Cameco reports fourth quarter and 2012 financial results

Cameco reports fourth quarter and 2012 financial results 
SASKATOON, SASKATCHEWAN -- (Marketwire) -- 02/08/13 --  
ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED) 


 
--  achieved annual sales targets-record fourth quarter deliveries 
--  exceeded annual production target 
--  recorded a $168 million write-down on Kintyre project 
--  solid progress at Cigar Lake-on track for first production in 2013 
--  continued to grow the company by completing three key acquisitions 

 
Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated financial
and operating results for the fourth quarter and year ended December
31, 2012.  
"2012 was a busy and challenging year; but we again delivered solid
results," said Tim Gitzel, president and CEO. "Our focus in 2013 will
be on execution and reducing costs without compromising on our
values.  
"We are confident in a positive future for our industry based on its
fundamentals. On the demand side, new reactor construction continues
in China and there are strong indications that additional plants will
be coming back on line in Japan. On the supply side, about 24 million
pounds of annual uranium supply will be removed from the market after
2013 with the end of the Russian highly enriched uranium agreement.
We are also seeing new mine projects delayed or cancelled due to the
prevailing uncertainty in our markets. Cameco remains committed to
nuclear energy. We see a great opportunity to grow our business and
build value for shareholders and are working to realize it." 


 
HIGHLIGHTS                                      THREE MONTHS ENDED          
($ MILLIONS EXCEPT PER SHARE AMOUNTS)                  DECEMBER 31          
                                              ------------------------------
                                                    2012      2011  CHANGE  
----------------------------------------------------------------------------
Revenue                                              958       971      (1)%
----------------------------------------------------------------------------
Gross profit                                         307       353     (13)%
----------------------------------------------------------------------------
Net earnings attributable to equity holders           45       26
5     (83)%
----------------------------------------------------------------------------
 $ per common share (basic and diluted)             0.11      0.67     (84)%
----------------------------------------------------------------------------
Adjusted net earnings (non-IFRS, see Non-IFRS                               
 measures)                                           237       249      (5)%
----------------------------------------------------------------------------
 $ per common share (adjusted and diluted)          0.60      0.63      (5)%
----------------------------------------------------------------------------
Cash provided by operations (after working                                  
 capital changes)                                    283       258      10% 
----------------------------------------------------------------------------
Average        Uranium                                                      
 realized                      $US/lb              49.97     52.09      (4)%
 prices                                                                     
                                                                            
                               $Cdn/lb             49.37     53.08      (7)%
               -------------------------------------------------------------
               Fuel services   $Cdn/kgU            16.70     14.67      14% 
               -------------------------------------------------------------
               Electricity     $Cdn/MWh               54        53       2% 
----------------------------------------------------------------------------
 
HIGHLIGHTS                                              YEAR ENDED          
($ MILLIONS EXCEPT PER SHARE AMOUNTS)                  DECEMBER 31          
                                              ------------------------------
                                                    2012      2011  CHANGE  
----------------------------------------------------------------------------
Revenue                                            2,321     2,384      (3)%
----------------------------------------------------------------------------
Gross profit                                         723       776      (7)%
----------------------------------------------------------------------------
Net earnings attributable to equity holders          266       450     (41)%
----------------------------------------------------------------------------
 $ per common share (basic and diluted)             0.67      1.14     (41)%
----------------------------------------------------------------------------
Adjusted net earnings (non-IFRS, see Non-IFRS                               
 measures)                                           447       509     (12)%
----------------------------------------------------------------------------
 $ per common share (adjusted and diluted)          1.13      1.29     (12)%
----------------------------------------------------------------------------
Cash provided by operations (after working                                  
 capital changes)                                    644       745     (14)%
----------------------------------------------------------------------------
Average        Uranium                             47.62     49.17      (3)%
 realized                      $US/lb                                       
 prices                                                                     
                                                                            
                               $Cdn/lb             47.61     49.18      (3)%
               -------------------------------------------------------------
               Fuel services   $Cdn/kgU            17.24     16.71       3% 
               -------------------------------------------------------------
               Electricity     $Cdn/MWh               55        54       2% 
----------------------------------------------------------------------------

 
The 2012 annual financial statements have been audited; however, the
2011 and 2012 fourth quarter financial information presented is
unaudited. You can find a copy of our 2012 audited financial
statements on our website at cameco.com. Our 2012 annual management's
discussion and analysis (MD&A) will be posted on our website before
markets open on Monday, February 11, 2013.  
Starting in the first quarter of 2013, IFRS 11 - Joint Arrangements
requires that we account for our interest in Bruce Power Limited
Partnership (BPLP) using equity accounting. We will recast our
quarterly results for 2012 for comparative purposes.  
For the purposes of this document our interest in BPLP is presented
in accordance with the proportionate consolidation method. 
Full year  
Our net earnings attributable to equity holders (net earnings) were
$266 million ($0.67 per share diluted) compared to $450 million
($1.14 per share diluted) in 2011 mainly due to: 


 
--  a $168 million write-down of our investment in the Kintyre project 
--  lower earnings from our uranium business as a result of lower realized
    prices and an increase in the cost of product sold 
--  lower earnings from our fuel services business as a result of a decrease
    in sales volumes 
--  h
igher earnings from our electricity business due to higher generation
    and lower costs 
--  lower taxes due mainly to lower pre-tax earnings and a decrease in the
    expense recorded in 2012 related to our transfer pricing dispute with
    the Canadian Revenue Agency (CRA). See Consolidated outlook for details.

