Cameco (CCJ) 6-K Cameco reports second quarter financial results

Exhibit 99.2

Management’s discussion and analysis

for the quarter ended June 30, 2013

SECOND QUARTER UPDATE	4
CONSOLIDATED FINANCIAL RESULTS	8
OUTLOOK FOR 2013	13
LIQUIDITY AND CAPITAL RESOURCES	14
FINANCIAL RESULTS BY SEGMENT
URANIUM	17
FUEL SERVICES	20
NUKEM	21
ELECTRICITY	23
OUR OPERATIONS AND DEVELOPMENT PROJECT	25
URANIUM 2013 Q2 UPDATES	27
FUEL SERVICES 2013 Q2 UPDATES	28
QUALIFIED PERSONS	29
ADDITIONAL INFORMATION	29

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, 2013 (interim financial statements). The information is based on what we knew as of July 31, 2013 and updates our first quarter and annual MD&A included in our 2012 annual report.

As you review this 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, 2012 and annual MD&A. 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.

Throughout this document, the termswe, us, ourandCameco mean Cameco Corporation and its subsidiaries, including NUKEM Energy Gmbh (NUKEM), unless otherwise indicated.

Caution about forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans, future financial and operating performance, or other things that have not yet taken place, we are making statements considered to beforward-lookinginformation orforward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A asforward-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, believe, estimate, expect, plan, will, intend, goal, target, forecast, project, strategy and outlook (see examples below).

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

• It is based on a number ofmaterial 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 thesematerial 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 othermaterial risks that could cause actual results to differ significantly from our current expectations.

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

Examples of forward-looking information in this MD&A

• the discussion under the headingOur strategy

• our expectations about 2013 and future global uranium supply and demand, including the discussion under the headingUranium market update

• our target for a sustainable 10% future cost reduction

• the outlook for each of our operating segments for 2013 and our consolidated outlook for the year

• our expectation that existing cash balances and operating cash flows will meet our anticipated 2013 capital requirements without the need for any significant additional funding

• our estimate of the amount and timing of expected cash taxes payable to Canada Revenue Agency (CRA)

• our expectations for 2013, 2014 and 2015 capital expenditures

• our expectation that our operating and investment activities in 2013 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 2013 to 2017 and our plan to achieve annual supply of 36 million pounds by 2018

• our expectation that Talvivaara will start uranium production in the first half of 2014

• our future plans for each of our uranium operating properties and development project

• our expectation that we will begin jet boring in ore this summer at Cigar Lake with first packaged pounds from AREVA’s McClean Lake mill in the fourth quarter

• our estimates of Cigar Lake capital costs

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, or we are unsuccessful in our dispute with the CRA

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

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

• we are unable to enforce our legal rights under our existing agreements, permits or licences, or are subject to litigation or arbitration that has an adverse outcome

• there are defects in, or challenges to, title to our properties

• our mineral reserve and resource estimates are 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, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy

2     CAMECO CORPORATION

• 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 fulfill 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, processing of the ore, or our inability to acquire any of the required jet boring equipment

• our McArthur River development, mining or production plans are delayed or do not succeed

• 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 (including an inability to renew agreements with unionized employees at McArthur River and Key Lake), strikes or lockouts, underground floods, cave ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

• NUKEM’s actual uranium sales volume, cash flows and revenue in 2013 are lower than expected due to losses in connection with spot market purchases, counterparty default on payment or other obligations, counterparty insolvency or other risks

• departure of key personnel at NUKEM could have an adverse effect on continuing operations

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 more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants

• our expected production level and production costs

• the assumptions regarding market conditions upon which we have based our capital expenditure expectations

• our expectations regarding spot prices and realized prices for uranium, and other factors discussed on page 19,Price sensitivity analysis: uranium

• our expectations regarding tax rates and payments, the outcome of the dispute with the CRA, 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 are successful, including success with the jet boring mining method and processing of the ore, and that we will be able to obtain the additional jet boring systems we require on schedule

• the success of our McArthur River development, mining and production plans

• 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 (including an inability to renew agreements with unionized employees at McArthur River and Key Lake), 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

• NUKEM’s actual uranium sales volume, cash flows and revenue in 2013 will be consistent with our expectations

• key personnel will remain with NUKEM

2013 SECOND QUARTER REPORT    3

Our strategy

Our strategy is to profitably increase annual uranium supply to 36 million pounds by 2018, subject to market conditions, and to invest in opportunities across the nuclear fuel cycle that we expect will complement and enhance our business. Lead-times in our industry are long, so we are preparing our assets today to make sure we can be among the first to respond when the market signals new production is needed.

However, we are also committed to enhancing our near-term financial returns and continuing to create shareholder value. In the context of current market uncertainty, we have made some modifications to our operating and development plans to ensure we remain a low cost producer and profitably grow the company. This resulted in the consolidation of a number of business and operating functions, which has allowed us to reduce the workforce by about 8%. Though these changes have led to some restructuring costs that will impact our financial results in 2013, our target is to achieve a sustainable 10% future cost reduction through a combination of decreased spending for administration, operations and capital. For more detailed discussion, please seeRestructuring on page 10.

You can read more about our strategy in our 2012 annual MD&A.

Second quarter update

Effective January 1, 2013,IFRS 11 – Joint Arrangements requires that we account for our interest in Bruce Power Limited Partnership (BPLP) using equity accounting. Our quarterly results for 2012 have been restated for comparative purposes. SeeNew standards and interpretations on page 29 for more information.

Our performance

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED JUNE  30						CHANGE			SIX MONTHS ENDED JUNE  30				CHANGE
	2013			2012						2013		2012
Revenue		421			282			49	%		865		748		16	%
Gross profit		99			50			98	%		194		200		(3	)%
Net earnings attributable to equity holders		34			5			580	%		43		133		(68	)%
$ per common share (diluted)		0.09			0.01			800	%		0.11		0.34		(68	)%
Adjusted net earnings (non-IFRS, see page 9)		61			31			97	%		88		151		(42	)%
$ per common share (adjusted and diluted)		0.15			0.08			88	%		0.22		0.38		(42	)%
Cash provided by operations (after working capital changes)		(37	)		(117	)		68	%		232		257		(10	)%

SECOND QUARTER

Net earnings attributable to equity holders (net earnings) this quarter were $34 million ($0.09 per share diluted) compared to $5 million ($0.01 per share diluted) in the second quarter of 2012. Net earnings were impacted by the items noted below, partially offset by mark-to-market losses on foreign exchange derivatives.

On an adjusted basis, our earnings this quarter were $61 million ($0.15 per share diluted) compared to $31 million ($0.08 per share diluted) (non-IFRS measure, see page 9) in the second quarter of 2012, mainly due to:

• higher earnings from our uranium business based on higher realized prices and increased sales volumes

• higher tax recoveries due to a decline in pre-tax earnings in Canada

• partially offset by lower earnings in the electricity business as a result of lower generation and higher operating costs

SeeFinancial results by segment on page 9 for more detailed discussion.

FIRST SIX MONTHS

Net earnings in the first six months of the year were $43 million ($0.11 per share diluted) compared to $133 million ($0.34 per share diluted) in the first six months of 2012. In addition to the items noted below, net earnings were impacted by mark-to-market losses on foreign exchange derivatives.

4     CAMECO CORPORATION

On an adjusted basis, our earnings for the first six months of this year were $88 million ($0.22 per share diluted) compared to $151 million ($0.38 per share diluted) (non-IFRS measure, see page 9) for the first six months of 2012, mainly due to:

• lower earnings in the electricity business as a result of lower generation and higher operating costs

• lower earnings from our uranium business based on lower sales volumes

• higher expenditures for administration due to the addition of NUKEM’s administration and advisory fee, and costs for corporate restructuring as described in Restructuring on page 10

• partially offset by higher tax recoveries due to a decline in pre-tax earnings in Canada

SeeFinancial results by segment on page 9 for more detailed discussion.

