EX-99.2 3 d403558dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

 

LOGO

Management’s discussion and analysis

for the quarter ended June 30, 2017

 

4

 

7

 

13

 

16

 

18

 

22

 

23

 

23

   

SECOND QUARTER MARKET UPDATE

 

CONSOLIDATED FINANCIAL RESULTS

 

OUTLOOK FOR 2017

 

LIQUIDITY AND CAPITAL RESOURCES

 

FINANCIAL RESULTS BY SEGMENT

 

OUR OPERATIONS—SECOND QUARTER UPDATES

 

QUALIFIED PERSONS

 

ADDITIONAL INFORMATION

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited condensed consolidated interim financial statements and notes for the quarter ended June 30, 2017 (interim financial statements). The information is based on what we knew as of July 26, 2017 and updates our first quarter and annual MD&A included in our 2016 annual report.

As you review this MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2016 and annual MD&A. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.

The financial information in this MD&A and in our financial statements and notes are prepared according to International Financial Reporting Standards (IFRS), unless otherwise indicated.

Unless we have specified otherwise, all dollar amounts are in Canadian dollars.

Throughout this document, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries, including NUKEM Energy Gmbh (NUKEM), unless otherwise indicated.

Caution about forward-looking information

Our MD&A 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 (US) securities laws. We refer to them in this MD&A as forward-looking information.

Key things to understand about the forward-looking information in this MD&A:

 

  •   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 on page 3, 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, and first quarter 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 MD&A

 

  •   the discussion under the heading Our strategy

 

  •   our expectations about 2017 and future global uranium supply and demand, including the discussion under the heading Second quarter market update

 

  •   the discussion of our expectations relating to our dispute with Tokyo Electric Power Company Holdings, Inc. (TEPCO)

 

  •   the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our estimate of the amount and timing of expected cash taxes and transfer pricing penalties

 

  •   our 2017 consolidated outlook and the outlook for our uranium, fuel services and NUKEM segments for 2017

 

  •   that our overall annual outlook continues to point to an expectation of a weaker adjusted net earnings result in 2017 than in 2016, and that we expect cash from operations to be higher in 2017 than the $312 million reported in 2016

 

  •   our expectations for quarterly uranium deliveries, quarterly
 

average realized prices, and quarterly unit production costs for the remainder of 2017

 

  •   our price sensitivity analysis for our uranium segment

 

  •   our expectation that existing cash balances and operating cash flows will meet our anticipated 2017 capital requirements without the need for any significant additional funding, other than temporary drawings on short-term liquidity during the course of the year

 

  •   our expectation that our operating and investment activities for the remainder of 2017 will not be constrained by the financial-related covenants in our unsecured revolving credit facility

 

  •   our future plans and expectations for each of our uranium operating properties and fuel services operating sites

 

  •   our expectations related to annual Rabbit Lake care and maintenance costs
 

 

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 currency exchange rates, interest rates, royalty rates, or tax rates

 

  •   our production costs are higher than planned, or our cost reduction strategies are unsuccessful, or necessary supplies are not available, or not available on commercially reasonable terms

 

  •   our estimates of production, purchases, costs, care and maintenance, decommissioning or reclamation expenses, or our tax expense estimate prove to be inaccurate

 

  •   we are unable to enforce our legal rights under our existing agreements, permits or licences

 

  •   we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our dispute with CRA or with TEPCO
  •   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

 

  •   we are unable to utilize letters of credit to the extent anticipated in our dispute with CRA

 

  •   our expectations relating to 2017 adjusted net earnings and/or 2017 cash from operations prove to be inaccurate

 

  •   there are defects in, or challenges to, title to our properties

 

  •   our mineral reserve and resource estimates are not reliable, or we face challenging or unexpected geological, hydrological or mining conditions

 

  •   we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays

 

  •   the necessary permits or approvals from government authorities are not obtained or maintained, including the approvals necessary for closing of the 2016 JV Inkai Restructuring Agreement
 

 

2    CAMECO CORPORATION

  •   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 or our uranium purchasers fail to fulfil purchase commitments

 

  •   our McArthur River, Cigar Lake, and/or Inkai development, mining or production plans are delayed or do not succeed for any reason
  •   any difficulties in milling of Cigar Lake ore at McClean Lake, or resuming production after the mandatory summer vacation periods and planned maintenance shutdowns at our northern Saskatchewan operations

 

  •   our expectations relating to Rabbit Lake care and maintenance costs prove to be inaccurate

 

  •   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’ or 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, unanticipated consequences of our cost reduction strategies, or other development and operating risks
 

 

Material assumptions

 

  •   our expectations regarding sales and purchase volumes and prices for uranium and fuel services, and that the counterparties to our sales and purchase agreements will honour their commitments

 

  •   our expectations regarding the demand for, and supply of, uranium, the pressure for a return to long-term contracting, 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 levels and production costs, including our expectations regarding the success of our cost reduction strategies

 

  •   the assumptions regarding market conditions and other factors upon which we have based our capital expenditures expectations and our 2017 adjusted net earnings and 2017 cash from operations expectations

 

  •   that our 2017 adjusted net earnings and cash from operations will be as expected

 

  •   our expectations regarding spot prices and realized prices for uranium, and other factors discussed under the heading Price sensitivity analysis: uranium segment

 

  •   our assumptions regarding tax rates and payments, royalty rates, currency exchange rates and interest rates

 

  •   our expectations about the outcome of disputes with the CRA and with TEPCO

 

  •   we are able to utilize letters of credit to the extent anticipated in our dispute with CRA

 

  •   our decommissioning and reclamation expenses

 

  •   our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable
  •   our understanding of the geological, hydrological and other conditions at our mines

 

  •   our McArthur River, Cigar Lake, and Inkai development, mining and production plans succeed, including the planned resumption of production after the mandatory summer vacation periods and planned maintenance shutdowns at our northern Saskatchewan operations

 

  •   the McClean Lake mill is able to process Cigar Lake ore as expected

 

  •   that annual Rabbit Lake care and maintenance costs will be as expected

 

  •   our ability to continue to supply our products and services in the expected quantities and at the expected times

 

  •   our and our contractors’ ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals, including approvals necessary to close the 2016 JV Inkai Restructuring Agreement

 

  •   our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, social or political activism, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, lack of tailings capacity, transportation disruptions or accidents, unanticipated consequences of our cost reduction strategies, or other development or operating risks
 

 

2017 SECOND QUARTER REPORT    3

Our strategy

We are a pure-play nuclear fuel supplier, 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, and to do that with an emphasis on safety, people and the environment.

In light of today’s oversupplied market and the lingering uncertainty as to how long the weak market conditions will persist, we are focussing our resources on our lowest cost assets, on maintaining a strong balance sheet, and on efficiently managing the company in a low price environment. We believe this approach provides us with the opportunity to meet rising demand with increased production from our best margin assets, and helps to mitigate risk during a prolonged period of uncertainty.

We plan to:

 

  •   ensure continued safe, reliable, low-cost production from our tier-one assets – McArthur River/Key Lake, Cigar Lake and Inkai

 

  •   complete rampup of production at Cigar Lake

 

  •   continue to evaluate all sources of supply and supply expansion opportunities in our portfolio, in order to retain the flexibility to respond to market signals and take advantage of value adding opportunities

 

  •   focus on maximizing margins through cost management, productivity improvements, and supply discipline

You can read more about our strategy in our 2016 annual MD&A.

