EX-99.2
Exhibit 99.2
Management’s discussion and analysis
for the quarter ended June 30, 2018
| 5 |
SECOND QUARTER MARKET UPDATE |
| 7 |
CONSOLIDATED FINANCIAL RESULTS |
| 16 |
LIQUIDITY AND CAPITAL RESOURCES |
| 19 |
FINANCIAL RESULTS BY SEGMENT |
| 22 |
OUR OPERATIONS - SECOND QUARTER UPDATES |
| 24 |
ADDITIONAL INFORMATION |
This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited
condensed consolidated interim financial statements and notes for the quarter ended June 30, 2018 (interim financial statements). The information is based on what we knew as of July 25, 2018 and updates our first quarter and annual
MD&A included in our 2017 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, 2017 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 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:
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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). |
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It represents our current views, and can change significantly. |
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It is based on a number of material assumptions, including those we have listed on page 3, which may prove
to be incorrect. |
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Actual results and events may be significantly different from what we currently expect, due to the risks
associated with our business. We list a number of these material risks below. We recommend you also review our annual information form, first quarter and annual MD&A, which includes a discussion of other material risks that could
cause actual results to differ significantly from our current expectations. |
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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
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the discussion under the headings Our strategy and Strategy in action |
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our expectations about 2018 and future global uranium supply, consumption, contracting volumes and demand, including the discussion under the heading Second quarter market update |
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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
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our 2018 consolidated outlook and the outlook for our uranium and fuel services segments for 2018 |
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our expectations for uranium deliveries for the remainder of 2018 |
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the discussion under the heading Additional outlook tied to the extended shutdown of McArthur River/Key Lake |
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our price sensitivity analysis for our uranium segment
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our expectations regarding 2018 cash flow, and that existing cash balances and operating cash flows will meet our anticipated 2018 capital requirements |
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our expectation that our operating and investment activities for the remainder of 2018 will not be constrained by the financial-related covenants in our unsecured revolving credit facility |
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our future plans and expectations for each of our uranium operating properties and fuel services operating sites, including production levels |
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our expectations related to care and maintenance costs |
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our plans regarding consideration of the payment of a dividend |
Material risks
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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, loss of market share to a competitor or trade restrictions
|
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we are adversely affected by changes in currency exchange rates, interest rates, royalty rates, or tax rates |
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our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms |
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our strategies are unsuccessful or have unanticipated consequences |
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our estimates of production, purchases, cash flow, costs, decommissioning, reclamation expenses, or our tax expense prove to be inaccurate |
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we are unable to enforce our legal rights under our existing agreements, permits or licences |
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the necessary permits or approvals from government authorities are not obtained or maintained |
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our Cigar Lake development, mining or production plans are delayed or do not succeed for any reason |
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we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our dispute with CRA or with Tokyo Electric Power Company Holdings, Inc. (TEPCO) |
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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 |
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we are unable to utilize letters of credit to the extent anticipated in our dispute with CRA |
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there are defects in, or challenges to, title to our properties |
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our mineral reserve and resource estimates are not reliable, or there are challenging or unexpected geological, hydrological or mining conditions |
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we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays
|
2 CAMECO
CORPORATION
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any difficulties in milling of Cigar Lake ore at McClean Lake mill, including water treatment or resuming production after the extended Cigar Lake shutdown scheduled for the third quarter |
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JV Inkai’s development, mining or production plans are delayed or do not succeed for any reason |
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our expectations relating to care and maintenance costs prove to be inaccurate |
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we are affected by political risks |
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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 |
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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 |
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government laws, regulations, policies, or decisions that adversely affect us, including tax and trade laws |
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the outcome of the investigation initiated by the US Department of Commerce under Section 232 of the Trade Expansion Act |
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our uranium suppliers fail to fulfil delivery commitments or our uranium purchasers fail to fulfil purchase commitments |
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we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes |
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operations are disrupted due to problems with facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages,
labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks
|
Material assumptions
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our expectations regarding sales and purchase volumes and prices for uranium and fuel services, trade restrictions and that the counterparties to our sales and purchase agreements will honour their commitments
|
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our expectations regarding the demand for and supply of uranium |
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our expectations regarding spot prices and realized prices for uranium, and other factors discussed under the heading Price sensitivity analysis: uranium segment |
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that the construction of new nuclear power plants and the relicensing of existing nuclear power plants will not be more adversely affected than expected by changes in regulation or in the public perception of the safety
of nuclear power plants |
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our ability to continue to supply our products and services in the expected quantities and at the expected times |
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our expected production levels for uranium and conversion services |
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our cost expectations, including production costs, and purchase costs |
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the success of our plans and strategies |
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the agreement of our partners with our plans and strategies |
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our expectations regarding tax rates and payments, royalty rates, currency exchange rates and interest rates |
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our expectations about the outcome of disputes with CRA and with TEPCO |
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we are able to utilize letters of credit to the extent anticipated in our dispute with CRA |
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our decommissioning and reclamation expenses |
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our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable |
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our understanding of the geological, hydrological and other conditions at our uranium properties |
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our Cigar Lake development, mining and production plans succeed, including the resumption of production after the end of the extended shutdown scheduled for the third quarter |
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the McClean Lake mill is able to process Cigar Lake ore as expected |
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JV Inkai’s development, mining and production plans succeed |
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that care and maintenance costs will be as expected |
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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 |
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operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, governmental or political actions, litigation
or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods,
cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, or other development or operating risks
|
2018 SECOND QUARTER
REPORT 3
Our strategy
We are a pure-play nuclear fuel supplier, focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to
respond to market conditions as they evolve. Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to preserve the value of those assets and
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 focused on preserving the value of our lowest cost assets, on maintaining a strong balance sheet, on protecting and extending the value of our contract
portfolio and on efficiently managing the company in a low price environment. We have undertaken a number of deliberate and disciplined actions. We have reduced supply, resisted selling into a weak spot market, restructured our global marketing
organization, streamlined our operations and reduced costs.
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.
You can read more about our
strategy in our 2017 annual MD&A.
Strategy in action
In response to market conditions, we have made the necessary decision to extend the suspension of production at our McArthur River/Key Lake operation, removing
18 million pounds of uranium per year from the market for an indeterminate duration. Our joint venture partner, Orano, has agreed to extend the suspension.
This action will result in the permanent layoff of approximately 550 site employees, including those currently on temporary layoff since January of this year.
A reduced workforce of approximately 200 employees will remain at the McArthur River and Key Lake sites to keep the facilities in a state of safe care
and maintenance. We expect our share of the costs to maintain both sites to range between $5 million and $6 million per month once all the permanent layoffs take effect.
In addition, to further decrease costs, the workforce at our corporate office will be reduced by approximately 150 positions including employees and
vacancies.
As a result of the permanent layoffs at site and the associated workforce reduction at our corporate office, we will incur about
$40 million to $45 million in severance costs in the third quarter. For more information on how these costs will impact 2018, see Outlook for 2018 on page 14.
We have also agreed to extend repayment under the agreement to provide our partner, Orano, with up to 5.4 million pounds of uranium concentrates. Orano
is now obligated to repay us, in kind, with uranium concentrates no later than December 31, 2023 (previously December 31, 2021).
We evaluate
our strategy in the context of our market environment and continue to adjust our actions in accordance with the following marketing framework:
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First, we will not produce from our tier-one assets to sell into an
oversupplied spot market. Until we can commit our tier-one pounds under long-term contracts that provide an acceptable rate of return on these assets for our owners, we do not plan to restart McArthur River
and Key Lake. |
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Second, we do not intend to build up an inventory of excess uranium. Excess inventory serves to contribute to the
sense that uranium is abundant and creates an overhang on the market, and it ties up working capital on our balance sheet. |
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Third, in addition to our committed sales, we will capture demand in the market where we think we can obtain
value. We will take advantage of opportunities the market provides, where it makes sense from an economic, logistical and strategic point of view. Those opportunities may come in the form of spot, mid-term or
long-term demand, and will be additive to our current committed sales. |
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Fourth, once we capture demand, we will decide how to best source material to satisfy that demand. Depending on
the timing and volume of our production, purchase commitments, and our inventory volumes, this means we will be active buyers in the market in order to meet our demand obligations. |
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And finally, in general, if we choose to source material to meet demand by purchasing it, we expect the price of
that material will be more than offset by the leverage to market prices in our sales portfolio over a rolling 12-month period. |
4 CAMECO
CORPORATION
In addition to this framework, our contracting decisions always factor in who the customer is, our desire for
regional diversification, the product form, and logistical factors.
