SASKATOON, SASKATCHEWAN--(Marketwired - Feb. 7, 2014) -
ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED)
- strong performance in a weak market
- delivered record annual consolidated revenue
- strong uranium segment results - record annual revenue and average realized price
- record quarterly and annual uranium production
- began jet boring in ore at Cigar Lake
- recorded a $70 million write-down on Talvivaara asset
- announced the sale of our interest in Bruce Power Limited Partnership
Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated financial and operating results for the fourth quarter and year ended December 31, 2013 in accordance with International Financial Reporting Standards (IFRS).
"2013 was a challenging year, but also a year in which Cameco was, again, able to demonstrate resilience and strength," said president and CEO, Tim Gitzel. "We were able to achieve record production and a number of record financial results, despite the continued uncertainty in the uranium market.
That uncertainty has lasted for longer than had been expected, and this year, we've moved away from our production target of 36 million pounds by 2018. Although we still have an extensive portfolio of assets from which we can increase our production, the market incentive must be there. We're confident this change will ensure we have the flexibility to remain competitive, create value for shareholders, and benefit when certainty and growth return to the market over the long term."
|HIGHLIGHTS||THREE MONTHS ENDED|
| ||YEAR ENDED|
|($ MILLIONS EXCEPT PER SHARE AMOUNTS)||2013||2012||CHANGE||2013||2012||CHANGE|
|Net earnings attributable to equity holders||64||41||56%||318||253||26%|
|$ per common share (basic and diluted)||0.16||0.10||60%||0.81||0.64||27%|
|Adjusted net earnings (see non-IFRS)||150||233||(36)%||445||434||3%|
|$ per common share (adjusted and diluted)||0.38||0.59||(36)%||1.12||1.10||2%|
|Cash provided by operations (after working capital changes)||154||286||(46)%||530||579||(8)%|
|Average realized prices||Uranium|| ||$US/lb||47.76||49.97||(4)%||48.35||47.72||1%|
| || || ||$Cdn/lb||49.80||49.37||1%||49.81||47.72||4%|
| ||Fuel services|| ||$Cdn/kgU||17.24||17.16||-||18.12||17.75||2%|
| ||NUKEM|| ||$Cdn/lb||41.84||-||-||42.26||-||-|
| ||Electricity|| ||$Cdn/MWh||54||54||-||54||55||(2)%|
The 2013 annual financial statements have been audited; however, the 2012 and 2013 fourth quarter financial information presented is unaudited. You can find a copy of our 2013 audited financial statements on our website at cameco.com. Our 2013 annual management's discussion and analysis (MD&A) will be posted on our website before markets open on Monday, February 10, 2014.
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. Our results for 2012 have been revised for comparative purposes.
Our net earnings attributed to equity holders (net earnings) were $318 million ($0.81 per share diluted) compared to $253 million ($0.64 per share diluted) in 2012, mainly due to:
- the impact of a one-time $168 million write-down of our investment in the Kintyre project in 2012
- higher earnings from our fuel services business as a result of an increase in sales volumes and realized prices
- lower exploration expenditures due to a decreased activity at our Kintyre project in Australia
- higher tax recoveries due to a decline in pre-tax earnings in Canada
partially offset by:
- lower earnings from our electricity business due to lower generation, a lower average realized price and higher costs
- a $70 million write-down of our Talvivaara asset due to their weakened financial position and pending corporate restructuring
- higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar
On an adjusted basis, our earnings were $445 million ($1.12 per share diluted) (see non-IFRS measure) compared to $434 million ($1.10 per share diluted) in 2012, mainly due to:
- addition of gross profit from NUKEM
- lower exploration costs due to a decrease in activity at our Kintyre project in Australia
- lower income taxes
partially offset by:
- lower earnings from our electricity business due to lower generation, a lower average realized price and higher costs
See 2013Financial results by segment for more detailed discussion.
In the fourth quarter of 2013, our net earnings were $64 million ($0.16 per share diluted), an increase of $23 million compared to $41 million ($0.10 per share diluted) in 2012, mainly due to:
- the impact of a one-time $168 million write-down of our investment in the Kintyre project in the fourth quarter of 2012
- lower exploration and administrative expenditures
- higher income tax recovery
- lower uranium gross profits due to lower sales volumes and higher average unit cost of sales
- a $70 million write-down of our Talvivaara asset, due to their weakened financial position and pending corporate restructuring
- higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar
On an adjusted basis, our earnings this quarter were $150 million ($0.38 per share diluted) compared to $233 million ($0.59 per share diluted) (see non-IFRS measure) in the fourth quarter of 2012, mainly due to:
- lower uranium gross profits due to lower sales volumes and higher average unit cost of sales
- lower exploration and administrative expenditures
- higher income tax recovery
See 2013Financial results by segment for more detailed discussion.
IMPAIRMENT CHARGE ON NON-PRODUCING ASSETS
During the fourth quarter of 2013, we recognized a $70 million impairment charge relating to our agreement with Talvivaara Mining Company Plc. to purchase uranium produced at the Sotkamo nickel-zinc mine in Finland. The impairment charge represents the full amount of our investment, which was used to cover construction costs, with the amount to be repaid through deliveries of uranium concentrate. The amount of the charge was determined as the excess of the carrying value over the fair value, less costs to sell. Due to Talvivaara's weak financial position and application to the Finnish government to undergo a corporate restructuring, as an unsecured creditor, we determined the fair value less costs to sell to be nil, and as such, recognized an impairment charge for the full amount of the asset.
The nuclear energy industry today
The long-term outlook for the uranium industry continues to be very positive, despite the uncertainty that exists today. Against the backdrop of the world's growing need for safe, clean, reliable and large-scale sources of energy, nuclear energy continues to play a significant role in the global energy mix. The challenge for the industry is the pathway and timing of the transition from today's stagnant, over-supplied short-term market to the promise of nuclear growth and positive uranium market conditions in the long term.
