EX-99.2

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 March 31, 2011(interim financial statements). The information is based on what we knew as of May 5, 2011 and updates the 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 quarter 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 starting on page 27 of this MD&A and 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 First 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 capital 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 expected delivery volumes for the second quarter being the lowest for the year and the fourth quarter deliveries accounting 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

•		the discussion of the expected impact of IFRS on our financial reporting and business activities

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

•		we are affected by new IFRS standards or changes in the standards or their interpretation

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, 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

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

2011 First quarter report 3

First quarter update

As a pure-play nuclear energy investment, we are well positioned as the world continues to focus on nuclear as a source of 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.

Our performance


		Three months ended
Highlights		March 31
($ millions except where indicated)		2011		2010		change

Revenue			454		485		(6	)%
Gross profit			136		184		(26	)%
Net earnings			91		143		(36	)%
$ per common share (diluted)			0.23		0.36		(36	)%
Adjusted net earnings (non-IFRS measure, see pages 10 and 11)			85		112		(24	)%
$ per common share (adjusted and diluted)			0.21		0.28		(25	)%
Cash provided by operations (after working capital changes)			266		146		82	%
Average realized prices	Uranium $US/lb		48.06		42.34		14	%
	$Cdn/lb		48.60		45.79		6	%
	Fuel services $Cdn/kgU		20.63		26.06		(21	)%
	Electricity $Cdn/MWh		53.00		58.00		(9	)%

First quarter

Net earnings attributable to our shareholders (net earnings) this quarter were $91 million ($0.23 per share diluted) compared to $143 million ($0.36 per share diluted) in the first quarter of 2010. In addition to the items noted below, our net earnings were impacted by lower gains on derivatives. While the Canadian dollar strengthened in the first three months of 2011, it strengthened to a greater extent in the first three months of last year.

On an adjusted basis, our earnings this quarter were $85 million ($0.21 per share diluted) compared to $112 million ($0.28 per share diluted) (non-IFRS measure, see pages 10 and 11) in the first quarter of 2010. The decline was due to:

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

•		lower earnings from our fuel services business due to lower average realized prices

•		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

See Financial results by segment for more detailed discussion.

4 cameco corporation

Operations update


		Three months ended
Highlights		March 31
March 31		2011		2010		change

Uranium	Production volume (million lbs)		4.7		6.1		(23	)%
	Sales volume (million lbs)		6.1		6.6		(8	)%
	Revenue ($ millions)		297		302		(2	)%
Fuel services	Production volume (million kgU)		4.3		4.8		(10	)%
	Sales volume (million kgU)		2.4		2.2		9	%
	Revenue ($ millions)		49		58		(16	)%
Electricity	Output (100%) (TWh)		6.4		6.8		(6	)%
	Revenue (100%) ($ millions)		340		394		(14	)%
	Our share of earnings before taxes ($ millions)		30		55		(45	)%

Production in our uranium segment this quarter was down 23% compared to the first quarter of 2010 mainly due to a change in the production schedule at McArthur River/Key Lake. At McArthur River, we decided to remove abandoned freezepipes from the new production chamber in zone 2, panel 5 prior to beginning production. This work resulted in lower ore deliveries to the Key Lake mill. To optimize production for the year, we rescheduled the maintenance outage at the Key Lake mill from the second quarter to the first quarter. We do not expect the change in the schedule to impact our production target for the year. See Uranium 2011 Q1 Updates for more information.

Some key highlights:

•		at Cigar Lake, we began to freeze the ground around shaft 2 and restarted freezing of the orebody

•		at Inkai, we received final approval for annual production of 3.9 million pounds (100% basis)

•		at Kintyre, we completed a mineral resource estimate

Production in our fuel services segment decreased by 10% this quarter compared to 2010 due to operational issues experienced at the Port Hope conversion facility, which were resolved following a two week shutdown. We continue to expect production to be between 15 million and 16 million kgU this year.

In our electricity segment, BPLP’s generation was 6% lower for the quarter compared to the same period last year. The capacity factor this quarter was 91%.

Uranium market update

Of note this quarter:

On March 11, 2011, Japan suffered a devastating earthquake and tsunami. This natural disaster resulted in significant human tragedy and widespread damage to infrastructure, including at the Fukushima-Daiichi nuclear power plant.

With events still unfolding, the long-term impact on nuclear power generation and global uranium supply and demand is unclear. However, we have reviewed our supply and demand outlook and revised our estimates to take into account the information that is currently available. We now expect world uranium demand will be 2.2 billion pounds over the next 10 years, compared to our previous estimate of 2.3 billion pounds, a 4% decline. Given our contract portfolio and marketing strategy, we expect the impact on Cameco to be significantly less.

We expect the nuclear renaissance will continue, although it may take a somewhat different shape. Almost every country with a nuclear program or contemplating a nuclear program has said it will take time to review existing and new plant designs. This may mean delays in licensing and permitting for new reactors and relicensing of existing reactors. We do not expect that reactors currently under construction will be significantly affected.

2011 First quarter report 5

With 437 operable reactors today, we expect a net increase of approximately 90 reactors by 2020, a decrease of 10% from our previous estimate of about 100.

Much of the growth in nuclear is expected to come from countries such as China, India, South Korea, United Arab Emirates and Turkey. These countries seek diversified sources of energy and security of supply at a time when energy demand is growing rapidly and is essential to an improved standard of living. So, while these countries will take time to incorporate lessons learned from Fukushima, all have recently reconfirmed their commitment to include nuclear as a necessary part of their energy mix.