Operations update

HIGHLIGHTS					THREE MONTHS ENDED JUNE  30				CHANGE			SIX MONTHS ENDED JUNE 30					CHANGE
					2013		2012					2013			2012
Uranium	Production volume (million lbs)					4.4		5.3		(17	)%		10.3			10.2		1	%
	Sales volume (million lbs)					6.4		5.0		28	%		11.6			13.2		(12	)%
	Average realized price	($	US/lb	)		46.30		42.17		10	%		47.24			46.20		2	%
		($	Cdn/lb	)		47.35		42.29		12	%		47.75			46.66		2	%
	Revenue ($ millions)					305		211		45	%		552			617		(11	)%
	Gross profit ($ millions)					91		44		107	%		174			187		(7	)%
Fuel services	Production volume (million kgU)					4.8		4.3		12	%		9.6			8.8		9	%
	Sales volume (million kgU)					4.0		4.2		(5	)%		7.3			7.1		3	%
	Average realized price ($Cdn/kgU)					16.45		16.94		(3	)%		17.89			18.43		(3	)%
	Revenue ($ millions)					65		70		(7	)%		131			130		1	%
	Gross profit ($ millions)					10		9		11	%		21			20		5	%
NUKEM1	Sales volume U3O8(million lbs)					1.2		—		—			3.5			—		—
	Average realized price ($Cdn/lb)					44.40		—		—			44.26			—		—
	Revenue ($ millions)					53		—		—			183			—		—
	Gross profit ($ millions)					3		—		—			8			—		—
Electricity	Output (100%) (TWh)					5.5		6.5		(15	)%		11.0			12.5		(12	)%
	Average realized price ($Cdn/MWh)					54.00		55.00		(2	)%		53.00			55.00		(4	)%
	Revenue (100%)					307		377		(19	)%		595			711		(16	)%
	Our share of earnings (loss) before taxes ($ millions)					1		46		(98	)%		(1	)		69		(101	)%

¹  SeeNUKEM on page 21 for details of the purchase price allocation.

Production in our uranium segment this quarter was 17% lower compared to the second quarter of 2012, mainly due to lower production at Rabbit Lake and McArthur River/Key Lake. For the first six months, production is 1% higher than for the same period in 2012 mainly due to higher production from Inkai. SeeUranium 2013 Q2 updates starting on page 27 for more information.

Key highlights:

• At Cigar Lake, we were granted an eight-year mine licence by the Canadian Nuclear Safety Commission (CNSC) and we continued to make progress towards first production. See page 28 for more information.

• In the US, our North Butte satellite operation began production. See page 27 for more information.

• Unionized employees at the Port Hope conversion facility accepted new three-year contracts. See Fuel services 2013 Q2 update on page 28 for additional details.

• On May 31, 2013 we announced the signing of a collaboration agreement that will strengthen the relationship between us, AREVA Resources Canada Inc. and the English River First Nation. This furthers our efforts to

2013 SECOND QUARTER REPORT    5

formalize our relationship with local communities and continues to build on past cooperation and sharing of benefits from our operations.

Production in our fuel services segment was 12% higher this quarter than in the second quarter of 2012 and 9% higher for the first six months compared to last year. We increased our annual production target in 2013, which we expect to result in higher quarterly production over comparable periods in 2012.

In our electricity segment, BPLP’s generation was 15% lower for the quarter and 12% lower for the first half of the year compared to the same periods last year mainly due to an increase in the number of planned outage days. The capacity factor this quarter and for the first half of the year was 77%, compared to 91% in the second quarter of 2012 and 88% for the first six months of 2012.

Uranium market update

Similar to the previous quarter, near- to medium-term uncertainty continues to impede a recovery in the market, with neither buyers nor suppliers under significant pressure to contract. Volumes contracted have remained low, and uranium prices were relatively stable during the second quarter, though there has recently been downward pressure on the spot price. We believe the market will remain in this ‘wait-and-see’ mode for the present, particularly during the summer months, during which contracting is traditionally light.

The inventories and lack of demand as a result of Japan’s idled reactors are largely responsible for the continued market sluggishness, and restarts of those reactors will be an important catalyst. There has been some progress in Japan: the Nuclear Regulatory Authority finalized new safety guidelines against which reactor restarts will be evaluated, and as of July 31, four utilities have applied to restart 12 reactors. Like most industry participants, we will be paying close attention to how the review process progresses and what it could mean for subsequent restart applications.

Over the long term, Japan’s energy policy is still being determined; however, we believe nuclear remains an important energy source for the country. Japan’s Liberal Democratic Party (LDP) has expressed support for nuclear energy as being important for the country’s economy and for achieving their environmental goals. In July, the party won control of the country’s upper house, giving the LDP a strong majority, which we expect to be positive for the industry.

The supply side continues to evolve. Over the past few quarters, we have seen some projects delayed due to uranium prices insufficient to support new production. However, more recently, there have been announcements that other projects, primarily driven by sovereign interests, will go ahead despite market conditions. These developments do not directly impact the near-term market, but could have an effect on the longer term outlook for the uranium industry.

In July, the US Department of Energy (DOE) updated its plan for excess uranium inventories, which is used to outline such things as total volume of inventories, planned use and future sales. Overall, total UF₆ volumes and future sales referenced in the plan are generally in line with industry expectations. However, the revised plan removes the well-known guideline which had limited DOE uranium excess inventory sales to 10% of US reactor fuel requirements. There is potential for this to impact the uranium market; however, DOE sales will continue to be governed by Secretarial Determinations, which require that any such sales not have a material adverse impact on the US uranium, conversion and enrichment industries.

Despite the current challenging industry environment, we are well positioned to continue to succeed. We have the advantage of extensive mineral reserves and resources, low cost operations, a strong sales contract portfolio, experienced employees and a growth strategy that will allow us to remain competitive in challenging environments, while maintaining the ability to respond with additional production when the market signals that more supply is required.

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

This discussion of our expectations for the nuclear industry, including future global uranium supply and demand, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headingCaution about forward-looking information beginning on page 2.

6     CAMECO CORPORATION

Industry prices

	JUN 30 2013		MAR 31 2013		JUN 30 2012		MAR 31 2012
Uranium ($US/lb U3O8) 1
Average spot market price		39.60		42.25		50.75		51.05
Average long-term price		57.00		56.50		61.25		60.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		10.00		10.50		6.63		6.63
Europe		10.38		11.00		7.00		7.00
Average long-term price
North America		16.75		16.75		16.75		16.75
Europe		17.25		17.25		17.25		17.25
Note: the industry does not publish UO2prices.
Electricity ($/MWh)
Average Ontario electricity spot price		25.00		29.00		19.00		20.00

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

Buying interest has increased slightly with some utilities evaluating spot and term purchases. However, buyers are currently participating in the spot uranium market largely on a discretionary basis. We anticipate moderate spot and long-term demand through the balance of the year, though total long-term demand is expected to remain below average and lower than our anticipated range of 75 million to 100 million pounds in 2013.

On the spot market, where purchases call for delivery within one year, the volume reported for the second quarter of 2013 was approximately 9 million pounds. This compares to approximately 7 million pounds in the second quarter of 2012.

At the end of the quarter, the average spot price was $39.60 (US) per pound. On July 29, 2013, Ux reported a spot price of $34.50 (US) per pound.

The long-term uranium price held steady 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 UF₆conversion prices declined during the quarter whereas long-term UF₆ conversion prices held firm.

SHARES AND STOCK OPTIONS OUTSTANDING

At July 30, 2013, we had:

• 395,458,205 common shares and one Class B share outstanding

• 10,147,416 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.

2013 SECOND QUARTER REPORT    7

Financial results

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

Consolidated financial results

Effective January 1, 2013,IFRS 11 – Joint Arrangements requires that we account for our interest in BPLP using equity accounting. Our quarterly results for 2012 have been restated for comparative purposes. SeeNew standards and interpretations on page 29 for more information.

