Cameco Reports Third Quarter Financial Results

Cameco Reports Third Quarter Financial Results 
SASKATOON, SASKATCHEWAN -- (Marketwire) -- 10/31/12 --  
ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED) 
Quarterly items 


 
--  reconfirmed sales, revenue and production guidance for the year 
--  increased mineral reserves by 19% at McArthur River 
--  signed an MOA with our joint venture partner at Inkai 
--  received funding commitment from the Saskatchewan government to
    construct a highway connecting McArthur River and Cigar Lake 

 
Long-term growth plan 


 
--  strong long-term industry fundamentals - 64 reactors under construction 
--  ongoing market uncertainties reduce uranium demand forecast to 2021 
--  our growth plan adjusted to focus primarily on our brownfield projects
    resulting in annual supply of 36 million pounds by 2018 
--  maintain our world class portfolio of projects, providing the ability to
    respond to positive market signals 

 
Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated financial
and operating results for the third quarter ended September 30, 2012
in accordance with International Financial Reporting Standards
(IFRS). 
"Our results this quarter reflect the delivery pattern we reported in
our second quarter report and we still expect to deliver on our
sales, revenue and production guidance for the year," said Tim
Gitzel, president and CEO.  
"Longer term, we continue to see strong fundamentals. However,
ongoing market uncertainty in the near term led us to review and
adjust our growth plans this quarter. We decided to focus on
advancing projects with the greatest certainty in the near term, from
which we expect to achieve about 36 million pounds of annual supply
by 2018 compared to the 40 million previously targeted. We will also
continue with the rest of our projects in a measured manner in order
to preserve the option to bring them on as quickly as possible, if
profitable.  
"By taking these actions, we expect to spread our capital spending
over a longer period and decrease project-related expenses. Our focus
will be on execution and reducing costs without compromising on our
values. 
"With this adjustment, we believe we are positioned to continue to
succeed in the current market environment, add value for our
shareholders, and take advant
age of the growth in uranium demand we
see long term." 


 
                                --------------------------------------------
Highlights                      Three months                                
($ millions except where               ended                  Nine months   
indicated)                      September 30            ended September 30  
                                --------------------------------------------
                                 2012   2011 change     2012   2011 change  
----------------------------------------------------------------------------
Revenue                           408    527    (23)%  1,363  1,414     (4)%
----------------------------------------------------------------------------
Gross profit                      135    179    (25)%    416    423     (2)%
----------------------------------------------------------------------------
Net earnings                       82     39    110%     221    186     19% 
----------------------------------------------------------------------------
 $ per common share (diluted)    0.21   0.10    110%    0.56   0.47     19% 
----------------------------------------------------------------------------
Adjusted net earnings (non-IFRS,                                            
 see Outlook for 2012)             52    104    (50)%    210    259    (19)%
----------------------------------------------------------------------------
 $ per common share (adjusted                                               
  and diluted)                   0.13   0.26    (50)%   0.53   0.66    (20)%
----------------------------------------------------------------------------
Cash provided by operations                                                 
 (after working capital changes)   44    192    (77)%    361    487    (26)%
----------------------------------------------------------------------------
Average                                                                     
 realized                 $US/                                              
 prices       Uranium     lb    44.49  47.33     (6)%  45.76  47.06     (3)%
                                                                            
                          $Cdn/                                             
                          lb    44.99  45.97     (2)%  46.22  46.36      -  
              --------------------------------------------------------------
              Fuel        $Cdn/                                             
               services   kgU   16.98  17.42     (3)%  17.55  18.04     (3)%
              --------------------------------------------------------------
              Electricity $Cdn/                                             
                          MWh   54.00  54.00      -    55.00  54.00      2% 
----------------------------------------------------------------------------

 
Third quarter 
Net earnings attributable to our shareholders (net earnings) this
quarter were $82 million ($0.21 per share diluted) compared to $39
million ($0.10 per share diluted) in the third quarter of 2011. In
addition to the items noted below, net earnings were impacted by
higher mark-to-market gains on foreign exchange derivatives.  
On an adjusted basis, our earnings this quarter were $52 million
($0.13 per share diluted) compared to $104 million ($0.26 per share
diluted) (non-IFRS measure, see Outlook for 2012) in the third
quarter of 2011, mainly due to: 


 
--  lower earnings from our uranium business based on lower sales volumes,
    lower realized prices and higher costs 
--  higher expenditures for exploration and administration 
--  partially offset by higher earnings from our electricity business due to
    an increase in sales and lower costs 

 
See Financial results by segment for more detailed discussion. 
First nine months 
Net earnings in the first nine months of the year were $221 million
($0.56 per share diluted) compared to $186 million ($0.47 per share
diluted) in the first nine months of 2011. Net earnings were higher
than in 2011 due to higher mark-to-market gains on foreign exchange
derivatives and the items noted below. 
On an adjusted basis, our earnings for the first nine months of this
year were $210 million ($0.53 per share diluted) compared to $259
million ($0.66 per share diluted) (non-IFRS measure, see Outlook for
2012). The change was due to: 


 
--  lower earnings from our uranium business based on lower sales volumes,
    lower realized prices and higher costs 
--  a $30 million (US) contract termination charge 
--  higher expenditures for exploration and administration 
--  partially offset by higher earnings from our electricity business due to
    an increase in sales, higher realized prices and lower costs 

 
See Financial results by segment for more detailed discussion. 
Our strategy 
We remain confident in the long-term fundamentals of the nuclear
industry as world demand for safe, clean, reliable and affordable
energy continues to grow. Nuclear energy remains an integral part of
the energy mix, demonstrated by the 64 reactors under construction
today.  
However, recent developments in the nuclear industry, primarily
centred around Japan, have caused more 
uncertainty in the rate of
growth in nuclear power globally. This led us to review and adjust
our outlook, and examine our long-term growth plans. 
While market factors continue to evolve, our current view is that
over the next decade (to 2021), we expect there will be 80 net new
reactors, compared to the 95 previously anticipated. Most of this
change is due to the retirement of some reactors and new reactor
builds being pushed out beyond the 10-year period. As a result, we
have revised our cumulative world uranium demand forecast to 2.1
billion pounds for that period, down 50 million pounds from our
previous expectation. As always, we will continue to evaluate the
effects on demand as the nuclear market evolves. 
Given this expected near-term decrease in demand, we examined our
portfolio of projects to determine if we should adjust the timing of
development for them. From this review, we have decided to focus
primarily on advancing our brownfield projects, while deferring
development of our greenfield projects. However, we will undertake
some measured activity to preserve the option to bring on these
greenfield projects as quickly as possible should market conditions
warrant doing so. In addition, we will advance our arrangement with
Talvivaara and pace the expansion projects at Inkai. By taking these
actions we expect to achieve about 36 million pounds of annual supply
rather than 40 million pounds by 2018.  
This means we plan to spread our capital spending over a longer
period and decrease project-related expenses, which should enhance
our nearer term financial picture. Subject to market conditions, we
plan to undertake the following projects: 


