Direct administration costs in 2015 were $10 million higher than in 2014 due to costs related to our collaboration agreement with the startup of Cigar Lake, increased legal costs as our CRA dispute progresses toward trial, and the effect of foreign exchange on our US subsidiaries.
We recorded $14 million in stock-based compensation expenses this year under our stock option, restricted share unit, deferred share unit, performance share unit and phantom stock option plans, compared to $13 million in 2014. See note 25 to the financial statements.
Outlook for 2016
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.
Our 2015 exploration activities remained focused on Canada and Australia. As we continued to focus more on our core projects in Saskatchewan, and reduced our activities elsewhere, we decreased our spending from $47 million in 2014 to $40 million in 2015.
Outlook for 2016
We expect exploration expenses to be about 15% to 20% higher than they were in 2015 due to increased exploration activity at Cigar Lake.
Finance costs were $104 million compared to $112 million in 2014. The decrease from last year was a result of $12 million in settlement costs related to the early redemption of our Series C debentures being incurred in 2014, partially offset by higher interest on long-term debt in 2015. See note 20 to the financial statements.
Finance income was $5 million compared to $7 million in 2014, reflecting lower average cash balances in 2015.
Gains and losses on derivatives
In 2015, we recorded $281 million in losses on our derivatives compared to losses of $121 million in 2014. The increase reflects the continued weakening of the Canadian dollar compared to the US dollar in 2015. See Foreign exchange and note 27 to the financial statements.
We recorded an income tax recovery of $143 million in 2015 compared to a recovery of $175 million in 2014. The decrease in recovery was primarily due to the write-off of our deferred tax asset in the US, partially offset by a reduction in the provision related to our CRA litigation and a change in the distribution of earnings between jurisdictions compared to 2014. See note 22 to the financial statements.
During the fourth quarter, we reversed amounts related to our deferred tax asset in the US totaling $73 million. We determined that it was no longer probable that there would be sufficient taxable profit in the future against which the operating losses and other tax deductions could be used.
The recovery was impacted by a decrease of $42 million to our provision related to the CRA litigation. Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2010 tax returns. 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. See note 22 to the financial statements.
In 2015, we recorded losses of $960 million in Canada compared to $841 million in 2014, while earnings in foreign jurisdictions increased to $880 million from $722 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate.
In the third quarter, we expected our annual income tax rate, based on adjusted net earnings, to be a recovery of 25% to 30%. The actual result was a recovery of 15%, mainly due to one-time adjustments as discussed above. On an adjusted earnings basis, we recognized a tax recovery of $44 million in 2015 compared to a recovery of $120 million in 2014. Our effective tax rate was a recovery of 15% in 2015, compared to a recovery of 41% in 2014. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.
|Pre-tax adjusted earnings 1|
|Total pre-tax adjusted earnings||299||290|
|Adjusted income taxes 1|
|Adjusted income tax recovery||(44)||(120)|
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:
- the governance (structure) of the corporate entities involved in the transactions
- the price at which goods and services are sold by one member of a corporate group to another
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 is also proposing to allocate 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)||Cash Taxes||Interest and
|Total||Cash Remittance||Secured by LC|
|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 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 paid 1||420||255 – 280||65 – 90||825 – 850|
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 prices received by our US mining subsidiaries for the sale of uranium to CEL are too low
- the compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate
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||
|Years under consideration||
|Timing of resolution||
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 the Forward-Looking Information page and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.
- CRA will reassess us for the years 2011 through 2015 using a similar methodology as for the years 2003 through 2010, and the reassessments will be issued on the basis we expect
- we will be able to apply elective deductions and utilize letters of credit to the extent anticipated
- CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years 2007 through 2009) in addition to interest charges and instalment penalties
- we will be substantially successful in our dispute with CRA and the cumulative tax provision of $50 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date
- IRS may propose adjustments for later years subsequent to 2012
- we will be substantially successful in our dispute with IRS
Material risks that could cause actual results to differ materially
- CRA reassesses us for years 2011 through 2015 using a different methodology than for years 2003 through 2010, or we are unable to utilize elective deductions or letters of credit to the extent anticipated, resulting in the required cash payments or security provided to CRA pending the outcome of the dispute being higher than expected
- the time lag for the reassessments for each year is different than we currently expect
- we are unsuccessful and the outcomes of our dispute with CRA and/or IRS result 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 or IRS not related to transfer pricing
- IRS proposes adjustments for years 2013 through 2015 using a different methodology than for 2009 through 2012
- we are unable to effectively eliminate all double taxation
Outlook for 2016
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.
The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments.
We sell the majority of our uranium and fuel services products under long-term contracts, which are routinely denominated in US dollars, while our production costs are largely denominated in Canadian dollars. To provide cash flow predictability and certainty as we undertake our operating and capital expenditures, we use hedging to try to protect our net exposure (e.g. total sales less US dollar expenses and product purchases) against shorter term exchange rate volatility.
Our risk management policy permits us to hedge 35% to 100% of our expected net exposure over a rolling 60-month period. Our normal practice is to hedge over a three- to four-year period by hedging 50% to 80% of net exposure in the first 12 months with decreasing hedge ratios in subsequent years. The actual hedge position is reflected in Revenue, cash flow and earnings sensitivity analysis.
In the reporting period, some hedge contracts may be settled and the remaining contracts outstanding, we mark-to-market, which can result in reported gains or losses on derivatives for the period depending on the movement in the US/Cdn exchange rate. In periods of rapid currency fluctuations, the average exchange rate under our hedge contracts will lag the market. For example, the average US/Cdn exchange rate for our 2015 hedge position included exchange rates for periods prior to the rapid devaluation of the Canadian dollar and was much lower than the average exchange rate for 2015. As a result, as a Canadian dollar reporter, we reported significant losses on derivatives in 2015. However, over time and as we add hedges at current market rates, we expect to realize the benefit of the weak Canadian dollar as the average exchange rate under our hedge contracts increases. In the event of a rapidly appreciating Canadian dollar, we would see the opposite effect.
Since we use hedging to protect our foreign exchange exposure in a particular period, when we put contracts in place we designate them for use in that period. Therefore, a portion of the reported gains and losses noted above do not apply in the current period. We take this into account in our adjusted net earnings measure, with the goal of better matching the benefits of our hedging activities with the expected foreign currency exposure to which they apply. In our adjusted net earnings measure, we adjust net earnings in the reporting period for one-time items that are not representative of our ongoing operations and to:
- remove mark-to-market gains or losses on the outstanding hedge position at the end of the period
- remove the portion of gains and losses on those contracts that were rolled over in the reporting period for use in a future period
- add back gains and losses previously removed and that apply to the current period
At December 31, 2015:
- The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.38 (Cdn), up from $1.00 (US) for $1.16 (Cdn) at December 31, 2014. The exchange rate averaged $1.00 (US) for $1.28 (Cdn) over the year.
- We had foreign currency forward contracts of $1.0 billion (US), EUR 12 million and foreign currency options of $250 million (US) at December 31, 2015. The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.23 (Cdn) and US currency option contracts had an average exchange rate range of $1.00 (US) for $1.28 to $1.34 (Cdn), and €1.00 for $1.11 (US) for EUR currency contracts.
- The mark-to-market loss on all foreign exchange contracts was $167 million compared to a $67 million loss at December 31, 2014.
We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2015, with the exception of the EUR hedge, all of our counterparties to foreign exchange hedging contracts had a Standard & Poor’s (S&P) credit rating of A or better.