Ultimately, we believe continuing to use this framework will allow us to create
long-term value for our shareholders. And, as always, our focus will continue to be on maximizing cash flow, while maintaining our investment-grade rating so we can self-manage risk, including being in a position to retire our 2019 debt maturity
when it comes due.
Second quarter market update
There were several significant announcements in the uranium market during the second quarter and to-date in July. On
the supply side, Paladin announced that it was putting its Langer Heinrich mine on care and maintenance, Kazatomprom announced that it would reduce 2018 planned production from about 60 million pounds to about 56 million pounds, and we
announced our decision to extend the suspension of production at McArthur River/Key Lake.
In addition, there has been increased financial interest in
physical uranium, including the initial public offering for a new uranium fund called Yellow Cake. The fund has purchased about 8 million pounds of uranium from Kazatomprom, sequestering it in an investment vehicle, with the option to purchase
up to $100 million in additional material annually over the next nine years.
On the demand side, in Japan, there were two additional reactor
restarts, bringing the total restarted to nine, including one that is currently not operating. The Japanese government also approved a new basic energy plan confirming that nuclear power will play a significant role in its energy strategy. In China,
the first AP1000 and EPR reactors were connected to the grid, and fuel loading was approved and has begun on a second AP1000 nuclear power plant. We believe the startup and regulatory approval of this new generation of reactors will clear the path
for additional new build projects in that country. In South Korea, the government announced plans for the early retirement of one of its nuclear reactors and cancelled plans for four new units. In the US, a petition was filed under Section 202
of the Federal Power Act. This petition could result in assistance for struggling nuclear and coal plants as a matter of national security. And, the US Department of Commerce initiated an investigation under section 232 of the Trade Expansion Act to
determine whether the quantity and circumstances of foreign uranium imports into the US threaten to impair national security.
Despite an approximately 8%
increase in the uranium spot price during the quarter, there has not been a lot of activity in the long-term market. The market continues to try to digest the changing market dynamics, including the developments discussed above and the implications
of the review of the Russian Suspension Agreement, which imposes annual quotas on imports of Russian uranium into the US, and expires at the end of 2020.
Longer term, uranium demand is backed by steady reactor growth with 57 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, some mines approaching the end of their reserve life, declining secondary supplies, and growing uncovered requirements are expected to generate increasing pressure for fuel buyers to return to long-term
contracting.
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.
2018 SECOND QUARTER
REPORT 5
Industry prices at quarter end
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JUN 30 |
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MAR 31 |
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DEC 31 |
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SEP 30 |
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JUN 30 |
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MAR 31 |
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2018 |
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2018 |
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2017 |
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2017 |
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2017 |
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2017 |
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| Uranium ($US/lb U3O8)1 |
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| Average spot market price |
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22.65 |
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21.05 |
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23.75 |
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20.33 |
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20.15 |
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23.88 |
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| Average long-term price |
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29.00 |
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29.00 |
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31.00 |
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30.50 |
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33.00 |
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33.00 |
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| Fuel services ($US/kgU as UF6)1 |
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| Average spot market price |
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| North America |
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9.03 |
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6.68 |
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5.80 |
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4.55 |
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5.13 |
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5.93 |
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| Europe |
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9.38 |
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6.93 |
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6.13 |
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4.93 |
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5.50 |
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6.45 |
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| Average long-term price |
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| North America |
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14.25 |
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12.25 |
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13.00 |
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14.50 |
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14.50 |
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13.50 |
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| Europe |
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14.25 |
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12.25 |
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13.00 |
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14.25 |
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14.25 |
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14.00 |
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Note: the industry does not publish UO2 prices.
| 1 |
Average of prices reported by TradeTech and Ux Consulting (UxC) |
On the spot market, where purchases call for delivery within one year, the volume reported by Ux Consulting (UxC) for the second quarter of 2018 was
approximately 20 million pounds, compared to 12 million pounds in the second quarter of 2017. Total volume in the spot market year-to-date is 43 million
pounds, significantly higher than in previous years. This volume includes the 8 million pounds purchased by the newly established uranium fund, Yellow Cake. At the end of the quarter, the average reported spot price was $22.65 (US) per pound,
up $1.60 (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 six months of 2018 was about 16 million pounds compared to about 54 million pounds reported over the same period in 2017. Volumes continue to be less than the quantities consumed, and remain largely discretionary due to
currently high inventory levels. The average reported long-term price at the end of the quarter was $29.00 (US) per pound, unchanged from last quarter.
Spot UF6 conversion prices increased in both the North American and European markets, as did long-term
UF6 conversion prices.
Shares and stock options outstanding
At July 25, 2018, we had:
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395,792,732 common shares and one Class B share outstanding |
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8,909,524 stock options outstanding, with exercise prices ranging from $11.32 to $39.53
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Dividend
In 2017, our board of directors reduced the planned dividend to $0.08 per common share to be paid annually. The decision to declare a dividend by our board
will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings. Accordingly, the dividend will be considered at the time of the third quarter earnings
release.
6 CAMECO
CORPORATION
Financial results
This section of our MD&A discusses our performance, financial condition and outlook for the future.
In this MD&A, our 2018 financial outlook and other disclosures relating to our contract portfolio are presented on a basis which excludes the agreement
with TEPCO, which is under dispute. See our annual MD&A for more information.
As of January 1, 2018, due to restructuring and a change in our
ownership interest, we now account for JV Inkai on an equity basis, with no restatement of prior periods.
Consolidated financial results
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THREE MONTHS |
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SIX MONTHS |
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| CONSOLIDATED HIGHLIGHTS |
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ENDED JUNE 30 |
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ENDED JUNE 30 |
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| ($ MILLIONS EXCEPT WHERE INDICATED) |
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2018 |
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2017 |
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CHANGE |
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2018 |
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2017 |
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|
CHANGE |
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| Revenue |
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|
333 |
|
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|
470 |
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(29 |
)% |
|
|
773 |
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|
862 |
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|
(10 |
)% |
| Gross profit |
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|
26 |
|
|
|
93 |
|
|
|
(72 |
)% |
|
|
94 |
|
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|
148 |
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|
(36 |
)% |
| Net losses attributable to equity holders |
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|
(76 |
) |
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|
(2 |
) |
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|
>(100 |
%) |
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(22 |
) |
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(20 |
) |
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(10 |
)% |
| $ per common share (basic) |
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|
(0.19 |
) |
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|
(0.00 |
) |
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>(100 |
%) |
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(0.05 |
) |
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(0.05 |
) |
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— |
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| $ per common share (diluted) |
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(0.19 |
) |
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(0.00 |
) |
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>(100 |
%) |
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(0.05 |
) |
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(0.05 |
) |
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— |
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| Adjusted net losses (non-IFRS, see page 8) |
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(28 |
) |
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(44 |
) |
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36 |
% |
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(6 |
) |
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(73 |
) |
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|
92 |
% |
| $ per common share (adjusted and diluted) |
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|
(0.07 |
) |
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(0.11 |
) |
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36 |
% |
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(0.01 |
) |
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(0.18 |
) |
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94 |
% |
| Cash provided by operations (after working capital changes) |
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57 |
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|
130 |
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(56 |
)% |
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|
332 |
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|
122 |
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|
>100 |
% |
NET EARNINGS
The
following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 8) in the second quarter and the first six months of 2018, compared to the same
periods in 2017.
