6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 Under

the Securities Exchange Act of 1934

For the month of July, 2012

Cameco Corporation

(Commission file No. 1-14228)

2121-11th Street West

Saskatoon, Saskatchewan, Canada S7M 1J3

(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F  ¨             Form 40-F  x

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes  ¨             No  x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

Exhibit Index
Exhibit No.	Description	Page No.
99.1	Press Release dated July 27, 2012
99.2	Management’s Discussion & Analysis for the second quarter ending June 30, 2012
99.3	Interim Unaudited Financial Statements for the second quarter ending June 30, 2012
99.4	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 dated July 27, 2012
99.5	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 dated July 27, 2012

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: July 27, 2012	Cameco Corporation
	By:
	“Gary M. S. Chad”
	Gary M. S. Chad
	Senior Vice-President, Chief Legal Officer and Corporate Secretary

EX-99.1

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	%

-1-

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.

-2-

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.

-3-

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,

-4-

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.

-5-

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.

-7-

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.

-8-

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.

-10-

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.

-11-

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

-12-

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

-13-

• 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

-14-

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.

- End -

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

-15-

EX-99.2

Exhibit 99.2

Management’s discussion and analysis

for the quarter ended June 30, 2012

Second quarter update	4
Financial results	9
Our operations and development projects	25
Qualified persons	30
Additional information	30

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

Management’s discussion and analysis

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited condensed consolidated interim financial statements and notes for the quarter ended June 30, 2012 (interim financial statements). The information is based on what we knew as of July 26, 2012 and updates our first quarter and annual MD&A included in our 2011 annual financial review.

As you review the MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2011 and annual MD&A of the audited consolidated financial statements. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.

The financial information in this MD&A and in our financial statements and notes are prepared according to International Financial Reporting Standards (IFRS), unless otherwise indicated.

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

Caution about forward-looking information

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

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

• It typically includes words and phrases about the future, such as: anticipate, estimate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples on page 2).

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

• It is based on a number of material assumptions, including those we have listed on page 3, which may prove to be incorrect.

• Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks on pages 2 and 3. We recommend you also review our annual information form and our annual and first 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.

2012 SECOND QUARTER REPORT   1

Examples of forward-looking information in this MD&A

• our strategy for increasing annual production to 40 million pounds by 2018

• 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 and number of new reactors, 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 expectation that our operating and investment activities in 2012 will not be constrained by the financial covenants in our unsecured revolving credit facility

• our uranium price sensitivity analysis

• forecast production at our uranium operations from 2012 to 2016

• 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

• 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

2   CAMECO CORPORATION

• with respect to our 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 on page 20, Price sensitivity analysis: uranium

• 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

2012 SECOND QUARTER REPORT   3

Our strategy

Our corporate growth strategy to double annual uranium production to 40 million pounds by 2018 is as relevant today as it was in 2008 when we set our course. We remain confident in the long-term fundamentals of the nuclear industry. World demand for safe, clean, reliable and affordable energy continues to grow and the need for nuclear energy as part of the world’s energy mix remains compelling.

We are preparing our assets now to ensure we can be among the first to respond when the market signals new production is needed and to maintain our position as one of the world’s largest uranium producers. In addition, our strategy is to invest in opportunities across the nuclear fuel cycle that we expect will complement and enhance our business.

The projects we have identified to reach our 2018 production target are at various stages of evaluation and the mix may change depending on the results of our evaluations. Our production decisions will be driven by project economics.

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

You can read more about our strategy in our 2011 annual MD&A.

Second quarter update

Our performance

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 pages 10 and 11)				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	%
Average realized prices	Uranium	$US/lb		42.08			45.65		(8	)%		46.26		46.89		(1	)%
		$Cdn/lb		42.21			44.48		(5	)%		46.70		46.60		—
	Fuel services	$Cdn/kgU		16.33			17.24		(5	)%		17.82		18.49		(4	)%
	Electricity	$Cdn/MWh		55.00			55.00		—			55.00		54.00		2	%

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

4   CAMECO CORPORATION

this quarter were $34 million ($0.09 per share diluted) compared to $71 million ($0.18 per share diluted) (non-IFRS measure, see pages 10 and 11) 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 18 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 pages 10 and 11). 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.

Operations update

Highlights		Three months ended June  30							Six months ended June 30
		2012		2011		change			2012		2011		change
Uranium	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	%
	Revenue ($ millions)		206		256		(20	)%		607		554		10	%
	Gross profit ($ millions)		42		86		(51	)%		184		186		(1	)%
Fuel services	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	%
	Revenue ($ millions)		66		70		(6	)%		122		119		3	%
	Gross profit ($ millions)		9		13		(31	)%		20		19		5	%
Electricity	Output (100%) (TWh)		6.5		5.6		16	%		12.5		12.0		4	%
	Revenue (100%) ($ millions)		377		314		20	%		711		654		9	%
	Our share of earnings before taxes ($ millions)		51		10		410	%		78		40		95	%

Production in our uranium segment this quarter was down 7% compared to the second quarter of 2011. This is mainly due to lower production from McArthur River/Key Lake where production varies from quarter to quarter depending on the sequencing of mining raises and timing of planned maintenance shutdowns at the mill. For the first six months, production is 3% lower than for the same period in 2011 mainly due to lower production at Smith Ranch-Highland and Inkai. See Uranium 2012 Q2 updates starting on page 27 for more information.

Key highlights:

• at McArthur River, we made productivity improvements to our 2013 production plan. See page 27 for more information.

2012 SECOND QUARTER REPORT   5

• at Cigar Lake, we are preparing to test the jet boring system underground at site. See page 28 for more information.

• at Millennium, our agreement to purchase AREVA’s share of the project for $150 million closed, increasing our ownership interest to 69.9%. See page 29 for more information.

Production in our fuel services segment was 4% lower this quarter than in the second quarter of 2011, and for the first six months is unchanged compared to last year. We continue to expect production to be between 13 million and 14 million kgU this year.

In our electricity segment, BPLP’s generation was 16% higher for the quarter and 4% higher for the first half of the year compared to the same periods last year. The capacity factor this quarter was 91% and 88% for the first six months.

Also 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.

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

6   CAMECO CORPORATION

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.

Caution about forward-looking information relating to our uranium market update

This discussion of our expectations for the nuclear industry, including its growth profile and future global uranium supply and demand and the number of reactors, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 1.

2012 SECOND QUARTER REPORT   7

Industry prices

	Jun 30 2012		Mar 31 2012		Jun 30 2011		Mar 31 2011
Uranium ($US/lb U3O8 )1
Average spot market price		50.75		51.05		52.88		60.50
Average long-term price		61.25		60.00		68.00		70.00
Fuel services ($US/kgU UF6)1
Average spot market price
North America		6.63		6.63		11.00		12.00
Europe		7.00		7.00		11.00		12.00
Average long-term price
North America		16.75		16.75		16.00		15.75
Europe		17.25		17.25		16.25		16.00
Note: the industry does not publish UO2 prices
Electricity ($/MWh)
Average Ontario electricity spot price		19.00		20.00		28.00		32.00

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

On the spot market, where purchases call for delivery within one year, the volume reported for the second quarter of 2012 was just under 8 million pounds. This compares to approximately 10 million pounds in the second quarter of 2011.

The spot market remained stable over the quarter. At the end of the quarter, the average spot price was $50.75 (US) per pound. On July 23, 2012, Ux reported a spot price of $50.00 (US) per pound. In general, utilities are well covered under existing contracts, so we expect uranium demand in the near term to remain somewhat discretionary.

The long-term uranium price strengthened during the quarter. Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices adjusted by inflation indices, and market referenced prices (spot and long-term indicators quoted near the time of delivery).

Spot and long-term UF₆ conversion price indicators held firm throughout the quarter.

Long-term fundamentals are strong

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

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

Shares and stock options outstanding

At July 25, 2012, we had:

• 395,343,018 common shares and one Class B share outstanding

• 9,851,753 stock options outstanding, with exercise prices ranging from $15.79 to $54.38

Dividend policy

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

8   CAMECO CORPORATION

Financial results

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

2012 Q2 results
Consolidated financial results	9
Outlook for 2012	15
Liquidity and capital resources	16
Financial results by segment	18
Uranium	18
Fuel services	22
Electricity	23

Consolidated financial results

Highlights	Three months ended June 30								Six months ended June 30
($ millions except per share amounts)	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 (basic)		0.02			0.14		(86	)%		0.35		0.37		(5	)%
$ per common share (diluted)		0.02			0.14		(86	)%		0.35		0.37		(5	)%
Adjusted net earnings (non-IFRS, see pages 10 and 11)		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	%

Net earnings

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. Lower earnings in 2012 were 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 higher earnings from our electricity business

2012 SECOND QUARTER REPORT   9

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 pages 10 and 11). 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

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.

