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Management’s discussion and analysis

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited consolidated financial statements and notes for the quarter ended June 30, 2010. The information is based on what we knew as of August 12, 2010 and updates our first quarter and annual MD&A included in our 2009 annual report.

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

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

About forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans 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, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples on pages 1 and 2).

•		It represents our current views, and can change significantly.

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

•		Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review our annual information form and our annual MD&A, which include a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

Forward-looking information is designed to help you understand management’s current views of our near and longer term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

Examples of forward-looking information in this MD&A

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

•		our expectations about future worldwide uranium supply and demand

•		our expectation that remaining uranium and fuel services deliveries will be heavily weighted to the fourth quarter of 2010

2010 SECOND QUARTER REPORT 1

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

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

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

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

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

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

•		our uranium price sensitivity analysis

•		our expectation that an amendment to the Subsoil Use Contract to extend the term of our block 3 licence and to increase annual Inkai production to 3.9 million pounds will be approved by the Kazakh government by the end of the third quarter of 2010

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

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

Material risks

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

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

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

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

•		we are unable to enforce our legal rights, or are subject to litigation or arbitration that has an adverse outcome

•		there are defects in title to our properties

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

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

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

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

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

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

•		our uranium and conversion suppliers fail to fulfil delivery commitments

•		delay or lack of success in remediating and developing Cigar Lake

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

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

•		new IFRS standards or changes in the standards or their interpretation

Material assumptions

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

•		expected production costs

•		expected spot prices and realized prices for uranium, and other factors discussed on page 16, Price sensitivity analysis: uranium

•		tax rates, foreign currency exchange rates and interest rates

•		decommissioning and reclamation expenses

•		reserve and resource estimates

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

•		our Cigar Lake remediation and development plans succeed

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

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

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

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

2 CAMECO CORPORATION

Second quarter update

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

Our vision is to be a dominant nuclear energy company producing uranium fuel and generating clean electricity. We are already one of the largest uranium producers in the world, and when we sold our gold segment late last year, became a pure-play nuclear energy investment.

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

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

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

Our performance

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

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


			Three months ended							Six months ended
Highlights			June 30							June 30
($ millions except where indicated)			2010		2009		change			2010		2009		change

Revenue				546		646		(15	)%		1,031		1,139		(9	)%

Gross profit				167		235		(29	)%		346		396		(13	)%

Net earnings				68		247		(72	)%		211		329		(36	)%

$ per common share (diluted)				0.17		0.63		(73	)%		0.53		0.85		(38	)%

Adjusted net earnings (non-GAAP, see page 8)				114		162		(30	)%		226		265		(15	)%

$ per common share (adjusted and diluted)				0.29		0.41		(29	)%		0.57		0.69		(17	)%

Cash provided by operations (after working capital changes)				272		147		85	%		405		327		24	%

		$US/lb		41.31		40.64		2	%		41.76		38.86		7	%
Average realized prices	Uranium	$Cdn/lb		43.00		51.45		(16	)%		44.23		49.31		(10	)%

	Fuel services	$Cdn/kgU		15.98		18.94		(16	)%		19.28		21.28		(9	)%

	Electricity	$Cdn/MWh		58.00		70.00		(17	)%		58.00		63.00		(8	)%

Second quarter

Net earnings this quarter were $68 million ($0.17 per share diluted) compared to $247 million ($0.63 per share diluted) in the second quarter of 2009. This decline was mainly the result of the $46 million in after-tax expense we recorded this quarter for unrealized mark-to-market losses on financial instruments, compared to a gain of $107 million in the second quarter of 2009.

2010 SECOND QUARTER REPORT 3

On an adjusted basis, our earnings this quarter were $114 million ($0.29 per share diluted) compared to $162 million ($0.41 per share diluted) (non-GAAP, see page 8) in the second quarter of 2009. This 30% decline was attributable to:

•		lower profits from our uranium business due to lower sales volumes and lower realized selling prices. In our uranium business, a stronger Canadian dollar resulted in lower $Cdn realized prices ($US realized prices increased by 2%). Our exchange rate averaged $1.04 compared to $1.27 a year ago. Lower costs plus the benefit of our currency hedging program partially offset the decline in sales volumes and realized prices.

•		lower profits from our fuel services and electricity businesses due to lower $Cdn realized prices, which were partially offset by higher sales volumes and lower costs

First six months

Net earnings in the first half of the year were $211 million ($0.53 per share diluted) compared to $329 million ($0.85 per share diluted) in the first half of 2009. This decline was mainly the result of a $15 million after-tax expense we recorded in the first six months for unrealized mark-to-market losses on financial instruments, compared to a gain of $83 million in 2009.

On an adjusted basis, our earnings for the first half of this year were $226 million ($0.57 per share diluted) compared to $265 million ($0.69 per share diluted) (non-GAAP, see page 8). This 15% decline was attributable to:

•		lower profits from our uranium business due to lower sales volumes and lower realized selling prices. In our uranium business, a stronger Canadian dollar resulted in lower $Cdn realized prices ($US realized prices increased by 7%). Our exchange rate averaged $1.06 compared to $1.27 a year ago. Lower costs plus the benefit of our currency hedging program partially offset the decline in sales volumes and realized prices.