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THREE MONTHS |
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SIX MONTHS |
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ENDED JUNE 30 |
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ENDED JUNE 30 |
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| ($ MILLIONS) |
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IFRS |
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ADJUSTED |
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IFRS |
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ADJUSTED |
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| Net losses – 2017 |
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(2 |
) |
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(44 |
) |
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|
(20 |
) |
|
|
(73 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 |
|
|
(11 |
) |
|
|
(11 |
) |
|
|
1 |
|
|
|
1 |
|
|
|
Higher (lower) realized prices ($US) |
|
|
(11 |
) |
|
|
(11 |
) |
|
|
62 |
|
|
|
62 |
|
|
|
Foreign exchange impact on realized prices |
|
|
(11 |
) |
|
|
(11 |
) |
|
|
(30 |
) |
|
|
(30 |
) |
|
|
Higher costs |
|
|
(31 |
) |
|
|
(31 |
) |
|
|
(64 |
) |
|
|
(64 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change – uranium |
|
|
(64 |
) |
|
|
(64 |
) |
|
|
(31 |
) |
|
|
(31 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fuel services |
|
Higher (lower) sales volume |
|
|
(6 |
) |
|
|
(6 |
) |
|
|
1 |
|
|
|
1 |
|
|
|
Higher (lower) realized prices ($Cdn) |
|
|
5 |
|
|
|
5 |
|
|
|
(9 |
) |
|
|
(9 |
) |
|
|
Higher costs |
|
|
(6 |
) |
|
|
(6 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change – fuel services |
|
|
(7 |
) |
|
|
(7 |
) |
|
|
(9 |
) |
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other changes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Lower administration expenditures |
|
|
13 |
|
|
|
13 |
|
|
|
18 |
|
|
|
18 |
|
| Lower exploration expenditures |
|
|
2 |
|
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
| Change in reclamation provisions |
|
|
(56 |
) |
|
|
— |
|
|
|
(51 |
) |
|
|
— |
|
| Higher earnings from equity-accounted investee |
|
|
3 |
|
|
|
3 |
|
|
|
4 |
|
|
|
4 |
|
| Change in gains or losses on derivatives |
|
|
(48 |
) |
|
|
16 |
|
|
|
(87 |
) |
|
|
21 |
|
| Change in foreign exchange gains or losses |
|
|
22 |
|
|
|
22 |
|
|
|
31 |
|
|
|
31 |
|
| Gain on restructuring of JV Inkai |
|
|
— |
|
|
|
— |
|
|
|
49 |
|
|
|
— |
|
| Gain on customer contract restructuring in 2018 |
|
|
— |
|
|
|
— |
|
|
|
6 |
|
|
|
6 |
|
| Change in income tax recovery or expense |
|
|
41 |
|
|
|
11 |
|
|
|
52 |
|
|
|
11 |
|
| Other |
|
|
20 |
|
|
|
20 |
|
|
|
13 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net losses – 2018 |
|
|
(76 |
) |
|
|
(28 |
) |
|
|
(22 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Financial results by segment beginning on page 19 for more detailed discussion.
2018 SECOND QUARTER
REPORT 7
ADJUSTED NET EARNINGS (NON-IFRS MEASURE)
Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS
(non-IFRS measure). We use this measure as a 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 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 impairment charges, reclamation provisions for our Rabbit Lake and US
operations, which had been impaired, the gain on restructuring of JV Inkai, and income taxes on adjustments.
Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure
differently, so you may not be able to make a direct comparison to similar measures presented by other companies.
The following table reconciles adjusted
net earnings with net earnings for the second quarter and first six months of 2018 and compares it to the same periods in 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS |
|
|
SIX MONTHS |
|
| |
|
ENDED JUNE 30 |
|
|
ENDED JUNE 30 |
|
| ($ MILLIONS) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
| Net losses attributable to equity holders |
|
|
(76 |
) |
|
|
(2 |
) |
|
|
(22 |
) |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments on derivatives |
|
|
20 |
|
|
|
(44 |
) |
|
|
42 |
|
|
|
(66 |
) |
| Reclamation provision adjustments |
|
|
44 |
|
|
|
(12 |
) |
|
|
45 |
|
|
|
(6 |
) |
| Gain on restructuring of JV Inkai |
|
|
— |
|
|
|
— |
|
|
|
(49 |
) |
|
|
— |
|
| Income taxes on adjustments |
|
|
(16 |
) |
|
|
14 |
|
|
|
(22 |
) |
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted net losses |
|
|
(28 |
) |
|
|
(44 |
) |
|
|
(6 |
) |
|
|
(73 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Every quarter we are required to update the reclamation provisions for all operations based on new cash flow estimates,
discount and inflation rates. This normally results in an adjustment to an asset retirement obligation asset in addition to the provision balance. When the assets of an operation have been written off due to an impairment, as is the case with our
Rabbit Lake and US ISR operations, the adjustment is recorded directly to the statement of earnings as “other operating expense (income)”. In the second quarter, our estimate for Rabbit Lake decommissioning costs increased due to a
scheduled revision to its preliminary decommissioning plan that was submitted to the relevant regulatory authorities. See note 9 of our interim financial statements for more information. This amount has been excluded from our adjusted net earnings
measure.
Quarterly trends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| HIGHLIGHTS |
|
2018 |
|
|
2017 |
|
|
2016 |
|
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
| Revenue |
|
|
333 |
|
|
|
439 |
|
|
|
809 |
|
|
|
486 |
|
|
|
470 |
|
|
|
393 |
|
|
|
887 |
|
|
|
670 |
|
| Net earnings (losses) attributable to equity holders |
|
|
(76 |
) |
|
|
55 |
|
|
|
(62 |
) |
|
|
(124 |
) |
|
|
(2 |
) |
|
|
(18 |
) |
|
|
(144 |
) |
|
|
142 |
|
| $ per common share (basic) |
|
|
(0.19 |
) |
|
|
0.14 |
|
|
|
(0.16 |
) |
|
|
(0.31 |
) |
|
|
(0.00 |
) |
|
|
(0.05 |
) |
|
|
(0.36 |
) |
|
|
0.36 |
|
| $ per common share (diluted) |
|
|
(0.19 |
) |
|
|
0.14 |
|
|
|
(0.16 |
) |
|
|
(0.31 |
) |
|
|
(0.00 |
) |
|
|
(0.05 |
) |
|
|
(0.36 |
) |
|
|
0.36 |
|
| Adjusted net earnings (losses) (non-IFRS, see page
8) |
|
|
(28 |
) |
|
|
23 |
|
|
|
181 |
|
|
|
(50 |
) |
|
|
(44 |
) |
|
|
(29 |
) |
|
|
90 |
|
|
|
118 |
|
| $ per common share (adjusted and diluted) |
|
|
(0.07 |
) |
|
|
0.06 |
|
|
|
0.46 |
|
|
|
(0.13 |
) |
|
|
(0.11 |
) |
|
|
(0.07 |
) |
|
|
0.23 |
|
|
|
0.30 |
|
| Cash provided by (used in) operations (after working capital changes) |
|
|
57 |
|
|
|
275 |
|
|
|
320 |
|
|
|
154 |
|
|
|
130 |
|
|
|
(8 |
) |
|
|
255 |
|
|
|
385 |
|
8 CAMECO
CORPORATION
Key things to note:
| |
• |
|
our financial results are strongly influenced by the performance of our uranium segment, which accounted for 71%
of consolidated revenues in the second quarter of 2018 |
| |
• |
|
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 |
The following table compares the net earnings and adjusted net earnings for the second quarter to
the previous seven quarters.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| HIGHLIGHTS |
|
2018 |
|
|
2017 |
|
|
2016 |
|
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
| Net earnings (losses) attributable to equity holders |
|
|
(76 |
) |
|
|
55 |
|
|
|
(62 |
) |
|
|
(124 |
) |
|
|
(2 |
) |
|
|
(18 |
) |
|
|
(144 |
) |
|
|
142 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjustments on derivatives |
|
|
20 |
|
|
|
22 |
|
|
|
(2 |
) |
|
|
(40 |
) |
|
|
(44 |
) |
|
|
(22 |
) |
|
|
23 |
|
|
|
(27 |
) |
| Impairment charges |
|
|
— |
|
|
|
— |
|
|
|
247 |
|
|
|
111 |
|
|
|
— |
|
|
|
— |
|
|
|
238 |
|
|
|
— |
|
| Reclamation provision adjustments |
|
|
44 |
|
|
|
1 |
|
|
|
15 |
|
|
|
(9 |
) |
|
|
(12 |
) |
|
|
6 |
|
|
|
(28 |
) |
|
|
(6 |
) |
| Gain on restructuring of JV Inkai |
|
|
— |
|
|
|
(49 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| Income taxes on adjustments |
|
|
(16 |
) |
|
|
(6 |
) |
|
|
(17 |
) |
|
|
12 |
|
|
|
14 |
|
|
|
5 |
|
|
|
1 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted net earnings (losses) (non-IFRS, see page
8) |
|
|
(28 |
) |
|
|
23 |
|
|
|
181 |
|
|
|
(50 |
) |
|
|
(44 |
) |
|
|
(29 |
) |
|
|
90 |
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate expenses
ADMINISTRATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS |
|
|
|
|
|
SIX MONTHS |
|
|
|
|
| |
|
ENDED JUNE 30 |
|
|
|
|
|
ENDED JUNE 30 |
|
|
|
|
| ($ MILLIONS) |
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
| Direct administration |
|
|
26 |
|
|
|
43 |
|
|
|
(40 |
)% |
|
|
55 |
|
|
|
77 |
|
|
|
(29 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Stock-based compensation |
|
|
5 |
|
|
|
1 |
|
|
|
400 |
% |
|
|
11 |
|
|
|
7 |
|
|
|
57 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total administration |
|
|
31 |
|
|
|
44 |
|
|
|
(30 |
)% |
|
|
66 |
|
|
|
84 |
|
|
|
(21 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct administration costs were $17 million lower for the second quarter of 2018 compared to the same period last year,
and $22 million lower for the first six months due mainly to changes to our global marketing structure, lower costs related to our CRA litigation and our continued actions to reduce costs.