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED JUNE  30						CHANGE			SIX MONTHS ENDED JUNE  30				CHANGE
	2013			2012						2013		2012
Revenue		421			282			49	%		865		748		16	%
Gross profit		99			50			98	%		194		200		(3	)%
Net earnings attributable to equity holders		34			5			580	%		43		133		(68	)%
$ per common share (basic)		0.09			0.01			800	%		0.11		0.34		(68	)%
$ per common share (diluted)		0.09			0.01			800	%		0.11		0.34		(68	)%
Adjusted net earnings (non-IFRS, see page 9)		61			31			97	%		88		151		(42	)%
$ per common share (adjusted and diluted)		0.15			0.08			88	%		0.22		0.38		(42	)%
Cash provided by operations (after working capital changes)		(37	)		(117	)		68	%		232		257		(10	)%

Net earnings

In the second quarter of 2013, our net earnings were $34 million ($0.09 per share diluted), an increase of $29 million compared to $5 million ($0.01 per share diluted) in 2012. Net earnings were impacted by the items noted below, partially offset by mark-to-market losses on foreign exchange derivatives.

On an adjusted basis, our earnings this quarter were $61 million ($0.15 per share diluted) compared to $31 million ($0.08 per share diluted) (non-IFRS measure, see page 9) in the second quarter of 2012. This increase was largely the result of:

• higher earnings from our uranium business based on higher realized prices and increased sales volumes

• higher tax recoveries due to a decline in pre-tax earnings in Canada

• partially offset by lower earnings in the electricity business as a result of lower generation and higher operating costs

Net earnings in the first six months of the year were $43 million ($0.11 per share diluted), a decrease of $90 million compared to $133 million ($0.34 per share diluted) in 2012. In addition to the items noted below, net earnings were impacted by mark-to-market losses on foreign exchange derivatives.

On an adjusted basis, our earnings for the first six months of this year were $88 million ($0.22 per share diluted) compared to $151 million ($0.38 per share diluted) (non-IFRS measure, see page 9). This decline was largely the result of:

• lower earnings in the electricity business as a result of lower generation and higher operating costs

• lower earnings from our uranium business based on lower sales volumes

• higher expenditures for administration due to the addition of NUKEM’s administration and advisory fee, and costs for corporate restructuring as described in Restructuring on page 10

• partially offset by higher tax recoveries due to a decline in pre-tax earnings in Canada

SeeFinancial results by segment on page 9 for more detailed discussion.

8     CAMECO CORPORATION

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, and has been adjusted for impairment charges on a non-producing property.

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
	2013			2012			2013			2012
Net earnings attributable to equity holders		34			5			43			133
Adjustments
Adjustments on derivatives1(pre-tax)		36			35			61			25
Income taxes on adjustments to derivatives		(9	)		(9	)		(16	)		(7	)
Adjusted net earnings		61			31			88			151

¹  We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.

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

			THREE MONTHS			SIX MONTHS
($ MILLIONS)			ENDED JUNE 30			ENDED JUNE 30
Adjusted net earnings– 2012				31			151
Change in gross profitbysegment		(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 volume			13			(24	)
	Higher realized prices ($US)			27			12
	Foreign exchange impact on realized prices			6			1
	Lower (higher) costs			1			(1	)
	Hedging benefits			(18	)		(27	)
	change –uranium			29			(39	)
Fuel services	Higher sales volume			—			1
	Lower realized prices ($Cdn)			(2	)		(4	)
	Lower costs			3			4
	Hedging benefits			(3	)		(4	)
	change –fuel services			(2	)		(3	)
NUKEM	Gross profit			3			8
	change –NUKEM			3			8
Other changes
Lower earnings from equity investment in BPLP				(45	)		(70	)
Lower (higher) administration expenditures				3			(14	)
Lower exploration expenditures				2			4
Lower income taxes				16			25
Contract termination fee (incurred in Q2, 2012)				30			30
Other				(6	)		(4	)
Adjusted net earnings– 2013				61			88

SeeFinancial results by segment on page 17 for more detailed discussion.

2013 SECOND QUARTER REPORT    9

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2013					2012									2011
	Q2			Q1		Q41		Q31		Q21			Q11		Q41		Q31
Revenue		421			444		846		296		282			466		971		527
Net earnings attributable to equity holders		34			9		41		79		5			128		265		39
$ per common share (basic)		0.09			0.02		0.10		0.20		0.01			0.33		0.67		0.10
$ per common share (diluted)		0.09			0.02		0.10		0.20		0.01			0.33		0.67		0.10
Adjusted net earnings (non-IFRS, see page 9)		61			27		233		49		31			120		249		104
$ per common share (adjusted and diluted)		0.15			0.07		0.59		0.12		0.08			0.30		0.63		0.26
Cash provided by operations (after working capital changes)		(37	)		269		286		36		(117	)		374		258		192

¹  Our quarterly results have been restated in accordance with IFRS 11 – Joint Arrangements and IAS 19 – Employee Benefits. Our quarterly results prior to the first quarter of 2012 have not been restated.

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

	2013						2012												2011
($ MILLIONS)	Q2			Q1			Q42			Q32			Q22			Q12			Q4			Q3
Net earnings attributable to equity holders		34			9			41			79			5			128			265			39
Adjustments
Adjustments on derivatives1 (pre-tax)		36			25			33			(40	)		35			(10	)		(22	)		88
Income taxes on adjustments to derivatives		(9	)		(7	)		(9	)		10			(9	)		2			6			(23	)
Impairment charge on non-producing property		—			—			168			—			—			—			—			—
Adjusted net earnings (non-IFRS, see page 9)		61			27			233			49			31			120			249			104

¹  We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.

²  Our quarterly results have been restated in accordance with IAS 19 – Employee Benefits. Our quarterly results prior to the first quarter of 2012 have not been restated.

Key things to note:

• Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 72% of consolidated revenues in the second quarter of 2013.

• The timing of customer requirements, which tends 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 (see page 9 for more information).

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

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

RESTRUCTURING

In response to current market uncertainty, we have made some modifications to our operating and development plans to ensure we remain a low cost producer and profitably grow the company. This resulted in the consolidation of a number of business and operating functions, which has allowed us to reduce the workforce by about 8%. The changes target achieving a sustainable 10% future cost reduction through a combination of decreased spending for administration, operations and capital. In order to achieve our targeted cost reduction, we have incurred $13 million in restructuring costs, which will impact our financial results this year. Of this total, $5 million relates to an increase in our direct administration costs, while the other $8 million will flow through cost of sales. We do not expect to incur any significant additional costs. Our goal is to make the company a

10     CAMECO CORPORATION

more efficient, streamlined and profitable organization that is prepared to weather the current uncertainty, increase our focus on execution and be ready for the sustained long-term growth we expect.

ADMINISTRATION

($ MILLIONS)	THREE MONTHS ENDED JUNE  30				CHANGE			SIX MONTHS ENDED JUNE 30				CHANGE
	2013		2012					2013		2012
Direct administration		37		38		(3	)%		81		73		11	%
Restructuring charges		2		—		—			5		—		—
Stock-based compensation		4		8		(50	)%		13		12		8	%
Total administration		43		46		(7	)%		99		85		16	%

Direct administration costs were $1 million lower this quarter and $8 million higher for the first six months than the same periods last year. The increase in the first six months primarily reflects the addition of NUKEM’s administration ($6 million) and advisory fee ($3 million). In 2013 we also recognized $5 million for one-time restructuring costs. SeeRestructuring on page 10.

Stock based compensation was $4 million lower this quarter and $1 million higher for the first six months of 2013 compared to 2012 due to the timing of awarding options. In 2012, options were issued in May due to a trading blackout, compared to being issued in March in 2013.

EXPLORATION

In the second quarter, uranium exploration expenses were $16 million, a decrease of $2 million compared to the second quarter of 2012. Exploration expenses in the first six months of the year decreased to $37 million from $41 million in 2012 as a result of decreased activity at our Kintyre property in Australia. We expect exploration expenses to be about 15% to 20% lower than they were in 2012. Our exploration efforts in 2013 are focused on Canada, Australia, Kazakhstan and the United States.