•		lower profits in our electricity business due to lower realized prices, which were partially offset by higher output and lower costs

•		higher profits from our fuel services business due to higher sales volumes and lower costs, which were partially offset by lower $Cdn realized prices

Operations update


									Six months
		Three months ended							ended
Highlights		June 30							June 30
June 30		2010		2009		change			2010		2009		change

Uranium	Production volume (million lbs)		4.9		3.8		29	%		10.9		8.6		27	%

	Sales volume (million lbs)		8.4		8.5		(1	)%		14.9		15.6		(4	)%

	Revenue ($ millions)		364		443		(18	)%		668		779		(14	)%

Fuel services	Production volume (million kgU)		4.5		2.2		105	%		9.3		4.4		111	%

	Sales volume (million lbs)		4.6		4.1		12	%		6.8		6.0		13	%

	Revenue ($ millions)		78		82		(5	)%		138		135		2	%

Electricity	Output (100%) (TWh)		6.2		5.3		17	%		13.0		12.0		8	%

	Revenue (100%)		359		405		(11	)%		753		760		(1	)%

	Our share of earnings before taxes ($ millions)		24		40		(40	)%		78		84		(7	)%

Production in our uranium segment was 29% higher this quarter and 27% higher for the first half of the year than the same periods in 2009.

Key highlights:

•		The operating licence for McArthur River was amended to allow flexibility in the annual licensed production limit, similar to the approval Key Lake received in 2009.

•		At Inkai, completion of the processing facilities and a stable acid supply resulted in higher production than in the first half of 2009.

4 CAMECO CORPORATION

Routine operation of the Port Hope UF₆ plant increased production in our fuel services segment by 105% this quarter compared to 2009, and by 111% in the first half of the year. The Port Hope UF₆ plant did not operate for most of the first half of 2009.

In our electricity segment, BPLP’s generation was 17% higher for the quarter and 8% higher for the first six months, compared to the same periods last year. The capacity factor this quarter was 86%, and 92% for the first half of the year.

Uranium market update

There are several things of note this quarter.

As announced on June 24, 2010, we signed two agreements with Chinese utilities:

•		a long-term agreement with China Nuclear Energy Industry Corporation (CNEIC), a wholly-owned subsidiary of China National Nuclear Corporation, to supply approximately 23 million pounds of uranium through 2020. The deal with CNEIC is our first long-term uranium supply agreement with a major Chinese nuclear utility.

•		a long-term co-operation agreement with China Guangdong Nuclear Power Holding Co., Ltd. to pursue opportunities to supply uranium fuel for its growing fleet of nuclear power plants

We updated our ten-year world supply and demand forecast to reflect the startup of commercial operations at new uranium production centres and reactors in 2010. We continue to forecast that the world will consume just over 2 billion pounds of U₃O₈ over the next 10 years. We expect this demand will be met by the following sources:

•		about 75% of uranium supply is expected to come from mines that are currently in commercial operation, compared to our previous estimate of about 67%

•		existing secondary supplies are expected to supply about 20% of world uranium consumption, compared to our previous estimate of about 21%

•		about 5% is expected to come from new sources of primary production, compared to our previous estimate of about 12%

The government of Canada signed a civil nuclear co-operation agreement with India on June 28. The deal provides for the export of nuclear technology, equipment and uranium in support of India’s growing nuclear energy industry. Canada is the eighth nation to sign such a deal with India since 2008 when the Nuclear Suppliers Group lifted a 34 year ban on nuclear co-operation with India.

Industry prices


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

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

Fuel services ($US/kgU UF₆)¹
Average spot market price
• North America		7.00		5.63		7.00		8.50
• Europe		7.88		7.50		8.50		9.75
Average long-term price
• North America		11.25		11.00		12.25		12.25
• Europe		12.75		12.75		13.38		13.38
Note: the industry does not publish UO₂prices.

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


¹		Average of prices reported by TradeTech and Ux Consulting (Ux)

2010 SECOND QUARTER REPORT 5

On the spot market, where purchases call for delivery within one year, the volume reported for the second quarter of 2010 was about 9.6 million pounds U₃O₈. This is well below the record 24.3 million pounds purchased in the second quarter of 2009. For the first half of the year, spot purchases totalled 22.7 million pounds compared to 32.3 million pounds for the same period in 2009.

Spot uranium prices continued to trend down during the quarter. However, at the end of July the spot price increased significantly as market activity picked up and sellers looked for higher prices. Demand in the spot market continues to be extremely discretionary.

Long-term uranium prices remained at $59.00 (US) per pound throughout the quarter. Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices adjusted by inflation indices, and market referenced prices (spot and long-term indicators).

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

Spot market UF₆ conversion prices remained weak this quarter, although there was a small improvement at the end of June. Long-term UF₆ conversion prices were stable this quarter. Both the spot and long term indicators increased dramatically in the month of July due to increased demand for UF₆ conversion.

Long-term fundamentals are strong

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

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

Shares and stock options outstanding

At August 9, 2010, we had:

•		393,026,435 common shares and one Class B share outstanding

•		9,015,147 stock options outstanding, with exercise prices ranging from $5.75 to $55.00

Dividend policy

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

6 CAMECO CORPORATION

Financial results

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


2010 Q2 results
Consolidated financial results			7
Outlook for 2010			12
Liquidity and capital resources			13

Financial results by segment			15
Uranium			15
Fuel services			17
Electricity			18

Consolidated financial results

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


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

Revenue		546		646		(15	)%		1,031		1,139		(9	)%

Net earnings		68		247		(72	)%		211		329		(36	)%

$ per common share (basic)		0.17		0.63		(73	)%		0.54		0.86		(37	)%

$ per common share (diluted)		0.17		0.63		(73	)%		0.53		0.85		(38	)%

Adjusted net earnings (non-GAAP, see page 8)		114		162		(30	)%		226		265		(15	)%

$ per common share (adjusted and diluted)		0.29		0.41		(29	)%		0.57		0.69		(17	)%

Cash provided by operations (after working capital changes)		272		147		85	%		405		327		24	%

Net earnings

Net earnings this quarter were $68 million ($0.17 per share diluted) compared to $247 million ($0.63 per share diluted) in the second quarter of 2009. This was mainly the result of the $46 million in after-tax expense we recorded this quarter for unrealized mark-to-market losses on financial instruments, compared to a gain of $107 million in the second quarter of 2009.