Stock-based compensation in the first six months was higher due to the 27% increase in our share price compared to the same period in 2017.
EXPLORATION
In the second quarter, uranium exploration
expenses were $4 million, a decrease of $2 million compared to the second quarter of 2017. Exploration expenses for the first six months of the year decreased by $3 million compared to 2017, to $13 million, due to a planned
reduction in expenditures.
2018 SECOND QUARTER
REPORT 9
INCOME TAXES
We recorded an income tax recovery of $12 million in the second quarter of 2018, compared to an expense of $29 million in the second quarter of 2017.
On an adjusted basis, we recorded an income tax expense of $4 million this quarter compared to an expense of $15 million in the second quarter
of 2017, primarily due to a change in the Saskatchewan corporate tax rate in 2017 which caused a decrease in our deferred tax asset, resulting in an expense of $24 million. In addition, the change in reporting for JV Inkai also contributes to
the difference. In 2018, we recorded earnings of $3 million in Canada compared to earnings of $4 million in 2017, while we recorded losses of $27 million in foreign jurisdictions compared to losses of $33 million last year.
In the first six months of 2018, we recorded an income tax recovery of $19 million compared to an expense of $33 million in 2017.
On an adjusted basis, we recorded an income tax expense of $3 million for the first six months compared to an expense of $14 million in 2017 due to
the change in the Saskatchewan corporate tax rate in 2017, as well as a change in the distribution of earnings among jurisdictions in 2018 which includes the change in accounting for JV Inkai. In 2018, we recorded losses of $38 million in
Canada compared to earnings of $3 million in 2017, while we recorded earnings of $36 million in foreign jurisdictions compared to losses of $62 million last year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS |
|
|
SIX MONTHS |
|
| |
|
ENDED JUNE 30 |
|
|
ENDED JUNE 30 |
|
| ($ MILLIONS) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
| Pre-tax adjusted earnings1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Canada |
|
|
3 |
|
|
|
4 |
|
|
|
(38 |
) |
|
|
3 |
|
| Foreign |
|
|
(27 |
) |
|
|
(33 |
) |
|
|
36 |
|
|
|
(62 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total pre-tax adjusted earnings |
|
|
(24 |
) |
|
|
(29 |
) |
|
|
(2 |
) |
|
|
(59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted income taxes1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Canada |
|
|
2 |
|
|
|
20 |
|
|
|
(4 |
) |
|
|
19 |
|
| Foreign |
|
|
2 |
|
|
|
(5 |
) |
|
|
7 |
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted income tax expense |
|
|
4 |
|
|
|
15 |
|
|
|
3 |
|
|
|
14 |
|
|
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|
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|
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|
|
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|
|
| 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 DISPUTE
We have
been reporting on our transfer pricing dispute with CRA since 2008, when it originated.
Below, we discuss the general nature of transfer pricing disputes
and, more specifically, the ongoing dispute 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 entered into between arm’s-length parties at that time.
For the years 2003 to 2012, 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. We expect that CRA will seek to impose a transfer pricing penalty for 2012. Taxes of approximately $321 million for the 2003 – 2017 years have already been paid to date 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.
10 CAMECO
CORPORATION
CRA dispute
Since 2008, CRA has disputed our marketing and trading 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 2012 tax returns. We have recorded a cumulative tax provision of $61 million, where an argument could be made that, based on our methodology, our transfer
price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through June 30, 2018. We are confident that we will be successful in our case and continue to believe the ultimate resolution of
this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.
For the years 2003 through
2012, CRA issued notices of reassessment for approximately $4.9 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 remitted a net amount of
$303 million in cash. In addition, we have provided $478 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed after 2014. The amounts paid or secured are shown in the table below.
|
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|
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|
|
|
|
| YEAR PAID ($ 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 |
|
| 2018 |
|
|
17 |
|
|
|
40 |
|
|
|
— |
|
|
|
57 |
|
|
|
— |
|
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
377 |
|
|
|
219 |
|
|
|
185 |
|
|
|
781 |
|
|
|
303 |
|
|
|
478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
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|
Using the methodology we believe CRA will continue to apply, and including the $4.9 billion already reassessed, we expect
to receive notices of reassessment for a total of approximately $8.4 billion of additional income taxable in Canada for the years 2003 through 2017, which would result in a related tax expense of approximately $2.5 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 $1.95 billion and $2.15 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 required to remit or otherwise provide security for 50% of the cash taxes and transfer pricing penalties (between
$970 million and $1.07 billion), plus related interest and instalment penalties assessed, which would be material to us. We have already secured $562 million in cash taxes and transfer pricing penalties and $219 million in interest
and instalment penalties.
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, for amounts reassessed after 2014, as an alternative to remitting 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 2017, and include the expected timing adjustment for the inability to use any loss
carry-backs starting with the 2008 tax year. We plan to update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2017.
2018 SECOND QUARTER
REPORT 11
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ MILLIONS |
|
2003-2017 |
|
|
2018-2019 |
|
|
2020-2023 |
|
|
TOTAL |
|
| 50% of cash taxes and transfer pricing penalties paid, secured or owing in the
period |
|
| Cash payments |
|
|
226 |
|
|
|
65 - 90 |
|
|
|
120 - 145 |
|
|
|
410 - 460 |
|
| Secured by letters of credit |
|
|
319 |
|
|
|
10 - 35 |
|
|
|
230 - 255 |
|
|
|
560 - 610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total paid1 |
|
|
545 |
|
|
|
75 - 125 |
|
|
|
350 - 400 |
|
|
|
970 - 1070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 1 |
These amounts do not include interest and instalment penalties, which totaled approximately $219 million
to June 30, 2018. |
In light of our view of the likely outcome of the case as described above, we expect to recover the amounts
remitted, including the $781 million already paid or otherwise secured to date.
We have spent a total of about $57 million disputing the CRA
reassessments and presenting our appeal in the Tax Court of Canada. This 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 were incurred in 2016 and 2017 during trial preparation and court proceedings. If the decision of the Tax Court is appealed, additional costs will be incurred.
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 the next nine
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 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 or secure
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.
12 CAMECO
CORPORATION
Assumptions
| |
• |
|
CRA will reassess us for the years 2013 through 2017 using a similar methodology as for the years 2003 through 2012, 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 $61 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 2013 through 2017 using a different methodology than for years 2003 through 2012, 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 of $61 million, which could
have a material adverse effect on our liquidity, financial position, results of operations and cash flows |
| |
• |
|
cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing |
| |
• |
|
we are unable to effectively eliminate all double taxation |
FOREIGN EXCHANGE
The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments. See Revenue, adjusted
net earnings, and cash flow sensitivity analysis on page 15 for more information on how a change in the exchange rate will impact our revenue, cash flow, and adjusted net earnings (ANE) (see Non-IFRS
measures on page 8).
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 economic 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
We designate contracts for use in particular periods, based on our expected net exposure in that period. Hedge contracts are layered in over time
based on this expected net exposure. The result is that our current hedge portfolio is made up of a number of contracts which are currently designated to net exposures we expect in 2018 and future years, and we will recognize the gains and losses in
ANE in those periods.
For the purposes of ANE, gains and losses on derivatives are reported based on the difference between the effective hedge rate of
the contracts designated for use in the particular period and the exchange rate at the time of settlement. This results in an adjustment to current period IFRS earnings to effectively remove reported gains and losses on derivatives that arise from
contracts put in place for use in future periods. The effective hedge rate will lag the market in periods of rapid currency movement. See Non-IFRS measures on page 8.
For more information, see our 2017 annual MD&A.
2018 SECOND QUARTER
REPORT 13
At June 30, 2018:
| |
• |
|
The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.32 (Cdn), up from $1.00 (US) for
$1.29 (Cdn) at March 31, 2018. The exchange rate averaged $1.00 (US) for $1.29 (Cdn) over the quarter. |
| |
• |
|
The mark-to-market position on
all foreign exchange contracts was a $27 million loss compared to a $1 million gain at March 31, 2018. |
For information
on the impact of foreign exchange on our intercompany balances, see note 18 to the financial statements.
Outlook for 2018
Our outlook for 2018 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 2018 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 consolidated revenue; uranium delivery volumes, revenue, average realized price, and average unit cost of sales (including D&A); capital
expenditures; the expected contribution of our uranium and fuel services segments to gross profit; and cash flow has changed. We do not provide an outlook for the items in the table that are marked with a dash.
See 2018 Financial results by segment on page 19 for details.
