Cameco Corporation - Reports Second Quarter 2013 Financial Results

• second quarter results as expected
• production, uranium and fuel services sales and consolidated revenue outlook reconfirmed
• restructured our business, targeting a 10% future cost reduction through a combination of reduced spending for administration, operations and capital
• at Cigar Lake preparing to begin jet boring in ore
• our share of the total capital cost for Cigar Lake expected to increase between 15% and 25%
• in the US, our North Butte satellite operation began production

SASKATOON, Aug 1, 2013 - Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated financial and operating results for the second quarter ended June 30, 2013 in accordance with International Financial Reporting Standards (IFRS).

"Despite the prolonged weakness in the uranium market, our strong contract portfolio has continued to serve us well," said Tim Gitzel, president and CEO, "providing us with average realized prices that continue to be above the current uranium spot price.

"This year, we have undergone some restructuring with the intent of increasing profitability and achieving a sustainable 10% future cost reduction. The changes we've made are part of our commitment to improving near-term financial results and creating shareholder value by growing the company and remaining a low-cost producer. We continue to focus on achieving our strategy to profitably increase production, and look forward to Cigar Lake starting production later this year as a highlight of our progress toward that goal."

HIGHLIGHTS		THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS EXCEPT WHERE INDICATED)		2013		2012		CHANGE		2013	2012	CHANGE
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 (see non-IFRS)		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) (see non-IFRS measure) 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

See Financial results by segment 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.

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) (see non-IFRS measure) 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
• partially offset by higher tax recoveries due to a decline in pre-tax earnings in Canada

See Financial results by segment for more detailed discussion.


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.

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.

See Financial results by segment 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.

	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.
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 UF₆ sales 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.

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 see Cigar Lake for additional information. For our expected capital expenditures breakdown for 2013 by site and our outlook for investing activities in 2014 and 2015, please see Capital spending.

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).

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.

			THREE MONTHS ENDED JUNE 30				SIX MONTHS ENDED JUNE 30
($ MILLIONS)		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.

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 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.

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 see Cigar Lake 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

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.


Financial results by segment

Uranium

		THREE MONTHS ENDED JUNE 30				SIX MONTHS ENDED JUNE 30
HIGHLIGHTS		2013	2012	CHANGE		2013	2012	CHANGE
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. See Operations and development project updates 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. See Operations and development project updates 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 below 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.

		THREE MONTHS ENDED JUNE 30				SIX MONTHS ENDED JUNE 30
($CDN/LB)		2013	2012	CHANGE		2013	2012	CHANGE
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

		THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS)		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	%

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

	THREE MONTHS ENDED JUNE 30				SIX MONTHS ENDED JUNE 30
HIGHLIGHTS	2013	2012	CHANGE		2013	2012	CHANGE
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.

NUKEM

	THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS EXCEPT WHERE INDICATED)	NUKEM		PURCHASE ACCOUNTING		CONSOLIDATED		NUKEM		PURCHASE ACCOUNTING		CONSOLIDATED
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 (see non-IFRS measure).

On January 9, 2013, we acquired NUKEM Energy GmbH (NUKEM) for cash consideration of EUR107 million ($140 million (US)). We also assumed NUKEM's net debt which amounted to about EUR79 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 on the 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 (see non-IFRS measure). 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 (see non-IFRS measure) were $8 million for the quarter.

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 (see non-IFRS measure) 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 (see non-IFRS measure) 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.

Electricity results

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.

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.

Operations and development project updates

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.

URANIUM PRODUCTION

CAMECO'S SHARE (MILLION LBS)	THREE MONTHS ENDED JUNE 30				SIX MONTHS ENDED JUNE 30
	2013	2012	CHANGE		2013	2012	CHANGE
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	%

McArthur River/Key Lake

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.

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 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.

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

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.

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.

Inkai

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.

Cigar Lake

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.

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.

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.

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

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.

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.


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

Inkai

• Alain G. Mainville, director, mineral resources management, Cameco

Cigar Lake

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

CAUTION ABOUT FORWARD-LOOKING INFORMATION

This document 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 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, 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 of material assumptions, including those we have listed below, which may prove to be incorrect.
• Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review our annual information form and our annual 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.

Examples of forward-looking information in this document

• our expectations about 2013 and future global uranium supply and demand, including the discussion under the heading Uranium market update
• the outlook for each of our operating segments for 2013 and our consolidated outlook for the year
• our target for a sustainable 10% future cost reduction
• our expectations for 2013, 2014 and 2015 capital expenditures
• 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 Canada Revenue Agency
• 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
• 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 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

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, 2013, to shareholders of record at the close of business on September 30, 2013.


Conference call

We invite you to join our second quarter conference call on Thursday August 1, 2013 at 1:00 p.m. Eastern.

The call will be open to all investors and the media. To join the call, please dial (866) 225-0198 (Canada and US) or (416) 340-8061. 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, September 1, 2013
  by calling (800) 408-3053 or (905) 694-9451 (Passcode 7039949#)

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 2012 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 Corp. and its subsidiaries, including NUKEM Energy Gmbh (NUKEM), unless otherwise indicated.

ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED)



Contact

Cameco
Investor inquiries:
Rachelle Girard
(306) 956-6403
Media inquiries:
Rob Gereghty
(306) 956-6190