 
See 2012 Financial results by segment for more detailed discussion. 
Fourth quarter  
In the fourth quarter of 2012, our net earnings were $45 million
($0.11 per share diluted), a decrease of $220 million compared to
$265 million ($0.67 per share diluted) in 2011. This decline was
largely the result of the $168 million write-down of our interest in
the Kintyre project and lower earnings from our uranium business,
partially offset by stronger results in the electricity business.
Uranium profits were impacted by a 7% decline in the average realized
selling price due mainly to a lower spot price compared to the fourth
quarter of 2011. Earnings in the electricity business improved as a
result of higher generation and lower operating costs.  
The 5% decrease in adjusted net earnings in the quarter followed the
same trend as our net earnings, due to lower results in our uranium
business, partially offset by the results in our electricity
business.  
See 2012 Financial results by segment for more detailed discussion. 
Impairment charge on non-producing property  
During the fourth quarter of 2012, we recorded a $168 million
write-down of the carrying value of our interest in Kintyre, our
advanced uranium exploration project in Australia. Due to the
weakening of the uranium market since the asset was purchased in
2008, no increase in mineral resources in 2012 and the decision not
to proceed with the feasibility study, we concluded it was
appropriate to recognize an impairment charge for this asset. Kintyre
remains an important asset in our portfolio. However, given the
current state of the market, it was necessary to reduce its carrying
value at this time. The amount of the write-down was determined as
the excess of the carrying value over the fair value less cost to
sell based on the implied fair value of the resources in place using
comparable market transaction metrics. 
The nuclear energy industry today  
In last year's annual review of the uranium market, we indicated that
the near-term environment for the industry was challenging, but that
the long-term outlook remained very positive. We believe this
continues to be the case today.  
There was little improvement in 2012 over 2011 due to the lingering
effects of the events in Japan, as well as global economic slowdown.
However, we started to see some clarity on issues that have been
overhanging the market. The most significant of these was the
establishment in Japan of the Nuclear Regulatory Authority (NRA),
which is currently drafting new safety standards for the nuclear
industry in that country, against which reactor restarts will be
evaluated. The NRA indicated that this process would likely take
until mid-2013. While this means that reactor restarts will take
longer than we had previously thought, we believe that the NRA brings
important stability to the nuclear regulatory environment in Japan,
and welcome the clarity it has already brought to the issue of
reactor restarts.  
We believe the election of the Liberal Democratic Party (LDP) in
Japan will be similarly positive for the nuclear industry. Though it
remains to be seen what kind of energy policy will emerge from the
newly elected government, the LDP has been positively disposed
towards nuclear in the past, and has been clear that rebuilding
Japan's economy is its main priority, in which the nuclear industry
plays a large role.  
Later in 2012, China lifted a temporary moratorium on new reactor
construction and has since started construction on four reactors. The
resumption of reactor construction in China is clearly a positive
signal for the market.  
Beyond Japan and China, some other countries made changes to their
nuclear programs, including announcements of older reactor
retirements from Canada, France and Belgium. India also revised its
2020 nuclear target down from 20 to 14.6 gigawatts. These changes,
combined with slower than expected restarts in Japan, the temporary
pause in China new-build approvals, and slower economic growth
worldwide, caused us to re-examine our reactor forecast at the end of
2012. While the market continues to evolve, our current estimates
project nuclear generating capacity to reach about 510 gigawatts by
2022 from today's 392 gigawatts, which represents average annual
growth of 3%. Of this expected growth, approximately 64 new reactors
with 64 gigawatts of generating capacity are under construction
today.  
Reactor retirements and delays in both restarts and new construction
have had an effect on demand and the uranium price in 2012. There has
been concern that excess inventories resulting from reduced
requirements, deferrals and/or cancellations of deliveries under
sales contracts could be introduced to the market. In 2012, any
excess inventories have been responsibly managed between suppliers
and customers, but the situation has caused market participants to be
discretionary in their purchases and the uranium price to remain
depressed. This remains the case at the beginning of 2013, but we
believe the clearing of excess inventories, resumption of restarts in
Japan and new-build around the world, in addition to promising
supply-demand fundamentals, will lead to improved market conditions.
We also anticipate utilities will be ramping up contracting
activities well in advance of their requirements becoming uncovered
around 2016.  
The other side of the equation is supply, which saw a great deal of
destruction and deferral in 2012 as the uranium spot price remained
at a level well below where new projects are economic. A number of
uranium producers decreased their production growth plans, ourselves
included when we announced the adjustment to our growth plans from 40
million pounds annual production down to 36 million pounds of annual
supply by 2018.  
These challenges to primary supply occur while secondary supply is
decreasing as a result of the end of the Russian Highly Enriched
Uranium (HEU) commercial agreement in 2013, and while steady demand
growth continues - with an expectation that it will reach about 3%
per year.  
So, although the supply-demand outlook continues to evolve, nuclear
remains an important part of the global energy mix and it is clear
that new uranium supply will be needed. Though some of the future
supply gap could be filled by additions to secondary supplies, the
majority will need to come from new mines and expansions to existing
mines, which we expect will bring the economics of new production to
bear on the market.  
Outlook for 2013  
Over the next several years, we expect to invest significantly in
expanding production at existing mines and advancing projects,
subject to market conditions, 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 2013 capital requirements without the need for
significant additional funding. Cash balances will decline as we use
the funds in our business and pursue our growth plans.  
Our outlook for 2013 reflects the growth expenditures necessary to
help us achieve our strategy. We do not provide an outlook for the
items in the table that are marked with a dash.  
See Financial results by segment for details.  
2013 Financial outlook  
BPLP is not included in consolidated amounts due to a change in
accounting (see below). NUKEM is also excluded (see below). 


 
                     CONSOLIDATED URANIUM        FUEL SERVICES  ELECTRICITY 
----------------------------------------------------------------------------
Production           -            23.3 million   14 to 15       -           
                                  lbs            million kgU                
----------------------------------------------------------------------------
Sales volume         -            31 to 33       Increase       -           
                                  million lbs    0% to 5%                   
----------------------------------------------------------------------------
Capacity factor      -            -              -              88%         
----------------------------------------------------------------------------
Revenue compared to  Increase     Increase       Increase       Decrease    
 2012                0% to 5%     0% to 5%(1)    5% to 10%      5% to 10%   
----------------------------------------------------------------------------
Average unit cost of -            Increase       Decrease       Increase    
 sales(including                  0% to 5%(2)    0% to 5%       25% to 30%  
 depreciation and                                                           
 amortization (D&A))                                                        
----------------------------------------------------------------------------
Direct               Decrease     -              -              -           
 administration      0% to 5%                                               
 costs compared to                                                          
 2012(3)                                                                    
----------------------------------------------------------------------------
Exploration costs    -            Decrease       -              -           
 compared to 2012                 5% to 10%                                 
----------------------------------------------------------------------------
Tax rate             Recovery of  -              -              -           
                     15% to 20%                                             
----------------------------------------------------------------------------
Capital expenditures $655         -              -              $93 million 
                     million(4)                                 (our share) 
----------------------------------------------------------------------------
1   Based on a uranium spot price of $43.65(US) per pound (the Ux spot price
    as of February 4, 2013), a long-term price indicator of $56.00 (US) per 
    pound (the Ux long-term indicator on January 28, 2013) and an exchange  
    rate of $1.00 (US) for $1.00 (Cdn).                                     
2   This increase is based on the unit cost of sale for produced material   
    and committed long-term purchases. If we decide to make discretionary   
    purchases in 2013 then we expect the overall unit cost of product sold  
    to increase further.                                                    
3   Direct administration costs do not include stock-based compensation     
    expenses.                                                               
4   Does not include our share of capital expenditures at BPLP.             

 
Consolidated outlook  
Effective January 1, 2013, with the adoption of IFRS 11 - Joint
Arrangements, we will apply the equity method of accounting for our
interest in BPLP and will no longer consolidate our share of their
revenues. Our revenue outlook for 2013 does not include BPLP. For
comparative purposes, our revenue for 2012 was $1,851,000 excluding
BPLP. Furthermore, our outlook for 2013 presented below does not
include any revenues expected to be recognized through NUKEM (see
NUKEM Gmbh).  
We expect consolidated revenue to be up to 5% higher in 2013 due to: 


 
--  an increase in realized prices in the uranium business 
--  higher sales volumes in the fuel services business 
--  an increase in realized prices in the fuel services business 

 
We expect administration costs (not including stock-based
compensation) to be up to 5% lower than in 2012 due to expected
reductions in business development and corporate administrative
activities related to our adjusted growth plans.  
We expect exploration expenses to be about 5% to 10% lower than they
were in 2012 due to: 


 
--  decreased evaluation activities at Kintyre 
--  a general reorganization of our global exploration portfolio that has
    allowed us to focus on our core projects in Saskatchewan, the US,
    Kazakhstan and Australia 