Second quarter market update

The final reporting of 2016 primary and secondary global production data was completed and released during the second quarter, confirming the continued state of oversupply in the uranium market over the past year. The quarter remained quiet on the supply side and producers generally maintained existing 2017 production targets, without announcing further cuts. As has been the case in recent quarters, discretionary long-term contracting and financially distressed producers supporting the weak market, combined with uncertainty around new and existing nuclear reactors and programs in certain jurisdictions, overshadowed the industry and kept prices low.

In Japan, Kansai Electric’s Takahama 3 and 4 reactors restarted and achieved commercial operation, while a favourable court ruling moved Kyushu Electric’s Genkai 3 and 4 reactors a step closer to restarting. However, those positives were offset by the uncertain budgets and completion timelines for the four AP1000 units under construction in the US, following the bankruptcy of the lead contractor, the US division of Westinghouse Electric Company.

On the policy front, the election of new leaders in both South Korea and France added uncertainty to the existing nuclear programs in those countries. The South Korean election of President Moon Jae-In, whose platform included abolishing the nuclear-centered energy policy in favour of renewables, led Korea Hydro and Nuclear Power to pause further construction of two units currently underway. In France, the newly-elected President Emmanuel Macron, re-affirmed support for his predecessor’s energy transition law, which would see the share of nuclear generation drop from approximately 75%, to about 50%. However, in both cases, the strategy for replacing nuclear remains unclear.

Despite the publicized local setbacks, the global growth in future demand for uranium continued, with 57 units under construction. While the long-term new build story is dominated by players like China and India, which together represent nearly half of the construction currently underway, cautious optimism extends to other jurisdictions with Slovakia, Pakistan, South Korea, the United Arab Emirates, and Russia, all expected to bring new reactors into commercial operation in 2017.

 

4    CAMECO CORPORATION

LOGO

Although today’s market remains oversupplied, each new reactor comes with a long-term need for a safe and reliable source of uranium. And while the availability of pounds in the spot market has helped satisfy the needs of utilities in the near-term, the continued risk of mine curtailments, financially distressed producers, and declining secondary supplies, are expected to reduce the availability of spot material and generate increasing pressure for fuel buyers to return to long-term contracting. Industry consultants estimate the cumulative uncovered requirements to total nearly 800 million pounds over the next decade; a substantial amount of uranium needs to be contracted to keep both new and existing reactors running into the next decade. The uncovered requirements fuel our confidence that the current discretionary demand sentiment will eventually give way to concerns about the security of future supply. We believe those concerns will create opportunities for producers that can weather today’s low prices and provide a recovering market with uncommitted uranium from long-lived, tier-one assets.

 

Caution about forward-looking information relating to the nuclear industry

This discussion of our expectations for the nuclear industry, including its growth profile, future global uranium supply, demand, reactor growth, and pressure for long-term contracting 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 2

 

Industry prices at quarter end                  
     JUN 30      MAR 31      DEC 31      SEP 30      JUN 30      MAR 31  
     2017      2017      2016      2016      2016      2016  

Uranium ($US/lb U3O8)1

                  

Average spot market price

      20.15        23.88        20.25        23.00        26.70        28.70  

Average long-term price

      33.00        33.00        30.00        37.50        40.50        43.50  

Fuel services ($US/kgU as UF6)1

                  

Average spot market price

                  

North America

      5.13        5.93        5.93        5.93        6.75        6.75  

Europe

      5.50        6.45        6.45        6.45        7.25        7.25  

Average long-term price

                  

North America

      14.50        13.50        12.50        12.25        12.75        12.75  

Europe

      14.25        14.00        13.00        13.00        14.00        14.00  

 

Note: the industry does not publish UO2 prices.
1  Average of prices reported by TradeTech and Ux Consulting (UxC)

On the spot market, where purchases call for delivery within one year, the volume reported by Ux Consulting (UxC) for the second quarter of 2017 was approximately 12 million pounds. This compares to approximately nine million pounds in the second quarter of 2016. Year to date, approximately 21 million pounds has been transacted in the spot market, compared to 19 million pounds in the first half of 2016. At the end of the quarter, the average reported spot price was $20.15 (US) per pound, down $3.73 (US) from the previous quarter.

 

2017 SECOND QUARTER REPORT    5

Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices escalated over the term of the contract, and market referenced prices (spot and long-term indicators) quoted near the time of delivery. The volume of long-term contracting reported by UxC for the first six months of 2017 was approximately 54 million pounds. Although higher than the 21 million pounds reported over the same period in 2016, the volumes were still less than the quantities consumed, and remained largely discretionary due to current high inventory levels. The average reported long-term price at the end of the quarter was $33.00 (US) per pound, unchanged (US) from last quarter.

Spot UF6 conversion prices declined in both the North American and European markets, while long-term UF6 conversion prices increased during the quarter.

 

Shares and stock options outstanding

At July 26, 2017, we had:

 

  •   395,792,732 common shares and one Class B share outstanding

 

  •   8,487,096 stock options outstanding, with exercise prices ranging from $14.70 to $39.53

Dividend

Our board of directors has established a quarterly dividend of $0.10 ($0.40 per year) per common share. The dividend is reviewed quarterly based on our cash flow, earnings, financial position, strategy and other relevant factors.

 

 

Also of note:

IRS DISPUTE SETTLEMENT

In July, our Cameco US subsidiary reached an agreement to settle the tax dispute with the IRS regarding their audit of the 2009 through 2012 taxation years. The settlement agreement results in a cash tax payment of about $122,000 (US), which will be reflected in our third quarter results. See IRS dispute on page 12 for more information.

 

6    CAMECO CORPORATION

Financial results

This section of our MD&A discusses our performance, financial condition and outlook for the future.

On February 1, 2017, we announced that on January 31, 2017, TEPCO, alleging force majeure, confirmed that it would not withdraw a contract termination notice it provided to Cameco Inc. with respect to a uranium supply agreement, which affects approximately 9.3 million pounds of uranium deliveries through 2028, worth approximately $1.3 billion in revenue to Cameco, including about $126 million in 2017. We see no basis for terminating the agreement. In this MD&A, our 2017 financial outlook and other disclosures relating to our contract portfolio are presented on a basis which excludes this agreement with TEPCO, which is under dispute.

 

Consolidated financial results  
     THREE MONTHS           SIX MONTHS        
CONSOLIDATED HIGHLIGHTS    ENDED JUNE 30           ENDED JUNE 30        

($ MILLIONS EXCEPT WHERE INDICATED)

    2017     2016     CHANGE     2017     2016     CHANGE  

Revenue

      470       466       1 %      862       875       (1 )% 

Gross profit

      93       43       >100 %      148       161       (8 )% 

Net losses attributable to equity holders

      (2 )      (137 )      99 %      (20 )      (59 )      66 % 

$ per common share (basic)

      (0.00 )      (0.35 )      100 %      (0.05 )      (0.15 )      67 % 

$ per common share (diluted)

      (0.00 )      (0.35 )      100 %      (0.05 )      (0.15 )      67 % 

Adjusted net losses (non-IFRS, see page 8)

      (44 )      (57 )      23 %      (73 )      (64 )      (14 )% 

$ per common share (adjusted and diluted)

      (0.11 )      (0.14 )      21 %      (0.18 )      (0.16 )      (13 )% 

Cash provided by (used in) operations (after working capital changes)

      130       (51 )      >100 %      122       (328 )      >100 % 

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 8) in the second quarter and the first six months of 2017, compared to the same periods in 2016.

