40-F
CAMECO CORP (CCJ)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
40-F
☐
REGISTRATION STATEMENT
PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE
ACT OF 1934
OR
☒
ANNUAL REPORT PURSUANT TO SECTION 13(a) or
15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended
December 31, 2022
Commission file number
:
1-14228
CAMECO CORPORATION
(Exact name of Registrant as specified in its charter)
Canada
(Province or other jurisdiction of incorporation or organization)
1090
(Primary Standard Industrial Classification Code Number)
98-0113090
(I.R.S. Employer Identification)
2121 – 11
th
Street West
,
Saskatoon
,
Saskatchewan
,
Canada
,
S7M 1J3
, Telephone:
(
306
)
956-6200
(Address and telephone number of Registrant’s principal executive offices)
Cristina Giffin, Power Resources, Inc., Smith Ranch-Highland Operation
762 Ross Road
,
Douglas
,
Wyoming
, USA,
82633
Telephone: (
307
)
358-6541
(Name, address, (including zip code) and telephone number (including area code) of agent for service in the United States)
Securities registered pursuant to Section 12(b) of the Act:
Title of Class:
Common Shares
,
no
par value
Trading Symbol(s):
CCJ
Name of Exchange where Securities are listed:
New York Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of
the Act:
None
Securities for which there is a reporting obligation pursuant
to Section 15(d) of the Act:
None
Information filed with this Form:
☒
Annual Information Form
☒
Audited annual financial statements
Number of outstanding shares of each of the issuer’s classes
of
capital or common stock as of the close of the period covered by
the annual report:
432,518,470
Common Shares outstanding as of December 31, 2022
2
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of
the Exchange
Act during
the preceding
12 months
(or for
such shorter
period that
the Registrant
was required
to
file such reports), and (2) has been subject to such filing requirements
for the past 90 days.
☒
Yes
☐
No
Indicate by check
mark whether the
registrant has submitted
electronically,
every Interactive Data
File required to
be submitted pursuant to Rule 405 of
Regulation S-T (§232.405 of this chapter) during the
preceding 12 months (or
for such shorter period that the Registrant was required
to submit and post such files).
☒
Yes
☐
No
Indicate
by
check
mark
whether
the
registrant
is
an
emerging
growth
company
as
defined
in
Rule
12b-2
of
the
Exchange Act.
Emerging growth company
☐
If an emerging
growth company
that prepares
its financial
statements in
accordance with
U.S. GAAP,
indicate by
check mark
if the
registrant has
elected not
to use
the extended
transition period
for complying
with any
new or
revised financial accounting standards†
provided pursuant to Section 13(a) of the Exchange
Act.
☐
Indicate by check mark
whether the registrant has filed a
report on and attestation to
its management’s assessment
of the effectiveness
of its internal
control over financial
reporting under Section
404(b) of the
Sarbanes-Oxley Act
(15 U.S.C. 7262(b)) by the registered public accounting
firm that prepared or issued its audit report.
☑
If
securities
are
registered
pursuant
to
Section
12(b)
of
the
Exchange
Act,
indicate
by
check
mark
whether
the
financial
statements
of
the
registrant
included
in
the
filing
reflect
the
correction
of
an
error
to
previously
issued
financial statements.
☐
Indicate by check
mark whether any
of those error
corrections are restatements
that required a
recovery analysis
of incentive-based compensation received by any of the registrant’s executive officers
during the relevant recovery
period pursuant to §240.10D-1(b).
☐
FORWARD-LOOKING
STATEMENTS
Certain statements
in this
Annual Report on
Form 40-F
and the documents
filed as exhibits
hereto, and including
certain information
about Cameco’s
business outlook,
objectives, strategies,
plans, strategic
priorities and
results
of operations, as well as
other statements which are
not current statements or
historical facts, constitute “forward-
looking information
”
within the
meaning of
applicable
Canadian securities
laws and
“forward-looking
statements”
within
the
meaning
of
the
Private
Securities
Litigation
Reform
Act
of
1995.
Forward-looking
information
and
statements
involve
risks,
uncertainties
and
other
factors
that
could
cause
actual
results
to
differ
materially
from
those
expressed
or
implied
by
them.
Sentences
and
phrases
containing
words
such
as
“anticipate”,
“believe”,
“estimate”,
“expect”,
“forecast”,
“goal”,
“intend”,
“outlook”,
“plan”,
“potential”,
“predict”,
“project”,
“proposed”,
“scheduled”,
“strategy”,
“target”
and
“will”,
and
the
negative
of
any
of
these
words
or
variations
of
them
or
comparable terminology that does not relate strictly
to current or historical facts, are all
indicative of forward-looking
information or statements.
3
The forward-looking information and statements included
in this Annual Report on Form 40-F (including the
exhibits hereto) represent our views as of the date of
such documents and should not be relied upon as
representing our views as of any subsequent date. While we
anticipate that subsequent events and developments
may cause our views to change, we specifically disclaim
any intention or obligation to update forward-looking
information and statements, whether as a result of new information,
future events or otherwise, except to the
extent required by applicable securities laws. Forward-looking
information and statements contained in this
Annual Report on Form 40-F about prospective results
of operations, financial position or cash flows that are
based upon assumptions about future economic conditions
and courses of action are presented for the purpose
of assisting our security holders in understanding management’s
current views regarding those future outcomes,
and may not be appropriate for other purposes.
See Cameco’s Annual Information Form for the year
ended December 31, 2022, attached as Exhibit
99.1 to this
Annual Report on Form 40-F,
under the heading “Caution about forward-looking information”
and Cameco’s
management’s discussion and analysis for the year
ended December 31, 2022, attached as Exhibit 99.3 to
this
Annual Report on Form 40-F (the “Cameco 2022 MD&
A”), under the heading “Caution about forward-looking
information”, for a discussion of forward-looking statements.
Certifications and Disclosure Regarding Controls and
Procedures
.
(a)
Certifications regarding controls and procedures
.
See Exhibits 99.6 and 99.7.
(b)
Evaluation of
disclosure controls
and procedures
. As
of December
31, 2022
an evaluation
of the
effectiveness of Cameco Corporation’s “disclosure controls and procedures” (as such term is defined in
Rules 13a-15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934, as amended (the
“Exchange Act”)) was carried ou
t
by Cameco Corporation’s
Chief
Executive Officer (“CEO”)
and Chief
Financial Officer (“CFO”). Based on
that evaluation, the CEO and CFO have concluded
that as of such
date Cameco
Corporation’s
disclosure controls
and procedures
are effective
to provide
a reasonable
level of
assurance that
information
required
to be
disclosed
by Cameco
Corporation
in reports
that it
files or
submits under
the Exchange
Act is
recorded, processed,
summarized and
reported within
the
time periods specified in United States Securities
and Exchange Commission (the “Commission”) rules
and forms.
It should be noted that
while the CEO and
CFO believe that Cameco
Corporation’s disclosure controls
and procedures provide a reasonable
level of assurance that
they are effective, they
do not expect the
disclosure controls
and procedures or
internal control
over financial reporting
to be
capable of preventing
all
errors
and
fraud.
A
control
system,
no
matter
how
well
conceived
or
operated,
can
provide
only
reasonable, not absolute, assurance that the objectives of the control
system are met.
(c)
Management’s
annual
report
on
internal
control
over
financial
reporting
.
Management
of
the
Company,
including
the
CEO
and
CFO,
is
responsible
for
establishing
and
maintaining
adequate
“internal control over financial reporting”, as that term is
defined in Rules 13a-15(f) and 15d-15(f) under
the Exchange Act, for Cameco Corporation. Management conducted an evaluation of the effectiveness
of internal control
over financial reporting
based on criteria
established in Internal
Control – Integrated
Framework (2013) issued by
the Committee of
Sponsoring Organizations of the
Treadway Commission.
Based
on
that
evaluation,
management
concluded
that
Cameco
Corporation’s
internal
control
over
financial reporting was effective as of December 31,
2022.
(d)
Attestation
report
of
the
registered
public
accounting
firm
.
The
effectiveness
of
Cameco
Corporation’s internal
control over financial
reporting as
of December 31,
2022 was
audited by KPMG
LLP,
an independent
registered public
accounting firm,
as stated
in its
report, which
accompanies the
Cameco
2022
Consolidated
Audited
Financial
Statements
that
is
filed
as
Exhibit 99.2
to
this
Annual
Report on Form 40-
F.
4
(e)
Changes
in
internal
control
over
financial
reporting
.
During
the
fiscal
year
ended
December 31,
2022, there was no significant change in
Cameco Corporation’s internal control
over financial reporting
that has
materially affected,
or is
reasonably likely
to materially
affect,
Cameco Corporation’s
internal
control over financial reporting.
Audit & Finance
Committee Financial
Expert
.
Cameco Corporation’s
board of
directors has determined
that at
least one member of its audit and finance committee (the “audit committee”) is an audit committee financial expert.
The audit committee financial expert
is Daniel Camus. Mr.
Camus has been determined by Cameco
Corporation’s
board
of
directors
to
be
an
independent
director
as
such
term
is
defined
under
the
Canadian
Securities
Administrators’
National Instr
ument 52-110
(Audit Committees)
(“NI 52-110”)
,
the Commission’s
audit committee
independence
requirements,
and
the
rules
of
the
New
York
Stock
Exchange
(the
“NYSE”)
relating
to
the
independence of audit committee members.
Information concerning the relevant
experience of Mr.
Camus is included in his biographical
information contained
in Cameco Corporation’s Annual Information Form
that is filed as Exhibit 99.1 to this Annual Report on Form
40-F.
The Commission
has indicated
that the
designation
of a
person as
an audit
committee financial
expert does
not
make such person
an “expert”
for any purpose,
impose any
duties, obligations
or liability on
such person
that are
greater
than
those
imposed
on
members
of
the
audit
committee
and
board
of
directors
who
do
not
carry
this
designation, or affect the
duties, obligations or liability
of any other member of
the audit committee or
the board of
directors.
Code of
Ethics
.
Cameco Corporation’s code
of conduct and
ethics (the
“Code”) is applicable
to all
directors, officers
and
employees
of
Cameco
Corporation,
including
the
Company’s
principal
executive
officer,
principal
financial
officer and principal
accounting officer.
The Code, as
well as
Cameco Corporation’s corporate governance
practices
and mandates
of the
board of
directors
and
its committees,
and position
descriptions
for the
CEO and
the non-
executive chair, can be found on Cameco Corporation’s website at www.cameco.com under “About – Governance”
and are
also available
in print
to any
shareholder
upon request.
Since the
adoption of
the Code,
there have
not
been
any
waivers,
including
implied
waivers,
from
any
provision
of
the
Code.
In
2022,
Cameco
Corporation
amended
its
previously
filed
Code
and
made
non-substantive
changes,
including
the
addition
of
information
on
psychological safety;
diversity,
equity and
inclusion; human
rights; and
compliance with
sanctions.
Except as
set
forth in this
Annual Report on
Form 40-F, the information on the
Company’s website is not
part of this
Annual Report
on Form 40-
F.
The
Code
was
furnished
to
the
Commission
on
January
13,
2023
as
Exhibit
1
to
a
report
on
Form
6-K
and
is
incorporated by reference herein as Exhibit 99.17.
Principal
Accountant
Fees
and
Services
.
Our
independent
registered
public
accounting
firm
is
KPMG LLP
,
Saskatoon, Saskatchewan, Canada
, Auditor Firm ID:
85
. See Exhibit 99.4.
Off-Balance
Sheet Arrangements
.
In the
normal course
of operations,
Cameco Corporation
enters into
certain
transactions that
are not
required to
be recorded
on its
balance sheet.
These activities include
the issuing
of financial
assurances
and long-term
product purchase
contracts. These
activities are
disclosed in
the following
sections
of
Exhibit 99.3
– 2022
Management’s
Discussion
and Analysis
and
the notes
to the
financial
statements
in Exhibit
99.2 – 2022 Consolidated Audited Financial Statements:
(a)
Financial assurances
. In the 2022 Management’s Discussion and Analysis, see the disclosure at “Off-
balance sheet
arrangements”
(page 54).
In the
2022 Consolidated
Audited Financial
Statements, see
the disclosure at notes 16 and 26 of the financial statements.
(b)
Long-term product purchase contracts
. In the 2022 Management’s Discussion and
Analysis, see the
disclosure at “Off-balance sheet arrangements” (page
54).
(c)
Other arrangements
. In the 2022
Management’s Discussion
and Analysis, see
the disclosure at
“Off-
balance sheet
arrangements” (page
54). In
the 2022
Consolidated Audited
Financial Statements,
see
the disclosure at notes 14 and 15
of the financial statements.
5
Tabular
Disclosure
of
Contractual
Obligations
.
In
the
2022
Management’s
Discussion
and
Analysis,
see
the
disclosures at “Financing Activities” (pages 53 and
54) and “Off-balance sheet arrangements”
(page 54).
Identification
of
the
Audit
Committee.
Cameco
Corporation
has
a
separately-designated
standing
audit
committee established
in accordance
with Section
3(a)(58)(A)
of the
Exchange Act.
Cameco Corporation’s
audit
committee
is
comprised
of:
Daniel
Camus
(chair),
Ian
Bruce,
Catherine
Gignac,
Jim
Gowans
and
Leontine
van
Leeuwen-Atkins.
Audited Annual Financial Statements
.
The report of the independent registered public accounting firm
relating to
Cameco Corporation’s Consolidated Audited
Financial Statements as of December
31, 2022 and 2021 is included
in Exhibit 99.2 – 2022 Consolidated Audited Financial
Statements.
Mine Safety Disclosure
.
Neither Cameco Corporation
nor any of
its subsidiaries
is the “operator”
of any “coal
or
other mine”, as those terms
are defined in section 3 of
the Federal Mine Safety and Health
Act of 1977 (30 U.S.C.
802),
that
is
subject
to
the
provisions
of
such
Act
(30
U.S.C.
801
et
seq.).
Therefore,
the
provisions
of
Section
1503(a) of the Dodd-Frank Wall
Street Reform and Consumer
Protection Act and Item 16 of
General Instruction B
to Form
40-F requiring
disclosure concerning
mine safety
violations and
other regulatory
matters do
not apply
to
Cameco Corporation or any of its subsidiaries or U.S.
mines.
Disclosure Regarding Foreign Jurisdictions That Prevent
Inspections.
Not Applicable
.
Disclosure Pursuant to the Requirements of the New
York Stock Exchange
.
(a)
Corporate
governance
practices
.
Disclosure
of
the
significant
ways
in
which
Cameco
Corporation’s
corporate governance
practices differ
from those
required for
U.S. companies
under the
New York
Stock
Exchange (“NYSE”) listing standards can be found
on Cameco Corporation’s website at www.cameco.com
under “About – Governance.”
(b)
Presiding director at meetings of
non-management directors
. Cameco Corporation schedules regular
director sessions
in which
Cameco Corporation’s
“non-management
directors” (as
that term
is defined
in
the rules
of the
NYSE) meet
without management
participation. Mr.
Ian Bruce,
as non-executive
chair of
Cameco Corporation, serves
as the presiding director
(the “Presiding Director”)
at such sessions. Each
of
Cameco Corporation’s non-management directors is “independent” as such term is used in the rules of the
NYSE.
Cameco
Corporation’s
criteria
for
director
independence
are
available
on
Cameco
Corporation’s
website at www.cameco.com
under “About – Governance.”
(c)
Communication with non-management directors
. Shareholders may send communications
to Cameco
Corporation’s Presiding Director
or non-management directors
by mailing (by regular
mail or other means
of delivery)
to the
corporate head
office at
2121 –
11
th
Street West,
Saskatoon, Saskatchewan,
Canada,
S7M 1J3, in a sealed envelope
marked “Private and Strictly
Confidential – Attention: Chair of
the Board of
Directors of Cameco Corporation”. Any such envelope will be delivered unopened to
the Presiding Director
for appropriate
action. The
status of
all outstanding
concerns addressed
to the
Presiding Director
will be
reported to the board of directors as appropriate.
(d)
Corporate governance guidelines
. According to Section 303A.09 of the
NYSE Listed Company Manual,
a listed
company must adopt
and disclose
a set
of corporate governance
guidelines with
respect to
specified
topics. Such
guidelines and
the charters
of the
listed company’s
most important
committees of
the board
of
directors
are
required
to
be
posted
on
the
listed
company’s
website
and
be
available
in
to
any
shareholder upon request. Cameco
Corporation operates under corporate
governance guidelines that are
consistent
with
the
requirements
of
Section
303A.09
of
the
NYSE
Listed
Company
Manual.
Cameco
Corporation’s
corporate
governance guidelines
and the
charters of
its most
important committees
of the
board
of
directors
can
be
found
at
Cameco
Corporation’s
website
at
www.cameco.com
under
“About
–
Governance” and are available in print to any shareholder who
requests them.
6
(e)
Independent directors
. The names
of Cameco Corporation’s
non-management directors
are: Ian Bruce,
Daniel
Camus,
Donald
Deranger,
Catherine
Gignac,
Jim Gowans,
Kathryn
Jackson,
Don Kayne
and
Leontine van
Leeuwen-Atkins.
Each of
the non-management
directors
is “independent”,
as such
term is
used in the rules of the NYSE.
7
EXHIBIT INDEX
Exhibit No.
Description
99.1
99.2
2022 Consolidated Audited Financial Statements
99.3
2022 Management’s Discussion and Analysis
99.4
Principal Accountant Fees and Services
99.5
Consent of Independent Registered Public Accounting Firm
99.6
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d 14(a) of the U.S.
Securities Exchange Act of 1934, as amended
99.7
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d 14(a) of the U.S.
Securities Exchange Act of 1934, as amended
99.8
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of
99.9
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of
99.10
Consent of Alain D. Renaud, P. Geo.
99.11
Consent of Biman Bharadwaj, P. Eng.
99.12
Consent of Scott Bishop, P. Eng.
99.13
Consent of Lloyd Rowson, P. Eng.
99.14
Consent of Gregory M. Murdock, P. Eng.
99.15
Consent of Sergey Ivanov, P. Geo.
99.16
Consent of Daley McIntyre, P. Eng.
99.17
Code of Conduct and Ethics (as amended and restated as of July 2022) (incorporated by
reference to Cameco Corporation’s Form 6-K, furnished to the Commission on January 13,
101
Interactive Data File (formatted as Inline XBRL)
104
Cover Page Interactive Data File (formatted as Inline
XBRL and contained in Exhibit 101)
8
UNDERTAKING AND
CONSENT TO SERVICE OF PROCESS
Undertaking
Registrant undertakes to
make available, in
person or by
telephone, representatives
to respond to
inquiries made
by the
Commission staff,
and to
furnish promptly,
when requested
to do
so by
the Commission
staff,
information
relating to: the
securities registered
pursuant to
Form 40-F; the
securities in
relation to
which the obligation
to file
an Annual Report on Form 40-F arises; or transactions
in said securities.
Consent to Service of Process
Registrant has previously
filed a
Form F-X in
connection with the
class of
securities in relation
to which
the obligation
to file this Annual Report on Form 40-F arises.
Any
change
to
the
name
or
address
of
the
agent
for
service
of
process
of
Registrant
shall
be
communicated
promptly
to
the
Commission
by
an
amendment
to
the
Form
F-X
referencing
the
file
number
of
the
relevant
registration statement.
SIGNATURES
Pursuant to the requirements of the Exchange Act, Registrant certifies that it meets all of the requirements for filing
on Form 40-F and
has duly caused this
Annual Report to be
signed on its behalf
by the undersigned, thereto
duly
authorized.
DATED this 29
th
day of March,
2023.
CAMECO CORPORATION
By:
/s/ Grant Isaac
Name: Grant Isaac
Title:
Executive Vice-President and
Chief Financial Officer
EX-99.1
EXHIBIT 99.1
Cameco Corporation
2022 Annual Information Form
March 29, 2023
Cameco Corporation
2022 Annual information form
March 29, 2023
Contents
| Important information about this document | 1 |
|---|---|
| Our business | 5 |
| Our vision, values and strategy | 10 |
| Operations, projects and other nuclear fuel cycle investments | 24 |
| Uranium – Tier-one operations | 25 |
| Uranium – Tier-two operations | 69 |
| Uranium – Advanced projects | 70 |
| Uranium – exploration | 72 |
| Fuel services | 73 |
| Other nuclear fuel cycle investments | 75 |
| Corporate development | 78 |
| Mineral reserves and resources | 78 |
| Our ESG principles and practices | 84 |
| The regulatory environment | 87 |
| Risks that can affect our business | 98 |
| 1 – Operational risks | 98 |
| 2 – Financial risks | 104 |
| 3 – Governance and compliance risks | 110 |
| 4 – Social risks | 112 |
| 5 – Environmental risks | 113 |
| 6 – Strategic risks | 114 |
| Legal proceedings | 126 |
| Investor information | 126 |
| Governance | 132 |
| Appendix A | 137 |
Important information about this document
This annual information form (AIF) for the year ended December 31, 2022 provides important information about Cameco Corporation. It describes our history, our markets, our operations and projects, our mineral reserves and resources, our approach to environmental, social and governance matters (ESG), our regulatory environment, the risks we face in our business and the market for our shares, among other things.
It also incorporates by reference:
| • our management’s discussion and analysis for the year ended<br>December 31, 2022 (2022 MD&A), which is available on SEDAR (sedar.com) and on EDGAR (sec.gov) as an exhibit to our Annual Report on Form 40-F; and | Throughout this document, the terms we, us, our, the company and Cameco mean Cameco Corporation and its subsidiaries. |
|---|---|
| • Our audited<br>consolidated financial statements for the year ended December 31, 2022 (2022 financial statements), which are also available on SEDAR and on EDGAR as an exhibit to our Annual Report on Form<br>40-F. |
We have prepared this document to meet the requirements of Canadian securities laws, which are different from what United States (US) securities laws require.
The information contained in this AIF is presented as at December 31, 2022, the last day of our most recently completed financial year, and is based on what we knew as of March 15, 2023, except as otherwise stated.
Reporting currency and financialinformation
Unless we have specified otherwise, all dollar amounts are in Canadian dollars. Any references to $(US) mean US dollars.
The financial information in this AIF has been presented in accordance with International Financial Reporting Standards (IFRS).
Caution about forward-looking information
Our AIF and the documents incorporated by reference include statements and information about our expectations for the future. When we discuss our strategy, plans and 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 US securities laws. We refer to them in this AIF as forward-looking information. In particular, the discussions under the headings Market overview and developments, Building a balanced portfolio, and Other nuclear fuel cycle investments – Proposed acquisition of Westinghouse in this AIF contain forward-looking information.
Key things to understand about the forward-looking information in this AIF:
| • | 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 on page 2). |
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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 below, which may prove to<br>be incorrect. |
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| • | Actual results and events may be significantly different from what we currently expect, due to the risks<br>associated with our business. We list a number of these material risks below. We recommend you also review other parts of this document, including Risks that can affect our business starting on page 98, and our 2022 MD&A, which includes a<br>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 Canadian or US securities laws.
2022 ANNUAL INFORMATION FORM Page 1
Examples of forward-looking information in this AIF
| • | our view that we have the strengths to take advantage of the world’s rising demand for safe, reliable, affordable, and carbon-free energy, and our vision to energize a<br>clean-air world |
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| • | our expectations about 2023 and future global uranium supply, consumption, contracting, demand, geopolitical issues and the market, including the discussion under the headings Market overview and developmentsand Building a balanced portfolio |
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| • | our expectations about 2023 and future consumption of conversion services |
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| • | our efforts to participate in the commercialization and deployment of small modular reactors (SMRs) and contribute to the mitigation of global climate change and help to provide energy security and affordability by<br>exploring SMRs and other emerging opportunities within the fuel cycle |
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| • | our expectation that the US Department of Energy (DOE) will make available a portion of its excess uranium inventory over the next two decades |
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| • | the discussion under the heading Our ESG principles and practices, including our belief there is a significant opportunity for us to be part of the solution to combat climate change and that we are well<br>positioned to deliver significant long-term business value |
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| • | our ability to implement and execute our overarching low-carbon transition strategy |
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| • | our expectations relating to care and maintenance costs |
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| • | the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute |
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| • | our expectations for future tax payments and rates, including effective tax rates |
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| • | our expectations of executing major supply contracts |
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| • | our ability to capitalize on the current backlog of long-term contracting as a proven and reliable supplier with tier-one productive capacity and a record of honouring supply<br>commitments, and to increase value throughout these price cycles |
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| • | future plans and expectations for our uranium properties, advanced projects, and fuel services operating sites, including production levels and the suspension of production at certain properties, pace of advancement and<br>expansion capacity, and carbon reduction targets |
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| • | estimates of operating and capital costs and mine life for our tier one uranium operations |
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| • | our expectations in receiving positive re-licensing decisions from the Canadian Nuclear Safety Commission (CNSC) for McArthur River and Rabbit Lake |
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| • | our ability to successfully negotiate a new collective agreement for the unionized employees at McArthur River |
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| • | estimated decommissioning and reclamation costs for uranium properties and fuel services operating sites |
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| • | the discussion of Joint Venture Inkai LLP’s (JV Inkai) expansion plans for a 10.4 million pound per year operation (100% basis) |
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| • | our mineral reserve and resource estimates |
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| • | our expectations that the price of uranium, production costs, and recovery rates will allow us to operate or develop a particular site or sites |
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| • | estimates of metallurgical recovery and other production parameters for each uranium property |
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| • | production estimates at the McArthur River/Key Lake, Cigar Lake and Inkai operations, and the Port Hope UF6 conversion facility |
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| • | our discussion of the ongoing conflict between Russia and Ukraine |
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| • | our investments allowing us to participate in the entire nuclear fuel value chain; fuel fabrication; reactor maintenance; development of new reactors; and nuclear sustainability services |
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| • | the discussion of our expectations relating to our acquisition of a 49% interest in Westinghouse Electric Company (Westinghouse), including the sources and uses of financing for the acquisition, the timeline of the<br>acquisition, including the anticipated closing thereof, and the acquisition organizational structure, equity accounting for our investment, generation of new revenue opportunities, the potential to generate additional revenue in the year<br>following the acquisition closing, our expectation that the acquisition will be accretive to our cash flow after closing, Westinghouse’s ability to generate cash flow to fund its approved annual operating budget and provide quarterly<br>distributions to the partners after closing, the acquisition expanding our participation in the nuclear fuel value chain, and providing a platform for further growth, our intention in respect of not issuing additional equity to fund our portion of<br>the purchase price for the Westinghouse acquisition and various factors and drivers for Westinghouse’s business segments |
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2022 ANNUAL INFORMATION FORM Page 2
Material risks
| • | actual sales volumes or market prices for any of our products or services are lower than we expect, or cost of sales is higher than we expect, for any reason, including changes in market prices, loss of market share to<br>a competitor, trade restrictions, geopolitical issues or the impact of the COVID-19 pandemic |
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| • | we are adversely affected by changes in currency exchange rates, interest rates, royalty rates, tax rates or inflation |
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| • | our production costs are higher than planned, or necessary supplies are not available, delayed or not available on commercially reasonable terms |
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| • | our strategies may change, be unsuccessful or have unanticipated consequences, or we may not be able to achieve anticipated operational flexibility and efficiency |
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| • | changing views of governments regarding the pursuit of carbon reduction strategies or our view may prove to be inaccurate on the role of nuclear power in pursuit of those strategies |
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| • | our estimates and forecasts prove to be inaccurate, including production, purchases, deliveries, cash flow, revenue, costs, decommissioning, reclamation expenses, or receipt of future dividends from JV Inkai, and those<br>relating to the Westinghouse acquisition |
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| • | we are unable to enforce our legal rights under our agreements, permits or licences |
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| • | disruption or delay in the transportation of our products |
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| • | we are subject to litigation or arbitration that has an adverse outcome |
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| • | that we may not receive expected refunds and payments from CRA |
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| • | that the courts may accept the same, similar or different positions and arguments advanced by CRA to reach decisions that are adverse to us for other tax years |
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| • | the possibility of a materially different outcome in disputes with CRA for other tax years |
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| • | that CRA does not agree that the court rulings for the years that have been resolved in our favour should apply to subsequent tax years |
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| • | that CRA will not return all or substantially all of the cash and security that has been paid or otherwise secured in a timely manner, or at all |
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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 unexpected or challenging geological, hydrological, or mining conditions |
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| • | we are affected by environmental, safety and regulatory risks, including workforce health and safety or increased regulatory burdens or delays resulting from the COVID-19 pandemic<br>or other causes |
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| • | operations are disrupted due to problems with our own or our suppliers’ or customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment<br>failure, cyber-attacks, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, fires, underground floods, cave-ins, ground movements, tailings dam failures, transportation<br>disruptions or accidents, aging infrastructure, or other development and operating risks |
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| • | we are affected by political risks, including unrest in Kazakhstan, and geopolitical events, including the Russian invasion of Ukraine |
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| • | we are affected by war, terrorism, sabotage, blockades, civil unrest, social or political activism, outbreak of illness (such as a pandemic like COVID-19), accident or a<br>deterioration in political support for, or demand for, nuclear energy |
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| • | a major accident or incident at a nuclear power plant |
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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<br>uranium |
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| • | government laws, regulations, policies, or decisions that adversely affect us, including tax and trade laws and sanctions on nuclear fuel exports and imports |
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| • | our uranium suppliers or purchasers fail to fulfil their commitments |
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| • | our McArthur River development, mining or production plans are delayed or do not succeed for any reason, including due to labour disruption |
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| • | our Key Lake mill production plan is delayed or does not succeed for any reason, including due to labour disruption |
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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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| • | the McClean Lake’s mill production plan is delayed or does not succeed for any reason |
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| • | our production plans for our Port Hope UF6 conversion facility do not succeed for any reason |
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| • | water quality and environmental concerns could result in a potential deferral of production and additional capital and operating expenses required for the Cigar Lake operation and McArthur River/Key Lake operations |
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| • | JV Inkai’s development, mining or production plans are delayed or do not succeed for any reason or JV Inkai is unable to transport and deliver its production |
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2022 ANNUAL INFORMATION FORM Page 3
| • | necessary permits or approvals from government authorities cannot be obtained or maintained |
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| • | the Westinghouse acquisition may be delayed or may not be completed on the terms in the acquisition agreement or at all |
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| • | consummation of the Westinghouse acquisition is subject to closing conditions and regulatory approvals that may not be satisfied on a timely basis or at all |
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| • | that we may not realize the expected benefits from the Westinghouse acquisition |
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| • | after closing the acquisition, Westinghouse fails to generate sufficient cash flow to fund its approved annual operating budget or make quarterly distributions to the partners |
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| • | we may be unsuccessful in pursuing innovation or implementing advanced technologies, including the risk that the commercialization and deployment of SMRs or new enrichment technology may incur unanticipated delays or<br>expenses, or ultimately prove to be unsuccessful |
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| • | our expectations relating to care and maintenance costs prove to be inaccurate |
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| • | we are affected by climate change or natural phenomena, including inclement weather, forest fires, flood, and earthquakes |
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Material assumptions
| • | our expectations regarding sales and purchase volumes and prices for uranium and fuel services, cost of sales, trade restrictions, inflation, and that counterparties to our sales and purchase agreements will honour<br>their commitments |
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| • | our expectations for the nuclear industry, including its growth profile, market conditions, geopolitical issues, and the demand for and supply of uranium |
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| • | our ability to adopt innovative and advanced digital and automation technologies to improve efficiency and operational flexibility |
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| • | the continuing pursuit of carbon reduction strategies and greenhouse gas emissions strategies by governments and the role of nuclear in the pursuit of those strategies |
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| • | our expectations regarding spot prices and realized prices for uranium |
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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<br>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 Cigar Lake, McArthur River/Key Lake, JV Inkai and our fuel services operating sites |
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| • | plans to transport our products succeed, including the shipment of our share of JV Inkai production to our Blind River refinery |
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| • | our ability to mitigate adverse consequences of delays in the shipment of our share of JV Inkai production to our Blind River refinery |
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| • | our cost expectations, including production costs, operating costs, and capital costs, |
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| • | our expectations regarding tax rates and payments, royalty rates, currency exchange rates, interest rates and inflation |
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| • | our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, climate change, natural disasters, forest or other fires,<br>outbreak of illness (such as a pandemic like COVID-19), governmental, political or regulatory actions, litigation or arbitration proceedings, cyber-attacks, the unavailability of reagents, equipment, operating<br>parts and supplies critical to production, supply chain issues, labour shortages, labour relations issues, strikes or lockouts, health and safety issues, underground floods, loadings to the environment, cave —ins, ground movements,<br>tailings dam failure, lack of tailings capacity, improper air emissions releases or treated water releases, transportation disruptions or accidents, aging infrastructure, or other development or operating risks |
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| • | JV Inkai’s ability to abide by the provisions of the subsoil code, ecological code, and Currency Law (as defined in this document under the heading Currency Control Regulation) |
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| • | our Cigar Lake and McArthur River development, mining and production plans succeed |
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| • | our Key Lake mill production plan succeeds |
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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, and that JV Inkai will be able to deliver its production |
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| • | the ability of JV Inkai to pay dividends |
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| • | our production plan for our Port Hope UF6 conversion facility succeeds |
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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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| • | our entitlement to and ability to receive expected refunds and payments from CRA in our dispute with CRA, that courts will reach consistent decisions for other tax years that are based upon similar positions and<br>arguments |
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| • | that CRA will not successfully advance different positions and arguments that may lead to different outcomes for other tax years |
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| • | our expectation that we will recover all or substantially all of the amounts paid or secured in respect of the CRA dispute to date |
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| • | our decommissioning and reclamation estimates, including the assumptions upon which they are based, are reliable |
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| • | our ability to select mine designs and mining methods which mitigate hydrological, radiological and geotechnical risks |
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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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| • | the Westinghouse acquisition is closed on the anticipated timeline and on the terms in the acquisition agreement |
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| • | Westinghouse’s ability to generate cash flow and fund its approved annual operating budget and make quarterly distributions to the partners after closing of the acquisition |
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| • | our ability to compete for additional business opportunities so as to generate additional revenue for us in the year after closing the Westinghouse acquisition |
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| • | market conditions and other factors upon which we based the Westinghouse acquisition and our related forecasts will be as expected |
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| • | the success of our plans and strategies relating to the Westinghouse acquisition |
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Our business
| Our vision is to energize a clean-air world. We have a more than 30-year proven track record of providing secure and reliable nuclear fuel supplies to a<br>global customer base to generate safe, reliable, and affordable carbon-free energy. Nuclear energy plants around the world use our uranium products to generate one of the cleanest sources of electricity<br>available today. | Cameco Corporation<br> <br><br><br><br>2121 – 11^th^ Street West<br><br><br>Saskatoon, Saskatchewan<br> <br>Canada S7M 1J3<br><br><br>Telephone: 306.956.6200<br> <br><br><br><br>This is our head office, registered office and principal place of business.<br> <br><br><br><br>We are publicly listed on the Toronto and New York stock exchanges, and had a total of 2,424 employees at December 31, 2022. |
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| Our operations span the nuclear fuel cycle from exploration to fuel<br>services, which include uranium production, refining, UO2 and UF6 conversion services and CANDU fuel manufacturing for heavy water<br>reactors. To meet our customers’ growing demand for nuclear fuel supplies and services that are reliable and secure, we have also made investments, that if successful, we expect will allow us to participate in the entire nuclear fuel value<br>chain, adding capabilities in enrichment; fuel fabrication for light water reactors; reactor maintenance and other services; the design, engineering, and support for the development of new reactors; and nuclear sustainability services. |
With extraordinary assets, a proven operating track record, long-term contract portfolio, strong ESG commitment, employee expertise, comprehensive industry knowledge, and a strong balance sheet, the company is making investments that it expects will create a platform for strategic growth. We are confident in our ability to increase long-term growth by positioning the company as one of the global leaders in supporting the clean energy transition at a time when the world’s prioritization of decarbonization and energy security is driving growth in demand and when geopolitics are creating concerns about the origin and security of supplies across the nuclear fuel cycle.
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Business segments
URANIUM
| Our uranium production capacity is among the world’s largest. However, in 2022, with many of our operations in care and maintenance, we<br>accounted for about 12% **** of world production. We have controlling ownership of the world’s largest high-grade mineral reserves.<br> <br><br><br><br>Product<br> <br><br><br><br>• uranium concentrates (U3O8)<br> <br><br> <br>Mineral reserves andresources<br> <br><br> <br>Mineral reserves<br><br><br><br> <br>• approximately<br>469 million pounds proven and probable<br> <br><br> <br>Mineral resources<br><br><br><br> <br>• approximately<br>451 million pounds measured and indicated<br> <br><br><br><br>• approximately 154 million pounds inferred | Tier-one operations<br> <br><br><br><br>• McArthur River and Key Lake, Saskatchewan<br><br><br><br> <br>• Cigar Lake, Saskatchewan<br><br><br><br> <br>• Inkai, Kazakhstan<br><br><br><br> <br>Tier-two operations<br><br><br><br> <br>• Rabbit Lake, Saskatchewan<br><br><br><br> <br>• Smith Ranch-Highland,<br>Wyoming<br> <br><br> <br>• Crow Butte,<br>Nebraska<br> <br><br> <br>Advanced projects<br><br><br><br> <br>• Millennium, Saskatchewan<br><br><br><br> <br>• Yeelirrie, Australia<br><br><br><br> <br>• Kintyre, Australia<br><br><br><br> <br>Exploration<br><br><br><br> <br>• focused on North America<br><br><br><br> <br>• approximately<br>0.78 million hectares of land |
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FUEL SERVICES
| We are an integrated uranium fuel supplier, offering refining, conversion, and fuel manufacturing services.<br><br><br><br> <br>Products<br> <br><br><br><br>• uranium trioxide (UO3)<br><br><br><br> <br>• uranium hexafluoride (UF6) for light-water reactors (we have about 21% of world primary conversion capacity)<br> <br><br><br><br>• uranium dioxide (UO2) for CANDU<br>heavy-water reactors<br> <br><br> <br>• fuel<br>bundles, reactor components and monitoring equipment used by CANDU heavy-water reactors | Operations<br> <br><br><br><br>• Blind River refinery, Ontario (refines uranium concentrates to UO3)<br> <br><br><br><br>• Port Hope conversion facility, Ontario (converts UO3 to UF6 or UO2)<br><br><br><br> <br>• Cameco Fuel Manufacturing<br>Inc. (CFM), Ontario (manufactures fuel bundles and reactor components for CANDU heavy-water reactors) |
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For information about our revenue and gross profit by business segment for the years ended December 31, 2022 and 2021, see our 2022 MD&A as follows:
| • | uranium – page 57 |
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| • | fuel services – page **** 59 |
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OTHER NUCLEAR FUEL CYCLE INVESTMENTS
Enrichment
We have a 49% interest in Global Laser Enrichment LLC (GLE) which is testing third-generation enrichment technology that, if successful, will use lasers to commercially enrich uranium. GLE is the exclusive licensee of the proprietary SILEX laser enrichment technology, that is in the development phase.
Westinghouse Electric Company (Westinghouse)
In October 2022, we announced the planned acquisition of a 49% interest in Westinghouse, a global provider of mission critical and specialized technologies, products, and services for light-water reactors across most phases of the nuclear power sector. The planned acquisition is through a strategic partnership with Brookfield Renewable. The acquisition is expected to close in the second half of 2023 and is subject to customary closing conditions and certain regulatory approvals.
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The nuclear fuel cycle
Our operations and investments span the nuclear fuel cycle, from exploration to fuel manufacturing.
| 1 | Mining |
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Once an orebody is discovered and defined by exploration, there are three common ways to mine uranium, depending on the depth of the orebody and the deposit’s geological characteristics:
| • | Open pit mining is used if the ore is near the surface. The ore is usually mined using drilling and blasting. |
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| • | Underground mining is used if the ore is too deep to make open pit mining economical. Tunnels and shafts provide access to the ore. |
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| • | In situ recovery (ISR) does not require large scale excavation. Instead, holes are drilled into the ore and a solution is used to dissolve the uranium. The solution is pumped to the surface where the uranium is<br>recovered. |
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| 1 | Milling |
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Ore from open pit and underground mines is processed to extract the uranium and package it as a powder typically referred to as uraniumore concentrates (UOC) or yellowcake (U3O8). The leftover processed rock and other solid waste (tailings) is placed in an engineered tailings facility.
| 2 | Refining |
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Refining removes the impurities from the uranium concentrate and changes its chemical form to uranium trioxide (UO3).
| 3 | Conversion |
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For light water reactors, the UO3 is converted to uranium hexafluoride (UF6) gas to prepare it for enrichment. For heavy water reactors like the CANDU reactor, the UO3 is converted into powdered uraniumdioxide (UO2).
| 4 | Enrichment |
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Uranium is made up of two main isotopes: U-238 and U-235. Only U-235 atoms, which make up 0.7% of natural uranium, are involved in the nuclear reaction (fission). Most of the world’s commercial nuclear reactors require uranium that has an enriched level of U-235 atoms.
The enrichment process increases the concentration of U-235 to between 3% and 5% by separating U-235 atoms from the U-238. Enriched UF6 gas is then converted to powdered UO2.
| 5 | Fuel manufacturing |
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Natural or enriched UO2 is pressed into pellets, which are baked at a high temperature. These are packed into zircaloy or stainless steel tubes, sealed and then assembled into fuel bundles.
| 6 | Generation |
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Nuclear reactors are used to generate electricity. U-235 atoms in the reactor fuel fission, creating heat that generates steam to drive turbines. The fuel bundles in the reactor need to be replaced as the U-235 atoms are depleted, typically after one or two years depending upon the reactor type. The used – or spent – fuel is stored or reprocessed.
Spent fuel management
The majority of spent fuel is safely stored at the reactor site. A small amount of spent fuel is reprocessed. The reprocessed fuel is used in some European and Japanese reactors.
2022 ANNUAL INFORMATION FORM Page 7
Major developments
| 2020 | 2021 | 2022 |
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| March<br> <br><br><br><br>• We announce the temporary suspension of production at Cigar Lake as a precautionary measure due to<br>the threat posed by the COVID-19 pandemic.<br> <br><br><br><br>April<br> <br><br><br><br>• We announce temporary operational changes at our fuel services division as a precautionary measure<br>due to the challenge of maintaining an adequate workforce due to the COVID-19 pandemic.<br> <br><br><br><br>• We extend the temporary Cigar Lake production suspension and withdraw our 2020 outlook.<br><br><br><br> <br>May<br> <br><br><br><br>• We announce resumption of production at our Port Hope UF6 plant and the Blind River refinery, and the continued Cigar Lake mine production suspension.<br> <br><br><br><br>June<br> <br><br><br><br>• We announce that the Federal Court of Appeal upheld the 2018 decision of the Tax Court of Canada<br>in Cameco’s favour for the 2003, 2005 and 2006 tax years.<br> <br><br> <br>September<br><br><br><br> <br>• We resume production at Cigar<br>Lake.<br> <br><br> <br>October<br><br><br><br> <br>• We issue $400 million of<br>debentures, bearing interest at 2.95%, maturing in 2027.<br> <br><br><br><br>• We receive notification and announce that CRA has sought leave from the Supreme Court of Canada to<br>appeal the June 2020 decision of the Federal Court of Appeal.<br> <br><br> <br>November<br><br><br><br> <br>• We redeem $400 million<br>of debentures, bearing interest at 3.75%, maturing in 2022.<br> <br><br> <br>December<br><br><br><br> <br>• We announce a second<br>temporary suspension of production at Cigar Lake as a precautionary measure due to the increasing risks posed by the COVID-19 pandemic. | January<br> <br><br><br><br>• We announce the closing of the agreement between Cameco, Silex Systems Limited and GE-Hitachi Nuclear Energy, completing the ownership restructuring of GLE with Cameco’s interest in GLE increasing from 24% to 49%.<br> <br><br><br><br>February<br> <br><br><br><br>• We announce the Supreme Court of Canada dismissed CRA’s application for leave to appeal the<br>June 26, 2020 decision of the Federal Court of Appeal with respect to the 2003, 2005 and 2006 tax years.<br> <br><br><br><br>April<br> <br><br><br><br>• We announce plans to restart production at the Cigar Lake mine.<br><br><br><br> <br>October<br> <br><br><br><br>• We file a notice of appeal with the Tax Court of Canada, asking it to order the reversal of<br>CRA’s transfer pricing adjustment and the return of $777 million in cash and letters of credit we paid or secured for the tax years 2007 through 2013, with costs. | January<br> <br><br><br><br>• We announce plans to transition McArthur River and Key Lake from care and maintenance to planned<br>production of 15 million pounds per year (100% basis) by 2024, 40% below its annual licensed capacity, and to reduce production at Cigar Lake in 2024 to 13.5 million pounds per year (100% basis), 25% below its annual licensed capacity<br>starting in 2024.<br> <br><br> <br>May<br><br><br><br> <br>• We acquire an additional<br>4.522 percentage points in Cigar Lake increasing our interest to 54.547%.<br> <br><br><br><br>October<br> <br><br><br><br>• We announce our plans to form a strategic partnership with Brookfield Renewable Partners L.P.,<br>together with its institutional partners (Brookfield Renewable), to acquire Westinghouse, a global provider of nuclear services, from Brookfield Business Partners L.P. and its institutional partners. Brookfield Renewable will own a 51% interest and<br>we will own a 49% interest in Westinghouse. We are responsible to contribute approximately <br>$2.2 billion (US) in respect of the acquisition. The acquisition is subject to closing conditions, including regulatory approvals, and it is<br>anticipated to be completed in the second half of 2023.<br> <br><br><br><br>• We issue 34,057,250 common shares at a price of $21.95 (US) per share for gross proceeds to us of<br>approximately $747.6 million (US) pursuant to a bought deal. The net offering proceeds are intended to partially fund our share of the acquisition of Westinghouse.<br> <br><br><br><br>November<br> <br><br><br><br>• We announce that the first pounds of uranium ore from the McArthur River mine have now been milled<br>and packaged at the Key Lake mill, marking the achievement of initial production as these facilities transition back into normal operations. |
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Updated 2024 Production Plan for McArthur Rive/Key Lake and Cigar Lake
In February 2023, we announced our plan will now be for McArthur River/Key Lake to produce 18 million pounds per year (100% basis) starting in 2024 and to continue to operate Cigar Lake at its licensed capacity of 18 million pounds per year (100% basis) in 2024.
Agreement on Key Supply Terms withEnergoatom
In February 2023, we announced we had reached agreement on commercial terms for a major supply contract with SE NNEGC Energoatom (Energoatom), Ukraine’s state-owned utility and that the agreement was subject to contract finalization. The agreement was finalized and signed in March 2023.
The 12-year agreement will run from 2024 through 2035. The agreement will see Cameco supply 100% of Energoatom’s UF6 requirements (consisting of uranium and conversion services) for the nine nuclear reactors at the Rivne, Khmelytskyy and South Ukraine nuclear power plants. These plants have combined requirements over the contract term of approximately 15.3 million KgU as UF6 (the equivalent of around 40.1 million pounds of uranium concentrate, or U3O8).
The contract will also contain an option for Cameco to supply up to 100% of the fuel requirements for the six reactors at the Zaporizhzhya nuclear power plant, currently under Russian control, should it return to Energoatom’s operation. If this option was exercised in 2024, the Zaporizhzhya power plant would require roughly 10.4 million KgU as UF6 the equivalent of around 27.2 million pounds of uranium concentrate, or U3O8) over the contract period.
Cameco to ReceiveSubstantial Refund of $300 Million from Canada Revenue Agency
On March 27, 2023, we announced that CRA issued revised reassessments for the 2007 through 2013 tax years that will result in a refund of approximately $300 million of the $780 million in cash and letters of credit being held by CRA. The refund will consist of $89 million in cash and $211 million in letters of credit. The timing of the refund is yet to be determined. Notwithstanding this pending refund, our broader tax dispute with CRA remains ongoing. CRA continues to hold $480 million ($206 million in cash and $274 million in letters of credit) that Cameco has remitted or secured to date. See The Regulatory Environment – Taxes and Royalties.
How Cameco was formed
Cameco was incorporated under the Canada Business Corporations Act on June 19, 1987.
We were formed when two crown corporations were privatized and their assets merged:
| • | Saskatchewan Mining Development Corporation (SMDC) (uranium mining and milling operations); and<br> |
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| • | Eldorado Nuclear Limited (uranium mining, refining and conversion operations) (now Canada Eldor Inc.)<br> |
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There are constraints and restrictions on ownership of shares in the capital of Cameco (Cameco shares) set out in our company articles, and a related requirement to maintain offices in Saskatchewan. These are requirements of the Eldorado Nuclear Limited Reorganization and Divestiture Act (Canada), as amended, and The Saskatchewan Mining Development CorporationReorganization Act, as amended, and are described on pages 128 and 129.
We have made the following amendments to our articles:
| 2002 | • increased the maximum share ownership for individual non-residents to 15%<br>from 5%<br> <br><br> <br>• increased the<br>limit on voting rights of non-residents to 25% from 20% |
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| 2003 | • allowed the board to appoint new directors between shareholder meetings<br>as permitted by the Canada Business Corporations Act, subject to certain limitations<br> <br><br><br><br>• eliminated the requirement for the chair of the board to be ordinarily resident in the province of<br>Saskatchewan |
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| We have one main subsidiary:<br> <br><br><br><br>• Cameco Europe Ltd., a Swiss company that we have 100% ownership of through subsidiaries<br><br><br><br> <br>At January 1, 2023, we do not have any other subsidiary that is material, either<br>individually or collectively. | For more information<br> <br><br><br><br>You can find more information about Cameco on SEDAR (sedar.com), EDGAR (sec.gov) and on our website (cameco.com).<br><br><br><br> <br>See our most recent management proxy circular for additional information, including how<br>our directors and officers are compensated and any loans to them, principal holders of our securities, and securities authorized for issue under our equity compensation plans. We expect the circular for our May 10, 2023 annual meeting of<br>shareholders to be available on April 6, 2023.<br> <br><br> <br>See our 2022 financial<br>statements and 2022 MD&A for additional financial information. |
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Our vision, values and strategy
Our vision
Our vision – “Energizing a clean-air world” – recognizes that we have an important role to play in enabling the vast reductions in global GHG emissions required to achieve a resilient net-zero carbon economy. We support climate action that is consistent with the ambition of the Paris Agreement and the Canadian government’s commitment to the agreement to limit global temperature rise to less than 2°C and we believe that this means the world needs to reach net-zero emissions by 2050 or sooner. The uranium we produce is used around the world in the generation of safe, carbon-free, affordable, base-load nuclear power.
We believe we have the right strategy to achieve our vision and we will do so in a manner that reflects our values. For over 30 years, we have been delivering our products responsibly. Building on that strong foundation, we remain committed to our efforts to transform our own, already low, greenhouse gas footprint in our ambition to reach net-zero emissions, while identifying and addressing the ESG risks and opportunities that we believe may have a significant impact on our ability to add long-term value for our stakeholders.
Committed to our values
Our values are discussed below. They define who we are as a company and are at the core of everything we do and help to embed ESG principles and practices as we execute on our strategy in pursuit of our vision. They are:
| • | safety and environment |
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| • | people |
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| • | integrity |
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| • | excellence |
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Safety and Environment
The safety of people and protection of the environment are the foundations of our work. All of us share in the responsibility of continually improving the safety of our workplace and the quality of our environment.
We are committed to keeping people safe and conducting our business with respect and care for both the local and global environment.
People
We value the contribution of every employee and we treat people fairly by demonstrating our respect for individual dignity, creativity and cultural diversity. By being open and honest, we achieve the strong relationships we seek.
We are committed to developing and supporting a flexible, skilled, stable and diverse workforce, in an environment that:
| • | attracts and retains talented people and inspires them to be fully productive and engaged |
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| • | encourages relationships that build the trust, credibility and support we need to grow our business<br> |
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Integrity
Through personal and professional integrity, we lead by example, earn trust, honour our commitments and conduct our business ethically.
We are committed to acting with integrity in every area of our business, wherever we operate.
Excellence
We pursue excellence in all that we do. Through leadership, collaboration and innovation, we strive to achieve our full potential and inspire others to reach theirs.
Our strategy
We are a pure-play investment in the growing demand for nuclear energy. We are focused on providing nuclear fuel products and services across the fuel cycle to support the generation of clean, reliable, secure and affordable energy, and we are focused on taking advantage of the long-term growth we see coming in our industry. Our strategy is set within the context of what we believe is a transitioning market environment, where increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are expected to durably strengthen the long-term fundamentals for our industry. Nuclear energy must be a central part of the solution to the world’s shift to a low-carbon, climate resilient economy. It is an option that can provide the power needed, not only reliably, but also safely and affordably, and in a way that will help avoid some of the worst consequences of climate change.
Our strategy is to capture full-cycle value by:
| • | remaining disciplined in our contracting activity, building a balanced portfolio in accordance with our<br>contracting framework |
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| • | profitably producing from our tier-one assets and aligning our production<br>decisions in all segments of our business with our contract portfolio and customer needs |
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| • | being financially disciplined to allow us to execute on our strategy, take advantage of strategic opportunities<br>and to self-manage risk |
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| • | exploring other emerging and non-traditional opportunities within the<br>fuel cycle, which align with our commitment to responsibly and sustainably manage our business, contribute to the mitigation of global climate change, and help to provide energy security and affordability |
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We expect our strategy will allow us to increase long-term value, and we will execute it with an emphasis on safety, people and the environment.
For more information on our strategy, see our 2022 MD&A.
Market overview and developments
A market intransition
In 2022, geopolitical events coupled with the ongoing focus on the climate crisis created what we believe are transformative tailwinds for the nuclear power industry from both a demand and supply perspective. Uranium prices continued to rise, reaching levels not seen since 2011 driven by a tightened uranium market and growing security of supply concerns. In early-January, unrest in Kazakhstan raised concerns about the more than 40% of global uranium supply that originates from Kazakhstan. However, it was the Russian invasion of Ukraine in late-February that was the most transformative event for our industry. We believe it has set in motion a geopolitical realignment in energy markets that is highlighting the increasingly important role for nuclear power not just in providing clean energy, but also providing secure and affordable energy. And, with the global nuclear industry reliant on Russian supplies for approximately 14% of uranium concentrates, 27% of conversion and 39% of enrichment, it is highlighting the security of supply risk associated with the growing primary supply gap and shrinking secondary supplies and increasing the focus on origin of supply.
With the heightened supply risk caused by geopolitical uncertainty, utilities are evaluating their nuclear fuel supply chains. Utilities continue to be focused on ensuring they have the conversion and enrichment services they require secured under long-term contracts and are now beginning to return their focus to uranium. The uncertainty about where nuclear fuel supplies will come from to satisfy growing demand led to increased long-term contracting activity in 2022. This contracting activity resulted in a 22% increase in the long-term price of uranium over the past year, conversion prices that are at historic highs, and enrichment prices that have increased over 210% since the start of the invasion of Ukraine. Notably, utilities are now approaching replacement rate contracting for the first time in over a decade. Therefore, we expect there will be continued
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competition to secure uranium, conversion and enrichment services under long-term contracts with proven producers and assets in geopolitically attractive jurisdictions, with strong environmental, social and governance (ESG) performance and on terms that will ensure the availability of reliable supply to satisfy demand.
Durable demand growth
The benefits of nuclear energy have come clearly into focus with a durability we believe has not been previously seen. The durability is being driven not only by accountability for achieving the net-zero carbon targets set by countries and companies around the world, but also by a geopolitical realignment that is causing countries to reexamine how they approach their energy needs. Net-zero carbon targets are turning attention to a triple challenge. First, is to lift one-third of the global population out of energy poverty by growing clean and reliable baseload electricity. Second, is to replace 85% of the current global electricity grids that run on carbon-emitting sources of thermal power with a clean, reliable alternative. And finally, is to grow global power grids by electrifying industries, such as private and commercial transportation, home, and industrial heating, largely powered with carbon-emitting sources of thermal energy today. Additionally, the Russian invasion of Ukraine has deepened the energy crisis experienced in some parts of the world and amplified concerns about energy security, highlighting the role of energy policy in balancing three main objectives: providing a clean emissions profile; providing a reliable and secure baseload profile; and providing an affordable levelized cost profile. There is increasing recognition that nuclear power meets these objectives and has a key role to play in achieving decarbonization goals. The growth in demand is not just long-term in the form of new builds, it is medium-term demand in the form of reactor life extensions, and it is near-term growth as early reactor retirements are prevented and new markets continue to emerge. And we are seeing momentum building for non-traditional commercial uses of nuclear power around the world such as development of small modular reactors and advanced reactors, with numerous companies and countries pursuing projects.
Demand and energy policy highlights
| • | China announced plans to accelerate new nuclear projects to combat future electricity shortages, indicating it<br>could raise the number of new reactor construction approvals to ten or more per year. In 2022, there were ten approvals. |
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| • | In December 2022, Japan announced a new plan to maximize nuclear power by restarting as many existing reactors as<br>possible, prolonging the operating lives of aging reactors beyond a 60-year limit, and building new reactors. This followed an earlier pledge by Japan’s Prime Minister Kishida to have up to 17 reactors<br>restarted by the summer of 2023. Additionally, the Japanese government set a target for nuclear to make up 20% to 22% of the country’s energy mix by the end of the decade, and under the new policy will push for the development and construction<br>of “next-generation innovative reactors” to replace about 20 reactors now set for decommissioning. |
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| • | South Korea finalized their 10^th^ Basic Plan for Electricity<br>Supply and Demand in January 2023. The plan aims to maintain 30% of the country’s 2030 energy mix as nuclear power, resume construction on Units 3 and 4 at the Shin Hanul nuclear plant, and sets a goal of exporting 10 nuclear power plants by<br>2030, as well as the development of a Korean small modular reactor (SMR). This positive news builds from the earlier 2022 announcements that included nuclear power in South Korea’s green taxonomy and reversed the previous administration’s<br>anti-nuclear stance. |
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| • | In July 2022, the European Parliament voted to keep nuclear power in the European Union’s sustainable<br>finance taxonomy as a transitional “green” investment. The Complimentary Delegated Act from this vote was entered into application on January 1, 2023. Including nuclear power in the “transitional” category indicates that it<br>will help mitigate climate change but cannot yet be replaced by economically and technologically feasible low-carbon alternatives. |
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| • | Following the Russian invasion of Ukraine, numerous European countries announced their intention to reduce<br>reliance on Russian-supplied nuclear fuel under long-term contracts. For example, on June 2, 2022, Ukraine’s state-owned utility, Energoatom, signed an agreement with Westinghouse to supply all its nuclear fuel and increase the number of<br>planned AP1000 reactor new builds from five to nine. Numerous other countries have also taken steps to diversify their nuclear fuel supply. |
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| • | In Sweden, a newly elected coalition majority government immediately updated the country’s energy policy to<br>be more pro-nuclear. They cited a significant shift away from the previous focus on renewables, changing the previous goal of “100% renewable” electricity by 2040 to “100% fossil free<br>electricity”, and have put forward legislation to allow for the construction of more reactors. |
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| • | Belgium shut down its Doel-3 nuclear reactor in September, but in January<br>announced 10-year life extensions for their two newest reactors, Doel 4 and Tihange 3. These reactors were set to close in 2025 but will now restart in November 2026 after the necessary preparation and will<br>continue operating for 10 years. |
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| • | Chancellor Olaf Scholz has ordered the life extension of Germany’s three remaining reactors until mid-April 2023, keeping them on stand-by due to energy concerns. |
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| • | In November 2022, the United Kingdom (UK) announced that it would take a joint stake alongside French partner<br>Électricité de France (EDF) in the construction of its new Sizewell C nuclear power station, replacing China General Nuclear’s 20% stake. The UK will invest £700 million in the project, which will be matched by EDF.<br> |
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| • | In France, the government and regulator are working on conditions to extend the operating lives of existing<br>reactors and are planning an “industrial build” program with the start of construction around 2028 for the first two of six new EPR reactors and with plans for eight additional EPRs in the future. In addition, France is finalizing<br>increased ownership in EDF from 84% to 100% to provide a smooth energy transition, ensure sovereignty in the face of war and firm up the company’s diminished financial situation. |
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| • | In Finland, Teollisuuden Voima Oyj announced Olkiluoto 3, the 1,600 Mwe EPR, resumed test electricity production<br>in December 2022 following a few months delay with regular electricity production now scheduled to start in March 2023. |
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| • | Poland confirmed its intent to build nuclear power capacity for the first time and is progressing plans with both<br>Westinghouse for AP1000 PWR’s and Korea Hydro & Nuclear Power (KHNP) for APR 1400’s. |
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| • | Egypt began construction on the first two of four Russian built VVER 1200 reactors at the El-Dabaa Power Plant as the government looks to accelerate the project. Additionally, in December 2022, Egypt announced plans to start mining uranium in 2024 as part of the country’s rapidly developing program<br>for peaceful use of nuclear energy. |
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| • | India’s first domestically designed 700 Mwe pressurized heavy water reactor at Kakrapar is now in commercial<br>operation, an important milestone for the country. Three more units of this design are expected to come online in the next few years. The country is targeting an expansion to have 22.5 Gwe operating by 2031. |
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| • | In August 2022, President Biden signed the Inflation Reduction Act of 2022 (IRA) into law. Through<br>$369 billion (US) in tax incentives and other investments, IRA is a major federal legislative initiative enacted to address climate change. The IRA includes significant support for nuclear power with the establishment of a Production Tax Credit<br>to support existing nuclear reactors and provides $700 million (US) to incentivize the development of domestic sources of high-assay low-enriched uranium. Additionally, in December 2022, the International<br>Nuclear Energy Act passed a US Senate Committee vote and is expected to be reintroduced to Congress. The bill seeks to promote engagement with partner and ally nations to develop a civil nuclear export strategy, establish financing relationships,<br>standardize licensing frameworks, and is designed to offset the influence of Russia and China in the international nuclear market. This support comes in addition to ongoing work at various levels of the US government to eliminate US dependence on<br>nuclear fuel imports from Russia. |
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| • | In the US state of California, Governor Newsom signed a bill seeking to extend operations at the Diablo Canyon<br>Power Plant for five years beyond its current licence, which expires in 2025. |
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| • | Southern Company announced fuel loading began in October 2022 for Vogtle unit 3, the first of two 1,250 Mwe<br>AP1000’s under construction in Georgia. Southern Company also confirmed its plans to apply to have the operating licences for its Farley and Hatch reactors extended to 80 years. This followed similar announced extensions for Tennessee Valley<br>Authority’s Browns Ferry reactor, Xcel Energy’s Monticello reactor, and Dominion Energy’s Virgil C. Summer reactor. |
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| • | Mexico’s Laguna Verde nuclear plant has been granted 30-year<br>operating life extensions for its two units. |
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| • | In Canada, Ontario Power Generation (OPG) announced plans to extend the life of the Pickering nuclear power plant<br>until at least 2026 and potentially up to 30 years. In addition, OPG signed an agreement with X-energy to examine deploying their Xe-100 SMR. Finally, OPG issued a<br>$300 million Green Bond, a first-of-its-kind for the company and part of its commitment to be net zero by 2040. The funds<br>are to be used to finance the refurbishment activities at its Darlington site, where life extensions to four units are in progress, as well as for maintenance of existing nuclear facilities. |
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| • | In October 2022, OPG completed a significant project milestone by submitting an application for a Licence to<br>Construct to the CNSC. This licence application is the next step in the deployment of a SMR at the Darlington site. The submission comes after the beginning of site preparation activities earlier in 2022, which was another significant milestone.<br> |
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| • | In late 2022, Bruce Power achieved a major milestone in the refurbishment of Unit 6, as project teams<br>successfully installed the CANDU reactor’s fuel channel assembly, which puts the project on track to return to operation in 2023. Additionally, the Unit 3 refurbishment campaign is scheduled to begin in March 2023. |
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| • | Sprott Physical Uranium Trust (SPUT) purchased about 17 million pounds U3O8 in 2022, bringing total purchases since inception to over 41 million pounds<br>U3O8. The challenging equity markets in recent months have contributed to SPUT shares trading at a discount to net asset value, impacting<br>its ability to raise funds to purchase uranium. |
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According to the International Atomic Energy Agency, globally there are currently 439 operable reactors and 57 reactors under construction. Several nations are appreciating the clean energy and energy security benefits of nuclear power. They have
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reaffirmed their commitment to it and are developing plans to support existing reactor units and are reviewing their policies to encourage more nuclear capacity. Several other non-nuclear countries have emerged as candidates for new nuclear capacity. In the EU, specific nuclear energy projects have been identified for inclusion under its sustainable financing taxonomy and therefore eligible for access to low-cost financing. Even in countries where phase-out policies were in place, there have been policy reversals and decisions to, at a minimum, temporarily keep reactors running, with public opinion polls showing growing support for it. With a number of reactor construction projects recently approved, and many more planned, the demand for uranium continues to improve. There is growing recognition of the role nuclear must play in providing safe, affordable, carbon free- baseload electricity that achieves a low-carbon economy while being a reliable energy source to help countries diversify away from Russian energy supply.
Supply uncertainty
In addition to low uranium prices, government-driven trade policies, the COVID-19 pandemic, and ongoing supply chain challenges, the most notable factor impacting security of supply in 2022 was geopolitical uncertainty. The geopolitical uncertainty, driven by the Russian invasion of Ukraine, has led many governments and utilities to re-examine supply chains and procurement strategies that are reliant on nuclear fuel supplies coming out of Russia. In addition, sanctions on Russia, government restrictions, and restrictions on and cancellations of some cargo insurance coverage are creating transportation and further supply chain risks for fuel supplies coming out of Central Asia. Despite the recent increase in uranium prices, years of underinvestment in new capacity and the deepening geopolitical uncertainty has shifted risk from producers to utilities.
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Supply and trade policy highlights
| • | In November 2022, Cameco announced that the first pounds of uranium ore from the McArthur River mine had been<br>milled and packaged at the Key Lake mill, marking the achievement of initial production as the facilities transition back into normal operations. |
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| • | In early January 2022, Kazakhstan saw the most significant political instability since it became independent in<br>1991. The events resulted in a state of emergency being declared across the country. Order was restored in the second half of January, and the state of emergency was gradually lifted. In November 2022, President Tokayev was re-elected for a new 7-year term. |
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| • | Kazatomprom (KAP) announced in August 2022 its plan to produce 10% below its total Subsoil Use Contracts level in<br>2024. This plan was expected to result in increased production in Kazakhstan of about 5 million to 8 million pounds U3O8<br>compared to the current 20% reduction, bringing total expected annual uranium production to about 65 million pounds in 2024. KAP stated the decision was based on its contracting progress but that it may still face significant challenges to<br>increase above current production levels due to the state of global supply chains. In January 2023, KAP’s operational update showed lower expected production in 2023 due to wellfield development, procurement and supply chain issues, resulting<br>in forecasted production of between 53.3 million and 55.9 million pounds, compared to between 58.5 million and 59.8 million pounds previously. |
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| • | KATCO, the joint venture between Orano Mining (Orano) and KAP, was granted a new mining permit for a parcel of<br>the Muyunkum uranium deposit in Kazakhstan bringing total estimated uranium reserves to about 120 million pounds U3O8. The full<br>production level of about 10.4 million pounds U3O8 is planned for 2026 at the earliest. |
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| • | Orano announced plans to increase its enrichment production capacity by 30%, which could involve an expansion of<br>the Georges-Besse II plant located in Tricastin, France. The cost of the project is estimated at $970M (US) and could increase the capacity at its Georges Besse II plant to 11 million separative work units (SWU) from 7.5 million SWU.<br> |
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| • | GLE made progress with the first full-scale laser system module, successfully completing eight months of testing<br>in Australia. The system, which was developed by Silex Systems Ltd for deployment in GLE’s commercial pilot demonstration facility has been delivered to GLE’s facility in the US. Additionally, GLE signed letters of intent (LOI) to<br>collaborate with two major US utilities to help diversify a portion of the US nuclear fuel supply chain, including measures to support its deployment of laser enrichment technology in the US. |
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| • | In June, Boss Energy Limited (Boss) finalized their decision to develop the Honeymoon Uranium Project in South<br>Australia. Boss intends to accelerate construction and is projecting Honeymoon will have first production in the fourth quarter of 2023, ramping up to 2.45 million pounds U3O8 production per year within three years. |
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| • | ConverDyn’s parent, Honeywell, is planning for a 2023 restart of its UF6 conversion facility in Illinois. |
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Long-term contracting creates full-cycle valuefor proven productive assets
Like other commodities, the demand for uranium is cyclical. However, unlike other commodities, uranium is not traded in meaningful quantities on a commodity exchange. The uranium market is principally based on bilaterally negotiated long-term contracts covering the annual run-rate requirements of nuclear power plants, with a small spot market to serve discretionary demand. History demonstrates that in general, when prices are rising and high, uranium is perceived as scarce, and more contracting activity takes place with proven and reliable suppliers. The higher demand discovered during this contracting cycle drives investment in higher-cost sources of production, which due to lengthy development timelines, tend to miss the contracting cycle and ramp up after demand has already been won by proven producers. The new uncommitted supply exposed to the small, discretionary spot market puts downward pressure on price and can create the perception that uranium is abundant, potentially resulting in a failure of long-term price signals. When prices are declining and low, there is no perceived urgency to contract, and contracting activity and investment in new supply dramatically decreases. After years of low prices, and a lack of investment in supply, and as the uncommitted material available in the spot market begins to thin, security-of-supply tends to overtake price concerns. Utilities typically re-enter the long-term contracting market to ensure they have a reliable future supply of uranium to run their reactors.
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UxC reports that over the last five years approximately 430 million pounds U3O8 equivalent have been locked-up in the long-term market, while approximately 775 million pounds U3O8 equivalent have been consumed in reactors. We remain confident that utilities have a growing gap to fill.
We believe the current backlog of long-term contracting presents a substantial opportunity for proven and reliable suppliers with tier-one productive capacity and a record of honouring supply commitments. As a low-cost producer, we manage our operations to increase value throughout these price cycles.
In our industry, customers do not come to the market right before they need to load nuclear fuel into their reactors. To operate a reactor that could run for more than 60 years, natural uranium and the downstream services have to be purchased years in advance, allowing time for a number of processing steps before a finished fuel bundle arrives at the power plant. At present, we believe there is a significant amount of uranium that needs to be contracted to keep reactors running into the next decade.
UxC estimates that cumulative uncovered requirements are about 2.3 billion pounds to the end of 2040. With the lack of investment over the past decade, there is growing uncertainty about where uranium will come from to satisfy growing demand, and utilities are becoming increasingly concerned about the availability of material to meet their long-term needs. In addition, secondary supplies have diminished, and the material available in the spot market has thinned as producers and financial funds continue to purchase material. Furthermore, the Russian invasion of Ukraine in February has given rise to a geopolitical realignment in energy markets that is causing some utilities to seek nuclear fuel suppliers whose values are aligned with their own or whose origin of supply better protects them from potential interruptions, including from transportation challenges or the possible imposition of formal sanctions.
We will continue to take the actions we believe are necessary to position the company for long-term success. Therefore, we will continue to align our production decisions with our customers’ needs under our contract portfolio. We will undertake
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contracting activity which is intended to ensure we have adequate protection while maintaining exposure to the benefits that come from having uncommitted, low-cost supply to place into a strengthening market.
Building a balanced portfolio
The purpose of our contracting framework is to deliver value. Our approach is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that optimizes our realized price.
Contracting decisions in all segments of our business need to consider the nuclear fuel market structure, the nature of our competitors, and the current market environment. The vast majority of run-rate fuel requirements are procured under long-term contracts. The spot market is thinly-traded where utilities buy small, discretionary volumes. This market structure is reflective of the baseload nature of nuclear power and the relatively small proportion of the overall operating costs the fuel represents compared to other sources of baseload electricity. Additionally, about half of the fuel supply typically comes from diversified mining companies that produce uranium as a by-product, or by state-owned entities with production volume strategies or ambitions to serve state nuclear power ambitions with low-cost fuel supplies. We evaluate our strategy in the context of our market environment and continue to adjust our actions in accordance with our contracting framework:
| • | First, we build a long-term contract portfolio by layering in volumes over time. In addition to our committed<br>sales, we will compete for end-user demand in the market where we think we can obtain value and, in general, as part of longer-term contracts. We will take advantage of opportunities the market provides, where<br>it makes sense from an economic, logistical, diversification 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<br>committed sales. |
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| • | Once we have built a portfolio of long-term contracts, we decide how to best source material to satisfy that<br>demand, planning our production in accordance with our contract portfolio and other available sources of supply. We will not produce from our tier-one assets to sell into an oversupplied spot market.<br> |
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| • | We do not intend to build an inventory of excess uranium. Excess inventory serves to contribute to the sense that<br>uranium is abundant and creates an overhang on the market, and it ties up working capital on our balance sheet. |
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| • | Depending on the timing and volume of our production, purchase commitments, and our inventory volumes, this means<br>we may be active buyers in the market in order to meet our annual delivery commitments. Historically, prior to the supply curtailments that we began in 2016, we have generally planned our annual delivery commitments to slightly exceed the annual<br>supply we expect to come from our annual production and our purchase commitments and have therefore relied on the spot market to meet a small portion of our delivery commitments. In general, if we choose to purchase material to meet demand, we<br>expect the cost of that material will be more than offset by the volume of commitments in our sales portfolio that are exposed to market prices at the time of delivery over the long-term. |
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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, our goal is to protect and extend the value of our contract portfolio on terms that recognize the value of our assets and pricing mechanisms that provide adequate protection when prices go down and exposure to rising prices. We believe using this framework will allow us to create long-term value. Our focus will continue to be on ensuring we have the financial capacity to execute our strategy and self-manage risk.
Long-term contracting
Uranium is not traded in meaningful quantities on a commodity exchange. Utilities have historically bought the majority of their uranium and fuel services products under long-term contracts that are bilaterally negotiated with suppliers. The spot market is discretionary and typically used for one-time volumes, not to satisfy annual demand. We sell uranium and fuel products and services directly to nuclear utilities around the world as uranium concentrates, UO2 and UF6, conversion services, or fuel fabrication and reactor components for CANDU heavy water reactors. We have a solid portfolio of long-term sales contracts that reflect our reputation as a proven, reliable supplier of geographically stable supply, and the long-term relationships we have built with our customers.
In general, we are active in the market, buying and selling uranium when it is beneficial for us and in support of our long-term contract portfolio. We undertake activity in the spot and term markets prudently, looking at the prices and other business factors to decide whether it is appropriate to purchase or sell into the spot or term market. Not only is this activity a source of profit, but it also gives us insight into underlying market fundamentals.
2022 ANNUAL INFORMATION FORM Page 17
We deliver the majority of our uranium under long-term contracts each year, some of which are tied to market-related pricing mechanisms quoted at time of delivery. Therefore, our net earnings and operating cash flows are affected by changes in the uranium price. Market prices are influenced by the fundamentals of supply and demand, market access and trade policy issues, geopolitical events, disruptions in planned supply and demand, and other market factors.
The objectives of our contracting strategy are to:
| • | optimize realized price by balancing exposure to future market prices while providing some certainty for our<br>future earnings and cash flow |
|---|---|
| • | focus on meeting the nuclear industry’s growing annual uncovered requirements with our tier-one production |
| --- | --- |
| • | establish and grow market share with strategic and regionally diverse customers |
| --- | --- |
We have a portfolio of long-term contracts, each bilaterally negotiated with customers, that have a mix of base-escalated pricing and market-related pricing mechanisms, including provisions that provide exposure to rising market prices and also protect us when the market price is declining. This is a balanced and flexible approach that allows us to adapt to market conditions, put a floor on our average realized price and deliver the best value over the long term.
This approach has allowed our realized price to outperform the market during periods of weak uranium demand, and we expect it will enable us to realize increases linked to higher market prices in the future.
Base-escalated contracts foruranium (price at time of acceptance escalated over the term): use a pricing mechanism based on a term-price indicator at the time the contract is accepted and escalated to time of each delivery over the term of the contract.
Market-related contracts for uranium: are different from base-escalated contracts in that the pricing mechanism may be based on either the spot price or the long-term price, and that price is as quoted at the time of delivery rather than at the time the contract is accepted. These contracts may provide for discounts, and typically include floor prices and/or ceiling prices, which are fixed at time of contract acceptance and usually escalate over the term of the contract.
Fuel services contracts: the majority of our fuel services contracts use a base-escalated mechanism per kgU and reflect the market at the time the contract is accepted.
Optimizing our contract portfolio
We work with our customers to optimize the value of our contract portfolio. With respect to new contracting activity, there is often a lag from when contracting discussions begin and when contracts are executed. With our large pipeline of business under negotiation in our uranium segment, and a value driven strategy, we continue to be strategically patient in considering the commercial terms we are willing to accept. We layer in contracts over time, with higher commitments in the near term and declining over time in accordance with utilities growing uncovered requirements. Much of our pending business is off-market but we are starting to see more on-market activity emerge. We remain confident that we can add acceptable new sales commitments to our portfolio of long-term contracts to underpin the ongoing operation of our productive capacity and capture long-term value.
Given our view that additional long-term supply will need to be incented to meet the growing demand for safe, clean, reliable, carbon-free nuclear energy, our preference today is to sign long-term contracts with market-related pricing mechanisms. Unsurprisingly, we believe our customers too expect prices to rise and prefer to lock-in today’s prices, with a fixed-price mechanism. Our goal is to balance all these factors, along with our desire for customer and regional diversification, with product form, and logistical factors to ensure we have adequate protection and will have exposure to rising market prices under our contract portfolio, while maintaining the benefits that come from having low-cost supply to deliver into a strengthening market.
With respect to our existing contracts, at times we may also look for opportunities to optimize the value of our portfolio. In cases where there is a changing policy, operating, or economic environment, we may consider options that allow us to maintain our customer relationships and are mutually beneficial.
Contract portfolio status
We have commitments to sell approximately 180 million pounds of U3O8 with 34 customers worldwide in our uranium segment, and over 55 million kilograms as UF6 conversion with 31 customers worldwide in our fuel services segment.
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Customers – U3O8:
Five largest customers account for 56% of commitments
Customers – UF6 conversion:
Five largest customers account for 59% of commitments
Managing our contract commitments
We allow sales volumes to vary year-to-year depending on:
| • | the level of sales commitments in our long-term contract portfolio |
|---|---|
| • | market opportunities |
| --- | --- |
| • | our sources of supply |
| --- | --- |
To meet our delivery commitments and to mitigate risk, we have access to a number of sources of supply, which includes uranium obtained from:
| • | our productive capacity |
|---|---|
| • | purchases under our JV Inkai agreement, under long-term agreements and in the spot market |
| --- | --- |
| • | our inventory in excess of our working requirements |
| --- | --- |
| • | product loans |
| --- | --- |
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Our supply discipline
As spot is not the fundamental market, true value is built under a long-term contract portfolio and is measured over the full commodity cycle. Therefore, we align our uranium production decisions with our contract commitments and market opportunities to avoid carrying excess inventory or having to sell into an oversupplied spot market. In accordance with market conditions, and to mitigate risk, we evaluate the optimal mix of our production, inventory and purchases in order to satisfy our contractual commitments and in order to realize the best return over the entire commodity cycle. During a prolonged period of uncertainty, this could mean leaving our uranium in the ground. For the years 2016 through 2022, we left more than 130 million pounds of uranium in the ground (100% basis) by curtailing our production. We purchased more than 60 million pounds including spot and long-term purchases and in 2018 we drew down our inventory by almost 20 million pounds. That totals over 210 million pounds (100% basis) of uranium that were not available to the market.
