SASKATOON, SASKATCHEWAN–(Marketwired – Feb. 5, 2016) –
ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED)
Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated financial and operating results for the fourth quarter and year ended December 31, 2015 in accordance with International Financial Reporting Standards (IFRS).
“In 2015, the company continued to perform well, in the context of the global challenges our industry faces,” said president and CEO, Tim Gitzel. “But despite the challenges, we continued to concentrate on the aspects of our business that are within our control, which has led us to once again deliver on, and in some cases exceed, our annual guidance.
“We are still waiting on a market recovery that was expected to come sooner, but we’ve learned to put those expectations aside and prepare for whatever comes our way. Looking ahead, our strategy is to continue focusing our capital on tier-one assets, because it’s those world-class, low-cost mines that will position us to quickly respond when the market calls for more production. And we believe that the question is not ‘if’ the market will make that call, but ‘when’, as we continue to see a bright long-term outlook for the nuclear industry.”
|THREE MONTHS ENDED||YEAR ENDED|
|HIGHLIGHTS||DECEMBER 31||DECEMBER 31|
|($ MILLIONS EXCEPT WHERE INDICATED)||2015||2014||CHANGE||2015||2014||CHANGE|
|Net earnings (loss) attributable to equity holders||(10)||73||(114)%||65||185||(65)%|
|$ per common share (diluted)||(0.03)||0.18||(114)%||0.16||0.47||(65)%|
|Adjusted net earnings (non-IFRS, see page 8)||151||205||(26)%||344||412||(17)%|
|$ per common share (adjusted and diluted)||0.38||0.52||(27)%||0.87||1.04||(16)%|
|Cash provided by operations (after working capital changes)||503||236||113%||450||480||(6)%|
|Average realized prices||Uranium||($US/lb)||46.36||50.57||(8)%||45.19||47.53||(5)%|
The 2015 annual financial statements have been audited; however, the 2014 and 2015 fourth quarter financial information presented is unaudited. You can find a copy of our 2015 annual management’s discussion and analysis (MD&A), and our 2015 audited financial statements, on our website at cameco.com.
Our net earnings attributable to equity holders (net earnings) in 2015 were $65 million ($0.16 per share diluted) compared to $185 million ($0.47 per share diluted) in 2014, mainly due to:
partially offset by:
In addition, in 2014 there were a number of one-time items that contributed to the higher net earnings in 2014 compared to 2015, including:
partially offset by:
On an adjusted basis, our earnings were $344 million ($0.87 per share diluted) (non-IFRS measure, see page 8) in 2015 compared to $412 million ($1.04 per share diluted) in 2014.
The 17% decrease from 2014 to 2015 resulted from:
partially offset by:
In addition, in 2014 there was a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in 2014 compared to 2015. The impact of the settlement was partially offset by an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL and settlement costs of $12 million with respect to the early redemption of our Series C debentures in 2014.
In the fourth quarter of 2015, our net loss was $10 million ($(0.03) per share diluted), a decrease of $83 million compared to net earnings of $73 million ($0.18 per share diluted) in 2014, mainly due to:
partially offset by:
In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher net earnings in the fourth quarter of 2014 compared to the same period in 2015. The impact of the settlement was partially offset by the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects in the fourth quarter of 2014.
On an adjusted basis, our earnings this quarter were $151 million ($0.38 per share diluted) compared to $205 million ($0.52 per share diluted) (non-IFRS measure, see page 8) in 2014, mainly due to:
partially offset by:
In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in the fourth quarter of 2014 compared to the same period in 2015.
Impairment charge on producing assets
During the fourth quarter of 2015, we recognized a $210 million impairment charge related to our Rabbit Lake operation. The impairment was due to increased uncertainty around future production sources for the Rabbit Lake mill as a result of the ongoing economic conditions. The amount of the charge was determined as the excess of carrying value over the recoverable amount. The recoverable amount of the mill was determined to be $69 million. See note 9 to the financial statements.
2015 market developments
As has been the case in recent years, a lot happened over the course of 2015, although the general state of the market did not see much change.
Making positive news for nuclear, as usual, was China. Not only did the country continue with its rapid reactor new build program and bring eight reactors online, but Chinese companies also signed agreements with Argentina, Romania and the UK for new reactors, illustrating the country’s commitment to nuclear and its intent to become a major international player in the nuclear industry.
Undoubtedly, the biggest headline of 2015 was the long-awaited first reactor restarts in Japan. Sendai units 1 and 2 were the first reactors in Japan to restart since 2013, and it is hoped they are the first of many to come.
New builds in the UK and US continued to be bright spots for the industry, in addition to a number of reactor life extensions approved in Japan, and the US, with utilities now considering additional extensions that could see reactor lives reaching 80 years.
However, these positive developments could not outweigh the more powerful influence of a continued sluggish global economy, geopolitical issues, concerns around growth in China, and flat electricity demand. These more general drivers had help from industry specific factors as well, such as slower new reactor construction, eight reactor shutdowns, the continued high level of inventories held by market participants, and France’s policy to reduce nuclear in their energy mix to 50% by 2025 becoming law.
In addition, supply performed relatively well, with only minor disruptions and one curtailment, unlike 2014, which saw six projects tempered or curtailed.
The end result was a market seemingly indifferent to the commotion of events that occurred throughout the year.
