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Quarterly Results Archive

QUARTERLY REPORTS

2011 Q3

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Cameco Reports Third Quarter Financial Results

Saskatoon, Saskatchewan, Canada, November 7, 2011

currency: Cdn (unless noted)

News Release - PDF
MD&A, Financial and Notes - PDF
Financial Statements - XLS

  • third quarter results as expected — higher uranium sales and realized prices
  • strong fourth quarter expected — over one-third of 2011 uranium deliveries
  • sales and revenue guidance for 2011 reconfirmed
  • uranium and fuel services 2011 production outlook decreased slightly
  • long-term fundamentals strong — expect near- to medium-term market uncertainty

Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the third quarter ended September 30, 2011 in accordance with International Financial Reporting Standards (IFRS).

"Cameco performed well during the quarter despite the prevailing economic uncertainty. We realized higher prices on our uranium sales and achieved higher sales volumes resulting in higher adjusted earnings," said president and CEO Tim Gitzel. "With sales commitments of over 300 million pounds, we are positioned to continue delivering solid financial performance while preparing our assets for the growth we expect in the nuclear industry.

"During the quarter, we undertook several initiatives to advance our strategy to double annual uranium production by 2018 and add value for our shareholders. We signed a memorandum of agreement (MOA) with our Inkai partner to increase total production to 5.2 million pounds annually. We also signed a non-binding memorandum of understanding (MOU) to process all Cigar Lake ore at McClean Lake mill, which we expect will result in a significant reduction in the operating cost.

"We believe in the long-term fundamentals of the nuclear industry and will continue to pursue our strategy in a disciplined manner to ensure we can respond appropriately to evolving market conditions."

Highlights
($ millions except per share amounts)
Three months ended   Nine months ended  
September 30   September 30  
2011 2010 change 2011 2010 change
             
Revenue 527 419  26%  1,407 1,450 (3)%
Net earnings 39 98  (60)% 186 311 (40)%
  $ per common share (basic) 0.10 0.25  (60)% 0.47 0.79 (41)%
  $ per common share (diluted) 0.10 0.25  (60)% 0.47 0.79 (41)%
Adjusted net earnings (non-IFRS measure) 104 80  30%  259 307 (16)%
  $ per common share (adjusted and diluted) 0.26 0.20  30%  0.66 0.78 (15)%
Cash provided by operations
(after working capital changes)
190 (5) 3900%  477 412 16% 
             

Transition to IFRS

Effective January 1, 2011, we adopted IFRS for Canadian publicly accountable enterprises. Our unaudited condensed consolidated interim financial statements for the quarter ended September 30, 2011 (interim financial statements) have been prepared using IFRS. Amounts relating to the year ended December 31, 2010 in this document, our interim financial statements and related third quarter management's discussion and analysis (third quarter MD&A) have been recast to reflect our adoption of IFRS. Details of the more significant accounting differences can be found in note 3 to our interim financial statements.

Third quarter

Net earnings attributable to our shareholders (net earnings) this quarter were $39 million ($0.10 per share diluted) compared to $98 million ($0.25 per share diluted) in the third quarter of 2010. Net earnings were down this quarter primarily as a result of losses on foreign exchange derivatives compared to gains in 2010, partially offset by lower income taxes and the item noted below. The Canadian dollar weakened in the third quarter of 2011 relative to the US dollar, while it strengthened in the third quarter of 2010.

On an adjusted basis, our earnings this quarter were $104 million ($0.26 per share diluted) compared to $80 million ($0.20 per share diluted) (non-IFRS measure) in the third quarter of 2010 mainly due to:

  • higher earnings from our uranium business based on higher sales volumes and higher realized prices, partially offset by an increase in the average cost of product sold

See Financial results by segment for more detailed discussion.

First nine months

Net earnings in the first nine months of the year were $186 million ($0.47 per share diluted) compared to $311 million ($0.79 per share diluted) in the first nine months of 2010. Net earnings were lower than in 2010 mainly as a result of the items noted below along with losses on foreign exchange derivatives compared to gains in 2010, partially offset by lower income taxes.