 

          THREE MONTHS     SIX MONTHS  
          ENDED JUNE 30     ENDED JUNE 30  

($ MILLIONS)

    IFRS     ADJUSTED     IFRS     ADJUSTED  

Net losses – 2016

      (137 )      (57 )      (59 )      (64 ) 
     

 

 

    

 

 

    

 

 

    

 

 

  

Change in gross profit by segment

         

(We calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A))

 

Uranium

    Higher sales volume      12       12       18       18  
   Lower realized prices ($US)      (51 )      (51 )      (111 )      (111 ) 
   Foreign exchange impact on realized prices      11       11       (5 )      (5 ) 
   Lower costs      74       74       78       78  
     

 

 

    

 

 

    

 

 

    

 

 

  
   Change – uranium      46       46       (20 )      (20 ) 
     

 

 

    

 

 

    

 

 

    

 

 

  

Fuel services

    Lower sales volume      (1 )      (1 )      (5 )      (5 ) 
   Higher realized prices ($Cdn)      7       7       19       19  
   Higher costs      —         —         (7 )      (7 ) 
     

 

 

    

 

 

    

 

 

    

 

 

  
   Change – fuel services      6       6       7       7  
     

 

 

    

 

 

    

 

 

    

 

 

  

NUKEM

    Gross profit      (4 )      2       (4 )      2  
     

 

 

    

 

 

    

 

 

    

 

 

  
   Change – NUKEM      (4 )      2       (4 )      2  
     

 

 

    

 

 

    

 

 

    

 

 

  

Other changes

         

Lower administration expenditures

      17       17       29       29  

Lower impairment charge

      124       —         124       —    

Lower exploration expenditures

      6       6       12       12  

Rabbit Lake reclamation provision

      12       —         6       —    

Lower loss on disposal of assets

      —         —         4       4  

Lower loss (lower gain) on derivatives

      34       —         (42 )      18  

Foreign exchange gains (losses)

      (18 )      (18 )      14       14  

Lower income tax recovery

      (94 )      (52 )      (89 )      (73 ) 

Other

      6       6       (2 )      (2 ) 
     

 

 

    

 

 

    

 

 

    

 

 

  

Net losses – 2017

      (2 )      (44 )      (20 )      (73 ) 
     

 

 

    

 

 

    

 

 

    

 

 

  
See Financial results by segment beginning on page 18 for more detailed discussion.    

 

2017 SECOND QUARTER REPORT    7

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 adjustments, Rabbit Lake reclamation provisions, impairment charges, 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.

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

 

     THREE MONTHS      SIX MONTHS  
     ENDED JUNE 30      ENDED JUNE 30  

($ MILLIONS)

    2017      2016      2017      2016  

Net losses attributable to equity holders

      (2 )       (137 )       (20 )       (59 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Adjustments

            

Adjustments on foreign exchange derivatives

      (44 )       (10 )       (66 )       (126 ) 

NUKEM purchase price inventory adjustment

      —          (6 )       —          (6 ) 

Impairment charge

      —          124        —          124  

Rabbit Lake reclamation provision

      (12 )       —          (6 )       —    

Income taxes on adjustments

      14        (28 )       19        3  
  

 

 

     

 

 

     

 

 

     

 

 

  

Adjusted net losses

      (44 )       (57 )       (73 )       (64 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

 

Quarterly trends  
HIGHLIGHTS    2017     2016     2015  

($ MILLIONS EXCEPT PER SHARE AMOUNTS)

    Q2     Q1     Q4     Q3      Q2     Q1     Q4     Q3  

Revenue

      470       393       887       670        466       408       975       649  

Net earnings (losses) attributable to equity holders

      (2 )      (18 )      (144 )      142        (137 )      78       (10 )      (4 ) 

$ per common share (basic)

      (0.00 )      (0.05 )      (0.36 )      0.36        (0.35 )      0.20       (0.03 )      (0.01 ) 

$ per common share (diluted)

      (0.00 )      (0.05 )      (0.36 )      0.36        (0.35 )      0.20       (0.03 )      (0.01 ) 

Adjusted net earnings (losses) (non-IFRS, see page 8)

      (44 )      (29 )      90       118        (57 )      (7 )      151       78  

$ per common share (adjusted and diluted)

      (0.11 )      (0.07 )      0.23       0.30        (0.14 )      (0.02 )      0.38       0.20  

Cash provided by (used in) operations (after working capital changes)

      130       (8 )      255       385        (51 )      (277 )      503       (121 ) 

Key things to note:

 

  •   our financial results are strongly influenced by the performance of our uranium segment, which accounted for 63% of consolidated revenues in the second quarter of 2017

 

  •   the timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments, meaning quarterly results are not necessarily a good indication of annual results due to seasonal variability

 

  •   net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 8 for more information).

 

  •   cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments

 

8    CAMECO CORPORATION

The following table compares the net earnings and adjusted net earnings for the second quarter to the previous seven quarters.

 

HIGHLIGHTS    2017     2016     2015  

($ MILLIONS EXCEPT PER SHARE AMOUNTS)

    Q2     Q1     Q4     Q3     Q2     Q1     Q4     Q3  

Net earnings (losses) attributable to equity holders

      (2 )      (18 )      (144 )      142       (137 )      78       (10 )      (4 ) 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Adjustments

                 

Adjustments on foreign exchange derivatives

      (44 )      (22 )      23       (27 )      (10 )      (116 )      10       112  

NUKEM purchase price inventory adjustment

      —         —         —         —         (6 )      —         —         —    

Impairment charges

      —         —         238       —         124       —         210       —    

Rabbit Lake reclamation provision

      (12 )      6       (28 )      (6 )      —         —         —         —    

Income taxes on adjustments

      14       5       1       9       (28 )      31       (59 )      (30 ) 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Adjusted net earnings (losses) (non-IFRS, see page 8)

      (44 )      (29 )      90       118       (57 )      (7 )      151       78  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

  

Corporate expenses

ADMINISTRATION

     THREE MONTHS            SIX MONTHS         
     ENDED JUNE 30            ENDED JUNE 30         

($ MILLIONS)

    2017      2016      CHANGE     2017      2016      CHANGE  

Direct administration

      43        59        (27 )%      77        107        (28 )% 

Stock-based compensation

      1        2        (50 )%      7        6        17 % 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Total administration

      44        61        (28 )%      84        113        (26 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Direct administration costs were $16 million lower for the second quarter of 2017 compared to the same period last year, and $30 million lower for the first six months. The decrease was mainly due to higher costs in 2016 related to:

 

  •   one-time costs related to collaboration agreements

 

  •   charges related to the consolidation of office space

 

  •   legal costs as our CRA dispute progressed towards trial

 

  •   restructuring of our NUKEM segment,

In addition, some of the actions we took in 2016 to reduce our costs resulted in lower costs in the first half of 2017.

EXPLORATION

In the second quarter, uranium exploration expenses were $6 million, a decrease of $6 million compared to the second quarter of 2016. Exploration expenses for the first six months of the year decreased by $11 million compared to 2016, to $16 million, due to a planned reduction in expenditures.

INCOME TAXES

We recorded an income tax expense of $29 million in the second quarter of 2017, compared to a recovery of $65 million in the second quarter of 2016.

On an adjusted basis, we recorded an income tax expense of $15 million this quarter compared to a recovery of $37 million in the second quarter of 2016, primarily due to a change in the Saskatchewan corporate tax rate which caused a decrease in our deferred tax asset, resulting in an expense of $24 million. In addition, there was a change in the distribution of earnings among jurisdictions. In 2017, we recorded earnings of $4 million in Canada compared to losses of $151 million in 2016, while we recorded losses of $33 million in foreign jurisdictions compared to earnings of $59 million last year.

In the first six months of 2017, we recorded an income tax expense of $33 million compared to a recovery of $56 million in 2016.