 
--  bring Cigar Lake project to production 
--  expand production at the McArthur River mine 
--  refurbish and expand the Key Lake mill 
--  work to extend the Rabbit Lake mine life 
--  expand our US ISR production by advancing our various satellite
    operations 
--  advance the process for extracting uranium from the Talvivaara mine 

 
Market opportunities will drive the rate of development of the
following projects: 


 
--  advancing the Millennium project to achieve regulatory approvals as soon
    as possible to allow development to occur independently 
--  pacing the increase in uranium production at Inkai blocks 1 and 2 to
    match progress on the transfer of our refining/conversion technology,
    both subject to market conditions, and continuing work on the test leach
    facility at block 3 
--  completing the value engineering and the environmental permitting at
    Kintyre, but not proceeding with the detailed feasibility study 

 
Of course, we will adjust the timing of our projects should market
conditions evolve, which could change our supply plan. Adjusting a
growth plan is not unique in our industry. A number of uranium
producers have halted or delayed projects because they are not
economic in today's environment. These economic challenges, driven by
continued global economic turmoil and the issues surrounding nuclear
power noted above, point to an uncertain future supply of global
primary uranium production. And to fuel the 431 currently operating
reactors, the 64 reactors under construction today, and the further
growth we expect by 2021, new primary sources of production will be
needed. We anticipate economics will eventually need to reflect the
realities of bringing on new, higher cost production; it's a matter
of timing.  
As a result, we continue to prepare our assets now to ensure we can
be among the first to respond when the market signals that new
production is needed, and project economics improve. We want to be
clear that any decision to increase our supply will be driven by
profitability. 
In the meantime, today's market environment calls for us to increase
our focus on execution and maximize efficiencies in order to
continually improve our margins to ensure we remain competitive.
Specifically, we are in the process of reducing costs at all
operations and corporate departments without compromising our values.
In addition, we plan to decrease expenditures for exploration and
research and development to better match market opportunities. 
We maintain a strong balance sheet, which will be enhanced by taking
these actions. As part of our normal strategic planning process, we
will continue to review our capital structure and asset base to
ensure it is optimal.  
Our extraordinary assets, extensive portfolio of long-term sales
contracts, employee expertise and comprehensive industry knowledge
provide us with the confidence that we will be able to achieve these
goals. And, as always, we will look for opportunities across the
nuclear fuel cycle that we expect will complement and enhance our
business. 
We will continue to monitor the market closely and adjust our plans
accordingly. 
Uranium market update 
Since the previous quarter, the nuclear industry continues to
experience near- to medium-term uncertainty, driven primarily by the
evolving situation in Japan. 
In September 2012, a Japanese government panel announced a draft
energy policy that included plans to phase out nuclear power
generation by 2040. But the plan drew intense opposition from
business groups and communities whose economies depend on the local
nuclear power plants. The Japanese government did not adopt the plan,
but agreed to take it under consideration while engaging with local
governments, the public and the international community in developing
an energy policy. 
Japan's new Nuclear Regulatory Authority (NRA) also came into effect
in September. It will create new regulatory standards against which
reactor restarts will be evaluated. We believe the NRA brings
important stability to the regulatory environment in Japan and has
already brought some clarity to the issue of reactor restarts. It
indicated that no additional reactors will be restarted until the new
standards are in place - a process expected to take about 10 months.
This requirement suggests there will be no more reactor restarts in
Japan this year and possibly not until mid-2013 or later depending on
when the standards are put in place. 
The slower reactor restarts expected in Japan, combined with slower
economic growth worldwide and changes to nuclear programs in some
other countries led us to re-examine our reactor forecast. For
example, Canada, France and Belgium have announced plans to retire
their older reactors, and India has revised its 2020 nuclear target
down from 20 to 14.6 gigawatts. So while the market continues to
evolve, our initial review results in an estimated 80 net new
reactors over the period 2012 to 2021, compared to the 95 we expected
earlier this year. Most of the decrease is due to the retirement of
reactors, although some is also due to deferrals beyond 2021. 
New Build Outlook - Planned Reactors (2012 to 2021) 


 
---------------------------- -----------------------------------------------
Region / Country                                                            
(as of Sept 30,                                  Change to                  
 2012)              Operable  Previous Forecast    net new    New Forecast  
                             --------------------          -----------------
                                             Net              Net   Operable
                           
     New  Shut    New              New       2021
----------------------------------------------------------------------------
Americas                 127     11    (6)     5        (1)     4        131
----------------------------------------------------------------------------
Europe                   137     11   (14)    (3)       (3)    (6)       131
----------------------------------------------------------------------------
Asia                      77     14    (1)    13        (8)     5         82
----------------------------------------------------------------------------
Other(i)                   6      7     -      7         -      7         13
----------------------------------------------------------------------------
India                     20     15     -     15        (3)    12         32
----------------------------------------------------------------------------
China                     15     52     -     52         -     52         67
----------------------------------------------------------------------------
Russia/E.                                                                   
 Europe(ii)               49     17   (11)     6         -      6         55
----------------------------------------------------------------------------
Total                    431    127   (32)    95       (15)    80        511
----------------------------------------------------------------------------
(i)Other includes Iran, Pakistan, South Africa, Turkey and United Arab      
 Emirates.                                                                  
(ii) Eastern Europe includes Armenia, Belarus and Ukraine.                  