Market conditions deteriorated in 2013 and we believe the uncertainty could continue, depending on how events unfold. In particular, the slower than expected pace of Japanese reactor restarts, unexpected reactor shutdowns in the United States and temporary shutdowns in South Korea led to demand erosion. Compounding the issue, the supply side performed well: primary supply remained stable while secondary supply increased modestly, primarily due to enricher underfeeding. The impact of these conditions was the extension of the post-Fukushima inventory overhang and further downward price pressure.
This market dynamic also led to a reduction in market contracting activity. Utilities are well covered under long-term contracts for the time being and are not under pressure to buy. Similarly, existing suppliers appear reluctant to enter into meaningful contract volumes at current prices. The result was very low levels of long-term contracting in 2013-around 10% of current annual reactor consumption estimates, highlighting a cordial stalemate between buyers and sellers. How this stalemate is resolved between buyers and sellers will be a key factor influencing the pace of market recovery.
Looking beyond the current market challenges, there were several positive indications for the long term in 2013. In Japan, more clarity was gained around the process for reactor restarts: the Nuclear Regulatory Authority (NRA) implemented measures that improved regulatory stability; restart applications were submitted by seven utilities covering 16 reactors; and, there was observable confidence from Japanese utilities who are spending billions of dollars on plant upgrades in anticipation of a positive restart environment.
In other regions, China's remarkable nuclear growth program remains on track. Three more reactors were brought online, and construction began on four more in 2013. The United Kingdom (UK) also garnered positive attention as a result of a government-backed revenue arrangement with Électricité de France, designed to support new build there. Overall, the anticipated increase in nuclear plants from 433 (representing 394 gigawatts) today to 526 (representing 514 gigawatts) by 2023 illustrates a promising growth picture.
And it is clear that this growth will require new sources of uranium supply at a time when secondary supplies are diminishing and current market conditions have resulted in deferrals and cancellations of several uranium projects. Current prices are insufficient to incent new production. The end of the Russian Highly Enriched Uranium (HEU) commercial agreement in 2013, removing 24 million pounds of annual supply from the market, highlights the need for increasing reliance on primary uranium supply in the future. The timing of this required supply may well be muted in the near term due to the extension of the over-supply situation, but it remains clear new supply will be required this decade. The development and execution of new uranium supply projects, as well as continued performance of existing supply, will also play a significant role in determining the timing and pace of market recovery.
Our strategy remains focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. As a result of the longer-than-anticipated market uncertainty, we are adjusting our plans in line with this focus.
Market challenges have persisted since early 2011 and we expect they will continue for the near to medium term, depending on:
- the pace of Japanese reactor restarts
- how long it takes for excess supply to clear the market
- when long-term contracting resumes in meaningful quantities
- the development and execution of new uranium supply projects
- continued performance of existing supply
In this environment, a fixed production target is no longer appropriate; although we still have an extensive portfolio of assets from which we can increase production capacity, we have decided the prudent action is to eliminate our previous 2018 supply target of 36 million pounds. This will allow us increased flexibility in order to deliver the best value through this period of uncertainty, while at the same time retaining the ability to benefit when more certainty returns to the market environment, as we expect it will. Today, our strategy is to profitably produce at a pace aligned with market signals to increase long-term shareholder value.
We plan to:
- carry out all of our business with a focus on safety, people and the environment
- ensure continued reliable, low-cost production from our flagship operation, McArthur River/Key Lake and seek to expand that production
- ensure continued reliable, low-cost production at Inkai
- successfully bring on and ramp up production at Cigar Lake
- manage the rest of our production facilities and potential sources of supply in a manner that retains the flexibility to respond to market signals and take advantage of value adding opportunities within our own portfolio and the uranium market
- manage and allocate capital in a way that balances growing the long-term value of the business and returns to shareholders, while maintaining a strong balance sheet and our investment grade rating
Outlook for 2014
Our strategy is to profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.
Our outlook for 2014 reflects the 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.
2014 FINANCIAL OUTLOOK
Subject to closing, we sold our interest in BPLP effective December 31, 2013, and we will no longer provide an outlook for the electricity segment.
| || ||CONSOLIDATED|| ||URANIUM|| ||FUEL SERVICES|| ||NUKEM|
|Production|| ||-|| ||23.8 to 24.3|
| ||13 to 14|
|Sales volume|| ||-|| ||31 to 33|
5% to 10%
| ||9 to 11|
million lbs U3O8
|Revenue compared to 2013|| ||Increase|
0% to 5%
| ||Increase |
0% to 5%1
5% to 10%
| ||Increase |
0% to 5%
|Average unit cost of sales(including depreciation and amortization (D&A))|| ||-|| ||Increase|
0% to 5%2
0% to 5%
0% to 5%
|Direct administration costs compared to 20133|| ||Increase|
0% to 5%
| ||-|| ||-|| ||Increase|
0% to 5%
|Exploration costs compared to 2013|| ||-|| ||Decrease|
35% to 40%
| ||-|| ||-|
|Tax rate|| ||Recovery of|
30% to 35%
| ||-|| ||-|| ||Expense of|
30% to 35%
|Capital expenditures|| ||$495 million|| ||-|| ||-|| ||-|
|1||Based on a uranium spot price of $35.50(US) per pound (the Ux spot price as of February 3, 2014), a long-term price indicator of $50.00 (US) per pound (the Ux long-term indicator on January 27, 2014) and an exchange rate of $1.00 (US) for $1.03 (Cdn).|
|2||This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2014 then we expect the overall unit cost of sales to increase further.|
|3||Direct administration costs do not include stock-based compensation expenses. |
We expect consolidated revenue to be up to 5% higher in 2014 due to an increase in realized prices in our uranium business.
We expect administration costs (not including stock-based compensation) to be relatively stable (0% to 5% higher) compared to 2013, as restructuring efforts offset inflation.
We expect exploration expenses to be about 35% to 40% lower than they were in 2013 due to:
- decreased activities in Australia
- a general reorganization of our global exploration portfolio that has allowed us to focus on our core projects in Saskatchewan
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 tax recovery of 30% to 35% in 2014 from our uranium, fuel services and NUKEM segments, as taxable income in Canada is expected to decline. Subject to our success in the litigation with CRA, we expect our tax recovery to continue in accordance with the 2014 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.
