ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED)
-- delivered a strong fourth quarter-record revenue and gross profit from
our nuclear business
-- record annual revenue and gross profit from our nuclear business, and
record revenue and realized prices in our uranium segment
-- uranium production 3% higher than plan-on track with our Double U
strategy
-- matched our 2010 production record at McArthur River/Key Lake
-- continued progress at Cigar Lake-broke through on the 480 metre level,
putting it on the path to become another source of high-grade, low-cost
production
Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated
financial and operating results for the fourth quarter ended
December 31, 2011 and for the year.
"2011 was a challenging year for the nuclear industry," said CEO
Tim Gitzel. "However, it was business as usual for us, and in some
ways, even better than usual. We achieved a number of financial
records including record revenue and gross profit from our nuclear
business and record realized prices for uranium. At our operations
we delivered on a number of key milestones in a safe and
responsible manner.
"Looking forward, we remain confident in the long-term
fundamentals of the nuclear industry. With our extraordinary
assets, contract portfolio, employee expertise, industry knowledge
and financial strength, we are well positioned to meet the growing
demand for uranium and add value for our shareholders."
----------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
------------------ ------------------
Highlights($
millions except
per share amounts) 2011 2010 change 2011 2010 change
----------------------------------------------------------------------------
Revenue 977 673 45% 2,384 2,124 12%
----------------------------------------------------------------------------
Gross profit 353 252 40% 776 771 1%
----------------------------------------------------------------------------
Net earnings(1) 265 206 29% 450 516 (13)%
----------------------------------------------------------------------------
$ per common share
(basic and
diluted) 0.67 0.52 29% 1.14 1.31 (13)%
----------------------------------------------------------------------------
Adjusted net
earnings (non-
IFRS, see Non-IFRS
measures) 249 190 31% 509 497 2%
----------------------------------------------------------------------------
$ per common share
(adjusted and
diluted) 0.63 0.48 31% 1.29 1.26 2%
----------------------------------------------------------------------------
Cash provided by
operations (after
working capital
changes) 255 109 134% 732 521 40%
----------------------------------------------------------------------------
(1) Net earnings attributable to our shareholders.
The 2011 annual financial statements have been audited; however,
the 2010 and 2011 fourth quarter financial information presented is
unaudited. You can find a copy of our 2011 audited financial
statements on our website at cameco.com. Our 2011 annual
management's discussion and analysis (MD&A) will be posted on
our website on Thursday, February 9, 2012.
Transition to IFRS
On January 1, 2011, we adopted International Financial Reporting
Standards (IFRS) for Canadian publicly accountable enterprises. Our
financial statements have been prepared using IFRS. Amounts
relating to the year ended December 31, 2010 in this document and
our related financial statements have been revised using IFRS for
comparative purposes. Amounts for periods prior to January 1, 2010
are presented in accordance with Canadian GAAP in effect prior to
January 1, 2011.
Full year
Net earnings attributable to our shareholders (net earnings) for
the year were $450 million ($1.14 per share diluted) compared to
$516 million ($1.31 per share diluted) in 2010. In addition to the
items noted below, our net earnings were impacted by losses on
foreign exchange derivatives compared to gains in 2010.
On an adjusted basis, our earnings for the year were $509
million ($1.29 per share adjusted and diluted) compared to $497
million ($1.26 per share adjusted and diluted) (non-IFRS, see
Non-IFRS measures). The 2% increase resulted from:
-- higher earnings from our uranium business due to higher realized prices,
and an increase in sales volumes
partially offset by:
-- an increase in the cost of sales
-- lower earnings from our electricity business due to higher costs, lower
realized prices and lower sales volumes
-- lower earnings from our fuel services business resulting from higher
costs, partially offset by higher sales volumes
-- higher income taxes due to an increase in the provision related to our
transfer pricing dispute with the Canadian Revenue Agency (CRA)
See 2011 Financial results by segment for more detailed
discussion.
Fourth quarter
In the fourth quarter of 2011, our net earnings were $265
million ($0.67 per share diluted), an increase of $59 million
compared to $206 million ($0.52 per share diluted) in 2010. Uranium
revenues were up significantly due to an increase in sales volumes
and an increase in the average realized selling price, partially
offset by lower results in the electricity business due to lower
sales volumes and a lower realized price.
On an adjusted basis, our earnings this quarter were $249
million ($0.63 per share diluted) compared to $190 million ($0.48
per share diluted) (non-IFRS, see Non-IFRS measures) in the fourth
quarter of 2010. The 31% increase in adjusted net earnings in the
quarter followed the same trend as our net earnings, due to our
positive results in the uranium business partially offset by our
results in the electricity business.
See 2011 Financial results by segment for more detailed
discussion.
The nuclear energy industry today
The nuclear energy industry addressed significant challenges in
2011 related to events at the Fukushima-Daiichi nuclear power plant
in Japan. As a result, the outlook for the industry remains
uncertain for the near to medium term. In the long term, however,
we continue to see a very strong and promising growth profile for
the nuclear industry.
On March 11, an earthquake and tsunami in Japan caused cooling
systems at the Fukushima-Daiichi nuclear power station to fail, and
radioactive materials were released. This reduced public confidence
in nuclear power in some countries, most notably Germany, which
represents 5% of world nuclear generating capacity. It decided to
revert to its previous phase-out policy, shutting down eight of its
reactors, and plans to shut down the remaining nine reactors by
2022.
It remains unclear what level of nuclear power Japan
itself-which represents 12% of global nuclear generating
capacity-will depend on in the future. As of February 8, 2012,
Japan had three reactors operating. These three reactors are
scheduled to enter regular maintenance shutdowns between late
February and the end of April, at which time we expect all of
Japan's nuclear reactors will be offline. Many are unaffected by
the events in March 2011 but are offline for both planned and
unplanned maintenance outages, and diminished public support has
prevented utilities from gaining the regulatory and political
approvals necessary to restart them. The Japanese government has
ordered stress tests to be conducted on all reactors before
allowing them to restart, and is implementing reforms to its
existing nuclear regulatory framework and energy policy. Stress
tests are progressing, but the government has not made any final
decisions about restarting the reactors. Local government approval
will also likely be required to allow reactors to restart.