 
Of these net new reactors, 64 are under construction today. China is
the most aggressive, and we expect it to grow its nuclear power
program from the 15 currently operating reactors to 67 in 2021, of
which 26 are under construction.  
The 80 net new reactors combined with the current base of nuclear
power plants translates into a cumulative uranium demand of about 2.1
billion pounds to 2021, which is down by about 50 million pounds from
our earlier forecast. 
While expected demand has decreased, there has also been an increase
in global supply. In China, Uzbekistan and Namibia production
increased at a number of mines, which we expect will equate to about
30 million pounds of further supply over the 10-year period. 
The result when we put these changes to supply and demand together is
a demonstrated need for new supply of 360 million pounds from 2012 to
2021, compared to the 440 million pounds we had forecast earlier in
the year. 
However, the current market environment also poses challenges to
bringing on new supply and could impact supply expectations as
conditions continue to evolve. A number of project deferrals and
cancellations have been announced as producers have reacted to lower
uranium prices and general economic pressures. As well, secondary
supplies continue to diminish, particularly with the end of the
Russian Highly Enriched Uranium (HEU) agreement in 2013. Conclusion
of this arrangement will mean the removal of 24 million pounds of
relatively low-cost secondary annual uranium supply from the market,
and there are no indications of a second Russian HEU deal. 
Despite the changes we see to the supply/demand outlook, what remains
clear is that new supply will be needed. Though some could come from
additions to secondary supplies, the majority will need to come from
new mines and expansions to existing mines at a time when pursuing
such projects is becoming increasingly difficult. In addition, the
long-term fundamentals of the industry remain strong, with 64
reactors currently under construction and some of the growth pushed
further out in time. As a result, we are managing our assets through
this period of uncertainty with a focus on safety, efficiency and
profitable growth. 
Caution about forward-looking information relating to our uranium
market update 
This discussion of our expectations for the nuclear industry,
including its growth profile and future global uranium supply and
demand and the number of reactors, is forward-looking information
that is based upon the assumptions and subject to the material risks
discussed under the heading Caution about forward-looking
information. 
Outlook for 2012 
Our outlook for 2012 reflects the growth expenditures necessary to
help us achieve our strategy. Our outlook for consolidated capital
expenditures and consolidated tax rate has changed. We explain the
changes below. All other items in the table are unchanged. We do not
provide an outlook for the items in the table that are marked with a
dash.  
See Financial results by segment for details. 
2012 Financial outlook 


 
----------------------------------------------------------------------------
                      Consolidated       Uranium  Fuel services  Electricity
----------------------------------------------------------------------------
Production                          21.7 million       13 to 14             
                                 -           lbs    million kgU            -
----------------------------------------------------------------------------
Sales volume                            31 to 33      Decrease              
                                 -   million lbs     10% to 15%            -
----------------------------------------------------------------------------
Capacity factor                  -             -              -          93%
----------------------------------------------------------------------------
Revenue compared to       Decrease     Decrease       Decrease     Increase 
 2011                     0% to 5%   0% to 5%(1)     10% to 15%    5% to 10%
----------------------------------------------------------------------------
Average unit cost of                                                        
 sales (including                      Increase       Increase     Decrease 
 D&A)                            -   0% to 5%(2)     10% to 15%   15% to 20%
----------------------------------------------------------------------------
Direct                                                                      
 administration                                                             
 costs compared to       Increase                                           
 2011(3)                10% to 15%             -              -            -
----------------------------------------------------------------------------
Exploration costs                      Increase                             
 compared to 2011                -    15% to 20%              -            -
----------------------------------------------------------------------------
Tax rate               Recovery of                                          
                        10% to 15%             -              -            -
----------------------------------------------------------------------------
Capital expenditures          $730                                          
                        million(4)             -              -  $70 million
----------------------------------------------------------------------------
(1) Based on a uranium spot price of $42.50 (US) per pound (the Ux spot     
 price as of October 29, 2012), a long-term price indicator of $60.00 (US)  
 per pound (the Ux long-term indicator on September 30, 2012) 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 2012 then we expect the average unit cost of sales to increase
 further.                                                                   
(3) Direct administration costs do not include stock-based compensation     
 expenses.                                                                  
(4) Does not include our share of capital expenditures at BPLP.      

 
Our customers choose when in the year to receive deliveries of
uranium and fuel services products, so our quarterly delivery
patterns, and therefore our sales volumes and revenue, can vary
significantly. In the fourth quarter, we expect about 40% of our 2012
deliveries to occur with an improvement in our average realized
uranium price due to pricing under the mix of contracts.  
We now expect a recovery of 10% to 15% for our consolidated tax rate
(previously a 5% to 10% recovery). The change is primarily related to
the $9 million recovery in our income tax expense that we recognized
in the second quarter due to additional certainty we received on
particular tax provisions. 
We now expect our capital expenditures to be about $730 million
compared to our previous estimate of $680 million due to changes in
scope and scheduling of some of our projects in northern
Saskatchewan. 
Sensitivity analysis 
For the rest of 2012:  


 
--  a change of $5 (US) per pound in both the Ux spot price ($42.50 (US) per
    pound on October 29, 2012) and the Ux long-term price indicator ($60.00
    (US) per pound on September 30, 2012) would change revenue by $13
    million and net earnings by $7 million 
--  a change of $5/MWh in the electricity spot price would change our 2012
    net earnings by $1 million based on the assumption that the spot price
    will remain below the floor price of $51.62/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 $2 million and adjusted net earnings by
    $1 million. This sensitivity is based on an exchange rate of $1.00 (US)
    for $1.02 (Cdn). 

 
Adjusted net earnings (non-IFRS measure) 
Adjusted net earnings is a measure that does not have a standardized
meaning or a consistent basis of calculation under IFRS (non-IFRS
measure). We use this measure as a more meaningful way to compare our
financial performance from period to period. We believe that, in
addition to conventional measures prepared in accordance with IFRS,
certain investors use this information to evaluate our performance.
Adjusted net earnings is our net earnings attributable to equity
holders, adjusted to better reflect the underlying financial
performance for the reporting period. The adjusted earnings measure
reflects the matching of the net benefits of our hedging program with
the inflows of foreign currencies in the applicable reporting period. 
Adjusted net earnings is non-standard supplemental information and
should not be considered in isolation or as a substitute for
financial information prepared according to accounting standards.
Other companies may calculate this measure differently so you may not
be able to make a direct comparison to similar measures presented by
other companies.  
The table below reconciles adjusted net earnings with our net
earnings. 


 
----------------------------------------------------------------------------
                                      Three months ended  Nine months ended 
($ millions)                                September 30       September 30 
                                      --------------------------------------
                                           2012     2011      2012     2011 
----------------------------------------------------------------------------
Net earnings                                 82       39       221      186 
----------------------------------------------------------------------------
Adjustments                                                                 
----------------------------------------------------------------------------
  Adjustments on derivatives(1) (pre-                                       
   tax)                                     (40)      88       (15)     100 
----------------------------------------------------------------------------
  Income taxes on adjustments to                                            
   derivatives                               10      (23)        4      (27)
----------------------------------------------------------------------------
Adjusted net earnings                        52      104       210      259 
----------------------------------------------------------------------------
(1) In 2008, we opted to discontinue hedge accounting for our portfolio of  
 foreign currency forward sales contracts. Since then, we have adjusted our 
 gains or losses on derivatives to reflect what our earnings would have been
 had hedge accounting been applied.                                         