On an adjusted basis, our earnings for the first nine months of this year were $259 million ($0.66 per share diluted) compared to $307 million ($0.78 per share diluted) (non-IFRS measure) mainly due to:

  • lower earnings from our electricity business due to lower realized prices, higher costs, and a decline in sales
  • lower earnings from our uranium business based on an increase in the average cost of product sold and lower sales volumes, partially offset by an increase in the realized price
  • lower earnings from our fuel services business as a result of an increase in the average cost of product sold and lower realized prices

See Financial results by segment for more detailed discussion.

Outlook for 2011

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

We expect our existing cash balances and operating cash flows will meet our anticipated requirements over the next several years, without the need for significant additional funding. Cash balances will decline as we use the funds in our business and pursue our growth plans.

Our outlook for 2011 reflects the expenditures necessary to help us achieve our strategy. Our outlook for uranium production, exploration, fuel services production, direct administration costs and capital expenditures has changed from the outlook included in our second quarter MD&A. We explain the changes on the next page. All other items in the table are unchanged. We do not include an outlook for the items in the table that are marked with a dash.

See Financial results by segment for details.

  Consolidated Uranium Fuel services Electricity
         
Production - 21.7 million lbs 14 to 15 million kgU -
Sales volume - 31 to 33 million lbs Increase 10% to 15% -
Capacity factor - - - 87%
Revenue compared to 2010 Increase 5% to 10% Increase 10% to 15%1 Increase 5% to 10% Decrease 10% to 15%
Unit cost of produced product sold (including DDR) - Increase 0% to 5%2 Increase 5% to 10% Increase 10% to 15%
Direct administration costs compared to 20103 Increase 10% to 15% - - -
Exploration costs compared to 2010 - Increase 0% to 5% - -
Tax rate Recovery of 0% to 5% - - -
Capital expenditures $575 million4 - - $80 million
         
 
1 Based on a uranium spot price of $52.00 (US) per pound (the Ux spot price as of October 31, 2011), a long-term price indicator of $63.00 (US) per pound (the Ux long-term indicator on October 31, 2011) 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. Any additional discretionary purchases in 2011 may cause the overall unit cost of product sold to increase further.
3 Direct administration costs do not include stock-based compensation expenses.
4 Does not include our share of capital expenditures at BPLP.

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. A delivery that was expected in the third quarter was moved into the fourth quarter. We now expect deliveries in the fourth quarter to account for over one-third of our 2011 sales volumes.

We now expect uranium production to be 21.7 million pounds this year compared to our previous forecast of 21.9 million pounds. The decrease is due to lower expected production at our US and Inkai operations, partially offset by higher expected production at McArthur River/Key Lake. Please see our Uranium production outlook in our third quarter MD&A for more information.

Exploration costs are now expected to increase 0% to 5% over 2010 (previously a 5% to 10% decrease) based on increased evaluation activities at Kintyre.

Due to current unfavourable market conditions for UF6 conversion, we are reducing production for this year. We now expect fuel services to produce between 14 million and 15 million kgU this year (previously 15 million to 16 million kgU).

We have narrowed the scope of some of our business development activities and now expect our direct administration costs to increase 10% to 15% over 2010 (previously a 15% to 20% increase).

We expect capital expenditures to be about $575 million in 2011 compared to our previous estimate of $590 million due to changes in the scheduling of some projects. We do not expect this reduction in capital expenditures in 2011 will impact our plans to double annual uranium production to 40 million pounds by 2018.

Sensitivity analysis

For the rest of 2011:

  • a change of $5 (US) per pound in both the Ux spot price ($52.00 (US) per pound on October 31, 2011) and the Ux long-term price indicator ($63.00 (US) per pound on October 31, 2011) would change revenue by $13 million and net earnings by $9 million
  • a change of $5/MWh in the electricity spot price would not change our 2011 net earnings as gains under BPLP's financial contracts have been fully locked in for 2011 and based on the assumption that the spot price will remain below the floor price of $50.18/MWh provided for under BPLP's agreement with the Ontario Power Authority (OPA)
  • a one-cent change in the value of the Canadian dollar versus the US dollar would change revenue by $7 million and adjusted net earnings by $3 million. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

Debt

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1.2 billion at September 30, 2011, the same as at June 30, 2011. At September 30, 2011, we had approximately $606 million outstanding in letters of credit.