2018 FINANCIAL OUTLOOK
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
CONSOLIDATED |
|
|
URANIUM |
|
|
FUEL SERVICES |
|
| EXPECTED CONTRIBUTION TO GROSS PROFIT |
|
100% |
|
|
81% |
|
|
19% |
|
| Production (owned and operated properties) |
|
|
— |
|
|
|
9.2 million lbs |
|
|
|
9 to 10 million kgU |
|
| Purchases |
|
|
— |
|
|
|
8 to 9 million lbs |
1 |
|
|
— |
|
| Sales/delivery volume2 |
|
|
— |
|
|
|
34 to 35 million lbs |
3 |
|
|
11 to 12 million kgU |
|
| Revenue2 |
|
$ |
1,890-2,140 million |
|
|
$ |
1,550-1,640 million |
4 |
|
$ |
280-310 million |
|
| Average realized price3 |
|
|
— |
|
|
$ |
46.10/lb |
4 |
|
|
— |
|
| Average unit cost of sales (including D&A) |
|
|
— |
|
|
$ |
40.00-42.00/lb |
5 |
|
$ |
21.60-22.60/kgU |
|
| Direct administration costs6 |
|
$ |
120-130 million |
|
|
|
— |
|
|
|
— |
|
| Exploration costs |
|
|
— |
|
|
$ |
20 million |
|
|
|
— |
|
| Expected loss on derivatives - ANE
basis4 |
|
$ |
0-10 million |
|
|
|
— |
|
|
|
— |
|
| Tax recovery - ANE basis7 |
|
$ |
40-50 million |
|
|
|
— |
|
|
|
— |
|
| Capital expenditures8 |
|
$ |
80 million |
|
|
|
— |
|
|
|
— |
|
| 1 |
Based on the volumes we currently have commitments to acquire under contract in 2018. This includes our JV
Inkai purchases. It does not include the 3 million to 4 million pounds of intersegment committed purchases we have, or the 2 million to 4 million pounds of uranium we expect we may need to purchase to meet our 2018 delivery
commitments, and taking into account the Orano loan. |
| 2 |
Our 2018 outlook for sales volume and revenue does not include sales between our segments.
|
| 3 |
Based on the volumes we currently have commitments to deliver under contract in 2018. |
| 4 |
Based on a uranium spot price of $22.55 (US) per pound (the Ux spot price as of June 25, 2018), a
long-term price indicator of $30.00 (US) per pound (the Ux long-term indicator on June 25, 2018) and an exchange rate of $1.00 (US) for $1.25 (Cdn). |
| 5 |
Based on the expected unit cost of sales for produced material and committed long-term purchases including our
JV Inkai purchases. If we make discretionary purchases in 2018, then we expect the overall unit cost of sales may be affected. |
| 6 |
Direct administration costs do not include stock-based compensation expenses or severance costs associated with
our announced corporate office workforce reduction. |
| 7 |
Our outlook for the tax recovery is based on adjusted net earnings and the other assumptions listed in the
table. The outlook does not include our share of taxes on JV Inkai profits as the income from JV Inkai is net of taxes. If other assumptions change then the expected recovery may be affected. |
| 8 |
Our share of JV Inkai capital spending for 2018 is not included as it is reflected on the basis of equity
accounting for our minority ownership interest. JV Inkai cash flows are expected to cover capital expenditures in 2018. |
14 CAMECO
CORPORATION
We now expect our annual uranium sales volume to be 34 million to 35 million pounds (previously
32 million to 33 million pounds) as a result of additional sales commitments made during the quarter. Sales revenue for the uranium segment will also be affected and is now expected to be $1,550 million to $1,640 million
(previously $1,460 million to $1,550 million), resulting in consolidated revenue of $1,890 million to $2,140 million (previously $1,800 million to $1,930 million).
Average realized price for our uranium segment is now expected to be $46.10 per pound (previously $46.30 per pound) as a result of entering additional sales
commitments for delivery in 2018 at prices lower than the previous average realized price outlook provided. In addition, average unit cost of sales is now expected to be $40.00 per pound to $42.00 per pound (previously $38.00 per pound to $40.00 per
pound) due to the severance costs associated with the continued suspension of production at McArthur River and Key Lake.
As a result of the changes to
the uranium average realized price and average unit cost of sales, we now expect the contribution to gross profit to be 81% from the uranium segment and 19% from the fuel services segment (previously 85% and 15% respectively).
We now expect capital expenditures to be $80 million (previously $90 million) mainly as a result of the optimization of the Cigar Lake development plan,
which results in a reduction in expenditures this year.
Cash from operations for 2018 is now expected to be between 20% and 30% higher than the
$596 million reported in 2017. This estimate is 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. In addition to our purchase commitments of between
8 million and 9 million pounds, the estimate also includes expected purchases of 2 million to 4 million pounds.
Direct administration
costs remain unchanged, however, we expect an increase in our overall administration costs of about $10 million due to the severance costs associated with the workforce reduction at corporate office. These costs will be expensed in the third
quarter.
In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns,
sales/delivery volumes and revenue can vary significantly. We are on track for our uranium sales/delivery targets in 2018, with deliveries weighted to the second half of the year.
Additional outlook tied to the extended shutdown of McArthur River/Key Lake
To meet our delivery commitments in 2018, and taking into account the Orano loan of up to 5.4 million pounds, we expect we will need to purchase
2 million to 4 million pounds of uranium this year in addition to the purchase commitments outlined in the 2018 Financial Outlook table. This will achieve our inventory reduction plan, assuming we target four and a half months of forward
sales in inventory.
In the absence of an extended shutdown, that would be the extent of our required purchases this year. However, considering the
extended production suspension, and our willingness to capture demand in the market, we may undertake additional purchasing activity if the opportunity or need arises.
Looking at 2019, in our uranium segment, we expect to produce 9 million pounds, we have commitments to purchase between 5 million and 6 million
pounds, and have sales commitments to deliver between 25 million and 27 million pounds. To meet our 2019 delivery commitments and maintain our target inventory, we expect we will need to purchase an additional 9 million to
11 million pounds. The timing of purchases may be impacted by the timing of deliveries and opportunities in the market.
REVENUE, ADJUSTED NET
EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| FOR 2018 ($ MILLIONS) |
|
|
|
IMPACT ON: |
|
| |
CHANGE |
|
REVENUE |
|
|
ANE |
|
|
CASH FLOW |
|
| Uranium spot and term price1 |
|
$5(US)/lb increase |
|
|
37 |
|
|
|
24 |
|
|
|
30 |
|
|
|
$5(US)/lb decrease |
|
|
(37 |
) |
|
|
(24 |
) |
|
|
(30 |
) |
| Value of Canadian dollar vs US dollar |
|
One cent decrease in CAD |
|
|
9 |
|
|
|
3 |
|
|
|
3 |
|
|
|
One cent increase in CAD |
|
|
(9 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
| 1 |
Assuming change in both UxC spot price ($22.55 (US) per pound on June 25, 2018) and the UxC long-term
price indicator ($30.00 (US) per pound on June 25, 2018) |
2018 SECOND QUARTER
REPORT 15
PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT
The following table is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table. It
is designed to indicate how the portfolio of long-term contracts we had in place on June 30, 2018 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was
on June 30, 2018 and none of the assumptions we list below change.
We intend to update this table each quarter in our MD&A to reflect changes to
our contract portfolio. As a result, we expect the table to change from quarter to quarter.
Expected realized uranium
price sensitivity under various spot price assumptions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (rounded to the nearest $1.00) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SPOT PRICES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($US/lb U3O8) |
|
$20 |
|
|
$40 |
|
|
$60 |
|
|
$80 |
|
|
$100 |
|
|
$120 |
|
|
$140 |
|
| 2019 |
|
|
32 |
|
|
|
43 |
|
|
|
56 |
|
|
|
66 |
|
|
|
75 |
|
|
|
83 |
|
|
|
89 |
|
| 2020 |
|
|
31 |
|
|
|
41 |
|
|
|
54 |
|
|
|
64 |
|
|
|
73 |
|
|
|
80 |
|
|
|
86 |
|
| 2021 |
|
|
28 |
|
|
|
41 |
|
|
|
55 |
|
|
|
65 |
|
|
|
74 |
|
|
|
83 |
|
|
|
90 |
|
| 2022 |
|
|
27 |
|
|
|
41 |
|
|
|
55 |
|
|
|
66 |
|
|
|
75 |
|
|
|
84 |
|
|
|
92 |
|
The table illustrates the mix of long-term contracts in our June 30, 2018 portfolio, and is consistent with our marketing
strategy. It has been updated to reflect contracts entered into up to June 30, 2018, 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 23 million pounds per year, with commitment levels of between 34 million and 35 million pounds in 2018 and 25 million to 27 million pounds in 2019. Commitments for
2020 through 2022 are lower. |
| |
• |
|
excludes sales between our 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 21% 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 other financial obligations.
