Cameco
TSX : CCO
NYSE : CCJ

Cameco

October 30, 2015 18:47 ET

Cameco reports third quarter financial results

SASKATOON, SASKATCHEWAN--(Marketwired - Oct. 30, 2015) -

  • higher consolidated revenue and gross profit for the first nine months
  • lower uranium segment gross profit for the quarter and first nine months
  • annual uranium sales outlook confirmed
  • strong performance at Cigar Lake, increased annual production target range

ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED)

Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated financial and operating results for the third quarter ended September 30, 2015 in accordance with International Financial Reporting Standards (IFRS).

"Our results for the quarter and the first nine months are as expected" said Tim Gitzel, president and CEO, "with a higher proportion of our deliveries scheduled for the fourth quarter.

"We've continued to see the oversupply in the market impacting demand and price, and while we can't control the pace of industry recovery, we can ensure that our company is ready at each step along the way. Our positive long-term view has not changed, so today that means preparing for the demand-driven market we see coming, by keeping our costs down and operating our mines safely and efficiently. Those mines continue to return excellent results, particularly Cigar Lake, which has already exceeded our 2015 production target range. The Cigar Lake operation, along with our other world-class assets, are at the core of our strategy to enhance our operating leverage and maintain the flexibility needed to respond quickly as the market improves."

THREE MONTHS NINE MONTHS
HIGHLIGHTS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
($ MILLIONS EXCEPT WHERE INDICATED) 2015 2014 CHANGE 2015 2014 CHANGE
Revenue 649 587 11 % 1,779 1,508 18 %
Gross profit 133 143 (7 )% 415 386 8 %
Net earnings (losses) attributable to equity holders (4 ) (146 ) 97 % 75 113 (34 )%
$ per common share (diluted) (0.01 ) (0.37 ) 97 % 0.19 0.28 (32 )%
Adjusted net earnings (non-IFRS, see section) 78 93 (16 )% 193 207 (7 )%
$ per common share (adjusted and diluted) 0.20 0.23 (13 )% 0.49 0.52 (6 )%
Cash provided by (used in) operations (after working capital changes) (121 ) 263 (146 )% (53 ) 244 (122 )%

THIRD QUARTER

Net losses attributable to equity holders this quarter were $4 million ($0.01 per share diluted) compared to net losses of $146 million ($0.37 per share diluted) in the third quarter of 2014. In addition to the items noted below, our net losses were affected by mark-to-market losses on foreign exchange derivatives. Net losses in the third quarter of 2014 included the impairment of our investment in GE-Hitachi Global Laser Enrichment of $184 million and the impairment of our investment in GoviEx Uranium Inc. of $12 million.

On an adjusted basis, our earnings this quarter were $78 million ($0.20 per share diluted) compared to earnings of $93 million ($0.23 per share diluted) (non-IFRS measure, see section) in the third quarter of 2014. The change was mainly due to:

  • lower gross profit from our uranium segment
  • lower tax recovery

partially offset by:

  • higher gross profit from our fuel services and NUKEM segments

See Financial results by segment below for more detailed discussion.

FIRST NINE MONTHS

Net earnings in the first nine months of the year were $75 million ($0.19 per share diluted) compared to earnings of $113 million ($0.28 per share diluted) in the first nine months of 2014. In addition to the items noted below, our net earnings were affected by mark-to-market losses on foreign exchange derivatives. Our 2014 earnings also included a gain on the sale of our interest in BPLP of $127 million, the impairment of our investment in GE-Hitachi Global Laser Enrichment of $184 million and the impairment of our investment in GoviEx Uranium Inc. of $12 million.

On an adjusted basis, our earnings for the first nine months of this year were $193 million ($0.49 per share diluted) compared to earnings of $207 million ($0.52 per share diluted) (non-IFRS measure, see section) for the first nine months of 2014. Key variances include:

  • lower gross profit from our uranium segment
  • higher administration costs
  • a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014
  • lower tax recovery

partially offset by:

  • higher gross profit from our fuel services and NUKEM segments
  • lower losses from equity accounted investments

Our 2014 adjusted net earnings were also impacted by:

  • an early termination fee of $18 million incurred in 2014 as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd., which was to expire in 2016
  • settlement costs of $12 million with respect to the early redemption our Series C debentures recorded in 2014

See Financial results by segment below for more detailed discussion.