The current operating status of reactors in Germany and Japan
has caused concern that, in the near to medium term, additional
volumes could be introduced to the market from deferrals and/or
cancellations of deliveries under sales contracts. This has caused
market participants to be discretionary in their purchases. We
believe that utilities will continue to work with producers to
manage these materials and minimize the impact on the market.
Industry taking action
At the same time, the industry has taken action. Countries with
nuclear programs are reviewing regulatory standards, assessing the
safety of existing facilities and the design of reactors under
construction or in the planning stage. Third party organizations
such as the International Atomic Energy Association, Nuclear Energy
Institute, World Association of Nuclear Operators, Institute of
Nuclear Power Operators, and the World Nuclear Association are
lending their support and technical expertise to governments and
operators, and providing an accurate source of information for the
public.
Preliminary safety reviews are now complete and lessons are
being applied that we expect will make the industry even safer.
Most countries with nuclear generation capacity have reconfirmed
their commitment to the technology and to the future of nuclear
energy.
Long-term outlook is positive
Electricity is essential to maintaining and improving the
standard of living for people around the world. Demand for safe,
clean, reliable, affordable energy continues to grow and the need
for nuclear as part of the world's energy mix remains compelling.
We expect demand for uranium to grow, and along with it the need
for new supply to meet future customer requirements. You can read
more about our outlook on future supply and demand in our annual
MD&A.
Cameco well positioned
During this period of uncertainty, we are in the enviable
position of being heavily committed under long-term sales contracts
through 2016. As well, we have commitments to supply a total of
about 290 million pounds of uranium under all of our long-term
contracts, many of which extend beyond 2016. Therefore, we expect
to have a solid revenue stream for years to come, even in the event
of declining uranium market prices.
Outlook for 2012
Over the next several years, we expect to invest significantly
in expanding production at existing mines and advancing projects as
we pursue our growth strategy. The projects are at various stages
of development, from exploration and evaluation to
construction.
We expect our existing cash balances and operating cash flows
will meet our anticipated 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 2012 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.
2012 Financial outlook
----------------------------------------------------------------------------
Consolidated Uranium Fuel services Electricity
----------------------------------------------------------------------------
21.7 million 13 to 14
Production - lbs million kgU -
----------------------------------------------------------------------------
31 to 33 Decrease
Sales volume - million lbs 10% to 15% -
----------------------------------------------------------------------------
Capacity factor - - - 95%
----------------------------------------------------------------------------
Revenue compared to Decrease Decrease Decrease Increase
2011 0% to 5% 0% to 5%(1) 10% to 15% 5% to 10%
----------------------------------------------------------------------------
Average unit cost of Increase Increase Decrease
sales (including D&A) - 0% to 5%(2) 10% to 15% 5% to 10%
----------------------------------------------------------------------------
Direct administration
costs compared to Increase
2011(3) 10% to 15% - - -
----------------------------------------------------------------------------
Exploration costs Increase
compared to 2011 - 15% to 20% - -
----------------------------------------------------------------------------
Recovery of
Tax rate 0% to 5% - - -
----------------------------------------------------------------------------
$620
Capital expenditures million(4) - - $80 million
----------------------------------------------------------------------------
(1) Based on a uranium spot price of $52.00 (US) per pound (the
Ux Consulting spot price as of February 6, 2012), a long-term price
indicator of $61.00 (US) per pound (the Ux long-term indicator on
January 30, 2012) and an exchange rate of $1.00 (US) for $1.00
(Cdn).
(2) This increase is based on the unit cost of sale for produced
material and committed long-term purchases. If we decide to make
discretionary purchases in 2012 then we expect the average unit
cost of sales to increase further.
(3) Direct administration costs do not include stock-based
compensation expenses.
(4) Does not include our share of capital expenditures at
BPLP.
Consolidated outlook
We expect consolidated revenue to be 0% to 5% lower in 2012 due
to:
-- lower sales volumes in the fuel services business
-- lower realized prices in the uranium business
-- partially offset by higher volumes in the electricity business
We expect administration costs (not including stock-based
compensation) to be about 10% to 15% higher than in 2011 due to
planned higher spending in support of our growth strategy.
We expect exploration expenses to be about 15% to 20% higher
than they were in 2011 due to an increase in evaluation activities
at Kintyre and Inkai block 3. We will also continue to focus
efforts in Canada.
Uranium outlook
We expect to produce 21.7 million pounds in 2012. In addition,
we have commitments under long-term contracts to purchase about 8
million pounds.
Based on the contracts we have in place, we expect to sell
between 31 million and 33 million pounds of U3O8 in 2012. We expect
the average unit cost of sales to be 0% to 5% higher than in 2011.
The increase is due primarily to higher costs for produced
material. If we decide to make additional discretionary purchases
in 2012 then we expect the average unit cost of sales to increase
further.
Based on current spot prices, revenue should be about 0% to 5%
lower than it was in 2011 as a result of an expected decrease in
the realized price.
Our customers choose when in the year to receive deliveries of
uranium and fuel services products, so our quarterly delivery
patterns, and therefore our sales volumes and revenue, can vary
significantly. In 2012, we expect that deliveries will be evenly
distributed across the quarters. However, not all delivery notices
have been received to date, which could alter the delivery
pattern.
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, 2011 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, 2011, 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 $1.00)
----------------------------------------------------------------------------
($US/lb U3O8)
----------------------------------------------------------------------------
Spot prices $20 $40 $60 $80 $100 $120 $140
----------------------------------------------------------------------------
2012 38 42 50 57 66 74 81
----------------------------------------------------------------------------
2013 43 46 54 62 71 80 88
----------------------------------------------------------------------------
2014 45 48 56 65 74 83 91
----------------------------------------------------------------------------
2015 43 47 56 66 77 87 97
----------------------------------------------------------------------------
2016 45 50 58 68 78 88 97
----------------------------------------------------------------------------
The table illustrates the mix of long-term contracts in our
December 31, 2011 portfolio, and is consistent with our contracting
strategy. The table has been updated to December 31, 2011 to
reflect:
-- deliveries made and contracts entered into up to December 31, 2011
-- changes to deliveries under some sales contracts to assist our customers
who were directly impacted by the March nuclear incident in Japan
-- changes to deliveries under some contracts where deliveries are tied to
reactor requirements
Our portfolio includes a mix of fixed-price and market-related
contracts, which we target at a 40:60 ratio. We signed many of our
current contracts in 2003 to 2005, when market prices were low ($11
to $31 (US)). Those that are fixed at lower prices or have low
ceiling prices will yield prices that are lower than current market
prices. These older contracts are beginning to expire, 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 2012
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 14% 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.
