Exhibit 99.1

TSX: CCO NYSE: CCJ website: cameco.com currency: Cdn (unless noted)

2121 – 11th Street West, Saskatoon, Saskatchewan, S7M 1J3 Canada

Tel: (306) 956-6200 Fax: (306) 956-6201

Cameco reports second quarter financial results

• second quarter deliveries as expected

• sales, revenue and production guidance for the year reconfirmed

• at McArthur River, made productivity improvements to our 2013 production plan

• at Cigar Lake, preparing to test the jet boring system underground

• closed agreement to increase ownership at the Millennium project

Saskatoon, Saskatchewan, Canada, July 27, 2012

Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the second quarter ended June 30, 2012 in accordance with International Financial Reporting Standards (IFRS).

“We saw some declines in our results this quarter, but we are in-line to deliver on our sales, revenue and production guidance for the year” said Tim Gitzel, president and CEO.

“Our operations performed well and we are pleased with the continued progress we see, particularly the productivity improvements we made in our 2013 production plan at McArthur River and our success in further advancing our Cigar Lake project toward first production.

“There were also a number of other positive developments this quarter – our increased ownership interest at Millennium, our acquisition of NUKEM, and some reactor restarts in Japan, which we expect to pave the way for more restarts.

“So we continue to pursue our growth plans with an eye to the demand growth we see on the horizon.”

Highlights ($ millions except where indicated)	Three months ended June 30								Six months ended June 30
	2012			2011		change			2012		2011		change
Revenue		391			426		(8	)%		955		887		8	%
Gross profit		103			108		(5	)%		281		244		15	%
Net earnings		8			55		(85	)%		140		146		(4	)%
$ per common share (diluted)		0.02			0.14		(86	)%		0.35		0.37		(5	)%
Adjusted net earnings (non-IFRS, see page 5)		34			71		(52	)%		158		155		2	%
$ per common share (adjusted and diluted)		0.09			0.18		(50	)%		0.40		0.39		3	%
Cash provided by operations (after working capital changes)		(94	)		23		(509	)%		318		294		8	%

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Second quarter

As we disclosed in our first quarter report, our deliveries in the second quarter were low and we recorded a $30 million (US) expense related to a contract termination, which impacted our results. In the fourth quarter, we expect more than a third of our 2012 deliveries to occur and an improvement in our average realized uranium price due to pricing under the mix of contracts. Our sales and revenue guidance are unchanged for the year.

Net earnings attributable to our shareholders (net earnings) this quarter were $8 million ($0.02 per share diluted) compared to $55 million ($0.14 per share diluted) in the second quarter of 2011. On an adjusted basis, our earnings this quarter were $34 million ($0.09 per share diluted) compared to $71 million ($0.18 per share diluted) (non-IFRS measure, see page 5) in the second quarter of 2011, mainly due to:

• lower earnings from our uranium business based on lower sales volumes, lower realized prices and higher costs

• a $30 million (US) contract termination charge

• higher expenditures for exploration and administration

• partially offset by increased earnings from our electricity business

See Financial results by segment on page 6 for more detailed discussion.

First six months

Net earnings in the first six months of the year were $140 million ($0.35 per share diluted) compared to $146 million ($0.37 per share diluted) in the first six months of 2011. Net earnings were lower than in 2011 due to lower mark-to-market gains on foreign exchange derivatives and the items noted below.

On an adjusted basis, our earnings for the first six months of this year were $158 million ($0.40 per share diluted) compared to $155 million ($0.39 per share diluted) (non-IFRS measure, see page 5). The change was due to:

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

• partially offset by a $30 million (US) contract termination charge, and higher charges for administration and exploration

See Financial results by segment for more detailed discussion.

Of note this quarter:

As disclosed in our first quarter MD&A, we terminated a sales contract with one of our customers during the second quarter at a cost of about $30 million (US), which has been recorded as an expense in our financial statements for the period ended June 30, 2012. The contract included base-escalated pricing terms at rates well below current market prices, and provides for deliveries of 3.4 million pounds covering the years 2012 through 2016, of which 0.8 million pounds is scheduled for 2012. We do not anticipate a significant impact on our financial results for 2012. Some of the material has already been placed into higher-priced contracts and we expect to place the remaining volumes as well. We do not anticipate terminating any other sales arrangements, unless it is expected to be financially beneficial to us.