Uranium market update

In the third quarter, there was no significant change to the market in terms of contract volumes or price. Quantities transacted in the spot market were at normal levels, and spot prices remained in the mid-$30s (US). This is in keeping with the rest of the year so far, and is, we believe, simply a function of the currently over-supplied market.

Reactor restarts in Japan remain an important driver of market sentiment in the short term, and the first of these were finally realized: Kyushu's Sendai unit 1 restarted in August and unit 2 in mid-October. Three additional reactors have been approved by the regulator to restart, and twenty more applications await decisions. We remain confident that a significant number of units will be restarted in Japan over time, though the regulatory approval process and restart schedules are clearly hard to predict.

Longer term, strong fundamentals underpin a positive outlook for the industry. The 65 reactors under construction today and additional units planned over the next decade means increasing uranium demand as those reactors come online. As future supply continues to be negatively affected by current depressed market conditions, we expect to see a shift from the currently over-supplied market we are experiencing today to a demand-driven market that requires more primary supply. Demand growth combined with the timing, development and execution of new supply projects and the continued performance of existing supply, will determine the pace of that shift.

Caution about forward-looking information relating to our uranium market update

This discussion of our expectations for the nuclear industry, including its growth profile, future global uranium supply and demand 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 below.

Outlook for 2015

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 2015 reflects the expenditures necessary to help us achieve our strategy. Our outlook for uranium production, uranium, fuel services and NUKEM revenue, NUKEM unit cost, consolidated tax rate, and capital expenditures has changed. We do not provide an outlook for the items in the table that are marked with a dash.

See 2015 Financial results by segment below for details.

2015 FINANCIAL OUTLOOK
CONSOLIDATED URANIUM FUEL SERVICES NUKEM
Production - 27.3
million lbs
9 to 10
million kgU
-
Sales volume1 - 31 to 33
million lbs
Decrease
5% to 10%
7 to 8
million lbs U3O8
Revenue compared to 20142 Increase
5% to 10%
Increase
5% to 10%
3
Increase
5% to 10%
Increase
30% to 35%
Average unit cost of sales (including D&A) - Increase
5% to 10%4
Increase
5% to 10%
Increase
15% to 20%
Direct administration costs compared to 20145 Increase
5% to 10%
- - -
Exploration costs compared to 2014 - Decrease
5% to 10%
- -
Tax rate6 Recovery of
25% to 30%
- - -
Capital expenditures $385 million - - -
1 Our 2015 outlook for sales volume does not include sales between our uranium, fuel services and NUKEM segments.
2 For comparison of our 2015 outlook and 2014 results for revenue, we do not include sales between our uranium, fuel services and NUKEM segments.
3 Based on a uranium spot price of $36.50 (US) per pound (the Ux spot price as of October 26, 2015), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on October 26, 2015) and an exchange rate of $1.00 (US) for $1.25 (Cdn).
4 This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in the remainder of 2015, then we expect the overall unit cost of sales to increase further.
5 Direct administration costs do not include stock-based compensation expenses.
6 Our outlook for the tax rate is based on adjusted net earnings.

We have increased our uranium production outlook to 27.3 million pounds U3O8 (previously between 25.3 million and 26.3 million pounds) to reflect the higher expected production from Cigar Lake/McClean Lake. See Uranium 2015 Q3 updates below for more information.

Our outlook for uranium revenue and for fuel services revenue have both changed to an increase of 5% to 10% in each segment (previously an increase up to 5% in each) due to the effects of foreign exchange. We have also adjusted our outlook for NUKEM revenue to an increase of 30% to 35% (previously an increase of 20% to 25%) due to the effects of foreign exchange; however, the higher revenue expectation is largely offset by our adjusted outlook for NUKEM unit cost of sales, which is now expected to increase 15% to 20% (previously an increase of 5% to 10%), also due to the effects of foreign exchange.

We have adjusted our outlook for the consolidated tax rate to a recovery of 25% to 30% (previously 40% to 45%) due to the expected impact of the changes to our revenue outlook noted above, and a change in the distribution of earnings between jurisdictions.

We now expect capital expenditures to be $385 million (previously $405 million). The decrease is primarily due to the timing of expenditures on projects at Key Lake and McArthur River, as well as a reduction in planned spending at Cigar Lake due to changes in the mine plan, slightly offset by increased costs at Inkai and our US operations due to the effect of foreign exchange.