10   CAMECO CORPORATION

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

Change in adjusted net earnings ($ millions)		Three months ended June  30			Six months ended June  30
Adjusted net earnings — 2011			71			155
Change in gross profit by segment	(we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)
Uranium	Higher (lower) sales volumes		(13	)		17
	Lower realized prices ($US)		(17	)		(8	)
	Foreign exchange impact on realized prices		6			9
	Higher costs		(19	)		(20	)
	Hedging benefits		(15	)		(19	)
	change — uranium		(58	)		(21	)
Fuel services	Higher sales volumes		—			1
	Higher (lower) realized prices ($Cdn)		(4	)		(5	)
	(Higher) lower costs		1			5
	Hedging benefits		(3	)		(2	)
	change — fuel services		(6	)		(1	)
Electricity	Higher sales volumes		2			2
	Higher realized prices ($Cdn)		4			9
	Lower costs		35			26
	change — electricity		41			37
Other changes
Higher exploration expenditures			(3	)		(11	)
Higher administration expenditures			(12	)		(17	)
Lower income taxes			24			35
Contract termination charge			(30	)		(30	)
Other			7			11
Adjusted net earnings — 2012			34			158

See Financial results by segment on page 18 for more detailed discussion.

Average realized prices

		Three months ended June 30							Six months ended June 30
		2012		2011		change			2012		2011		change
Uranium	$US/lb		42.08		45.65		(8	)%		46.26		46.89		(1	)%
	$Cdn/lb		42.21		44.48		(5	)%		46.70		46.60		—
Fuel services	$Cdn/kgU		16.33		17.24		(5	)%		17.82		18.49		(4	)%
Electricity	$Cdn/MWh		55.00		55.00		—			55.00		54.00		2	%

2012 SECOND QUARTER REPORT   11

Quarterly trends

Highlights	2012					2011								2010
($ millions except per share amounts)	Q2			Q1		Q4		Q3		Q2		Q1		Q4		Q3
Revenue		391			564		970		527		426		461		673		419
Net earnings		8			132		265		39		55		91		206		97
$ per common share (basic)		0.02			0.33		0.67		0.10		0.14		0.23		0.52		0.25
$ per common share (diluted)		0.02			0.33		0.67		0.10		0.14		0.23		0.52		0.25
Adjusted net earnings (non-IFRS, see pages 10 and 11)		34			124		249		104		71		84		190		79
$ per common share (adjusted and diluted)		0.09			0.31		0.63		0.26		0.18		0.21		0.48		0.21
Cash provided by operations
(after working capital changes)		(94	)		412		258		193		23		271		111		(2	)

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

	2012						2011												2010
($ millions)	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Net earnings		8			132			265			39			55			91			206			97
Adjustments
Adjustments on derivatives1 (pre-tax)		35			(10	)		(22	)		88			22			(10	)		(22	)		(25	)
Income taxes on adjustments to derivatives		(9	)		2			6			(23	)		(6	)		3			6			7
Adjusted net earnings (non-IFRS, see pages 10 and 11)		34			124			249			104			71			84			190			79

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.

Key things to note:

• Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 53% of consolidated revenues in the second quarter of 2012.

• The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments.

• Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period.

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

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

12   CAMECO CORPORATION

Administration

	Three months ended June 30							Six months ended June 30
($ millions)	2012		2011		change			2012		2011		change
Direct administration		38		33		15	%		73		64		14	%
Stock-based compensation		8		1		700	%		12		4		200	%
Total administration		46		34		35	%		85		68		25	%

Direct administration costs were $5 million higher this quarter and $9 million higher for the first six months than the same periods last year. These increases reflect mainly the following:

• studies and analyses of various opportunities

• enhancements to information systems

Stock-based compensation expenses were $12 million for the first six months of 2012 compared to $4 million for the same period in 2011. Our share price appreciated in the first half of 2012 whereas it declined in the first half of 2011.

Exploration

Uranium exploration expenses were $18 million this quarter compared to $15 million in the same quarter in 2011, as exploration activity in Saskatchewan increased. Exploration expenses in the first six months of the year increased to $41 million from $30 million in 2011. We expect exploration expenses to be about 15% to 20% higher than they were in 2011 due to an increase in evaluation activities at Kintyre and Inkai block 3. We are also continuing to focus efforts in Canada and the United States.

Income taxes

In the second quarter of 2012, we recorded an income tax recovery of $28 million compared to a recovery of $1 million in the second quarter of 2011. The increase in recoveries this quarter was mainly due to lower pre-tax earnings and a change in the distribution of earnings. In 2012, we recorded losses of $85 million in Canada compared to $55 million in 2011, whereas earnings in foreign jurisdictions declined to $64 million from $108 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which we operate. Also, we received additional certainty on particular tax provisions that allowed us to recognize a $9 million recovery in our income tax expense. This also applies to our results of the first six months of the year.

On an adjusted basis, we recorded an income tax recovery of $19 million this quarter compared to an expense of $5 million in the second quarter of 2011. Our effective tax rate this quarter on an adjusted net earnings basis reflects a recovery of 130% compared to an expense of 6% for the second quarter of 2011.

In the first six months of 2012, we recorded an income tax recovery of $36 million compared to an expense of $3 million in 2011. The recovery for the first half of the year was mainly due to lower pre-tax earnings and a change in the distribution of earnings. In 2012, we recorded higher losses in Canada. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which we operate.

On an adjusted basis, we recorded an income tax recovery of $29 million in the first six months of 2012 compared to an expense of $6 million in 2011. Our effective tax rate for the first six months of 2012, on an adjusted net earnings basis, reflects a recovery of 23% compared to an expense of 4% in 2011.

2012 SECOND QUARTER REPORT   13

	Three months ended June 30									Six months ended June 30
($ millions)	2012			2011			change			2012			2011			change
Pre-tax Adjusted Earnings1
Canada2		(49	)		(33	)		52	%		(139	)		(63	)		121	%
Foreign		64			108			(41	)%		267			224			19	%
Total pre-tax adjusted earnings		15			75			(80	)%		128			161			(20	)%
Adjusted Income Taxes2
Canada2		(19	)		(8	)		(138	)%		(38	)		(14	)		(171	)%
Foreign		—			13			(100	)%		9			20			(55	)%
Adjusted income tax expense (recovery)		(19	)		5			(480	)%		(29	)		6			(583	)%
Effective tax rate		(130	%)		6	%		(2,267	)%		(23	%)		4	%		(675	)%

¹ Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures.

² Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on pages 10 and 11).

Foreign exchange

At June 30, 2012:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.02 (Cdn), up from $1.00 (US) for $1.00 (Cdn) at March 31, 2012. The exchange rate averaged $1.00 (US) for $1.01 (Cdn) over the quarter.

• We had foreign currency contracts of $1.5 billion (US) and EUR 76 million at June 30, 2012. The US currency contracts had an average exchange rate of $1.00 (US) for $1.01 (Cdn).

• The mark-to-market loss on all foreign exchange contracts was $8 million compared to a $2 million gain at March 31, 2012. We received cash of $12 million this quarter related to the settlement of foreign exchange contracts.

14   CAMECO CORPORATION

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.

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 on page 18 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. See page 13 for more information.

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.

2012 SECOND QUARTER REPORT   15

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, 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).

Liquidity and capital resources

Cash from operations

Cash from operations was $117 million lower this quarter than in 2011 due largely to lower uranium deliveries. Working capital required $54 million more in 2012 largely as a result of an increase in uranium inventories during the quarter. Not including working capital requirements, our operating cash flows this quarter were lower by $64 million, based on lower profits in our uranium segment. See Financial results by segment on page 18 for details.

Cash from operations was $24 million higher for the first six months of 2012 than for the same period in 2011 mainly due to higher profits from the electricity business and higher uranium sales volumes. Not including working capital requirements, our operating cash flows in the first six months were down by $43 million.

Debt

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1.9 billion at June 30, 2012, the same as at March 31, 2012. At June 30, 2012, we had approximately $679 million outstanding in letters of credit.

Debt covenants

We are bound by certain covenants in our unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at June 30, 2012, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2012 to be constrained by them.

Long-term contractual obligations and off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at June 30, 2012:

• purchase commitments

• financial assurances

At the end of the second quarter, we had an agreement to purchase NUKEM for $136 million (US), and the obligation for its net debt of $164 million (US) as of January 1, 2012, ($114 million (US) on June 30, 2012).

16   CAMECO CORPORATION

Other than the NUKEM agreement, there have been no material changes to our long-term contractual obligations, purchase commitments and financial assurances since December 31, 2011, 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)	Jun 30, 2012		Dec 31, 2011		change
Cash and short-term investments		895		1,202		(26	)%
Total debt		992		1,039		(5	)%
Inventory		577		494		17	%

Total cash and short-term investments at June 30, 2012 were $895 million, or 26% lower than at December 31, 2011 due to a higher rate of capital expenditures and our purchase of an incremental interest in the Millennium project. Net debt at June 30, 2012 was $97 million.

Total debt decreased by $47 million to $992 million at June 30, 2012. Of this total, $74 million was classified as current, down $39 million compared to December 31, 2011. See notes 16 and 17 of our audited annual financial statements for more detail.