On May 14, we announced we signed an agreement with Advent International to purchase NUKEM Energy GmbH (NUKEM) for $136 million (US) on closing, subject to certain adjustments. We will receive the benefits of owning NUKEM and the obligation for the company’s net debt of $164 million (US) as of January 1, 2012. As of June 30, 2012, NUKEM’s net debt was $114 million (US). We do not expect NUKEM to make any further payments on the balance of its debt prior to closing, which we now expect could occur in the third quarter. NUKEM is one of the world’s leading traders and brokers of nuclear fuel products and services.

Uranium market update

Since the previous quarter, the nuclear industry continues to experience near- to medium-term uncertainty; however, positive developments have emerged as well.

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In June, approval was given for the restart of two reactors at the Ohi plant in Japan’s Fukui prefecture. The approval was a result of support from the local authorities, and the units being confirmed safe by the Nuclear Safety Commission of Japan and the Nuclear and Industrial Safety Agency. Unit 3 was restarted July 2 and unit 4 on July 18.

The restarts are seen as critical to supplying power to the country through the hot summer months and as Japan works to rebuild its economy and the areas affected by the natural disasters. We also believe these initial restarts will help pave the way for additional restarts in the near future. From a long-term perspective, the government is still in the process of determining what Japan’s future energy mix will look like.

In June, Japan also passed a bill to establish a new national, independent nuclear regulatory body – the Nuclear Regulatory Authority (NRA). The new body is important to the future of the country’s nuclear program as part of a focus on improving safety, restoring public trust and bringing added certainty to the reactor restart approval process. The NRA is expected to be in place by September.

Overall, the uranium market continues to be in a wait and see mode as utilities are generally well covered for the next few years, and suppliers are similarly heavily committed. However, we have seen the emergence of some long-term contracting over the past few months.

Some clarity has been given around plans for the disposition of uranium from the US Department of Energy (DOE), which made an announcement in May. These changes amount to a potential increase in the disposition of excess DOE inventory in the near term. Previous DOE Secretarial Determinations have resulted in the disposition of roughly 5 million to 6 million pounds per year, equating to approximately 10% of annual US reactor consumption. The most recent Secretarial Determination outlined programs that could increase excess inventory dispositions to about 15% of annual US reactor consumption. While this announcement effectively introduces additional supply in the near term, we see some benefit in the added certainty around these inventories. To put the potential increase into perspective, it should also be noted that it will not be sufficient to balance the market once the Russian Highly Enriched Uranium (HEU) commercial agreement has expired, and that DOE programs and initiatives have not generally resulted in dispositions equal to volumes provided for under the Secretarial Determinations.

For the long term, a strong and promising growth profile remains for the industry. Ninety-five net new reactors are expected to be built over the next decade, more than 60 of which are currently under construction, driving a looming increase in demand. This translates into an expected annual average growth rate of about 3% for global uranium consumption.

This growth is expected at a time when supply is challenged: a number of new primary supply projects have been put on hold, and a major source of secondary supply – the Russian HEU commercial agreement – is coming to an end after 2013. That alone is the equivalent of removing a mine producing 24 million pounds of uranium per year from the market.

At Cameco, we are well positioned to meet this growing demand and help fill the supply gap by increasing our annual production to 40 million pounds by 2018. We have an extensive base of mineral reserves and resources near existing infrastructure, diversified sources of supply, global exploration program and long-term sales contracts. We are preparing our assets and will continue to look for opportunities to ensure we are among the first to respond to changing market conditions with a continued focus on profitability.

Outlook for 2012

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 capital requirements without the need for significant additional funding. Cash balances will decline as we use the funds in our business and pursue our growth plans.

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Our outlook for 2012 reflects the growth expenditures necessary to help us achieve our strategy. Our outlook for consolidated tax rate, consolidated capital expenditures, electricity capacity factor and electricity average unit cost of sales (including D&A) has changed. We explain the changes below. All other items in the table are unchanged. We do not provide an outlook for the items in the table that are marked with a dash.