REVENUE AND EARNINGS SENSITIVITY ANALYSIS

For the rest of 2015:

  • an increase of $5 (US) per pound in both the Ux spot price ($36.50 (US) per pound on October 26, 2015) and the Ux long-term price indicator ($44.00 (US) per pound on October 26, 2015) would increase revenue by $22 million and net earnings by $12 million. Conversely, a decrease of $5 (US) per pound would decrease revenue by $19 million and net earnings by $9 million.
  • a one-cent change in the value of the Canadian dollar versus the US dollar would change adjusted net earnings by $3 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact

ADJUSTED NET EARNINGS (NON-IFRS MEASURE)

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 has also been adjusted for NUKEM purchase price inventory write-downs and recoveries, income taxes on adjustments, impairment charges on non-producing property, and the after tax gain on the sale of our interest in BPLP.

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.

The following table reconciles adjusted net earnings with our net earnings.

THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
($ MILLIONS) 2015 2014 2015 2014
Net earnings (losses) attributable to equity holders (4 ) (146 ) 75 113
Adjustments
Adjustments on derivatives (pre-tax) 112 60 157 37
NUKEM purchase price inventory recovery - (2 ) (3 ) (2 )
Impairment charge - 196 6 196
Income taxes on adjustments (30 ) (15 ) (42 ) (10 )
Gain on interest in BPLP (after tax) - - - (127 )
Adjusted net earnings 78 93 193 207

Discontinued operation

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP, which was accounted for effective January 1, 2014. The aggregate sale price for our interest in BPLP and certain related entities was $450 million. We realized an after tax gain of $127 million on this divestiture. As a result of the transaction, we presented the results of BPLP as a discontinued operation and we revised our statement of earnings, statement of comprehensive income and statement of cash flows to reflect the change in presentation. See note 4 to the interim financial statements for more information.

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with Canada Revenue Agency (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 2009, CRA has shifted CEL's income (as re-calculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. The IRS also allocated a portion of CEL's income for 2009 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $290 million for the 2003 - 2014 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.

CRA dispute

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 2009 tax returns. We have recorded a cumulative tax provision of $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 September 30, 2015. 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 2009, CRA issued notices of reassessment for approximately $2.8 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $820 million. We expect to receive the reassessment for 2010 in the fourth quarter. 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 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 paid a net amount of $229 million cash to the Government of Canada, which includes the amounts shown in the table below.


YEAR PAID ($ MILLIONS)
CASH
TAXES

INTEREST AND
INSTALMENT PENALTIES
TRANSFER PRICING
PENALTIES

TOTAL
Prior to 2013 - 13 - 13
2013 1 9 36 46
2014 106 47 - 153
2015 (63 ) 1 79 17
Total 44 70 115 229

Using the methodology we believe CRA will continue to apply, and including the $2.8 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $6.6 billion of additional income taxable in Canada for the years 2003 through 2014, which would result in a related tax expense of approximately $1.9 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 $1.45 billion and $1.5 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 $725 million and $750 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 will not change the total amount shown in the table below as paid, secured or owing, but it does change the distribution among years. As an alternative to paying cash, we expect to be able to provide security in the form of letters of credit to satisfy our requirements. We have updated the table below to reflect the potential use of letters of credit. 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 2014, and include the expected adjustment for the inability to use 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 2014.

$ MILLIONS 2003 - 2014 2015 2016 - 2017 2018 - 2023 TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period1
Cash payments 143 35 - 60 155 - 180 0 335 - 360
Potential letters of credit 0 255 - 280 95 - 120 15 - 40 380 - 400
Total paid 143 295 - 320 255 - 280 15 - 40 725 - 750
1 These amounts do not include interest and instalment penalties, which totalled approximately $70 million to September 30, 2015.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $229 million already paid to date.

We are expecting the trial for the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016 and to conclude within four months thereafter. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

In the first quarter, we received a Revenue Agent's Report (RAR) from the IRS challenging the transfer pricing used under certain intercompany transactions pertaining to the 2009 tax year for certain of our US subsidiaries. The RAR lists the adjustments proposed by the IRS and calculates 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 being 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 $108 million (US) and a corresponding increased income tax expense of approximately $32 million (US) for the 2009 taxation year, with interest being charged thereon. In addition, the IRS proposed penalties of approximately $7 million (US) in respect of the adjustment.