 
In 2012, approximately $27 million in cash taxes became payable on
receipt of the reassessment of our 2007 tax return due to the ongoing
dispute with the Canada Revenue Agency (CRA) related to our transfer
pricing structure and methodology. The Canadian Income Tax Act
includes provisions that require certain companies to pay 50% of the
tax associated with disputed reassessments up front until the dispute
is settled. Until now, we have not been required to make any
significant cash payments due to the availability of elective
deductions and tax loss carryovers. We expect CRA will reassess our
tax returns for subsequent years on a similar basis and that these
will result in future cash payments on receipt of the reassessments.
See note 24 to the financial statements for more information.  
We have contractual arrangements to sell uranium produced at our
Canadian mining operations to a trading and marketing company located
in a foreign jurisdiction. These arrangements reflect the uranium
markets at the time they were signed, with the risk and benefit of
subsequent movements in uranium prices accruing to the foreign
trading and marketing company.  
On an adjusted net earnings basis, we expect a recovery of 15% to 20%
in 2013 from our uranium, fuel services and electricity segments, as
taxable income in Canada is expected to decline. Subject to our
success in the litigation with CRA, we expect our tax rate to
continue in accordance with the 2013 outlook until the contractual
arrangements noted above expire in 2016. As these arrangements expire
and are replaced by new contracts that reflect the uranium market at
the time of signing, our tax expense is expected to rise over time.  
First quarter 2013  
It is not our practice to provide earnings outlook. However, due to a
combination of factors expected to occur in the first quarter, we
have determined it appropriate to provide some outlook for investors
regarding our current expectations for our first quarter earnings.  
In our uranium and fuel services segments, our customers choose when
in the year to receive deliveries, so our quarterly delivery
patterns, sales volumes and revenue, can vary significantly. We
expect our uranium deliveries for the first quarter will be in the
range of 5 million to 6 million pounds, down considerably from the 8
million reported in the first three months of 2012. Uranium sales for
the balance of 2013 are expected to be more heavily weighted (approx.
60%) to the second half of the year. However, not all delivery
notices have been received to date, which could alter the delivery
pattern. Typically, we receive notices six months in advance of the
requested delivery date.  
In addition, BPLP has outages scheduled for three of its four units
in the first three months of 2013. Accordingly, we expect electricity
generation to be significantly lower in the first quarter of 2013
than it was in the first quarter of 2012. The capacity factor is
likely to be in the range of 75% to 80% and it is probable BPLP will
report an operating loss for the quarter.  
As a result, we expect our adjusted net earnings for the first
quarter of 2013 will be significantly lower than the $124 million
($0.31 per share) in the first quarter of 2012. We do not believe
that these factors will continue to have an impact on our adjusted
net earnings for subsequent quarters of 2013. The guidance we have
provided in the outlook table reflects our current expectations for
the full year. We also expect our net earnings attributable to equity
holders will be similarly impacted. 
Uranium outlook  
We expect to produce 23.3 million pounds in 2013 and have commitments
under long-term contracts to purchase 12 million pounds.  
Based on the contracts we have in place, we expect to sell between 31
million and 33 million pounds of U3O8 in 2013. We expect the unit
cost of sales to be up to 5% higher than in 2012. The increase is due
primarily to higher costs for produced material. If we decide to make
additional discretionary purchases in 2013, then we expect the
overall unit cost of sales to increase further.  
Based on current spot prices, revenue should be up to 5% higher than
it was in 2012 as a result of an expected increase in the realized
price. 
Price sensitivity analysis: uranium  
The table below is not a forecast of prices we expect to receive. The
prices we actually realize will be different from the prices shown in
the table. It is designed to indicate how the portfolio of long-term
contracts we had in place on December 31, 2012 would respond to
different spot prices. In other words, we would realize these prices
only if the contract portfolio remained the same as it was on
December 31, 2012, and none of the assumptions we list below change.  
We intend to update this table each quarter in our MD&A to reflect
deliveries made and changes to our contract portfolio each quarter.
As a result, we expect the table to change from quarter to quarter. 
Expected realized uranium price sensitivity under various spot price
assumptions  
(rounded to the nearest $1.00) 


 
SPOT PRICES                                                                 
($US/lb U3O8)            $20     $40     $60     $80    $100    $120    $140
----------------------------------------------------------------------------
2013                      43      46      53      61      69      77      83
----------------------------------------------------------------------------
2014                      45      48      56      64      73      82      89
----------------------------------------------------------------------------
2015                      41      46      56      66      76      86      95
----------------------------------------------------------------------------
2016                      43      48      58      69      80      90      98
----------------------------------------------------------------------------
2017                      42      47      57      67      78      87      95
----------------------------------------------------------------------------

 
The table illustrates the mix of long-term contracts in our December
31, 2012 portfolio, and is consistent with our contracting strategy.
It has been updated to December 31, 2012 to reflect: 


 
--  deliveries made and contracts entered into up to December 31, 2012 
--  our best estimate of future deliveries 

 
Our portfolio includes a mix of fixed-price and market-related
contracts, which we target at a 40:60 ratio. Those that are fixed at
lower prices or have low ceiling prices will yield prices that are
lower than current market prices. In 2012, a number of older
contracts expired and we are starting to deliver into more favourably
priced contracts.  
Our portfolio is affected by more than just the spot price. We made
the following assumptions (which are not forecasts) to create the
table: 
Sales 


 
--  sales volumes on average of 32 million pounds per year 

 
Deliveries  


 
--  customers take the maximum quantity allowed under each contract (unless
    they have already provided a delivery notice indicating they will take
    less) 
--  we defer a portion of deliveries under existing contracts for 2013 

 
Inflation  


 
--  is 2% per year 

 
Prices 


 
--  the average long-term price indicator is the same as the average spot
    price for the entire year (a simplified approach for this purpose only).
    Since 1996, the long-term price indicator has averaged 15% higher than
    the spot price. This differential has varied significantly. Assuming the
    long-term price is at a premium to spot, the prices in the table will be
    higher. 

 
Cameco's share of production - annual forecast to 2017 


 
CURRENT FORECAST (MILLION lbs)          2013    2014    2015    2016    2017
----------------------------------------------------------------------------
McArthur River/Key Lake                 13.2    13.1    13.1    13.1    13.1
----------------------------------------------------------------------------
Rabbit Lake                              4.2     4.2     4.2     4.2     4.2
----------------------------------------------------------------------------
US ISR                                   2.6     2.9     2.9     3.0     3.0
----------------------------------------------------------------------------
Inkai(1)                                 2.9     2.9     2.9     2.9     2.9
----------------------------------------------------------------------------
Cigar Lake                               0.3     1.8     5.5     7.9     8.2
----------------------------------------------------------------------------
Total share of production               23.2    24.9    28.6    31.1    31.4
----------------------------------------------------------------------------
Cameco's share of Inkai's production                                        
 on which profits are generated(2)                                          
----------------------------------------------------------------------------
Inkai(1)                                 3.0     3.0     3.0     3.0     3.0
----------------------------------------------------------------------------
Total(2)                                23.3    25.0    28.7    31.2    31.5
----------------------------------------------------------------------------
1   In 2011, we signed a memorandum of agreement (2011 MOA) with Kazatomprom
    to increase annual production to 5.2 million pounds (100% basis). Under 
    the 2011 MOA, we will have the right to purchase 2.9 million pounds of  
    Inkai's annual production and receive profits on 3.0 million pounds.    
2   We have adjusted the production table to reflect the share of Inkai's   
    production we will use to calculate our profits under the 2011 MOA, as  
    described in the note above.                                            

 
Our 2013 and future annual production targets for Inkai assume, and
we expect, that Inkai will obtain the necessary government permits
and approvals to produce at an annual rate of 5.2 million pounds
(100% basis), including an amendment to the resource use contract.  
There is no certainty Inkai will receive these permits or approvals.
If Inkai does not, or if the permits and approvals are delayed, Inkai
may be unable to achieve its 2013 and future annual production
targets and we may have to re-categorize some of Inkai's mineral
reserves as resources.  
This forecast is forward-looking information. It is based on the
assumptions and subject to the material risks discussed at the end of
this document, and specifically on the assumptions and risks noted
above and listed below. Actual production may be significantly
different from this forecast. 
Assumptions  


 
--  we achieve our forecast production for each operation, which requires,
    among other things, that our mining plans succeed, processing plants and
    equipment are available and function as designed, we have sufficient
    tailings capacity and our mineral reserve estimates are reliable 
--  we obtain or maintain the necessary permits and approvals from
    government authorities 
--  our production is not disrupted or reduced as a result of natural
    phenomena, labour disputes, political risks, blockades or other acts of
    social or political activism, shortage or lack of supplies critical to
    production, equipment failures or other development and operation risks 

 
Material risks that could cause actual results to differ materially 


 
--  we do not achieve forecast production levels for each operation because
    of a change in our mining plans, processing plants or equipment are not
    available or do not function as designed, lack of tailings capacity or
    for other reasons 
--  we cannot obtain or maintain necessary permits or approvals from
    government authorities 
--  natural phenomena, labour disputes (including an inability to renew
    agreements with unionized employees at McArthur River and Key Lake),
    political risks, blockades or other acts of social or political
    activism, shortage or lack of supplies critical to production, equipment
    failures or other development and operation risks disrupt or reduce our
    production 