INCOME TAXES

We recorded an income tax recovery of $45 million in second quarter of 2013 compared to a recovery of $29 million in the second quarter of 2012. The change in the net recovery was due to the distribution of earnings between jurisdictions. In 2013, we recorded losses of $198 million in Canada compared to $91 million in 2012, whereas earnings in foreign jurisdictions rose to $187 million from $66 million. 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 $35 million this quarter compared to a recovery of $20 million in the second quarter of 2012 due to the distribution of earnings between jurisdictions.

In the first six months of 2013, we recorded an income tax recovery of $73 million compared to a recovery of $38 million in 2012. The change in the net recovery was in part due to a decline in pre-tax earnings in Canada in 2013. The distribution of earnings between jurisdictions was also different compared to 2012. In 2013, we recorded losses of $326 million in Canada compared to $173 million in 2012, whereas earnings in foreign jurisdictions increased to $295 million from $267 million. 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 $57 million in the first six months of 2013 compared to a recovery of $31 million in 2012 due in part to lower pre-tax adjusted earnings.

2013 SECOND QUARTER REPORT    11

	THREE MONTHS ENDED JUNE  30						SIX MONTHS ENDED JUNE  30
($ MILLIONS)	2013			2012			2013			2012
Pre-tax adjusted earnings1
Canada2		(156	)		(56	)		(262	)		(148	)
Foreign		181			66			292			267
Total pre-tax adjusted earnings		25			10			30			119
Adjusted income taxes1
Canada2		(36	)		(20	)		(64	)		(40	)
Foreign		1			—			7			9
Adjusted income tax expense (recovery)		(35	)		(20	)		(57	)		(31	)
Effective tax rate		(140	)%		(200	)%		(190	)%		(26	)%

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 page 9).

FOREIGN EXCHANGE

At June 30, 2013:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.05 (Cdn), up from $1.00 (US) for $1.02 (Cdn) at March 31, 2013. The exchange rate averaged $1.00 (US) for $1.02 (Cdn) over the quarter.

• We had foreign currency contracts of $1.5 billion (US) and €123 million at June 30, 2013. The mark-to-market loss on all foreign exchange contracts was $53 million compared to a $17 million loss at March 31, 2013. The average exchange rate for USD currency contracts was $1.00 (US) for $1.02 (Cdn) and €1.00 (EUR) for $1.30 (US) for EUR currency contracts.

12     CAMECO CORPORATION

Outlook for 2013

Our outlook reflects our expectations for 2013 and the growth expenditures necessary to help us achieve our strategy. Our outlook for NUKEM sales volumes, revenue and operating cash flows, electricity average unit cost of sales (including D&A) and capital expenditures, uranium exploration and consolidated capital expenditures has changed and we explain the changes below. We do not provide an outlook for the items in the table that are marked with a dash.

SeeFinancial results by segment on page 17 for details.

2013 FINANCIAL OUTLOOK

NUKEM is included in the consolidated amounts, BPLP is not included in the consolidated amounts due to a change in accounting. SeeConsolidated financial results on page 8 for details.

	CONSOLIDATED	URANIUM	FUEL SERVICES	NUKEM	ELECTRICITY
Production	—	23.3 million lbs	15 to 16 million kgU	—	—
Sales volume	—	31 to 33 million lbs	Increase 5% to 10%	8 to 10 million lbs U3O8	—
Capacity factor	—	—	—	—	88%
Revenue compared to 2012	Increase 25% to 30%	Increase 0% to 5%1	Increase 5% to 10%	$450 to $550 million	Decrease 5% to 10%
NUKEM operating cash flows	—	—	—	$60 to $80 million	—
NUKEM gross profit	—	—	—	3% to 5%	—
Average unit cost of sales (including D&A)	—	Increase 0% to 5%2	Decrease 0% to 5%	—	Increase 20% to 25%
Direct administration costs compared to 20123	Increase 0% to 5%	—	—	$10 to $12 million	—
Exploration costs compared to 2012	—	Decrease 15% to 20%	—	—	—
Tax rate	Recovery of 15% to 20%	—	—	Expense of 30% to 35%	—
Capital expenditures	$685 million4	—	—	—	$80 million (our share)

¹  Based on a uranium spot price of $34.50 (US) per pound (the Ux spot price as of July 29, 2013), a long-term price indicator of $55.00 (US) per pound (the Ux long-term indicator on July 29, 2013) and an exchange rate of $1.00 (US) for $1.00 (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 2013 then we expect the overall unit cost of product sold to increase further.

³  Direct administration costs do not include stock-based compensation expenses or restructuring costs. See page 10 for more information.

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

In the NUKEM segment, sales volumes are now expected to be 8 million to 10 million pounds (previously 9 million to 11 million pounds) as a result of a decision to decrease planned sales activities given the current spot price. We also now expect revenue of $450 million to $550 million (previously $500 million to $600 million) due to the reduced sales expectation. Operating cash flows are, therefore, also expected to be less than previously forecast at $60 million to $80 million (previously $100 million to $125 million).

We are discontinuing providing outlook for NUKEM’s SWU sales volumes as the amount is not material to our results. Therefore, we will not be reporting NUKEM’s SWU sales volumes and will also discontinue reporting UF₆sales volumes. However, the revenue for these sales will be included in the total revenue figure reported for NUKEM.

In our electricity segment, average unit cost of sales (including D&A) is now expected to increase by 20% to 25% (previously 25% to 30%) due to lower outage costs.

We now expect uranium exploration expenditures to be 15% to 20% lower than 2012 (previously 5% to 10%), due to the restructuring activities which took place during the first quarter.

2013 SECOND QUARTER REPORT    13

We expect consolidated capital expenditures to be about $685 million compared to our previous estimate of $655 million mainly due to increased costs at Cigar Lake. In 2013, we expect our capital cost for Cigar Lake will be about $260 million compared to our previous estimate of $182 million due to additional scope, increased costs at the mine and mill and the inclusion of some capital costs that will be incurred subsequent to the mining of the first ore and not included in our previous estimate. Please seeDevelopment Project on page 28 for additional information. For our expected capital expenditures breakdown for 2013 by site and our outlook for investing activities in 2014 and 2015, please seeCapital spendingstarting on page 15.

Capital expenditures for BPLP are now expected to be $80 million (previously $93 million) due to deferral of projects.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales volumes and revenue, can vary significantly. However, the majority of delivery notices have been received for 2013, reducing the variability of our delivery pattern for the remainder of the year. Uranium sales for the balance of 2013 are expected to be more heavily weighted (more than 60%) to the second half of the year.

SENSITIVITY ANALYSIS

For the rest of 2013:

• a change of $5 (US) per pound in both the Ux spot price ($34.50 (US) per pound on July 29, 2013) and the Ux long-term price indicator ($55.00 (US) per pound on July 29, 2013) would change revenue by $37 million and net earnings by $19 million

• a change of $5/MWh in the electricity spot price would change our 2013 net earnings by $1 million based on the assumption that the spot price will remain below the floor price of $52.34/MWh provided 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 $7 million and adjusted net earnings by $3 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

Liquidity and capital resources

Our financial objective is to make sure we have the cash and debt capacity to fund our operating activities, investments and growth. We expect our existing cash balances and operating cash flows will meet our anticipated 2013 capital requirements without the need for significant additional funding.

We have large, creditworthy customers that continue to need uranium even during weak economic conditions, and we expect the uranium contract portfolio we have built to provide a solid revenue stream for years to come.

We expect to continue investing in expanding our production capacity over the next several years. We have a number of alternatives to fund this continued growth, including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, and raising additional capital through debt or equity financings. We are always considering our financing options so that we can take advantage of favourable market conditions when they arise.

We have an ongoing dispute with CRA regarding our offshore marketing company structure and related transfer pricing arrangements. Until this dispute is settled, we expect to make cash payments to CRA for 50% of the cash taxes payable on income reassessed and the related interest and instalment penalties. We provided an estimate of the amount and timing of the expected cash taxes payable in our first quarter MD&A. There has been no material change to our estimate. See note 12 of our financial statements for more details.

CASH FROM OPERATIONS

Cash from operations was $80 million higher this quarter than in 2012, due largely to higher uranium deliveries. Working capital requirements were the same as in 2013. SeeFinancial results by segment on page 17 for details.

