃O₈)							(million lbs)
ended June 30	2011		2010		change			2011		2010		change

Produced		24.88		23.80		5	%		3.5		6.5		(46	)%

Purchased		27.01		22.82		18	%		2.3		1.9		21	%

Total		25.71		23.58		9	%		5.8		8.4		(31	)%

18 CAMECO CORPORATION

First six months

Production volumes for the first six months of the year were 4% lower than in the previous year due to planned variations in mill production at Rabbit Lake. See Operating properties for more information.

For the first six months of 2011, uranium revenues were down 16% compared to 2010, due to a 20% decline in sales volumes partially offset by a 5% increase in the $Cdn realized selling price. As we anticipated, deliveries in the second quarter were low.

Our realized prices were higher than the first six months of 2010 mainly due to higher $US prices under market-related contracts, partially offset by a less favourable exchange rate. In the first six 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) decreased by 11% ($323 million compared to $363 million in 2010). This was mainly the result of the following:

•

the 20% decline in sales volumes

•

average unit costs for produced uranium were 6% higher due to increased unit production costs relating to the lower production during the first six months. We continue to expect unit costs to increase by 0% to 5% for the year, compared to 2010.

•

average unit costs for purchased uranium were 23% higher due to increased purchases at spot prices

The net effect was a $48 million decrease in gross profit for the first six months.


	Unit cash cost of sale							Quantity sold
Six months	($Cdn/lb U₃O₈)							(million lbs)
ended June 30	2011		2010		change			2011		2010		change

Produced		25.58		24.22		6	%		7.5		11.0		(32	)%

Purchased		29.95		24.39		23	%		4.4		3.9		13	%

Total		27.17		24.27		12	%		11.9		14.9		(20	)%

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 June 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 June 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		44		46		50		54		57		61		65

2012		38		42		50		58		67		75		83

2013		46		48		56		64		73		81		88

2014		49		51		59		67		75		84		91

2015		46		50		59		68		78		88		96

2011 SECOND QUARTER REPORT 19

The table illustrates the mix of long-term contracts in our June 30, 2011 portfolio, and is consistent with our contracting strategy. The table has been updated to reflect deliveries made and contracts entered into up to June 30, 2011.

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)

20 CAMECO CORPORATION

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)


	Three months ended							Six months ended
	June 30							June 30
Highlights	2011		2010		change			2011		2010		change
Production volume (million kgU)		4.5		4.5		—			8.8		9.3		(5	)%

Sales volume (million kgU)		4.0		4.6		(13	)%		6.4		6.8		(6	)%

Realized price ($Cdn/kgU)		17.24		15.98		8	%		18.50		19.28		(4	)%

Cost of sales ($Cdn/kgU) (including DDR)		14.13		12.01		18	%		15.48		13.27		17	%

Revenue ($ millions)		70		73		(4	)%		119		131		(9	)%

Gross profit ($ millions)		13		18		(28	)%		19		41		(54	)%

Gross profit (%)		19		25		(24	)%		16		31		(48	)%

Second quarter

Total revenue was $3 million lower than in 2010 as an 8% increase in the average realized price for our fuel services products was offset by an 13% decrease in sales volumes.

Our $Cdn realized price for fuel services was affected by 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 4% ($57 million compared to $55 million in the second quarter of 2010) due to the mix of products delivered in the quarter which caused the average unit cost of sales to be 18% higher.

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

First six months

In the first six months of the year, total revenue decreased by 9% due to a 6% decrease in sales volumes and a 4% decline in the realized selling price.

The total cost of products and services sold (including DDR) increased by 11% ($100 million compared to $90 million in 2010) due to the increase in the unit cost of product sold. The average unit cost of sales was 17% higher due to lower production levels in the first six months of 2011 and the recognition of higher cost recoveries in 2010.

The net effect was a $22 million decrease in gross profit.