Net earnings in the first half of the year were $211 million ($0.53 per share diluted) compared to $329 million ($0.85 per share diluted) in the first half of 2009. This was mainly the result of a $15 million after-tax expense we recorded in the first six months for unrealized mark-to-market losses on financial instruments, compared to a gain of $83 million in 2009. The Canadian dollar weakened slightly in the first half of 2010, while it strengthened in the first six months of 2009.

2010 SECOND QUARTER REPORT 7

Adjusted net earnings (non-GAAP measure)

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

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


	Three months ended					Six months ended
	June 30					June 30
($ millions)	2010		2009			2010		2009

Net earnings (GAAP measure)		68		247			211		329

Adjustments (after tax)

Losses from discontinued operations		—		22			—		19

Unrealized losses (gains) on financial instruments		46		(107	)		15		(83	)

Adjusted net earnings (non-GAAP measure)		114		162			226		265

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


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

Adjusted net earnings — 2009			162			265

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		(4	)		(12	)
	Lower realized prices ($Cdn)		(71	)		(76	)
	Lower costs		23			22

	change — uranium		(52	)		(66	)

Fuel services	Higher sales volumes		3			4
	Lower realized prices ($Cdn)		(14	)		(14	)
	Lower costs		4			17

	change — fuel services		(7	)		7

Electricity	Higher sales volumes		7			7
	Lower realized prices ($Cdn)		(36	)		(21	)
	Lower costs		15			15

	change — electricity		(14	)		1

Other changes
Realized gains on derivatives & foreign exchange			17			22
Reduced losses from associated companies			2			14
Income taxes			5			(21	)
Miscellaneous			1			4

Adjusted net earnings — 2010			114			226

8 CAMECO CORPORATION

Revenue


Change in revenue		Three months ended			Six months ended
($ millions)		June 30			June 30

Revenue - 2009			646			1,139

Uranium	Lower sales volumes, lower realized prices ($Cdn)		(80	)		(109	)

Fuel services	Higher sales volumes, lower realized prices ($Cdn)		(5	)		3

Electricity	Higher sales volumes, lower realized prices ($Cdn)		(15	)		(2	)

Revenue - 2010			546			1,031

See Financial results by segment for more detailed discussion.

Average realized prices


		Three months ended							Six months ended
		June 30							June 30
		2010		2009		change			2010		2009		change

	$US/lb		41.31		40.64		2	%		41.76		38.86		7	%
Uranium	$Cdn/lb		43.00		51.45		(16	)%		44.23		49.31		(10	)%

Fuel services	$Cdn/kgU		15.98		18.94		(16	)%		19.28		21.28		(9	)%

Electricity	$Cdn/MWh		58.00		70.00		(17	)%		58.00		63.00		(8	)%

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

Quarterly trends


Highlights
($ millions except per share amounts)	2010			2009					2008

		Q2	Q1		Q4	Q3	Q2	Q1		Q4	Q3

Revenue		546	485		659	518	646	493		640	329

Net earnings		68	142		598	172	247	82		31	136

$ per common share (basic)		0.17	0.36		1.52	0.44	0.63	0.22		0.08	0.39

$ per common share (diluted)		0.17	0.36		1.52	0.44	0.63	0.22		0.08	0.39

Adjusted net earnings (non-GAAP, see page 8)		114	111		169	94	162	103		179	128

$ per share diluted		0.29	0.28		0.43	0.24	0.41	0.27		0.49	0.37

Earnings from continuing operations		68	142		174	195	269	78		5	124

$ per common share (basic)		0.17	0.36		0.44	0.49	0.69	0.21		0.01	0.37

$ per common share (diluted)		0.17	0.36		0.44	0.49	0.69	0.21		0.01	0.37

Cash provided by operations		272	133		188	175	147	180		224	87

Key things to note:

•

Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 67% of consolidated revenues in the second quarter of 2010.

2010 SECOND QUARTER REPORT 9

•

The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments. For the rest of 2010, uranium and fuel services deliveries are expected to be heavily weighted to the fourth quarter — similar to 2009.

•

Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our results from period to period (see page 8 for more information).

•

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

•

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

Administration



	Three months ended				Six months ended
	June 30				June 30
($ millions)	2010		2009		2010		2009

Direct administration		30		26		59		52

Stock-based compensation		—		4		2		9

Total administration		30		30		61		61

Direct administration costs were $30 million in the quarter, or $4 million higher than the same period last year. Through the first six months of 2010, our direct administration costs were 13% higher than in 2009. The increases largely reflect an increase in our workforce necessary to achieve our strategic growth plans. Stock-based compensation expenses were nil in the quarter due to a decline in our share price.

Exploration

Uranium exploration expenses were $18 million this quarter compared to $12 million in the same quarter in 2009, as activity in Canada and at the Kintyre project in Australia increased. Exploration expenses in the first half of the year increased to $33 million from $22 million in 2009. Exploration in 2010 is focused on Canada, the United States, Mongolia, Kazakhstan, Australia and South America.

Gains and losses on derivatives

We recorded $60 million in mark-to-market losses on our financial instruments this quarter, compared to gains of $101 million in the second quarter of 2009. In the first half of the year, we recorded $17 million in mark-to-market losses on our financial instruments compared to gains of $72 million in 2009. The Canadian dollar weakened slightly in the first half of 2010, while it strengthened in the first six months of 2009. We voluntarily removed the hedging designation on our foreign currency forward sales contracts in 2008 and have since recognized unrealized mark-to-market gains and losses in earnings.