See Financial results by segment starting on page 6 for details.

2012 Financial outlook

	Consolidated	Uranium	Fuel services	Electricity
Production	—	21.7 million lbs	13 to 14 million kgU	—
Sales volume	—	31 to 33 million lbs	Decrease 10% to 15%	—
Capacity factor	—	—	—	93%
Revenue compared to 2011	Decrease 0% to 5%	Decrease 0% to 5%1	Decrease 10% to 15%	Increase 5% to 10%
Average unit cost of sales (including D&A)	—	Increase 0% to 5%2	Increase 10% to 15%	Decrease 15% to 20%
Direct administration costs compared to 20113	Increase 10% to 15%	—	—	—
Exploration costs compared to 2011	—	Increase 15% to 20%	—	—
Tax rate	Recovery of 5% to 10%	—	—	—
Capital expenditures	$680 million4	—	—	$70 million

¹  Based on a uranium spot price of $50.00 (US) per pound (the Ux spot price as of July 23, 2012), a long-term price indicator of $61.50 (US) per pound (the Ux long-term indicator on June 30, 2012) and an exchange rate of $1.00 (US) for $1.02 (Cdn).

²  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we decide to make discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

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

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

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. In the fourth quarter, we expect more than a third of our 2012 deliveries to occur and an improvement in our average realized uranium price due to pricing under the mix of contracts. However, not all delivery notices have been received to date, which could alter the delivery patterns.

We now expect a recovery of 5% to 10% for our consolidated tax rate (previously a 0% to 5% recovery). We received additional certainty on particular tax provisions that allowed us to recognize a $9 million recovery in our income tax expense.

We expect our capital expenditures to be about $680 million compared to our previous estimate of $620 million due to changes in scope and scheduling of some of our projects in northern Saskatchewan.

We now expect BPLP’s capacity factor for 2012 to be 93% compared to 95% as previously reported. The change in outlook is largely the result of increased outage days in the first half of the year.

BPLP now expects its average unit cost of sales (including D&A) for electricity to decrease by 15% to 20% over 2011 (previously a 5% to 10% decrease). Given the average price of electricity in Ontario for the first half of the year, BPLP expects a decrease in the amount of supplemental rent they will have to pay in 2012. In addition to base rent,

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BPLP pays an annual supplemental rent ($32 million for 2012) for each Bruce B operating reactor that increases with inflation. If the annual average price of electricity falls below $30 per megawatt hour, the supplemental rent decreases to $12 million per operating reactor.

Sensitivity analysis

For the rest of 2012:

• a change of $5 (US) per pound in both the Ux spot price ($50.00 (US) per pound on July 23, 2012) and the Ux long-term price indicator ($61.50 (US) per pound on June 30, 2012) would change revenue by $31 million and net earnings by $16 million

• a change of $5/MWh in the electricity spot price would change our 2012 net earnings by $2 million based on the assumption that the spot price will remain below the floor price of $51.62/MWh provided for under BPLP’s agreement with the Ontario Power Authority (OPA)

• a one-cent change in the value of the Canadian dollar versus the US dollar would change revenue by $4 million and adjusted net earnings by $1 million. This sensitivity is based on an exchange rate of $1.00 (US) for $1.02 (Cdn).

Adjusted net earnings (non-IFRS measure)

Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period.

Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently so you may not be able to make a direct comparison to similar measures presented by other companies.

The table below reconciles adjusted net earnings with our net earnings.

($ millions)	Three months ended June  30						Six months ended June 30
	2012			2011			2012			2011
Net earnings		8			55			140			146
Adjustments
Adjustments on derivatives1 (pre-tax)		35			22			25			12
Income taxes on adjustments to derivatives		(9	)		(6	)		(7	)		(3	)
Adjusted net earnings		34			71			158			155

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

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Financial results by segment