On November 1, 2011:

  • we cancelled our $100 million unsecured revolving credit facility that was maturing February 4, 2012
  • we amended, and extended the term of our $500 million unsecured revolving credit facility that was maturing November 30, 2012. This credit facility was increased to $1.25 billion and now matures November 1, 2016. Each year on the anniversary date, and upon mutual agreement, the facility can be extended for an additional year. In addition to borrowing directly from this facility, we can use up to $100 million of it to issue letters of credit and we may use it to provide liquidity for our commercial paper program, as necessary. From time to time we may increase the revolving credit facility above $1.25 billion, by no less than increments of $50 million, up to a total of $1.75 billion. The facility ranks equally with all of our other senior debt. As of November 4, 2011, there was nothing outstanding under this facility.

With these changes, our unsecured lines of credit total about $1.9 billion as of November 4, 2011.

Adjusted net earnings (non-IFRS measures)

Adjusted net earnings is a measure with no standardized meaning under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our net earnings adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period.

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

  Three months Nine months
ended September 30 ended September 30
($ millions) 2011 2010 2011 2010
         
Net earnings 39 98  186 311 
Adjustments on derivatives (after tax)1 65 (18) 73 (4)
Adjusted net earnings 104 80  259 307 
         
1 In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains or losses on derivatives as reported under IFRS to reflect what our earnings would have been had hedge accounting been applied.

Of note this quarter

On August 30, 2011, we made an all-cash offer to acquire all the outstanding shares of Hathor Exploration Limited (Hathor) for a price of $3.75 per share in a transaction which values the fully diluted share capital of Hathor at approximately $520 million.1

On October 19, 2011, Hathor announced that it had entered into an agreement with Rio Tinto pursuant to which Rio Tinto will make an offer for all of the common shares of Hathor. Rio Tinto subsequently made its offer.

We are reviewing the Hathor announcement and Rio Tinto offer. On October 31, 2011, we announced the extension of the expiry date of our offer to November 14, 2011.

1Estimated fully diluted share capital of approximately 139 million shares, based on Hathor's public disclosure.

Uranium market update

The uranium market during the third quarter can be characterized as uncertain. We expect this uncertainty to continue in the near to medium term as the industry continues to determine the extent to which short- to medium-term demand has been impacted by the March nuclear incident in Japan. The biggest drivers of uncertainty are concerns about excess German and Japanese uranium inventories and the extent to which deferrals and/or cancellations under sales contracts will introduce additional volumes into the market.

Germany, which has 17 nuclear reactors and represents 5% of the global generating capacity, has decided to revert to its previous phase out policy. Currently, eight of its reactors (about 2% of global generating capacity) are shutdown; we do not expect these reactors to restart. Germany has indicated it plans to shut down the remaining nine reactors by 2022.

In Japan, 11 of its 54 nuclear reactors are currently operating. Many of the reactors currently off-line were unaffected by the March earthquake and tsunami; however, they require regulatory and political approvals before they can restart (four of the Fukushima-Daiichi units are permanently shut down). There is concern that these approvals may be delayed due to decreased public support for nuclear in Japan. However, there has been some progress. In August, the local government approved the restart of the first nuclear reactor since March — Hokkaido's Tomari 3 reactor. Japan's 54 reactors represent 12% of global nuclear generating capacity.

Despite the near- to medium-term uncertainty, in the long term we continue to see a very strong and promising growth profile for the nuclear industry. Countries around the world, with very few exceptions, have reconfirmed their commitment to nuclear energy. China, India, France, Russia, South Korea, the United Kingdom, Canada, the United States, and almost every other country with a nuclear program are maintaining nuclear as a part of their energy mix.

