EX-99.2
Exhibit 99.2
Management’s discussion and analysis
for the quarter ended September 30, 2017
| 4 |
THIRD QUARTER MARKET UPDATE |
| 7 |
CONSOLIDATED FINANCIAL RESULTS |
| 16 |
LIQUIDITY AND CAPITAL RESOURCES |
| 18 |
FINANCIAL RESULTS BY SEGMENT |
| 22 |
OUR OPERATIONS - THIRD QUARTER UPDATES |
| 23 |
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 September 30, 2017 (interim financial statements). The information is based on what we
knew as of October 26, 2017 and updates our first quarter, second 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, second 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 Third 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 expectation related to annual cost reductions resulting from the full implementation of changes to our global marketing activities |
| |
• |
|
our 2017 consolidated outlook and the outlook for our uranium, fuel services and NUKEM segments for 2017 |
| |
• |
|
our 2017 adjusted net earnings and cash from operations expectations
|
| |
• |
|
our expectations for uranium deliveries, and average realized prices in the fourth quarter |
| |
• |
|
our expectation that there could be further variability in uranium production in the future if current market conditions continue |
| |
• |
|
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 |
| |
• |
|
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 2017 adjusted net earnings estimate or cash flow estimate 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
|
2 CAMECO
CORPORATION
| |
• |
|
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 |
| |
• |
|
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 |
| |
• |
|
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 |
| |
• |
|
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 |
| |
• |
|
the timing of the judge’s decision in the CRA trial and the TEPCO arbitration hearing |
| |
• |
|
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 |
| |
• |
|
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 THIRD 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.
Third quarter market update
There was little change in the market during the third quarter of 2017. During the largest annual industry symposium in September, discussions centred around
the continued state of oversupply in the uranium market, risks to reactor construction programs, the potential impact of policy shifts by some governments, and risks to demand from non-nuclear electricity
generating sources. Global demand expectations have come down, and the industry continues to work its way through supply that was incented during previous price spikes.
Longer term, uranium demand is backed by steady reactor growth with 56 reactors under construction. However, while under construction, these reactors are not
yet consuming uranium. Therefore, there has not yet been a corresponding increase in uranium consumption.
With each new reactor, comes the long-term need
for a safe and reliable source of uranium. And while the availability of pounds in the spot market has helped to satisfy the needs of utilities in the near term, the continued risk of production curtailments, financially distressed producers, lack
of investment in new primary supply, declining secondary supplies, and growing uncovered requirements are expected to generate increasing pressure for fuel buyers to return to long-term contracting.
4 CAMECO
CORPORATION
Industry consultants now estimate that utilities’ cumulative uncovered requirements total over
600 million pounds over the next decade. We believe the reduction from the previous estimate of 800 million pounds is due to some limited contracting activity, delays in construction programs, early reactor retirements and project
cancellations. Some of these requirements should return as delayed reactor construction is completed, however it is beyond the 2026 timeframe. As annual supply adjusts and uncovered requirements grow, we believe the pounds available in the spot
market won’t be enough to satisfy the demand. The need to eventually contract for replacement volumes to fill these uncovered requirements 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, pressure for long-term contracting and utilities’ uncovered requirements 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
|
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|
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|
|
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|
|
|
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|
|
|
| |
|
SEP 30
2017 |
|
|
JUN 30
2017 |
|
|
MAR 31
2017 |
|
|
DEC 31
2016 |
|
|
SEP 30
2016 |
|
|
JUN 30
2016 |
|
| Uranium ($US/lb U3O8)1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average spot market price |
|
|
20.33 |
|
|
|
20.15 |
|
|
|
23.88 |
|
|
|
20.25 |
|
|
|
23.00 |
|
|
|
26.70 |
|
| Average long-term price |
|
|
30.50 |
|
|
|
33.00 |
|
|
|
33.00 |
|
|
|
30.00 |
|
|
|
37.50 |
|
|
|
40.50 |
|
|
|
|
|
|
|
|
| Fuel services ($US/kgU as UF6)1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average spot market price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| North America |
|
|
4.55 |
|
|
|
5.13 |
|
|
|
5.93 |
|
|
|
5.93 |
|
|
|
5.93 |
|
|
|
6.75 |
|
| Europe |
|
|
4.93 |
|
|
|
5.50 |
|
|
|
6.45 |
|
|
|
6.45 |
|
|
|
6.45 |
|
|
|
7.25 |
|
|
|
|
|
|
|
|
| Average long-term price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| North America |
|
|
14.50 |
|
|
|
14.50 |
|
|
|
13.50 |
|
|
|
12.50 |
|
|
|
12.25 |
|
|
|
12.75 |
|
| Europe |
|
|
14.25 |
|
|
|
14.25 |
|
|
|
14.00 |
|
|
|
13.00 |
|
|
|
13.00 |
|
|
|
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 third quarter of 2017 was approximately 12 million pounds, which is on par with the third quarter of 2016. Year to date, approximately 34 million pounds has been
transacted in the spot market, compared to 31 million pounds in the first three quarters of 2016. At the end of the quarter, the average reported spot price was $20.33 (US) per pound, up $0.18 (US) from the previous quarter.
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 nine months of 2017 was
approximately 63 million pounds. Although higher than the 38 million pounds reported over the same period in 2016, the volumes were still less than the quantities consumed, and remained largely discretionary due to currently high inventory
levels. The average reported long-term price at the end of the quarter was $30.50 (US) per pound, down $2.50 (US) from last quarter.
Spot UF6 conversion prices declined in both the North American and European markets, while long-term UF6 conversion prices were unchanged for the
quarter.
Shares and stock options outstanding
At October 26, 2017, we had:
| |
• |
|
395,792,732 common shares and one Class B share outstanding |
| |
• |
|
8,411,384 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.
2017 THIRD QUARTER
REPORT 5
Also of note:
TEPCO DISPUTE
On the TEPCO dispute, the three arbitrators
have been appointed and based on the current schedule set by them, we expect the case will be heard in the first quarter of 2019. However, the timing for a final decision will be dependent on how long the arbitrators deliberate following the
conclusion of the hearing.
GLOBAL MARKETING CONSOLIDATION
In line with the other disciplined actions we have taken, we made some changes during the quarter to the way our global marketing activities are organized. All
future Canadian and international marketing activities will be consolidated in Saskatoon. These actions are expected to reduce costs between $8 million and $10 million per year once fully implemented.
IMPAIRMENT
The changes to our global marketing
organization significantly impacts the marketing activities historically performed by NUKEM. This required us to perform an impairment test on the NUKEM segment. As a result, we have recognized an impairment charge for the full carrying value of the
goodwill of $111 million. See note 4 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 $126 million in 2017. We see no basis for terminating the agreement. In this MD&A, our 2017 financial outlook and other disclosures relating to our contract portfolio are presented on a basis which excludes this agreement with TEPCO,
which is under dispute.