We expect events in Japan will result in an 8% reduction in global uranium consumption in 2011 from our previous estimate of 195 million pounds. The decrease is primarily driven by the shutdown of six units at Fukushima and Germany’s decision to temporarily shut down seven of its oldest reactors and to place a three-month moratorium on the previously announced life extension of its reactor fleet. Some of these units in Germany will likely be shut down permanently. Nevertheless, we continue to expect annual world uranium consumption to be about 230 million pounds in 2020, an average annual growth rate of about 3% compared to our previous estimate of 2%. The increase in the growth rate is due to the lower expected consumption in 2011. We expect world consumption of UF₆ and UO₂ conversion services in 2011 to remain the same as 2010.

Over the next 10 years, we expect the new supply required to meet global uranium demand will be about 320 million pounds compared to our previous estimate of 400 million pounds. The decrease in new supply required is less than the decrease in expected global demand due to revised production forecasts from a number of producers. As a result of the revised forecasts, we expect global uranium production in 2011 will be about 145 million pounds compared to our previous estimate of 150 million pounds.

We expect about 70% of global uranium supply over the next 10 years to come from mines currently in commercial operation. We expect less than 20% to come from existing secondary supply sources and the remainder will come from new sources of supply.

The industry is responding in a responsible manner to the events in Japan and the increased safety concerns regarding nuclear power. Governments, regulators and the general public are looking for assurances that every segment of the industry has learned the lessons resulting from Fukushima. In the weeks and months ahead, this will mean reviewing and testing operating, safety and emergency response systems, and where necessary, taking action to implement changes.

We continue to monitor the situation at Fukushima. We will review all of the lessons learned from this event and, where applicable, we will incorporate them at all our facilities to ensure the health and safety of our employees, communities and the environment.

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.

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

6 cameco corporation

Other items of note this quarter:

The US Department of Energy (DOE) authorized the transfer of up to 1.2 million pounds U₃O₈ equivalent per quarter (annually no more than 4.2 million pounds) from its uranium inventories to fund accelerated clean up activities at the Portsmouth gaseous diffusion plant. Starting with the sale of about 0.9 million pounds U₃O₈ equivalent in the first quarter, the transfers are scheduled to run through the third quarter of 2013. The industry expects the DOE to adhere to its limitations, with total annual transfers under all its programs not to exceed 10% of the domestic US market (about 5.2 million pounds U₃O₈ equivalent).

USEC announced the signing of a new 10-year agreement with Russia’s Techsnabexport (Tenex) for the supply of commercial enrichment services beginning in 2013. The agreement enables USEC to access enrichment services from Russia to replace the Separative Work Units (SWU) of enrichment services that will be lost when the Russian highly enriched uranium (HEU) commercial agreement expires in 2013. The SWU will come from Russia’s commercial enrichment activities as opposed to the blend down of Russian weapons as is currently the case under the Russian HEU commercial agreement. The details of the transactions contemplated under the agreement, including US and Russian government to government implementing agreements and Russian regulatory approval, still need to be finalized. We do not expect the USEC/Tenex agreement to have an impact on the uranium or conversion markets.

Industry prices


	Mar 31		Dec 31		Mar 31		Dec 31
	2011		2010		2010		2009

Uranium ($US/lb U₃O₈)¹
Average spot market price		60.50		62.25		41.88		44.50
Average long-term price		70.00		66.00		59.00		61.00

Fuel services
($US/kgU UF₆)¹
Average spot market price
• North America		12.00		12.50		5.63		5.75
• Europe		12.00		12.50		7.50		8.00
Average long-term price
• North America		15.75		15.00		11.00		11.00
• Europe		16.00		15.25		12.75		12.75
Note: the industry does not publish UO₂prices.

Electricity ($/MWh)
Average Ontario electricity spot price		32.00		36.00		34.00		30.00


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 first quarter of 2011 was about 19 million pounds U₃O₈. This compares to about 13 million pounds in the first quarter of 2010.

After an increase in January, the situation at the Fukushima nuclear plant in Japan put downward pressure on the spot price. At the end of the quarter, the average spot price was $60.50 (US) per pound and has continued to drift down with Ux reporting $55.25 on May 2, 2011. Demand remains extremely discretionary and buyers are very price sensitive.

The long-term uranium price increased at the beginning of the quarter, declining slightly during the month of March, but ending the quarter higher than at the end of last year. Term contracting activity has been limited, but demand increased at the end of 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).

2011 First quarter report 7

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 rose at the beginning of the quarter, but fell in March to end the quarter slightly lower than at the end of 2010. Long-term UF₆conversion price indicators increased throughout the quarter.

Long-term fundamentals are strong

While the tragic events in Japan may result in increased scrutiny for the nuclear industry in the months ahead, we believe the long-term fundamentals remain positive. 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 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 May 4, 2011, we had:

•		394,702,685 common shares and one Class B share outstanding

•		8,722,872 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 Q1 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.


	Three months ended
Highlights	March 31
($ millions except per share amounts)	2011		2010		change

Revenue		454		485		(6	)%
Net earnings		91		143		(36	)%
$ per common share (basic)		0.23		0.36		(36	)%
$ per common share (diluted)		0.23		0.36		(36	)%
Adjusted net earnings (non-IFRS measure, see pages 10 and 11)		85		112		(24	)%
$ per common share (adjusted and diluted)		0.21		0.28		(25	)%
Cash provided by operations (after working capital changes)		266		146		82	%

Net earnings

Net earnings this quarter were $91 million ($0.23 per share diluted) compared to $143 million ($0.36 per share diluted) in the first quarter of 2010 due to:

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

•		lower earnings from our fuel services business due to lower average realized prices

•		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 gains on derivatives

2011 First quarter report 9

The following table shows the items that contribute to the difference between our Canadian GAAP and IFRS earnings for the three months ended March 31, 2010. For more information about these accounting differences see page 27 in this MD&A or note 3 to our interim financial statements.