 
Financial results by segment 
Uranium 


 
----------------------------------------------------------------------------
                              Three months             Nine months          
                                     ended                   ended          
Highlights                    September 30            September 30          
                            --------------          --------------          
                               2012   2011  change     2012   2011  change  
----------------------------------------------------------------------------
Production volume (million                                                  
 lbs)                           5.3    5.3       -     15.4   15.8      (3)%
----------------------------------------------------------------------------
Sales volume (million lbs)      5.1    7.2     (29)%   18.1   19.1      (5)%
----------------------------------------------------------------------------
Average spot price ($US/lb    48.08  51.04      (6)%  50.38  57.89     (13)%
Average long-term price                                                     
 ($US/lb)                     60.67  65.33      (7)%  60.67  68.22          
Average realized price                                                 (11)%
($US/lb)                      44.49  47.33      (6)%  45.76  47.06      (3)%
($Cdn/lb)                     44.99  45.97      (2)%  46.22  46.36       -  
----------------------------------------------------------------------------
Average unit cost of sales                                                  
 ($Cdn/lb U3O8) (including                                                  
 D&A)                         28.75  27.59       4%   31.47  29.68       6% 
----------------------------------------------------------------------------
Revenue ($ millions)            231    332     (30)%    837    885      (5)%
----------------------------------------------------------------------------
Gross profit ($ millions)        83    133     (38)%    267    318     (16)%
----------------------------------------------------------------------------
Gross profit (%)                 36     40     (10)%     32     36     (11)%
----------------------------------------------------------------------------

 
Third quarter 
Production volumes this quarter were unchanged compared to the third
quarter of 2011. See Operations and development project updates for
more information. 
Uranium revenues this quarter were down 30% compared to 2011, due to
a 29% decrease in sales volumes and a 2% decrease in the $Cdn
realized selling price. 
Our realized prices this quarter were lower than the third quarter of
2011 mainly due to lower $US prices under fixed-price contracts. In
the third quarter of 2012, our realized foreign exchange rate was
$1.01, compared to $0.97 for the prior year. 
Total cost of sales (including D&A) decreased by 26% ($147 million
compared to $199 million in 2011). This was mainly the result of the
following: 


 
--  a 29% decrease in sales volumes 
--  lower royalty charges ($7 million in 2012; $26 million in 2011) due to
    decreased deliveries of Saskatchewan-produced material 
--  partially offset by average unit costs for produced uranium being 16%
    higher due to increased non-cash production costs at our ISR locations 

 
The net effect was a $50 million dec
rease in gross profit for the
quarter. 
First nine months 
Production volumes for the first nine months of the year were lower
than in the previous year due to lower output at Smith Ranch-Highland
and Inkai. See Operations and development project updates for more
information. 
For the first nine months of 2012, uranium revenues were down 5%
compared to 2011, due to a 5% decrease in sales volumes. 
Our $US realized prices were lower than the first nine months of 2011
mainly due to lower prices under market-related contracts being
offset by a more favourable exchange rate. In the first nine months
of 2012, our realized foreign exchange rate was $1.01 compared to
$0.99 in the prior year. 
Total cost of sales (including D&A) increased by 1% ($570 million
compared to $567 million in 2011). This was mainly the result of the
following: 


 
--  average unit costs for produced uranium were 13% higher due to increased
    unit production costs relating mainly to the lower production during the
    first nine months. We continue to expect our average unit cost of sales
    (including D&A) to increase by 0% to 5% for the year compared to 2011. 
--  royalty charges in 2012 were $2 million higher due to increased
    deliveries of Saskatchewan-produced material 
--  partially offset by a 5% decrease in sales volume 

 
The net effect was a $51 million decrease in gross profit for the
first nine months. 
The following table shows the costs of produced and purchased uranium
incurred in the reporting periods (non-IFRS measures see below).
These costs do not include selling costs such as royalties,
transportation and commissions, nor do they reflect the impact of
opening inventories on our reported cost of sales. 


 
----------------------------------------------------------------------------
                               Three months            Nine months          
                                      ended                  ended          
($Cdn/lb)                      September 30           September 30          
                             --------------         --------------          
                                2012   2011  change    2012   2011  change  
----------------------------------------------------------------------------
Produced                                                                    
  Cash cost                    21.11  17.89      18%  21.18  18.87      12% 
  Non-cash cost                 8.62   7.79      11%   8.01   6.92      16% 
----------------------------------------------------------------------------
  Total production cost        29.73  25.68      16%  29.19  25.79      13% 
----------------------------------------------------------------------------
  Quantity produced (million                                                
   lbs)                          5.3    5.3       -    15.4   15.8      (3)%
----------------------------------------------------------------------------
Purchased                                                                   
  Cash cost                    26.08  17.90      46%  27.04  28.32      (5)%
----------------------------------------------------------------------------
  Quantity purchased (million                                               
   lbs)                          4.6    3.1      48%    8.4    7.3      15% 
----------------------------------------------------------------------------
Totals                                                                      
  Produced and purchased                                                    
   costs                       28.03  22.81      23%  28.43  25.36      12% 
----------------------------------------------------------------------------
  Quantities produced and                                                   
   purchased (million lbs)       9.9    8.4      18%   23.8   23.1       3% 
----------------------------------------------------------------------------

 
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 third quarters and first nine months of 2012 and 2011.  
Cash and total cost per pound reconciliation  


 
----------------------------------------------------------------------------
                           Three months               Nine months           
                        ended September           ended September           
($ millions)                         30                        30           
                        ----------------          ----------------          
                           2012    2011   change     2012    2011   change  
----------------------------------------------------------------------------
Cost of product sold      121.8   164.7      (26)%  480.6   487.5       (1)%
Add / (subtract)                                                            
  Royalties                (6.7)  (26.3)     (75)%  (64.3)  (62.3)       3% 
  Standby charges          (8.0)   (5.2)      54%   (20.9)  (16.0)      31% 
  Other selling costs      (0.6)   (0.6)       -     (2.9)   (6.7)     (57)%
  Change in inventories   125.4    17.7      608%   160.9   102.5       57% 
----------------------------------------------------------------------------
Cash operating costs (a)  231.9   150.3       54%   553.4   505.0       10% 
Add / (subtract)                                                            
  Depreciation and                                                          
   amortization            25.7    34.3      (25)%   89.5    79.1       13% 
  Change in inventories    19.9     7.0      184%    33.7     1.7     1882% 
----------------------------------------------------------------------------
Total operating costs                                                       
 (b)                      277.5   191.6       45%   676.6   585.8       16% 
----------------------------------------------------------------------------
  Uranium produced &                                                        
   purchased (millions                                                      
   lbs) (c)                 9.9     8.4       18%    23.8    23.1        3% 
----------------------------------------------------------------------------
Cash costs per pound (a                                                     
 / c)                     23.42   17.89       31%   23.25   21.86        6% 
Total costs per pound (b                                                    
 / c)                     28.03   22.81       23%   28.43   25.36       12% 
----------------------------------------------------------------------------