Other previously non-nuclear countries are either moving ahead with their reactor construction programs or considering adding nuclear to their energy programs in the future. For example, the United Arab Emirates is proceeding with its plans to have 5.6 gigawatts of nuclear capacity in place by 2020 and is beginning the process to secure fuel for those reactors. In Saudi Arabia, where power demand has been increasing by 7% to 8% annually, plans to build 16 reactors by 2030 have been announced.

We are in the enviable position of being heavily committed under long-term sales contracts until 2016. With more than 300 million pounds of uranium under contract, we expect to have a solid revenue stream for years to come, even in the event of declining uranium market prices. With a target of 40% fixed-price contracts and 60% market-related, our portfolio is designed to give us increasing leverage when uranium prices increase, and to protect us when prices decline.

Caution about forward-looking information relating to the March 2011 Japanese nuclear incident

This discussion of the expected impact of the March 2011 nuclear incident in Japan, including its potential impact on future global uranium demand and the number of operating reactors, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information.

Financial results by segment

Uranium

  Three months ended   Nine months ended  
September 30   September 30  
Highlights
2011 2010 change 2011 2010 change
             
Production volume (million lbs) 5.3 5.6 (5)% 15.8 16.5 (4)%
Sales volume (million lbs) 7.2 5.6 29%  19.1 20.5 (7)%
Average spot price ($US/lb) 51.04 45.83 11%  57.89 43.01 35% 
Average realized price            
  ($US/lb) 47.33 40.63 16%  47.06 41.46 14% 
  ($Cdn/lb) 45.97 43.01 7%  46.36 43.90 6% 
Cost of sales ($Cdn/lb)
(including DDR)
27.59 23.61 17%  29.68 27.20 9% 
Revenue ($ millions) 332 240 38%  885 901 (2)%
Gross profit ($ millions) 133 108 23%  319 343 (7)%
Gross profit (%) 40 45 (11)% 36 38 (5)%
             

Third quarter

Production volumes this quarter were 5% lower compared to the third quarter of 2010 primarily due to lower production from Smith Ranch-Highland and Inkai. See Operations and development project updates for more information.

Uranium revenues this quarter were up 38% compared to 2010, due to a 29% increase in sales volumes and a 7% increase in the $Cdn realized selling price.

Our realized prices this quarter were higher than the third quarter of 2010 mainly due to higher $US prices under market-related contracts, partially offset by a less favourable exchange rate. In the third quarter of 2011, our realized foreign exchange rate was $0.97 compared to $1.06 in the prior year.

Total cash cost of sales (excluding DDR) increased by 68% ($165 million compared to $98 million in 2010). This was mainly the result of the following:

  • the 29% increase in sales volumes
  • average unit costs for produced uranium were 32% higher largely due to standby costs paid to AREVA relating to the McClean Lake mill. As well, royalty charges in 2011 were higher due to higher deliveries of produced material and higher realized prices.
  • average unit costs for purchased uranium were 21% higher due to increased purchases at spot prices

The net effect was a $25 million increase in gross profit for the quarter.

The following table shows our cash cost of sales per unit (excluding DDR) for produced and purchased material, including royalty charges on produced material, and the quantity of produced and purchased uranium sold.

Three months ended
September 30
Unit cash cost of sale   Quantity sold  
($Cdn/lb)   (million lbs)  
2011 2010 change 2011 2010 change
             
Produced 23.63 17.85 32% 5.3 3.5 51% 
Purchased 20.57 17.05 21% 1.9 2.1 (10)%
Total 22.84 17.55 30% 7.2 5.6 29% 
             

First nine months

Production volumes for the first nine months of the year were 4% lower than in the previous year mainly due to lower production from Smith Ranch-Highland and Inkai. See Operations and development project updates for more information.

For the first nine months of 2011, uranium revenues were down 2% compared to 2010, due to a 7% decline in sales volumes partially offset by a 6% increase in the $Cdn realized selling price.