14     CAMECO CORPORATION

Cash from operations was $25 million lower for the first six months of 2013 than for the same period in 2012 mainly due to lower uranium deliveries. Working capital required $52 million less in 2013, largely as a result of an increase in accounts payable during the quarter. Not including working capital requirements, our operating cash flows in the first six months were higher by $27 million. SeeFinancial results by segment on page 17 for details.

CAPITAL SPENDING

We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development.

CAMECO’S SHARE ($ MILLIONS)	2013 PLAN
Sustaining capital
McArthur River/Key Lake		55
Rabbit Lake		70
US ISR		5
Inkai		7
Fuel services		10
Other		23
Total sustaining capital		170
Capacity replacement capital
McArthur River/Key Lake		75
Rabbit Lake		5
US ISR		30
Inkai		20
Total capacity replacement capital		130
Growth capital
McArthur River/Key Lake		55
US ISR		30
Millennium		5
Inkai		21
Cigar Lake		260
Fuel Services		4
Total growth capital		375
Talvivaara		10
Total uranium & fuel services		685
Electricity(our 31.6% share of BPLP)		80

We expect our total sustaining capital to be $170 million (previously $200 million) primarily due to a reduction in expenditures at McArthur River/Key Lake related to restructuring activities. We expect our total growth capital to be $375 million (previously $310 million) due to additional scope and increased costs at Cigar Lake. Please seeDevelopment Project on page 28 for additional information. Our capital spending related to Talvivaara is expected to increase to $10 million this year (previously $5 million) due to increased costs associated with the construction of the uranium extraction facility.

OUTLOOK FOR INVESTING ACTIVITIES

CAMECO’S SHARE ($ MILLIONS)	2014 PLAN		2015 PLAN
Sustaining capital		200-220		195-215	��
Capacity replacement capital		125-140		120-135
Growth capital		175-190		135-150
Total uranium & fuel services		500-550		450-500

2013 SECOND QUARTER REPORT    15

We expect total uranium and fuel services capital expenditures to be between $500 million and $550 million in 2014 (previously $600 million to $650 million) and between $450 million and $500 million in 2015 (previously $550 million to $600 million) due to a decrease in expected sustaining capital expenditures resulting from our restructuring activities.

DEBT

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totaling about $2.2 billion at June 30, 2013, up $0.1 billion from March 31, 2013. The increase is due to increases in letters of credit and changes in foreign exchange rates. At June 30, 2013, we had approximately $768 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, 2013, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2013 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, 2013:

• purchase commitments

• financial assurances

There have been no material changes to our long-term contractual obligations or financial assurances since December 31, 2012, or to our purchase commitments since March 31, 2013, including payments due for the next five years and thereafter. Please see our annual and first quarter MD&A for more information.

BALANCE SHEET

($ MILLIONS)	JUN 30, 2013		DEC 31, 2012		CHANGE
Cash and short-term investments		332		799		(58	)%
Total debt		1,346		1,360		(1	)%
Inventory		933		564		65	%

Total cash and short-term investments at June 30, 2013 were $332 million, or 58% lower than at December 31, 2012 due to capital expenditures and completion of the acquisition of NUKEM Energy GmbH in January. Net debt June 30, 2013 was $1,014 million.

Total debt decreased by $14 million to $1,346 million at June 30, 2013. Of this total, $54 million was classified as current, down $13 million compared to December 31, 2012. See notes 16 and 17 of our audited annual financial statements for more detail.

Total product inventories increased by $369 million. Uranium and fuel services inventories increased as sales were lower than production and purchases in the first six months of the year. NUKEM inventories also increased as sales were lower than purchases.

16     CAMECO CORPORATION

Financial results by segment

Uranium

HIGHLIGHTS	THREE MONTHS ENDED JUNE  30				CHANGE			SIX MONTHS ENDED JUNE 30				CHANGE
	2013		2012					2013		2012
Production volume (million lbs)		4.4		5.3		(17	)%		10.3		10.2		1	%
Sales volume (million lbs)		6.4		5.0		28	%		11.6		13.2		(12	)%
Average spot price ($US/lb)		40.18		51.33		(22	)%		41.45		51.53		(20	)%
Average long-term price ($US/lb)		57.00		61.00		(7	)%		56.75		60.67		(6	)%
Average realized price
($US/lb)		46.30		42.17		10	%		47.24		46.20		2	%
($Cdn/lb)		47.35		42.29		12	%		47.75		46.66		2	%
Average unit cost of sales ($Cdn/lb) (including D&A)		33.25		33.45		(1	)%		32.65		32.54		—
Revenue ($ millions)		305		211		45	%		552		617		(11	)%
Gross profit ($ millions)		91		44		107	%		174		187		(7	)%
Gross profit (%)		30		21		43	%		32		30		7	%

SECOND QUARTER

Production volumes this quarter were 17% lower compared to the second quarter of 2012, due mainly to lower production at Rabbit Lake and McArthur River/Key Lake. SeeUranium 2013 Q2 updates starting on page 27 for more information.

Uranium revenues were up 45% due to a 12% increase in the Canadian dollar average realized price and a 28% increase in sales volumes. The average realized price in the second quarter of 2012 was significantly lower due to lower US dollar prices under fixed price contracts.

Our realized prices this quarter were higher than the second quarter of 2012, mainly due to higher US dollar prices under fixed price contracts. In the second quarter of 2013, our realized foreign exchange rate was $1.02 compared to $1.00 in the prior year.

Total cost of sales (including D&A) increased by 28% ($214 million compared to $167 million in 2012). This was mainly the result of a 28% increase in sales volumes.

The net effect was a $47 million increase in gross profit for the quarter.

FIRST SIX MONTHS

Production volumes for the first six months of the year were 1% higher than in the previous year due to higher production from Inkai. SeeUranium 2013 Q2 updates starting on page 27 for more information.

For the first six months of 2013, uranium revenues were down 11% compared to 2012, due to a 12% decrease in sales volumes, partially offset by a 2% increase in the Canadian dollar average realized price.

Our realized prices for the first six months of 2013 were higher than 2012, mainly due to higher US dollar prices under fixed price contracts.

Total cost of sales (including D&A) decreased by 12% ($377 million compared to $430 million in 2012). This was mainly the result of a 12% decrease in sales volumes.

The net effect was a $13 million decrease in gross profit for the first six months.

The table on the following page shows the costs of produced and purchased uranium incurred in the reporting periods (which are non-IFRS measures, see the paragraphs below the table). 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.

2013 SECOND QUARTER REPORT    17

($CDN/LB)	THREE MONTHS ENDED JUNE  30				CHANGE			SIX MONTHS ENDED JUNE 30				CHANGE
	2013		2012					2013		2012
Produced
Cash cost		23.00		20.13		14	%		20.78		21.21		(2	)%
Non-cash cost		9.34		7.87		19	%		8.83		7.70		15	%
Total production cost		32.34		28.00		16	%		29.61		28.91		2	%
Quantity produced (million lbs)		4.4		5.3		(17	)%		10.3		10.2		1	%
Purchased
Cash cost		24.05		24.38		(1	)%		28.45		28.18		1	%
Quantity purchased (million lbs)		2.6		2.4		8	%		4.9		3.8		29	%
Totals
Produced and purchased costs		29.26		26.87		9	%		29.24		28.71		2	%
Quantities produced and purchased (million lbs)		7.0		7.7		(9	)%		15.2		14.0		9	%

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 following table presents a reconciliation of these measures to our unit cost of sales for the second quarters and the first six months of 2013 and 2012.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS)	THREE MONTHS ENDED JUNE  30									SIX MONTHS ENDED JUNE 30
	2013			2012			CHANGE			2013			2012			CHANGE
Cost of product sold		213.8			167.3			28	%		377.3			430.3			(12	)%
Add / (subtract)
Royalties		(17.6	)		(24.2	)		(27	)%		(32.1	)		(57.6	)		(44	)%
Standby charges		(9.1	)		(5.8	)		57	%		(17.2	)		(12.9	)		33	%
Other selling costs		0.8			(0.4	)		(300	)%		3.6			(2.4	)		(250	)%
Change in inventories		(24.2	)		28.3			(186	)%		21.8			(34.0	)		164	%
Cash operating costs (a)		163.7			165.2			(1	)%		353.4			323.4			9	%
Add / (subtract)
Depreciation and amortization		46.7			32.7			43	%		66.1			64.6			2	%
Change in inventories		(5.6	)		9.0			(162	)%		24.9			13.9			79	%
Total operating costs (b)		204.8			206.9			(1	)%		444.4			401.9			11	%
Uranium produced & purchased (millions lbs) (c)		7.0			7.7			(9	)%		15.2			14.0			9	%
Cash costs per pound (a ÷ c)		23.39			21.45			9	%		23.25			23.10			1	%
Total costs per pound (b ÷ c)		29.26			26.87			9	%		29.24			28.71			2	%

18     CAMECO CORPORATION

PRICE SENSITIVITY ANALYSIS: URANIUM

The table and graph below are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place in our uranium segment on June 30, 2013 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on June 30, 2013, and none of the assumptions we list below change.