Consolidated financial results
|
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|
|
|
| |
|
THREE MONTHS |
|
|
|
|
|
NINE MONTHS |
|
|
|
|
| CONSOLIDATED HIGHLIGHTS |
|
ENDED SEPTEMBER 30 |
|
|
|
|
|
ENDED SEPTEMBER 30 |
|
|
|
|
| ($ MILLIONS EXCEPT WHERE INDICATED) |
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
| Revenue |
|
|
486 |
|
|
|
670 |
|
|
|
(27 |
)% |
|
|
1,348 |
|
|
|
1,544 |
|
|
|
(13 |
)% |
| Gross profit |
|
|
51 |
|
|
|
146 |
|
|
|
(65 |
)% |
|
|
199 |
|
|
|
307 |
|
|
|
(35 |
)% |
| Net earnings (losses) attributable to equity holders |
|
|
(124 |
) |
|
|
142 |
|
|
|
>(100 |
%) |
|
|
(143 |
) |
|
|
83 |
|
|
|
>(100 |
%) |
| $ per common share (basic) |
|
|
(0.31 |
) |
|
|
0.36 |
|
|
|
>(100 |
%) |
|
|
(0.36 |
) |
|
|
0.21 |
|
|
|
>(100 |
%) |
| $ per common share (diluted) |
|
|
(0.31 |
) |
|
|
0.36 |
|
|
|
>(100 |
%) |
|
|
(0.36 |
) |
|
|
0.21 |
|
|
|
>(100 |
%) |
| Adjusted net earnings (losses) (non-IFRS, see page
8) |
|
|
(50 |
) |
|
|
118 |
|
|
|
>(100 |
%) |
|
|
(122 |
) |
|
|
54 |
|
|
|
>(100 |
%) |
| $ per common share (adjusted and diluted) |
|
|
(0.13 |
) |
|
|
0.30 |
|
|
|
>(100 |
%) |
|
|
(0.31 |
) |
|
|
0.14 |
|
|
|
>(100 |
%) |
| Cash provided by operations (after working capital changes) |
|
|
154 |
|
|
|
385 |
|
|
|
(60 |
)% |
|
|
276 |
|
|
|
57 |
|
|
|
>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 third quarter and the first nine months of 2017, compared to the same
periods in 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
THREE MONTHS |
|
|
NINE MONTHS |
|
| |
|
|
|
ENDED SEPTEMBER 30 |
|
|
ENDED SEPTEMBER 30 |
|
| ($ MILLIONS) |
|
|
|
IFRS |
|
|
ADJUSTED |
|
|
IFRS |
|
|
ADJUSTED |
|
| Net earnings – 2016 |
|
|
142 |
|
|
|
118 |
|
|
|
83 |
|
|
|
54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 (lower) sales volume |
|
|
(2 |
) |
|
|
(2 |
) |
|
|
17 |
|
|
|
17 |
|
|
|
Lower realized prices ($US) |
|
|
(131 |
) |
|
|
(131 |
) |
|
|
(243 |
) |
|
|
(243 |
) |
|
|
Foreign exchange impact on realized prices |
|
|
(4 |
) |
|
|
(4 |
) |
|
|
(7 |
) |
|
|
(7 |
) |
|
|
Lower costs |
|
|
35 |
|
|
|
35 |
|
|
|
111 |
|
|
|
111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change – uranium |
|
|
(102 |
) |
|
|
(102 |
) |
|
|
(122 |
) |
|
|
(122 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fuel services |
|
Lower sales volume |
|
|
(4 |
) |
|
|
(4 |
) |
|
|
(9 |
) |
|
|
(9 |
) |
|
|
Higher realized prices ($Cdn) |
|
|
13 |
|
|
|
13 |
|
|
|
34 |
|
|
|
34 |
|
|
|
Higher costs |
|
|
(18 |
) |
|
|
(18 |
) |
|
|
(27 |
) |
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change – fuel services |
|
|
(9 |
) |
|
|
(9 |
) |
|
|
(2 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| NUKEM |
|
Gross profit |
|
|
14 |
|
|
|
14 |
|
|
|
10 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change – NUKEM |
|
|
14 |
|
|
|
14 |
|
|
|
10 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other changes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Lower (higher) administration expenditures |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
26 |
|
|
|
26 |
|
| Lower (higher) impairment charges |
|
|
(111 |
) |
|
|
— |
|
|
|
13 |
|
|
|
— |
|
| Lower exploration expenditures |
|
|
2 |
|
|
|
2 |
|
|
|
13 |
|
|
|
13 |
|
| Rabbit Lake reclamation provision |
|
|
3 |
|
|
|
— |
|
|
|
9 |
|
|
|
— |
|
| Loss (gain) on disposal of assets |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
3 |
|
|
|
3 |
|
| Lower loss (lower gain) on derivatives |
|
|
34 |
|
|
|
21 |
|
|
|
(8 |
) |
|
|
39 |
|
| Higher foreign exchange losses |
|
|
(30 |
) |
|
|
(30 |
) |
|
|
(16 |
) |
|
|
(16 |
) |
| Gain on customer contract settlements in 2016 |
|
|
(59 |
) |
|
|
(59 |
) |
|
|
(59 |
) |
|
|
(59 |
) |
| Lower income tax recovery |
|
|
(7 |
) |
|
|
(4 |
) |
|
|
(97 |
) |
|
|
(78 |
) |
| Other |
|
|
1 |
|
|
|
1 |
|
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net losses – 2017 |
|
|
(124 |
) |
|
|
(50 |
) |
|
|
(143 |
) |
|
|
(122 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Financial results by segment beginning on
page 18 for more detailed discussion.