On an adjusted basis, we recorded an income tax expense of $14 million for the first six months compared to a recovery of $59 million in 2016 due to a change in the distribution of earnings among foreign jurisdictions in 2017 and a change in the Saskatchewan corporate tax rate. In 2017, we recorded earnings of $3 million in Canada compared to losses of $249 million in 2016, while we recorded losses of $62 million in foreign jurisdictions compared to earnings of $128 million last year.

 

2017 SECOND QUARTER REPORT    9

As a result of the change in the Saskatchewan corporate tax rate and its impact on our deferred tax asset, we now expect a tax expense on an adjusted net earnings basis of $10 million to $20 million for 2017 (we previously expected a recovery of $10 million to $20 million).

 

     THREE MONTHS      SIX MONTHS  
     ENDED JUNE 30      ENDED JUNE 30  

($ MILLIONS)

    2017      2016      2017      2016  

Pre-tax adjusted earnings1

            

Canada

      4        (151 )       3        (249 ) 

Foreign

      (33 )       59        (62 )       128  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total pre-tax adjusted earnings

      (29 )       (92 )       (59 )       (121 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Adjusted income taxes1

            

Canada

      20        (37 )       19        (67 ) 

Foreign

      (5 )       —          (5 )       8  
  

 

 

     

 

 

     

 

 

     

 

 

  

Adjusted income tax expense (recovery)

      15        (37 )       14        (59 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

 

1  Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures. Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 8).

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with CRA since 2008, when it originated, and with the 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 2011, 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 2011, transfer pricing penalties. Taxes of approximately $350 million for the 2003 – 2016 years have already been paid in a jurisdiction outside Canada, and we are considering our options under bilateral international tax treaties to limit double taxation of this income. There is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our CRA tax dispute are represented by the amounts claimed by CRA 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. To date, we received notices of reassessment for our 2003 through 2011 tax returns. We have recorded a cumulative tax provision of $56 million, where an argument could be made that, based on our methodology, our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through June 30, 2017. 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.

 

10    CAMECO CORPORATION

For the years 2003 through 2011, CRA issued notices of reassessment for approximately $4.1 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $1.2 billion. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2010 in the amount of $292 million. Subsequent to the end of the second quarter, CRA issued a reassessment charging a transfer pricing penalty of $78 million related to 2011. 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 $264 million in cash. In addition, we have provided $421 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed after 2014. The amounts paid or secured are shown in the table below. A 50% payment in 2017 related to the transfer pricing penalty assessed for 2011, which was received subsequent to the end of the second quarter, has not yet been paid and is therefore not included in the tables.

 

            INTEREST      TRANSFER                       
            AND INSTALMENT      PRICING             CASH      SECURED BY  

YEAR PAID ($ MILLIONS)

    CASH TAXES      PENALTIES      PENALTIES      TOTAL      REMITTANCE      LC  

Prior to 2014

      1        22        36        59        59        —    

2014

      106        47        —          153        153        —    

2015

      202        71        79        352        20        332  

2016

      51        38        31        120        32        88  

2017

      —          1        —          1        —          1  
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Total

      360        179        146        685        264        421  
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Using the methodology we believe CRA will continue to apply, and including the $4.1 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $8.1 billion of additional income taxable in Canada for the years 2003 through 2016, which would result in a related tax expense of approximately $2.4 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2011. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.75 billion and $1.95 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 $875 million and $975 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. CRA has 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, beginning with 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 believe we will 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 2016, 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 2016.

 

$ MILLIONS

    2003-2016      2017-2018    2019-2023    TOTAL

50% of cash taxes and transfer pricing penalties paid, secured or owing in the period

Cash payments

      187      65 - 90    145 - 170    390 - 445

Secured by letters of credit

      319      10 - 35    150 - 175    480 - 530
  

 

 

     

 

   

 

   

 

Total paid1

      506      75 - 125    295 - 345    875 - 975
  

 

 

     

 

   

 

   

 

 

1 These amounts do not include interest and instalment penalties, which totaled approximately $179 million to June 30, 2017, or the transfer pricing penalty for 2011 that was received subsequent to the end of the second quarter.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $685 million already paid or otherwise secured to date.

 

2017 SECOND QUARTER REPORT    11

We expect that the total cost of disputing the CRA reassessments and presenting our appeal in Tax Court will be about $57 million. This estimated amount includes legal fees, expert witness fees, consultant fees, filing expenses, and other costs related to the case, from the time we started specifically tracking such costs in 2009, through 2017, the largest expenditures having been incurred in 2016 as we prepared for trial and began the court proceedings. If the decision of the Tax Court is appealed, additional costs will be incurred.

The trial related to the 2003, 2005 and 2006 reassessments commenced in October, 2016. Final arguments are currently scheduled for September, 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.

IRS dispute

In July, we received confirmation of a settlement reached with the IRS regarding the audit of the 2009 through 2012 taxation years. As a result of the settlement, a cash payment of about $122,000 (US) will be made in the third quarter.

We had received Revenue Agents Reports (RARs) from the IRS for the above tax years, whereby the IRS had challenged the transfer pricing used under certain intercompany transactions for certain of our US subsidiaries.

The audit position of the IRS was that a portion of the non-US income reported under our corporate structure and taxed in non-US jurisdictions should have been 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 were too low

 

•   the compensation earned by Cameco Inc., one of our US subsidiaries, was inadequate

The original proposed adjustments would have resulted 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 had proposed cumulative penalties of approximately $8 million (US) in respect of the adjustment.

 

Caution about forward-looking information relating to our CRA tax dispute

This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA 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 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

 

Assumptions

 

  •   CRA will reassess us for the years 2012 through 2016 using a similar methodology as for the years 2003 through 2011, 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 2011) in addition to interest charges and instalment penalties

 

  •   we will be substantially successful in our dispute with CRA and the cumulative tax provision of $56 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

Material risks that could cause actual results to differ materially

 

  •   CRA reassesses us for years 2012 through 2016 using a different methodology than for years 2003 through 2011, 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 outcome of our dispute with CRA results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows

 

  •   cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing

 

  •   we are unable to effectively eliminate all double taxation
 

 

FOREIGN EXCHANGE

The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments. See Revenue, adjusted net earnings, and cash flow sensitivity analysis on page 15 for more information on how a change in the exchange rate will impact our revenue, cash flow, and adjusted net earnings (ANE) (see Non-IFRS measures on page 8).

 

12    CAMECO CORPORATION

We sell the majority of our uranium and fuel services products under long-term sales contracts, which are routinely denominated in US dollars, while our production costs are largely denominated in Canadian dollars. To provide cash flow predictability, we hedge a portion of our net US/Cdn exposure (e.g. total US dollar sales less US dollar expenditures and product purchases) to manage shorter term exchange rate volatility. Our results are therefore affected by the movements in the exchange rate on our hedge portfolio, and on the unhedged portion of our net exposure.

Impact of hedging on IFRS earnings

We do not use hedge accounting under IFRS and, therefore, we are required to report gains and losses on all hedging activity, both for contracts that close in the period and those that remain outstanding at the end of the period. For the contracts that remain outstanding, we must treat them as though they were settled at the end of the reporting period (mark-to-market).

However, we do not believe the gains and losses that we are required to report under IFRS appropriately reflect the intent of our hedging activities, so we make adjustments in calculating our ANE to better reflect the benefits of our hedging program in the applicable reporting period.

Impact of hedging on ANE

The table below provides a summary of our hedge portfolio at June 30, 2017. You can use this information to estimate the expected gains or losses on derivatives for the remainder of 2017 on an ANE basis. However, if we add contracts to the portfolio that are designated for use in 2017 or if there are changes in the US/Cdn exchange rates in the year, those expected gains or losses could change.