Our realized prices were higher than the first nine months of 2010 mainly due to higher $US prices under market-related contracts, partially offset by a less favourable exchange rate. In the first nine months of 2011, our realized foreign exchange rate was $0.99 compared to $1.06 in the prior year.

Total cash cost of sales (excluding DDR) increased by 6% ($487 million compared to $460 million in 2010). This was mainly the result of the following:

  • average unit costs for produced uranium were 10% higher due to increased unit production costs relating to the lower production during the first nine months
  • standby costs paid to AREVA relating to the McClean Lake mill
  • average unit costs for purchased uranium were 22% higher due to increased purchases at spot prices

The net effect was a $24 million decrease in gross profit for the first nine months.

The following table shows our cash cost of sales per unit (excluding DDR) for produced and purchased material, including royalty charges on produced material, and the quantity of produced and purchased uranium sold.

Nine months ended
September 30
Unit cash cost of sale   Quantity sold  
($Cdn/lb)   (million lbs)  
2011 2010 change 2011 2010 change
             
Produced 24.78 22.54 10% 12.8 14.5 (12)%
Purchased 27.11 22.22 22% 6.3 6.0 5% 
Total 25.54 22.45 14% 19.1 20.5 (7)%
             

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

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

Highlights
Three months ended   Nine months ended  
September 30   September 30  
2011 2010 change 2011 2010 change
             
Production volume (million kgU) 2.8 2.3 22%  11.6 11.7 (1)%
Sales volume (million kgU) 4.6 3.9 18%  11.1 10.7 4% 
Realized price ($Cdn/kgU) 17.42 16.32 7%  18.05 18.19 (1)%
Cost of sales ($Cdn/kgU) (including DDR) 15.34 13.55 13%  15.42 13.38 15% 
Revenue ($ millions) 81 64 27%  199 195 2% 
Gross profit ($ millions) 10 11 (9)% 29 52 (44)%
Gross profit (%) 12 17 (29)% 15 27 (44)%
             

Third quarter

Total revenue was $17 million higher than in 2010 due to a 7% increase in the average realized price for our fuel services products along with an 18% increase in sales volumes.

Our $Cdn realized price for fuel services was affected by a 5% increase in our realized price for UF6 as well as the mix of products delivered in the quarter. In 2011, a higher proportion of fuel services sales were for fuel fabrication, which typically yields a much higher price than the other fuel services products.

The total cost of products and services sold (including DDR) increased by 34% ($71 million compared to $53 million in the third quarter of 2010) due to the increase in sales volumes along with the mix of products delivered in the quarter. As a result of the product mix, the average unit cost of sales was 13% higher for the quarter.

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

First nine months

In the first nine months of the year, total revenue increased by 2% due to a 4% increase in sales volumes, partially offset by a 1% decline in the realized selling price.

The total cost of products and services sold (including DDR) increased by 18% ($170 million compared to $144 million in 2010) due to the increase in the unit cost of product sold. The average unit cost of sales was 15% higher due to the mix of products delivered in the year and the recognition of higher cost recoveries in 2010.

The net effect was a $23 million decrease in gross profit.

Electricity results

Third quarter

Total electricity revenue decreased slightly this quarter compared to the third quarter of 2010 due to lower realized prices which were almost completely offset by increased output. Realized prices reflect spot sales, revenue recognized under BPLP's agreement with the OPA and financial contract revenue. BPLP recognized revenue of $119 million this quarter under its agreement with the OPA, compared to $41 million in the third quarter of 2010. About 53% of BPLP's output was sold under financial contracts this quarter, compared to 46% in the third quarter of 2010. Pricing under these contracts was lower than in 2010. From time to time BPLP enters the market to lock in the gains under these contracts.

The capacity factor was 93% this quarter, up from 88% in the third quarter of 2010 due to a lower volume of planned and unplanned outage days when compared to last year. Operating costs were similar at $232 million compared to $229 million in 2010.

The result was a 3% decrease in our share of earnings before taxes.