Uranium

Highlights	Three months ended June 30							Six months ended June 30
	2012		2011		change			2012		2011		change
Production volume (million lbs)		5.3		5.7		(7	)%		10.2		10.5		(3	)%
Sales volume (million lbs)		4.9		5.8		(16	)%		13.0		11.9		9	%
Average spot price ($US/lb)		51.33		55.04		(7	)%		51.53		61.31		(16	)%
Average long-term price ($US/lb)		61.00		68.33		(11	)%		60.67		69.67		(13	)%
Average realized price
($US/lb)		42.08		45.65		(8	)%		46.26		46.89		(1	)%
($Cdn/lb)		42.21		44.48		(5	)%		46.70		46.60		—
Average unit cost of sales ($Cdn/lb U3O8 ) (including D&A)		33.49		29.61		13	%		32.54		30.95		5	%
Revenue ($ millions)		206		256		(20	)%		607		554		10	%
Gross profit ($ millions)		42		86		(51	)%		184		186		(1	)%
Gross profit (%)		20		34		(41	)%		30		34		(12	)%

Second quarter

Production volumes this quarter were 7% lower compared to the second quarter of 2011 primarily due to lower production from McArthur River/Key Lake. See Operations and development project updates starting on page 10 for more information.

Uranium revenues this quarter were down 20% compared to 2011, due to a 16% decrease in sales volumes and a 5% decrease in the $Cdn realized selling price.

Our realized prices this quarter were lower than the second quarter of 2011 mainly due to lower $US prices under fixed-price contracts. In the second quarter of 2012, our realized foreign exchange rate was $1.00, compared to $0.97 for the prior year.

Total cost of sales (including D&A) decreased by 5% ($163 million compared to $171 million in 2011). This was mainly the result of the following:

• a 16% decrease in sales volumes

Partially offset by:

• higher royalty charges ($24 million in 2012; $13 million in 2011) due to increased deliveries of Saskatchewan-produced material

• average unit costs for produced uranium being 13% higher due to increased non-cash production costs at our ISR locations and lower total production

The net effect was a $44 million decrease in gross profit for the quarter.

First six months

Production volumes for the first six months of the year were 3% lower than in the previous year due to lower output at Smith Ranch-Highland and Inkai. See Operations and development project updates starting on page 10 for more information.

For the first six months of 2012, uranium revenues were up 10% compared to 2011, due to a 9% increase in sales volumes. As we anticipated, deliveries in the second quarter were low.

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Our $US realized prices were lower than the first six months of 2011 mainly due to lower prices under market-related contracts being offset by a more favourable exchange rate. In the first six months of 2012, our realized foreign exchange rate was $1.01 compared to $0.99 in the prior year.

Total cost of sales (including D&A) increased by 15% ($423 million compared to $368 million in 2011). This was mainly the result of the following:

• the 9% increase in sales volumes

• average unit costs for produced uranium were 5% higher due to increased unit production costs relating mainly to the lower production during the first six months. We continue to expect unit costs to increase by 0% to 5% for the year compared to 2011.

• royalty charges in 2012 were $22 million higher due to increased deliveries of Saskatchewan-produced material

• partially offset by average unit costs for purchased uranium being 22% lower due to decreased purchases at spot prices

The net effect was a $2 million decrease in gross profit for the first six months.

The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures see below). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

($Cdn/lb)	Three months ended June 30							Six months ended June 30
	2012		2011		change			2012		2011		change
Produced
Cash cost		20.13		16.95		19	%		21.21		19.38		9	%
Non-cash cost		7.87		5.89		34	%		7.70		6.46		19	%
Total production cost		28.00		22.84		23	%		28.91		25.84		12	%
Quantity produced (million lbs)		5.3		5.7		(7	)%		10.2		10.5		(3	)%
Purchased
Cash cost		24.38		26.93		(9	)%		28.18		35.90		(22	)%
Quantity purchased (million lbs)		2.4		2.8		(14	)%		3.8		4.2		(10	)%
Totals
Produced and purchased costs		26.87		24.19		11	%		28.71		28.71		—
Quantities produced and purchased (million lbs)		7.7		8.5		(9	)%		14.0		14.7		(5	)%

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.

These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the table on the following page presents a reconciliation of these measures to our unit cost of sales for the second quarters and first six months of 2012 and 2011.