We expect to produce 23.8 million to 24.3 million pounds in 2014 and have commitments under long-term contracts to purchase approximately 2 million pounds.
Based on the contracts we have in place, we expect to deliver between 31 million and 33 million pounds of U3O8 in 2014. We expect the unit cost of sales to be up to 5% higher than in 2013, primarily due to higher costs for produced material. In 2014, we will complete a number of capital projects at our various production facilities, including Cigar Lake. Upon completion, we will begin to depreciate the assets, which will increase the non-cash portion of our production costs. In addition, until Cigar Lake ramps up to full production, the cash cost of material produced from the mine will initially be higher. If we make additional discretionary purchases in 2014, 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 2013 as a result of an expected increase in the realized price.
In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns and, therefore, our sales volumes and revenue, can vary significantly. We expect that uranium deliveries in the first quarter of 2014 will be slightly higher than the first quarter of 2013, with about 20% of the year's deliveries scheduled for the first three months. We expect uranium deliveries for the balance of 2014 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.
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. The table is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2013 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, 2013, 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 |
The table illustrates the mix of long-term contracts in our December 31, 2013 portfolio, and is consistent with our marketing strategy. It has been updated to reflect deliveries made and contracts entered into up to December 31, 2013.
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.
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 volumes on average of 30 million pounds per year, with commitment levels through 2016 higher than in 2017 and 2018
- deliveries include best estimates of requirements contracts and contracts with volume flex provisions
- we defer a portion of deliveries under existing contracts for 2014
- is 1.5% in Canada and 2% per year in the US
- 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 17% 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.
On January 3, 2014, the government of Saskatchewan released regulations to implement the changes to the Saskatchewan uranium royalty system originally announced in the 2013 provincial budget.
The government has changed tiered royalties from a revenue-based system to a modified profit-based system, retroactive to January 1, 2013. Under the new system, a 10% royalty will be charged on profit up to and including $22/kg U3O8 ($9.98/lb), and a 15% royalty on profit in excess of $22/kg U3O8. Profit will be determined as revenue less certain operating, exploration, reclamation and capital costs (applied to Saskatchewan uranium production). Under the new system, both exploration and capital costs will be deductible at the discretion of the producer.
During the period from 2013 to 2015, transitional rules will apply whereby only 50% of capital costs will be deductible. The remaining 50% will be accumulated and deductible commencing in 2016. In addition, the capital allowance related to Cigar Lake under the previous system, will be grandfathered and deductible in 2016.
Also, as previously reported, the net basic royalty (basic royalty of 5% less the Saskatchewan resource credit) increased from 4.0% to 4.25% effective April 1, 2013. Other than the increase of the rate, there were no changes to the determination of the basic royalty, which continues to be levied by the province on the gross revenue from the sales of Saskatchewan uranium production.
LONG-TERM URANIUM PRODUCTION OUTLOOK
Although we have an extensive portfolio of assets from which we can increase our production capacity, we have eliminated our 2018 supply target of 36 million pounds in order to allow us to respond to market signals, and as a result, it is no longer appropriate to provide a long-term production forecast.
FUEL SERVICES OUTLOOK
In 2014, we plan to produce 13 million to 14 million kgU, and we expect sales volumes to be 5% to 10% lower than in 2013. Overall revenue is expected to decrease by 5% to 10% as a result of the lower sales volumes. We expect the unit cost of product sold (including D&A) to increase by 0% to 5%; therefore, overall gross profit will decrease as a result.
Much of the purchase price for NUKEM was related to nuclear fuel inventories and the portfolio of sales and purchase contracts acquired. The amounts attributed to inventory and contracts were based on market values as at the acquisition date. They will be charged to earnings in the period(s) in which related transactions occur. The amount categorized as goodwill reflects the value assigned to the expected future earnings capabilities of the organization. This is the earnings potential that we anticipate will be realized through new business arrangements. Goodwill is not amortized and is tested for impairment at least annually.
For 2014, NUKEM expects to deliver between 9 million and 11 million pounds of uranium, resulting in an increase in total revenues of up to 5% compared to 2013. NUKEM expects to incur administration costs similar to 2013. The effective income tax rate is expected to remain in the range of 30% to 35%.
We classify 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.
|CAMECO'S SHARE ($ MILLIONS)||2013 PLAN||2013 ACTUAL||2014 PLAN|
|Sustaining capital|| || || |
| ||McArthur River/Key Lake||55||64||30|
| ||Cigar Lake||-||-||15|
| ||Rabbit Lake||70||50||40|
| ||US ISR||5||5||5|
| ||Fuel services||10||8||10|
|Total sustaining capital||170||137||115|
|Capacity replacement capital|| || || |
| ||McArthur River/Key Lake||75||73||60|
| ||Cigar Lake||-||-||25|
| ||Rabbit Lake||5||3||15|
| ||US ISR||30||22||20|
|Total capacity replacement capital||130||114||135|
|Growth capital|| || || |
| ||McArthur River/Key Lake||55||29||75|
| ||US ISR||30||33||10|
| ||Cigar Lake||260||284||145|
| ||Fuel Services||4||2||5|
|Total growth capital||375||362||245|
|Total uranium & fuel services||6851||623||495|
|Electricity (our 31.6% share of BPLP)||80||75||-|
|1||We updated our 2013 capital cost estimate in the Q2 MD&A to $685 million.|
Capital expenditures were 9% below our 2013 plan, mainly due to variances at Rabbit Lake, Inkai, and McArthur River/Key Lake caused by a change in the timing of expenditures.
|(CAMECO'S SHARE IN $ MILLIONS)||2015 PLAN||2016 PLAN|
|Total uranium & fuel services||400-450||500-550|
| ||Sustaining capital||160-175||220-240|
| ||Capacity replacement capital||150-170||165-175|
| ||Growth capital||90-105||115-135|
We expect total capital expenditures for uranium and fuel services to decrease by about 21% in 2014.
Major sustaining, capacity replacement and growth expenditures in 2014 include:
- McArthur River/Key Lake - At McArthur River, the largest project is the upgrade of the electrical infrastructure at about $56 million. Mine development is also planned at about $105 million. Other projects include expansion of freeze capacity and other site facility and equipment purchases. At Key Lake, projects will be undertaken to finish work on the calciner and upgrade site electrical services
- US in situ recovery (ISR) - Continued work on the development of the North Butte mine represents a large portion of our wellfield construction expenditures in the US. Well installation at other mine units is also significant.