Income taxes

In the second quarter of 2010, we recorded an $18 million recovery of income taxes compared to an expense of $43 million in the second quarter of 2009. The decline this quarter was mainly due to a $264 million decrease in pretax earnings, which was largely attributable to the $60 million in losses we recorded on derivatives compared to $101 million in gains in 2009. Lower realized prices in 2010 also contributed to the decline in the tax expense.

On an adjusted basis, we recorded a net income tax recovery of $2 million this quarter compared to a $3 million expense in the second quarter of 2009. The decline in expense this quarter was mainly due to a $50 million decrease in pretax earnings (adjusted), which was largely attributable to the lower gross profit in the uranium business.

Our effective tax rate in this quarter on an adjusted net earnings basis was -2%, or 4% lower than in the second quarter of 2009. We recorded losses in our Canadian operations this quarter, whereas we reported net income in our Canadian operations in the second quarter of 2009. This resulted in the net recovery noted above.

10 CAMECO CORPORATION

In the first six months of 2010, we recorded an income tax expense of $7 million compared to $22 million in 2009. The decline in 2010 was mainly due to a $155 million decrease in pretax earnings, which was largely attributable to the $17 million in losses we recorded on derivatives compared to $72 million in gains in 2009.

On an adjusted basis, we recorded a net income tax expense of $12 million in the first six months of 2010 compared to a net recovery of $9 million in 2009. The increase in expense this year was mainly due to a change in the distribution of our taxable income. We earned a higher proportion of taxable income in jurisdictions with higher tax rates in the first half of this year.

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

Foreign exchange

At June 30, 2010:

•

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.06 (Cdn), up from $1.00 (US) for $1.02 (Cdn) at March 31, 2010. The exchange rate averaged $1.00 (US) for $1.03 (Cdn) over the quarter.

•

We had foreign currency contracts of $1.6 billion (US) and EUR 71 million at June 30, 2010. The US currency contracts had an average exchange rate of $1.00 (US) for $1.04 (Cdn).

•

The mark-to-market loss on all foreign exchange contracts was $26 million compared to a $59 million gain at March 31, 2010. We received cash of $24 million this quarter and $79 million for the first six months of the year related to the settlement of foreign exchange contracts.

Timing differences between the maturity dates and designation dates on previously closed hedge contracts can result in deferred gains or charges. At June 30, 2010, we had net deferred gains of $20 million. The table below shows when we will recognize the gains in earnings.


$ millions (Cdn)	2010		2011

Deferred gains (charges)		15		5

Sensitivity analysis

At June 30, 2010, every one-cent change in the value of the Canadian dollar versus the US dollar would change our net earnings by about $12 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.06 (Cdn).

2010 SECOND QUARTER REPORT 11

Outlook for 2010

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

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

Our outlook for 2010 reflects the growth expenditures necessary to help us achieve our strategy. Our outlook for uranium sales volume, uranium revenue, unit cost of product sold (including DDR) for electricity, consolidated direct administration costs, exploration costs, consolidated capital expenditures and capital expenditures for electricity has changed from the outlook in our 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	—	21.5 million lbs	14 to 16 million kgU	—

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

Capacity factor	—	—	—	About 90%

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

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

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

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

Tax rate	Less than 5%	—	—	—

Capital expenditures	$510 million⁴	—	—	$40 million


¹		Based on a uranium spot price of $46.50 (US) per pound (the Ux spot price as of August 9, 2010) and an exchange rate of $1.00 (US) for $1.03 (Cdn).

²		Assumes the unit cost of sale for produced material will decline by 2% to 5% and the unit cost of sale for purchased material will decline by 15% to 20%.

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

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

We expect uranium sales to be 30 million pounds in 2010, compared to our previous range of 31 million to 33 million pounds. This change is the result of two things:

•

some customers deferred deliveries under contracts until 2011

•

given the continued discretionary nature of spot market demand and the low level of spot market prices, we have reduced our expected spot market sales for this year

We participate in the uranium spot market from time to time, including making spot purchases to take advantage of opportunities to place the material into higher priced contracts. We determine the appropriate extent of our spot market activity based on the current spot price and various factors relating to our business.

We now expect uranium revenues to decline by 10% to 15% over 2009, compared to our previous expectation of a 5% to 10% decline due to the decrease in expected deliveries noted above.

12 CAMECO CORPORATION

We expect unit cost of product sold (including DDR) in our electricity segment to increase by less than 5% over 2009 mainly due to a change in the maintenance schedule that will move a fourth quarter planned outage into 2011. Previously, we expected unit costs to increase by 10% to 15% over 2009.

Capital expenditures in 2010 are expected be about $510 million, compared to our previous estimate of $552 million due to changes in the scheduling of some projects. We do not expect this reduction in capital expenditures in 2010 will impact our plans to double annual uranium production by 2018.

Sensitivity analysis

For the rest of 2010:

•

a change of $5 (US) from the Ux spot price on August 9, 2010 ($46.50 (US) per pound) would change revenue by $20 million and net earnings by $14 million

•

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

Liquidity and capital resources

Cash from operations

Cash from operations was $125 million higher this quarter than in 2009 due to much lower working capital requirements. Working capital changes provided $93 million, primarily from a decrease in accounts receivable. In 2009, working capital consumed $81 million in cash largely due to increases in accounts receivable and product inventories. Not including working capital requirements, our operating cash flows this quarter were down by $49 million, largely due to lower realized prices in all of our business segments. See Financial results by segment for details.

Cash from operations was $78 million higher for the first six months of 2010 than for the same period in 2009 mainly due to the settlement of foreign exchange contracts at favourable exchange rates. Not including working capital requirements, our operating cash flows in the first half of this year were up by $62 million.