 
Fuel services outlook  
In 2013, we plan to produce 14 million to 15 million kgU, and we
expect sales volumes to be up to 5% higher than in 2012. Overall
revenue is expected to increase by 5% to 10%, as a result of the
higher volumes and an expected increase in the average realized
price. We expect the unit cost of product sold (including D&A) to
decrease by 0% to 5%, therefore overall gross profit will increase as
a result. 
NUKEM Gmbh (NUKEM)  
On January 9, 2013, we completed the acquisition of NUKEM GmbH from
Advent International (Advent) and other shareholders. NUKEM is one of
the world's leading traders and brokers of nuclear fuel products and
services.  
NUKEM was acquired for cash consideration of EUR107 million ($140
million (US)), plus closing adjustments. We also assumed NUKEM's net
debt which amounted to about EUR84 million ($111 million (US)) on
January 9, 2013. Acquisition related costs of $4 million have been
expensed and included in administration expense in the consolidated
statement of earnings. We received the economic benefits of owning
NUKEM as of January 1, 2012, however, in accordance with accounting
requirements, our financial reporting will reflect results from
January 9, 2013 forward.  
The purchase agreement also includes an earn-out provision that could
provide Advent with a share of NUKEM's earnings under certain
conditions for the years 2012 through 2014. The earn-out is based on
NUKEM exceeding certain minimum threshold levels of EBITDA, as
specified and defined in the purchase agreement. The EBITDA is
derived from NUKEM's audited financial statements and the earn-out
payment to Advent is paid in the following year. For 2012, we
estimate the earn-out amount will be about $5 million (US).  
For accounting purposes, the purchase price is allocated to the
assets and liabilities acquired based on their fair values as of the
acquisition date (January 9, 2013). As the acquisition has closed
very recently, we have not yet finalized the allocation of the
purchase price. However, we expect that the majority of the purchase
price will be allocated to the purchase and sales contracts acquired,
nuclear fuel inventories, and goodwill. 
NUKEM outlook  
The requirement to assign fair values to the sales and purchase
contracts as of the acquisition date will impact the future operating
results reported for NUKEM. For example, NUKEM is a party to the
Russian HEU commercial agreement, which provides for the purchase of
uranium at a price well below the current market. We will assign a
portion of the purchase price to this contract. Our future cost of
sales will reflect the amortization of the value assigned to the
contract in the periods in which this HEU material is delivered. This
accounting will be applied to all contracts in the portfolio as of
the acquisition date. As a result, we expect the profit margins we
report for NUKEM will be in the range of 3% to 5% in 2013. We plan to
report NUKEM as a separate business segment.  
For 2013, NUKEM expects to deliver approximately 9 million to 11
million pounds of uranium and about 500,000 Separative Work Units
(enrichment), resulting in total revenues in the range of $500
million to $600 million. NUKEM expects to incur costs for
administration in the range of $10 million to $12 million. The
effective income tax rate is expected to be in the range of 30% to
35%. Operating cash flows are expected to be in the range of $100
million to $125 million. 
Electricity outlook  
Bruce Power estimates the average capacity factor for the four Bruce
B reactors to be 88% in 2013, and actual output to be about 5% to 10%
lower than it was in 2012 due to more planned outage days in 2013.
The 2013 realized price for electricity is projected to be slightly
lower than 2012. As a result we expect that revenue will decrease by
about 5% to 10%.  
We expect the average unit cost (net of cost recoveries) to be 25% to
30% higher in 2013 and total operating costs to increase by about 15%
to 20%, mainly due to more planned outages resulting in higher costs. 
In 2013, we will account for our interest in BPLP using equity
accounting. 
Capital spending  
Starting in 2013, we are classifying capital spending as sustaining,
capacity replacement or growth. As a mining company, sustaining
capital is the money we spend to keep our facilities running in their
present state, which would follow a gradually decreasing production
curve, while capacity replacement capital is spent to maintain
current production levels at those operations. Growth capital is
money we invest to generate incremental production, and for business
development. Previously, we categorized our capital spending as
either sustaining (which included capacity replacement projects) or
growth. 


 
(CAMECO'S SHARE IN $ MILLIONS)                        2012 PLAN  2012 ACTUAL
----------------------------------------------------------------------------
Growth capital                                                              
----------------------------------------------------------------------------
  Cigar Lake                                                215          231
----------------------------------------------------------------------------
  Inkai                                                      10            9
----------------------------------------------------------------------------
  McArthur River                                             35           32
----------------------------------------------------------------------------
  Millennium                                                  5            9
----------------------------------------------------------------------------
  US ISR                                                     30           48
----------------------------------------------------------------------------
Total growth capital                                        295          329
----------------------------------------------------------------------------
Sustaining capital                                                          
----------------------------------------------------------------------------
  McArthur River/Key Lake                                   145          154
----------------------------------------------------------------------------
  US ISR                                                     50           26
----------------------------------------------------------------------------
  Rabbit Lake                                                75           77
----------------------------------------------------------------------------
  Inkai                                                      30           15
----------------------------------------------------------------------------
  Fuel services                                              20           15
----------------------------------------------------------------------------
  Other                                                       5           15
----------------------------------------------------------------------------
Total sustaining capital                                    325          302
----------------------------------------------------------------------------
Talvivaara                                                    -           41
----------------------------------------------------------------------------
Total uranium & fuel services                            620(1)          672
----------------------------------------------------------------------------
Electricity (our 31.6% share of BPLP)                        80           62
----------------------------------------------------------------------------
1   We updated our 2012 capital cost estimate in the Q2 MD&A to $680 million
    and in the Q3 MD&A to $730 million.                                     

 
Capital expenditures were 5% above our 2012 plan, mainly due to
variances at Cigar Lake caused by a change in the timing of
expenditures and increased costs.  
We expect total capital expenditures for uranium and fuel services to
decrease by about 1% in 2013. 


 
(CAMECO'S SHARE IN $ MILLIONS)           2013 PLAN    2014 PLAN    2015 PLAN
----------------------------------------------------------------------------
Total uranium & fuel services                  650      600-650      550-600
----------------------------------------------------------------------------
  Sustaining capital                           200      300-320      290-310
----------------------------------------------------------------------------
  Growth capital                               310      175-190      140-155
----------------------------------------------------------------------------
  Capacity replacement capital                 140      125-140      120-135
----------------------------------------------------------------------------
Talvivaara                                       5                          
--------------------------------------------------                          
Total uranium & fuel services                  655                          
--------------------------------------------------                          
Electricity (our 31.6% share of BPLP)           93                          
--------------------------------------------------                          

 
We expect total capital expenditures for uranium and fuel services to
decrease by about 1% in 2013. 
Major sustaining, capacity replacement and growth expenditures in
2013 include: 


 
--  McArthur River/Key Lake - At McArthur River, the largest component is
    mine development at about $50 million. Other projects include upgrade of
    electrical infrastructure at about $40 million, as well as other site
    facility expansion and equipment purchases. At Key Lake, various
    projects to revitalize the mill will be undertaken at about $30 million,
    as well as upgrades to site electrical services and work on the tailings
    facilities. 
--  US in situ recovery (ISR) - Wellfield construction and well installation
    is the largest project at approximately $40 million. We also plan to
    continue work on the development of the North Butte project and
    revitalization of the processing plant. 
--  Rabbit Lake - At Eagle Point, the largest project includes mine
    development at about $15 million. Other projects include work on
    electrical systems, various mill equipment replacements and continued
    work on mine dewatering systems and tailings facilities. 
--  Cigar Lake - In order to bring Cigar Lake into production in 2013, we
    estimate our share of capital expenditures will be about $182 million,
    including $27 million on modifications to the McClean Lake mill. 

 
Our growth capital expenditures are related to our strategy to
increase annual supply to 36 million pounds by 2018 and maintain the
ability to respond quickly to changing market signals. The mix of
projects and their underlying capital estimates could change
significantly.  
This information regarding currently expected capital expenditures
for future periods is forward-looking information, and is based upon
the assumptions and subject to the material risks discussed at the
end of this document. Our actual capital expenditures for future
periods may be significantly different. 
Sensitivity analysis  
At December 31, 2012, every one-cent change in the value of the
Canadian dollar versus the US dollar would change our 2013 net
earnings by about $10 million (Cdn). This sensitivity is based on an
exchange rate of $1.00 (US) for $1.00 (Cdn).  
For 2013: 


 
--  a change of $5 (US) per pound in each of the Ux spot price ($43.65 (US)
    per pound on February 4, 2013) and the Ux long-term price indicator
    ($56.00 (US) per pound on January 28, 2013) would change revenue by $77
    million and net earnings by $44 million 
--  a change of $5/MWh in the electricity spot price would change our 2013
    net earnings by $2 million based on the assumption that the spot price
    will remain below the floor price of $51.62/MWh provided for under
    BPLP's agreement with the Ontario Power Authority (OPA) 

 
Non-IFRS measures - Adjusted net earnings  
Adjusted net earnings is a measure that does not have a standardized
meaning or a consistent basis of calculation under IFRS (non-IFRS
measure). We use this measure as a more meaningful way to compare our
financial performance from period to period. We believe that, in
addition to conventional measures prepared in accordance with IFRS,
certain investors use this information to evaluate our performance.
Adjusted net earnings is our net earnings attributable to equity
holders, adjusted to better reflect the underlying financial
performance for the reporting period. The adjusted earnings measure
reflects the matching of the net benefits of our hedging program with
the inflows of foreign currencies in the applicable reporting period,
and adjusted for impairment charges on non-producing properties.  
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.  
To facilitate a better understanding of these measures, the table
below reconciles adjusted net earnings with our net earnings for the
years ended 2012, 2011 and 2010, as reported in our financial
statements.  