-- we deliver all volumes that we do not have contracts for at the spot
price for each scenario
Inflation
-- is 3% per year
Cameco's share of production - annual forecast to 2016
We have geographically diverse sources of production. We are on
track with our strategy to increase our annual production to 40
million pounds by 2018, which we expect will come from our
operating properties, development projects and projects under
evaluation.
----------------------------------------------------------------------------
Current forecast(million lbs) 2012 2013 2014 2015 2016
----------------------------------------------------------------------------
McArthur River/Key Lake 13.1 13.1 13.1 13.1 13.1
----------------------------------------------------------------------------
Rabbit Lake 3.7 3.7 3.7 3.7 3.4
----------------------------------------------------------------------------
US ISR 2.4 3.0 3.1 3.7 3.8
----------------------------------------------------------------------------
Inkai(1) 2.5 2.9 2.9 2.9 2.9
----------------------------------------------------------------------------
Cigar Lake - 0.3 1.9 5.5 7.9
----------------------------------------------------------------------------
Total share of production 21.7 23.0 24.7 28.9 31.1
----------------------------------------------------------------------------
Cameco's share of Inkai's production on
which profits are generated(2)
----------------------------------------------------------------------------
Inkai(1) 2.6 3.0 3.0 3.0 3.0
----------------------------------------------------------------------------
Total(2) 21.8 23.1 24.8 29.0 31.2
----------------------------------------------------------------------------
(1) We have signed a memorandum of agreement (MOA) with
Kazatomprom to increase annual production to 5.2 million pounds
(100% basis). Once implemented, we will receive the right to
purchase 2.9 million pounds of Inkai's annual production and
receive profits on 3.0 million pounds. See Inkai for more
information.
(2) We have adjusted the production table to reflect the share
of Inkai's production we will use to calculate our profits under
the MOA. See Inkai for more information.
In 2013, production at McArthur River may be lower as we
transition to mining upper zone 4.
Our 2012 and future annual production targets for Inkai assume,
and we expect:
-- 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
-- we reach a binding agreement with Kazatomprom to finalize the terms of
the MOA
-- Inkai will ramp up production to an annual rate of 5.2 million pounds
(100% basis)
There is no certainty Inkai will receive these permits or
approvals or we will reach a binding agreement with Kazatomprom or
that Inkai will be able to ramp up production. If Inkai does not,
or if the permits and approvals are delayed, Inkai may be unable to
achieve its 2012 and future annual production targets and we may
have to recatagorize 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 under
Caution about forward-looking information 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, 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
Due to current unfavourable market conditions for UF6
conversion, we are decreasing our production in 2012. We plan to
produce between 13 million and 14 million kgU, and expect sales
volumes in 2012 to be 10% to 15% lower than in 2011.
We are changing our fuel services product mix in 2012, producing
and selling less UF6 than in 2011. We will also realize fewer 2012
cost recoveries in UF6 conversion. Therefore, in fuel services we
expect:
-- the average realized price for our fuel services products to increase by
0% to 5%
-- revenue to decrease by 10% to 15%
-- average unit cost of sales (including depreciation and amortization
(D&A)) to increase by 10% to 15%
Electricity outlook
Bruce Power estimates the average capacity factor for the four
Bruce B reactors to be 95% in 2012, and actual output to be about
9% higher than it was in 2011 due to fewer planned outage days in
2012. The 2012 realized price for electricity is projected to be
about the same as 2011. As a result, we expect that revenue will
increase by 5% to 10%.
We expect the average unit cost of sales (net of cost
recoveries) to be 5% to 10% lower in 2012 and total operating costs
to decrease by about 0% to 5%, mainly due to fewer planned outages
resulting in lower costs.
Capital spending
----------------------------------------------------------------------------
(Cameco's share in $ millions) 2011 plan 2011 actual 2012 plan
----------------------------------------------------------------------------
Growth capital
----------------------------------------------------------------------------
Cigar Lake 176 172 215
----------------------------------------------------------------------------
Inkai 9 1 10
----------------------------------------------------------------------------
McArthur River 14 24 35
----------------------------------------------------------------------------
Millennium 6 4 5
----------------------------------------------------------------------------
US ISR 13 15 30
----------------------------------------------------------------------------
Total growth capital 218 216 295
----------------------------------------------------------------------------
Sustaining capital
----------------------------------------------------------------------------
McArthur River/Key Lake 169 168 145
----------------------------------------------------------------------------
US ISR 38 39 50
----------------------------------------------------------------------------
Rabbit Lake 85 77 75
----------------------------------------------------------------------------
Inkai 19 15 30
----------------------------------------------------------------------------
Fuel services 32 18 20
----------------------------------------------------------------------------
Other 14 20 5
----------------------------------------------------------------------------
Total sustaining capital 357 337 325
----------------------------------------------------------------------------
Total uranium & fuel services 575(1) 553 620
----------------------------------------------------------------------------
Electricity (our 31.6% share of
BPLP) 80 77 80
----------------------------------------------------------------------------
(1) We updated our 2011 capital cost estimate in the Q1 MD&A
to $620 million, in the Q2 MD&A to $590 million and in the Q3
MD&A to $575 million.
Capital expenditures were 4% below the updated guidance we
provided in our third quarter MD&A, mainly due to variances at
Inkai and in the fuel services division. We do not expect this
reduction in capital expenditures in 2011 will impact our plans to
increase annual uranium production by 2018. The variance at fuel
services was mainly due to cancellation of certain projects and
revisions to project schedules. The variance at Inkai was mainly
due to the deferral of upgrades to infrastructure and slower than
expected progress on approvals for block 3.