Debt

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1.1 billion at June 30, 2010, unchanged from March 31, 2010. Our short-term borrowing and letters of credit facilities decreased by about $12 million this quarter. At June 30, 2010, we had approximately $529 million outstanding in letters of credit.

Credit ratings

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


Security	DBRS	S&P

Commercial paper	R-1 (low)	A-1 (low)¹

Senior unsecured debentures	A (low)	BBB+


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

Debt covenants

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

2010 SECOND QUARTER REPORT 13

Long-term contractual obligations and off-balance sheet arrangements

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

•

purchase commitments

•

financial assurances

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

Balance sheet


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

Cash and short-term investments		1,436		1,304		10	%

Total debt		1,037		1,041		—

Inventory		445		453		(2	)%

Total cash and short-term investments at June 30, 2010 were $1.4 billion, or 10% higher than at December 31, 2009, exceeding our total debt by $399 million.

Total debt declined by $4 million to $1,037 million at June 30, 2010. Of this total, $90 million was classified as current compared to $88 million at December 31, 2009. See notes 10 and 11 of our audited annual financial statements for more detail.

Total product inventories decreased by 2% to $445 million. This is the result of slightly lower uranium inventory, as sales were marginally higher than production and purchases in the first half of the year.

14 CAMECO CORPORATION

Financial results by segment

Uranium


	Three months ended							Six months ended
	June 30							June 30
Highlights	2010		2009		change			2010		2009		change

Production volume (million lbs)		4.9		3.8		29	%		10.9		8.6		27	%

Sales volume (million lbs)		8.4		8.5		(1	)%		14.9		15.6		(4	)%

Average spot price ($US/lb)		41.42		48.33		(14	)%		41.60		46.50		(11	)%
Average realized price
($US/lb)		41.31		40.64		2	%		41.76		38.86		7	%
($Cdn/lb)		43.00		51.45		(16	)%		44.23		49.31		(10	)%

Cost of sales ($Cdn/lb U₃O₈) (including DDR)		28.35		31.21		(9	)%		29.00		30.76		(6	)%

Revenue ($ millions)		364		443		(18	)%		668		779		(14	)%

Gross profit ($ millions)		119		171		(30	)%		221		287		(23	)%

Gross profit (%)		33		39		(15	)%		33		37		(11	)%

Second quarter

Production volumes this quarter were 29% higher than the same quarter in 2009 due to higher production at McArthur River/Key Lake, Inkai and Rabbit Lake. See Operating properties for more information.

Uranium revenues this quarter were down 18% compared to 2009, mainly due to a 16% decrease in our $Cdn realized price: the Canadian dollar was much stronger this quarter — our exchange rate averaged $1.04 compared to $1.27 a year ago. In $US, our realized price this quarter was 2% higher than the first quarter of 2009 mainly due to higher prices under fixed-price sales contracts.

Total cash cost of sales (excluding DDR) decreased by 13% this quarter, to $199 million ($23.58 per pound U₃O₈). This was mainly the result of the following:

•

average costs for produced uranium were lower by 15% due to higher production levels

•

average costs for purchased uranium were lower by 9% due to fewer purchases at spot prices

•

lower royalty charges

The net effect was a $52 million decrease in gross profit for the quarter.

First six months

Production volumes for the first half of the year were 27% higher than in the previous year due to higher production at McArthur River/Key Lake, Inkai and Rabbit Lake.

For the first six months of 2010, uranium revenues were down 14% compared to 2009, mainly due to a 10% decrease in our $Cdn realized price: our exchange rate averaged $1.06 compared to $1.27 a year ago. In $US, our realized price was 7% higher than in 2009 mainly due to the mix of contracts into which we delivered uranium. So far this year, deliveries have been more heavily weighted toward market related contracts.

Total cash cost of sales (excluding DDR) decreased by 10% in the first half of the year, to $366 million ($24.27 per pound U₃O₈). This was mainly the result of the following:

•

average costs for produced uranium were lower by 10% due to higher production levels

•

average costs for purchased uranium were lower by 10% due to fewer purchases at spot prices

•

sales volumes were 4% lower

The net effect was a $66 million decrease in gross profit for the first six months.

2010 SECOND QUARTER REPORT 15

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)
June 30	2010		2009		change			2010		2009		change

Produced		23.80		28.12		(4.32	)		6.5		5.4		1.1

Purchased		22.82		24.99		(2.17	)		1.9		3.1		(1.2	)

Total		23.58		26.99		(3.41	)		8.4		8.5		(0.1	)


Six months ended
June 30	2010		2009		change			2010		2009		change

Produced		24.22		26.79		(2.57	)		11.0		9.6		1.4

Purchased		24.39		27.21		(2.82	)		3.9		6.0		(2.1	)

Total		24.27		26.95		(2.68	)		14.9		15.6		(0.7	)

Price sensitivity analysis: uranium

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

The table has been updated to reflect deliveries made and contracts entered into up to June 30, 2010. It is designed to indicate how the portfolio of long-term contracts we had in place on June 30, 2010 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on June 30, 2010, 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

2010		39		41		44		47		51		54		57

2011		35		38		46		52		59		65		72

2012		37		40		49		57		65		74		82

2013		43		46		55		65		75		84		92

2014		44		47		56		65		76		86		94

In the table, our average realized price increases over time under all spot price scenarios. This illustrates the mix of long-term contracts in our June 30, 2010 portfolio, and is consistent with our contracting strategy.