Total product inventories increased marginally to $577 million. Uranium inventories increased, as sales were lower than production and purchases in the first six months of the year. Fuel services inventories increased as sales were also lower than production and purchases.

Accounting change

In August 2008, we acquired a 70% interest in the Kintyre exploration project in Australia. Previously, we consolidated our investment in Kintyre on the basis that we were able to exercise control over the asset. In the second quarter, we reconsidered the accounting treatment applied to Kintyre and concluded that instead of consolidation of the investment we should recognize only our proportionate interest in the accounts of Kintyre. Accordingly, the non-controlling interest in the assets, liabilities and expenses has been removed from our financial statements. The change in accounting has been applied retrospectively and the comparative statements for 2011 have been recast. There was no impact on retained earnings or net earnings attributable to equity holders for any of the previously reported periods. The most significant changes relate to a reduction of property, plant and equipment of $183 million and a reduction of the non-controlling interest on the balance sheet of $182 million. We have concluded that the impact of this change is not material to our financial statements.

2012 SECOND QUARTER REPORT   17

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 Uranium 2012 Q2 updates starting on page 27 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 Operating properties 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.

18   CAMECO CORPORATION

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.

2012 SECOND QUARTER REPORT   19

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

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			—

Price sensitivity analysis: uranium

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

It is designed to indicate how our portfolio of long-term contracts would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same and none of the assumptions we list below change.

We intend to update this table each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio each quarter. As a result we expect the table to change from quarter to quarter.

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
2012		44		45		49		53		57		62		66
2013		43		46		54		63		72		81		88
2014		45		48		56		65		74		83		90
2015		42		46		56		66		77		88		97
2016		44		49		58		68		78		88		97

20   CAMECO CORPORATION

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

• deliveries made and contracts entered into

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

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

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

Sales

• sales volumes on average of 32 million pounds per year

Deliveries

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

• we defer a portion of deliveries under existing contracts for 2012

Prices

• the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 14% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table will be higher.

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

Inflation

• is 2% per year

2012 SECOND QUARTER REPORT   21

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.

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.

22   CAMECO CORPORATION

Electricity

BPLP

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

Highlights ($ millions except where indicated)	Three months ended June  30									Six months ended June 30
	2012			2011			change			2012			2011			change
Output—terawatt hours (TWh)		6.5			5.6			16	%		12.5			12.0			4	%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		91	%		78	%		17	%		88	%		85	%		4	%
Realized price ($/MWh)		55	1		55	2		—			55	3		54	4		2	%
Average Ontario electricity spot price ($/MWh)		19			28			(32	)%		20			30			(33	)%
Revenue		377			314			20	%		711			654			9	%
Operating costs (net of cost recoveries)		204			270			(24	)%		445			503			(12	)%
Cash costs		150			224			(33	)%		337			410			(18	)%
Non-cash costs		54			46			17	%		108			93			16	%
Income before interest and finance charges		173			44			293	%		266			151			76	%
Interest and finance charges		10			10			—			10			16			(38	)%
Cash from operations		202			121			67	%		351			240			46	%
Capital expenditures		49			58			(16	)%		88			97			(9	)%
Distributions		160			55			191	%		190			125			52	%
Capital calls		17			11			55	%		33			11			200	%
Operating costs ($/MWh)		30	1		47	2		(36	)%		34	3		41	4		(17	)%

¹  Three months ended June 30, 2012 are based on actual generation of 6.5 TWh plus deemed generation of 0.3 TWh

²  Three months ended June 30, 2011 are based on actual generation of 5.6 TWh plus deemed generation of 0.2 TWh

³  Six months ended June 30, 2012 are based on actual generation of 12.5 TWh plus deemed generation of 0.4 TWh

⁴  Six months ended June 30, 2011 are based on actual generation of 12.0 TWh plus deemed generation of 0.2 TWh

Our earnings from BPLP

Highlights ($ millions except where indicated)	Three months ended June 30									Six months ended June 30
	2012			2011			change			2012			2011			change
BPLP’s earnings before taxes (100%)		163			34			379	%		256			135			90	%
Cameco’s share of pretax earnings before adjustments (31.6%)		52			11			373	%		81			43			88	%
Proprietary adjustments		(1	)		(1	)		—			(3	)		(3	)		—
Earnings before taxes from BPLP		51			10			410	%		78			40			95	%

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

2012 SECOND QUARTER REPORT   23

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.

24   CAMECO CORPORATION

Our operations and development projects

Uranium — production overview

Production in our uranium segment this quarter was down 7% compared to the second quarter of 2011 mainly due to lower production from McArthur River/Key Lake. For the first six months, production was down 3% compared to the first half of last year mainly due to lower production at Smith Ranch-Highland and Inkai. See Uranium 2012 Q2 updates starting on page 27 for more information.

Key highlight:

• at McArthur River, we made productivity improvements to our 2013 production plan. See page 27 for more information.

Uranium production

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	)%

Outlook

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

Cameco’s share of production — annual forecast to 2016

Current forecast (million lbs)	2012		2013		2014		2015		2016
McArthur River/Key Lake		13.1		13.1		13.1		13.1		13.1
Rabbit Lake		3.7		3.7		3.7		3.7		3.4
US ISR		2.4		3.0		3.1		3.7		3.8
Inkai1		2.5		2.9		2.9		2.9		2.9
Cigar Lake		—		0.3		1.9		5.5		7.9
Total share of production		21.7		23.0		24.7		28.9		31.1
Cameco’s share of Inkai’s production on which profits are generated2
Inkai1		2.6		3.0		3.0		3.0		3.0
Total2		21.8		23.1		24.8		29.0		31.2

¹ We have signed a memorandum of agreement (MOA) with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). Once implemented, we will receive the right to purchase 2.9 million pounds of Inkai’s annual production and receive profits on 3.0 million pounds.

²  We have adjusted the production table to reflect the share of Inkai’s production we will use to calculate our profits under the MOA, as described in the note above.

2012 SECOND QUARTER REPORT   25

Our 2012 and future annual production targets for Inkai assume, and we expect:

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

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

• Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis)

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to re-categorize some of Inkai’s mineral reserves as resources.

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.

Assumptions

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

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

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

Material risks that could cause actual results to differ materially

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

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

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

26   CAMECO CORPORATION

Uranium 2012 Q2 updates

Operating properties

McArthur River/Key Lake

Production update

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.

Operations update

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 update

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

Operations update

We 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 update

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.

Operations update

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.

2012 SECOND QUARTER REPORT   27

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 update

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.

Operations update

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.

Development project

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.

28   CAMECO CORPORATION

Projects under evaluation

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.

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 2012 Q2 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc.

Springfields Fuels Ltd. (SFL)

Production update

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.

2012 SECOND QUARTER REPORT   29

Operations update

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 MD&A for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:

McArthur River/Key Lake

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

• Les Yesnik, general manager, Key Lake, Cameco

Cigar Lake

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

Inkai

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

Additional information

Related party transactions

We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In the first half of 2012, we paid PACL $22 million for construction and contracting services (2011 — $33 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

Critical accounting estimates

In our 2011 annual MD&A, we have identified the critical accounting estimates that reflect the more significant judgments used in the preparation of our financial statements. Please refer to note 2 of our interim financial statements for a detailed description of our application of estimates and judgment in the preparation of our financial information.

Controls and procedures

As of June 30, 2012, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of June 30, 2012, the CEO and CFO concluded that:

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

• such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure

30   CAMECO CORPORATION

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New accounting pronouncements

New standards and interpretations not yet adopted

We have not yet adopted the standards and amendments to existing standards that have been issued. The standards and amendments, unless otherwise stated, are effective for periods beginning on or after January 1, 2013. We are assessing the impact of the following standards and amendments on our financial statements:

Financial instruments

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

Consolidated financial statements

In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements (“IFRS 10”). This standard establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 defines the principle of control and establishes control as the basis for determining which entities are consolidated in the consolidated financial statements.

Joint arrangements

In May 2011, the IASB issued IFRS 11, Joint Arrangements (“IFRS 11”). This standard establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 requires a party to assess the rights and obligations arising from an arrangement in determining whether an arrangement is either a joint venture or a joint operation. Joint ventures are to be accounted for using the equity method while joint operations will continue to be accounted for using proportionate consolidation.

Disclosure of interests in other entities

In May 2011, the IASB issued IFRS 12, Disclosure of Interests in Other Entities (“IFRS 12”). This standard applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 integrates and makes consistent the disclosure requirements for a reporting entity’s interest in other entities and presents those requirements in a single standard.

Fair value measurement

In May 2011, the IASB issued IFRS 13, Fair Value Measurement (“IFRS 13”). This standard provides additional guidance where IFRS requires fair value to be used. IFRS 13 defines fair value, sets out in a single standard a framework for measuring fair value and establishes the required disclosures about fair value measurements.

2012 SECOND QUARTER REPORT   31

Employee benefits

In June 2011, the IASB issued an amended version of IAS 19, Employee Benefits (“IAS 19”). This amendment eliminates the ‘corridor method’ of accounting for defined benefit plans. Revised IAS 19 also streamlines the presentation of changes in assets and liabilities arising from defined benefit plans, and enhances the disclosure requirements for defined benefit plans.