We expect total capital expenditures for uranium and fuel
services to be about 12% higher in 2012 as a result of higher
spending for:
-- growth capital at Cigar Lake
-- growth and sustaining capital at US ISR
-- sustaining capital at Inkai
In addition, we expect capital expenditures for 2013 and 2014 to
be as follows:
----------------------------------------------------------------------------
($ millions) 2013 2014
----------------------------------------------------------------------------
Growth capital 325 - 350 250 - 275
Sustaining capital 325 - 350 350 - 375
----------------------------------------------------------------------------
Total uranium & fuel services 650 - 700 600 - 650
----------------------------------------------------------------------------
These growth capital expenditures are related to our Double U
strategy. Many of these are early stage projects, however, and the
mix of projects and their underlying capital estimates could change
significantly. This is a preliminary estimate that we expect to
fund using existing cash balances and operating cash flows.
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 factors
discussed under Caution about forward-looking information. Our
actual capital expenditures for future periods may be significantly
different.
Sensitivity analysis
At December 31, 2011, every one-cent change in the value of the
Canadian dollar versus the US dollar would change our 2011 net
earnings by about $10 million (Cdn). This sensitivity is based on
an exchange rate of $1.00 (US) for $1.02 (Cdn).
For 2012:
-- a change of $5 (US) per pound in each of the Ux spot price ($52.00 (US)
per pound on February 6, 2012) and the Ux long-term price indicator
($61.00 (US) per pound on January 30, 2012) would change revenue by $68
million and net earnings by $55 million.
-- a change of $5/MWh in the electricity spot price would change our 2012
net earnings by $4 million based on the assumption that the spot price
will remain below the floor price of $50.18/MWh provided for under
BPLP's agreement with the Ontario Power Authority (OPA).
Non-IFRS measures
Adjusted net earnings is a measure that does not have a
standardized meaning or a consistent basis of calculation under
IFRS (non-IFRS measure). We use this measure as a more meaningful
way to compare our financial performance from period to period. We
believe that, in addition to conventional measures prepared in
accordance with IFRS, certain investors use this information to
evaluate our performance. Adjusted net earnings is our net earnings
attributable to equity holders, adjusted to better reflect the
underlying financial performance for the reporting period. The
adjusted earnings measure reflects the matching of the net benefits
of our hedging program with the inflows of foreign currencies in
the applicable reporting period and adjusted for earnings from
discontinued operations. We also used this measure prior to
adoption of IFRS (non-GAAP measure).
Adjusted net earnings is non-standard supplemental information
and should not be considered in isolation or as a substitute for
financial information prepared according to accounting standards.
Other companies may calculate this measure differently so you may
not be able to make a direct comparison to similar measures
presented by other companies.
To facilitate a better understanding of these measures, the
table below reconciles adjusted net earnings with our net earnings
for the fourth quarters of 2011 and 2010 and the years ended 2011
and 2010 as reported in our financial statements.
----------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
----------------------------------------------------------------------------
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Net earnings 265 206 450 516
----------------------------------------------------------------------------
Adjustments
----------------------------------------------------------------------------
Adjustments on derivatives(1) (pre-
tax) (22) (22) 80 (26)
----------------------------------------------------------------------------
Income taxes on adjustments to
derivatives 6 6 (21) 7
----------------------------------------------------------------------------
Adjusted net earnings 249 190 509 497
----------------------------------------------------------------------------
(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 and losses on derivatives as reported
under IFRS to reflect what our earnings would have been had hedge
accounting been applied.
2011 financial results by segment
Uranium
----------------------------------------------------------------------------
Three months
ended Year ended
Highlights December 31 December 31
------------------ ------------------
2011 2010 change 2011 2010 change
----------------------------------------------------------------------------
Production volume
(million lbs) 6.6 6.4 3% 22.4 22.8 (2)%
----------------------------------------------------------------------------
Sales volume
(million lbs) 13.8 9.1 52% 32.9 29.6 11%
----------------------------------------------------------------------------
Average spot price
($US/lb) 51.79 58.29 (11)% 56.36 46.83 20%
Average long-term
price ($US/lb) 62.50 64.33 (3)% 66.79 60.92 10%
Average realized
price
($US/lb) 52.09 48.51 7% 49.17 43.63 13%
($Cdn/lb) 53.08 50.10 6% 49.18 45.81 7%
----------------------------------------------------------------------------
Average unit cost
of sales ($Cdn/lb)
(including D&A) 30.29 29.38 3% 29.94 27.87 7%
----------------------------------------------------------------------------
Revenue ($
millions) 731 457 60% 1,616 1,358 19%
----------------------------------------------------------------------------
Gross profit ($
millions) 314 189 66% 632 532 19%
----------------------------------------------------------------------------
Gross profit (%) 43 41 5% 39 39 -
----------------------------------------------------------------------------
Fourth quarter
Production volumes were 3% higher due to slightly higher output
at Rabbit Lake and Inkai, partially offset by slightly lower output
at McArthur River/Key Lake and Smith Ranch-Highland. See Operations
and development project updates for more information.
Uranium revenues were up 60% due to a 6% increase in the
Canadian dollar average realized price, and a 52% increase in sales
volumes.
Our realized prices this quarter were higher than the fourth
quarter of 2010 mainly due to higher US dollar prices under market
related contracts, partially offset by a less favourable exchange
rate. In the fourth quarter of 2011, our realized foreign exchange
rate was $1.02 compared to $1.03 in the prior year.
Total cost of sales (including D&A) increased by 56% ($417
million compared to $268 million in 2010). This was mainly the
result of the following:
-- the 52% increase in sales volumes
-- higher royalty charges due to higher deliveries of Saskatchewan-produced
material and higher realized prices
-- average unit costs for produced uranium were 2% higher
-- partially offset by 33% lower average unit costs for purchased uranium
due to fewer purchases at spot prices
The net effect was a $125 million increase in gross profit for
the quarter.
Full year
Production volumes in 2011 were 2% lower than 2010 due to lower
production from Smith Ranch-Highland and Inkai. See Operations and
development project updates for more information.