We intend to update this table and graph 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 and graph to change from quarter to quarter.

EXPECTED REALIZED URANIUM PRICE SENSITIVITY UNDER VARIOUS SPOT PRICE ASSUMPTIONS

(rounded to the nearest $1.00)

SPOT PRICES ($US/LB U3O8)
	$	20	$	40	$	60	$	80	$	100	$	120	$	140
2013		46		47		52		56		61		66		70
2014		45		48		56		64		72		80		86
2015		41		46		56		65		76		86		94
2016		42		48		58		68		79		89		98
2017		42		47		57		67		77		86		94

The table and graph illustrate the mix of long-term contracts in our June 30, 2013 portfolio, and are consistent with our contracting strategy. Both have been updated to reflect deliveries made and contracts entered into up to June 30, 2013.

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices. In 2012, a number of older contracts expired 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)

• deliveries include our best estimate of quantities under requirements-based contracts

• we defer a portion of deliveries under existing contracts for 2013

Annual inflation

• is 1.5% in Canada and 2% in the US

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 16% 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 and graph will be higher.

2013 SECOND QUARTER REPORT    19

ROYALTIES

The government of Saskatchewan has recently approved changes to both the basic and tiered royalty system as outlined in our first quarter MD&A. The overall structure is expected to be positive over the next 15 years, although the magnitude of the impact will not be known until the provincial regulations are finalized.

Fuel services

(includes results for UF₆, UO₂and fuel fabrication)

HIGHLIGHTS	THREE MONTHS ENDED JUNE  30				CHANGE			SIX MONTHS ENDED JUNE 30				CHANGE
	2013		2012					2013		2012
Production volume (million kgU)		4.8		4.3		12	%		9.6		8.8		9	%
Sales volume (million kgU)		4.0		4.2		(5	)%		7.3		7.1		3	%
Average realized price ($Cdn/kgU)		16.45		16.94		(3	)%		17.89		18.43		(3	)%
Average unit cost of sales ($Cdn/kgU) (including D&A)		13.98		14.76		(5	)%		15.03		15.54		(3	)%
Revenue ($ millions)		65		70		(7	)%		131		130		1	%
Gross profit ($ millions)		10		9		11	%		21		20		5	%
Gross profit (%)		15		13		15	%		16		15		7	%

SECOND QUARTER

Total revenue decreased by 7% due to a 5% decrease in sales volumes and a 3% decrease in realized price.

The total cost of sales (including D&A) decreased by 10% ($55 million compared to $61 million in the second quarter of 2012) mainly due to a 5% decrease in sales volumes and differences in the mix of fuel services products sold.

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

FIRST SIX MONTHS

In the first six months of the year, total revenue increased by 1% due to a 3% increase in sales volumes, offset by a 3% decrease in realized price.

The total cost of sales (including D&A) was unchanged at $110 million, as the 3% increase in sales volume was offset by a 3% decrease in the average unit cost of sales. The decrease in the average unit cost of sales was due to the mix of fuel services products sold.

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

20     CAMECO CORPORATION

NUKEM

($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED JUNE 30						CONSOLIDATED			SIX MONTHS ENDED JUNE 30						CONSOLIDATED
	NUKEM			PURCHASE ACCOUNTING						NUKEM			PURCHASE ACCOUNTING
Uranium sales (million lbs)		1.2			—			1.2			3.5			—			3.5
Revenue		60			(7	)		53			191			(8	)		183
Cost of product sold (including D&A)		43			7			50			144			31			175
Gross profit		17			(14	)		3			47			(39	)		8
Net earnings		13			(10	)		3			27			(27	)		—
Adjustments on derivatives1		(5	)		—			(5	)		(3	)		—			(3	)
Adjusted net earnings1		8			(10	)		(2	)		24			(27	)		(3	)
Cash provided by operations		(11	)		—			(11	)		88			—			88

¹  Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 9).

On January 9, 2013, we acquired NUKEM Energy GmbH (NUKEM) for cash consideration of €107 million ($140 million (US)). We also assumed NUKEM’s net debt which amounted to about €79 million ($104 million (US)).

For accounting purposes, the purchase price is allocated to the assets and liabilities acquired based on their fair values as of the acquisition date. The purchase price allocation is provided in the table below. We believe that these values are representative of the transaction; however, it is possible that the final allocation will differ.

Much of the purchase price was related to nuclear fuel inventories and the portfolio of sales and purchase contracts acquired. The amounts attributed to inventory and contracts were based on market values as at the acquisition date. They will be charged to earnings in the period(s) in which related transactions occur. The amount categorized as goodwill reflects the value assigned to the expected future earnings capabilities of the organization. This is the earnings potential that we anticipate will be realized through new business arrangements. Goodwill is not amortized and is tested for impairment at least annually.

PURCHASE PRICE ALLOCATION

	$US MILLIONS
Net assets
Working capital		(22	)
Inventory		165
Sales, purchase contracts and other intangibles		88
Goodwill		88
Debt		(117	)
Deferred taxes		(54	)
Net assets acquired		148
Financed by
Cash		140
Additional consideration (earn-out provision)		8
Liabilities and equity		148

SECOND QUARTER

During the second quarter of 2013, NUKEM delivered 1.2 million pounds of uranium. On a consolidated basis, NUKEM contributed $53 million in revenues and $3 million in gross profit. Adjusted net earnings were a loss of $2 million (non-IFRS measure, see page 9). NUKEM’s contribution to our earnings is significantly impacted by our purchase price accounting. Excluding the impact of the purchase accounting, NUKEM’s adjusted net earnings (non-IFRS measure, see page 9) were $8 million for the quarter.

2013 SECOND QUARTER REPORT    21

FIRST SIX MONTHS

During the first six months of 2013, NUKEM delivered 3.5 million pounds of uranium. On a consolidated basis, NUKEM contributed $183 million in revenues, $8 million in gross profit, and adjusted net earnings (non-IFRS measure, see page 9) amounted to a loss of $3 million. NUKEM’s contribution to our earnings is significantly impacted by our purchase price accounting. Excluding the impact of the purchase accounting, NUKEM’s adjusted net earnings (non-IFRS measure, see page 9) were $24 million for the first six months. NUKEM generated strong cash flows of $88 million from its operating activities due largely to the collection of accounts receivable.

As noted above, much of the NUKEM purchase price was attributable to inventories and the portfolio of contracts. With respect to nuclear fuel inventories, amounts assigned were based on market values as of the date of acquisition. As these quantities are delivered to NUKEM’s customers, we will adjust the cost of product sold to reflect the values at the acquisition date, regardless of NUKEM’s historic costs.

As of the date of the purchase agreement, had NUKEM’s sales and purchase contracts been settled, it would have realized significant financial benefit. As a result, we paid a premium to acquire the portfolio. Accordingly, a portion of the purchase price has been attributed to the various contracts. In our accounting for NUKEM, we will amortize the amounts assigned to the portfolio in the periods in which NUKEM transacts under the relevant contracts. The net effect is a reduction in reported profit margins relative to NUKEM’s results. We expect the majority of the amount allocated to the contract portfolio will be amortized within two years.