2011 SECOND QUARTER REPORT 21

Electricity

BPLP

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


Highlights	Three months ended June 30									Six months ended June 30
($ millions except where indicated)	2011			2010			change			2011			2010			change

Output — terawatt hours (TWh)		5.6			6.2			(10	)%		12.0			13.0			(8	)%

Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		78	%		86	%		(9	)%		85	%		92	%		(8	)%

Realized price ($/MWh)		55	¹		58			(5	)%		54	²		58			(7	)%

Average Ontario electricity spot price ($/MWh)		28			37			(24	)%		30			35			(14	)%

Revenue		314			359			(13	)%		654			753			(13	)%

Operating costs(net of cost recoveries)		270			247			9	%		503			456			10	%

Cash costs		224			205			9	%		410			373			10	%
Non-cash costs		46			42			10	%		93			83			12	%

Income before interest and finance charges		44			112			(61	)%		151			297			(49	)%

Interest and finance charges		10			7			43	%		16			14			14	%

Cash from operations		121			226			(46	)%		240			391			(39	)%

Capital expenditures		58			56			4	%		97			73			33	%

Distributions		55			155			(65	)%		125			305			(59	)%

Operating costs ($/MWh)		47	¹		40			18	%		41	²		35			17	%


¹		Three months ended June 30, 2011 are based on actual generation of 5.6 TWh plus deemed generation of 0.2 TWh

²		Six months ended June 30, 2011 are based on actual generation of 12.0 TWh plus deemed generation of 0.2 TWh

Our earnings from BPLP



Highlights				Three months ended June 30							Six months ended June 30
($ millions except where indicated)	2011				2010			change			2011			2010			change

BPLP’s earnings before taxes (100%)		34				105			(68	)%		135			283			(52	)%

Cameco’s share of pretax earnings before adjustments (31.6%)		11				33			(67	)%		43			89			(52	)%

Proprietary adjustments		(1	)			(1	)		—			(3	)		(2	)		(50	)%

Earnings before taxes from BPLP		10				32			(69	)%		40			87			(54	)%

Second quarter

Total electricity revenue decreased 13% this quarter compared to the second quarter of 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 $123 million this quarter under its agreement with the OPA, compared to $80 million in the second quarter of 2010. About 60% of BPLP’s output was sold under financial contracts this quarter, compared to 39% in the second 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 78% this quarter, down from 86% in the second quarter of 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 $270 million compared to $247 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

The result was a 69% decrease in our share of earnings before taxes.

22 CAMECO CORPORATION

BPLP distributed $55 million to the partners in the second quarter. Our share was $17 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

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

First six months

Total electricity revenue for the first six months decreased 13% 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 $232 million in the first six months of 2011 under its agreement with the OPA, compared to $183 million in the first six months of 2010. The equivalent of about 48% of BPLP’s output was sold under financial contracts in the first six months of this year, compared to 39% 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 85% for the first six months of this year, down from 92% 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 $503 million compared to $456 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

The result was a 54% decrease in our share of earnings before taxes.

BPLP distributed $125 million to the partners in the first six months of 2011. Our share was $40 million.

2011 SECOND QUARTER REPORT 23

Our operations and development projects

Uranium — production overview

Our production this quarter was 16% higher than a year ago, mainly due to a change in the production schedule at McArthur/Key Lake. Due to planned variations in mill production at Rabbit Lake, production was 4% lower for the first six months of the year. Production remains on track for the year. See Uranium 2011 Q2 updates for more information.

Uranium production


Cameco’s share	Three months ended June 30							Six months ended June 30
(million lbs U₃O₈)	2011		2010		change			2011		2010		change

McArthur River/Key Lake		3.7		2.5		48	%		6.2		6.2		—

Rabbit Lake		0.7		1.1		(36	)%		1.7		2.1		(19	)%

Smith Ranch-Highland		0.5		0.4		25	%		0.9		0.9		—

Crow Butte		0.2		0.2		—			0.4		0.4		—

Inkai		0.6		0.7		(14	)%		1.3		1.3		—

Total		5.7		4.9		16	%		10.5		10.9		(4	)%

Outlook

We have geographically diversified sources of production. We expect to produce about 123 million pounds of U₃O₈ over the next five years from the properties listed below. Our strategy is to double our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and projects under evaluation.