BPLP distributed $80 million to the partners in the third quarter. Our share was $25 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

During the fourth quarter, there is a planned maintenance outage at one unit.

First nine months

Total electricity revenue for the first nine months decreased 9% compared to 2010 due to lower output and lower realized prices. Realized prices reflect spot sales, revenue recognized under BPLP's agreement with the OPA and financial contract revenue. BPLP recognized revenue of $351 million in the first nine months of 2011 under its agreement with the OPA, compared to $224 million in the first nine months of 2010. The equivalent of about 49% of BPLP's output was sold under financial contracts in the first nine months of this year, compared to 41% in 2010. Pricing under these contracts was lower than in 2010. From time to time BPLP enters the market to lock in the gains under these contracts.

The capacity factor was 87% for the first nine months of this year, down from 90% in 2010 due to a higher volume of outage days during this year's planned outage compared to last year's planned outage. Operating costs were $735 million compared to $685 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

The result was a 39% decrease in our share of earnings before taxes.

BPLP distributed $205 million to the partners in the first nine months of 2011. Our share was $65 million.

Operations and development project updates

Uranium - production overview

Cameco's share
(million lbs U3O8)
Three months ended   Nine months ended  
September 30   September 30  
2011 2010 change 2011 2010 change
             
McArthur River/Key Lake 3.8 3.7 3%  10.0 9.9 1% 
Rabbit Lake 0.5 0.5 - 2.2 2.5 (12)%
Smith Ranch-Highland 0.3 0.4 (25)% 1.2 1.4 (14)%
Crow Butte 0.2 0.2 - 0.6 0.6 -
Inkai 0.5 0.8 (38)% 1.8 2.1 (14)%
Total 5.3 5.6 (5)% 15.8 16.5 (4)%
             

McArthur River/Key Lake

At McArthur River/Key Lake, production was 3% higher in the third quarter and 1% higher for the first nine months of the year compared to the same periods last year. These increases were due to better recovery and improved equipment reliability at the mill. We expect the mill to operate through year end with no scheduled shutdown until 2012.

At Key Lake, we continued work on the new oxygen, acid and steam plants. Commissioning of the steam plant commenced in the third quarter. We expect that the oxygen, acid and steam plants will all be operating by the end of the year.

Smith Ranch-Highland and Crow Butte

Production this quarter was 17% lower and 10% lower for the first nine months of the year compared to the same periods last year due to lower production from Smith Ranch-Highland. We have decreased our production forecast for the year by 8% to 2.3 million pounds. The review process to obtain regulatory approvals has lengthened at Smith Ranch-Highland, which has increased the timeline to bring new wellfields into production.

We continue to seek regulatory approvals to proceed with expansions at our various satellite operations in Wyoming and Nebraska. However, we are experiencing some permitting delays. As a result, we do not expect to receive approval to expand Reynolds Ranch this year. We recognize the regulators have a large volume of permits to process. We are working with them to improve communications and ensure we understand and meet their needs.

Inkai

Production for the quarter was 38% lower and 14% lower for the first nine months of the year compared to the same periods last year. For the quarter, lower production was primarily due to in-process uranium inventory changes. Prior to final commissioning of the processing facilities in 2010, the in-process uranium inventory had built up. A significant reduction of this inventory added to production in the third quarter of 2010 compared to 2011.

In addition, during 2010, the first year of full operation at Inkai, production benefited from the grade peak associated with multiple new wellfields. As our existing wellfields mature, the grades decrease. Average grades at in situ recovery operations typically stabilize at levels lower than initial years as uranium is recovered from a mix of wellfields of varying maturities. We are ramping up capacity at the Inkai operation in order to accommodate lower grades. We have lowered our production forecast to 2.5 million pounds, a 7% decrease from our initial estimate but in line with the currently approved production level.

Inkai's supply of sulphuric acid was consistent during the quarter. We experienced brief interruptions to supply during the first six months of the year. We do not anticipate any further interruptions to supply this year.