Presentation of other comprehensive income (OCI)

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

Financial assets and financial liabilities

In December 2011, the IASB issued amendments to IAS 32, Financial Instruments: Presentation (“IAS 32”) and IFRS 7, Financial Instruments: disclosures (“IFRS 7”). The amendments are effective for periods beginning on or after January 1, 2013 for IFRS 7 and January 1, 2014 for IAS 32 and are to be applied retrospectively. These amendments clarify matters regarding offsetting financial assets and financial liabilities as well as related disclosure requirements.

32   CAMECO CORPORATION

EX-99.3

Exhibit 99.3

CAMECO CORPORATION

2012 CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

(unaudited)

July 26, 2012

Cameco Corporation

Consolidated Statements of Earnings

(Unaudited)

($Cdn Thousands, except per share amounts)

						(Recast -						(Recast -
						note 3(b))						note 3(b))
			Three Months Ended						Six Months Ended
	Note		Jun 30/12			Jun 30/11			Jun 30/12			Jun 30/11
Revenue from products and services			$	391,424		$	425,705		$	954,682		$	886,806
Cost of products and services sold				226,193			268,059			552,539			543,624
Depreciation and amortization				61,835			49,716			120,830			98,787
Cost of sales				288,028			317,775			673,369			642,411
Gross profit				103,396			107,930			281,313			244,395
Administration				46,408			34,214			85,429			67,981
Exploration				17,888			14,647			40,857			30,486
Research and development				853			732			3,978			1,727
Loss (gain) on sale of assets				913			719			(2,149	)		695
Earnings from operations				37,334			57,618			153,198			143,506
Finance costs		8		(12,750	)		(19,704	)		(35,018	)		(39,562	)
Gains (losses) on derivatives		13		(22,880	)		11,859			1,574			35,588
Finance income				5,808			6,463			11,788			13,116
Share of loss from equity-accounted investees				(1,959	)		(2,324	)		(2,771	)		(5,016	)
Other income (expense)				(26,506	)		(133	)		(25,745	)		1,439
Earnings (loss) before income taxes				(20,953	)		53,779			103,026			149,071
Income tax expense (recovery)		9		(28,241	)		(873	)		(35,809	)		2,934
Net earnings			$	7,288		$	54,652		$	138,835		$	146,137
Net earnings (loss) attributable to:
Equity holders			$	7,877		$	54,652		$	139,615		$	146,137
Non-controlling interest				(589	)		—			(780	)		—
Net earnings			$	7,288		$	54,652		$	138,835		$	146,137
Earnings per common share attributable to equity holders
Basic		14	$	0.02		$	0.14		$	0.35		$	0.37
Diluted		14	$	0.02		$	0.14		$	0.35		$	0.37

See accompanying notes to condensed consolidated interim financial statements.

1

Cameco Corporation

Consolidated Statements of Comprehensive Income

(Unaudited)

($Cdn Thousands)

						(Recast - note 3(b))						(Recast - note 3(b))
			Three Months Ended						Six Months Ended
	Note		Jun 30/12			Jun 30/11			Jun 30/12			Jun 30/11
Net earnings			$	7,288		$	54,652		$	138,835		$	146,137
Other comprehensive income (loss), net of taxes		9
Exchange differences on translation of foreign operations				15,718			6,997			(3,106	)		(14,382	)
Gains (losses) on derivatives designated as cash flow hedges				(1,375	)		1,511			5,688			3,122
Gains on derivatives designated as cash flow hedges transferred to net earnings				(6,298	)		(5,102	)		(11,833	)		(11,232	)
Unrealized gains (losses) on available-for-sale assets				185			217			(90	)		684
Losses (gains) on available-for-sale assets transferred to net earnings				8			(5	)		(39	)		(1,840	)
Other comprehensive income (loss), net of taxes				8,238			3,618			(9,380	)		(23,648	)
Total comprehensive income			$	15,526		$	58,270		$	129,455		$	122,489
Other comprehensive income (loss) attributable to:
Equity holders			$	8,209		$	3,618		$	(9,290	)	$	(23,648	)
Non-controlling interest				29			—			(90	)		—
Other comprehensive income (loss) for the period			$	8,238		$	3,618		$	(9,380	)	$	(23,648	)
Total comprehensive income (loss) attributable to:
Equity holders			$	16,086		$	58,270		$	130,325		$	122,489
Non-controlling interest				(560	)		—			(870	)		—
Total comprehensive income for the period			$	15,526		$	58,270		$	129,455		$	122,489

See accompanying notes to condensed consolidated interim financial statements.

2

Cameco Corporation

Consolidated Statements of Financial Position

(Unaudited)

($Cdn Thousands)

					(Recast -
					note 3(b))
			As At
	Note		Jun 30/12		Dec 31/11
Assets
Current assets
Cash and cash equivalents			$	313,628	$	398,084
Short-term investments				581,222		804,141
Accounts receivable				320,821		611,815
Current tax assets				33,048		31,388
Inventories		4		577,251		493,875
Supplies and prepaid expenses				198,286		182,037
Current portion of long-term receivables, investments and other		5		75,101		62,433
Total current assets				2,099,357		2,583,773
Property, plant and equipment				4,666,684		4,349,492
Intangible assets				96,564		98,954
Long-term receivables, investments and other		5		308,374		283,818
Investments in equity-accounted investees				220,822		220,226
Deferred tax assets				134,791		81,392
Total non-current assets				5,427,235		5,033,882
Total assets			$	7,526,592	$	7,617,655
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities			$	385,104	$	455,499
Current tax liabilities				16,663		39,330
Short-term debt				58,360		97,830
Dividends payable				39,531		39,475
Current portion of finance lease obligation				15,579		14,852
Current portion of other liabilities		6		40,279		50,495
Current portion of provisions				15,936		14,857
Total current liabilities				571,452		712,338
Long-term debt				795,484		795,144
Finance lease obligation				122,987		130,982
Other liabilities		6		523,856		528,264
Provisions				516,948		519,625
Deferred tax liabilities				9,550		8,165
Total non-current liabilities				1,968,825		1,982,180
Shareholders’ equity
Share capital				1,850,598		1,842,289
Contributed surplus				161,518		155,757
Retained earnings				2,935,531		2,874,973
Other components of equity				37,285		46,575
Total shareholders’ equity attributable to equity holders				4,984,932		4,919,594
Non-controlling interest				1,383		3,543
Total shareholders’ equity				4,986,315		4,923,137
Total liabilities and shareholders’ equity			$	7,526,592	$	7,617,655

Commitments and contingencies [notes 9,12]

See accompanying notes to condensed consolidated interim financial statements.

3

Cameco Corporation

Consolidated Statements of Changes in Equity

(Unaudited)

($Cdn Thousands)

																					(Recast -
																					note 3(b))
	Attributable to equity holders
	Share Capital		Contributed Surplus			Retained Earnings			Foreign Currency Translation			Cash Flow Hedges			Available-For- Sale Assets			Total			Non- Controlling Interest			Total Equity
Balance at January 1, 2012	$	1,842,289	$	155,757		$	2,874,973		$	26,867		$	19,560		$	148			4,919,594		$	3,543		$	4,923,137
Net earnings		—		—			139,615			—			—			—			139,615			(780	)		138,835
Total other comprehensive loss		—		—			—			(3,016	)		(6,145	)		(129	)		(9,290	)		(90	)		(9,380	)
Total comprehensive income for the period		—		—			139,615			(3,016	)		(6,145	)		(129	)		130,325			(870	)		129,455
Share-based compensation		—		9,926			—			—			—			—			9,926			—			9,926
Share options exercised		8,309		(4,165	)		—			—			—			—			4,144			—			4,144
Dividends		—		—			(79,057	)		—			—			—			(79,057	)		—			(79,057	)
Change in ownership interests in subsidiary		—		—			—			—			—			—			—			(1,290	)		(1,290	)
Balance at June 30, 2012	$	1,850,598	$	161,518		$	2,935,531		$	23,851		$	13,415		$	19		$	4,984,932		$	1,383		$	4,986,315
Balance at January 1, 2011		1,833,257		142,376			2,690,184			(7,276	)		30,306			1,793			4,690,640			—			4,690,640
Net earnings		—		—			146,137			—			—			—			146,137			—			146,137
Total other comprehensive loss		—		—			—			(14,382	)		(8,110	)		(1,156	)		(23,648	)		—			(23,648	)
Total comprehensive income for the period		—		—			146,137			(14,382	)		(8,110	)		(1,156	)		122,489			—			122,489
Share-based compensation		—		11,320			—			—			—			—			11,320			—			11,320
Share options exercised		8,508		(5,988	)		—			—			—			—			2,520			—			2,520
Dividends		—		—			(78,942	)		—			—			—			(78,942	)		—			(78,942	)
Transactions with owners—contributed equity		—		—						—			—			—			—			3,376			3,376
Balance at June 30, 2011	$	1,841,765	$	147,708		$	2,757,379		$	(21,658	)	$	22,196		$	637		$	4,748,027		$	3,376		$	4,751,403

See accompanying notes to condensed consolidated interim financial statements.