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

16 CAMECO CORPORATION

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 volume of 30 million pounds in 2010 and every year following

Deliveries

•

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

•

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

Prices

•

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

•

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

Inflation

•

is 2.0% per year

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)


	Three months ended							Six months ended
	June 30							June 30
Highlights	2010		2009		change			2010		2009		change

Production volume (million kgU)		4.5		2.2		105	%		9.3		4.4		111	%

Sales volume (million kgU)		4.6		4.1		12	%		6.8		6.0		13	%

Realized price ($Cdn/kgU)		15.98		18.94		(16	)%		19.28		21.28		(9	)%

Cost of sales ($Cdn/kgU) (including DDR)		12.31		13.10		(6	)%		13.62		16.06		(15	)%

Revenue ($ millions)		78		82		(5	)%		138		135		2	%

Gross profit ($ millions)		18		25		(28	)%		40		33		21	%

Gross profit (%)		23		31		(26	)%		29		24		21	%

Second quarter

The Port Hope UF₆ conversion plant was fully operational this quarter. It had been shut down during most of the second quarter of 2009. Total revenue declined by 5% due to a lower average realized selling price. Our $Cdn realized price for UF₆ was affected by a less favourable exchange rate — our exchange rate averaged $1.04 in the second quarter compared to $1.27 in 2009.

The cost of products and services sold (including DDR) increased by 7% ($60 million compared to $56 million in the second quarter of 2009) due to a 12% increase in sales volume. The unit cost of sales was 6% lower as we allocated costs related to the UF₆ plant to inventory this quarter. In the second quarter of 2009, we expensed the majority of these costs, due to the plant shutdown.

The net effect was a $7 million decrease in gross profit.

First six months

In the first half of the year, total revenue increased by 2% due to a 13% increase in sales volumes, partially offset by a 9% decline in our average realized selling price. Our $Cdn realized price for UF₆ was affected by a less favourable exchange rate — our exchange rate averaged $1.06 in 2010 compared to $1.27 in 2009.

2010 SECOND QUARTER REPORT 17

The cost of products and services sold (including DDR) decreased by 4% ($98 million compared to $102 million in 2009) as the impact of the increase in sales volume was more than offset by a lower cost per unit sold. The unit cost of sales was 15% lower as we allocated costs related to the UF₆ plant to inventory during the first six months of this year. In 2009, we expensed the majority of these costs, due to the plant having been shut down throughout most of the first half.

The net effect was a $7 million increase in gross profit.

Electricity

BPLP

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


	Three months ended									Six months ended
Highlights	June 30									June 30
($ millions except where indicated)	2010			2009			change			2010			2009			change
Output — terawatt hours (TWh)		6.2			5.3			17	%		13.0			12.0			8	%

Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		86	%		75	%		15	%		92	%		86	%		7	%

Realized price ($/MWh)		58			70			(17	)%		58			63			(8	)%

Average Ontario electricity spot price ($/MWh)		37			23			61	%		35			33			6	%

Revenue		359			405			(11	)%		753			760			(1	)%

Operating costs(net of cost recoveries)		272			270			1	%		485			477			2	%

Cash costs		236			236			—			414			411			1	%
Non-cash costs		36			34			6	%		71			66			8	%

Income before interest and finance charges		87			135			(36	)%		268			283			(5	)%

Interest and finance charges		7			6			17	%		14			7			100	%

Cash from operations		202			217			(7	)%		367			319			15	%

Capital expenditures		31			37			(16	)%		48			49			(2	)%

Distributions		155			165			(6	)%		305			270			13	%

Operating costs ($/MWh)		44			51			(14	)%		37			40			(8	)%

Our earnings from BPLP


	Three months ended									Six months ended
Highlights	June 30									June 30
($ millions except where indicated)	2010			2009			change			2010			2009			change

BPLP’s earnings before taxes (100%)		80			129			(38	)%		254			276			(8	)%

Cameco’s share of pretax earnings before adjustments (31.6%)		25			41			(39	)%		80			87			(8	)%

Proprietary adjustments		(1	)		(1	)		—			(2	)		(3	)		(33	)%

Earnings before taxes from BPLP		24			40			(40	)%		78			84			(7	)%

Second quarter

Total electricity revenue decreased by 11% this quarter compared to the second quarter of 2009 as higher output was more than offset by lower realized prices. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $80 million this quarter under its agreement with the OPA, compared to $172 million in the second quarter of 2009. The equivalent of about 39% of BPLP’s output was sold under financial contracts this quarter, compared to 60% in the second quarter of 2009.

18 CAMECO CORPORATION

The capacity factor was 86% this quarter, up from 75% in the second quarter of 2009 due to fewer planned and unplanned outage days. Operating costs were $272 million compared to $270 million in 2009.

The result was a 40% decrease in our share of earnings before taxes.

BPLP distributed $155 million to the partners in the second quarter. Our share was $49 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

First six months

Total electricity revenue for the first half of the year decreased 1% compared to 2009, as higher output was more than offset by lower realized prices. BPLP recognized revenue of $183 million under its agreement with the OPA in the first half of 2010, compared to $172 million for the same period in 2009. The equivalent of about 39% of BPLP’s output was sold under financial contracts in the first six months of this year, compared to 62% in 2009.

The capacity factor was 92% for the first six months of this year, up from 86% in 2009 due to fewer planned and unplanned outage days. Operating costs were $485 million compared to $477 million in 2009.

The result was a 7% decrease in our share of earnings before taxes.

BPLP distributed $305 million to the partners in the first half of this year. Our share was $96 million.

2010 SECOND QUARTER REPORT 19

Our operations and development projects

Uranium – production overview

We increased production by 29% this quarter and 27% for the first half of the year compared to the same periods in 2009.

Key highlights:

•		McArthur River/Key Lake performed better than planned. We are beginning to see the benefits from our focus on reliability and maintenance over the last few years.