As of June 30, 2018, we had cash and short-term investments of $837 million, while our total debt amounted to $1.5 billion.
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 continue to provide a solid revenue stream. Over the next five years, we have commitments to
deliver an average of 23 million pounds per year, with commitments levels in 2018 of 34 million to 35 million pounds and 25 million to 27 million pounds in 2019. Commitments for 2020 through 2022 are lower.
16 CAMECO
CORPORATION
In the currently weak uranium price environment, our focus is on preserving the value of our tier-one assets and reducing our operating, capital and general and administrative spending. We have a number of alternatives to fund future capital requirements, including using our operating cash flow, drawing on
our existing credit facilities, entering new credit facilities, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they
arise. Due to the deliberate cost reduction measures implemented over the past five years, the reduction in our 2018 planned dividend, and the drawdown of inventory in 2018 as a result of the suspension of production at our McArthur River/Key Lake
operation, we expect to generate significant cash flow in 2018. Therefore, we expect our cash balances and operating cash flows to meet our capital requirements during 2018, and help position us to self-manage risk.
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 12.
CASH FROM/USED IN OPERATIONS
Cash provided by operations was $73 million lower this quarter than in the second quarter of 2017. Contributing to this change was lower gross profits in
both our uranium and fuel services segments. In addition, there was an increase in working capital requirements, which required $29 million more in 2018 than in 2017. Not including working capital requirements, our operating cash flows this
quarter were lower by $44 million.
Cash provided by operations was $210 million higher in the first six months of 2018 than for the same period
in 2017 due largely to a decrease in working capital requirements. This was a result of a decrease in inventory compared to an increase in 2017 as well as changes in other working capital items. Working capital required $171 million less in
2018. In addition, while we had lower gross profits in our operating segments, income taxes paid decreased and cost reduction measures resulted in a lower use of cash. Not including working capital requirements, our operating cash flows in the first
six months were higher by $39 million.
FINANCING ACTIVITIES
We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $3.0 billion at
June 30, 2018, unchanged from March 31, 2018. At June 30, 2018, we had approximately $1.6 billion outstanding in financial assurances, up from $1.5 billion at December 31, 2017. At June 30, 2018, we had no
short-term debt outstanding on our $1.25 billion unsecured revolving credit facility, unchanged from December 31, 2017. This facility matures November 1, 2021.
Long-term contractual obligations
Since
December 31, 2017, there have been no material changes to our long-term contractual obligations. Please see our 2017 annual MD&A for more information.
Debt covenants
We are bound by certain covenants in our
unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at June 30, 2018, we met these financial covenants and do not expect our operating and investment activities for
the remainder of 2018 to be constrained by them.
OFF-BALANCE SHEET ARRANGEMENTS
We had three kinds of off-balance sheet arrangements at June 30, 2018:
2018 SECOND QUARTER
REPORT 17
Purchase commitments
The following table is based on our purchase commitments in our uranium and fuel services segments, as well as commitments previously contracted by NUKEM, at
July 17, 2018. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the
market prices in effect at the time of delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| JULY 17 ($ MILLIONS) |
|
2018 |
|
|
2019 AND
2020 |
|
|
2021 AND
2022 |
|
|
2023 AND
BEYOND |
|
|
TOTAL |
|
| Purchase commitments1 |
|
|
408 |
|
|
|
249 |
|
|
|
178 |
|
|
|
132 |
|
|
|
967 |
|
| 1 |
Denominated in US dollars, converted to Canadian dollars as of June 30, 2018 at the rate of $1.32.
|
As of July 25, 2018, we had commitments of about $967 million for the following:
| |
• |
|
approximately 25 million pounds of U3O8 equivalent from 2018 to 2028 |
| |
• |
|
approximately 1 million kgU as UF6 in conversion
services in 2018 and 2019 |
| |
• |
|
about 0.2 million Separative Work Units (SWU) of enrichment services to meet existing forward sales
commitments under agreements with a non-Western supplier |
The suppliers do not have the right to
terminate agreements other than pursuant to customary events of default provisions.
Financial assurances
At June 30, 2018, our financial assurances totalled $1.6 billion, up from $1.5 billion at December 31, 2017.
Other arrangements
We continue to have factoring
arrangements available to us to manage short-term cash flow fluctuations. At June 30, 2018 we did not have any balances outstanding under these arrangements. You can read more about these arrangements in our 2017 annual MD&A.
BALANCE SHEET
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($ MILLIONS) |
|
JUN 30, 2018 |
|
|
DEC 31, 2017 |
|
|
CHANGE |
|
| Cash, cash equivalents and short-term investments |
|
|
837 |
|
|
|
592 |
|
|
|
41 |
% |
| Total debt |
|
|
1,495 |
|
|
|
1,494 |
|
|
|
— |
|
| Inventory |
|
|
838 |
|
|
|
950 |
|
|
|
(12 |
)% |
Total cash, cash equivalents and short-term investments at June 30, 2018 were $837 million, or 41% higher than at
December 31, 2017, primarily due to cash from operations of $332 million, partially offset by capital expenditures of $30 million, 2017 dividend payments of $40 million, and interest payments of $35 million. Net debt at
June 30, 2018 was $658 million.
Under the restructuring agreement for JV Inkai, the partners have agreed that JV Inkai will distribute excess
cash, after capital expenditures, as priority repayment of our loan. We have an outstanding loan for Inkai’s work on block 3 prior to the restructuring. In the second quarter of 2018 we received distributions of $4.2 million (US), totaling
$13.3 million (US) year-to-date, which were made as loan and interest repayments, and as of June 30, 2018, the outstanding principal balance of the loan was
$106 million (US).
Total product inventories decreased to $838 million. Inventories decreased as sales were higher than production and
purchases in the first six months of the year. In addition, the product provided to Orano contributed to the decrease. The average cost for uranium has increased to $31.50 per pound compared to $30.72 per pound at December 31, 2017. As of
June 30, 2018, we held an inventory of 19.3 million pounds of U3O8 equivalent in our uranium segment (excluding broken ore).
18 CAMECO
CORPORATION
Financial results by segment
Uranium
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
THREE MONTHS
ENDED JUNE 30 |
|
|
|
|
|
SIX MONTHS
ENDED JUNE 30 |
|
|
|
|
| HIGHLIGHTS |
|
|
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
| Production volume (million lbs) |
|
|
|
|
2.9 |
|
|
|
7.1 |
|
|
|
(59 |
)% |
|
|
5.3 |
|
|
|
13.8 |
|
|
|
(62 |
)% |
| Sales volume (million lbs)1 |
|
|
|
|
5.3 |
|
|
|
6.1 |
|
|
|
(13 |
)% |
|
|
11.9 |
|
|
|
11.8 |
|
|
|
1 |
% |
| Average spot price |
|
($US/lb) |
|
|
22.13 |
|
|
|
20.79 |
|
|
|
6 |
% |
|
|
21.78 |
|
|
|
22.29 |
|
|
|
(2 |
)% |
| Average long-term price |
|
($US/lb) |
|
|
29.00 |
|
|
|
32.83 |
|
|
|
(12 |
)% |
|
|
29.25 |
|
|
|
32.83 |
|
|
|
(11 |
)% |
| Average realized price |
|
($US/lb) |
|
|
34.93 |
|
|
|
36.51 |
|
|
|
(4 |
)% |
|
|
39.38 |
|
|
|
35.50 |
|
|
|
11 |
% |
|
|
($Cdn/lb) |
|
|
44.91 |
|
|
|
49.11 |
|
|
|
(9 |
)% |
|
|
50.04 |
|
|
|
47.36 |
|
|
|
6 |
% |
| Average unit cost of sales (including D&A) |
|
($Cdn/lb) |
|
|
41.12 |
|
|
|
35.29 |
|
|
|
17 |
% |
|
|
41.84 |
|
|
|
36.47 |
|
|
|
15 |
% |
| Revenue ($ millions)1 |
|
|
|
|
237 |
|
|
|
298 |
|
|
|
(20 |
)% |
|
|
596 |
|
|
|
558 |
|
|
|
7 |
% |
| Gross profit ($ millions) |
|
|
|
|
20 |
|
|
|
84 |
|
|
|
(76 |
)% |
|
|
98 |
|
|
|
128 |
|
|
|
(23 |
)% |
| Gross profit (%) |
|
|
|
|
8 |
|
|
|
28 |
|
|
|
(71 |
)% |
|
|
16 |
|
|
|
23 |
|
|
|
(30 |
)% |
| 1 |
There were no significant intersegment transactions in the periods shown. |
SECOND QUARTER
Production volumes this quarter were 59%
lower compared to the second quarter of 2017, mainly due to a lack of production from the suspended McArthur River/Key Lake operations and a change in reporting for JV Inkai. See Uranium 2018 Q2 updates starting on page 22 for more
information.