At present, the RAR pertains only to the 2009 tax year; however, the IRS is also auditing our tax returns for 2010 through 2012 on a similar basis and we expect adjustments in these years to be similar to those made for 2009. If the IRS audits years subsequent to 2012 on a similar basis, we expect these proposed adjustments would also be similar to those made for 2009.

We believe that the conclusions of the IRS in the RAR are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. At present, this matter is still at an early stage and, 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.

Caution about forward-looking information relating to our CRA and IRS tax disputes

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 below and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

Assumptions

  • CRA will reassess us for the years 2010 through 2014 using a similar methodology as for the years 2003 through 2009, and the reassessments will be issued on the basis we expect
  • we will be able to apply elective deductions to the extent anticipated
  • we will be able to 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 $92 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date
  • IRS will continue to propose adjustments for the years 2010 through 2012 and may propose adjustments for later years
  • 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 2010 through 2014 using a different methodology than for years 2003 through 2009, or we are unable to apply elective deductions or utilize letters of credit 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 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 2010 through 2014 using a different methodology than for 2009
  • we are unable to effectively eliminate all double taxation
Financial results by segment
Uranium
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
HIGHLIGHTS 2015 2014 CHANGE 2015 2014 CHANGE
Production volume (million lbs) 8.2 5.4 52 % 18.7 15.1 24 %
Sales volume (million lbs)1 6.9 9.0 (23 )% 21.2 23.3 (9 )%
Average spot price ($US/lb ) 36.21 31.80 14 % 36.91 31.90 16 %
Average long-term price ($US/lb ) 44.17 44.33 - 47.06 45.94 2 %
Average realized price ($US/lb ) 43.61 45.87 (5 )% 44.57 46.14 (3 )%
($Cdn/lb ) 56.07 49.83 13 % 55.65 50.35 11 %
Average unit cost of sales (including D&A) ($Cdn/lb ) 40.16 35.09 14 % 39.13 34.81 12 %
Revenue ($ millions)1 388 447 (13 )% 1,179 1,171 1 %
Gross profit ($ millions) 110 132 (17 )% 350 362 (3 )%
Gross profit (%) 28 30 (7 )% 30 31 (3 )%
1 Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil pounds in sales and nil revenue in Q3, 2015; 802,000 pounds and revenue of $28.0 million in Q3, 2014; 15,000 pounds in sales and revenue of $0.5 million in the first nine months of 2015; 967,000 pounds and revenue of $33.0 million in the first nine months of 2014).

THIRD QUARTER

Production volumes this quarter were 52% higher compared to the third quarter of 2014, mainly due to production from Cigar Lake and higher production from McArthur River/Key Lake, Rabbit Lake and Inkai, which was partially offset by lower production at our US operations. See Uranium 2015 Q3 updates below for more information.

The 13% decrease in uranium revenues was a result of a 23% decrease in sales volume, partially offset by a 13% increase in the Canadian dollar average realized price.

The US dollar average realized price decreased by 5% compared to 2014 mainly due to lower prices on fixed price contracts, while the higher Canadian dollar realized prices this quarter were a result of the weakening of the Canadian dollar compared to 2014. This quarter the exchange rate on the average realized price was $1.00 (US) for $1.29 (Cdn) compared to $1.00 (US) for $1.09 (Cdn) in the third quarter of 2014.

Total cost of sales (including D&A) decreased by 12% ($278 million compared to $315 million in 2014) due to a 23% decrease in sales volume, partially offset by a 14% increase in the unit cost of sales. The increase in the unit cost of sales was mainly the result of an increase in the volume of material purchased in the quarter at prices higher than our average cost of inventory and an increase in unit production costs related to the addition of higher cost production from Cigar Lake during ramp up.

The net effect was a $22 million decrease in gross profit for the quarter.

FIRST NINE MONTHS

Production volumes for the first nine months of the year were 24% higher than in the previous year due to the addition of production from Cigar Lake and higher production at McArthur/Key Lake, and Rabbit Lake, partially offset by lower production at our US operations. See Uranium 2015 Q3 updates below for more information.

Uranium revenues increased 1% compared to the first nine months of 2014 due to an 11% increase in the Canadian dollar average realized price, partially offset by a 9% decrease in sales volumes in the first nine months.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales volumes and revenue can vary significantly. We are on track to meet our 2015 uranium sales targets, and, therefore, expect to deliver between 10 million and 12 million pounds in the fourth quarter.