2010 changes in earnings	Three months ended
($ millions)	March 31

Net earnings — Canadian GAAP		142

Accounting differences
Borrowing costs		(10	)
Decommissioning provision		(1	)
In-process research & development		3
Income taxes		8
All other		1

Total accounting differences		1

Net earnings — IFRS		143

Adjusted net earnings (non-IFRS/GAAP measures)

Adjusted net earnings is a measure with no standardized meaning under IFRS (non-IFRS measure). We use adjusted net earnings as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our net earnings adjusted for unrealized mark-to-market gains and losses on our financial instruments, which we believe do not reflect underlying financial performance. 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 ended
	March 31
($ millions)	2011			2010

Net earnings		91			143
Adjustments (after tax)
Unrealized gains on financial instruments		(6	)		(31	)

Adjusted net earnings		85			112

10 cameco corporation

The table that follows describes what contributed to the changes in adjusted net earnings this quarter.


Change in adjusted net earnings		Three months ended
($ millions)		March 31

Adjusted net earnings — 2010			112

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		(8	)
	Higher realized prices ($US)		38
	Foreign exchange impact on realized prices		(21	)
	Higher costs		(16	)
	change — uranium		(7	)
Fuel services	Higher sales volumes		2
	Lower realized prices ($Cdn)		(13	)
	Higher costs		(5	)
	change — fuel services		(16	)
Electricity	Lower sales volumes		(3	)
	Lower realized prices ($Cdn)		(10	)
	Higher costs		(12	)
	change — electricity		(25	)
Other changes
Higher realized gains on derivatives & foreign exchange			14
Lower income taxes			4
Minority interest			1
Miscellaneous			2

Adjusted net earnings — 2011			85

See Financial results by segment for more detailed discussion.

Average realized prices


		Three months ended
		March 31
		2011		2010		change

Uranium	$US/lb		48.06		42.34	14	%
	$Cdn/lb		48.60		45.79	6	%

Fuel services	$Cdn/kgU		20.63		26.06	(21	)%

Electricity	$Cdn/MWh		53.00		58.00	(9	)%

2011 First quarter report 11

Quarterly trends


Highlights																					Canadian GAAP
($ millions except per share amounts)	2011											2010									2009

	Q1			Q4			Q3			Q2		Q1			Q4			Q3			Q2

Revenue		454			673			419			546		485			659			518			645
Net earnings		91			205			98			70		143			598			172			247
$ per common share (basic)		0.23			0.52			0.25			0.18		0.36			1.52			0.44			0.64
$ per common share (diluted)		0.23			0.51			0.25			0.18		0.36			1.52			0.44			0.64
Adjusted net earnings (non-IFRS/GAAP measures, see pages 10 & 11)		85			189			80			116		112			170			94			161
$ per share diluted		0.21			0.48			0.21			0.29		0.28			0.43			0.24			0.41
Earnings from continuing operations		91			205			98			70		143			174			195			269
$ per common share (basic)		0.23			0.52			0.25			0.18		0.36			0.44			0.49			0.68
$ per common share (diluted)		0.23			0.51			0.25			0.18		0.36			0.44			0.49			0.68
Cash provided by operations		266			111			(2	)		266		146			188			175			147
The table that follows presents the differences between net earnings and adjusted net earnings for the previous eight quarters.

																					Canadian GAAP
($ millions)	2011											2010									2009

	Q1			Q4			Q3			Q2		Q1			Q4			Q3			Q2

Net earnings		91			205			98			70		143			598			172			247
Adjustments (net of tax)
Unrealized losses (gains) on financial instruments		(6	)		(16	)		(18	)		46		(31	)		(4	)		(101	)		(108	)
Loss (earnings) from discontinued operations		—			—			—			—		—			(424	)		23			22

Adjusted net earnings (non-IFRS/GAAP measures, see pages 10 & 11)		85			189			80			116		112			170			94			161

Key things to note:

•		Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 65% of consolidated revenues in the first 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 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
	March 31
($ millions)	2011		2010		change

Direct administration		31		29		7	%
Stock-based compensation		3		2		50	%

Total administration		34		31		10	%

Direct administration costs were $31 million this quarter, or $2 million higher than the same period last year. 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 $18 million this quarter compared to $15 million in the same quarter in 2010, as activity at the Kintyre project in Australia increased. Exploration in 2011 is focused on Canada, Australia, Kazakhstan and the United States.

Gains and losses on derivatives

We recorded $24 million in mark-to-market gains on our financial instruments this quarter, compared to gains of $43 million in the first quarter of 2010. While the Canadian dollar strengthened in the first three months of 2011, it strengthened to a greater extent in the first three months of 2010.

Income taxes

In the first quarter of 2011, we recorded an income tax expense of $4 million compared to $17 million in the first quarter of 2010. The decline this quarter was mainly due to a $66 million decrease in pre-tax earnings, which was largely attributable to the decline in gains we recorded on derivatives and lower earnings in our electricity, fuel services and uranium businesses compared to 2010.

On an adjusted basis, we recorded an income tax expense of $1 million this quarter compared to $5 million in the first quarter of 2010. Our effective tax rate this quarter on an adjusted net earnings basis reflects an expense of 2% compared to 5% for the first quarter of 2010.

Foreign exchange

At March 31, 2011:

•

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $0.97 (Cdn), down from $1.00 (US) for $0.99 (Cdn) at December 31, 2010. The exchange rate averaged $1.00 (US) for $0.99 (Cdn) over the quarter.