- Rabbit Lake - At Eagle Point, the largest component is mine development at about $24 million, along with mine equipment upgrades and purchases. Work on various mill facility and equipment replacements will also continue.
- Cigar Lake - Underground mine development makes up the largest portion of capital at the Cigar Lake site, at about $30 million. Completion of various mine facilities will continue into 2014, as well as the purchase of mine equipment in order to ramp up to full production. Our share of the costs to modify the McClean Lake mill are expected to be about $100 million in 2014.
We previously estimated capital costs on our brownfield expansions and development projects to be between $135 and $190 million per year for the next three years. We now estimate capital costs for our brownfield expansions and development projects to be about $245 million in 2014 due to the delayed startup of Cigar Lake production and additional costs at the McClean Lake mill. Growth capital is then expected to be between $90 and $135 million per year for 2015 and 2016.
The removal of our fixed production target allows us to better align our capital spending with market signals. As the market begins to signal new production is needed, we plan to increase our capital expenditures to allow us to be among the first to respond to the growth we see coming.
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 below. Our actual capital expenditures for future periods may be significantly different.
ACQUISITIONS AND DIVESTITURES
On January 9, 2013 we completed the acquisition of NUKEM by paying a total of $140 million (US) and assuming its net debt of $111 million (US). In the third quarter of 2013, as part of our strategy to focus on projects that provide the most certainty in the near term, we divested our interests in Argentina and Peru and recorded a loss of $15 million.
On January 30, 2014, we signed an agreement with BPC Generation Infrastructure Trust to sell our 31.6% limited partnership interest in BPLP and related entities for $450 million. The effective date for the sale is December 31, 2013. We expect to realize an after tax gain of approximately $129 million on this divestiture.
Under the agreements governing BPLP, the limited partners have rights of first offer upon a sale by us. Closing of the transaction is subject to completion or waiver of the right of first offer process by the other limited partners and receipt of certain regulatory approvals.
At December 31, 2013, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2014 net earnings by about $5 million (Cdn), with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).
For 2014, a change of $5 (US) per pound in each of the Ux spot price ($35.50 (US) per pound on February 3, 2014) and the Ux long-term price indicator ($50.00 (US) per pound on January 27, 2014) would change revenue by $67 million and net earnings by $42 million.
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, NUKEM inventory write-down, loss on exploration properties, and income taxes on adjustments.
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 2013, 2012 and 2011, as reported in our financial statements.
|Net earnings attributable to equity holders||318||253||450|
|Adjustments|| || || |
| ||Adjustments on derivatives1 (pre-tax)||56||17||80|
| ||Impairment charge on non-producing property||70||168||-|
| ||NUKEM inventory write-down||14||-||-|
| ||Loss on exploration properties||15||-||-|
| ||Income taxes on adjustments||(28)||(4)||(21)|
|Adjusted net earnings||445||434||509|
|1||We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.|
Since 2008, the Canada Revenue Agency (CRA) has disputed the offshore marketing company structure and related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2008 tax returns. We believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.
Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of a case like ours as there are only a handful of reported court decisions on transfer pricing in Canada. However, tax authorities generally test two things:
- the governance (structure)
- the price
As the majority of our customers are located outside Canada, we established an offshore marketing subsidiary. This subsidiary entered into intercompany purchase and sales agreements as well as uranium supply agreements with third parties. We have arm's-length transfer price arrangements in place, which expose both parties to the risks and the rewards accruing to them under this portfolio of purchase and sales contracts.
With respect to the contract prices, they are generally comparable to those established in sales contracts between arm's-length buyers and sellers entered into at that time. We have recorded a cumulative tax provision of $73 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 to 2013.
We are confident that we will be successful in our case; however, for the years 2003 through 2008, CRA issued notices of reassessment for approximately $2.0 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $590 million. The Canadian Income Tax Act includes provisions that require certain companies to pay 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have been required to pay a net amount of $103 million to CRA ($59 million as of December 31, 2013; $44 million in January 2014), which includes the amounts shown in the table below and described subsequently.
|YEAR ($ MILLIONS)|| ||CASH TAXES|| ||INTEREST AND|
| ||TRANSFER PRICING PENALTIES|| ||TOTAL|
|Prior to 2013|| ||-|| ||13|| ||-|| ||13|
|2013|| ||1|| ||9|| ||36|| ||46|
|2014|| ||16|| ||28|| ||-|| ||44|
|Total|| ||17|| ||50|| ||36|| ||103|
- approximately $13 million for interest and instalment penalties paid prior to 2013. These amounts were not reported separately as they were not material in any given year.
- approximately $27 million in January 2013, representing 50% of the amount owed for the amounts reassessed in December 2012 - $20 million of this payment was refunded in the second quarter of 2013 when it was determined by CRA that they had reassessed amounts outside of the allowable review period
- approximately $36 million in December 2013 that related to a $72 million transfer pricing penalty we were assessed for the 2007 taxation year. This was the first transfer pricing penalty assessed since CRA began to issue reassessments with respect to the transfer pricing dispute.
- approximately $3 million paid in 2013. This amount would have been refundable in the year, but instead was applied as a credit against the amounts reassessed in December 2013 (for which a further payment was made in January 2014).
- approximately $44 million in January 2014, representing 50% of the amount owed as reassessed in December 2013 and related to the 2008 taxation year
Using the methodology we believe CRA will continue to apply, and including the $2.0 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $5.7 billion in income as taxable in Canada for the years 2003 through 2013, which would result in a related tax expense of approximately $1.6 billion. As well, CRA may continue to apply transfer price penalties to taxation years subsequent to 2007. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1.25 billion and $1.3 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to Cameco. We would be responsible for remitting 50% of the cash taxes and transfer pricing penalties (between $625 million and $650 million) plus related interest and instalment penalties assessed, which would be material to Cameco.