4

Cameco Corporation

Consolidated Statements of Cash Flows

(Unaudited)

($Cdn Thousands)

						(Recast - note 3(b))						(Recast - note 3(b))
			Three Months Ended						Six Months Ended
	Note		Jun 30/12			Jun 30/11			Jun 30/12			Jun 30/11
Operating activities
Net earnings			$	7,288		$	54,652		$	138,835		$	146,137
Adjustments for:
Depreciation and amortization				61,835			49,716			120,830			98,787
Deferred charges				(15,568	)		(4,460	)		(15,640	)		(8,186	)
Unrealized losses (gains) on derivatives				16,000			15,490			(3,276	)		9,856
Share-based compensation		11		7,706			3,225			9,926			11,320
Loss (gain) on sale of assets				913			719			(2,149	)		695
Finance costs		8		12,750			19,704			35,018			39,562
Finance income				(5,808	)		(6,463	)		(11,788	)		(13,116	)
Share of loss from equity-accounted investees				1,959			2,324			2,771			5,016
Other income				(3,796	)		(352	)		(3,796	)		(4,975	)
Income tax expense (recovery)		9		(28,241	)		(873	)		(35,809	)		2,934
Interest received				5,288			5,714			12,230			9,689
Income taxes paid				(6,809	)		(9,209	)		(53,329	)		(47,883	)
Income taxes refunded				13,163			—			13,163			—
Other operating items		10		(160,625	)		(107,191	)		110,687			44,386
Net cash provided by (used in) operations				(93,945	)		22,996			317,673			294,222
Investing activities
Additions to property, plant and equipment				(315,427	)		(140,019	)		(451,501	)		(263,839	)
Decrease in short-term investments				328,227			142,719			222,770			10,746
Decrease (increase) in long-term receivables, investments and other				(4,360	)		(341	)		(29,952	)		27,494
Proceeds from sale of property, plant and equipment				3,066			7			3,099			32
Net cash provided by (used in) investing				11,506			2,366			(255,584	)		(225,567	)
Financing activities
Decrease in debt				(11,041	)		(7,046	)		(46,636	)		(10,870	)
Interest paid				(2,644	)		(2,893	)		(26,982	)		(27,088	)
Proceeds from issuance of shares, stock option plan				727			159			6,304			6,938
Dividends paid				(39,525	)		(39,470	)		(79,000	)		(67,075	)
Net cash used in financing				(52,483	)		(49,250	)		(146,314	)		(98,095	)
Decrease in cash during the period				(134,922	)		(23,888	)		(84,225	)		(29,440	)
Exchange rate changes on foreign currency cash balances				503			1,938			(231	)		(449	)
Cash and cash equivalents at beginning of period				448,047			367,441			398,084			375,380
Cash and cash equivalents at end of period			$	313,628		$	345,491		$	313,628		$	345,491
Cash and cash equivalents is comprised of:
Cash									$	63,762		$	100,684
Cash equivalents										249,866			244,807
									$	313,628		$	345,491

See accompanying notes to condensed consolidated interim financial statements.

5

Cameco Corporation

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

($Cdn thousands except per share amounts and as noted)

1. Cameco Corporation

Cameco Corporation is incorporated under the Canada Business Corporations Act. The address of its registered office is 2121 11^th Street West, Saskatoon, Saskatchewan, S7M 1J3. The condensed consolidated interim financial statements as at and for the period ended June 30, 2012 comprise Cameco Corporation and its subsidiaries (collectively, the “Company” or “Cameco”) and the Company’s interest in associates and joint ventures. The Company is primarily engaged in the exploration for and the development, mining, refining, conversion and fabrication of uranium for sale as fuel for generating electricity in nuclear power reactors in Canada and other countries. Cameco has a 31.6% interest in Bruce Power L.P. (“BPLP”), which operates the four Bruce B nuclear reactors in Ontario.

2. Significant Accounting Policies

(a) Statement of Compliance

These condensed consolidated interim financial statements have been prepared in accordance with IAS 34, Interim Financial Reporting. The condensed consolidated interim financial statements do not include all of the information required for full annual financial statements and should be read in conjunction with Cameco’s annual consolidated financial statements as at and for the year ended December 31, 2011.

These condensed consolidated interim financial statements were authorized for issuance by the Company’s board of directors on July 26, 2012.

(b) Basis of Presentation

These condensed consolidated interim financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand except where otherwise noted.

The condensed consolidated interim financial statements have been prepared on the historical cost basis except for the following material items in the statement of financial position: derivative financial instruments, available-for-sale financial assets and liabilities for cash-settled share-based payment arrangements are measured at fair value and the defined benefit asset is recognized as plan assets, plus unrecognized past service cost, less the present value of the defined benefit obligation.

The preparation of the condensed consolidated interim financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may vary from these estimates.

In preparing these condensed consolidated interim financial statements, the significant judgments made by management in applying the Company’s accounting policies and key sources of estimation uncertainty were the same as those that applied to the consolidated financial statements as at and for the year ended December 31, 2011.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements, are disclosed in note 6 of the December 31, 2011 consolidated financial statements.

3. Accounting Changes

(a) New Standards and Interpretations not yet Adopted

The Company has not yet adopted the standards and amendments to existing standards that have been issued. The standards and amendments, unless otherwise stated, are effective for periods beginning on or after January 1, 2013. Cameco is assessing the impact of the following standards and amendments on its financial statements:

(i) Financial Instruments

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

6

(ii) Consolidated Financial Statements

In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements (“IFRS 10”). This standard establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 defines the principle of control and establishes control as the basis for determining which entities are consolidated in the consolidated financial statements.

(iii) Joint Arrangements

In May 2011, the IASB issued IFRS 11, Joint Arrangements (“IFRS 11”). This standard establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 requires a party to assess the rights and obligations arising from an arrangement in determining whether an arrangement is either a joint venture or a joint operation. Joint ventures are to be accounted for using the equity method while joint operations will continue to be accounted for using proportionate consolidation.

(iv) Disclosure of Interests in Other Entities

In May 2011, the IASB issued IFRS 12, Disclosure of Interests in Other Entities (“IFRS 12”). This standard applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 integrates and makes consistent the disclosure requirements for a reporting entity’s interest in other entities and presents those requirements in a single standard.

(v) Fair Value Measurement

In May 2011, the IASB issued IFRS 13, Fair Value Measurement (“IFRS 13”). This standard provides additional guidance where IFRS requires fair value to be used. IFRS 13 defines fair value, sets out in a single standard a framework for measuring fair value and establishes the required disclosures about fair value measurements.

(vi) Employee Benefits

In June 2011, the IASB issued an amended version of IAS 19, Employee Benefits (“IAS 19”). This amendment eliminates the ‘corridor method’ of accounting for defined benefit plans. Revised IAS 19 also streamlines the presentation of changes in assets and liabilities arising from defined benefit plans, and enhances the disclosure requirements for defined benefit plans.

(vii) Presentation of Other Comprehensive Income (“OCI”)

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

(viii) Financial Assets and Financial Liabilities

In December 2011, the IASB issued amendments to IAS 32, Financial Instruments: Presentation (“IAS 32”) and IFRS 7, Financial Instruments: Disclosures (“IFRS 7”). The amendments are effective for periods beginning on or after January 1, 2013 for IFRS 7 and January 1, 2014 for IAS 32 and are to be applied retrospectively. These amendments clarify matters regarding offsetting financial assets and financial liabilities as well as related disclosure requirements.

7

(b) Accounting for Kintyre

In August 2008, Cameco acquired a 70% interest in the Kintyre exploration project in Australia. The Company previously consolidated its investment in Kintyre on the basis that it was able to exercise control over the asset. In the second quarter of 2012, the Company reconsidered the accounting treatment applied to Kintyre and concluded that consolidation of the investment was not appropriate and only Cameco’s interest in the assets and liabilities of Kintyre should be recognized. Accordingly, the non-controlling interest in the assets, liabilities and expenses has been removed from the financial statements. The change in accounting has been applied retrospectively and the comparative statements for 2011 have been recast. There was no impact on retained earnings or net earnings attributable to equity holders for any of the recast periods. The most significant changes relate to a reduction of property, plant and equipment of $182,615,000 and a reduction of the non-controlling interest on the balance sheet of $182,395,000.

4. Inventories

	Jun 30/12		Dec 31/11
Uranium
Concentrate	$	413,241	$	361,481
Broken ore		16,113		14,310
		429,354		375,791
Fuel Services		147,897		118,084
Total	$	577,251	$	493,875

5. Long-Term Receivables, Investments and Other

	Jun 30/12			Dec 31/11
BPLP
Capital lease receivable from Bruce A Limited Partnership (“BALP”) (a)	$	84,688		$	87,785
Derivatives [note 13]		46,045			54,010
Available-for-sale securities
GoviEx Uranium (privately held)		21,100			21,057
Derivatives [note 13]		14,032			17,392
Advances receivable from Inkai JV LLP [note 16]		98,064			78,058
Investment tax credits		63,440			54,038
Other		56,106			33,911
		383,475			346,251
Less current portion		(75,101	)		(62,433	)
Net	$	308,374		$	283,818

^(a)  BPLP leases the Bruce A nuclear generating plants and other property, plant and equipment to BALP under a sublease agreement. Future minimum base rent sublease payments under the capital lease receivable are imputed using a 7.5% discount rate.