Our Canadian dollar realized prices for the first nine months of 2015 were higher than 2014, primarily as a result of the weakening of the Canadian dollar compared to 2014. For the first nine months of 2015, the exchange rate on the average realized price was $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.09 (Cdn) for the same period in 2014.

Total cost of sales (including D&A) increased by 2% ($829 million compared to $810 million in 2014) mainly due to a 12% increase in the unit cost of sales, partially offset by a 9% decrease in sales volume for the first nine months. The increase in the unit cost of sales was mainly the result of an increase in the volume of material purchased in the first nine months at prices higher than our average cost of inventory, and an increase in unit production costs related to the addition of higher cost production from Cigar Lake during rampup.

The net effect was a $12 million decrease in gross profit for the first nine months.

We are active in the uranium market, buying and selling uranium on the spot market and under long-term contracts when we expect it will be beneficial for us. Purchases are impacted by foreign exchange rates, and may, in some cases, require we pay prices higher or lower than current spot prices. Depending on the volume and unit cost of purchases in a quarter, our average cost of inventory can be impacted, which flows through to our cost of sales.

The table below shows the costs of produced and purchased uranium incurred in the reporting periods (which are non-IFRS measures, see the paragraphs below the table). 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 NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
($CDN/LB) 2015 2014 CHANGE 2015 2014 CHANGE
Produced
Cash cost 17.56 17.91 (2 )% 22.97 21.19 8 %
Non-cash cost 9.53 7.31 30 % 11.79 10.47 13 %
Total production cost 27.09 25.22 7 % 34.76 31.66 10 %
Quantity produced (million lbs) 8.2 5.4 52 % 18.7 15.1 24 %
Purchased
Cash cost 47.19 30.91 53 % 46.83 37.25 26 %
Quantity purchased (million lbs) 2.7 1.8 50 % 9.3 3.4 174 %
Totals
Produced and purchased costs1, 2 32.07 26.64 20 % 38.77 32.69 19 %
Quantities produced and purchased (million lbs) 10.9 7.2 51 % 28.0 18.5 51 %
1 This quarter, cash costs of purchased material were $37.78 US per pound compared to $27.98 US per pound in the same period in 2014. In the third quarter the exchange rate on purchases averaged $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.10 (Cdn) in the third quarter of 2014.
2 For the first nine months, cash costs of purchased material were $37.51 US per pound compared to $33.89 per lb in the same period in 2014. For the first nine months of 2015, the exchange rate on purchases averaged $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.10 (Cdn) for the same period 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 third quarter and the first nine months of 2015 and 2014.

Cash and total cost per pound reconciliation
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
($ MILLIONS) 2015 2014 2015 2014
Cost of product sold 205.5 248.2 660.9 633.8
Add / (subtract)
Royalties (31.3 ) (21.5 ) (67.0 ) (56.7 )
Standby charges - (5.8 ) - (24.8 )
Other selling costs (1.9 ) (1.2 ) (7.1 ) (6.7 )
Change in inventories 99.1 (67.3 ) 278.1 (99.0 )
Cash operating costs (a) 271.4 152.4 864.9 446.6
Add / (subtract)
Depreciation and amortization 72.2 66.7 168.2 175.9
Change in inventories 6.0 (27.3 ) 52.5 (17.7 )
Total operating costs (b) 349.6 191.8 1,085.6 604.8
Uranium produced & purchased (million lbs) (c) 10.9 7.2 28.0 18.5
Cash costs per pound (a ÷ c) 24.90 21.17 30.89 24.14
Total costs per pound (b ÷ c) 32.07 26.64 38.77 32.69
Fuel services
(includes results for UF6, UO2 and fuel fabrication)
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
HIGHLIGHTS 2015 2014 CHANGE 2015 2014 CHANGE
Production volume (million kgU) 0.6 1.1 (45 )% 6.3 8.9 (29 )%
Sales volume (million kgU) 3.8 3.1 23 % 9.1 8.2 11 %
Average realized price ($Cdn/kgU ) 22.22 23.11 (4 )% 24.11 22.21 9 %
Average unit cost of sales (including D&A) ($Cdn/kgU ) 18.75 21.55 (13 )% 19.71 19.46 1 %
Revenue ($ millions) 83 71 17 % 220 182 21 %
Gross profit ($ millions) 13 5 160 % 40 23 74 %
Gross profit (%) 16 7 129 % 18 13 38 %

THIRD QUARTER

Total revenue for the third quarter of 2015 increased to $83 million from $71 million for the same period last year. A 23% increase in sales volumes was partially offset by a 4% decrease in average realized price, primarily due to the mix of products sold, partially offset by the weakening of the Canadian dollar compared to 2014.