•

We had foreign currency contracts of $1.3 billion (US) and EUR 92 million at March 31, 2011. The US currency contracts had an average exchange rate of $1.00 (US) for $1.02 (Cdn).

•

The mark-to-market gain on all foreign exchange contracts was $54 million compared to a $47 million gain at December 31, 2010. We received cash of $17 million this quarter related to the settlement of foreign exchange contracts.

2011 First quarter report 13

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 consolidated revenue, uranium revenue and capital expenditures has changed from the outlook in our 2010 annual MD&A. We explain the material 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	—	—	—	89%
Revenue	Increase	Increase	Increase	Decrease
compared to 2010	5% to 10%	10% to 15%¹	5% to 10%	10% to 15%
Unit cost of produced product sold (including	—	Increase	Increase	Increase
DDR)		0% to 5%²	2% to 5%	10% to 15%
Direct administration costs compared	Increase	—	—	—
to 2010³	15% to 20%
Exploration costs compared	—	Decrease	—	—
to 2010		5% to 10%
Tax rate	Recovery of 0% to 5%	—	—	—
Capital expenditures	$620 million⁴	—	—	$80 million


¹		Based on a uranium spot price of $55.25 (US) per pound (the Ux spot price as of May 2, 2011), a long-term price indicator of $70.00 (US) per pound (the Ux long-term indicator on April 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.

We now expect uranium revenues to increase by 10% to 15% over 2010 (previously a 15% to 20% increase), due to the strengthening of the Canadian dollar relative to the US dollar. Our previous expectation was based on an exchange rate assumption of $1.00 (US) for $1.00 (Cdn). Our updated expectation is based on the May 2, 2011 exchange rate of $1.00 (US) for $0.95 (Cdn). The change in the exchange rate also caused a change in our outlook for consolidated revenues. We now expect consolidated revenues to increase by 5% to 10% over 2010 (previously a 10% to 15% increase). To offset some of this decline, we expect additional value from our foreign exchange contracts.

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 second quarter to be the lowest for the year and the fourth quarter to account for about one-third of our 2011 sales volumes.

Our investment in Talvivaara is now being shown as a capital expenditure. As a result, our estimate of capital expenditures has increased to $620 million compared to our previous estimate of $575 million.

14 cameco corporation

Sensitivity analysis

For the rest of 2011:

•

a change of $5 (US) per pound in both the Ux spot price ($55.25 (US) per pound on May 2, 2011) and the Ux long-term price indicator ($70.00 (US) per pound on April 25, 2011) would change revenue by $29 million and net earnings by $21 million

•

a change of $5 in the electricity spot price would change our 2011 net earnings by $2 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 $15 million and adjusted net earnings by $5 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 $120 million higher this quarter than in 2010 due to lower working capital requirements. Working capital changes provided $171 million, primarily from a decrease in accounts receivable partially offset by an increase in uranium inventories during the quarter. In 2010, working capital consumed $50 million in cash largely due to increases in product inventories. Not including working capital requirements, our operating cash flows this quarter were down by $76 million, largely due to lower uranium sales volumes and a lower realized price for electricity. 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 March 31, 2011, the same as at December 31, 2010. At March 31, 2011, we had approximately $546 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 March 31, 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 March 31, 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.

2011 First quarter report 15

Balance sheet


($ millions except per share amounts)	Mar 31, 2011		Dec 31, 2010		change

Cash and short-term investments		1,383		1,260		10	%
Total debt		1,034		1,039		—
Inventory		601		533		13	%

Total cash and short-term investments at March 31, 2011 were $1,383 million, or 10% higher than at December 31, 2010, exceeding our total debt by $349 million.

Total debt declined by $5 million to $1,034 million at March 31, 2011. Of this total, $97 million was classified as current, down $2 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 13% to $601 million. This was the result of higher fuel services inventory, as sales were lower than production and purchases in the first three months of the year. In addition, the average carrying cost for uranium increased during the quarter due to material purchased at near-market prices and higher costs for produced uranium.

16 cameco corporation

Financial results by segment

Uranium


	Three months ended
	March 31
Highlights	2011		2010		change

Production volume (million lbs)		4.7		6.1		(23	)%
Sales volume (million lbs)		6.1		6.6		(8	)%
Average spot price ($US/lb)		67.58		41.79		62	%
Average realized price
($US/lb)		48.06		42.34		14	%
($Cdn/lb)		48.60		45.79		6	%
Cost of sales ($Cdn/lb U₃O₈) (including DDR)		32.30		29.51		9	%
Revenue ($ millions)		297		302		(2	)%
Gross profit ($ millions)		100		107		(7	)%
Gross profit (%)		34		35		(3	)%

First quarter

Production volumes this quarter were 23% lower compared to the first quarter of 2010 primarily due to lower production at McArthur River/Key Lake. See Operating Properties for more information.

Uranium revenues this quarter were down 2% compared to 2010, due to a 8% decline in sales volumes partially offset by a 6% increase in the $Cdn realized selling price.

Our realized prices this quarter were higher than the first quarter of 2010 mainly due to higher $US prices under market-related contracts, partially offset by a less favourable exchange rate. In the first quarter of 2011, our realized foreign exchange rate was $1.01 compared to $1.08 in the prior year.