8

6. Other Liabilities

	Jun 30/12			Dec 31/11
Deferred sales	$	10,318		$	13,739
Derivatives [note 13]		22,241			28,499
Accrued pension and post-retirement benefit liability		29,493			38,050
BPLP
Accrued pension and post-retirement benefit liability		474,317			468,363
Derivatives [note 13]		19,247			19,439
Ontario Power Generation (“OPG”) loan		3,476			4,045
Other		5,043			6,624
		564,135			578,759
Less current portion		(40,279	)		(50,495	)
Total	$	523,856		$	528,264

7. Share Capital

(a) At June 30, 2012, there were 395,313,278 common shares outstanding.

(b) Options in respect of 9,896,605 shares are outstanding under the stock option plan and are exercisable up to 2019. For the quarter ended June 30, 2012, 60,880 options were exercised resulting in the issuance of shares (2011 –11,488). For the six months ended June 30, 2012, 567,855 options were exercised resulting in the issuance of shares (2011 – 360,040).

8. Finance Costs

	Three Months Ended					Six Months Ended
	Jun 30/12			Jun 30/11		Jun 30/12			Jun 30/11
Interest on long-term debt	$	13,443		$	14,171	$	26,835		$	28,143
Unwinding of discount on provisions		3,413			3,447		6,776			6,738
Other charges		1,652			981		4,043			2,141
Foreign exchange losses (gains)		(5,182	)		576		(2,746	)		1,317
Interest on short-term debt		425			529		1,111			1,223
Capitalized interest		(1,001	)		—		(1,001	)		—
Total	$	12,750		$	19,704	$	35,018		$	39,562

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9. Income Taxes

	Three Months Ended						Six Months Ended
	Jun 30/12			Jun 30/11			Jun 30/12			Jun 30/11
Earnings (loss) before income taxes
Canada	$	(84,999	)	$	(54,606	)	$	(164,344	)	$	(74,619	)
Foreign		64,046			108,385			267,370			223,690
	$	(20,953	)	$	53,779		$	103,026		$	149,071
Current income taxes (recovery)
Canada	$	(880	)	$	6,266		$	534		$	(425	)
Foreign		3,331			5,556			14,224			17,136
	$	2,451		$	11,822		$	14,758		$	16,711
Deferred income taxes (recovery)
Canada	$	(27,023	)	$	(20,273	)	$	(45,408	)	$	(16,756	)
Foreign		(3,669	)		7,578			(5,159	)		2,979
	$	(30,692	)	$	(12,695	)	$	(50,567	)	$	(13,777	)
Income tax expense (recovery)	$	(28,241	)	$	(873	)	$	(35,809	)	$	2,934

In 2008, as part of the ongoing annual audits of Cameco’s Canadian tax returns, Canada Revenue Agency (“CRA”) disputed the transfer pricing methodology used by Cameco and its wholly owned Swiss subsidiary, Cameco Europe Ltd. (“CEL”), in respect of sale and purchase agreements for uranium products. From December 2008 to date, CRA issued notices of reassessment for the taxation years 2003, 2004, 2005 and 2006, which have increased Cameco’s income for Canadian income tax purposes by approximately $43,000,000, $108,000,000, $197,000,000 and $243,000,000 respectively. No reassessment received to date has resulted in more than a nominal amount of cash taxes becoming payable due to the availability of elective deductions and tax loss carrybacks. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for subsequent years on a similar basis.

CRA’s Transfer Pricing Review Committee has not imposed a transfer pricing penalty for any year reassessed to date.

Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect, and Cameco is contesting CRA’s position. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco has recorded a cumulative tax provision related to this matter for the years 2003 through the current period in the amount of $58,000,000. No provisions for penalties or interest have been recorded. Cameco does not expect more than a nominal amount of cash taxes to be payable due to the availability of elective deductions and tax loss carryovers. While the resolution of this matter may result in liabilities that are higher or lower than the reserve, management believes that the ultimate resolution will not be material to Cameco’s financial position, results of operations or liquidity over the period. However, an unfavourable outcome for the years 2003 to 2011 could be material to Cameco’s financial position, results of operations or cash flows in the year(s) of resolution.

Further to Cameco’s decision to contest CRA’s reassessments, Cameco is pursuing its appeal rights under the Income Tax Act.

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Other comprehensive income included on the consolidated statements of comprehensive income and the consolidated statements of changes in equity is presented net of income taxes. The following income tax amounts are included in each component of other comprehensive income:

For the three months ended June 30, 2012

	Before tax			Income tax recovery (expense)			Net of tax
Exchange differences on translation of foreign operations	$	15,718		$	—		$	15,718
Losses on derivatives designated as cash flow hedges		(1,833	)		458			(1,375	)
Gains on derivatives designated as cash flow hedges transferred to net earnings		(8,397	)		2,099			(6,298	)
Unrealized gains on available-for-sale assets		213			(28	)		185
Losses on available-for-sale assets transferred to net earnings		9			(1	)		8
	$	5,710		$	2,528		$	8,238

For the three months ended June 30, 2011

	Before tax			Income tax recovery (expense)			Net of tax
Exchange differences on translation of foreign operations	$	6,997		$	—		$	6,997
Gains on derivatives designated as cash flow hedges		2,023			(512	)		1,511
Gains on derivatives designated as cash flow hedges transferred to net earnings		(6,977	)		1,875			(5,102	)
Unrealized gains on available-for-sale assets		253			(36	)		217
Gains on available-for-sale assets transferred to net earnings		(6	)		1			(5	)
	$	2,290		$	1,328		$	3,618

For the six months ended June 30, 2012

	Before tax			Income tax recovery (expense)			Net of tax
Exchange differences on translation of foreign operations	$	(3,106	)	$	—		$	(3,106	)
Gains on derivatives designated as cash flow hedges		7,584			(1,896	)		5,688
Gains on derivatives designated as cash flow hedges transferred to net earnings		(15,777	)		3,944			(11,833	)
Unrealized losses on available-for-sale assets		(105	)		15			(90	)
Gains on available-for-sale assets transferred to net earnings		(45	)		6			(39	)
	$	(11,449	)	$	2,069		$	(9,380	)

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For the six months ended June 30, 2011

	Before tax			Income tax recovery (expense)			Net of tax
Exchange differences on translation of foreign operations	$	(14,382	)	$	—		$	(14,382	)
Gains on derivatives designated as cash flow hedges		4,273			(1,151	)		3,122
Gains on derivatives designated as cash flow hedges transferred to net earnings		(15,341	)		4,109			(11,232	)
Unrealized gains on available-for-sale assets		791			(107	)		684
Gains on available-for-sale assets transferred to net earnings		(2,120	)		280			(1,840	)
	$	(26,779	)	$	3,131		$	(23,648	)

10. Statements of Cash Flows

Other Operating Items

	Three Months Ended						Six Months Ended
	Jun 30/12			Jun 30/11			Jun 30/12			Jun 30/11
Changes in non-cash working capital:
Accounts receivable	$	(34,449	)	$	(18,978	)	$	295,102		$	229,650
Inventories		(66,050	)		(57,381	)		(63,038	)		(116,579	)
Supplies and prepaid expenses		(23,014	)		(9,317	)		(16,195	)		(4,040	)
Accounts payable and accrued liabilities		(23,961	)		(15,681	)		(70,470	)		(39,865	)
Other		(13,151	)		(5,834	)		(34,712	)		(24,780	)
Total	$	(160,625	)	$	(107,191	)	$	110,687		$	44,386

11. Share-Based Compensation Plans

The Company has the following equity-settled plans:

(a) Stock Option Plan

The Company has established a stock option plan under which options to purchase common shares may be granted to employees of Cameco. Options granted under the stock option plan have an exercise price of not less than the closing price quoted on the TSX for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options vest over three years and expire eight years from the date granted.

The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed 43,017,198, of which 27,054,674 shares have been issued.

(b) Executive Performance Share Unit (“PSU”)

The Company has established a PSU plan whereby it provides each plan participant an annual grant of PSUs in an amount determined by the board. Each PSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash at the board’s discretion, at the end of each three-year period if certain performance and vesting criteria have been met. The final value of the PSUs will be based on the value of Cameco common shares at the end of the three-year period and the number of PSUs that ultimately vest. Vesting of PSUs at the end of the three-year period will be based on total shareholder return over the three years, Cameco’s ability to meet its annual cash flow from operations targets and whether the participating executive remains employed by Cameco at the end of the three-year vesting period.