22     CAMECO CORPORATION

Electricity

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

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED JUNE  30						CHANGE			SIX MONTHS ENDED JUNE 30						CHANGE
	2013			2012						2013			2012
Output—terawatt hours (TWh)		5.5			6.5			(15	)%		11.0			12.5			(12	)%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		77	%		91	%		(15	)%		77	%		88	%		(13	)%
Realized price ($/MWh)		54	1		55	2		(2	)%		53	3		55	4		(4	)%
Average Ontario electricity spot price ($/MWh)		25			19			32	%		27			20			35	%
Revenue		307			377			(19	)%		595			711			(16	)%
Operating costs (net of cost recoveries)		297			217			37	%		580			472			23	%
Cash costs		246			163			51	%		475			364			30	%
Non-cash costs		51			54			(6	)%		105			108			(3	)%
Income before interest and finance charges		10			160			(94	)%		15			239			(94	)%
Interest and finance charges		4			10			(60	)%		10			10			—
Cash from operations		46			200			(77	)%		341			329			4	%
Capital expenditures		66			49			35	%		136			88			55	%
Distributions		—			160			—			100			190			(47	)%
Capital calls		9			17			(47	)%		16			33			(52	)%
Operating costs ($/MWh)		52	1		32	2		63	%		52	3		37	4		41	%

¹  Based on actual generation of 5.5 TWh plus deemed generation of 0.2 TWh in the second quarter of 2013.

²  Based on actual generation of 6.5 TWh plus deemed generation of 0.3 TWh in the second quarter of 2012.

³  Based on actual generation of 11.0 TWh plus deemed generation of 0.2 TWh in the first six months of 2013.

⁴  Based on actual generation of 12.5 TWh plus deemed generation of 0.4 TWh in the first six months of 2012.

OUR EARNINGS (LOSS) FROM BPLP

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED JUNE 30						CHANGE			SIX MONTHS ENDED JUNE  30						CHANGE
	2013			2012						2013			2012
BPLP’s earnings (loss) before taxes (100%)		6			150			(96	)%		5			229			(98	)%
Cameco’s share of pretax earnings before adjustments (31.6%)		2			47			(96	)%		2			72			(97	)%
Proprietary adjustments		(1	)		(1	)		—			(3	)		(3	)		—
Earnings (loss) before taxes from BPLP		1			46			(98	)%		(1	)		69			(101	)%

SECOND QUARTER

Total electricity revenue decreased 19% this quarter due to lower output and a lower realized price. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $159 million this quarter under its agreement with the OPA, compared to $225 million in the second quarter of 2012. Gains on BPLP’s contract activity in the second quarter of 2013 were $14 million, compared to $32 million in the second quarter of 2012.

The capacity factor was 77% this quarter, down from 91% in the second quarter of 2012. There were 70 planned and three unplanned outage days in the quarter, compared to no planned and 19 unplanned outage days in the second quarter of 2012.

2013 SECOND QUARTER REPORT    23

Operating costs were $297 million compared to $217 million in 2012 due to higher maintenance costs incurred primarily as a result of more planned outage days in the second quarter of 2013, and lower supplemental lease charges in 2012.

The result was $1 million in earnings before taxes in the second quarter of 2013 compared to $46 million in earnings before taxes in the second quarter of 2012.

BPLP did not make any distributions to the partners in the second quarter. BPLP capital calls to the partners in the second quarter were $9 million. Our share was $3 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 decreased 16% compared to 2012 due to lower output and a lower realized price. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $283 million in the first six months of 2013 under its agreement with the OPA, compared to $409 million in the first six months of 2012. Gains on BPLP’s contract activity in the first six months of 2013 were $22 million, compared to $63 million in the first six months of 2012.

The capacity factor was 77% for the first six months of the year, down from 88% for the same period in 2012. There were 140 planned and 12 unplanned outage days in the first six months of 2013, compared to 46 planned and 23 unplanned outage days in the first six months of 2012.

Operating costs were $580 million compared to $472 million in 2012 due to higher maintenance costs incurred primarily as a result of more planned outage days and lower supplemental lease charges in 2012.

The result was a $1 million loss before taxes in the first six months of 2013 compared to $69 million in earnings before taxes in the first six months of 2012.

BPLP distributed $100 million to the partners in the first six months of 2013. Our share was $32 million. BPLP capital calls to the partners in the first six months of the year were $16 million. 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.

24     CAMECO CORPORATION

Our operations and development project

Uranium – production overview

Production in our uranium segment this quarter was 0.9 million pounds lower compared to the second quarter of 2012. Production in the first half of the year was 0.1 million pounds higher than the same period in 2012. SeeUranium 2013 Q2 updatesstarting on page 27 for more information.

URANIUM PRODUCTION

CAMECO’S SHARE (MILLION LBS)	THREE MONTHS ENDED JUNE  30				CHANGE			SIX MONTHS ENDED JUNE  30				CHANGE
	2013		2012					2013		2012
McArthur River/Key Lake		2.7		3.3		(18	)%		6.3		6.3		—
Rabbit Lake		0.4		0.9		(56	)%		1.5		1.8		(17	)%
Smith Ranch-Highland		0.3		0.3		—			0.6		0.6		—
Crow Butte		0.2		0.2		—			0.4		0.4		—
Inkai		0.8		0.6		33	%		1.5		1.1		36	%
Total		4.4		5.3		(17	)%		10.3		10.2		1	%

Outlook

We have geographically diverse sources of production. Subject to market conditions, our plan is to focus primarily on advancing our brownfield projects and the process to extract uranium from the Talvivaara mine to achieve annual supply of 36 million pounds by 2018. We expect to purchase about 900,000 pounds of supply under our agreement with Talvivaara when all regulatory approvals are received, work on the extraction process is complete, and once they ramp up to full production. We expect production to start in the first half of 2014.

CAMECO’S SHARE OF PRODUCTION – ANNUAL FORECAST TO 2017

CURRENT FORECAST (MILLION LBS)	2013		2014		2015		2016		2017
McArthur River/Key Lake		13.2		13.1		13.1		13.1		13.1
Rabbit Lake		4.2		4.2		4.2		4.2		4.2
US ISR		2.6		2.9		2.9		3.0		3.0
Inkai1		2.9		2.9		2.9		2.9		2.9
Cigar Lake		0.3		1.8		5.5		7.9		8.2
Total share of production		23.2		24.9		28.6		31.1		31.4
Cameco’s share of Inkai’s production on which profits are generated2
Inkai1		3.0		3.0		3.0		3.0		3.0
Total2		23.3		25.0		28.7		31.2		31.5

¹  In 2011, we signed a memorandum of agreement (2011 MOA) with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). Under the 2011 MOA, we will have 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 2011 MOA, as described in the note above.

Our 2013 and future annual production targets for Inkai assume, and we expect, that 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.

There is no certainty Inkai will receive these permits or approvals. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2013 and future annual production targets and we may have to re-categorize some of Inkai’s mineral reserves as resources.

2013 SECOND QUARTER REPORT    25

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 expected, 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 expected, lack of tailings capacity or for other reasons

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

• natural phenomena, labour disputes (including an inability to renew agreements with unionized employees at McArthur River and Key Lake), 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 2013 Q2 updates

Operating properties

McArthur River/Key Lake

Production update

Production was 18% lower in the second quarter compared to the same period last year due to the timing of planned maintenance shutdowns at the mill, which occurred in May this year. Production for the first six months of 2013 was unchanged compared to 2012.

Operations update

At McArthur River, we finished drilling freeze holes in zone 4 north. We plan to begin freezing the ground later this year and begin mining this zone in late 2014.

At Key Lake, we completed the installation of the electrical substation. We have finished flattening the Deilmann tailings management facility pitwalls and continue working to install a toe buttress at the base of the west and northwest slope. This is expected to stabilize the ground to prevent sloughing, which can occur as the water level in the pit is allowed to increase.

We also continue to advance work on the environmental assessment for the Key Lake extension project. We plan to submit the final environmental impact statement for review by the provincial and federal regulators in the fourth quarter and pursue the required regulatory approvals in 2014.