Market contracting activity was modest. Spot volumes were normal, but long-term contracting was well below historical averages and current consumption levels-about half of current annual reactor consumption estimates, similar to 2014. Long-term contracting is a key factor in the timing of market recovery, and its pace will depend on the respective coverage levels, market views and risk appetite of both buyers and sellers.
The big news in Japan was the restart of Sendai units 1 and 2, which occurred in August and October. In addition, the court injunction against the two Takahama units was overturned in December, 2015, clearing the way for Takahama unit 3 to restart on January 29, 2016, with unit 4 expected to restart later in the first quarter. Ikata unit 3 has also cleared a safety inspection by the Nuclear Regulatory Authority, and four more units are in the final stages of approval. In all, three reactors are now in operation, while 23 remain under evaluation for restart.
Over the long term, Japan’s energy policy states that nuclear will make up 20 to 22% of the energy mix in the country. The billions of dollars in investment being made by Japan’s utilities suggest a high degree of confidence in reactors coming back online and meeting this target; however, public sentiment towards nuclear in Japan remains somewhat uncertain.
China’s remarkable nuclear growth program remains on track and the UK’s plans for new reactor construction continue to move forward. India and South Korea are also among several key regions growing their nuclear generation fleet.
In 2015, growth was tangible as 10 reactors came online-double that of 2014. These included the eight noted in China, one in Russia and one in South Korea. And seven more reactors began construction-six in China and one in the UAE, a formerly non-nuclear country with four reactors now under construction.
But, to round out the picture, eight units shut down. Five of these were in Japan, plus one in Sweden, one in Germany as part of its phase-out plans, and one in the UK-the last Magnox reactor operating in the world. In addition, there were announcements for future shutdowns in the US, where nuclear struggles to remain competitive in deregulated electricity markets and in the context of low natural gas prices.
One event that could have an effect on the future of nuclear in the US and other western countries is the UN Climate Conference COP-21 agreement, finalized in 2015. As a non-GHG emitter, nuclear could play a significant role in achieving climate change prevention goals.
Outlook for 2016
Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.
Our outlook for 2016 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 2015 Financial results by segment on page 12 for details.
|2016 FINANCIAL OUTLOOK|
|8 to 9
|Delivery volume1||–||30 to 32
up to 5%
|9 to 10
million lbs U3O8
|Revenue compared to 20153||Decrease
up to 5%
up to 5%4
up to 5%
5% to 10%
|Average unit cost of sales (including D&A)||–||Increase
up to 5%5
10% to 15%
|Direct administration costs compared to 20156||Increase
5% to 10%
|Gross profit||–||–||–||Gross profit
4% to 5%
|Exploration costs compared to 2015||–||Increase
15% to 20%
|Tax rate7||Recovery of
25% to 30%
|Capital expenditures||$320 million||–||–||–|
|(1)||Our 2016 outlook for delivery volume in our uranium and NUKEM segments does not include sales between our uranium, fuel services and NUKEM segments.|
|(2)||Our uranium delivery volume is based on the volumes we currently have commitments to deliver under contract in 2016.|
|(3)||For comparison of our 2016 outlook and 2015 results for revenue in our uranium and NUKEM segments, we do not include sales between our uranium, fuel services and NUKEM segments.|
|(4)||Based on a uranium spot price of $34.65 (US) per pound (the Ux spot price as of February 1, 2016), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on January 25, 2016) and an exchange rate of $1.00 (US) for $1.25 (Cdn).|
|(5)||This increase is based on the unit cost of sales for produced material and committed long-term purchases. If we make discretionary purchases in 2016, then we expect the overall unit cost of sales may be affected.|
|(6)||Direct administration costs do not include stock-based compensation expenses.|
|(7)||Our outlook for the tax rate is based on adjusted net earnings.|
We expect consolidated revenue to decrease up to 5% in 2016, based on currently committed sales volumes, due to a planned decrease in uranium and fuel services sales volumes. If we make additional sales with deliveries in 2016, we would expect our revenue outlook to increase.
We expect administration costs (not including stock-based compensation) to be 5% to 10% higher compared to 2015 due to increased costs related to the northern collaboration agreements and increased project work. In 2016, we are continuing to negotiate new collaboration agreements with northern communities, which could result in additional one-time payments. Due to the uncertainty of the timing for the potential signing of agreements, the cost is not included in our outlook. If agreements are signed and there is an impact on our administrative costs, we will update our outlook.
We expect exploration expenses to be about 15% to 20% higher than they were in 2015 due to increased exploration activity at Cigar Lake.
On an adjusted net earnings basis, we expect a tax recovery of 25% to 30% in 2016 from our uranium, fuel services and NUKEM segments.
Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. We have a global customer base and we have established a marketing and trading structure involving foreign subsidiaries, which entered into various intercompany purchase and sale arrangements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s-length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts between arm’s-length parties entered into at that time.
This year, many of the existing intercompany purchase and sale arrangements in our portfolio expire. We have started to replace these contracts and will continue to put new intercompany arrangements in place, which, as the existing arrangements did, will reflect the market at the time they are signed.
As a result, in 2017, we expect our consolidated tax rate will transition to a modest expense, and trend toward a tax expense of approximately 20% over the next five years. The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and the market conditions at the time transactions occur under both our intercompany and third-party purchase and sale arrangements.
We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:
As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.