However, today we believe we are in the early stages of a uranium market transition, driven by the growing demand for nuclear energy and the increasingly undeniable conclusion that it is essential to the clean-energy transition and to energy security. In our uranium segment, in 2022 we added 80 million pounds to our portfolio of long-term uranium contracts, about 58 million of which are finalized and 22 million pounds accepted with key commercial terms, such as pricing mechanism, volume, and tenor having been agreed to, but still awaiting contract finalization; and we have a large and growing pipeline of uranium business under discussion. As the market continues to transition, we expect to continue to place our uranium under long-term contracts and to meet rising demand with production from our best margin operations.
With the improvements in the market, the new long-term contracts we have put in place, and a pipeline of contracting discussions, we have decided to adjust our production plan for McArthur River/Key Lake to produce 18 million pounds (100% basis) starting in 2024, and we plan to continue to operate Cigar Lake at its licensed capacity of 18 million pounds per year (100% basis) in 2024. At Inkai, production will continue to follow the 20% reduction planned by KAP until the end of 2023.
With annual licensed capacity of 25 million pounds (100% basis) at McArthur River/Key Lake, we continue to have the ability to expand production from our existing assets, however some additional investment would be required. Any decision to expand production will be dependent on further improvements in the uranium market and our ability to secure the appropriate long-term contract homes for our unencumbered, in-ground inventory, demonstrating that we continue to responsibly manage our assets in accordance with our customers’ needs. In addition to our plans to expand uranium production, at our Port Hope UF6 conversion facility we are working on increasing production to 12,000 tonnes by 2024 to satisfy our book of long-term business for conversion services and customer demand, at a time when conversion prices are at historic highs.
Our adjusted production plans for McArthur River/Key Lake and Cigar Lake are expected to significantly improve our financial performance by allowing us to source more of our committed sales from the lower-cost produced pounds and we will no longer be required to expense care and maintenance or operational readiness costs related to McArthur River/Key Lake to cost of sales. In addition, with conversion demand elevated, we have been successful in securing long-term sales commitments that will support increased UF6 production at Port Hope, which is expected to further improve its contribution to our financial results. Over the course of 2023, we will undertake all of the activities necessary to ensure we are operationally ready to achieve the 2024 production plan. However, this is not an end to our supply discipline. We expect to continue to adjust our production in accordance with our contract portfolio. This will remain our production plan until we see further improvements in the uranium market and contracting progress, once again demonstrating that we are a responsible fuel supplier.
Managing our costs
Production costs
In order to operate efficiently and cost-effectively, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology, and business process improvements. Like all mining companies, our uranium segment is affected by the cost of inputs such as labour and fuel.
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| * | Production supplies include reagents, fuel and other items. Contracted services include utilities and camp<br>costs, air charters, mining and maintenance contractors and security and ground freight. |
|---|
Over the last number of years, the annual cash cost of production reflected the operating cost of mining and milling our share of Cigar Lake as this was our only operating site. With the restart of the McArthur River/Key Lake operations the annual cost of production will reflect a combined cost of all our operating uranium assets. See 2022 financial results by segment – Uranium starting on page 57 of our 2022 MD&A for more information. In 2023, our cash production costs may continue to be affected by inflation, the availability of personnel with the necessary skills and experience, supply chain challenges impacting the availability of materials and reagents, and our ability to ramp up to planned production at McArthur River/Key Lake.
Operating costs in our fuel services segment are mainly fixed. In 2022, labour accounted for about 51% of the total. The largest variable operating cost is for zirconium, followed by anhydrous hydrogen fluoride, and energy (natural gas and electricity).
We continue to look to adopt innovative and advanced digital and automation technologies to improve efficiency and operational flexibility, and to further reduce cost.
Care and maintenance costs andoperational readiness costs
In 2023, we expect to incur between $50 million and $60 million in care and maintenance costs related to the suspension of production at our Rabbit Lake mine and mill, and our US operations. These operations are higher-cost and a restart is less certain. We continue to evaluate our options in order to minimize these costs.
Purchases and inventory costs
Our costs are also affected by the purchases of uranium and conversion services we make under long-term contracts and on the spot market.
To meet our delivery commitments, we make use of our mined production, inventories, purchases under long-term contracts, purchases we make on the spot market and product loans. In 2023, the price for the majority of our purchases will be quoted at the time of delivery.
The cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions. The cost of purchased material affects our cost of sales, which is determined by calculating the average of all of our sources of supply, including opening inventory, production, and purchases, and adding royalties, selling costs, and care and maintenance costs. Our cost of sales could be impacted if we do not achieve our annual production plan, or we are unable to source uranium as planned, and we are required to purchase uranium at prices that differ from our cost of inventory.
Financial impact
The growing demand for nuclear power due to its safety, clean energy, reliability, security and affordability attributes has contributed to increased demand for nuclear fuel products and services. As a result, we have seen price increases across the nuclear fuel value chain, which reflect the need for capacity increases to satisfy the projected growth.
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The deliberate and disciplined actions we took to curtail production and streamline operations over the past decade came with near-term costs like care and maintenance costs, operational readiness costs, and purchase costs higher than our production costs. However, we considered these costs as investments in our future.
Today, thanks to our investments, and with our continued ability to secure new long-term sales commitments we believe we are well-positioned for growth. Our core growth is expected to come from our existing tier-one mining and fuel services assets. We do not have to build new capacity to pursue new opportunities. We currently have sufficient productive capacity to expand, a position we have not enjoyed in previous price cycles.
And, with the planned joint acquisition of Westinghouse, we expect to be able to expand our growth profile by extending our reach in the nuclear fuel cycle at a time when there are tremendous tailwinds for the nuclear power industry. We are extending our reach with an investment in assets, that like ours, are strategic, proven, licensed and permitted, that are located in geopolitically favourable jurisdictions, and that we expect will be able to grow from their existing footprint. These assets are also expected to provide new opportunities for our existing suite of uranium and fuel services assets.
We believe our actions and investments have helped position the company to self-manage risk and as we make the transition back to a tier-one run rate, we expect our financial performance to significantly improve, allowing us to execute on our strategy while rewarding our stakeholders for their continued patience and support of our strategy to build long-term value.
Supply sources
Uranium supply sources include primary production (production from mines that are currently in commercial operation) and secondary supply sources (excess inventories, uranium made available from defense stockpiles and the decommissioning of nuclear weapons, re-enriched depleted uranium tails, and used reactor fuel that has been reprocessed).
Primary production
While the uranium production industry is international in scope, there are only a small number of companies operating in relatively few countries. In addition, there are barriers to entry and bringing on and ramping up production can take a significant number of years. During the low-price environment that persisted for about a decade following 2011, a number of projects were cancelled or delayed, and some production was discontinued. While today’s uranium prices and contracting activity have supported the restart of some tier-one assets, they are not sufficient to encourage the restart of tier-two assets, or the investment in new mine development.
We estimate world mine production in 2022 was about 133 million pounds U3O8, up from 124 million pounds in 2021:
| • | About 85% of estimated world production came from five countries: Kazakhstan (42%), Canada (15%), Namibia (12%),<br>Australia (9%), and Uzbekistan (7%). |
|---|---|
| • | About 76% of estimated world production was attributable to five producers. We accounted for about 12%<br>(15 million pounds) of estimated world production in 2022. |
| --- | --- |
Secondary sources
There are a number of secondary sources, but most of these sources are finite and will not meet long-term needs:
| • | The US government has historically made some of its inventories available to the market, although in smaller and<br>predictable quantities. |
|---|---|
| • | The Russian government also holds substantial volumes of nuclear fuel inventory largely in the form of depleted<br>uranium, but overall, their contribution to secondary supplies has reduced significantly since the end of the HEU Agreement. |
| --- | --- |
| • | Utilities, mostly in Europe and some in Japan and Russia, use reprocessed uranium and plutonium from used reactor<br>fuel. |
| --- | --- |
| • | Re-enriched depleted uranium tails and uranium from underfeeding are also<br>generated when there is excess enrichment capacity. |
| --- | --- |
Uranium from US inventories
We expect a sizeable portion of the US Department of Energy (DOE) inventory will be available to the market over the next two decades, although a significant portion of the inventory requires either further processing or the development of commercial arrangements before it can be brought to market.
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DOE Excess Uranium Inventory Management Plan
Historically, the DOE was one of the primary sources of secondary supplies in the uranium market. This role has been significantly reduced since the suspension of the barter program of its natural UF6 inventory. DOE’s current primary contribution to secondary supplies is high-enriched uranium (HEU) downblending. The vast majority of the DOE’s inventory is large volumes of depleted uranium (DU).
In 2018, the DOE suspended its practice of bartering its excess uranium through 2019. The barter suspension has since been extended on an annual basis. The DOE has indicated a commitment to continue the suspension of the UF6 barter program. There is currently no available timetable to dispose of the remaining natural UF6 in DOE’s excess inventory, estimated at less than 9 million pounds.
Trade restraints and policies
The importation of Russian uranium into the US market is regulated by the amended USEC Privatization Act and by the Agreement Suspending the Antidumping Action against Russian Uranium Products (RSA), which together impose annual quotas on imports of Russian uranium. These quotas were set at the equivalent of 20% of annual US reactor demand and expired at the end of 2020. An amendment to the RSA was signed that extends the agreement from January 1, 2021 through December 31, 2040 and provides a clear set of rules around access to the US nuclear energy sector by Russian nuclear fuel suppliers. Since 1992, the importation of Russian uranium products in the US has been subject to a quota under the RSA. The amendment reduces the average overall quota and introduces caps, which will reduce the amount of Russian uranium, conversion and enrichment supplied to the US over the long-term. The amendment also includes important new provisions to ensure that all Russian origin uranium must be counted against the quota even if it is imported after further processing in other countries.
The US restrictions do not affect the sale of Russian uranium to other countries. A significant portion of world uranium demand is from utilities in countries that are not affected by the US restrictions. Utilities in some countries, however, adopt policies that limit the amount of Russian uranium they will buy. The Euratom Supply Agency in Europe must approve all uranium related contracts for members of the European Union (EU) and limits the use of certain nuclear fuel supplies from any one source to maintain security of supply, although these limits do not apply to uranium sold separately from enriched uranium product.
Since the Russian invasion of Ukraine on February 24, 2022, many jurisdictions have imposed strict economic sanctions against Russia, including Canada, the United States, the European Union, the United Kingdom, and others. The Canadian government has cancelled existing export permits to Russia and will not grant new export permits to Russia. The US government is yet to ban imports of Russian supplies, though a bill has been introduced in the US House of Representatives which proposes an immediate ban on Russian imports 90 days after enactment. However, the proposed bill allows for a waiver process which authorizes imports equal to but not exceeding volumes stipulated in the RSA. These waivers would expire on January 1, 2028, and no new Russian imports would be permitted thereafter. Trade sanctions will impact the flow of nuclear fuel supplies coming in and out of Russia, including supplies shipped through Russian ports. The global nuclear industry currently relies on Russia for approximately 14% of its supply of uranium concentrates, 27% of conversion supply, and 39% of enrichment capacity.
The US Congress approved an omnibus spending bill for 2021, providing nearly $1.5 billion (US) in spending for nuclear programs which notably included initial funding of $75 million (US) for the creation of a national uranium reserve. This allowed the US government to begin purchasing domestically produced uranium and UF6 to guard against potential commercial and national security risks as a result of the country’s near-total reliance on foreign imports. In 2022, contracts were awarded to five US uranium producers for 1.1 million pounds U3O8.
Conversion services
We have about 21% of world UF6 primary conversion capacity and supply UO2 for Canadian-made CANDU reactors. For conversion services, we compete with a small number of primary commercial suppliers to meet global demand. In addition, at times we compete with secondary supplies that come to market as UF6 and are described above.
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Operations, projects and other nuclear fuel cycle investments
Uranium
| Tier-one operations | |
|---|---|
| McArthur River mine/Key Lake mill | 25 |
| Cigar Lake | 40 |
| Inkai | 54 |
| Tier-two operations | |
| Rabbit Lake | 69 |
| US ISR Operations | 70 |
| Advanced projects | |
| Millennium | 71 |
| Yeelirrie | 71 |
| Kintyre | 71 |
| Exploration | 72 |
Fuel services
| Refining, conversion and fuel manufacturing | |
|---|---|
| Blind River Refinery | 73 |
| Port Hope Conversion Services | 74 |
| Cameco Fuel Manufacturing Inc. | 75 |
Other nuclear fuel cycle investments
| Global Laser Enrichment (GLE) | 75 |
|---|---|
| Proposed acquisition of Westinghouse | 76 |
| Corporate development | 78 |
| --- | --- |
Uranium production
| Cameco’s share<br><br><br>(million lbs U3O8) | 2021 | 2022 | 2023 Plan | ||||||
|---|---|---|---|---|---|---|---|---|---|
| McArthur River/Key Lake | — | ^1^ | 0.8 | ^3^ | 10.5 | ||||
| Cigar Lake | 6.1 | ^2^ | 9.6 | ^3^ | 9.8 | ||||
| Rabbit Lake | — | ^1^ | — | ^1^ | — | ^1^ | |||
| US ISR Operations | — | ^1^ | — | ^1^ | — | ^1^ | |||
| Total | 6.1 | 10.4 | 20.3 | ||||||
| ^1^ | The McArthur River/Key Lake operations began to restart in 2022, the Rabbit Lake operation remains in a state<br>of care and maintenance, and we are no longer developing new wellfields at US ISR Operations. | ||||||||
| --- | --- | ||||||||
| ^2^ | A production target was not set in 2021 until after production at Cigar Lake resumed following the proactive<br>four-month COVID-19 related suspension that started in December 2020. A production target of up to 6.0 million pounds (our share) was provided in our 2021 second quarter MD&A. | ||||||||
| --- | --- | ||||||||
| ^3^ | Cigar Lake was successful in catching up on development work that had been deferred from 2021, and the<br>production target was updated to 9.5 million pounds (our share) in our 2022 second quarter MD&A. The increase also reflected our increase in ownership at Cigar Lake. A production target of up to 1.4 million pounds (our share) from<br>McArthur River/Key Lake was provided in our 2022 second quarter MD&A due to commissioning delays at the mill. | ||||||||
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 24
We expect total production from Inkai to be 8.3 million pounds in 2023 on a 100% basis, assuming no production disruptions due to the COVID-19 pandemic, civil unrest, supply chain issues or other causes. Due to equity accounting, our share of production is shown as a purchase. An adjustment to the production purchase entitlement allows us to purchase 4.2 million pounds in 2023.
Uranium – Tier-one operations
McArthur River mine / Key Lake mill
| 2022 Production (our share) |
|---|
| 0.8M lbs |
| 2023 Production Outlook (our share) |
| 10.5M lbs |
| Estimated Reserves (our share) |
| 275.0M lbs |
| Estimated Mine Life |
| 2044 |
McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the world’s largest uranium mill. We are the operator of both the mine and mill.
McArthur River is considered a material uranium property for us. There is a technical report dated March 29, 2019 (effective December 31, 2018) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).
| Location | Saskatchewan, Canada | |
|---|---|---|
| Ownership | McArthur River – 69.805% | |
| Key Lake – 83.33% | ||
| Mine type | Underground | |
| Mining methods | Blasthole stoping, | |
| Raiseboring | ||
| End product | Uranium concentrate | |
| Certification | ISO 14001 certified | |
| Estimated reserves | 275.0 million pounds (proven and probable), average grade U3O8: 6.70% | |
| Estimated resources | 4.7 million pounds (measured and indicated), average grade U3O8: 2.23% | |
| 1.7 million pounds (inferred), average grade U3O8: 2.89% | ||
| Licensed capacity | Mine and mill: 25.0 million pounds per year | |
| Licence term | Through October 2023 | |
| Total packaged production: | 2000 to 2022 | 326.5 million pounds (McArthur River/Key Lake) (100% basis) |
| 1983 to 2002 | 209.8 million pounds (Key Lake) (100% basis) | |
| 2022 production | 0.8 million pounds (1.1 million pounds on 100% basis) | |
| 2023 production outlook | 10.5 million pounds (15.0 million pounds on 100% basis) | |
| Estimated decommissioning cost | $42 million – McArthur River (100% basis) | |
| $223 million – Key Lake (100% basis) |
All values shown, including reserves and resources, represent our share only, unless indicated.
2022 ANNUAL INFORMATION FORM Page 25
Business structure
| McArthur River is owned by a joint venture (MRJV) <br>between two companies: | Key Lake is owned by a joint venture between <br>the same two companies: |
|---|---|
| • Cameco – 69.805% (operator) | • Cameco – 83.333% (operator) |
| • Orano Canada Inc. (Orano) – 30.195% | • Orano – 16.667% |
History
| 1976 | • Canadian Kelvin Resources Ltd. and Asamera Oil Corporation Ltd. form an<br>exploration joint venture, which includes the lands that the McArthur River mine is situated on |
|---|---|
| 1977 | • SMDC, one of our predecessor companies, acquires a 50% interest |
| 1980 | • McArthur River joint venture is formed<br><br><br><br> <br>• SMDC becomes the operator<br><br><br><br> <br>• Active surface exploration<br>begins<br> <br><br> <br>• Between 1980 and<br>1988 SMDC reduces its interest to 43.991% |
| 1988 | • Eldorado Resources Limited merges with SMDC to form Cameco<br><br><br><br> <br>• We become the operator<br><br><br><br> <br>• Deposit discovered by surface<br>drilling |
| 1988-1992 | • Surface drilling reveals significant mineralization of potentially economic<br>uranium grades, in a 1,700 metre zone at depths of between 500 to 640 metres |
| 1992 | • We increase our interest to 53.991% |
| 1993 | • Underground exploration program receives government approval – program<br>consists of shaft sinking (completed in 1994) and underground development and drilling |
| 1995 | • We increase our interest to 55.844% |
| 1997-1998 | • Federal authorities issue construction licences for McArthur River after<br>reviewing the environmental impact statement, holding public hearings, and receiving approvals from the governments of Canada and Saskatchewan |
| 1998 | • We acquire all of the shares of Uranerz Exploration and Mining Ltd. (UEM),<br>increasing our interest to 83.766%<br> <br><br><br><br>• We sell half of the shares of UEM to Orano, reducing our interest to 69.805%, and increasing<br>Orano’s to 30.195% |
| 1999 | • Federal authorities issue the operating licence and provincial authorities<br>give operating approval, and mining begins in December |
| 2003 | • Production is temporarily suspended in April because of a water inflow<br><br><br><br> <br>• Mining resumes in<br>July |
| 2009 | • UEM distributes equally to its shareholders:<br><br><br><br> <br>• its 27.922% interest in the<br>McArthur River joint venture, giving us a 69.805% direct interest, and Orano a 30.195% direct interest<br> <br><br><br><br>• its 33.333% interest in the Key Lake joint venture, giving us an 83.33% direct interest, and Orano<br>a 16.667% direct interest |
| 2013 | • Federal authorities granted a 10-year<br>renewal of the McArthur River and Key Lake operating licences |
| 2014 | • After a two-week labour disruption, we<br>enter into a four-year collective agreement with unionized employees at McArthur River and Key Lake operations |
| 2017 | • We announce our plan to temporarily suspend production at McArthur River and<br>Key Lake in 2018 |
| 2018 | • We announce the suspension of production at McArthur River and Key Lake for an<br>indeterminate duration |
| 2022 | • We announce plans to transition McArthur River and Key Lake from care and<br>maintenance to planned production of 15 million pounds per year (100% basis) by 2024 |
| 2023 | • We updated our production plans for McArthur River and Key Lake to achieve<br>production of 18 million pounds per year (100% basis) starting in 2024 |
2022 ANNUAL INFORMATION FORM Page 26
Technical report
| This description is based on the project’s technical report: McArthur River Operation, Northern Saskatchewan, Canada, dated<br>March 29, 2019 (effective December 31, 2018). The report was prepared for us in accordance with Canadian National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), by or under the supervision of Linda Bray, P. Eng., Gregory M. Murdock, P. Eng., and Alain D. Renaud, P. Geo. The following description has been prepared under the supervision of Biman Bharadwaj, P. Eng.,<br>Daley McIntyre, P. Eng., Gregory M. Murdock, P. Eng., and Alain D. Renaud, P. Geo. They are all qualified persons within the meaning of NI 43-101 but are not independent of us.<br><br><br><br> <br>The conclusions, projections and estimates included in this description are subject to<br>the qualifications, assumptions and exclusions set out in the technical report. We recommend you read the technical report in its entirety to fully understand the project. You can download a copy from SEDAR (sedar.com) or from EDGAR<br>(sec.gov). | For information about uranium sales see pages 17 to 20, environmental matters see Our ESG principles and practices and Theregulatory environment starting on pages 84 and 87, and taxes see page 95.<br> <br><br> <br>For a<br>description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see page 94.<br> <br><br><br><br>For a description of risks that might affect access, title or the right or ability to perform work on the property, see Governance and compliance risks<br>starting at page 110, Social risks starting at page 112 and Environmental risks starting at page 113. |
|---|
About the McArthur River property
Location
The McArthur River mine site is located near Toby Lake, approximately 620 kilometres north of Saskatoon. The mine site is in close proximity to other uranium production operations: the Key Lake mill is 80 kilometres southwest by road and the Cigar Lake mine is 46 kilometres northeast by air.
Access
Access to the property is by an all-weather gravel road and by air. Supplies are transported by truck from Saskatoon and elsewhere. There is a 1.6-kilometre unpaved air strip and an air terminal one kilometre east of the mine site, on the surface lease.
Saskatoon, a major population centre south of the McArthur River property, has highway and air links to the rest of North America.
Leases
Surface lease
The MRJV acquired the right to use and occupy the lands necessary to mine the deposit under a surface lease agreement with the province of Saskatchewan. The lease covers 1,425 hectares and expires in May 2043.
We are required to report annually on the status of the environment, land development and progress on northern employment and business development.
Mineral lease
We have the right to mine the deposit under ML 5516, granted to us by the province of Saskatchewan. The lease covers 1,380 hectares and expires in March 2024. We have the right to renew the lease for further 10-year terms.
Mineral claims
A mineral claim gives us the right to explore for minerals and to apply for a mineral lease. There are 28 mineral claims, totalling 87,747 hectares, adjoining the mineral lease and surrounding the deposit. The mineral claims are in good standing until 2024, or later.
Environment, social and community factors
The climate is typical of the continental sub-arctic region of northern Saskatchewan. Summers are short and cool even though daily temperatures can sometimes reach above 30°C. The mean daily temperature for the coldest month is below -20°C, and winter daily temperatures can reach below -40°C.
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The deposit is 40 kilometres inside the eastern margin of the Athabasca Basin in northern Saskatchewan. The topography and environment are typical of the taiga forested lands in the Athabasca Basin.
We are committed to building long-lasting and trusting relationships with the communities in which we operate. For more information, see Our ESG principles and practices at page 84.
No communities are in the immediate vicinity of McArthur River. The community of Wollaston Lake is approximately 120 kilometres by air to the east of the mine site. The community of Pinehouse is approximately 300 kilometres south of the mine by road.
Athabasca Basin community resident employees and contractors fly to the mine site from designated pick-up points. Other employees and contractors fly to the mine from Saskatoon with pick-up points in Prince Albert and La Ronge.
Geological setting
The deposit is in the southeastern portion of the Athabasca Basin in northern Saskatchewan, within the southwest part of the Churchill structural province of the Canadian Shield. The deposit is located at or near the unconformity contact between the Athabasca Group sandstones and underlying metasedimentary rocks of the Wollaston Domain.
The deposit is similar to other Athabasca Basin deposits but is distinguished by its very high grade and overall size. Unlike Cigar Lake, there is no development of extensive hydrothermal clay alteration in the sandstone above the uranium mineralization and the deposit is relatively simple geochemically with negligible amounts of other metals.
McArthur River’s geological setting is similar to the Cigar Lake deposit in that the sandstone that overlies the deposit and basement rocks contains large volumes of water at significant pressure.
Mineralization
McArthur River’s mineralization is structurally controlled by a northeast-southwest trending reverse fault (the P2 fault), which dips 40-65 degrees to the southeast and has thrust a wedge of basement rock into the overlying sandstone with a vertical displacement ranging between 60 and 80 metres.
The deposit consists of nine mineralized zones with delineated mineral resources and/or reserves: Zones 1, 2, 3, 4, 4 South, A, B, McA North 1 and McA North 2. These and three under-explored mineralized showings, known as McA North 3, McA North 4 and McA South 1, as well as other mineralized occurrences have been identified over a strike length of 2,700 metres.
The main part of the mineralization, generally at the upper part of the basement wedge, averages 12.7 metres in width and has a vertical extent ranging between 50 metres and 120 metres.
The deposit has two distinct styles of mineralization:
| • | high-grade mineralization at the unconformity near the P2 reverse fault and within both sandstone and basement<br>rocks |
|---|---|
| • | fracture controlled and vein like mineralization that occurs in the sandstone away from the unconformity and<br>within the basement quartzite |
| --- | --- |
The high-grade mineralization along the unconformity constitutes most of the mineralization within the McArthur River deposit. Mineralization occurs across a zone of strongly altered basement rocks and sandstone across both the unconformity and the P2 structure. Mineralization is generally within 15 metres of the basement/sandstone contact with the exception of Zone 2.
Uranium oxide in the form of uraninite and pitchblende (+/- coffinite) occurs as disseminated grains in aggregates ranging in size from millimetres to decimetres, and as massive mineralization up to several metres thick.
Geochemically, the deposit does not contain any significant quantities of the elements nickel, copper, cobalt, lead, zinc, molybdenum, and arsenic that are present in other unconformity related Athabasca uranium deposits although locally elevated quantities of these elements have been observed in Zone B.
Deposit type
McArthur River is an unconformity-associated uranium deposit. Deposits of this type are believed to have formed through an oxidation-reduction reaction at a contact where oxygenated fluids met with reducing fluids. The geological model was confirmed by surface drilling, underground drilling, development, and production activities.
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About the McArthur River operation
McArthur River is a fully developed property with sufficient surface rights to meet current mining operation needs. In February 2018, we began a planned 10-month production suspension. In response to market conditions, in July 2018 we extended the suspension for an indeterminate duration. In February 2022, we announced plans to transition from care and maintenance to planned production of 15 million pounds per year (100% basis) by 2024. In February 2023, we updated our 2024 production plan to achieve 18 million pounds per year (100% basis) by 2024.
We began construction and development of the McArthur River mine in 1997 and completed it on schedule. Mining began in December 1999 and commercial production on November 1, 2000. We have successfully extracted over 325 million pounds (100% basis) since we began mining in 1999.
The mineral reserves at McArthur River are contained within seven zones: Zones 1, 2, 3, 4, 4 South, A and B. Prior to care and maintenance, there were two active mining zones and one where development was significantly advanced.
Zone 2 has been actively mined since production began in 1999. The ore zone was initially divided into three freeze panels. As the freeze wall was expanded, the inner connecting freeze walls were decommissioned to recover the inaccessible uranium around the active freeze pipes. Mining of Zone 2 is almost complete. About 4.7 million pounds of mineral reserves remain (100% basis) and we expect to recover them using a combination of raisebore and blasthole stope mining.
Zone 4 has been actively mined since 2010. The zone was divided into four freeze panels, and like in Zone 2, as the freeze wall was expanded, the inner connecting freeze walls were decommissioned. Zone 4 has 116.6 million pounds of mineral reserves (100% basis) secured behind freeze walls and it will be the main source of production for the next several years. Raisebore mining and blasthole stoping will be used to recover the mineral reserves.
Zone 1 is the next planned mine area to be brought into production. Freezehole drilling was 90% complete and brine distribution construction was approximately 10% complete when work was suspended in 2018 as part of the production suspension. Work remaining before production can begin includes completion of the freezehole drilling, brine distribution construction, ground freezing, and drill and extraction chamber development. Work is expected to resume in zone 1 in 2023. Once complete, an additional 48.0 million pounds of mineral reserves (100% basis) will be secured behind freeze walls. Blasthole stope mining is currently planned as the main extraction method.
Permits
We need three key permits to operate the McArthur River mine:
| • | Uranium Mine Operating Licence – renewed in 2013 and expires on October 31, 2023 (from the CNSC);<br> |
|---|---|
| • | Approval to Operate Pollutant Control Facilities – renewed in 2017 and expires on June 30, 2023 (from<br>the Saskatchewan Ministry of Environment (SMOE)); and |
| --- | --- |
| • | Water Rights Licence and Approval to Operate Works – amended in 2011 and valid for an undefined term (from<br>the Saskatchewan Watershed Authority) |
| --- | --- |
The CNSC relicensing process is under way for McArthur River and Key Lake, and we expect a decision from the CNSC later in 2023. We do not expect any interruption or significant risks from this process.
The CNSC licence conditions handbook allows McArthur River to produce up to 25.0 million pounds (100% basis) per year.
Infrastructure
Surface facilities are 550 metres above sea level. The site includes:
| • an underground mine with three shafts: one full service shaft and two<br>ventilation shafts<br> <br><br> <br>• 1.6-kilometre gravel airstrip and air terminal<br> <br><br><br><br>• waste rock stockpiles<br> <br><br><br><br>• water containment ponds and treatment plant<br><br><br><br> <br>• a freshwater pump house<br><br><br><br> <br>• a powerhouse<br><br><br><br> <br>• electrical<br>substations | • backup electrical generators<br><br><br><br> <br>• a warehouse<br><br><br><br> <br>• freeze plants<br><br><br><br> <br>• a concrete batch plant<br><br><br><br> <br>• an administration and<br>maintenance shop building<br> <br><br><br><br>• a permanent residence and recreation facilities<br><br><br><br> <br>• an ore slurry load out<br>facility |
|---|
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Water, power and heat
Toby Lake, which is nearby and easy to access, has enough water to satisfy all surface water requirements. Collection of groundwater that naturally enters our shafts is sufficient to meet all underground process water requirements and supplements the surface industrial water supply. The site is connected to the provincial power grid, and it has backup generators in case there is an interruption in grid power.
McArthur River operates throughout the year despite cold winter conditions. During the winter, we heat the fresh air necessary to ventilate the underground workings using propane-fired burners.
Employees
Employees are recruited with preference given to residents of northern Saskatchewan.
We reached a new collective agreement with unionized employees at our McArthur River/Key Lake operations in July 2019. The agreement expired on December 31, 2022. Negotiations for a new agreement have commenced. As in past negotiations, work continues under the terms of the expired collective agreement. There is a risk to the production plan if we are unable to reach an agreement and there is a labour dispute.
Mining
The McArthur River deposit presents unique challenges that are not typical of traditional hard or soft rock mines. These challenges are the result of mining in or near high pressure ground water in challenging ground conditions with significant radiation concerns due to the high-grade uranium ore. We take significant steps and precautions to reduce the risks. Mine designs and mining methods are selected based on their ability to mitigate hydrological, radiological, and geotechnical risks. Operational experience gained since the start of production has resulted in a significant reduction in risk. However, there is no guarantee that our efforts to mitigate risk will be successful.
Mining methods and techniques
There are three approved mining methods at McArthur River: raisebore mining, blasthole stope mining and boxhole mining. However, only raisebore and blasthole stope mining remain in use. These methods all use ground freezing to mine the McArthur River deposit.
Ground freezing
All the mineralized areas discovered to date at McArthur River are in, or partially in, water-bearing ground with significant pressure at mining depths. This high pressure water source is isolated from active development and production areas in order to reduce the inherent risk of an inflow. To date, McArthur River has relied on pressure grouting and ground freezing to successfully mitigate the risks of the high pressure ground water.
Chilled brine is circulated through freeze holes to form an impermeable freeze barrier around the area being mined. This prevents water from entering the mine, and helps stabilize weak rock formations. Ground freezing significantly reduces, but does not fully eliminate, the risk of water inflows.
Blasthole stoping
Blasthole stoping began in 2011 and was the main extraction method prior to our production suspension. It is planned in areas where blastholes can be accurately drilled and small stable stopes excavated without jeopardizing the freeze wall integrity. The use of this method has allowed the site to improve operating costs by increasing overall extraction efficiency by reducing underground development, concrete consumption, mineralized waste generation and improving extraction cycle time.
Raisebore mining
Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River, and it has been used since mining began in 1999. This method is favourable for mining the weaker rock mass areas of the deposit, and is suitable for massive high-grade zones where there is access both above and below the ore zone.
Initial processing
McArthur River produces two product streams, high-grade slurry and low-grade mineralized rock. Both product streams are shipped to the Key Lake mill to produce uranium ore concentrate.
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The high-grade material is ground and thickened into a slurry underground and then pumped to surface. The material is then thickened further, blended for grade control and shipped to Key Lake in slurry totes using haul trucks.
The low-grade mineralized material is hoisted to surface and shipped as a dry product to Key Lake using covered haul trucks. Once at Key Lake, the material is ground, thickened and blended with the high-grade slurry to a nominal 5% U3O8 mill feed grade. It is then processed into uranium ore concentrate and packaged in drums for further processing offsite.
New mining areas
We must bring on new mining zones to sustain production. Prior to the production shutdown, two new areas were under active development. Zone 1 was in the freeze drilling stage (90% complete) and Zone 4 South was in the initial freeze drift development stage.
In 2018, all development and construction activities for the new mining zones were halted as part of the production suspension. Work is expected to resume in zone 1 in 2023.
Tailings
McArthur River does not have a tailings management facility (TMF) as it ships all mineralized material to Key Lake for final milling and processing.
Waste rock
The waste rock piles are confined to a small footprint on the surface lease and managed in contained facilities. These are separated into three categories:
| • | clean waste (includes mine development waste, crushed waste, and various piles for concrete aggregate and<br>backfill) |
|---|---|
| • | low-grade mineralization temporarily stored on lined pads until trucked<br>to Key Lake |
| --- | --- |
| • | waste with acid-generating potential – temporarily stored on lined pads – for concrete aggregate<br> |
| --- | --- |
Water inflow incidents
There have been two notable water inflow incidents at the McArthur River mine. These two inflows have strongly influenced our mine design, inflow risk mitigation and inflow preparedness:
Bay 12 Inflow: Production was suspended on April 6, 2003, as increased water inflow due to a rock fall in a new development area (Bay 12 located just above the 530-metre level) began to flood the lower portions of the mine, including the underground grinding circuit area. Additional dewatering capacity was installed, and the flooded areas were dewatered and repaired. We resumed mining in July 2003 and sealed off the excess water inflow in July 2004.
590-7820N Inflow: In November 2008, there was a small water inflow in the lower Zone 4 development area on the 590-metre level. It did not impact production but did delay local development for approximately one year. In January 2010, the inflow was sealed off and local development was resumed.
Pumping capacity and treatment limits
Our standard for this mine is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before we begin work on any new zone. As our mine plan is advanced, our dewatering system will be expanded to handle water from the new mine areas. We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow.
Production
McArthur River Mine
No mining took place from 2019 through 2021. In 2022, we produced 0.64 million pounds; our share 0.45 million pounds. We plan to produce 15 million pounds (100% basis) in 2023 and 18 million pounds (100% basis) in 2024.
The mine plan is designed to extract all current McArthur River mineral reserves. The following is a general summary of the mine plan production schedule parameters on a 100% basis for these mineral reserves:
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| Total mine production | • 2,221,000 tonnes of ore<br><br><br><br> <br>• 389 million pounds of U3O8, based on current unmined mineral reserves<br> <br><br><br><br>• Average grade of 7.94%<br> <br><br><br><br>• 150 to 350 tonnes per day, varying with ore grade |
|---|
Note: Broken and in-circuit ore inventory (previously mined material) is not included in the mine production plan total. Current broken inventory consists of 3.6 million pounds at McArthur River and 1.5 million pounds at Key Lake.
With the improvement in the uranium market and the success we have had in securing new long-term contracts, we have updated our 2024 production plan to achieve 18 million pounds (100% basis) per year starting in 2024.
Key Lake Mill
No milling took place from 2019 through 2021. In 2022, we packaged 1.1 million pounds; our share 0.8 million pounds.
The mill plan is designed to process all current McArthur River mineral reserves plus Key Lake low-grade mineralization remaining from the Deilmann and Gaertner pits. In addition, a small amount of recycled product from Blind River and Port Hope facilities is planned to be processed. The following is a general summary of the mill plan production schedule parameters on a 100% basis for these mineral reserves, mineralized material, and product:
| Total mill production | • 3,466,000 tonnes of mill feed including blend and recycle material<br><br><br><br> <br>• Average feed grade of<br>5.20%<br> <br><br> <br>• 394 million<br>pounds of U3O8 packaged based on an average recovery of 99.0% |
|---|
Production Suspension
In 2018, we had a temporary planned production suspension and in July 2018 we extended the suspension for an indeterminate duration. There was nominal production in 2018 and no production from 2019 through 2021. A reduced workforce remained at McArthur River and Key Lake to keep the facilities in a state of safe care and maintenance. Care and maintenance activities included mine dewatering, water treatment, freeze wall maintenance, and environmental monitoring, as well as preservation maintenance and monitoring of critical facilities.
Production Resumption Plan
With our February 2022 announcement to transition McArthur River and Key Lake from care and maintenance to resuming production, through most of 2022, we undertook the necessary operational readiness activities prior to restarting production.
In November 2022, we announced that the first pounds of uranium ore from the McArthur River mine had been milled and packaged at the Key Lake mill, marking the achievement of initial production as these facilities transition back into normal operations. Total packaged production from McArthur River and Key Lake in 2022 was 1.1 million pounds (0.8 million pounds our share).
Operational readiness activities consisted of recruitment, training, infrastructure upgrades and commissioning as well as reactivation of mobile equipment previously stored for care and maintenance. Operational activities included mine dewatering, water treatment, freeze wall maintenance, and environmental monitoring.
In 2022, production forecasts were revised as we worked through normal commissioning issues to integrate the existing and new assets with upgraded operational technology which caused some delays to the schedule at the mill. During the year, we expensed operational readiness costs of approximately $169 million directly to cost of sales. With the restart of production in 2023, we will no longer expense monthly operational readiness costs.
With the extended period of time the assets were on care and maintenance, the operational changes made, and commissioning issues that we have worked through at the mill, which caused delays to the production schedule in 2022, there is continued uncertainty regarding the timing of a successful ramp up to planned production and the associated costs. In addition, inflation, the availability of personnel with the necessary skills and experience, and the potential impact of supply chain challenges on the availability of materials and reagents carry with them the risks of not achieving our production plans, production delays and increased costs.
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Licensed annual production capacity
The McArthur River mine and Key Lake mill are both licensed to produce up to 25 million pounds (100% basis) per year. To achieve annual production at the licensed capacity, additional investment will be required.
Innovation
In 2020, we began a program to advance the assessment of innovation opportunities at the McArthur River mine and Key Lake mill. We established a team of internal experts who have been tasked with assessing, designing, and implementing opportunities to improve operating efficiency. We continue to advance the projects that meet our investment criteria.
Key Lake mill
Location and access
The Key Lake mill is located in northern Saskatchewan, 570 kilometres north of Saskatoon. The site is 9 kilometres long and 5 kilometres wide and is connected to McArthur River by an 80-kilometre all-weather road. There is a 1.6-kilometre unpaved air strip and an air terminal on the east edge of the site.
Permits
We need two key permits to operate the Key Lake mill:
| • | Uranium Mill Operating Licence – renewed in 2013 and expires on October 31, 2023 (from the<br>CNSC); and |
|---|---|
| • | Approval to Operate Pollutant Control Facilities – renewed in 2021 and expires on November 30,<br>2029 (from the SMOE) |
| --- | --- |
The CNSC licence conditions handbook allows the Key Lake mill to produce up to 25.0 million pounds (100% basis) per year.
Supply
All McArthur River ore, including our share, is milled at Key Lake. We do not have a formal toll milling agreement with the Key Lake joint venture.
In June 1999, the Key Lake joint venture (Cameco and UEM) entered a toll milling agreement with Orano to process their total share of McArthur River ore. The terms of the agreement (as amended in January 2001) include the following:
| • | processing is at cost, plus a toll milling fee; and |
|---|---|
| • | the Key Lake joint venture owners are responsible for decommissioning the Key Lake mill and for certain capital<br>costs, including the cost of any tailings management associated with milling Orano’s share of McArthur River ore |
| --- | --- |
With the UEM distribution in 2009 (see History on page 26 for more information), we made the following changes to the agreement:
| • | the fees and expenses related to Orano’s pro-rata share of ore<br>produced just before the UEM distribution (16.234% – the first ore stream) have not changed. Orano is not responsible for any capital or decommissioning costs related to the first ore stream. |
|---|---|
| • | the fees and expenses related to Orano’s pro-rata share of ore<br>produced as a result of the UEM distribution (an additional 13.961% – the second ore stream) have not changed. Orano’s responsibility for capital and decommissioning costs related to the second ore stream are, however, as a Key Lake joint<br>venture owner under the original agreement. |
| --- | --- |
The agreement was amended again in 2011 and now requires:
| • | milling of the first ore stream at the Key Lake mill until May 31, 2028; and |
|---|---|
| • | milling of the second ore stream at the Key Lake mill for the entire life of the McArthur River project<br> |
| --- | --- |
Processing
McArthur River low-grade mineralization, including legacy low-grade mineralized waste rock stored at Key Lake, is ground and thickened at Key Lake and then blended with McArthur River high-grade slurry to a nominal 5% U3O8 mill feed grade. All remaining uranium processing (leaching through to calcined uranium ore concentrate packaging) and tailings disposal also occur at Key Lake.
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The Key Lake mill comprises the following eight plants:
| • | ore slurry receiving plant |
|---|---|
| • | grinding/blending plant |
| --- | --- |
| • | reverse osmosis plant |
| --- | --- |
| • | leaching/counter current decantation plant |
| --- | --- |
| • | solvent extraction plant |
| --- | --- |
| • | yellowcake precipitation/dewatering/calcining/packing/ammonium sulphate plant |
| --- | --- |
| • | bulk neutralization/lime handling/tailings treatment and pumping |
| --- | --- |
| • | powerhouse/utilities/acid plant/oxygen plant complex |
| --- | --- |
Recovery and metallurgical testing
The McArthur River original flowsheet was largely based on the use of conventional mineral processing concepts and equipment. Where necessary, testwork was undertaken to prove design concepts or adapt conventional equipment for unique services. Simulated ore was utilized in much of the testwork because the off-site testing facilities were not licensed to receive radioactive materials. Testwork at the Key Lake metallurgical laboratory also confirmed the suitability of the Key Lake mill circuit for processing McArthur River ore with some Key Lake circuit modifications.
To date, numerous changes have been made to both the McArthur River and Key Lake processing and water treatment circuits to improve their operational reliability and efficiency. From a uranium recovery perspective, the most important was to change the McArthur River grinding circuit classification system from screens to cyclones. This was completed in late 2009 and provided a measurable recovery increase as well as reduced particle segregation issues. From 2012 to 2017 Key Lake achieved an annual mill recovery of 99% and this is assumed to continue.
Testing at Key Lake has shown that use of a silica coagulant was able to alleviate the issues caused by the cement dilution in the ore from McArthur River. This has eliminated the need to operate the gravity concentrator circuit as well as increased the solvent extraction circuit operational reliability.
Waste rock
There are five rock stockpiles at the Key Lake site:
| • | three contain non-mineralized waste rock. These will be decommissioned<br>when the site is closed. |
|---|---|
| • | two contain low-grade mineralized material. These are used to lower the<br>grade of McArthur River ore before it enters the milling circuit. |
| --- | --- |
Treatment of effluent
We modified Key Lake’s effluent treatment process to satisfy our licence and permit requirements.
Tailings capacity
There are two tailings management facilities (TMF)at the Key Lake site:
| • | an above-ground impoundment facility, where tailings are stored within compacted till embankments. We have not<br>deposited tailings here since 1996, and are looking at several options for decommissioning this facility in the future; and |
|---|---|
| • | the Deilmann open pit, which was mined out in the 1990s. Tailings from processing McArthur River ore are<br>deposited in the Deilmann in-pit TMF. |
| --- | --- |
Beginning in July 2001, periodic sloughing of the pit walls in the western portion of the Deilmann TMF was experienced. We implemented a long-term stabilization plan, with the final phase completed in 2019.
Based upon the current licence conditions, tailings capacity is sufficient to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.
Decommissioning and financial assurances
Updated preliminary decommissioning plans for McArthur River and Key Lake were submitted in 2017 and 2018 as part of the regular five-year update schedule. Prior to revising the letters of credit, approval of the updated plans is required from the province of Saskatchewan and CNSC staff as well as formal approval from the CNSC through a Commission proceeding. The
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necessary approvals were received. The documents included our estimated cost for implementing the plans and addressing known environmental liabilities.
In 2022, as part of the required five-year update schedule, we submitted revised preliminary decommissioning estimates for McArthur River and Key Lake, which are currently being reviewed by the province of Saskatchewan and CNSC staff.
For more information, see Nuclear waste management anddecommissioning.
Operating and capital costs
The following is a summary of the operating and capital cost estimates for the life of mine, stated in constant 2022 dollars and reflecting a forecast life-of-mine mill production of 394 million pounds U3O8 packaged.
| Operating Costs ($Cdn million) | Total(2023 – 2044) | |
|---|---|---|
| McArthur River Mining | ||
| Site administration | $ | 973.7 |
| Mining costs | 1,865.9 | |
| Process | 315.0 | |
| Corporate overhead | 209.7 | |
| Total mining costs | $ | 3,364.3 |
| Key Lake Milling | ||
| Administration | $ | 928.6 |
| Milling costs | 1,901.9 | |
| Corporate overhead | 172.7 | |
| Total milling costs | $ | 3,003.2 |
| Total operating costs | $ | 6,367.5 |
| Total operating cost per pound U3O8 | $ | 16.15 |
Note:
| 1. | Presented as total cost to the McArthur River Joint Venture. |
|---|
Estimated operating costs to the MRJV consist of annual expenditures at McArthur River to mine the mineral reserves, process it underground, including grinding, density control and pumping the resulting slurry to surface for transportation to Key Lake.
Operating costs at Key Lake consist of costs for receipt of the slurry, up to and including precipitation of the uranium into yellowcake, including cost of disposal of tailings to the Deilmann TMF.
| Capital Costs ($Cdn million) | Total(2023 – 2044) | |
|---|---|---|
| McArthur River Mine Development | $ | 453.7 |
| McArthur River Mine Capital | ||
| Freeze infrastructure | $ | 133.2 |
| Water management and electrical infrastructure | 10.1 | |
| Other mine capital | 332.3 | |
| Total mine capital | $ | 475.6 |
| Key Lake Mill Sustaining | ||
| Total mill capital | $ | 244.0 |
| Total capital costs | $ | 1,173.3 |
Notes:
| 1. | Presented as total cost to the McArthur River Joint Venture. |
|---|---|
| 2. | Mine development includes delineation drilling, mine development, probe and grout drilling, freeze drilling,<br>and minor support infrastructure. |
| --- | --- |
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Estimated capital costs to the MRJV include sustaining costs for both McArthur River and Key Lake, as well as underground development at McArthur River to bring mineral reserves into production. Overall, the largest segment of capital at McArthur River is mine development. Other significant capital includes freeze infrastructure costs.
The economic analysis, effective as of December 31, 2018, being the effective date of the technical report for McArthur River and Key Lake operations, resulted in an estimated pre-tax net present value (NPV) (at a discount rate of 8%) to Cameco for net cash flows from January 1, 2019 forward of $2.97 billion for its share of the current McArthur River mineral reserves. Using the total capital invested to December 31, 2018, along with the operating and capital estimates for the remainder of the mineral reserves, the pre-tax internal rate of return (IRR) was estimated to be 11.6%.
The analysis was from the point of view of Cameco, which owns 69.805% of the MRJV, and incorporated a projection of Cameco’s sales revenue from its proportionate share of the related production, less its share of related operating and capital costs of the MRJV, as well as royalties and surcharges that will be payable on the sale of concentrates.
For the purpose of the economic analysis, the projected impact of income taxes was excluded due to the nature of the required calculations. McArthur River operates as an unincorporated joint venture and is, therefore, not subject to direct income taxation at the joint venture level. It is not practical to allocate a resulting income tax cost to Cameco’s portion of the McArthur River operation, as Cameco’s tax expense is a function of several variables, most of which are independent of its investment in McArthur River.
| Economic Analysis ($Cdn M) | Year 0 | Year 1 | Year 2 | Year 3 | Year 4 | Year 5 | Year 6 | Year 7 | Year 8 | Year 9 | Year 10 | Year 11 | Year 12 | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Production volume (000’s lbs U3O8) | — | 2,788 | 12,508 | 12,550 | 12,653 | 12,591 | 12,621 | 12,611 | 12,550 | 12,556 | 12,587 | 12,553 | 12,569 | |||||||||||||||
| Sales revenue | $ | — | $ | 131.7 | $ | 572.2 | $ | 577.5 | $ | 602.8 | $ | 618.7 | $ | 635.0 | $ | 651.6 | $ | 662.9 | $ | 683.3 | $ | 698.0 | $ | 709.1 | $ | 719.4 | ||
| Operating costs | 68.2 | 137.5 | 171.1 | 169.5 | 169.0 | 168.9 | 170.1 | 172.9 | 177.5 | 177.9 | 179.3 | 179.9 | 180.0 | |||||||||||||||
| Capital costs | 3.7 | 31.1 | 36.7 | 31.9 | 31.0 | 42.9 | 36.8 | 34.7 | 35.0 | 42.6 | 43.6 | 74.4 | 32.0 | |||||||||||||||
| Basic royalty | — | 5.6 | 24.3 | 24.5 | 25.6 | 26.3 | 27.0 | 27.7 | 28.2 | 29.0 | 29.7 | 30.1 | 30.6 | |||||||||||||||
| Resource surcharge | — | 3.9 | 17.2 | 17.3 | 18.1 | 18.6 | 19.0 | 19.5 | 19.9 | 20.5 | 20.9 | 21.3 | 21.6 | |||||||||||||||
| Profit royalty | — | — | 42.6 | 49.7 | 53.5 | 54.1 | 57.3 | 59.6 | 60.4 | 62.3 | 64.1 | 61.1 | 69.1 | |||||||||||||||
| Net pre-tax cash flow | $ | (71..9 | ) | $ | (46.5 | ) | $ | 280.2 | $ | 284.6 | $ | 305.5 | $ | 307.9 | $ | 324.8 | $ | 337.2 | $ | 341.8 | $ | 351.0 | $ | 360.4 | $ | 342.3 | $ | 386.2 |
| Economic Analysis ($Cdn M) | Year 13 | Year 14 | Year 15 | Year 16 | Year 17 | Year 18 | Year 19 | Year 20 | Year 21 | Year 22 | Year 23 | Total | ||||||||||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | |||
| Production volume (000’s l bs U3O8) | 12,567 | 12,630 | 12,618 | 12,602 | 12591 | 12,603 | 12,611 | 12,649 | 12,779 | 11,705 | 6,060 | 272,553 | ||||||||||||||||
| Sales revenue | $ | 748.7 | $ | 757.8 | $ | 772.9 | $ | 787.6 | $ | 780.6 | $ | 787.7 | $ | 794.5 | $ | 796.9 | $ | 805.1 | $ | 737.4 | $ | 381.8 | $ | 15,413.2 | ||||
| Operating costs | 182.1 | 184.7 | 185.3 | 184.5 | 184.0 | 182.1 | 181.8 | 178.8 | 175.4 | 171.0 | 148.6 | 4,080.3 | ||||||||||||||||
| Capital costs | 33.3 | 23.6 | 21.7 | 21.4 | 21.6 | 21.9 | 17.7 | 11.9 | 6.4 | 1.4 | — | 657.5 | ||||||||||||||||
| Basic royalty | 31.8 | 32.2 | 32.8 | 335 | 33.2 | 33.5 | 33.8 | 33.9 | 34.2 | 31.3 | 16.2 | 655.1 | ||||||||||||||||
| Resource surcharge | 22.5 | 22.7 | 23.2 | 23.6 | 23.4 | 23.6 | 23.8 | 23.9 | 24.2 | 22.1 | 11.5 | 462.4 | ||||||||||||||||
| Profit royalty | 73.1 | 75.7 | 78.1 | 80.5 | 79 5 | 80.8 | 82.5 | 84.2 | 86.6 | 78.5 | 31.7 | 1,465.0 | ||||||||||||||||
| Net pre-tax cashflow | $ | 405.9 | $ | 418.9 | $ | 431.7 | $ | 444.1 | $ | 438.9 | $ | 445.7 | $ | 454.9 | $ | 464.3 | $ | 478.2 | $ | 433.0 | $ | 173.8 | $ | 8,092.9 | ||||
| Pre-tax NPV (8%) to January 1,2019 | $ | 2,973.3 | ||||||||||||||||||||||||||
| Pre-tax IRR (%) | 11.6 | % | ||||||||||||||||||||||||||
| Notes: | ||||||||||||||||||||||||||||
| --- | ||||||||||||||||||||||||||||
| 1. | The economic analysis assumes the McArthur River in and Key Lake mill are both in a state of care and<br>maintenance during Year 0 with a restart occurring in Year 1. | |||||||||||||||||||||||||||
| --- | --- | |||||||||||||||||||||||||||
| 2. | Production volume does not include recycled product received from the Blind River Refinery and the Port Hope<br>Conversion Facility. | |||||||||||||||||||||||||||
| --- | --- | |||||||||||||||||||||||||||
| 3. | In February 2022, Cameco announced its plan to transition McArthur River and Key Lake from care and maintenance<br>to planned production of 15 million pounds (100% basis) by 2024. In February 2023, Cameco announced an update to this plan with planned production of 18 million pounds (100% basis) by 2024. The economic analysis has not been updated for<br>these announcements. | |||||||||||||||||||||||||||
| --- | --- |
Our expectations and plans regarding McArthur River/Key Lake, including forecasts of operating and capital costs, net cash flow, production and mine life are forward-looking information and are based specifically on the risks and assumptions discussed on pages 3, 4 and 5. We may change our operating or capital spending plans in 2023, depending upon uranium markets, our financial position, results of operation, or other factors. Estimates of expected future production, and capital and operating costs are inherently uncertain, particularly beyond one year, and may change materially over time.
2022 ANNUAL INFORMATION FORM Page 36
Exploration, drilling, sampling, data quality and estimates
There are no historical mineral resource estimates within the meaning of NI 43-101 to report. The original McArthur River mineral resource estimates were derived from surface diamond drilling from 1980 to 1992. In 1988 and 1989, this drilling first revealed significant uranium mineralization and by 1992, we had delineated the mineralization over a strike length of 1,700 metres at depths of between 500 to 640 metres. Following the drillhole results, development of an underground exploration project was undertaken in 1993.
Exploration
Drilling has been carried out extensively from both surface and underground to locate and delineate mineralization. Surface exploration drilling is initially used in areas where underground access is not available. The results are used to guide future underground exploration activities.
There was no exploration activity in 2022 as we focused on the restart of production.
Drilling
Surface drilling
We have carried out surface drilling since 2004, to test the extension of mineralization identified from the historical surface drillholes, to test new targets along the strike, and to evaluate the P2 trend northeast and southwest of the mine. Surface drilling since 2004 has extended the potential strike length to more than 2,700 metres.
We have completed preliminary drill tests of the P2 trend at 300 metre intervals or less over 11.5 kilometres (5.0 kilometres northeast and 6.4 kilometres southwest of the McArthur River deposit) of the total 13.75 kilometres strike length of the P2 trend. Surface exploration drilling in 2015 focused on additional evaluation in the southern part of the P2 trend south of the P2 main mineralization. Starting in 2016, exploration efforts shifted away from the P2 trend to the north part of the property.
Underground drilling
In 1993, regulators approved an underground exploration program, consisting of shaft sinking, lateral development and drilling. We completed the shaft in 1994.
We have drilled more than 1,260 underground drillholes since 1993 to get detailed information along 1,800 metres of strike length. The drilling was primarily completed from the 530 and 640 metre levels.
Other data
In addition to the exploration drilling, geological data has been collected from the underground probe and grout, service, drain, freeze, and geotechnical drill programs.
Recent activity
Since the halt of underground delineation drilling in 2018 as part of the production suspension, there has been no drilling activity. Resumption of drilling activities is planned for 2023.
Sampling, analysis and data verification
Surfacesamples
Surface holes were generally drilled on sections spaced between 50 and 200 metres with 12 to 25 metres between holes on a section when necessary. Drilled depths average 670 metres.
The orientation of mineralization is variable but, in general, vertical holes generally intersect mineralization at angles of 25 to 45 degrees, resulting in true widths being 40 to 70% of the intersected width. Angled holes usually intercept mineralization closer to perpendicular, giving intercepts that are closer to true width.
Any stratigraphy exhibiting noteworthy alteration, structures or radiometric anomalies is split and sampled.
Given that the vast majority of the deposit has been delineated from underground, few surface holes are used for mineral resource and reserve estimation purposes.
2022 ANNUAL INFORMATION FORM Page 37
Underground samples
Underground drilling is generally planned to provide close to true thicknesses results. All underground exploration holes are core drilled and gamma probed whenever possible. McArthur River uses a high-flux gamma probe designed and constructed by alphaNUCLEAR, a member of the Cameco group of companies. This high-flux gamma probe utilizes two Geiger Mûller tubes to detect the amount of gamma radiation emanating from the surroundings. The count rate obtained from the high-flux probe is compared against chemical assay results to establish a correlation to convert corrected probe count rates into equivalent % U3O8 grades for use when assay results are unavailable. The consistency between probe data and chemical assays demonstrates that secular equilibrium exists within the deposit. A small portion of the data used to estimate mineral resources is obtained from assays, and in these cases, the core depth is validated by comparing the down-hole gamma survey results with a hand-held scintillometer on core before it is logged, photographed, and then sampled for uranium analysis. Attempts are made to avoid having samples cross geological boundaries.
When sampled, the entire core from each sample interval is taken for assay or other measurements to characterize the physical and geochemical properties of the deposit. This reduces the potential sample bias inherent when splitting core. Core recovery throughout the deposit has generally been very good. However, in areas of poor core recovery, uranium grade determination is generally based on radiometric probe results.
The typical sample collection process at our operations is performed by or under the supervision of a qualified geoscientist and includes the following procedures:
| • | marking the sample intervals on the core boxes at nominal 50 cm sample lengths |
|---|---|
| • | collection of the samples in plastic bags, taking the entire core |
| --- | --- |
| • | documentation of the sample location, assigning a sample number, and description of the sample, including<br>radiometric values from a hand-held device |
| --- | --- |
| • | bagging and sealing, with sample tags inside bags and sample numbers on the bags; and |
| --- | --- |
| • | placement of samples in steel drums for shipping |
| --- | --- |
Sample security
Current sampling protocols dictate that all samples are collected and prepared in a restricted core processing facility. The core samples are collected and transferred from the core boxes to high-strength plastic sample bags, then sealed. The sealed bags are then placed in steel drums and shipped in compliance with the Transport of Dangerous Goods regulations with tamper-proof security seals. Chain of custody documentation is present from inserting samples into steel drums to the final delivery of results by the Saskatchewan Research Council Geoanalytical Laboratories (SRC).
All samples collected are prepared and analysed under the close supervision of qualified personnel at SRC, which is a restricted access laboratory licensed by the CNSC.
Analysis
Drill core assay sample preparation is performed at SRC’s main laboratory, which is independent of the participants of the MRJV. It involves jaw crushing to 60% @ 2 mm and splitting out a 100 – 200 g sub-sample using a riffle splitter. The sub-sample is pulverized to 90% @ -106 microns using a puck and ring grinding mill. The pulp is then transferred to a bar coded plastic snap top vial. Assaying by SRC involves digesting an aliquot of pulp in concentrated 3:1 HCL:HNO3, on a hot plate for approximately one hour. The volume is then made up in a 100 ml volumetric flask using deionized water prior to analysis by ICP-OES. Instruments used in the analysis are calibrated using certified commercial solutions. This method is ISO/IEC 17025:2017 accredited by the Standards Council of Canada.
Quality control and data verification
The quality assurance and quality control procedures used during early drilling programs were typical for the time. Many of the original signed assay certificates from surface drilling are available and have been reviewed by Cameco geologists.
More recent sample preparation and assaying was completed under the supervision of qualified personnel at SRC and includes preparing and analysing standards, duplicates and blanks. At least two standards are analysed for each 40-sample batch, with another sample being analysed in duplicate. We also include a pulp repeat and 1 split sample repeat with every group. Samples that fail quality controls are re-analyzed.
2022 ANNUAL INFORMATION FORM Page 38
In 2013, McArthur River implemented an SQL server based centralized geological data management system to manage all drillhole and sample related data. All core logging, sample collection, downhole probing and sample dispatching activities are carried out and managed within this system. All assay, geochemical and physical analytical results obtained from the external laboratory are uploaded directly into the centralized database, thereby mitigating the potential for manual data transfer errors. The database used for the current mineral resource and mineral reserve estimates was validated by Cameco qualified geoscientists.
Additional data quality control measures include:
| • | review of drillhole collar coordinates and downhole deviations in the database against planned location of the<br>holes. All results from work performed in 2022 were within acceptable tolerances. |
|---|---|
| • | comparison of the information in the database against the original data, including paper logs, assay certificates<br>and original probing data files as required. Some hole intervals were reviewed against scintillometer data and core logs to confirm the presence or absence of mineralization. |
| --- | --- |
| • | validation of core logging information in plan and section views, and review of logs against photographs of the<br>core. Some hole intervals were reviewed against core photos to confirm the presence or absence of mineralization. |
| --- | --- |
| • | checking for data errors such as overlapping intervals and out of range values. No issues were observed.<br> |
| --- | --- |
| • | radiometric probes undergo annual servicing and re-calibration as well as<br>additional checks including control probing to ensure precision and accuracy of the probes. Servicing and re-calibration of the probes were performed to prepare for the resumption of drilling activities.<br> |
| --- | --- |
| • | validating uranium grades comparing radiometric probing, core radioactivity measurements and sample assay<br>results. No new measurement data has been collected since the temporary production suspension. |
| --- | --- |
No quality control and data verification related issues of note were identified during the minor mineral resource estimation work performed in 2022.
Since the start of commercial production, we have regularly compared information collected from production activities, such as freezeholes, raisebore pilot holes, radiometric scanning of scoop tram buckets and mill feed sampling, to the drillhole data informed models. We also compare the uranium block model with mine production results monthly to ensure an acceptable level of accuracy is maintained.
Our geoscientists, including a qualified person as such term is defined in NI 43-101, have witnessed or reviewed drilling, core handling, radiometric probing, logging, sampling facilities and data verification procedures employed at the McArthur River operation and consider the methodologies to be satisfactory and the results representative and reliable. There has been no indication of significant inconsistencies in the data used or verified nor any failures to adequately verify the data.
Accuracy
We are satisfied with the quality of data and consider it valid for use in the estimation of mineral resources and reserves for McArthur River. Comparison of actual mine production with past expected production supports this opinion.
Mineral reserve and resource estimates
Please see page 78 for our mineral reserve and resource estimates for McArthur River.
2022 ANNUAL INFORMATION FORM Page 39
Uranium – Tier-one operations
Cigar Lake
| 2022 Production (our share) |
|---|
| 9.6M lbs |
| 2023 Production Outlook (our share) |
| 9.8M lbs |
| Estimated Reserves (our share) |
| 84.4M lbs |
| Estimated Mine Life |
| 2031 |
Cigar Lake is the world’s highest grade uranium mine. We are a 54.547% owner and the mine operator. Cigar Lake uranium is milled at Orano’s McClean Lake mill.
Cigar Lake is considered a material uranium property for us. There is a technical report dated March 29, 2016 (effective December 31, 2015) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).
| Location | Saskatchewan, Canada |
|---|---|
| Ownership | 54.547% |
| Mine type | Underground |
| Mining method | Jet boring system |
| End product | Uranium concentrate |
| Certification | ISO 14001 certified |
| Estimated reserves | 84.4 million pounds (proven and probable), average grade U3O8: 17.21% |
| Estimated resources | 57.5 million pounds (measured and indicated), average grade U3O8: 13.19% 12.0 million pounds (inferred),<br>average grade U3O8: 5.62% |
| Licensed capacity | 18.0 million pounds per year (our share 9.8 million pounds per year*)* |
| Licence term | Through June, 2031 |
| Total packaged production: 2014 to 2022 | 123 million pounds (100% basis) |
| 2022 production | 9.6 million pounds (18.0 million pounds on 100% basis) |
| 2023 production outlook | 9.8 million pounds (18.0 million pounds on 100% basis) |
| Estimated decommissioning cost | $62 million (100% basis) |
All values shown, including reserves and resources, represent our share only, unless otherwise indicated.
Business structure
Cigar Lake is owned by a joint venture of three companies (CLJV):
| • | Cameco – 54.547% (operator) |
|---|---|
| • | Orano – 40.453% |
| --- | --- |
| • | TEPCO Resources Inc. – 5.000% |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 40
History
| 1976 | • Canadian Kelvin Resources and Asamera Oil Corporation form an exploration joint<br>venture, which includes the lands that the Cigar Lake mine was built on |
|---|---|
| 1977 | • SMDC, one of our predecessor companies, acquires a 50% interest |
| 1980 | • Waterbury Lake joint venture formed, includes lands now called Cigar<br>Lake |
| 1981 | • Deposit discovered by surface drilling – it was delineated by a surface<br>drilling program between 1982 and 1986 |
| 1985 | • Reorganization of the Waterbury Lake joint venture – Cigar Lake Mining<br>Corporation becomes the operator of the Cigar Lake lands and a predecessor to Orano becomes the operator of the remaining Waterbury Lake lands<br> <br><br><br><br>• SMDC has a 50.75% interest |
| 1987-1992 | • Test mining, including sinking shaft 1 to 500 metres and lateral development<br>on 420 metre, 465 metre and 480 metre levels |
| 1988 | • Eldorado Resources Limited merges with SMDC to form Cameco |
| 1993-1997 | • Canadian and Saskatchewan governments authorize the project to proceed to<br>regulatory licensing stage, based on recommendation of the joint federal-provincial panel after public hearings on the project’s environmental impact |
| 2000 | • JBS tested in waste and frozen ore |
| 2001 | • Joint venture approves a feasibility study and detailed engineering begins in<br>June |
| 2002 | • Joint venture is reorganized, new joint venture agreement is signed, Rabbit<br>Lake and JEB toll milling agreements are signed, and we replace Cigar Lake Mining Corporation as Cigar Lake mine operator |
| 2004 | • Environmental assessment process is complete<br><br><br><br> <br>• CNSC issues a construction<br>licence |
| 2005 | • Development begins in January |
| 2006 | • Two water inflow incidents delay development:<br><br><br><br> <br>• in April, shaft 2 floods<br><br><br><br> <br>• in October, underground<br>development areas flood<br> <br><br><br><br>• In November, we begin work to remediate the underground development areas |
| 2008 | • Remediation interrupted by another inflow in August, preventing the mine from<br>being dewatered |
| 2009 | • Remediation of shaft 2 completed in May<br><br><br><br> <br>• We seal the 2008 inflow in<br>October |
| 2010 | • We finish dewatering the underground development areas in February, establish<br>safe access to the 480 metre level, the main working level of the mine, and backfill the 465 metre level<br> <br><br><br><br>• We substantially complete clean-up, inspection, assessment<br>and securing of underground development and resume underground development in the south end of the mine |
| 2011 | • We begin to freeze the ground around shaft 2 and restart freezing the orebody<br>from underground and from the surface<br> <br><br><br><br>• We resume the sinking of shaft 2 and early in 2012 achieve breakthrough to the 480 metre level,<br>establishing a second means of egress for the mine<br> <br><br><br><br>• We receive regulatory approval of our mine plan and begin work on our Seru Bay project<br><br><br><br> <br>• Agreements are signed by the<br>Cigar Lake and McClean Lake joint venture participants to mill all Cigar Lake ore at the McClean Lake mill and the Rabbit Lake toll milling agreement is terminated |
| 2012 | • We achieve breakthrough to the 500 metre level in shaft 2<br><br><br><br> <br>• We assemble the first JBS<br>unit underground and move it to a production tunnel where we commence preliminary commissioning |
| 2013 | • CNSC issues an eight-year operating licence<br><br><br><br> <br>• We begin jet boring in<br>ore |
| 2014 | • First Cigar Lake ore shipped to McClean Lake mill<br><br><br><br> <br>• McClean Lake mill starts<br>producing uranium concentrate from Cigar Lake ore |
2022 ANNUAL INFORMATION FORM Page 41
| 2015 | • We declared commercial production in May |
|---|---|
| 2016 | • We updated the CNSC on our commissioning activities to satisfy a condition in<br>our federal licence |
| 2020 | • In March, production is temporarily suspended as a precautionary measure due to<br>the COVID-19 pandemic<br> <br><br><br><br>• In September, production resumes<br><br><br><br> <br>• In December, production is<br>temporarily suspended as a precautionary measure due to the COVID-19 pandemic |
| 2021 | • In April, we announce plans to restart production<br><br><br><br> <br>• In June, CNSC granted a 10-year renewal of Cigar Lake’s uranium operating licence |
| 2022 | • In February, we announce plans to reduce production at Cigar Lake in 2024 to<br>13.5 million pounds per year (100% basis), 25% below its annual licensed capacity<br> <br><br><br><br>• In May, we acquire an additional 4.522 percentage points in Cigar Lake increasing our interest to<br>54.547% |
| 2023 | • We updated our production plans for Cigar Lake to maintain production of<br>18 million pounds per year (100% basis) in 2024 |
Technical report
| This description is based on the project’s technical report: Cigar Lake Operation, Northern Saskatchewan, Canada, dated March 29,<br>2016 (effective December 31, 2015) except for some updates that reflect developments since the technical report was published. The report was prepared for us in accordance with NI 43-101, by or under the<br>supervision of Scott Bishop, P. Eng., Alain G. Mainville, P. Geo., and Leslie D. Yesnik, P. Eng. The following description has been prepared under the supervision of Biman Bharadwaj, P. Eng., Scott Bishop, P. Eng., Alain D. Renaud, P. Geo., and<br>Lloyd Rowson, P. Eng. They are all qualified persons within the meaning of NI 43-101 but are not independent of us.<br> <br><br><br><br>The conclusions, projections and estimates included in this description are subject to the qualifications, assumptions and exclusions set out in the technical<br>report except as such qualifications, assumptions and exclusions may be modified in this AIF. We recommend you read the technical report in its entirety to fully understand the project. You can download a copy from SEDAR (sedar.com) or from EDGAR<br>(sec.gov). | For information about uranium sales see pages 17 to 20, environmental matters see Our ESG principles and practices andThe regulatory environment starting on pages 84 and 87, and taxes see page 95.<br> <br><br><br><br>For a description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see page 94.<br><br><br><br> <br>For a description of risks that might affect access, title or the right or ability to<br>perform work on the property, see Governance and compliance risks starting at page 110, Social risks starting at page 112 and Environmental risks starting at page 113. |
|---|
About the Cigar Lake property
We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows. In October 2014, the McClean Lake mill produced the first uranium concentrate from ore mined at the Cigar Lake operation. Commercial production was declared in May 2015.
Location
The Cigar Lake mine site is located near Waterbury Lake, approximately 660 kilometres north of Saskatoon. The mine site is near other uranium production operations: McClean Lake mill is 69 kilometres northeast by road and McArthur River mine is 46 kilometres southwest by air from the mine site.
Access
Access to the property is by an all-weather road and by air. Site activities occur year-round, including supply deliveries. There is an unpaved airstrip and air terminal east of the mine site.
Saskatoon, a major population centre south of the Cigar Lake deposit, has highway and air links to the rest of North America.
2022 ANNUAL INFORMATION FORM Page 42
Leases
Surface lease
The CLJV acquired the right to use and occupy the lands necessary to mine the deposit under a surface lease agreement with the province of Saskatchewan. The lease covers approximately 1,042 hectares and expires in May 2044.
We are required to report annually on the status of the environment, land development and progress on northern employment and business development.
Mineral lease
We have the right to mine the deposit under ML 5521, granted to the CLJV by the province of Saskatchewan. The lease covers 308 hectares and expires in December 2031. The CLJV has the right to renew the lease for further 10-year terms.
Mineral claims
A mineral claim gives us the right to explore for minerals and to apply for a mineral lease. There are 38 mineral claims totalling 95,293 hectares, adjoining the mineral lease and surrounding the site. The mineral claims are in good standing until 2037 or later.
Environment, social and community factors
The climate is typical of the continental sub-arctic region of northern Saskatchewan. Summers are short and cool even though daily temperatures can sometimes reach above 30°C. The mean daily temperature for the coldest month is below -20°C, and winter daily temperatures can reach below -40°C.
The deposit is 40 kilometres west of the eastern margin of the Athabasca Basin in northern Saskatchewan. The topography and environment are typical of the taiga forested lands in the Athabasca Basin. This area is covered with 30 to 50 metres of overburden. Vegetation is dominated by black spruce and jack pine. There is a lake known as “Cigar Lake” which, in part, overlays the deposit.
We are committed to building long-lasting and trusting relationships with the communities in which we operate. For more information, see Our ESG principlesand practices at page 84.
The closest inhabited site is Points North Landing, 56 kilometres northeast by road. The community of Wollaston Lake is approximately 80 kilometres by air to the east of the mine site.
Athabasca Basin community resident employees and contractors fly to the mine site from designed pick-up points. Other employees and contractors fly to site from Saskatoon with pickup points in Prince Albert and La Ronge.
Geological setting
The deposit is at the unconformity contact separating late Paleoproterozoic to Mesoproterozoic sandstone of the Athabasca Group from middle Paleoproterozoic metasedimentary gneiss and plutonic rocks of the Wollaston Group. The Key Lake, McClean Lake and Collins Bay deposits all have a similar structural setting. While Cigar Lake shares many similarities with these deposits, it is distinguished from other similar deposits by its size, very high grade, and the high degree of clay alteration.
Cigar Lake’s geological setting is similar to McArthur River’s: the permeable sandstone, which overlays the deposit and basement rocks, contains large volumes of water at significant pressure. Unlike McArthur River, however, the deposit is flat lying with the ore zone being overlain by variably developed clay alteration as opposed to silica enrichment.
Mineralization
The Cigar Lake deposit has the shape of a flat- to cigar-shaped lens and is approximately 1,950 metres in length, 20 to 100 metres in width, and ranges up to 13.5 metres thick, with an average thickness of about 5.4 metres. It occurs at depths ranging between 410 to 450 metres below the surface. The eastern part of Cigar Lake is approximately 670 metres long by 100 metres wide and the western part is approximately 1,280 metres long by 75 metres wide.
The deposit has two distinct styles of mineralization:
| • | high-grade mineralization at the unconformity which includes almost all of the mineral resources and mineral<br>reserves |
|---|---|
| • | fracture controlled, vein-like mineralization which is located either higher up in the sandstone or in the<br>basement rock mass |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 43
The uranium oxide in the form of uraninite and pitchblende occurs as disseminated grains in aggregates ranging in size from millimetres to decimetres, and as massive lenses of mineralization up to a few metres thick in a matrix of sandstone and clay. Coffinite (uranium silicate) is estimated to form less than 3% of the total uranium mineralization.
Geochemically, the deposit contains quantities of the elements nickel, copper, cobalt, lead, zinc, molybdenum and arsenic, but in non-economic concentrations. Higher concentrations of these elements are associated with massive pitchblende or massive sections of arseno-sulphides.
Deposit type
Cigar Lake is an unconformity-associated uranium deposit. Deposits of this type are believed to have formed through a redox reaction at a contact where oxygenated fluids met with reducing fluids. The geological model was confirmed by surface drilling, underground drilling, development, and production activities.
About the Cigar Lake operation
Cigar Lake is a developed property with sufficient surface rights to meet current mining operation needs. We are currently mining in the eastern part of the ore body.
Permits
Please see page 49 for more information about regulatory approvals for Cigar Lake.
Infrastructure
Surface facilities are 490 metres above sea level. The site includes:
| • an underground mine with two shafts<br><br><br><br> <br>• access road joining the<br>provincial highway and McClean Lake<br> <br><br><br><br>• site roads and site grading<br><br><br><br> <br>• airport and terminal<br><br><br><br> <br>• employee residence and<br>construction camp<br> <br><br> <br>• Shaft<br>No. 1 and No. 2 surface facilities<br> <br><br><br><br>• freeze plants and brine distribution equipment<br><br><br><br> <br>• surface freeze pads<br><br><br><br> <br>• water supply, storage and<br>distribution for industrial water, potable water and fire suppression<br> <br><br><br><br>• propane, diesel and gasoline storage and distribution<br><br><br><br> <br>• electrical power substation<br>and distribution | • compressed air supply and distribution<br><br><br><br> <br>• mine water storage ponds and<br>water treatment<br> <br><br> <br>• sewage<br>collection and treatment<br> <br><br><br><br>• surface and underground pumping system installation<br><br><br><br> <br>• waste rock stockpiles<br><br><br><br> <br>• garbage disposal landfill<br><br><br><br> <br>• administration, maintenance<br>and warehousing facilities<br> <br><br><br><br>• underground tunnels<br> <br><br><br><br>• ore load out facility<br> <br><br><br><br>• concrete batch plant<br> <br><br><br><br>• Seru Bay pipeline<br> <br><br><br><br>• emergency power generating facilities |
|---|
The Cigar Lake mine site contains all the necessary services and facilities to operate a remote underground mine, including personnel accommodation, access to water, airport, site roads and other necessary buildings and infrastructure.
Water, power and heat
Waterbury Lake, which is nearby, provides water for the industrial activities and the camp. The site is connected to the provincial electricity grid, and it has standby generators in case there is an interruption in grid power.
Cigar Lake operates throughout the year despite cold winter conditions. During the winter, we use propane-fired burners to heat the fresh air necessary to ventilate the underground workings.
Employees
Employees are recruited with preference given to residents of northern Saskatchewan.
Mining
The Cigar Lake deposit presents unique challenges that are not typical of traditional hard or soft rock mines. These challenges are the result of mining in or near high-pressure ground water in challenging ground conditions with significant radiation concerns due to the high-grade uranium and elements of concern in the orebody with respect to water quality. We take significant steps and precautions to reduce the risks. Mine designs and the mining method are selected based on their ability
2022 ANNUAL INFORMATION FORM Page 44
to mitigate hydrological, radiological, and geotechnical risks. Operational experience gained since the start of production has resulted in a significant reduction in risk. However, there is no guarantee that our efforts to mitigate risk will be successful.
Mining methods
We use the JBS method to mine the Cigar Lake deposit.
Bulkground freezing
The permeable sandstone that overlays the deposit and basement rocks contains large volumes of water under significant pressure. From surface, we freeze the ore zone and surrounding ground in the area to be mined to prevent water from entering the mine, to help stabilize weak rock formations, and meet our production schedule. This system freezes the deposit and underlying basement rock in two to four years, depending on water content and geological conditions. We have identified greater variation of the freeze rates of different geological formations encountered in the mine, based on information obtained through surface freeze drilling. To manage our risks and to meet our production schedule, the area being mined must meet specific ground freezing requirements before we begin jet boring. Bulk freezing reduces but does not eliminate the risk of water inflows.
Artificial ground freezing is accomplished by drilling a systematic grid of boreholes through the orebody from surface. A network of supply and return pipes on surface convey a calcium chloride brine to and from each hole. The warm brine returning from each hole is chilled to a temperature of approximately -30ºC at the surface freeze plant and recirculated.