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(c) Executive Restricted Share Unit (“RSU”)

In 2011, the Company established an RSU plan whereby it provides each plan participant a grant of RSUs in an amount determined by the board. Each RSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash at the board’s discretion. The final value of the RSUs will be based on the value of Cameco common shares at the end of the three year vesting period.

Cameco records compensation expense with an offsetting credit to contributed surplus to reflect the estimated fair value of the equity-settled share-based compensation plans granted to employees.

	Three Months Ended				Six Months Ended
	Jun 30/12		Jun 30/11		Jun 30/12		Jun 30/11
Stock option plan	$	6,072	$	2,375	$	9,056	$	9,620
Performance share unit		1,486		850		573		1,700
Restricted share unit		148		—		297		—
Total	$	7,706	$	3,225	$	9,926	$	11,320

The fair value of the units granted through the PSU plan was determined based on Monte Carlo simulation. The fair value of all other share-based payment plans was measured based on the Black-Scholes option-pricing model. Expected volatility is estimated by considering historic average share price volatility. The inputs used in the measurement of the fair values at grant date were as follows:

	Stock Option
	Plan			PSUs
Number of options granted		2,097,573			178,640
Average strike price	$	21.14			—
Expected dividend	$	0.40		$	0.40
Expected volatility		47	%		36	%
Risk-free interest rate		1.4	%		1.4	%
Expected life of option		4.3 years			3 years
Expected forfeitures		10	%		0	%
Weighted average grant date fair values	$	7.21		$	20.05

In addition to these inputs, other features of the PSU grant were incorporated into the measurement of fair value. The market condition based on total shareholder return was incorporated by utilizing a Monte Carlo simulation. The non-market criteria relating to realized selling prices, production targets and cost control have been incorporated into the valuation at grant date by reviewing prior history and corporate budgets.

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12. Commitments and Contingencies

(a) On May 16, 2012, Cameco, Cameco Bruce Holdings II Inc., BPC Generation Infrastructure Trust (“BPC”) and TransCanada Pipelines Limited (“TransCanada”) (collectively, the “Consortium”) received an arbitration award in their favour against British Energy Limited and British Energy International Holdings Limited (collectively, “BE”) ruling in favour of the Consortium on the issues of repair costs and lost revenue for breach of a representation and warranty contained in the February 14, 2003 Amended and Restated Master Purchase Agreement under which the Consortium acquired BE’s interest in BPLP. The Consortium and BE are in discussions over the quantification of the damages under the arbitrators award. If these issues are not resolved, they will be referred back to the arbitrator for a final decision. The Company recorded an estimate of the expected net proceeds.

In connection with this arbitration, BE issued on February 10, 2006, and then served on OPG and BPLP a Statement of Claim. This Statement of Claim seeks damages for any amounts that BE is found liable to pay to the Consortium in connection with the Unit 8 steam generator arbitration described above, damages in the amount of $500,000,000, costs and pre and post judgment interest amongst other things. Further proceedings in this action are on hold pending final disposition of the arbitration award.

(b) Annual supplemental rents of $30,000,000 (subject to CPI) per operating reactor are payable by BPLP to OPG. Should the hourly annual average price of electricity in Ontario fall below $30 per megawatt hour for any calendar year, the supplemental rent reduces to $12,000,000 per operating reactor. In accordance with the Sublease Agreement, BALP will participate in its share of any adjustments to the supplemental rent.

(c) Cameco, TransCanada and BPC have assumed the obligations to provide financial guarantees on behalf of BPLP. Cameco has provided the following financial assurances, with varying terms that range from 2012 to 2018:

i) Guarantees to customers under power sales agreements of up to $19,000,000. At June 30, 2012, Cameco’s actual exposure under these agreements was $6,500,000.

ii) Termination payments to OPG pursuant to the lease agreement of $58,300,000. The fair value of these guarantees is nominal.

(d) Under a supply contract with the Ontario Power Authority (“OPA”), BPLP is entitled to receive payments from the OPA during periods when the market price for electricity in Ontario is lower than the floor price defined under the agreement during a calendar year. On July 6, 2009, BPLP and the OPA amended the supply contract such that beginning in 2009, the annual payments received will not be subject to repayment in future years. Previously, the payments received under the agreement were subject to repayment during the entire term of the contract, dependent on the spot price in future periods. BPLP’s entitlement to receive these payments remains in effect until December 31, 2019 but the generation that is subject to these payments starts to decrease in 2016, reflecting the original estimated lives for the Bruce B units. During 2012, BPLP recorded $409,400,000 under this agreement which was recognized as revenue with Cameco’s share being $129,400,000.

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13. Derivatives

The following tables summarize the fair value of derivatives and classification on the statements of financial position:

As at June 30, 2012

	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives—sales contracts	$	74		$	7,443		$	7,517
Foreign currency contracts		(13,811	)		—			(13,811	)
Interest rate contracts		5,528			—			5,528
Cash flow hedges:
Energy and sales contracts		—			19,355			19,355
Net	$	(8,209	)	$	26,798		$	18,589
Classification:
Current portion of long-term receivables, investments and other [note 5]	$	7,110		$	37,166		$	44,276
Long-term receivables, investments and other [note 5]		6,922			8,879			15,801
Current portion of other liabilities [note 6]		(18,826	)		(17,097	)		(35,923	)
Other liabilities [note 6]		(3,415	)		(2,150	)		(5,565	)
Net	$	(8,209	)	$	26,798		$	18,589

As at December 31, 2011

	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives—sales contracts	$	(639	)	$	8,033		$	7,394
Foreign currency contracts		(17,633	)		—			(17,633	)
Interest rate contracts		7,165			—			7,165
Cash flow hedges:
Energy and sales contracts		—			26,538			26,538
Net	$	(11,107	)	$	34,571		$	23,464
Classification:
Current portion of long-term receivables, investments and other [note 5]	$	8,922		$	42,088		$	51,010
Long-term receivables, investments and other [note 5]		8,470			11,922			20,392
Current portion of other liabilities [note 6]		(26,555	)		(16,913	)		(43,468	)
Other liabilities [note 6]		(1,944	)		(2,526	)		(4,470	)
Net	$	(11,107	)	$	34,571		$	23,464

15

The following tables summarize different components of the gains (losses) on derivatives:

For the three months ended June 30, 2012

	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives—sales contracts	$	(205	)	$	(492	)	$	(697	)
Foreign currency contracts		(22,454	)		—			(22,454	)
Interest rate contracts		1,272			—			1,272
Cash flow hedges:
Energy and sales contracts		—			(1,001	)		(1,001	)
Net	$	(21,387	)	$	(1,493	)	$	(22,880	)

For the three months ended June 30, 2011

	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives—sales contracts	$	(101	)	$	464		$	363
Foreign currency contracts		10,223			—			10,223
Interest rate contracts		2,642			—			2,642
Cash flow hedges:
Energy and sales contracts		—			(1,369	)		(1,369	)
Net	$	12,764		$	(905	)	$	11,859

For the six months ended June 30, 2012

	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives—sales contracts	$	125		$	1,593		$	1,718
Foreign currency contracts		1,433			—			1,433
Interest rate contracts		(403	)		—			(403	)
Cash flow hedges:
Energy and sales contracts		—			(1,174	)		(1,174	)
Net	$	1,155		$	419		$	1,574

For the six months ended June 30, 2011

	Cameco		BPLP			Total
Non-hedge derivatives:
Embedded derivatives—sales contracts	$	1,372	$	138		$	1,510
Foreign currency contracts		33,660		—			33,660
Interest rate contracts		1,873		—			1,873
Cash flow hedges:
Energy and sales contracts		—		(1,455	)		(1,455	)
Net	$	36,905	$	(1,317	)	$	35,588

Over the next 12 months, based on current exchange rates, Cameco expects an estimated $15,110,000 of pre-tax gains from BPLP’s various energy and sales related cash flow hedges to be reclassified through other comprehensive income to net earnings. The maximum length of time BPLP is hedging its exposure to the variability in future cash flows related to electricity prices on future transactions is six years.

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14. Earnings Per Share

Per share amounts have been calculated based on the weighted average number of common shares outstanding during the period. The weighted average number of paid shares outstanding in 2012 was 395,121,999 (2011 – 394,607,145).

	Three Months Ended				Six Months Ended
	Jun 30/12		Jun 30/11		Jun 30/12		Jun 30/11
Basic earnings per share computation
Net earnings attributable to equity holders	$	7,877	$	54,652	$	139,615	$	146,137
Weighted average common shares outstanding		395,277		394,706		395,122		394,607
Basic earnings per common share	$	0.02	$	0.14	$	0.35	$	0.37
Diluted earnings per share computation
Net earnings attributable to equity holders	$	7,877	$	54,652	$	139,615	$	146,137
Weighted average common shares outstanding		395,277		394,706		395,122		394,607
Dilutive effect of stock options		94		667		568		1,335
Weighted average common shares outstanding, assuming dilution		395,371		395,373		395,690		395,942
Diluted earnings per common share	$	0.02	$	0.14	$	0.35	$	0.37

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15. Segmented Information

Cameco has three reportable segments: uranium, fuel services and electricity. The uranium segment involves the exploration for, mining, milling, purchase and sale of uranium concentrate. The fuel services segment involves the refining, conversion and fabrication of uranium concentrate and the purchase and sale of conversion services. The electricity segment involves the generation and sale of electricity.