•		At Inkai, completion of the processing facilities and a stable acid supply resulted in higher production than in the first half of 2009.

Uranium production


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

McArthur River/Key Lake		2.5		2.0		25	%		6.2		5.6		11	%

Rabbit Lake		1.1		1.0		10	%		2.1		1.5		40	%

Smith Ranch-Highland		0.4		0.5		(20	)%		0.9		0.9		—

Crow Butte		0.2		0.2		—			0.4		0.4		—

Inkai		0.7		0.1		600	%		1.3		0.2		550	%

Total		4.9		3.8		29	%		10.9		8.6		27	%

Outlook

Our sources of production are diversified both geographically and geologically. As outlined below, we expect production to total 115.9 million pounds of U₃O₈ over the next five years. Our strategy is to double our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and other projects already in our portfolio.

Cameco’s share of production — annual forecast to 2014


Current forecast
(million lbs U₃O₈)	2010		2011		2012		2013		2014

McArthur River/Key Lake		13.1		13.1		13.1		13.1		13.1

Rabbit Lake		3.6		3.6		3.6		3.6		3.0

US ISR		2.5		2.6		3.0		3.4		3.8

Inkai		2.3		3.1		3.1		3.1		3.1

Cigar Lake		—		—		—		1.0		2.0

Total		21.5		22.4		22.8		24.2		25.0

In mid-June Inkai received approval in principle to increase annual production from blocks 1 and 2 to 3.9 million pounds U₃O₈ (100% basis), which is in line with Inkai’s production target for 2010. See Uranium 2010 Q2 updates for more information.

We expect Inkai to produce 5.2 million pounds of U₃O₈ per year starting in 2011 (our share 3.1 million pounds). Inkai will seek approval to produce at an annual rate of 5.2 million pounds in future years, subject to confirmation with our partner Kazatomprom.

We expect Inkai to receive the permits and approvals it requires to support these production plans.

20 CAMECO CORPORATION

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on page 2, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.

Assumptions

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

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

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

Material risks that could cause actual results to differ materially

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

•		we cannot obtain or maintain necessary permits or government approvals

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

2010 SECOND QUARTER REPORT 21

Uranium 2010 Q2 updates

Operating properties

McArthur River/Key Lake

Production update

Production increases for this quarter and the first six months of the year were largely the result of a shorter maintenance shut-down and improved startup at the Key Lake mill during the quarter compared to 2009. We are beginning to see the benefits from our focus on reliability and maintenance over the last few years.

Operations update

At Key Lake, construction is on schedule for the acid and oxygen plants. Installation of major equipment and structural steel are in progress.

At McArthur River, production from the zone 2, panel 5 mining area continues to be strong.

In zone 4, we completed the ventilation expansion required to begin production. Development work will continue in the third quarter.

The regulator approved an amendment to our operating licence for McArthur River, giving us flexibility in the annual licensed production limit, similar to the approval Key Lake received in 2009. McArthur River mine can produce up to 21 million pounds U₃O₈ per year as long as average annual production does not exceed 18.7 million pounds. If production is lower than 18.7 million pounds in any year, we can produce more in future years until we recover the shortfall. This provides us with an opportunity to recover the almost 5 million pounds in production shortfalls that have occurred since 2003.

After the Key Lake mill is revitalized, annual production will depend mainly on mine production. We are continuing to plan for annual production of 18.7 million pounds (100% basis) for the next few years.

We expect conciliation with unionized employees at the McArthur River/Key Lake operations will begin in the fall.

Rabbit Lake

Production update

Production for the first half of the year was higher than in the first half of 2009 as the mill operated for a longer period in the first quarter of 2010 than in the first quarter of 2009. 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

In early June, after we completed planned mill production, the scheduled mill maintenance shutdown began. We continued to work on replacing major components of the acid plant, increasing near-term surface water handling capacity, and studying future tailings expansion.

Installation of a new exhaust air raise remains on track. We expect the work will be complete in the latter half of the year.

22 CAMECO CORPORATION

Smith Ranch-Highland and Crow Butte

Production update

Production remains on schedule, and the variance for this quarter compared to the second quarter of 2009 is due to timing of new production areas.

Operations update

We will be submitting the licence renewal application for Smith Ranch-Highland to the regulators in the third quarter. We expect production to continue throughout the licence renewal process.

Inkai

Production update

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

Operations update

In mid-June, Inkai received approval in principle from the Kazakh government to:

•		amend the block 3 licence to provide for a five-year appraisal period to carry out delineation drilling, construction and operation of a test leach facility, and to complete a feasibility study

•		increase annual production from blocks 1 and 2 to 3.9 million pounds U₃O₈(100%basis) in accordance with Inkai’s production target for 2010

To complete the final stage of the approval process, Inkai recently submitted a draft amendment to the Subsoil Use Contract and supporting documents to the Kazakh government. We expect the contract amendment to be approved by the end of the third quarter of 2010.

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

Development project

Cigar Lake

This quarter we:

•		continued to clean up, inspect, assess and secure the underground development

•		made significant progress on freeze drilling at shaft 2, as part of our preparations to resume shaft sinking

•		continued on the environmental assessment required for regulatory approval to release treated water directly to Seru Bay of Waterbury Lake. Public consultations are close to completion.

•		initiated a surface drilling program designed to upgrade mineral resources. The program will continue for the rest of the year.

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

•		completing work to secure the underground

•		determining if additional remedial work is needed

•		beginning to restore the underground mine systems and infrastructure for construction to resume

•		increasing installed pumping capacity to 2,500 m³/hr

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

•		starting the field work to implement a surface freeze strategy that could potentially shorten the rampup period for the project and bring forward up to 10 million pounds of uranium production in the early years and improve project economics

2010 SECOND QUARTER REPORT 23

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 a development decision.