You can read more about our hedging program in our 2016 annual MD&A.

HEDGE PORTFOLIO SUMMARY

 

JUNE 30, 2017                            AFTER        

($ MILLIONS)

          20171     2018     2019     2019     TOTAL  

US dollar forward contracts

        215       310       70       10       605  

Average contract rate 2

      (US/Cdn dollar )      1.32       1.31       1.31       1.35       1.31  

US dollar option contracts

        60       80       90       10       240  

Average contract rate range2

      (US/Cdn dollar )      1.31 to 1.36       1.31 to 1.35       1.29 to 1.35       1.31 to 1.35       1.30 to 1.35  

Total US dollar hedge contracts

        275       390       160       20       845  

Effective hedge rate range3

      (US/Cdn dollar )      1.23 to 1.24       1.23 to 1.24       1.26 to 1.29       1.33 to 1.35       1.24 to 1.25  

Hedge ratio4

        45 %      35 %      16 %      2 %      16 % 

 

1  Represents hedge contracts for the remainder of the year. See 2017 Financial Outlook for the full-year expected gain/loss on derivatives on an adjusted net earnings basis.
2  The average contract rate is the average of the rates stipulated in the outstanding contracts.
3  The effective hedge rate is the exchange rate on the original hedge contract at the time it was established and designated for use. Therefore the effective hedge rate range shown reflects an average of contract exchange rates at the time of designation.
4  Hedge ratio is calculated by dividing the amount (in foreign currency) of outstanding derivative contracts by estimated future net exposures.

At June 30, 2017:

 

  •   The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.30 (Cdn), down from $1.00 (US) for $1.33 (Cdn) at March 31, 2017. The exchange rate averaged $1.00 (US) for $1.34 (Cdn) over the quarter.

 

  •   The mark-to-market gain on all foreign exchange contracts was $18 million compared to a $12 million loss at March 31, 2017.

For information on the impact of foreign exchange on our intercompany balances, see note 16 to the financial statements.

Outlook for 2017

Our outlook for 2017 reflects the expenditures necessary to help us achieve our strategy and is based on the assumptions found below the table, including a given uranium spot price, uranium term price, and foreign exchange rate. For more information on how changes in the exchange rate or uranium prices can impact our outlook see Revenue, adjusted net earnings, and cash flow sensitivity analysis on page 15, and Foreign exchange on page 12. Our 2017 financial outlook, and other disclosures relating to our contract portfolio, have been presented on a basis that excludes our contract with TEPCO, which is under dispute.

Our outlook for NUKEM sales volume, consolidated revenue, consolidated tax expense, and capital expenditures has changed. We do not provide an outlook for the items in the table that are marked with a dash.

 

2017 SECOND QUARTER REPORT    13

See 2017 Financial results by segment on page 18 for details.

2017 FINANCIAL OUTLOOK

 

     CONSOLIDATED     URANIUM     FUEL SERVICES     NUKEM  

EXPECTED CONTRIBUTION TO GROSS PROFIT

      100 %      85 %      14 %      1 % 

Production

      —        

 25.2

million lbs

  

 

    

 8 to 9

million kgU

  

 

     —    

Sales/delivery volume1

      —        

 30 to 32

million lbs

  

2 

    

 11 to 12

million kgU

  

 

    

 8 to 9

million lbs U3O8

  

 

Revenue ($ million)1

      2,100 to 2,270       1,470 to 1,570 3      300 to 330       —    

Average realized price3

      —       $ 49.00/lb 2      —         —    

Average unit cost of sales (including D&A)

      —       $ 36.00-38.00/lb 4    $ 21.60-22.60/kgU       —    

Gross profit5

      —         —         —         3% to 4%  

Direct administration costs6

    $ 150-160 million       —         —         —    

Exploration costs

      —       $ 30 million       —         —    

Expected loss on derivatives - ANE basis3

    $ 45-50 million       —         —         —    

Tax expense - ANE basis7

    $ 10-20 million       —         —         —    

Capital expenditures8

    $ 175 million       —         —         —    

 

1  Our 2017 outlook for sales/delivery volume and revenue does not include sales between our uranium, fuel services and NUKEM segments.
2  Our uranium sales/delivery volume is based on the volumes we currently have commitments to deliver under contract in 2017.
3  Based on a uranium spot price of $20.10 (US) per pound (the UxC spot price as of June 26, 2017), a long-term price indicator of $32.00 (US) per pound (the UxC long-term indicator on June 26, 2017) and an exchange rate of $1.00 (US) for $1.30 (Cdn).
4  Based on the expected unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in the remainder of 2017, then we expect the overall unit cost of sales may be affected.
5  Gross profit excludes inventory write-downs to reflect net realizable value.
6  Direct administration costs do not include stock-based compensation expenses. See page 9 for more information.
7  Our outlook for the tax expense is based on adjusted net earnings and the other assumptions listed in the table. If other assumptions change then the expected expense may be affected.
8  Capital expenditures do not include adjustments for revenue from sales of pre-commercial production.

Although certain aspects of our 2017 financial outlook have been adjusted as explained below, our overall annual outlook, as presented in our 2016 annual MD&A and 2017 first quarter MD&A, continues to point to an expectation of a weaker adjusted net earnings result in 2017 than in 2016. However, we expect cash from operations to be higher in 2017 than the $312 million reported in 2016.

Our outlook range for consolidated revenue has increased to $2,100 million to $2,270 million (previously $1,950 million to $2,080 million) as a result of increased sales volumes expected at NUKEM. Sales volumes at NUKEM are now expected to be 8 million to 9 million lbs (previously 5 million to 6 million lbs) as a consequence of additional market opportunities.

We now expect a tax expense on an adjusted net earnings basis of $10 million to $20 million (previously a recovery of $10 million to $20 million) due to a change in the Saskatchewan corporate tax rate and its impact on our deferred tax asset.

Our outlook for capital expenditures has decreased to $175 million (previously $190 million) due to a reduction in spending at both McArthur River and Cigar Lake.

We continue to expect an annual average realized price of $49.00 in our uranium segment for 2017. However, we expect pricing on deliveries in the third quarter to be the lowest for the year, which translates to an expectation of higher prices on deliveries in the fourth quarter.

 

14    CAMECO CORPORATION

While we continue to expect our annual average unit cost of sales (including D&A) in our uranium segment to be between $36.00 and $38.00 per pound, our quarterly unit production costs can vary significantly depending on production volumes. In the third quarter, we expect unit costs of production in our uranium segment to be significantly higher than in the first two quarters, due to expected lower production in the third quarter resulting from the summer shutdowns at our northern Saskatchewan operations.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales/delivery volumes and revenue can vary significantly. We are on track for our uranium sales/delivery targets and expect the quarterly distribution of uranium deliveries in 2017 to be weighted to the second half of the year as shown below. However, not all delivery notices have been received to date and the expected delivery pattern could change.

 

LOGO

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

 

          IMPACT ON:  

FOR 2017 ($ MILLIONS)

    CHANGE    REVENUE      ANE      CASH FLOW  

Uranium spot and term price1

    $5(US)/lb increase

$5(US)/lb decrease

     

 22

(18

  

) 

     

 15

(11

  

) 

     

 17

(13

  

) 

Value of Canadian dollar vs US dollar

    One cent decrease in CAD

One cent increase in CAD

     

 9

(9

  

) 

     

 4

(4

  

) 

     

 4

(4

  

) 

 

1  Assuming change in both UxC spot price ($20.10 (US) per pound on June 26, 2017) and the UxC long-term price indicator ($32.00 (US) per pound on June 26, 2017)

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 June 30, 2017 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 June 30, 2017 and none of the assumptions we list below change.