Under the Canadian federal and provincial tax legislation, the amount required to be remitted each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers; however, we expect it will generally follow the schedule in the table below.
|DECEMBER 31, 2013 |
| ||2003 - 2013|| ||2014 - 2016|| ||2017 - 2023|| |
|50% of cash taxes and transfer pricing penalties payable in the period1|| ||37|| ||250 - 275|| ||325 - 350|| ||625 - 650|
|1||These amounts do not include interest and instalment penalties, which totaled approximately $22 million to December 31, 2013.|
In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to CRA, including the $103 million already paid to date.
The case on the 2003 reassessment is expected to go to trial in 2015. If this timing is adhered to, we expect to have a Tax Court decision in 2015 or 2016.
CAUTION ABOUT FORWARD-LOOKING INFORMATION RELATING TO OUR CRA TAX DISPUTE
This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA, including the amounts of future additional taxable income, additional tax expense, cash taxes payable, transfer pricing penalties and interest and possible instalment penalties thereon and related remittances, and timing of a Tax Court decision, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning below and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.
- CRA will reassess us for the years 2009 through 2013 using a similar methodology as for the years 2003 through 2008, with the time lag for the reassessments for each year being similar to what has occurred to date
- we will be able to apply elective deductions and tax loss carryovers to the extent anticipated
- CRA will seek to impose transfer pricing penalties (10% of the income adjustment) in addition to interest charges and instalment penalties
- we will be substantially successful in our dispute with CRA and the cumulative tax provision of $73 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date
Material risks that could cause actual results to differ materially
- CRA reassesses us for years 2009 through 2013 using a different methodology than for years 2003 through 2008, or we are unable to utilize elective deductions and loss carryovers to the same extent as anticipated, resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected
- the time lag for the reassessments for each year is different than for those to date
- we are unsuccessful and the outcome of our dispute with CRA results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows
- cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing
2013 financial results by segment
| ||THREE MONTHS ENDED |
| ||YEAR ENDED|
|Production volume (million lbs)||7.5||6.5||15%||23.6||21.9||8%|
|Sales volume (million lbs)||12.7||14.5||(12)%||32.8||32.9||-|
|Average spot price ($US/lb)||35.03||42.46||(17)%||38.17||48.40||(21)%|
|Average long-term price ($US/lb)||50.00||58.50||(15)%||54.13||60.13||(10)%|
|Average realized price|| || || || || || |
|Average unit cost of sales ($Cdn/lb) (including D&A)||37.94||32.85||15%||33.01||32.09||3%|
|Revenue ($ millions)||631||716||(12)%||1,633||1,571||4%|
|Gross profit ($ millions)||150||240||(38)%||550||514||7%|
|Gross profit (%)||24||34||(29)%||34||33||3%|
Production volumes this quarter were 15% higher compared to the fourth quarter of 2012, mainly due to higher production at McArthur River/Key Lake, Rabbit Lake, Inkai, and Smith-Ranch Highland with the rampup of the North Butte satellite operation.
Uranium revenues were down 12% due to a 12% decrease in sales volumes, which represents normal quarterly variance in our delivery schedule.
The average realized price increased slightly compared to 2012 despite a 17% drop in the spot price, due to the mix of contract deliveries, higher US dollar prices under fixed price contracts, and the effect of foreign exchange. In the fourth quarter of 2013, our realized foreign exchange rate was $1.04 compared to $0.99 in the prior year.
Total cost of sales (including D&A) increased by 1% ($481 million compared to $476 million in 2012). This was mainly the result of a 15% increase in the average unit cost of sales, offset by a 12% decrease in sales volumes.
The unit cost of sales increased due to an increase in the non-cash costs of produced material in the fourth quarter compared to the same period in 2012, and an increase in the unit cost of material purchased.
In 2013, we purchased about 10 million pounds of material under the Russian HEU commercial agreement, more than the annual 7 million historically purchased. Some of this additional material was made available under an option in the agreement, which we exercised in 2006. Under the agreement, pricing of this option material was at a discount to spot prices at the time of delivery. We received the option material in the fourth quarter as our final purchase under the Russian HEU commercial agreement.
In addition, in the fourth quarter, we had back-to-back purchase and sale arrangements that, while profitable, required we purchase material at a price higher than the current spot price.
The net effect was a $90 million decrease in gross profit for the quarter.
Production volumes in 2013 were 8% higher than 2012 due to higher production from nearly every site compared to 2012. See Uranium - production overview for more information.
Uranium revenues this year were up 4% compared to 2012, due to an increase of 4% in the Canadian dollar average realized price. Although the spot and term prices were lower than 2012, our average realized prices this year were higher mainly due to the mix of contracts, higher US dollar prices under fixed price contracts and the effect of foreign exchange. The realized foreign exchange rate was $1.03 compared to $1.00 in 2012. The spot price for uranium averaged $38.17 (US) per pound in 2013, a decline of 21% compared to the 2012 average price of $48.40 (US) per pound. Total cost of sales (including D&A) remained stable compared to 2012 at $1.1 billion as an increase in the average unit cost of sales was offset by slightly lower sales volumes.
The net effect was a $36 million increase in gross profit for the year.
The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures see below). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
| || THREE MONTHS ENDED|
| || YEAR ENDED |
|($CDN/LB)|| 2013|| 2012|| CHANGE|| 2013|| 2012|| CHANGE|
|Produced|| || || || || || |
| ||Cash cost||15.61||17.01||(8)%||18.37||19.95||(8)%|
| ||Non-cash cost||9.42||8.41||12%||9.46||8.13||16%|
| ||Total production cost||25.03||25.42||(2)%||27.83||28.08||(1)%|
| ||Quantity produced (million lbs)||7.5||6.5||15%||23.6||21.9||8%|
|Purchased|| || || || || || |
| ||Cash cost||37.26||32.94||13%||27.95||28.50||(2)%|
| ||Quantity purchased (million lbs)||4.4||2.8||57%||13.2||11.2||18%|
|Totals|| || || || || || |
| ||Produced and purchased costs||29.55||27.69||7%||27.87||28.22||(1)%|
| ||Quantities produced and purchased (million lbs)||11.9||9.3||28%||36.8||33.1||11%|
Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.