Fuel services 2010 Q2 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc. (CFM)

Springfields Fuels Ltd. (SFL)

Fuel services production totalled 4.5 million kgU this quarter, compared to 2.2 million kgU in the second quarter of 2009.

Production for the first half of the year was 9.3 million kgU compared to 4.4 million kgU in the first half of 2009.

Higher production in both this quarter and the first half of the year is largely due to the routine operation of the Port Hope UF₆ plant, which did not operate for the majority of the first half of 2009.

As announced on July 8, 2010, unionized employees in Port Hope voted to accept a new, three-year collective agreement. The new agreement expires June 30, 2013.

Qualified persons

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

McArthur River/Key Lake

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

•		Les Yesnik, general manager, Key Lake, Cameco

Inkai

•

Charles Foldenauer, general manager operations and development, Inkai

Cigar Lake

•

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

24 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 the first six months of 2010, we paid PACL $9.7 million for construction and contracting services (2009 — $20.3 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

Controls and procedures

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

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

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

New accounting pronouncements

International financial reporting standards (IFRS)

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

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

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

Phase 1: Preliminary study and diagnostic — complete

During this phase, we:

•		completed a high-level impact assessment

•		prioritized areas to evaluate in phase 2

•		developed a detailed plan for convergence and implementation

•		determined which information technology systems need to be modified to meet IFRS reporting requirements. We tested and implemented systems modifications by June 30, 2009.

2010 SECOND QUARTER REPORT 25

Phase 2: Detailed component evaluation — complete

During this phase, we:

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

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

•		specified all changes we needed to make to existing business processes

See the detailed status below.

Phase 3: Embedding – in progress

During this final phase, we will:

•		carry out the changes to our business processes

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

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

•		communicate the impact of the IFRS transition to external stakeholders

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

•		receive the board’s approval of the new statements

Progress update

During the quarter, we continued to evaluate key accounting policy alternatives and implementation decisions, but have not yet completed our analysis of the full accounting effects of adopting IFRS. We are nearing completion of our work relating to the quantification of our January 1, 2010 opening balances under IFRS. See Opening balances under IFRS for more information about the most significant differences expected between our Canadian GAAP and IFRS balances.

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

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

Asset impairment

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

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

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

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

•

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

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

26 CAMECO CORPORATION

Employee benefits

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

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

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

Share-based payments

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

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

Provisions (Including asset retirement obligations)

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

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

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

•		the obligation can be reliably estimated

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

IFRS also measures provisions differently. For example:

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

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

Joint ventures

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

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

Income taxes

Under Canadian GAAP, we credit (or charge) income tax directly to equity only when it relates to items that we are crediting (or charging) directly to equity in the same period. IAS 12, Income Taxes, requires companies to credit (or charge) income tax directly to equity whether or not the related item is credited (or charged) directly to equity in the same period. This means we may have to recognize some income tax effects directly in equity rather than through net income or loss.

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

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

2010 SECOND QUARTER REPORT 27

Convertible debentures

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

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

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

Exploration expenses

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

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

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

28 CAMECO CORPORATION

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 are analyzing the options available to us, and currently expect to use the exemptions in the table below. This is a summary of the changes we currently believe will be most significant when we transition to IFRS – it is not a complete list of changes we will be required or may elect to make. We are still working on our analysis and have not made final decisions about the accounting policies that are available. We are nearing completion of our work to quantify the expected impacts of these differences on our consolidated financial statements. See Opening balances under IFRS for more information.


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

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

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

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

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

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

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

2010 SECOND QUARTER REPORT 29

Opening balances under IFRS

During the second quarter, we neared completion of our work relating to the quantification of our January 1, 2010 balances under IFRS. Audit work on our opening balances under IFRS is well advanced but incomplete at this time.

The table below presents our current estimates of the most significant differences between our Canadian GAAP and IFRS balances as at January 1, 2010. This information reflects our most recent views, assumptions and expectations. However, circumstances may arise, such as changes in IFRS standards or interpretations of existing IFRS standards, which could alter the information presented below.


Accounting	Balance sheet	Change
difference	category	($ million)

Impairment reversal¹	Property, plant & equipment		35

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

Borrowing costs³	Property, plant & equipment		(330	)

Cumulative translation adjustment⁴	Cumulative translation adjustment		(50	)

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

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

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

Convertible debentures⁸	Share capital		297

Income taxes⁹	Deferred tax liabilities		(135	)

Amounts closed to retained earnings¹⁰	Retained earnings		(740	)

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


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

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

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

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

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

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

30 CAMECO CORPORATION


⁷		Under IFRS, IPR&D that meets the definition of an intangible asset is capitalized with amortization commencing when the asset is ready for use (i.e. when development is complete). Under Canadian GAAP, we have been amortizing IPR&D related to the acquisition of our interest in Global Laser Enrichment LLC, a development stage entity. At the transition date, we reversed the full amount amortized under Canadian GAAP.

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

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

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

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

Other updates

As we proceed with our transition, we are also assessing the impact on our internal controls over financial reporting, and on our disclosure controls and procedures. Changes in accounting policies or business processes could require the implementation of additional controls or procedures to ensure the integrity of our financial disclosures. We plan to design and test the effectiveness of new controls in 2010. We do not, however, anticipate any significant changes to be required in our internal control over financial reporting or our disclosure controls and procedures as a result of the transition to IFRS.

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

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

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

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

2010 SECOND QUARTER REPORT 31


Second quarter update			3
Financial results			7
Our operations and development projects			20
Qualified persons			24
Additional information			25