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Cameco reports fourth quarter and 2012 financial results
Published : February 09, 2013
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SASKATOON, SASKATCHEWAN--(Marketwire - Feb. 8, 2013) -

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 (News - Market indicators) (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
($ MILLIONS EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED
DECEMBER 31
    YEAR ENDED
DECEMBER 31
   
2012 2011 CHANGE   2012 2011 CHANGE  
Revenue 958 971 (1 )% 2,321 2,384 (3 )%
Gross profit 307 353 (13 )% 723 776 (7 )%
Net earnings attributable to equity holders 45 265 (83 )% 266 450 (41 )%
 $ per common share (basic and diluted) 0.11 0.67 (84 )% 0.67 1.14 (41 )%
Adjusted net earnings (non-IFRS, see Non-IFRS measures) 237 249 (5 )% 447 509 (12 )%
 $ per common share (adjusted and diluted) 0.60 0.63 (5 )% 1.13 1.29 (12 )%
Cash provided by operations (after working capital changes) 283 258 10 % 644 745 (14 )%
Average realized prices Uranium   $US/lb 49.97 52.09 (4 )% 47.62 49.17 (3 )%
$Cdn/lb 49.37 53.08 (7 )% 47.61 49.18 (3 )%
  Fuel services   $Cdn/kgU 16.70 14.67 14 % 17.24 16.71 3 %
  Electricity   $Cdn/MWh 54 53 2 % 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
  • higher 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 lbs 14 to 15 million kgU -
Sales volume   - 31 to 33 million lbs Increase
0% to 5%
-
Capacity factor   - - - 88%
Revenue compared to 2012   Increase
0% to 5%
Increase
0% to 5%1
Increase
5% to 10%
Decrease
5% to 10%
Average unit cost of sales(including depreciation and amortization (D&A))   - Increase
0% to 5%2
Decrease
0% to 5%
Increase
25% to 30%
Direct administration costs compared to 20123   Decrease
0% to 5%
- - -
Exploration costs compared to 2012   - Decrease
5% to 10%
- -
Tax rate   Recovery of
15% to 20%
- - -
Capital expenditures   $655 million4 - - $93 million
(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 (~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
Inkai1 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 generated2          
Inkai1 3.0 3.0 3.0 3.0 3.0
Total2 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 6201 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 derivatives1(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
 
HIGHLIGHTS THREE MONTHS ENDED
DECEMBER 31
      YEAR ENDED
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
DECEMBER 31
      YEAR ENDED
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
 DECEMBER 31
  YEAR ENDED
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)
 
HIGHLIGHTS THREE MONTHS ENDED
DECEMBER 31
      YEAR ENDED
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
(MILLION lbs)
THREE MONTHS ENDED
 DECEMBER 31
YEAR ENDED
DECEMBER 31
2012 PLAN
2012 2011 2012 2011
McArthur River/Key Lake 3.5 3.9 13.6 13.9 13.51
Rabbit Lake 1.7 1.6 3.8 3.8 3.7
Smith Ranch-Highland 0.3 0.2 1.1 1.4 1.31
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 21.71
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.



Cameco
Investor inquiries:
Rachelle Girard
(306) 956-6403
or
Cameco
Media inquiries:
Gord Struthers
(306) 956-6593
Data and Statistics for these countries : Japan | Kazakhstan | All
Gold and Silver Prices for these countries : Japan | Kazakhstan | All
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Cameco Corporation

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CODE : CCO.TO
ISIN : CA13321L1085
CUSIP : 13321L108
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In the News and Medias of Cameco Corporation
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TORONTO (CCO.TO)NYSE (CCJ)
18.65-2.86%16.57-3.10%
TORONTO
CA$ 18.65
10/22 15:59 -0.550
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Prev close Open
19.20 19.23
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18.62 19.39
Year l/h YTD var.
17.85 -  27.63 -14.09%
52 week l/h 52 week var.
17.85 -  27.63 -1.43%
Volume 1 month var.
2,083,791 -7.44%
24hGold TrendPower© : -13
Produces Cobalt - Copper - Nickel - Uranium - Zinc
Develops Uranium
Explores for Gold - Uranium
 
 
 
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2014-15.34%27.1921.06
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201019.92%38.7220.37
 
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