We intend to update this table each quarter in our MD&A to reflect 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)

 

SPOT PRICES

($US/lb U3O8)

    $20      $40      $60      $80      $100      $120      $140  

2017

      Provided in financial outlook table and in revenue, adjusted net earnings, and cash flow sensitivity analysis  

2018

      38        45        56        66        75        83        90  

2019

      34        44        56        66        75        82        88  

2020

      36        44        57        66        74        81        86  

2021

      32        43        57        67        75        84        91  

 

2017 SECOND QUARTER REPORT    15

The table illustrates the mix of long-term contracts in our June 30, 2017 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to June 30, 2017, and it excludes our contract under dispute with TEPCO.

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 higher prices or have high floor prices will yield prices that are higher than current market prices.

 

Our portfolio is affected by more than just the spot price. We made the following assumptions (which are not forecasts) to create the table:

 

Sales

 

  •   sales volumes on average of 25 million pounds per year, with commitment levels in 2017 through 2019 higher than in 2020 and 2021

 

  •   excludes sales between our uranium, fuel services and NUKEM segments

 

  •   excludes the contract under dispute with TEPCO

Deliveries

 

  •   deliveries include best estimates of requirements contracts and contracts with volume flex provisions

Annual inflation

 

  •   is 2.5% in the US

Prices

 

  •   the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 20% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table will be higher.
 

 

Liquidity and capital resources

Our financial objective is to ensure we have the cash and debt capacity to fund our operating activities, investments and growth.

We have large, creditworthy customers that continue to need uranium even during weak economic conditions, and we expect the uranium contract portfolio we have built to provide a solid revenue stream for years to come.

We expect to continue investing in maintaining our tier-one production capacity and flexibility over the next several years. We have a number of alternatives to fund future capital requirements, including using our operating cash flow, drawing on our existing credit facilities, entering new credit facilities, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. Due to the cyclical nature of our business, we may need to temporarily draw on our short-term liquidity during the course of the year. However, apart from these short-term fluctuations, we expect our cash balances and operating cash flows to meet our capital requirements during 2017.

We have an ongoing transfer pricing dispute with CRA. See page 10 for more information. Until this dispute is resolved, we expect to pay cash or provide security in the form of letters of credit for future amounts owing to the Government of Canada for 50% of the cash taxes payable and the related interest and penalties. We have provided an estimate of the amount and timing of the expected cash taxes and transfer pricing penalties paid, secured or owing in the table on page 11.

CASH FROM/USED IN OPERATIONS

Cash from operations was $181 million higher this quarter than in the second quarter of 2016. Contributing to this change was a decrease in working capital requirements, which required $63 million less in 2017 than in 2016. In addition, higher gross profits in our operating segments contributed to the increase. Not including working capital requirements, our operating cash flows this quarter were higher by $118 million.

Cash provided by operations was $450 million higher in the first six months of 2017 than for the same period in 2016 due largely to a decrease in working capital requirements. This was a result of the increase in inventory being higher in 2016 compared to the current period. Working capital required $269 million less in 2017. In addition, there was a decrease in income taxes paid, less cash was required by our hedge portfolio as derivative contracts matured and cost reduction measures resulted in a lower use of cash. Not including working capital requirements, our operating cash flows in the first six months were higher by $181 million.

 

16    CAMECO CORPORATION

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $3.0 billion at June 30, 2017, unchanged from March 31, 2017. At June 30, 2017, we had approximately $1.5 billion outstanding in letters of credit, unchanged from December 31, 2016. At June 30, 2017, we had no short-term debt outstanding on our $1.25 billion unsecured revolving credit facility, unchanged from December 31, 2016. At June 30, 2017, NUKEM had no balance outstanding on their 75 million (€) multicurrency revolving loan facility, compared to $2 million (US) on March 31, 2017.

Long-term contractual obligations

Since December 31, 2016, there have been no material changes to our long-term contractual obligations. Please see our 2016 annual MD&A for more information.

Debt covenants

We are bound by certain covenants in our unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at June 30, 2017, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2017 to be constrained by them.

NUKEM financing arrangements

NUKEM enters into financing arrangements with third parties where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (see notes 4 and 6 to the financial statements for more information). In addition, NUKEM is required to pledge the underlying inventory as security against these performance obligations. As of June 30, 2017, we had $4.7 million ($3.6 million (US)) of inventory pledged as security under financing arrangements, compared with $4.9 million ($3.6 million (US)) at December 31, 2016.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at June 30, 2017:

 

  •   purchase commitments

 

  •   financial assurances

 

  •   other arrangements

Purchase commitments

The following table is based on our purchase commitments in our uranium, fuel services, and NUKEM segments at June 30, 2017. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of purchase. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

 

            2018 AND      2020 AND      2022 AND         

JUNE 30 ($ MILLIONS)

    2017      2019      2021      BEYOND      TOTAL  

Purchase commitments1

      233        495        157        72        957  

 

1  Denominated in US dollars, converted to Canadian dollars as of June 30, 2017 at the rate of $1.33.

During the second quarter, our purchase commitments decreased, as we have taken delivery of some of the material under these commitments.

As of June 30, 2017, we had commitments of about $957 million for the following:

 

  •   approximately 20 million pounds of U3O8 equivalent from 2017 to 2028

 

  •   approximately 2 million kgU as UF6 in conversion services from 2017 to 2019

 

  •   about 0.3 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions.

Financial assurances

At June 30, 2017, our financial assurances totalled $1.5 billion, unchanged from December 31, 2016.

 

2017 SECOND QUARTER REPORT    17

Other arrangements

We continue to use factoring and other third party arrangements to manage short-term cash flow fluctuations. You can read more about these arrangements in our 2016 annual MD&A.

BALANCE SHEET

 

($ MILLIONS)

    JUN 30, 2017      DEC 31, 2016      CHANGE  

Cash and cash equivalents

      283        320        (12 )% 

Total debt

      1,494        1,493        —    

Inventory

      1,327        1,288        3 % 

Total cash and cash equivalents at June 30, 2017 were $283 million, or 12% lower than at December 31, 2016, primarily due to capital expenditures of $53 million, dividend payments of $79 million, and interest payments of $35 million, partially offset by cash from operations of $122 million. Net debt at June 30, 2017 was $1,211 million.

Total product inventories increased to $1,327 million, including NUKEM’s inventories ($127 million). Inventories increased as sales were lower than production and purchases in the first six months of the year. As of June 30, 2017, we held an inventory of 32.9 million pounds of U3O8 equivalent in our uranium segment (excluding broken ore).

Financial results by segment

Uranium

 

         THREE MONTHS           SIX MONTHS        
         ENDED JUNE 30           ENDED JUNE 30        

HIGHLIGHTS

        2017     2016     CHANGE     2017     2016     CHANGE  

Production volume (million lbs)

        7.1       7.0       1 %      13.8       14.0       (1 )% 

Sales volume (million lbs)1

        6.1       4.6       33 %      11.8       10.5       12 % 

Average spot price

    ($US/lb)     20.79       27.15       (23 )%      22.29       29.50       (24 )% 

Average long-term price

    ($US/lb)     32.83       41.50       (21 )%      32.83       42.67       (23 )% 

Average realized price

    ($US/lb)     36.51       42.91       (15 )%      35.50       42.52       (17 )% 
   ($Cdn/lb)     49.11       55.70       (12 )%      47.36       57.16       (17 )% 

Average unit cost of sales (including D&A)

    ($Cdn/lb)     35.29       47.46       (26 )%      36.47       43.09       (15 )% 

Revenue ($ millions)1

        298       256       16 %      558       603       (7 )% 

Gross profit ($ millions)

        84       38       121 %      128       148       (14 )% 

Gross profit (%)

        28       15       87 %      23       25       (8 )% 

 

1  There were no significant intersegment transactions in the periods shown.

SECOND QUARTER

Production volumes this quarter were 1% higher compared to the second quarter of 2016, mainly due to higher production from McArthur River/Key Lake related to the timing of mill maintenance shut downs and higher production from Cigar Lake as a result of the scheduled rampup of the operation. These increases were partially offset by planned lower production from Inkai and our US operations, and a lack of production from the suspended Rabbit Lake operation. See Uranium 2017 Q2 updates starting on page 22 for more information.