As announced on August 31, 2011, we signed an MOA with our partner, Kazatomprom, to increase production from blocks 1 and 2 to 5.2 million pounds of U3O8 (100% basis). Under the MOA, our share of Inkai's annual production will be 2.9 million pounds with the processing plant at full capacity. We will also be entitled to receive profits on 3.0 million pounds.

We believe this is a fair and reasonable approach that allows both parties to benefit from changes in the uranium market that were not envisioned when the initial agreements were signed. To implement the increase, we need a binding agreement finalizing the terms of the MOA, government approval and an amendment to the resource use contract.

We continue to proceed with delineation drilling and the engineering of infrastructure and the test leach facility at block 3.

Cigar Lake

The sinking of shaft 2 continues as planned. We expect to reach the main mine workings on the 480 metre level before the end of the year. The final depth of the shaft will be 500 metres.

We also continued drilling freeze holes from surface during the quarter.

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

As announced on October 5, 2011, we signed a non-binding MOU with our joint venture partners, which contemplates a change in the milling arrangements for the ore from Cigar Lake. Under the current toll milling agreements, both the McClean Lake mill and the Rabbit Lake mill would process uranium from Cigar Lake. Under the new arrangement, the McClean Lake mill would process and package all of the Cigar Lake uranium.

Rabbit Lake will continue to process ore mined on site and has the flexibility to process ore from other sources.

We expect the new milling arrangement will have a positive impact on the economics of the Cigar Lake project. To reflect the impact of this new milling arrangement and other developments (such as surface freezing) since the March 2010 Cigar Lake technical report, we are planning to file an updated Cigar Lake technical report with, or prior to, our February 2012 annual information form.

The most significant project developments since the March 2010 technical report are:

  • a decrease in the estimated average cash operating cost to about $18.60 per pound from $23.14 per pound. The reduction in the operating cost estimate is primarily due to the new milling arrangement.
  • a $189 million increase in our share of the total capital cost at completion to $1.1 billion. The capital cost estimate has increased primarily as a result of the implementation of the surface freeze strategy, general cost escalation, costs to upgrade and expand the McClean Lake mill and improvements to the mine plan.

The projected production startup date remains mid-2013.

Binding agreements with the owners of the Cigar Lake project and McClean Lake mill are required to proceed with the new milling arrangements. We expect these to be complete before November 30, 2011.

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


The intention to mill all Cigar Lake ore at the McClean Lake mill and the expected benefit of that arrangement, the estimated average cash operating cost and our expected share of the total capital cost at completion for Cigar Lake, and our projected production startup date of mid-2013 are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 12 and 13, and specifically on the assumptions and risks listed below.

Assumptions Material Risks
  • we will reach binding agreements to implement the MOU
  • our expectation that the arrangement will result in the expected reduction in operating costs
  • our Cigar Lake remediation, development and production plans succeed
  • there is no material delay or disruption in our plans as a result of additional water inflows, natural phenomena, equipment failure or other causes
  • we are unable to reach binding agreements to implement the new milling arrangements on expected terms
  • the new milling arrangement does not result in the expected cost savings or other benefits
  • our remediation, development or production plans for Cigar Lake are delayed or do not succeed for any reason

Fuel services

Fuel services production totalled 2.8 million kgU this quarter, compared to 2.3 million kgU in the third quarter of 2010. Production was 22% higher due to the planned maintenance shutdown of the Port Hope UF6 plant in 2010.

Production for the first nine months of the year was 11.6 million kgU compared to 11.7 million kgU in the first nine months of 2010.

Due to current unfavourable market conditions for UF6 conversion, we are reducing production for this year. We now expect fuel services to produce between 14 million and 15 million kgU this year (previously 15 million to 16 million kgU).

Based on the unfavourable market outlook for UF6 conversion, we have discontinued discussions to extend our toll conversion contract with SFL beyond 2016. We remain fully committed to the current contract. Should market conditions improve over the next few years, we would consider resuming our discussions to extend the contract.