Uranium revenues this year were up 19% compared to 2010, due to
an 11% increase in sales volumes and an increase of 7% in the
Canadian dollar average realized price. Sales volumes in 2011 were
higher than 2010 due to some customers deferring 2010 deliveries
under contracts until 2011. The 19% increase was higher than the
guidance we provided in the third quarter (increase 10% to 15%) as
sales volumes for 2011 were at the top of the range provided (31
million pounds to 33 million pounds) at that time.
Our realized prices this year in US dollars were 13% higher than
2010 mainly due to higher US dollar prices under market-related
contracts. Our Canadian dollar selling price, however, was only 7%
higher than 2010 as a result of a less favourable exchange rate
when compared to 2010. Our exchange rate averaged $1.00 compared to
$1.05 in 2010.
Total cost of sales (including D&A) increased by 19% this
year ($983 million compared to $826 million in 2010). This was
mainly the result of the following:
-- the 11% increase in sales volumes
-- average unit costs for produced uranium were 7% higher, although our
average unit cost of sale for produced material was within the guidance
we provided
-- average unit costs for purchased uranium were 14% higher due to the
increase in spot prices
-- standby costs paid to AREVA relating to the McClean Lake mill
-- higher royalty charges due to higher deliveries of Saskatchewan-produced
material and higher realized prices. In 2011, total royalties rose to
$124 million from $78 million in 2010.
The net effect was a $100 million increase in gross profit for
the year.
The following table shows the costs of produced and purchased
uranium incurred in the reporting periods (non-IFRS measures, see
below). These costs do not include selling costs such as royalties,
transportation and commissions, nor do they reflect the impact of
opening inventories on our reported cost of sales.
----------------------------------------------------------------------------
Three months
ended Year ended
December 31 December 31
---------------- ----------------
($Cdn/lb) 2011 2010 change 2011 2010 change
----------------------------------------------------------------------------
Produced
Cash cost 17.44 15.94 9% 18.45 16.89 9%
Non-cash cost 5.52 6.52 (15)% 6.50 6.32 3%
----------------------------------------------------------------------------
Total production cost 22.96 22.46 2% 24.95 23.21 7%
----------------------------------------------------------------------------
Quantity produced
(million lbs) 6.6 6.4 3% 22.4 22.8 (2)%
----------------------------------------------------------------------------
Purchased
Cash cost 18.86 28.14 (33)% 26.08 22.85 14%
----------------------------------------------------------------------------
Quantity purchased
(million lbs) 2.3 4.3 (47)% 9.6 10.6 (9)%
----------------------------------------------------------------------------
Totals
Produced and purchased
costs 21.90 24.74 (11)% 25.29 23.10 9%
----------------------------------------------------------------------------
Quantities produced and
purchased (million
lbs) 8.9 10.7 (17)% 32.0 33.4 (4)%
----------------------------------------------------------------------------
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 fourth quarters of 2011 and 2010 and the
years ended 2011 and 2010 as reported in our financial
statements.
Cash and total cost per pound reconciliation
----------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
--------------------------------------------
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Cost of product sold 336.8 230.9 824.3 691.3
Add / (subtract)
Royalties (61.3) (18.2) (123.6) (78.2)
Standby charges (6.0) (6.4) (22.0) (12.0)
Other selling costs (2.8) (7.9) (9.4) (13.4)
Change in inventories (108.2) 24.6 (5.7) 39.6
----------------------------------------------------------------------------
Cash operating costs (a) 158.5 223.0 663.6 627.3
Add / (subtract)
Depreciation and amortization 80.1 37.3 159.2 134.9
Change in inventories (43.7) 4.4 (13.6) 9.2
----------------------------------------------------------------------------
Total operating costs (b) 194.9 264.7 809.2 771.4
----------------------------------------------------------------------------
Uranium produced and purchased
(millions lbs) (c) 8.9 10.7 32.0 33.4
----------------------------------------------------------------------------
Cash costs per pound (a / c) 17.81 20.84 20.74 18.78
Total costs per pound (b / c) 21.90 24.74 25.29 23.10
----------------------------------------------------------------------------
Fuel services results
(includes results for UF6, UO2 and fuel fabrication)
----------------------------------------------------------------------------
Three months
ended Year ended
December 31 December 31
---------------- ----------------
Highlights 2011 2010 change 2011 2010 change
----------------------------------------------------------------------------
Production volume
(million kgU) 3.1 3.9 (21)% 14.7 15.4 (5)%
----------------------------------------------------------------------------
Sales volume (million
kgU) 7.2 6.3 14% 18.3 17.0 8%
----------------------------------------------------------------------------
Realized price
($Cdn/kgU) 14.66 14.59 - 16.71 16.86 (1)%
----------------------------------------------------------------------------
Average unit cost of
sales ($Cdn/kgU)
(including D&A) 11.18 12.49 (10)% 13.75 13.05 5%
----------------------------------------------------------------------------
Revenue ($ millions) 106 91 16% 305 287 6%
----------------------------------------------------------------------------
Gross profit ($
millions) 25 13 92% 54 65 (17)%
----------------------------------------------------------------------------
Gross profit (%) 24 14 71% 18 23 (22)%
----------------------------------------------------------------------------
Fourth quarter
Production volumes were 21% lower than in 2010 due to the
decrease in production of UF6. We reduced our production forecast
in the third quarter as a result of unfavourable market
conditions.
Total revenue increased by 16% due to a 14% increase in sales
volumes and a slight increase in realized price.
The total cost of sales (including D&A) increased by 4% ($81
million compared to $78 million in the fourth quarter of 2010) due
to the increase in sales volumes. When compared to 2010, the
average unit cost of sales was 10% lower primarily due to higher
cost recoveries in 2011.
The net effect was a $12 million increase in gross profit.
Full year
Total revenue increased by 6% due to an 8% increase in sales
volumes.
The total cost of sales (including D&A) increased by 13%
($251 million compared to $222 million in 2010) due to the increase
in sales volumes. The average unit cost of sales was 5% higher due
to higher unit costs for UF6 relating to lower production.
The net effect was a $11 million decrease in gross profit.