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Cash and total cost per pound reconciliation

($ millions)	Three months ended June 30									Six months ended June 30
	2012			2011			change			2012			2011			change
Cost of product sold		130.7			148.1			(12	)%		358.8			322.8			11	%
Add / (subtract)
Royalties		(24.2	)		(13.5	)		79	%		(57.6	)		(36.0	)		60	%
Standby charges		(5.8	)		(5.5	)		5	%		(12.9	)		(10.8	)		19	%
Other selling costs		(0.4	)		(1.6	)		(75	)%		(2.4	)		(6.1	)		(61	)%
Change in inventories		64.9			44.5			46	%		37.5			84.3			(56	)%
Cash operating costs (a)		165.2			172.0			(4	)%		323.4			354.2			(9	)%
Add / (subtract)
Depreciation and amortization		32.4			22.4			45	%		63.8			44.8			42	%
Change in inventories		9.3			11.2			(17	)%		14.7			23.0			(36	)%
Total operating costs (b)		206.9			205.6			1	%		401.9			422.0			(5	)%
Uranium produced & purchased (millions lbs) (c)		7.7			8.5			(9	)%		14.0			14.7			(5	)%
Cash costs per pound (a ÷ c)		21.45			20.24			6	%		23.10			24.10			(4	)%
Total costs per pound (b ÷ c)		26.87			24.19			11	%		28.71			28.71			—

Please see our second quarter MD&A for updates to our uranium price sensitivity analysis.

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

Highlights	Three months ended June 30							Six months ended June 30
	2012		2011		change			2012		2011		change
Production volume (million kgU)		4.3		4.5		(4	)%		8.8		8.8		—
Sales volume (million kgU)		4.1		4.0		3	%		6.9		6.4		8	%
Realized price ($Cdn/kgU)		16.33		17.24		(5	)%		17.82		18.49		(4	)%
Average unit cost of sales ($Cdn/kgU) (including D&A)		14.07		14.13		—			14.90		15.48		(4	)%
Revenue ($ millions)		66		70		(6	)%		122		119		3	%
Gross profit ($ millions)		9		13		(31	)%		20		19		5	%
Gross profit (%)		14		19		(26	)%		16		16		—

Second quarter

Production volumes in the quarter were 4% lower than in 2011. Production is on track for the year.

Total revenue was $4 million lower than in 2011 due to a 5% decline in the average realized price for our fuel services products.

Our $Cdn realized price for fuel services was affected by the mix of products delivered in the quarter. In 2012, a higher proportion of fuel services sales were for UF₆, which typically yields a lower price than the other fuel services products.

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The total cost of sales (including D&A) was $57 million unchanged compared to the second quarter of 2011.

The net effect was a decrease of $4 million in gross profit for the quarter.

First six months

In the first six months of the year, total revenue increased by 3% due to an 8% increase in sales volumes, partially offset by a 4% decline in the realized selling price.

The total cost of products and services sold (including D&A) increased by 2% ($102 million compared to $100 million in 2011) due to the decrease in the unit cost of product sold. The average unit cost of sales was 4% lower due to the mix of products delivered in the first six months.

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

Electricity results

Second quarter

Total electricity revenue increased by 20% this quarter compared to the second quarter of 2011 due to higher output. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. BPLP recognized revenue of $225 million this quarter under its agreement with the OPA, compared to $123 million in the second quarter of 2011. About 66% of BPLP’s output was sold under financial contracts this quarter compared to 60% in the second quarter of 2011. From time to time BPLP enters the market to lock in the gains under these contracts. Gains on BPLP’s contracting activity were slightly higher than in 2011.

The capacity factor was 91% this quarter, up from 78% in the second quarter of 2011 as a result of no planned outage days. This was offset slightly by an increase in the number of unplanned outage days when compared to the second quarter of 2011. Operating costs were lower at $204 million compared to $270 million in 2011 mainly due to lower supplemental lease payments and lower maintenance costs.

The result was a $41 million increase in our share of earnings before taxes.

BPLP distributed $160 million to the partners in the second quarter, our share was $51 million. Also, BPLP made capital calls of $17 million to the partners in the second quarter, our share was $5 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 six months increased 9% compared to 2011 due to slightly higher output and higher realized prices. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. BPLP recognized revenue of $409 million in the first six months of 2012 under its agreement with the OPA, compared to $232 million in the first six months of 2011. The equivalent of about 64% of BPLP’s output was sold under financial contracts in the first six months of this year, compared to 48% in 2011. From time to time BPLP enters the market to lock in the gains under these contracts. Gains on BPLP’s contracting activity were slightly higher than in 2011.