These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.
To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2013 and 2012, and years ended 2013 and 2012 as reported in our financial statements.
Cash and total cost per pound reconciliation
| ||THREE MONTHS ENDED DECEMBER 31||YEAR ENDED |
|Cost of product sold||359.8||394.4||869.1||883.7|
|Add / (subtract)|| || || || |
| ||Standby charges||(11.1)||(7.7)||(37.4)||(28.6)|
| ||Other selling costs||(4.8)||(3.3)||(1.4)||(6.2)|
| ||Change in inventories||(10.3)||(128.9)||63.1||23.1|
|Cash operating costs (a)||281.1||202.8||802.6||756.0|
|Add / (subtract)|| || || || |
| ||Depreciation and amortization||121.2||82.1||212.9||172.9|
| ||Change in inventories||(50.7)||(27.4)||10.1||5.2|
|Total operating costs (b)||351.6||257.5||1,025.6||934.1|
|Uranium produced and purchased (millions lbs) (c)||11.9||9.3||36.8||33.1|
|Cash costs per pound (a ÷ c)||23.62||21.81||21.81||22.84|
|Total costs per pound (b ÷ c)||29.55||27.69||27.87||28.22|
| || || || || |
|Fuel services results|
|(includes results for UF6, UO2 and fuel fabrication)|
| ||THREE MONTHS ENDED|
| ||YEAR ENDED|
|Production volume (million kgU)||2.7||3.3||(18)%||14.9||14.2||5%|
|Sales volume (million kgU)||6.5||6.0||8%||17.6||16.4||7%|
|Realized price ($Cdn/kgU)||17.24||17.16||-||18.12||17.75||2%|
|Average unit cost of sales ($Cdn/kgU) (including D&A)||14.42||14.06||3%||15.16||15.24||(1)%|
|Revenue ($ millions)||112||103||9%||319||291||10%|
|Gross profit ($ millions)||18||19||(5)%||52||41||27%|
|Gross profit (%)||16||18||(11)%||16||14||14%|
Total revenue increased by 9% due to an 8% increase in sales volumes.
The total cost of sales (including D&A) increased by 9% ($93 million compared to $85 million in the fourth quarter of 2012) mainly due to an 8% increase in sales volumes.
The net effect was a $1 million decrease in gross profit.
Total revenue increased by 10% due to a 7% increase in sales volumes and a 2% increase in the realized price.
The total cost of products and services sold (including D&A) increased by 7% ($267 million compared to $250 million in 2012) due to the increase in sales volumes.
The net effect was an $11 million increase in gross profit.
NUKEM GmbH (NUKEM)
On January 9, 2013, we acquired NUKEM for cash consideration of EUR107 million ($140 million (US)). We also assumed NUKEM's net debt, which amounted to about EUR79 million ($104 million (US)).
In accordance with the purchase agreement, we paid Advent additional consideration of EUR6,075,000 ($7,808,000), representing a share of NUKEM's 2012 earnings. There will be no additional payments to Advent related to the transaction.
For accounting purposes, the purchase price is allocated to the assets and liabilities acquired based on their fair values as of the acquisition date.
During the fourth quarter of 2013, NUKEM delivered 3.3 million pounds of uranium. On a consolidated basis, NUKEM contributed $188 million in revenues and gross profit of $19 million. Adjusted net earnings were $11 million (see non-IFRS measure). During the quarter, NUKEM's operating activities provided $9 million in cash, which was lower than expected due to the timing of a product purchase that was originally planned for early 2014 occurring in December of 2013.
During 2013, NUKEM delivered 8.9 million pounds of uranium. On a consolidated basis, NUKEM contributed $465 million in revenues and $20 million in gross profit. Adjusted net earnings were $14 million (see non-IFRS measure). NUKEM's contribution to our earnings is significantly impacted by our purchase price accounting. Excluding the impact of the purchase accounting, NUKEM's adjusted net earnings (see non-IFRS measure) were $47 million for the year. NUKEM's operating activities provided $6 million in cash during 2013 compared to our expectation of $50 million to $70 million. During the fourth quarter, we concluded a product purchase that had previously been planned for early 2014, reducing our reported cash flows for 2013 by approximately $55 million.
Uranium to be purchased under contractual fixed price arrangements and inventory on hand at the acquisition date were valued using the spot price at that time. The decline in the spot price in recent months has caused the carrying values of certain quantities to exceed their estimated realizable value, and we recorded an initial charge of $17 million ($11 million net of tax) and a subsequent recovery of $3 million ($1 million net of tax).
As noted above, much of the NUKEM purchase price was attributable to inventories and the portfolio of contracts. With respect to nuclear fuel inventories, amounts assigned were based on market values as of the date of acquisition. As these quantities are delivered to NUKEM's customers, we will adjust the cost of product sold to reflect the values at the acquisition date, regardless of NUKEM's historic costs.
As of the date of the purchase agreement, had NUKEM's sales and purchase contracts been settled, it would have realized significant financial benefit. As a result, we paid a premium to acquire the portfolio. Accordingly, a portion of the purchase price has been attributed to the various contracts. In our accounting for NUKEM, we will amortize the amounts assigned to the portfolio in the periods in which NUKEM transacts under the relevant contracts. The net effect is a reduction in reported profit margins relative to NUKEM's results. We expect the majority of the amount allocated to the contract portfolio will be amortized within two years.
Total electricity revenue decreased 3% this quarter due to a lower output. Realized prices reflect spot sales, revenue recognized under BPLP's agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $212 million this quarter under its agreement with the OPA, compared to $198 million in the fourth quarter of 2012. Gains on BPLP's contract activity in the fourth quarter of 2013 were $17 million, compared to $22 million in the fourth quarter of 2012.
The capacity factor was 96% this quarter, down from 100% in the fourth quarter of 2012. There were seven unplanned outage days in the quarter, compared to no outage days in the fourth quarter of 2012.
Operating costs this quarter of $234 million were similar to the $236 million in 2012.
The result was $47 million in earnings before taxes (our share) in the fourth quarter of 2013 compared to $46 million in earnings before taxes in the fourth quarter of 2012.