Total cash cost of sales (excluding DDR) increased by 5% this quarter, to $175 million ($28.55 per pound U₃O₈). This was mainly the result of the following:

•

average unit costs for produced uranium were 14% higher due to increased unit production costs relating to the lower production during the quarter. 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 12% higher due to increased purchases at spot prices

The net effect was a $7 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 ended	($Cdn/lb U₃O₈)						(million lbs)
March 31	2011		2010		change		2011		2010		change

Produced		27.50		24.22		3.28		4.0		4.6		(0.6	)
Purchased		30.61		27.26		3.35		2.1		2.0		0.1

Total		28.55		25.14		3.41		6.1		6.6		(0.5	)

2011 First quarter report 17

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 March 31, 2011 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on March 31, 2011, and none of the assumptions listed below change.

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)


($US/lb U₃O₈)
Spot prices	$20		$40		$60		$80		$100		$120		$140

2011		41		43		48		52		57		62		67
2012		37		40		49		57		66		74		83
2013		43		46		54		63		72		81		89
2014		44		47		55		64		73		82		90
2015		41		45		55		65		75		86		95

The table illustrates the mix of long-term contracts in our March 31, 2011 portfolio, and is consistent with our contracting strategy. The table has been updated to reflect deliveries made and contracts entered into up to March 31, 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.

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)


	Three months ended
	March 31
Highlights	2011		2010		change

Production volume (million kgU)		4.3		4.8		(10	)%
Sales volume (million kgU)		2.4		2.2		9	%
Realized price ($Cdn/kgU)		20.63		26.06		(21	)%
Cost of sales ($Cdn/kgU) (including DDR)		17.77		15.86		12	%
Revenue ($ millions)		49		58		(16	)%
Gross profit ($ millions)		7		23		(70	)%
Gross profit (%)		14		40		(65	)%

First quarter

Total revenue decreased by 16% due to a 21% decline in the average realized price for our fuel services products partially offset by a 9% increase in sales volumes.

Our $Cdn realized price for fuel services was affected by the mix of products delivered in the quarter. In 2010, 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 20% ($42 million compared to $35 million in the first quarter of 2010) due to the increase in sales volume. The average unit cost of sales was 12% higher due to lower production levels in the first quarter of 2011 and the recognition of higher cost recoveries in the first quarter of 2010.

The net effect was a $16 million decrease in gross profit.

20 cameco corporation

Electricity

BPLP

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


	Three months ended
Highlights	March 31
($ millions except where indicated)	2011			2010			change

Output — terawatt hours (TWh)		6.4			6.8			(6	)%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		91	%		98	%		(7	)%
Realized price ($/MWh)		53			58			(9	)%
Average Ontario electricity spot price ($/MWh)		32			34			(6	)%
Revenue		340			394			(14	)%
Operating costs(net of cost recoveries)		233			209			11	%

Cash costs		186			168			11	%
Non-cash costs		47			41			15	%
Income before interest and finance charges		107			185			(42	)%
Interest and finance charges		6			7			(14	)%
Cash from operations		119			165			(28	)%
Capital expenditures		39			17			129	%
Distributions		70			150			(53	)%
Operating costs ($/MWh)		36			31			16	%

Our earnings from BPLP


	Three months ended
Highlights	March 31
($ millions except where indicated)	2011			2010			change

BPLP’s earnings before taxes (100%)		101			178			(43	)%
Cameco’s share of pretax earnings before adjustments (31.6%)		32			56			(43	)%
Proprietary adjustments		(2	)		(1	)		100	%
Earnings before taxes from BPLP		30			55			(45	)%

First quarter

Total electricity revenue decreased 14% this quarter compared to the first 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 $109 million this quarter under its agreement with the OPA, compared to $103 million in the first quarter of 2010. About 36% of BPLP’s output was sold under financial contracts this quarter, compared to 38% in the first quarter of 2010. From time to time BPLP enters the market to lock in the gains under these contracts.

The capacity factor was 91% this quarter, down from 98% in the first quarter of 2010 due to a planned outage. There were no planned outages in the first quarter of 2010. Operating costs were $233 million compared to $209 million in 2010.

The result was a 45% decrease in our share of earnings before taxes.

BPLP distributed $70 million to the partners in the first quarter. Our share was $22 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

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

2011 First quarter report 21

Our operations and development projects

Uranium — production overview

Our production this quarter was 23% lower than a year ago, mainly due to a change in the production schedule at McArthur/ Key Lake. See Uranium 2011 Q1 Updates for more information.

Key highlight:

•

Inkai received final approval to produce at 3.9 million pounds per year (100% basis)

Uranium production


	Three months ended
Cameco’s share	March 31
(million lbs U₃O₈)	2011		2010		change

McArthur River/Key Lake		2.4		3.7		(35	)%
Rabbit Lake		1.0		1.0		—
Smith Ranch-Highland		0.4		0.5		(20	)%
Crow Butte		0.2		0.2		—
Inkai		0.7		0.7		—

Total		4.7		6.1		(23	)%

Outlook

We have geographically diversified sources of production. We expect to produce about 125 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		3.1		3.1		3.7		3.8
Inkai		2.7		3.1		3.1		3.1		3.1
Cigar Lake		—		—		1.0		2.0		5.6

Total		21.9		22.9		23.9		25.5		29.2

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 (our share 3.1 million pounds)

•

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.

22 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 First quarter report 23

Uranium 2011 Q1 updates

Operating properties

McArthur River/Key Lake

Production update

At McArthur River, we decided to remove abandoned freezepipes from the new production chamber in zone 2, panel 5 prior to beginning production. This work resulted in lower ore deliveries to the Key Lake mill. To optimize production for the year, we rescheduled the maintenance outage at the Key Lake mill from the second quarter to the first quarter. We do not expect the change in the schedule to impact our production target for the year.

Operations update

At McArthur River, we began producing from the second raisebore chamber in zone 2, panel 5. We expect the addition of the second chamber will improve production efficiency.