The capacity factor was 88% for the first six months of this year, up from 85% in the second quarter of 2011 due to a lower volume of outage days during this year’s planned outage compared to last year’s planned outage. Operating costs were lower at $445 million compared to $503 million in 2011 mainly due to lower supplemental lease payments and lower maintenance costs. These decreases were partially offset by higher fuel costs in the first six months of 2012.

The result was a $38 million increase in our share of earnings before taxes.

BPLP distributed $190 million to the partners in the first six months of 2012, our share was $60 million. BPLP made capital calls of $33 million to the partners in the first six months of this year, our share was $10 million.

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Operations and development project updates

Uranium – production overview

Cameco’s share (million lbs U3O8)	Three months ended June  30							Six months ended June 30
	2012		2011		change			2012		2011		change
McArthur River/Key Lake		3.3		3.7		(11	)%		6.3		6.2		2	%
Rabbit Lake		0.9		0.7		29	%		1.8		1.7		6	%
Smith Ranch-Highland		0.3		0.5		(40	)%		0.6		0.9		(33	)%
Crow Butte		0.2		0.2		—			0.4		0.4		—
Inkai		0.6		0.6		—			1.1		1.3		(15	)%
Total		5.3		5.7		(7	)%		10.2		10.5		(3	)%

McArthur River/Key Lake

At McArthur River/Key Lake production was 11% lower in the second quarter compared to the same period last year. Production varies from quarter to quarter depending on the sequencing of mining raises and timing of planned maintenance shutdowns at the mill.

Production for the first six months of the year was 2% higher and is on track for the year.

At McArthur River, we have mitigated the risk to production in 2013 associated with the transition to the upper mining area of zone 4. We have made productivity improvements on cycle times, which may include the use of blasthole stoping in smaller, lower-grade areas of the mine located away from the freezewalls. In addition, we have changed the sequencing of the raises in zone 2, panel 5, which will improve productivity.

We are continuing to commission the new acid plant at Key Lake and address startup issues as they arise.

We are continuing to advance work on the environmental assessment for the Key Lake extension project. We have received comments from the regulators on our draft environmental impact statement and are working to address the questions and issues they have raised.

Rabbit Lake

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

We are continuing our underground reserve replacement drilling. We completed the first phase of our surface exploration drilling program, designed to test and evaluate areas east and northeast of the mine, as well as to the north and south. We are planning further field work in the second half of 2012.

Smith Ranch-Highland and Crow Butte

Production for the quarter and the first six months was lower compared to the same periods last year due to lower production from Smith Ranch-Highland. Our ability to bring new wellfields into production at Smith Ranch-Highland continues to be affected by the lengthened review process to obtain regulatory approvals.

We continue to seek regulatory approvals to proceed with expansions at our various satellite operations in Wyoming and Nebraska. The regulators are constrained by a shortage of resources as they try to work through a large volume of permit and licence amendment requests from resource companies, however we are beginning to receive some approvals. We continue to communicate with them to ensure we understand and meet their information needs in a timely manner.

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We have started the initial phases of construction for the satellite plant and the first wellfield at North Butte in Wyoming. Production is expected to start in 2013 and ramp up to a target annual production rate of more than 700,000 pounds per year by 2015.

Inkai

Production was unchanged for the quarter and 15% lower for the first six months compared to the same periods last year. As our existing wellfields mature, the grades decrease. Average grades at in situ recovery operations typically stabilize at levels lower than initial years as uranium is recovered from a mix of wellfields of varying maturities. We continue to bring on additional wellfields to maintain some new, typically higher grade, wellfields in the production mix. We have increased flow capacity at the Inkai operation and grades were starting to improve at the end of the second quarter.

We are pursuing government approval of an amendment to the resource use contract in order to implement the production increase from blocks 1 and 2 to 5.2 million pounds of U₃O₈ (100% basis).