 
($ MILLIONS)                                         2012     2011     2010 
----------------------------------------------------------------------------
Net earnings attributable to equity holders           266      450      516 
----------------------------------------------------------------------------
Adjustments                                                                 
----------------------------------------------------------------------------
  Adjustments on derivatives(1)(pre-tax)               17       80      (26)
----------------------------------------------------------------------------
  Income taxes on adjustments to derivatives           (4)     (21)       7 
----------------------------------------------------------------------------
  Impairment charge on non-producing property         168        -        - 
----------------------------------------------------------------------------
Adjusted net earnings                                 447      509      497 
----------------------------------------------------------------------------
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.                            
                                                                            
2012 financial results by segment                                           
                                                                            
Uranium                                                                     
                                                                            
                   THREE MONTHS ENDED                    YEAR ENDED         
HIGHLIGHTS                 DECEMBER 31                  DECEMBER 31         
                  ----------------------------------------------------------
                        2012      2011 CHANGE        2012      2011 CHANGE  
----------------------------------------------------------------------------
Production volume                                                           
 (million lbs)           6.5       6.6     (2)%      21.9      22.4     (2)%
----------------------------------------------------------------------------
Sales volume                                                                
 (million lbs)          14.4      13.8      4%       32.5      32.9     (1)%
----------------------------------------------------------------------------
Average spot price                                                          
 ($US/lb)              42.46     51.79    (18)%     48.40     56.36    (14)%
Average long-term                                                           
 price ($US/lb)        58.50     62.50     (6)%     60.13     66.79    (10)%
Average realized                                                            
 price                                                                      
($US/lb)               49.97     52.09     (4)%     47.62     49.17     (3)%
($Cdn/lb)              49.37     53.08     (7)%     47.61     49.18     (3)%
----------------------------------------------------------------------------
Average unit cost                                                           
 of sales                                                                   
 ($Cdn/lb)                                                                  
 (including D&A)       32.88     30.29      9%      32.09     29.94      7% 
----------------------------------------------------------------------------
Revenue ($                                                                  
 millions)               709       731     (3)%     1,546     1,616     (4)%
----------------------------------------------------------------------------
Gross profit ($                                                             
 millions)               237       314    (25)%       504       632    (20)%
----------------------------------------------------------------------------
Gross profit (%)          33        43    (23)%        33        39    (15)%
----------------------------------------------------------------------------

 
Fourth quarter  
Production volumes for the quarter decreased by 2% year over year.
See Operations and development projects for more information.  
Uranium revenues were down 3% due to a 7% decrease in the Canadian
dollar average realized price, partially offset by a 4% increase in
sales volumes.  
Our realized prices this quarter were lower than the fourth quarter
of 2011 mainly due to lower US dollar prices under market related
contracts. In the fourth quarter of 2012, the uranium spot price
averaged $42.46 (US), 18% lower than the $51.79 (US) in the fourth
quarter of 2011.  
Total cost of sales (including D&A) increased by 13% ($472 million
compared to $417 million in 2011). This was mainly the result of the
following:  


 
--  the 4% increase in sales volumes 
--  the 11% increase in average unit costs for produced uranium due to an
    increase in non-cash costs 
--  a 75% increase in the average unit costs for purchased uranium due to
    increased purchases at spot prices. In the fourth quarter of 2011, most
    of our purchases were under long-term contracts at more favourable fixed
    prices. 
--  lower royalty charges due to the lower realized price and reduced
    deliveries of Saskatchewan-produced material. In 2012, total royalty
    charges were $52 million compared to $61 million in 2011. 

 
The net effect was a $77 million decrease in gross profit for the
quarter. 
Full year  
Production volumes in 2012 were 2% lower than 2011 due to lower
production from Smith Ranch-Highland and McArthur River/Key Lake,
which had record production in 2011. See Operations and development
projects for more information.  
Uranium revenues this year were down 4% compared to 2011, due to a
slight decrease in sales volumes and a decrease of 3% in the Canadian
dollar average realized price. Our realized prices this year in US
dollars were 3% lower than 2011 mainly due to lower US dollar prices
under market-related contracts. The spot price for uranium averaged
$48.40 in 2012, a decline of 14% compared to the 2011 average price
of $56.36. Total cost of sales (including D&A) increased by 6% this
year ($1.0 billion compared to $984 million in 2011). This was mainly
the result of the following: 


 
--  average unit costs for produced uranium were 13% higher and average unit
    costs for purchased uranium were 9% higher due to an increase in spot
    purchases 
--  lower royalty charges in 2012 due mainly to the decline in the realized
    price. In 2012, total royalties were $116 million compared to $124
    million in 2011. 

 
The net effect was a $128 million decrease in gross profit for the
year.  
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 ENDED                  YEAR ENDED          
                           DECEMBER 31                  DECEMBER 31         
                  ----------------------------------------------------------
($CDN/lb)               2012      2011 CHANGE        2012      2011 CHANGE  
----------------------------------------------------------------------------
Produced                                                                    
  Cash cost            17.01     17.44     (2)%     19.95     18.45      8% 
  Non-cash cost         8.41      5.52     52%       8.13      6.50     25% 
----------------------------------------------------------------------------
  Total production                                                          
   cost                25.42     22.96     11%      28.08     24.95     13% 
----------------------------------------------------------------------------
  Quantity                                                                  
   produced                                                                 
   (million lbs)         6.5       6.6     (2)%      21.9      22.4     (2)%
----------------------------------------------------------------------------
Purchased                                                                   
  Cash cost            32.94     18.86     75%      28.50     26.08      9% 
----------------------------------------------------------------------------
  Quantity                                                                  
   purchased                                                                
   (million lbs)         2.8       2.3     22%       11.2       9.6     17% 
----------------------------------------------------------------------------
Totals                                                                      
  Produced and                                                              
   purchased costs     27.69     21.90     26%      28.22     25.29     12% 
----------------------------------------------------------------------------
  Quantities                                                                
   produced and                                                             
   purchased                                                                
   (million lbs)         9.3       8.9      4%       33.1      32.0      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 table
below presents a reconciliation of these measures to our unit cost of
sales for the years ended 2012 and 2011 as reported in our financial
statements. 