Uranium revenues this quarter were up 16% compared to 2016 due to an increase in sales volumes of 33% partially offset by a decrease of 12% in the Canadian dollar average realized price. The spot price for uranium averaged $20.79 (US) per pound in the second quarter of 2017, a decline of 23% compared to the 2016 second quarter average price of $27.15 (US) per pound. While our average realized price outperformed the market, it decreased by 12% compared to last year mainly due the impact of the disputed TEPCO agreement and lower prices for uranium delivered under both fixed and market-related contracts, partially offset by a weaker Canadian dollar compared to a year ago. The weaker Canadian dollar also explains why the average realized price differed from the outlook we provided in the first quarter. The realized foreign exchange rate was $1.35 compared to $1.30, which was the rate in 2016 and the rate used in our assumptions. In the third quarter, we expect pricing on deliveries to be the weakest for the year. In the fourth quarter, we expect pricing on deliveries to result in a higher average realized price. We continue to expect an annual average realized price of $49.00 in 2017.

 

18    CAMECO CORPORATION

Total cost of sales (including D&A) decreased by 2% ($214 million compared to $218 million in 2016) despite a 33% increase in sales volume as a result of unit cost of sales that was 26% lower than the same period last year, due mainly to higher costs in 2016 at Rabbit Lake and in the US associated with curtailing production. In addition, the rampup of production at Cigar Lake, and the other measures we have taken to reduce costs, have resulted in lower production costs. The cost of our purchases have decreased as well.

The net effect was a $46 million increase in gross profit for the quarter.

FIRST SIX MONTHS

Production volumes for the first six months of the year were 1% lower than in the previous year mainly due to planned lower production from Inkai and our US operations, and a lack of production from the suspended Rabbit Lake operation, partially offset by higher production from McArthur River/Key Lake and Cigar Lake. See Uranium 2017 Q2 updates starting on page 22 for more information.

Uranium revenues decreased 7% compared to the first six months of 2016 due to a 17% decrease in the Canadian dollar average realized price, partially offset by a 12% increase in sales volumes.

Our Canadian dollar realized prices for the first six months of 2017 were lower than 2016, primarily as a result of the decrease in the US dollar average realized price. Pricing under our contract portfolio has been impacted by the disputed TEPCO agreement and weaker uranium prices than a year ago.

Total cost of sales (including D&A) decreased by 5% ($430 million compared to $454 million in 2016) mainly due to a 15% decrease in the unit cost of sales partially offset by a 12% increase in sales volume for the first six months. The decrease in the unit cost of sales compared to last year was mainly due to higher costs in 2016 at Rabbit Lake and in the US associated with curtailing production. In addition, the rampup of production at Cigar Lake, and the other measures we have taken to reduce costs, have resulted in lower production costs this year. The cost of our purchases have decreased as well.

The net effect was a $20 million decrease in gross profit for the first six months.

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 care and maintenance costs, 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            SIX MONTHS         
     ENDED JUNE 30            ENDED JUNE 30         

($CDN/LB)

    2017      2016      CHANGE     2017      2016      CHANGE  

Produced

                 

Cash cost

      13.53        15.96        (15 )%      14.02        18.32        (23 )% 

Non-cash cost

      10.59        11.07        (4 )%      10.47        11.81        (11 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Total production cost

      24.12        27.03        (11 )%      24.49        30.13        (19 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Quantity produced (million lbs)

      7.1        7.0        1 %      13.8        14.0        (1 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Purchased

                 

Cash cost

      37.34        38.18        (2 )%      40.36        49.77        (19 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Quantity purchased (million lbs)

      0.7        0.6        17 %      2.5        5.7        (56 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Totals

                 

Produced and purchased costs

      25.31        27.91        (9 )%      26.92        35.81        (25 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

Quantities produced and purchased (million lbs)

      7.8        7.6        3 %      16.3        19.7        (17 )% 
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

  

The average cash cost of production was 15% lower for the quarter and 23% lower in the first six months than in comparable periods in 2016. The change was primarily due to the rampup of low-cost production from Cigar Lake, and the impact of our actions in 2016 to curtail production from Rabbit Lake and our US operations, where production costs were higher.

While we continue to expect our annual average unit cost of sales (including D&A) to be between $36.00 and $38.00 per pound, our quarterly unit production costs can vary significantly depending on production volumes. In the third quarter, we expect unit costs of production to be significantly higher than in the first two quarters due to expected lower production in the third quarter resulting from the summer shutdowns at our northern Saskatchewan operations.

 

2017 SECOND QUARTER REPORT    19

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the second quarter, the average cash cost of purchased material was $37.34 (Cdn) per pound, or $27.82 (US) per pound in US dollar terms, compared to $29.20 (US) per pound in the second quarter of 2016. For the first six months, the average cash cost of purchased material was $40.36 (Cdn), or $30.40 (US) per pound, compared to $36.18 (US) per pound in the same period in 2016.

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 second quarter and the first six months of 2017 and 2016.

Cash and total cost per pound reconciliation

 

     THREE MONTHS      SIX MONTHS  
     ENDED JUNE 30      ENDED JUNE 30  

($ MILLIONS)

    2017      2016      2017      2016  

Cost of product sold

      158.9        165.6        340.9        368.9  

Add / (subtract)

            

Royalties

      (13.0 )       (19.1 )       (23.2 )       (39.9 ) 

Care and maintenance costs

      (10.4 )       (38.7 )       (20.8 )       (38.7 ) 

Other selling costs

      (2.2 )       (3.0 )       (2.9 )       (2.9 ) 

Change in inventories

      (11.1 )       29.8        0.4        252.8  
  

 

 

     

 

 

     

 

 

     

 

 

  

Cash operating costs (a)

      122.2        134.6        294.4        540.2  

Add / (subtract)

            

Depreciation and amortization

      55.5        52.7        89.0        85.5  

Change in inventories

      19.7        24.8        55.4        79.8  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total operating costs (b)

      197.4        212.1        438.8        705.5  
  

 

 

     

 

 

     

 

 

     

 

 

  

Uranium produced & purchased (million lbs) (c)

      7.8        7.6        16.3        19.7  
  

 

 

     

 

 

     

 

 

     

 

 

  

Cash costs per pound (a ÷ c)

      15.67        17.71        18.06        27.42  

Total costs per pound (b ÷ c)

      25.31        27.91        26.92        35.81  
  

 

 

     

 

 

     

 

 

     

 

 

  

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

 

           THREE MONTHS            SIX MONTHS         
           ENDED JUNE 30            ENDED JUNE 30         

HIGHLIGHTS

          2017      2016      CHANGE     2017      2016      CHANGE  

Production volume (million kgU)

        2.2        2.6        (15 )%      4.8        5.9        (19 )% 

Sales volume (million kgU)1

        2.7        2.9        (7 )%      4.3        5.2        (17 )% 

Average realized price

    ($ Cdn/kgU )      30.46        27.75        10 %      31.50        27.06        16 % 

Average unit cost of sales (including D&A)

    ($ Cdn/kgU )      21.44        21.31        1 %      22.66        20.90        8 % 

Revenue ($ millions)1

        82        81        1 %      137        140        (2 )% 

Gross profit ($ millions)

        24        19        26 %      38        32        19 % 

Gross profit (%)

        29        23        26 %      28        23        22 % 

 

1  There were no significant intersegment transactions in the periods shown.

 

20    CAMECO CORPORATION

SECOND QUARTER

Total revenue for the second quarter of 2017 increased to $82 million from $81 million for the same period last year. This was primarily due to a 10% increase in average realized price partially offset by a 7% decrease in sales volumes compared to 2016.