Uranium revenues this quarter were down 20% compared to 2017 due to a decrease of 9% in the Canadian dollar average realized price and a
decrease in sales volumes of 13%. While the average spot price for uranium increased by 6% compared to the same period in 2017, our average realized price decreased due to lower prices on fixed price contracts and the strengthening of the Canadian
dollar compared to the same period in the prior year.
Total cost of sales (including D&A) increased by 1% ($217 million compared to
$214 million in 2017) as a result of unit cost of sales that was 17% higher than the same period last year offset by a 13% decrease in sales volume. The increase in the unit cost of sales was due mainly to increased costs associated with the
temporary suspension of production at our McArthur River/Key Lake operation and the cessation of production at our US ISR operations. The cost of our purchases have decreased from the second quarter in 2017.
The net effect was a $64 million decrease in gross profit for the quarter.
Equity earnings from investee, JV Inkai, were $4 million in the second quarter.
FIRST SIX MONTHS
Production volumes for the first six
months of the year were 62% lower than in the previous year mainly due to planned lower production from McArthur River/Key Lake as the operation moved into care and maintenance in the first quarter and a change in reporting for JV Inkai. See
Uranium 2018 Q2 updates starting on page 22 for more information.
Uranium revenues increased 7% compared to the first six months of 2017 due to a
6% increase in the Canadian dollar average realized price and a 1% increase in sales volumes. The increase in sales volume was due to the restructuring of an agreement with one of our utility customers. The restructuring advanced the majority of
contract deliveries into the first quarter of 2018.
Our Canadian dollar realized prices for the first six months of 2018 were higher than 2017, primarily
as a result of higher prices on fixed price contracts.
Total cost of sales (including D&A) increased by 16% ($499 million compared to
$430 million in 2017) mainly due to a 15% increase in the unit cost of sales and a 1% increase in sales volume for the first six months. The increase in the unit cost of sales compared to last year was mainly due to increased costs associated
with the temporary suspension of production at our McArthur River/Key Lake and US ISR operations. The cost of our purchases have decreased from the same period in 2017.
The net effect was a $30 million decrease in gross profit for the first six months.
2018 SECOND QUARTER
REPORT 19
Equity earnings from investee, JV Inkai, were $5 million for the first six months.
The table below shows the costs of produced and purchased uranium incurred in the reporting periods (which are
non-IFRS measures, see the paragraphs below the table). These costs do not include care and maintenance costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of
opening inventories on our reported cost of sales.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS
ENDED JUNE 30 |
|
|
|
|
|
SIX MONTHS
ENDED JUNE 30 |
|
|
|
|
| ($CDN/LB) |
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
| Produced |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash cost |
|
|
10.78 |
|
|
|
13.53 |
|
|
|
(20 |
)% |
|
|
14.14 |
|
|
|
14.02 |
|
|
|
1 |
% |
| Non-cash cost |
|
|
15.96 |
|
|
|
10.59 |
|
|
|
51 |
% |
|
|
16.55 |
|
|
|
10.47 |
|
|
|
58 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total production cost 1 |
|
|
26.74 |
|
|
|
24.12 |
|
|
|
11 |
% |
|
|
30.69 |
|
|
|
24.49 |
|
|
|
25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Quantity produced (million lbs)1 |
|
|
2.9 |
|
|
|
7.1 |
|
|
|
(59 |
)% |
|
|
5.3 |
|
|
|
13.8 |
|
|
|
(62 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash cost1 |
|
|
29.64 |
|
|
|
37.34 |
|
|
|
(21 |
)% |
|
|
32.73 |
|
|
|
40.36 |
|
|
|
(19 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Quantity purchased (million lbs)1 |
|
|
2.2 |
|
|
|
0.7 |
|
|
|
214 |
% |
|
|
3.9 |
|
|
|
2.5 |
|
|
|
56 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Totals |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Produced and purchased costs |
|
|
27.99 |
|
|
|
25.31 |
|
|
|
11 |
% |
|
|
31.55 |
|
|
|
26.92 |
|
|
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Quantities produced and purchased (million lbs) |
|
|
5.1 |
|
|
|
7.8 |
|
|
|
(35 |
)% |
|
|
9.2 |
|
|
|
16.3 |
|
|
|
(44 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 1 |
Our share of Inkai production was 0.7 million pounds for Q2, 2018 (1.4 million pounds for the first
six months of 2018). Due to the transition to equity accounting, our share of production will be shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. In
the second quarter we purchased 856,000 pounds at a purchase price per pound of $27.52 ($21.46 (US)) (870,000 pounds in the first six months of 2018 at $27.54 ($21.47 (US))). |
The average cash cost of production was 20% lower for the quarter compared to 2017 due to higher production at Cigar Lake. In addition, with the cessation of
higher cost production at our US operations in the first quarter, any costs associated with the operation are considered care and maintenance and expensed directly to cost of sales as incurred. For the first six months, the average cash cost of
production was 1% higher than in in 2017 due to lower production from McArthur River/Key Lake as the operations moved into care and maintenance.
The
other item affecting this table was the change to equity accounting for our interest in JV Inkai.
The change removes the impact of our share of
Inkai’s low cash cost of production from the mix. Those pounds now are reflected as a purchase at a discount to the spot price in this table. The benefit of the estimated $9.55 per pound life-of-mine operating cost is expected to be reflected in the line item on our statement of earnings called “share of earnings from equity-accounted investee”.
As a result, while McArthur River and Key Lake are shut down, our cash cost of production is expected to be reflective of the estimated $15.42 per pound life-of-mine operating cost of mining and milling our share of Cigar Lake pounds.
Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the second quarter, the average cash cost of
purchased material was $29.64 (Cdn) per pound, or $23.07 (US) per pound in US dollar terms, compared to $27.82 (US) per pound in the second quarter of 2017. For the first six months, the average cash cost of purchased material was $32.73 (Cdn),
or $25.69 (US) per pound, compared to $30.40 (US) per pound in the same period in 2017. As a result, the average cash cost of purchased material in Canadian dollar terms decreased by 21% this quarter and by 19% for the six months compared to the
same periods last year.
Cash cost per pound, non-cash cost per pound and total cost per pound for produced and
purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment
of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.
20 CAMECO
CORPORATION
These measures are non-standard supplemental information and should not
be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other
companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.
To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the
second quarter and the first six months of 2018 and 2017.