 
Cash and total cost per pound reconciliation                                
                                                                            
                                     THREE MONTHS ENDED          YEAR ENDED 
                                            DECEMBER 31         DECEMBER 31 
                                    ----------------------------------------
($ MILLIONS)                             2012      2011      2012      2011 
----------------------------------------------------------------------------
Cost of product sold                    390.7     336.8     871.3     824.3 
Add / (subtract)                                                            
  Royalties                             (51.7)    (61.3)   (116.0)   (123.6)
  Standby charges                        (7.7)     (6.0)    (28.6)    (22.0)
  Other selling costs                    (3.3)     (2.8)     (6.2)     (9.4)
  Change in inventories                (125.2)   (108.2)     35.6      (5.7)
----------------------------------------------------------------------------
Cash operating costs (a)                202.8     158.5     756.1     663.6 
Add / (subtract)                                                            
  Depreciation and amortization          81.3      80.1     170.9     159.2 
  Change in inventories                 (26.6)    (43.7)      7.2     (13.6)
----------------------------------------------------------------------------
Total operating costs (b)               257.5     194.9     934.2     809.2 
----------------------------------------------------------------------------
Uranium produced and purchased                                              
 (millions lbs) (c)                       9.3       8.9      33.1      32.0 
----------------------------------------------------------------------------
Cash costs per pound (a / c)            21.81     17.81     22.84     20.74 
Total costs per pound (b / c)           27.69     21.90     28.22     25.29 
----------------------------------------------------------------------------
                                                                            
Fuel services results                                                       
                                                                            
(includes results for UF6, UO2 and fuel fabrication)                        
                                                                            
                    THREE MONTHS ENDED                   YEAR ENDED         
HIGHLIGHTS                 DECEMBER 31                  DECEMBER 31         
                  ----------------------------------------------------------
                        2012      2011 CHANGE        2012      2011 CHANGE  
----------------------------------------------------------------------------
Production volume                                                           
 (million kgU)           3.3       3.1      6%       14.2      14.7     (3)%
----------------------------------------------------------------------------
Sales volume                                                                
 (million kgU)           5.9       7.2    (18)%      16.1      18.3    (12)%
----------------------------------------------------------------------------
Realized price                                                              
 ($Cdn/kgU)            16.70     14.67     14%      17.24     16.71      3% 
----------------------------------------------------------------------------
Average unit cost                                                           
 of sales                                                                   
 ($Cdn/kgU)                                                                 
 (including D&A)       13.44     11.18     20%      14.63     13.75      6% 
----------------------------------------------------------------------------
Revenue ($                                                                  
 millions)                99       106     (7)%       277       305     (9)%
----------------------------------------------------------------------------
Gross profit ($                                                             
 millions)                19        25    (24)%        42        54    (22)%
----------------------------------------------------------------------------
Gross profit (%)          19        24    (21)%        15        18    (17)%
----------------------------------------------------------------------------

 
Fourth quarter  
Total revenue decreased by 7% due to an 18% decrease in sales
volumes, offset by a 14% increase in realized price.  
The total cost of products and services sold (including D&A)
decreased by 2% ($79 million compared to $81 million in the fourth
quarter of 2011) due to the decrease in sales volumes, offset by an
increase in the average unit cost of sales. When compared to 2011,
the average unit cost of sales was 20% higher due to the mix of fuel
services products sold and to higher cost recoveries being recorded
in 2011.  
The net effect was a $6 million decrease in gross profit. 
Full year  
Total revenue decreased by 9% due to a 12% decrease in sales volumes.
We set lower sales target in 2012 due to weak market conditions at
the beginning of the year.  
The total cost of products and services sold (including D&A)
decreased by 6% ($235 million compared to $251 million in 2011) due
to the decrease in sales volumes. The average unit cost of sales was
6% higher due to higher unit costs for UF6 relating to lower
production.  
The net effect was a $12 million decrease in gross profit. 
Electricity results 
Fourth quarter  
Total electricity revenue increased 16% due to higher output and
slightly higher realized price. Realized prices reflect spot sales,
revenue recognized under BPLP's agreement with the OPA, and financial
contract revenue. BPLP recognized revenue of $198 million this
quarter under its agreement with the OPA, compared to $147 million in
the fourth quarter of 2011. The equivalent of about 58% of BPLP's
output was sold under financial contracts this quarter, compared to
66% in the fourth quarter of 2011. From time to time BPLP enters the
market to lock in gains under these contracts. Gains on BPLP's
contracting activity in the fourth quarter 2012 were similar to 2011. 
The capacity factor was 100% this quarter, up from 86% in the fourth
quarter of 2011. There were no outage days in the fourth quarter this
year compared to a planned outage in 2011.  
Operating costs were $221 million compared to $271 million in 2011
due to lower supplemental lease payments and lower maintenance costs
incurred as a result of no outages in the fourth quarter.  
The result was a 194% increase in our share of earnings before taxes. 
BPLP distributed $140 million to the partners in the fourth quarter.
Our share was $44 million. BPLP capital calls to the partners in the
fourth quarter were $14 million. Our share was $4 million. The
partners have agreed that BPLP will distribute excess cash monthly,
and will make separate cash calls for major capital projects. 
Full year  
BPLP's increased results in 2012 when compared to 2011 are partially
the result of revenues being 10% higher than in 2011 due to a 2%
increase in realized electricity prices. BPLP's average realized
price reflects spot sales, revenue recognized under BPLP's agreement
with the Ontario Power Authority (OPA) and revenue from financial
contracts.  
BPLP has an agreement with the OPA under which output from each B
reactor is supported by a floor price (currently $51.62/MWh) that is
adjusted annually for inflation. The floor price mechanism and any
associated payments to BPLP for the output from each individual B
reactor will expire on a date specified in the agreement. The expiry
dates are December 31, 2015 for unit B6, December 31, 2016 for unit
B5, December 31, 2017 for unit B7 and December 31, 2019 for unit B8.
Revenue is recognized monthly, based on the positive difference
between the floor price and the spot price. BPLP does not have to
repay the revenue from the agreement with the OPA to the extent that
the floor price for the particular year exceeds the average spot
price for that year.  
The agreement also provides for payment if the Independent
Electricity System Operator (IESO) reduces BPLP's generation because
Ontario's baseload generation supply is higher than required. The
amount of the reduction is considered 'deemed generation', for which
BPLP is paid either the spot price or the floor price-whichever is
higher. The deemed generation approach has provided the IESO with
significant flexibility in dealing with changes to the Ontario
electricity market in recent years. Deemed generation was 0.4 TWh in
2012, the same as in 2011.  
During 2012, BPLP recognized revenue of $773 million under the
agreement with the OPA, compared to $498 million in 2011.  
BPLP also has financial contracts in place that reflect market
conditions at the time they were signed. BPLP receives or pays the
difference between the contract price and the spot price. BPLP sold
the equivalent of about 64% of its output under financial contracts
in 2012, compared to 54% in 2011. From time to time, BPLP enters the
market to lock in gains under these contracts. Gains on BPLP's
contracting activity were slightly higher than in 2011.  
In addition, BPLP's increased results in 2012 when compared to 2011
were also partially the result of lower operating costs. BPLP's
operating costs were $889 million this year compared to $1.0 billion
in 2011 due to lower supplemental lease payments and lower
maintenance costs incurred during outage periods.  
The net effect was an increase in our share of earnings before taxes
of 90%.  
BPLP distributed $425 million to the partners in 2012. Our share was
$134 million. BPLP capital calls to the partners in 2012 were $63
million. Our share was $20 million. The partners have agreed that
BPLP will distribute excess cash monthly, and will make separate cash
calls for major capital projects.  
BPLP's capacity factor was 94% in 2012, up from 87% in 2011 due to a
lower volume of outage days during the year's planned outages
compared to last year's planned outages.  


 
                                                                            
Operations and development projects                                         
                                                                            
Uranium - production overview                                               
                                                                            
CAMECO'S SHARE              THREE MONTHS ENDED         YEAR ENDED           
(MILLION lbs)                      DECEMBER 31         DECEMBER 31 2012 PLAN
                          ----------------------------------------          
                                2012      2011      2012      2011          
----------------------------------------------------------------------------
McArthur River/Key Lake          3.5       3.9      13.6      13.9   13.5(1)
----------------------------------------------------------------------------
Rabbit Lake                      1.7       1.6       3.8       3.8       3.7
----------------------------------------------------------------------------
Smith Ranch-Highland             0.3       0.2       1.1       1.4    1.3(1)
----------------------------------------------------------------------------
Crow Butte                       0.2       0.2       0.8       0.8       0.7
----------------------------------------------------------------------------
Inkai                            0.8       0.7       2.6       2.5       2.5
----------------------------------------------------------------------------
Total                            6.5       6.6      21.9      22.4   21.7(1)
----------------------------------------------------------------------------
1   We updated our initial 2012 plan for McArthur River/Key Lake (to 13.5   
    million pounds from 13.1 million pounds) and Smith Ranch-Highland (to   
    1.3 million pounds from 1.6 million pounds) in our Q3 MD&A.             