At Key Lake, we began installing major equipment in the new oxygen plant. We also began mechanical, electrical and instrumentation work on the major equipment in the new acid and steam plants. We expect to complete and commission all three plants this year.

We are continuing to advance work on the environmental assessment for the Key Lake extension project and are working to maximize tailings capacity.

Rabbit Lake

Production update

Production is 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

We continued preparing for the second phase of upgrades at the acid plant. We expect to complete this work during the planned maintenance shutdown later this year.

We received regulatory approval to begin exploration-related development and diamond drilling at the Eagle Point Powell zone later this year. This work will help us gain a better understanding of the potential of this zone.

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.

24 cameco corporation

Inkai

Production update

Production is on track for the year.

Operations update

With the signing of the amendment to its resource use contract, Inkai received final approval to:

•

increase annual production from blocks 1 and 2 to 3.9 million pounds of U₃O₈ (100% basis)

•

undertake a five-year assessment program at block 3 to carry out delineation drilling, mineral resource estimation, construction and operation of a test leach facility, and completion of a feasibility study

Development project

Cigar Lake

In preparation for resuming shaft sinking, we began to freeze the ground around shaft 2. We also restarted freezing of the orebody from underground.

We continued to implement the surface freeze strategy and expect to begin drilling freezeholes from surface in the second 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.

In the technical report we filed in early 2010, we reported our share of the total capital cost for the Cigar Lake project as $912 million. This included completion of the underground development and surface construction, and completion of modifications at the Rabbit Lake and McClean Lake mills. In addition, our 2010 annual MD&A provided a capital cost estimate of $80 million to $85 million for the implementation of the surface freeze strategy.

We are currently incorporating 2010 developments into our Cigar Lake mine plan, including our decision to proceed with the surface freeze strategy. Once we have completed this work, we will review and update our estimates including our capital cost estimate, production rampup schedule, operating cost estimate and mineral reserve and resource estimates. We plan to provide revised estimates and file an updated technical report in the third quarter.

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

Kintyre

We completed a mineral resource estimate during the first quarter. It is based on 355 historical diamond drillholes and 261 new diamond drillholes.

Mineral resources

As at March 31, 2011 (100% basis — only the last column shows our share)
(tonnes in thousands; pounds in millions)


			Grade		Content		Our share
Category	Tonnes		% U₃O₈		(lbs U₃O₈)		(lbs U₃O₈)

Indicated		5,257.0		0.49		56.4		39.5
Inferred		505.0		0.47		5.3		3.7

2011 First quarter report 25

To test the mineralization at depth, we drilled approximately 40 additional holes. We will incorporate the results of this drilling program in our mineral resource estimate once the program is complete.

We continue to advance the project toward a development decision using our stage gate process. See our annual MD&A for more information regarding the milestones for this project.

Millennium

We continue to advance the project toward a development decision using our stage gate process. See our annual MD&A for more information regarding the milestones for this project.

Fuel services 2011 Q1 updates

Port Hope conversion services
Cameco Fuel Manufacturing Inc.
Springfields Fuels Ltd.

Production update

Fuel services production totalled 4.3 million kgU this quarter, compared to 4.8 million kgU in the first quarter of 2010. We experienced operational issues at the Port Hope conversion facility which were resolved following a two week shutdown.

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

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

•		Charles Foldenauer, operations director, JV Inkai

Cigar Lake

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

26 cameco corporation

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 $13.8 million for construction and contracting services during the first three months (2010 — $3.6 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

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 notes 2 and 6 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 March 31, 2011, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of March 31, 2011, the Chief Executive Officer and Chief Financial Officer concluded that:

•

the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required

•

such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure

There has been no change in our internal control over financial reporting during the quarter ended March 31, 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 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. IFRS 9 retains but simplifies the mixed measurement model and establishes two primary measurement categories for financial assets: 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. 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.

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 first 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.

Although IFRS has a conceptual framework that is similar to previous Canadian GAAP, there are significant differences in recognition, measurement and disclosure. The transition to the IFRS framework has resulted in several

2011 First quarter report 27

changes to our accounting policies that impact our financial reporting. The following are the more significant accounting differences:

Asset impairment

Under Canadian GAAP, we used a two-step approach to test for impairment:

•

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

•

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

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

•

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

The difference in accounting for asset impairment under IFRS could lead to greater volatility in reported earnings in future periods. The value-in-use test under IFRS uses discounted future cash flows, increasing the likelihood of asset impairment compared to the test under Canadian GAAP, which used undiscounted cash flow. IFRS also requires companies to reverse impairment losses (for everything except goodwill) if an impairment is reduced due to a change in circumstances. Canadian GAAP did not allow companies to reverse impairment losses. As at January 1, 2011, we have not recorded any impairment charges on transition to IFRS. We have, however, under IFRS reversed portions of impairment charges previously recorded. See Opening statement of financial position and interim period financial results under IFRS for more information.

Employee benefits

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

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

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

Share-based payments

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

Provisions (including asset retirement obligations)

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

•

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

•

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

•

the obligation can be reliably estimated

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

IFRS also measures provisions differently. For example:

•

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

•

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

Joint ventures

Under Canadian GAAP, we proportionately accounted for interests in jointly controlled enterprises, such as our interest in BPLP. The IASB has indicated that it expects to issue a new standard in 2011 that will replace IAS 31, Interests in Joint Ventures. It is considering Exposure Draft 9, Joint Arrangements (ED 9), which proposes that an entity recognize its interest in a jointly controlled enterprise using the equity method. However, it is uncertain when

28 cameco corporation

the new standard will become effective. Until then, we have elected under the current IFRS standard to continue to use the proportionate consolidation method to account for our interests in jointly controlled enterprises.