JBS mining
As a result of the unique geological conditions at Cigar Lake, we are unable to utilize traditional mining methods that require access above the ore, which necessitated the development of a non-entry mining method specifically adapted for this deposit. After many years of test mining, we selected jet boring, a non-entry mining method, and it has been used since we began mining in 2014. This method involves:
| • | drilling a pilot hole into the frozen orebody, inserting a high-pressure water jet and cutting a cavity out of<br>the frozen ore; |
|---|---|
| • | collecting the ore and water mixture (slurry) from the cavity and pumping it to a storage sump, allowing it to<br>settle; |
| --- | --- |
| • | using a clamshell, transporting the ore from the storage sump to an underground grinding and processing circuit;<br> |
| --- | --- |
| • | once mining is complete, filling each cavity in the orebody with concrete; and |
| --- | --- |
| • | starting the process again with the next cavity. |
| --- | --- |
This is a non-entry method, which means mining is carried out from headings in the basement rock below the deposit, so employees are not exposed to the ore. This mining approach is highly effective at managing worker exposure to radiation levels. Combined with ground freezing and the cuttings collection and hydraulic conveyance system, jet boring reduces radiation exposure to acceptable levels that are below regulatory limits.
The mine equipment fleet is currently comprised of three JBS units plus other equipment to support mine development, drilling and other services, and is sufficient to meet production requirements for the remainder of the mine life.
We have divided the orebody into production panels. At least three production panels need to be frozen at one time to achieve the full annual production rate of 18 million pounds. One JBS machine will be located below each frozen panel and the three
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JBS machines required are currently in operation. Two machines actively mine at any given time while the third is moving, setting up, or undergoing maintenance.
Mine development
Mine development for construction and operation uses two basic approaches: drill and blast with conventional ground support is applied in areas with a competent rock mass. Most permanent areas of the mine, which contain the majority of the installed equipment and infrastructure, are hosted in competent rock mass and are excavated and supported conventionally. The production tunnels immediately below the orebody are primarily in poor, weak rock mass and are excavated and supported using the New Austrian Tunnelling Method (NATM). NATM was adopted as the primary method of developing new production cross-cuts, replacing the former Mine Development System (MDS).
NATM, as applied at Cigar Lake, involves a multi-stage sequential mechanical excavation, extensive external ground support and a specialized shotcrete liner. The liner system incorporates yielding elements which permit controlled deformation required to accommodate additive pressure from mining and ground freezing activities. The production tunnels have an inside diameter of five metres and are approximately circular in profile.
We plan our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk and apply extensive additional technical and operating controls for all higher risk development.
In order to successfully achieve the planned production schedule, we must continue to successfully transition into new mining areas, which includes mine development and investment in critical support infrastructure. If development work is delayed for any reason, including availability of storage capacity for waste rock, our ability to meet our future production plans may be impacted.
Mine access
There are two main levels in the mine: the 480 and 500 metre levels. Both levels are in the basement rocks below the unconformity. Mining is conducted from the 480-metre level which is located approximately 40 metres below the ore zone. The main underground processing and infrastructure facilities are located on this level. The 500-metre level is accessed via a ramp from the 480-metre level. The 500-metre level provides for the main ventilation exhaust drift for the mine, the mine dewatering sump and additional processing facilities. All construction required for production has been completed.
Processing
Cigar Lake ore slurry is processed in two locations:
Cigar Lake – Ore slurry produced by the JBS is pumped to Cigar Lake’s underground crushing, grinding and thickening facility. The resulting finely ground, high density ore slurry is pumped 500 meters to surface to one of the two slurry holding tanks. It is blended and thickened, further removing excess water. The final slurry, at an average grade of approximately 17%, is pumped into transport truck containers like the ones used at McArthur River.
Water from this process, including water from underground operations, is treated on the surface. Any excess treated water is released into the environment.
McClean Lake – Containers of ore slurry are trucked to Orano’s McClean Lake mill, 69 kilometres to the northeast for further processing (Leaching to Yellowcake Packaging). See Toll milling agreement below for a discussion of this arrangement.
Recovery and metallurgical testing
Extensive metallurgical test work was performed on core samples of Cigar Lake ore over a seven-year period from 1992 to 1999. This work was used to design the McClean Lake mill circuits relevant to Cigar Lake ore and associated modifications. Samples used for metallurgical test work may not be representative of the deposit as a whole. Additional test work, completed in 2012 with drill core samples, verified that a high uranium recovery rate could be achieved regardless of the variability of the ore. Test work also concluded that more hydrogen gas evolution took place than previously anticipated, which resulted in modifications to the leaching circuit. Leaching modifications were completed in 2014.
The 1992 – 1999 work was performed in France at Orano’s SEPA test centre. The results of this test work have provided the core process criteria for the design of the additions and modifications required at the McClean Lake mill for processing Cigar
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Lake ore. To date, a range of monthly average ore grades, as high as 28% U3O8, have been processed at the McClean Lake milling facility. Based on the test results and past mill performance, an overall uranium recovery of 98.8% is expected.
There is a risk that elevated arsenic concentration in the mill feed may result in increased leaching circuit solution temperatures. The leach process cooling system was updated in 2016 and testing confirmed solution temperature control. The plan is to continue to monitor leaching temperature.
Tailings
Cigar Lake site does not have a TMF. The ore is processed at the McClean Lake mill. See Toll milling agreement below for a discussion of the McClean Lake TMF.
Waste rock
The waste rock piles are separated into three categories:
| • | clean rock – will remain on the mine site for use as aggregate for roads, concrete backfill and future site<br>reclamation |
|---|---|
| • | mineralized waste (>0.03% U3O8) – will be disposed of underground at the Cigar Lake mine; and |
| --- | --- |
| • | waste with acid-generating potential – temporarily stored on lined pads |
| --- | --- |
The latter two stockpiles are contained on lined pads; however, no significant mineralized waste has been identified during development to date.
Production
The mine plan is designed to extract all current Cigar Lake mineral reserves. The following is a general summary of the mine plan production schedule parameters on a 100% basis for these mineral reserves:
| Total mill production | • 153 million pounds of<br>U3O8, based on current mineral reserves and an overall milling recovery of 98.8%<br><br><br><br> <br>• Full annual production of<br>18 million pounds of U3O8 |
|---|---|
| Total mine production | • 408,000 tonnes of ore |
| Average annual mine production | • 100 to 200 tonnes per day during peak production, depending on ore<br>grade |
| Average mill feed grade | • 17.2% U3O8 |
Total packaged production from Cigar Lake in 2022 was 18 million pounds U3O8 (9.6 million pounds our share) compared to 12.2 million pounds U3O8 (6.1 million pounds our share) in 2021. 2021 production was impacted by suspensions, which were a precautionary measure due to the COVID-19 pandemic. In 2022, we were successful in catching up on development work that had been deferred from 2021. Our share of production for 2022 has been updated to reflect the ownership increase effective May 19, 2022.
Consistent with our strategy to align our production decisions with our contract portfolio and market opportunities, we have updated our 2024 production plan. We expect to maintain production at the licensed rate of 18 million pounds (100% basis) per year based on our contracting success and the improved outlook for the uranium market compared to our previous plan of 13.5 million pounds (100% basis) per year in 2024.
Inflation, the availability of personnel with the necessary skills and experience, and the impact of supply chain challenges on the availability of materials and reagents carry with them the risk of not achieving our production plans, production delays and increased costs in 2023 and future years.
Decommissioning and financial assurances
An updated preliminary decommissioning plan for Cigar Lake was submitted in 2017 and 2018 as part of the regular five-year update schedule. Prior to revising the letters of credit, approval of the updated plan is required from the province and CNSC staff as well as formal approval from the CNSC through a Commission proceeding. The necessary approvals were received. The document included our estimated cost for implementing the plan and addressing known environmental liabilities.
The reclamation and remediation activities associated with waste rock and tailings at the McClean Lake mill are covered by the plans and cost estimates for this facility.
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In 2022, as part of the required five-year update schedule, we submitted a revised preliminary decommissioning estimate for Cigar Lake, which is currently being reviewed by the province and CNSC staff.
For more information, see Nuclear wastemanagement and decommissioning.
Water inflow and mine/mill development
Cigar Lake water inflow incidents
From 2006 through 2008, the Cigar Lake project suffered several setbacks because of three water inflow incidents. The first occurred in 2006, resulting in the flooding of the then partially completed Shaft No. 2. The two subsequent incidents involved inflows in the mine workings connected to Shaft No. 1 and resulted in flooding of the mine workings. We executed recovery and remediation plans for all three inflows. Re-entry into the main mine workings was achieved in 2010 and work to secure the mine was completed in 2011. The mine is fully remediated and entered commercial production in 2015.
Lessons learned from the inflows have been applied to the subsequent mine plan and development to reduce the risk of future inflows and improve our ability to manage them should they occur.
Increased pumping capacity
In 2012, we increased the installed mine dewatering capacity to 2,500 cubic metres per hour. Mine water treatment capacity has been increased to 2,550 cubic metres per hour, and regulatory approval to discharge routine and non-routine treated water to Seru Bay is in place. As a result, we believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum inflow.
Current status of development
Construction of all major permanent underground development and process facilities required for the duration of the mine life is complete. A number of underground access drifts and production crosscuts remain to be driven as part of ongoing mine development to sustain production rates.
On surface, construction of all permanent infrastructure required to achieve nameplate capacity has been completed.
Underground mine development continued in 2022. We completed the first production crosscut in the western portion of the orebody in preparation for ore mining starting in the second quarter of 2023.
During 2022, we:
| • | executed planned 21-day annual maintenance activities in July<br> |
|---|---|
| • | executed production activities from four production tunnels in the eastern part of the orebody<br> |
| --- | --- |
| • | in alignment with our long-term production planning, brought one new panel online as another production panel was<br>depleted |
| --- | --- |
| • | continued underground header construction activities and expanded our ground freezing program to ensure continued<br>frozen ore inventory |
| --- | --- |
In 2023, we plan to:
| • | continue production activities focused on bringing two new production panels online |
|---|---|
| • | complete surface freeze drilling and complete construction and commissioning of freeze distribution<br>infrastructure expansion in support of future production |
| --- | --- |
| • | continue underground mine development on two new production tunnels as well as expand ventilation and access<br>drifts in alignment with the long-term mine plan |
| --- | --- |
| • | continue upgrades to process water handling circuits and the surface backfill batch plant to support ongoing<br>operations |
| --- | --- |
| • | execute a surface delineation drilling program and underground geotechnical drilling program<br> |
| --- | --- |
The McClean Lake mill has been expanded to process and package all Cigar Lake ore.
Toll milling agreement
The McClean Lake joint venture agreed to process Cigar Lake’s ore slurry at its McClean Lake mill, according to the terms in its agreement with the CLJV: JEB toll milling agreement (effective January 1, 2002 and amended and restated effective November 30, 2011), dedicating the necessary McClean Lake mill capacity to process and package 18 million pounds of Cigar Lake uranium concentrate annually.
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The CLJV pays a toll milling fee and its share of milling expenses.
The McClean Lake mill started receiving Cigar Lake ore in March 2014 and produced its first drum of Cigar Lake yellowcake in October 2014. All of Cigar Lake’s ore slurry from current mineral reserves will be processed at the McClean Lake mill, operated by Orano. Orano does not expect any new major infrastructure is necessary at McClean Lake mill to receive and process Cigar Lake’s mineral reserves. Minor upgrades related to throughput optimisation were completed in 2020.
The McClean Lake joint venture commenced work in 2012 to optimize its TMF to accommodate all of Cigar Lake’s current mineral reserves. The first stage of the work is complete. Additional work, which involves increasing the required elevation of a liner for the facility, is scheduled to take place from 2022 to 2024. With the liner extended, the TMF is expected to have capacity to receive tailings from processing all of Cigar Lake’s current mineral reserves.
In January 2022, the CNSC granted the McClean Lake joint venture an amendment to its licence to expand its TMF, which will provide capacity for tailings from processing additional ore.
The McClean Lake joint venture is responsible for all costs of decommissioning the McClean Lake mill. As well, the joint venture is responsible for the liabilities associated with tailings produced from processing Cigar Lake ore at the McClean Lake mill.
The collective agreement with unionized employees at the McClean Lake mill ends on May 31, 2025.
Regulatory approvals
There are three key permits that are required to operate the mine.
Operating and processing licences
Federally, Cigar Lake holds a “Uranium Mine Licence” from the CNSC with a corresponding Licence Conditions Handbook (LCH). Provincially, Cigar Lake holds an “Approval to Operate Pollutant Control Facilities” from the SMOE and a “Water Rights Licence to Use Surface Water and Approval to Operate Works” from the Saskatchewan Watershed Authority.
The CNSC licence expires on June 30, 2031. The SMOE approval was renewed in 2017 and expires in 2023. The Saskatchewan Watershed Authority water rights licence was obtained in 1988 and was last amended in July 2011. It is valid for an undefined term.
The current Cigar Lake LCH authorizes an annual production rate up to 18 million pounds per year. In 2016, Orano received approval to increase annual production at the McClean Lake mill to 24 million pounds per year.
Water treatment/effluent discharge system
The mine dewatering system was designed and constructed to handle both routine and non-routine water treatment and effluent discharge, and it has been approved and licensed by the CNSC and the SMOE.
We began discharging treated water to Seru Bay in August 2013 following the receipt of regulatory approvals.
The Cigar Lake orebody contains elements of concern with respect to the water quality and the receiving environment. The distribution of elements such as arsenic, molybdenum, selenium and others is non-uniform throughout the orebody, and this can present challenges in attaining and maintaining the required effluent concentrations.
There have been ongoing efforts to optimize the current water treatment process and water handling systems to ensure acceptable environmental performance, which is expected to avoid the need for additional capital upgrades and potential deferral of production.
Operating andcapital costs
The following is a summary of the Cigar Lake operating and capital cost estimates for the remaining life of mine, stated in constant 2022 dollars and reflecting a forecast life-of-mine mill production of 153 million pounds.
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| Operating Costs ($Cdn million) | Total(2023 – 2031) | |
|---|---|---|
| Cigar Lake Mining | ||
| Site administration | $ | 440.8 |
| Mining costs | 604.0 | |
| Process | 240.3 | |
| Corporate overhead | 90.3 | |
| Total mining costs | $ | 1,375.4 |
| McClean Lake Milling | ||
| Administration | $ | 422.2 |
| Milling costs | 750.5 | |
| Corporate overhead | 69.6 | |
| Toll milling | 156.9 | |
| Total milling costs | $ | 1,399.2 |
| Total operating costs | $ | 2,774.6 |
| Total operating cost per pound U3O8 | $ | 18.13 |
Note: presented as total cost to the CLJV (100% basis)
Operating costs consist of annual expenditures at Cigar Lake to mine the ore, treat the ore underground, including crushing, grinding and density control, followed by pumping the resulting slurry to surface for transportation to McClean Lake.
Operating costs at McClean Lake consist of the cost of offloading and leaching the Cigar Lake ore slurry into uranium solution and further processing into calcined U3O8 product.
| Capital Costs ($Cdn million) | Total(2023 – 2031) | |
|---|---|---|
| Cigar Lake Mine Development | $ | 76.8 |
| Cigar Lake Mine Capital | ||
| Sustaining capital | $ | 73.2 |
| Capacity replacement capital | 33.3 | |
| Growth capital | — | |
| Reclamation | — | |
| Total mine capital | $ | 106.5 |
| McClean Lake mill sustaining capital | $ | 107.3 |
| McClean Lake mill expansion capital | 47.3 | |
| Total mill capital | $ | 154.6 |
| Total capital costs | $ | 337.9 |
Note: presented as total cost to the CLJV (100% basis)
Estimated capital costs to the CLJV include sustaining capital for Cigar Lake and McClean Lake mill, as well as underground development at Cigar Lake to bring mineral reserves into production. Overall, the largest capital cost at Cigar Lake is surface freeze drilling and brine distribution infrastructure. Other significant capital includes tunnel outfitting and mine development costs.
Our expectations and plans regarding Cigar Lake, including forecasts of operating and capital costs, production and mine life are forward-looking information, and are based specifically on the risks and assumptions discussed on pages 3, 4 and 5. We may change operating or capital spending plans in 2023, depending upon uranium markets, our financial position, results of operation and other factors. Estimates of expected future production and capital and operating costs are inherently uncertain, particularly beyond one year, and may change materially over time.
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Exploration, drilling, sampling, data quality and estimates
There are no historical estimates within the meaning of NI 43-101 to report. The Cigar Lake uranium deposit was discovered in 1981 by surface exploration drilling.
We focus most of our exploration activities on mineral lease ML 5521. Orano is responsible for exploration activity on the 38 surrounding mineral claims. The data from the exploration program on the 38 mineral claims is not part of the database used for the estimate of the mineral resources and mineral reserves at Cigar Lake.
Exploration
After the 2006 water inflow events, it was recognized that more detailed geophysical information in the immediate deposit area was required. Since 2006, a number of geophysical surveys over the Cigar Lake deposit provided additional knowledge on geological structures and fault zones. In the fall of 2007, a supplementary geophysical program was conducted over a portion of the eastern area of the deposit to identify major structures within the sandstone column. This information has since been incorporated into our geological models. These are regularly updated as additional information is collected, allowing for better mine planning and mitigation of potential risk.
Drilling
Surface drilling – mineral lease
The last diamond drillhole of the 1981 program was located south of Cigar Lake and was the discovery hole for the Cigar Lake uranium deposit. The deposit was subsequently delineated by surface drilling between 1982 and 1986, and followed by several small drilling campaigns to gather geotechnical and infill data between 1986 and 2007. Additional diamond drilling campaigns over the eastern part of the deposit and the western portion were conducted by us between 2007 and 2012, which targeted a broad range of technical objectives. In 2016, we initiated a surface delineation program on the western portion of the deposit, which ended in 2017.
Average drill depths for surface delineation holes range from approximately 460 m to 500 m, with the majority of surface freezeholes drilled to a depth of approximately 462 m. Delineation drilling in the eastern area has been done at a nominal drillhole fence spacing of 25 to 50 m (east-west), with holes at 20 to 25 m (north-south) spacing on the fences. The approximate surface freezehole spacing is 7 x 7 metres.
The western area was historically drilled at a nominal drillhole fence spacing of 200 m, with holes at 20 m spacing on the fences. Additional infill drillholes were completed in 2011 and 2012 by Cameco for select areas, locally reducing the drillhole spacing down to an approximate 15 x 15 m pattern followed by additional drilling in 2016 and 2017 to upgrade the majority of the resource to the indicated category. A total of 125 delineation holes currently inform the western area mineral resource estimate. Minor delineation drilling is planned for 2023.
Drilling results have been used to delineate and interpret the 3-dimensional geometry of the mineralized areas, the litho structural settings, the geotechnical conditions, and to estimate the distribution and content of uranium and other elements.
Surface freezehole drilling over the eastern part of the deposit has been ongoing since 2012. Drilling results obtained between September 2021 and September 2022, representing 146 additional freezeholes, are reflected in our reported mineral resources and reserves.
Underground drilling – mineral lease
Diamond drilling from underground is primarily to ascertain rock mass characteristics in advance of development and mining. Cigar Lake Mining Corporation, the previous operator, and Cameco have conducted underground geotechnical drilling since 1989 at Cigar Lake, except for the period from 2007 to 2009 during which time the mine was flooded.
At one time, freezeholes were drilled from underground into the deposit for the purpose of freezing the ground prior to mining. No underground freezeholes have been drilled since 2006. None of them are currently used for freezing or for mineral resource and reserve estimation purposes.
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Sampling, analysis and data verification
Sampling
Vertical surface drilling generally represents the true thickness of the zone given the flat-lying mineralization. All holes are core drilled and gamma probed whenever possible. Cigar Lake uses a high-flux gamma probe designed and constructed by alphaNUCLEAR, a member of the Cameco group of companies. This high-flux gamma probe utilizes two Geiger Mûller tubes to detect the amount of gamma radiation emanating from the surroundings. The count rate obtained from the high-flux probe is compared against chemical assay results to establish a correlation to convert corrected probe count rates into equivalent % U3O8 grades for use when assay results are unavailable. The consistency between probe data and chemical assays demonstrates that secular equilibrium exists within the deposit. Approximately 25% of the data used to estimate mineral resources is obtained from assays, and in these cases, the core depth is validated by comparing the down-hole gamma survey results with a hand-held scintillometer on core before it is logged, photographed, and then sampled for uranium analysis. Attempts are made to avoid having samples cross geological boundaries.
When sampled, the entire core from each sample interval is taken for assay or other measurements to characterize the physical and geochemical properties of the deposit, except for some of the earliest sampling in 1981 and 1982 (which were validated or removed following subsequent delineation drilling and whole core assay measurements). This reduces the potential sample bias inherent when splitting core. Core recovery throughout the deposit has generally been very good. However, in areas of poor core recovery, uranium grade determination is generally based on radiometric probe results.
The typical sample collection process at our operations is performed by or under the supervision of a qualified geoscientist and includes the following procedures:
| • | marking the sample intervals on the core boxes at nominal 50 cm sample lengths |
|---|---|
| • | collection of the samples in plastic bags, taking the entire core |
| --- | --- |
| • | documentation of the sample location, assigning a sample number, and description of the sample, including<br>radiometric values from a hand-held device |
| --- | --- |
| • | bagging and sealing, with sample tags inside bags and sample numbers on the bags; and |
| --- | --- |
| • | placement of samples in steel drums for shipping |
| --- | --- |
Sample security
Current sampling protocols dictate that all samples are collected and prepared in a restricted core processing facility. Core samples are collected and transferred from core boxes to high-strength plastic sample bags, then sealed. The sealed bags are then placed in steel drums and shipped in compliance with the Transport of Dangerous Goods regulations with tamper-proof security seals. Chain of custody documentation is present from inserting samples into steel drums to final delivery of results by SRC.
All samples collected are prepared and analysed under close supervision of qualified personnel at SRC, which is a restricted access laboratory licensed by the CNSC.
Analysis
Since 2002, assay sample preparation has been done at SRC, which is independent of the participants of CLJV. It involves jaw crushing to 60% @ -2 mm and splitting out a 100 – 200 g sub-sample using a riffle splitter. The sub-sample is pulverized to 90% @ -106 microns using a puck and ring grinding mill. The pulp is then transferred to a bar coded plastic snap top vial. Assaying by SRC involves digesting an aliquot of pulp in concentrated 3:1 HCL:HNO3 on a hot plate for approximately one hour. The volume is then made up in a 100 ml volumetric flask using deionized water prior to analysis by ICP-OES. Instruments used in the analysis are calibrated using certified commercial solutions. This method is ISO/IEC 17025:2017 accredited by the Standards Council of Canada.
Quality control and data verification
The quality assurance and quality control procedures used during the early drilling programs were typical for the time. The majority of uranium assays in the database from the early drilling programs were obtained from Loring Laboratories Ltd., which was independent of the participants of CLJV. For uranium assays up to 5% U3O8, 12 standards and two blanks were run with each batch of samples and for uranium assays over 5% U3O8, a minimum of four standards were run with each batch of samples.
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More recent sample preparation and assaying is being completed under the close supervision of qualified personnel at SRC and includes preparing and analysing standards, duplicates, and blanks. At least two standards are analysed for each 40-sample batch, with another sample being analyzed in duplicate. We also include a pulp repeat and 1 split sample repeat with every group. Samples that fail quality controls are re-analyzed.
The original database, which forms part of the database used for the current mineral resource and mineral reserve estimates, was compiled by previous operators. Many of the original signed assay certificates are available and have been reviewed by Cameco geologists.
In 2013, Cigar Lake implemented an SQL server based centralized geological data management system to manage all drillhole and sample related data. All core logging, sample collection, downhole probing and sample dispatching activities are carried out and managed within this system. All assay, geochemical and physical analytical results obtained from the external laboratory are uploaded directly into the centralized database, thereby mitigating potential for manual data transfer errors. The database used for the current mineral resource and mineral reserve estimates was validated by Cameco qualified geoscientists.
Additional data quality control measures include:
| • | review of drillhole collar coordinates and downhole deviations in the database against planned location of the<br>holes. All results were within acceptable tolerances. |
|---|---|
| • | comparison of the information in the database against the original data, including paper logs, assay certificates<br>and original probing files as required. Approximately 10% of holes in the resource estimate update were compared against the assay certificates with no discrepancies observed. |
| --- | --- |
| • | validation of core logging information in plan and section views, and review of logs against photographs of the<br>core. Core logging information reviewed during geological modelling. Three historical holes were removed from the mineral resource update dataset following the addition of new surface freeze hole information. |
| --- | --- |
| • | checking for data errors such as overlapping intervals and out of range values. No issues were observed in 2022.<br> |
| --- | --- |
| • | radiometric probes undergo annual servicing and re-calibration as well as<br>additional checks including control probing to ensure precision and accuracy of the probes. All probes were serviced and re-calibrated. Control probing results were within acceptable tolerances in 2022.<br> |
| --- | --- |
| • | validating uranium grades comparing radiometric probing with core radioactivity measurements and sample assay<br>results. Uranium grades were reviewed during the 2022 mineral resource update. A review of the correlation to convert corrected probe count rates into equivalent % U3O8 grades was initiated. |
| --- | --- |
Since the start of commercial production, we have compared the uranium block model with mine production results on a quarterly basis to ensure an acceptable level of accuracy is maintained. Historically, we have seen acceptable variances, but in 2022, we saw apparent model overperformance variances justifying further review.
Our geoscientists, including a qualified person as such term is defined in NI 43-101, have witnessed or reviewed drilling, core handling, radiometric probing, logging, sampling facilities and data verification procedures employed at the Cigar Lake operation and consider the methodologies to be satisfactory and the results representative and reliable. There has been no indication of significant inconsistencies in the data used or verified nor any failures to adequately verify the data.
Accuracy
We are satisfied with the quality of data and consider it valid for use in the estimation of mineral resources and reserves for Cigar Lake. Comparison of actual mine production with expected production supports this opinion.
Mineral reserve and resource estimates
Please see page 78 for our mineral reserve and resource estimates for Cigar Lake.
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Uranium – Tier-one operations
Inkai
| 2022 Production (100% basis)<br> <br><br><br><br>8.3M lbs<br> <br><br><br><br>2023 Production Outlook (100% basis)<br> <br><br><br><br>8.3M lbs<br> <br><br><br><br>Estimated Reserves (our share)<br> <br><br><br><br>108.7M lbs<br> <br><br><br><br>Estimated Mine Life<br> <br><br><br><br>2045 (based on licence term) **** |
|---|
Inkai is a very significant uranium deposit, located in Kazakhstan. The operator is JV Inkai limited liability partnership, which we jointly own (40%)^1^with Kazatomprom (60%).
Inkai is considered a material uranium property for us. There is a technical report dated January 25, 2018 (effective January 1, 2018) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).
| Location | South Kazakhstan | ||
|---|---|---|---|
| Ownership | 40%^1^ | ||
| Mine type | In situ recovery (ISR) | ||
| End product | Uranium concentrate | ||
| Certifications | BSI OHSAS 18001 | ||
| ISO 14001 certified | |||
| Estimated reserves | 108.7 million pounds (proven and probable), average grade U3O8: 0.04% | ||
| Estimated resources | 35.6 million pounds (measured and indicated), average grade<br>U3O8: 0.03% | ||
| 9.6 million pounds (inferred), average grade U3O8: 0.03% | |||
| Licensed capacity (wellfields) | 10.4 million pounds per year (our share 4.2 million pounds per year*)^1^ | ||
| Licence term | Through July 2045 | ||
| Total packaged production: 2009 to 2022 | 81 million pounds (100% basis) | ||
| 2022 production | 8.3 million pounds (100% basis)^1^ | ||
| 2023 production outlook | 8.3 million pounds (100% basis)*^1^ | ||
| Estimated decommissioning cost (100% basis) | $30 million (US) (100% basis) | ||
| All values shown, including reserves and resources, represent our share only, unless indicated. | |||
| ^1^ Our<br>ownership interest in the joint venture is 40% and we equity account for our investment. As such, our share of production is shown as a purchase. |
Business structure
JV Inkai is a Kazakhstan limited liability partnership between two companies:
| • | Cameco – 40% |
|---|---|
| • | Kazatomprom (KAP) – 60% |
| --- | --- |
History
| 1976-78 | • Deposit is discovered<br><br><br><br> <br>• Exploration drilling<br>continues until 1996 |
|---|---|
| 1979 | • Regional and local hydrogeology studies begin<br><br><br><br> <br>• Borehole tests characterize<br>the four aquifers within the Inkai deposit (Uvanas, Zhalpak, Inkuduk and Mynkuduk) |
| 1988 | • Pilot test in the northeast area of block 1 begins, lasts 495 days and<br>recovers 92,900 pounds of uranium |
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| 1993 | • First Kazakhstan estimates of uranium resources for block 1 |
|---|---|
| 1996 | • First Kazakhstan estimates of uranium resources for block 2<br><br><br><br> <br>• Kazakhstan regulators<br>registers JV Inkai, a joint venture among us, Uranerzbergbau-GmbH and KATEP |
| 1997 | • KAP is established |
| 1998 | • KATEP transfers all of its interest in JV Inkai to KAP<br><br><br><br> <br>• We acquire all of<br>Uranerzbergbau-GmbH’s interest in JV Inkai, increasing our interest to 66 2/3%<br> <br><br><br><br>• We agree to transfer a 6 2/3% interest to KAP, reducing our holdings to a 60%<br>interest |
| 1999 | • JV Inkai receives a mining licence for block 1 and an exploration with<br>subsequent mining licence for blocks 2 and 3 from the government of Kazakhstan |
| 2000 | • JV Inkai and the government of Kazakhstan sign a subsoil use contract (called<br>the resource use contract), which covers the licences issued in 1999 (see above) |
| 2002 | • Pilot leach test in the north area of block 2 begins |
| 2005 | • Construction of ISR commercial processing facility at block 1<br>begins |
| 2006 | • Complete pilot leach test at block 2<br><br><br><br> <br>• Exploration-delineation<br>drilling initiated at block 3 |
| 2007 | • Sign Amendment No.1 to the resource use contract, extending the exploration<br>period at blocks 2 and 3 |
| 2008 | • Commission front half of the main processing plant in the fourth quarter, and<br>begin processing solution from block 1 |
| 2009 | • Sign Amendment No. 2 to the resource use contract, which approves the<br>mining licence at block 2, extends the exploration period for block 3 to July 13, 2010, and requires JV Inkai to adopt the new tax code and meet the Kazakhstan content thresholds for human resources, goods, works and services<br><br><br>• Commission the main processing plant, and started commissioning the first satellite<br>plant |
| 2010 | • Receive regulatory approval for commissioning of the main processing plant<br><br><br><br> <br>• File a notice of potential<br>commercial discovery at block 3<br> <br><br><br><br>• Receive approval in principle for the extension of block 3 exploration for a five-year appraisal<br>period that expires July 2015, and an increase in annual production from blocks 1 and 2 to 3.9 million pounds (100% basis) |
| 2011 | • Receive regulatory approval for commissioning of the first satellite plant<br><br><br><br> <br>• Sign Amendment No. 3 to<br>the resource use contract, which extends the exploration period for block 3 to July 2015 and provides government approval to increase annual production from blocks 1 and 2 to 3.9 million pounds (100% basis)<br><br><br><br> <br>• Sign a memorandum of<br>agreement with KAP to increase annual production from blocks 1 and 2 from 3.9 million pounds to 5.2 million pounds (100% basis) |
| 2012 | • Sign a memorandum of agreement with KAP setting out the framework to increase<br>annual production from blocks 1 and 2 to 10.4 million pounds (100% basis), to extend the term of JV Inkai’s resource use contract through 2045 and to cooperate on the development of uranium conversion capacity, with the primary focus on<br>uranium refining rather than uranium conversion<br> <br><br><br><br>• Start construction of a test leach facility at block 3 |
| 2013 | • Sign Amendment No. 4 to the resource use contract, which provides<br>government approval to increase annual production from blocks 1 and 2 to 5.2 million pounds (100% basis) |
| 2015 | • At block 3, construction of the test leach facility is completed and the pilot<br>leach test initiated |
| 2016 | • Sign an agreement with KAP and JV Inkai to restructure and enhance JV Inkai,<br>subject to closing, increasing KAP’s holdings to a 60% interest and reducing our holdings to a 40% interest<br> <br><br><br><br>• Sign Amendment No. 5 to the resource use contract, which extends the exploration period for<br>block 3 to July 2018 |
| 2017 | • In December, close the agreement with KAP and JV Inkai to restructure and<br>enhance JV Inkai. Under the agreement, effective January 1, 2018, our ownership interest dropped to 40% and we will equity account for our investment.<br> <br><br><br><br>• Sign Amendment No. 6 to the resource use contract, which grants JV Inkai the right to produce<br>up to 10.4 million pounds per year and extends the term of the resource use contract until July 13, 2045 |
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| Technical report<br> <br><br><br><br>This description is based on the project’s technical report: Inkai Operation, South Kazakhstan Oblast, Republic of Kazakhstan, dated January 25, 2018<br>(effective January 1, 2018) except for some updates that reflect developments since the technical report was published. The report was prepared for us in accordance with NI 43-101, by or under the<br>supervision of Darryl Clark, PhD, FAusIMM, Alain G. Mainville, P. Geo., Stuart B. Soliz, P. Geo., and Robert J. Sumner, PhD, P. Eng. The following description has been prepared under the supervision of Biman Bharadwaj, P. Eng., Scott Bishop, P.<br>Eng., Sergey Ivanov, P. Geo., and Alain D. Renaud, P. Geo. They are all qualified persons within the meaning of NI 43-101 but are not independent of us.<br><br><br><br> <br>The conclusions, projections and estimates included in this description are subject to<br>the qualifications, assumptions and exclusions set out in the technical report except as such qualifications, assumptions and exclusions may be modified in this AIF. We recommend you read the technical report in its entirety to fully understand the<br>project. You can download a copy from SEDAR (sedar.com) or from EDGAR (sec.gov). | For information about environmental matters, see Our ESGprinciples and practices and The regulatory environment starting on pages 84 and 87.<br> <br><br><br><br>For a description of royalties payable to the government of Kazakhstan on the sale of uranium extracted from orebodies within the country and taxes, see page<br>95.<br> <br><br> <br>For a description of risks that might affect access, title or the right or<br>ability to perform work on the property, see Strategic risks – Foreign investments and operations and Kazakhstan at pages 118 and 119, Operational risks – Permitting and licensing at pages 103 and 104, Governanceand compliance risks starting at page 110, Social risks starting at page 112, and Environmental risks starting at page 113. |
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About the Inkai property
Location
Inkai is in the Suzak District of Turkestan Oblast, Kazakhstan near the town of Taikonur, 350 kilometres northwest of the city of Shymkent and 155 kilometres east of the city of Kyzyl-Orda. JV Inkai’s corporate office is in Shymkent.
Access
The road to Taikonur is the primary road for transporting people, supplies and uranium product to and from the mine. It is a paved road that crosses the Karatau Mountains. Rail transportation is available from Almaty to Shymkent, then northwest to Shieli, Kyzyl-Orda and beyond. A rail line also runs from the town of Dzhambul to a KAP facility to the south of Taikonur. From Almaty and Astana, commercial airline services are available to Shymkent and Kyzyl-Orda.
Property tenure – MA area and mining allotment
The resource use contract between the Republic of Kazakhstan and JV Inkai (the resource use contract) grants JV Inkai the rights to explore for and to extract uranium from the subsoil contained in the Mining Allotment Area (the MA Area). The MA Area is the 139 square kilometres area in which JV Inkai currently has the right to mine, as covered by the Mining Allotment, which includes block 1 and portions of blocks 2 and 3. The Mining Allotment was the document issued by the Geology Committee of the Republic of Kazakhstan to JV Inkai in July 2017, which graphically and descriptively defines the area in which JV Inkai has the right to mine. As provided for in Amendment No. 6, it is part of the resource use contract. JV Inkai owns uranium extracted from the subsoil contained in the MA Area and has the right to use the surface of the MA Area. JV Inkai has obligations under the resource use contract which it must comply with to maintain these rights.
In addition to complying with its obligations under the resource use contract, JV Inkai, like all subsoil users, is required to abide by the work program appended to its resource use contract, which relates to its mining operations.
Under Kazakhstan law, subsoil and mineral resources belong to the state. Currently, the state provides access to subsoil and mineral resources under a resource use contract (hydrocarbons and uranium only) and a licence (the rest of mineral resources). Minerals extracted from the subsoil by a subsoil user under a resource use contract are the property of the subsoil user unless the subsoil code (as defined below) or a resource use contract provides otherwise.
A resource use contract gives the contractor a right to use the surface of the property while exploring, mining, and reclaiming the land. However, this right must be set forth in a land lease agreement with the applicable local administrative authorities.
On a regular basis, JV Inkai obtains from local authorities the necessary land lease agreements for new buildings and infrastructure. JV Inkai does not hold land leases for the entire MA Area. JV Inkai obtains land leases gradually only for surface area required for exploration, mining, or construction of new infrastructure.
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Environment, social and community factors
Inkai lies in the Betpak Dala Desert, which has a semi-arid climate, minimal precipitation, and relatively high evaporation. The average precipitation varies from 130 to 140 millimetres per year, and 22 to 40% of this is snow. The surface elevation within the MA Area ranges from 140 to 300 metres above mean sea level.
The area also has strong winds. The prevailing winds are northeast. Dust storms are common. The major water systems in the area include the Shu, Sarysu and Boktykaryn rivers.
The resource use contract prescribes that a certain level of employees be from Kazakhstan. See Resource use contract on page 61 for more information.
JV Inkai must give preference to local businesses. See Kazakhstan government and legislation – local content on pages 63 and 64 for more information.
In accordance with JV Inkai’s corporate responsibility strategy and to comply with its obligations under the resource use contract, JV Inkai finances projects and provides goods and services to support the district’s social infrastructure.
Geologicalsetting
South-central Kazakhstan geology is comprised of a large relatively flat basin of Cretaceous to Quaternary age continental clastic sedimentary rocks. The Chu-Sarysu basin extends for more than 1,000 kilometres from the foothills of the Tien Shan Mountains located on the south and southeast sides of the basin, and merges into the flats of the Aral Sea depression to the northwest. The basin is up to 250 kilometres wide, bordered by the Karatau Mountains on the southwest and the Kazakh Uplands on the northeast. The basin is composed of gently dipping to nearly flat-lying fluvial-derived unconsolidated sediments composed of inter-bedded sand, silt, and local clay horizons.
The Cretaceous and Paleogene sediments contain several stacked and relatively continuous, sinuous “roll-fronts” or oxidation reduction (redox) fronts hosted in the more porous and permeable sand and silt units. Several uranium deposits and active uranium ISR mines are located at these regional redox roll-fronts, developed along a regional system of superimposed mineralization fronts. The overall stratigraphic horizon of interest in the basin is approximately 200 to 250 metres in vertical section.
The Inkai deposit is one of these roll-front deposits. It is hosted within the Lower and Middle Inkuduk horizons and Mynkuduk horizon which comprise fine, medium, and coarse-grained sands, gravels and clays. The redox boundary can be readily recognised in core by a distinct colour change from grey and greenish-grey on the reduced side to light-grey with yellowish stains on the oxidized side, stemming from the oxidation of pyrite to limonite.
The sands have high horizontal hydraulic conductivities. Hydrogeological parameters of the deposit play a key role in ISR mining. Studies and mining results indicate Inkai has favourable hydrogeological conditions for ISR mining.
Mineralization
Mineralization in the Middle Inkuduk horizon occurs in the central, western, and northern parts of the MA Area. The overall strike length is approximately 35 kilometres. Width in plan view ranges from 40 to 1,600 metres and averages 350 metres. The depth ranges from 262 to 380 metres, averaging 314 metres.
Mineralization in the Lower Inkuduk horizon occurs in the southern, eastern, and northern parts of the MA Area. The overall strike length is approximately 40 kilometres. Width in plan view ranges from 40 to 600 metres and averages 250 metres. The depth ranges from 317 to 447 metres, averaging 382 metres.
Mineralization in the Mynkuduk horizon stretches from south to north in the eastern part of the MA Area. The overall strike length is approximately 40 kilometres. Width in plan view ranges from 40 to 350 metres and averages 200 metres. The depth ranges from 350 to 528 metres, averaging 390 metres.
Mineralization comprises sooty pitchblende (85%) and coffinite (15%). The pitchblende occurs as micron-sized globules and spherical aggregates, while the coffinite forms tiny crystals. Both uranium minerals occur in pores on interstitial materials such as clay minerals, as films around and in cracks within sand grains, and as replacements of rare organic matter, and are commonly associated with pyrite.
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Deposit type
The Inkai uranium deposit is a roll-front type deposit. Roll-front deposits are a common example of stratiform deposits that form within permeable sandstones at the interface between oxidized and reduced environments. The Cretaceous and Paleogene sediments contain several stacked and relatively continuous, sinuous “roll-fronts”, or redox fronts hosted in the more porous and permeable sand and silt units. Microcrystalline uraninite and coffinite are deposited during diagenesis by ground water, in a crescent-shaped lens that cuts across bedding and forms at the interface between oxidized and reduced ground. Sandstone host rocks are medium to coarse grained were highly permeable at the time of mineralization. There are several uranium deposits and active ISR uranium mines at these regional oxidation roll-fronts, developed along a regional system of superimposed mineralization fronts.
About the Inkai operation
Inkai is a developed producing property with sufficient surface rights to meet future mining operation needs for the current mineral reserves. It has site facilities and infrastructure. Plans are progressing to expand the operation to give it the capability to produce up to 10.4 million pounds per year.
Licences
The resource use contract grants JV Inkai the rights to explore for and to extract uranium from the subsoil contained in the MA Area until July 13, 2045. Other material licences JV Inkai currently holds relating to its mining activities are:
| • | “Licence for radioactive substances handling” valid until December 31, 2024 |
|---|---|
| • | “Licence for operation of mining production and mineral raw material processing” with an indefinite<br>term |
| --- | --- |
| • | “Licence for transportation of radioactive substances within the territory of the Republic of<br>Kazakhstan” valid until December 30, 2024 |
| --- | --- |
| • | “Licence for radioactive waste handling” valid until December 30, 2024 |
| --- | --- |
JV Inkai’s material environmental permits are described on page 62.
Infrastructure
There are three processing facilities on the MA Area: the Main Processing Plant (MPP) and two satellite plants, Sat1 and Sat2.
As part of the expansion, the following upgrades were completed:
| • | addition of new pumping stations and sand ponds at Sat2 |
|---|---|
| • | expansion of the processing facilities to add processing capacity at Sat2 |
| --- | --- |
The existing MPP, Sat1 and Sat2 circuit capacities were estimated using Inkai daily process summaries, which were subsequently demonstrated since 2019 by actual annual production. The MPP has an ion exchange (IX) capacity of 2.7 million pounds U3O8 per year and a product drying and packaging capacity of 8.3 million pounds U3O8 per year. Sat1 and Sat2 have respective IX capacities of 6.0 and 4.5 million pounds U3O8 per year.
The following infrastructure currently exists on the MA Area: administrative, engineering and construction offices, a laboratory, shops, garages, holding ponds and reagent storage tanks, enclosures for low-level radioactive waste and domestic waste, an emergency response building, food services facilities, roads and power lines, wellfield pipelines and header houses.
As part of the expansion, the following upgrades are planned:
| • | addition of calcining capability and processing capacity at the MPP |
|---|---|
| • | expansion of office buildings and the laboratory |
| --- | --- |
At Taikonur, JV Inkai has an employee residence camp with catering and leisure facilities. As part of the expansion, the following upgrades are planned:
| • | expansion of the camp in a phased approach with construction of two residential blocks for 165 people each and<br>addition of a dining room for 150 people |
|---|---|
| • | construction of a 24-kilometre asphalt paved road connecting the camp to<br>the three processing facilities |
| --- | --- |
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Water, power and heat
Groundwater wells provide sufficient water for all planned industrial activities. Potable water for use at the camp and at site facilities is supplied from shallow wells on the site. The site is connected to the national power grid. In case of power outages, there are standby generators. Operations continue throughout the year despite cold winters (lows of -35°C) and hot summers (highs of +40°C).
Employees
Taikonur has a population of about 680 who are mainly employed in uranium development and exploration. Whenever possible, JV Inkai hires personnel from Taikonur and surrounding villages.
Mining
Mining at Inkai is based upon a conventional and well-established ISR process. ISR mining of uranium is defined by the IAEA as:
“The extraction of ore from a host sandstone by chemical solutions and the recovery of uranium at the surface. ISR extraction is conducted by injecting a suitable leach solution into the ore zone below the water table; oxidizing, complexing and mobilizing the uranium; recovering the pregnant solutions through production wells; and finally, pumping the uranium bearing solution to the surface for further processing.”
ISR mining at Inkai is comprised of the following components to produce a uranium-bearing lixiviant (an aqueous solution which includes sulphuric acid), which goes to settling ponds and then to the processing plants for production as yellowcake:
| • | Determination of the GT (grade x thickness) cut-off for the<br>initial design and the operating period. The design sets a lower limit to the pounds per pattern required to warrant installation of a pattern before funds are committed, and the operating cut-off applies to<br>individual producer wells and dictates the lower limit of operation once a well has entered production. |
|---|---|
| • | Preparation of a production sequence, which will deliver the uranium-bearing lixiviant to meet production<br>requirements, considering the rate of uranium recovery, lixiviant uranium head grades, and wellfield flow rates. |
| --- | --- |
| • | Wellfield development practices, using an optimal pattern design, distribute barren lixiviant to the<br>wellfield injectors, and then collect lixiviant, which carries the dissolved uranium, back to the MPP, Sat1 or Sat2, as the case may be. |
| --- | --- |
The above factors are used to estimate the number of operating wellfields, wellfield patterns and wellfield houses over the production life. They also determine the unit cost of each of the mining components required to achieve the production schedule, including drilling, wellfield installation and wellfield operation.
There is ongoing wellfield development to support the current production plan. The mining project documents are being updated following the 2021 completion of the resource estimate report as described in Exploration on page 67 below.
Processing
As a result of extensive test work and operational experience, a very efficient process of uranium recovery has been established. The process consists of the following major steps:
| • | uranium in-situ leaching with a lixiviant |
|---|---|
| • | uranium adsorption from solution with IX resin |
| --- | --- |
| • | elution of uranium from resin with ammonium nitrate |
| --- | --- |
| • | precipitation of uranium as yellowcake with hydrogen peroxide and ammonia |
| --- | --- |
| • | yellowcake thickening, dewatering, and drying |
| --- | --- |
| • | packaging of dry yellowcake product in containers |
| --- | --- |
All plants load and elute uranium from resin while the resulting eluate is converted to yellowcake at the MPP. Inkai is designed to produce a dry uranium product that meets the quality specifications of uranium refining and conversion facilities. Overall recovery in 2022 slightly exceeded our target of 85%.
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Production
Total production
Based on current mineral reserves and resource use contract term, we expect Inkai to produce a total of 224 million pounds U3O8 (100% basis, recovered after processing) over the life of the mine from January 2023 to mid-2045.
Average annual production
Collectively the MPP, Sat1 and Sat2 have the capacity to produce about 8.3 million pounds U3O8 per year (100% basis) depending on the grade of the production solution. Construction work for a process expansion of the Inkai circuit to 10.4 million pounds U3O8 per year is in progress. The expansion project includes an upgrade to the yellowcake filtration and packaging units and the addition of a pre-dryer and calciner.
Production increase and restructuring – Implementation Agreement
In 2016, we signed an agreement with KAP and JV Inkai to restructure and enhance JV Inkai (the implementation agreement). The restructuring closed in December 2017 and took effect January 1, 2018. This restructuring was subject to obtaining all required government approvals, including an amendment to the resource use contract, which were obtained. The restructuring consisted of the following:
| • | JV Inkai has the right to produce 10.4 million pounds of<br>U3O8 per year, an increase from the prior licensed annual production of 5.2 million pounds |
|---|---|
| • | JV Inkai has the right to produce until 2045 (previously, the licence terms, based on the boundaries prior to the<br>restructuring, were to 2024 and 2030) |
| --- | --- |
| • | our ownership interest in JV Inkai is 40% and KAP’s ownership interest is 60%. However, during production<br>ramp up to the licensed limit of 10.4 million pounds, we are entitled to purchase 57.5% of the first 5.2 million pounds, and, as annual production increases above 5.2 million pounds, we are entitled to purchase 22.5% of any<br>incremental production, to the maximum annual share of 4.2 million pounds. Once the ramp up to 10.4 million pounds annually is complete, we will be entitled to purchase 40% of such annual production, matching our ownership interest<br> |
| --- | --- |
| • | a governance framework that provides protection for us as a minority owner |
| --- | --- |
| • | the boundaries of the MA Area match the agreed production profile for JV Inkai to 2045 |
| --- | --- |
| • | priority payment of the loan that our subsidiary made to JV Inkai to fund exploration and evaluation of the<br>historically defined block 3 area (in 2019, the loan was repaid) |
| --- | --- |
With KAP, we completed and reviewed a feasibility study for the purpose of evaluating the design, construction, and operation of a uranium refinery in Kazakhstan. In accordance with the agreement, a decision was made not to proceed with construction of the uranium refinery as contemplated in the feasibility study. We subsequently signed an agreement to licence our proprietary UF6 conversion technology to KAP, which will allow KAP to examine the feasibility of constructing and operating its own UF6 conversion facility in Kazakhstan.
The subsoil code allows producers to deviate within 20% (above or below) from the production parameters (including annual production levels) set out in the state approved project documentation, without triggering a mandatory amendment process.
With the change in ownership interests, we account for JV Inkai on an equity basis.
2022 Production
Total 2022 production from Inkai was 8.3 million pounds (100% basis) as planned, a decrease of 7% from 2021. In 2022, Inkai experienced a number of operational issues related to interruptions in reagent delivery and wellfield drilling. While the issues have been partially mitigated, their impact on production and inflationary pressure on production supplies pose a risk to JV Inkai’s 2023 production volume and its costs.
The first shipment of our share of JV Inkai’s 2022 production via the Trans-Caspian route arrived at a Canadian port in December 2022. This was the first shipment of our share of finished product from JV Inkai that did not rely on Russian rail lines or ports. However, the geopolitical situation continues to cause transportation risks in the region. Our 2022 share of earnings from this equity-accounted investee were impacted due to the timing of delivery of our share of 2022 production.
Based on an adjustment to the production purchase entitlement under the 2016 implementation agreement, in 2022 we were entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s 2022 production of 8.3 million pounds.
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2023 Production
Based on an adjustment to the production purchase entitlement under the 2016 implementation agreement described above, we are entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s planned 2023 production of 8.3 million pounds.
Presently, JV Inkai is experiencing wellfield development, procurement and supply chain issues, and inflationary pressures on its production materials and reagents. Achievement of its 2023 production forecast requires it to successfully manage these risks. If there is a significant disruption to JV Inkai’s operations for any reason, it may not achieve its production plans, there may be a delay in production, and it may experience increased costs to produce uranium. In addition, JV Inkai’s costs could be impacted by potential changes to the tax code in Kazakhstan and by possible increased financial contributions to social and other state causes, although these risks cannot be quantified or estimated at this time.
Our share of production is purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures.
In August 2022, KAP announced its plan to produce 10% below the planned volumes under its subsoil use contracts in 2024.
Sales
There are annual uranium sales contracts entered into between JV Inkai and a Cameco subsidiary to purchase Cameco’s share of Inkai production for each year, as well as similar contracts between JV Inkai and KAP. JV Inkai currently has no other forward-sales commitments for its uranium production.
In accordance with the Kazakhstan government’s resolution on uranium concentrate pricing regulations, product is currently purchased from JV Inkai at a price equal to the uranium spot price, less a 5% discount.
Cash distribution
Excess cash, net of working capital requirements, will be distributed to the partners as dividends. In 2022, we received dividend payments from JV Inkai totaling $92.4 million (US). Our share of dividends follows our production purchase entitlements as described above.
Resource use contract
The resource use contract was signed by the Republic of Kazakhstan and JV Inkai and then registered on July 13, 2000 based on the licence granted on April 20, 1999. The resource use contract provides for JV Inkai’s mining rights to the MA Area, as well as containing obligations with which JV Inkai must comply in order to maintain such rights. There have been six amendments to the resource use contract, the most recent in November 2017, being Amendment No. 6 to:
| • | define the boundaries of the MA Area to match the agreed production profile for JV Inkai to 2045<br> |
|---|---|
| • | increase the annual production rate from the MA Area to 10.4 million pounds U3O8 |
| --- | --- |
| • | extend the extraction term from the MA Area until July 13, 2045 |
| --- | --- |
The other prior significant amendments to the resource use contract are as follows:
| • | In 2007, Amendment No. 1 to the resource use contract was signed, extending the exploration period of blocks<br>2 and 3 for two years. |
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| • | In 2009, Amendment No. 2 to the resource use contract was signed, adopting the 2009 Tax Code, implementing<br>local content and employment requirements, and extending the exploration period at block 3. |
| --- | --- |
| • | In 2011, Amendment No 3 to the resource use contract was signed, increasing production and giving JV Inkai<br>government approval to carry out a five-year assessment program on block 3 that included delineation drilling, uranium resource estimation, construction and operation of a processing plant at block 3, and completion of a feasibility study.<br> |
| --- | --- |
| • | In 2013, Amendment No. 4 to the resource use contract was signed to increase annual production from blocks 1<br>and 2 to 5.2 million pounds U3O8. |
| --- | --- |
| • | In 2016, Amendment No. 5 to the resource use contract was signed, extending the exploration period at block<br>3 to July 13, 2018. |
| --- | --- |
In addition to complying with its obligations under the resource use contract, JV Inkai, like all subsoil users, is required to abide by the work program appended to the resource use contract, which relates to its mining operations. The current work program, to increase the annual production rate to 10.4 million pounds U3O8, is attached to Amendment No. 6.
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Environment
JV Inkai has to comply with environmental requirements during all stages of the operation, and develop an environmental impact assessment for examination by a state environmental expert before making any legal, organizational, or economic decisions that could have an effect on the environment and public health.
As required under Kazakhstan law, JV Inkai has a permit for environmental emissions and discharges for the operation that is valid until December 31, 2030. JV Inkai also holds certain water use permits which have various expiry dates.
JV Inkai carries environmental insurance, as required by the resource use contract and environmental law.
Decommissioning
JV Inkai’s decommissioning obligations are defined by the resource use contract and the subsoil code. JV Inkai is required to maintain a fund, which is capped at $500,000 (US), as security for meeting its decommissioning obligations. Under the resource use contract, JV Inkai must submit a plan for decommissioning the property to the government six months before mining activities are complete.
JV Inkai has developed a preliminary decommissioning plan to estimate total decommissioning costs, and updates the plan when there is a significant change at the operation that could affect decommissioning estimates. The preliminary decommissioning estimate is $30 million (US) and is subject to ongoing review.
Groundwater is not actively restored post-mining in Kazakhstan. See page 92 for additional details.
Kazakhstan government and legislation
Subsoil law
The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Code of the Republic of Kazakhstan on Subsoil andSubsoil Use No. 125-VI dated December 27, 2017 (which became effective on June 28, 2018), as amended (the subsoil code). It replaced the Law on the Subsoil and Subsoil Use datedJune 24, 2010, as amended.
In general, the rights held by JV Inkai are governed by the old subsoil law that was in effect at the time of the resource use contract registration in July 2000. The subsoil use rights held by JV Inkai came into effect upon the initial issuance of these licences (April 1999) and the execution and the state registration of the resource use contract (July 2000).
The subsoil code defines the framework and procedures connected with the granting, transfer and termination of subsoil rights, and the regulation of the activities of subsoil users. The subsoil, including mineral resources in their underground state, are the property of the people of Kazakhstan and the people’s property rights are exercised by the state by the regime of state property. Resources brought to the surface belong to the subsoil user, unless otherwise provided by the subsoil code. The state has priority and approval rights with regards to strategic deposits with some exceptions (for example, for inter-group transfers in certain circumstances), if a subsoil user transfers its subsoil rights or if there is a transfer (direct or indirect) of an ownership interest in a subsoil user.
Subsoil rights go into effect when a contract with the competent authority is finalized and registered. Pursuant to the subsoil code, the subsoil user is given, among other things, the exclusive right to conduct mining operations, to build production facilities, to freely dispose of its share of production and to negotiate extensions of the contract, subject to restrictions and requirements set out in the subsoil code.
Currently, the Ministry of Energy of the Republic of Kazakhstan is the competent authority on hydrocarbons and uranium under the subsoil code.
Stabilization
The subsoil code provides, subject to a number of exceptions, that any licences issued and contracts executed before the enactment of the subsoil code remain valid. Therefore, the resource use contract remains valid. Most of the general provisions of the subsoil code apply to subsoil contracts concluded and licences issued before the subsoil code enactment. At the same time, the subsoil code’s special provisions on uranium generally do not have retrospective effect except for certain rules such as obligations in the spheres of education, science and social, regional economic development during production, procurement, environmental protection, and contract termination rules.
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Given that some subsoil use contracts (including the resource use contract) contain the legislation stability guarantee and the latter is also provided for by both the stabilized law and the subsoil code, any retrospective provisions of the subsoil code do not override such stability guarantee unless an exception applies. For example, environmental regulations of the subsoil code are an exception to the stability guarantee and apply to subsoil users operating under old contracts.
Overall, the Republic of Kazakhstan has gradually weakened the stabilization guarantee, particularly in relation to the new projects, and the national security exception in the subsoil code is applied broadly to encompass security over strategic national resources.
Amendment No. 2 to the resource use contract eliminated the tax stabilization provision that applied to JV Inkai.
Transfer of subsoil rights and priority rights
The subsoil code liberates to some extent the regime of regulatory approvals by requiring the consent for the transfer of an object connected with the subsoil use right only in relation to hydrocarbons, uranium and deposits under a solid minerals licence. In addition, it abolished the requirement to obtain consent in case of a charter capital increase without change in shareholding and a transaction with government, state body, national management holding or national company. As previously, failing to obtain the consent of the competent authority makes the transaction void.
Similar to the old subsoil law, the subsoil code provides the state with the priority right only with respect to transfers of a subsoil use right related to a strategic subsoil area and shares and other securities circulated at organized securities market, which constitutes an object connected with the subsoil use right related to the strategic subsoil area. The exemptions from the requirement to obtain the consent of the competent authority discussed above also exempts a transaction from the requirement to obtain a waiver of the priority right of the state.
The subsoil code has introduced a new requirement, which is a change of control notification to be made within 30 calendar days from such change. The subsoil code provides that control means inter alia holding more than 25% shares (participatory interests or securities convertible in shares), having voting rights for more than 25% of all votes in the highest management body.
Dispute resolution
The subsoil code contains provisions on resolution of disputes by a court order (meaning state courts) on a number of specific issues such as disputes regarding revocation of licences or termination of resource use contracts. Pursuant to amendments to the subsoil code that came into effect on January 10, 2023, disputes under contracts related to complex hydrocarbon projects are expressly allowed to be referred to international arbitration under UNCITRAL rules.
The subsoil code is silent on the status of arbitration clauses contained in uranium resource use contracts currently in effect. Therefore, strictly speaking, the subsoil code does not disallow international arbitration for uranium resource use contracts.
The resource use contract contains a dispute resolution clause referring contractual disputes to international arbitration. We believe the subsoil code does not affect this right.
Contract termination
The subsoil code introduces specific grounds for unilateral termination of subsoil use contracts (hydrocarbons and uranium).
Due to March 2021 amendments to the subsoil code, the provisions on termination of resource use contracts were given retrospective effect. Generally, however, those retrospective provisions should not override the stability guarantee and should not apply to the resource use contract.
The subsoil code applies some general grounds for unilateral repudiation retrospectively. Those are (i) a breach of the requirement to obtain the competent authority’s consent for transfer of a subsoil use right or an object connected with subsoil use right for hard minerals containing a major or strategic deposit which lead to a threat to national security; and (ii) actions of subsoil user during subsoil use operations at major deposits of hard minerals leading to a change in the economic interest of the Republic of Kazakhstan which creates a threat to national security. To the extent these grounds for unilateral termination relate to national security which is an area not covered by the stability guarantee, they apply to resource use contracts entered into before the subsoil code came into effect.
Local content
The subsoil code imposes local content requirements for works, services and employees.
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The resource use contract imposes local content requirements on JV Inkai with respect to employees, goods, works and services. As such, at least 40% of the costs of the acquired goods and equipment, 90% of contract works and 100%, 70% and 60% of employees, depending on their qualifications (workers, engineers, and management, respectively), must be of local origin. Effective January 1, 2021, under Kazakhstan law this local content requirement ceased to apply to goods procured by JV Inkai.
Strategic deposits
The subsoil code provides that all uranium deposits are strategic deposits. According to a governmental resolution On Determination of the Strategic Subsoil Areas Importance dated June 28, 2018 No. 389, 137 areas are strategic deposits, including Inkai’s blocks.
Transfer of subsoil use rights on strategic areas is subject to the priority right and the competent authority’s consent, as described above.
Reintroduction of the licensing regime
The subsoil code reintroduces the licensing regime for widespread and solid minerals except uranium. The regime of the resource use contracts only applies to exploration and production rights for hydrocarbons and uranium. As such, the rights to explore and produce uranium will continue to be provided based on a resource use contract.
Decommissioning
The subsoil code modified the general provisions related to decommissioning. Some of them are applied retroactively. One such modification introduces a new requirement to provide financial security for a subsoil user’s decommissioning obligations in the form of a guarantee, insurance and/or bank deposit.
The subsoil code also contains special provisions on decommissioning of uranium wellfields. They do not have retroactive effect. However, because they fall within the sphere of environmental protection, they are not covered by the stability guarantee.
Uranium special regulations
The subsoil code differentiates uranium from the rest of solid minerals and provides an additional and distinct set of rules to govern uranium mining specifically.
The subsoil code provides that a uranium deposit is granted for mining only to a uranium national company (a joint stock company created by a decree of the government of Kazakhstan with the controlling stock belonging to the state or the national management fund on the basis of direct negotiations).
The subsoil code further stipulates that a subsoil use right for uranium mining (or a share in such subsoil use right) granted to a uranium national company on the basis of direct negotiations may only be further transferred to its subsidiary entities where the uranium national company holds more than 50% of the shares (participating interests) directly or indirectly. Such a transferee, in turn, may only transfer the subsoil use right (or share in the subsoil use right) to the uranium national company’s subsidiary entities where the uranium national company holds more than 50% of the shares (participating interests) directly or indirectly.
The uranium special rules also regulate issues such as termination of the uranium subsoil use right, provision of a uranium deposit and its extension/reduction, conditions, and periods of mining and project and design documents. The subsoil code does not make these special uranium rules retroactive, subject to a few exceptions.
Currency control regulations
Under the Law of theRepublic of Kazakhstan on Currency Regulation and Currency Control No. 167-VI dated July 2, 2018 (effective from July 1, 2019) (the Currency Law), in the event of an emergency situation presenting a threat to economic security and stability of the financial system of Kazakhstan, the Kazakhstan government based on a joint recommendation from the National Bank of Kazakhstan (the NBK) and other relevant state authorities is entitled to introduce a special currency regime for a period of up to one year. The following terms and requirements may potentially be imposed under such special currency regime:
| • | the requirement to deposit money on an interest free basis with a Kazakhstan bank or the NBK for a set period<br> |
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| • | the requirement to obtain a special permit from the NBK to carry out certain foreign exchange transactions<br> |
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| • | the requirement to sell foreign currency received by Kazakhstan residents |
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| • | the restriction on use of overseas bank accounts |
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| • | the establishment of a term for the return of foreign currency earnings and limits on volumes, amount and<br>currency of settlement under foreign exchange transactions; and |
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| • | other temporary currency restrictions |
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Under the Currency Law, the requirements of the special currency regime may not restrict:
| • | the performance of obligations by Kazakhstan residents towards<br>non-residents of Kazakhstan arising as a result of such non-residents of Kazakhstan performing their obligations under currency contracts entered into before the<br>introduction of the special currency regime; and |
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| • | the transfer by non-residents of Kazakhstan of dividends, interest and<br>other proceeds under deposit, and securities |
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Since the Currency Law has become effective, the following substantial changes envisaged by the Currency Law are noteworthy:
| • | amendment to the definition of Kazakhstan residents |
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| • | introduction of a requirement for Kazakhstan legal entities to confirm the purpose of the purchase and use of<br>foreign currency in the Kazakhstan market |
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| • | cancellation of current currency operations registration and notification regimes and introduction of one regime<br>for currency operations monitoring; and |
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| • | new requirements applicable to export/import operations with customs clearance in the territory of Kazakhstan<br> |
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The resource use contract grants JV Inkai a measure of protection from currency control regulations, granting it the right to freely transfer funds, in state and other currencies, inside and outside of Kazakhstan with the exception that financial transactions within Kazakhstan must be concluded in the national currency.
Operating, capital costs and economic analysis
The following is a summary of the operating and capital cost estimates for the remaining life of mine, stated in constant 2022 dollars and reflecting a forecast life-of-mine production of 224 million pounds U3O8 and a 391 Kazakhstan Tenge to 1 Cdn dollar exchange rate assumption.
| Operating Costs ($Cdn million) | Total(2023 – 2045) | |
|---|---|---|
| Site administration | $ | 458.0 |
| Processing costs | 269.2 | |
| Mining costs | 599.8 | |
| Corporate overhead | 422.2 | |
| Total operating costs | $ | 1,749.2 |
| Average cost per pound U3O8 | $ | 7.80 |
Note: presented as total cost to JV Inkai (100% basis).
Estimated operating costs consist of annual expenditures to mine and process the mineral reserves into U3O8 as well as site administration and corporate overhead costs.
| Capital Costs ($Cdn million) | Total(2023 – 2045) | |
|---|---|---|
| Total wellfield development | $ | 610.5 |
| Construction and maintenance capital | 57.4 | |
| Sustaining capital | 58.7 | |
| Total capital costs | $ | 726.6 |
Note: presented as total cost to JV Inkai (100% basis).
The economic analysis, effective as of January 1, 2018 being the effective date of the technical report for Inkai, undertaken from the perspective of JV Inkai, based on JV Inkai’s share (100%) of Inkai mineral reserves, results in an after tax NPV of $2.2 billion (at a discount rate of 12%), for the net annual cash flows from January 1, 2018 to mid-2045 totalling $8.9 billion.
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Using the total capital invested, along with the operating and capital cost estimates for the remainder of mineral reserves, the after tax IRR is estimated to be 27.1%. Payback for JV Inkai, including all actual costs was achieved in 2015, on an undiscounted, after tax basis. All future capital expenditures are forecasted to be covered by operating cash flow.
Annual Cash Flows – 100% JV Inkai basis
| Annual cash flows<br><br><br>($Cdn M) | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Production volume <br>(000’s lbs U3O8) | 6,896 | 8,351 | 10,406 | ^1^ | 10,399 | ^1^ | 10,399 | ^1^ | 10,293 | ^1^ | 9,305 | 9,445 | 8,526 | 7,979 | 7,417 | 5,776 | 6,134 | ||||||||||||||
| Sales Revenue | $ | 229.3 | $ | 337.2 | $ | 531.4 | $ | 642.1 | $ | 679.2 | $ | 696.7 | $ | 629.8 | $ | 639.3 | $ | 577.1 | $ | 540.1 | $ | 502.0 | $ | 391.0 | $ | 415.2 | |||||
| Operating Costs | 67.0 | 77.5 | 89.8 | 86.0 | 86.6 | 87.8 | 82.0 | 82.3 | 79.1 | 77.2 | 76.2 | 69.0 | 70.0 | ||||||||||||||||||
| Capital Costs | 59.4 | 81.1 | 75.3 | 45.0 | 49.9 | 37.6 | 36.9 | 37.9 | 43.0 | 34.5 | 32.7 | 25.2 | 28.0 | ||||||||||||||||||
| Mineral Extraction Tax | 14.2 | 18.3 | 20.5 | 19.2 | 19.6 | 19.0 | 16.1 | 16.4 | 14.4 | 14.0 | 13.3 | 9.8 | 10.4 | ||||||||||||||||||
| Corporate Income Tax | 23.7 | 39.7 | 74.9 | 96.9 | 103.8 | 107.9 | 97.6 | 99.3 | 89.0 | 82.2 | 75.5 | 57.1 | 61.2 | ||||||||||||||||||
| Net cash flow | $ | 65.1 | $ | 120.6 | $ | 271.0 | **** | $ | 395.1 | **** | $ | 419.3 | **** | $ | 444.5 | **** | $ | 397.2 | $ | 403.4 | $ | 351.5 | $ | 332.2 | $ | 304.5 | $ | 230.0 | $ | 245.7 | |
| 2031 | 2032 | 2033 | 2034 | 2035 | 2036 | 2037 | 2038 | 2039 | 2040 | 2041 | 2042 | 2043 | 2044 | 2045 | Total | ||||||||||||||||
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| 6,986 | 7,908 | 9,650 | 8,389 | 7,522 | 6,186 | 6,917 | 7,321 | 9,115 | 9,412 | 8,876 | 8,762 | 8,892 | 8,421 | 3,475 | 229,159 | ||||||||||||||||
| $472.9 | $ | 535.3 | $ | 653.2 | $ | 567.8 | $ | 509.1 | $ | 418.7 | $ | 468.2 | $ | 495.5 | $ | 617.0 | $ | 637.1 | $ | 600.8 | $ | 593.1 | $ | 601.8 | $ | 570.0 | $ | 235.2 | $ | 14,786.1 | |
| 73.8 | 75.3 | 80.7 | 78.5 | 74.3 | 71.8 | 73.9 | 75.2 | 81.3 | 83.3 | 81.2 | 80.0 | 81.3 | 82.3 | 65.3 | 2,188.5 | ||||||||||||||||
| 27.6 | 30.3 | 37.7 | 34.8 | 29.9 | 26.0 | 31.2 | 29.9 | 39.5 | 38.4 | 36.0 | 34.9 | 35.2 | 34.3 | 11.5 | 1,063.5 | ||||||||||||||||
| 11.5 | 12.5 | 15.3 | 12.7 | 10.7 | 9.4 | 10.4 | 10.7 | 13.4 | 14.2 | 13.1 | 13.0 | 13.1 | 13.0 | 5.5 | 383.5 | ||||||||||||||||
| 71.3 | 82.5 | 102.8 | 88.6 | 79.0 | 62.6 | 71.3 | 76.3 | 97.4 | 100.6 | 94.5 | 93.0 | 96.0 | 90.2 | 30.8 | 2,245.5 | ||||||||||||||||
| **** | $288.7 | $ | 334.7 | $ | 416.7 | $ | 353.2 | $ | 315.2 | $ | 248.9 | $ | 281.5 | $ | 303.5 | $ | 385.4 | $ | 400.6 | $ | 376.1 | $ | 372.1 | $ | 376.2 | $ | 350.2 | $ | 122.1 | $ | 8,905.1 |
Note: Effective January 1, 2018 and presented from the perspective of JV Inkai and based on JV Inkai’s share (100%) of the mineral reserves at an 85% recovery.
| ^1^ | Due to KAP’s announced plans to maintain its aggregate production reduction of 20% through 2023, we expect<br>total production from JV Inkai to be 8.3 million pounds in 2023. The production reduction of 20% also applied to the 2020 through 2022 production plans for an annual target of 8.3 million pounds; however, due to the impact of COVID-19, actual 2020 production was 7.0 million pounds. 2021 production was 9.0 million pounds and 2022 production was 8.3 million pounds. |
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Estimated capital costs include wellfield development to mine the mineral reserves as well as construction and maintenance capital along with sustaining capital. Construction capital was originally heavily weighted to 2019 to 2020 due to the capital required for the production ramp up to 10.4 million pounds annually as well as upgrades to existing facilities. The spending during those years was somewhat lower than projected as the construction capital will continue through 2023 to coincide with the ramp up of production in 2024.
The current forecast production is now 224 million pounds U3O8 for the remaining term of the resource use contract, ending mid-2045. Operating costs are expected to decrease by approximately 7% as compared to the 2021 AIF and decrease by approximately 18% compared to the 2018 technical report as a result of the valuation of the Kazakhstan Tenge, expected adjustments to remuneration programs, and inflationary factors. There is considerable uncertainty regarding the future political
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and economic landscape in Kazakhstan, which could impact capital and operating cost estimates (for additional information see a discussion of Financial risks starting on page 104 and Strategic risks – Foreign investments and operations and Kazakhstan on page 118 and page 119).
Our expectations and plans regarding Inkai, including forecasts of operating and capital costs, net annual cash flow, production and mine life are forward-looking information, and are based specifically on the risks and assumptions discussed on pages 3, 4 and 5. Operating or capital spending plans may change in 2023, depending on uranium markets and other factors. Estimates of expected future production, net annual cash flows, and capital and operating costs are inherently uncertain, particularly beyond one year, and may change materially over time.
Exploration, drilling, sampling, data quality and estimates
Exploration at Inkai began in the 1970s and progressed until 1996. Since 2006, exploration and delineation drilling is conducted by JV Inkai, with the focus on block 3. From 2013 to 2016, delineation drilling was conducted at block 1 and block 2 to better establish the mineralization distribution and to support further development and wellfield design. In 2018 and 2019 JV Inkai carried out infill drilling program in the central and western parts of the MA Area (referred to as Sat1 area).
We have relied on historical data to estimate mineral reserves and resources for portions of the MA Area that came from block 1. Extensive exploration and delineation work was completed in the portion of the MA Area that came from block 3. It was used to estimate mineral reserves and resources. There are no historical mineral resources and reserves estimates within the meaning of NI 43-101 to report.
Exploration
Exploration drilling
JV Inkai’s uranium exploration and delineation drilling programs were conducted by drilling vertical holes from surface. Delineation of the deposit on the MA Area and its geological structural features was carried out by drilling on a grid at prescribed density of 3.2 to 1.6-kilometre line spacing and 200 to 50-metre hole spacing with coring. Increasing level of geological knowledge and confidence is obtained by further drilling at grids of 800 to 400 x 200 to 50 metre with coring and 200 to 100 x 50 to 25 metre grid, usually without core.
Vertical holes are drilled with a triangular drill bit for use in unconsolidated formations down to a certain depth and the rest of the hole is cored. At the Inkai deposit, approximately 50% of all exploration holes are cored through the entire mineralized interval, and 70% core recovery is required for assay sampling. Radiometric probing, hole deviation, geophysical and hole diameter surveys are done by site crews and experienced contractors.
As the mineralized horizons lie practically horizontal and the drill holes are nearly vertical, the mineralized intercepts represent the true thickness of the mineralization.
The total number of exploration holes drilled before 2018 on the MA Area was approximately 4,500.
The drilling results were used for the identification of the horizons and mineralization encountered and served for the geological modelling, the estimation of uranium distribution and content, and the understanding of hydrogeological and metallurgical characteristics.
In 2019, JV Inkai continued the infill drilling program started in 2018 in the Sat1 area aimed at upgrading the inferred and indicated resources and probable reserves to higher categories. From the beginning of the drilling program, a total of 1,208 drillholes (487,638 metres) were drilled, including 482 core holes (196,727 metres) and 716 non-core holes (290,910 metres). Drilling was carried out by progressively tightening from 400 by 100 metres to 200 by 50 metres grids. The infill drilling program was completed in September 2019. Preparation of a resource estimate report was initiated in October 2019 and was completed in 2021, incorporating the infill drilling results from 2018 and 2019. These results have been assessed and went through the local governmental approval process. The report is being used to update the mining project documents. This update also involves updating the work program for mining operations by amendment to the resource use contract and obtaining the required government approvals. This process is ongoing and at this stage JV Inkai has retained a local engineering firm to update the mining project documents.
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Sampling analysis and data verification
The sampling, sample preparation, analyses, and geophysical downhole logging during the exploration and delineation programs follow the procedures and manuals which adhere to the requirements set out in the State Reserves Commission guidelines.
Sampling
| • | Detailed sampling procedures guide the sampling interval within the mineralization. Holes are drilled on<br>progressively tightening grids: 3.2 to 1.6 kilometre x 200-50 metre, 800-400 metre x 200-50 metre and 200-100 metre x 50-25 metre. When core recoveries are higher than 70% and radioactivity greater than a certain threshold, core samples are taken at intervals of 0.2 to 1.2<br>metres. Sample intervals are also differentiated by barren or low permeability material. |
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| • | The drillholes are nearly vertical and the mineralized horizons are almost horizontal, so the mineralized<br>intercepts represent the true thickness of the mineralization. |
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| • | JV Inkai surveys the drillholes, logging radiometric, electrical (spontaneous potential and resistivity), caliper<br>and deviation data. |
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| • | Sampling is done on half of the core. The average core sample length is 0.4 metre. |
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| • | The split core is tested for grainsize and carbonate content. |
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| • | Core recovery is considered acceptable given the unconsolidated state of the mineralized material.<br> |
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Sample security
JV Inkai’s current sampling process follows the strict regulations imposed by the Kazakhstan government, and includes the highest level of security measures, quality assurance and quality control. We have not been able to locate the documents describing sample security for historical Kazakhstan exploration on the MA Area, but we believe the security measures taken to store and ship samples were of the same high quality.
Analysis
| • | The core samples for uranium and radium determination are ground down to 1.0 mm grain size and are further<br>subdivided by one or three times quartering until the final representative weight of samples and duplicates is reached (0.2 kg). |
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| • | The laboratory tests for uranium and radium were performed by the Central Analytical Laboratory of JSC<br>Volkovgeology, a company related to KAP, the other owner of JV Inkai. The laboratory is certified and licensed by the National Centre for Accreditation of the Republic of Kazakhstan. |
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| • | The uranium content was determined by using the X-ray fluorescence<br>spectrum analysis. The radium content was determined from the gamma-X-ray spectrum analysis. |
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Quality control and data verification
| • | The sampling reproducibility for the uranium and radium assays was determined by two methods: (1) having the<br>remaining half of the core sampled by another sampler and by (2) by compositing samples consisting of the original sample rejects and samples of the remaining half of the core. Reproducibility of uranium and radium assays were within acceptable<br>tolerances. |
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| • | Internal laboratory control of the uranium and the radium grade determination is performed by comparing the<br>results of the sample and its blind duplicate. The mean square error between sample and duplicate was calculated by measuring the deviation to ensure it stayed within the prescribed limits. |
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| • | External (inter-laboratory) controls for the uranium and radium assays were carried out at the VIMS laboratory in<br>Moscow, Russia, Nevskoe PGO laboratory in Saint-Petersburg, Russia and Kyzyltepageologiya Laboratory in Navoi, Uzbekistan. The number of control samples was approximately 2% of all samples for uranium and approximately 1% of all samples for radium.<br> |
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| • | All of the drillhole information in use at Inkai is regularly provided to Cameco. The current database has been<br>validated a number of times by geologists with JV Inkai, JSC Volkovgeology, the State Reserve Commission, Two Key LLP, and Cameco, and is considered relevant and reliable. |
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| • | Our geoscientists, including qualified persons as such term is defined in NI<br>43-101, have witnessed or reviewed drilling, core handling, radiometric probing, logging and sampling facilities used at the Inkai mine and consider the methodologies to be satisfactory and the results<br>representative and reliable. |
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| • | We confirmed the correlation between radioactive readings and calculated radium grades. |
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| • | We carried out data verification processes that validated the mineral resource and reserve estimates. Our<br>geoscientists, including qualified persons as such term is defined in NI 43-101, consider the data verification processes employed to be representative and reliable. There has been no indication of significant<br>inconsistencies in the data used or verified nor any failures to adequately verity the data. |
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| • | All drilling, logging, core drilling, and subsequent core splitting and assaying, were completed under the<br>direction of various geological expeditions of the USSR Ministry of Geology and later under the supervision of JSC Volkovgeology. |
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| • | Based on numerous quality assurance and quality controls applied by JSC Volkovgeology, including internal checks<br>and inter-laboratory checks, the repeatability of the results for uranium and radium confirmed the accuracy required and no significant systematic deviations were found. |
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| • | Sampling and analysis procedures have been examined by an independent consultant and found to be detailed and<br>thorough. |
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| • | The findings are supported by results of the leach tests and wellfield drilling results on the MA Area.<br> |
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Accuracy
We are satisfied with the quality of data and consider it valid for use in the estimation of mineral resources and reserves for the MA Area. Comparison of the actual mine production with the expected production supports this opinion.