We continue to advance delineation drilling at block 3. In July, Inkai received a construction permit and has begun work on the test leach facility.

In our annual MD&A, we discussed our strategy to implement our 2007 non-binding memorandum of understanding (MOU) with our partner, Kazatomprom, to increase future annual production capacity at Inkai to 10.4 million pounds (100% basis). In addition to the various partner and government approvals required, we also noted that we expected our ability to increase annual uranium production at Inkai would be closely tied to the success of a uranium conversion project. With their success in developing new mines, bringing on new production and signing long-term uranium supply contracts, Kazakhstan and Kazatomprom have stated their interest in furthering their participation in the nuclear fuel cycle by obtaining access to new technologies, their preference being in-country. However, they also recognize the current unfavourable market conditions that exist for UF₆ conversion. As such, we are working with them to identify the best way to meet their longer-term goals.

Cigar Lake

We continued to make solid progress at Cigar Lake this quarter. The Seru Bay pipeline has progressed to the point where we can use it in the event of a non-routine inflow.

We have lowered the main components of the jet boring system underground at site and have begun assembly. Once we have completed assembly, we will begin testing the system.

In shaft 2, we achieved breakthrough on the 500 metre level. For the remainder of the year we will focus on installing infrastructure, including construction of a concrete ventilation partition, installation of electrical cable, water services, ore slurry pipes and hoist systems.

We will focus on carrying out the remainder of our 2012 plans and implementing the strategies we outlined in our annual MD&A.

We continue to expect first commissioning in ore in mid-2013 and the first packaged pounds in the fourth quarter of 2013.

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

Millennium

As announced on June 11, 2012, our agreement with AREVA Resources Canada Inc. to purchase AREVA’s 27.94% interest in the Millennium project for $150 million has closed. With the closing, our interest in the Millennium project increases to 69.9%. The remaining 30.1% is owned by JCU (Canada) Exploration Co.

The terms of the purchase agreement provide AREVA with a 4% royalty on revenue from 27.94% of any production that exceeds 63 million pounds U₃O₈ from the project.

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We have submitted the draft environmental impact statement to the regulators. Comments on the draft are expected before the end of the year.

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

Kintyre

At Kintyre, we have completed the prefeasibility study. Given the measured and indicated mineral resource estimate of about 55 million pounds (100% basis) at an average grade of 0.58%, current uranium prices and continued cost escalation in Western Australia, the economics of the project are challenging. The study was based on an open pit mine with an estimated mine life of about seven years, estimated total production of about 40 million pounds of packaged uranium at an average production rate of about 6 million pounds per year. To break even, the prefeasibility study indicates the project would require an average realized price of about $67(US) or about 62 million pounds of packaged production using a uranium price similar to today’s spot price.

Despite the challenging economics, we are proceeding to a feasibility study and have accelerated our exploration drilling to determine if we can increase our mineral resource base, which would improve project economics. We continue to have a positive view of the long-term fundamentals of the uranium market and want to ensure our assets are ready to respond when the market signals new production is needed. We expect a feasibility study would take about eighteen months to complete.

Kintyre provides a potential opportunity for us to diversify our portfolio in mining method and geography. A decision to proceed with the feasibility study is not a production decision, but the next step in our stage gate process, which will provide us with more comprehensive information. Our decision to advance to production will ultimately be based on positive project economics.

Future supply of global primary uranium production is uncertain, while global consumption is quite predictable. We believe that to fuel the more than 60 reactors currently under construction and the further growth we expect by 2021, production will have to come from new primary sources of production. In today’s environment, those sources of production pose economic challenges, for us and other producers, similar to those we have identified at Kintyre.

Fuel services

Fuel services production totalled 4.3 million kgU for the quarter, 4% lower than the same period last year. Production for the first half of the year was 8.8 million kgU, unchanged compared to the same period last year. Production is on track for the year.

On July 6, we announced that unionized employees at our fuel manufacturing operations in Port Hope and Cobourg, Ontario voted to accept a new three-year collective agreement. The agreement includes a 5.25% wage increase over the term of the agreement. The previous agreement expired on June 1, 2012.