During the period from 2013 to 2015, transitional rules for the new profit royalty regime were applied whereby only 50% of capital costs were deductible. The remaining 50% was accumulated and will now be deductible beginning in 2016. In addition, the capital allowance related to Cigar Lake under the previous system was grandfathered and is also now deductible beginning in 2016. Based on the expected application of transitional and grandfathered capital allowance deductions, we anticipate that only the first tier of the profit royalty (10%) will apply in 2016 and 2017. As capital pools are depleted, we expect to also be subject to the top tier of the profit royalty (15%) in 2018.
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)||2015 PLAN1||2015 ACTUAL||2016 PLAN|
|McArthur River/Key Lake||20||16||30|
|Total sustaining capital||95||84||115|
|Capacity replacement capital|
|McArthur River/Key Lake||95||96||55|
|Total capacity replacement capital||165||168||120|
|McArthur River/Key Lake||15||13||40|
|Total growth capital||125||107||85|
|Total uranium & fuel services||385 1||359||320|
|(1)||Capital spending outlook was updated to $385 million in our third quarter MD&A.|
|Outlook for investing activities|
|CAMECO’S SHARE ($ MILLIONS)||2017 PLAN||2018 PLAN|
|Total uranium & fuel services||300-350||250-300|
|Capacity replacement capital||135-150||145-160|
We expect total capital expenditures for uranium and fuel services to decrease by about 11% in 2016.
Major sustaining, capacity replacement and growth expenditures in 2016 include:
We previously expected to spend between $350 million and $400 million in 2017. We now expect to spend between $300 million and $350 million in 2017. Due to the continued market uncertainty, we have reduced growth capital to focus on our tier-one properties.
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 on pages 21 and 22. Our actual capital expenditures for future periods may be significantly different.
REVENUE, CASH FLOW AND EARNINGS SENSITIVITY ANALYSIS
URANIUM SEGMENT OUTLOOK
We expect to produce 30.0 million pounds in 2016 and have commitments under long-term contracts to purchase approximately 9 million pounds.
Based on the contracts we have in place, and not including sales between our segments, we expect to deliver between 30 million and 32 million pounds of U3O8 in 2016. We expect the unit cost of sales to be up to 5% higher than in 2015, primarily due to the planned purchases during the year. If we make additional discretionary purchases in 2016 at a cost different than our other sources of supply, then we expect the overall unit cost of sales to be affected.
We expect revenue to be up to 5% lower than in 2015 as a result of an expected decrease in deliveries, not including sales between our segments, partially offset by a higher average realized price.
In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly as shown below. We expect the quarterly distribution of uranium deliveries in 2016 to be weighted to the second half of the year. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.
PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT
The following table 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, 2015 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, 2015, 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. 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)|
The table illustrates the mix of long-term contracts in our December 31, 2015 portfolio, and is consistent with our marketing strategy. It has been updated to reflect deliveries made and contracts entered into up to December 31, 2015.
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:
FUEL SERVICES OUTLOOK
In 2016, we plan to produce 8 million to 9 million kgU, and we expect sales volumes, not including intersegment sales, to be up to 5% lower than in 2015. Overall revenue is expected to increase by up to 5% as lower sales volumes will be more than offset by an increase in the average realized price. We expect the average unit cost of sales (including D&A) to increase by 10% to 15%; therefore, overall gross profit will decrease as a result.
For 2016, NUKEM expects to deliver between 9 million and 10 million pounds of uranium. Total revenue and unit cost of sales, not including intersegment sales, is expected to increase by 5% to 10% compared to 2015; however, the overall gross profit percentage is expected to be slightly lower than 2015 at 4% to 5%.
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, the write-off of assets, NUKEM inventory write-down, gain on interest in BPLP (after tax), 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 2015 and 2014, and three months ended December 31, 2015 and December 31, 2014.
|THREE MONTHS ENDED||YEAR ENDED|
|DECEMBER 31||DECEMBER 31|
|Net earnings (loss) attributable to equity holders||(10)||73||65||185|
|Adjustments on derivatives (pre-tax)||10||10||166||47|
|NUKEM purchase price inventory recovery||–||(4)||(3)||(5)|
|Income taxes on adjustments||(59)||(46)||(99)||(56)|
|Write-off of assets||–||41||–||41|
|Gain on interest in BPLP (after tax)||–||–||–||(127)|
|Adjusted net earnings||151||205||344||412|
TRANSFER PRICING DISPUTES
We have been reporting on our transfer pricing disputes with CRA since 2008, when it originated, and with the United States Internal Revenue Service (IRS) since the first quarter of 2015. Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing disputes we have.
Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of cases like ours. However, tax authorities generally test two things:
We have a global customer base and we established a marketing and trading structure involving foreign subsidiaries, including Cameco Europe Limited (CEL), which entered into various intercompany arrangements, including purchase and sale agreements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s-length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts between arm’s-length parties entered into at that time.
For the years 2003 to 2010, CRA has shifted CEL’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. There has not yet been a decision regarding a transfer pricing penalty for 2010. The IRS also allocated a portion of CEL’s income for the years 2009 through 2012 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $320 million for the 2003 – 2015 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options, including remedies under international tax treaties that would limit double taxation; however, there is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.
Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements. To the end of 2014, we received notices of reassessment for our 2003 through 2009 tax returns, and, in the fourth quarter of 2015, we received a notice of reassessment for our 2010 tax year. We have recorded a cumulative tax provision of $50 million (September 30, 2015 – $92 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 through 2015. We have reduced the provision to reflect management’s revised estimate, which takes into account additional contract information. We are confident that we will be successful in our case and continue to 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.
For the years 2003 through 2010, CRA issued notices of reassessment for approximately $3.4 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $1.1 billion. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions, we have paid a net amount of $232 million cash. In addition, we have provided $332 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed in 2015. The amounts paid or secured are shown in the table below.
YEAR PAID ($ MILLIONS)
|Prior to 2013||–||13||–||13||13||–|
Using the methodology we believe CRA will continue to apply, and including the $3.4 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $7.0 billion of additional income taxable in Canada for the years 2003 through 2015, which would result in a related tax expense of approximately $2.1 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.65 billion and $1.70 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to us. While in dispute, we would be responsible for remitting or otherwise providing security for 50% of the cash taxes and transfer pricing penalties (between $825 million and $850 million), plus related interest and instalment penalties assessed, which would be material to us.
Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. Recently, the CRA decided to disallow the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This does not impact the anticipated income tax expense for a particular year, but does impact the timing of any required security or payment. As noted above, for the 2010 tax year, as an alternative to paying cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. We expect to be able to continue to provide security in the form of letters of credit to satisfy these requirements. The estimated amounts summarized in the table below reflect actual amounts paid or secured and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2015, and include the expected timing adjustment for the inability to use any loss carry-backs starting in 2008. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2015.
|50% of cash taxes and transfer pricing penalties paid, secured or owing in the period|
|Cash payments||156||155 – 180||30 – 55||335 – 360|
|Secured by letters of credit||264||95 – 120||20 – 45||425 – 450|
|Total paid1||420||255 – 280||65 – 90||825 – 850|
|(1)||These amounts do not include interest and instalment penalties, which totaled approximately $140 million to December 31, 2015.|
In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $564 million already paid or otherwise secured to date.
We are expecting the trial for the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments in April 2017. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.
In the fourth quarter of 2015, we received a Revenue Agents Report (RAR) from the IRS for the tax years 2010 to 2012. Similar to the 2009 RAR received in the first quarter of 2015, the IRS is challenging the transfer pricing used under certain intercompany transactions pertaining to the 2010 to 2012 tax years for certain of our US subsidiaries. The 2009 and 2010 to 2012 RARs list the adjustments proposed by the IRS and calculate the tax and any penalties owing based on the proposed adjustments.
The current position of the IRS is that a portion of the non-US income reported under our corporate structure and taxed in non-US jurisdictions should be recognized and taxed in the US on the basis that:
The proposed adjustments result in an increase in taxable income in the US of approximately $419 million (US) and a corresponding increased income tax expense of approximately $122 million (US) for the 2009 through 2012 taxation years, with interest being charged thereon. In addition, the IRS proposed cumulative penalties of approximately $8 million (US) in respect of the adjustment.
We believe that the conclusions of the IRS in the RARs are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. Until this matter progresses further, we cannot provide an estimation of the likely timeline for a resolution of the dispute.
We believe that 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.
Overview of disputes
The table below provides an overview of some of the key points with respect to our CRA and IRS tax disputes.
|Basis for dispute||Corporate structure/governance
Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements
Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2010 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax)
|Income earned on sales of uranium by the US mines to CEL is inadequate
Compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate
Allocates a portion of CEL’s income for the years 2009 through 2012 to the US (a portion of the same income we paid tax on in foreign jurisdictions and which the CRA is proposing to tax)
|Years under consideration||CRA reassessed 2003 to 2010
Auditing 2011 to 2012
|IRS has proposed adjustments for 2009 through 2012|
|Timing of resolution||Expect our appeal of the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments expected in April 2017
Expect Tax Court decision six to 18 months after completion of trial
|Contesting proposed adjustments in an administrative appeal
We cannot yet provide an estimate as to the timeline for resolution
|Required payments||Expect to provide security in form of letters of credit and/or make cash payments for 50% of cash taxes, interest and penalties as reassessed
Paid $232 million in cash to date
Secured $332 million using letters of credit
|No security or cash payments required while under administrative appeal|
Caution about forward-looking information relating to our CRA and IRS tax dispute
This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 21 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.
Material risks that could cause actual results to differ materially
|2015 financial results by segment|
|THREE MONTHS ENDED||YEAR ENDED|
|DECEMBER 31||DECEMBER 31|
|Production volume (million lbs)||9.6||8.2||17%||28.4||23.3||22%|
|Sales volume (million lbs)1||11.2||10.7||5%||32.4||33.9||(4)%|
|Average spot price||($US/lb)||35.45||37.13||(5)%||36.55||33.21||10%|
|Average long-term price||($US/lb)||44.00||48.00||(8)%||46.29||46.46||–|
|Average realized price||($US/lb)||46.36||50.57||(8)%||45.19||47.53||(5)%|
|Average unit cost of sales (including D&A)||($Cdn/lb)||38.25||34.27||12%||38.83||34.64||12%|
|Revenue ($ millions)1||687||606||13%||1,866||1,777||5%|
|Gross profit ($ millions)||257||240||7%||608||602||1%|
|Gross profit (%)||37||40||(8)%||33||34||(3)%|
|(1)||Includes sales and revenue between our uranium, fuel services and NUKEM segments (17,000 pounds in sales and revenue of $0.5 million in Q4 2015, 400,000 pounds in sales and revenue of $15 million in Q4 2014, and 32,000 pounds in sales and revenue of $1.0 million in 2015, 1.4 million pounds in sales and revenue of $48 million in 2014).|
Production volumes this quarter were 17% higher compared to the fourth quarter of 2014, mainly as a result of higher production from the rampup of Cigar Lake production, offset by lower production at McArthur River/Key Lake, Rabbit Lake and our US ISR operations. See Our operations starting on page 15 for more information.