 
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) 


 
----------------------------------------------------------------------------
                              Three months             Nine months          
                    
                 ended                   ended          
Highlights                    September 30            September 30          
                            --------------          --------------          
                               2012   2011  change     2012   2011  change  
----------------------------------------------------------------------------
Production volume (million                                                  
 kgU)                           2.1    2.8     (25)%   10.9   11.6      (6)%
----------------------------------------------------------------------------
Sales volume (million kgU)      3.3    4.6     (28)%   10.1   11.1      (9)%
----------------------------------------------------------------------------
Realized price ($Cdn/kgU)     16.98  17.42      (3)%  17.55  18.04      (3)%
----------------------------------------------------------------------------
Average unit cost of sales                                                  
 ($Cdn/kgU) (including D&A)   16.20  15.34       6%   15.32  15.42      (1)%
----------------------------------------------------------------------------
Revenue ($ millions)             56     81     (31)%    178    199     (11)%
----------------------------------------------------------------------------
Gross profit ($ millions)         3     10     (70)%     23     29     (21)%
----------------------------------------------------------------------------
Gross profit (%)                  5     12     (58)%     13     15     (13)%
----------------------------------------------------------------------------

 
Third quarter 
Production volumes in the quarter were 25% lower than in 2011 due to
the reduction of planned production for 2012.  
Total revenue was $25 million lower than in 2011 due to a 28% decline
in deliveries of our fuel services products and a 3% decline in the
realized selling price.  
Our $Cdn realized price for fuel services was affected by the mix of
products delivered in the quarter. In 2012, a higher proportion of
fuel services sales were for UF6, which typically yields a lower
price than the other fuel services products. 
The total cost of sales (including D&A) decreased by 25% ($53 million
compared to $71 million in 2011) due to the decrease in the sales
volumes. The average unit cost of sales was 6% higher due to the mix
of products delivered in the quarter.  
The net effect was a decrease of $7 million in gross profit for the
quarter. 
First nine months 
Production was 10.9 million kgU, 6% lower than the same period last
year. As a result of the planned reduction in production, results
will remain lower than comparable periods in 2011; production remains
on track for the year. 
Total revenue decreased by 11% due to a 9% decrease in sales volumes
and a 3% decline in the realized selling price.  
The total cost of sales (including D&A) decreased by 9% ($155 million
compared to $170 million in 2011) due to the decrease in the sales
volume. The average unit cost of sales was similar to the first nine
months of 2011.  
The net effect was a $6 million decrease in gross profit. 
Electricity results  
Third quarter 
Total electricity revenue increased by 6% this quarter compared to
the third quarter of 2011 due to higher output. Realized prices
reflect spot sales, revenue recognized under BPLP's agreement with
the OPA and financial contract revenue. BPLP recognized revenue of
$166 million this quarter under its agreement with the OPA, compared
to $119 million in the third quarter of 2011. About 72% of BPLP's
output was sold under financial contracts this quarter compared to
53% in the third quarter of 2011. From time to time BPLP enters the
market to lock in the gains under these contracts. Gains on BPLP's
contracting activity were slightly lower than in 2011.  
The capacity factor was 99% this quarter, up from 93% in the third
quarter of 2011 as a result of no planned outage days. Operating
costs were slightly lower at $223 million compared to $232 million in
2011. 
The result was a $11 million increase in our share of earnings before
taxes.  
BPLP distributed $95 million to the partners in the third quarter;
our share was $30 million. Also, BPLP made capital calls of $17
million to the partners in the third quarter; our share was $5
million. The partners have agreed that BPLP will distribute excess
cash monthly and will make separate cash calls for major capital
projects. 
First nine months 
Total electricity revenue for the first nine months increased 8%
compared to 2011 due to higher output and higher realized prices.
Realized prices reflect spot sales, revenue recognized under BPLP's
agreement with the OPA and financial contract revenue. BPLP
recognized revenue of $575 million in the first nine months of 2012
under its agreement with the OPA, compared to $351 million in the
first nine months of 2011. The equivalent of about 67% of BPLP's
output was sold under financial contracts in the first nine months of
this year, compared to 49% in 2011. From time to time BPLP enters the
market to lock in the gains under these contracts. Gains on BPLP's
contracting activity were slightly higher than in 2011. 
The capacity factor was 92% for the first nine months of this year,
up from 87% in the third quarter of 2011 due to a lower volume of
outage days during this year's planned outage compared to last year's
planned outage. Operating costs were lower at $668 million compared
to $735 million in 2011 mainly due to lower supplemental lease
payments and lower maintenance costs. These decreases were partially
offset by higher fuel costs in the first nine months of 2012.  
The result was a $50 million increase in our share of earnings before
taxes.  
BPLP distributed $285 million to the partners in the first nine
months of 2012; our share was $90 million. BPLP made capital calls of
$50 million to the partners in the first nine months of this year;
our share was $16 million. 
Operations and development project updates 
Uranium - production overview 


 
----------------------------------------------------------------------------
                           Three months               Nine months           
Cameco's share           ended September           ended September          
(million lbs U3O8)                    30                        30          
                        ----------------          ----------------          
                            2012    2011  change      2012    2011  change  
----------------------------------------------------------------------------
McArthur River/Key Lake      3.8     3.8       -      10.1    10.0       1% 
----------------------------------------------------------------------------
Rabbit Lake                  0.3     0.5     (40)%     2.1     2.2      (5)%
----------------------------------------------------------------------------
Smith Ranch-Highland         0.3     0.3       -       0.8     1.2     (33)%
----------------------------------------------------------------------------
Crow Butte                   0.2     0.2       -       0.6     0.6       -  
----------------------------------------------------------------------------
Inkai                        0.7     0.5      40%      1.8     1.8       -  
----------------------------------------------------------------------------
Total                        5.3     5.3       -      15.4    15.8      (3)%
----------------------------------------------------------------------------