Income taxes

Under Canadian GAAP, we could not recognize deferred tax for a temporary difference that arises from intercompany transactions. We recorded the taxes related to these transactions as assets or liabilities, and then recognized them as a tax expense or recovery when the asset left the group or was otherwise used. IAS 12 requires entities to recognize deferred taxes for temporary differences that arise from intercompany transactions, and to recognize taxes paid or recovered in these transactions in the period incurred.

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

First-time adoption of IFRS

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

We analyzed the options available to us and have used the exemptions described in the table below. This is a summary of the most significant decisions relating to the transition to IFRS and IFRS 1 elections — it is not a complete list of decisions we were required or elected to make.


Business combinations		There is an option to apply IFRS 3, Business Combinations, retrospectively or prospectively from a date no later than the transition date.

		We have elected to apply IFRS 3 prospectively to all business combinations that occur after January 1, 2010 except as required under IFRS 1.

Fair value as deemed cost		There is an option to choose to use the fair value of an item of property, plant and equipment as deemed cost at the transition date or a previous revaluation under Canadian GAAP as deemed cost under IFRS.

		We have elected not to use fair value as deemed cost on January 1, 2010. Instead, these items are reported at cost as determined under IFRS.

Share-based payments		There is an option to apply IFRS 2, Share-Based Payments, to all equity instruments granted on or before November 7, 2002, and to those granted after November 7, 2002 only if they had not vested by the transition date.

		We have elected to apply IFRS 2 to all equity instruments granted after November 7, 2002 that had not vested as of January 1, 2010, and to all liabilities arising from share-based payment transactions that existed at January 1, 2010.

Borrowing costs		There is an option to apply IAS 23, Borrowing Costs, retrospectively, using a date we specify, or to capitalize borrowing costs for all qualifying assets when capitalization begins on or after January 1, 2010.

		We have elected to apply IAS 23 prospectively. For all qualifying assets, we expensed the borrowing costs we were capitalizing before January 1, 2010, and will capitalize qualifying borrowing costs after that date.

Employee benefits		IAS 19, Employee Benefits, requires entities to defer or amortize certain actuarial gains and losses, subject to certain provisions (corridor approach), or to immediately recognize them in equity.

		We have elected to recognize cumulative actuarial gains and losses on benefit plans in retained earnings at January 1, 2010.

Differences in currency translation		IAS 21, The Effects of Changes in Foreign Exchange Rates, requires the retrospective calculation of currency translation differences from the date a subsidiary or associate was formed or acquired. IFRS 1 provides the option of resetting cumulative translation gains and losses to zero at the transition date.

		We have elected to reset all cumulative translation gains and losses to zero in retained earnings at January 1, 2010.

2011 First quarter report 29


Decommissioning liabilities		There is an option to apply International Financial Reporting Interpretations Committee 1 (IFRIC 1), Changes in Existing Decommissioning, Restoration and Similar Liabilities, retrospectively or prospectively.

		IFRIC 1 requires us to add or deduct a change in our obligations to dismantle, remove and restore items of property, plant and equipment from the cost of the asset it relates to. The adjusted amount is then depreciated prospectively over the asset’s remaining useful life.

		We have elected to adopt IFRIC 1 prospectively at January 1, 2010.

Opening statement of financial position and interim period financial results under IFRS

The following tables include our estimates of the most significant differences between our 2010 Canadian GAAP and our IFRS earnings for interim periods and statement of financial position under IFRS as at January 1, 2010.

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

2010 financial results


2010 changes in earnings	Three months ended
($ millions)	Mar 31			Jun 30			Sep 30			Dec 31			2010

Net earnings — Canadian GAAP		142			68			98			207			515

Accounting differences
Borrowing costs¹		(10	)		(11	)		(11	)		(11	)		(43	)
Decommissioning provision²		(1	)		2			1			2			4
In-process research & development⁴		3			3			3			2			11
BPLP — pension and maintenance costs¹⁰		—			8			(2	)		—			6
Income taxes — tax effect on differences⁹		2			—			1			1			4
Income taxes — IFRS accounting difference⁹		6			—			8			6			20
All other		1			—			—			(2	)		(1	)

Total accounting differences		1			2			—			(2	)		1

Net earnings — IFRS		143			70			98			205			516

Adjustments
Unrealized losses (gains) on financial instruments		(31	)		46			(18	)		(16	)		(19	)

Adjusted net earnings (non-IFRS measure see pages 10 and 11)		112			116			80			189			497

30 cameco corporation

Opening statement of financial position (January 1, 2010)


	Canadian		Transitional
($Cdn Millions)	GAAP		adjustments			IFRS

Current assets
Cash and cash equivalents		1,101		—			1,101
Short-term investments		203		—			203
Accounts receivable		447		1			448
Inventories		453		(8	)		445
Supplies and prepaid expenses		169		—			169
Current portion of long-term receivables, investments and other		155		—			155

Total current assets		2,528		(7	)		2,521

Property, plant and equipment (1, 2, 3, 10)		4,068		(351	)		3,717
Intangible assets		98		—			98
Long-term receivables, investments and other (4, 5, 6)		667		(266	)		401
Investments in equity-accounted investees (4)		—		222			222
Deferred tax assets (9)		33		(9	)		24

Total non-current assets		4,866		(404	)		4,462

Total assets		7,394		(411	)		6,983

Current liabilities
Accounts payable and accrued liabilities		492		2			494
Current tax liabilities		31		—			31
Short-term debt		88		—			88
Dividends payable		24		—			24
Current portion of finance lease obligation		12		—			12
Current portion of other liabilities		29		—			29
Current portion of provisions		—		16			16
Deferred tax liabilities (9)		87		(87	)		—