Uranium revenues were up 13% due to a 5% increase in sales volumes, which represents normal quarterly variance in our delivery schedule, and an 8% increase in the average realized price.
Average spot and long-term prices decreased, as did our US dollar average realized price due to lower prices under fixed-price contracts, and the mix of market and fixed contracts. However, the effect of foreign exchange resulted in an 8% higher Canadian dollar average realized price than the prior year. In the fourth quarter of 2015, our realized foreign exchange rate was $1.32 compared to $1.12 in the prior year.
Total cost of sales (including D&A) increased by 17% ($429 million compared to $366 million in 2014). This was the result of a 12% increase in the average unit cost of sales and a 5% increase in sales volumes.
The unit cost of sales increased due to an increase in the volume of material purchased throughout the year at prices higher than our average cost of inventory and an increase in the unit production costs related to the addition of higher cost production from Cigar Lake during rampup.
The net effect was a $17 million increase in gross profit for the quarter.
Production volumes in 2015 increased by 22% compared to 2014. Lower production at our US ISR operations was more than offset by the rampup of Cigar Lake production. See Our operations starting on page 15 for more information.
Uranium revenues this year were up 5% compared to 2014 due to an increase of 10% in the Canadian dollar average realized price, partially offset by a decrease in sales volumes of 4%. The spot price for uranium averaged $36.55 (US) per pound in 2015, an increase of 10% compared to the 2014 average price of $33.21 (US) per pound; however, our US dollar average realized price was lower mainly due to lower prices under fixed price contracts. The effect of foreign exchange resulted in a higher Canadian dollar average realized price than in the prior year. The realized foreign exchange rate was $1.27 compared to $1.10 in 2014.
Total cost of sales (including D&A) increased by 7% ($1.26 billion compared to $1.18 billion in 2014) due to higher unit cost of sales offset by lower sales volumes. The higher unit cost of sales was mainly the result of an increase in the volume of material purchased at prices higher than our average cost of inventory, and an increase in unit production costs related to the addition of higher costs from Cigar Lake during rampup.
The net effect was a $6 million increase in gross profit for the year.
The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures, see below). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
|THREE MONTHS ENDED||YEAR ENDED|
|DECEMBER 31||DECEMBER 31|
|Total production cost||27.00||21.34||27%||32.13||27.96||15%|
|Quantity produced (million lbs)||9.6||8.2||17%||28.4||23.3||22%|
|Quantity purchased (million lbs)||3.2||3.7||(14)%||12.5||7.1||76%|
|Produced and purchased costs1||31.16||26.84||16%||36.38||30.34||20%|
|Quantities produced and purchased (million lbs)||12.8||11.9||8%||40.9||30.4||35%|
|(1)||In the fourth quarter of 2015, cash costs of purchased material were $33.79 (US) per pound compared to $35.05 (US) per pound in the same period in 2014. In the fourth quarter of 2015, the exchange rate on purchases averaged $1.00 (US) for $1.29 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) during the same period in 2014. Cash costs of purchased material in 2015 were $36.57 (US) per pound compared to $34.51 (US) per pound in 2014. In 2015, the exchange rate on purchases averaged $1.00 (US) for $1.26 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) in 2014.|
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 years ended 2015 and 2014 and three months ended December 31, 2015 and December 31, 2014 as reported in our financial statements.
|Cash and total cost per pound reconciliation|
|THREE MONTHS ENDED||YEAR ENDED|
|DECEMBER 31||DECEMBER 31|
|Cost of product sold||328.3||269.0||989.2||902.8|
|Add / (subtract)|
|Other selling costs||(6.7)||(2.3)||(13.8)||(9.0)|
|Change in inventories||21.5||28.5||301.8||(71.9)|
|Cash operating costs (a)||293.6||260.7||1,160.7||705.9|
|Add / (subtract)|
|Depreciation and amortization||100.9||96.7||269.1||272.6|
|Change in inventories||4.3||(38.0)||58.1||(56.2)|
|Total operating costs (b)||398.8||319.4||1,487.9||922.3|
|Uranium produced & purchased (million lbs) (c)||12.8||11.9||40.9||30.4|
|Cash costs per pound (a ÷ c)||22.94||21.91||28.38||23.22|
|Total costs per pound (b ÷ c)||31.16||26.84||36.38||30.34|
|Fuel services results|
|(includes results for UF6, UO2 and fuel fabrication)|
|THREE MONTHS ENDED||YEAR ENDED|
|DECEMBER 31||DECEMBER 31|
|Production volume (million kgU)||3.4||2.7||26%||9.7||11.6||(16)%|
|Sales volume (million kgU)1||4.5||7.4||(39)%||13.6||15.5||(12)%|
|Average realized price||($Cdn/kgU)||21.88||16.92||29%||23.37||19.70||19%|
|Average unit cost of sales (including D&A)||($Cdn/kgU)||17.18||14.78||16%||18.87||17.24||9%|
|Revenue ($ millions)1||99||125||(21)%||319||306||4%|
|Gross profit ($ millions)||21||16||31%||61||38||61%|
|Gross profit (%)||21||13||62%||19||12||58%|
|(1)||Includes sales and revenue between our uranium, fuel services and NUKEM segments (339,000 kgU in sales and revenue of $2.9 million in Q4 2015, 0.5 million kgU in sales and revenue of $4 million in Q4 2014, and 339,000 kgU in sales and revenue of $2.9 million in 2015, 0.5 million kgU in sales and revenue of $4 million in 2014).|
Total revenue decreased by 21% due to a 39% decrease in sales volumes, partially offset by a 29% increase in average realized price.