2017 THIRD 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,
impairment charges, Rabbit Lake reclamation provisions, 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
2017 adjusted net earnings for the third quarter and for the first nine months with our net earnings for the same periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS |
|
|
NINE MONTHS |
|
| |
|
ENDED SEPTEMBER 30 |
|
|
ENDED SEPTEMBER 30 |
|
| ($ MILLIONS) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
| Net earnings (losses) attributable to equity holders |
|
|
(124 |
) |
|
|
142 |
|
|
|
(143 |
) |
|
|
83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments on foreign exchange derivatives |
|
|
(40 |
) |
|
|
(27 |
) |
|
|
(106 |
) |
|
|
(153 |
) |
| NUKEM purchase price inventory adjustment |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(6 |
) |
| Impairment charges |
|
|
111 |
|
|
|
— |
|
|
|
111 |
|
|
|
124 |
|
| Rabbit Lake reclamation provision |
|
|
(9 |
) |
|
|
(6 |
) |
|
|
(15 |
) |
|
|
(6 |
) |
| Income taxes on adjustments |
|
|
12 |
|
|
|
9 |
|
|
|
31 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted net earnings (losses) |
|
|
(50 |
) |
|
|
118 |
|
|
|
(122 |
) |
|
|
54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly trends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| HIGHLIGHTS |
|
2017 |
|
|
2016 |
|
|
2015 |
|
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
| Revenue |
|
|
486 |
|
|
|
470 |
|
|
|
393 |
|
|
|
887 |
|
|
|
670 |
|
|
|
466 |
|
|
|
408 |
|
|
|
975 |
|
| Net earnings (losses) attributable to equity holders |
|
|
(124 |
) |
|
|
(2 |
) |
|
|
(18 |
) |
|
|
(144 |
) |
|
|
142 |
|
|
|
(137 |
) |
|
|
78 |
|
|
|
(10 |
) |
| $ per common share (basic) |
|
|
(0.31 |
) |
|
|
(0.00 |
) |
|
|
(0.05 |
) |
|
|
(0.36 |
) |
|
|
0.36 |
|
|
|
(0.35 |
) |
|
|
0.20 |
|
|
|
(0.03 |
) |
| $ per common share (diluted) |
|
|
(0.31 |
) |
|
|
(0.00 |
) |
|
|
(0.05 |
) |
|
|
(0.36 |
) |
|
|
0.36 |
|
|
|
(0.35 |
) |
|
|
0.20 |
|
|
|
(0.03 |
) |
| Adjusted net earnings (losses) (non-IFRS, see page
8) |
|
|
(50 |
) |
|
|
(44 |
) |
|
|
(29 |
) |
|
|
90 |
|
|
|
118 |
|
|
|
(57 |
) |
|
|
(7 |
) |
|
|
151 |
|
| $ per common share (adjusted and diluted) |
|
|
(0.13 |
) |
|
|
(0.11 |
) |
|
|
(0.07 |
) |
|
|
0.23 |
|
|
|
0.30 |
|
|
|
(0.14 |
) |
|
|
(0.02 |
) |
|
|
0.38 |
|
| Cash provided by (used in) operations (after working capital changes) |
|
|
154 |
|
|
|
130 |
|
|
|
(8 |
) |
|
|
255 |
|
|
|
385 |
|
|
|
(51 |
) |
|
|
(277 |
) |
|
|
503 |
|
Key things to note:
| |
• |
|
our financial results are strongly influenced by the performance of our uranium segment, which accounted for 79% of consolidated revenues in the third 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 third quarter to the previous
seven quarters.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| HIGHLIGHTS |
|
2017 |
|
|
2016 |
|
|
2015 |
|
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
| Net earnings (losses) attributable to equity holders |
|
|
(124 |
) |
|
|
(2 |
) |
|
|
(18 |
) |
|
|
(144 |
) |
|
|
142 |
|
|
|
(137 |
) |
|
|
78 |
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments on foreign exchange derivatives |
|
|
(40 |
) |
|
|
(44 |
) |
|
|
(22 |
) |
|
|
23 |
|
|
|
(27 |
) |
|
|
(10 |
) |
|
|
(116 |
) |
|
|
10 |
|
| NUKEM purchase price inventory adjustment |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(6 |
) |
|
|
— |
|
|
|
— |
|
| Impairment charges |
|
|
111 |
|
|
|
— |
|
|
|
— |
|
|
|
238 |
|
|
|
— |
|
|
|
124 |
|
|
|
— |
|
|
|
210 |
|
| Rabbit Lake reclamation provision |
|
|
(9 |
) |
|
|
(12 |
) |
|
|
6 |
|
|
|
(28 |
) |
|
|
(6 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
| Income taxes on adjustments |
|
|
12 |
|
|
|
14 |
|
|
|
5 |
|
|
|
1 |
|
|
|
9 |
|
|
|
(28 |
) |
|
|
31 |
|
|
|
(59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted net earnings (losses) (non-IFRS, see page
8) |
|
|
(50 |
) |
|
|
(44 |
) |
|
|
(29 |
) |
|
|
90 |
|
|
|
118 |
|
|
|
(57 |
) |
|
|
(7 |
) |
|
|
151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate expenses
ADMINISTRATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS
ENDED SEPTEMBER 30 |
|
|
|
|
|
NINE MONTHS
ENDED SEPTEMBER 30 |
|
|
|
|
| ($ MILLIONS) |
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
| Direct administration |
|
|
38 |
|
|
|
39 |
|
|
|
(3 |
)% |
|
|
116 |
|
|
|
145 |
|
|
|
(20 |
)% |
| Stock-based compensation |
|
|
2 |
|
|
|
— |
|
|
|
— |
|
|
|
9 |
|
|
|
6 |
|
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total administration |
|
|
40 |
|
|
|
39 |
|
|
|
3 |
% |
|
|
125 |
|
|
|
151 |
|
|
|
(17 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct administration costs were $1 million lower for the third quarter of 2017 compared to the same period last year.
Included in the current quarter are $5 million in one-time costs related to the changes made to the way our global marketing activities are organized. These actions are expected to reduce costs between
$8 million and $10 million per year once fully implemented.
Direct administration costs were $29 million lower for the first nine 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 nine months of 2017. The decrease was partially offset by the charges related to the reorganization of our global marketing activities.
EXPLORATION
In the third quarter, uranium exploration
expenses were $8 million, a decrease of $2 million compared to the third quarter of 2016. Exploration expenses for the first nine months of the year decreased by $13 million compared to 2016, to $24 million, due to a planned
reduction in expenditures.
INCOME TAXES
We recorded
an income tax recovery of $3 million in the third quarter of 2017, compared to a recovery of $10 million in the third quarter of 2016.
On an
adjusted basis, we recorded an income tax recovery of $15 million this quarter compared to a recovery of $19 million in the third quarter of 2016, primarily due to a change in the distribution of earnings among jurisdictions. In 2017, we
recorded losses of $31 million in Canada compared to losses of $121 million in 2016, while we recorded losses of $34 million in foreign jurisdictions compared to earnings of $221 million last year.
In the first nine months of 2017, we recorded an income tax expense of $31 million compared to a recovery of $66 million in 2016.
2017 THIRD QUARTER
REPORT 9
On an adjusted basis, we recorded an income tax recovery of $1 million for the first nine months compared to
a recovery of $79 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 losses of $27 million in Canada compared to
losses of $371 million in 2016, while we recorded losses of $95 million in foreign jurisdictions compared to earnings of $349 million last year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS |
|
|
NINE MONTHS |
|
| |
|
ENDED SEPTEMBER 30 |
|
|
ENDED SEPTEMBER 30 |
|
| ($ MILLIONS) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
| Pre-tax adjusted earnings1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Canada |
|
|
(31 |
) |
|
|
(121 |
) |
|
|
(27 |
) |
|
|
(371 |
) |
| Foreign |
|
|
(34 |
) |
|
|
221 |
|
|
|
(95 |
) |
|
|
349 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total pre-tax adjusted earnings |
|
|
(65 |
) |
|
|
100 |
|
|
|
(122 |
) |
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted income taxes1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Canada |
|
|
(9 |
) |
|
|
(28 |
) |
|
|
10 |
|
|
|
(96 |
) |
| Foreign |
|
|
(6 |
) |
|
|
9 |
|
|
|
(11 |
) |
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted income tax recovery |
|
|
(15 |
) |
|
|
(19 |
) |
|
|
(1 |
) |
|
|
(79 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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. We have now settled our IRS dispute related to the 2009 through 2012 tax years, and in the third quarter we paid $198,000 (US) comprised of $122,000 (US) taxes owing plus interest.