Electricity results
Fourth quarter
Total electricity revenue decreased 14% due to lower output and
a lower realized price. Realized prices reflect spot sales, revenue
recognized under BPLP's agreement with the OPA, and financial
contract revenue. BPLP recognized revenue of $147 million this
quarter under its agreement with the OPA, compared to $114 million
in the fourth quarter of 2010. The equivalent of about 66% of
BPLP's output was sold under financial contracts this quarter,
compared to 45% in the fourth quarter of 2010. From time to time
BPLP enters the market to lock in gains under these contracts.
The capacity factor was 86% this quarter, down from 91% in the
fourth quarter of 2010 due to a higher volume of outage days during
the year's planned outages compared to last year's planned
outages.
Operating costs were $271 million compared to $225 million in
2010 due to higher maintenance costs incurred during outage periods
and increased staff costs.
The result was a 65% decrease in our share of earnings before
taxes.
BPLP distributed $65 million to the partners in the fourth
quarter. Our share was $21 million. BPLP capital calls to the
partners in the fourth quarter were $10 million. Our share was $3
million. The partners have agreed that BPLP will distribute excess
cash monthly, and will make separate cash calls for major capital
projects.
Full year
BPLP's results in 2011 are largely the result of lower revenues,
which were 10% lower than 2010 due to a 7% decrease in realized
electricity prices. BPLP's average realized price reflects spot
sales, revenue recognized under BPLP's agreement with the OPA and
revenue from financial contracts.
During 2011, BPLP recognized revenue of $498 million under the
agreement with the OPA, compared to $339 million in 2010.
BPLP also has financial contracts in place that reflect market
conditions at the time they were signed. Contracts signed in 2006
to 2008, when the spot price was higher than the floor price,
reflected the strong forward market at the time. BPLP receives or
pays the difference between the contract price and the spot price.
BPLP sold the equivalent of about 54% of its output under financial
contracts in 2011, compared to 42% in 2010. Pricing under these
contracts was lower than in 2010. From time to time, BPLP enters
the market to lock in gains under these contracts.
BPLP's operating costs were $1.0 billion this year compared to
$910 million in 2010 due to higher maintenance costs incurred
during outage periods and increased staff costs.
The net effect was a decrease in our share of earnings before
taxes of 47%.
BPLP distributed $270 million to the partners in 2011. Our share
was $85 million. BPLP capital calls to the partners in 2011 were
$21 million. Our share was $7 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 87% in 2011, down from 91% in 2010
due to a higher volume of outage days during the year's planned
outages compared to last year's planned outages.
Operations and development project updates
Uranium - production overview
----------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
------------------------------------------------------------------
Cameco's share (million
lbs) 2011 2010 2011 2010 2011 plan
----------------------------------------------------------------------------
McArthur River/Key Lake 3.9 4.0 13.9 13.9 13.3
----------------------------------------------------------------------------
Rabbit Lake 1.6 1.3 3.8 3.8 3.6
----------------------------------------------------------------------------
Smith Ranch-Highland 0.2 0.4 1.4 1.8 1.6
----------------------------------------------------------------------------
Crow Butte 0.2 0.2 0.8 0.7 0.7
----------------------------------------------------------------------------
Inkai 0.7 0.5 2.5 2.6 2.5
----------------------------------------------------------------------------
Total 6.6 6.4 22.4 22.8 21.7(1)
----------------------------------------------------------------------------
(1) We updated our 2011 plan in our Q3 MD&A to 21.7 million
pounds from 21.9 million pounds at the beginning of 2011.
McArthur River/Key Lake
Our share of production in 2011 was 5% higher than our target of
13.3 million pounds, and the same as 2010.
At McArthur River and Key Lake we matched our production record
set in 2010, realizing benefits under the production flexibility
amendments to the McArthur River and Key Lake operating licences.
Our revitalization program has improved the efficiency and
reliability of equipment at the Key Lake mill, which had record
monthly production in the latter part of the year.
We began drilling for the freezewall required to bring the upper
mining area of zone 4 into production and in 2012, we will continue
this drilling. We expect to start freezing upper zone 4 in 2013 and
begin production from this area in 2014.
The Key Lake revitalization plan includes upgrading circuits
with new technology to simplify operations and improve
environmental performance. After the mill is revitalized, annual
production will depend mainly on mine production. As part of this
plan, we replaced the acid, steam and oxygen plants.
At the end of 2011, construction of all three plants was
complete. The steam plant was commissioned at year end and the
oxygen plant was commissioned in early 2012. In 2012, we expect
to:
-- complete the commissioning of the new acid plant
-- begin work for the construction of a new electrical substation and
calciner
As part of the McArthur River extension, we advanced the
exploration drifts to zones A and B, north of current mining
operations, and were successful in upgrading the majority of the
zone B inferred mineral resources to the indicated category based
on surface drilling. This area continues to show promise. In
addition to exploration work, we advanced feasibility work on the
McArthur River extension project this year.
We are currently drafting the environmental impact study for the
Key Lake extension project for submission to the regulator as part
of the environmental assessment process. In 2011 we:
-- completed the detailed design for the stabilization of the Deilmann
tailings management facility pitwalls
-- relocated the infrastructure necessary to allow us to flatten the slope
of the pitwalls
-- continued our work on the environmental assessment
In 2012, for the Key Lake extension project, we expect to:
-- begin to flatten the slope of the Deilmann tailings management facility
pitwalls
-- advance the environmental assessment for the Key Lake extension project.
We expect to submit the draft environmental impact statement to the
regulators by the end of the second quarter. Comments on the draft are
expected before year end.
In 2012, we plan to continue advancing the underground
exploration drift to the south of the current mining areas. We also
plan to test, from surface, along the entire length of the
mineralized zone to identify additional mineral resources.
Inkai
Production this year was in line with the currently approved
production level, but about 4% lower than production in 2010. Lower
production was a result of in-process uranium inventory changes.
Prior to final commissioning of the processing facilities in 2010,
the in-process uranium inventory had built up. A significant
reduction of this inventory added to production in 2010.