Mineral reserve and resource estimates
Please see page 78 for our mineral reserve and resource estimates for Inkai.
Uranium – Tier-two operations
Rabbit Lake
Located in Saskatchewan, Canada, our 100% owned Rabbit Lake operation opened in 1975. Due to market conditions, we suspended production at Rabbit Lake during the second quarter of 2016.
| Location | Saskatchewan, Canada |
|---|---|
| Ownership | 100% |
| End product | Uranium concentrates |
| ISO certification | ISO 14001 certified |
| Mine type | Underground |
| Estimated reserves | — |
| Estimated resources | 38.6 million pounds (indicated), average grade U3O8: 0.95% |
| 33.7 million pounds (inferred), average grade U3O8: 0.62% | |
| Mining methods | Vertical blasthole stoping |
| Licensed capacity | Mill: maximum 16.9 million pounds per year; currently 11 million |
| Licence term | Through October 2023 |
| Total production: 1975 to 2022 | 202.2 million pounds |
| 2022 production | 0 million pounds |
| 2023 production outlook | 0 million pounds |
| Estimated decommissioning cost | $213 million |
Production suspension
The facilities remained in a state of safe and sustainable care and maintenance throughout 2022.
While in standby, we continue to evaluate our options in order to minimize care and maintenance costs. We expect care and maintenance costs to range between $27 million and $32 million annually.
The current operating licence from the CNSC for Rabbit Lake expires in October 2023. The relicensing process is under way, and we expect a decision from the CNSC later in 2023.
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Future production
We do not expect any production in 2023.
US ISR Operations
Located in Nebraska and Wyoming in the US, the Crow Butte and Smith Ranch-Highland (including the North Butte satellite) operations began production in 1991 and 1975. Each operation has its own processing facility. Due to market conditions, we curtailed production and deferred all wellfield development at these operations during the second quarter of 2016.
| Ownership | 100% | |
|---|---|---|
| End product | Uranium concentrates | |
| ISO certification | ISO 14001 certified | |
| Estimated reserves | Smith Ranch-Highland: | — |
| North Butte-Brown Ranch: | — | |
| Crow Butte: | — | |
| Estimated resources | Smith Ranch-Highland: | 24.9 million pounds (measured and indicated), average grade U3O8: 0.06% |
| 7.7 million pounds (inferred), average grade U3O8: 0.05% | ||
| North Butte-Brown Ranch: | 9.4 million pounds (measured and indicated), average grade U3O8: 0.07% | |
| 0.4 million pounds (inferred), average grade U3O8: 0.06% | ||
| Crow Butte: | 13.9 million pounds (measured and indicated), average grade U3O8: 0.25% | |
| 1.8 million pounds (inferred), average grade U3O8: 0.16% | ||
| Mining methods | In situ recovery (ISR) | |
| Licensed capacity | **^1^**Smith Ranch-Highland: | Wellfields: 3 million pounds per year; processing plants: 5.5 million pounds per year |
| Crow Butte: | Processing plants and wellfields: 2 million pounds per year | |
| Licence term | Smith Ranch-Highland: | Through September 2028 |
| Crow Butte: | Through October 2024 | |
| Total production: 2002 to 2022 | 33.0 million pounds | |
| 2022 production | 0 million pounds | |
| 2023 production outlook | 0 million pounds | |
| Estimated decommissioning cost | Smith Ranch-Highland: $219 million (US), including North Butte | |
| Crow Butte: $56 million (US) | ||
| ^1^ | Including Highland mill. | |
| --- | --- |
Production and curtailment
As a result of our 2016 decision, production at the US operations ceased in 2018.
We expect ongoing cash and non-cash care and maintenance costs to range between $12 million (US) and $14 million (US) for 2023.
Future production
We do not expect any production in 2023.
Uranium –Advanced projects
Work on our advanced projects has been scaled back and will continue at a pace aligned with market signals.
2022 ANNUAL INFORMATION FORM Page 70
Millennium
| Location | Saskatchewan, Canada |
|---|---|
| Ownership | 69.9% |
| End product | Uranium concentrates |
| Potential mine type | Underground |
| Estimated resources (our share) | 53.0 million pounds (indicated), average grade U3O8: 2.39% |
| 20.2 million pounds (inferred), average grade U3O8: 3.19% |
Background
The Millennium deposit was discovered in 2000 and was delineated by surface drilling work between 2000 and 2013.
Yeelirrie
| Location | Western Australia |
|---|---|
| Ownership | 100% |
| End product | Uranium concentrates |
| Potential mine type | Open pit |
| Estimated resources | 128.1 million pounds (measured and indicated), average grade U3O8: 0.15% |
Background
The Yeelirrie deposit was discovered in 1972 and is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.
Kintyre
| Location | Western Australia |
|---|---|
| Ownership | 100% |
| End product | Uranium concentrates |
| Potential mine type | Open pit |
| Estimated resources (our share) | 53.5 million pounds (indicated), average grade U3O8: 0.62% |
| 6.0 million pounds (inferred), average grade U3O8: 0.53% |
Background
The Kintyre deposit was discovered in 1985 and is amenable to open pit mining techniques.
2022 project updates
We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment our primary focus is on producing from our tier-one uranium assets at a pace aligned with our contract portfolio and market opportunities. We continue to await a signal from our customers that additional production is needed prior to making any new development decisions.
Planning for the future
2023 Planned activity
No work is planned at Millennium, Yeelirrie or Kintyre.
Further progress towards a development decision on any of these projects is not expected until the market fully transitions and supply is incented by prices that reflect production economics.
Project approval
The approval received for Kintyre from the prior state government required substantial commencement of the project by March 2020, being within five years of the grant of the approval, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future, we can apply for an extension of time to achieve substantial commencement of the
2022 ANNUAL INFORMATION FORM Page 71
project. If granted by a future government we could commence the Kintyre project, provided we have all other required regulatory approvals.
The approval for the Yeelirrie project, received from the prior state government, required substantial commencement of the project by January 2022, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future, we can again apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Yeelirrie project, provided we have all other required regulatory approvals. Approval for the Yeelirrie project at the federal level was granted in 2019 and extends until 2043.
Uranium – exploration
Our exploration program is directed at replacing mineral reserves as they are depleted by our production and is key to sustaining our business. We are focused on exploration near our existing operations where we have established infrastructure and capacity to expand. Globally, we have land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia and the US. Our land holdings total about 0.78 million hectares (1.9 million acres). In northern Saskatchewan alone, we have direct interests in about 0.68 million hectares (1.7 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin.
2022 UPDATE
Brownfield exploration
Brownfield exploration is uranium exploration near our existing operations and includes expenses for advanced exploration on the evaluation of projects where uranium mineralization is being defined.
In 2022, we spent about $2 million on brownfields and advanced uranium projects in Saskatchewan and Australia. At the US operations we spent $1 million.
Regional exploration
We spent about $8 million on regional exploration programs (including support costs), primarily in Saskatchewan’s Athabasca Basin.
PLANNING FOR THEFUTURE
We will maintain an active uranium exploration program and continue to focus on our core projects in Saskatchewan under our long-term exploration strategy. Long-term, we look for properties that meet our investment criteria. We may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our industry expertise in both exploration and corporate social responsibility make us a partner of choice.
2022 ANNUAL INFORMATION FORM Page 72
Fuel services
Refining, conversion and fuel manufacturing
We have about 21% of world UF6 primary conversion capacity and are a supplier of natural UO2. Our focus is on cost-competitiveness and operational efficiency, as well as increasing our production of UF6 in line with our contract portfolio and market opportunities.
Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and meet customer needs.
In 2022, fuel services produced 13.0 million kgU, 7% higher than 2021 due to an increase in demand in 2022.
We plan to produce between 13 million and 14 million kgU in 2023. In addition, at our Port Hope UF6 conversion facility we are working on increasing annual production to 12,000 tonnes in 2024 to satisfy our book of long-term business and demand for conversion services.
In conjunction with our initiative intended to provide a greater focus on technology and its applications to improve efficiency and reduce costs across the organization, we will continue to look for opportunities to improve operational effectiveness, including the use of digital and automation technologies.
Inflation, the availability of personnel with the necessary skills and experience, aging infrastructure, and the potential impact of supply chain challenges on the availability of materials and reagents carry the risk of not achieving our production plans, production delays, and increased costs in 2023 and future years.
Blind River Refinery
| Licensed Capacity<br> <br><br><br><br>24.0M kgU as UO3<br> <br><br><br><br>Licence renewal in<br> <br><br><br><br>February 2032 |
|---|
Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO3.
| Location | Ontario, Canada |
|---|---|
| Ownership | 100% |
| End product | UO3 |
| ISO certification | ISO 14001 certified |
| Licensed capacity | 18.0 million kgU as UO3 per year, approved to 24.0 million subject to the completion of certain equipment upgrades (advancement depends on market<br>conditions) |
| Licence term | Through February 2032 |
| Estimated decommissioning cost | $58 million |
Markets
UO3 is shipped to Port Hope for conversion into either UF6 or UO2.
2022 ANNUAL INFORMATION FORM Page 73
Capacity
In 2012, the CNSC granted an increase to our annual licensed production capacity from 18 million kgU per year as UO3 to 24 million kgU as UO3, subject to the completion of certain equipment upgrades. These upgrades will be advanced based on market conditions.
Licensing
In February 2022, the CNSC granted our Blind River refinery a 10-year operating licence, which will expire in February 2032.
Port HopeConversion Services
| Licensed Capacity<br> <br><br><br><br>12.5M kgU as UF6<br> <br><br><br><br>2.8M kgU as UO2<br> <br><br><br><br>Licence renewal in<br> <br><br><br><br>February 2027 |
|---|
Port Hope is the only uranium conversion facility in Canada and a supplier of UO2 for Canadian-made CANDU reactors.
| Location | Ontario, Canada |
|---|---|
| Ownership | 100% |
| End product | UF6, UO2 |
| ISO certification | ISO 14001 certified |
| Licensed capacity | 12.5 million kgU as UF6 per year |
| 2.8 million kgU as UO2 per year | |
| Licence term | Through February 2027 |
| Estimated decommissioning cost | $129 million |
Conversion services
At our UO2 plant, we convert UO3 to UO2 powder, used to make pellets for Canadian CANDU reactors and CANDU reactors in other countries and blanket fuel for light water nuclear reactors.
At our UF6 plant, we convert UO3 to UF6, and then ship it to enrichment plants primarily in the US and Europe. There, it is processed to become low enriched UF6, which is subsequently converted to enriched UO2 and used as reactor fuel for light water nuclear reactors.
Anhydrous hydrofluoric acid (AHF) is a primary feed material for the production of UF6. We have agreements with more than one supplier of AHF to provide us with diversity of supply.
Port Hope conversion facility clean-up and modernization (Vision in Motion)
Vision in Motion is a unique opportunity that demonstrates our continued commitment to a clean environment. It has been made possible by the opening of a long-term waste management facility by the Government of Canada’s Port Hope Area Initiative project. There is a limited opportunity during the life of this project to engage in clean-up and renewal activities that address legacy waste at the Port Hope Conversion facility inherited from historic operations. Progress was made over the past year to facilitate the removal of some old buildings and structures, which will be the focus in the year ahead.
Licensing
In February 2017, the CNSC approved a ten-year operating licence for the Port Hope conversion facility.
2022 ANNUAL INFORMATION FORM Page 74
Labour relations
The current collective bargaining agreement with the unionized employees at our Port Hope conversion facility ends on June 30, 2025.
Cameco Fuel Manufacturing Inc. (CFM)
| Licensed Capacity<br> <br><br><br><br>1.65M kgU as UO2 fuel pellets<br><br><br><br> <br>Licence renewal in<br><br><br><br> <br>February 2043 |
|---|
CFM produces fuel bundles and reactor components for CANDU reactors.
| Location | Ontario**,** Canada |
|---|---|
| Ownership | 100% |
| End product | CANDU fuel bundles and components |
| ISO certification | ISO 9001 certified, ISO 14001 certified |
| Licensed capacity | 1.65 million kgU as UO2 fuel pellets |
| Licence term | Through February 2043 |
| Estimated decommissioning cost | $10.8 million |
Fuel manufacturing
CFM’s main business is making fuel bundles for CANDU reactors. CFM presses UO2 powder into pellets that are loaded into tubes, manufactured by CFM, and then assembled into fuel bundles. These bundles are ready to insert into a CANDU reactor core. CFM also produces many different zirconium-based reactor components for CANDU reactors.
Manufacturing services agreements
A substantial portion of CFM’s business is the supply of fuel bundles to the Bruce Power A and B nuclear units in Ontario. We supply the UO2 for these fuel bundles.
Licensing
In January 2023, the CNSC granted a 20-year renewal to the licence for CFM. The licence renewal also grants CFM’s request for a slight production increase to 1,650 tonnes as UO2 fuel pellets.
Labour relations
The current collective bargaining agreement with the unionized employees at CFM ends on June 1, 2024.
Other nuclear fuel cycle investments
Global Laser Enrichment
GLE is the exclusive licensee of the proprietary Separation of Isotopes by Laser Excitation (SILEX) laser enrichment technology, a third-generation uranium enrichment technology. We are the commercial lead for the GLE project with a 49% interest and starting in February 2023, an option to attain a majority interest of up to 75% ownership.
Subject to completion of the technology development program, and its progression through to commercialization, GLE has the potential to offer a variety of advantages to the global nuclear energy sector over the long-term, which include:
2022 ANNUAL INFORMATION FORM Page 75
| • | re-enriching depleted uranium tails leftover as a by-product of previous-generation enrichment technologies, repurposing legacy waste into a commercial source of uranium and conversion products to fuel nuclear reactors and aiding in the responsible clean-up of enrichment facilities no longer in operation, as per GLE’s agreement with the US Department of Energy |
|---|---|
| • | producing commercial low-enriched uranium (LEU) fuel for the world’s<br>existing and future fleet of large-scale light-water reactors with greater efficiency and flexibility than current enrichment technologies |
| --- | --- |
| • | producing high-assay low-enriched uranium (HALEU), the primary fuel stock<br>for the majority of small modular reactor (SMR) and advanced reactor designs that are proceeding through the development stage and continuing toward commercial readiness |
| --- | --- |
In 2022, GLE made progress with the first full-scale laser system module, successfully completing eight months of testing in Australia, and the system was delivered to GLE’s commercial pilot demonstration facility in the US. In addition, GLE signed letters of intent to collaborate with two major US utilities to help diversify the US nuclear fuel supply chain, including measures to support its deployment of laser enrichment technology in the US.
The development timeline for GLE will be dependent on several factors, including market fundamentals, securing government funding, support for HALEU availability in the US and GLE’s ability to secure long-term contracts to underpin the deployment of a commercial facility.
Proposed acquisition of Westinghouse
As announced on October 11, 2022, we entered into a strategic partnership with Brookfield Renewable to acquire Westinghouse, a global provider of mission-critical and specialized technologies, products and services across most phases of the nuclear power sector. Brookfield Renewable will beneficially own a 51% interest in Westinghouse and Cameco will beneficially own 49%. Bringing together Cameco’s expertise in the nuclear industry with Brookfield Renewable’s expertise in clean energy positions nuclear power at the heart of the energy transition and creates a powerful platform for strategic growth across the nuclear sector.
Westinghouse’s history in the energy industry stretches back over a century, during which time the company became a pioneer in nuclear energy.
Westinghouse is organized in three business segments:
| • | Operating Plant Services: Long-term contracting for the manufacturing and<br>installation of fuel assemblies and other ancillary equipment across multiple light water reactor technologies. Westinghouse provides recurring services for outages and maintenance, engineering solutions, and replacement components and parts.<br> |
|---|---|
| • | Energy Systems: Designing, engineering and supporting the development of new nuclear reactors.<br> |
| --- | --- |
| • | Environmental Services: Services to government and commercial customers that support nuclear sustainability,<br>environmental stewardship and remediation. |
| --- | --- |
The largest business segment is Operating Plant Services, which accounted for approximately $2.7 billion (US) or about 81% of Westinghouse’s total 2021 revenue of approximately $3.3 billion (US). This segment is built on long-term customer relationships. These customers seek solutions to ensure their reactors operate efficiently and reliably and therefore results in predictable revenue streams.
The acquisition of Westinghouse will be through a strategic partnership with Brookfield Renewable in the form of a limited partnership that will allow each of us to further participate in and support the growing momentum for nuclear energy. The board of directors of the general partner of the limited partnership will consist of six directors, three appointed by Cameco and three appointed by Brookfield Renewable. Decision-making by the board of the general partnership will correspond to percentage ownership interests in the limited partnership (51% Brookfield Renewable and 49% Cameco). There are a number of significant decisions that require the presence and support of both Cameco and Brookfield Renewable appointees to the board as long as certain ownership thresholds are met. These “reserved” matters will include decisions such as the approval of the annual budget, entering into material contracts, the making of significant investments, entering into new lines of business and related-party transactions. We expect to account for our share of the investment using the equity method.
2022 ANNUAL INFORMATION FORM Page 76
We expect the acquisition to:
| • | expand our participation in the nuclear fuel value chain. The acquisition is expected to complement our<br>high-quality, tier-one uranium assets and fuel services, including CANDU fuel manufacturing for heavy water reactors with Westinghouse’s global nuclear fuel and plant services platform for light water<br>reactors, which we expect will augment and expand our ability to meet the growing demand for nuclear fuel supplies and services that are reliable and secure; |
|---|---|
| • | be accretive to our cash flow after the closing, and prior to considering new revenue opportunities and to<br>complement our existing business. Based on Westinghouse’s strong long-term customer relationships, the service type model of the Operating Plant Services segment and resulting reliable revenue streams we expect it to generate stable cash flow,<br>to fund its approved annual operating budget and provide quarterly distributions to the partners after the closing; |
| --- | --- |
| • | create new revenue opportunities for us by expanding our ability to satisfy existing and new customer needs. In<br>addition to Westinghouse’s contribution to our financial results, the acquisition is expected to result in up to $50 million in additional revenue for Cameco in the year following the closing of the transaction and to result in additional<br>revenue opportunities for us in the future from new customers and existing customers seeking a fully fabricated fuel supply option; and |
| --- | --- |
| • | maintain our strong balance sheet through a disciplined funding strategy designed to enhance our financial<br>strength. At the same time, we expect to continue to execute on our strategy and provide a platform for further growth, expanding our reach in an industry that has historically performed well during varying macroeconomic environments due to the<br>baseload nature of nuclear power and its strong customer base. |
| --- | --- |
The total enterprise purchase price for the acquisition is $7.875 billion (US), which includes an assumption of an estimated $3.4 billion (US) of debt which will remain with Westinghouse, and which is subject to customary purchase price adjustments. The remainder of the purchase price will be paid by approximately $4.5 billion (US) of aggregate cash contributions, our share of which will be approximately $2.2 billion (US).
Concurrently with the execution of the acquisition agreement, we secured commitments that provide for a $1 billion (US) bridge loan facility and $600 million (US) in term loans. Following the announcement, we undertook a $650 million (US) bought deal offering of common shares, with an underwriter option to purchase additional shares. The offering closed on October 17, 2022, providing us with gross proceeds of approximately $747.6 million (US) including the underwriters’ exercise of the option to purchase additional shares in full. With the proceeds from the closing of the offering and based on current uncertainty in the global macroeconomic environment and the success we are having in adding new long-term business, at this time, we do not intend to issue additional equity to fund our portion of the purchase price for the Westinghouse acquisition. As of the closing of the bought deal offering, the bridge loan facility was reduced to $280 million (US). The debt facilities will remain undrawn until closing of the acquisition. The bridge facility, if funded, will mature 364 days after the acquisition closing date, and the term loans consisting of two tranches of $300 million (US) each, are expected to mature two years and three years after the acquisition closes.
The acquisition is expected to close in the second half of 2023 and continues to be subject to customary closing conditions and certain regulatory approvals. The final financing is not required until close of the acquisition and will be determined based on market conditions and the expected run rate of our business at that time. We expect a permanent financing mix of capital sources, including cash, debt and equity, designed to preserve our balance sheet and ratings strength, while maintaining healthy liquidity. The acquisition is not subject to a financing condition.
For more information on the proposed acquisition of Westinghouse, see page 122 – Proposed acquisition of Westinghouse risks and our 2022 MD&A under the heading Proposed acquisition of Westinghouse.
Caution about forward-looking information relating to the Westinghouse acquisition
This discussion of our expectations for the Westinghouse acquisition, including sources and uses of financing for the acquisition, timeline for the acquisition, including anticipated closing date, expected benefits, and our intention in respect of not issuing additional equity to fund our portion of the purchase price for the Westinghouse acquisition is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headings Caution about forward-looking information beginning on page 1 and in our October 18, 2022 material change report, and Proposed acquisition of Westinghouserisks on page 122.The material change report is available at www.sedar.com and www.sec.gov. Actual results and events may be significantly different from what we currently expect.
2022 ANNUAL INFORMATION FORM Page 77
Corporate development
Investment program
Currently, with our extensive portfolio of mineral reserves and resources and our belief that we have ample productive capacity with the ability to expand as the demand for nuclear energy and nuclear fuels grows, our focus is on navigating by our investment-grade rating and returning to our tier-one run rate while aligning our tier-one production with our delivery commitments and market opportunities. We expect that these assets will allow us to meet rising uranium demand with increased production from our best margin operations and will help to mitigate risk in the event of prolonged uncertainty.
Additionally, we are exploring opportunities across the fuel cycle, which align well with our commitment to responsibly and sustainably manage our business and increase our contributions to global climate change solutions. These opportunities include investments such as our recently announced plans to acquire a 49% interest in Westinghouse, as well as emerging opportunities such as our investment in GLE. It also includes the non-binding arrangements we have signed to explore several areas of cooperation to advance the commercialization and deployment of small modular reactors in Canada and around the world.
We continually evaluate investment opportunities within the nuclear fuel cycle that could add to our future supply options, support our customer’s needs, and complement and enhance our business in the nuclear industry. We will make an investment decision when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our stakeholders in a fundamentally stronger position. As such, an investment opportunity is never assessed in isolation. Investments must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described in our 2022 MD&A under Our vision, values and strategy.
Mineral reserves and resources
Our mineral reserves and resources are the foundation of our company and fundamental to our success.
We have interests in a number of uranium properties. The tables in this section show the estimates of the proven and probable mineral reserves, and measured, indicated, and inferred mineral resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River/Key Lake, Cigar Lake and Inkai. Mineral reserves and resources are all reported as of December 31, 2022.
We estimate and disclose mineral reserves and resources in five categories, using the definition standards adopted by the Canadian Institute of Mining, Metallurgy and Petroleum Council, and in accordance with NI 43-101. You can find out more about these categories at www.cim.org.
About mineral resources
Mineral resources do not have to demonstrate economic viability but have reasonable prospects for eventual economic extraction. They fall into three categories: measured, indicated and inferred. Our reported mineral resources are exclusive of mineral reserves.
| • | Measured and indicated mineral resources can be estimated with sufficient confidence to allow the<br>appropriate application of technical, economic, marketing, legal, environmental, social, and governmental factors to support evaluation of the economic viability of the deposit. |
|---|---|
| • | measured resources: we can confirm both geological and grade continuity to support detailed mine planning<br> |
| --- | --- |
| • | indicated resources: we can reasonably assume geological and grade continuity to support mine planning<br> |
| --- | --- |
| • | Inferred mineral resources are estimated using limited geological evidence and sampling information. We do<br>not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource, but it is reasonably<br>expected that the majority of inferred mineral resources could be upgraded to indicated mineral resources with continued exploration. |
| --- | --- |
Our share of uranium in the following mineral resource tables is based on our respective ownership interests. Mineral resources that are not mineral reserves have no demonstrated economic viability.
2022 ANNUAL INFORMATION FORM Page 78
About mineral reserves
Mineral reserves are the economically mineable part of measured and/or indicated mineral resources demonstrated by at least a preliminary feasibility study. The reference point at which mineral reserves are defined is the point where the ore is delivered to the processing plant, except for ISR operations where the reference point is where the mineralization occurs under the existing or planned wellfield patterns. Mineral reserves fall into two categories:
| • | proven reserves: the economically mineable part of a measured resource for which at least a preliminary<br>feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified with a high degree of confidence |
|---|---|
| • | probable reserves: the economically mineable part of a measured and/or indicated resource for which at<br>least a preliminary feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified with a degree of confidence lower than that applying to proven reserves |
| --- | --- |
For properties for which we are the operator, we use current geological models, an average uranium price of $53 (US) per pound U3O8, and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate. For properties in which we have an interest but are not the operator, we take reasonable steps to ensure that the reserve and resource estimates we report are reliable.
Our share of uranium in the mineral reserves table below is based on our respective ownership interests.
Qualified persons
The technical and scientific information discussed in this AIF, including mineral reserve and resource estimates, for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:
| McArthur River/Key Lake | Cigar Lake |
|---|---|
| • Greg Murdock, general manager, McArthur River, Cameco<br><br><br><br> <br>• Daley McIntyre, general<br>manager, Key Lake, Cameco<br> <br><br><br><br>• Alain D. Renaud, principal resource geologist, technical services, Cameco<br><br><br><br> <br>• Biman Bharadwaj, principal<br>metallurgist, technical services, Cameco | • Lloyd Rowson, general manager, Cigar Lake, Cameco<br><br><br><br> <br>• Scott Bishop, director,<br>technical services, Cameco<br> <br><br><br><br>• Alain D. Renaud, principal resource geologist, technical services, Cameco<br><br><br><br> <br>• Biman Bharadwaj, principal<br>metallurgist, technical services, Cameco |
| Inkai | |
| • Sergey Ivanov, deputy director general, technical services, Cameco Kazakhstan<br>LLP<br> <br><br> <br>• Alain D. Renaud,<br>principal resource geologist, technical services, Cameco<br> <br><br><br><br>• Scott Bishop, director, technical services, Cameco<br><br><br><br> <br>• Biman Bharadwaj, principal<br>metallurgist, technical services, Cameco |
Important information about mineral reserve and resource estimates
Although we have carefully prepared and verified the mineral reserve and resource figures in this document, the figures are estimates, based in part on forward-looking information.
Estimates are based on our knowledge, mining experience, analysis of drilling results, the quality of available data and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions including:
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| • | geological interpretation |
|---|---|
| • | extraction plans |
| --- | --- |
| • | commodity prices and currency exchange rates |
| --- | --- |
| • | recovery rates |
| --- | --- |
| • | operating and capital costs |
| --- | --- |
There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 1 for information about forward-looking information, and page 98 for a discussion of the risks that can affect our business.
Please see pages 82 and 83 for the specific assumptions, parameters and methods used for the McArthur River, Cigar Lake and Inkai mineral reserve and resource estimates.
Our estimate of mineral resources and mineral reserves may be materially affected by the occurrence of one or more of the risks described under the heading Reserve and resource estimates are not precise on page 106. In addition to those risks, our estimates of mineral resources and mineral reserves for certain properties may be materially affected by the occurrence of one or more of the following risks or factors:
McArthur River and Cigar Lake mineral resource and reserve estimates
| • | Water inflows – see Flooding at McArthur River and Cigar Lake at page 99 |
|---|---|
| • | Technical challenges – see Technical challenges at Cigar Lake and McArthur River at page 100<br> |
| --- | --- |
Inkai mineral resource and reserve estimates
| • | Political risks – see Foreign investments and operations at page 118 and Kazakhstan at<br>page 119. |
|---|
The extent to which our estimates of mineral resources and mineral reserves may be affected by the foregoing issues could vary from material gains to material losses.
Important information for US investors
We present information about mineralization, mineral reserves and resources as required by NI 43-101 of the Canadian Securities Administrators, in accordance with applicable Canadian securities laws. As a foreign private issuer filing reports with the US Securities and Exchange Commission (SEC) under the Multijurisdictional Disclosure System, we are not required to comply with the SEC’s disclosure requirements relating to mining properties. Investors in the US should be aware that the disclosure requirements of NI 43-101 are different from those under applicable SEC rules, and the information that we present concerning mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for mining companies.
Mineral reserves
As of December 31, 2022 (100% – only the shaded column shows our share)
Proven and probable
(tonnes in thousands; pounds in millions)
| PROVEN | PROBABLE | TOTAL MINERAL RESERVES | OURSHARERESERVES<br>CONTENT(LBS U3O8) | |||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| PROPERTY | MININGMETHOD | TONNES | GRADE% U3O8 | CONTENT(LBS U3O8) | TONNES | GRADE% U3O8 | CONTENT(LBS U3O8) | TONNES | GRADE% U3O8 | CONTENT(LBS U3O8) | METALLURGICALRECOVERY (%) | |||||||||||||
| Cigar Lake | UG | 308.9 | 16.25 | 110.7 | 99.1 | 20.19 | 44.1 | 408.0 | 17.21 | 154.8 | **** | 84.4 | 98.8 | |||||||||||
| Key Lake | OP | 61.1 | 0.52 | 0.7 | — | — | — | 61.1 | 0.52 | 0.7 | **** | 0.6 | 95 | |||||||||||
| McArthur River | UG | 2,138.3 | 7.00 | 329.9 | 530.7 | 5.47 | 64.0 | 2,669.0 | 6.70 | 394.0 | **** | 275.0 | 99 | |||||||||||
| Inkai | ISR | 253,647.2 | 0.04 | 218.3 | 71,803.1 | 0.03 | 53.5 | 325,450.3 | 0.04 | 271.8 | **** | 108.7 | 85 | |||||||||||
| Total | **** | 256,155.6 | **** | — | **** | 659.7 | **** | 72,432.9 | **** | — | **** | 161.6 | **** | 328,588.5 | **** | — | **** | 821.3 | **** | 468.8 | — |
(UG – underground, OP – open pit, ISR – in situ recovery)
Note that the estimates in the above table:
| • | use a constant dollar average uranium price of approximately $53 (US) per pound U3O8 |
|---|---|
| • | are based on exchange rates of $1.00 US=$1.26 Cdn and $1.00 US=490 Kazakhstan Tenge |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 80
Metallurgical recovery
We report mineral reserves as the quantity of contained ore supporting our mining plans and provide an estimate of the metallurgical recovery for each uranium property. The estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process is obtained by multiplying the quantity of contained metal (content) by the planned metallurgical recovery percentage. The content and our share of uranium in the table above are before accounting for estimated metallurgical recovery.
Changes this year
Our share of proven and probable mineral reserves increased from 464 million pounds U3O8 at the end of 2021, to 469 million pounds at the end of 2022. The change was primarily the result of:
| • | a mineral resource and reserve estimate update at Cigar Lake which added 9 million pounds to proven and<br>probable reserves based on ongoing surface freeze drilling results |
|---|---|
| • | increased ownership stake at Cigar Lake which added 7 million pounds |
| --- | --- |
partially offset by:
| • | production at Cigar Lake, Inkai and McArthur River, which removed 14 million pounds from our mineral<br>inventory |
|---|
The remaining changes are attributable to other adjustments based on the mineral resource and reserve estimate updates at Cigar Lake and McArthur River.
Mineral resources
As of December 31, 2022 (100% – only the shaded columns show our share)
Measured, indicated and inferred
(tonnes in thousands; pounds in millions)
| MEASURED RESOURCES (M) | INDICATED RESOURCES (I) | OURSHARE | INFERRED RESOURCES | OURSHARE | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| PROPERTY | TONNES | GRADE% U3O8 | CONTENT(LBS U3O8) | TONNES | GRADE% U3O8 | CONTENT(LBS U3O8) | TOTAL M+I<br>CONTENT(LBSU3O8) | TOTAL M+ICONTENT(LBSU3O8) | TONNES | GRADE% U3O8 | CONTENT(LBS U3O8) | INFERRED<br>CONTENT(LBSU3O8) | ||||||||||||
| Cigar Lake | 48.0 | 6.06 | 6.4 | 314.1 | 14.28 | 98.9 | 105.3 | 57.5 | 178.2 | 5.62 | 22.1 | 12.0 | ||||||||||||
| Fox Lake | — | — | — | — | — | — | — | — | 386.7 | 7.99 | 68.1 | 53.3 | ||||||||||||
| Kintyre | — | — | — | 3,897.7 | 0.62 | 53.5 | 53.5 | 53.5 | 517.1 | 0.53 | 6.0 | 6.0 | ||||||||||||
| McArthur River | 74.9 | 2.23 | 3.7 | 63.0 | 2.23 | 3.1 | 6.8 | 4.7 | 38.9 | 2.89 | 2.5 | 1.7 | ||||||||||||
| Millennium | — | — | — | 1,442.6 | 2.39 | 75.9 | 75.9 | 53.0 | 412.4 | 3.19 | 29.0 | 20.2 | ||||||||||||
| Rabbit Lake | — | — | — | 1,836.5 | 0.95 | 38.6 | 38.6 | 38.6 | 2,460.9 | 0.62 | 33.7 | 33.7 | ||||||||||||
| Tamarack | — | — | — | 183.8 | 4.42 | 17.9 | 17.9 | 10.3 | 45.6 | 1.02 | 1.0 | 0.6 | ||||||||||||
| Yeelirrie | 27,172.9 | 0.16 | 95.9 | 12,178.3 | 0.12 | 32.2 | 128.1 | 128.1 | — | — | — | — | ||||||||||||
| Crow Butte | 1,558.1 | 0.19 | 6.6 | 939.3 | 0.35 | 7.3 | 13.9 | 13.9 | 531.4 | 0.16 | 1.8 | 1.8 | ||||||||||||
| Gas Hills—Peach | 687.2 | 0.11 | 1.7 | 3,626.1 | 0.15 | 11.6 | 13.3 | 13.3 | 3,307.5 | 0.08 | 6.0 | 6.0 | ||||||||||||
| Inkai | 87,192.7 | 0.03 | 56.1 | 65,236.0 | 0.02 | 32.9 | 89.1 | 35.6 | 36,165.2 | 0.03 | 23.9 | 9.6 | ||||||||||||
| North Butte—Brown Ranch | 604.2 | 0.08 | 1.1 | 5,530.3 | 0.07 | 8.4 | 9.4 | 9.4 | 294.5 | 0.06 | 0.4 | 0.4 | ||||||||||||
| Ruby Ranch | — | — | — | 2,215.3 | 0.08 | 4.1 | 4.1 | 4.1 | 56.2 | 0.13 | 0.2 | 0.2 | ||||||||||||
| Shirley Basin | 89.2 | 0.15 | 0.3 | 1,638.2 | 0.11 | 4.1 | 4.4 | 4.4 | 508.0 | 0.10 | 1.1 | 1.1 | ||||||||||||
| Smith Ranch—Highland | 3,703.5 | 0.10 | 7.9 | 14,372.3 | 0.05 | 17.0 | 24.9 | 24.9 | 6,861.0 | 0.05 | 7.7 | 7.7 | ||||||||||||
| Total | **** | 121,130.7 | **** | — | **** | 179.7 | **** | 113,473.7 | **** | — | **** | 405.5 | **** | 585.2 | **** | 451.4 | **** | 51,763.7 | **** | — | **** | 203.5 | **** | 154.4 |
Note that mineral resources:
| • | do not include amounts that have been identified as mineral reserves |
|---|---|
| • | do not have demonstrated economic viability |
| --- | --- |
| • | totals may not add due to rounding |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 81
Changes this year
Our share of measured and indicated mineral resources increased from 447 million pounds U3O8 at the end of 2021, to 451 million pounds at the end of 2022. Our share of inferred mineral resources remains unchanged at 154 million pounds U3O8.
Key assumptions, parameters andmethods
McArthur River
Key assumptions
| • | Mineral reserves assume a 99.4% planned mine recovery and have allowances for expected waste (42% average) and<br>backfill (6.8% average) dilution as part of the normal mining extraction process. Mineral resources do not include such allowances. |
|---|---|
| • | A constant dollar average uranium price of $53 (US) per pound<br>U3O8 with a $1.00 (US) = $1.26 (Cdn) fixed exchange rate was used to estimate the mineral reserves. |
| --- | --- |
| • | Mining rates assume annual packaged production of at least 15 million pounds. |
| --- | --- |
Key parameters
| • | Grades of U3O8 were obtained from chemical assaying of drill core or from equivalent % U3O8 grades<br>obtained from radiometric probing results. In areas of poor core recovery (usually < 75%) or missing samples, the grade was determined from probing. |
|---|---|
| • | When not measured, densities are determined using formulas based on the relation between density measurements of<br>drill core and chemical assay grades. |
| --- | --- |
| • | Mineral resources are estimated at a minimum mineralized thickness of 1.0 metre and at a minimum grade of 0.50% U3O8. Reported mineral reserves are based on pounds U3O8 recovered per excavation, translating into an average cut-off grade of 0.75% U3O8. |
| --- | --- |
| • | Mineral reserves are estimated based on the use of raisebore and blasthole stope mining methods in conjunction<br>with freeze curtains. |
| --- | --- |
| • | Reasonable expectation for eventual economic extraction of the mineral resources is based on a uranium price of<br>$57 (US) per pound U3O8, anticipated exchange rates, mining and process recoveries, production costs, royalties and mineralized area<br>tonnage, grade, and spatial continuity considerations. |
| --- | --- |
Key methods
| • | The models were created from the geological interpretation in section views and in<br>3-dimensions from surface and underground drillhole information. |
|---|---|
| • | Mineral resources and mineral reserves were estimated using 3-dimensional<br>block models. Ordinary kriging and inverse distance squared methods were used to estimate the grade and density. |
| --- | --- |
| • | Maptek Vulcan and Leapfrog Geo software were used to generate the mineral resource and reserve estimates.<br> |
| --- | --- |
Cigar Lake
Key assumptions
| • | Mineral reserves have been estimated with an average allowance of 34% dilution at 0% U3O8 and a 86% mining recovery factor. Mineral resources do not include such allowances. |
|---|---|
| • | The mining rate is assumed to vary between 100 and 200 tonnes per day and a full mill production rate of<br>approximately 18 million pounds U3O8 per year. |
| --- | --- |
| • | Areas being mined must meet specific ground freezing requirements before jet boring begins.<br> |
| --- | --- |
| • | A constant dollar average uranium price of $53 (US) per pound<br>U3O8 with a $1.00 (US) = $1.26 (Cdn) fixed exchange rate was used to estimate the mineral reserves. |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 82
Key parameters
| • | Grades of U3O8 were obtained from chemical assaying of drill core or from equivalent % U3O8 grades<br>obtained from radiometric probing results. In areas of poor core recovery (usually < 75%) or missing samples, the grade was determined from probing. |
|---|---|
| • | When not measured, densities are determined using formulas based on the relation between density measurements of<br>drill core and chemical assay grades. |
| --- | --- |
| • | Mineral resources have been estimated using a minimum mineralization thickness of 1.0 metre and a minimum grade<br>of 1.0% U3O8. |
| --- | --- |
| • | Mineral reserves have been estimated on the basis of designed JBS cavities with positive economics from the<br>estimated recovered uranium. |
| --- | --- |
| • | Reasonable expectation for eventual economic extraction of the mineral resources is based on a uranium price of<br>$57 (US) per pound U3O8, anticipated exchange rates, mining and process recoveries, production costs, royalties and mineralized area<br>tonnage, grade, and spatial continuity considerations. |
| --- | --- |
Key methods
| • | The geological interpretation of the orebody was done in section views and in<br>3-dimensions from surface drillhole information. |
|---|---|
| • | Mineral resources and mineral reserves were estimated using 3-dimensional<br>block models. Geostatistical conditional simulation (with sequential Gaussian simulation) and inverse distance squared methods were used to estimate the grade and density. |
| --- | --- |
| • | Maptek Vulcan and Leapfrog Geo software were used to generate the mineral resource and reserve estimates.<br> |
| --- | --- |
Inkai
Key assumptions
| • | Mineral resources have been estimated based on the use of the ISR extraction method. |
|---|---|
| • | Average metallurgical recovery of 85%. |
| --- | --- |
| • | A constant dollar average uranium price of $53 (US) per pound<br>U3O8, with a $1.00 US = $1.26 Cdn and 490 Kazakhstan Tenge to $1.00 US fixed exchange rate was used to estimate the mineral reserves.<br> |
| --- | --- |
Key parameters
| • | Grades (% U3O8) were obtained from gamma radiometric probing of drillholes, checked against assay results and prompt fission neutron logging results to account for disequilibrium. |
|---|---|
| • | Average density of approximately 1.7 tonnes per cubic metre was used, based on historical and current sample<br>measurements. |
| --- | --- |
| • | Mineral resources are estimated using a minimum grade of 0.012%<br>U3O8 per drillhole interval and minimum Grade x Thickness (GT) of 0.071 m% U3O8 for MPP area and 0.047 m% U3O8 for Sat1 and Sat2 areas. |
| --- | --- |
| • | Mineral reserves represent the in-situ ore available for production<br>within the term of the resource use contract. |
| --- | --- |
| • | A cut-off for the mineral reserves of 0.13 m% U3O8 is applied on the estimated GT value for each block of the model. |
| --- | --- |
| • | Reasonable expectation for eventual economic extraction of the mineral resources is based on a uranium price of<br>$57 (US) per pound U3O8, anticipated exchange rates, mining and process recoveries, production costs, royalties and mineralized area<br>tonnage, grade, and spatial continuity considerations. |
| --- | --- |
Key methods
| • | The geological interpretation of the orebody was done in section and plan views derived from surface drillhole<br>information. |
|---|---|
| • | Mineral resources were estimated with the GT area average method, where the estimated variable is the uranium<br>grade multiplied by the thickness of the interval, and using averages for two-dimensional block models. |
| --- | --- |
| • | A resource block must be confined to one aquifer taking into consideration the distribution of local aquitards.<br> |
| --- | --- |
| • | Considerations of the rate of in-situ uranium recovery, lixiviant uranium<br>head grades, wellfield flow rates and production requirements to define the production sequence. |
| --- | --- |
| • | Geological modelling and mining software used were AtomGeo, MapInfo and Micromine. |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 83
Our ESG principles and practices
A key part of our strategy, reflecting our values
We are committed to delivering our products responsibly. We integrate ESG principles and practices into every aspect of our business, from our corporate objectives and approach to compensation, to our overall corporate strategy, risk management, and day-to-day operations, and they align with our values. We seek to be transparent with our stakeholders, keeping them updated on the risks and opportunities that we believe may have a significant impact on our ability to achieve our strategic plan and add long-term value. We recognize the importance of integrating certain ESG factors, such as safety performance, a clean environment and supportive communities, into our executive compensation strategy as we see success in these areas as critical to the long-term success of the company.
Our board of directors holds the highest level of oversight for our business strategy and strategic risks, including ESG matters and climate-related risks. Oversight of ESG and climate-related reporting and disclosure has been delegated by the board to the Safety, Health and Environment (SHE) committee of the board of directors. We also have a multi-disciplinary ESG steering committee, chaired by our senior vice-president and chief corporate officer that includes representatives from across the organization whose role is to review our ESG governance and reporting, and our current approach to sustainability, against evolving trends. Additional information about our governance of ESG matters is included in our most recent ESG report.
In an effort to continually evolve the robustness of our sustainability commitments and communications, starting in 2020, we aligned our ESG performance indicators with the ones recommended by the Sustainability Accounting Standards Board (SASB). In addition, we began addressing the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) in our ESG report. In 2022, we continued to progress our work, conducting a gap analysis to identify how we could better align to TCFD recommendations. Findings from this work identified the need to undertake scenario analysis (physical and transition) to develop a robust evidence base for our climate strategy and pursue opportunities to financially quantify identified climate-related risks and opportunities where possible. See the discussion below regarding our climate change scenario analysis for more information.
In July 2022, we published our 2021 ESG report. The report sets out our strategy and the policies and programs we use to govern and manage ESG issues that are important to our stakeholders. In addition to SASB and TCFD, the report provides key ESG performance indicator data based on the Global Reporting Initiative’s Sustainability Framework as well as some unique corporate indicators, to measure and report our performance on environmental, social and economic impacts in the areas we believe have a significant impact on our sustainability in the long-term and that are important to our stakeholders. This is our ESG report card to our stakeholders. You can find our report at cameco.com/about/sustainability.
Environment
We recognize and embrace our responsibility to manage our activities with care for the protection of environmental resources. Protection of the environment is one of our highest corporate priorities during all stages of our activities from exploration through development, operations, and decommissioning. Environmental stewardship is embedded in how we operate.
We are guided by our safety, health, environment and quality policy and associated programs that are designed to minimize our impact on air, land, and water and to conserve the biodiversity of surrounding ecosystems. Across our operations, we comply with strict regulations and have systems in place to monitor and mitigate our potential impacts. In addition to our own environmental monitoring, we collaborate with local communities in northern Saskatchewan around our operations to give confidence to them that traditionally harvested foods remain safe to eat, and water remains safe to drink.
Climate change: Nuclear power is part of the solution
We recognize the critical nature of the fight against climate change, and want our employees, customers, investors, and community partners near our operations to know we are committed to being an active and constructive partner in addressing this challenge. The reduction of carbon and greenhouse gas (GHG) emissions is important and necessary in Canada and around the world. Nuclear power must be a central part of the solution to the world’s shift to a low-carbon, climate-resilient economy. As one of the world’s largest producers of the uranium needed to fuel nuclear reactors, we believe there is a significant opportunity for us to be part of the solution to combat climate change. We enable vast emissions reductions that
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can be achieved through nuclear power and are committed to transforming our already low GHG emissions footprint to achieve our ambition of having net-zero emissions while delivering significant long-term business value.
In accordance with our 2022 compensable corporate objectives, we undertook a planning process to outline our overarching low-carbon transition strategy. We identified the practical and achievable actions that we expect to take to decarbonize our operations and manage climate-related risks. In doing so, we are demonstrating our alignment with the ambitions of the Paris Agreement to, “limit global temperature rise to well below 2 degrees Celsius (°C), above pre-industrial levels, and to pursue efforts to limit global temperature rise even further to 1.5°C”. By extension, we are demonstrating our alignment with the Government of Canada’s commitment to the Paris Agreement in accordance with the Net Zero Accountability Act and resulting 2030 Emissions Reduction Plan.
We recognize that climate change, including shifts in temperature, precipitation and more frequent severe weather events could affect our operations in a range of possible ways. As part of our low-carbon transition planning, we completed a climate change scenario analysis to understand how projected long-term changing climate conditions could impact our employees, assets, and operations in northern Saskatchewan. We leveraged internal subject matter expertise with assistance from a third-party expert to complete the assessment.
The physical risk assessment study was undertaken to deliver an initial forward-looking physical climate risk assessment across our four sites in northern Saskatchewan and identify possible risk management and adaptation options. The next steps for the northern Saskatchewan physical risk assessment are to embed the physical climate risk findings into Cameco’s internal risk processes and develop an adaptation action plan for each site in the study. We are targeting the completion of similar assessments for all our majority owned and operated facilities over the next five years. In 2023, we will focus our physical climate risk assessment efforts on our Ontario operations.
We will continue to explore climate change projections for the areas where we operate and those critical to moving supplies and products through our value chain. We will use this information to identify where our existing climate-related acute and chronic risk management practices are expected to remain sufficient in the years to come and where adaptation and other enhancements may be required.
When it comes to climate change, we have tracked and reported our GHG emissions for more than two decades. A summary of our activities to understand and mitigate the risks associated with climate change scenarios is reported to the board of directors on a regular basis in accordance with our Enterprise Risk Management program, including the mitigating controls and management actions taken to reduce these risks.
In 2022, we developed the Energy and GHG Emissions Reductions Ideas Box that allows all employees to submit ideas to support us in reducing operational emissions. The Ideas Box also provides employees the opportunity to see key details from all decarbonization projects under investigation today.
We have also enjoyed some significant success in our efforts to reduce our energy use and GHG emissions to date. For example, at our Port Hope conversion facility, we have achieved a 28% reduction to peak power demand and more than $2.1 million in annual energy savings with projects such as HVAC and compressed air system upgrades and lighting efficiency retrofits. At our northern Saskatchewan mining and milling operations, recent efforts have focused on the implementation of an Energy Management Information System (EMIS) in alignment with our larger digital transformation efforts. The EMIS improves our ability to visualize, monitor, and manage our energy use and emissions profile in real time. Ultimately, EMIS gives those operations the ability to identify where our highest impact emissions reduction opportunities exist and assurance that the actions we have taken are maintained over time.
Beyond these projects and initiatives, we have completed work to profile our emissions, enabling the identification of multiple high impact energy efficiency and emissions reductions opportunities including lighting retrofits, building envelope improvements, heat recovery projects, and the ability to explore alternative energy sources. Through these and other innovative decarbonization actions across efficiency, electrification, waste to value, carbon economy, and fuel switching themes – we expect to achieve a 30% absolute reduction from our total Scope 1 and 2 emissions level by 2030 from our 2015 baseline as our first major milestone on the journey to achieve our ambition of being net zero. For our Scope 2 emissions (purchased power), achieving this target will largely be dependent on the success of SaskPower in decarbonizing its grid in accordance with its current plans.
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Social
Our relationships with our workforce, Indigenous Peoples, and local communities are fundamental to our success. The safety and protection of our workforce and the public is our top priority in our assessment of risk and planning for safe operations and product transport. To deliver on our vision, we invest in programs to attract and retain a diverse and skilled workforce that better reflects the communities in which we operate and to increase the participation of underrepresented groups in trades and technical positions. We want to build a workforce that is dedicated to continuous improvement and shares our values.
The importance of our workers and Indigenous Peoples working and living near our operations is exemplified by our ongoing commitment to help manage the impacts of the COVID-19 pandemic on our workforce, their families and their communities.
Ourresponse to the COVID*–*19 pandemic
We continue to closely monitor and adapt to the developments related to COVID-19. Throughout the pandemic, our priority has been to protect the health and well-being of our workers, including employees and contractors, their families, and their communities.
The proactive decisions we made, and our ongoing efforts to monitor and manage the risk of COVID-19, to help ensure our workers are safe are consistent with our values. The health and safety of our workers, their families and their communities continues to be the priority in all our plans, which will align with the guidance of the relevant health authorities where we operate.
Governance
We believe that sound governance is the foundation for strong corporate performance. Our diverse and independent board of directors’ primary role is to provide strategic direction and risk oversight in order to help the company achieve its vision of “energizing a clean-air world”. The board guides the company to operate as a sustainable business, to optimize financial returns while effectively managing risk, and to conduct business in a way that is transparent, independent, and ethical.
The board has formal governance guidelines that set out our approach to governance and the board’s governance role and practices. The guidelines ensure we comply with all of the applicable governance rules and legislation in Canada and the US, conduct ourselves in the best interests of our stakeholders, and meet industry best practices. The guidelines are reviewed and updated regularly.
Our corporate governance framework includes an established and recognized management system that describes the policies, processes and procedures we use to help us fulfill all the tasks required to achieve our objectives and strategy. It sets out our vision, values, and measures of success. It speaks to our strategic planning process, leadership alignment and accountability, compliance and assessment, people and culture, process identification and work management, risk management, communications and stakeholder support, knowledge and information management, change management, problem identification and resolution, and continual improvement.
Risk and Risk Management
Our board of directors oversees management’s implementation of appropriate risk management processes and controls. We have a Risk Policy that is supported by our formal Risk Management Program.
Our Risk Management Program involves a broad, systematic approach to identifying, assessing, monitoring, reporting and managing the significant risks we face in our business and operations, including consideration of ESG and climate-related risks that could impact our four measures of success. The program is based on the ISO 31000 Risk Management guidelines. ISO 31000 provides guidance on risk management activities with internationally recognized practices and provides sound principles for effective management and governance of risks. Our program applies to all risks facing the company, including climate-related risks. The program establishes clear accountabilities for employees throughout the company to take ownership of risks specific to their area and to effectively manage those risks. The program is reviewed annually to ensure that it continues to meet our needs.
We use a common risk matrix throughout the company. Any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan is considered an enterprise risk and is brought to the attention of senior management and the board. We continually update our risk profile by performing regular monitoring of risks across the organization. Regular monitoring helps us to properly manage risks and identify any new risks. Detailed risk reporting is
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provided on a quarterly basis to senior management and the board and its committees on the status of the mitigating and/or monitoring plans for each of the enterprise risks. Management also reviews monthly updates on the company’s progress in managing these risks.
See Managing the risks, starting on page 67 of our 2022 MD&A, for a discussion of the material risks, and the specific risks discussed under each operation, advanced project, and other nuclear fuel cycle investment update in our 2022 MD&A. In addition to carefully considering the other information in this AIF, we also recommend you review Risks that can affect our business starting at page 98 of this AIF which includes a discussion of other material risks that could have an impact on our business.
Measuring our results
Targets and Metrics: The Linkbetween ESG Factors and Executive Pay
Each year, we set corporate objectives that are aligned with our strategic plan. These objectives fall under our four measures of success: (1) outstanding financial performance, (2) safe, healthy and rewarding workplace, (3) clean environment and (4) supportive communities. Performance against specific targets under these objectives forms the foundation for a portion of annual employee and executive compensation. See our most recent management proxy circular for more information on how executive compensation is determined.
Our targets for 2022 continue to reflect the operational and strategic actions that we have taken. While we are beginning to see a significant improvement in our financial performance (earnings and cash flow) as our tier-one production increases and our average realized price reflects the improving market, our results still do not reflect our expected long-term run rate performance. As our long-term contract portfolio continues to grow and our tier-one production continues to ramp up, we believe that the strategic actions we have taken have helped to pave the way to stronger financial performance over time. Additionally, we will not compromise our commitment to safety, people and our environment. For more information on our compensation targets and our reported performance against those targets, see the Measuring our results section in our 2022 MD&A and our most recent management proxy circular.
The regulatory environment
This section discusses some of the more significant government controls and regulations that have a material effect on our business. A significant part of our economic value depends on our ability to comply with the extensive and complex laws and regulations that govern our activities. At this time, we do not expect any of the proposed legislation or changes to existing legislation will have a material effect on our business.
International treaty on the non-proliferation of nuclear weapons
The Treaty on the Non-Proliferation of Nuclear Weapons (NPT) is an international treaty that was established in 1970. It has three objectives:
| • | to prevent the spread of nuclear weapons and weapons technology |
|---|---|
| • | to foster the peaceful uses of nuclear energy |
| --- | --- |
| • | to further the goal of achieving general and complete disarmament |
| --- | --- |
The NPT establishes a safeguards system under the responsibility of the IAEA. Almost all countries are signatories to the NPT, including Canada, the US, the United Kingdom and France. We are therefore subject to the NPT and comply with the IAEA’s requirements.
Industry regulation and permits
Canada
Our Canadian operations have regulatory obligations to both the federal and provincial governments. There are four main regulatory agencies that issue licences and approvals:
| • | CNSC (federal) |
|---|---|
| • | Fisheries and Oceans Canada (federal) |
| --- | --- |
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| • | SMOE |
|---|---|
| • | Ontario Ministry of Environment |
| --- | --- |
Environment and Climate Change Canada (federal) is also a major regulatory agency that has a mandate involving specific pieces of federal regulations.
Uranium industry regulation
The government of Canada recognizes the special importance of the uranium industry to Canada’s national interest, and regulates the industry through legislation and regulations, and exerts additional control through government policy.
Federal legislation applies to any work or undertaking in Canada for the development, production, or use of nuclear energy or for the mining, production, refinement, conversion, enrichment, processing, reprocessing, possession, or use of a nuclear substance. Federal policy requires that any property or plant used for any of these purposes must be legally and beneficially owned by a company incorporated in Canada.
Mine ownership restrictions
The federal government has instituted a policy that restricts ownership of Canadian uranium mining properties to:
| • | a minimum of 51% ownership by residents |
|---|---|
| • | a basic maximum limit of 49% ownership by non-residents of uranium<br>properties at the first stage of production |
| --- | --- |
The government may grant exceptions. For example, resident ownership may be less than 51% if the property is Canadian controlled. Exceptions will only be granted in cases where it is demonstrated that Canadian partners cannot be found, and it must receive Cabinet approval.
The government issued a letter to the Canadian uranium industry on December 23, 1987, outlining the details of this ownership policy. On March 3, 2010, the government announced its intention to liberalize the foreign investment restrictions on Canada’s uranium mining sector to “ensure that unnecessary regulation does not inhibit the growth of Canada’s uranium mining industry by unduly restricting foreign investment”. However, after striking an expert panel to study the issue and soliciting feedback from various stakeholders, the federal government stated in October 2011 that it would not be changing the policy.
The Canada-EU Trade Agreement (CETA) was provisionally implemented in September 2017. The Non-resident Ownership Policy provisions for CETA countries are now in effect, which removes the requirement to seek a Canadian partner to hold the majority interest in a Canadian uranium mining property before applying for an exemption. An EU company is still required to apply for an exemption to hold a majority interest in a Canadian uranium mining property and the proposal will be evaluated by the government on its merits.
Cameco ownership restriction
We are subject to ownership restrictions under the Eldorado Nuclear Limited Reorganization and Divestiture Act, which restricts the issue, transfer, and ownership, including joint ownership, of Cameco shares to prevent both residents and non-residents of Canada from owning or controlling more than a certain percentage of shares. See page 128 for more information.
Industry governance
The Nuclear Safety and ControlAct (NSCA) is the primary federal legislation governing the control of the mining, extraction, processing, use and export of uranium in Canada. It authorizes the CNSC to make regulations governing all aspects of the development and application of nuclear energy, including uranium mining, milling, conversion, fuel fabrication and transportation. It grants the CNSC licensing authority. A person may only possess or dispose of nuclear substances and build, operate, and decommission its nuclear facilities according to the terms and conditions of a CNSC licence. Licensees must satisfy specific conditions of the licence to maintain the right to operate their nuclear facilities.
The NSCA emphasizes the importance of environmental as well as health and safety matters and requires licence applicants and licensees to make adequate provisions for protection of the environment and for the health and safety of workers and the public.
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Regulations made under the NSCA include those dealing with the specific licence requirements of facilities, radiation protection, physical security for all nuclear facilities and the transport of radioactive materials. The CNSC has also issued regulatory documents to assist licensees in complying with regulatory requirements, such as decommissioning, emergency planning, and optimizing radiation protection measures.
All of our Canadian operations are governed primarily by licences granted by the CNSC and are subject to all federal statutes and regulations that apply to us, and all the laws that generally apply in the province where the operation is located, unless there is a conflict with the terms and conditions of the licence or the federal laws that apply to us.
Uranium export
We must secure export licences and export permits from the CNSC and Global Affairs Canada to export our uranium. These arrangements are governed by the bi-lateral and multi-lateral agreements that are in place between governments.
Land tenure
Most of our uranium reserves and resources are in the province of Saskatchewan:
| • | a mineral claim from the province gives us the right to explore for minerals (other government approvals<br>are required to carry out surface exploration) |
|---|---|
| • | a crown lease with the province gives us the right to mine the minerals on the property<br> |
| --- | --- |
| • | a surface lease with the province gives us the right to use the land for surface facilities and mine<br>shafts while mining and reclaiming the land |
| --- | --- |
A mineral claim has a one-year term, with the right to renew for successive one-year periods. Generally, the holder must spend a certain amount on exploration to keep the mineral claim in good standing. If we spend more than the amount required, then the extra amount can be applied to future years.
A holder of a mineral claim in good standing has the right to convert it into a crown lease. A crown lease is for 10 years, with a right to renew for additional 10-year terms. The lessee must spend a certain amount on work during each year of the crown lease. The lease cannot be terminated unless the lessee defaults on any terms of the lease, or under any provisions of The Crown Minerals Act (Saskatchewan) or regulations under it, including any prescribed environmental concerns. Crown leases can be amended unilaterally by the lessor by an amendment to TheCrown Minerals Act (Saskatchewan) or The Mineral Tenure Registry Regulations (Saskatchewan).
A surface lease can be for up to 33 years in accordance with The Crown Resource Land Regulations, 2019 (Saskatchewan) made pursuant to The Provincial Lands Act, 2016 (Saskatchewan), as necessary for operating the mine and reclaiming the land. The province also uses surface leases to specify other requirements relating to environmental and radiation protection as well as socioeconomic objectives.
United States
Uranium industry regulation
In the US, uranium recovery is regulated by the NRC according to the Atomic Energy Act of 1954, as amended. Its primary function is to:
| • | ensure employees, the public and the environment are protected from radioactive materials |
|---|---|
| • | regulate most aspects of the uranium recovery process |
| --- | --- |
The NRC’s regulations for uranium recovery facilities are codified in Title 10 of the Code of Federal Regulations (10 CFR). It issues Domestic Source Material Licences under 10 CFR, Part 40. The National Environmental Policy Act governs the review of licence applications, which is implemented through 10 CFR, Part 51.
At Smith Ranch-Highland and Crow Butte, safety is regulated by the federal Occupational Safety and Health Administration.
Other governmental agencies are also involved in the regulation of the uranium recovery industry.
The NRC also regulates the export of uranium from the US and the transport of nuclear materials within the US. It does not review or approve specific sales contracts. It also grants export licences to ship uranium outside the US.
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Wyoming
The uranium recovery industry is also regulated by the WDEQ, the Land Quality Division (LQD) according to the Wyoming Environmental Quality Act (WEQA) and the Land Quality Division Non Coal Rules and Regulations under the WEQA. According to the state act, the WDEQ issues a permit to mine. The LQD administers the permit. As of September 30, 2018, the NRC has entered into an agreement with the state of Wyoming, transferring regulatory authority for licensing, rulemaking, inspection, and enforcement activities necessary to regulate uranium ISR mining. The WDEQ LQD Uranium Recovery Program (URP) has assumed this regulatory authority.
The state also administers a number of EPA programs under the Clean Air Act and the Clean Water Act. Some of the programs, like the Underground Injection Control Regulations, are incorporated in the Land Quality Division Non-Coal Rules and Regulations. Wyoming currently requires wellfield decommissioning to the standard of pre-mining use.
Nebraska
The uranium recovery industry is regulated by the NRC, and the Nebraska Department of Environmental Quality according to the Nebraska EnvironmentalProtection Act. The Nebraska Department of Environmental Quality issues a permit to mine. The state requires wellfield groundwater be restored to the class of use water standard.
Land tenure
Our uranium resources in the US are held by subsidiaries located in Wyoming and Nebraska. The right to mine or develop minerals is acquired either by leases from the owners (private parties or the state) or mining claims located on property owned by the US federal government. Our subsidiaries acquire surface leases that allow them to conduct operations.
Kazakhstan
See Kazakhstan government and legislation starting on page 62.
Complying with environmental regulations
Our business is required to comply with laws and regulations that are designed to protect the environment and control the management of hazardous wastes and materials. Some laws and regulations focus on environmental issues in general, and others are specifically related to mining and the nuclear sector. They change often, with requirements increasing, and existing standards being applied more stringently. While this dynamic promotes continuous improvement, it can increase expenses and capital expenditures, or limit or delay our activities.
Government legislation and regulation in various jurisdictions establish standards for system performance, standards, objectives and guidelines for air and water quality emissions, and other design or operational requirements for the various SHEQ components of our operations and the mines that we plan to develop. In addition, we must complete an environmental assessment before we begin developing a new mine or make any significant change to our operations. Once we have permanently stopped mining and processing activities, we are required to decommission and reclaim the operating site to the satisfaction of the regulators, and we may be required to actively manage former mining properties for many years.
Canada
Not only is there ongoing regulatory oversight by the CNSC, the SMOE, the Ontario Ministry of the Environment, and Environment and Climate Change Canada, but there is also public scrutiny of the impact our operations have on the environment.
The CNSC, an independent regulatory authority established by the federal government under the NSCA, is our main federal regulator in Canada. In 2019, the federal government introduced the Impact Assessment Act along with changes to the Fisheries Act and introduced the Canadian Navigable WatersAct. The new assessment legislation broadens the scope of a federal assessment beyond strictly environment, and the Fisheries Act and the Canadian Navigable Waters Act introduced changes to the language that will take some time to fully understand as the government is still developing and issuing guidance and working out the impact of the revisions.
Plans to build new mines in Saskatchewan are subject to the provincial environmental assessment process. In certain cases, a review panel may be appointed, and public hearings held.
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Over the past few years, CNSC audits of our operations have focused on the following SHEQ programs:
| • radiation protection<br><br><br><br> <br>• environmental<br>monitoring<br> <br><br> <br>• fire<br>protection<br> <br><br><br><br>• operational quality assurance<br><br><br><br> <br>• organization and<br>management systems effectiveness | • transportation systems<br><br><br><br> <br>• geotechnical<br>monitoring<br> <br><br><br><br>• training<br> <br><br><br><br>• ventilation systems<br><br><br><br> <br>• waste<br>management |
|---|
Improving our environmental performance is challenging and we have focused on maintaining our excellent water quality while maintaining production at our facilities or while they are in care and maintenance.
Efforts like these often require additional environmental studies near the operations, and we will continue to undertake these as required.
It can take a significant amount of time for regulators to make requested changes to a licence or grant a requested approval because the activity may require an approval with an extensive review of supporting technical data, management programs and procedures. We are improving the quality of our proposals and submissions and have introduced a number of programs to ensure we continue to comply with regulatory requirements, but this has also increased our capital expenditures and our operating costs.
As our SHEQ management system matures, regulators continue to review our programs and recommend ways to improve our SHEQ performance. These recommendations are generally procedural and do not involve large capital costs, although systems applications can be significant and result in higher operating costs.
Federal requirements stemming from the Species at Risk Act are introducing significant uncertainty into the management of activities in northern Saskatchewan. One specific example includes the amended national recovery strategy for woodland caribou, which contains strategic directions that have the potential to impact economic and social development in northern Saskatchewan. As a requirement of this document, the province of Saskatchewan is responsible for developing range plans that outline population and habitat protection measures for activities conducted in northern Saskatchewan. Mitigation requirements, and other measures, could have an impact on our Saskatchewan operations and advanced projects in northern Saskatchewan.
A number of government or governmental bodies have introduced or are contemplating regulatory changes in response to the potential impacts of climate change. While we have a relatively small carbon footprint, our Canadian facilities could experience higher annual operating costs due to changes in GHG pricing and regulations, such as carbon pricing, the Canadian Clean Fuel Standard, and/or other policy changes. As indicated above, we recognize that climate change, including shifts in temperature, precipitation and more frequent severe weather events could affect our operations in a range of possible ways. As part of our low-carbon transition planning, we completed a climate change scenario analysis to understand how projected long-term changing climate conditions could impact our employees, assets, and operations in northern Saskatchewan. We leveraged internal subject matter expertise with the assistance of a third-party expert to complete the assessment.
We believe that regulatory expectations of the CNSC and other federal and provincial regulators will continue to evolve, and lead to changes to both requirements and the regulatory framework. This will likely increase our costs.
United States
Our ISR operations in the US must meet federal, state, and local regulations governing air emissions, water discharges, handling and disposal of hazardous materials and site reclamation, among other things.
Mining activities must meet comprehensive environmental regulations from the NRC, Bureau of Land Management, Environmental Protection Agency (EPA) and state environmental agencies. The process of obtaining mine permits and licences generally takes several years, and involves environmental assessment reports, public hearings, and comments. We have the permits and licences required for our US ISR Operations for 2023.
The ISR mining method at our US ISR Operations involves extracting uranium from underground non-potable aquifers by dissolving the uranium with a carbonate-based water solution and pumping it to a processing facility on the surface. After mining is complete, ISR wellfields must be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of use water standard. Restoration of Crow Butte wellfields is regulated
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by the Nebraska Department of Environmental Quality and the NRC. Restoration of Smith Ranch-Highland wellfields is regulated by the WDEQ.
See page 97 for the status of wellfield restoration and regulatory approvals.
Kazakhstan
In its resource use contract with the Kazakhstan government, JV Inkai committed to conducting its operations according to good international mining practices. It must comply with the environmental requirements of Kazakhstan legislation and regulations, and, as an industrial company, it must also reduce, control, or eliminate various kinds of pollution and protect natural resources. JV Inkai is required to submit annual reports on pollution levels to the Kazakhstan environmental, tax and statistics authorities. The authorities conduct tests to validate JV Inkai’s results.
Environmental protection legislation in Kazakhstan has evolved rapidly, especially in recent years. As the subsoil use sector has evolved, there has been a trend towards greater regulation, heightened enforcement, and greater liability for non-compliance. The most significant development was the adoption of the Ecological Code in 2007. This code replaced the three main laws related to environmental protection. Kazakhstan enacted a new ecological code, which took effect July 1, 2021 (2021 Ecological Code).
JV Inkai is required to comply with environmental requirements during all stages of the project and must develop an environmental impact assessment for examination by a state environmental expert before making any legal, organizational, or economic decisions that could have an effect on the environment and public health.
Under the 2007 Ecological Code, JV Inkai required an environmental permit to operate. The permit certifies the holder’s right to discharge emissions into the environment, provided that it complies with the requirements of the permit and that code. JV Inkai obtained a permit for environmental emissions and discharges for the operation under the 2007 Ecological Code. This permit is no longer in effect. JV Inkai has obtained a permit under the 2021 Ecological Code.
Facilities, based on their environmental impact, are divided into 4 categories both under the 2007 Ecological Code and the 2021 Ecological Code. In August 2021, JV Inkai was assigned category 1 and obtained an emissions permit under the 2021 EcologicalCode, valid until the end of 2030. Generally, this new permit is similar to an emissions permit issued under the 2007 Ecological Code. After expiry of this emissions permit at the end of 2030, JV Inkai will be required to have a comprehensive environmental permit.
A comprehensive environmental permit includes standards for emissions, waste accumulation, and water use. An operator of a category I facility must introduce and invest in best available techniques. The best available techniques are technologies, ways, and methods that are used during an activity and are effective, advanced, and practically applicable. Operators of category I facilities who operate under this permit and invest in best available techniques are exempt from payments for emissions into the environment.
JV Inkai also holds the required permits under the Water Code.
Government authorities and the courts enforce compliance with these permits, and violations can result in the imposition of administrative, civil or criminal penalties, the suspension or stopping of operations, orders to pay compensation, orders to remedy the effects of violations and orders to take preventive steps against possible future violations. In certain situations, the issuing authority may suspend or revoke the permits. With the adoption of the 2021 Ecological Code, the level of administrative penalties has generally been increased.
The ISR mining method at Inkai uses an acid in the mining solution to extract uranium from underground non potable aquifers. The injection and recovery system is engineered to prevent the mining solution from migrating to the aquifer above the orebody, which has water with higher purity.
JV Inkai is not required to actively restore groundwater post-mining. After a number of decommissioning steps are taken, natural attenuation of the residual acid in the mined-out horizon, as a passive form of groundwater restoration, has been accepted. Attenuation is a combination of neutralization of the groundwater residual acid content by interaction with the host rock minerals and other chemical reactions which immobilize residual groundwater contaminants in the mined-out subsoil horizon. This approach is considered acceptable because it results in water quality similar to the pre-mining baseline status.
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JV Inkai has environmental insurance, as required by the 2007 Ecological Code, the 2021Ecological Code, and the resource use contract.
Taxes and Royalties
Transfer pricing dispute
Background
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.
For the years 2003 to 2014, CRA shifted Cameco Europe Limited’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. In addition, for 2014 to 2016, CRA has advanced an alternate reassessing position, see Reassessments, remittance and next steps below for more information.
In September 2018, the Tax Court of Canada (Tax Court) ruled that our marketing and trading structure involving foreign subsidiaries, as well as the related transfer pricing methodology used for certain intercompany uranium sales and purchasing agreements, were in full compliance with Canadian law for the tax years in question (2003, 2005 and 2006). On June 26, 2020, the Federal Court of Appeal (Court of Appeal) upheld the Tax Court’s decision.
On February 18, 2021, the Supreme Court of Canada (Supreme Court) dismissed CRA’s application for leave to appeal the June 26, 2020 decision of the Court of Appeal. The dismissal means that the dispute for the 2003, 2005 and 2006 tax years is fully and finally resolved in our favour. Although not technically binding, there is nothing in the reasoning of the lower court decisions that should result in a different outcome for the 2007 through 2014 tax years, which were reassessed on the same basis.
Refund and cost award
The Minister of National Revenue issued new reassessments for the 2003 through 2006 tax years in accordance with the decision and in July 2021, refunded the tax paid for those years. Pursuant to a cost award from the courts, we are expecting a payment of approximately $13 million for disbursements which is in addition to the $10 million we received from CRA in April 2021 as reimbursement for legal fees.
Reassessments, remittances and next steps
The Canadian income tax rules include provisions that generally 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. Following the Supreme Court’s dismissal of CRA’s application for leave to appeal, we wrote to CRA requesting reversal of CRA’s transfer pricing adjustments for 2007 through 2013 and the return the $780 million in cash and letters of credit we have paid or provided for those years. Given the strength of the court decisions received, our request was made on the basis that the Tax Court would reject any attempt by CRA to defend its reassessments for the 2007 through 2013 tax years applying the same or similar positions already denied for previous years.
On March 27, 2023, we announced that CRA issued revised reassessments for the 2007 through 2013 tax years that will result in a refund of approximately $300 million of the $780 million in cash and letters of credit being held by CRA. The refund will consist of $89 million in cash and $211 million in letters of credit. The timing of the refund is yet to be determined.
The series of court decisions that were completely and unequivocally in our favour for the 2003, 2005 and 2006 tax years, determined that the income earned by our foreign subsidiary from the sale of non-Canadian produced uranium was not taxable in Canada. In accordance with these decisions, CRA issued reassessments reducing the proposed transfer pricing adjustment from $5.12 billion to $3.25 billion, resulting in a reduction of $1.87 billion in income taxable in Canada compared to the previous reassessments issued to us by CRA for the 2007 through 2013 tax years.
Notwithstanding the pending refund of approximately $300 million in cash and security due to the reduced reassessment amounts for 2007 through 2013, our broader tax dispute with CRA remains ongoing. CRA continues to hold $480 million ($206 million in cash and $274 million in letters of credit) that Cameco has remitted or secured to date.
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The remaining transfer pricing adjustment of $3.25 billion for the 2007 to 2013 tax years relates to the sale of Canadian-produced uranium by our foreign subsidiary. Cameco maintains that the clear and decisive court decisions described above apply, and that CRA should fully reverse the remaining transfer pricing adjustments for these years and return the cash and security being held.
In October 2021, due to a lack of significant progress on our points of contention, we filed a notice of appeal with the Tax Court for the years 2007 through 2013. We have asked the Tax Court to order the complete reversal of CRA’s transfer pricing adjustment for those years and the return of the remainder of our cash and letters of credit being held, with costs.
In 2020, CRA advanced an alternate reassessing position for the 2014 tax year in the event the basis for its original reassessment, noted above, is unsuccessful. Subsequent to this, in 2021, we received a reassessment for the 2015 tax year and in late 2022, we received a reassessment for the 2016 tax year, both using this alternative reassessing position. The new basis of reassessment is inconsistent with the methodology CRA has pursued for prior years and we are disputing it separately. Our view is that this alternate methodology will not result in a materially different outcome from our 2014 to 2016 filing positions. On October 12, 2022, we filed an appeal with the Tax Court for the years 2014 and 2015, and recently filed a notice of objection for 2016. At the time of these reassessments, CRA did not require additional security for the tax debts they considered owing for 2014 and 2015. We have requested the same treatment with respect to the 2016 reassessment.
We will not be in a position to determine the definitive outcome of this dispute for any tax year other than 2003 through 2006 until such time as all reassessments have been issued advancing CRA’s arguments and final resolution is reached for that tax year. CRA may also advance alternative reassessment methodologies for years other than 2003 through 2006, such as the alternative reassessing position advanced for 2014 through 2016.
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 1 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.
| Assumptions<br> <br><br><br><br>• our entitlement and ability to receive the expected refunds and payments from CRA<br><br><br><br> <br>• the courts will reach<br>consistent decisions for subsequent tax years that are based on similar positions and arguments<br> <br><br><br><br>• CRA will not successfully advance different positions and arguments that may lead to a<br>different outcome for other tax years | Material risks that could cause actual results to differ materially<br><br><br><br> <br>• we will not receive<br>the expected refunds and payments from CRA<br> <br><br><br><br>• the possibility the courts may accept the same, similar or different positions and<br>arguments advanced by CRA to reach decisions that are adverse to us for other tax years<br> <br><br><br><br>• the possibility that we will not be successful in eliminating all double taxation<br><br><br><br> <br>• the possibility that<br>CRA does not agree that the court decisions for the years that have been resolved in Cameco’s favour should apply to subsequent tax years<br> <br><br><br><br>• the possibility CRA will not return all or substantially all of the cash and security that<br>has been paid or otherwise secured by Cameco in a timely manner, or at all<br> <br><br><br><br>• the possibility of a materially different outcome in disputes for other tax years<br><br><br><br> <br>• an unfavourable<br>determination of the officer of the Tax Court of the amount of our disbursements award |
|---|
Canadian royalties
We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan.
Two types of royalties are paid:
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| • | Basic royalty: This royalty is calculated as 5% of gross sales of uranium, less the Saskatchewan resource<br>credit of 0.75%. |
|---|---|
| • | Profit royalty: A 10% royalty is charged on profit up to and including $26.268/kg U3O8 ($11.91/lb) and a 15% royalty is charged on profit in excess of $26.268/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.<br> |
| --- | --- |
As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.
Canadian income taxes
We are subject to federal income tax and provincial taxes in Saskatchewan and Ontario. Current income tax expense for 2022 was $2.26 million.
Our Ontario fuel services operations are eligible for a manufacturing and processing tax credit.
The Organization for Economic Co-operation and Development has proposed the introduction of rules that would impose a global minimum tax rate of 15%. The European Union has unanimously agreed to implement these rules and impose them into each country’s national law by the end of 2023, and we expect Canada to follow suit. If these tax laws are enacted or substantively enacted in any jurisdiction in which we operate, we may be subject to a minimum rate of 15% in that jurisdiction.
US taxes
Our subsidiaries in Wyoming and Nebraska pay severance taxes, property taxes and Ad Valorem taxes in those states. They incurred $0.77 million (US) in taxes in 2022.
Our US subsidiaries are subject to US federal and state income tax.
Kazakhstan taxes
Stability of the tax regime envisaged by a number of resource use contracts, including the resource use contract, was abolished with the entry into legal force of the 2009 Tax Code in 2009. Amendment No. 2 to the resource use contract, signed in 2009, by making applicable the 2009 Tax Code, eliminated the tax stabilization provision of the resource use contract.