BPLP distributed $125 million to the partners in the fourth quarter. Our share was $40 million. BPLP capital calls to the partners in the fourth quarter were $15 million. Our share was $5 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.
BPLP's decreased results in 2013 when compared to 2012 are partially the result of revenues being 8% lower than in 2012 due to a 7% decrease in generation and a 2% decrease 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 $52.34/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 June 30, 2019 for unit B5, April 30, 2020 for unit B6, August 31, 2020 for unit B7 and December 31, 2020 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 compensation for deemed generation is a reflection of the Bruce B units' ability to provide flexible output to the Ontario market, and the relatively high fixed cost nature of the business. Deemed generation was 0.6 TWh in 2013 and 0.4 TWh in 2012.
During 2013, BPLP recognized revenue of $698 million under the agreement with the OPA, compared to $773 million in 2012.
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. During 2013, gains on BPLP's contracting activity were $59 million, compared to $108 million in 2012.
BPLP's capacity factor was 87% in 2013, down from 94% in 2012 due to a higher volume of outage days during the year. In 2013, there were 140 planned and 20 unplanned outage days, compared to 46 planned and 25 unplanned outage days in 2012.
In addition, BPLP's decreased results in 2013 when compared to 2012 were also partially the result of higher operating costs. BPLP's operating costs were $1.0 billion this year compared to $945 million in 2012 due to higher maintenance costs incurred primarily as a result of more planned outage days than in 2012.
The net effect was a decrease in our share of earnings before taxes of 31%
BPLP distributed $330 million to the partners in 2013. Our share was $104 million. BPLP capital calls to the partners in 2013 were $42 million. Our share was $13 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.
Subject to closing, we have sold our entire interest in BPLP and related entities effective December 31, 2013.
|Operations and development projects|
|Uranium - production overview |
| ||THREE MONTHS ENDED|
| || |
|2013||2012||2013||2012||2013 PLAN||2014 PLAN|
|McArthur River/Key Lake||4.0||3.5||14.1||13.6||13.61||13.1|
|Cigar Lake||-||-||-||-||-1||1.0 - 1.5|
|Total||7.5||6.5||23.6||21.9||23.2||23.8 - 24.3|
|1||We updated our initial 2013 plan for McArthur River/Key Lake (to 13.6 million pounds from 13.2 million pounds), US ISR (to 2.3 million pounds from 2.6 million pounds) and Cigar Lake (to nil from 0.3 million pounds) in our Q3 MD&A.|
MCARTHUR RIVER/KEY LAKE
Total production from McArthur River/Key Lake was 20.1 million pounds, which is the highest annual output from a uranium facility anywhere in the world. Our share of production in 2013 was 14.1 million pounds U3O8, 4% higher than our forecast for the year, and 4% higher than annual production in 2012.
At McArthur River and Key Lake we realized benefits under the production flexibility provision in our operating licences. Ongoing efforts to improve the efficiency and reliability of the Key Lake mill resulted in record mill performance.
On October 29, 2013, the CNSC granted a renewal of our McArthur River and Key Lake operating licences. The licence term is from November 1, 2013 to October 31, 2023. As long as average annual production does not exceed 18.7 million pounds per year, production flexibility provisions in the licence conditions handbooks allow:
- the Key Lake mill to produce up to 20.4 million pounds (100% basis) per year
- the McArthur River mine to produce up to 21 million pounds (100% basis) per year
Our average annual production at McArthur River/Key Lake over the past five years is 19.7 million pounds. Consequently, we have limited flex capacity remaining under our licence provisions.
McArthur River production expansion
A limiting factor for production at the McArthur River mine is the licence limit of 18.7 million pounds (100% basis) per year, and in order to maintain the flexibility to produce more, we plan to request a production limit increase to 21 million pounds (100% basis) in 2014. This would match the currently approved maximum production level. We expect a decision on this increase in 2014.
In addition, we will continue the work to further increase our annual production rate to 22 million pounds (100% basis) by 2018, subject to regulatory approval, as contemplated in the revision to our mine plan in 2012.
We were notified by the CNSC that the environmental assessment for the planned increase in production to 22 million pounds would be transitioned to the CNSC licensing and compliance processes, rather than the federal environmental assessment process.
In order to implement the planned production increases, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. In addition, we plan to:
- obtain all the necessary regulatory approvals, including at Key Lake, to ensure the mill can process all of the ore mined annually at McArthur River
- 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
We completed installation of the freezewall and brine lines in the upper mining area of zone 4 north. We began freezing the ground in the third quarter of 2013, with plans to start mining the zone in late 2014.
In addition to the underground work, we continued 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.
Key Lake extension project and mill revitalization
The Key Lake mill began operating in 1983 and is currently licensed to produce 18.7 million pounds (100% basis) per year. 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 (EA), we are seeking approval to increase Key Lake's nominal annual production rate to 25 million pounds and to increase our tailings capacity; in 2014, we expect the federal and provincial EA to conclude and expect a decision to be made on these increases.
The mill revitalization plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. Major components of a new calciner circuit were installed in 2013 and commissioning is expected to be completed in 2014. As part of the revitalization plan, we also replaced the existing electrical substation in order to meet future electrical demands.
This year we:
- submitted the final environmental impact statement for review by the regulators, and plan to pursue the required regulatory approvals in 2014
- completed flattening of the Deilmann tailings management facility pitwalls
In 2014, we expect to:
- complete installation and commissioning of the new calciner
- upgrade the electrical services necessary to add standby electrical generating capacity for the new electrically heated calciner
In 2014, we expect to complete the regulatory process required to increase production to 25 million pounds per year at Key Lake. We will also seek approval to deposit tailings in the Deilmann tailings management facility to a higher level, providing enough tailings capacity to potentially mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.
Production this year was slightly higher than our forecast for the year and 15% higher than production in 2012. Inkai added new wellfields to the production mix, which increased the head grade and resulted in higher 2013 production.
In December 2013, Inkai received government approval of an amendment to the resource use contract to increase production from blocks 1 and 2 to 5.2 million pounds (100% basis). Our share of Inkai's annual production is 3.0 million pounds with the processing plant at full capacity.