In addition, production in 2010, the first full year of
operation, benefited from the higher grades associated with new
wellfields. Average grades at in situ recovery operations typically
stabilize at levels lower than initial years because uranium is
recovered from a mix of wellfields of varying maturities and, as
wellfields mature, the grades decrease. The processing plant has
the capacity to produce at an annual rate of 5.2 million pounds per
year (100% basis) depending on the grade of the production
solution. Inkai is planning to expand the existing satellite plant
capacity in order to support this production rate from lower grade
solution. Regulatory approval is required to carry out production
at the annual rate of 5.2 million pounds per year (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
We signed an MOA this year with our partner, Kazatomprom, to
increase production from blocks 1 and 2 to 5.2 million pounds (100%
basis). Under the MOA, our share of Inkai's annual production will
be 2.9 million pounds with the processing plant at full capacity.
We will also be entitled to receive profits on 3.0 million
pounds.
To implement the increase, we need a binding agreement
finalizing the terms of the MOA, government approval and an
amendment to the resource use contract.
Inkai continued delineation drilling, began infrastructure
development and completed engineering for a test leach facility for
the block 3 assessment program. Regulatory approval of the detailed
delineation and test leach work programs is required.
Cigar Lake
During 2011, we:
-- completed remediation of the underground
-- resumed underground construction in the south end of the mine
-- completed the sinking of shaft 2 to the 480 metre level in early 2012
-- substantially completed the ore loadout facility
-- procured additional equipment for the jet boring system
-- obtained regulatory approval to change the discharge location for the
release of treated water to Seru Bay of Waterbury Lake
-- obtained regulatory approval for the Cigar Lake mine plan
As of December 31, 2011, we had:
-- invested about $675 million for our share of the construction costs to
develop Cigar Lake
-- expensed about $86 million in remediation expenses, including about $4
million in 2011
-- expensed about $35 million in standby costs
We expect to spend an additional $484 million (our share) to
complete this project, which requires us to:
-- invest about $429 million for our share of the remaining capital costs,
bringing our total share to about $1.1 billion
-- expense about $55 million for our share of the remaining standby costs,
bringing our total share to about $90 million
This would bring our total share of the cost for this project to
about $1.3 billion since we began development in 2005.
We completed a surface drilling program this year, which
increased the mineral reserves and average ore grade slightly, and
extended the orebody further to the west. It also increased our
confidence in the geology and the grade we can expect during the
rampup period. We also initiated a drilling program to further
delineate the west end of the mineralization.
In 2012, we expect to:
-- complete the sinking of shaft 2 to its final depth of 500 metres
-- begin installing shaft 2 infrastructure, including construction of a
concrete ventilation partition, installation of electrical cable, water
services, ore slurry pipes and hoist systems
-- complete the surface ore loadout facility
-- resume underground development in the north end of the mine
-- move the jet boring system to site and begin testing underground
-- develop two mining tunnels using the mine development system
-- complete the Seru Bay pipeline
-- complete all engineering designs and drawings for the project
-- construct the clarifier
Cigar Lake continues to be a key part of our plan to increase
our annual production to 40 million pounds by 2018 and we are
pleased with the progress we are making to bring this valuable
orebody into production. Over the year, we implemented a number of
changes to the project, which have enhanced the overall economics
of the project. These changes have put Cigar Lake on the path to
becoming another high-grade, low-cost source of production, similar
to our McArthur River operation.
We are updating the March 2010 Cigar Lake technical report to
reflect these changes including the impact of the new milling
arrangement, surface freezing and other developments. We plan to
file the updated technical report with our February 2012 annual
information form. The highlights of the technical report are:
-- a decrease in the estimated average cash operating cost to about $18.60
per pound from about $23.10 per pound estimated in 2010. The reduction
is primarily due to the new milling arrangement.
-- an increase of about $190 million in our share of the total estimated
capital cost at completion to $1.1 billion. The increase is mainly due
to the implementation of the surface freeze strategy, general cost
escalation, costs to upgrade and expand the McClean Lake mill and
improvements to the mine plan.
-- a change to the production profile, with slightly lower production
expected in the first years of the project offset by higher production
in the later years. We expect our share of production in 2013 to be
about 0.3 million pounds. This compares to our previous estimate of 1
million pounds. This and the other revisions to our production schedule
on Cameco's share of production represent an 8.7% decrease in our
production forecast through 2016 and are a result of the extended
period required for remediation and a better understanding of the
geology and lower grades in the initial production panels.
-- first commissioning in ore expected in mid-2013 and the first pounds
expected to be packaged at the McClean Lake mill in the fourth quarter
-- rampup to the full production rate expected by the end of 2017
-- a 4% increase in our share of the mineral reserves estimate from 104.7
million pounds to 108.4 million pounds and an 8% increase in the
estimated average ore grade
-- an upgrade of probable mineral reserves to proven minerals reserves
Given the scale of this project and the challenging nature of
the geology and mining method, we have made significant
achievements since 2010. We will continue to develop this asset in
a safe and deliberate manner to ensure we realize the economic
benefits of this project.
Our expectations and plans regarding Cigar Lake, the expected
benefit of milling Cigar Lake ore at the McClean Lake mill, the
estimated average cash operating cost, our expected share of the
total project and capital cost at completion for Cigar Lake and our
mineral reserve estimate, are forward-looking information. They are
based on the assumptions and subject to the material risks
discussed under Caution about forward-looking information.
Fuel services
Fuel services produced 14.7 million kgU in 2011, slightly lower
than our plan at the beginning of the year and 5% lower than 2010.
In the third quarter, we reduced our production due to unfavourable
market conditions for UF6conversion.
Based on the unfavourable market conditions for UF6 conversion,
we have discontinued discussions to extend our toll conversion
contract with Springfields Fuels Limited 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.
Qualified persons
The technical and scientific information discussed in this
document, including mineral reserve and resource estimates, 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
-- Alain G. Mainville, director, mineral resources management, Cameco
-- David Bronkhorst, vice-president, Saskatchewan mining south, Cameco
-- Greg Murdock, technical superintendent, McArthur River, Cameco
-- Les Yesnik, general manager, Key Lake, Cameco
Inkai
-- Alain G. Mainville, director, mineral resources management, Cameco
-- Dave Neuburger, vice-president, international mining, Cameco
-- Lawrence Reimann, manager, technical services, Cameco Resources
Cigar Lake
-- Alain G. Mainville, director, mineral resources management, Cameco
-- Eric Paulsen, interim chief metallurgist, technology & innovation,
Cameco
-- Grant Goddard, vice-president, Saskatchewan mining north, Cameco
-- Scott Bishop, principal mine engineer, technology & innovation, 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, predict, goal,
target, project, potential, strategy and outlook (see examples below).