The total cost of products and services sold (including D&A) increased by 6% ($70 million compared to $66 million in the third quarter of 2014) due to the increase in sales volumes, partially offset by a decrease in the average unit cost of sales. When compared to 2014, the average unit cost of sales was 13% lower due to the mix of fuel services products sold, partially offset by higher production costs.

The net effect was an $8 million increase in gross profit.

FIRST NINE MONTHS

In the first nine months of the year, total revenue increased by 21% due to an 11% increase in sales volumes and a 9% increase in realized price that was the result of the weakening of the Canadian dollar and the mix of products sold.

The total cost of sales (including D&A) increased 13% ($180 million compared to $159 million in 2014) due to an increase in sales volume and a 1% increase in the average unit cost of sales, which resulted from increased production costs, partially offset by the mix of fuel services products sold.

The net effect was a $17 million increase in gross profit.

NUKEM
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
HIGHLIGHTS 2015 2014 CHANGE 2015 2014 CHANGE
Uranium sales (million lbs)1 2.9 2.5 16 % 6.9 4.7 47 %
Average realized price ($Cdn/lb ) 52.70 38.52 37 % 46.97 39.72 18 %
Cost of product sold (including D&A) 170 88 93 % 326 171 91 %
Revenue ($ millions)1 183 97 89 % 361 190 90 %
Gross profit ($ millions) 14 9 56 % 35 19 84 %
Gross profit (%) 8 9 (11 )% 10 10 -
1 Includes sales and revenue between our uranium, fuel services and NUKEM segments (130,000 pounds in sales and revenue of $6.0 million in Q3, 2015, nil in Q3, 2014; 873,000 pounds in sales and revenue of $19.3 million in the first nine months of 2015, nil in the first nine months of 2014).

THIRD QUARTER

During the third quarter of 2015, NUKEM delivered 2.9 million pounds of uranium, an increase of 16% from the same period last year. Total revenues increased by 89% as a result of higher sales volumes and average realized prices which were 37% higher than those realized in the third quarter of 2014.

Gross profit percentage was 8% in the third quarter of 2015, a slight increase from 9% recorded in the third quarter of 2014. The allocation of the historic purchase price to the sale of inventory on hand at the time of acquisition of NUKEM, impacted margins for the quarter.

The net effect was a $5 million increase in gross profit.

FIRST NINE MONTHS

During the nine months ended September 30, 2015, NUKEM delivered 6.9 million pounds of uranium, an increase of 47%, due to timing of customer requirements and generally lower activity in the market during 2014. Total revenues increased 90% due to a 47% increase in sales volumes and an 18% increase in average realized price.

Gross profit percentage was 10% for the first nine months of 2015, unchanged from the same period in 2014. Included in the 2014 margin was a $6 million write-down of inventory compared to a $3 million recovery in 2015. The write-down in 2014 was a result of a decline in the spot price during the period.

The net effect was a $16 million increase in gross profit.

Uranium 2015 Q3 updates

URANIUM PRODUCTION
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
OUR SHARE (MILLION LBS) 2015 2014 CHANGE 2015 2014 CHANGE 2015 PLAN
McArthur River/Key Lake 3.9 3.1 26 % 9.5 9.0 6 % 13.7
Cigar Lake 1.8 - - 3.3 - - 5.0
Inkai 1.0 0.8 25 % 2.2 2.2 - 3.0
Rabbit Lake 1.1 0.9 22 % 2.2 2.0 10 % 3.9
Smith Ranch-Highland 0.3 0.5 (40 )% 1.2 1.5 (20 )% 1.4
Crow Butte 0.1 0.1 - 0.3 0.4 (25 )% 0.3
Total 8.2 5.4 52 % 18.7 15.1 24 % 27.3

MCARTHUR RIVER/KEY LAKE

Production for the quarter was 26% higher compared to the same period last year and 6% higher for the first nine months due to the timing of mill maintenance.

At Key Lake, commissioning of the new calciner is underway and expected to be complete by year end. The existing calciner circuit will remain in place until operational reliability of the new calciner is achieved. The operation remains on track to achieve our planned 2015 production; however, operational tie-ins of the new calciner will require brief production outages in the fourth quarter, and the output of the mill will be sensitive to the performance of the calciners.