A new tax code, effective January 1, 2018 (the 2018 Tax Code), provides that subsoil users pay all taxes and payments provided in the tax legislation effective as of the date of occurrence of tax obligations. Although under the 2018 Tax Code the main principles of subsoil users’ taxation remain the same (for example, the rate of corporate income tax, 20%), there were several important changes relevant to special taxes and payments of subsoil users as briefly described below:
| • | Starting January 1, 2023, significant changes were introduced in relation to computation of the mineral<br>extraction tax on uranium, including changes to the tax base and the tax rate. It is expected that the amount of tax may increase due to such changes. |
|---|---|
| • | The exemption of dividends payable by a subsoil user to a foreign shareholder from income tax withholding at the<br>source of payment was abolished starting January 1, 2023. Under the 2018 Tax Code the standard tax rate on dividends is 15%. A reduced rate of 10% may be applied subject to compliance with certain conditions (similar to those that<br>were provided in respect of the prior dividend exemption). Potentially, dividends that will be paid to us by JV Inkai may qualify for this reduced rate under the 2018 Tax Code. In addition, such dividends may qualify for reduced 5%<br>withholding tax on dividends under the Canada-Kazakhstan double taxation treaty (subject to compliance with certain requirements). |
| --- | --- |
| • | The Excess Profits Tax has been abolished with respect to several categories of subsoil use contracts,<br>including, “contracts for exploration and (or) production of solid minerals, subsoil water and (or) therapeutic muds provided that such contracts do not envisage extraction of other categories of minerals.” Based on the subsoil<br>code, we believe that for the purposes of the 2018 Tax Code, the term solid minerals includes uranium. However, there is a risk that the tax authorities may hold the opposite view. |
| --- | --- |
| • | The commercial discovery bonus has been abolished. |
| --- | --- |
| • | The rates of payment for the use of land by subsoil users is now expressly provided for in the 2018 TaxCode. |
| --- | --- |
JV Inkai’s costs could be impacted by potential changes to the 2018 Tax Code and by possible increased financial contributions to social and other state causes, although these risks cannot be quantified or estimated at this time.
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Nuclear waste management and decommissioning
Once we have permanently stopped mining and processing activities, we are required to decommission the operating sites. This includes reclaiming all waste rock, TMF and other areas of the site affected by our activities to the satisfaction of regulatory authorities.
Estimating decommissioning andreclamation costs
We develop conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. We also submit them to regulators to determine the amount of financial assurance we must provide to secure our decommissioning obligations. Our plans include reclamation techniques that we believe generate reasonable environmental and radiological performance. Regulators give “conceptual approval” to a decommissioning plan if they believe the concept is reasonable.
We started conducting reviews of our conceptual decommissioning plans for all Canadian sites in 1996. We typically review them every five years, or when we amend or renew an operating licence. We review our cost estimates for both accounting purposes and licence applications. For our US sites, they are reviewed annually. A preliminary decommissioning plan has been established for Inkai. The plan is updated every five years or as significant changes take place, which would affect the decommissioning estimate.
As properties approach or go into decommissioning, regulators review the detailed decommissioning plans. This can result in additional regulatory process, requirements, costs, and financial assurances.
At the end of 2022, our estimate of total decommissioning and reclamation costs was $1.36 billion. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $1.06 billion at the end of 2022 (the present value of the $1.36 billion). Regulatory approval is required prior to beginning decommissioning. Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, and none of our assets have approval for decommissioning, our expected costs for decommissioning and reclamation for the next five years are not material.
We provide financial assurances for decommissioning and reclamation such as letters of credit or surety bonds to regulatory authorities, as required. We had a total of about $1.04 billion in financial assurances supporting our reclamation liabilities at the end of 2022. All of our North American operations have financial assurance in place in connection with our approved preliminary plans for decommissioning of the sites.
Please also see note 16 to our 2022 financial statements for our estimate of decommissioning and reclamation costs and related financial assurances.
Canada
Decommissioning estimates
| (100% basis) | ||
|---|---|---|
| McArthur River | $ | 42 million |
| Rabbit Lake | $ | 213 million |
| Key Lake | $ | 223 million |
| Cigar Lake | $ | 62 million |
Preliminary decommissioning plans for all Saskatchewan mining operations were submitted in 2017 and 2018 as part of the regular five-year update schedule. Prior to revising the letters of credit, approval of the updated plans is required from the province and CNSC staff as well as formal approval from the CNSC through a Commission proceeding. All Saskatchewan mining operations have received the necessary approvals.
In 2022, as part of the required five-year update schedule, we submitted revised preliminary decommissioning estimates for all Saskatchewan mining operations, which are currently being reviewed the province and CNSC staff.
The reclamation and remediation activities associated with waste rock and tailings from processing Cigar Lake ore and uranium solution are covered in the plans and cost estimates for the facility that will be processing it.
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Decommissioning estimates
| (100% basis) | ||
|---|---|---|
| Port Hope | $ | 129 million |
| Blind River | $ | 58 million |
| CFM | $ | 11 million |
We renewed our licence for Port Hope in 2017. As part of that process, an update to the Port Hope Conversion Facility preliminary decommissioning plan was finalized and accepted in February 2017. The letter of credit was updated in March 2017 and reflects the current decommissioning estimate. In 2022, as part of the required five-year update schedule, we submitted a revised preliminary decommissioning estimate for PHCF, which is currently being reviewed by CNSC staff. We renewed our licence for Blind River in 2022. As part of the process, an update to the Blind River preliminary decommissioning plan was finalized and accepted in February 2022. An update to the CFM preliminary decommissioning plan was also finalized and accepted in February 2022.
Recycling uranium byproducts
We have arrangements with two facilities for processing certain uranium-bearing by-products from Blind River and Port Hope. An agreement has been in place with the White Mesa mill in Blanding, Utah for a number of years. Recycled by-product material was being processed at Key Lake until the decision was made in 2018 to suspend production and place the mill and the McArthur River mine in care and maintenance.
United States
After mining has been completed, an ISR wellfield has to be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of water standard.
For wellfield restoration to be complete, regulatory approval is required. It is difficult for us to estimate the timing for wellfield restoration due to the uncertainty in timing for receiving final regulatory approval.
Crow Butte
Restoration of Crow Butte wellfields is regulated by the Nebraska Department of Environmental Quality and the Nuclear Regulatory Commission (NRC). There are five wellfields being restored at Crow Butte. The groundwater at mine unit #1 has been restored to pre mining quality standards, all wells are plugged, and the piping removed.
Our estimated cost of decommissioning the property is $56 million (US). We have provided the state of Nebraska with $56 million (US) in financial assurances as security for decommissioning the property.
Smith Ranch-Highland
Restoration of Smith Ranch-Highland wellfields is regulated by the Wyoming Department of Environmental Quality (WDEQ). In 2018, the NRC transferred to the state of Wyoming its authority to regulate uranium ISR mining in the state. There are nine wellfields being restored at Smith Ranch-Highland, one wellfield in stability, and two wellfields (mine unit A and mine unit B) that have been fully restored.
Restoration of mine unit B was approved by the WDEQ in 2008, while NRC approval has not yet been attained. An Alternate Concentration Limit (ACL) request was submitted to the NRC in May 2013. The NRC subsequently requested additional information, and that additional sampling be conducted.
Our estimated cost of decommissioning the property is $219 million (US), including North Butte. We have provided the state of Wyoming with $218 million (US) in financial assurances as security for decommissioning the property.
Kazakhstan
JV Inkai’s decommissioning obligations are defined by the resource use contract and the subsoil code. JV Inkai is required to maintain a fund, which is capped at $500,000 (US), as security for meeting its decommissioning obligations. Under the resource use contract, JV Inkai must submit a plan for decommissioning the property to the government six months before mining activities are complete.
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JV Inkai has developed a preliminary decommissioning plan to estimate total decommissioning costs and updates the plan when there is a significant change at the operation that could affect decommissioning estimates. The preliminary decommissioning estimate is $30 million (US) and is subject to ongoing review.
Groundwater is not actively restored post-mining in Kazakhstan. See page 92 for additional details.
Risks that can affect our business
The nature of our business means we face many kinds of risks and hazards – some that relate to the nuclear energy industry in general, and others that apply to specific properties, operations, planned operations, or planned investments. These risks could have a significant impact on our business, earnings, cash flows, financial condition, results of operations or prospects, which may result in a significant decrease in the market price of our common shares. In addition to considering the other information in this AIF, you should consider carefully the risks discussed in this section in deciding whether to invest in securities of Cameco.
The following section describes the risks that are most material to our business. This is not, however, a complete list of the potential risks we face – there may be others we are not aware of, or risks we feel are not material today that could become material in the future. Our risk policy and process involves a broad, systematic approach to identifying, assessing, reporting and managing the significant risks we face in our business and operations. However, there is no assurance that we will be successful in preventing the harm that any of these risks could cause.
Please also see the risk discussion in our 2022 MD&A.
Types of risk
| • Operational<br><br><br><br> <br>• Financial<br><br><br><br> <br>• Governance and<br>compliance | • Environmental<br><br><br><br> <br>• Social<br><br><br><br><br><br>• Strategic |
|---|
1 – Operational risks
General operating risks and hazards
We are subject to a number of operational risks and hazards, many of which are beyond our control.
These risks and hazards include:
| • catastrophic accidents resulting in large-scale releases of hazardous<br>chemicals, or a tailings facility failure, which could pose a significant risk to the environment, and to employee and public safety<br> <br><br><br><br>• environmental incidents (including hazardous emissions from our refinery and conversion<br>facilities, such as a release of UF6 or a leak of anhydrous hydrogen fluoride used in the UF6 conversion process)<br><br><br><br> <br>• industrial safety<br>accidents<br> <br><br><br><br>• equipment failures<br> <br><br><br><br>• fires<br> <br><br><br><br>• transportation incidents, which may involve radioactive or other hazardous materials<br><br><br><br> <br>• transportation and<br>delivery disruptions<br> <br><br><br><br>• labour shortages, disputes or strikes<br><br><br><br> <br>• availability of<br>personnel with the necessary skills and experience | • cyberattacks<br><br><br><br> <br>• joint venture dispute<br>or litigation<br> <br><br><br><br>• non-compliance with legal requirements, including<br>exceedances of applicable air or water limits or requirements<br> <br><br><br><br>• inability to obtain and renew the licences and other approvals needed to operate, restart,<br>and to increase production at our mines, mills, and processing facilities, or to develop new mines<br> <br><br><br><br>• workforce health and safety or increased regulatory burdens resulting from the COVID 19<br>pandemic or other causes<br> <br><br><br><br>• uncertain impact of changing regulations or policy leading to higher annual operating<br>costs, including GHG pricing and regulations (e.g., carbon pricing, the Canadian Clean Fuel Standard)<br> <br><br><br><br>• blockades or other acts of social or political activism<br><br><br><br> <br>• natural phenomena,<br>such as forest fires, floods, and earthquakes as well as shifts in temperature, |
|---|
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| • cost increases for labour, contracted or purchased materials, supplies<br>and services<br> <br><br><br><br>• shortages of, or interruptions in the supply of, required equipment, materials, and<br>supplies (including anhydrous hydrofluoric acid at our conversion facilities)<br> <br><br><br><br>• interruptions in the supply of electricity, water, and other utilities or other<br>infrastructure<br> <br><br><br><br>• inability of our innovation initiatives to achieve the expected cost saving and operational<br>flexibility objectives | precipitation, and the impact of more frequent severe weather conditions on our operations as a result of climate<br>change<br> <br><br> <br>• outbreak of<br>illness (such as a pandemic like COVID-19)<br> <br><br><br><br>• unusual, unexpected or adverse mining or geological conditions<br><br><br><br> <br>• underground water<br>inflows at our mining operations<br> <br><br><br><br>• ground movement or cave-ins at our mining<br>operations<br> <br><br><br><br>• subsurface contamination from current or legacy operations |
|---|
There is no assurance that any of the above risks will not result in:
| • damage to or destruction of our properties and facilities located on<br>these properties<br> <br><br><br><br>• personal injury or death<br><br><br><br> <br>• environmental<br>damage<br> <br><br> <br>• delays in,<br>or interruptions of, our exploration or development activities or transportation and delivery of our products | • delays in, interruptions of, or decrease in production at our<br>operations<br> <br><br> <br>• costs,<br>expenses, or monetary losses<br> <br><br><br><br>• legal liability<br> <br><br><br><br>• adverse government or regulatory action |
|---|
Any of these events could result in one or more of our operations becoming unprofitable, cause us not to receive an adequate return on invested capital, or have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Insurance coverage
We buy insurance to cover losses or liabilities arising from some of the operating risks and hazards listed above, as well as other business risks. We do not have dedicated cyber insurance coverage and we do not buy property insurance for our Rabbit Lake operation.
We believe we have a reasonable amount of coverage for the risks we choose to insure against. There is no assurance, however, that this coverage will be adequate, that it will continue to be available, that premiums will be economically feasible, or that we will maintain this coverage. Like other nuclear energy and mining companies, we do not have insurance coverage for certain environmental losses or liabilities and other risks, either because it is not available, or because it cannot be purchased at a reasonable cost. Insurance availability at any time is driven by several factors and availability may be impacted by the announced intention of certain providers to restrict underwriting of certain industries, assets or projects. We may also be required to increase the amount of our insurance coverage due to changes in the regulation of the nuclear industry.
We may suffer material losses from uninsurable or uninsured risks or insufficient insurance coverage, which could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Flooding at McArthur River and Cigar Lake
The sandstone that overlays the McArthur River and Cigar Lake deposits and basement rock is water-bearing with significant pressure at mining depths. This high-pressure water source is isolated from active development and production areas in order to reduce the inherent risk of an inflow. McArthur River relies on pressure grouting and ground freezing, and sufficient pumping, water treatment and above ground storage capacity to mitigate the risks of the high-pressure ground water. Cigar Lake relies on these same controls except for pressure grouting. These steps reduce, but do not fully eliminate, the risk of water inflows.
A water inflow could have a material and adverse effect on us, including:
| • | significant delays or interruptions in production or lower production |
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| • | significant delays or interruptions in mine development |
|---|---|
| • | loss of mineral reserves |
| --- | --- |
| • | a material increase in capital or operating costs |
| --- | --- |
| • | erosion of stakeholder support, including governments, communities and shareholders |
| --- | --- |
It could also have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects. The degree of impact depends on the magnitude, location and timing of the flood or water inflow. Floods and water inflows are generally not insurable.
McArthur River and Cigar Lake have had water inflows. There is no guarantee that there will not be water inflows at McArthur River or Cigar Lake in the future.
McArthurRiver
Production was suspended for three months in 2003 due to a water inflow event that occurred as the result of a ground failure during tunnel development. This resulted in flooding of portions of the mine and caused a major setback in the development advancement of a new mining zone. In 2008, we also had a small water inflow event that did not impact production but caused significant development delay.
Cigar Lake
We have had three water inflows at Cigar Lake since 2006 (please see page 48 for details).
These water inflows caused:
| • | a significant delay in development and production at the property |
|---|---|
| • | a significant increase in capital costs |
| --- | --- |
| • | the need to notify many of our customers of the interruption in planned uranium supply |
| --- | --- |
Technical challenges at Cigar Lake and McArthur River
The unique nature of the deposits at Cigar Lake and McArthur River poses many technical challenges, including but not limited to: high-pressure ground water management, unplanned water inflows, weak and altered ground conditions, unplanned ground failures, schedule uncertainty of development and freeze times of new mine zones, radiation protection, ore-handling and transport controls, water treatment performance and other mining-related challenges such as variable dilution and recovery values.
The areas being mined at Cigar Lake must meet specific ground freezing requirements before we begin jet boring. We have encountered longer than anticipated freeze durations due to inherent variability of the underlying geology across the deposit.
The Cigar Lake orebody contains elements of concern with respect to the water quality and the receiving environment. The distribution of elements such as arsenic, molybdenum, selenium and others is non-uniform throughout the orebody, and this can present challenges in attaining and maintaining the required effluent concentrations. There have been ongoing efforts to optimize the current water treatment process and water handling systems to ensure acceptable environmental performance, which is expected to avoid the need for additional capital upgrades and potential deferral of production.
Metallurgical test work has been used to design the McClean Lake mill circuits and associated modifications relevant to Cigar Lake ore. Samples used for metallurgical test work may not be representative of the deposit as a whole. There is a risk that elevated arsenic concentration in the mill feed may result in increased leaching circuit solution temperatures, potentially causing an increase in costs and reducing production.
If any of these technical challenges are not managed, it could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
McArthur River mine and Key Lake mill ramp up
In 2018, production was suspended. In November 2022, the McArthur River mine and Key Lake mill resumed production.
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With the extended period of time the assets were on care and maintenance, the operational changes made, and commissioning issues worked through at the mill, which caused delays to the production schedule in 2022, there is increased uncertainty regarding the timing of a successful ramp up to planned production and the associated costs. In addition, inflation, the availability of personnel with the necessary skills and experience, and the potential impact of supply chain challenges on the availability of materials and reagents carry with them the risks of not achieving our production plans, production delays and increased costs.
Information technology systems
We have become increasingly dependent on the availability and integrity of our electronic information and the reliability of our information technology systems and infrastructure. We rely on our information technology to process, transmit and store electronic information, including information we use to safely operate our assets. Our information technology systems are subject to disruption, damage, or failure from a variety of sources, including without limitation, security breaches, cyber-attacks, computer viruses, malicious software, natural disasters or defects in hardware or software systems.
Cyber attackers may use a range of techniques, from manipulating people to using sophisticated malicious software and hardware on a single or distributed basis. Often, advanced cyber attackers use a combination of techniques in their attempt to evade safeguards and delay discovery of a cyber-attack. We take measures to secure our infrastructure against potential cyber-attacks that may damage our infrastructure, systems, and data. We have implemented a defense in depth security program to secure and protect our information and business operations including formalizing and implementing an information security policy, user awareness training, and introducing system security configuration standards and access control measures. As technologies evolve and cyber-attacks become more sophisticated, we may incur significant costs to upgrade or enhance our security measures to mitigate potential harm.
We do not have dedicated cyber insurance coverage. However, to reduce the risk of successful cyber-attacks and to reduce the impact of any successful cyber-attacks, we have implemented several layers of perimeter and endpoint security defense and response mechanisms, security event logging and monitoring of network activities, and developed a cyber incident response process.
Despite the measures put in place to protect our systems and data, there can be no assurance that these measures will be sufficient to protect against such cyber-attacks or mitigate against such risks, or if such cyber-attacks or risks occur, that they will be adequately addressed in a timely manner.
Such a breach could result in unauthorized access to proprietary, confidential or sensitive information, destruction or corruption of data, disruption or delay in our business activities, remediation costs that may include liability for stolen assets or information, repairing system damage or incentives offered to customers or suppliers in an effort to maintain business relationships after an attack, legal or regulatory consequences, and a negative effect on our reputation and customer confidence. Disruption of critical information technology services or breaches of information security could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Tailings management
Managing tailings is integral to mining. Cameco has four tailings management facilities (TMFs), two at the Key Lake mill and two at the Rabbit Lake operation (where the site is in a state of safe care and maintenance). Key Lake and Rabbit Lake each have one active in pit TMF and one inactive above ground TMF.
Our active tailings management facilities are in pit with no risk of dam failure. If a TMF failure, pit slope failure, regulatory, or other issues prevent us from maintaining the existing tailings management capacity at our Key Lake mill, or if these issues prevent Orano from maintaining or increasing tailing capacity at the McClean Lake mill, then uranium production could be constrained and this could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
A failure of the confining embankment for either of Cameco’s above ground TMFs (one at Key Lake, one at Rabbit Lake) may release stored water and tailings into the environment. This failure could result in environmental damage, increased costs, and regulatory action. Such an event could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
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We have designed and operated our tailings management facilities with the intent to achieve a safe state both during operations and post-decommissioning. Our conceptual decommissioning plans for our Canadian properties address decommissioning of our tailing management facilities. Among other things, the plans are based upon a conceptual design model of the decommissioned facility that seeks to limit the environmental impact in accordance with regulatory requirements. Although we seek to ensure closure design of the facility accomplishes that objective, due to the inherent uncertainty with modeling outcomes, we cannot guarantee that we will. As the facilities approach or go into decommissioning, this can result in additional requirements and costs. In addition, as the facilities are decommissioned, there is a possibility of increased loadings to the environment, resulting in environmental damage, increased costs and regulatory action among other things. The occurrence of one or more of these events could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Aging facilities
Our Blind River and Port Hope fuel services facilities and our milling facilities in northern Saskatchewan are aging. This exposes us to many risks, including the potential for higher maintenance and operating costs, the need for significant capital expenditures to upgrade and refurbish these facilities, the potential for decreases or delays in, or interruption of, production, and the potential for environmental damage.
These risks could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Ability to attract and retain a skilled and diverse workforce
The company’s ability to manage its operations efficiently and effectively including maintaining strong safety and environmental performance, is dependent on the efforts of the company’s employees and contractors, including our executive, and senior technical and operating personnel. Having a diverse and inclusive workplace is integral to the success of the company to bring new ideas, perspectives, experiences, and expertise to the company which can create a competitive advantage and enhance the support of the communities where we operate.
We compete with mining and other companies on a global basis to attract and retain workers at all levels with appropriate skills and experience necessary to operate our mines, fuel processing and manufacturing facilities and work at our corporate office. We may not always be able to fill positions on a timely basis. There is a limited pool of skilled people and competition is intense. We also experience employee turnover because of an aging workforce. From time to time, the mining or nuclear energy industry experiences a shortage of tradespeople and other skilled or experienced personnel globally, regionally, or locally. We have a comprehensive strategy to attract and retain high caliber people, including programs to increase inclusion and diversity in our workplace. Our goal is to create an inclusive work environment, with a workforce that is skilled, diverse and reflects the demographics where we operate. Despite our efforts, there is no assurance the company will be able to attract and retain a skilled and diverse workforce that is fully reflective of the communities closest to our operations. Failure to do so could adversely impact our measures of success, increase our recruiting and training costs and reduce the efficiency of our operations, and have an adverse effect on our earnings, cash flows, financial condition or results of operations.
Collective agreements
We have unionized employees and face the risk of strikes. On December 31, 2022, we had 2,424 employees (including employees of our subsidiaries). This includes 689 unionized employees at McArthur River, Key Lake, Port Hope, and at CFM’s facilities, who are members of four different locals of the United Steelworkers trade union.
| • | The collective agreement with the bargaining unit employees at our conversion facilities at Port Hope ends on<br>June 30, 2025. |
|---|---|
| • | The collective agreement with the bargaining unit employees at the McArthur River and Key Lake operations ended<br>on December 31, 2022. Negotiations for a new agreement have commenced. As in past negotiations work continues under the terms of the expired agreement. |
| --- | --- |
| • | The collective agreement with the bargaining unit employees at CFM ends on June 1, 2024. |
| --- | --- |
| • | Orano’s collective agreement with bargaining unit employees at the McClean Lake mill ends on May 31, 2025.<br> |
| --- | --- |
We cannot predict whether we or Orano will reach new collective agreements with these and other employees without a work stoppage or work interruptions while negotiations are underway.
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A lengthy work interruption could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.
Supplies and contractors
Supplies
We buy reagents and other production inputs and supplies from suppliers around the world. If there is a shortage of, or disruption in the delivery of, any of these supplies, including parts and equipment, or their costs rise significantly, it could limit or interrupt production or increase production costs. It could also have an adverse effect on our ability to carry out operations or have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations. We examine our entire supply chain as necessary to identify areas to diversify or add inventory where we may be vulnerable, but there is no assurance that we will be able to mitigate the risk. Disruptions to the supply chain worldwide due to the COVID-19 pandemic has increased the risk and the February 2022 Russian invasion of Ukraine further increased the risk. In 2021, planned production from our fuel services operations was impacted by hydrogen supply issues.
Presently, JV Inkai is experiencing wellfield development, procurement, and supply chain issues, including inflationary pressure on production materials and reagents, which are expected to continue and could pose a risk to JV Inkai’s 2023 production volume, impacting its costs and our purchases.
Contractors
In some cases, we rely on a single contractor or supplier to provide us with services and/or reagents or other production inputs and supplies. Relying on a single contractor or supplier is a security of supply risk because we may not receive quality service, timely service, or service that otherwise meets our needs. These risks could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Transportation
Due to the geographical location of many of our mines and operations, including Inkai, and our customers, we are highly dependent on third parties for the provision of transportation services, including road, air, and port services. We negotiate prices for the provision of these services in circumstances where we may not have viable alternatives to using specific providers. We require regulatory approvals to transport and export our products. Contractual disputes, demurrage charges and port capacity issues, regulatory issues, availability of transports and vessels, inclement weather or other factors can have a material adverse effect on our ability to transport materials and our products according to schedules and contractual commitments. These risks could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
The geopolitical situation continues to cause transportation risks for Inkai, which impacted our shipments of finished product from JV Inkai in 2022. We may experience delays in our expected deliveries for Inkai from 2022 and for 2023. To mitigate this risk, we have inventory, long-term purchase agreements and loan arrangements in place we can draw on. Depending on when we receive shipments of our share of Inkai’s production, our share of earnings from this equity-accounted investee and the timing of the receipt of our share of dividends from JV Inkai may be impacted.
Infrastructure
Mining, processing, development, and exploration can only be successful with adequate infrastructure. Reliable roads, bridges, power sources and water supply are important factors that affect capital and operating costs and the ability to produce and deliver products on a timely basis.
Our activities could be negatively affected if climate change, unusual weather, interference from communities, government or others, aging, sabotage, or other causes affect the quality or reliability of the infrastructure.
A lack of adequate infrastructure could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Permitting and licensing
All mining projects and processing facilities around the world require government approvals, licences, or permits, and operations and development projects in Canada, the US, Kazakhstan, and Australia are no exception. Depending on the
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location of the project, this can be a complex and time-consuming process involving multiple government agencies. We also require governmental permits to export and transport our products.
Many approvals, licences and permits must be obtained from regulatory authorities and maintained, but there is no assurance that they will grant or renew them, approve any additional licences or permits for potential changes to operations in the future or in response to new legislation, or that they will process any of the applications on a timely basis. Stakeholders, like environmental groups, non-government organizations (NGOs) and Indigenous groups claiming rights to traditional lands, can raise legal challenges. A significant delay in obtaining or renewing the necessary approvals, licences or permits, or failure to receive the necessary approvals, licences or permits, could interrupt operations, or prevent them from operating, or disrupt the transportation and sale of our products, which could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
Public health issues and disease outbreaks
Our business and results of operations are subject to uncertainties arising out of public health issues. A local, regional, national, or international outbreak of an illness or contagious disease, such as a pandemic like COVID-19, could result in a general or acute decline in economic activity in the regions where our customers reside, where we operate in or hold assets in, production and transport delays, and general business interruptions. In addition, these risks could result in an increase in the cost of supplies and equipment, delays from difficulties in obtaining export or import licenses, tariffs and other barriers and restrictions, a decrease in the willingness of the general population to travel, staff shortages, mobility restrictions and other quarantine measures, supply shortages, increased government regulation, and the quarantine or contamination of one or more of our operating sites or buildings. Any such events could have a material and adverse impact on our business, financial condition, and results of operations.
In 2020 and 2021, our operations were impacted because of precautionary production suspensions due to the COVID-19 pandemic. Production at Cigar Lake was suspended between March and September 2020, and for a subsequent period between December 2020 and April 2021.
There were disruptions to the supply chain worldwide due to the COVID-19 pandemic. 2021 planned production from our fuel services operations was impacted by hydrogen supply issues.
Fuel fabrication defects and product liability
We fabricate nuclear fuel bundles, other reactor components, and monitoring equipment. These products are complex and may have defects that can be detected at any point in their product life cycle. Flaws in the products could materially and adversely affect our reputation, which could result in a significant cost to us and have a negative effect on our ability to sell our products in the future. We could also incur substantial costs to correct any product errors, which could have an adverse effect on our operating margins. While we have introduced significant automation to limit the potential for quality issues, there is no guarantee that we will detect all defects or errors in our products.
It is possible that some customers may demand compensation if we deliver defective products. If there are a significant number of product defects, it could have a significant impact on our operating results.
Agreements with some customers may include specific terms limiting our liability to customers. Even if there are limited liability provisions in place, existing or future laws, or unfavourable judicial decisions may make them ineffective. We have not experienced any material product liability claims to date, however, they could occur in the future because of the nature of nuclear fuel products. A successful product liability claim could result in significant monetary liability and could seriously disrupt our fuel manufacturing business and the company overall.
2 – Financial risks
Volatility and sensitivity to prices
We are concentrated in the nuclear fuel business, with our primary focus on uranium mining. As such, our earnings and cash flow are closely related to, and sensitive to, fluctuations in the spot and long-term market prices of U3O8 and uranium conversion services.
Many factors beyond our control affect these prices, including the following, among others:
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| • | demand for nuclear power and the rate of construction of nuclear power plants |
|---|---|
| • | timing and volume of demand for uranium and conversion services |
| --- | --- |
| • | forward contracts of U3O8 supplies for nuclear power plants |
| --- | --- |
| • | accidents in any part of the world affecting the nuclear industry in a specific region or in general, such as the<br>March 11, 2011 accident at Fukushima Dai-ichi Nuclear Power Plant in Japan |
| --- | --- |
| • | terrorist attacks on uranium mining, transport, or production or on nuclear power plants |
| --- | --- |
| • | war and civil disturbances (including the ongoing conflict between Russia and Ukraine) |
| --- | --- |
| • | uncertain legal, political, and economic environments |
| --- | --- |
| • | political and economic conditions in countries producing and buying uranium |
| --- | --- |
| • | government laws, policies, and decisions, including trade restrictions and sanctions |
| --- | --- |
| • | reprocessing of used reactor fuel and the re-enrichment of depleted<br>uranium tails |
| --- | --- |
| • | uranium from underfeeding generated using excess enrichment capacity |
| --- | --- |
| • | sales of excess civilian and military inventories of uranium by governments and industry participants<br> |
| --- | --- |
| • | levels of uranium production and production costs |
| --- | --- |
| • | significant production interruptions or delays in expansion plans or new mines going into production<br> |
| --- | --- |
| • | actions of investment and hedge funds in the uranium market |
| --- | --- |
| • | transactions by speculators and producers |
| --- | --- |
| • | prices of alternate sources to nuclear power, including oil, natural gas, coal, hydroelectric, solar and wind<br> |
| --- | --- |
We cannot predict the effect that any one or all of these factors will have on the prices of U3O8 and uranium conversion services.
Prices have fluctuated widely in the last several years, though have seen recovery in 2022 with long term U3O8 prices now approaching levels seen before the March 11, 2011 accident at Fukushima. We have experienced difficult uranium markets, which have adversely impacted our financial condition and prospects, though the recent price trend has been positive.
The table below shows the range in spot prices over the last five years.
| Range of spot uranium prices<br>US/lb of U3O8 | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| 2019 | 2020 | 2021 | 2022 | ||||||
| High | 29.10 | $ | 28.90 | $ | 33.93 | $ | 45.75 | $ | 58.20 |
| Low | 21.00 | 24.05 | 24.63 | 27.98 | 43.08 |
All values are in US Dollars.
| Spot UF6 conversion values<br>US/kg U | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| High | 13.50 | $ | 22.13 | $ | 22.50 | $ | 21.75 | $ | 40.00 |
| Low | 6.13 | 13.75 | 21.50 | 16.10 | 16.25 |
All values are in US Dollars.
The next table shows the range in term prices over the last five years.
| Range of long-term uranium prices<br>US/lb of U3O8 | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| 2019 | 2020 | 2021 | 2022 | ||||||
| High | 32.00 | $ | 32.50 | $ | 36.00 | $ | 43.00 | $ | 52.00 |
| Low | 29.00 | 31.00 | 32.50 | 33.50 | 42.88 | ||||
| Term UF6 conversion values<br>US/kg U | |||||||||
| High | 16.00 | $ | 18.13 | $ | 19.00 | $ | 19.00 | $ | 27.25 |
| Low | 12.25 | 15.50 | 18.00 | 18.00 | 18.50 |
All values are in US Dollars.
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Notes:
| • | Spot and long-term uranium prices are the average of prices published monthly by UxC, LLC (UxC) and from The<br>Nuexco Exchange Value, published by TradeTech. |
|---|---|
| • | Spot and term UF6 conversion values are the average of<br>the North American prices published monthly by UxC and from The Nuexco Conversion Value, published by TradeTech. |
| --- | --- |
If prices for U3O8 or uranium conversion services fall below our own production costs for a sustained period, continued production or conversion at our sites may cease to be profitable and we may have to change our operating plans. This would have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects. We have been impacted by low U3O8 prices in the past. In 2016, we suspended production at Rabbit Lake and curtailed production at our US mines and in 2018, we suspended production at our McArthur River and Key Lake operations and reduced our dividend.
Declines in U3O8 prices could also delay or deter a decision to build a new mine or begin commercial production once constructed, or adversely affect our ability to finance our operations, as well necessitate a decision to cut production volumes further for an extended period. Any of these events could have an adverse effect on our future earnings, cash flows, financial condition, results of operations, or prospects.
A sustained decline in U3O8 prices may require us to write down our mineral reserves and mineral resources, and any significant write downs may lead to material write downs of our investment in the mining properties affected, and an increase in charges for amortization, reclamation, and closures.
In our uranium segment, we use a uranium contracting strategy to reduce volatility in our future earnings and cash flow from exposure to fluctuations in uranium prices. It involves building a portfolio that consists of base-escalated contracts and market-related contracts with terms of 5 to 10 years (on average). This strategy can create opportunity losses because we may not benefit fully if there is a significant increase in U3O8 prices. This strategy also creates currency risk since we receive payment under the majority of our sales contracts in US dollars. In addition, this strategy has provided us with a measure of protection for our business from the low uranium prices experienced since 2011. At year end, the annual average sales commitments in our contract portfolio over the next five years in our uranium segment is 21 million pounds, with commitment levels in 2023 through 2025 higher than average and in 2026 and 2027 lower than average. As a result, we may become more exposed to fluctuations in uranium prices and this could have an adverse effect on our future earnings, cash flows, financial condition, results of operations or prospects. There is no assurance that our contracting strategy will be successful.
We make purchases on the spot market and under long-term agreements to supplement our production and supply our contracts. There are, however, risks associated with these purchases, including the risk of losses, which could have an adverse effect on our earnings, cash flows, financial condition, or results of operations.
Reserve, resource, production, capital and operating cost estimates
Reserve and resource estimates are not precise
Our mineral reserves and resources are the foundation of our uranium mining operations and are fundamental to our success.
The uranium mineral reserves and resources reported in this AIF are estimates and are therefore subjective and subject to numerous inherent uncertainties. There is no assurance that the indicated tonnages or grades of uranium will be mined or milled or that we will receive the uranium price we used in estimating these reserves.
While we believe that the mineral reserve and resource estimates included in this AIF are well established and reflect management’s best estimates, reserve and resource estimates, by their nature, are imprecise, do not reflect exact quantities and depend to a certain extent on statistical inferences that may ultimately prove unreliable. The tonnage and grade of reserves we actually recover, and rates of production from our current mineral reserves, may be less than our estimates. Fluctuations in the market price of uranium and changing exchange rates and operating and capital costs can make reserves uneconomic to mine in the future and ultimately cause us to reduce our reserves.
Short-term operating factors relating to mineral reserves, like the need for orderly development of orebodies or the processing of different ore grades, can also prompt us to modify reserve estimates or make reserves uneconomic to mine in the future, and can ultimately cause us to reduce our reserves. Reserves also may have to be re-estimated based on actual production experience.
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Mineral resources may be upgraded to proven or probable mineral reserves if they demonstrate profitable recovery. Estimating reserves or resources is always affected by economic and technological factors, which can change over time, and experience in using a particular mining method. There is no assurance that any resource estimate will ultimately be upgraded to proven or probable reserves. If we do not obtain or maintain the necessary permits or government approvals, or there are changes to applicable legislation, it could cause us to reduce our reserves.
Mineral resource and reserve estimates can be uncertain because they are based on data from limited sampling and drilling and not from the entire orebody. As we gain more knowledge and understanding of an orebody, the resource and reserve estimate may change significantly, either positively or negatively.
The reliability of resource and reserve estimates is highly dependent upon the accuracy of the assumptions upon which they are based and the quality of information available. These assumptions may prove to be inaccurate.
If our mineral reserve or resource estimates for our uranium properties are inaccurate or are reduced in the future, it could:
| • | require us to write down the value of a property |
|---|---|
| • | result in lower uranium concentrate production than previously estimated |
| --- | --- |
| • | result in lower revenue than previously estimated |
| --- | --- |
| • | require us to incur increased capital or operating costs, or |
| --- | --- |
| • | require us to operate mines or facilities unprofitably |
| --- | --- |
This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
Production, capital and operating cost estimates may be inaccurate
We establish our operating and capital plans based on the information we have at the time, including expert opinions. There is no assurance, however, that these plans will not change as new information is available or there is a change in expert opinion.
Studies we use may contain estimated capital and operating costs, production and economic returns and other estimates that may be significantly different than actual results.
We prepare estimates of future production, capital costs and operating costs for particular operations, but there is no assurance we will achieve these estimates. Estimates of expected future production, capital costs and operating costs are inherently uncertain, particularly beyond one year, and could change materially over time.
Production, capital cost and operating cost estimates for:
| • | McArthur River/Key Lake assume that development, mining, milling, and production plans proceed as expected<br> |
|---|---|
| • | Cigar Lake assume that development, mining, milling, and production plans proceed as expected<br> |
| --- | --- |
| • | Inkai assume that development, mining, and production plans proceed as expected |
| --- | --- |
Production estimates for uranium refining, conversion and fuel manufacturing assume there is no disruption or reduction in supply from us or third-party sources, and that estimated rates and costs of processing are accurate, among other things.
Our actual production and costs may vary from estimates for a variety of reasons, including, among others:
| • | actual ore mined varying from estimated grade, tonnage, dilution, metallurgical and other characteristics |
|---|---|
| • | mining and milling losses greater than planned |
| --- | --- |
| • | short-term operating factors relating to the ore, such as the need for sequential development of orebodies and the processing of new or different ore grades |
| --- | --- |
| • | risks and hazards associated with mining, milling, uranium refining, conversion and fuel manufacturing |
| --- | --- |
| • | failure of mining methods and plans |
| --- | --- |
| • | failure to obtain and maintain the necessary regulatory and participant approvals |
| --- | --- |
| • | difficulties in milling McArthur River ore at Key Lake |
| --- | --- |
| • | development, mining, or production plans for Cigar Lake are delayed or do not succeed for any reason |
| --- | --- |
| • | difficulties in milling Cigar Lake ore at McClean Lake |
| --- | --- |
| • | development, mining, or production plans for Inkai are delayed or do not succeed for any reason |
| --- | --- |
| • | interruptions in the supply of electricity, water, and other utilities or infrastructure |
| --- | --- |
| • | delays, interruption or reduction in production or construction activities due to fires, failure or unavailability of critical equipment, shortage of |
| --- | --- |
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| • | natural phenomena, such as forest fires, floods, or earthquakes as well as shifts in temperature, precipitation, and the impact of more frequent severe weather condition as the result of climate change |
|---|---|
| • | labour shortages or strikes |
| --- | --- |
| • | development, mining, or production plans for McArthur River are delayed or do not succeed for any reason |
| --- | --- |
| supplies, underground floods, earthquakes, tailings dam failures, lack of tailings capacity, ground movements and cave-ins, outbreak of illness (such as a pandemic like COVID-19), cyber-attacks, or other difficulties | |
| --- |
Operating costs may also be affected by a variety of factors including changing waste to ore ratios, ore grade metallurgy, mine and mill recoveries, labour costs, costs of supplies and services (for example, fuel and power), general inflationary pressures, and currency exchange rates, and increasing regulatory burdens.
Failure to achieve production or cost estimates or a material increase in costs could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Market price volatility
The company’s common shares are listed on the TSX and the NYSE. The price of our common shares may be significantly affected by factors unrelated to our performance, including the following:
| • | market risk and sentiment |
|---|---|
| • | legal, political, and economic environments factors |
| --- | --- |
| • | energy prices |
| --- | --- |
| • | a reduction in analytical coverage of us by investment banks with research capabilities |
| --- | --- |
| • | a drop in trading volume and general market interest in our securities may adversely affect an investor’s<br>ability to liquidate an investment and consequently an investor’s interest in acquiring a significant stake in us |
| --- | --- |
| • | our failure to meet the reporting and other obligations under Canadian and US securities laws or imposed by the<br>exchanges could result in a delisting of our common shares from the TSX or NYSE |
| --- | --- |
As a result of any of these factors, the market price of our common shares may increase or decline even if our operating results, underlying asset values or prospects have not changed. This may cause decreases in asset values that are deemed to be non-temporary, which may result in impairment losses. There can be no assurance that continuing fluctuations in price and volume will not occur. If such increased levels of volatility and market turmoil continue, our operations could be adversely impacted, and the trading price of our common shares may be materially adversely affected.
Currency fluctuations
Our earnings and cash flow may also be affected by fluctuations in the exchange rate between the Canadian and US dollar. We sell the majority of our uranium and fuel services products under long-term sales contracts, which are routinely denominated in US dollars. Our product purchases are denominated in US dollars while our production costs are largely denominated in Canadian dollars. In addition, our purchases of uranium are primarily denominated in US dollars. Our consolidated financial statements are expressed in Canadian dollars.
Any fluctuations in the exchange rate between the US dollar and Canadian dollar can result in favourable or unfavourable foreign currency exposure, which can have a material effect on our future earnings, cash flows, financial condition or results of operations, as has been the case in the past. While we use a hedging program to limit any adverse effects of fluctuations in foreign exchange rates, there is no assurance that these hedges will eliminate any potential material negative impact of fluctuating exchange rates.
Interest Rate Changes
Our exposure to changes in interest rates results from investing and borrowing activities undertaken to manage our liquidity and capital requirements. While we use a hedging program to limit any adverse effects of fluctuations in interest rates, there is no assurance that these hedges will eliminate any potential material negative impact of fluctuating interest rates.
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Customers
Our main business relates to the production and sale of uranium concentrates (our uranium segment) and providing uranium conversion services (our fuel services segment). We rely heavily on a small number of customers to purchase a significant portion of our uranium concentrates and conversion services.
At December 31, 2022:
| • | in our uranium segment, our five largest customers account for 56% of our contracted supply of U3O8 |
|---|---|
| • | in our fuel services segment, our five largest UF6<br>conversion customers account for 59% of our contracted supply of UF6 conversion services |
| --- | --- |
We are a supplier of UO2 used by Canadian CANDU heavy water reactors. Our sales to our largest customer accounted for 51% of our UO2 sales in 2022. In addition, revenues in 2022 from our two largest customers of our uranium and conversion segments represented $260 million or approximately 21% of our total revenues from those segments.
Sales for the Bruce A and B reactors represent a substantial portion of our fuel manufacturing business.
If we lose any of our largest customers, if any of them curtails their purchases, or if we are unable to transport our products to them, it could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.
Counterparty and credit risk
Our business operations expose us to the risk of counterparties not meeting their contractual obligations, including:
| • | customers |
|---|---|
| • | suppliers |
| --- | --- |
| • | financial institutions and other counterparties to our derivative financial instruments and hedging arrangements<br>relating to foreign currency exchange rates and interest rates |
| --- | --- |
| • | financial institutions which hold our cash on deposit and through which we make short-term investments<br> |
| --- | --- |
| • | insurance providers |
| --- | --- |
Credit risk is the risk that counterparties will not be able to pay for services provided under the terms of the contract. If a counterparty to any of our significant contracts defaults on a payment or other obligation or becomes insolvent, it could have a material and adverse effect on our cash flows, earnings, financial condition, or results of operations.
Uranium products, conversion and fuel services
In our uranium and fuel services segments, we manage the credit risk of our customers for uranium products, conversion, and fuel services by:
| • | monitoring their creditworthiness |
|---|---|
| • | asking for pre-payment or another form of security if they pose an<br>unacceptable level of credit risk |
| --- | --- |
As of December 31, 2022, 92% of our forecast revenue under contract for the period 2023 to 2025 is with customers whose creditworthiness meets our standards for unsecured payment terms.
Other
We manage the credit risk on our derivative and hedging arrangements, cash deposits and insurance policies by dealing with financial institutions and insurers that meet our credit rating standards and by limiting our exposure to individual counterparties.
We diversify or increase inventory in our supply chain to limit our reliance on a single contractor, or limited number of contractors. We also monitor the creditworthiness of our suppliers to manage the risk of suppliers defaulting on delivery commitments.
There is no assurance, however, that we will be successful in our efforts to manage the risk of default or credit risk.
Liquidity and financing
Liquidity, or access to funds, is essential to our business.
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Nuclear energy and mining are extremely capital-intensive businesses, and companies need significant ongoing capital to maintain and improve existing operations, invest in large scale capital projects with long lead times, and manage uncertain development and permitting timelines and the volatility associated with fluctuating uranium and input prices.
We believe our current financial resources are sufficient to support projects planned for 2023. We have a number of alternatives to fund future capital requirements, including using our operating cash flow, drawing on our cash balances, drawing on existing credit facilities, entering new credit facilities, and raising additional capital through debt or equity financings.
There is no assurance that we will obtain the financing we need when needed. Volatile uranium markets, a claim against us, an adverse court or arbitration decision, a significant event disrupting our business or operations, or other factors, may make it difficult or impossible for us to obtain debt or equity financing on favourable terms, or at all.
A lack of liquidity could result in a delay or postponement of any or all of our exploration, development or other growth initiatives, or could otherwise have a material adverse impact on our financial condition.
Decommissioning and reclamation obligations
Environmental regulators are demanding more and more financial assurances so that the parties involved, and not the government, bear the cost of decommissioning and reclaiming sites. Our North American operations have financial assurances in place in connection with our preliminary plans for decommissioning of the sites.
We have filed conceptual decommissioning plans for some of our properties with the regulators. We review these plans for Canadian facilities every five years, or at the time of an amendment or renewal of an operating licence. Plans for our US sites are reviewed every year. Regulators review our conceptual plans on a regular basis. As the sites approach or go into decommissioning, regulators review the detailed decommissioning plans, and this can lead to additional requirements, costs, and financial assurances. It is not possible to predict what level of decommissioning and reclamation and financial assurances regulators may require in the future.
If we must comply with additional regulations, or the actual cost of decommissioning and reclamation in the future is significantly higher than our current estimates, this could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Carryingvalues of assets
We evaluate the carrying value of our assets to decide whether current events and circumstances indicate if we can recover the carrying amount. This involves comparing the estimated fair value of our reporting units to their carrying values.
We base our fair value estimates on various assumptions, however, the actual fair values can be significantly different than the estimates. If we do not have any mitigating valuation factors or experience a decline in the fair value of our reporting units, it could ultimately result in an impairment charge.
Dilution of common shares
We are authorized to issue an unlimited number of common shares, of which 432,518,470 were issued and outstanding as of December 31, 2022. Future issuances for financings, acquisitions, reorganizations, amalgamations, and other transactions, may result in significant dilution to our common shares, and these issuances may be at prices substantially below the price paid for our common shares by our existing shareholders. Significant dilution would reduce the proportionate ownership and voting power held by our existing shareholders and may result in a decrease in the market price of our common shares.
3 – Governance and compliance risks
Litigation
We are currently subject to litigation or threats of litigation and may be involved in disputes with other parties in the future that result in litigation. This litigation may involve joint venture participants, suppliers, customers, governments, regulators, tax authorities, or other persons.
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We cannot accurately predict the outcome of any litigation. The costs of defending or settling litigation can be significant. If a dispute cannot be resolved favourably, it may have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects. See Legal proceedings on page 126 more information.
We are currently involved in a tax dispute with CRA and in 2017 settled a dispute with the IRS. See Transfer pricing dispute at pages 93 and 94. In addition, we are subject to the risk that CRA, the IRS or other tax authorities in other countries may seek to challenge or reassess our income tax returns on the same or a different basis for the same periods or other previously reported periods. Substantial success for CRA in the tax dispute would be material, and other unfavourable outcomes of challenges or reassessments initiated by the IRS or tax authorities in other countries could be material to our cash flows, financial condition, results of operations or prospects.
Joint ventures
We participate in McArthur River, Key Lake, Cigar Lake, Inkai, Millennium, and GLE through joint ventures with third parties, and, subject to closing, will participate in Westinghouse through a joint venture with third parties. Some of these joint ventures are unincorporated and some are incorporated (like JV Inkai, GLE and Westinghouse). We have other joint ventures and may enter more in the future.
There are risks associated with joint ventures, including:
| • | disagreement with a joint venture participant about how to develop, operate or finance a project<br> |
|---|---|
| • | a joint venture participant not complying with a joint venture agreement |
| --- | --- |
| • | possible litigation or arbitration between joint venture participants about joint venture matters<br> |
| --- | --- |
| • | the inability to exert control over decisions related to a joint venture we do not have a controlling interest in<br> |
| --- | --- |
The other owner of JV Inkai is KAP, an entity majority owned by the government of Kazakhstan, so its actions and priorities could be dictated by government policies instead of commercial considerations.
These risks could result in legal liability, affect our ability to develop or operate a project under a joint venture, or have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Government laws and regulations
In addition to laws and regulations relating to the protection of the environment, employee health and safety, and waste management (see Environmental risks), our business activities are subject to extensive and complex laws and regulations in other areas.
There are laws and regulations for uranium exploration, development, mining, milling, refining, conversion, fuel manufacturing, transport, exports, imports, taxes and royalties, labour standards, occupational health, waste disposal, protection, and remediation of the environment, decommissioning and reclamation, safety, hazardous substances, emergency response, land use, water use and other matters.
Significant financial and management resources are required to comply with these laws and regulations, and this will likely continue as laws and government regulations become more and more strict. We are unable to predict the ultimate cost of compliance or its effect on our business because legal requirements change frequently, are subject to interpretation, and may be enforced to varying degrees.
Some of our operations are regulated by government agencies that exercise discretionary powers conferred by statute. If these agencies do not apply their discretionary authority consistently, then we may not be able to predict the ultimate cost of complying with these requirements or their effect on operations.
Existing, new, or changing laws, regulations and standards of regulatory enforcement could disrupt transportation of our products, increase costs, lower, delay or interrupt production, or affect decisions about whether to continue with existing operations or development projects. This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
If we do not comply with the laws and regulations that apply to our business, or it is alleged we do not comply, then regulatory or judicial authorities could take any number of enforcement actions, including:
| • | corrective measures that require us to increase capital or operating expenditures or install additional equipment<br> |
|---|
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| • | remedial actions that result in temporary or permanent shut-down or reduction of our operations<br> |
|---|---|
| • | requirements that we compensate communities that suffer loss or damage because of our activities<br> |
| --- | --- |
| • | civil or criminal fines or penalties |
| --- | --- |
Legal and political circumstances are different outside North America, which can change the nature of regulatory risks in foreign jurisdictions when compared with regulatory risks associated with operations in North America.
Internal controls over financial reporting
We use internal controls over financial reporting to provide reasonable assurance that we authorize transactions, safeguard assets against improper or unauthorized use, and record and report transactions properly. This gives us reasonable assurance that our financial reporting is reliable and prepared in accordance with IFRS.
It is impossible for any system to provide absolute assurance or guarantee reliability, regardless of how well it is designed or operated. We continue to evaluate our internal controls to identify areas for improvement and provide as much assurance as reasonably possible. We conduct an annual assessment of our internal controls over financial reporting and produce an attestation report of their effectiveness by our independent auditors to meet the requirement of Section 404 of the Sarbanes- Oxley Act of 2002.
If we do not satisfy the requirements for internal controls on an ongoing, timely basis, it could negatively affect investor confidence in our financial reporting, which could have an impact on our business and the trading price of our common shares. If a deficiency is identified and we do not introduce new or better controls, or have difficulty implementing them, it could harm our financial results or our ability to meet reporting obligations.
Anti-bribery and anti-corruption laws
We are subject to anti-bribery and anti-corruption laws, including the Corruption of Foreign Public Officials Act (Canada) and the United States Foreign Corrupt Practices Act of 1977. Failure to comply with these laws could subject us to, among other things, reputational damage, civil or criminal penalties, other remedial measures and legal expenses which could adversely affect our business, results from operations, and financial condition. It may not be possible for us to ensure compliance with anti-bribery and anti-corruption laws in every jurisdiction in which our employees, agents, sub-contractors or joint venture partners are located or may be located in the future.
4 – Social risks
Defects in title
We have investigated our rights to explore and mine our material properties, and those rights are in good standing to our knowledge. There is no assurance, however, that these rights will not be revoked or significantly altered to our detriment, or that our rights will not be challenged by third parties, including local governments and by Indigenous groups, such as First Nations and Métis in Canada.
Relationships with Indigenous peoples and local communities
Our ability to foster and maintain the support of local communities and governments for our development projects and operations is critical to the conduct and growth of our business, and we do this by engaging in dialogue and consulting with them about our activities and the social and economic benefits they will generate. There is no assurance, however, that this support can be fostered or maintained. There is an increasing focus on ensuring that appropriate ESG policies, programs and policies are in place to manage nuclear energy and mining activities to protect the environment and communities affected by the activities. Some NGOs are vocal critics of the nuclear energy and mining industries, and oppose globalization, nuclear energy, and resource development. Adverse publicity generated by these NGOs or others, related to the nuclear energy industry or the extractive industry in general, or our operations in particular, could have an adverse effect on our reputation or financial condition and may affect our relationship with the communities we operate in. While we are committed to operating in a socially responsible way, there is no guarantee that our efforts will mitigate this risk.
Indigenous rights, title claims, engagement and consultation
Managing Indigenous rights, title claims, engagement and related consultation is an integral part of our exploration, development, and mining activities, and we are committed to managing them effectively. We have signed agreements with
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the communities closest to our Canadian mining operations to help mitigate the risks associated with potential Indigenous land or consultation claims that could impact our Canadian mining operations. These agreements provide substantial socioeconomic opportunities to these communities and are intended to provide us with support for these operations from those communities. There is no assurance, however, that we will not face material adverse consequences because of the legal and factual uncertainties inherent with Indigenous rights, title claims and consultation.
Exploration, development, mining, milling and decommissioning activities at our various properties in Saskatchewan may be affected by claims by Indigenous groups, and related consultation issues. We also face similar issues with our activities in other provinces and countries.
It is generally acknowledged that under historical treaties, First Nations in northern Saskatchewan ceded title to most traditional lands in the region in exchange for treaty benefits and reserve lands. Some First Nations in Saskatchewan, however, assert that their treaties are not an accurate record of their agreement with the Canadian government and that they did not cede title to the minerals when they ceded title to their traditional lands. Further, the United Nations Declaration on the Rights of Indigenous Peoples Act (UNDRIP) came into force on June 21, 2021, which creates some additional risk for future activities. UNDRIP requires that an action plan setting out how the objectives of the Declaration will be achieved be tabled by June 21, 2023. The action plan may provide further clarity for future activities.
5 – Environmental risks
Complex legislation andenvironmental, health and safety risk
Our activities have an impact on the environment, so our operations are subject to extensive and complex laws and regulations relating to the protection of the environment, employee health and safety, and waste management. We also face risks that are unique to uranium mining, processing, and fuel manufacturing. Laws to protect the environment as well as employee health and safety are becoming more stringent for members of the nuclear energy industry.
Our facilities operate under various operating and environmental approvals, licences, and permits that have conditions that we must meet as part of our regular business activities. In a number of instances, our right to continue operating these facilities depends on our compliance with these conditions.
Our ability to obtain approvals, licences, and permits, maintain them, and successfully develop and operate our facilities may be adversely affected by the real or perceived impact of our activities on the environment and human health and safety at our development projects and operations and in surrounding communities. The real or perceived impact of activities of other nuclear energy or mining companies can also have an adverse effect on our ability to secure and maintain approvals, licences and permits.
Our compliance with laws and regulations relating to the protection of the environment, employee health and safety, and waste management requires significant expenditures, and can cause delays in production or project development. This has been the case in the past and may be so in the future. Failing to comply can lead to fines and penalties, temporary or permanent suspension of development and operational activities, clean-up costs, damages, and the loss of, or the inability to obtain, key approvals, permits, and licences. We are exposed to these potential liabilities for our development projects and operations as well as our closed operations. There is no assurance that we have been or will be in full compliance with all these laws and regulations, or with all the necessary approvals, permits, and licences.
These risks could delay or interrupt our operations or project development activities, delay, interrupt or lower our production, and could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Treated water releases
Responsible management of water is critical to our business success. At our Canadian operations, treated water releases are monitored and studies are conducted to monitor conditions in the downstream receiving environment. However, changes in ore chemistry, identification of a new elements of concern, changes in regulatory requirements or other issues, may result in additional costs and regulatory action, and could also require installation of new water treatment facilities. The occurrence of one or more of these events could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
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Air emissions at Port Hope Conversion Facility
At the Port Hope Conversion Facility, the main stacks for UF6 and UO2 are continuously monitored and have discharge limits in place, which are monitored while the plants are operational. A large-scale process failure or catastrophic accident has potential to significantly impact the surrounding community and have other consequences, including constraining production, regulatory action, and environmental damage. The occurrence of one or more of such events could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
6 – Strategic risks
Major nuclear incident risk
Due to their inherent materiality, major accidents in the nuclear industry, and most notably at nuclear power plants, such as the Chernobyl nuclear power plant accident of 1986 in the Soviet Union and the accident in 2011 at the Fukushima-Daiichi nuclear power plant in Japan, garner significant worldwide attention and spawn global public sentiment favouring more significant regulation for nuclear power generation. For example, following the accident at Fukushima, certain countries, including Germany, Switzerland and Belgium, announced their intention to phase out nuclear power. As of December 31, 2022, Germany had shut down 14 of its 17 nuclear reactors. The remaining three reactors were extended until at least mid-April 2023, keeping them online due to energy concerns. Prior to the accident in 2011 at Fukushima, Japan had 54 nuclear reactors, which represented 12% of global nuclear generating capacity. As of December 31, 2022, Japan has restarted 10 reactors. The effect of the 2011 accident at the Fukushima-Daiichi nuclear power plant on the uranium market has had a material and adverse effect on our earnings, cash flows, financial condition, results of operations, and prospects.
Another major accident at a nuclear power plant, or a similar disaster related to the nuclear industry, including as the result of the military conflict between Russia and Ukraine, could lead to more countries adopting increasingly stringent safety regulations in the nuclear industry, cause the public sentiment to shift more in favour of phasing-out nuclear power, and reverse or halt the recent positive trend towards nuclear power. The reaction to any such major accident could be significantly more severe and may result in a rapid global abandonment of nuclear power generation. Any such event may result in, among other things, a significant reduction in the demand for uranium and the resulting decline in the price of uranium.
Another major accident at a nuclear power plant, or a similar disaster related to the nuclear industry, could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, and prospects.
Public acceptance of nuclear energy is uncertain
Maintaining the demand for uranium at current levels and achieving any growth in demand in the future will depend on society’s acceptance of nuclear technology as a means of generating electricity and pursuing carbon reduction. Because of unique political, technological, and environmental factors affecting the nuclear industry, including public attention following the 2011 accident at Fukushima in Japan, the industry is subject to public opinion risks that could have a material adverse impact on the demand for nuclear power and increase the regulation of the nuclear power industry.
A major shift in public opinion, whether due to an accident at a nuclear power plant, changing views regarding the pursuit of carbon reduction strategies, or other causes, could impact the continuing acceptance of nuclear energy and the future prospects for nuclear power generation, which could have a material adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
In addition, we may be impacted by changes in regulation and public perception of the safety of nuclear power plants, which could adversely affect the construction of new plants, the re-licensing of existing plants, the demand for uranium and the future prospects for nuclear generation. These events could have a material adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Industry concentration risk
We are concentrated in the nuclear fuel business, with our primary focus on uranium mining. As such, we are sensitive to changes in, and our performance and future prospects, will depend to a greater extent on, the overall condition of the nuclear energy industry and the public acceptance of nuclear energy. We may be susceptible to increased risks, compared
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to diversified metals trading companies or diversified mining companies, as a result of the fact that our operations are concentrated in the nuclear fuel business.
Because we derive the majority of our revenues from sales of nuclear fuel, our results of operations and cash flows will fluctuate as the price of nuclear fuel increases or decreases. A sustained period of declining nuclear fuel prices would materially and adversely affect our results of operations and cash flows. Additionally, if the market price for nuclear fuel declines or remains at relatively low levels for a sustained period, we may have to revise our operating plans, including reducing operating costs and capital expenditures, terminating, or suspending mining operations at one or more of our properties, and discontinuing certain exploration and development plans. We have been impacted by the sustained period of low prices. In a sustained period of low prices, we may be unable to decrease our costs in an amount sufficient to offset reductions in revenues and may incur losses. See Financial risks – Volatility and sensitivity to prices on page 104.
Mine concentration risk
Our main sources of uranium production are mines at Cigar Lake and McArthur River and our interest in JV Inkai.
In 2023, our share of planned Cigar Lake production is 9.8 million pounds. Cigar Lake production is milled at the McClean Lake mill operated by Orano. There is a risk to our Cigar Lake production plan if the McClean Lake is unable to mill Cigar Lake production.
In 2023, our share of planned McArthur River production is 10.5 million pounds and we have announced plans to produce 18 million pounds per year (100% basis) by 2024. McArthur River production is milled at the Key Lake mill we operate. There is uncertainty regarding the timing of a successful ramp up to planned production. See McArthur River mine and Key Lake mill ramp up on page 100.
We own a 40% interest in JV Inkai and have the right to purchase production from the Inkai mine (in 2023 we are entitled to purchase 4.2 million pounds due to an adjustment to our purchase entitlement under the implementation agreement (see 2023 Production on page 61).
Any disruption in or reduction in production from one or more of these mines could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Environmental Regulatory Uncertainty
Laws and regulations on the environment, employee health and safety, and waste management continue to evolve, and this can create significant uncertainty around the environmental, employee health and safety, and waste management costs we incur. If new legislation and regulations are introduced in the future, then they could lead to additional capital and operating costs, restrictions and delays at existing operations or development projects, and the extent of any of these possible changes cannot be predicted in a meaningful way.
Environmental and regulatory review is a long and complex process that can delay the opening, modification or expansion of a mine, conversion facility or refining facility, or extend decommissioning activities at a closed mine or other facility.
These risks could delay or interrupt our operations or project development activities, delay, interrupt or lower our production, and could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Alternate sources of energy
Nuclear energy competes with other sources of energy like oil, natural gas, coal, hydroelectric, solar and wind. These sources are somewhat interchangeable with nuclear energy, particularly over the longer term and sustained lower prices for these energy sources may result in lower demand for nuclear energy and consequently reduction in demand for uranium and uranium prices.
A major shift in the power generation industry towards non-nuclear power or non-uranium based sources of nuclear energy, whether due to lower cost of power generation associated with such sources, government policy decisions, or otherwise, could have a material adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
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Industry competition and international trade restrictions
The international uranium industry, which includes supplying uranium concentrates and uranium conversion services, is highly competitive. We directly compete with a relatively small number of uranium mining and enrichment companies in the world. Their supply may come from mining uranium, excess inventories, including inventories made available from decommissioning of nuclear weapons, reprocessed uranium and plutonium derived from used reactor fuel, and from using excess enrichment capacity to re-enrich depleted uranium tails and generate uranium from underfeeding. The number of potential end customers for our uranium products, being utility companies, is relatively scarce.
The supply of uranium is affected by a number of international trade agreements and government legislation and policies. These and any similar future agreements, governmental legislation, policies, or trade restrictions are beyond our control and may affect the supply of uranium available in the US, Europe and Asia, the world’s largest markets for uranium.
For conversion services, we compete with a small number of primary commercial suppliers. In addition, we compete with the availability of additional supplies from excess inventories, including those from decommissioning nuclear weapons and using excess enrichment capacity to re-enrich depleted uranium tails.
Any political decisions about the uranium market can affect our future prospects. There is no assurance that the US or other governments will not enact legislation or take other actions that restricts who can buy or supply uranium or facilitates a new supply of uranium.
Technical innovation andobsolescence
Requirements for our products may be affected by technological changes and innovation in nuclear reactors and other uses of uranium. These technological changes could reduce the demand for uranium, which could have a material adverse impact on our future earnings, cash flows, financial condition or results of operations.
Deregulation of the electrical utility industry
A significant part of our future prospects is directly linked to developments in the global electrical utility industry.
Deregulation of the utility industry, particularly in the US, Japan, and Europe, could affect the market for nuclear and other fuels and could lead to the premature shutdown of some nuclear reactors.
Deregulation has resulted in utilities improving the performance of their reactors to record capacity, but there is no assurance this trend will continue.
Deregulation can have a material and adverse effect on our future earnings, cash flows, financial condition or results of operations.
Reputational risks
Damage to our reputation can occur from actual or perceived actions or inactions and a variety of events and circumstances, many of which are out of our control. The growing use of social media to generate, publish and discuss community news and issues and to connect with others has made it significantly easier for individuals and groups to share their opinions of us and our activities, whether accurate or not. We do not control how we are perceived by others. Loss of reputation could result in, among other things, a decrease to the price of our common shares, decreased investor confidence, challenges in maintaining positive relationships with the communities in which we operate and other important stakeholders, and increased risks in obtaining permits or financing for our operations, any of which could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
Replacement of depleted reserves
Cigar Lake, Inkai and McArthur River mines are currently our main sources of mined uranium concentrates. We must replace mineral reserves depleted by production at these mines to maintain or increase our annual production levels over the long term. Reserves can be replaced by expanding known orebodies, locating new deposits, or making acquisitions. Substantial expenditures are required to establish new mineral reserves. We may not be able to sustain or increase production if:
| • | we do not identify, discover, or acquire other deposits |
|---|---|
| • | we do not find extensions to existing ore bodies |
| --- | --- |
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| • | we do not convert resources to reserves at our mines or other projects |
|---|
This could have a material and adverse effect on our ability to maintain production to or beyond currently contemplated mine lives, as well it could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Although we have successfully replenished reserves in the past through ongoing exploration, development and acquisition programs, there is no assurance that we will be successful in our current or future exploration, development, or acquisition efforts.
Development and expansion projects to sustain production and fuel growth
Our ability to sustain and increase our uranium production depends in part on successfully developing new mines and/or expanding existing operations.
Several factors affect the economics and success of these projects:
| • | the attributes of the deposit, including its depth, size and grade |
|---|---|
| • | capital and operating costs |
| --- | --- |
| • | metallurgical recoveries |
| --- | --- |
| • | the accuracy of reserve estimates |
| --- | --- |
| • | government regulations |
| --- | --- |
| • | availability of appropriate infrastructure, particularly power and water |
| --- | --- |
| • | future uranium prices |
| --- | --- |
| • | the accuracy of feasibility studies |
| --- | --- |
| • | acquiring surface or other land rights |
| --- | --- |
| • | receiving necessary government permits |
| --- | --- |
| • | receiving necessary stakeholder support |
| --- | --- |
The effect of these factors, either alone or in combination, cannot be accurately predicted and their impact may result in our inability to extract uranium economically from any identified mineral resource.
Generally, development projects have no operating history that can be used to estimate future cash flows. We must invest a substantial amount of capital and time to develop a project and achieve commercial production. A change in costs or construction schedule can affect the economics of a project. Actual costs could increase significantly, and economic returns could be materially different from our estimates. We could fail to obtain the necessary governmental approvals for construction or operation. In any of these situations, a project might not proceed according to its original timing, or at all.
It is not unusual in the nuclear energy or mining industries for new or expanded operations to experience unexpected problems during start-up or ramp-up, resulting in delays, higher capital expenditures than anticipated and reductions in planned production. Production may be insufficient to recover exploration, development, and production costs. Delays, additional costs or reduced or insufficient production could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
There is no assurance we will be able to complete development of new mines, or expand existing operations, economically or on a timely basis.
Uranium explorationis highly speculative
Uranium exploration is highly speculative and involves many risks, and few properties that are explored are ultimately developed into producing mines.
Even if mineralization is discovered, it can take several years in the initial phases of drilling until a production decision is possible, and the economic feasibility of developing an exploration property may change over time. We are required to make a substantial investment to establish proven and probable mineral reserves, to determine the optimal metallurgical process to extract minerals from the ore, to construct mining and processing facilities (in the case of new properties) and to extract and process the ore. We might abandon an exploration project because of poor results or because we feel that we cannot economically mine the mineralization.
Given these uncertainties, there is no assurance that our exploration activities will be successful and result in new reserves to expand or replace our current mineral reserves to maintain or increase our production.
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Competition for sources of uranium
There is competition for mineral acquisition opportunities throughout the world, so we may not be able to acquire rights to explore additional attractive uranium mining properties on terms that we consider acceptable.
There is no assurance that we will acquire any interest in additional uranium properties or buy additional uranium concentrates from the decommissioning of nuclear weapons or the release of excess government inventory, that will result in additional uranium concentrates we can sell. If we are not able to acquire these interests or rights, it could have a material and adverse effect on our future earnings, cash flows, financial condition, or results of operations. Even if we do acquire these interests or rights, the resulting business arrangements may ultimately prove not to be beneficial.
Changes in climate conditions and regulatory regime could adversely affect our business and operations
There is significant evidence of the effects of climate change on our planet and an intensifying focus on addressing these issues. We recognize that climate change is a global challenge that may have both favorable and adverse affects on our business in a range of possible ways. Mining and uranium processing operations are energy intensive and result in a carbon footprint either directly or through the purchase of fossil-fuel based electricity. As such, we are impacted by current and emerging policy and regulation relating to green house gas emission levels, energy efficiency, and reporting of climate-change related risks. While some of the costs associated with reducing emissions may be offset by increased energy efficiency, technological innovation, or the increased demand for our uranium and conversion services, the current regulatory trend may result in additional transition costs at some of our operations. A number of government or governmental bodies have introduced or are contemplating regulatory changes in response to the potential impacts of climate change. Where legislation already exists, regulations relating to emissions levels and energy efficiency are becoming more stringent. Changes in legislation and regulation will likely increase our compliance costs.
In addition, the physical risks of climate change may also have an adverse effect at our operations. These may include shifts in temperature and precipitation as well as extreme weather events such as floods, droughts, forest and bush fires, and extreme storms. Such events may occur more frequently. These physical impacts could require us to suspend or reduce production or close operations and could prevent us from pursuing expansion opportunities. These effects may adversely impact the cost, production, and financial performance of our operations.
As mentioned above, in 2022, Cameco completed a physical risk assessment study to deliver an initial forward-looking physical climate risk assessment across our four sites in northern Saskatchewan and identify possible risk management and adaptation options. The next steps for the northern Saskatchewan physical risk assessment are to embed the physical climate risk findings into Cameco’s internal risk processes and develop an adaptation action plan for each site in the study. We are targeting the completion of similar assessments for all our majority owned and operated facilities over the next five years. In 2023, we will focus our physical climate risk assessment efforts on our Ontario operations.
We will continue to explore climate change projections for the areas where we operate and those critical to moving supplies and products through our value chain. We will use this information to identify where our existing climate-related acute and chronic risk management practices are expected to remain sufficient in the years to come and where adaptation and other enhancements may be required.
However, we can provide no assurance that efforts to mitigate the risks of climate change will be effective and that physical risks of climate change will not have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
Foreign investments and operations
We do business in countries and jurisdictions outside of Canada and the US, including the developing world. Doing business in these countries poses risks because they have different economic, cultural, regulatory, and political environments. Future economic and political conditions could also cause governments of these countries to change their policies on foreign investments, development and ownership of resources, or impose other restrictions, limitations or requirements that we may not foresee today.
Risks related to doing business in a foreign country can include:
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| • | uncertain legal, political, and economic environments |
|---|---|
| • | strong governmental control and regulation |
| --- | --- |
| • | lack of an independent judiciary |
| --- | --- |
| • | war, terrorism, and civil disturbances (including the ongoing conflict between Russia and Ukraine) |
| --- | --- |
| • | crime, corruption, making improper payments or providing benefits that may violate Canadian or US law or laws relating to foreign corrupt practices |
| --- | --- |
| • | unexpected changes in governments and regulatory officials |
| --- | --- |
| • | uncertainty or disputes as to the authority of regulatory officials |
| --- | --- |
| • | changes in a country’s laws or policies, including those related to mineral tenure, mining, imports, exports, tax, duties, and currency |
| --- | --- |
| • | cancellation or renegotiation of permits or contracts |
| --- | --- |
| • | exposure to global public health issues (for example, an outbreak of illness like COVID-19) |
| --- | --- |
| • | disruption in transportation between jurisdictions |
| --- | --- |
| • | royalty and tax increases or other claims by government entities, including retroactive claims |
| --- | --- |
| • | expropriation and nationalization |
| --- | --- |
| • | delays in obtaining necessary permits or inability to obtain or maintain them |
| --- | --- |
| • | currency fluctuations |
| --- | --- |
| • | high inflation |
| --- | --- |
| • | joint venture participants falling out of political favour |
| --- | --- |
| • | restrictions on local operating companies selling their production offshore |
| --- | --- |
| • | exchange or capital controls, including restrictions on local operating companies holding US dollars or other foreign currencies in offshore bank accounts |
| --- | --- |
| • | import and export regulations, including restrictions on the export of uranium |
| --- | --- |
| • | limitations on the repatriation of earnings |
| --- | --- |
| • | exposure to different employment practices and labour laws |
| --- | --- |
| • | increased financing costs |
| --- | --- |
If one or more of these risks occur, it could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
We also risk being at a competitive disadvantage to companies from countries that are not subject to Canadian or US law or laws relating to foreign corrupt practices.
We enter joint venture arrangements with local participants from time to time to mitigate political risk. There is no assurance that these joint ventures will mitigate our political risk in a foreign jurisdiction.
We do not have political risk insurance for our foreign investments, including our investment in JV Inkai.
Kazakhstan
Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our investment in JV Inkai is subject to the greater risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal, and fiscal instability. Kazakhstan laws and regulations are complex and still developing and their application can be difficult to predict. The other owner of JV Inkai is KAP, an entity majority owned by the government of Kazakhstan. We have entered into agreements with JV Inkai and KAP intended to mitigate political risk. Among other things, this risk includes the imposition of governmental laws or policies that could restrict or hinder JV Inkai paying us dividends, or selling us our share of JV Inkai production, or that impose discriminatory taxes or currency controls on these transactions. The restructuring of JV Inkai, which took effect January 1, 2018, was undertaken with the objective to better align the interests of Cameco and KAP and includes a governance framework that provides for protection for us as a minority owner of JV Inkai. There can be no assurance we will be successful in managing this risk.
Complex legal regime
JV Inkai has a contract with the Kazakhstan government and was granted licences to conduct mining and exploration activities at Inkai. The licensing regime has long been abolished but licences issued before such abolishment remain valid. JV Inkai’s ability to conduct these activities, however, depends on the regulator’s view on whether its licences are still valid and other government approvals being granted.
To maintain and increase production at Inkai, JV Inkai needs ongoing support, agreement, and co-operation from KAP and from the Kazakhstan government. Kazakhstan foreign investment, environmental and mining laws and regulations are complex and still developing, so it can be difficult to predict how they will be applied. JV Inkai’s best efforts may therefore not always reflect full compliance with the law, and non-compliance can lead to an outcome that is disproportionate to the nature of the breach.
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Subsoil law
Amendments to the old subsoil law in 2007 allow the government to reopen resource use contracts in certain circumstances, and in 2009, the Kazakhstan government passed a resolution that classified 231 blocks, including Inkai’s blocks, as strategic deposits. The Kazakhstan government re-approved this list in 2011 and in 2018 and Inkai’s blocks remain on it. These actions may increase the government’s ability to expropriate JV Inkai’s properties in certain situations. In 2009, at the request of the Kazakhstan government, JV Inkai amended the resource use contract to adopt a new tax code, even though the government had agreed to tax stabilization provisions in the original contract.
The previous subsoil use law which went into effect in 2010 weakened the stabilization guarantee of the prior law and the current subsoil code contains a significant number of provisions which apply retrospectively. These developments reflect increased political risk in Kazakhstan.
Nationalization
Industries like mineral production are regarded as nationally or strategically important, but there is no assurance they will not be expropriated or nationalized. Government policy can change to discourage foreign investment and nationalize mineral production, or the government can implement new limitations, restrictions, or requirements.
There is no assurance that our investment in Kazakhstan will not be nationalized, taken over or confiscated by any authority or body, whether the action is legitimate or not. While there are provisions for compensation and reimbursement of losses to investors under these circumstances, there is no assurance that these provisions would restore the value of our original investment or fully compensate us for the investment loss. This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
Government regulations
Our investment in Kazakhstan may be affected in varying degrees by government regulations restricting production, price controls, export controls, currency controls, taxes and royalties, expropriation of property, environmental, mining and safety legislation, and annual fees to maintain mineral properties in good standing. Kazakhstan regulatory authorities exercise considerable discretion in the interpretation and enforcement of local laws and regulations. At times, authorities use this discretion to enforce rights in a manner that is inconsistent with relevant legislation, particularly with respect to licence issuance, renewal, and compliance. Requirements imposed by regulatory authorities may be costly and time-consuming and may result in delays in the commencement, continuation, or expansion of production operations. Regulatory authorities may impose more onerous requirements and obligations than those currently in effect.
There is no assurance that the laws in Kazakhstan which provide protection to investments, including foreign investments, will not be amended, or abolished, or that these existing laws will be enforced or interpreted to provide adequate protection against any or all of the risks described above. There is also no assurance that the resource use contract can be enforced or will provide adequate protection against any or all the risks described above.
See pages 62 to 65 for a more detailed discussion of the regulatory and political environment in Kazakhstan.
Presidential succession and recent instability
The President of Kazakhstan, Nursultan Nazarbayev, was in office since Kazakhstan became an independent republic in 1991 until he resigned on March 20, 2019. He was succeeded by Kassym-Jomart Tokayev. Subsequently Kazakhstan began to experience some instability.
In early January 2022, Kazakhstan saw the most significant instability since it became independent in 1991. The events resulted in a state of emergency being declared across the country. With the assistance of the Collective Security Treaty Organization (CSTO), the government restored order and in the second half of January, the state of emergency was gradually lifted and withdrawal of CSTO forces from Kazakhstan was completed. The early outcome of those events was a number of political and economic reforms declared by the government. While the exact impact of those reforms is unclear, they could potentially impact JV Inkai’s operations and costs. In November 2022, President Tokayev was re-elected for a new 7-year term.
There is considerable uncertainty regarding the future political and economic landscape in Kazakhstan, which could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
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Australia
Western Australian Government’s uranium policy
State governments in Australia have prohibited uranium mining or uranium exploration from time to time. From 2002 to 2008, uranium mining was banned in Western Australia, where our Kintyre and Yeelirrie projects are located. In 2017, the Western Australian state government announced a ban on the grant of future uranium mining leases and that it would not prevent the progress of four uranium projects that had received approval from the previous government, two of the approved projects being Kintyre and Yeelirrie.
The approval received for Kintyre from the prior state government required substantial commencement of the project by March 2020, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future, we can apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Kintyre project, provided we have all other required regulatory approvals.
The approval received for Yeelirrie project from the prior state government required substantial commencement of the project by January 2022, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future we can again apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Yeelirrie project, provided we have all other required regulatory approvals. Approval for the Yeelirrie project at the federal level was granted in 2019 and extends until 2043.
A prohibition or restriction on uranium exploration or mining in the future that interferes with the development of Kintyre or Yeelirrie could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations, or prospects.
Conflict inUkraine
On February 24, 2022, Russia commenced a military invasion of Ukraine. In response, many jurisdictions have imposed strict economic sanctions against Russia, including Canada, the United States, the European Union, the United Kingdom, and others. Currently, the global nuclear industry relies on Russia for approximately 14% of its supply of uranium concentrates, 27% of conversion supply and 39% of enrichment capacity. With continued conflict, there is ongoing uncertainty about the ability to continue to rely on nuclear fuel supplies coming out of Russia or that ship through Russian ports. The geopolitical situation continues to cause transportation risks in Central Asia, which impacted our shipments of finished JV Inkai product in 2022 and we may continue to experience delays in our expected deliveries from 2022 and for 2023. Our 2022 share of earnings from JV Inkai were impacted due to delays to the delivery of our share of 2022 production. See Uranium – Tier-one operations – Inkai and Operational risks – Transportation.
Our business has been and may continue be impacted by the ongoing conflict between Russia and Ukraine and the related economic sanctions.