Cash and total cost per pound reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS
ENDED JUNE 30 |
|
|
SIX MONTHS
ENDED JUNE 30 |
|
| ($ MILLIONS) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
| Cost of product sold |
|
|
156.4 |
|
|
|
158.9 |
|
|
|
388.1 |
|
|
|
340.9 |
|
| Add / (subtract) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Royalties |
|
|
(9.5 |
) |
|
|
(13.0 |
) |
|
|
(21.8 |
) |
|
|
(23.2 |
) |
| Care and maintenance costs |
|
|
(34.6 |
) |
|
|
(10.4 |
) |
|
|
(76.5 |
) |
|
|
(20.8 |
) |
| Other selling costs |
|
|
(1.2 |
) |
|
|
(2.2 |
) |
|
|
(5.5 |
) |
|
|
(2.9 |
) |
| Change in inventories |
|
|
(14.6 |
) |
|
|
(11.1 |
) |
|
|
(81.7 |
) |
|
|
0.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash operating costs (a) |
|
|
96.5 |
|
|
|
122.2 |
|
|
|
202.6 |
|
|
|
294.4 |
|
| Add / (subtract) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Depreciation and amortization |
|
|
48.8 |
|
|
|
55.5 |
|
|
|
91.5 |
|
|
|
89.0 |
|
| Care and maintenance costs |
|
|
12.0 |
|
|
|
— |
|
|
|
19.0 |
|
|
|
— |
|
| Change in inventories |
|
|
(14.5 |
) |
|
|
19.7 |
|
|
|
(22.8 |
) |
|
|
55.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total operating costs (b) |
|
|
142.8 |
|
|
|
197.4 |
|
|
|
290.3 |
|
|
|
438.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Uranium produced & purchased (million lbs) (c) |
|
|
5.1 |
|
|
|
7.8 |
|
|
|
9.2 |
|
|
|
16.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cash costs per pound (a ÷ c) |
|
|
18.92 |
|
|
|
15.67 |
|
|
|
22.02 |
|
|
|
18.06 |
|
| Total costs per pound (b ÷ c) |
|
|
27.99 |
|
|
|
25.31 |
|
|
|
31.55 |
|
|
|
26.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel services
(includes
results for UF6, UO2 and fuel fabrication)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
THREE MONTHS
ENDED JUNE 30 |
|
|
|
|
|
SIX MONTHS
ENDED JUNE 30 |
|
|
|
|
| HIGHLIGHTS |
|
|
|
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
| Production volume (million kgU) |
|
|
|
|
|
|
2.3 |
|
|
|
2.2 |
|
|
|
5 |
% |
|
|
6.2 |
|
|
|
4.8 |
|
|
|
29 |
% |
| Sales volume (million kgU)1 |
|
|
|
|
|
|
2.1 |
|
|
|
2.7 |
|
|
|
(22 |
)% |
|
|
4.5 |
|
|
|
4.3 |
|
|
|
5 |
% |
| Average realized price |
|
($ |
Cdn/kgU |
) |
|
|
32.63 |
|
|
|
30.46 |
|
|
|
7 |
% |
|
|
29.40 |
|
|
|
31.50 |
|
|
|
(7 |
)% |
| Average unit cost of sales (including D&A) |
|
($ |
Cdn/kgU |
) |
|
|
24.30 |
|
|
|
21.44 |
|
|
|
13 |
% |
|
|
22.83 |
|
|
|
22.66 |
|
|
|
1 |
% |
| Revenue ($ millions)1 |
|
|
|
|
|
|
68 |
|
|
|
82 |
|
|
|
(17 |
)% |
|
|
133 |
|
|
|
137 |
|
|
|
(3 |
)% |
| Gross profit ($ millions) |
|
|
|
|
|
|
17 |
|
|
|
24 |
|
|
|
(29 |
)% |
|
|
30 |
|
|
|
38 |
|
|
|
(21 |
)% |
| Gross profit (%) |
|
|
|
|
|
|
25 |
|
|
|
29 |
|
|
|
(14 |
)% |
|
|
23 |
|
|
|
28 |
|
|
|
(18 |
)% |
| 1 |
There were no significant intersegment transactions in the periods shown. |
SECOND QUARTER
Total revenue for the second quarter of
2018 decreased to $68 million from $82 million for the same period last year. This was primarily due to a 22% decrease in sales volumes partially offset by a 7% increase in average realized price compared to 2017. Average realized price
increased mainly due to the mix of product sold, as well as an increase in the average realized price for UO2 and fabrication.
The total cost of products and services sold (including D&A) decreased 12% ($51 million compared to $58 million in 2017) due to the 22% decrease
in sales volume, partially offset by a 13% increase in the average unit cost of sales.
The net effect was a $7 million decrease in gross profit.
2018 SECOND QUARTER
REPORT 21
FIRST SIX MONTHS
In the first six months of the year, total revenue decreased by 3% due to a 7% decrease in realized price, partially offset by a 5% increase in sales volumes.
The decrease in realized price was the result of decreased prices on the sale of UF6, and the mix of products sold.
The total cost of products and services sold (including D&A) increased 5% ($103 million compared to $98 million in 2017) due to the 5% increase
in sales volume and a 1% increase in the average unit cost of sales.
The net effect was an $8 million decrease in gross profit.
Our operations
Uranium – production overview
Production in our uranium segment this quarter was 59% lower than the second quarter of 2017 due to the production suspension at McArthur River and
Key Lake and a change in reporting for JV Inkai. See table below for more information. We continue to evaluate the optimal mix of production, inventory and purchases in order to retain the flexibility to deliver long-term value.
URANIUM PRODUCTION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
THREE MONTHS
ENDED JUNE 30 |
|
|
|
|
|
SIX MONTHS
ENDED JUNE 30 |
|
|
|
|
|
|
|
| OUR SHARE (MILLION LBS) |
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
|
2018 |
|
|
2017 |
|
|
CHANGE |
|
|
2018 PLAN |
|
| McArthur River/Key Lake |
|
|
— |
|
|
|
3.6 |
|
|
|
(100 |
)% |
|
|
0.1 |
|
|
|
7.2 |
|
|
|
(99 |
)% |
|
|
0.1 |
|
| Cigar Lake |
|
|
2.9 |
|
|
|
2.5 |
|
|
|
16 |
% |
|
|
5.1 |
|
|
|
4.8 |
|
|
|
6 |
% |
|
|
9.0 |
|
| Inkai1 |
|
|
— |
|
|
|
0.8 |
|
|
|
(100 |
)% |
|
|
— |
|
|
|
1.5 |
|
|
|
(100 |
)% |
|
|
— |
|
| US ISR |
|
|
— |
|
|
|
0.2 |
|
|
|
(100 |
)% |
|
|
0.1 |
|
|
|
0.3 |
|
|
|
(67 |
)% |
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
2.9 |
|
|
|
7.1 |
|
|
|
(59 |
)% |
|
|
5.3 |
|
|
|
13.8 |
|
|
|
(62 |
)% |
|
|
9.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 1 |
We expect total production from Inkai to be 6.9 million pounds in 2018 on a 100% basis. Due to the
transition to equity accounting, our share of production will be shown as a purchase. Please see below for more information. |
Uranium
2018 Q2 updates
PRODUCTION UPDATE
McArthur
River/Key Lake
There was no production in the second quarter as a result of the planned 10-month production
suspension that began in February.
Due to continued weakness in the uranium market, we have made the decision to extend the suspension for an
indeterminate duration. This action will result in the permanent layoff of approximately 550 employees, including those currently on temporary layoff.
A
reduced workforce of approximately 200 employees will remain at the operations to keep the facilities in a state of safe care and maintenance.
We will
incur about $30 million to $35 million in severance costs in the third quarter as a result of the permanent layoffs. Our share of the cost to maintain both operations during the suspension is expected to range between $5 million and
$6 million per month (previously $6.5 million to $7.5 million per month) once the permanent layoffs take effect.
Cigar Lake
Total packaged production from Cigar Lake was 16% higher in the second quarter and 6% higher for the first six months compared to the same periods last year.
Production is expected to be lower in the third quarter as the site enters an extended summer shutdown period starting in July, which is expected to increase quarterly unit production costs. Production is expected to restart at the end of August and
remains on track to meet forecast for the year.
22 CAMECO
CORPORATION
Inkai
Production on a 100% basis was 1.8 million pounds for the quarter and 3.5 million pounds for the first six months of the year. Production is tracking
higher than the comparable period in 2017 due to increased planned production in 2018 above 2017 production levels. Due to the transition to equity accounting, our share of production will be shown as a purchase at a discount to the spot price and
included in inventory at this value at the time of delivery. Our share of the profits earned by JV Inkai on the sale of its production will be included in “share of earnings from equity-accounted investee” on our consolidated statement of
earnings.
TIER-TWO CURTAILED OPERATIONS
US ISR Operations
As a result of the decision to curtail
production and defer all wellfield development at our US operations, there was no production in the second quarter. We have now effectively ceased production, which is expected to result in production of less than 100,000 pounds for the year. As
long as production is suspended, we expect care and maintenance costs to range between $18 million (US) and $22 million (US) annually for the first few years.
Rabbit Lake
The Rabbit Lake operation is in a safe state
of care and maintenance; there was no production in the second quarter of 2018. 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 2018 Q2 updates
PORT HOPE CONVERSION SERVICES
CAMECO FUEL
MANUFACTURING INC. (CFM)
Production update
Fuel
services produced 2.3 million kgU in the second quarter, 5% higher than the same period last year due to the timing of scheduled production.
Labour relations
Approximately 90 unionized employees at
CFM’s operations in Ontario accepted a new collective agreement. The employees, represented by the United Steelworkers Local 14193, agreed to a three-year contract. The previous contract expired May 30, 2018.
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
| |
• |
|
Greg Murdock, manager, operations, McArthur River, Cameco |
CIGAR LAKE
| |
• |
|
Jeremy Breker, general manager, Rabbit Lake/Cigar Lake, Cameco
|
INKAI
| |
• |
|
Brian Reilly, senior vice-president and chief operating officer, Cameco |
2018 SECOND QUARTER
REPORT 23
Additional information
Critical accounting estimates
Due to the nature of our
business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the
Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.
Controls and procedures
As of June 30, 2018, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive
officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of
human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.
Based upon that evaluation and as of June 30, 2018, the CEO and CFO concluded that:
| |
• |
|
the disclosure controls and procedures were effective to provide reasonable assurance that information required
to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required |
| |
• |
|
such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to
allow timely decisions regarding required disclosure |
There has been no change in our internal control over financial reporting during
the quarter ended June 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
24 CAMECO
CORPORATION