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 September 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 2011 in the amount of
$371 million. The Canadian income tax rules include provisions that require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these
provisions, after applying elective deductions, we have paid a net amount of $303 million in cash. In addition, we have provided $421 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed
after 2014. The amounts paid or secured are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| YEAR PAID ($ MILLIONS) |
|
CASH TAXES |
|
|
INTEREST
AND INSTALMENT
PENALTIES |
|
|
TRANSFER
PRICING
PENALTIES |
|
|
TOTAL |
|
|
CASH
REMITTANCE |
|
|
SECURED BY
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 |
|
|
|
39 |
|
|
|
40 |
|
|
|
39 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
360 |
|
|
|
179 |
|
|
|
185 |
|
|
|
724 |
|
|
|
303 |
|
|
|
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 |
|
| Securedby 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 September 30, 2017. |
In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $724 million already
paid or otherwise secured to date.
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.
2017 THIRD QUARTER
REPORT 11
The trial for the 2003, 2005 and 2006 tax years concluded on September 13, 2017 and we expect to receive a
Tax Court decision within six to 18 months. Once the decision is issued, the rules that apply to our case permit either party to appeal the Tax Court decision to the Federal Court of Appeal. The decision of the Federal Court of Appeal can be
appealed to the Supreme Court of Canada, but only if the Supreme Court agrees to hear the appeal. An appeal of a Tax Court of Canada decision to the Federal Court of Appeal must be filed within 30 days after the issuance of a Tax Court decision
(excluding the months of July and August). The request to appeal a decision of the Federal Court of Appeal to the Supreme Court of Canada must be made within 60 days of issuance of a Federal Court of Appeal decision.
In the event that either party appeals the Tax Court decision, we anticipate that it would take about two years from the date the Tax Court decision is issued
to receive a decision from the Federal Court of Appeal. If a further appeal is pursued, it would likely take about two years from the date the Federal Court of Appeal decision is issued to receive a decision from the Supreme Court of Canada.
The total tax amount reassessed for the 2003, 2005 and 2006 tax years was $11 million, and we remitted 50% of such amount at the time the reassessments
were issued. In certain circumstances, including where neither party pursues an appeal of the Tax Court decision, CRA would issue revised reassessments for the 2003, 2005 and 2006 tax years that comply with the Tax Court decision. Following those
reassessments, the corresponding tax payments or refunds, as applicable, plus interest, would be made or received, as applicable, within a reasonable period. Where one or more appeals are pursued by either party, reassessments might not be issued
until after the decision on the final appeal is received. If the Tax Court decision results in an aggregate tax amount in excess of what we have already remitted, and we pursue an appeal of that decision, we may be required to remit additional cash
tax amounts not exceeding the remaining unpaid portion of the original $11 million (plus interest) while that appeal is underway. Where the Tax Court decision results in a refund of the remitted portion of the original $11 million (with
interest), we may not receive that refund until and unless the Tax Court decision is confirmed after the final appeal.
Once the Tax Court has delivered a
decision for the 2003, 2005 and 2006 tax years we will consider how the decision relates to other years in issue (being 2004 and years subsequent to 2006). While the decision would not be legally binding for any year other than the trial years, we
expect the ultimate decision for the trial years to be an important factor in resolving the dispute for the other years in issue.
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 |
12 CAMECO
CORPORATION
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).
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 September 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SEPTEMBER 30, 2017
($ MILLIONS) |
|
|
|
20171 |
|
|
2018 |
|
|
2019 |
|
|
AFTER
2019 |
|
|
TOTAL |
|
| US dollar forward contracts |
|
|
|
|
150 |
|
|
|
320 |
|
|
|
70 |
|
|
|
40 |
|
|
|
580 |
|
| Average contract rate 2 |
|
(US/Cdn dollar) |
|
|
1.28 |
|
|
|
1.31 |
|
|
|
1.31 |
|
|
|
1.27 |
|
|
|
1.30 |
|
| US dollar option contracts |
|
|
|
|
30 |
|
|
|
105 |
|
|
|
120 |
|
|
|
10 |
|
|
|
265 |
|
| Average contract rate range2 |
|
(US/Cdn dollar) |
|
|
1.33 to 1.37 |
|
|
|
1.29 to 1.33 |
|
|
|
1.27 to 1.33 |
|
|
|
1.31 to 1.35 |
|
|
|
1.28 to 1.33 |
|
| Total US dollar hedge contracts |
|
|
|
|
180 |
|
|
|
425 |
|
|
|
190 |
|
|
|
50 |
|
|
|
845 |
|
| Effective hedge rate
range3 |
|
(US/Cdn dollar) |
|
|
1.26 to 1.27 |
|
|
|
1.23 to 1.24 |
|
|
|
1.25 to 1.29 |
|
|
|
1.28 to 1.29 |
|
|
|
1.24 to 1.26 |
|
| Hedge ratio4 |
|
|
|
|
51 |
% |
|
|
41 |
% |
|
|
17 |
% |
|
|
4 |
% |
|
|
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 September 30, 2017:
| |
• |
|
The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.25 (Cdn), down from $1.00 (US) for $1.30 (Cdn) at June 30, 2017. The exchange rate averaged $1.00 (US) for $1.25 (Cdn) over the
quarter. |
| |
• |
|
The mark-to-market gain on all foreign exchange contracts was $43 million compared to an $18 million gain at June 30, 2017.
|
For information on the impact of foreign exchange on our intercompany balances, see note 16 to the financial statements.
2017 THIRD QUARTER
REPORT 13
Outlook for 2017
Our outlook for 2017 reflects the expenditures necessary to help us achieve our strategy and is based on the assumptions found below the table, including a
given uranium spot price, uranium term price, and foreign exchange rate. For more information on how changes in the exchange rate or uranium prices can impact our outlook see Revenue, adjusted net earnings, and cash flow sensitivity analysis
on page 15, and Foreign exchange on page 13. Our 2017 financial outlook, and other disclosures relating to our contract portfolio, have been presented on a basis that excludes our contract with TEPCO, which is under dispute.
Our outlook for uranium production, uranium sales volume, uranium revenue, uranium average realized price, uranium average unit cost of sales, consolidated
tax expense, and capital expenditures has changed. We do not provide an outlook for the items in the table that are marked with a dash.
See 2017
Financial results by segment on page 18 for details.
2017 FINANCIAL OUTLOOK
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
CONSOLIDATED |
|
|
URANIUM |
|
|
FUEL SERVICES |
|
|
NUKEM |
|
| EXPECTED CONTRIBUTION TO
GROSS PROFIT |
|
100% |
|
|
85% |
|
|
14% |
|
|
1% |
|
| |
|
|
|
| Production |
|
|
— |
|
|
|
24.0
million lbs |
|
|
|
8 to 9
million kgU |
|
|
|
— |
|
| Sales/delivery volume1 |
|
|
— |
|
|
|
32 to 33
million lbs |
2 |
|
|
11 to 12
million kgU |
|
|
|
8 to 9
million lbs U3O8 |
|
| Revenue ($ million)1 |
|
|
2,100 to 2,270 |
|
|
|
1,520 to 1,570 |
3 |
|
|
300 to 330 |
|
|
|
— |
|
| Average realized price3 |
|
|
— |
|
|
$ |
47.50/lb |
2 |
|
|
— |
|
|
|
— |
|
| Average unit cost of sales (including D&A) |
|
|
— |
|
|
$ |
35.00-36.00/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 million |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| Capital expenditures8 |
|
$ |
160 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 $20.25 (US) per pound (the UxC spot price as of September 30, 2017), a long-term price indicator of $31.00 (US) per pound (the UxC long-term indicator on September 30, 2017)
and an exchange rate of $1.00 (US) for $1.25 (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. |
Based on the outlook provided in the table and the assumptions for uranium prices and foreign exchange rates used in and listed below the table, and as we
reported in the second quarter, we continue to expect 2017 adjusted net earnings to be weaker than in 2016. However, we continue to expect cash from operations to be higher in 2017 than the $312 million reported in 2016. This is forward looking
information that is based on the additional assumptions and subject to the material risks discussed under the heading Caution about forward looking information beginning on page 2.