In February 2023, we announced that we had reached agreement on commercial terms for a major supply contract with Energoatom, Ukraine’s state-owned nuclear energy utility, including an option supply up to 100% of the fuel requirements for the six reactors at the Zaporizhzhya nuclear power plant, currently under Russian control, should it return to Energoatom’s operation. See MajorDevelopments – Agreement on Key Supply Terms with Energoatom. The military conflict between Russia and Ukraine may have a negative impact on this supply contract, which could have a material and adverse effect on our earnings, cash flow, financial condition, result of operations, or prospects.
The military conflict between Russia and Ukraine has had and continues to have a negative impact on Westinghouse’s operations in Ukraine, resulting in the loss of revenue and the corresponding loss of earnings, See Strategic risks – Proposed acquisition of Westinghouse risks – A future major nuclear accident or disaster couldhave a negative effect on our and Westinghouse’s operations.
As we have from time to time purchased uranium enrichment services from a Russia-based entity in order to sell enriched uranium directly to customers, we may be required to purchase such enrichment services from other suppliers. Cameco infrequently purchases these services, as the majority of our customers work directly with their own enrichment services providers. In addition, our customer contracts may require deliveries of uranium to areas that are directly affected by the ongoing conflict and the related economic sanctions. These deliveries may need to be adjusted in consideration of the ongoing conflict and/or to comply with applicable sanctions.
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The ongoing conflict and economic sanctions may also give rise to additional indirect impacts, including increased fuel prices, supply chain challenges, logistics and transport disruptions and heightened cybersecurity disruptions and threats. Increased fuel prices and ongoing volatility of such prices may have adverse impacts on our costs of doing business.
We have not yet been materially affected by the current conflict and economic sanctions, but there remains significant uncertainty surrounding the outcome of the ongoing conflict, future economic sanctions, our contractual arrangements with Energoatom and shipments of our share of finished JV product. We will continue to monitor the potential impacts on our business as the situation develops.
Proposed acquisition of Westinghouse risks
Delay or failure to complete the acquisition
The acquisition of Westinghouse may be delayed or may not be completed on the terms contemplated in the acquisition agreement or at all. No assurance can be given that the acquisition will be completed when expected, on the terms proposed or at all. Closing of the acquisition is subject to the receipt of required regulatory approvals and the satisfaction of various closing conditions. There is no certainty, nor can we provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied.
Given a potentially long period prior to closing the acquisition, there can be no assurance that Westinghouse or its operations and assets will not be adversely affected by intervening events before the closing of the acquisition. The relevant regulatory authorities may decline to give approval or clearance for the acquisition, or may attach terms or conditions to their approval or clearance, which could have a material adverse effect on our ability to realize any or all of the anticipated benefits of, or complete, the acquisition.
If the acquisition is not completed, we could be subject to a number of risks that may adversely affect our business and the market price of our common shares, including:
| • | the time and resources committed by our management to matters relating to the acquisition could otherwise have<br>been devoted to pursuing other beneficial opportunities; |
|---|---|
| • | the market price of our common shares could decline to the extent that the current market price reflects a market<br>assumption that the acquisition will be completed; |
| --- | --- |
| • | we would not realize any or all of the benefits we expect to realize from completing the acquisition; and<br> |
| --- | --- |
| • | we will be required to pay costs relating to the acquisition, such as legal, accounting, and financial advisory<br>fees, whether or not the acquisition is completed. |
| --- | --- |
We may also be subject to litigation related to any failure to complete the acquisition. If the acquisition is not completed, these risks may materialize and may adversely affect our business, financial results, and financial condition, as well as the price of our common shares, which may cause the value of an investment in our common shares to decline.
No financing condition in the acquisition agreement
There exists no closing condition for financing under the acquisition agreement that we can rely on to terminate the acquisition agreement. As a result, if our new credit facilities to finance the acquisition were not available, we would remain obligated to complete the acquisition and may not have sufficient funds to do so or may have to incur additional costs to do so, which could result in a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.
Completion of the acquisition is subject to thesatisfaction of closing conditions and regulatory approvals
The acquisition closing is subject to certain closing conditions that may not be satisfied or completed on a timely basis, if at all, which may prevent or delay the consummation of the acquisition. Any delay in completing the acquisition may reduce or eliminate the expected benefits of the acquisition. These, include, among other things:
| • | the receipt of certain approvals under applicable antitrust laws and foreign investment laws;<br> |
|---|---|
| • | the receipt of required national security clearances; |
| --- | --- |
| • | the conclusion of the applicable notice period under the International Traffic in Arms Regulations or receipt of<br>the consent of the US Department of State, Directorate of Defense Trade Controls; and |
| --- | --- |
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| • | the filing of certain other applications and notices with, and receipt of the approvals, licences or consents<br>from, other applicable governmental authorities. |
|---|
We cannot provide any assurance that all necessary regulatory and other approvals will be obtained nor the timing of such approvals, nor can we provide any assurance that all of the other closing conditions will be satisfied or waived. The failure to obtain necessary approvals or the failure to satisfy some or all of the other required conditions could delay the acquisition closing for a significant period of time or prevent it from occurring. Lawsuits or other legal proceedings brought in connection with the acquisition could also delay or prevent the acquisition closing, and may cause us to incur additional costs and divert management’s attention from the acquisition process and our core business operations. Any delay in obtaining the required approvals or satisfying the other closing conditions could reduce or eliminate the anticipated benefits of the acquisition, or prevent the acquisition closing from occurring at all.
Failure to realize any orall of the anticipated benefits from the acquisition
Following the acquisition, we expect to see certain near-term benefits, including potential new revenue opportunities related to integrated fuel supply and improved access for uranium and conversion services, as well as longer-term opportunities for growth from new capacity.
Any benefits and growth that we realize from such efforts may differ materially from our estimates. In particular, our estimates of the potential benefits and growth from the acquisition are based in part on a valuation of Westinghouse that may differ from the performance of Westinghouse in the future.
In addition, any benefits that we realize may be offset, in whole or in part, by reductions in revenues, or through increases in other expenses, including costs to achieve our estimated synergies and growth. Our plans for Westinghouse following the acquisition are subject to numerous risks and uncertainties that may change at any time.
We cannot provide any assurance that our initiatives will be completed as anticipated or that the benefits we expect will be achieved on a timely basis or at all. Even if the acquisition is completed, it may take longer than expected to achieve the anticipated benefits and growth.
Failure to comply with nuclear licence and quality assurance requirements at certain Westinghouse facilities could result in costs, additional regulatoryoversight and reputational risk
Westinghouse is a supplier of nuclear reactors, components, fuel and fuel handling equipment, maintenance and operating support services, and dismantling and decontamination services to the global nuclear power sector. Westinghouse and its affiliates maintain licences from nuclear regulatory authorities in the United States, United Kingdom, Sweden, and Spain to operate fuel fabrication facilities. These facilities are subject to significant regulatory scrutiny and any failure to comply with safety, security and quality assurances requirements at those facilities could result in increased regulatory oversight and civil penalties, as well as costs in remedying noncompliance and reputational risk.
In addition, enhanced safety or security requirements promulgated by these regulatory bodies could necessitate capital expenditures by Westinghouse. Significant non-compliance could result in revocation of certain of Westinghouse’s licenses.
Further, Westinghouse operates major nuclear component fabrication facilities in the United States and Italy. Components fabricated by Westinghouse at these facilities must comply with stringent quality requirements, including certifications under nuclear quality standards. Failure to adhere to these standards could result in liability under customer contracts, including replacement of supplied components and potential exposure to litigation over nuclear power plant shutdowns resulting from defective components. Quality control issues at these facilities could also result in additional regulatory oversight and costs arising out of implementation of corrective actions. Any such adverse effects would negatively impact the acquisition and may adversely affect our business, financial results, and financial condition, as well as the price of our common shares.
Westinghouse’s comprehensive protections against liability for nuclear damage depend on the viability of global indemnities and continuation ofnuclear liability regimes
Global nuclear liability regimes shield nuclear industry participants from unlimited exposure to nuclear accident risks and ensure compensation for victims of nuclear incidents. The US regime, based on the Price-Anderson Nuclear Industries Indemnity Act, as amended, provides for “economic channeling” of liability by establishing requirements for nuclear reactor operators to maintain two layers of insurance (totaling approximately $14 billion (US)), which cover anyone potentially liable,
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including suppliers, for nuclear damage. International global nuclear liability regimes under the 1963 Vienna Convention on Civil Liability, as amended by the 1997 Protocol; the Paris Convention on Third Party Liability in the Field of Nuclear Energy and the Brussels Supplementary Convention; and the 1997 Convention on Supplementary Compensation for Nuclear Damage provide for legal channeling of liability to the operator of a nuclear installation.
While these nuclear liability regimes shield nuclear suppliers and service providers from nuclear damage in the specific jurisdiction in which a nuclear incident occurs, radioactive releases can be transboundary, and there is no single global nuclear liability regime. Only approximately 70 countries are party to an existing liability regime, and not all the regimes are interconnected. This exposes suppliers to potential liability in jurisdictions not party to a nuclear liability regime. In addition, nuclear liability regimes cover only offsite nuclear damage and do not apply to property damage to the plant itself or any equipment onsite, which typically is covered by separate insurance maintained by nuclear operators.
To address these gaps, Westinghouse obtains from its customers global indemnities against nuclear damage as well as waivers of any onsite property damage. However, should an existing nuclear liability regime be repealed in any country, should any such indemnity be insufficient or should a customer become unable to act on an indemnity due to a bankruptcy or other financial hardship, Westinghouse could be exposed to claims in the event of a nuclear incident.
Westinghouse operates in a politically sensitive environment, and the public perception of nuclear energy can affect Westinghouse’s customers andWestinghouse
Westinghouse’s business involves providing products and services for the nuclear industry, which is a politically sensitive environment. Opposition by third parties to particular projects, including in connection with any incident involving the potential discharge of radioactive materials, could affect Westinghouse and its customers’ businesses. Adverse public reaction could also lead to increased regulation, limitations on the activities of Westinghouse and Westinghouse’s customers, more onerous operating requirements or other conditions that could have a material adverse impact on Westinghouse and its customers.
Nuclear power plant operations are also potentially subject to disruption by a nuclear accident. A future accident at a nuclear reactor anywhere in the world could result in the shutdown of existing plants or impact the continued acceptance by the public and regulatory authorities of nuclear energy and the future prospects for nuclear generators, each of which could have a material adverse impact on Westinghouse.
Furthermore, accidents, terrorism, natural disasters or other incidents occurring at nuclear facilities or involving shipments of nuclear materials or technological changes could reduce the demand for nuclear products and services. All of these risks could adversely impact our operations and our investment in Westinghouse after the acquisition.
Threat of increased nuclear trade barriers could have an adverse impact on Westinghouse’s business
The nuclear energy industry is global and also susceptible to nuclear trade controls due to the sensitive nature of nuclear technologies, equipment and material and the importance of nuclear energy to national security. The ability of Westinghouse to conduct business globally is dependent on its ability to maintain and secure new licenses for the export of nuclear technology, equipment, and materials.
While licences are not always required, there are certain nuclear exports and destinations for those exports that are subject to stringent licensing requirements. For example, Westinghouse’s continued ability to sell services and equipment to reactors in China is dependent on its existing specific authorization under applicable law. In case of geopolitical circumstances that would result in sanctions on China, this specific authorization would be limited or terminated, negatively impacting the business.
A future major nuclearaccident or disaster could have a negative effect on our and Westinghouse’s operations
Due to their inherent materiality, major accidents in the nuclear industry, and most notably at nuclear power plants garner significant worldwide attention and spawn global public sentiment favouring more significant regulation for nuclear power generation. Westinghouse has various contracts in place with Energoatom, Ukraine’s national nuclear power company and actively carries on business in the country. The military conflict between Russia and Ukraine has had and continues to have a negative impact on Westinghouse’s operations in Ukraine, resulting in loss of revenue and corresponding loss of earnings. Furthermore, certain nuclear power plants are located in the disputed territory.
A major accident at a nuclear power plant, or a similar disaster related to the nuclear industry, including as a result of the military conflict between Russia and Ukraine, could lead to more countries adopting increasingly stringent safety regulations in
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the nuclear industry, cause public sentiment to shift more in favour of phasing-out nuclear power, and reverse or halt the recent positive trend towards nuclear power. The reaction to any such major accident or disaster could be significantly more severe, and may result in a rapid global abandonment of nuclear power generation. Any such event may result in, among other things, a significant reduction in the demand for uranium and the resulting decline in the price of uranium plus a significant reduction in demand for nuclear services or production of new power plants.
A major accident at a nuclear power plant, or a similar disaster related to the nuclear industry, could have a material and adverse effect on our and Westinghouse’s earnings, cash flows, financial condition, results of operations, and prospects.
We do not currently control Westinghouse and willnot control Westinghouse after the Acquisition is completed
We do not currently control Westinghouse and, after the closing of the acquisition, we will beneficially own 49% of Westinghouse, and Brookfield Renewable will beneficially own 51%. Until the acquisition closing, we cannot provide any assurance that Westinghouse will be operated in the same way that it would be operated under the control of us and Brookfield Renewable. Although we will have certain governance and approval rights in connection with our ownership interest in the partnership used for the acquisition (Acquisition Partnership) following the acquisition closing, we cannot provide any assurance that Westinghouse will be operated in the same way we would operate Westinghouse if we were its sole owner.
Theliabilities of Westinghouse may exceed our estimates, and there may also be unknown or undisclosed liabilities in connection with the Acquisition
Westinghouse has various potential liabilities relating to the conduct of its business prior to the acquisition, including, but not limited to, potential liability for unfunded pension liabilities, liability for cleanup, decommissioning or remediation of environmental conditions, intellectual property disputes, and other potential liabilities that could adversely affect Westinghouse’s financial position. If the acquisition is completed, these potential liabilities could negatively impact the value of our investment in the Acquisition Partnership. Although we have conducted what we believe to be a sufficient level of investigation in connection with the acquisition, it is possible that the potential liabilities we have identified may exceed our expectations, and there may be liabilities that we failed to discover or were unable to quantify accurately or at all in our due diligence, which we conducted prior to the entry into the acquisition agreement. Only certain of these events may entitle the purchaser to recourse under the acquisition agreement for such liabilities and contingencies. The discovery of any material liabilities, or the inability to obtain full recourse for such liabilities, could have a material adverse effect on our investment in the Acquisition Partnership and our ability to realize the benefits of the proposed acquisition.
In connection with the acquisition, the Acquisition Partnership and the general partner (each an Acquisition Entity) obtained representation and warranty coverage, with total limits of up to $800 million (US) above retention of 0.5% of the enterprise value. Nevertheless, this insurance policy is subject to certain exclusions and limitations. In addition, there may be circumstances for which the insurer may elect to limit such coverage or refuse to indemnify us or situations for which the coverage provided under the representation and warranty insurance policy may not be sufficient or applicable.
Certain defaults under specified Westinghouse credit facilities or an event of default under the Westinghouse credit facilities could result in the failureto complete the acquisition
Westinghouse has entered into various credit agreements with its lenders, pursuant to which it has incurred approximately $4.6 billion (US) in principal amount of indebtedness in the aggregate. A breach of certain covenants in the credit agreements governing Westinghouse’s credit facilities, or the occurrence of certain events, including certain change of control triggering events, may constitute an event of default. The closing of the acquisition is conditioned upon the absence of certain defaults under specified credit facilities of Westinghouse and its affiliates. The failure to satisfy any such condition could result in the failure to complete the acquisition, which could have a material adverse effect on Westinghouse.
If an event of default exists under Westinghouse’s credit facilities, the lenders could declare all amounts outstanding thereunder to be immediately due and payable and foreclose on any pledged collateral. Westinghouse may not have access to sufficient funds at the time of any such acceleration to repay outstanding amounts under the credit agreements, or may be subject to contractual restrictions that may prohibit such repayments. This could have a material adverse effect on Westinghouse’s financial condition and on the Acquisition Partnership.
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Westinghouse’s operations are exposed to occupational health and safety and accident risks
Some of the tasks undertaken by Westinghouse’s employees and contractors are inherently dangerous and have the potential to result in serious injury or death. Accordingly, Westinghouse’s operations are exposed to the risk of accidents that may give rise to personal injury, loss of life, disruption to service and economic loss, including, for example, resulting from related litigation.
Westinghouse is subject to increasingly stringent laws and regulations governing health and safety matters, which differ in the jurisdictions in which Westinghouse operates. Any violation of these obligations, or serious accidents involving Westinghouse’s employees, contractors or members of the public, could expose Westinghouse or its operating businesses to adverse regulatory consequences, including the forfeiture or suspension of its operating licences, potential litigation, claims for material financial compensation, reputational damage, fines or other legislative sanctions, which may materially and adversely impact Westinghouse’s financial condition.
Risks to our business associated with entry into the strategic partnership with Brookfield Renewable
Although we have certain rights pursuant to a shareholders’ agreement between us and Brookfield Renewable with regards to the governance of the Acquisition Partnership general partner, including the right to designate directors of the boards of directors of the general partner and certain material subsidiaries of the Acquisition Entities, our beneficial ownership in the strategic partnership entities will be 49%, whereas Brookfield Renewable will beneficially own 51%, and the directors are entitled to weighted voting corresponding to the designating shareholder’s proportionate equity interest. Consequently, other than in the case of certain reserved matters expressly set out in the governance agreement, Brookfield Renewable has the power to control the strategic partnership entities. Accordingly, we cannot provide any assurance that the strategic partnership entities will be operated in the same way they would have been operated if we were the sole owner.
Following the acquisition closing, we expect that the strategic partnership entities will, to the greatest extent possible, be funded by their own cash flows and third-party funding. Pursuant to the governance agreement, to the extent a strategic partnership entity requires additional capital to meet a funding shortfall for certain approved activities, if approved as a reserved matter, the Acquisition Partnership may make equity funding requests to us and Brookfield Renewable, on a pro rata basis on the basis of our and Brookfield Renewable’s respective equity interests in the Acquisition Entities. Failure by us to meet such an equity funding request would not constitute a default under the governance agreement, but in the event that Brookfield Renewable elects to participate in the equity financing and we do not, our interest in the Acquisition Partnership may be diluted. There can be no assurance that we or Brookfield Renewable will have the necessary capital resources to meet an equity funding request if and when made by the Acquisition Partnership. In the event that the Acquisition Partnership cannot raise the necessary funds from us or Brookfield Renewable or otherwise obtain adequate required capital on favorable terms or at all, it may be required to scale back or entirely halt any operating or expansion plans and its business, financial condition and results of operations could be adversely affected.
Further, disputes may arise between us and Brookfield Renewable that may adversely affect the success of the strategic partnership entities and have a material adverse effect on our business, results of operations and financial performance. Our failure to otherwise comply with our obligations under the governance agreement may result in us being in default under the governance agreement and could result in us losing some or all of our interest in the Acquisition Partnership.
Legal proceedings
We discuss any legal proceedings that we or our subsidiaries are a party, as at December 31, 2022, in note 22 to the 2022 financial statements.
We are currently involved in a dispute with CRA. See Transfer pricing dispute at page 93 for more details about this dispute.
Investor information
Share capital
Our authorized share capital consists of:
| • | first preferred shares |
|---|
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| • | second preferred shares |
|---|---|
| • | common shares |
| --- | --- |
| • | one class B share |
| --- | --- |
Preferred shares
We do not currently have any preferred shares outstanding, but we can issue an unlimited number of first preferred or second preferred shares with no nominal or par value, in one or more series. The board must approve the number of shares, and the designation, rights, privileges, restrictions and conditions attached to each series of first or second preferred shares.
Preferred shares can carry voting rights, and they rank ahead of common shares and the class B share for receiving dividends and distributing assets if the company is liquidated, dissolved or wound up.
Firstpreferred shares
Each series of first preferred shares ranks equally with the shares of other series of first preferred shares. First preferred shares rank ahead of second preferred shares, common shares and the class B share.
Second preferred shares
Each series of second preferred shares ranks equally with the shares of other series of second preferred shares. Second preferred shares rank after first preferred shares and ahead of common shares and the class B share.
Common shares
We can issue an unlimited number of common shares with no nominal or par value. Only holders of common shares have full voting rights in Cameco.
If you hold our common shares, you are entitled to vote on all matters that are to be voted on at any shareholder meeting, other than meetings that are only for holders of another class or series of shares. Each Cameco share you own represents one vote, except where noted below. As a holder of common shares, you are also entitled to receive any dividends that are declared by our board of directors.
Common shares rank after preferred shares with respect to the payment of dividends and the distribution of assets if the company is liquidated, dissolved or wound up, or any other distribution of our assets among our shareholders if we were to wind up our affairs.
Holders of our common shares have no pre-emptive, redemption, purchase or conversion rights for these shares. Except as described under Ownership and voting restrictions, non-residents of Canada who hold common shares have the same rights as shareholders who are residents of Canada.
On December 31, 2022, we had 432,518,470 common shares outstanding. These were fully paid and non-assessable.
On February 28, 2023, there were 2,553,854 stock options outstanding to acquire common shares of Cameco under the company’s stock option plan with exercise prices ranging from $11.32 to $16.38.
In 2022 and 2023, no stock options were granted.
Our articles of incorporation have provisions that restrict the issue, transfer, and ownership of voting securities of Cameco (see Ownership and voting restrictions below).
Class B shares
The province of Saskatchewan holds our one class B share outstanding. It is fully paid and non-assessable.
The one class B share entitles the province to receive notices of and attend all meetings of shareholders, for any class or series.
The class B shareholder can only vote at a meeting of class B shareholders, and only as a class if there is a proposal to:
| • | amend Part 1 of Schedule B of the articles, which states that: |
|---|---|
| • | Cameco’s registered office and head office operations must be in Saskatchewan |
| --- | --- |
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| • | the vice-chair of the board, chief executive officer (CEO), president, chief financial officer (CFO) and<br>generally all of the senior officers (vice-presidents and above) must live in Saskatchewan |
|---|---|
| • | all annual meetings of shareholders must be held in Saskatchewan |
| --- | --- |
| • | amalgamation, if it would require an amendment to Part 1 of Schedule B of the articles, or |
| --- | --- |
| • | an amendment to the articles in a way that would change the rights of class B shareholders |
| --- | --- |
The class B shareholder can request and receive information from us to determine whether or not we are complying with Part 1 of Schedule B of the articles.
The class B shareholder does not have the right to receive any dividends declared by Cameco. The class B share ranks after first and second preferred shares, but equally with common shareholders, with respect to the distribution of assets if the company is liquidated, dissolved or wound up. The class B shareholder has no pre-emptive, redemption, purchase or conversion rights with its class B share, and the share cannot be transferred.
Ownership and voting restrictions
The federal government established ownership restrictions when Cameco was formed so we would remain Canadian controlled. There are restrictions on issuing, transferring, and owning Cameco common shares whether you own the shares as a registered shareholder, hold them beneficially or control your investment interest in Cameco directly or indirectly. These are described in the Eldorado Nuclear LimitedReorganization and Divestiture Act (Canada) (ENL Reorganization Act) and our company articles.
The following is a summary of the restrictions listed in our company articles.
Residents
A Canadian resident, either individually or together with associates, cannot hold, beneficially own or control shares or other Cameco securities, directly or indirectly, representing more than 25% of the votes that can be cast to elect directors.
Non-residents
A non-resident of Canada, either individually or together with associates, cannot hold, beneficially own or control shares or other Cameco securities, directly or indirectly, representing more than 15% of the total votes that can be cast to elect directors.
Voting restrictions
All votes cast at the meeting by non-residents, either beneficially or controlled directly or indirectly, will be counted and pro-rated collectively to limit the proportion of votes cast by non-residents to no more than 25% of the total shareholder votes cast at the meeting.
We limit the counting of votes by non-residents of Canada at our annual meeting of shareholders to abide by this restriction. This has resulted in non-residents receiving less than one vote per share.
Enforcement
The company articles allow us to enforce the ownership and voting restrictions by:
| • | suspending voting rights |
|---|---|
| • | forfeiting dividends and other distributions |
| --- | --- |
| • | prohibiting the issue and transfer of Cameco shares |
| --- | --- |
| • | requiring the sale or disposition of Cameco shares |
| --- | --- |
| • | suspending all other shareholder rights. |
| --- | --- |
To verify compliance with restrictions on ownership and voting of Cameco shares, we require existing shareholders, proposed transferees or other subscribers for voting shares to declare their residency, ownership of Cameco shares and other things relating to the restrictions. Nominees such as banks, trust companies, securities brokers or other financial institutions who hold the shares on behalf of beneficial shareholders need to make the declaration on their behalf.
We cannot issue or register a transfer of any voting shares if it would result in a contravention of the resident or non-resident ownership restrictions.
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If we believe there is a contravention of our ownership restrictions based on any shareholder declarations filed with us, or our books and records or those of our registrar and transfer agent or otherwise, we can suspend all shareholder rights for the securities they hold, other than the right to transfer them. We can only do this after giving the shareholder 30 days’ notice, unless he or she has disposed of the holdings, and we have been advised of this.
Understanding the terms
Please see our articles for the exact definitions of associate, resident, non-resident, control, and beneficial ownership which are used for the restrictions described above.
Other restrictions
The ENL Reorganization Act imposes some additional restrictions on Cameco. We must maintain our registered office and our head office operations in Saskatchewan. We are also prohibited from:
| • | creating restricted shares (these are generally defined as a participating share with restrictive voting rights)<br> |
|---|---|
| • | applying for continuance in another jurisdiction |
| --- | --- |
| • | enacting articles of incorporation or bylaws that have provisions that are inconsistent with the ENL<br>Reorganization Act |
| --- | --- |
We must maintain our registered office and head office operations in Saskatchewan under the Saskatchewan MiningDevelopment Corporation Reorganization Act. This generally includes all executive, corporate planning, senior management, administrative and general management functions.
Credit ratings
Credit ratings provide an independent, professional assessment of a corporation’s credit risk. They are not a comment on the market price of a security or suitability for an individual investor and are, therefore, not recommendations to buy, hold or sell our securities.
We provide rating agencies DBRS Limited (DBRS) and Standard & Poor’s (S&P) with confidential information to support the credit rating process.
The credit ratings assigned to our securities by external ratings agencies are important to our ability to raise capital at competitive pricing to support our business operations and execute our strategy.
We have three series of senior unsecured debentures outstanding:
| • | $100 million of debentures issued on November 14, 2012, that have an interest rate of 5.09% per year<br>and mature on November 14, 2042 |
|---|---|
| • | $500 million of debentures issued on June 24, 2014, that have an interest rate of 4.19% per year and<br>mature on June 24, 2024 |
| --- | --- |
| • | $400 million of debentures issued on October 21, 2020, that have an interest rate of 2.95% per year and<br>mature on October 21, 2027 |
| --- | --- |
We have a commercial paper program which is supported by a $1 billion unsecured revolving credit facility that matures October 1, 2026. As of December 31, 2022, there were no amounts outstanding under the commercial paper facility.
The table below shows the current DBRS and S&P ratings and the rating trends/outlooks of our commercial paper and senior unsecured debentures:
| Rating Agency | Rating | Rating Trend/Outlook |
|---|---|---|
| Commercial paper | ||
| DBRS | R-2 (middle) | Stable |
| S&P | A-3 | Stable |
| Senior Unsecured Debentures | ||
| DBRS | BBB | Stable |
| S&P | BBB- | Stable |
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The rating agencies may revise or withdraw these ratings at any time if they believe circumstances warrant. The rating trend/outlook represents the ratings agency’s assessment of the likelihood and direction that the rating could change in the future.
A change in our credit ratings could affect our cost of funding and our access to capital through the capital markets.
On May 28, 2020, DBRS changed Cameco’s rating outlook to stable from negative. The change was based on the improving outlook for the uranium industry, including the uranium price increases in 2020. On May 26, 2021 and May 27, 2022, DBRS confirmed the rating and the outlook. Currently our rating is under review following the announcement of the proposed acquisition of Westinghouse.
On February 16, 2022, S&P revised its outlook for Cameco to stable from negative and affirmed the BBB- rating. The outlook reflected the estimated improvement in profitability and credit measures, with an expected reduction in unit costs based on expanded uranium output with the restart of McArthur River/Key Lake and relatively favourable prices.
Commercial paper
Rating scales for commercial paper are meant to indicate the risk that a borrower will not fulfill its near-term debt obligations in a timely manner.
The table below explains the credit ratings of our commercial paper in more detail:
| Rating | Ranking | |
|---|---|---|
| DBRS<br><br><br>rates commercial paper by categories ranging from a high of R-1 to a low of D | R-2 (Middle) | • middle of the R-2 category<br><br><br><br> <br>• represents “adequate<br>credit quality”<br> <br><br><br><br>• fifth highest of 10 available credit rating categories |
| S&P<br><br><br>rates commercial paper by categories ranging from a high of A-1 (high) to a low of D | A-3 | • represents “adequate protection parameters”<br><br><br><br> <br>• third highest of six<br>available credit rating categories |
Senior unsecured debentures
Long-term debt rating scales are meant to indicate the risk that a borrower will not fulfill its full obligations, with respect to interest and principal, in a timely manner.
The table below explains the credit ratings of our senior unsecured debentures in more detail:
| Rating | Ranking | |
|---|---|---|
| DBRS<br><br><br>rates senior unsecured debentures by categories ranging from a high **** of AAA to a low of D | BBB | • middle of the BBB category<br><br><br><br> <br>• represents “adequate<br>credit quality”<br> <br><br><br><br>• fourth highest of eight available credit rating categories<br><br><br>• capacity for the payment of financial obligations is considered acceptable<br><br><br><br> <br>• may be vulnerable to future<br>economic events |
| S&P<br><br><br>rates senior unsecured debentures by categories ranging from a high of AAA to a low of D | BBB- | • the lower end of the BBB category<br><br><br><br> <br>• exhibits “adequate<br>protection parameters”<br> <br><br><br><br>• fourth highest of 10 available credit rating categories<br><br><br><br> <br>• adverse economic conditions<br>or changing circumstances are more likely to lead to a weakened capacity to meet financial commitments |
Payments to credit rating agencies
Over the last two years, we paid $1,354,000 in connection with credit ratings related services.
Material contracts
Below is a list of material contracts entered into and still in effect, which have been filed on SEDAR in accordance with National Instrument 51-102 Continuous Disclosure requirements:
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Supplemental indentures
We entered into the Sixth supplemental indenture with CIBC Mellon on November 14, 2012, relating to the issue of $100 million in unsecured debentures at an interest rate of 5.09% per year and due in 2042.
We entered into the Seventh supplemental indenture with CIBC Mellon on June 24, 2014, relating to the issue of $500 million in unsecured debentures at an interest rate of 4.19% per year and due in 2024.
We entered into the Eigh th supplemental indenture with CIBC Mellon on October 21, 2020, relating to the issue of $400 million in unsecured debentures at an interest rate of 2.95% per year and due in 2027.
We entered into the Resignation and Appointment Agreement with CIBC Mellon and BNY Trust Company of Canada on February 22, 2021, relating to resignation of CIBC Mellon as trustee and appointment of BNY as trustee under the above supplemental indentures.
See Senior unsecured debentures, above for more information about these debentures.
US trust indenture
We entered into an indenture with The Bank of New York Mellon on May 22, 2012, to set forth the general terms and provisions of debt securities. The terms of this indenture were fully described in our final short form base shelf prospectus dated December 9, 2014. We have not issued any debt securities under this indenture. The specific terms of any offering of debt securities under this indenture would be set forth in a shelf prospectus supplement.
Resource use contract
See page 61 at Resource use contract for information about this contract.
Westinghouse acquisition agreement
We entered into the equity purchase agreement with Watt New Aggregator L.P., Brookfield WEC Aggregator L.P., Brookfield Capital Partners (Bermuda) Ltd., Watt Aggregator L.P., and Brookfield Business Partners L.P. on October 11, 2022 related to the Westinghouse acquisition. See page 76 at Other nuclear fuel cycle investments – Proposed acquisition of Westinghouse for information about this contract.
Market for our securities
Our common shares are listed and traded on the Toronto Stock Exchange (TSX) (under the symbol CCO) and the New York Stock Exchange (under the symbol CCJ).
We have a registrar and transfer agent in Canada and the US for our common shares:
| Canada | TSX Trust Company <br>1 Toronto Street, Suite 1200 <br>Toronto, ON M5C 2V6 | US | American Stock Transfer & Trust Company, LLC <br>6201 15^th^ Avenue <br>Brooklyn, New York <br>United States of America 11219 |
|---|
Trading activity
The table below shows the high and low closing prices and trading volume for our common shares on the TSX in 2022.
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| 2022 | High () | Low () | Volume | |
|---|---|---|---|---|
| January | 35,990,940 | |||
| February | 37,530,335 | |||
| March | 51,576,915 | |||
| April | 33,678,991 | |||
| May | 45,800,217 | |||
| June | 33,183,435 | |||
| July | 24,109,445 | |||
| August | 28,378,477 | |||
| September | 34,560,419 | |||
| October | 44,935,332 | |||
| November | 29,558,548 | |||
| December | 24,561,360 |
All values are in US Dollars.
Dividend
In 2022, our board of directors declared a dividend of $0.12 per common share which was paid on December 15, 2022. The decision to declare an annual dividend by our board is reviewed regularly and will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.
The table below shows the dividends per common share for the last three fiscal years.
| 2022 | 2021 | 2020 | ||||
|---|---|---|---|---|---|---|
| Cash dividends | $ | 0.12 | $ | 0.08 | $ | 0.08 |
| Total dividends paid (millions) | $ | 52 | $ | 32 | $ | 32 |
Governance
Directors
| Director | Board committees | Principal occupation or employment |
|---|---|---|
| Ian Bruce<br> <br>Calgary, Alberta, Canada<br><br><br><br> <br>Director since 2012 | A member of all board committees | Corporate director as of 2010 |
| Daniel Camus<br> <br>Westmount, Québec,<br>Canada<br> <br><br> <br>Director since 2011 | Audit and finance (Chair)<br> <br>Human resources and<br>compensation | Corporate director as of 2011 |
| Don Deranger<br> <br>Prince Albert,<br>Saskatchewan, Canada<br> <br><br> <br>Director since 2009 | Nominating, corporate governance and risk<br><br><br>Safety, health and environment<br> <br>Technical | May 2013 to present – non-executive chair of the board of Points Athabasca Contracting LP, a<br>civil, earthworks and industrial contracting company<br> <br>1997 to present – Advisor to First Nations Communities |
| Catherine Gignac<br> <br>Mississauga, Ontario,<br>Canada<br> <br>Director since 2014 | Nominating, corporate governance and risk (Chair) <br>Audit and finance<br><br><br>Technical | Corporate director as of 2011 |
135
| Director | Board committees | Principal occupation or employment |
|---|---|---|
| Tim Gitzel<br> <br>Saskatoon, Saskatchewan,<br>Canada<br> <br><br> <br>Director since 2011 | None | July 2011 to present – President and Chief Executive Officer |
| Jim Gowans<br> <br>Surrey, British Columbia,<br>Canada<br> <br><br> <br>Director since 2009 | Safety, health and environment (Chair)<br> <br>Audit<br>and finance<br> <br>Technical | Corporate director as of 2018 <br>August 2019 to May 2020 – Interim president, CEO and a director of Trilogy Metals Inc.<br><br><br>January 2016 to 2018 – President and CEO of Arizona Mining Inc., an exploration and development company |
| Kathryn Jackson<br> <br>Pittsburgh,<br>Pennsylvania, USA<br> <br><br> <br>Director since 2017 | Human resources and compensation<br> <br>Nominating,<br>corporate governance and risk<br> <br>Safety, health and environment<br><br><br>Technical (Chair) | Corporate director as of 2008 |
| Don Kayne<br> <br>Delta, British Columbia,<br>Canada<br> <br><br> <br>Director since 2016 | Human resources and compensation (Chair)<br><br><br>Safety, health and environment | May 2011 to present – President and CEO of Canfor Corporation<br><br><br>September 2012 to April 2022 – Chief Executive Officer of Canfor Pulp Products Incorporated, an integrated forest products company |
| Leontine van Leeuwen-Atkins<br> <br>Calgary,<br>Alberta, Canada<br> <br><br> <br>Director since 2020 | Nominating, corporate governance and risk<br> <br>Audit<br>and finance<br> <br>Technical | Corporate director as of 2019 <br>2006 to early 2019 – Partner at KPMG Canada |
Each director is elected for a term of one year, and holds office until the next annual meeting unless he or she steps down, as required by corporate law.
Officers
| Officer | Principal occupation or employment for past fiveyears |
|---|---|
| Ian Bruce<br> <br>Chair of the Board<br><br><br>Calgary, Alberta, Canada | Corporate director as of 2010 |
| Tim Gitzel<br> <br>President and Chief Executive<br>Officer<br> <br>Saskatoon, Saskatchewan, Canada | Assumed current position July 2011 |
| Grant Isaac<br> <br>Executive Vice-President and<br>Chief Financial Officer<br> <br>Saskatoon, Saskatchewan, Canada | Assumed current position February 2023<br> <br>July<br>2011 to February 1, 2023 – Senior Vice-President and Chief Financial Officer |
| Sean Quinn<br> <br>Senior Vice-President, Chief<br>Legal Officer<br> <br>and Corporate Secretary<br> <br>Saskatoon,<br>Saskatchewan, Canada | Assumed current position April 2014 |
| Brian Reilly<br> <br>Senior Vice-President and<br>Chief Operating Officer<br> <br>Saskatoon, Saskatchewan, Canada | Assumed current position July 2017<br> <br>March to<br>June 2017 – Vice-President, Mining, Projects and Technology |
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| Officer | Principal occupation or employment for past fiveyears |
|---|---|
| Heidi Shockey<br> <br>Senior Vice-President and<br>Deputy Chief Financial Officer<br> <br>Saskatoon, Saskatchewan, Canada | Assumed current position February 2023<br> <br>April<br>2013 to February 1, 2023 – Vice-President, Controller<br> <br>October 2017 to April 2020 – Vice-President, Controller and Treasurer |
| Alice Wong<br> <br>Senior Vice-President and<br>Chief Corporate Officer<br> <br>Saskatoon, Saskatchewan, Canada | Assumed current position July 2011 |
To our knowledge, the total number of common shares that the directors and executive officers as a group either: (i) beneficially owned; or (ii) exercised direction or control over, directly or indirectly, was 763,297 as at March 15, 2023. This represents less than 1% of our outstanding common shares.
To the best of our knowledge, none of the directors, executive officers or shareholders that either: (i) beneficially owned; or (ii) exercised direction or control of, directly or indirectly, over 10% of any class of our outstanding securities, nor their associates or affiliates, have or have had within the three most recently completed financial years, any material interests in material transactions which have affected, or will materially affect, the company.
Other information about our directors and officers
None of our directors or officers, or a shareholder with significant holdings that could materially affect control of us, is or was a director or executive officer of another company in the past 10 years that:
| • | was the subject of a cease trade or similar order, or an order denying that company any exemption under<br>securities legislation, for more than 30 consecutive days while the director or executive officer held that role with the company |
|---|---|
| • | was involved in an event that resulted in the company being subject to one of the above orders after the director<br>or executive officer no longer held that role with the company |
| --- | --- |
| • | while acting in that capacity, or within a year of acting in that capacity, became bankrupt, made a proposal<br>under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that company, except<br>for: |
| --- | --- |
| • | Ian Bruce was a director of Laricina Energy Limited (Laricina), a junior oilsands private company, from 2013 to<br>December 2017. Laricina was under a Companies’ Creditors Arrangement Act (Canada) (CCAA) protection order from March 26, 2015 to February 1, 2016; and |
| --- | --- |
| • | Jim Gowans was a director of Gedex Technologies Inc. (Gedex), an Ontario-based developer of airborne geological<br>imaging technology, from 2015 to November 2019. Gedex was under a CCAA protection from August 12 to December 5, 2019. |
| --- | --- |
None of them in the past 10 years:
| • | became bankrupt |
|---|---|
| • | made a proposal under any legislation relating to bankruptcy or insolvency |
| --- | --- |
| • | has been subject to or launched any proceedings, arrangement or compromise with any creditors, or<br> |
| --- | --- |
| • | had a receiver, receiver manager or trustee appointed to hold any of their assets |
| --- | --- |
None of them has ever been subject to:
| • | penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory<br>authority or has entered into a settlement agreement with a securities regulatory authority, or |
|---|---|
| • | any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important<br>to a reasonable investor in making an investment decision |
| --- | --- |
About the audit and finance committee
Audit and finance committee charter
See appendix A for a copy of the audit and finance committee charter. You can also find a copy on our website (cameco.com/about/governance/board committees).
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Composition of the audit and finance committee
The committee is made up of five members: Daniel Camus (chair), Ian Bruce, Catherine Gignac, Jim Gowans, and Leontine van Leeuwen-Atkins. Each member is independent and financially literate using criteria that meet the standards of the Canadian Securities Administrators as set out in National Instrument 52-110.
Relevant education and experience
Ian Bruce, a corporate director, is the former President and CEO of Peters & Co. Limited, an independent investment dealer. He was a past member of the Expert Panel on Securities Regulation for the Minister of Finance of Canada. He currently serves on the board of one other publicly-traded company and one private company and has served as a director and audit committee member of several public companies since 1997. Mr. Bruce was a board member and chair of the Investment Industry Association of Canada. Mr. Bruce is a Fellow of the Chartered Professional Accountants (CPA) of Alberta, a recognized Specialist in Valuation under Canadian CPA rules and is a Chartered Business Valuator.
Daniel Camus is the former group chief financial officer and former head of strategy and international activities of Electricité de France SA (EDF), a France-based integrated energy operator active in the generation, distribution, transmission, supply and trading of electrical energy with international subsidiaries. He is the audit committee chair and board member of the non-governmental organization, FIND Diagnostics, located in Geneva, Switzerland and of MedAccess plc, located in London, UK . He is the former Chief Financial Officer of the humanitarian finance organization, The Global Fund to Fight AIDS, Tuberculosis and Malaria. Mr. Camus received his PhD in Economics from Sorbonne University and an MBA in finance and economics from the Institute d’Études Politiques de Paris.
Catherine Gignac, a corporate director, is a former mining equity research analyst with leading global brokerage firms. She currently serves on the board of one other publicly-traded company and served on the board of the publicly-traded company, Corvus Gold Inc., for six years and as chair of its board for five years. She has more than 30 years’ experience as a mining equity research analyst and geologist. She held senior positions with leading firms, including Merrill Lynch Canada, RBC Capital Markets, UBS Investment Bank and Dundee Capital Markets Inc. and Loewen Ondaatje McCutcheon Limited. Ms. Gignac was the principal of Catherine Gignac & Associates from 2011 to 2015.
Jim Gowans, a corporate director, is a former mining executive. He served as interim President and CEO of Trilogy Metals Inc. from 2019 to 2020, as the president and CEO of Arizona Mining Inc. from 2016 to 2018, and at Barrick Gold Corporation in various senior executive positions throughout 2014 and 2015. He has over 30 years of experience as a senior mining executive and is the past chair of the Mining Association of Canada. Mr. Gowans currently serves on the board of four other publicly-traded companies. He received his applied science degree in mineral engineering from the University of British Columbia and attended the Banff School of Advanced Management.
Leontine van Leeuwen-Atkins, a corporate director, is a former Partner with KPMG Canada, and served as a board member of KPMG Canada’s National Board of Directors until 2019. Ms. Atkins serves on the board of one other publicly-traded company and as its audit committee chair. She serves on the board of one private company as well as audit committee member. She is a Fellow of the Chartered Professional Accountants (CPA) of Alberta and holds the ICD.D designation from the Institute of Corporate Directors. She has over 30 years of experience in the global mining, power, utility and oil and gas industries, with a focus on corporate strategy. Ms. Atkins received her bachelor of business administration degree in finance from Acadia University and a master of business administration degree from Dalhousie University.
Auditors’ fees
The table below shows the fees billed by the external auditors for services in 2022 and 2021:
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| 2022() | % oftotal fees | 2021() | % oftotal fees | |||
|---|---|---|---|---|---|---|
| Audit fees | ||||||
| Cameco^1^ | 82.8 | 83.8 | ||||
| Subsidiaries^2^ | 4.7 | 6.6 | ||||
| Total audit fees | 87.5 | 90.4 | ||||
| Audit-related fees | ||||||
| Translation services^3^ | 4.8 | — | ||||
| Pensions | 1.0 | 1.3 | ||||
| Total audit-related fees | 5.8 | 1.3 | ||||
| Tax fees | ||||||
| Compliance | 0.2 | 0.7 | ||||
| Planning and advice^4^ | 4.1 | 7.6 | ||||
| Total tax fees | 4.3 | 8.3 | ||||
| All other fees | ||||||
| Other non-audit fees^5^ | 2.4 | — | ||||
| Total other non-audit fees | 2.4 | — | ||||
| Total fees | 100.0 | 100.0 |
All values are in US Dollars.
| ^1^ | Includes amounts billed for the audit of Cameco’s annual consolidated financial statements and the review<br>of interim financial statements. |
|---|---|
| ^2^ | Includes amounts billed for the audit of Cameco’s subsidiary financial statements. |
| --- | --- |
| ^3^ | Translation services for 2022 relate to the French translation of the 2021 annual financial statements and<br>MD&A, 2022 Q2 interim financial statements and MD&A, and certain sections of the September 2022 base shelf prospectus. No invoices were issued in 2021 for translation services. |
| --- | --- |
| ^4^ | Includes amounts billed for tax compliance and tax advisory services. |
| --- | --- |
| ^5^ | Includes amounts billed for Cameco’s I-4 Membership. No invoices<br>were issued in 2021. |
| --- | --- |
Approving services
The audit and finance committee must pre-approve all services the external auditors will provide to make sure they remain independent. This is according to our audit and finance committee charter and consistent with our corporate governance practices. The audit and finance committee pre-approves services up to a specific limit. If we expect the fees to exceed the limit, or the external auditors to provide new audit or non-audit services that have not been pre-approved in the past, then this must be pre-approved separately.
Any service that is not generally pre-approved must be approved by the audit and finance committee before the work is carried out, or by the committee chair, or board chair in his or her absence, as long as the proposed service is presented to the full audit and finance committee at its next meeting.
The committee has adopted a written policy that describes the procedures for implementing these principles.
Interest of experts
Our auditor is KPMG LLP, independent chartered accountants, who have audited our 2022 financial statements.
KPMG LLP are the auditors of Cameco and have confirmed with respect to Cameco that they are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and that they are independent accountants with respect to Cameco under all relevant US professional and regulatory standards.
The individuals who are qualified persons for the purposes of NI 43-101 are listed under Mineral reserves and resources on page 79 and under Technical report on pages 27, 42 and 56. As a group, they beneficially own, directly or indirectly, less than 1% of any class of the outstanding securities of Cameco and our associates and affiliates.
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Appendix A
Audit and finance committee of the Board of Directors
Mandate
Purpose
The primary purpose of the audit and finance committee (the “committee”) is to assist the board of directors (the “board”) in fulfilling its oversight responsibilities for (a) the accounting and financial reporting processes, (b) the internal controls, (c) the external auditors, including performance, qualifications, independence, and their audit of the corporation’s financial statements, (d) the performance of the corporation’s internal audit function, (e) financial matters and risk management of financial risks, (f) the corporation’s process for monitoring compliance with laws and regulations (other than environmental and safety laws) and its code of conduct and ethics, and (g) prevention and detection of fraudulent activities. The committee shall also prepare such reports as required to be prepared by it by applicable securities laws.
In addition, the committee provides an avenue for communication between each of the internal auditor, the external auditors, management, and the board. The committee shall have a clear understanding with the external auditors that they must maintain an open and transparent relationship with the committee and that the ultimate accountability of the external auditors is to the board and the committee, as representatives of the shareholders. The committee, in its capacity as a committee of the board, subject to the requirements of applicable law, is directly responsible for the appointment, compensation, retention, and oversight of the external auditors.
The committee has the authority to communicate directly with the external auditors and internal auditor.
The committee shall make regular reports to the board concerning its activities and in particular shall review with the board any issues that arise with respect to the quality or integrity of the corporation’s financial statements, the performance and independence of the external auditors, the performance of the corporation’s internal audit function, or the corporation’s process for monitoring compliance with laws and regulations other than environmental and safety laws.
Composition
The board shall appoint annually, from among its members, a committee and its chair. The committee shall consist of at least three members and shall not include any director employed by the corporation.
Each committee member will be independent pursuant to the standards for independence adopted by the board.
Each committee member shall be financially literate with at least one member having accounting or related financial expertise, using the terms defined as follows:
“Financially literate” means the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the corporation’s financial statements; and
“Accounting or related financial expertise” means the ability to analyse and interpret a full set of financial statements, including the notes attached thereto, in accordance with Canadian generally accepted accounting principles.
In addition, where possible, at least one member of the committee shall qualify as an “audit committee financial expert” within the meaning of applicable securities law.
Members of the committee may not serve on the audit and finance committees of more than three public companies (including Cameco’s) without the approval of the board.
Meetings
The committee will meet at least four times annually and as many additional times as the committee considers necessary to carry out its duties effectively. The committee will hold separate closed sessions with the external auditors, the internal auditor, the chief financial officer and other members of management at each regularly scheduled meeting.
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A majority of the members of the committee shall constitute a quorum. No business may be transacted by the committee except at a meeting of its members at which a quorum of the committee is present.
The committee may invite such officers, directors and employees of the corporation as it may see fit from time to time to attend at meetings of the committee and assist thereat in the discussion and consideration of any matter.
A meeting of the committee may be convened by the chair of the committee, a member of the committee, the external auditors, the internal auditor, the chief executive officer or the chief financial officer. The secretary, who shall be appointed by the committee, shall, upon direction of any of the foregoing, arrange a meeting of the committee. The committee shall report to the board in a timely manner with respect to each of its meetings.
Duties and responsibilities
To carry out its oversight responsibilities, the committee shall:
Financial reporting process
| 1. | Review with management and the external auditors any items of concern, any proposed changes in the selection or<br>application of major accounting policies and the reasons for the change, any identified risks and uncertainties, and any issues requiring management judgement, to the extent that the foregoing may be material to financial reporting.<br> |
|---|---|
| 2. | Consider any matter required to be communicated to the committee by the external auditors under applicable<br>generally accepted auditing standards, applicable law and listing standards, including the external auditors’ report to the committee (and management’s response thereto) on: (a) all critical accounting policies and practices used by<br>the corporation; (b) all material alternative accounting treatments of financial information within generally accepted accounting principles that have been discussed with management, including the ramifications of the use of such alternative<br>treatments and disclosures and the treatment preferred by the external auditors; and (c) any other material written communications between the external auditors and management. |
| --- | --- |
| 3. | Require the external auditors to present and discuss with the committee their views about the quality, not just<br>the acceptability, of the implementation of generally accepted accounting principles with particular focus on accounting estimates and judgements made by management and their selection of accounting principles. |
| --- | --- |
| 4. | Discuss with management and the external auditors (a) any accounting adjustments that were noted or<br>proposed (i.e. immaterial or otherwise) by the external auditors but were not reflected in the financial statements, (b) any material correcting adjustments that were identified by the external auditors in accordance with generally<br>accepted accounting principles or applicable law, (c) any communication reflecting a difference of opinion between the audit team and the external auditors’ national office on material auditing or accounting issues raised by the<br>engagement, and (d) any “management” or “internal control” letter issued, or proposed to be issued, by the external auditors to the corporation. |
| --- | --- |
| 5. | Discuss with management and the external auditors any significant financial reporting issues considered during<br>the fiscal period and the method of resolution. Resolve disagreements between management and the external auditors regarding financial reporting. |
| --- | --- |
| 6. | Review with management and the external auditors (a) any<br>off-balance sheet financing mechanisms being used by the corporation and their effect on the corporation’s financial statements and (b) the effect of regulatory and accounting initiatives on the<br>corporation’s financial statements, including the potential impact of proposed initiatives. |
| --- | --- |
| 7. | Review with management and the external auditors and legal counsel, if necessary, any litigation, claim or<br>other contingency, including tax assessments, that could have a material effect on the financial position or operating results of the corporation, and the manner in which these matters have been disclosed or reflected in the financial statements.<br> |
| --- | --- |
| 8. | Review with the external auditors any audit problems or difficulties experienced by the external auditors in<br>performing the audit, including any restrictions or limitations imposed by management, and management’s response. Resolve any disagreements between management and the external auditors regarding these matters. |
| --- | --- |
| 9. | Review the results of the external auditors’ audit work including findings and recommendations,<br>management’s response, and any resulting changes in accounting practices or policies and the impact such changes may have on the financial statements. |
| --- | --- |
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| 10. | Review and discuss with management and the external auditors the audited annual financial statements and<br>related management discussion and analysis, make recommendations to the board with respect to approval thereof, before being released to the public, and obtain an explanation from management of all significant variances between comparable reporting<br>periods. |
|---|---|
| 11. | Review and discuss with management and the external auditors all interim unaudited financial statements and<br>related interim management discussion and analysis and make recommendations to the board with respect to the approval thereof, before being released to the public. |
| --- | --- |
| 12. | Obtain confirmation from the chief executive officer and the chief financial officer (and considering the<br>external auditors’ comments, if any, thereon) to their knowledge: |
| --- | --- |
| (a) | that the audited financial statements, together with any financial information included in the annual MD&A<br>and annual information form, fairly present in all material respects the corporation’s financial condition, cash flow and results of operation, as of the date and for the periods presented in such filings; and |
| --- | --- |
| (b) | that the interim financial statements, together with any financial information included in the interim<br>MD&A, fairly present in all material respects the corporation’s financial condition, cash flow and results of operation, as of the date and for the periods presented in such filings. |
| --- | --- |
| 13. | Review news releases to be issued in connection with the audited annual financial statements and related<br>management discussion and analysis and the interim unaudited financial statements and related interim management discussion and analysis, before being released to the public. Discuss the type and presentation of information to be included in news<br>releases (paying particular attention to any use of “pro-forma” or “adjusted” non-GAAP, information). |
| --- | --- |
| 14. | Review any news release, before being released to the public, containing earnings guidance or financial<br>information based upon the corporation’s financial statements prior to the release of such statements. |
| --- | --- |
| 15. | Review the appointment of the chief financial officer and have the chief financial officer report to the<br>committee on the qualifications of new key financial executives involved in the financial reporting process. |
| --- | --- |
| 16. | Consult with the human resources and compensation committee on the succession plan for the chief financial<br>officer and controller. Review the succession plans in respect of the chief financial officer and controller. |
| --- | --- |
Internal controls
| 1. | Receive from management a statement of the corporation’s system of internal controls over accounting and<br>financial reporting. |
|---|---|
| 2. | Consider and review with management, the internal auditor and the external auditors, the adequacy and<br>effectiveness of internal controls over accounting and financial reporting within the corporation and any proposed significant changes in them. |
| --- | --- |
| 3. | Consider and discuss the scope of the internal auditors’ and external auditors’ review of the<br>corporation’s internal controls, and obtain reports on significant findings and recommendations, together with management responses. |
| --- | --- |
| 4. | Discuss, as appropriate, with management, the external auditors and the internal auditor, any major issues as<br>to the adequacy of the corporation’s internal controls and any special audit steps in light of material internal control deficiencies. |
| --- | --- |
| 5. | Review annually the disclosure controls and procedures, including (a) the certification timetable and<br>related process and (b) the procedures that are in place for the review of the corporation’s disclosure of financial information extracted from the corporation’s financial statements and the adequacy of such procedures. Receive<br>confirmation from the chief executive officer and the chief financial officer of the effectiveness of disclosure controls and procedures, and whether there are any significant deficiencies and material weaknesses in the design or operation of<br>internal control over financial reporting which are reasonably likely to adversely affect the corporation’s ability to record, process, summarize and report financial information or any fraud, whether or not material, that involves management<br>or other employees who have a significant role in the corporation’s internal control over financial reporting. In addition, receive confirmation from |
| --- | --- |
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| the chief executive officer and the chief financial officer that they are prepared to sign the annual and quarterly certificates required by applicable securities law. | |
|---|---|
| 6. | Review management’s annual report and the external auditors’ report on the assessment of the<br>effectiveness of the corporation’s internal control over financial reporting. |
| --- | --- |
| 7. | Receive a report, at least annually, from the technical committee of the board on the corporation’s<br>mineral reserves. |
| --- | --- |
External auditors
| (i) | External Auditors’ Qualifications and Selection |
|---|---|
| 1. | Subject to the requirements of applicable law, be solely responsible to select, retain, compensate, oversee,<br>evaluate and, where appropriate, replace the external auditors, who must be registered with agencies mandated by applicable law. The committee shall be entitled to adequate funding from the corporation for the purpose of compensating the external<br>auditors for completing an audit and audit report. |
| --- | --- |
| 2. | Instruct the external auditors that: |
| --- | --- |
| (a) | they are ultimately accountable to the board and the committee, as representatives of shareholders; and<br> |
| --- | --- |
| (b) | they must report directly to the committee. |
| --- | --- |
| 3. | Ensure that the external auditors have direct and open communication with the committee and that the external<br>auditors meet regularly with the committee without the presence of management to discuss any matters that the committee or the external auditors believe should be discussed privately. |
| --- | --- |
| 4. | Evaluate the external auditors’ qualifications, performance, and independence. As part of that evaluation:<br> |
| --- | --- |
| (a) | at least annually, request and review a formal report by the external auditors describing: the firm’s<br>internal quality-control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding<br>five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (to assess the auditors’ independence) all relationships between the external auditors and the corporation,<br>including the amount of fees received by the external auditors for the audit services and for various types of non-audit services for the periods prescribed by applicable law; and |
| --- | --- |
| (b) | annually review and confirm with management and the external auditors the independence of the external<br>auditors, including the extent of non-audit services and fees, the extent to which the compensation of the audit partners of the external auditors is based upon selling<br>non-audit services, the timing and process for implementing the rotation of the lead audit partner, reviewing partner and other partners providing audit services for the corporation, whether there should be a<br>regular rotation of the audit firm itself, and whether there has been a “cooling off” period of one year for any former employees of the external auditors who are now employees with a financial oversight role, in order to assure compliance<br>with applicable law on such matters; and |
| --- | --- |
| (c) | annually review and evaluate senior members of the external audit team, including their expertise and<br>qualifications. In making this evaluation, the audit and finance committee should consider the opinions of management and the internal auditor. |
| --- | --- |
Conclusions on the independence of the external auditors should be reported to the board.
| 5. | Review and approve the corporation’s policies for the corporation’s hiring of employees and former<br>employees of the external auditors. Such policies shall include, at minimum, a one-year hiring “cooling off” period. |
|---|---|
| (ii) | Other Matters |
| --- | --- |
| 6. | Meet with the external auditors to review and approve the annual audit plan of the corporation’s financial<br>statements prior to the annual audit being undertaken by the external auditors, including reviewing the year-to-year<br>co-ordination of the audit plan and the planning, staffing and extent of the scope of the annual audit. This review should include an explanation from the external auditors of the factors considered by the<br>external auditors in determining their audit scope, |
| --- | --- |
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| including major risk factors. The external auditors shall report to the committee all significant changes to the approved audit plan. | |
|---|---|
| 7. | Review and approve the basis and amount of the external auditors’ fees with respect to the annual audit in<br>light of all relevant matters. |
| --- | --- |
| 8. | Review and pre-approve all audit and<br>non-audit service engagement fees and terms in accordance with applicable law, including those provided to the subsidiaries of the corporation by the external auditors or any other person in its capacity as<br>external auditors of such subsidiary. Between scheduled committee meetings, the chair of the committee, on behalf of the committee, is authorised to pre-approve any audit or<br>non-audit service engagement fees and terms. At the next committee meeting, the chair shall report to the committee any such pre-approval given. Establish and adopt<br>procedures for such matters. |
| --- | --- |
Internal auditor
| 1. | Review and approve the appointment or removal of the internal auditor. |
|---|---|
| 2. | Review and discuss with the external auditors, management, and internal auditor the responsibilities, budget<br>and staffing of the corporation’s internal audit function. |
| --- | --- |
| 3. | Review and approve the mandate for the internal auditor and the scope of annual work planned by the internal<br>auditor, receive summary reports of internal audit findings, management’s response thereto, and reports on any subsequent follow-up to any identified weakness. |
| --- | --- |
| 4. | Ensure that the internal auditor has direct and open communication with the committee and that the internal<br>auditor meets regularly with the committee without the presence of management to discuss any matters that the committee or the internal auditor believe should be discussed privately, such as problems or difficulties which were encountered in the<br>course of internal audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management. |
| --- | --- |
| 5. | Review and discuss with the internal auditor and management the internal auditor’s ongoing assessments of<br>the corporation’s business processes and system of internal controls. |
| --- | --- |
| 6. | Review the effectiveness of the internal audit function, including staffing, organizational structure and<br>qualifications of the internal auditor and staff. |
| --- | --- |
Compliance
| 1. | Monitor compliance by the corporation with all payments and remittances required to be made in accordance with<br>applicable law, where the failure to make such payments could render the directors of the corporation personally liable. |
|---|---|
| 2. | The receipt of regular updates from management regarding compliance with laws and regulations and the process<br>in place to monitor such compliance, excluding, however, legal compliance matters subject to the oversight of the safety, health and environment committee of the board. Review the findings of any examination by regulatory authorities and any<br>external auditors’ observations relating to such matters. |
| --- | --- |
| 3. | Establish and oversee the procedures in the code of conduct and ethics policy to address:<br> |
| --- | --- |
| (a) | the receipt, retention and treatment of complaints received by the corporation regarding accounting, internal<br>accounting or auditing matters; and |
| --- | --- |
| (b) | confidential, anonymous submissions by employees of concerns regarding questionable accounting and auditing<br>matters. |
| --- | --- |
Receive periodically a summary report from the senior vice-president, chief legal officer and corporate secretary on such matters as required by the code of conduct and ethics.
| 4. | Review and recommend to the board for approval a code of conduct and ethics for employees, officers and<br>directors of the corporation. Monitor management’s implementation of the code of conduct and ethics and the global anti-corruption program and review compliance therewith by, among other things, obtaining an annual report summarizing statements<br>of compliance by employees pursuant to such policies and reviewing the findings of any investigations of non-compliance. |
|---|
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| Periodically review the adequacy and appropriateness of such policies and programs and make recommendations to the board thereon. | |
|---|---|
| 5. | Monitor management’s implementation of the anti-fraud policy; and review compliance therewith by, among<br>other things, receiving reports from management on: |
| --- | --- |
| (a) | any investigations of fraudulent activity; |
| --- | --- |
| (b) | monitoring activities in relation to fraud risks and controls; and |
| --- | --- |
| (c) | assessments of fraud risk. |
| --- | --- |
Periodically review the adequacy and appropriateness of the anti-fraud policy and make recommendations to the board thereon.
| 6. | Review all proposed related party transactions and situations involving a director’s, senior<br>officer’s or an affiliate’s potential or actual conflict of interest that are not required to be dealt with by an “independent committee” pursuant to securities law rules, other than routine transactions and situations arising in<br>the ordinary course of business, consistent with past practice. Between scheduled committee meetings, the chair of the committee, on behalf of the committee, is authorized to review all such transactions and situations. At the next committee<br>meeting, the chair shall report the results of such review. |
|---|---|
| 7. | Monitor management of hedging, debt and credit, make recommendations to the board respecting policies for<br>management of such risks, and review the corporation’s compliance therewith. |
| --- | --- |
| 8. | Approve the review and approval process for the expenses submitted for reimbursement by the chief executive<br>officer. |
| --- | --- |
| 9. | Oversee management’s mitigation of material risks within the committee’s mandate and as otherwise<br>assigned. |
| --- | --- |
| 10. | Undertake such other tasks as may be directed to it from time to time by the board. |
| --- | --- |
Financial oversight
| 1. | Assist the board in its consideration and ongoing oversight of matters pertaining to: |
|---|---|
| (a) | capital structure and funding including finance and cash flow planning; |
| --- | --- |
| (b) | capital management planning and initiatives; |
| --- | --- |
| (c) | property and corporate acquisitions and divestitures including proposals which may have a material impact on<br>the corporation’s capital position; |
| --- | --- |
| (d) | the corporation’s annual budget and business plan; |
| --- | --- |
| (e) | the corporation’s insurance program; |
| --- | --- |
| (f) | directors’ and officers’ liability insurance and indemnity agreements; |
| --- | --- |
| (g) | the annual approval to elect the end-user exception under Dodd Frank;<br>and |
| --- | --- |
| (h) | matters the board may refer to the committee from time to time in connection with the corporation’s<br>capital position. |
| --- | --- |
Organizational matters
| 1. | The procedures governing the committee shall, except as otherwise provided for herein, be those applicable to<br>the board committees as set forth in Part 7 of the General Bylaws of the corporation. |
|---|---|
| 2. | The members and the chair of the committee shall be entitled to receive remuneration for acting in such<br>capacity as the board may from time to time determine. |
| --- | --- |
| 3. | The committee shall have the resources and authority appropriate to discharge its duties and responsibilities,<br>including the authority to: |
| --- | --- |
| (a) | select, retain, terminate, set and approve the fees and other retention terms of special or independent<br>counsel, accountants or other experts, as it considers appropriate; and |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 142
| (b) | obtain appropriate funding to pay, or approve the payment of, such approved fees; |
|---|
without seeking approval of the board or management.
| 4. | Any member of the committee may be removed or replaced at any time by the board and shall cease to be a member<br>of the committee upon ceasing to be a director. The board may fill vacancies on the committee by appointment from among its members. If and whenever a vacancy shall exist on the committee, the remaining members may exercise all its powers so long as<br>a quorum remains in office. Subject to the foregoing, each member of the committee shall remain as such until the next annual meeting of shareholders after that member’s election. |
|---|---|
| 5. | The committee shall annually review and assess the adequacy of its mandate and recommend any proposed changes<br>to the nominating, corporate governance and risk committee for recommendation to the board for approval. |
| --- | --- |
| 6. | The committee shall participate in an annual performance evaluation, the results of which will be reviewed by<br>the board. |
| --- | --- |
| 7. | The committee shall perform any other activities consistent with this mandate, the corporation’s governing<br>laws and the regulations of stock exchanges, as the committee or the board considers necessary or appropriate. |
| --- | --- |
| 8. | A standing invitation will be issued to all non-executive directors to<br>attend the financial oversight portion of each committee meeting. |
| --- | --- |
2022 ANNUAL INFORMATION FORM Page 143
EX-99.2
1
EXHIBIT 99.2
Cameco Corporation
2022 Consolidated Audited Financial Statements
February 8, 2023
2
Cameco Corporation
2022 consolidated financial statements
February 8, 2023
3
Report of management’s accountability
The accompanying consolidated financial statements have been prepared by management in accordance with International
Financial Reporting Standards as issued by the International Accounting Standards Board. Management is responsible for
ensuring that these statements, which include amounts based upon estimates and judgments, are consistent with other
information and operating data contained in the annual financial review and reflect the corporation's business transactions and
financial position.
Management is also responsible for the information disclosed in the management’s discussion and analysis including
responsibility for the existence of appropriate information systems, procedures and controls to ensure that the information
used internally by management and disclosed externally is complete and reliable in all material respects.
In addition, management is responsible for establishing and maintaining an adequate system of internal control over financial
reporting. The internal control system includes an internal audit function and a code of conduct and ethics, which is
communicated to all levels in the organization and requires all employees to maintain high standards in their conduct of the
Company's affairs. Such systems are designed to provide reasonable assurance that the financial information is relevant,
reliable and accurate and that the Company’s assets are appropriately accounted for and adequately safeguarded.
Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on
the criteria established in “Internal Control – Integrated Framework (2013)” issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s system of
internal control over financial reporting was effective as of December 31, 2022.
KPMG LLP has audited the consolidated financial statements in accordance with the standards of the Public Company
Accounting Oversight Board (United States).
The board of directors annually appoints an audit and finance committee comprised of directors who are not employees of the
corporation. This committee meets regularly with management, the internal auditor and the shareholders' auditors to review
significant accounting, reporting and internal control matters. Both the internal and shareholders' auditors have unrestricted
access to the audit and finance committee. The audit and finance committee reviews the consolidated financial statements,
the report of the shareholders' auditors, and management’s discussion and analysis and submits its report to the board of
directors for formal approval.
Original signed by Tim S. Gitzel
Original signed by Grant E. Isaac
President and Chief Executive Officer
Senior Vice-President and Chief Financial Officer
February 8, 2023
February 8, 2023
4
Report of independent registered public accounting firm
To
the Shareholders and Board of Directors of Cameco Corporation
Opinion on the consolidated financial statements
We have audited the accompanying consolidated statements of financial position of Cameco Corporation (the “Company”) as
of December 31, 2022 and 2021, the related consolidated statements of earnings, comprehensive income, changes in equity
and cash flows for each of the years in the two-year period ended December 31, 2022, and the related notes (collectively, the
“consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2022 and 2021, and its financial performance and its cash
flows for each of the years in the two-year period ended December 31, 2022, in conformity with International Financial
Reporting Standards as issued by the International Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2022,
based on criteria established in
Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 8, 2023 expressed an unqualified opinion on the effectiveness of the
Company’s internal control over financial reporting.
Basis for opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond
to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the
consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates
made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that
our audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial
statements that was communicated or required to be communicated to the audit and finance committee and that: (1) relates to
accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging,
subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the
consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below,
providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Assessment of recoverability of deferred tax assets
As discussed in note 22 to the consolidated financial statements, as of December 31, 2022 the Company has recorded a
deferred tax asset of $984,071,000. The realization of this deferred tax asset is dependent on the generation of future taxable
income in certain jurisdictions during the periods in which the Company’s deferred tax assets are available. Based on
projections of future taxable income over the periods in which the deferred tax assets are available, realization of these
deferred tax assets is probable. As discussed in note 5D, the calculation of income taxes requires the use of judgment and
estimates. The determination of the recoverability of deferred tax assets is dependent on assumptions and judgments
regarding future market conditions and production rates, which can materially impact estimated future taxable income.
5
We identified the assessment of the recoverability of the deferred tax asset as a critical audit matter due to the high degree of
judgment required in assessing the significant assumptions and judgments that are reflected in the projections of future
taxable income.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and
tested the operating effectiveness of certain internal controls related to the Company’s assessment of the recoverability of the
deferred tax asset, including controls related to the assumptions and judgments used in the projections of future taxable
income. To
assess the Company’s ability to estimate future taxable income, we compared the Company’s previous forecasts
to actual results. To
assess the Company’s estimate of future taxable income, we evaluated certain significant assumptions in
the projections. We compared future market conditions of forecast uranium sales prices to published views of independent
market participants. We compared forecast sales to historical trends, board approved budgets and committed sales volumes,
including to a selection of committed sales contracts. We compared forecast production rates to historical data, board
approved budgets and life of mine plans. We involved income tax professionals with specialized skills and knowledge to assist
in assessing the Company’s application of the tax regulations in relevant jurisdictions.
Original signed by KPMG LLP
Chartered Professional Accountants
We have served as the Company’s auditor since 1988.
Saskatoon, Canada
February 8, 2023
6
Report of independent registered public accounting firm
To
the Shareholders and Board of Directors of Cameco Corporation
Opinion on internal control over financial reporting
We have audited Cameco Corporation’s (the “Company”) internal control over financial reporting as of December 31, 2022,
based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the consolidated statements of financial position of the Company as of December 31, 2022 and 2021, the related
consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the years in the
two-year period ended December 31, 2022, and the related notes (collectively, the "consolidated financial statements") and
our report dated February 8, 2023 expressed an unqualified opinion on those consolidated financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report of
management’s accountability. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent
with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our
opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
7
Original signed by KPMG LLP
Chartered Professional Accountants
Saskatoon, Canada
February 8, 2023
8
Consolidated statements of earnings
For the years ended December 31
Note
2022
2021
($Cdn thousands, except per share amounts)
Revenue from products and services
18
$
1,868,003
$
1,474,984
Cost of products and services sold
1,457,336
1,282,635
Depreciation and amortization
177,376
190,415
Cost of sales
29
1,634,712
1,473,050
Gross profit
233,291
1,934
Administration
172,029
127,566
Exploration
10,578
8,016
Research and development
12,175
7,168
Other operating expense (income)
16
22,944
(8,407)
Loss on disposal of assets
514
3,803
Earnings (loss) from operations
15,051
(136,212)
Finance costs
20
(85,728)
(76,612)
Gain (loss) on derivatives
27
(72,949)
12,529
Finance income
37,499
6,804
Share of earnings from equity-accounted investee
12
93,988
68,283
Other income
21
96,934
21,353
Earnings (loss) before income taxes
84,795
(103,855)
Income tax recovery
22
(4,469)
(1,201)
Net earnings (loss)
$
89,264
$
(102,654)
Net earnings (loss) attributable to:
Equity holders
89,382
(102,577)
Non-controlling interest
(118)
(77)
Net earnings (loss)
$
89,264
$
(102,654)
Earnings (loss) per common share attributable to equity holders:
Basic
23
$
0.22
$
(0.26)
Diluted
23
$
0.22
$
(0.26)
See accompanying notes to consolidated financial statements.
9
Consolidated statements of comprehensive income
For the years ended December 31
Note
2022
2021
($Cdn thousands)
Net earnings (loss)
$
89,264
$
(102,654)
Other comprehensive income (loss), net of taxes:
-
-
Items that will not be reclassified to net earnings:
Remeasurements of defined benefit liability
1
26
19,242
3,897
Equity investments at FVOCI - net change in fair value
2
-
22,059
-
Items that are or may be reclassified to net earnings:
Exchange differences on translation of foreign operations
(38,141)
(30,384)
Other comprehensive loss, net of taxes
(18,899)
(4,428)
Total comprehensive income (loss)
$
70,365
$
(107,082)
Other comprehensive income (loss) attributable to:
Equity holders
$
(18,901)
$
(4,426)
Non-controlling interest
2
(2)
Other comprehensive loss for the year
$
(18,899)
$
(4,428)
Total comprehensive income (loss) attributable to:
Equity holders
$
70,481
$
(107,003)
Non-controlling interest
(116)
(79)
Total comprehensive income (loss) for the year
$
70,365
$
(107,082)
1
Net of tax (2022 - $(
5,440
); 2021 - $(
1,274
))
2
Net of tax (2022 - $
0
; 2021 - $(
3,267
))
See accompanying notes to consolidated financial statements.
10
Consolidated statements of financial position
As at December 31
Note
2022
2021
($Cdn thousands)
Assets
Current assets
Cash and cash equivalents
$
1,143,674
$
1,247,447
Short-term investments
1,138,174
84,906
Accounts receivable
7
183,944
276,139
Current tax assets
1,056
4,966
Inventories
8
664,698
409,521
Supplies and prepaid expenses
157,910
95,341
Current portion of long-term receivables, investments and other
11
32,180
23,232
Total
current assets
3,321,636
2,141,552
Property, plant and equipment
9
3,473,490
3,576,599
Intangible assets
10
47,117
51,247
Long-term receivables, investments and other
11
595,507
577,527
Investment in equity-accounted investee
12
210,972
233,240
Deferred tax assets
22
984,071
937,579
Total
non-current assets
5,311,157
5,376,192
Total assets
$
8,632,793
$
7,517,744
Liabilities and shareholders' equity
Current liabilities
Accounts payable and accrued liabilities
13
$
374,714
$
340,458
Current tax liabilities
6,498
4,129
Current portion of other liabilities
15
131,324
22,791
Current portion of provisions
16
48,305
46,365
Total
current liabilities
560,841
413,743
Long-term debt
14
997,000
996,250
Other liabilities
15
216,162
171,774
Provisions
16
1,022,725
1,090,009
Total
non-current liabilities
2,235,887
2,258,033
Shareholders' equity
Share capital
2,880,336
1,903,357
Contributed surplus
224,687
230,039
Retained earnings
2,696,379
2,639,650
Other components of equity
34,652
72,795
Total shareholders' equity attributable to equity holders
5,836,054
4,845,841
Non-controlling interest
11
127
Total shareholders' equity
5,836,065
4,845,968
Total liabilities and shareholders' equity
$
8,632,793
$
7,517,744
Commitments and contingencies [notes 9, 16, 22, 33]
See accompanying notes to consolidated financial statements.
11
Consolidated statements of changes in equity
Attributable to equity holders
Foreign
Equity
Non-
Share
Contributed
Retained
currency
investments
controlling
Total
($Cdn thousands)
capital
surplus
earnings
translation
at FVOCI
Total
interest
equity
Balance at January 1, 2022
$
1,903,357
$
230,039
$
2,639,650
$
73,543
$
(748)
$
4,845,841
$
127
$
4,845,968
Net earnings (loss)
-
-
89,382
-
-
89,382
(118)
89,264
Other comprehensive
income (loss)
-
-
19,242
(38,143)
-
(18,901)
2
(18,899)
Total comprehensive
income (loss)
-
-
108,624
(38,143)
-
70,481
(116)
70,365
Share-based compensation
-
3,318
-
-
-
3,318
-
3,318
Stock options exercised
12,101
(2,469)
-
-
-
9,632
-
9,632
Restricted share units
released
-
(6,201)
-
-
-
(6,201)
-
(6,201)
Dividends
-
-
(51,895)
-
-
(51,895)
-
(51,895)
Equity issuance [note 17]
964,878
-
-
-
-
964,878
-
964,878
Balance at December 31, 2022
$
2,880,336
$
224,687
$
2,696,379
$
35,400
$
(748)
$
5,836,054
$
11
$
5,836,065
Balance at January 1, 2021
$
1,869,710
$
237,358
$
2,735,830
$
103,925
$
11,532
$
4,958,355
$
206
$
4,958,561
Net loss
-
-
(102,577)
-
-
(102,577)
(77)
(102,654)
Other comprehensive
income (loss)
-
-
3,897
(30,382)
22,059
(4,426)
(2)
(4,428)
Total comprehensive
income (loss)
-
-
(98,680)
(30,382)
22,059
(107,003)
(79)
(107,082)
Share-based compensation
-
4,536
-
-
-
4,536
-
4,536
Stock options exercised
33,647
(6,876)
-
-
-
26,771
-
26,771
Restricted share units
released
-
(4,979)
-
-
-
(4,979)
-
(4,979)
Dividends
-
-
(31,839)
-
-
(31,839)
-
(31,839)
Transfer to retained
earnings [note 27]
-
-
34,339
-
(34,339)
-
-
-
Balance at December 31, 2021
$
1,903,357
$
230,039
$
2,639,650
$
73,543
$
(748)
$
4,845,841
$
127
$
4,845,968
See accompanying notes to consolidated financial statements.