The total cost of sales (including D&A) decreased by 28% ($78 million compared to $109 million in the fourth quarter of 2014) mainly due to a 39% decrease in sales volumes, partially offset by an increase of 16% in the average unit cost of sales, primarily as a result of the mix of products sold.
The net effect was a $5 million increase in gross profit.
Total revenue increased by 4% due to a 19% increase in the realized price, partially offset by a 12% decrease in sales volumes.
The total cost of products and services sold (including D&A) decreased by 4% compared to 2014 ($258 million compared to $268 million in 2014), as a 12% decrease in sales volumes was partially offset by a 9% increase in the average unit cost of sales (including D&A). When compared to 2014, the average unit cost of sales was 9% higher due to the mix of fuel services products sold.
The net effect was a $23 million increase in gross profit.
|THREE MONTHS ENDED||YEAR ENDED|
|DECEMBER 31||DECEMBER 31|
|Sales volume U3O8 (million lbs)1||3.7||3.4||9%||10.7||8.1||32%|
|Average realized price||($Cdn/lb)||52.22||52.12||–||48.82||44.90||9%|
|Cost of product sold (including D&A)||186||156||19%||512||327||57%|
|Revenue ($ millions)1||192||159||21%||554||349||59%|
|Gross profit ($ millions)||6||3||100%||42||22||91%|
|Gross profit (%)||3||2||50%||8||6||33%|
|(1)||Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in Q4 2015, 1.1 million pounds in sales and revenue of $43 million in Q4 2014, and 0.9 million pounds in sales and revenue of $19.3 million in 2015, 1.1 million pounds in sales and revenue of $43 million in 2014).|
NUKEM delivered 3.7 million pounds of uranium, an increase of 0.3 million pounds compared to 2014. NUKEM revenues amounted to $192 million compared to $159 million in 2014 due to an increase in volumes delivered.
Gross profit percentage was 3% in the fourth quarter of 2015, compared to 2% in the fourth quarter of 2014.
The net effect was a $3 million increase in gross profit.
During 2015, NUKEM delivered 10.7 million pounds of uranium, an increase of 2.6 million pounds compared to the previous year due to an increase in market activity. Revenues from NUKEM amounted to $554 million, 59% higher than in 2014 as a result of higher sales volumes and an increase in the average realized price, mainly due to weakening of the Canadian dollar. Gross profit percentage was 8% for 2015, compared to 6% for 2014.
The net effect was a $20 million increase in gross profit.
|THREE MONTHS ENDED||YEAR ENDED|
|CAMECO SHARE||DECEMBER 31||DECEMBER 31|
|(MILLION LBS)||2015||2014||2015||2014||2015 PLAN1||2016 PLAN|
|McArthur River/Key Lake||3.8||4.4||13.3||13.3||13.7||14.0|
|Cigar Lake||2.3||0.2||5.7||0.2||4.0 – 5.0||8.02|
|Total||9.6||8.2||28.4||23.3||26.3 – 27.3||30.02|
|(1)||We updated our initial 2015 plan for Cigar Lake (to 5 million pounds, from between 3 and 4 million pounds) in our Q3 MD&A.|
|(2)||Our 2016 plan for packaged production from Cigar Lake is subject to regulatory approval for an annual production limit increase at the McClean Lake mill. See Cigar Lake starting on page 17 for more information.|
We remain 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. Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to increase long-term shareholder value.
We plan to:
MCARTHUR RIVER/KEY LAKE
Production from McArthur River/Key Lake was 19.1 million pounds; our share was 13.3 million pounds. This was 3% lower than our forecast for the year due to unplanned maintenance outages to repair the calciner at Key Lake. Annual production was unchanged from 2014.
Licensing and production capacity
In 2015, the CNSC approved our application to increase McArthur River’s licensed annual production to 25 million pounds (100% basis) to allow flexibility to match the approved Key Lake mill capacity. The licence conditions handbooks for these operations now allow both operations to produce up to 25 million pounds (100% basis) per year.
Key Lake extension and McArthur River production expansion
In support of our strategy to maintain the flexibility to respond to market conditions as they evolve, we continue to advance projects that are necessary to sustain and increase production when the market signals that additional production is needed.
The Key Lake mill began operating in 1983 and we continue to upgrade circuits with new technology to simplify operations and improve environmental performance. The extension project involved increasing our tailings capacity and the mill’s nominal annual production rate to closely follow production from the McArthur River mine. As part of the mill upgrades, we continue to construct and commission a new calciner circuit, and expect to begin operating with the new calciner in 2016. The existing calciner circuit will remain in place until operational reliability of the new calciner is achieved. The calciner replacement project was planned in a way that temporarily allows us to use either calciner, which will help to mitigate risks to our production rate during the commissioning phase. In order to increase production at Key Lake, we also need to optimize and expand the solvent extraction and crystallization circuits in the mill (projects planned for 2017).