This quarter we applied for a renewal of our McArthur River and Key Lake operating licences.

Rabbit Lake

Production update

Production was 56% lower in the second quarter and 17% lower for the first six months compared to the same periods last year. The timing of the scheduled mill maintenance shutdown and changes to the Rabbit Lake mill’s operating schedule had an impact on production in the first half of the year, although annual production remains on track. To ensure the most efficient operation of the mill throughout the year, we continually manage ore supply and, therefore, experience large variations in mill production from quarter to quarter.

Operations update

The mill shut down for scheduled maintenance in May and will resume operations in September.

This quarter we applied for a renewal of our Rabbit Lake operating licence.

Smith Ranch-Highland and Crow Butte

Production update

At our US operations, production for the quarter and for the first six months of the year was unchanged from the same periods in 2012.

Our ability to bring new wellfields into production in both Wyoming and Nebraska continues to be affected by the lengthened review process to obtain regulatory approvals. The operating environment has become more complex as public interest and regulatory oversight has increased.

Operations update

In the second quarter, our North Butte satellite operation began production. It is expected to contribute approximately 300,000 pounds in 2013 and ramp up to a target annual production rate of more than 700,000 pounds per year by 2015.

2013 SECOND QUARTER REPORT    27

Inkai

Production update

Production was 33% higher in the second quarter and 36% higher in the first six months of 2013 compared to the same periods last year. We have continued to bring on new wellfields to maintain a higher head grade in the wellfield production mix, which has resulted in the higher production for the second quarter and first six months. The higher head grade and other improvements to the extraction processes allow the Inkai operation to produce at its design capacity of 5.2 million pounds per year.

Development project

Cigar Lake

Production update

We continued to make solid progress at Cigar Lake in the second quarter and expect to begin jet boring in ore this summer, with the first packaged pounds from AREVA’s McClean Lake mill expected in the fourth quarter.

Operations update

During the quarter, the second jet boring unit was shipped to site and assembled underground.

Installation of the underground and surface infrastructure required to begin jet boring is progressing well.

Capital expenditures

Like the rest of the mining industry, we are facing upward pressures on costs, which have led to an increase in the expected capital cost at Cigar Lake. As well, there have been some scope changes at the mine and mill. As a result, we expect our share of the total capital cost for the project to increase between 15% and 25% (the prior estimate of our share was $1.1 billion).

In 2013, we expect our capital cost will be about $260 million compared to our previous estimate of $182 million due to additional scope, increased costs at the mine and mill and the inclusion of some capital costs that will be incurred subsequent to the mining of the first ore and not included in our previous estimate.

These additional capital expenditures will allow us to achieve first production this year in a safe and deliberate manner, and to realize the economic benefits from one of the world’s largest high-grade uranium deposits, second only to McArthur River.

Licensing

The CNSC has granted a uranium mining licence authorizing construction and operation of the Cigar Lake project. The licence term is from July 1, 2013 to June 30, 2021.

Fuel services 2013 Q2 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc.

Springfields Fuels Ltd. (SFL)

Production update

Fuel services produced 4.8 million kgU in the second quarter, 12% higher than the same period last year. Production for the first half of the year was 9.6 million kgU, 9% higher compared to last year. We increased our production target in 2013 to between 15 million and 16 million kgU, so quarterly production is anticipated to be higher than comparable periods in 2012. Production remains on track for the year.

Labour relations

On July 5, 2013, unionized employees at the Port Hope conversion facility accepted new three-year contracts that include a 6% wage increase over the term of the agreements. The previous contracts expired on June 30, 2013.

28     CAMECO CORPORATION

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	Inkai •     Alain G. Mainville, director, mineral resources management, Cameco
Cigar Lake •     Grant Goddard, vice-president, Saskatchewan mining north, Cameco

Additional information

Critical accounting estimates

Due to the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.

Controls and procedures

As of June 30, 2013, 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, 2013, the CEO and CFO concluded that:

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

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

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management has excluded NUKEM from its assessment of internal control over financial reporting as of June 30, 2013 because we acquired NUKEM in 2013. The total assets and total revenues of NUKEM represented approximately 6% and 21%, respectively, of our consolidated financial statement amounts as of and for the quarter ended June 30, 2013.

New standards and interpretations

The following new standards and amendments to existing standards were required to be applied for our accounting periods beginning on or after January 1, 2013, unless otherwise noted. These standards did not have a material impact on the financial statements.

• IFRS 7 Financial Instruments: Disclosures

• IFRS 10 Consolidated Financial Statements

• IFRS 12 Disclosure of Interests in Other Entities

• IFRS 13 Fair Value Measurement

• IAS 1 Presentation of Financial Statements(effective for annual periods beginning on or after July 1, 2012)

2013 SECOND QUARTER REPORT    29

In addition, the following two accounting changes required a restatement of prior period results:

• IFRS 11 Joint Arrangements (IFRS 11)—Under IFRS 11, we classify our interests in joint arrangements as either joint operations or joint ventures depending on our rights to the assets and obligations for the liabilities of the arrangements, the legal form of any separate vehicles, the contractual terms of the arrangements and other facts and circumstances. In accordance with IFRS 11, we have re-evaluated our involvement in joint arrangements at January 1, 2013 and as a result, we have changed our classification conclusion with respect to our investment in BPLP and have determined that our investment should be classified as a joint venture. Accordingly, we applied equity accounting to the investment commencing on January 1, 2013. Previously, the investee was accounted for as a jointly controlled entity using the proportionate consolidation method.

• RevisedIAS 19 Employee Benefits (IAS 19R)—The revisions to IAS 19 have accelerated the recognition of past service costs and replaced interest cost and expected return on plan assets with a measure of net interest on the defined benefit asset or liability. In addition, IAS 19R has resulted in a change in the accounting for both plan administration costs and assets earning no return in refundable tax accounts. These revisions have resulted in adjustments to both our, and BPLP’s defined benefit obligation balances. The adoption of this revised standard did not have a material impact on our financial statements.

Refer to our 2012 Annual MD&A for a description of each of the above accounting standards and amendments to existing standards.

A number of new standards, interpretations and amendments to existing standards are not yet effective for the year ended December 31, 2013, and have not been applied in preparing these consolidated financial statements. The following standards, amendments to and interpretations of existing standards have been published and are mandatory for our accounting periods beginning on January 1, 2014, unless otherwise noted.

• IFRS 9, Financial Instruments (IFRS 9)—In October 2010, the International Accounting Standards Board (IASB) issued 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. IFRS 9 is effective for annual periods beginning on or after January 1, 2015, with early adoption permitted. We do not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

• IAS 32, Financial Instruments: Presentation (IAS 32)—In December 2011, the IASB issued an amendment to IAS 32. The amendment clarifies matters regarding offsetting financial assets and financial liabilities as well as related disclosure requirements and is to be applied retrospectively. We do not expect the amendments to have a material impact on the financial statements.

• IFRIC 21, Levies (IFRIC 21)—In May 2013, the IASB issued International Financial Reporting Interpretations Committee (IFRIC) 21, Levies. IFRIC 21 is to be applied retrospectively. IFRIC 21 provides guidance on accounting for levies in accordance with IAS 37,Provisions, Contingent Liabilities and Contingent Assets. The interpretation defines a levy as an outflow from an entity imposed by a government in accordance with legislation and confirms that an entity recognizes a liability for a levy only when the triggering event specified in the legislation occurs. The extent of the impact of IFRIC 21 has not yet been determined.

• IAS 36 Impairment of Assets (IAS 36)—In May 2013, the IASB issued amendments to IAS 36 Impairment of Assets. The amendments are to be applied retrospectively. The amendments reverse the unintended requirement in IFRS 13,Fair Value Measurement to disclose the recoverable amount of every cash-generating unit to which significant goodwill or indefinite-lived intangible assets have been allocated. Under these amendments, the recoverable amount is required to be disclosed only when an impairment loss has been recognized or reversed. We do not expect the amendments to have a material impact on the financial statements.

30     CAMECO CORPORATION