14 CAMECO
CORPORATION
Our outlook range for uranium revenue has been updated to $1,520 million to $1,570 million (previously
$1,470 million to $1,570 million) as a result of additional certainty on deliveries and increased sales volumes. Sales volumes for uranium are now expected to be 32 million to 33 million lbs (previously 30 million to
32 million lbs) as a consequence of some contract optimization opportunities, whereby we accelerated some deliveries into 2017.
We now expect an
annual average realized price of $47.50 per pound (previously $49.00 per pound) in our uranium segment for 2017, as a result of the revised US dollar exchange rate assumption of 1.25 (previously 1.30). Our Canadian dollar realized prices for the
first nine months of 2017 were $44.86 per pound, which translates to an expectation of higher prices on deliveries in the fourth quarter.
Average unit
cost of sales (including D&A) in our uranium segment is now expected to be $35.00 to $36.00 per pound (previously $36.00 to $38.00 per pound). The reduction is a result of purchase deferrals in 2017 and the impact of the revised US dollar
exchange rate assumption of 1.25 (previously 1.30), partially offset by increased unit production costs due to a decrease in expected uranium production.
Uranium production is now expected to be 24 million pounds (previously 25.2 million pounds) due to production delays at Key Lake caused by work
required on the existing calciner circuit and lower production than expected at Smith Ranch-Highland. Given our inventory position, we are willing to accept some variability in 2017 production, and expect there could be further variability in the
future if current market conditions continue. However, we won’t compromise safety, the environment, or the long-term health of the company.
We now
expect a tax expense on an adjusted net earnings basis of less than $10 million (previously $10 million to $20 million) due to a changes in our outlook noted above. However, on October 25, 2017, in its throne speech, the Saskatchewan
government announced that it would reverse a previously enacted corporate tax decrease. If this change is substantively enacted before the end of 2017, we will reverse the corresponding reduction to the deferred tax asset we recorded in the second
quarter of this year with the expected effect of decreasing our 2017 tax expense by $24 million.
Our outlook for capital expenditures has decreased
to $160 million (previously $175 million) due to a further reduction in spending at both McArthur River and Cigar Lake.
In our uranium and fuel
services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales/delivery volumes and revenue can vary significantly. We are on track for our uranium sales/delivery targets in 2017 and,
therefore expect to deliver between 11 million and 12 million pounds in the fourth quarter.
REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW
SENSITIVITY ANALYSIS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| FOR 2017 ($ MILLIONS) |
|
|
|
IMPACT ON: |
|
| |
CHANGE |
|
REVENUE |
|
|
ANE |
|
|
CASH FLOW |
|
| Uranium spot and term price1 |
|
$5(US)/lb increase |
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
|
|
$5(US)/lb decrease |
|
|
— |
|
|
|
— |
|
|
|
— |
|
| Value of Canadian dollar vs US dollar |
|
One cent decrease in CAD |
|
|
6 |
|
|
|
3 |
|
|
|
3 |
|
|
|
One cent increase in CAD |
|
|
(6 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
| 1 |
Assuming change in both UxC spot price ($20.25 (US) per pound on September 30, 2017) and the UxC long-term price indicator ($31.00 (US) per pound on September 30, 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
September 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 September 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.
2017 THIRD QUARTER
REPORT 15
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 |
|
|
36 |
|
|
|
44 |
|
|
|
55 |
|
|
|
65 |
|
|
|
75 |
|
|
|
84 |
|
|
|
91 |
|
| 2019 |
|
|
32 |
|
|
|
42 |
|
|
|
55 |
|
|
|
65 |
|
|
|
74 |
|
|
|
81 |
|
|
|
87 |
|
| 2020 |
|
|
32 |
|
|
|
42 |
|
|
|
55 |
|
|
|
65 |
|
|
|
74 |
|
|
|
81 |
|
|
|
87 |
|
| 2021 |
|
|
30 |
|
|
|
42 |
|
|
|
57 |
|
|
|
67 |
|
|
|
76 |
|
|
|
84 |
|
|
|
92 |
|
The table illustrates the mix of long -term contracts in our September 30, 2017 portfolio, and is consistent with our
marketing strategy. It has been updated to reflect contracts entered into up to September 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 26 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
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. 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 provided by operations
was $231 million lower this quarter than in the third quarter of 2016. Contributing to this change were lower gross profits in our operating segments and an increase in income taxes paid. In addition, there was an increase in working capital
requirements, which provided $45 million less in 2017 than in 2016. Not including working capital requirements, our operating cash flows this quarter were lower by $186 million.
16 CAMECO
CORPORATION
Cash provided by operations was $219 million higher in the first nine months of 2017 than for the same
period in 2016 due largely to a decrease in working capital requirements. This was a result of a decrease in inventory compared to an increase in 2016. Working capital required $224 million less in 2017. In addition, while we had lower gross
profits in our operating segments, 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 nine months were lower by $5 million.
FINANCING ACTIVITIES
We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.9 billion at
September 30, 2017, down from $3.0 billion at June 30, 2017. At September 30, 2017, we had approximately $1.5 billion outstanding in letters of credit, unchanged from December 31, 2016. At September 30, 2017, we
had no short-term debt outstanding on our $1.25 billion unsecured revolving credit facility, unchanged from December 31, 2016, and during the quarter, we extended the maturity date of the facility from November 1, 2020 to
November 1, 2021. During the quarter, NUKEM’s 75 million (€) multicurrency revolving loan facility was cancelled.
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 September 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
September 30, 2017, we had $4.5 million ($3.6 million (US)) of inventory pledged as security under financing arrangements, compared with $4.9 million ($3.6 million (US)) at December 31, 2016.
OFF-BALANCE SHEET ARRANGEMENTS
We had three kinds of off-balance sheet arrangements at September 30, 2017:
Purchase commitments
The following table is based on our purchase commitments in our uranium, fuel services, and NUKEM segments at September 30, 2017. These commitments
include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of
delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
2018 AND |
|
|
2020 AND |
|
|
2022 AND |
|
|
|
|
| SEPTEMBER 30 ($ MILLIONS) |
|
2017 |
|
|
2019 |
|
|
2021 |
|
|
BEYOND |
|
|
TOTAL |
|
| Purchase commitments1 |
|
|
270 |
|
|
|
474 |
|
|
|
124 |
|
|
|
49 |
|
|
|
917 |
|
| 1 |
Denominated in US dollars, converted to Canadian dollars as of September 30, 2017 at the rate of $1.25. |
As of September 30, 2017, we had commitments of about $917 million for the following:
| |
• |
|
approximately 23 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
|
2017 THIRD QUARTER
REPORT 17
The suppliers do not have the right to terminate agreements other than pursuant to customary events of default
provisions.