Total current liabilities		763		(69	)		694

Long-term debt		794		—			794
Finance lease obligation		159		—			159
Provision for reclamation		258		(258	)		—
Other liabilities (5, 6, 10)		245		52			297
Provisions (2)		—		341			341
Deferred tax liabilities (9)		167		(59	)		108

Total non-current liabilities		1,623		76			1,699

Minority interest		164		(164	)		—
Shareholders’ equity
Share capital (8)		1,512		297			1,809
Contributed surplus		132		—			132
Retained earnings		3,159		(766	)		2,393
Other components of equity (7)		41		51			92

Total shareholders equity attributable to equity holders		4,844		(418	)		4,426
Non-controlling interest		—		164			164

Total shareholders’ equity		4,844		(254	)		4,590

Total liabilities and shareholders’ equity		7,394		(411	)		6,983

2011 First quarter report 31


¹		We have elected under IFRS 1 not to apply IAS 23, Borrowing Costs, retrospectively to borrowing costs incurred on the construction of qualifying assets that commenced prior to January 1, 2010. Accordingly, we have expensed all borrowing costs that had been previously capitalized under Canadian GAAP. New guidance from the IASB is pending and it is possible that our accounting may change as a result. At January 1, 2010, the effect was a $334 million decrease in property, plant and equipment and a corresponding decrease in retained earnings.

²		We have elected under IFRS 1 to apply IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities, prospectively to changes in decommissioning liabilities that occurred prior to January 1, 2010. No new liabilities were recognized as a result of the transition to IFRS. However, the measurement of existing liabilities according to the IFRS standards provides a different result. At January 1, 2010, the effect was a $57 million increase in provisions, a $53 million decrease in property, plant and equipment and a $110 million decrease in retained earnings.

		The foregoing adjustments to opening balances under IFRS resulted in a decrease in depreciation expenses relative to amounts recorded under Canadian GAAP in 2010.

³		IFRS requires the reversal of any previously recorded impairment losses where circumstances have changed such that the impairments had been reduced. We reviewed our previously recorded impairment losses and reversed a portion of the charges relating to certain of our in situ recovery mine assets located in the United States. At January 1, 2010, the effect was a $35 million increase in property, plant and equipment with a corresponding increase in retained earnings.

⁴		Under IFRS, in-process research and development (IPR&D) that meets the definition of an intangible asset is capitalized with amortization commencing when the asset is ready for use (i.e. when development is complete). Under Canadian GAAP, we have been amortizing IPR&D related to the acquisition of our interest in GE-Hitachi Global Laser Enrichment LLC, a development stage entity. We reversed cumulative amounts as at January 1, 2010. At January 1, 2010, the effect was a $19 million increase to investments in equity accounted investees and a corresponding increase in retained earnings.

		In calculating our earnings under IFRS for 2010, we reversed the full amount amortized under Canadian GAAP.

⁵		We have elected under IFRS 1 to reclassify all cumulative actuarial gains and losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date. At January 1, 2010, the effect was a $2 million decrease in long-term receivables, investments and other, a $12 million decrease in other liabilities and a corresponding $14 million decrease in retained earnings.

⁶		As a result of BPLP also transitioning to IFRS, we have recorded our share of BPLP’s transition adjustments. The most significant of BPLP’s IFRS transition adjustments results from cumulative actuarial losses. BPLP reclassified cumulative actuarial losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date. The effect was a $61 million decrease in long-term receivables and investments and other, and a $76 million increase in other liabilities and a corresponding decrease in retained earnings.

⁷		We have elected under IFRS 1 to deem all foreign currency translation differences that exist at the date of transition to IFRS to be zero at the date of transition. At January 1, 2010, the effect was a $50 million adjustment to the cumulative translation adjustment account and a corresponding decrease in retained earnings.

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

⁹		As a result of the changes in our opening balances on transition to IFRS, we reduced our deferred tax liabilities by $138 million.

		For our 2010 earnings under IFRS, the adjustments relating to income tax expense reflect the tax effects of other adjustments as well as an IFRS accounting difference related to intra-group transactions. Under IFRS, deferred tax

32 cameco corporation


		assets and liabilities are recognized for intra-group transactions whereas Canadian GAAP allowed for the recognition of deferred tax assets and liabilities only when the transaction was with a third party.

¹⁰		On transition to IFRS all actuarial losses were reclassified to retained earnings. Under IFRS, future actuarial gains and losses will be recognized through other comprehensive income to equity. Under Canadian GAAP, we amortized the actuarial losses related to our interest in BPLP. As well, under IFRS, the costs of major inspections are capitalized and amortized over the period to the next inspection. Under Canadian GAAP, we expensed the inspection costs related to our interest in BPLP.

Other updates

We have assessed the impact of the IFRS transition on our internal control over financial reporting and on our disclosure controls and procedures. Changes in accounting policies or business processes require additional controls or procedures to ensure the integrity of our financial disclosures. We have completed the design and implementation of the new controls. The transition to IFRS has not required any changes in our internal controls over financial reporting or our disclosure controls and procedures that have materially affected them or are reasonably likely to materially affect them.

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

2011 First quarter report 33


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 2.0% per year


Royalty rate		Canadian dollar sales price in excess of:

6%		$18.05
plus 4%		$27.07
plus 5%		$36.09


First quarter update			4

Financial results			9

Our operations and development projects			22

Qualified persons			26

Additional information			27