At McArthur River, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. We plan to:
New mining areas
New mining zones and increased mine production require increased freeze capacity and ventilation. In 2015, we continued to upgrade our electrical infrastructure on surface as part of our plan to address these future needs. We advanced groundworks to prepare for the next freeze plant, which is scheduled to begin freezing the south end of the orebody (zone 4) in 2017.
We also made changes in shaft 2 to increase air flow, resulting in a 15% to 20% improvement in ventilation capacity. The improved ventilation eliminates the need for a new ventilation shaft to support a higher production rate.
We expect to have sufficient tailings capacity to 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.
PLANNING FOR THE FUTURE AT MCARTHUR RIVER/KEY LAKE
We plan to produce 20.0 million pounds in 2016; our share is 14.0 million pounds.
As previously disclosed in our 2012 Technical Report, we plan to reach an annual capacity of 22 million pounds by 2018. The capital required to do so is shown in our 2016 capital spending plan, and in our outlook for investing activities in 2017 and 2018, beginning on page 6.
As we increase to 22 million pounds per year, we will optimize the capacity of both the Key Lake mill and McArthur River mine with a view to further increasing production to 25 million pounds per year (100% basis), as market conditions improve. Using this approach, we do not expect significant additional growth capital will be required to increase from annual production of 22 million pounds to an annual rate of 25 million pounds. We expect that this paced approach will allow us to extract maximum value from the operation as the market transitions.
In 2015, underground drilling further delineated the zone A mineral resources. Underground definition drilling of zone B will be conducted in 2016 and 2017 to provide the information required for engineering work to develop more detailed mining plans.
Total packaged production from Cigar Lake was 11.3 million pounds U3O8; our share was 5.7 million pounds. The operation exceeded our forecast of 10 million pounds (100% basis) as a result of higher productivity and our intention to adjust annual production as necessary, based on our operating experience during rampup.
During the year, we:
Commercial production signals a transition in the accounting treatment for costs incurred at the mine. Cigar Lake met all of the criteria for commercial production, including cycle time and process specifications, in the second quarter of 2015. Therefore, effective May 1, 2015, we began charging all production costs, including depreciation, to inventory and subsequently recognizing them in cost of sales as the product is sold.
As a result of our decision to exclusively use surface freezing going forward, and the resulting change in the mine plan, the bulk of the development and freeze drilling required for mining in 2016 is already complete. We are continuing to plan for future expansion of surface freezing infrastructure in late 2016.
McClean Lake mill update
Additional estimated expenditures of $50 million (100% basis, our share $25 million) are expected to be required at the McClean Lake mill in 2016, primarily to complete upgrades in the tailings neutralization area in support of the continued rampup to full production of 18 million pounds per year.
PLANNING FOR THE FUTURE AT CIGAR LAKE
In 2016, we expect to produce 16.0 million packaged pounds at Cigar Lake; our share is 8.0 million pounds.
In 2016, we also expect to:
We are planning to conduct delineation drilling from surface to confirm and upgrade resources contained in the western portion of the deposit. Approximately 65,000 metres of diamond drilling is planned over a three-year period, starting in 2016, in order to complete a detailed geological and geotechnical interpretation, a resource estimate, and a technical study for the western portion of the deposit.
In 2017, we expect to reach full annual production of 18 million pounds (100% basis, 9 million pounds our share).
The McClean Lake mill’s operating licence currently has an annual production limit of 13 million pounds. AREVA has submitted an application to the CNSC to increase the mill’s licensed annual production limit; our 2016 and 2017 production outlook for Cigar Lake is therefore subject to AREVA securing the regulatory approvals necessary to increase mill production.
The current collective agreement between AREVA and unionized employees at the McClean Lake operation expires in May 2016. There is risk to our 2016 and 2017 production outlook for Cigar Lake if AREVA is unable to reach an agreement and there is a labour dispute.
Total production from Inkai was 5.8 million pounds; our share was 3.4 million pounds. Production was 17% higher than our production in 2014. During 2015, the subsoil use law in Kazakhstan was amended to allow producers to produce within 20% (above or below) their licensed capacity in a year. As a result, Inkai produced 5.8 million pounds in 2015, 11% higher than its licensed capacity. The increase in production was the result of a higher head grade and an increase in wellfield development efficiency compared to 2014.
As of December 31, 2015, Inkai had fully repaid the outstanding loan under our agreement to fund its project development costs related to blocks 1 and 2. In 2015, Inkai paid the remaining $0.8 million (US) in interest on the loan and repaid $55 million (US) of principal.
We are currently advancing funds for Inkai’s work on block 3 and, as of December 31, 2015, the principal amounted to $148 million (US). Under the loan agreement, Inkai is to repay Cameco from the net sales proceeds from the sale of production from block 3.
In 2012, we entered into a binding memorandum of agreement (2012 MOA) with our joint venture partner, Kazatomprom, setting out a framework to:
Kazatomprom is pursuing a strategic objective to develop uranium processing capacity in Kazakhstan to complement its leading uranium mining operations. Their primary focus is now on uranium refining, which is an intermediate step in the uranium conversion process. A Nuclear Co-operation Agreement between Canada and Kazakhstan is in place, providing the international framework necessary for applying to the two governments for the required licences and permits. We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. Discussions continue with Kazatomprom.