The total cost of products and services sold (including D&A) decreased by 6% ($58 million compared to $62 million in the second quarter of 2016) due to the decrease in sales volumes partially offset by an increase in the average unit cost of sales.

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

FIRST SIX MONTHS

In the first six months of the year, total revenue decreased by 2% due to a 17% decrease in sales volumes, partially offset by a 16% increase in realized price that was the result of increased prices on the sale of UF6 and fabrication, and the mix of products sold.

The total cost of products and services sold (including D&A) decreased 9% ($98 million compared to $108 million in 2016) due to the 17% decrease in sales volume, partially offset by an 8% increase in the average unit cost of sales.

The net effect was a $6 million increase in gross profit.

NUKEM

(financial results include U3O8, UF6, and SWU)

 

           THREE MONTHS           SIX MONTHS        
           ENDED JUNE 30           ENDED JUNE 30        

HIGHLIGHTS

          2017     2016     CHANGE     2017     2016     CHANGE  

Uranium sales (million lbs)1

        2.5       2.4       4 %      4.9       2.4       >100 % 

Average realized price

    ($ Cdn/lb )      34.86       52.51       (34 )%      34.24       52.24       (34 )% 

Cost of product sold (including D&A)

        103       139       (26 )%      181       141       28 % 

Revenue ($ millions)1

        88       129       (32 )%      166       131       27 % 

Gross loss ($ millions)

        (15 )      (10 )      (50 )%      (15 )      (10 )      (50 )% 

Gross loss (%)

        (17 )      (8 )     
 >(100
 %) 
     (9 )      (8 )      (13 )% 

 

1  There were no significant intersegment transactions in the periods shown.

SECOND QUARTER

During the second quarter of 2017, NUKEM delivered 2.5 million pounds of uranium, similar to the same period last year. Total revenues decreased 32% due mainly to a 34% decrease in average realized price. The decrease in realized price was mainly the result of a lower uranium spot price compared to the second quarter of 2016.

NUKEM recorded a gross loss of $15 million in the second quarter of 2017 compared to $10 million in 2016. In the current quarter, there was a $10 million write-down of inventory, which was the result of a decline in the spot price during the quarter. In 2016, a net write-down of inventory of $14 million was recorded.

FIRST SIX MONTHS

During the six months ended June 30, 2017, NUKEM delivered 4.9 million pounds of uranium, an increase of more than 100%, due to the timing of customer requirements and a greater number of acceptable spot sale opportunities relative to the same period in 2016. Total revenues increased 27% due to the increase in sales volumes, partially offset by a 34% decrease in average realized price. The decrease in realized price was mainly the result of a lower uranium spot price compared to the first six months of 2016.

NUKEM recorded a gross loss of $15 million in the first six months of 2017 compared to a $10 million loss in the same period in 2016. Included in the 2017 margin was an $11 million net write-down of inventory while the 2016 margin included a $14 million net write-down.

 

2017 SECOND QUARTER REPORT    21

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 1% higher than the second quarter of 2016. See below for more information.

URANIUM PRODUCTION

 

     THREE MONTHS
ENDED JUNE 30		            SIX MONTHS
ENDED JUNE 30		               

OUR SHARE (MILLION LBS)

    2017      2016      CHANGE     2017      2016      CHANGE     2017 PLAN  

McArthur River/Key Lake

      3.6        2.8        29 %      7.2        5.7        26 %      12.6  

Cigar Lake

      2.5        2.0        25 %      4.8        4.3        12 %      9.0  

Inkai

      0.8        1.1        (27 )%      1.5        2.2        (32 )%      3.1  

Rabbit Lake

      —          0.7        (100 )%      —          1.1        (100 )%      —    

Smith Ranch-Highland

      0.1        0.3        (67 )%      0.2        0.6        (67 )%      0.4  

Crow Butte

      0.1        0.1        —         0.1        0.1        —         0.1  
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

    

 

 

  

Total

      7.1        7.0        1 %      13.8        14.0        (1 )%      25.2  
  

 

 

     

 

 

     

 

 

    

 

 

     

 

 

     

 

 

    

 

 

  

Uranium 2017 Q2 updates

PRODUCTION UPDATE

McArthur River/Key Lake

Production was 29% higher for the second quarter, and 26% higher for the first six months compared to the same periods in 2016. Last year, outages to work on the existing calciner circuit, combined with the timing of the planned annual maintenance shutdown, resulted in reduced production during the first half of the year compared to 2017. This year, in alignment with our continued efforts to reduce costs, our production plan includes an extended summer shut-down during the third quarter. The shut-down consists of a four-week vacation period in July, followed by a two-week maintenance period at McArthur River and a four-week maintenance period at Key Lake, both of which are now underway. Production is expected to restart at the end of August. As a consequence of the summer shutdown, we expect third quarter production at McArthur River/Key Lake to be lower than the third quarter of 2016, which is expected to increase the quarterly unit production cost.

Cigar Lake

Total packaged production from Cigar Lake was 25% higher in the second quarter, and 12% higher in the first six months compared to the same periods last year. The year-over-year increase is the result of the scheduled rampup of the operation. On June 29, the Canadian Nuclear Safety Commission approved a 10-year renewal of the operating licence for AREVA’s McClean Lake mill. The licence is valid until June 30, 2027.

Inkai

Production was 27% lower for the quarter and 32% lower for the first six months compared to the same periods last year due to the timing of new wellfield development and the planned 10% decrease in production for 2017.

PRODUCTION CURTAILMENT

Smith Ranch-Highland/Crow Butte

Total production was 50% lower for the quarter and 57% lower for the first six months compared to the same periods in 2016, as a result of the decision to curtail production and defer all wellfield development at our US operations. Production is expected to continue trending down as the head grade decreases.

Rabbit Lake

The Rabbit Lake operation is in a safe state of care and maintenance; there was no production in the second quarter of 2017. We are continually weighing the value of maintaining the operation in standby, against the cost of doing so. However, as long as production is suspended, we expect care and maintenance costs to range between $35 million and $40 million annually for the first few years.

 

22    CAMECO CORPORATION

Fuel services 2017 Q2 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 2.2 million kgU in the second quarter, 15% lower than the same period last year due to the timing of scheduled production. Production in the first six months was 19% lower than the same period in 2016.

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

 

  •   Les Yesnik, general manager, McArthur River/Key Lake, Cameco

 

  •   Greg Murdock, mine manager, McArthur River, Cameco

CIGAR LAKE

 

  •   Jeremy Breker, general manager, Cigar Lake, Cameco

INKAI

 

  •   Darryl Clark, president, Cameco Kazakhstan LLP
 

 

Additional information

Critical accounting estimates

Due to the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.

Controls and procedures

As of June 30, 2017, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of June 30, 2017, the CEO and CFO concluded that:

 

  •   the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required

 

  •   such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

2017 SECOND QUARTER REPORT    23