 
McArthur River/Key Lake  
Our share of production in 2012 was 1% higher than our forecast for
the year and 2% lower than total production in 2011.  
At McArthur River and Key Lake we realized benefits under the
production flexibility amendments to the McArthur River and Key Lake
operating licences for the fourth consecutive year. Ongoing efforts
to improve the efficiency and reliability of the Key Lake mill
resulted in record mill performance.  
We have mitigated the risk to production in 2013 associated with the
transition to the upper mining area of zone 4. We have made
productivity improvements on cycle times, which include the use of
blasthole stoping in smaller, lower-grade areas of the mine located
away from the freezewalls. In addition, we have changed the
sequencing of the raises in zone 2, panel 5, which will improve
productivity.  
We continued drilling to install the freezewall in the upper mining
area of zone 4 north. We expect to finish installing brine
circulation lines and start freezing upper zone 4 north in 2013, and
begin production from this area in 2014.  
In addition to the underground work, we have started to upgrade our
electrical infrastructure on surface to address the future need for
increased ventilation and freeze capacity associated with mining new
zones and increasing mine production.  
In 2012, we completed the feasibility study on the McArthur River
extension project, and based on the positive results, revised our
mine plan to incorporate a mine expansion. This includes an increase
in our annual production rate to 22 million pounds U3O8 (100% basis)
by 2018, subject to receipt of regulatory approval.  
We were notified by the Canadian Nuclear Safety Commission (CNSC)
that the environmental assessment for the planned increase in
production would be transitioned to the CNSC licensing and compliance
processes rather than the federal environmental assessment process.
We are developing plans to complete this regulatory process.  
In addition, we must continue to successfully transition into new
mine areas through mine development and investment in support
infrastructure. As part of this multi-year project, we plan to: 


 
--  expand the freeze plant and electrical distribution systems 
--  increase ventilation by sinking a fourth shaft at the northern end of
    the mine 
--  improve our dewatering system and expand our water treatment capacity 

 
In 2012, we updated the McArthur River technical report. Highlights
included: 


 
--  a 19% increase in our share of the mineral reserves due to a 22%
    addition in tonnage and a slight decrease in the estimated average grade
--  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 
--  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 

 
In 2013, we plan to continue advancing the underground exploration
drifts to the southwest and northeast directions. Additional drilling
is planned underground to delineate zone A, and from surface to
identify additional mineral resources in the deposit.  
The Key Lake mill began operating in 1983. Mill production at Key
Lake is expected to closely follow McArthur River production, subject
to receipt of regulatory approval. As part of our Key Lake extension
environmental assessment, we are seeking approval to increase Key
Lake's nominal annual production rate to 25 million pounds U3O8 and
to increase our tailings capacity.  
The mill revitalization plan includes upgrading circuits with new
technology to simplify operations and improve environmental
performance. As part of this plan, we replaced the acid, steam and
oxygen plants.  
This year at Key Lake we: 


 
--  advanced the environmental assessment for the Key Lake extension project
    by submitting the draft environmental impact statement to the
    regulators, receiving their comments and providing responses 
--  began flattening the slope of the Deilmann tailings management facility
    pitwalls, relocating about 80% of the sand 

 
In 2013, at Key Lake, we expect to: 


 
--  complete installation and commissioning of a new electrical substation 
--  complete the structural steel work and equipment installation for a new
    calciner, to be commissioned in 2014 
--  complete flattening of the Deilmann tailings management facility
    pitwalls and begin constructing a buttress to prevent sand sloughing
    when the water level is raised 
--  advance the environmental assessment for the Key Lake extension project,
    by submitting the final environmental impact statement for review by the
    provincial and federal regulators and pursue the required regulatory
    approvals 

 
We will be applying for a renewal of our McArthur River and Key Lake
operating licences in 2013. The Canadian Nuclear Safety Commission
has scheduled a one-day hearing in the third quarter as part of the
application process. 
Inkai  
Production this year was 4% higher than our forecast for the year and
4% higher than production in 2011.  
We continued to bring on additional wellfields to maintain some new,
typically higher grade, wellfields in the production mix. The
processing plant has the capacity to produce at an annual rate of 5.2
million pounds (100% basis) depending on the grade of the production
solution. Production at Inkai steadily improved over the course of
the year and the facility is now operating at design capacity.
However, regulatory approval is required to carry out production at
the annual rate of 5.2 million pounds (100% basis).  
An amendment to Inkai's resource use contract was signed early in
2011, and Inkai received government approval to:  


 
--  increase annual production from blocks 1 and 2 to 3.9 million pounds
    (100% basis) 
--  carry out a five-year assessment program at block 3 that includes
    delineation drilling, uranium resource estimation, construction and
    operation of a test leach facility, and completion of a feasibility
    study 

 
In 2011, we also signed an MOA (2011 MOA) with our partner,
Kazatomprom, to increase production from blocks 1 and 2 to 5.2
million pounds (100% basis). Under the 2011 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.  
To implement the increase, we continue to await government approval
of an amendment to the resource use contract.  
In 2012, we entered into 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 (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, which sought to align the annual
production increase with the development of uranium conversion
capacity. Kazatomprom's primary focus is now 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 Kazatomprom, 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 
--  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 

 
In April 2012, Inkai received regulatory approval for the detailed
block 3 delineation and test leach work programs. Inkai continued
delineation drilling, started technological drilling of test
wellfields, continued with infrastructure development and started
construction of a test leach facility for the block 3 assessment
program. 
At block 3 in 2013, Inkai expects to: 


 
--  complete delineation drilling 
--  complete construction of the test leach facility and test wellfields 
--  extend power line to block 3 facilities 
--  start operation of the test wellfields 

 
Cigar Lake  
During the year, we: 


 
--  completed the sinking of shaft 2 to its final depth of 500 metres 
--  began installing shaft 2 infrastructure, including construction of a
    concrete ventilation partition, installation of electrical cable, water
    services, ore slurry pipes and hoist systems 
--  began commissioning of the surface ore loadout facility 
--  remediated a portion of an existing mine development tunnel and continue
    to explore ways to optimize our methods of ground support 
--  resumed underground development in the north end of the mine 
--  completed mine development on the 500 metre level 
--  replaced temporary contingency pumps with permanent infrastructure 
--  completed the Seru Bay pipeline 
--  completed all engineering designs and drawings for the project 
--  constructed the primary clarifier infrastructure 

 
We also assembled the first jet boring system unit underground and
moved it to a production tunnel where we: 


 
--  began preliminary commissioning and system testing 
--  established temporary infrastructure to support testing in waste rock 

 
As of December 31, 2012, we had: 


 
--  invested about $911 million for our share of the construction costs to
    develop Cigar Lake
--  expensed about $86 million in remediation expenses
--  expensed about $63 million in standby costs

 
Our total share of the capital cost for this project is about $1.1
billion since we began development in 2005. In order to bring Cigar
Lake into production in 2013, we estimate our share of capital
expenditures will be about $182 million, including $27 million on
modifications to the McClean Lake mill. Our share of standby charges
until production is achieved this year are estimated to be about $52
million. 
In 2013, we expect to: 


 
--  test the jet boring unit in waste and begin commissioning of the system 
--  complete the installation of all infrastructure required to begin
    production 
--  bring the mine into production in mid-2013 
--  produce the first packaged pounds from AREVA's McClean Lake mill in the
    fourth quarter 

 
We expect our share of production from Cigar Lake to be 0.3 million
pounds in 2013.  
We have submitted an operating licence application to the CNSC. The
CNSC will be holding a public hearing in the second quarter of 2013
as part of the process to obtain our operating licence. Our
construction licence is currently set to expire on December 31, 2013.
We anticipate that Cigar Lake will be in a position to start mining
in ore following the safe commissioning of the ore processing
circuits in mid-2013.  
Given the scale of this project and the challenging nature of the
geology and mining method, we have made significant progress. We will
continue to develop this asset in a safe and deliberate manner to
ensure we realize the economic benefits of this project. 
Fuel services  
Fuel services produced 14.2 million kgU, slightly higher than our
plan at the beginning of the year and 3% lower than 2011.  
In February, the CNSC approved a five-year operating licence for the
Port Hope conversion facility and a ten-year licence for CFM.  
Based on the current market for UF6 conversion, we do not anticipate
an extension of our toll conversion contract with SFL beyond 2016. We
remain fully committed to the current contract. If market conditions
improve over the next few years, we would consider resuming our
discussions to extend the contract.  
We have increased our production target for 2013 to between 15
million and 16 million kgU. 
Qualified persons  
The technical and scientific information discussed in this document
for our material properties (McArthur River/Key Lake, Inkai and Cigar
Lake) were approved by the following individuals who are qualified
persons for the purposes of NI 43-101: 
McArthur River/Key Lake 