 
McArthur River/Key Lake  
Production for the quarter and the first nine months was unchanged
compared to the same periods last year. We expect our share of
production this year to increase to 13.5 million pounds compared to
our previous forecast of 13.1 million pounds U3O8. 
Production varies from quarter to quarter depending on the sequencing
of mining raises and timing of maintenance shutdowns at the mill. 
At McArthur River, we have started to upgrade our electrical
infrastructure to address the future need for increase
d ventilation
and freeze capacity associated with mining new zones and increasing
mine production.  
At Key Lake, the new steam, oxygen and acid plants are operational.
We have started projects to replace the calciner and the electrical
substation. 
We continue to make excellent progress in flattening the slope of the
Deilmann tailings management facility pitwalls at Key Lake. The
project will reduce the risk of loss of tailings capacity due to
pitwall sloughing.  
We are continuing to advance work on the environmental assessment for
the Key Lake extension project. We have received comments from the
regulators on our draft environmental impact statement and are
working to address the questions and issues they have raised. We plan
to submit the final environmental impact statement in 2013. 
In cooperation with several uranium industry partners in
Saskatchewan, we have been working on a plan with the provincial
government to connect our McArthur River and Cigar Lake mine sites by
completing Highway 914 in the Athabasca Basin. This crucial
connection will expand access to milling infrastructure across the
northern part of the province, enhance transportation efficiency and
offer an alternate route in and out of northern Saskatchewan. The
Government of Saskatchewan has agreed to fund half of the cost of the
final road with the industry partners sharing the remaining half.  
Technical report 
We are updating the February 2009 McArthur River technical report to
reflect further advancements and changes to the McArthur River
operations since that time. We plan to file the updated technical
report during the fourth quarter. The highlights of the technical
report are: 


 
--  a 19% increase in our share of the mineral reserves estimate from 226.2
    million pounds at December 31, 2011 to 269.1 million pounds as of August
    31, 2012 due to a 22% addition in tonnage and a slight decrease in the
    estimated average grade. See McArthur River mineral reserves and mineral
    resources estimates table for more details. 
--  a decrease in the estimated average cash operating cost to about $19.23
    per pound over the life of the mine from about $19.69 per pound
    estimated in 2009, despite the escalating costs in the industry. See
    table titled McArthur River/Key Lake life of mine production, average
    unit operating costs and capital cost forecasts below for more details. 
--  a production rate increase to 22 million pounds per year scheduled for
    2018, subject to regulatory approval 
--  a mine life of at least 22 years, based on the planned production
    schedule 
--  our share of capital costs at McArthur River and Key Lake to 2034 is
    estimated at $2.5 billion compared to $1.4 billion in the previous
    report. More than 40% of this increase is related to the addition of
    more than 85 million pounds of new production since the 2009 technical
    report, and about 15% relates to expenditures required to allow
    production at a higher rate such as additional ventilation including the
    sinking of a fourth shaft. The remainder of the increase is related to
    expanding the infrastructure to support ongoing and expanded operations,
    and general cost escalation. We expect these changes will generate
    significant cash flows for years to come. 

 
McArthur River mineral reserves and mineral resources estimates 
(tonnes in thousands, pounds in millions) 


 
----------------------------------------------------------------------------
                                                                    Cameco's
                                                                    share of
                                               Grade     Content     content
(as at August 31, 2012)               Tonnes  % U3O8  (lbs U3O8)  (lbs U3O8)
----------------------------------------------------------------------------
Reserves                                                                    
----------------------------------------------------------------------------
  Proven                               384.4   23.81       201.8       140.8
----------------------------------------------------------------------------
  Probable                             677.8   12.30       183.7       128.3
----------------------------------------------------------------------------
Total proven and probable mineral                                           
 reserves                            1,062.2   16.46       385.5       269.1
----------------------------------------------------------------------------
Resources                                                                   
----------------------------------------------------------------------------
  Measured                              68.6    5.53         8.4         5.8
----------------------------------------------------------------------------
  Indicated                             15.5    9.97         3.4         2.4
----------------------------------------------------------------------------
Total measured and indicated                                                
 mineral resources                      84.1    6.35        11.8         8.2
----------------------------------------------------------------------------
Inferred mineral resources             325.0    7.86        56.3        39.3
----------------------------------------------------------------------------

 
Notes: 


 
--  Mineral reserves and mineral resources are reported separately. Mineral
    resources do not include amounts identified as mineral reserves.
    Reported mineral reserves have not been adjusted for estimated mill
    recovery of 98.7%. 
--  Our share of total mineral reserves and total mineral resources is
    69.805%. 
--  Inferred mineral resources have a great amount of uncertainty as to
    their existence and whether they can be mined legally or economically.
    It cannot be assumed that all or any part of the inferred mineral
    resources will be upgraded to a higher category. 
--  Mineral resources are estimated at a minimum mineralized thickness of
    1.0 metre and a minimum grade of 0.1% to 0.5% U3O8 assuming extraction
    by underground mining methods. Mineral reserves have been estimated at a
    cut-off grade of 0.77% U3O8. 
--  The geological model employed for McArthur River involves geological
    interpretations on section and plan derived from surface and underground
    drillhole information. 
--  Mineral reserves include allowances for dilution (20%) from backfill and
    mineralized waste mined and mining recovery (97.5%). Mineral resources
    do not include such allowances. 
--  Mineral reserves are estimated using the raisebore, boxhole and
    blasthole stope mining methods combined with freeze curtains.  
--  Mineral resources are estimated using a cross-sectional method and 3-
    dimensional block models. Mineral reserves are estimated using 3-
    dimensional block models. 
--  An average uranium price assumption of $61US/lb U3O8 and a fixed
    exchange rate of $1.00 US=$1.00 Cdn was used to estimate mineral
    reserves. The McArthur River mineral reserves are not significantly
    sensitive to variances in the uranium price of plus or minus $20
    provided that annual production remains above 10 million pounds U3O8.
    The price assumption is based on independent industry and analyst
    estimates of spot prices and the corresponding long-term prices and
    reflects our committed and uncommitted sales volumes. For committed
    sales volumes, the spot and term price assumptions were applied in
    accordance with the terms of the agreements. For uncommitted sales
    volumes the same price assumptions were applied using a spot-to-term
    price ratio of 60-40. 
--  No known metallurgical, environmental, permitting, legal, title,
    taxation, socio-economic, political, marketing or other issues are
    expected to materially affect the above estimates of mineral resources
    and mineral reserves. 
--
  Mineral resources that are not mineral reserves do not have demonstrated
    economic viability. Totals may not add due to rounding. 