12
Consolidated statements of cash flows
For the years ended December 31
Note
2022
2021
($Cdn thousands)
Operating activities
Net earnings (loss)
$
89,264
$
(102,654)
Adjustments for:
Depreciation and amortization
177,376
190,415
Deferred sales
43,528
608
Unrealized loss on derivatives
82,636
13,771
Share-based compensation
25
3,318
4,536
Loss on disposal of assets
514
3,803
Finance costs
20
85,728
76,612
Finance income
(37,499)
(6,804)
Share of earnings from equity-accounted investee
12
(93,988)
(68,283)
Other income
21
(96,934)
(446)
Other operating expense (income)
16
22,944
(8,407)
Income tax recovery
22
(4,469)
(1,201)
Interest received
35,443
9,374
Income taxes received (paid)
(1,521)
9,583
Dividends from equity-accounted investee
32
117,698
50,128
Other operating items
24
(119,431)
287,253
Net cash provided by operations
304,607
458,288
Investing activities
Additions to property, plant and equipment
9
(143,448)
(98,784)
Acquisition
6
(101,681)
-
Increase in short-term investments
(1,044,473)
(59,921)
Decrease (increase) in long-term receivables, investments and other
(2,000)
73,050
Proceeds from sale of property, plant and equipment
780
5,357
Net cash used in investing
(1,290,822)
(80,298)
Financing activities
Interest paid
(38,856)
(38,977)
Proceeds from issuance of shares, stock option plan
9,632
26,771
Proceeds from issuance of shares, net of issue costs
17
953,285
-
Lease principal payments
(2,908)
(2,727)
Dividends paid
(51,895)
(31,839)
Net cash provided by (used in) financing
869,258
(46,772)
Increase (decrease) in cash and cash equivalents, during the year
(116,957)
331,218
Exchange rate changes on foreign currency cash balances
13,184
(2,153)
Cash and cash equivalents, beginning of year
1,247,447
918,382
Cash and cash equivalents, end of year
$
1,143,674
$
1,247,447
Cash and cash equivalents is comprised of:
Cash
$
701,818
$
604,557
Cash equivalents
441,856
642,890
Cash and cash equivalents
$
1,143,674
$
1,247,447
See accompanying notes to consolidated financial statements.
13
Notes to consolidated financial statements
For the years ended December 31, 2022 and 2021
1.
Cameco Corporation
Cameco Corporation is incorporated under the Canada Business Corporations Act. The address of its registered office is 2121
11th Street West, Saskatoon, Saskatchewan, S7M 1J3. The consolidated financial statements as at and for the year ended
December 31, 2022 comprise Cameco Corporation and its subsidiaries (collectively, the Company or Cameco) and the
Company’s interests in associates and joint arrangements.
Cameco is one of the world’s largest providers of the uranium needed to generate clean, reliable baseload electricity around
the globe. The Company has mines in northern Saskatchewan and the United States, as well as a 40% interest in Joint
Venture Inkai LLP (JV Inkai), a joint arrangement with Joint Stock Company National Atomic Company Kazatomprom
(Kazatomprom),
located in Kazakhstan. JV Inkai is accounted for on an equity basis (see note 12).
Cameco’s Cigar Lake mine in northern Saskatchewan had been placed in a temporary state of care and maintenance
periodically throughout 2020 and 2021 due to the global COVID-19 pandemic. The mine was in a temporary state of care and
maintenance in January 2021 and production resumed in April 2021. Operations at McArthur River/Key Lake, which had been
suspended in 2018, resumed in November of 2022.
The Rabbit Lake operation was placed in care and maintenance in 2016.
Cameco’s operations in the United States, Crow Butte and Smith Ranch-Highland, are not currently producing as the decision
was made in 2016 to curtail production and defer all wellfield development. See note 29 for the financial statement impact.
The Company is also a leading provider of nuclear fuel processing services, supplying much of the world’s reactor fleet with
the fuel to generate one of the cleanest sources of electricity available today. It operates the world’s largest commercial
refinery in Blind River, Ontario, controls a significant portion of the world UF
6
primary conversion capacity in Port Hope,
Ontario and is a leading manufacturer of fuel assemblies and reactor components for CANDU reactors at facilities in Port
Hope and Cobourg, Ontario.
2.
Significant accounting policies
A.
Statement of compliance
These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards
(IFRS) as issued by the International Accounting Standards Board (IASB).
These consolidated financial statements were authorized for issuance by the Company’s board of directors on February 8,
2023.
B.
Basis of presentation
These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All
financial information is presented in Canadian dollars, unless otherwise noted. Amounts presented in tabular format have been
rounded to the nearest thousand except per share amounts and where otherwise noted.
The consolidated financial statements have been prepared on the historical cost basis except for the following material items
which are measured on an alternative basis at each reporting date:
14
Derivative financial instruments
Fair value through profit or loss (FVTPL)
Equity investments
Fair value through other comprehensive income
(FVOCI)
Liabilities for cash-settled share-based payment arrangements
FVTPL
Net defined benefit liability
Fair value of plan assets less the present value of the
defined benefit obligation
The preparation of the consolidated financial statements in conformity with IFRS requires management to make judgments,
estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities,
revenue and expenses. Actual results may vary from these estimates.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in
the period in which the estimates are revised and in any future periods affected. The areas involving a higher degree of
judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are
disclosed in note 5.
This summary of significant accounting policies is a description of the accounting methods and practices that have been used
in the preparation of these consolidated financial statements and is presented to assist the reader in interpreting the
statements contained herein. These accounting policies have been applied consistently to all entities within the consolidated
group.
C.
Consolidation principles
i.
Business combinations
The acquisition method of accounting is used to account for the acquisition of subsidiaries by the Company. The Company
measures goodwill at the acquisition date as the fair value of the consideration transferred, including the recognized amount of
any non-controlling interests in the acquiree, less the net recognized amount (generally fair value) of the identifiable assets
acquired and liabilities assumed, all measured as of the acquisition date. When the excess is negative, a bargain purchase
gain is recognized immediately in earnings. In a business combination achieved in stages, the acquisition date fair value of the
Company’s previously held equity interest in the acquiree is also considered in computing goodwill.
Consideration transferred includes the fair values of the assets transferred, liabilities incurred and equity interests issued by
the Company. Consideration also includes the fair value of any contingent consideration and share-based compensation
awards that are replaced mandatorily in a business combination.
The Company elects on a transaction-by-transaction basis whether to measure any non-controlling interest at fair value, or at
their proportionate share of the recognized amount of the identifiable net assets of the acquiree, at the acquisition date.
Acquisition-related costs are expensed as incurred, except for those costs related to the issue of debt or equity instruments.
ii.
Subsidiaries
The consolidated financial statements include the accounts of Cameco and its subsidiaries. Subsidiaries are entities over
which the Company has control. Subsidiaries are fully consolidated from the date on which control is acquired by the Company
and are deconsolidated from the date that control ceases.
iii.
Investments in equity-accounted investees
Cameco’s investments in equity-accounted investees include investments in associates.
Associates are those entities over which the Company has significant influence, but not control or joint control, over the
financial and operating policies. Significant influence is presumed to exist when the Company holds between 20% and 50% of
the voting power of another entity, but can also arise where the Company holds less than 20% if it has the power to be actively
involved and influential in policy decisions affecting the entity.
15
Investments in associates are accounted for using the equity method. The equity method involves the recording of the initial
investment at cost and the subsequent adjusting of the carrying value of the investment for Cameco’s proportionate share of
the earnings or loss and any other changes in the associates’ net assets, such as dividends. The cost of the investment
includes transaction costs.
Adjustments are made to align the accounting policies of the associate with those of the Company before applying the equity
method. When the Company’s share of losses exceeds its interest in an equity-accounted investee, the carrying amount of
that interest is reduced to zero, and the recognition of further losses is discontinued except to the extent that the Company has
incurred legal or constructive obligations or made payments on behalf of the associate. If the associate subsequently reports
profits, Cameco resumes recognizing its share of those profits only after its share of the profits equals the share of losses not
recognized.
iv.
Joint arrangements
A joint arrangement can take the form of a joint operation or joint venture. All joint arrangements involve a contractual
arrangement that establishes joint control.
A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the
assets, and obligations for the liabilities, relating to the arrangement. A joint operation may or may not be structured through a
separate vehicle. These arrangements involve joint control of one or more of the assets acquired or contributed for the
purpose of the joint operation. The consolidated financial statements of the Company include its share of the assets in such
joint operations, together with its share of the liabilities, revenues and expenses arising jointly or otherwise from those
operations. All such amounts are measured in accordance with the terms of each arrangement.
A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net
assets of the arrangement. A joint venture is always structured through a separate vehicle. It operates in the same way as
other entities, controlling the assets of the joint venture, earning its own revenue and incurring its own liabilities and expenses.
Interests in joint ventures are accounted for using the equity method of accounting, whereby the Company’s proportionate
interest in the assets, liabilities, revenues and expenses of jointly controlled entities are recognized on a single line in the
consolidated statements of financial position and consolidated statements of earnings. The share of joint ventures results is
recognized in the Company’s consolidated financial statements from the date that joint control commences until the date at
which it ceases.
When acquiring an additional interest in a joint arrangement, previously held interests are not remeasured at fair value. In an
acquisition of an asset or group of assets that does not constitute a business, the directly attributable transaction costs are
included in the cost of the asset or group of assets.
v.
Transactions eliminated on consolidation
Intra-group balances and transactions, and any unrealized income and expenses arising from intra-group transactions, are
eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity-accounted
investees are eliminated against the investment to the extent of the Company’s interest in the investee. Unrealized losses are
eliminated in the same manner as unrealized gains, but only to the extent that there is no evidence of impairment.
D.
Foreign currency translation
Items included in the financial statements of each of Cameco’s subsidiaries, associates and joint arrangements are measured
using their functional currency, which is the currency of the primary economic environment in which the entity operates. The
consolidated financial statements are presented in Canadian dollars, which is Cameco’s functional and presentation currency.
16
i.
Foreign currency transactions
Foreign currency transactions are translated into the respective functional currency of the Company and its entities using the
exchange rates prevailing at the dates of the transactions. At the reporting date, monetary assets and liabilities denominated in
foreign currencies are translated to the functional currency at the exchange rate at that date. Non-monetary items that are
measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the transaction.
The applicable exchange gains and losses arising on these transactions are reflected in earnings with the exception of foreign
exchange gains or losses on provisions for decommissioning and reclamation activities that are in a foreign currency, which
are capitalized in property, plant and equipment.
ii.
Foreign operations
The assets and liabilities of foreign operations, including goodwill and fair value adjustments arising on acquisition, are
translated to Canadian dollars at exchange rates at the reporting dates. The revenues and expenses of foreign operations are
translated to Canadian dollars at exchange rates at the dates of the transactions.
Foreign currency differences are recognized in other comprehensive income. When a foreign operation is disposed of, in
whole, the relevant amount in the foreign currency translation account is transferred to earnings as part of the gain or loss on
disposal.
When the settlement of a monetary item receivable from or payable to a foreign operation is neither planned nor likely in the
foreseeable future, foreign exchange gains and losses arising from such a monetary item are considered to form part of the
net investment in a foreign operation, and are recognized in other comprehensive income and presented within equity in the
foreign currency translation account.
E.
Cash and cash equivalents
Cash and cash equivalents consists of balances with financial institutions and investments in money market instruments,
which have a term to maturity of three months or less at the time of purchase and are measured at amortized cost.
F.
Short-term investments
Short-term investments are comprised of money market instruments with terms to maturity between three and 12 months and
are measured at amortized cost.
G.
Inventories
Inventories of broken ore, uranium concentrates, and refined and converted products are measured at the lower of cost and
net realizable value.
Cost includes direct materials, direct labour, operational overhead expenses and depreciation. Net realizable value is the
estimated selling price in the ordinary course of business, less the estimated costs of completion and selling expenses.
Consumable supplies and spares are valued at the lower of cost or replacement value.
H.
Property, plant and equipment
i.
Buildings, plant and equipment and other
Items of property, plant and equipment are measured at cost less accumulated depreciation and impairment charges. The cost
of self-constructed assets includes the cost of materials and direct labour, borrowing costs and any other costs directly
attributable to bringing the assets to the location and condition necessary for them to be capable of operating in the manner
intended by management, including the initial estimate of the cost of dismantling and removing the items and restoring the site
on which they are located.
When components of an item of property, plant and equipment have different useful lives, they are accounted for as separate
items of property, plant and equipment and depreciated separately.
17
Gains and losses on disposal of an item of property, plant and equipment are determined by comparing the proceeds from
disposal with the carrying amount of property, plant and equipment, and are recognized in earnings.
ii.
Mineral properties and mine development costs
The decision to develop a mine property within a project area is based on an assessment of the commercial viability of the
property, the availability of financing and the existence of markets for the product. Once the decision to proceed to
development is made, development and other expenditures relating to the project area are deferred as part of assets under
construction and disclosed as a component of property, plant and equipment with the intention that these will be depreciated
by charges against earnings from future mining operations. No depreciation is charged against the property until the
production stage commences. After a mine property has been brought into the production stage, costs of any additional work
on that property are expensed as incurred, except for large development programs, which will be deferred and depreciated
over the remaining life of the related assets.
The production stage is reached when a mine property is in the condition necessary for it to be capable of operating in the
manner intended by management. The criteria used to assess the start date of the production stage are determined based on
the nature of each mine construction project, including the complexity of a mine site. A range of factors is considered when
determining whether the production stage has been reached, which includes, but is not limited to, the demonstration of
sustainable production at or near the level intended (such as the demonstration of continuous throughput levels at or above a
target percentage of the design capacity).
iii.
Depreciation
Depreciation is calculated over the depreciable amount, which is the cost of the asset less its residual value. Assets which are
unrelated to production are depreciated according to the straight-line method based on estimated useful lives as follows:
Land
Not depreciated
Buildings
15
-
25
years
Plant and equipment
3
-
15
years
Furniture and fixtures
3
-
10
years
Other
3
-
5
years
Mining properties and certain mining and conversion assets for which the economic benefits from the asset are consumed in a
pattern which is linked to the production level are depreciated according to the unit-of-production method. For conversion
assets, the amount of depreciation is measured by the portion of the facilities' total estimated lifetime production that is
produced in that period. For mining assets and properties, the amount of depreciation or depletion is measured by the portion
of the mines' proven and probable mineral reserves recovered during the period.
Depreciation methods, useful lives and residual values are reviewed at each reporting period and are adjusted if appropriate.
iv.
Borrowing costs
Borrowing costs on funds directly attributable to finance the acquisition, production or construction of a qualifying asset are
capitalized until such time as substantially all the activities necessary to prepare the qualifying asset for its intended use are
complete. A qualifying asset is one that takes a substantial period of time to prepare for its intended use. Capitalization is
discontinued when the asset enters the production stage or development ceases. Where the funds used to finance a project
form part of general borrowings, interest is capitalized based on the weighted average interest rate applicable to the general
borrowings outstanding during the period of construction.
v.
Repairs and maintenance
The cost of replacing a component of property, plant and equipment is capitalized if it is probable that future economic benefits
embodied within the component will flow to the Company. The carrying amount of the replaced component is derecognized.
Costs of routine maintenance and repair are charged to products and services sold.
18
I.
Goodwill and intangible assets
Goodwill arising from the acquisition of subsidiaries is initially recognized at cost, measured as the excess of the fair value of
the consideration paid over the fair value of the identifiable net assets acquired. At the date of acquisition, goodwill is allocated
to the cash generating unit (CGU), or group of CGUs that is expected to receive the economic benefits of the business
combination. Goodwill is subsequently measured at cost, less accumulated impairment losses.
Intangible assets acquired individually or as part of a group of assets are initially recognized at cost and measured
subsequently at cost less accumulated amortization and impairment losses. Subsequent expenditure is capitalized only when
it increases the future economic benefits embodied in the specific asset to which it relates. The cost of a group of intangible
assets acquired in a transaction, including those acquired in a business combination that meet the specified criteria for
recognition apart from goodwill, is allocated to the individual assets acquired based on their relative fair values.
Intangible assets that have finite useful lives are amortized over their estimated remaining useful lives. Amortization methods
and useful lives are reviewed at each reporting period and are adjusted if appropriate.
J.
Leases
Cameco recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is
initially measured at cost, which is the initial amount of the lease liability adjusted for any lease payments made at or before
the commencement date, plus any initial direct costs incurred, less any lease incentives received, and subsequently at cost
less any accumulated depreciation and impairment losses. The right-of-use asset is subsequently depreciated using the
straight-line method from the commencement date to the end of the lease term, unless the cost of the right-of-use asset
reflects that the Company will exercise a purchase option, in which case the right-of-use asset will be depreciated on the same
basis as that of property, plant and equipment.
The lease liability is measured at amortized cost using the effective interest method. It is initially measured at the present value
of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease, or,
if that rate cannot be readily determined, the Company’s incremental borrowing rate. Generally, Cameco uses its incremental
borrowing rate as the discount rate. Current borrowing rates available for classes of leased assets are compared with the rates
of Cameco’s existing debt facilities to ensure that use of the Company’s incremental borrowing rate is reasonable.
The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made.
It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the
estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the
assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is
reasonably certain not to be exercised.
Cameco uses judgement in determining the lease term for some lease contracts that include renewal options. The assessment
of whether the Company is reasonably certain to exercise such options impacts the lease term, which affects the amount of
lease liabilities and right-of-use assets recognized.
The Company has elected not to recognize right-of-use assets and lease liabilities for leases of low-value assets and short-
term leases that have a lease term of 12 months or less. The lease payments associated with these leases are recognized as
an expense on a straight-line basis over the lease term.
K.
Finance income and finance costs
Finance income comprises interest income on funds invested. Interest income and interest expense are recognized in
earnings as they accrue, using the effective interest method. Finance costs comprise interest and fees on borrowings,
unwinding of the discount on provisions and costs incurred on redemption of debentures.
Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are
expensed in the period incurred.
19
L.
Research and development costs
Expenditures on research are charged against earnings when incurred. Development costs are recognized as assets when the
Company can demonstrate technical feasibility and that the asset will generate probable future economic benefits.
M.
Impairment
i.
Non-derivative financial assets
Cameco recognizes loss allowances for expected credit losses (ECLs) on financial assets measured at amortized cost, debt
investments measured at FVOCI, and contract assets. It measures loss allowances at an amount equal to lifetime ECLs,
except for debt securities that are determined to have low credit risk at the reporting date and other debt securities, loans
advanced and bank balances for which credit risk has not increased significantly since initial recognition. For these, loss
allowances are measured equal to 12-month ECLs.
Lifetime ECLs are the ECLs that result from all possible default events over the expected life of a financial instrument while 12-
month ECLs are the portion of ECLs that result from default events that are possible within the 12 months after the reporting
date (or a shorter period if the expected life of the instrument is less than 12 months). The maximum period considered when
estimating ECLs is the maximum contractual period over which the Company is exposed to credit risk.
ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of the difference
between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to
receive. ECLs are discounted at the effective interest rate of the financial asset.
When determining whether the credit risk of a financial asset has increased significantly since initial recognition and when
estimating ECLs, the Company considers reasonable and supportable information that is relevant and available without undue
cost or effort. This includes both quantitative and qualitative information and analysis, based on the Company’s historical
experience and informed credit assessment and including forward-looking information.
The Company considers a financial asset to be in default when the borrower is unlikely to pay its credit obligations in full,
without recourse by Cameco to actions such as realizing security (if any is held).
The Company considers a debt security to have low credit risk when it is at least an A (low) DBRS or A- S&P rating.
Financial assets carried at amortized cost and debt securities at FVOCI are assessed at each reporting date to determine
whether they are ‘credit-impaired’. A financial asset is ‘credit-impaired’ when one or more events that have a detrimental effect
on the estimated future cash flows of the financial asset have occurred. Evidence can include significant financial difficulty of
the borrower or issuer, a breach of contract, restructuring of an amount due to the Company on terms that the Company would
not consider otherwise, indications that a debtor or issuer will enter bankruptcy or other financial reorganization, or the
disappearance of an active market for a security.
Loss allowances for financial assets measured at amortized cost are deducted from the gross carrying amount of the assets.
For debt securities at FVOCI, the loss allowance is charged to earnings and is recognized in OCI. The gross carrying amount
of a financial asset is written off when the Company has no reasonable expectations of recovering a financial asset in its
entirety or a portion thereof.
ii.
Non-financial assets
The carrying amounts of Cameco’s non-financial assets are reviewed throughout the year to determine whether there is any
indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. Goodwill is tested
annually for impairment.
20
For impairment testing, assets are grouped together into CGUs which are the smallest group of assets that generate cash
inflows from continuing use that are largely independent of the cash inflows of other assets or CGUs. Goodwill arising from a
business combination is allocated to CGUs or groups of CGUs that are expected to benefit from the synergies of the
combination.
The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Value in use is
based on the estimated future cash flows, discounted to their present value using a pre-tax discount rate that reflects current
market assessments of the time value of money and the risks specific to the asset or CGU. Fair value is determined as the
amount that would be obtained from the sale of the asset or CGU in an arm’s-length transaction between knowledgeable and
willing parties. For exploration properties, fair value is based on the implied fair value of the resources in place using
comparable market transaction metrics.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment
losses are recognized in earnings. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying
amount of any goodwill allocated to the CGU, and then to reduce the carrying amounts of the other assets in the CGU on a pro
rata basis.
Impairment losses recognized in prior periods are assessed throughout the year, whenever events or changes in
circumstances indicate that the impairment may have reversed. If the impairment has reversed, the carrying amount of the
asset is increased to its recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying
amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no
impairment loss had been recognized. A reversal of an impairment loss is recognized immediately in earnings. An impairment
loss in respect of goodwill is not reversed.
N.
Exploration and evaluation expenditures
Exploration and evaluation expenditures are those expenditures incurred by the Company in connection with the exploration
for and evaluation of mineral resources before the technical feasibility and commercial viability of extracting a mineral resource
are demonstrable. These expenditures include researching and analyzing existing exploration data, conducting geological
studies, exploratory drilling and sampling, and compiling prefeasibility and feasibility studies. Exploration and evaluation
expenditures are charged against earnings as incurred, except when there is a high degree of confidence in the viability of the
project and it is probable that these costs will be recovered through future development and exploitation.
The technical feasibility and commercial viability of extracting a resource is considered to be determinable based on several
factors, including the existence of proven and probable reserves and the demonstration that future economic benefits are
probable. When an area is determined to be technically feasible and commercially viable, the exploration and evaluation
assets attributable to that area are first tested for impairment and then transferred to property, plant and equipment.
Exploration and evaluation costs that have been acquired in a business combination or asset acquisition are capitalized under
the scope of IFRS 6, Exploration for and Evaluation of Mineral Resources, and are reported as part of property, plant and
equipment.
O.
Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be
estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions
are determined by discounting the risk-adjusted expected future cash flows at a pre-tax risk-free rate that reflects current
market assessments of the time value of money. The unwinding of the discount is recognized as a finance cost.
21
i.
Environmental restoration
The mining, extraction and processing activities of the Company normally give rise to obligations for site closure and
environmental restoration. Closure and restoration can include facility decommissioning and dismantling, removal or treatment
of waste materials, as well as site and land restoration. The Company provides for the closure, reclamation and
decommissioning of its operating sites in the financial period when the related environmental disturbance occurs, based on the
estimated future costs using information available at the reporting date. Costs included in the provision comprise all closure
and restoration activity expected to occur gradually over the life of the operation and at the time of closure. Routine operating
costs that may impact the ultimate closure and restoration activities, such as waste material handling conducted as a normal
part of a mining or production process, are not included in the provision.
The timing of the actual closure and restoration expenditure is dependent upon a number of factors such as the life and nature
of the asset, the operating licence conditions and the environment in which the mine operates. Closure and restoration
provisions are measured at the expected value of future cash flows, discounted to their present value using a current pre-tax
risk-free rate. Significant judgments and estimates are involved in deriving the expectations of future activities and the amount
and timing of the associated cash flows.
At the time a provision is initially recognized, to the extent that it is probable that future economic benefits associated with the
reclamation, decommissioning and restoration expenditure will flow to the Company, the corresponding cost is capitalized as
an asset. The capitalized cost of closure and restoration activities is recognized in property, plant and equipment and
depreciated on a unit-of-production basis. The value of the provision is gradually increased over time as the effect of
discounting unwinds. The unwinding of the discount is an expense recognized in finance costs.
Closure and rehabilitation provisions are also adjusted for changes in estimates. The provision is reviewed at each reporting
date for changes to obligations, legislation or discount rates that effect change in cost estimates or life of operations. The cost
of the related asset is adjusted for changes in the provision resulting from changes in estimated cash flows or discount rates,
and the adjusted cost of the asset is depreciated prospectively.
ii.
Waste disposal
The refining, conversion and manufacturing processes generate certain uranium-contaminated waste. The Company has
established strict procedures to ensure this waste is disposed of safely. A provision for waste disposal costs in respect of
these materials is recognized when they are generated. Costs associated with the disposal, the timing of cash flows and
discount rates are estimated both at initial recognition and subsequent measurement.
P.
Employee future benefits
i.
Pension obligations
The Company accrues its obligations under employee benefit plans. The Company has both defined benefit and defined
contribution plans. A defined contribution plan is a pension plan under which the Company pays fixed contributions into a
separate entity. The Company has no legal or constructive obligations to pay further contributions if the fund does not hold
sufficient assets to pay all employees the benefits relating to employee service in the current and prior periods. A defined
benefit plan is a pension plan other than a defined contribution plan. Typically,
defined benefit plans define an amount of
pension benefit that an employee will receive on retirement, usually dependent on one or more factors such as age, years of
service and compensation.
22
The liability recognized in the consolidated statements of financial position in respect of defined benefit pension plans is the
present value of the defined benefit obligation at the reporting date less the fair value of plan assets. The defined benefit
obligation is calculated annually, by qualified independent actuaries using the projected unit credit method prorated on service
and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees
and expected health care costs. The present value of the defined benefit obligation is determined by discounting the estimated
future cash outflows using interest rates of high-quality corporate bonds that are denominated in the currency in which the
benefits will be paid, and that have terms to maturity approximating the terms of the related pension liability.
The Company recognizes all actuarial gains and losses arising from defined benefit plans in other comprehensive income, and
reports them in retained earnings. When the benefits of a plan are improved, the portion of the increased benefit relating to
past service by employees is recognized immediately in earnings.
For defined contribution plans, the contributions are recognized as employee benefit expense in earnings in the periods during
which services are rendered by employees. Prepaid contributions are recognized as an asset to the extent that a cash refund
or a reduction in future payments is available.
ii.
Other post-retirement benefit plans
The Company provides certain post-retirement health care benefits to its retirees. The entitlement to these benefits is usually
conditional on the employee remaining in service up to retirement age and the completion of a minimum service period. The
expected costs of these benefits are accrued over the period of employment using the same accounting methodology as used
for defined benefit pension plans. Actuarial gains and losses are recognized in other comprehensive income in the period in
which they arise. These obligations are valued annually by independent qualified actuaries.
iii.
Short-term employee benefits
Short-term employee benefit obligations are measured on an undiscounted basis and are expensed as the related service is
provided. A liability is recognized for the amount expected to be paid under short-term cash bonus plans if the Company has a
present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the
obligation can be measured reliably.
iv.
Termination benefits
Termination
benefits are payable when employment is terminated by the Company before the normal retirement date, or
whenever an employee accepts an entity’s offer of benefits in exchange for termination of employment. Cameco recognizes
termination benefits as an expense at the earlier of when the Company can no longer withdraw the offer of those benefits and
when the Company recognizes costs for a restructuring. If benefits are payable more than 12 months after the reporting
period, they are discounted to their present value.
v.
Share-based compensation
For equity-settled plans, the grant date fair value of share-based compensation awards granted to employees is recognized as
an employee benefit expense, with a corresponding increase in equity, over the period that the employees unconditionally
become entitled to the awards. The amount recognized as an expense is adjusted to reflect the number of awards for which
the related service and vesting conditions are expected to be met, such that the amount ultimately recognized as an expense
is based on the number of awards that meet the related service and non-market performance conditions at the vesting date.
For cash-settled plans, the fair value of the amount payable to employees is recognized as an expense, with a corresponding
increase in liabilities, over the period that the employees unconditionally become entitled to payment. The liability is re-
measured at each reporting date and at settlement date. Any changes in the fair value of the liability are recognized as
employee benefit expense in earnings.
23
When the terms and conditions of equity-settled plans at the time they were granted are subsequently modified, the fair value
of the share-based payment under the original terms and conditions and under the modified terms and conditions are both
determined at the date of the modification. Any excess of the modified fair value over the original fair value is recognised over
the remaining vesting period in addition to the grant date fair value of the original share-based payment. The share-based
payment expense is not adjusted if the modified fair value is less than the original fair value.
Cameco’s contributions under the employee share ownership plan are expensed during the year of contribution. Shares
purchased with Company contributions and with dividends paid on such shares become unrestricted on January 1 of the
second plan year following the date on which such shares were purchased.
Q.
Revenue recognition
Cameco supplies uranium concentrates, uranium conversion services, fabrication services and other services. Revenue is
measured based on the consideration specified in a contract with a customer. The Company recognizes revenue when it
transfers control, as described below, over a good or service to a customer. Customers do not have the
right to return
products,
except in limited circumstances.
Cameco’s sales arrangements with its customers are pursuant to enforceable contracts that indicate the nature and timing of
satisfaction of performance obligations, including significant payment terms, where payment is usually due in 30 days. Each
delivery is considered a separate performance obligation under the contract.
Uranium supply
In a uranium supply arrangement, Cameco is contractually obligated to provide uranium concentrates to its customers.
Cameco-owned uranium may be physically delivered to either the customer or to conversion facilities (Converters).
For deliveries to customers, terms in the sales contract specify the location of delivery. Revenue is recognized when the
uranium has been delivered and accepted by the customer at that location.
When uranium is delivered to Converters, the Converter will credit Cameco’s account for the volume of accepted uranium.
Based on delivery terms in the sales contract with its customer, Cameco instructs the Converter to transfer title of a
contractually specified quantity of uranium to the customer’s account at the Converter’s facility. At this point, control has been
transferred and Cameco recognizes revenue for the uranium supply.
Toll conversion services
In a toll conversion arrangement, Cameco is contractually obligated to convert customer-owned uranium to a chemical state
suitable for enrichment. Based on delivery terms in a sales contract with its customer, Cameco either (i) physically delivers
converted uranium to enrichment facilities (Enrichers) where it instructs the Enricher to transfer title of a contractually specified
quantity of converted uranium to the customer’s account at the Enricher’s facility, or (ii) transfers title of a contractually
specified quantity of converted uranium to either an Enricher’s account or the customer’s account at Cameco’s Port Hope
conversion facility. At this point, the customer obtains control and Cameco recognizes revenue for the toll conversion services.
Conversion supply
A conversion supply arrangement is a combination of uranium supply and toll conversion services. Cameco is contractually
obligated to provide converted uranium to its customers. Based on delivery terms in the sales contract, Cameco either (i)
physically delivers converted uranium to the Enricher where it instructs the Enricher to transfer title of a contractually specified
quantity of converted uranium to the customer’s account at the Enricher’s facility, or (ii) transfers title of a contractually
specified quantity of converted uranium to either an Enricher’s account or a customer’s account at Cameco’s Port Hope
conversion facility. At this point, the customer obtains control and Cameco recognizes revenue for both the uranium supplied
and the conversion service provided.
24
Fabrication services
In a fabrication services arrangement, Cameco is contractually obligated to provide fuel bundles or reactor components to its
customers. In a contract for fuel bundles, the bundles are inspected and accepted by the customer at Cameco’s Port Hope
fabrication facility or another location based on delivery terms in the sales contract. At this point, the customer obtains control
and Cameco recognizes revenue for the fabrication services.
In some contracts for reactor components, the components are made to a customer’s specification and if a contract is
terminated by the customer, Cameco is entitled to reimbursement of the costs incurred to date, including a reasonable margin.
Since the customer controls all of the work in progress as the products are being manufactured, revenue and associated costs
are recognized over time, before the goods are delivered to the customer’s premises. Revenue is recognized on the basis of
units produced as the contracts reflect a per unit basis. Revenue from these contracts represents an insignificant portion of
Cameco’s total revenue. In other contracts where the reactor components are not made to a specific customer’s specification,
when the components are delivered to the location specified in the contract, the customer obtains control and Cameco
recognizes revenue for the services.
Other services
Uranium concentrates and converted uranium are regulated products and can only be stored at regulated facilities. In a
storage arrangement, Cameco is contractually obligated to store uranium products at its facilities on behalf of the customer.
Cameco invoices the customer in accordance with the contract terms and recognizes revenue on a monthly basis.
Cameco also provides customers with transportation of its uranium products. In the contractual arrangements where Cameco
is acting as the principal, revenue is recognized as the product is delivered.
R.
Financial instruments
A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity
instrument of another.
Trade receivables and debt securities are initially recognized when they are originated. All other financial assets and liabilities
are initially recognized when the company becomes a party to the contractual provisions of the instrument. A financial asset
(unless it is a trade receivable without a significant financing component) or financial liability is initially measured at fair value
plus, for an item not at fair value through profit or loss, transaction costs that are directly attributable to its acquisition or issue.
A trade receivable without a significant financing component is initially measured at the transaction price.
i.
Financial assets
On initial recognition, financial assets are classified as measured at: amortized cost, fair value through other comprehensive
income, or fair value through profit or loss based on the Company’s business model for managing its financial assets and their
cash flow characteristics. Classifications are not changed subsequent to initial recognition unless the Company changes its
business model for managing its financial assets, in which case all affected financial assets are reclassified on the first day of
the first reporting period following the change in business model.
Amortized cost
A financial asset is measured at amortized cost if it is not designated as at fair value through profit or loss, is held within a
business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise to cash
flows on specified dates that are solely payments of principal and interest on the principal amount outstanding. Assets in this
category are subsequently measured at amortized cost using the effective interest method. The amortized cost is reduced by
impairment losses. Interest income, foreign exchange gains and losses and impairment are recognized in profit or loss, as is
any gain or loss on derecognition.
25
Fair value through other comprehensive income (FVOCI)
A debt investment is measured at FVOCI if it is not designated as at fair value through profit or loss, is held within a business
model whose objective is achieved by both collecting contractual cash flows and selling financial assets and its contractual
terms give rise to cash flows on specified dates that are solely payments of principal and interest on the principal amount
outstanding. These assets are subsequently measured at fair value. Interest income calculated using the effective interest
method, foreign exchange gains and losses and impairment are recognized in profit or loss. Other net gains and losses are
recognized in other comprehensive income (OCI). On derecognition, gains and losses accumulated in OCI are reclassified to
profit or loss.
On initial recognition of an equity investment that is not held for trading, Cameco may irrevocably elect to present subsequent
changes in the investments fair value in OCI. This election is made on an investment by investment basis. These assets are
subsequently measured at fair value. Dividends are recognized as income in profit or loss unless the dividend clearly
represents a recovery of part of the cost of the investment. Other net gains and losses are recognized in OCI and are never
reclassified to profit or loss.
Fair value through profit or loss (FVTPL)
All financial assets not classified as measured at amortized cost or FVOCI are measured at FVTPL. This includes all derivative
financial assets. On initial recognition, the Company may irrevocably designate a financial asset that otherwise meets the
requirements to be measured at amortized cost or at FVOCI as at FVTPL if doing so eliminates or significantly reduces an
accounting mismatch that would otherwise arise. These assets are subsequently measured at fair value. Net gains and losses,
including any interest or dividend income, are recognized in profit or loss.
Derecognition of financial assets
Cameco derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the
rights to receive the contractual cash flows in a transaction in which substantially all of the risks and rewards of ownership of
the financial asset are transferred or in which it neither transfers or retains substantially all of the risks and rewards of
ownership and it does not retain control of the financial asset.
If the Company enters into a transaction whereby it transfers assets recognized in its statement of financial position, but
retains either all or substantially all of the risks and rewards of the transferred assets, the transferred assets would not be
derecognized.
ii.
Financial liabilities
On initial recognition, financial liabilities are classified as measured at amortized cost or FVTPL. A financial liability is classified
as FVTPL if it is classified as held-for-trading, is a derivative or is designated as such on initial recognition. Financial liabilities
at FVTPL are measured at fair value and net gains and losses, including any interest expense, are recognized in profit or loss.
Other financial liabilities are subsequently measured at amortized cost using the effective interest method. Interest expense
and foreign exchange gains and losses are recognized in profit or loss as is any gain or loss on derecognition.
A financial liability is derecognized when its contractual obligations are discharged or cancelled, or expire. The Company also
derecognizes a financial liability when its terms are modified and the cash flows of the modified liability are substantially
different, in which case a new financial liability based on the modified terms is recognized at fair value. On derecognition of a
financial liability, the difference between the carrying amount extinguished and the consideration paid (including any non-cash
assets transferred or liabilities assumed) is recognized in profit or loss.
iii.
Derivative financial instruments
The Company holds derivative financial instruments to reduce exposure to fluctuations in foreign currency exchange rates and
interest rates. Embedded derivatives are separated from the host contract and accounted for separately if the host contract is
not a financial asset and certain criteria are met.
26
Derivative financial instruments are initially measured at fair value in the consolidated statements of financial position, with any
directly attributable transaction costs recognized in profit or loss as incurred. Subsequent to initial recognition, derivatives are
measured at fair value, and changes in fair value are recognized in profit or loss.
The purpose of hedging transactions is to modify the Company’s exposure to one or more risks by creating an offset between
changes in the fair value of, or the cash flows attributable to, the hedged item and the hedging item. When hedge accounting
is appropriate, the hedging relationship is designated as a fair value hedge, a cash flow hedge, or a foreign currency risk
hedge related to a net investment in a foreign operation. The Company does not have any instruments that have been
designated as hedge transactions at December 31, 2022 and 2021.
S.
Income tax
Income tax expense is comprised of current and deferred taxes. Current tax and deferred tax are recognized in earnings
except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive
income.
Current tax is the expected tax payable or receivable on the taxable income or loss for the year, using tax rates enacted or
substantively enacted at the reporting date, and any adjustments to tax payable in respect of previous years. Current tax
assets and liabilities are measured at the amount expected to be paid or recovered from the taxation authorities.
Deferred tax is recognized in respect of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for taxation purposes. In addition, deferred tax is not recognized for taxable
temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected
to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted
by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax
liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on
different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities
will be realized simultaneously.
A deferred tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it
is probable that future taxable income will be available against which they can be utilized. Deferred tax assets are reviewed at
each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.
The Company’s exposure to uncertain tax positions is evaluated and a provision is made where it is probable that this
exposure will materialize.
T.
Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized
as a reduction of equity, net of any tax effects.
U.
Earnings per share
The Company presents basic and diluted earnings per share data for its common shares. Earnings per share is calculated by
dividing the net earnings attributable to equity holders of the Company by the weighted average number of common shares
outstanding.
Diluted earnings per share is determined by adjusting the net earnings attributable to equity holders of the Company and the
weighted average number of common shares outstanding, for the effects of all dilutive potential common shares. The
calculation of diluted earnings per share assumes that outstanding options which are dilutive to earnings per share are
exercised and the proceeds are used to repurchase shares of the Company at the average market price of the shares for the
period. The effect is to increase the number of shares used to calculate diluted earnings per share.
27
V.
Segment reporting
An operating segment is a component of the Company that engages in business activities from which it may earn revenues
and incur expenses, including revenues and expenses that relate to transactions with any of the Company’s other segments.
To
be classified as a segment, discrete financial information must be available and operating results must be regularly
reviewed by the Company’s executive team.
Segment capital expenditure is the total cost incurred during the period to acquire property, plant and equipment, and
intangible assets other than goodwill.
W.
Government assistance
Government grants are recognized when there is reasonable assurance that the Company has complied with the relevant
conditions of the grant and that the grant will be received. Grants that compensate the Company for expenses incurred are
recognized in profit or loss as other income on a systematic basis in the periods in which the expenses have been recognized.
3.
Accounting standards
A.
Changes in accounting policy
A number of amendments to existing standards became effective January 1, 2022 but they did not have an effect on the
Company’s financial statements.
B.
New standards and interpretations not yet adopted
A
number of amendments to existing standards are not yet effective for the year ended December 31, 2022 and have not been
applied in preparing these consolidated financial statements. Cameco does not intend to early adopt any of the amendments
and does not expect them to have a material impact on its financial statements.
4.
Determination of fair values
A number of the Company’s accounting policies and disclosures require the measurement of fair value, for both financial and
non-financial assets and liabilities.
The fair value of an asset or liability is generally estimated as the amount that would be received on sale of an asset, or paid to
transfer a liability in an orderly transaction between market participants at the reporting date. Fair values of assets and
liabilities traded in an active market are determined by reference to last quoted prices, in the principal market for the asset or
liability. In the absence of an active market for an asset or liability,
fair values are determined based on market quotes for
assets or liabilities with similar characteristics and risk profiles, or through other valuation techniques. Fair values determined
using valuation techniques require the use of inputs, which are obtained from external, readily observable market data when
available. In some circumstances, inputs that are not based on observable data must be used. In these cases, the estimated
fair values may be adjusted in order to account for valuation uncertainty, or to reflect the assumptions that market participants
would use in pricing the asset or liability.
All fair value measurements are categorized into one of three hierarchy levels, described below, for disclosure purposes. Each
level is based on the transparency of the inputs used to measure the fair values of assets and liabilities:
Level 1 – Values based on unadjusted quoted prices in active markets that are accessible at the reporting date for identical
assets or liabilities.
Level 2 – Values based on quoted prices in markets that are not active or model inputs that are observable either directly or
indirectly for substantially the full term of the asset or liability.
Level 3 – Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the
overall fair value measurement.
28
When the inputs used to measure fair value fall within more than one level of the hierarchy, the level within which the fair value
measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety.
Transfers between levels of the fair value hierarchy are recognized at the end of the reporting period during which the transfer
occurred. There were no transfers between level 1, level 2, or level 3 during the period. Cameco does not have any recurring
fair value measurements that are categorized as level 3 as of the reporting date.
Further information about the techniques and assumptions used to measure fair values is included in the following notes:
Note 6 - Acquisition of additional interest in Cigar Lake Joint Venture (CLJV)
Note 25 - Share-based compensation plans
Note 27 - Financial instruments and risk management
5.
Use of estimates and judgments
The preparation of the consolidated financial statements in conformity with IFRS requires management to make judgments,
estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities,
revenues and expenses. Actual results may differ from these estimates.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in
the period in which the estimates are revised and in any future period affected.
Information about critical judgments in applying the accounting policies that have the most significant effect on the amounts
recognized in the consolidated financial statements is discussed below. Further details of the nature of these judgments,
estimates and assumptions may be found in the relevant notes to the consolidated financial statements.
A.
Recoverability of long-lived and intangible assets and investments
Cameco assesses the carrying values of property, plant and equipment, intangible assets and investments in associates and
joint ventures when there is an indication of possible impairment. If it is determined that carrying values of assets cannot be
recovered, the unrecoverable amounts are charged against current earnings. Recoverability is dependent upon assumptions
and judgments regarding market conditions, costs of production, sustaining capital requirements, mineral reserves and the
impact of geopolitical events. Other assumptions used in the calculation of recoverable amounts are discount rates, future
cash flows and profit margins. A material change in assumptions may significantly impact the potential impairment of these
assets.
B.
Cash generating units
In performing impairment assessments of long-lived assets, assets that cannot be assessed individually are grouped together
into the smallest group of assets that generates cash inflows that are largely independent of the cash inflows from other assets
or groups of assets. Management is required to exercise judgment in identifying these CGUs.
C.
Provisions for decommissioning and reclamation of assets
Significant decommissioning and reclamation activities are often not undertaken until near the end of the useful lives of the
productive assets. Regulatory requirements and alternatives with respect to these activities are subject to change over time.
A
significant change to either the estimated costs, timing of the cash flows or mineral reserves may result in a material change in
the amount charged to earnings.
29
D.
Income taxes
Cameco operates in a number of tax jurisdictions and is, therefore, required to estimate its income taxes in each of these tax
jurisdictions in preparing its consolidated financial statements. In calculating income taxes, consideration is given to factors
such as tax rates in the different jurisdictions, non-deductible expenses, changes in tax law and management’s expectations of
future operating results. Cameco estimates deferred income taxes based on temporary differences between the income and
losses reported in its consolidated financial statements and its taxable income and losses as determined under the applicable
tax laws. The tax effect of these temporary differences is recorded as deferred tax assets or liabilities in the consolidated
financial statements. The calculation of income taxes requires the use of judgment and estimates. The determination of the
recoverability of deferred tax assets is dependent on assumptions and judgments regarding future market conditions and
production rates, which can materially impact estimated future taxable income. If these judgments and estimates prove to be
inaccurate, future earnings may be materially impacted.
E.
Mineral reserves
Depreciation on property, plant and equipment is primarily calculated using the unit-of-production method. This method
allocates the cost of an asset to each period based on current period production as a portion of total lifetime production or a
portion of estimated mineral reserves. Estimates of life-of-mine and amounts of mineral reserves are updated annually and are
subject to judgment and significant change over time. If actual mineral reserves prove to be significantly different than the
estimates, there could be a material impact on the amounts of depreciation charged to earnings.
6.
Acquisition of additional interest in Cigar
Lake Joint Venture (CLJV)
On May 19, 2022, Cameco and Orano Canada Inc. (Orano) completed the acquisition of Idemitsu Canada Resources Ltd.’s
(Idemitsu)
7.875
% participating interest in the CLJV by acquiring their pro rata shares through an asset purchase. Cameco’s
ownership stake in the Cigar Lake uranium mine in northern Saskatchewan is now
54.547
% (previously
50.025
%). The
primary reason for the business combination was to increase our ownership interest.
Cash consideration of $
101,681,000
was paid for the additional
4.522
% interest. At December 31, 2022, $
3,000,000
remained
in escrow, to be paid upon finalization of closing adjustments. While Cameco received the economic benefit of owning the
additional interest as of January 1, 2022, the additional interest has been proportionately consolidated with the results of
Cameco commencing on May 19, 2022.
CLJV allocates uranium production to each joint operation participant and the joint operation participant derives revenue
directly from the sale of such product. Mining and milling expenses incurred by joint operations are included in the cost of
inventory. As such, there is no revenue or profit or loss of the acquiree included in the consolidated statements of earnings. If
the acquisition had occurred at the beginning of the year, Cameco’s share of production would have included an additional
296,000
pounds. The impact to the financial statements would not have been material.
Acquisition costs of $
1,495,000
have been included in administration expense in the consolidated statements of earnings for
the year ended December 31, 2022.
30
Included in the identifiable assets and liabilities acquired at the date of acquisition are inputs, production processes and
outputs. Therefore, Cameco has determined that together the acquired set is a business. In accordance with the acquisition
method of accounting, the purchase price was allocated to the underlying assets and liabilities assumed based on their fair
values at the date of acquisition. Fair values were determined based on discounted cash flows and quoted market prices. The
values assigned to the net assets acquired were as follows:
Property, plant and equipment
$
97,930
Deferred tax asset
(a)
28,196
Inventory
9,909
Working capital
(24)
Reclamation provision
(2,528)
Sales contracts
(9,000)
Net assts acquired
$
124,483
Cash paid
101,681
Bargain purchase gain
(b)
$
22,802
(a)
The deferred tax asset has been measured provisionally, pending further review of the income tax attributes of the
acquisition.
(b)
The preliminary bargain purchase gain resulted from applying the measurement requirements under IFRS 3,
Business
Combinations
. This standard requires the measurement of tax attributes that were acquired as part of the transaction be in
accordance with IAS 12,
Income Taxes
, rather than at fair value. The measured amount of these attributes exceeded the
amount paid for them and the resulting gain is included in other income (expense) in the consolidated statement of earnings.
The accounting for the acquisition will be revised if, within one year of the acquisition date, new information is obtained about
facts and circumstances that existed at the date of acquisition. Revision will occur if this new information identifies adjustments
to the above amounts, or any additional provisions that existed at the date of acquisition.
7.
Accounts receivable
2022
2021
Trade receivables
$
167,688
$
271,015
GST/VAT
receivables
5,856
3,919
Other receivables
10,400
1,205
Total
$
183,944
$
276,139
The Company’s exposure to credit and currency risks as well as credit losses related to trade and other receivables, excluding
goods and services tax (GST)/value added tax (VAT)
receivables, is disclosed in note 27.
31
8.
Inventories
2022
2021
Uranium
Concentrate
$
537,426
$
319,257
Broken ore
46,703
46,324
584,129
365,581
Fuel services
80,144
43,549
Other
425
391
Total
$
664,698
$
409,521
Cameco expensed $
1,359,000,000
of inventory as cost of sales during 2022 (2021 - $
1,218,000,000
).
9.
Property, plant and equipment
At December 31, 2022
Land
Plant
Furniture
Exploration
and
and
and
Under
and
buildings
equipment
fixtures
construction
evaluation
Total
Cost
Beginning of year
$
5,152,209
$
2,732,561
$
84,366
$
167,200
$
1,073,239
$
9,209,575
Acquisitions [note 6]
67,998
27,646
70
2,216
-
97,930
Additions
4,385
8,927
209
129,734
193
143,448
Transfers
25,023
39,091
(167)
(63,518)
-
429
Change in reclamation provision [note 16]
(93,451)
-
-
-
-
(93,451)
Disposals
(4,885)
(8,423)
(650)
(1,046)
-
(15,004)
Effect of movements in exchange rates
45,859
12,507
252
4
14,802
73,424
End of year
5,197,138
2,812,309
84,080
234,590
1,088,234
9,416,351
Accumulated depreciation and impairment
Beginning of year
3,101,740
1,962,228
78,119
36,798
458,247
5,637,132
Depreciation charge
137,543
101,923
1,857
-
-
241,323
Change in reclamation provision [note 16]
(a)
22,944
-
-
-
-
22,944
Disposals
(4,851)
(8,201)
(649)
-
-
(13,701)
Effect of movements in exchange rates
43,493
12,049
249
-
8,824
64,615
End of year
3,300,869
2,067,999
79,576
36,798
467,071
5,952,313
Right-of-use assets
Beginning of year
931
1,584
1,641
-
-
4,156
Additions
5,917
1,330
606
-
-
7,853
Disposals
-
(11)
-
-
-
(11)
Depreciation charge
(870)
(560)
(687)
-
-
(2,117)
Transfers
(19)
(778)
368
-
-
(429)
End of year
5,959
1,565
1,928
-
-
9,452
Net book value at December 31, 2022
$
1,902,228
$
745,875
$
6,432
$
197,792
$
621,163
$
3,473,490
32
At December 31, 2021
Land
Plant
Furniture
Exploration
and
and
and
Under
and
buildings
equipment
fixtures
construction
evaluation
Total
Cost
Beginning of year
$
5,224,333
$
2,699,844
$
78,911
$
139,051
$
1,125,483
$
9,267,622
Additions
1,520
8,807
700
87,637
120
98,784
Transfers
17,145
31,243
5,130
(52,797)
-
721
Change in reclamation provision
(62,427)
-
-
-
-
(62,427)
Disposals
(23,075)
(6,019)
(345)
(6,691)
-
(36,130)
Effect of movements in exchange rates
(5,287)
(1,314)
(30)
-
(52,364)
(58,995)
End of year
5,152,209
2,732,561
84,366
167,200
1,073,239
9,209,575
Accumulated depreciation and impairment
Beginning of year
3,031,292
1,876,336
74,246
36,798
483,663
5,502,335
Depreciation charge
104,641
92,670
4,246
-
-
201,557
Change in reclamation provision
(a)
(8,407)
-
-
-
-
(8,407)
Disposals
(20,999)
(5,623)
(345)
-
-
(26,967)
Effect of movements in exchange rates
(4,787)
(1,155)
(28)
-
(25,416)
(31,386)
End of year
3,101,740
1,962,228
78,119
36,798
458,247
5,637,132
Right-of-use assets
Beginning of year
1,806
2,322
2,142
-
-
6,270
Additions
-
477
-
-
-
477
Depreciation charge
(875)
(494)
(501)
-
-
(1,870)
Transfers
-
(721)
-
-
-
(721)
End of year
931
1,584
1,641
-
-
4,156
Net book value at December 31, 2021
$
2,051,400
$
771,917
$
7,888
$
130,402
$
614,992
$
3,576,599
Cameco has contractual capital commitments of approximately $
56,500,000
at December 31, 2022. Certain of the contractual
commitments may contain cancellation clauses, however the Company discloses the commitments based on management’s
intent to fulfill the contract. The majority of this amount is expected to be incurred in 2023.
(a) Asset retirement obligation assets are adjusted when the Company updates its reclamation provisions due to new cash
flow estimates or changes in discount and inflation rates. When the assets of an operation have been written off due to an
impairment, as is the case with our Rabbit Lake operation and some of our operations in the United States, the adjustment is
recorded directly to the statement of earnings as other operating expense or income.
33
10.
Intangible assets
A.
Reconciliation of carrying amount
At December 31, 2022
Intellectual
Contracts
property
Total
Cost
Beginning of year
$
110,618
$
118,819
$
229,437
Effect of movements in exchange rates
8,027
-
8,027
End of year
118,645
118,819
237,464
Accumulated amortization and impairment
Beginning of year
109,886
68,304
178,190
Amortization charge
739
3,454
4,193
Effect of movements in exchange rates
7,964
-
7,964
End of year
118,589
71,758
190,347
Net book value at December 31, 2022
$
56
$
47,061
$
47,117
At December 31, 2021
Intellectual
Contracts
property
Total
Cost
Beginning of year
$
111,388
$
118,819
$
230,207
Effect of movements in exchange rates
(770)
-
(770)
End of year
110,618
118,819
229,437
Accumulated amortization and impairment
Beginning of year
109,663
64,722
174,385
Amortization charge
975
3,582
4,557
Effect of movements in exchange rates
(752)
-
(752)
End of year
109,886
68,304
178,190
Net book value at December 31, 2021
$
732
$
50,515
$
51,247
B.
Amortization
The intangible asset values relate to intellectual property acquired with Cameco Fuel Manufacturing Inc. (CFM) and purchase
and sales contracts acquired with NUKEM. The CFM intellectual property is being amortized on a unit-of-production basis over
its remaining life. Amortization is allocated to the cost of inventory and is recognized in cost of products and services sold as
inventory was sold. The purchase and sales contracts were amortized to earnings over the terms of the underlying contracts.
Amortization of the purchase contracts was allocated to the cost of inventory and included in cost of products and services
sold as inventory was sold. Sales contracts were amortized to revenue.
34
11.
Long-term receivables, investments and other
2022
2021
Deferred charges
$
29,585
$
-
Derivatives [note 27]
2,807
32,098
Investment tax credits
95,812
95,722
Amounts receivable related to tax dispute [note 22]
(a)
295,221
295,221
Product loan
(b)
200,998
176,904
Other
3,264
814
627,687
600,759
Less current portion
(32,180)
(23,232)
Net
$
595,507
$
577,527
(a)
Cameco was required to remit or otherwise secure 50% of the cash taxes and transfer pricing penalties, plus related
interest and instalment penalties assessed, in relation to its dispute with Canada Revenue Agency (CRA) (see note 22). In
light of our view of the likely outcome of the case, Cameco expects to recover the amounts remitted to CRA, including cash
taxes, interest and penalties totalling $
295,221,000
already paid as at December 31, 2022 (December 31, 2021 -
$
295,221,000
) (note 22).
(b)
Cameco loaned
5,400,000
pounds of uranium concentrate to its joint venture partner, Orano Canada Inc., (Orano). Orano
was obligated to repay the Company in kind with uranium concentrate no later than December 31, 2023. During the first
quarter of 2022, the repayment terms were extended to
December 31, 2028
. During 2022,
1,828,999
pounds were returned as
repayment on this loan.
Cameco also agreed to lend to Orano up to
1,148,200
kgU of conversion supply and up to an additional
1,200,000
pounds of
uranium concentrate over the period 2022 to 2024. Repayment to Cameco is to be made in kind with U
3
O
8
quantities drawn
being repaid by
December 31, 2027
and quantities of UF
6
drawn by
December 31, 2035
.
As at December 31, 2022,
3,571,001
pounds of U
3
O
8
and
700,000
kgU of UF
6
conversion supply were drawn on the loans and
are recorded at Cameco’s weighted average cost of inventory.
12.
Equity-accounted investee
JV Inkai is the operator of the Inkai uranium deposit located in Kazakhstan. Cameco holds a
40
% interest and Kazatomprom
holds a
60
% interest in JV Inkai. Cameco does not have joint control over the joint venture and as a result, Cameco accounts
for JV Inkai on an equity basis.
JV Inkai is a uranium mining and milling operation that utilizes in-situ recovery (ISR) technology to extract uranium. The
participants in JV Inkai purchase uranium from Inkai and, in turn, derive revenue directly from the sale of such product to third-
party customers.
The following tables summarize the financial information of JV Inkai (100%):
2022
2021
Cash and cash equivalents
$
14,950
$
12,893
Other current assets
373,868
301,589
Non-current assets
334,954
328,469
Current liabilities
(34,606)
(32,774)
Non-current liabilities
(37,644)
(38,635)
Net assets
$
651,522
$
571,542
35
2022
2021
Revenue from products and services
$
476,354
$
387,319
Cost of products and services sold
(66,119)
(55,397)
Depreciation and amortization
(24,749)
(25,300)
Finance income
1,341
349
Finance costs
(2,635)
(796)
Other expense
(30,770)
(16,636)
Income tax expense
(74,763)
(60,357)
Net earnings
278,659
229,182
Total comprehensive income
$
278,659
$
229,182
The following table reconciles the summarized financial information to the carrying amount of Cameco’s interest in JV Inkai:
2022
2021
Opening net assets
$
571,542
$
440,565
Total
comprehensive income
278,659
229,182
Dividends declared
(195,865)
(85,198)
Impact of foreign exchange
(2,814)
(13,007)
Closing net assets
651,522
571,542
Cameco's share of net assets
260,609
228,617
Consolidating adjustments
(a)
(82,275)
(60,348)
Fair value increment
(b)
83,675
85,976
Dividends in excess of ownership percentage
(c)
(48,641)
(22,085)
Impact of foreign exchange
(2,396)
1,080
Carrying amount in the statement of financial position
$
210,972
$
233,240
(a) Cameco records certain consolidating adjustments to eliminate unrealized profit and amortize historical differences in
accounting policies. This amount is amortized to earnings over units of production.
(b) Upon restructuring, Cameco assigned fair values to the assets and liabilities of JV Inkai. This increment is amortized to
earnings over units of production.
(c) Cameco’s share of dividends follows its production purchase entitlements which is currently higher than its ownership
interest.
13.
Accounts payable and accrued liabilities
2022
2021
Trade payables
$
249,962
$
213,377
Non-trade payables
65,182
66,048
Payables due to related parties [note 25]
59,570
61,033
Total
$
374,714
$
340,458
The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in note 27.
36
14.
Long-term debt
2022
2021
Unsecured debentures
Series F -
5.09
% debentures due
November 14, 2042
99,355
99,336
Series G -
4.19
% debentures due
June 24, 2024
499,407
499,010
Series H -
2.95
% debentures due
October 21, 2027
398,238
397,904
Total
$
997,000
$
996,250
Cameco has a $
1,000,000,000
unsecured revolving credit facility that is available until
October 1, 2026
. Upon mutual
agreement, the facility can be extended for an additional year on the anniversary date. In addition to direct borrowings under
the facility, up to $
100,000,000
can be used for the issuance of letters of credit and, to the extent necessary, it may be used to
provide liquidity support for the Company’s commercial paper program. The agreement also provides the ability to increase the
revolving credit facility above $
1,000,000,000
by increments no less than $
50,000,000
, to a total of $
1,250,000,000
. The
facility ranks equally with all of Cameco’s other senior debt. As of December 31, 2022 and 2021, there were
no
amounts
outstanding under this facility.
Cameco has $
1,756,754,000
(2021 - $
1,696,041,000
) in letter of credit facilities. Outstanding and committed letters of credit at
December 31, 2022 amounted to $
1,593,379,000
(2021 - $
1,573,873,000
), the majority of which relate to future
decommissioning and reclamation liabilities (note 16).
Cameco is bound by a covenant in its revolving credit facility. The covenant requires a funded debt to tangible net worth ratio
equal to or less than
1
:1. Non-compliance with this covenant could result in accelerated payment and termination of the
revolving credit facility. At December 31, 2022, Cameco was in compliance with the covenant and does not expect its
operating and investing activities in 2023 to be constrained by it.
The table below represents currently scheduled maturities of long-term debt:
2023
2024
2025
2026
2027
Thereafter
Total
$
-
499,407
-
-
398,238
99,355
$
997,000
15.
Other liabilities
2022
2021
Deferred sales [note 18]
$
66,845
$
23,316
Derivatives [note 27]
58,342
4,997
Accrued pension and post-retirement benefit liability [note 26]
66,180
89,002
Lease obligation
9,287
4,872
Product loan
(a)
78,094
15,763
Sales contracts [note 6]
9,000
-
Other
59,738
56,615
347,486
194,565
Less: current portion
(131,324)
(22,791)
Net
$
216,162
$
171,774
Expenses related to short-term leases and leases of low-value assets were insignificant during 2022
.
37
(a) The Company has standby product loan facilities with various counterparties. The arrangements allow it to borrow up to
2,438,000
kgU of UF
6
conversion services and
2,817,000
pounds of U
3
O
8
by September 30, 2026 with repayment in kind up to
December 31, 2026
. Under the facilities, standby fees of up to
1
% are payable based on the market value of the facilities and
interest is payable on the market value of any amounts drawn at rates ranging from
0.5
% to
2.0
%. At December 31, 2022, we
have
1,529,000
kgU of UF
6
conversion services drawn on the loans with repayment by December 31 of the following years:
2023
2024
2025
2026
Total
kgU of UF
6
331,000
-
287,000
911,000
1,529,000
We also have
1,393,000
pounds of U
3
O
8
drawn with repayment due no later than December 31, 2023 of the following years:
2023
2024
2025
2026
Total
lbs of U
3
O
8
1,150,000
-
-
243,000
1,393,000
The loans are recorded at Cameco’s weighted average cost of inventory.
16.
Provisions
Reclamation
Waste disposal
Total
Beginning of year
$
1,126,969
$
9,405
$
1,136,374
Changes in estimates and discount rates [note 9]
Capitalized in property, plant and equipment
(116,395)
-
(116,395)
Recognized in earnings [note 9]
22,944
1,564
24,508
Acquisitions [note 6]
2,528
-
2,528
Provisions used during the period
(27,159)
(1,333)
(28,492)
Unwinding of discount [note 20]
28,681
298
28,979
Effect of movements in exchange rates
23,528
-
23,528
End of period
$
1,061,096
$
9,934
$
1,071,030
Current
$
46,004
$
2,301
$
48,305
Non-current
1,015,092
7,633
1,022,725
$
1,061,096
$
9,934
$
1,071,030
The reclamation provision decreased by $
90,923,000
due largely to an increase in risk-free nominal and implied inflation rates
during the year.
A.
Reclamation provision
Cameco's estimates of future decommissioning obligations are based on reclamation standards that satisfy regulatory
requirements. Elements of uncertainty in estimating these amounts include potential changes in regulatory requirements,
decommissioning and reclamation alternatives and amounts to be recovered from other parties.
Cameco estimates total undiscounted future decommissioning and reclamation costs for its existing operating assets to be
$
1,356,092,000
(2021 - $
1,100,378,000
). The expected timing of these outflows is based on life-of-mine plans with the
majority of expenditures expected to occur after
2028
. These estimates are reviewed by Cameco technical personnel as
required by regulatory agencies or more frequently as circumstances warrant. In connection with future decommissioning and
reclamation costs, Cameco has provided financial assurances of $
1,035,348,000
(2021 - $
1,007,009,000
) in the form of letters
of credit to satisfy current regulatory requirements.
38
The reclamation provision relates to the following segments:
2022
2021
Uranium
$
870,877
$
900,482
Fuel services
190,219
226,487
Total
$
1,061,096
$
1,126,969
B.
Waste disposal
The fuel services segment consists of the Blind River refinery, Port Hope conversion facility and Cameco Fuel Manufacturing
Inc.. The refining, conversion and manufacturing processes generate certain uranium contaminated waste. These include
contaminated combustible material (paper, rags, gloves, etc.) and contaminated non-combustible material (metal parts, soil
from excavations, building and roofing materials, spent uranium concentrate drums, etc.). These materials can in some
instances be recycled or reprocessed. A provision for waste disposal costs in respect of these materials is recognized when
they are generated.
Cameco estimates total undiscounted future costs related to existing waste disposal to be $
8,919,000
(2021 - $
8,169,000
).
The majority of these expenditures are expected to occur within the next four years.
17.
Share capital
Authorized share capital:
-
Unlimited number of first preferred shares
-
Unlimited number of second preferred shares
-
Unlimited number of voting common shares,
no
stated par value, not convertible or redeemable, and
-
One Class B share
A.
Common Shares
Number issued
(number of shares)
2022
2021
Beginning of year
398,059,265
396,262,741
Issued:
Stock option plan [note 25]
401,955
1,796,524
Equity issuance
(a)
34,057,250
-
End of year
432,518,470
398,059,265
(a) On October 17, 2022, Cameco issued
34,057,250
common shares pursuant to a public offering for a total consideration of
$
996,867,000
. The proceeds of the issue after deducting expenses were $
964,878,000
. Excluding the deferred tax recoveries,
the net cash proceeds amounted to $
953,285,000
.
All issued shares are fully paid. Holders of the common shares are entitled to exercise one vote per share at meetings of
shareholders, are entitled to receive dividends if, as and when declared by our Board of Directors and are entitled to
participate in any distribution of remaining assets following a liquidation.
The shares of Cameco are widely held and
no shareholder, resident in Canada, is allowed to own more than 25% of the
Company’s outstanding common shares, either individually or together with associates. A non-resident of Canada is not
allowed to own more than 15%. In addition, no more than 25% of total shareholder votes cast may be cast by non-resident
shareholders.
39
B.
Class B share
One Class B share issued during 1988 and assigned $
1
of share capital
entitles the shareholder to vote separately as a class
in respect of any proposal to locate the head office of Cameco to a place not in the province of Saskatchewan
.
C.
Dividends
Dividends on Cameco Corporation common shares are declared in Canadian dollars. For the year ended December 31, 2022,
the dividend declared per share was $
0.12
(December 31, 2021 - $
0.08
).
18.
Revenue
Cameco’s sales contracts with customers contain both fixed and market-related pricing. Fixed-price contracts are typically
based on a term-price indicator at the time the contract is accepted and escalated over the term of the contract. Market-related
contracts are based on either the spot price or long-term price, and the price is quoted at the time of delivery rather than at the
time the contract is accepted. These contracts often include a floor and/or ceiling prices, which are usually escalated over the
term of the contract. Escalation is generally based on a consumer price index. The Company’s contracts contain either one of
these pricing mechanisms or a combination of the two. There is no variable consideration in the contracts and therefore no
revenue is considered constrained at the time of delivery. Cameco expenses the incremental costs of obtaining a contract as
incurred as the amortization period is less than a year.
The following table summarizes Cameco’s sales disaggregated by geographical region and contract type and includes a
reconciliation to the Company’s reportable segments (note 29):
For the year ended December 31, 2022
Uranium
Fuel services
Other
Total
Customer geographical region
Americas
$
806,915
$
289,028
$
20,025
$
1,115,968
Europe
284,602
52,112
2,769
339,483
Asia
388,629
23,923
-
412,552
$
1,480,146
$
365,063
$
22,794
$
1,868,003
Contract type
Fixed-price
$
478,552
$
355,479
$
22,794
$
856,825
Market-related
1,001,594
9,584
-
1,011,178
$
1,480,146
$
365,063
$
22,794
$
1,868,003
For the year ended December 31, 2021
Uranium
Fuel services
Other
Total
Customer geographical region
Americas
$
547,257
$
287,802
$
12,769
$
847,828
Europe
218,879
77,110
2,945
298,934
Asia
288,857
39,365
-
328,222
$
1,054,993
$
404,277
$
15,714
$
1,474,984
Contract type
Fixed-price
$
307,858
$
384,065
$
11,421
$
703,344
Market-related
747,135
20,212
4,293
771,640
$
1,054,993
$
404,277
$
15,714
$
1,474,984
40
Deferred sales
The following table provides information about contract liabilities (note 15) from contracts with customers:
2022
2021
Beginning of year
$
23,316
$
14,382
Additions
45,978
16,531
Recognized in revenue
(2,463)
(7,596)
Effect of movements in exchange rates
14
(1)
End of year
$
66,845
$
23,316
Deferred sales primarily relates to advance consideration received from customers for future uranium and conversion
deliveries as well as revenue related to the storage of uranium and converted uranium held at Cameco facilities.
The revenue
related to storage is recognized over time while the revenue related to future uranium and conversion deliveries is expected to
be recognized between 2023 and 2030.
Cameco recognized a decrease of revenue of $
194,000
(2021 - increase of revenue of $
383,000
) during 2022 from
performance obligations satisfied (or partially satisfied) in previous periods. This is due to the difference between actual pricing
indices and the estimates at the time of invoicing.
Future sales commitments
Cameco’s sales portfolio consists of short and long-term sales commitments. The contracts can be executed well in advance
of a delivery and include both fixed and market-related pricing.
The following table summarizes the expected future revenue,
by segment, related to only fixed-price contracts with remaining future deliveries as follows:
2023
2024
2025
2026
2027
Thereafter
Total
Uranium
$
556,122
$
629,675
$
627,534
$
237,052
$
238,354
$
622,034
$
2,910,771
Fuel services
339,355
355,915
329,091
244,236
235,089
1,016,232
2,519,918
Total
$
895,477
$
985,590
$
956,625
$
481,288
$
473,443
$
1,638,266
$
5,430,689
The sales contracts are denominated largely in US dollars and converted from US to Canadian dollars at a rate of $
1.30
.
The amounts in the table represent the consideration the Company will be entitled to receive when it satisfies the remaining
performance obligations in the contracts. The amounts include assumptions about volumes for contracts that have volume
flexibility. Cameco’s total revenue that will be earned will also include revenue from contracts with market-related pricing. The
Company has elected to exclude these amounts from the table as the transaction price will not be known until the time of
delivery. Contracts with an original duration of one year or less have been included in the table.
41
19.
Employee benefit expense
The following employee benefit expenses are included in cost of products and services sold, administration, exploration,
research and development and property, plant and equipment:
2022
2021
Wages and salaries
$
278,980
$
236,181
Statutory and company benefits
52,247
43,870
Expenses related to defined benefit plans [note 26]
5,656
5,350
Expenses related to defined contribution plans [note 26]
15,189
12,939
Equity-settled share-based compensation [note 25]
6,859
7,837
Cash-settled share-based compensation [note 25]
24,369
41,839
Total
$
383,300
$
348,016
20.
Finance costs
2022
2021
Interest on long-term debt
$
40,059
$
39,266
Unwinding of discount on provisions [note 16]
28,979
21,445
Other charges
16,690
15,901
Total
$
85,728
$
76,612
No
borrowing costs were determined to be eligible for capitalization during the year.
21.
Other income (expense)
2022
2021
Foreign exchange gains
74,132
446
Government assistance
(a)
-
21,209
Bargain purchase gain [note 6]
22,802
-
Other
-
(302)
Total
$
96,934
$
21,353
(a)
In response to the negative economic impact of COVID-19, the Government of Canada announced the Canada
Emergency Wage Subsidy program (CEWS). CEWS provides a subsidy on eligible remuneration based on certain criteria. In
2021, the Company qualified for the subsidy for the periods January through June.
There were no unfulfilled conditions and
other contingencies attached to this government assistance.
42
22.
Income taxes
A.
Significant components of deferred tax assets and liabilities
Recognized in earnings
As at December 31
2022
2021
2022
2021
Assets
Property, plant and equipment
$
84,668
$
82,677
$
448,136
$
363,468
Provision for reclamation
(3,817)
(14,509)
203,816
207,633
Inventories
1,689
2,489
8,248
6,559
Foreign exploration and development
(1,816)
(812)
2,641
4,457
Income tax losses (gains)
(66,227)
(80,802)
235,683
301,910
Defined benefit plan actuarial losses
-
-
2,698
8,126
Long-term investments and other
(2,355)
16,405
82,849
45,426
Deferred tax assets
12,142
5,448
984,071
937,579
Liabilities
Property, plant and equipment
-
-
-
-
Inventories
-
-
-
-
Deferred tax liabilities
-
-
-
-
Net deferred tax asset
$
12,142
$
5,448
$
984,071
$
937,579
Deferred tax allocated as
2022
2021
Deferred tax assets
$
984,071
$
937,579
Deferred tax liabilities
-
-
Net deferred tax asset
$
984,071
$
937,579
Cameco has recorded a deferred tax asset of $
984,071,000
(2021 - $
937,579,000
). The realization of this deferred tax asset is
dependent upon the generation of future taxable income in certain jurisdictions during the periods in which the Company’s
deferred tax assets are available. The Company considers whether it is probable that all or a portion of the deferred tax assets
will not be realized. In making this assessment, management considers all available evidence, including recent financial
operations, projected future taxable income and tax planning strategies. Based on projections of future taxable income over
the periods in which the deferred tax assets are available, realization of these deferred tax assets is probable and
consequently the deferred tax assets have been recorded.
43
B.
Movement in net deferred tax assets and liabilities
2022
2021
Deferred tax asset at beginning of year
$
937,579
$
936,678
Recovery for the year in net earnings
12,142
5,448
Recovery for the year in equity
11,593
-
Recovery for the year in purchase price equation
28,196
-
Expense for the year in other comprehensive income
(5,440)
(4,541)
Effect of movements in exchange rates
1
(6)
End of year
$
984,071
$
937,579
C.
Significant components of unrecognized deferred tax assets
2022
2021
Income tax losses
$
337,749
$
288,637
Property, plant and equipment
2,297
2,209
Provision for reclamation
78,336
66,573
Long-term investments and other
18,628
58,330
Total
$
437,010
$
415,749
D.
Tax rate reconciliation
The provision for income taxes differs from the amount computed by applying the combined expected federal and provincial
income tax rate to earnings before income taxes. The reasons for these differences are as follows:
2022
2021
Earnings (loss) before income taxes and non-controlling interest
$
84,795
$
(103,855)
Combined federal and provincial tax rate
26.9%
26.9%
Computed income tax expense (recovery)
22,810
(27,937)
Increase (decrease) in taxes resulting from:
Difference between Canadian rates and rates
applicable to subsidiaries in other countries
8,986
28,690
Change in unrecognized deferred tax assets
1,234
22,068
Income in equity-accounted investee
(25,264)
(24,481)
Change in uncertain tax positions
(6,282)
1,099
Bargain purchase gain
(6,129)
-
Other permanent differences
176
(640)
Income tax recovery
$
(4,469)
$
(1,201)
44
E.
Earnings and income taxes by jurisdiction
2022
2021
Earnings (loss) before income taxes
Canada
$
99,944
$
58,624
Foreign
(15,149)
(162,479)
$
84,795
$
(103,855)
Current income taxes
Canada
$
2,260
$
2,257
Foreign
5,413
1,990
$
7,673
$
4,247
Deferred income tax recovery
Canada
$
(10,178)
$
(3,937)
Foreign
(1,964)
(1,511)
$
(12,142)
$
(5,448)
Income tax recovery
$
(4,469)
$
(1,201)
F.
Reassessments
Canada
On February 18, 2021, the Supreme Court of Canada (Supreme Court) dismissed Canada Revenue Agency’s (CRA)
application for leave to appeal the June 26, 2020 decision of the Federal Court of Appeal (Court of Appeal). The dismissal
means that the dispute for the 2003, 2005 and 2006 tax years is fully and finally resolved in the Company’s favour.
In September 2018, the Tax
Court of Canada (Tax Court) ruled that the marketing and trading structure involving foreign
subsidiaries, as well as the related transfer pricing methodology used for certain intercompany uranium sales and purchasing
agreements, were in full compliance with Canadian law for the tax years in question. Management believes the principles in
the decision apply to all subsequent tax years, and that the ultimate resolution of those years will not be material to Cameco’s
financial position, results of operations or liquidity in the year(s) of resolution.
The total tax reassessed for the three tax years was $
11,000,000
, and Cameco remitted
50
%. In 2021, Cameco received
refunds totaling about $
5,500,000
plus interest.
In addition, on April 30, 2019, the Tax Court had awarded Cameco $
10,300,000
for legal fees incurred, plus an amount for
disbursements of up to $
16,700,000
. As a result of additional information provided by the Tax Court, $
12,200,000
for
disbursements was recognized as a reduction of administration expense in 2021.
If CRA continues to pursue reassessments for tax years subsequent to 2006, Cameco will continue to utilize its appeal rights
under Canadian federal and provincial tax rules.
45
G.
Income tax losses
At December 31, 2022, income tax losses carried forward of $
2,171,825,000
(2021 - $
2,177,025,000
) are available to reduce
taxable income. These losses expire as follows:
Date of expiry
Canada
US
Other
Total
2026
$
-
$
-
$
14,720
$
14,720
2027
-
-
243
243
2028
-
-
63
63
2029
47
-
12,625
12,672
2031
-
21,768
-
21,768
2032
272
23,444
-
23,716
2033
-
36,033
-
36,033
2034
-
16,724
4,526
21,250
2035
282,522
7,622
7,233
297,377
2036
210,591
46,621
5,698
262,910
2037
27
34,921
2,985
37,933
2038
500
37,660
320
38,480
2039
6,423
29,130
335
35,888
2040
3,110
55,775
-
58,885
2041
77
229,464
-
229,541
2042
49
22,577
-
22,626
No expiry
-
-
1,057,720
1,057,720
$
503,618
$
561,739
$
1,106,468
$
2,171,825
Included in the table above is $
1,329,261,000
(2021 - $
1,083,848,000
) of temporary differences related to loss carry forwards
where no future benefit has been recognized.
23.
Per share amounts
Per share amounts have been calculated based on the weighted average number of common shares outstanding during the
period. The weighted average number of paid shares outstanding in 2022 was
405,494,353
(2021 -
397,630,947
).
2022
2021
Basic earnings (loss) per share computation
Net earnings (loss) attributable to equity holders
$
89,382
$
(102,577)
Weighted average common shares outstanding
405,494
397,631
Basic earnings (loss) per common share
$
0.22
$
(0.26)
Diluted earnings (loss) per share computation
Net earnings (loss) attributable to equity holders
$
89,382
$
(102,577)
Weighted average common shares outstanding
405,494
397,631
Dilutive effect of stock options
1,641
-
Weighted average common shares outstanding, assuming dilution
407,135
397,631
Diluted earnings (loss) per common share
$
0.22
$
(0.26)
In 2022, there were
no
options excluded from the diluted weighted average number of common shares because their inclusion
would have been anti-dilutive (2021 -
1,802
).
46
24.
Supplemental cash flow information
Other operating items included in the statements of cash flows are as follows:
2022
2021
Changes in non-cash working capital:
Accounts receivable
$
99,601
$
(75,678)
Inventories
(162,858)
300,307
Supplies and prepaid expenses
(63,500)
(5,908)
Accounts payable and accrued liabilities
16,401
91,757
Reclamation payments
(28,492)
(19,542)
Other
19,417
(3,683)
Total
$
(119,431)
$
287,253
The changes arising from financing activities were as follows:
Long-term
Interest
Lease
Dividends
Share
debt
payable
obligation
payable
capital
Total
Balance at January 1, 2022
$
996,250
$
3,558
$
4,872
$
-
$
1,903,357
$
2,908,037
Changes from financing cash flows:
Dividends paid
-
-
-
(51,895)
-
(51,895)
Interest paid
-
(38,531)
(325)
-
-
(38,856)
Lease principal payments
-
-
(2,908)
-
-
(2,908)
Shares issued, stock option plan
-
-
-
-
9,632
9,632
Issuance of shares [note 17]
-
-
-
-
953,285
953,285
Total cash changes
-
(38,531)
(3,233)
(51,895)
962,917
869,258
Non-cash changes:
Amortization of issue costs
750
-
-
-
-
750
Dividends declared
-
-
-
51,895
-
51,895
Interest expense
-
38,984
325
-
-
39,309
Right-of-use asset additions
-
-
7,853
-
-
7,853
Other
-
-
(523)
-
-
(523)
Shares issued, stock option plan
-
-
-
-
2,469
2,469
Issuance of shares, deferred tax [note 17]
-
-
-
-
11,593
11,593
Foreign exchange
-
-
(7)
-
-
(7)
Total non-cash changes
750
38,984
7,648
51,895
14,062
113,339
Balance at December 31, 2022
$
997,000
$
4,011
$
9,287
$
-
$
2,880,336
$
3,890,634
25.