-- It represents our current views, and can change significantly.
-- It is based on a number of material assumptions, including those we have
listed below, which may prove to be incorrect.
-- Actual results and events may be significantly different from what we
currently expect, due to the risks associated with our business. We list
a number of these material risks below. We recommend you
also review our annual information form, 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 outlook for the nuclear energy industry, including the discussion on
the expected impact resulting from the March 2011 nuclear incident in
Japan and how Cameco is well positioned
-- the outlook for each of our operating segments for 2012, and our
consolidated outlook for the year
-- our expectation that we will invest significantly in expanding
production at our existing mines and advancing projects as we pursue our
growth strategy
-- our expectation that existing cash balances and operating cash flows
will meet anticipated capital requirements without the need for any
significant additional financing to reach this goal
-- our expectation that cash balances will decline as we use the funds in
our business and pursue our growth plans
-- our uranium price sensitivity analysis
-- forecast production at our uranium operations from 2012 to 2016
-- our statements regarding our target to increase annual uranium
production to 40 million pounds by 2018
-- our expectations for 2012, 2013 and 2014 capital expenditures
-- our expectations and plans for our McArthur River/Key Lake, Inkai and
Cigar Lake uranium properties
Material risks
-- actual sales volumes or market prices for any of our products or
services are lower than we expect for any reason, including changes in
market prices or loss of market share to a competitor
-- we are adversely affected by changes in foreign currency exchange rates,
interest rates or tax rates
-- our production costs are higher than planned, or necessary supplies are
not available, or not available on commercially reasonable terms
-- our estimates of production, purchases, costs, decommissioning or
reclamation expenses, or our tax expense estimates, prove to be
inaccurate
-- we are unable to enforce our legal rights under our existing agreements,
permits or licences, or are subject to litigation or arbitration that
has an adverse outcome
-- there are defects in, or challenges to, title to our properties
-- our mineral reserve and resource estimates are not reliable, or we face
unexpected or challenging geological, hydrological or mining conditions
-- we are affected by environmental, safety and regulatory risks, including
increased regulatory burdens or delays
-- we cannot obtain or maintain necessary permits or approvals from
government authorities
-- we are affected by political risks in a developing country where we
operate
-- we are affected by terrorism, sabotage, blockades, civil unrest,
accident or a deterioration in political support for, or demand for,
nuclear energy
-- we are impacted by changes in the regulation or public perception of the
safety of nuclear power plants, which adversely affect the construction
of new plants, the relicensing of existing plants and the demand for
uranium
-- there are changes to government regulations or policies that adversely
affect us, including tax and trade laws and policies
-- our uranium and conversion suppliers fail to fulfil 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
-- the new arrangement for milling Cigar Lake ore does not result in the
expected cost savings or other benefits
-- we are affected by natural phenomena, including inclement weather, fire,
flood and earthquakes
-- our operations are disrupted due to problems with our own or our
customers' facilities, the unavailability of reagents, equipment,
operating parts and supplies critical to production, equipment failure,
lack of tailings capacity, labour shortages, labour relations issues,
strikes or lockouts, underground floods, cave ins, ground movements,
tailings dam failures, transportation disruptions or accidents, or other
development and operating risks
Material assumptions
-- our expectations regarding sales and purchase volumes and prices for
uranium, fuel services and electricity
-- our expectations regarding the demand for uranium, the construction of
new nuclear power plants and the relicensing of existing nuclear power
plants not being 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
-- our expectations regarding spot prices and realized prices for uranium,
and other factors discussed on under Price sensitivity analysis:
uranium
-- our expectations regarding tax rates, foreign currency exchange rates
and interest rates
-- our decommissioning and reclamation expenses
-- our mineral reserve and resource estimates, 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
-- the new arrangement for milling Cigar Lake ore will result in the
expected reduction in the operating cost
-- our ability to continue to supply our products and services in the
expected quantities and at the expected times
-- our ability to comply with current and future environmental, safety and
other regulatory requirements, and to obtain and maintain required
regulatory approvals
-- our operations are not significantly disrupted as a result of political
instability, nationalization, terrorism, sabotage, blockades, civil
unrest, breakdown, natural disasters, governmental or political actions,
litigation or arbitration proceedings, the unavailability of reagents,
equipment, operating parts and supplies critical to production, labour
shortages, labour relations issues, strikes or lockouts, underground
floods, cave ins, ground movements, tailings dam failure, lack of
tailings capacity, transportation disruptions or accidents or other
development or operating risks
Conference call
We invite you to join our fourth quarter conference call on
Friday, February 10, 2012 at 11:00 a.m. Eastern.
The call will be open to all investors and the media. To join
the call, please dial (800) 355-4959 (Canada and US) or (416)
695-7848. 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 10, 2012 by calling (800)
408-3053 (Canada and US) or (905) 694-9451 (Passcode 7817583 #)
Additional information
Our 2011 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 February 2012 annual information form, along with
our Cigar Lake technical report are expected to be available next
week.
Profile
We are one of the world's largest uranium producers, a
significant supplier of conversion services and one of two Candu
fuel manufacturers in Canada. Our competitive position is based on
our controlling ownership of the world's largest high-grade
reserves and low-cost operations. Our uranium products are used to
generate clean electricity in nuclear power plants around the
world, including Ontario where we are a limited partner in North
America's largest nuclear electricity generating facility. We also
explore for uranium in the Americas, Australia and Asia. Our shares
trade on the Toronto and New York stock exchanges. Our head office
is in Saskatoon, Saskatchewan.
As used in this news release, the terms we, us, our and Cameco
mean Cameco Corporation and its subsidiaries and affiliates unless
stated otherwise.
Contacts: Cameco Investor inquiries: Rachelle Girard (306)
956-6403 Media inquiries: Gord Struthers (306) 956-6593
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