Block 3 exploration
In 2015, Inkai completed construction of the test leach facility and began pilot production from test wellfields, as well as advancing work on a preliminary appraisal of the mineral potential of block 3 according to Kazakhstan standards.
Block 3 licence extension
The block 3 test leach facility is now operational and state commissioning of the test wellfields was accomplished during 2015. Our application for an extension of the block 3 evaluation period is still pending final approval from the Ministry of Energy of the Republic of Kazakhstan. Inkai continues working on the final appraisal of the mineral potential of block 3 according to Kazakhstan standards. Although a number of extensions of the licence term have been granted by Kazakh regulatory authorities in the past, there is no assurance that a further extension will be granted. Without such extension, there is a risk we could lose our rights to block 3, and a risk we will not be compensated for the funds we advanced to Inkai to fund block 3 activities.
PLANNING FOR THE FUTURE AT INKAI
We expect total production from blocks 1 and 2 to be 5.2 million pounds in 2016; our share is 3.0 million pounds. We expect to maintain production at this level until the potential growth plans are finalized with Kazatomprom.
Block 3 exploration
In 2016, Inkai expects to continue with pilot production from the test leach facility and to continue working on a final appraisal of the mineral potential according to Kazakhstan standards.
Production this year was unchanged from our 2014 production as a result of planned timing of production stopes, coupled with slightly improved ore grades.
Development and production continued at the Eagle Point mine. At the mill, we continued to improve the efficiency of the mill operation schedule.
Temporary mining restrictions
On December 17, 2015, we announced that underground mining activities at Eagle Point were being restricted due to a rock fall in an inactive area of the mine. As a precautionary measure, non-essential personnel were removed from the mine while the condition of the affected area was evaluated. Mine production was suspended, although milling of previously mined and transported ore continued through to year end.
The assessment determined that repairs were necessary to support the ground in the affected area of the mine. The repairs were completed, along with some further assessment of stability in other areas of the mine. The mine was reopened and normal operations resumed on February 3, 2016.
PLANNING FOR THE FUTURE AT RABBIT LAKE
We expect to produce 3.6 million pounds in 2016. The decrease compared to 2015 is the result of the restriction of mining activities at the end of 2015, which extended into 2016.
Under our current licence, we expect to have sufficient tailings capacity to support milling of Eagle Point ore until about late 2017, based upon expected ore tonnage, milling rates and tailings properties.
Our plan for fully utilizing the available tailings capacity of the Rabbit Lake In-Pit Tailings Management facility requires regulatory approval in 2016 for which we have submitted the required applications. With these regulatory approvals and after we complete the necessary work on the existing pit, we expect to then have sufficient tailings capacity to support milling of Eagle Point ore until at least 2021 based upon expected ore tonnage, milling rates, and tailings properties.
We plan to continue our underground drilling reserve replacement program in areas of interest north and northeast of the current mine workings in 2016. The drilling will be carried out from underground locations.
As part of our multi-year site-wide reclamation plan, we spent over $0.7 million in 2015 to reclaim facilities that are no longer in use and plan to spend over $0.5 million in 2016.
Fuel services produced 9.7 million kgU, 16% lower than 2014. This was a result of our decision to decrease production in response to weak market conditions and the termination of our toll milling agreement with SFL in 2014.
Port Hope conversion facility cleanup and modernization (Vision in Motion)
The Vision in Motion project is currently in the feasibility stage and will continue with the CNSC licensing process in 2016, which is required to advance the project.
Approximately 100 unionized employees at Cameco Fuel Manufacturing Inc.’s operations in Port Hope and Cobourg, Ontario accepted a new collective bargaining agreement in the second quarter of 2015. The employees, represented by the United Steelworkers local 14193, agreed to a three-year contract that includes a 7% wage increase over the term of the agreement. The previous contract expired on June 1, 2015.
PLANNING FOR THE FUTURE AT FUEL SERVICES
We have decreased our production target for 2016 to between 8 million and 9 million kgU in response to the continued weak market conditions.
The current collective bargaining agreement for our unionized employees at the Port Hope conversion facility expires on June 30, 2016. We will commence the bargaining process in early 2016.
The current operating licence for the Port Hope conversion facility expires in February 2017. The CNSC relicensing process will take place in 2016.
The technical and scientific information discussed in this document for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:
MCARTHUR RIVER/KEY LAKE
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:
Examples of forward-looking information in this document
We invite you to join our fourth quarter conference call on Monday, February 8, 2016 at 11:00 a.m. Eastern.
The call will be open to all investors and the media. To join the call, please dial (800) 769-8320 (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:
2016 quarterly report release dates
We plan to announce our 2016 quarter results as follows:
The 2017 date for the announcement of our fourth quarter and 2016 consolidated financial and operating results will be provided in our 2016 third quarter MD&A. Announcement dates are subject to change.
Our 2015 annual management’s discussion and analysis, and annual audited financial statements, will be available shortly on our website at cameco.com, on SEDAR at sedar.com and on EDGAR at sec.gov/edgar.shtml. Our 2015 annual information form is expected to be available later in March.
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 Energy GmbH, unless otherwise indicated.