Cameco’s reportable segments are strategic business units with different products, processes and marketing strategies.

Accounting policies used in each segment are consistent with the policies outlined in the most recent annual consolidated financial statements. Segment revenues, expenses and results include transactions between segments incurred in the ordinary course of business. These transactions are priced on an arm’s length basis and are eliminated on consolidation.

(a) Business Segments

For the three months ended June 30, 2012

	Uranium			Fuel Services		Electricity		Other			Total
Revenue	$	205,503		$	66,207	$	119,132	$	582		$	391,424
Expenses
Cost of products and services sold		130,673			51,169		44,273		78			226,193
Depreciation and amortization		32,373			5,870		19,748		3,844			61,835
Cost of sales		163,046			57,039		64,021		3,922			288,028
Gross profit (loss)		42,457			9,168		55,111		(3,340	)		103,396
Exploration		17,888			—		—		—			17,888
Loss on sale of assets		913			—		—		—			913
Share of loss from equity-accounted investees		1,253			706		—		—			1,959
Other expense		36,507			—		—		—			36,507
Non-segmented expenses												67,082
Earnings (loss) before income taxes		(14,104	)		8,462		55,111		(3,340	)		(20,953	)
Income tax recovery												(28,241	)
Net earnings											$	7,288

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For the three months ended June 30, 2011

	Uranium			Fuel Services		Electricity		Other			Total
Revenue	$	256,261		$	69,606	$	99,224	$	614		$	425,705
Expenses
Cost of products and services sold		148,139			51,094		68,752		74			268,059
Depreciation and amortization		22,449			5,947		16,845		4,475			49,716
Cost of sales		170,588			57,041		85,597		4,549			317,775
Gross profit (loss)		85,673			12,565		13,627		(3,935	)		107,930
Exploration		14,647			—		—		—			14,647
Loss on sale of assets		719			—		—		—			719
Share of loss from equity-accounted investees		1,951			373		—		—			2,324
Other expense		133			—		—		—			133
Non-segmented expenses												36,328
Earnings (loss) before income taxes		68,223			12,192		13,627		(3,935	)		53,779
Income tax recovery												(873	)
Net earnings											$	54,652
For the six months ended June 30, 2012
				Fuel
	Uranium			Services		Electricity		Other			Total
Revenue	$	606,581		$	122,452	$	224,518	$	1,131		$	954,682
Expenses
Cost of products and services sold		358,818			92,237		101,338		146			552,539
Depreciation and amortization		63,816			10,108		38,948		7,958			120,830
Cost of sales		422,634			102,345		140,286		8,104			673,369
Gross profit (loss)		183,947			20,107		84,232		(6,973	)		281,313
Exploration		40,857			—		—		—			40,857
Gain on sale of assets		(2,149	)		—		—		—			(2,149	)
Share of loss from equity-accounted investees		1,277			1,494		—		—			2,771
Other expense		35,744			—		—		—			35,744
Non-segmented expenses												101,064
Earnings (loss) before income taxes		108,218			18,613		84,232		(6,973	)		103,026
Income tax recovery												(35,809	)
Net earnings											$	138,835

19

For the six months ended June 30, 2011

	Uranium			Fuel Services		Electricity		Other			Total
Revenue	$	553,569		$	118,855	$	206,632	$	7,750		$	886,806
Expenses
Cost of products and services sold		322,792			89,089		124,828		6,915			543,624
Depreciation and amortization		44,798			10,439		34,558		8,992			98,787
Cost of sales		367,590			99,528		159,386		15,907			642,411
Gross profit (loss)		185,979			19,327		47,246		(8,157	)		244,395
Exploration		30,486			—		—		—			30,486
Loss on sale of assets		695			—		—		—			695
Share of loss from equity-accounted investees		3,866			1,150		—		—			5,016
Other income		(1,439	)		—		—		—			(1,439	)
Non-segmented expenses												60,566
Earnings (loss) before income taxes		152,371			18,177		47,246		(8,157	)		149,071
Income tax expense												2,934
Net earnings											$	146,137

16. Related Parties

The shares of Cameco are widely held and no shareholder, resident in Canada, is allowed to own more than 25% of the Company’s outstanding common shares, either individually or together with associates. A non-resident of Canada is not allowed to own more than 15%.

Transactions with Key Management Personnel

Key management personnel are those persons that have the authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly. Key management personnel of the Company include executive officers, vice-presidents, other senior managers and members of the board of directors.

Certain key management personnel, or their related parties, hold positions in other entities that result in them having control or significant influence over the financial or operating policies of those entities. As noted below, one of these entities transacted with the Company in the reporting period. The terms and conditions of the transactions were on an arm’s length basis.

Cameco purchases a significant amount of goods and services for its Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One such supplier is Points Athabasca Contracting Ltd. and the president of the company became a member of the board of directors of Cameco during 2009. In 2012, Cameco paid Points Athabasca Contracting Ltd. $22,000,000 (2011—$32,900,000) for construction and contracting services. The transactions were conducted in the normal course of business and were accounted for at the exchange amount. Accounts payable include a balance of $1,560,000 (2011—$6,840,000).

20

Other Related Party Transactions

	Transaction Value						Transaction Value						Balance Outstanding
	Three Months Ended						Six Months Ended						As at
	Jun 30/12			Jun 30/11			Jun 30/12			Jun 30/11			Jun 30/12			Jun 30/11
Sale of goods and services
Jointly Controlled Entities
BPLP (a)	$	22,057		$	6,726		$	38,853		$	22,217		$	29,376		$	7,806
Other
Jointly Controlled Entities
Interest income (Inkai)		562			567			1,071			1,203			98,064			97,136
Associates
Interest expense		(274	)		(509	)		(671	)		(1,035	)		(58,647	)		(76,790	)

(a) Disclosures in respect of transactions with jointly controlled entities represent the amount of such transactions which do not eliminate on proportionate consolidation.

Cameco has entered into fuel supply agreements with BPLP for the procurement of fabricated fuel. Under these agreements, Cameco will supply uranium, conversion services and fabrication services. Contract terms are at market rates and on normal trade terms.

Through an unsecured shareholder loan, Cameco has agreed to fund the development of the Inkai project. The limit of the advances of the loan facility is currently $263,150,000 (US) and bear interest at a rate of LIBOR plus 2%. At June 30, 2012, $240,600,000 (US) of principal and interest was outstanding (December 31, 2011—$191,900,000 (US)). At June 30, 2012 the remaining funds available for advance under the facility was $23,000,000 (US) (December 31, 2011—$14,200,000 (US)).

In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GE-Hitachi Global Laser Enrichment LLC (GLE). The promissory note is payable on demand and bears interest at market rates. At June 30, 2012, $57,500,000,000 (US) of principal and interest was outstanding (December 31, 2011—$72,200,000 (US)).

17. NUKEM Energy GmbH (“NUKEM”)

On May 14, 2012, Cameco entered into an agreement with Advent International (“Advent”) to purchase NUKEM, one of the world’s leading traders and brokers of nuclear fuel products and services, for cash proceeds of $136,000,000 (US) and the assumption of their debt. The agreement provides that Cameco will receive the benefits of owning NUKEM as of January 1, 2012. It also includes provisions that would provide Advent with a share of NUKEM’s future earnings under certain conditions until the end of 2014. The agreement is subject to regulatory approvals and is expected to close in the third quarter of 2012.

18. Millennium Project Agreement

On June 11, 2012, Cameco acquired a 27.94% interest in the Millennium project from AREVA Resources Canada Inc. (“AREVA”) for $150,000,000, increasing its ownership to 69.9%. The remaining 30.1% is owned by JCU (Canada) Exploration Co. The Millennium project is a proposed uranium mine located in the Athabasca Basin of northern Saskatchewan consisting of 590 hectares of land. Exploration on the Millennium project area has identified indicated resources of 50,900,000 pounds of U₃O₈ and inferred resources of 16,700,000 pounds of U₃O₈. The terms of the purchase agreement provides AREVA with a 4% royalty on revenue from 27.94% of any production that exceeds 63,000,000 pounds U₃O₈ from this project.

19. Comparative Figures

Certain prior period balances have been reclassified to conform to the current financial statement presentation.

21

EX-99.4

Exhibit 99.4

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Tim Gitzel, president and chief executive officer of Cameco Corporation, certify that:

1. I have reviewed this quarterly report on Form 6-K of Cameco Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 27, 2012

  “Tim Gitzel”

Tim Gitzel

President and Chief Executive Officer

EX-99.5

Exhibit 99.5

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Grant Isaac, senior vice-president and chief financial officer, of Cameco Corporation, certify that:

1. I have reviewed this quarterly report on Form 6-K of Cameco Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 27, 2012

        “Grant Isaac”

Grant Isaac

Senior Vice-President

and Chief Financial Officer