 
McArthur River/Key Lake life of mine production, average unit
operating costs and capital cost forecasts 
(as per technical report) 


 
----------------------------------------------------------------------------
(as at January 1,                                                           
 2012)               2012   2013   2014   2015   2016   2017   2018     2019
----------------------------------------------------------------------------
Production                                                                  
 (million lbs)       13.5   13.2   13.1   13.1   13.1   13.1   15.4     15.4
----------------------------------------------------------------------------
Average operating                                                           
 cost ($Cdn/lb                                                              
 U3O8)              16.74  17.26  17.52  17.37  17.64  17.20  15.01    15.37
----------------------------------------------------------------------------
Total capital                                                               
 costs ($                                                                   
 millions)          189.3  235.0  285.8  236.8  214.2  151.8  168.7    134.2
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
(as at January 1,                                                           
2012)                2020   2021   2022   2023   2024   2025   2026     2027
----------------------------------------------------------------------------
Production                                                                  
 (million lbs)       15.4   15.4   14.9   14.9   14.9   14.9   14.7     13.5
----------------------------------------------------------------------------
Average operating                                                           
 cost ($Cdn/lb                                                              
 U3O8)              15.28  15.28  15.91  15.99  16.09  17.25  17.47    18.75
----------------------------------------------------------------------------
Total capital                                                               
 costs ($                                                                   
 millions)          107.5  109.7   89.6   67.8   65.9   67.5   52.2     58.2
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
(as at January 1,                                                           
2012)                2028   2029   2030   2031   2032   2033   2034    Total
----------------------------------------------------------------------------
Production                                                                  
 (million lbs)       13.3    7.2    7.2    7.1    7.1    4.4    4.5    279.1
----------------------------------------------------------------------------
Average operating                                                           
 cost ($Cdn/lb                                                              
 U3O8)              18.74  31.90  31.23  31.68  31.65  48.29  47.97    19.23
----------------------------------------------------------------------------
Total capital                                                               
 costs ($                                                                   
 millions)           55.0   40.2   40.8   36.2   28.5   17.6   11.9  2,464.4
----------------------------------------------------------------------------

 
Rabbit Lake  
Production remains on track for the year. 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.  
We completed the scheduled mill maintenance shutdown this quarter. A
short delay in restarting the mill resulted in slightly lower
production compared to the third quarter of 2011, although we are
maintaining our forecast production of 3.7 million pounds for the
year. 
We completed our surface exploration drilling program, which returned
positive results near the existing mining operations.  
Smith Ranch-Highland and Crow Butte 
At our US operations, production for the quarter was unchanged
compared to the third quarter of 2011. Production for the first nine
months was 33% lower compared to the same period last year due to
lower production from Smith Ranch-Highland in the first half of the
year. 
We have decreased our production forecast for the year by 17% to 2.0
million pounds based on the outlook for the approval of new mine
units. Our ability to bring new wellfields into production at Smith
Ranch-Highland continues to be affected by the lengthened review
process to obtain regulatory approvals. 
We received approval to produce from mine unit K-North at Smith
Ranch-Highland and continue to seek regulatory approvals to proceed
with the rest of our expansion plans. 
Inkai 
Production was 40% higher for the quarter and unchanged for the first
nine months compared to the same periods last year. We continue to
bring on additional wellfields to maintain some new, typically higher
grade, wellfields in the production mix. Production at the Inkai
operation steadily improved over the quarter and the facility is now
operating at design capacity.  
We continue to pursue government approval of an amendment to the
resource use contract in order to implement the production increase
from blocks 1 and 2 to 5.2 million pounds of U3O8 (100% basis). 
Delineation drilling at block 3 continues and construction of the
test leach facility is underway. 
On October 31, 2012, our board of directors approved a binding
memorandum of agreement (2012 MOA) with our joint venture partner
Kazatomprom setting out a framework to: 


 
--  increase Inkai's annual production from blocks 1 and 2 to 10.4 million
    pounds of uranium concentrate (our share 5.2 million pounds) and sustain
    it at that level 
--  extend the term of Inkai's resource use contract through 2045 

 
Kazatomprom is pursuing a strategic objective to develop uranium
processing capacity in Kazakhstan to complement its leading uranium
mining operations. The 2012 MOA builds on the non-binding memorandum
of understanding signed in 2007 to co-operate on the development of
uranium conversion capacity, with Kazatomprom's primary focus now
being on uranium refining rather than uranium conversion.  
The 2012 MOA strengthens our partnership with Kazatomprom and
includes a number of connected provisions relating to the increase of
Inkai's annual production and extension to the term of Inkai's
resource use contract. Under the terms of the 2012 MOA, we agree to: 


 
--  adjust our ownership interests in Inkai to 50% on an overall basis after
    achieving the production increase 
--  make two milestone payments of $34 million (US) each - the first after
    Inkai receives all necessary government approvals to increase uranium
    production to 10.4 million pounds (100%) annually through 2045, and the
    second after the increased production target is achieved 
--  pay to Kazatomprom a royalty of $5 (US) per pound of uranium concentrate
    on our share of production above 2.6 million pounds annually from Inkai
    once Inkai obtains all approvals required for the production increase to
    10.4 million pounds (100% basis) 
--  participate in the construction and operation of a uranium refinery in
    Kazakhstan with capacity to produce 6,000 tonnes of uranium (tU) as UO3
    annually, where we will own one third of the refinery and the remaining
    two thirds will be owned by Kazatompr
om, with construction to begin by
    2018 
--  provide Kazatomprom with a five-year option to license our proprietary
    uranium conversion technology for purposes of constructing and operating
    a UF6 conversion facility in Kazakhstan 
--  negotiate with Kazatomprom toward a conversion services agreement for up
    to 4,000 tU of conversion services annually and/or, for a three-year
    period, provide an opportunity for Kazatomprom to acquire a one-third
    interest in our conversion facility in Canada 

 
Under the 2012 MOA, the first steps will be to complete a feasibility
study for the production increase, and a prefeasibility study for the
uranium refinery. We agree to work with Kazatomprom to pace
investments for increasing uranium production to match progress on
the transfer of our uranium refining technology and construction of
the uranium refinery in Kazakhstan, subject to market conditions. 
Implementation of the 2012 MOA is subject to: 


 
--  further agreements on a number of issues including agreements governing
    the ownership, construction and operation of the uranium refinery in
    Kazakhstan 
--  approval by Kazatomprom's board of directors 
--  the receipt of all necessary Canadian and Kazakhstan governmental
    approvals including all licences and permits required to allow the
    transfer and licensing of our uranium refining technology 

 
Cigar Lake  
We continued to make solid progress at Cigar Lake this quarter. 
We have assembled the first jet boring system unit underground and
moved it to a production tunnel where we: 


 
--  have begun preliminary commissioning 
--  will begin systems testing 
--  will prepare to test in waste rock. 