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 Cigar Lake
  • David Bronkhorst, vice-president, Saskatchewan mining south, Cameco
  • Les Yesnik, general manager, Key Lake, Cameco Inkai
  • Grant Goddard, vice-president, Saskatchewan mining north, Cameco
Inkai
  • Dave Neuburger, vice-president, international mining, Cameco

Caution about forward-looking information

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

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

  • It typically includes words and phrases about the future, such as: anticipate, estimate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples below).
  • It represents our current views, and can change significantly.
  • It is based on a number of material assumptions, including those we have listed on page 13, which may prove to be incorrect.
  • Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks on pages 12 and 13. We recommend you also review our annual information form and our annual MD&A, which include a discussion of other material risks that could cause actual results to differ significantly from our current expectations.
  • Forward-looking information is designed to help you understand management's current views of our near and longer term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

Examples of forward-looking information in this document

  • our expectations about 2011 and future global uranium supply, consumption, demand and number of operating reactors, including the discussion on the expected impact resulting from the March 2011 nuclear incident in Japan
  • our expectation that existing cash balances and operating cash flows will meet anticipated requirements without the need for any significant additional funding
  • the outlook for each of our operating segments for 2011, and our consolidated outlook for the year
  • our expectation that the fourth quarter will be strong and fourth quarter deliveries will account for over one-third of 2011 sales volumes
  • our expectation that we will invest significantly in expanding production at existing mines and advancing projects as we pursue our growth strategy
  • our expectation that cash balances will decline as we use the funds in our business and pursue our growth plans
  • our expectation that we will have a solid revenue stream for years to come, even in the event of declining uranium market prices
  • our future plans for each of our uranium operating properties, development projects and projects under evaluation, and fuel services operating sites
  • our mid-2013 target for initial production from Cigar Lake

Material risks

  • actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor
  • we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates
  • our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms
  • our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate
  • 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 inaccurate, or we face unexpected or challenging geological, hydrological or mining conditions
  • we are affected by environmental, safety and regulatory risks, including increased regulatory burdens 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, accident or a deterioration in political support for, or demand for, nuclear energy
  • we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium
  • there are changes to government regulations or policies that adversely affect us, including tax and trade laws and policies
  • our uranium and conversion suppliers fail to fulfil delivery commitments
  • we are delayed or do not succeed in remediating and developing Cigar Lake
  • we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes
  • our operations are disrupted due to problems with our own or our customers' facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, tailings dam failures, and other development and operating risks

Material assumptions

  • our expectations regarding sales and purchase volumes and prices for uranium, fuel services and electricity
  • our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being adversely affected by changes in regulation or in the public perception of the safety of nuclear power plants
  • our expected production costs
  • our expectations regarding spot prices and realized prices for uranium, and other factors discussed in our third quarter MD&A, Price sensitivity analysis: uranium
  • our expectations regarding tax rates, foreign currency exchange rates and interest rates
  • our decommissioning and reclamation expenses
  • our mineral reserve and resource estimates
  • the geological, hydrological and other conditions at our mines
  • our Cigar Lake remediation, development and production plans succeed
  • our ability to continue to supply our products and services in the expected quantities and at the expected times
  • our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals
  • our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave ins, tailings dam failure, lack of tailings capacity, or other development or operating risks

Conference call

We invite you to join our third quarter conference call on Monday, November 7, 2011 at 11:00 a.m. Eastern.

The call will be open to all investors and the media. To join the call, please dial (877) 240-9772 (Canada and US) or (416) 340-8530. An operator will put your call through. A live audio feed of the conference call will be available on this website. See the link on our home page on the day of the call.

Q3 Audio recording now available

A recorded version of the proceedings will be available:

  • on this website, shortly after the call
  • on post view until midnight, Eastern, December 7, 2011 by calling (800) 408-3053 or (905) 694-9451 (Passcode 2856426 )

Additional information

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

Additional information, including our 2010 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 this website.

Profile

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

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

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Investor inquiries:
Rachelle Girard (306) 956-6403

Media inquiries:
Rob Gereghty (306) 956-6190