Qualified persons

The technical and scientific information discussed in this document for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:

McArthur River/Key Lake

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

• Dave Neuburger, vice-president, international mining, Cameco

• Les Yesnik, general manager, Key Lake, Cameco

Inkai

Cigar Lake

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

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Caution about forward-looking information

This document 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 document as forward-looking information.

Key things to understand about the forward-looking information in this document:

• 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 14, 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, first and second quarter 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 document

• our forecasts relating to termination of uranium sales contracts with our customers

• our expectation regarding the closing date for the NUKEM acquisition and that NUKEM will not make any further payments on its debt prior to closing

• our expectations about 2012 and future global uranium supply, consumption, demand, number of new reactors and restart of reactors in Japan including the discussion under the heading Uranium market update

• our expectation that our average realized uranium price will improve in the fourth quarter of 2012

• the outlook for each of our operating segments for 2012, and our consolidated outlook for the year

• 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 existing cash balances and operating cash flows will meet anticipated capital requirements without the need for any significant additional financing

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

• our expectations regarding 2012 quarterly delivery patterns for our uranium and fuel service products

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

• our expectations regarding Cigar Lake

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

• our forecasts relating to termination of uranium sales contracts with our customers 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 not reliable, 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

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• 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, civil unrest, 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

• our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties encountered with the jet boring mining method or our inability to acquire any of the required jet boring equipment

• 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, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

• with respect to NUKEM related forecasts, the risk that the required regulatory approvals may not be obtained in a timely manner or at all or that other closing conditions may not be satisfied and the risk that the amount of NUKEM’s debt may change from current levels

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 level and production costs

• our expectations regarding spot prices and realized prices for uranium, and other factors discussed in our second quarter MD&A

• our expectations regarding uranium sales contract terminations, tax rates, foreign currency exchange rates and interest rates

• our decommissioning and reclamation expenses

• our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable

• the geological, hydrological and other conditions at our mines

• our Cigar Lake development, mining and production plans succeed, including the success of the jet boring mining method at Cigar Lake and that we will be able to obtain the additional jet boring system units we require on schedule

• 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, civil unrest, 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, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

• with respect to our NUKEM related forecasts, we have assumed the regulatory approvals and other closing conditions will be satisfied within the expected timeframes and NUKEM’s debt will remain at current levels

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Quarterly dividend notice

We announced today that our board of directors approved a quarterly dividend of $0.10 per share on the outstanding common shares of the corporation that is payable on October 15, 2012, to shareholders of record at the close of business on September 28, 2012.

Conference call

We invite you to join our second quarter conference call on Friday, July 27, 2012 at 1:00 p.m. Eastern.

The call will be open to all investors and the media. To join the call, please dial (866) 226-1792 (Canada and US) or (416) 340-2216. An operator will put your call through. A live audio feed of the conference call will be available from a link at cameco.com. See the link on our home page on the day of the call.

A recorded version of the proceedings will be available:

• on our website, cameco.com, shortly after the call

• on post view until midnight, Eastern, August 27, 2012 by calling (800) 408-3053 or (905) 694-9451 (Passcode 2717704#)

Additional information

You can find a copy of our second quarter MD&A and interim financial statements on our website at cameco.com, on SEDAR at sedar.com and on EDGAR at sec.gov/edgar.shtml.

Additional information, including our 2011 annual management’s discussion and analysis, annual audited financial statements and annual information form, is available on SEDAR at sedar.com, on EDGAR at sec.gov/edgar.shtml and on our website at cameco.com.

Profile

We are one of the world’s largest uranium producers, a significant supplier of conversion services and one of two Candu fuel manufacturers in Canada. Our competitive position is based on our controlling ownership of the world’s largest high-grade reserves and low-cost operations. Our uranium products are used to generate clean electricity in nuclear power plants around the world, including Ontario where we are a limited partner in North America’s largest nuclear electricity generating facility. We also explore for uranium in the Americas, Australia and Asia. Our shares trade on the Toronto and New York stock exchanges. Our head office is in Saskatoon, Saskatchewan.

As used in this news release, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries and affiliates unless stated otherwise.

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Investor inquiries:	Rachelle Girard (306) 956-6403
Media inquiries:	Gord Struthers (306) 956-6593

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