CIGAR LAKE

During the third quarter, Cigar Lake packaged approximately 3.6 million pounds (100% basis, 1.8 million pounds our share) for total production of 6.7 million pounds (100% basis, 3.3 million pounds our share) to the end of September. As of the end of October, the mill has packaged over 8 million pounds (100% basis) and exceeded the 2015 production target range.

If production continues at current rates, the McClean Lake mill could produce more than 10 million packaged pounds of uranium (100% basis, 5 million pounds our share) from Cigar Lake in 2015. As we ramp up production to 18 million pounds (100% basis) by 2018, volumes may not be linear year-to-year, but will vary based on our operational experience. To ensure the most efficient operation of the mine and mill throughout the year, we expect to continually manage ore supply and, therefore, may halt and resume mining several times during a quarter without impacting planned annual production.

INKAI

Production for the quarter was 25% higher compared to the same period last year due to the timing of new wellfield development. Production remains unchanged for the first nine months of the year compared to the same periods in 2014. The operation remains on track to achieve our planned 2015 production.

Qualified persons

The technical and scientific information discussed in this document for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was 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

CIGAR LAKE

  • Les Yesnik, general manager, Cigar Lake, Cameco

INKAI

  • Darryl Clark, general director, JV Inkai

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: anticipate, believe, estimate, expect, plan, will, intend, goal, target, forecast, project, strategy and outlook (see examples below).
  • It represents our current views, and can change significantly.
  • It is based on a number of material assumptions, including those we have listed below, which may prove to be incorrect.
  • Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review our annual information form, first quarter, second quarter and third quarter MD&A, and annual MD&A, 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 it 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 2015 and future global uranium supply and demand including the discussion under the heading Uranium market update
  • our consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2015
  • our expectations for uranium deliveries in the fourth quarter
  • our future plans and expectations for each of our uranium operating properties and fuel services operating sites

Material risks

  • actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor
  • we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates
  • our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms
  • our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate
  • we are unable to enforce our legal rights under our existing agreements, permits or licences
  • we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our disputes with tax authorities
  • we are unsuccessful in our dispute with CRA and this results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision
  • 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
  • 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 suppliers fail to fulfil delivery commitments
  • our McArthur River development, mining or production plans are delayed or do not succeed for any reason
  • our Cigar Lake development, 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, or any difficulties with the McClean Lake mill modifications or expansion or milling of Cigar Lake ore
  • 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 suppliers', our customers' facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

Material assumptions

  • our expectations regarding sales and purchase volumes and prices for uranium and fuel services
  • our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being more adversely affected than expected 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 expenditures expectations
  • our expectations regarding spot prices and realized prices for uranium
  • our expectations regarding tax rates and payments, foreign currency exchange rates and interest rates
  • our expectations about the outcome of disputes with tax authorities
  • 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 McArthur River development, mining and production plans succeed
  • our Cigar Lake development, mining and production plans succeed, the jet boring mining method works as anticipated, and the deposit freezes as planned
  • modification and expansion of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected
  • our ability to continue to supply our products and services in the expected quantities and at the expected times
  • our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals
  • our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

Conference call

We invite you to join our third quarter conference call on Monday, November 2, 2015 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:

  • on our website, cameco.com, shortly after the call
  • on post view until midnight, Eastern, December 6, 2015, by calling (800) 408-3053 (Canada and US) or (905) 694-9451 (Passcode 5846753#)

Additional information

You can find a copy of our third quarter MD&A and interim financial statements on our website at cameco.com, on SEDAR at sedar.com and on EDGAR at sec.gov/edgar.shtml.

Additional information, including our 2014 annual management's discussion and analysis, annual audited financial statements and annual information form, is available on SEDAR at sedar.com, on EDGAR at sec.gov/edgar.shtml and on our website at cameco.com.

Profile

We are one of the world's largest uranium producers, a significant supplier of conversion services and one of two CANDU fuel manufacturers in Canada. Our competitive position is based on our controlling ownership of the world's largest high-grade reserves and low-cost operations. Our uranium products are used to generate clean electricity in nuclear power plants around the world. 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.

Contact Information

  • Investor inquiries:
    Rachelle Girard
    (306) 956-6403

    Media inquiries:
    Gord Struthers
    (306) 956-6593