Cameco’s share of production — annual forecast to 2015


Current forecast
(million lbs U₃O₈)	2011		2012		2013		2014		2015

McArthur River/Key Lake		13.1		13.1		13.1		13.1		13.1

Rabbit Lake		3.6		3.6		3.6		3.6		3.6

US ISR		2.5		2.7		2.8		3.8		4.1

Inkai		2.7		3.1		3.1		3.1		3.1

Cigar Lake		—		—		1.0		2.0		5.6

Total		21.9		22.5		23.6		25.6		29.5

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

Our 2011 and future annual production targets assume Inkai:

•

obtains the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis)

•

ramps up production to an annual rate of 5.2 million pounds this year

We expect Inkai to receive all of the necessary permits and approvals to meet its 2011 and future annual production targets and we anticipate it will be able to ramp up production as noted above.

There is no certainty, however, that Inkai will receive these permits or approvals or that it will be able to ramp up production this year. If Inkai does not receive the permits and approvals it needs, if they are delayed, or if it is unable to ramp up production, Inkai may be unable to achieve its 2011 and future annual production targets.

24 CAMECO CORPORATION

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

2011 SECOND QUARTER REPORT 25

Uranium 2011 Q2 updates

Operating properties

McArthur River/Key Lake

Production update

At McArthur River/Key Lake, production in the second quarter was 48% higher than the same period last year. To optimize production for the year, we rescheduled the maintenance outage at the Key Lake mill from the second quarter to the first quarter.

Operations update

At Key Lake, we continued work on the new oxygen, acid and steam plants. We expect to complete and commission the plants this 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 as we manage ore supply to ensure efficient operation of the mill.

Operations update

At the end of May we commenced the next phase of upgrades at the acid plant. We expect to complete this work during the planned maintenance shutdown in the third quarter and return the mill to full service in September.

Smith Ranch-Highland and Crow Butte

Production update

Production remains on schedule for the year.

Operations update

We continue to seek regulatory approvals to proceed with our Reynolds Ranch expansion and to expand and re-licence Crow Butte. We do not expect production to be impacted by these activities.

Inkai

Production update

Production is on track for the year.

Operations update

During the first six months, Inkai experienced brief interruptions to its sulphuric acid supply. This quarter, the supply shortage had a small impact on production. Sulphuric acid supply is tight in Kazakhstan due to competing demand from the fertilizer industry. We are exploring alternative sources of sulphuric acid; if availability continues to be an issue, production may be impacted for the year.

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

26 CAMECO CORPORATION

Development project

Cigar Lake

During the quarter, we established the freeze wall for shaft 2 and resumed shaft sinking. 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.

As part of our surface freeze strategy, we began drilling freezeholes from surface.

We received regulatory approvals for our mine plan and to begin work on our Seru Bay project. This project involves establishing the infrastructure to allow the release of treated water directly to Seru Bay of Waterbury Lake.

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.

In our first quarter MD&A we indicated our plan to file an updated technical report in the third quarter, updating our estimates, including our capital cost estimate, production rampup schedule, operating cost estimate and mineral reserve and resource estimates. We are currently evaluating a number of strategic initiatives which may favourably impact some of these estimates. This work may not be completed in the third quarter. Once we have completed our evaluation, decided on the best course of action and incorporated the results into our mine plan, we plan to file an updated technical report.

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 using our stage gate process. See our annual MD&A for more information regarding these projects.

Fuel services 2011 Q2 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc.

Springfields Fuels Ltd.

Production update

Fuel services production totalled 4.5 million kgU this quarter, the same as in the second quarter of 2010.

Production for the first six months of the year was 8.8 million kgU compared to 9.3 million kgU in the first six months of 2010. We experienced operational issues in the first quarter at the Port Hope conversion facility which were resolved following a two week shutdown. In the second quarter, we had a planned shutdown of the U0₂ plant to reduce inventory levels.

We expect total production to be between 15 million and 16 million kgU in 2011.

2011 SECOND QUARTER REPORT 27

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 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

•

Dave Neuberger, 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 2011, we paid PACL $32.9 million for construction and contracting services during the first six months (2010 — $9.7 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.

Controls and procedures

As of June 30, 2011, we carried out an evaluation under the supervision and with the participation of our management, including our CEO and 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 June 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 June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

28 CAMECO CORPORATION

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 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.

2011 SECOND QUARTER REPORT 29

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 second 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.

30 CAMECO CORPORATION


Second quarter update			4

Financial results			10

Our operations and development projects			24

Qualified persons			28

Additional information			28