Financial assurances
At
September 30, 2017, our financial assurances totalled $1.5 billion, unchanged from December 31, 2016.
Other arrangements
We continue to use factoring and other third party arrangements to manage short-term cash flow fluctuations. You can read more about these arrangements in our
2016 annual MD&A.
BALANCE SHEET
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($ MILLIONS) |
|
SEP 30, 2017 |
|
|
DEC 31, 2016 |
|
|
CHANGE |
|
| Cash and cash equivalents |
|
|
352 |
|
|
|
320 |
|
|
|
10 |
% |
| Total debt |
|
|
1,494 |
|
|
|
1,493 |
|
|
|
— |
|
| Inventory |
|
|
1,119 |
|
|
|
1,288 |
|
|
|
(13 |
)% |
Total cash and cash equivalents at September 30, 2017 were $352 million, or 10% higher than at December 31,
2016, primarily due to cash from operations of $276 million, partially offset by capital expenditures of $89 million, dividend payments of $119 million, and interest payments of $49 million. Net debt at September 30, 2017
was $1,142 million.
Total product inventories decreased to $1,119 million, including NUKEM’s inventories ($115 million). Inventories
decreased as sales were higher than production and purchases in the first nine months of the year and the average cost for uranium has decreased to $31.56 per pound compared to $34.69 per pound at December 31, 2016. As of September 30,
2017, we held an inventory of 27.6 million pounds of U3O8 equivalent in our uranium segment (excluding broken ore).
Financial results by segment
Uranium
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
THREE MONTHS |
|
|
|
|
|
NINE MONTHS |
|
|
|
|
| |
|
|
|
ENDED SEPTEMBER 30 |
|
|
|
|
|
ENDED SEPTEMBER 30 |
|
|
|
|
| HIGHLIGHTS |
|
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
| Production volume (million lbs) |
|
|
|
|
3.1 |
|
|
|
5.9 |
|
|
|
(47 |
)% |
|
|
16.9 |
|
|
|
19.9 |
|
|
|
(15 |
)% |
| Sales volume (million lbs)1 |
|
|
|
|
9.2 |
|
|
|
9.3 |
|
|
|
(1 |
)% |
|
|
21.0 |
|
|
|
19.9 |
|
|
|
6 |
% |
| Average spot price |
|
($US/lb) |
|
|
20.22 |
|
|
|
24.57 |
|
|
|
(18 |
)% |
|
|
21.60 |
|
|
|
27.86 |
|
|
|
(22 |
)% |
| Average long-term price |
|
($US/lb) |
|
|
31.33 |
|
|
|
37.83 |
|
|
|
(17 |
)% |
|
|
32.33 |
|
|
|
41.06 |
|
|
|
(21 |
)% |
| Average realized price |
|
($US/lb) |
|
|
32.42 |
|
|
|
43.37 |
|
|
|
(25 |
)% |
|
|
34.15 |
|
|
|
42.92 |
|
|
|
(20 |
)% |
|
|
($Cdn/lb) |
|
|
41.66 |
|
|
|
56.34 |
|
|
|
(26 |
)% |
|
|
44.86 |
|
|
|
56.77 |
|
|
|
(21 |
)% |
| Average unit cost of sales (including D&A) |
|
($Cdn/lb) |
|
|
36.12 |
|
|
|
39.97 |
|
|
|
(10 |
)% |
|
|
36.32 |
|
|
|
41.63 |
|
|
|
(13 |
)% |
| Revenue ($ millions)1 |
|
|
|
|
385 |
|
|
|
526 |
|
|
|
(27 |
)% |
|
|
943 |
|
|
|
1,129 |
|
|
|
(16 |
)% |
| Gross profit ($ millions) |
|
|
|
|
51 |
|
|
|
153 |
|
|
|
(67 |
)% |
|
|
179 |
|
|
|
301 |
|
|
|
(41 |
)% |
| Gross profit (%) |
|
|
|
|
13 |
|
|
|
29 |
|
|
|
(55 |
)% |
|
|
19 |
|
|
|
27 |
|
|
|
(30 |
)% |
| 1 |
There were no significant intersegment transactions in the periods shown. |
THIRD QUARTER
Production volumes this quarter were 47% lower compared to the third quarter of 2016, mainly due to lower production from McArthur River/Key Lake and Cigar
Lake due to the timing of planned maintenance and vacation shut downs. See Uranium 2017 Q3 updates starting on page 22 for more information.
Uranium revenues this quarter were down 27% compared to 2016 due to a decrease of 26% in the Canadian dollar average realized price and a decrease in sales
volumes of 1%. The spot price for uranium averaged $20.22 (US) per pound in the third quarter of 2017, a decline of 18% compared to the 2016 third quarter average price of $24.57 (US) per pound. While our average realized price outperformed the
market, it decreased by 26% compared to last year mainly due to the impact of the disputed TEPCO agreement and lower prices for uranium delivered under both fixed and market-related contracts.
18 CAMECO
CORPORATION
Total cost of sales (including D&A) decreased by 10% ($334 million compared to $373 million in
2016) as a result of unit cost of sales that was 10% lower than the same period last year and a 1% decrease in sales volume. The decline in the unit cost of sales was 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 $102 million decrease in gross profit for the quarter.
FIRST NINE MONTHS
Production volumes for the first nine
months of the year were 15% lower than in the previous year mainly due to planned lower production from Inkai and our US operations, a lack of production from the suspended Rabbit Lake operation, and lower production from McArthur River/Key Lake due
to the extended summer shut-down during the third quarter partially offset by higher production from Cigar Lake as a result of the scheduled rampup of the operation. See Uranium 2017 Q3 updates starting on page 22 for more information.
Uranium revenues decreased 16% compared to the first nine months of 2016 due to a 21% decrease in the Canadian dollar average realized price, partially offset
by a 6% increase in sales volumes.
Our Canadian dollar realized prices for the first nine 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 8% ($764 million compared to $828 million in 2016) mainly due to a 13% decrease in the unit
cost of sales partially offset by a 6% increase in sales volume for the first nine 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 $122 million decrease in gross profit for the first nine months.