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, which is an intermediate step in the uranium conversion process.
We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. We are continuing to work on an assessment of the production increase, and in December 2013, we also completed the first draft of a prefeasibility study (PFS) for the potential construction of a uranium refinery in Kazakhstan. Cameco and Kazatomprom will determine if a feasibility study is justified based on the outcome of the refinery PFS. Advancement to the feasibility stage will require government approvals for the transfer of our proprietary uranium refining technology from Canada to Kazakhstan. An NCA between Canada and Kazakhstan was signed in 2013, providing the international framework necessary for applying to the two governments for the required licences and permits.
In 2013 at block 3, Inkai:
- completed exploration drilling
- continued construction of the test leach facility and test wellfields
- started work on an appraisal of mineral potential according to Kazakhstan standards
In 2014 at block 3, Inkai expects to:
- complete construction of the test leach facility and test wellfields
- start operation of the test wellfields and begin uranium production with the test leach facility
- complete a preliminary appraisal and continue to work on a final appraisal of mineral potential according to Kazakhstan standards
During the year, we:
- completed construction and began commissioning of all infrastructure required to begin ore production
- successfully tested the jet boring system in waste and began commissioning in ore
- continued freezing the ground from surface to ensure frozen ore is available for future production years
The CNSC granted a uranium mining licence authorizing construction and operation of the Cigar Lake project. The licence term is from July 1, 2013 to June 30, 2021.
As of December 31, 2013, we had:
- invested about $1.1 billion for our share of the construction costs to develop Cigar Lake
- expensed about $86 million in remediation expenses
- expensed about $100 million in standby costs
- expensed about $102 million to begin commissioning
In August 2013, we announced that our share of the total capital cost for Cigar Lake was expected to increase between 15% and 25% as a result of scope changes, increased costs at the mine and mill, and the inclusion of some capital costs that will be incurred subsequent to the mining of the first ore that were not included in our previous estimate. Our total share of the capital cost for this project is now estimated to be about $1.3 billion (previously $1.1 billion) since we began development in 2005. In order to bring Cigar Lake into production in 2014, we estimate our share of capital expenditures will be about $130 million, including $100 million on modifications to the McClean Lake mill. Additional expenditures of about $35 million will be required at McClean Lake mill in 2015 in order to continue ramping up to full production. Our share of standby charges until production is achieved this year are estimated to be about $15 million.
In 2014, we expect:
- to bring the mine into production in the first quarter of 2014
- processing of the ore to begin at AREVA's McClean Lake mill by the end of the second quarter of 2014
We expect Cigar Lake to produce between 2 million and 3 million packaged pounds from the mill (100% basis) in 2014. Based upon our commissioning and rampup experience, we will adjust our plans as necessary to allow us to reach our full production rate of 18 million pounds (100% basis) by 2018.
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 produced 14.9 million kgU, slightly higher than our plan at the beginning of the year and 5% higher than 2012 when we reduced production in response to weak market conditions.
In July, unionized employees at our Port Hope conversion facility accepted new three-year collective agreements, which include a 6% wage increase over the term of the agreements.
In December 2012, we received a positive decision on the environmental assessment for the Port Hope conversion facility cleanup and modernization (Vision in Motion, formerly Vision 2010) from Canada's Environment Minister. In 2013, we began the licensing process with the CNSC, which is required to advance the project. The process will continue in 2014.
Based on the current weak market for UF6 conversion, we do not anticipate an extension of our toll conversion contract with SFL beyond 2016. If market conditions improve over the next few years, we would consider resuming our discussions to extend the contract.
We have decreased our production target for 2014 to between 13 million and 14 million kgU in response to weak market conditions.
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, mining and technology, Cameco
- Les Yesnik, general manager, Key Lake, Cameco
- Scott Bishop, principal mine engineer, technology group, Cameco
- Ken Gullen, technical director, international, 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 2014 and future global uranium supply, demand, number of nuclear plants, and nuclear generating capacity, including the discussion under the heading The nuclear energy industry today
- the discussion under the heading Our strategy, including our expectation that market challenges will continue for the near to medium term
- our consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2014
- our expectations for uranium deliveries in the first quarter and for the balance of 2014
- future tax payments and rates
- our uranium price sensitivity analysis
- our expectations for 2014, 2015 and 2016 capital expenditures
- our expectations regarding our tax dispute with CRA and future tax reassessments by CRA
- 2014 forecast production at our uranium operations
- our expectations and plans for each of McArthur River/Key Lake, Inkai, Cigar Lake, and fuel services operating sites
- 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
- we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our dispute with CRA
- 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 mining or production plans are delayed or do not succeed, including as a result of any difficulties with the jet boring mining method or freezing the deposit to meet production targets, any difficulties with the McClean Lake mill modifications or commissioning or milling of Cigar Lake ore, or our inability to acquire any of the required jet boring equipment
- our McArthur River development, mining or production plans do not succeed for any reason
- 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 and Key Lake), strikes or lockouts, underground floods, cave ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks
- 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 on under Price sensitivity analysis: uranium
- our expectations regarding tax rates and payments, foreign currency exchange rates and interest rates
- our expectations regarding the outcome of the dispute with CRA
- 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 mining and production plans succeed, including the additional jet boring system unit is acquired on schedule and the jet boring mining method and our plans to freeze the deposit to meet production targets succeeds
- mill modifications and commissioning of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected
- our McArthur River development, mining and production plans succeed
- our ability to continue to supply our products and services in the expected quantities and at the expected times
- our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals
- our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, 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 and Key Lake), 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
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, 2014, to shareholders of record at the close of business on March 31, 2014.
We invite you to join our fourth quarter conference call on Monday, February 10, 2014 at 1:00 p.m. Eastern.
The call will be open to all investors and the media. To join the call, please dial (866) 225-0198 (Canada and US) or (416) 340-8061. 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 13, 2014 by calling (800) 408-3053 (Canada and US) or (905) 694-9451 (Passcode 7039949#)
Our 2013 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 2013 annual information form is expected to be available later in February.
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. 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, the Company and Cameco mean Cameco Corporation and its subsidiaries; including NUKEM GmbH, unless otherwise indicated.