 
In shaft 2 we are installing infrastructure, including a concrete
ventilation partition, electrical cable, water services, ore slurry
pipes and hoist systems.  
We will focus on carrying out the remainder of our 2012 plans and
implementing the strategies we outlined in our annual MD&A. We
continue to expect first commissioning in ore in mid-2013 and the
first packaged pounds in the fourth quarter of 2013. 
Cigar Lake is a key part of our plan to increase annual uranium
supply, and we are committed to bringing this valuable asset safely
into production. 
Millennium  
We have received comments from the regulators on our draft
environmental impact statement and are working to address the
questions and issues they have raised. We plan to submit the final
environmental impact statement in 2013.  
We completed the summer exploration drill program and successfully
identified additional mineralization at the unconformity.  
We will advance this project at a pace aligned with market
opportunities and economic circumstances. 
Kintyre  
On October 11, 2012 we announced the successful signing of a mine
development agreement with the Martu - a key activity in our project
planning. 
Based on our review of the current market environment, we will
complete the value engineering and the environmental permitting in
order to maintain the ability to proceed with the project should the
market factors improve the economics. However, we have decided not to
proceed with the detailed feasibility study at this time. 
Fuel services  
Fuel services produced 2.1 million kgU in the third quarter, 25%
lower than the same period last year. Production for the first nine
months of the year was 10.9 million kgU, 6% lower than the same
period last year. As a result of the planned reduction in production,
results will remain lower than comparable periods in 2011; however,
production remains on track for the year. 
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 
-- 
 Alain Mainville, director, mineral resources management, Cameco 
--  Les Yesnik, general manager, Key Lake, Cameco 
--  Gregory Murdock, technical manager, McArthur River, Cameco 

 
Cigar Lake 


 
--  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, will, intend, goal, target,
    forecast, 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
    curre
ntly 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, second and third
    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 MD&A 


 
--  the discussion under the heading Our strategy 
--  our plan for increasing annual uranium supply to 36 million pounds by
    2018, the expected sources for supply increases and expected production
    through 2016 at our uranium operations 
--  our expectations about future global uranium supply, consumption, demand
    and number of new reactors, including the discussion under the heading
    Uranium market update 
--  our expectation that our average realized uranium price will improve in
    the fourth quarter of 2012 
--  the outlook for each of our operating segments for 2012, and our
    consolidated outlook for the year 
--  our expectations regarding delivery patterns for our uranium and fuel
    service products 
--  our future plans for each of our uranium operating properties,
    development projects and projects under evaluation, and fuel services
    operating sites 
--  our expectations regarding timing for first commissioning in ore and
    first packaged pounds at Cigar Lake 
--  our expectation regarding production in our fuel services segment for
    2012 
--  our McArthur River mineral reserve and resource estimates 
--  our forecast of McArthur River production, operating and capital costs
    and mine life 

 
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 not reliable, or we face
    unexpected or challenging geological, hydrological or mining conditions 
--  we are affected by environmental, safety and regulatory risks, including
    increased regulatory burdens or delays 
--  we cannot obtain or maintain necessary permits or approvals from
    government authorities 
--  we are affected by political risks in a developing country where we
    operate 
--  we are affected by terrorism, sabotage, blockades, civil unrest,
    accident or a deterioration in political support for, or demand for,
    nuclear energy 
--  we are impacted by changes in the regulation or public perception of the
    safety of nuclear power plants, which adversely affect the construction
    of new plants, the relicensing of existing plants and the demand for
    uranium 
--  there are changes to government regulations or policies that adversely
    affect us, including tax and trade laws and policies  
--  our uranium and conversion suppliers fail to fulfill delivery
    commitments 
--  our Cigar Lake and McArthur River development, mining or production
    plans are delayed or do not succeed, including infrastructure expansion
    at McArthur River 
--  we are affected by natural phenomena, including inclement weather, fire,
    flood and earthquakes 
--  our operations are disrupted due to problems with our own or our
    customers' facilities, the unavailability of reagents, equipment,
    operating parts and supplies critical to production, equipment failure,
    lack of tailings capacity, labour shortages, labour relations issues,
    strikes or lockouts, underground floods, cave ins, ground movements,
    tailings dam failures, transportation disruptions or accidents, or other
    development and operating risks 

 
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 
--  our expectations regarding spot prices and realized prices for uranium,
    and other factors discussed in our third quarter MD&A 
--  our expectations regarding uranium sales contract terminations, tax
    rates, foreign currency exchange rates and interest rates 
--  our decommissioning and reclamation expenses 
--  our mineral reserve and resource estimates, and the assumptions upon
    which they are based, are reliable 
--  the geological, hydrological and other conditions at our mines 
--  the success of our Cigar Lake and McArthur River development, mining and
    production plans, including infrastructure expansion at McArthur River 
--  our ability to continue to supply our products and services in the
    expected quantities and at the expected times 
--  our ability to comply with current and future environmental, safety and
    other regulatory requirements, and to obtain and maintain required
    regulatory approvals 
--  our operations are not significantly disrupted as a result of political
    instability, nationalization, terrorism, sabotage, blockades, civil
    unrest, breakdown, natural disasters, governmental or political actions,
    litigation or arbitration proceedings, the unavailability of reagents,
    equipment, operating parts and supplies critical to production, labour
    shortages, labour relations issues, strikes or lockouts, underground
    floods, cave ins, ground movements, tailings dam failure, lack of
    tailings capacity, transportation disruptions or accidents or other
    development or operating risks 

 
Conference call 
We invite you to join our third quarter conference call on Thursday,
November 1, 2012 at 1:00 p.m. Eastern. 
The call will be open to all investors and the media. To join the
call, please dial (866) 226-1792 (Canada and US) or (416) 340-2216.
An operator will put your call through. A live audio feed of the
conference call will be available from a link at cameco.com. See the
link on our home page on the day of the call.  
A recorded version of the proceedings will be available: 


 
--  on our website, cameco.com, shortly after the call 
--  on post view until midnight, Eastern, December 1, 2012 
    by calling (800) 408-3053 or (905) 694-9451 (Passcode 3926907) 

 
Additional information 
You can find a copy of our third quarter MD&A and interim financial
statements on our website at cameco.com, on SEDAR at sedar.com and on
EDGAR at sec.gov/edgar.shtml. 
Additional information, including our 2011 annual management's
discussion and analysis, annual audited financial statements and
annual information form, is available on SEDAR at sedar.com, on EDGAR
at sec.gov/edgar.shtml and on our website at cameco.com. 
Profile 
We are one of the world's largest uranium producers, a significant
supplier of conversion services and one of two Candu fuel
manufacturers in Canada. Our competitive position is based on our
controlling ownership of the world's largest high-grade reserves and
low-cost operations. Our uranium products are used to generate clean
electricity in nuclear power plants around the world, including
Ontario where we are a limited partner in North America's largest
nuclear electricity generating facility. We also explore for uranium
in the Americas, Australia and Asia. Our shares trade on the Toronto
and New York stock exchanges. Our head office is in Saskatoon,
Saskatchew
an. 
As used in this news release, the terms we, us, our and Cameco mean
Cameco Corporation and its subsidiaries and affiliates unless stated
otherwise.
Contacts:
Cameco
Investor inquiries:
Rachelle Girard
(306) 956-6403 
Media inquiries:
Gord Struthers
(306) 956-6593
 
 
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