 
--  David Bronkhorst, vice-president, Saskatchewan mining south, Cameco 
--  Les Yesnik, general manager, Key Lake, Cameco 

 
Cigar Lake 


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

 
Inkai 


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

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


 
--  It typically includes words and phrases about the future, such as:
    believe, estimate, anticipate, expect, plan, intend, 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 below, which may prove to be incorrect. 
--  Actual results and events may be significantly different from what we
    currently expect, due to the risks associated with our business. We list
    a number of these material risks below. We recommend you also review our
    most recent annual information form and management's discussion and
    analysis, which includes 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
    may not be appropriate for other purposes. We will not necessarily
    update this information unless we are required to by securities laws. 

 
Examples of forward-looking information in this document 


 
--  our expectations about 2013 and future global uranium supply,
    consumption, demand, number of operable reactors and nuclear generating
    capacity, including the discussion under the heading The nuclear energy
    industry today 
--  the outlook for each of our operating segments for 2013, and our
    consolidated outlook for the year 
--  our outlook for the first quarter of 2013 
--  our expectation that existing cash balances and operating cash flows
    will meet anticipated 2013 capital requirements without the need for any
    significant additional funding 
--  our expectation that cash balances will decline as we use the funds in
    our business and pursue our growth plans 
--  future tax payments and rates 
--  our uranium price sensitivity analysis 
--  our expectations for 2013, 2014 and 2015 capital expenditures 
--  forecast production at our uranium operations from 2013 to 2017 
--  our expectations about 2013 production at our fuel services operations 
--  our future plans for each of our uranium operating properties and
    development projects, and fuel services operating sites 
--  our expectations regarding Cigar Lake 
--  our expectations regarding the cash flows, profit margins, uranium
    deliveries, sales, revenues, costs, tax rates and profitability
    recognized by NUKEM in 2013 and in the future 

 
Material risks 


 
--  actual sales volumes or market prices for any of our products or
    services are lower than we expect for any reason, including changes in
    market prices or loss of market share to a competitor 
--  we are adversely affected by changes in foreign currency exchange rates,
    interest rates or tax rates, or we are unsuccessful in our dispute with
    tax authorities 
--  our production costs are higher than planned, or necessary supplies are
    not available, or not available on commercially reasonable terms 
--  our estimates of production, purchases, costs, decommissioning or
    reclamation expenses, or our tax expense estimates, prove to be
    inaccurate 
--  we are unable to enforce our legal rights under our existing agreements,
    permits or licences, or are subject to litigation or arbitration that
    has an adverse outcome 
--  there are defects in, or challenges to, title to our properties 
--  our mineral reserve and resource estimates are not reliable, or we face
    unexpected or challenging geological, hydrological or mining conditions 
--  we are affected by environmental, safety and regulatory risks, including
    increased regulatory burdens or delays 
--  we cannot obtain or maintain necessary permits or approvals from
    government authorities 
--  we are affected by political risks in a developing country where we
    operate 
--  we are affected by terrorism, sabotage, blockades, civil unrest, social
    or political activism, accident or a deterioration in political support
    for, or demand for, nuclear energy 
--  we are impacted by changes in the regulation or public perception of the
    safety of nuclear power plants, which adversely affect the construction
    of new plants, the relicensing of existing plants and the demand for
    uranium 
--  there are changes to government regulations or policies that adversely
    affect us, including tax and trade laws and policies 
--  our uranium and conversion suppliers fail to fulfill delivery
    commitments 
--  our Cigar Lake development, mining or production plans are delayed or do
    not succeed, including as a result of any difficulties encountered with
    the jet boring mining method or our inability to acquire any of the
    required jet boring equipment 
--  we are affected by natural phenomena, including inclement weather, fire,
    flood and earthquakes 
--  our operations are disrupted due to problems with our own or our
    customers' facilities, the unavailability of reagents, equipment,
    operating parts and supplies critical to production, equipment failure,
    lack of tailings capacity, labour shortages, labour relations issues
    (including an inability to renew agreements with unionized employees at
    McArthur River, Key Lake or the Port Hope Conversion facility), strikes
    or lockouts, underground floods, cave ins, ground movements, tailings
    dam failures, transportation disruptions or accidents, or other
    development and operating risks 
--  NUKEM's actual uranium sales volume, cash flows and earnings in 2013 and
    in the future are lower than expected due to losses in connection with
    spot market purchases, counterparty default on payment or other
    obligations, counterparty insolvency or other risks 
--  departure of key personnel at NUKEM could have an adverse effect on
    continuing operations 

 
Material assumptions 


 
--  our expectations regarding sales and purchase volumes and prices for
    uranium, fuel services and electricity 
--  our expectations regarding the demand for uranium, the construction of
    new nuclear power plants and the relicensing of existing nuclear power
    plants not being adversely affected by changes in regulation or in the
    public perception of the safety of nuclear power plants 
--  our expected production level and production costs 
--  the assumptions regarding market conditions upon which we have based our
    capital expenditure expectations 
--  our expectations regarding spot prices and realized prices for uranium,
    and other factors discussed in Price sensitivity analysis: uranium 
--  our expectations regarding tax rates and payments, the outcome of the
    dispute with tax authorities, foreign currency exchange rates and
    interest rates 
--  our decommissioning and reclamation expenses 
--  our mineral reserve and resource estimates, and the assumptions upon
    which they are based, are reliable 
--  the geological, hydrological and other conditions at our mines 
--  our Cigar Lake development, mining and production plans succeed,
    including the success of the jet boring mining method at Cigar Lake and
    that we will be able to obtain the additional jet boring system units we
    require on schedule 
--  our ability to continue to supply our products and services in the
    expected quantities and at the expected times 
--  our ability to comply with current and future environmental, safety and
    other regulatory requirements, and to obtain and maintain required
    regulatory approvals 
--  our operations are not significantly disrupted as a result of political
    instability, nationalization, terrorism, sabotage, blockades, civil
    unrest, social or political activism, equipment breakdown, natural
    disasters, governmental or political actions, litigation or arbitration
    proceedings, the unavailability of reagents, equipment, operating parts
    and supplies critical to production, labour shortages, labour relations
    issues (including an inability to renew agreements with unionized
    employees at McArthur River, Key Lake or the Port Hope Conversion
    facility), strikes or lockouts, underground floods, cave ins, ground
    movements, tailings dam failure, lack of tailings capacity,
    transportation disruptions or accidents or other development or
    operating risks 
--  NUKEM's actual uranium sales volume, cash flows and earnings in 2013 and
    in the future will be consistent with our expectations 
--  key personnel will remain with NUKEM 

 
Quarterly dividend notice  
We announced today that our board of directors approved a quarterly
dividend of $0.10 per share on the outstanding common shares of the
corporation that is payable on April 15, 2013, to shareholders of
record at the close of business on March 28, 2013. 
Conference call  
We invite you to join our fourth quarter conference call on Monday,
February 11, 2013 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 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, March 11, 2013 by calling (800)
    408-3053 (Canada and US) or (905) 694-9451 (Passcode 7039949#) 

 
Additional information  
Our 2012 annual management's discussion and analysis and annual
audited financial statements will be available shortly on SEDAR at
sedar.com, on EDGAR at sec.gov/edgar.shtml and on our website at
cameco.com. Our 2012 annual information form is expected to be
available later in February. 
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; however it does not include
NUKEM Gmbh, unless otherwise indicated.
Contacts:
Cameco
Investor inquiries:
Rachelle Girard
(306) 956-6403 
Cameco
Media inquiries:
Gord Struthers
(306) 956-6593