The table below shows the costs of produced and purchased uranium incurred in the reporting periods (which are
non-IFRS measures, see the paragraphs below the table). These costs do not include care and maintenance costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of
opening inventories on our reported cost of sales.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS |
|
|
|
|
|
NINE MONTHS |
|
|
|
|
| |
|
ENDED SEPTEMBER 30 |
|
|
|
|
|
ENDED SEPTEMBER 30 |
|
|
|
|
| ($CDN/LB) |
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
| Produced |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash cost |
|
|
24.40 |
|
|
|
16.31 |
|
|
|
50 |
% |
|
|
15.90 |
|
|
|
17.72 |
|
|
|
(10 |
)% |
| Non-cash cost |
|
|
16.33 |
|
|
|
13.07 |
|
|
|
25 |
% |
|
|
11.53 |
|
|
|
12.18 |
|
|
|
(5 |
)% |
| Total production cost |
|
|
40.73 |
|
|
|
29.38 |
|
|
|
39 |
% |
|
|
27.43 |
|
|
|
29.90 |
|
|
|
(8 |
)% |
| Quantity produced (million lbs) |
|
|
3.1 |
|
|
|
5.9 |
|
|
|
(47 |
)% |
|
|
16.9 |
|
|
|
19.9 |
|
|
|
(15 |
)% |
| Purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash cost |
|
|
36.83 |
|
|
|
39.91 |
|
|
|
(8 |
)% |
|
|
39.75 |
|
|
|
48.91 |
|
|
|
(19 |
)% |
| Quantity purchased (million lbs) |
|
|
0.5 |
|
|
|
0.5 |
|
|
|
0 |
% |
|
|
3.0 |
|
|
|
6.2 |
|
|
|
(52 |
)% |
| Totals |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Produced and purchased costs |
|
|
40.19 |
|
|
|
30.20 |
|
|
|
33 |
% |
|
|
29.29 |
|
|
|
34.42 |
|
|
|
(15 |
)% |
| Quantities produced and purchased (million lbs) |
|
|
3.6 |
|
|
|
6.4 |
|
|
|
(44 |
)% |
|
|
19.9 |
|
|
|
26.1 |
|
|
|
(24 |
)% |
The average cash cost of production was 50% higher for the quarter and 10% lower in the first nine months than in comparable
periods in 2016. Cash cost in the quarter was impacted by lower production resulting from the planned shutdowns at McArthur River/Key Lake and Cigar Lake. The decrease for the year 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.
2017 THIRD QUARTER
REPORT 19
Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the
third quarter, the average cash cost of purchased material was $36.83 (Cdn) per pound, or $29.20 (US) per pound in US dollar terms, compared to $30.75 (US) per pound in the third quarter of 2016. For the first nine months, the average cash cost of
purchased material was $39.75 (Cdn), or $30.19 (US) per pound, compared to $35.70 (US) per pound in the same period in 2016.
Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a
standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain
investors use this information to evaluate our performance and ability to generate cash flow.
These measures are
non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily
indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.
To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the
third quarter and the first nine months of 2017 and 2016.
Cash and total cost per pound reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS |
|
|
NINE MONTHS |
|
| |
|
ENDED SEPTEMBER 30 |
|
|
ENDED SEPTEMBER 30 |
|
| ($ MILLIONS) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
| Cost of product sold |
|
|
250.5 |
|
|
|
285.7 |
|
|
|
591.4 |
|
|
|
654.6 |
|
| Add / (subtract) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Royalties |
|
|
(23.0 |
) |
|
|
(37.4 |
) |
|
|
(46.2 |
) |
|
|
(77.3 |
) |
| Care and maintenance costs |
|
|
(8.0 |
) |
|
|
(20.1 |
) |
|
|
(28.9 |
) |
|
|
(58.8 |
) |
| Other selling costs |
|
|
(2.8 |
) |
|
|
(5.6 |
) |
|
|
(5.7 |
) |
|
|
(8.5 |
) |
| Change in inventories |
|
|
(122.6 |
) |
|
|
(106.4 |
) |
|
|
(122.6 |
) |
|
|
145.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash operating costs (a) |
|
|
94.1 |
|
|
|
116.2 |
|
|
|
388.0 |
|
|
|
655.9 |
|
| Add / (subtract) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Depreciation and amortization |
|
|
83.2 |
|
|
|
87.6 |
|
|
|
172.2 |
|
|
|
173.1 |
|
| Change in inventories |
|
|
(32.6 |
) |
|
|
(10.5 |
) |
|
|
22.6 |
|
|
|
69.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total operating costs (b) |
|
|
144.7 |
|
|
|
193.3 |
|
|
|
582.8 |
|
|
|
898.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Uranium produced & purchased (million lbs) (c) |
|
|
3.6 |
|
|
|
6.4 |
|
|
|
19.9 |
|
|
|
26.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash costs per pound (a ÷ c) |
|
|
26.14 |
|
|
|
18.16 |
|
|
|
19.50 |
|
|
|
25.13 |
|
| Total costs per pound (b ÷ c) |
|
|
40.19 |
|
|
|
30.20 |
|
|
|
29.29 |
|
|
|
34.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel services
(includes
results for UF6, UO2 and fuel fabrication)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
THREE MONTHS |
|
|
|
|
|
NINE MONTHS |
|
|
|
|
| |
|
|
|
|
ENDED SEPTEMBER 30 |
|
|
|
|
|
ENDED SEPTEMBER 30 |
|
|
|
|
| HIGHLIGHTS |
|
|
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
| Production volume (million kgU) |
|
|
|
|
|
|
0.6 |
|
|
|
0.6 |
|
|
|
— |
|
|
|
5.4 |
|
|
|
6.5 |
|
|
|
(17 |
)% |
| Sales volume (million kgU)1 |
|
|
|
|
|
|
2.5 |
|
|
|
3.5 |
|
|
|
(29 |
)% |
|
|
6.9 |
|
|
|
8.7 |
|
|
|
(21 |
)% |
| Average realized price |
|
($ |
Cdn/kgU |
) |
|
|
27.27 |
|
|
|
22.09 |
|
|
|
23 |
% |
|
|
29.94 |
|
|
|
25.06 |
|
|
|
19 |
% |
| Average unit cost of sales (including D&A) |
|
($ |
Cdn/kgU |
) |
|
|
25.84 |
|
|
|
18.62 |
|
|
|
39 |
% |
|
|
23.83 |
|
|
|
19.98 |
|
|
|
19 |
% |
| Revenue ($ millions)1 |
|
|
|
|
|
|
69 |
|
|
|
77 |
|
|
|
(10 |
)% |
|
|
206 |
|
|
|
217 |
|
|
|
(5 |
)% |
| Gross profit ($ millions) |
|
|
|
|
|
|
4 |
|
|
|
12 |
|
|
|
(67 |
)% |
|
|
42 |
|
|
|
44 |
|
|
|
(5 |
)% |
| Gross profit (%) |
|
|
|
|
|
|
6 |
|
|
|
16 |
|
|
|
(63 |
)% |
|
|
20 |
|
|
|
20 |
|
|
|
— |
|
| 1 |
There were no significant intersegment transactions in the periods shown. |
20 CAMECO
CORPORATION
THIRD QUARTER
Total revenue for the third quarter of 2017 decreased to $69 million from $77 million for the same period last year. This was primarily due to a 29%
decrease in sales volumes partially offset by a 23% increase in average realized price compared to 2016.
Despite the decrease in sales volume, the total
cost of products and services sold (including D&A) remained unchanged at $65 million compared to the third quarter of 2016 due to an increase in the average unit cost of sales.
The net effect was an $8 million decrease in gross profit.
FIRST NINE MONTHS
In the first nine months of the year,
total revenue decreased by 5% due to a 21% decrease in sales volumes, partially offset by a 19% 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 5% ($164 million compared to
$173 million in 2016) due to the 21% decrease in sales volume, partially offset by a 19% increase in the average unit cost of sales.
The net effect
was a $2 million decrease in gross profit.
NUKEM
(financial results include U3O8, UF6, and SWU)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
THREE MONTHS
ENDED SEPTEMBER 30 |
|
|
|
|
|
NINE MONTHS
ENDED SEPTEMBER 30 |
|
|
|
|
| HIGHLIGHTS |
|
|
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
| Uranium sales (million lbs)1 |
|
|
|
|
|
|
1.1 |
|
|
|
1.5 |
|
|
|
(27 |
)% |
|
|
6.0 |
|
|
|
4.0 |
|
|
|
50 |
% |
| Average realized price |
|
($ |
Cdn/lb |
) |
|
|
28.72 |
|
|
|
43.52 |
|
|
|
(34 |
)% |
|
|
33.22 |
|
|
|
48.89 |
|
|
|
(32 |
)% |
| Cost of product sold (including D&A) |
|
|
|
|
|
|
33 |
|
|
|
82 |
|
|
|
(60 |
)% |
|
|
214 |
|
|
|
224 |
|
|
|
(4 |
)% |
| Revenue ($ millions)1 |
|
|
|
|
|
|
32 |
|
|
|
67 |
|
|
|
(52 |
)% |
|
|
198 |
|
|
|
198 |
|
|
|
— |
|
| Gross loss ($ millions) |
|
|
|
|
|
|
(1 |
) |
|
|
(15 |
) |
|
|
(93 |
)% |
|
|
(16 |
) |
|
|
(26 |
) |
|
|
(38 |
)% |
| Gross loss (%) |
|
|
|
|
|
|
(3 |
) |
|
|
(22 |
) |
|
|
(86 |
)% |
|
|
(8 |
) |
|
|
(13 |
) |
|
|
(38 |
)% |
| 1 |
There were no significant intersegment transactions in the periods shown. |
THIRD QUARTER
During the third quarter of 2017, NUKEM delivered 1.1 million pounds of uranium, a decrease of 27% from the same period last year due largely to a lack of
acceptable spot sale opportunities relative to the same period in 2016. Total revenues decreased 52% due to the decrease in sales volume and 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 third quarter of 2016.
NUKEM recorded a gross loss of $1 million in the third quarter of 2017 compared to
$15 million in 2016. In 2016, a net write-down of inventory of $12 million was recorded which was the result of a decline in the spot price. The net write-down in 2017 was nil.
FIRST NINE MONTHS
During the nine months ended
September 30, 2017, NUKEM delivered 6 million pounds of uranium, an increase of 50%, 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
were unchanged due to the increase in sales volumes being offset by a 32% decrease in average realized price. The decrease in realized price was mainly the result of a lower uranium spot price compared to the first nine months of 2016.
NUKEM recorded a gross loss of $16 million in the first nine months of 2017 compared to a $26 million loss in the same period in 2016. Included in
the 2017 margin was a $12 million net write-down of inventory while the 2016 margin included a $26 million net write-down.
2017 THIRD QUARTER
REPORT 21
Our operations
Uranium – production overview
Production in our
uranium segment this quarter was 47% lower than the third quarter of 2016. See below for more information.
URANIUM PRODUCTION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS
ENDED SEPTEMBER 30 |
|
|
|
|
|
NINE MONTHS
ENDED SEPTEMBER 30 |
|
|
|
|
|
|
|
| OUR SHARE (MILLION LBS) |
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 |
|
|
2016 |
|
|
CHANGE |
|
|
2017 PLAN |
|
| McArthur River/Key Lake |
|
|
0.6 |
|
|
|
3.1 |
|
|
|
(81 |
)% |
|
|
7.8 |
|
|
|
8.8 |
|
|
|
(11 |
)% |
|
|
11.5 |
1 |
| Cigar Lake |
|
|
1.7 |
|
|
|
1.9 |
|
|
|
(11 |
)% |
|
|
6.5 |
|
|
|
6.2 |
|
|
|
5 |
% |
|
|
9.0 |
|
| Inkai |
|
|
0.8 |
|
|
|
0.6 |
|
|
|
33 |
% |
|
|
2.3 |
|
|
|
2.8 |
|
|
|
(18 |
)% |
|
|
3.1 |
|
| Rabbit Lake |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1.1 |
|
|
|
(100 |
)% |
|
|
— |
|
| Smith Ranch-Highland |
|
|
— |
|
|
|
0.2 |
|
|
|
(100 |
)% |
|
|
0.2 |
|
|
|
0.8 |
|
|
|
(75 |
)% |
|
|
0.3 |
1 |
| Crow Butte |
|
|
— |
|
|
|
0.1 |
|
|
|
(100 |
)% |
|
|
0.1 |
|
|
|
0.2 |
|
|
|
(50 |
)% |
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
3.1 |
|
|
|
5.9 |
|
|
|
(47 |
)% |
|
|
16.9 |
|
|
|
19.9 |
|
|
|
(15 |
)% |
|
|
24.0 |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 1 |
We have reduced our 2017 production plan to 24.0 million pounds (from 25.2 million pounds) due to reductions at McArthur River/Key Lake and Smith Ranch-Highland. Please see Uranium 2017 Q3 updates for
more information. |
Uranium 2017 Q3 updates
PRODUCTION UPDATE
McArthur River/Key Lake
Production was 81% lower for the third quarter, and 11% lower for the first nine months compared to the same periods in 2016. This year, in alignment with our
continued efforts to reduce costs, our production plan included an extended summer shut-down during the third quarter. The shut-down consisted 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. Planned work on the existing calciner circuit at Key Lake, combined with the timing of the planned annual maintenance shutdown, resulted in reduced production
during the third quarter compared to 2017. Production was expected to restart at the end of August, however, the calciner work took longer than expected.
Additional work was required on the calciner in October, resulting in an unplanned outage at Key Lake. As a result, we have lowered our 2017 production target
to 11.5 million pounds (Cameco’s share) from 12.6 million pounds (Cameco’s share).
Initial discussions to set the collective
bargaining schedule with the United Steelworkers local 8914 have begun. We plan to begin contract negotiations prior to the current agreement expiring in December of this year.
Cigar Lake
Total packaged production from Cigar Lake was
11% lower in the third quarter, and 5% higher in the first nine months compared to the same periods last year. Packaged production was lower in the third quarter due primarily to the planned summer shutdown for maintenance and vacation. The shutdown
went as planned with the mine and mill returning to full production as scheduled at the end of August. The year-over-year increase is the result of the scheduled rampup of the operation.
Inkai
Production was 33% higher for the quarter and 18%
lower for the first nine 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 nominal for the quarter and 70% lower for the first nine 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.
As expected, production continues to trend down as the head
grade decreases. Given production volumes to the end of September, we have lowered our 2017 production plan by 0.1 million pounds to 0.3 million pounds.
22 CAMECO
CORPORATION
Rabbit Lake
The Rabbit Lake operation is in a safe state of care and maintenance; there was no production in the third 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.
Fuel services 2017 Q3 updates
PORT HOPE
CONVERSION SERVICES
CAMECO FUEL MANUFACTURING INC. (CFM)
Production update
Fuel services produced 0.6 million
kgU in the third quarter, unchanged from the same period last year. Production in the first nine months was 17% 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 |
|
INKAI |
|
|
| • 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 |
|
• 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 September 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 September 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 September 30, 2017 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial reporting.
2017 THIRD QUARTER
REPORT 23