Share-based compensation plans
The Company has the following plans:
A.
Stock option plan
The Company has established a stock option plan under which options to purchase common shares may be granted to
employees of Cameco. Options granted under the stock option plan have an exercise price of not less than the closing price
quoted on the Toronto
Stock Exchange (TSX) for the common shares of Cameco on the trading day prior to the date on which
the option is granted. The options carry vesting periods of
one
to
three years
, and expire
eight years
from the date granted.
47
The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed
43,017,198
of which
30,538,777
shares have been issued.
Stock option transactions for the respective years were as follows:
(Number of options)
2022
2021
Beginning of year
3,458,001
6,158,539
Options granted
-
-
Options forfeited
-
(18,005)
Options expired
(2,475)
(886,009)
Options exercised [note 17]
(401,955)
(1,796,524)
End of year
3,053,571
3,458,001
Exercisable
3,053,571
3,162,415
Weighted average share prices were as follows:
2022
2021
Beginning of year
$16.72
$16.98
Options granted
-
-
Options forfeited
-
26.08
Options expired
26.81
22.05
Options exercised
23.96
14.90
End of year
$15.75
$16.72
Exercisable
$15.75
$16.85
The weighted average share price at the dates of exercise during 2022 was $
23.96
per share (2021 - $
22.09
).
Total
options outstanding and exercisable at December 31, 2022 were as follows:
Options outstanding
Options exercisable
Option price per share
Number
Weighted
average
remaining
life
Weighted
average
exercisable
price
Number
Weighted
average
exercisable
price
$
11.32
-
15.83
1,772,271
3.2
$14.57
1,772,271
$14.57
$
15.84
-
19.3
1,281,300
0.8
$17.39
1,281,300
$17.39
3,053,571
3,053,571
The foregoing options have expiry dates ranging from March 1, 2023 to February 28, 2027.
48
B.
Executive performance share unit (PSU)
The Company has established a PSU plan whereby it provides each plan participant an annual grant of PSUs in an amount
determined by the board. Each PSU represents one phantom common share that entitles the participant to a payment of one
Cameco common share purchased on the open market, or cash with an equivalent market value, at the participant’s discretion
provided they have met their ownership requirements, at the end of each three-year period if certain performance and vesting
criteria have been met. The final value of the PSUs will be based on the value of Cameco common shares at the end of the
three-year period and the number of PSUs that ultimately vest. During the vesting period, dividend equivalents accrue to the
participants in the form of additional share units as of each normal cash dividend payment date of Cameco’s common shares.
Vesting of PSUs at the end of the three-year period is based on Cameco’s ability to meet its annual operating targets and
whether the participating executive remains employed by Cameco at the end of the
three-year vesting period
. If the participant
elects a cash payout, the redemption amount will be based on the volume-weighted average trading price of Cameco’s
common shares on March 1 or, if March 1 is not a trading day,
on the first trading day following March 1. As of December 31,
2022, the total number of PSUs held by the participants, after adjusting for forfeitures on retirement, was
1,255,255
(2021 -
1,495,709
).
C.
Restricted share unit (RSU)
The Company has established an RSU plan whereby it provides each plan participant an annual grant of RSUs in an amount
determined by the board. Each RSU represents one phantom common share that entitles the participant to a payment of one
Cameco common share purchased on the open market, or cash with an equivalent market value, at the board’s discretion.
The RSUs carry vesting periods of one to three years
, and the final value of the units will be based on the value of Cameco
common shares at the end of the vesting periods. In addition, certain eligible participants have a single vesting date on the
third anniversary of the date of the grant. These same participants, if they have met or are not subject to share ownership
requirements, may elect to have their award paid as a lump sum cash amount. During the vesting period, dividend equivalents
accrue to the participants in the form of additional share units as of each normal cash dividend payment date of Cameco’s
common shares. As of December 31, 2022, the total number of RSUs held by the participants was
1,131,493
(2021 -
1,081,783
).
D.
Phantom stock option
The Company has established a phantom stock option plan for eligible non-North American employees. Employees receive
the equivalent value of shares in cash when exercised. Options granted under the phantom stock option plan have an award
value equal to the closing price quoted on the TSX for the common shares of Cameco on the trading day prior to the date on
which the option is granted. The options
vest over three years and expire eight years from the date granted
. As of
December 31, 2022, the number of options held by participating employees was
94,135
(2021 -
173,835
) with exercise prices
ranging from $
11.32
to $
19.30
per share (2021 - $
11.32
to $
26.81
) and a weighted average exercise price of $
12.55
(2021 -
$
13.88
).
E.
Phantom restricted share unit (PRSU)
The Company has established a PRSU plan whereby it provides non-North American employees an annual grant of PRSUs in
an amount determined by the board. Each PRSU represents one phantom common share that entitles the participant to a
payment of cash with an equivalent market value.
The PRSUs carry vesting periods of one to three years
, and the final value
of the units will be based on the value of Cameco common shares at the end of the vesting periods. In addition, certain eligible
participants have a single vesting date on the third anniversary of the date of the grant. During the vesting period, dividend
equivalents accrue to the participants in the form of additional share units as of each normal cash dividend payment date of
Cameco’s common shares. As of December 31, 2022, the total number of PRSUs held by the participants was
21,148
(2021 -
16,027
).
49
F.
Employee share ownership plan
Cameco also has an employee share ownership plan, whereby both employee and Company contributions are used to
purchase shares on the open market for employees. The Company’s contributions are expensed during the year of
contribution.
Under the plan, employees have the opportunity to participate in the program to a maximum of 6% of eligible
earnings each year with Cameco matching the first 3% of employee-paid shares by 50%. Cameco contributes $1,000 of
shares annually to each employee that is enrolled in the plan
.
Shares purchased with Company contributions and with
dividends paid on such shares become unrestricted 12 months from the date on which such shares were purchased
. At
December 31, 2022, there were
2,603
participants in the plan (2021 -
2,301
). The total number of shares purchased in 2022
with Company contributions was
116,530
(2021 -
149,822
). In 2022, the Company’s contributions totaled $
3,541,000
(2021 -
$
3,301,000
).
G.
Deferred share unit (DSU)
Cameco offers a DSU plan to non-employee directors. A DSU is a notional unit that reflects the market value of a single
common share of Cameco.
60% of each director’s annual retainer is paid in DSUs. In addition, on an annual basis, directors
can elect to receive 25%, 50%, 75% or 100% of the remaining 40% of their annual retainer and any additional fees in the form
of DSUs
. If a director meets their ownership requirements, the director may elect to take 25%, 50%, 75% or 100% of their
annual retainer and any fees in cash, with the balance, if any, to be paid in DSUs.
Each DSU fully vests upon award
. Dividend
equivalents accrue to the participants in the form of additional share units as of each normal cash dividend payment date of
Cameco’s common shares. The DSUs will be redeemed for cash upon a director leaving the board. The redemption amount
will be based upon the weighted average of the closing prices of the common shares of Cameco on the TSX for the last 20
trading days prior to the redemption date multiplied by the number of DSUs held by the director. As of December 31, 2022, the
total number of DSUs held by participating directors was
547,304
(2021 -
579,362
).
Equity-settled plans
Cameco records compensation expense under its equity-settled plans with an offsetting credit to contributed surplus, to reflect
the estimated fair value of units granted to employees. During the year, the Company recognized the following expenses
under these plans:
2022
2021
Employee share ownership plan
$
3,541
$
3,301
Restricted share unit plan
3,273
2,933
Performance share unit plan
(a)
-
1,237
Stock option plan
45
366
Total
$
6,859
$
7,837
(a)
There are
no
remaining PSUs whereby it is at the board’s discretion whether shares will be purchased on the open market
or redeemed for cash with an equivalent market value.
Fair value measurement of equity-settled plans
The fair value of RSUs granted was determined based on their intrinsic value on the date of grant. Expected volatility was
estimated by considering historic average share price volatility.
50
The inputs used in the measurement of the fair values at grant date of the equity-settled RSU plan were as follows:
Grant date
Mar 1/22
Number of options granted
129,910
Average strike price
$31.17
Expected forfeitures
10%
Weighted average grant date fair values
$31.17
Cash-settled plans
Cameco has recognized the following expenses under its cash-settled plans:
2022
2021
Performance share unit plan
$
11,221
$
25,784
Restricted share unit plan
9,342
6,890
Deferred share unit plan
2,811
6,741
Phantom stock option plan
751
2,261
Phantom restricted share unit plan
244
163
Total
$
24,369
$
41,839
At December 31, 2022, a liability of $
59,577,000
(2021 - $
61,030,000
) was included in the consolidated statement of financial
position to recognize accrued but unpaid expenses for cash-settled plans.
Fair value measurement of cash-settled plans
The fair value of the units granted through the PSU plan was determined based on Monte Carlo simulation and projections of
the non-market criteria. The fair value of RSUs and PRSUs granted was determined based on their intrinsic value on the date
of grant. The phantom stock option plan was measured based on the Black-Scholes option-pricing model. Expected volatility is
estimated by considering historic average share price volatility.
The inputs used in the measurement of the fair values of the cash-settled share-based payment plans at the March 1, 2022
grant date were as follows:
Phantom
PSU
RSU
RSU
Number of units
238,610
159,140
10,142
Expected vesting
92%
-
-
Expected dividend
-
-
$0.08
Expected life of option
3
years
3
years
3
years
Expected forfeitures
9%
9%
7%
Weighted average measurement date fair values
$31.17
$31.17
$31.17
51
The inputs used in the measurement of the fair values of the cash-settled share-based payment plans at the reporting date
were as follows:
Phantom
Phantom
stock options
PSU
RSU
RSU
Number of units
94,135
1,255,255
815,098
21,148
Expected vesting
-
72%
-
-
Average strike price
$12.55
-
-
-
Expected dividend
$0.12
-
-
$0.12
Expected volatility
53%
-
-
-
Risk-free interest rate
3.8%
-
-
-
Expected life of option
3
years
0.7
years
0.8
years
1.4
years
Expected forfeitures
7%
2%
8%
8%
Weighted average measurement date fair values
$20.22
$30.69
$30.69
$30.69
In addition to these inputs, other features of the PSU grant were incorporated into the measurement of fair value. The non-
market criteria relating to realized selling prices and operating targets have been incorporated into the valuation at both grant
and reporting date by reviewing prior history and corporate budgets.
26.
Pension and other post-retirement benefits
Cameco maintains both defined benefit and defined contribution plans providing pension benefits to substantially all of its
employees. All regular and temporary employees participate in a registered defined contribution plan. This plan is registered
under the Pension Benefits Standard Act, 1985. In addition, all Canadian-based executives participate in a non-registered
supplemental executive pension plan which is a defined benefit plan.
Under the supplemental executive pension plan (SEPP), Cameco provides a lump sum benefit equal to the present value of a
lifetime pension benefit based on the executive’s length of service and final average earnings. The plan provides for
unreduced benefits to be paid at the normal retirement age of 65, however unreduced benefits could be paid if the executive
was at least 60 years of age and had 20 years of service at retirement. This program provides for a benefit determined by a
formula based on earnings and service, reduced by the benefits payable under the registered base plan. Security is provided
for the SEPP benefits through a letter of credit held by the plan’s trustee. The face amount of the letter of credit is determined
each year based on the wind-up liabilities of the supplemental plan, less any plan assets currently held with the trustee. A
valuation is required annually to determine the letter of credit amount. Benefits will continue to be paid from plan assets until
the fund is exhausted, at which time Cameco will begin paying benefits from corporate assets.
Cameco also maintains non-pension post-retirement plans (“other benefit plans”) which are defined benefit plans that cover
such benefits as group life insurance and supplemental health and dental coverage to eligible employees and their
dependents. The costs related to these plans are charged to earnings in the period during which the employment services are
rendered. These plans are funded by Cameco as benefit claims are made.
The board of directors of Cameco has final responsibility and accountability for the Cameco retirement programs. The board is
ultimately responsible for managing the programs to comply with applicable legislation, providing oversight over the general
functions and setting certain policies.
Cameco expects to pay $
1,675,000
in contributions and letter of credit fees to its defined benefit plans in 2023.
The post-retirement plans expose Cameco to actuarial risks, such as longevity risk, market risk, interest rate risk, liquidity risk
and foreign currency risk. The other benefit plans expose Cameco to risks of higher supplemental health and dental utilization
than expected. However, the other benefit plans have limits on Cameco’s annual benefits payable.
The effective date of the most recent valuation for funding purposes on the registered defined benefit pension plans is
January 1, 2021. The next planned effective date for valuations is January 1, 2024.
52
Cameco has more than one defined benefit plan and has generally provided aggregated disclosures in respect of these plans,
on the basis that these plans are not exposed to materially different risks. Information relating to Cameco’s defined benefit
plans is shown in the following table:
Pension benefit plans
Other benefit plans
2022
2021
2022
2021
Fair value of plan assets, beginning of year
$
5,693
$
6,217
$
-
$
-
Interest income on plan assets
157
144
-
-
Return on assets excluding interest income
(555)
172
-
-
Employer contributions
-
67
-
-
Benefits paid
(890)
(903)
-
-
Administrative costs paid
(3)
(4)
-
-
Fair value of plan assets, end of year
$
4,402
$
5,693
$
-
$
-
Defined benefit obligation, beginning of year
$
69,998
$
72,119
$
24,697
$
25,827
Current service cost
2,302
2,332
915
956
Interest cost
1,867
1,550
726
652
Actuarial loss (gain) arising from:
- financial assumptions
(20,913)
(1,996)
(5,881)
(1,403)
- experience adjustment
1,396
(903)
161
(697)
Benefits paid
(3,666)
(1,741)
(1,254)
(638)
Foreign exchange
234
(1,363)
-
-
Defined benefit obligation, end of year
$
51,218
$
69,998
$
19,364
$
24,697
Defined benefit liability [note 15]
$
(46,816)
$
(64,305)
$
(19,364)
$
(24,697)
The percentages of the total fair value of assets in the pension plans for each asset category at December 31 were as follows:
Pension benefit plans
2022
2021
Asset category
(a)
Canadian equity securities
6%
8%
U.S. equity securities
11%
13%
Global equity securities
6%
8%
Canadian fixed income
28%
32%
Other
(b)
49%
39%
Total
100%
100%
(a) The defined benefit plan assets contain
no
material amounts of related party assets at December 31, 2022 and 2021
respectively.
(b) Relates mainly to the value of the refundable tax account held by the Canada Revenue Agency. The refundable total is
approximately
equal to half of the sum of the realized investment income plus employer contributions less half of the benefits
paid by the plan
.
53
The following represents the components of net pension and other benefit expense included primarily as part of administration.
Pension benefit plans
Other benefit plans
2022
2021
2022
2021
Current service cost
$
2,302
$
2,332
$
915
$
956
Net interest cost
1,710
1,406
726
652
Administration cost
3
4
-
-
Defined benefit expense [note 19]
4,015
3,742
1,641
1,608
Defined contribution pension expense [note 19]
15,189
12,939
-
-
Net pension and other benefit expense
$
19,204
$
16,681
$
1,641
$
1,608
The total amount of actuarial gains recognized in other comprehensive income is:
Pension benefit plans
Other benefit plans
2022
2021
2022
2021
Actuarial gains
$
(19,517)
$
(2,899)
$
(5,720)
$
(2,100)
Return on plan assets excluding
interest income
555
(172)
-
-
$
(18,962)
$
(3,071)
$
(5,720)
$
(2,100)
The assumptions used to determine the Company’s defined benefit obligation and net pension and other benefit expense
were as follows at December 31 (expressed as weighted averages):
Pension benefit plans
Other benefit plans
2022
2021
2022
2021
Discount rate - obligation
4.5%
2.3%
5.1%
2.9%
Discount rate - expense
2.3%
2.4%
2.9%
2.5%
Rate of compensation increase
3.0%
3.0%
-
-
Health care cost trend rate
-
-
5.0%
5.0%
Dental care cost trend rate
-
-
4.5%
4.5%
At December 31, 2022, the weighted average duration of the defined benefit obligation for the pension plans was
17.1
years
(2021 -
20.0
years) and for the other benefit plans was
11.3
years (2021 -
13.6
years).
A
1
% change at the reporting date to one of the relevant actuarial assumptions, holding other assumptions
constant, would have affected the defined benefit obligation by the following:
Pension benefit plans
Other benefit plans
Increase
Decrease
Increase
Decrease
Discount rate
$
(6,148)
$
7,737
$
(2,366)
$
2,975
A 1% change in any of the other assumptions would not have a significant impact on the defined benefit obligation.
The methods and assumptions used in preparing the sensitivity analyses are the same as the methods and assumptions used
in determining the financial position of Cameco’s plans as at December 31, 2022. The sensitivity analyses are determined by
varying the sensitivity assumption and leaving all other assumptions unchanged. Therefore, the sensitivity analyses do not
recognize any interdependence in the assumptions. The methods and assumptions used in determining the above sensitivity
are consistent with the methods and assumptions used in the previous year.
54
In addition, an increase of one year in the expected lifetime of plan participants in the pension benefit plans would increase the
defined benefit obligation by $
1,236,000
.
To
measure the longevity risk for these plans, the mortality rates were reduced such that the average life expectancy for all
members increased by one year. The reduced mortality rates were subsequently used to re-measure the defined benefit
obligation of the entire plan.
27.
Financial instruments and related risk management
Cameco is exposed in varying degrees to a variety of risks from its use of financial instruments. Management and the board of
directors, both separately and together, discuss the principal risks of our businesses. The board sets policies for the
implementation of systems to manage, monitor and mitigate identifiable risks. Cameco’s risk management objective in relation
to these instruments is to protect and minimize volatility in cash flow. The types of risks Cameco is exposed to, the source of
risk exposure and how each is managed is outlined below.
Market risk
Market risk is the risk that changes in market prices, such as commodity prices, foreign currency exchange rates and interest
rates, will affect the Company’s earnings or the fair value of its financial instruments. Cameco engages in various business
activities which expose the Company to market risk. As part of its overall risk management strategy, Cameco uses derivatives
to manage some of its exposures to market risk that result from these activities.
Derivative instruments may include financial and physical forward contracts. Such contracts may be used to establish a fixed
price for a commodity, an interest-bearing obligation or a cash flow denominated in a foreign currency.
Market risks are
monitored regularly against defined risk limits and tolerances.
Cameco’s actual exposure to these market risks is constantly changing as the Company’s portfolios of foreign currency and
interest rate contracts change.
The types of market risk exposure and the way in which such exposure is managed are as follows:
A.
Commodity price risk
As a significant producer and supplier of uranium and nuclear fuel processing services, Cameco bears significant exposure to
changes in prices for these products. A substantial change in prices will affect the Company’s net earnings and operating cash
flows. Prices for Cameco’s products are volatile and are influenced by numerous factors beyond the Company’s control, such
as supply and demand fundamentals and geopolitical events.
Cameco’s sales contracting strategy focuses on reducing the volatility in future earnings and cash flow, while providing both
protection against decreases in market price and retention of exposure to future market price increases. To mitigate the risks
associated with the fluctuations in the market price for uranium products, Cameco seeks to maintain a portfolio of uranium
product sales contracts with a variety of delivery dates and pricing mechanisms that provide a degree of protection from
pricing volatility.
B.
Foreign exchange risk
The relationship between the Canadian and US dollar affects financial results of the uranium business as well as the fuel
services business. Sales of uranium product, conversion and fuel manufacturing services are routinely denominated in US
dollars while production costs are largely denominated in Canadian dollars.
55
Cameco attempts to provide some protection against exchange rate fluctuations by planned hedging activity designed to
smooth volatility. To
mitigate risks associated with foreign currency, Cameco enters into forward sales and option contracts to
establish a price for future delivery of the foreign currency. These foreign currency contracts are not designated as hedges and
are recorded at fair value with changes in fair value recognized in earnings. Cameco also has a natural hedge against US
currency fluctuations because a portion of its annual cash outlays, including purchases of uranium and conversion services, is
denominated in US dollars.
Cameco holds a number of financial instruments denominated in foreign currencies that expose the Company to foreign
exchange risk. Cameco measures its exposure to foreign exchange risk on financial instruments as the change in carrying
values that would occur as a result of reasonably possible changes in foreign exchange rates, holding all other variables
constant. As of the reporting date, the Company has determined its pre-tax exposure to foreign currency exchange risk on
financial instruments to be as follows based on a
5
% weakening of the Canadian dollar:
Carrying value
Currency
(Cdn)
Gain (loss)
Cash and cash equivalents
USD
$
414,683
$
20,734
Short-term investments
USD
886,020
44,301
Accounts receivable
USD
136,246
6,812
Accounts payable and accrued liabilities
USD
(176,746)
(8,837)
Net foreign currency derivatives
USD
(48,251)
(71,836)
A
5
% strengthening of the Canadian dollar against the currencies above at December 31, 2022 would have had an equal but
opposite effect on the amounts shown above, assuming all other variables remained constant.
C.
Interest rate risk
The Company has a strategy of minimizing its exposure to interest rate risk by maintaining target levels of fixed and variable
rate borrowings. The proportions of outstanding debt carrying fixed and variable interest rates are reviewed by senior
management to ensure that these levels are within approved policy limits. At December 31, 2022, the proportion of Cameco’s
outstanding debt that carries fixed interest rates is
92
% (2021 -
92
%).
Cameco was exposed to interest rate risk during the year through its interest rate swap contracts whereby fixed rate payments
on a notional amount of $
75,000,000
of the Series H senior unsecured debentures were swapped for variable rate payments.
Under the terms of the swap, Cameco makes interest payments based on
the three-month Canada Dealer Offered Rate
plus
an average margin of
1.3
% and receives fixed interest payments of
2.95
%. At December 31, 2022, the fair value of Cameco’s
interest rate swap net liability was $
7,284,000
(2021 - $
673,000
).
Cameco measures its exposure to interest rate risk as the change in cash flows that would occur as a result of reasonably
possible changes in interest rates, holding all other variables constant. As of the reporting date, the Company has determined
the impact on earnings of a
1
% increase in interest rate on its interest rate contracts to be a loss of $
766,000
.
56
Counterparty credit risk
Counterparty credit risk is associated with the ability of counterparties to satisfy their contractual obligations to Cameco,
including both payment and performance. The maximum exposure to credit risk, as represented by the carrying amount of the
financial assets, at December 31 was:
2022
2021
Cash and cash equivalents
$
1,143,674
$
1,247,447
Short-term investments
1,138,174
84,906
Accounts receivable [note 7]
178,088
272,220
Derivative assets [note 11]
2,807
32,098
Cash and cash equivalents
Cameco held cash and cash equivalents of $
1,143,674,000
at December 31, 2022 (2021 - $
1,247,447,000
). Cameco
mitigates its credit risk by ensuring that balances are held with counterparties with high credit ratings. The Company monitors
the credit rating of its counterparties on a monthly basis and has controls in place to ensure prescribed exposure limits with
each counterparty are adhered to.
Impairment on cash and cash equivalents has been measured on a 12-month ECL basis and reflects the short maturities of
the exposures. The Company considers that its cash and cash equivalents have low credit risk based on the external credit
ratings of the counterparties. Cameco has assessed its counterparty credit risk on cash and cash equivalents by applying
historic global default rates to outstanding cash balances based on S&P rating. The conclusion of this assessment is that the
loss allowance is insignificant.
Short-term investments
Cameco held short-term investments of $
1,138,174,000
at December 31, 2022 (2021 - $
84,906,000
). The Company mitigates
its credit risk by requiring that the issuer/guarantor of the investment have a minimum short-term credit rating and/or a long-
term debt rating at the time of purchase, according to the investment credit ratings as issued by DBRS or S&P,
or the
equivalent of the DBRS or S&P rating at another reputable rating agency.
In addition to the credit-rating requirement, Cameco also mitigates risk by prescribing limits by counterparty and types of
investment products.
Cameco has assessed its counterparty credit risk related to short-term investments by applying historic default rates to
outstanding investment balances based on S&P rating. The conclusion of this assessment is that the loss allowance is
insignificant.
Accounts receivable
Cameco’s sales of uranium product, conversion and fuel manufacturing services expose the Company to the risk of non-
payment. Cameco manages the risk of non-payment by monitoring the credit-worthiness of its customers and seeking pre-
payment or other forms of payment security
from customers with an unacceptable level of credit risk.
57
A summary of the Company’s exposure to credit risk for trade receivables is as follows:
Carrying
value
Investment grade credit rating
$
139,708
Non-investment grade credit rating
27,980
Total gross carrying amount
$
167,688
Loss allowance
-
Net
$
167,688
At December 31, 2022, there were no significant concentrations of credit risk and no amounts were held as collateral.
Historically, Cameco has experienced minimal customer defaults and, as a result, considers the credit quality of its accounts
receivable to be high.
Cameco uses customer credit rating data, historic default rates and aged receivable analysis to measure the ECLs of trade
receivables from corporate customers, which comprise a small number of large balances. Since the Company has not
experienced customer defaults in the past, applying historic default rates in calculating ECLs, as well as considering forward-
looking information, resulted in an insignificant allowance for losses.
The following table provides information about Cameco’s aged trade receivables as at December 31, 2022:
Corporate
Other
customers
customers
Total
Current (not past due)
$
166,361
$
398
166,759
1-30 days past due
639
171
810
More than 30 days past due
99
20
119
Total
$
167,099
$
589
167,688
Liquidity risk
Financial liquidity represents Cameco’s ability to fund future operating activities and investments. Cameco ensures that there
is sufficient capital in order to meet short-term business requirements, after taking into account cash flows from operations and
the Company’s holdings of cash and cash equivalents. The Company believes that these sources will be sufficient to cover the
likely short-term and long-term cash requirements.
The table below outlines the Company’s available debt facilities at December 31, 2022:
Outstanding and
Total amount
committed
Amount available
Unsecured revolving credit facility [note 14]
$
1,000,000
$
-
$
1,000,000
Letter of credit facilities [note 14]
1,756,754
1,593,379
163,375
58
The tables below present a maturity analysis of Cameco’s financial liabilities, including principal and interest, based on the
expected cash flows from the reporting date to the contractual maturity date:
Due in
Carrying
Contractual
less than
Due in 1-3
Due in 3-5
Due after 5
amount
cash flows
1 year
years
years
years
Accounts payable and accrued liabilities
$
374,714
$
374,714
$
374,714
$
-
$
-
$
-
Long-term debt
997,000
1,000,000
-
500,000
400,000
100,000
Foreign currency contracts
51,058
51,058
23,476
27,582
-
-
Interest rate contracts
7,284
7,284
2,437
2,987
1,860
-
Lease obligation [note 15]
9,287
10,314
2,681
2,595
1,718
3,320
Total contractual repayments
$
1,439,343
$
1,443,370
$
403,308
$
533,164
$
403,578
$
103,320
Due in
less than
Due in 1-3
Due in 3-5
Due after 5
Total
1 year
years
years
years
Total interest payments on long-term debt
$
192,225
$
37,840
$
44,255
$
33,780
$
76,350
Measurement of fair values
A.
Accounting classifications and fair values
The following tables summarize the carrying amounts and accounting classifications of Cameco’s financial instruments at the
reporting date:
At December 31, 2022
FVTPL
Amortized
cost
Total
Financial assets
Cash and cash equivalents
$
-
$
1,143,674
$
1,143,674
Short-term investments
-
1,138,174
1,138,174
Accounts receivable [note 7]
-
183,944
183,944
Derivative assets [note 11]
Foreign currency contracts
2,807
-
2,807
$
2,807
$
2,465,792
$
2,468,599
Financial liabilities
Accounts payable and accrued liabilities [note 13]
$
-
$
374,714
$
374,714
Lease obligation [note 15]
-
9,287
9,287
Derivative liabilities [note 15]
Foreign currency contracts
51,058
-
51,058
Interest rate contracts
7,284
-
7,284
Long-term debt [note 14]
-
997,000
997,000
58,342
1,381,001
1,439,343
Net
$
(55,535)
$
1,084,791
$
1,029,256
59
At December 31, 2021
FVTPL
Amortized
cost
Total
Financial assets
Cash and cash equivalents
$
-
$
1,247,447
$
1,247,447
Short-term investments
-
84,906
84,906
Accounts receivable [note 7]
-
276,139
276,139
Derivative assets [note 11]
Foreign currency contracts
31,534
-
31,534
Interest rate contracts
564
-
564
$
32,098
$
1,608,492
$
1,640,590
Financial liabilities
Accounts payable and accrued liabilities [note 13]
$
-
$
340,458
$
340,458
Lease obligation [note 15]
-
4,872
4,872
Derivative liabilities [note 15]
Foreign currency contracts
3,760
-
3,760
Interest rate contracts
1,237
-
1,237
Long-term debt [note 14]
-
996,250
996,250
4,997
1,341,580
1,346,577
Net
$
27,101
$
266,912
$
294,013
Cameco has pledged $
239,000,000
of cash as security against certain of its letter of credit facilities. This cash is being used
as collateral for an interest rate reduction on the letter of credit facilities. The collateral account has a term of
five years
effective July 1, 2018. Cameco retains full access to this cash.
Cameco has issued guarantees to certain banks in respect of the credit facilities granted to various subsidiaries. These
facilities consist of daily overdraft limits and credit lines. At December 31, 2022 the Company has issued guarantees of up to
$
179,700,000
($
132,600,000
(US)), which is the maximum amount the Company could be exposed to at any point in time.
During 2021, Cameco divested of its investments in equity securities. The fair value at the date of derecognition and the
cumulative gain or loss on disposal for the year ended December 31, 2021 were as follows:
Fair Value
Gain (loss)
Investment in Denison Mines Corp.
$
34,827
$
15,257
Investment in UEX Corporation
19,605
8,758
Investment in ISO Energy Ltd.
10,756
8,078
Investment in GoviEx
3,558
2,996
Other
265
(750)
$
69,011
$
34,339
The gains were presented net of tax. Cameco elected to transfer these cumulative net gains from equity investments at FVOCI
to retained earnings in the statement of changes in equity.
Cameco has not irrevocably designated a financial asset that would otherwise meet the requirements to be measured at
amortized cost at FVOCI or FVTPL to eliminate or significantly reduce an accounting mismatch that would otherwise arise.
60
The following tables summarize the carrying amounts and level 2 fair value measurements of Cameco’s financial instruments:
As at December 31, 2022
Carrying value
Fair value
Derivative assets [note 11]
Foreign currency contracts
$
2,807
$
2,807
Derivative liabilities [note 15]
Foreign currency contracts
(51,058)
(51,058)
Interest rate contracts
(7,284)
(7,284)
Long-term debt [note 14]
(997,000)
(1,014,010)
Net
$
(1,052,535)
$
(1,069,545)
As at December 31, 2021
Carrying value
Fair value
Derivative assets [note 11]
Foreign currency contracts
$
31,534
$
31,534
Interest rate contracts
564
564
Derivative liabilities [note 15]
Foreign currency contracts
(3,760)
(3,760)
Interest rate contracts
(1,237)
(1,237)
Long-term debt [note 14]
(996,250)
(1,103,978)
Net
$
(969,149)
$
(1,076,877)
The preceding tables exclude fair value information for financial instruments whose carrying amounts are a reasonable
approximation of fair value. The carrying values of Cameco’s cash and cash equivalents, short-term investments, accounts
receivable, and accounts payable and accrued liabilities approximate their fair values as a result of the short-term nature of the
instruments.
There were no transfers between level 1 and level 2 during the period. Cameco does not have any financial instruments that
are classified as level 3 as of the reporting date.
B.
Financial instruments measured at fair value
Cameco measures its derivative financial instruments and long-term debt at fair value. Derivative financial instruments and
long-term debt are classified as a recurring level 2 fair value measurement.
The fair value of Cameco’s long-term debt is determined using quoted market yields as of the reporting date, which ranged
from
3.3
% to
4.2
% (2021 -
1.1
% to
1.7
%).
Foreign currency derivatives consist of foreign currency forward contracts, options and swaps. The fair value of foreign
currency options is measured based on the Black Scholes option-pricing model. The fair value of foreign currency forward
contracts and swaps is measured using a market approach, based on the difference between contracted foreign exchange
rates and quoted forward exchange rates as of the reporting date.
Interest rate derivatives consist of interest rate swap contracts. The fair value of interest rate swaps is determined by
discounting expected future cash flows from the contracts. The future cash flows are determined by measuring the difference
between fixed interest payments to be received and floating interest payments to be made to the counterparty based on
Canada Dealer Offer Rate forward interest rate curves.
61
Where applicable, the fair value of the derivatives reflects the credit risk of the instrument and includes adjustments to take
into account the credit risk of the Company and counterparty. These adjustments are based on credit ratings and yield curves
observed in active markets at the reporting date.
Derivatives
The following table summarizes the fair value of derivatives and classification on the consolidated statements of financial
position:
2022
2021
Non-hedge derivatives:
Foreign currency contracts
$
(48,251)
$
27,774
Interest rate contracts
(7,284)
(673)
Net
$
(55,535)
$
27,101
Classification:
Current portion of long-term receivables, investments and other [note 11]
$
1,331
$
22,652
Long-term receivables, investments and other [note 11]
1,476
9,446
Current portion of other liabilities [note 15]
(25,913)
(378)
Other liabilities [note 15]
(32,429)
(4,619)
Net
$
(55,535)
$
27,101
The following table summarizes the different components of the gains (losses) on derivatives included in net earnings:
2022
2021
Non-hedge derivatives:
Foreign currency contracts
$
(66,360)
$
13,202
Interest rate contracts
(6,589)
(673)
Net
$
(72,949)
$
12,529
28.
Capital management
Cameco’s management considers its capital structure to consist of bank overdrafts, long-term debt, short-term debt (net of
cash and cash equivalents and short-term investments), non-controlling interest and shareholders’ equity.
Despite the impacts of COVID-19 on the global economy, Cameco’s approach to capital management has remained
consistent. Cameco’s capital structure reflects its strategy and the environment in which it operates. Delivering returns to long-
term shareholders is a top priority. The Company’s objective is to maximize cash flow while maintaining its investment grade
rating through close capital management of our balance sheet metrics. Capital resources are managed to allow it to support
achievement of its goals while managing financial risks such as weakness in the market, litigation risk and refinancing risk.
The overall objectives for managing capital in 2022 reflect the environment that the Company is operating in, similar to the
prior comparative period.
62
The capital structure at December 31 was as follows:
2022
2021
Long-term debt [note 14]
997,000
996,250
Cash and cash equivalents
(1,143,674)
(1,247,447)
Short-term investments
(1,138,174)
(84,906)
Net debt
(1,284,848)
(336,103)
Non-controlling interest
11
127
Shareholders' equity
5,836,054
4,845,841
Total
equity
5,836,065
4,845,968
Total capital
$
4,551,217
$
4,509,865
Cameco is bound by certain covenants in its general credit facilities. These covenants place restrictions on total debt, including
guarantees and set minimum levels for net worth. As of December 31, 2022, Cameco met these requirements.
29.
Segmented information
Cameco has two reportable segments: uranium and fuel services. Cameco's reportable segments are strategic business units
with different products, processes and marketing strategies.
The uranium segment involves the exploration for, mining, milling,
purchase and sale of uranium concentrate. The fuel services segment involves the refining, conversion and fabrication of
uranium concentrate and the purchase and sale of conversion services.
Cost of sales in the uranium segment includes care and maintenance costs for our operations that have had production
suspensions as well as operational readiness costs for our operations that are resuming operations. Operational readiness
costs include costs to complete critical projects, perform maintenance readiness checks, and recruit and train sufficient mine
and mill personnel before beginning operations. Cameco expensed $
218,439,000
of care and maintenance and operational
readiness costs during the year (2021 - $
209,556,000
of care and maintenance costs). Included in this amount in 2021 is
$
40,359,000
relating to care and maintenance costs for operations suspended as a result of COVID-19 and the related impact
of increased purchasing activity at a higher cost than produced pounds. This had a negative impact on gross profit in the
uranium segment.
Accounting policies used in each segment are consistent with the policies outlined in the summary of significant accounting
policies.
63
A.
Business segments - 2022
For the year ended December 31, 2022
Uranium
Fuel
services
Other
Total
Revenue
$
1,480,146
$
365,063
$
22,794
$
1,868,003
Expenses
Cost of products and services sold
1,223,558
215,660
18,118
1,457,336
Depreciation and amortization
135,800
32,618
8,958
177,376
Cost of sales
1,359,358
248,278
27,076
1,634,712
Gross profit (loss)
120,788
116,785
(4,282)
233,291
Administration
-
-
172,029
172,029
Exploration
10,578
-
-
10,578
Research and development
-
-
12,175
12,175
Other operating expense (income)
25,845
(2,901)
-
22,944
(Gain) loss on disposal of assets
726
(212)
-
514
Finance costs
-
-
85,728
85,728
Loss on derivatives
-
-
72,949
72,949
Finance income
-
-
(37,499)
(37,499)
Share of earnings from equity-accounted investee
(93,988)
-
-
(93,988)
Other income
(22,802)
-
(74,132)
(96,934)
Earnings (loss) before income taxes
200,429
119,898
(235,532)
84,795
Income tax recovery
(4,469)
Net earnings
89,264
Capital expenditures for the year
$
101,547
$
39,736
$
2,198
$
143,481
64
For the year ended December 31, 2021
Uranium
Fuel
services
Other
Total
Revenue
$
1,054,993
$
404,277
$
15,714
$
1,474,984
Expenses
Cost of products and services sold
1,028,816
242,574
11,245
1,282,635
Depreciation and amortization
134,629
43,344
12,442
190,415
Cost of sales
1,163,445
285,918
23,687
1,473,050
Gross profit (loss)
(108,452)
118,359
(7,973)
1,934
Administration
-
-
127,566
127,566
Exploration
8,016
-
-
8,016
Research and development
-
-
7,168
7,168
Other operating income
(8,407)
-
-
(8,407)
(Gain) loss on disposal of assets
(2,886)
6,689
-
3,803
Finance costs
-
-
76,612
76,612
Gain on derivatives
-
-
(12,529)
(12,529)
Finance income
-
-
(6,804)
(6,804)
Share of earnings from equity-accounted investee
(68,283)
-
-
(68,283)
Other expense (income)
-
301
(21,654)
(21,353)
Earnings (loss) before income taxes
(36,892)
111,369
(178,332)
(103,855)
Income tax recovery
(1,201)
Net loss
(102,654)
Capital expenditures for the year
$
72,786
$
22,792
$
3,206
$
98,784
B.
Geographic segments
Revenue is attributed to the geographic location based on the location of the entity providing the services. The Company’s
revenue from external customers is as follows:
2022
2021
Canada
$
994,534
$
704,719
United States
873,469
770,265
$
1,868,003
$
1,474,984
The Company’s non-current assets, excluding deferred tax assets and financial instruments, by geographic location
are as follows:
2022
2021
Canada
$
3,042,533
$
3,100,285
Australia
397,678
395,223
United States
80,352
131,683
Kazakhstan
38
46
Germany
6
11
$
3,520,607
$
3,627,248
65
C.
Major customers
Cameco relies on a small number of customers to purchase a significant portion of its uranium concentrates and uranium
conversion services. During 2022, revenues from one customer of Cameco’s uranium and fuel services segments represented
approximately $
227,846,000
(2021 - $
166,068,000
), approximately
12
% (2021 -
11
%) of Cameco’s total revenues from these
segments.
As customers are relatively few in number, accounts receivable from any individual customer may periodically
exceed 10% of accounts receivable depending on delivery schedule.
30.
Group entities
The following are the principal subsidiaries and associates of the Company:
Principal place
Ownership interest
of business
2022
2021
Subsidiaries:
Cameco Fuel Manufacturing Inc.
Canada
100%
100%
Cameco Marketing Inc.
Canada
100%
100%
Cameco Inc.
US
100%
100%
Power Resources, Inc.
US
100%
100%
Crow Butte Resources, Inc.
US
100%
100%
Cameco Australia Pty. Ltd.
Australia
100%
100%
Cameco Europe Ltd.
Switzerland
100%
100%
Associates:
JV Inkai
Kazakhstan
40%
40%
31.
Joint operations
Cameco conducts a portion of its exploration, development, mining and milling activities through joint operations. Operations
are governed by agreements that provide for joint control of the strategic operating, investing and financing activities among
the partners. These agreements were considered in the determination of joint control. Cameco’s significant Canadian uranium
joint operation interests are McArthur River, Key Lake and Cigar Lake. The Canadian uranium joint operations allocate
uranium production to each joint operation participant and the joint operation participant derives revenue directly from the sale
of such product. Mining and milling expenses incurred by joint operations are included in the cost of inventory.
66
Cameco reflects its proportionate interest in these assets and liabilities as follows:
Principal place
of business
Ownership
2022
2021
Total assets
McArthur River
Canada
69.81%
$
998,368
$
1,010,956
Key Lake
Canada
83.33%
527,841
549,051
Cigar Lake
(a)
Canada
54.55%
1,219,036
1,294,333
$
2,745,245
$
2,854,340
Total liabilities
McArthur River
69.81%
$
37,881
$
36,697
Key Lake
83.33%
240,487
267,579
Cigar Lake
(a)
54.55%
50,362
45,503
$
328,730
$
349,779
(a) Cameco’s ownership stake in the Cigar Lake uranium mine in northern Saskatchewan was previously
50.025
%. On May
19, 2022, Cameco and Orano completed the acquisition of Idemitsu’s
7.875
% participating interest in the CLJV by acquiring
their pro rata shares through an asset purchase (note 6).
32.
Related parties
A.
Transactions with key management personnel
Key management personnel are those persons that have the authority and responsibility for planning, directing and controlling
the activities of the Company, directly or indirectly.
Key management personnel of the Company include executive officers,
vice-presidents, other senior managers and members of the board of directors.
In addition to their salaries, Cameco also provides non-cash benefits to executive officers and vice-presidents and contributes
to pension plans on their behalf (note 26). Senior management and directors also participate in the Company’s share-based
compensation plans (note 25).
Executive officers are subject to terms of notice ranging from three to six months. Upon resignation at the Company’s request,
they are entitled to termination benefits of up to the lesser of 18 to 24 months or the period remaining until age 65. The
termination benefits include gross salary plus the target short-term incentive bonus for the year in which termination occurs.
Compensation for key management personnel was comprised of:
2022
2021
Short-term employee benefits
$
23,557
$
20,663
Share-based compensation
(a)
21,149
34,639
Post-employment benefits
6,532
6,188
Termination
benefits
-
161
Total
$
51,238
$
61,651
(a) Excludes deferred share units held by directors (see note 25).
B.
Other related party transactions
Cameco purchases uranium concentrates from JV Inkai. For the year ended December 31, 2022, Cameco had purchases of
$
206,818,000
($
155,937,000
(US)) (2021 - $
233,621,000
($
185,763,000
(US))). Cameco received a cash dividend from JV
Inkai of $
117,698,000
($
92,425,000
(US)) (2021 - $
50,128,000
($
40,286,000
(US))).
67
33.
Commitments
On October 11, 2022, Cameco announced that it had entered into a strategic partnership with Brookfield Renewable Partners
(Brookfield Renewable) and its institutional partners to acquire Westinghouse Electric Company (Westinghouse), one of the
world’s largest nuclear services businesses. Brookfield Renewable, with its institutional partners, will own a
51
% interest in
Westinghouse and Cameco will own
49
%.
Cameco’s share of the purchase price will be funded with a combination of cash, debt and equity. The Company secured a
bridge loan facility of $
280,000,000
(US) as well as $
600,000,000
(US) in term loans. The bridge facility, if funded, will mature
364 days after the acquisition closing date and the term loans, which consist of
two
$
300,000,000
(US) tranches, are expected
to mature two and three years after the closing of the acquisition. In addition, as disclosed in note 17, Cameco issued
34,057,250
common shares pursuant to a public offering.
Transaction costs of $
41,227,000
have been included in supplies and prepaid expenses in the consolidated statement of
financial position as of the year ended December 31, 2022. Under the terms of the agreement, if the transaction does not
close, Cameco is entitled to recover a portion of these costs.
EX-99.3
EXHIBIT 99.3
Cameco Corporation
2022 Management’s Discussion and Analysis
February 9, 2023
Management’s discussion and analysis
February 9, 2023
| 10 | MARKET OVERVIEW AND DEVELOPMENTS |
|---|---|
| 17 | 2022 PERFORMANCE HIGHLIGHTS |
| 23 | OUR VISION, VALUES AND STRATEGY |
| 32 | OUR ESG PRINCIPLES AND PRACTICES |
| 36 | MEASURING OUR RESULTS |
| 38 | FINANCIAL RESULTS |
| 66 | OPERATIONS AND PROJECTS |
| 94 | MINERAL RESERVES AND RESOURCES |
| 99 | ADDITIONAL INFORMATION |
This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2022. The information is based on what we knew as of February 8, 2023.
We encourage you to read our audited consolidated financial statements and notes as you review this MD&A. You can find more information about Cameco, including our 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, the Company 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:
| • | It typically includes words and phrases about the future, such as: anticipate, believe, estimate, expect, plan,<br>will, intend, goal, target, forecast, project, vision, strategy and outlook (see examples below). |
|---|---|
| • | It represents our current views and can change significantly. |
| --- | --- |
| • | It is based on a number of material assumptions, including those we have listed on page 5, which may prove to be<br>incorrect. |
| --- | --- |
| • | Actual results and events may be significantly different from what we currently expect, due to the risks<br>associated with our business. We list a number of these material risks on page 4. We recommend you also review our most recent annual information form, which includes a discussion of other material risks that could cause actual results<br>to differ significantly from our current expectations. |
| --- | --- |
| • | Forward-looking information is designed to help you understand management’s current views of our near- and<br>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
| • | our view that we have the strengths to take advantage of the world’s rising demand for safe, reliable, affordable and carbon-free energy, and our vision to energize a<br>clean-air world |
|---|---|
| • | we will continue to focus on delivering our products responsibly and addressing the environmental, social and governance (ESG) risks and opportunities that we believe will make our business sustainable and will build<br>long-term value |
| --- | --- |
| • | our expectations about 2023 and future global uranium supply, consumption, contracting, demand, geopolitical issues and the market including the discussion under the heading Market overview and developments |
| --- | --- |
| • | our expectations for the future of the nuclear industry and the potential for new enrichment technology, including that nuclear power must be a central part of the solution to the world’s shift to a low-carbon climate-resilient economy |
| --- | --- |
| • | our efforts to participate in the commercialization and deployment of small modular reactors (SMRs) and increase our contributions to global climate change solutions by exploring SMRs and other emerging opportunities<br>within the fuel cycle |
| --- | --- |
| • | our views on our ability to self-manage risk |
| --- | --- |
| • | the discussion under the heading Our strategy |
| --- | --- |
| • | the discussion under the heading Our response to the COVID-19 pandemic, including the priority of employee health and safety in our plans |
| --- | --- |
| • | our expectations regarding the operation of, and production levels for, the Cigar Lake mine and McArthur River/Key Lake operation and the Port Hope UF6 conversion<br>facility |
| --- | --- |
| • | the discussion under the heading Our ESG principles and practices including our belief there is a significant opportunity for us to be part of the solution to combat climate change and that we are well positioned<br>to deliver significant long-term business value |
| --- | --- |
| • | our expectations for uranium purchases, sales and deliveries |
| --- | --- |
| • | the anticipated timing for the finalization of the SE NNEGC Energoatom (Energoatom) supply contract, volume requirements under the contract and our expectation that Cameco will provide sufficient volumes of UF6 under it to meet Ukraine’s full nuclear fuel needs through 2035 |
| --- | --- |
| • | our intentions regarding future dividend payments |
| --- | --- |
| • | the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our expectations regarding receiving refunds and payment of disbursements from CRA, our confidence that<br>the courts would reject any attempt by CRA to utilize the same or similar positions for other tax years currently in dispute, our plan to file a notice of objection for 2016 and our belief that CRA should return the full amount of cash and security<br>that has been paid or otherwise secured by us |
| --- | --- |
| • | the discussion under the heading Outlook for 2023, including expected business resiliency, expectations for 2023 average unit cost of sales, average purchase price per pound, deliveries and production, 2023<br>financial outlook, our revenue, expectations for 2023 cash balances, tax rates, adjusted net earnings and cash flow sensitivity, and our price sensitivity analysis for our uranium segment |
| --- | --- |
| • | the discussion under the heading Liquidity and capital resources, including expected liquidity to meet our 2023 obligations and our expectations for our uranium contract portfolio to provide a solid revenue<br>stream |
| --- | --- |
| • | our expectation that the uranium contract portfolio we have built will continue to provide a solid revenue stream, and our portfolio management strategy, including our inventory strategy and the extent of our spot<br>market purchases |
| --- | --- |
| • | our expectation that our cash balances and operating cash flows will meet our anticipated 2023 capital requirements |
| --- | --- |
| • | our expectations for future capital expenditures |
| --- | --- |
| • | our expectation that in 2023 we will be able to comply with all the covenants in our unsecured revolving credit facility |
| --- | --- |
| • | life of mine operating cost estimates for the Cigar Lake, McArthur River/Key Lake and JV Inkai operations |
| --- | --- |
2 CAMECO CORPORATION
| • | future plans and expectations for uranium properties, advanced uranium projects, and fuel services operating sites, including production levels and suspension of production at certain properties, pace of advancement and<br>expansion capacity, carbon reduction targets and mine life, and that our core growth is expected to come from our existing tier-one mining and fuel services assets |
|---|---|
| • | our expectations related to care and maintenance costs |
| --- | --- |
| • | our mineral reserve and resource estimates |
| --- | --- |
| • | our decommissioning estimates |
| --- | --- |
| • | the discussion of our expectations relating to our acquisition of a 49% interest in Westinghouse Electric Company (Westinghouse), including the sources and uses of financing for the acquisition, the timeline of the<br>acquisition, including the anticipated closing thereof, and the acquisition organizational structure, equity accounting for our investment, generation of new revenue opportunities, the potential to generate additional revenue in the year following<br>the acquisition closing, our expectation that the acquisition will be accretive to our cash flow after closing, Westinghouse’s ability to generate cash flow to fund its approved annual operating budget and provide quarterly distributions to the<br>partners after closing, the acquisition expanding our participation in the nuclear fuel value chain, and providing a platform for further growth, our intention in respect of not issuing additional equity to fund our portion of the purchase price for<br>the Westinghouse acquisition and various factors and drivers for Westinghouse’s business segment |
| --- | --- |
MANAGEMENT’S DISCUSSION AND ANALYSIS 3
Material risks
| • | actual sales volumes or market prices for any of our products or services are lower than we expect, or cost of sales is higher than we expect, for any reason, including changes in market prices, loss of market share to<br>a competitor, trade restrictions, geopolitical issues or the impact of the COVID-19 pandemic |
|---|---|
| • | we are adversely affected by changes in currency exchange rates, interest rates, royalty rates, tax rates, or inflation |
| --- | --- |
| • | our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms |
| --- | --- |
| • | our strategies may change, be unsuccessful or have unanticipated consequences, or we may not be able to achieve anticipated operational flexibility and efficiency |
| --- | --- |
| • | changing views of governments regarding the pursuit of carbon reduction strategies or our view may prove to be inaccurate on the role of nuclear power in pursuit of those strategies |
| --- | --- |
| • | our estimates and forecasts prove to be inaccurate, including production, purchases, deliveries, cash flow, revenue, costs, decommissioning, reclamation expenses, or receipt of future dividends from JV Inkai |
| --- | --- |
| • | the Westinghouse acquisition may be delayed or may not be completed on the terms in the acquisition agreement or at all |
| --- | --- |
| • | consummation of the Westinghouse acquisition is subject to the satisfaction of closing conditions and regulatory approvals that may not be satisfied on a timely basis or at all |
| --- | --- |
| • | that we may not realize the expected benefits from the Westinghouse acquisition |
| --- | --- |
| • | after closing the acquisition, Westinghouse fails to generate sufficient cash flow to fund its approved annual operating budget or make quarterly distributions to the partners |
| --- | --- |
| • | we are unable to enforce our legal rights under our existing agreements, permits or licences |
| --- | --- |
| • | we are subject to litigation or arbitration that has an adverse outcome |
| --- | --- |
| • | that we may not receive expected refunds and payments from CRA |
| --- | --- |
| • | that the courts may accept the same, similar or different positions and arguments advanced by CRA to reach decisions that are adverse to us for other tax years |
| --- | --- |
| • | the possibility of a materially different outcome in disputes with CRA for other tax years |
| --- | --- |
| • | that CRA does not agree that the court rulings for the years that have been resolved in Cameco’s favour should apply to subsequent tax years |
| --- | --- |
| • | that CRA will not return all or substantially all of the cash and security that has been paid or otherwise secured in a timely manner, or at all |
| --- | --- |
| • | there are defects in, or challenges to, title to our properties |
| --- | --- |
| • | our mineral reserve and resource estimates are not reliable, or there are unexpected or challenging geological, hydrological or mining conditions |
| --- | --- |
| • | we are affected by environmental, safety and regulatory risks, including workforce health and safety or increased regulatory burdens or delays resulting from the COVID-19 pandemic<br>or other causes |
| --- | --- |
| • | necessary permits or approvals from government authorities cannot be obtained or maintained |
| --- | --- |
| • | we are affected by political risks, including the early-2022, and any potential future, unrest in Kazakhstan |
| --- | --- |
| • | operations are disrupted due to problems with our own or our suppliers’ or customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment<br>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<br>accidents, aging infrastructure or other development and operating risks |
| --- | --- |
| • | we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, outbreak of illness (such as a pandemic like COVID-19), accident or a deterioration<br>in political support for, or demand for, nuclear energy |
| --- | --- |
| • | a major accident at a nuclear power plant |
| --- | --- |
| • | 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<br>uranium |
| --- | --- |
| • | government laws, regulations, policies or decisions that adversely affect us, including tax and trade laws and sanctions on nuclear fuel imports |
| --- | --- |
| • | our uranium suppliers or purchasers fail to fulfil their commitments |
| --- | --- |
| • | our McArthur River development, mining or production plans are delayed or do not succeed for any reason |
| --- | --- |
| • | our Cigar Lake development, mining or production plans are delayed or do not succeed for any reason |
| --- | --- |
| • | our production plans for our Port Hope UF6 conversion facility do not succeed for any reason |
| --- | --- |
| • | the McClean Lake’s mill production plan is delayed or does not succeed for any reason |
| --- | --- |
| • | water quality and environmental concerns could result in a potential deferral of production and additional capital and operating expenses required for the Cigar Lake and McArthur River/Key Lake operations |
| --- | --- |
| • | JV Inkai’s development, mining or production plans are delayed or do not succeed for any reason, or JV Inkai is unable to transport and deliver its production |
| --- | --- |
| • | we may be unsuccessful in pursuing innovation or implementing advanced technologies, including the risk that the commercialization and deployment of SMRs or new enrichment technology may incur unanticipated delays or<br>expenses, or ultimately prove to be unsuccessful |
| --- | --- |
| • | our expectations relating to care and maintenance costs prove to be inaccurate |
| --- | --- |
| • | the risk that we may become unable to pay future dividends at the expected rate |
| --- | --- |
4 CAMECO CORPORATION
| • | we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes |
|---|---|
| • | the risks that generally apply to all our operations and advanced uranium projects that are discussed under the heading Managing the risks beginning on page 67 |
| --- | --- |
| • | the risks relating to our tier-one uranium operations discussed under the heading McArthur River mine/Key Lake mill – Managing Our Risks beginning on page 73, under<br>the heading Cigar Lake – Managing Our Risks beginning on page 76, and under the heading Inkai – Managing Our Risks beginning on page 80 |
| --- | --- |
| • | risks relating to the Energoatom supply contract, including the risk that it will not be finalized within the time or on the terms expected, our ability to supply<br>UF6 under the contract, that the option for us to supply the Zaporizhzhya nuclear power plant, if exercised, may not result in the delivery volumes expected and that the continuation or outcome<br>of the conflict between the Ukraine and Russia may prevent Cameco from realizing its expected benefits |
| --- | --- |
Material assumptions
| • | our expectations regarding sales and purchase volumes and prices for uranium and fuel services, cost of sales, trade restrictions, inflation and that counterparties to our sales and purchase agreements will honour their<br>commitments |
|---|---|
| • | our expectations for the nuclear industry, including its growth profile, market conditions, geopolitical issues and the demand for and supply of uranium |
| --- | --- |
| • | the continuing pursuit of carbon reduction strategies by governments and the role of nuclear in the pursuit of those strategies |
| --- | --- |
| • | the assumptions discussed under the heading 2023 Financial Outlook |
| --- | --- |
| • | our expectations regarding spot prices and realized prices for uranium, and other factors discussed under the heading Price sensitivity analysis: uranium segment |
| --- | --- |
| • | the Westinghouse acquisition is closed on the anticipated timeline and on the terms of the acquisition agreement |
| --- | --- |
| • | Westinghouse’s ability to generate cash flow and fund its approved annual operating budget and make quarterly distributions to the partners after closing of the acquisition |
| --- | --- |
| • | our ability to compete for additional business opportunities so as to generate additional revenue for us in the year after closing the Westinghouse acquisition |
| --- | --- |
| • | market conditions and other factors upon which we based the Westinghouse acquisition and our related forecasts will be as expected |
| --- | --- |
| • | the success of our plans and strategies relating to the Westinghouse acquisition |
| --- | --- |
| • | 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<br>of nuclear power plants |
| --- | --- |
| • | our ability to continue to supply our products and services in the expected quantities and at the expected times |
| --- | --- |
| • | our expected production levels for Cigar Lake, McArthur River/Key Lake, JV Inkai and our fuel services operating sites |
| --- | --- |
| • | our cost expectations, including production costs, operating costs, and capital costs |
| --- | --- |
| • | our expectations regarding tax payments, tax rates, royalty rates, currency exchange rates and interest rates |
| --- | --- |
| • | our entitlement to and ability to receive expected refunds and payments from CRA |
| --- | --- |
| • | in our dispute with CRA, that courts will reach consistent decisions for other tax years that are based upon similar positions and arguments |
| --- | --- |
| • | that CRA will not successfully advance different positions and arguments that may lead to different outcomes for other tax years |
| --- | --- |
| • | our expectation that we will recover all or substantially all of the amounts paid or secured in respect of the CRA dispute to date |
| --- | --- |
| • | our decommissioning and reclamation estimates, including the assumptions upon which they are based, are reliable |
| --- | --- |
| • | our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable |
| --- | --- |
| • | our understanding of the geological, hydrological and other conditions at our uranium properties |
| --- | --- |
| • | our Cigar Lake and McArthur River development, mining and production plans succeed |
| --- | --- |
| • | our Key Lake mill production plan succeeds |
| --- | --- |
| • | the McClean Lake mill is able to process Cigar Lake ore as expected |
| --- | --- |
| • | our production plans for our Port Hope UF6 conversion facility succeed |
| --- | --- |
| • | JV Inkai’s development, mining and production plans succeed, and that JV Inkai will be able to transport and deliver its production |
| --- | --- |
| • | the ability of JV Inkai to pay dividends |
| --- | --- |
| • | that care and maintenance costs will be as expected |
| --- | --- |
| • | 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 |
| --- | --- |
| • | our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, outbreak of illness (such as a pandemic<br>like COVID-19), governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages,<br>labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, aging infrastructure or<br>other development or operating risks |
| --- | --- |
MANAGEMENT’S DISCUSSION AND ANALYSIS 5
| • | assumptions regarding the Energoatom supply contract, including that we will reach agreement on final terms within the time and on the terms expected, delivery volumes, our ability to supply UF6 under the contract, and that we will not be prevented from realizing the expected benefits of the contract because of the continuation or outcome of the conflict between Ukraine and Russia |
|---|
6 CAMECO CORPORATION
[This page is intentionally left blank.]
MANAGEMENT’S DISCUSSION AND ANALYSIS 7
Market overview and developments
A market in transition
In 2022, geopolitical events coupled with the ongoing focus on the climate crisis created what we believe are transformative tailwinds for the nuclear power industry from both a demand and supply perspective. Uranium prices continued to rise, reaching levels not seen since 2011 driven by a tightened uranium market and growing security of supply concerns. In early-January, unrest in Kazakhstan raised concerns about the more than 40% of global uranium supply that originates from Kazakhstan. However, it was the Russian invasion of Ukraine in late-February that was the most transformative event for our industry. We believe it has set in motion a geopolitical realignment in energy markets that is highlighting the increasingly important role for nuclear power not just in providing clean energy, but also providing secure and affordable energy. And, with the global nuclear industry reliant on Russian supplies for approximately 14% of uranium concentrates, 27% of conversion and 39% of enrichment, it is highlighting the security of supply risk associated with the growing primary supply gap and shrinking secondary supplies and increasing the focus on origin of supply.
With the heightened supply risk caused by geopolitical uncertainty, utilities are evaluating their nuclear fuel supply chains. Utilities continue to be focused on ensuring they have the conversion and enrichment services they require secured under long-term contracts and are now beginning to return their focus to uranium. The uncertainty about where nuclear fuel supplies will come from to satisfy growing demand led to increased long-term contracting activity in 2022. This contracting activity resulted in a 22% increase in the long-term price of uranium over the past year, conversion prices that are at historic highs, and enrichment prices that have increased over 210% since the start of the invasion of Ukraine. Notably, utilities are now approaching replacement rate contracting for the first time in over a decade. Therefore, we expect there will be continued competition to secure uranium, conversion and enrichment services under long-term contracts with proven producers and assets in geopolitically attractive jurisdictions, with strong environmental, social and governance (ESG) performance and on terms that will ensure the availability of reliable supply to satisfy demand.
DURABLE DEMAND GROWTH
The benefits of nuclear energy have come clearly into focus with a durability we believe has not been previously seen. The durability is being driven not only by accountability for achieving the net-zero carbon targets set by countries and companies around the world, but also by a geopolitical realignment that is causing countries to reexamine how they approach their energy needs. Net-zero carbon targets are turning attention to a triple challenge. First, is to lift one-third of the global population out of energy poverty by growing clean and reliable baseload electricity. Second, is to replace 85% of the current global electricity grids that run on carbon-emitting sources of thermal power with a clean, reliable alternative. And finally, is to grow global power grids by electrifying industries, such as private and commercial transportation, home, and industrial heating, largely powered with carbon-emitting sources of thermal energy today. Additionally, the Russian invasion of Ukraine has deepened the energy crisis experienced in some parts of the world and amplified concerns about energy security, highlighting the role of energy policy in balancing three main objectives: providing a clean emissions profile; providing a reliable and secure baseload profile; and providing an affordable levelized cost profile. There is increasing recognition that nuclear power meets these objectives and has a key role to play in achieving decarbonization goals. The growth in demand is not just long-term in the form of new builds, it is medium-term demand in the form of reactor life extensions, and it is near-term growth as early reactor retirements are prevented and new markets continue to emerge. And we are seeing momentum building for non-traditional commercial uses of nuclear power around the world such as development of small modular reactors and advanced reactors, with numerous companies and countries pursuing projects.
Demand and energy policy highlights
| • | China announced plans to accelerate new nuclear projects to combat future electricity shortages, indicating it<br>could raise the number of new reactor construction approvals to ten or more per year. In 2022, there were ten approvals. |
|---|
10 CAMECO CORPORATION
| • | In December, Japan announced a new plan to maximize nuclear power by restarting as many existing reactors as<br>possible, prolonging the operating lives of aging reactors beyond a 60-year limit, and building new reactors. This followed an earlier pledge by Japan’s Prime Minister Kishida to have up to 17 reactors<br>restarted by the summer of 2023. Additionally, the government set a target for nuclear to make up 20% to 22% of the country’s energy mix by the end of the decade, and under the new policy will push for the development and construction of<br>“next-generation innovative reactors” to replace about 20 reactors now set for decommissioning. |
|---|---|
| • | South Korea finalized their 10^th^ Basic Plan for Electricity<br>Supply and Demand in January 2023. The plan aims to maintain 30% of the country’s 2030 energy mix as nuclear power, resume construction on Units 3 and 4 at the Shin Hanul nuclear plant, and sets a goal of exporting 10 nuclear power plants by<br>2030, as well as the development of a Korean small modular reactor (SMR). This positive news builds from the earlier 2022 announcements that included nuclear power in South Korea’s green taxonomy and reversed the previous administration’s<br>anti-nuclear stance. |
| --- | --- |
| • | In July 2022, the European Parliament voted to keep nuclear power in the European Union’s sustainable<br>finance taxonomy as a transitional “green” investment. The Complimentary Delegated Act from this vote was entered into application on January 1, 2023. Including nuclear power in the “transitional” category indicates that it<br>will help mitigate climate change but cannot yet be replaced by economically and technologically feasible low-carbon alternatives. |
| --- | --- |
| • | Following the Russian invasion, numerous European countries announced their intention to reduce reliance on<br>Russian-supplied nuclear fuel under long-term contracts. For example, on June 2^nd^, Ukraine’s state-owned utility, Energoatom, signed an agreement with Westinghouse to supply all its nuclear<br>fuel and increase the number of planned AP1000 reactor new builds from five to nine. Numerous other countries have also taken steps to diversify their nuclear fuel supply. |
| --- | --- |
| • | In Sweden, a newly elected coalition majority government immediately updated the country’s energy policy to<br>be more pro-nuclear. They cited a significant shift away from the previous focus on renewables, changing the previous goal of “100% renewable” electricity by 2040 to “100% fossil free<br>electricity”, and have put forward legislation to allow for the construction of more reactors. |
| --- | --- |
| • | Belgium shut down its Doel-3 nuclear reactor in September, but in January<br>announced 10-year life extensions for their two newest reactors, Doel 4 and Tihange 3. These reactors were set to close in 2025 but will now restart in November 2026 after the necessary preparation and will<br>continue operating for 10 years. |
| --- | --- |
| • | Chancellor Olaf Scholz has ordered the life extension of Germany’s three remaining reactors until mid-April 2023, keeping them on stand-by due to energy concerns. |
| --- | --- |
| • | In November 2022, the United Kingdom (UK) announced that it would take a joint stake alongside French partner<br>Électricité de France (EDF) in the construction of its new Sizewell C nuclear power station, replacing China General Nuclear’s 20% stake. The UK will invest £700 million in the project, which will be matched by EDF.<br> |
| --- | --- |
| • | In France, the government and regulator are working on conditions to extend the operating lives of existing<br>reactors and are planning an “industrial build” program with the start of construction around 2028 for the first two of six new EPR reactors and with plans for eight additional EPRs in the future. In addition, the French state is<br>finalizing increased ownership in EDF from 84% to 100% to provide a smooth energy transition, ensure sovereignty in the face of war and firm up the company’s diminished financial situation. |
| --- | --- |
| • | In Finland, Teollisuuden Voima Oyj announced Olkiluoto 3, the 1,600 MWe EPR, resumed test electricity production<br>in December following a few months delay with regular electricity production now scheduled to start in March 2023. |
| --- | --- |
| • | Poland confirmed its intent to build nuclear power capacity for the first time and is progressing plans with both<br>Westinghouse for AP1000 PWR’s and Korea Hydro & Nuclear Power (KHNP) for APR 1400’s. |
| --- | --- |
| • | Egypt began construction on the first two of four Russian built VVER 1200 reactors at the El-Dabaa Power Plant as the government looks to accelerate the project. Additionally, in December, Egypt announced plans to start mining uranium in 2024 as part of the country’s rapidly developing program for<br>peaceful use of nuclear energy. |
| --- | --- |
| • | India’s first domestically designed 700 MWe pressurized heavy water reactor at Kakrapar is now in commercial<br>operation, an important milestone for the country. Three more units of this design are expected to come online in the next few years. The country is targeting an expansion to have 22.5 GWe operating by 2031. |
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MANAGEMENT’S DISCUSSION AND ANALYSIS 11
| • | In August 2022, President Biden signed the Inflation Reduction Act of 2022 (IRA) into law. Through<br>$369 billion (US) in tax incentives and other investments, IRA is a major federal legislative initiative enacted to address climate change. The IRA includes significant support for nuclear power with the establishment of a Production Tax Credit<br>to support existing nuclear reactors and provides $700 million (US) to incentivize the development of domestic sources of high-assay low-enriched uranium. Additionally, in December, the International<br>Nuclear Energy Act passed a US Senate Committee vote and is expected to be reintroduced to Congress. The bill seeks to promote engagement with partner and ally nations to develop a civil nuclear export strategy, establish financing relationships,<br>standardize licensing frameworks, and is designed to offset the influence of Russia and China in the international nuclear market. This support comes in addition to ongoing work at various levels of the US government to eliminate US dependence on<br>nuclear fuel imports from Russia. |
|---|---|
| • | In California, Governor Newsom signed a bill seeking to extend operations at the Diablo Canyon Power Plant for<br>five years beyond its current licence, which expires in 2025. |
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| • | Southern Company announced fuel loading began in October 2022 for Vogtle unit 3, the first of two 1,250 MWe<br>AP1000’s under construction in Georgia. The company also confirmed its plans to apply to have the operating licences for its Farley and Hatch reactors extended to 80 years. This followed similar announced extensions for Tennessee Valley<br>Authority’s Browns Ferry reactor, Xcel Energy’s Monticello reactor, and Dominion Energy’s Virgil C. Summer reactor. |
| --- | --- |
| • | Mexico’s Laguna Verde nuclear plant has been granted 30-year<br>operating life extensions for its two units. |
| --- | --- |
| • | Ontario Power Generation (OPG) announced plans to extend the life of the Pickering nuclear power plant until at<br>least 2026 and potentially up to 30 years. In addition, OPG signed an agreement with X-energy to examine deploying their Xe-100 SMR. Finally, OPG issued a<br>$300 million Green Bond, a first-of-its-kind for the company and part of its commitment to be net zero by 2040. The funds<br>are to be used to finance the refurbishment activities at its Darlington site, where life extensions to four units are in progress, as well as for maintenance of existing nuclear facilities. |
| --- | --- |
| • | In October 2022, OPG completed a significant project milestone by submitting an application for a Licence to<br>Construct to the Canadian Nuclear Safety Commission (CNSC). This licence application is the next step in the deployment of a SMR at the Darlington site. The submission comes after the beginning of site preparation activities earlier in 2022, which<br>was another significant milestone. |
| --- | --- |
| • | In late 2022, Bruce Power achieved a major milestone in the refurbishment of Unit 6, as project teams<br>successfully installed the CANDU reactor’s fuel channel assembly, which puts the project on track to return to operation in 2023. Additionally, the Unit 3 refurbishment campaign is scheduled to begin in March 2023. |
| --- | --- |
| • | Sprott Physical Uranium Trust (SPUT) purchased about 17 million pounds U3O8 in 2022, bringing total purchases since inception to over 41 million pounds<br>U3O8. The challenging equity markets in recent months have contributed to SPUT shares trading at a discount to net asset value, impacting<br>its ability to raise funds to purchase uranium. |
| --- | --- |
According to the International Atomic Energy Agency, globally there are currently 439 operable reactors and 57 reactors under construction. Several nations are appreciating the clean energy and energy security benefits of nuclear power. They have reaffirmed their commitment to it and are developing plans to support existing reactor units and are reviewing their policies to encourage more nuclear capacity. Several other non-nuclear countries have emerged as candidates for new nuclear capacity. In the EU, specific nuclear energy projects have been identified for inclusion under its sustainable financing taxonomy and therefore eligible for access to low-cost financing. Even in countries where phase-out policies were in place, there have been policy reversals and decisions to, at a minimum, temporarily keep reactors running, with public opinion polls showing growing support for it. With a number of reactor construction projects recently approved, and many more planned, the demand for uranium continues to improve. There is growing recognition of the role nuclear must play in providing safe, affordable, carbon-free baseload electricity that achieves a low-carbon economy while being a reliable energy source to help countries diversify away from Russian energy supply.
12 CAMECO CORPORATION
SUPPLY UNCERTAINTY
In addition to low uranium prices, government-driven trade policies, the COVID-19 pandemic, and ongoing supply chain challenges, the most notable factor impacting security of supply in 2022 was geopolitical uncertainty. The geopolitical uncertainty, driven by the Russian invasion of Ukraine, has led many governments and utilities to re-examine supply chains and procurement strategies that are reliant on nuclear fuel supplies coming out of Russia. In addition, sanctions on Russia, government restrictions, and restrictions on and cancellations of some cargo insurance coverage are creating transportation and further supply chain risks for fuel supplies coming out of Central Asia. Despite the recent increase in uranium prices, years of underinvestment in new capacity and the deepening geopolitical uncertainty has shifted risk from producers to utilities.
Supply and trade policy highlights
| • | In November 2022, Cameco announced that the first pounds of uranium ore from the McArthur River mine had been<br>milled and packaged at the Key Lake mill, marking the achievement of initial production as the facilities transition back into normal operations. |
|---|---|
| • | In early January 2022, Kazakhstan saw the most significant political instability since it became independent in<br>1991. The events resulted in a state of emergency being declared across the country. Order was restored in the second half of January, and the state of emergency was gradually lifted. In November 2022, President Tokayev was re-elected for a new 7-year term. |
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MANAGEMENT’S DISCUSSION AND ANALYSIS 13
| • | Kazatomprom (KAP) announced in August 2022 its plan to produce 10% below its total Subsoil Use Contracts level in<br>2024. This plan was expected to result in increased production in Kazakhstan of about 5 million to 8 million pounds U3O8<br>compared to the current 20% reduction, bringing total expected annual uranium production to about 65 million pounds in 2024. KAP stated the decision was based on its contracting progress but that it may still face significant challenges to<br>increase above current production levels due to the state of global supply chains. In January 2023, KAP’s operational update showed lower expected production in 2023 due to wellfield development, procurement and supply chain issues, resulting<br>in forecasted production of between 53.3 million and 55.9 million pounds, compared to between 58.5 million and 59.8 million pounds previously. |
|---|---|
| • | KATCO, the joint venture between Orano Mining and KAP, was granted a new mining permit for a parcel of the<br>Muyunkum uranium deposit bringing total estimated uranium reserves to about 120 million pounds U3O8. The full production level of<br>about 10.4 million pounds U3O8 is planned for 2026 at the earliest. |
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| • | Orano announced plans to increase its enrichment production capacity by 30%, which could involve an expansion of<br>the Georges-Besse II plant located in Tricastin. The cost of the project is estimated at $970M (US) and could increase the capacity at its Georges Besse II plant to 11 million separative work units (SWU) from 7.5 million SWU.<br> |
| --- | --- |
| • | GLE made progress with the first full-scale laser system module, successfully completing eight months of testing<br>in Australia. The system, which was developed by Silex Systems Ltd for deployment in GLE’s commercial pilot demonstration facility has been delivered to GLE’s facility in the US. Additionally, GLE signed letters of intent (LOI) to<br>collaborate with two major US utilities to help diversify a portion of the US nuclear fuel supply chain, including measures to support its deployment of laser enrichment technology in the US. |
| --- | --- |
| • | In June, Boss Energy Limited (Boss) finalized their decision to develop the Honeymoon Uranium Project in South<br>Australia. Boss intends to accelerate construction and is projecting Honeymoon will have first production in the fourth quarter of 2023, ramping up to 2.45 million pounds U3O8 production per year within three years. |
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| • | ConverDyn’s parent, Honeywell, is planning for a 2023 restart of its UF6 conversion facility. |
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Long-term contracting creates full-cycle value for provenproductive assets
Like other commodities, the demand for uranium is cyclical. However, unlike other commodities, uranium is not traded in meaningful quantities on a commodity exchange. The uranium market is principally based on bilaterally negotiated long-term contracts covering the annual run-rate requirements of nuclear power plants, with a small spot market to serve discretionary demand. History demonstrates that in general, when prices are rising and high, uranium is perceived as scarce, and more contracting activity takes place with proven and reliable suppliers. The higher demand discovered during this contracting cycle drive investment in higher-cost sources of production, which due to lengthy development timelines, tend to miss the contracting cycle and ramp up after demand has already been won by proven producers. The new uncommitted supply exposed to the small, discretionary spot market puts downward pressure on price and can create the perception that uranium is abundant, potentially resulting in a failure of long-term price signals. When prices are declining and low, there is no perceived urgency to contract, and contracting activity and investment in new supply dramatically decreases. After years of low prices, and a lack of investment in supply, and as the uncommitted material available in the spot market begins to thin, security-of-supply tends to overtake price concerns. Utilities typically re-enter the long-term contracting market to ensure they have a reliable future supply of uranium to run their reactors.
14 CAMECO CORPORATION
UxC reports that over the last five years approximately 430 million pounds U3O8 equivalent have been locked-up in the long-term market, while approximately 775 million pounds U3O8 equivalent have been consumed in reactors. We remain confident that utilities have a growing gap to fill.
We believe the current backlog of long-term contracting presents a substantial opportunity for proven and reliable suppliers with tier-one productive capacity and a record of honoring supply commitments. As a low-cost producer, we manage our operations to increase value throughout these price cycles.
In our industry, customers do not come to the market right before they need to load nuclear fuel into their reactors. To operate a reactor that could run for more than 60 years, natural uranium and the downstream services have to be purchased years in advance, allowing time for a number of processing steps before a finished fuel bundle arrives at the power plant. At present, we believe there is a significant amount of uranium that needs to be contracted to keep reactors running into the next decade.
UxC estimates that cumulative uncovered requirements are about 2.3 billion pounds to the end of 2040. With the lack of investment over the past decade, there is growing uncertainty about where uranium will come from to satisfy growing demand, and utilities are becoming increasingly concerned about the availability of material to meet their long-term needs. In addition, secondary supplies have diminished, and the material available in the spot market has thinned as producers and financial funds continue to purchase material. Furthermore, the Russian invasion of Ukraine in February has given rise to a geopolitical realignment in energy markets that is causing some utilities to seek nuclear fuel suppliers whose values are aligned with their own or whose origin of supply better protects them from potential interruptions, including from transportation challenges or the possible imposition of formal sanctions.
MANAGEMENT’S DISCUSSION AND ANALYSIS 15
We will continue to take the actions we believe are necessary to position the company for long-term success. Therefore, we will continue to align our production decisions with our customers’ needs under our contract portfolio. We will undertake contracting activity which is intended to ensure we have adequate protection while maintaining exposure to the benefits that come from having uncommitted, low-cost supply to place into a strengthening market.
16 CAMECO CORPORATION
2022 performance highlights
It was another positive year for the nuclear energy industry. Demand for nuclear power, including support for existing reactors, continues to grow, catalyzed by the increasing recognition by policy makers and major industries that nuclear energy must play an important role in achieving the objectives of providing clean, secure, reliable and affordable energy. Geopolitical unrest highlighted the importance of energy policy decisions on national security. With nuclear energy clearly back in durable growth mode, we are also back in durable growth mode. Growth that will be sought in the same manner as we approach all aspects of our business; strategic, deliberate, disciplined and responsible and with a focus on generating full-cycle value.
In our uranium segment, in 2022, we added 80 million pounds to our portfolio of long-term uranium contracts; about 58 million of which are finalized and 22 million accepted with key commercial terms, such as pricing mechanism, volume and tenor having been agreed to, but still awaiting contract finalization; and we have a large and growing pipeline of uranium business under discussion. Our focus continues to be on obtaining market-related pricing mechanisms, while also providing adequate downside protection. We continue to be strategically patient in our discussions to maximize value in our contract portfolio and to maintain exposure to higher prices with unencumbered future productive capacity. In addition, with strong demand in the UF6 conversion market, we were successful in adding long-term contracts that we expect will profitably underpin that operation for years to come. We finalized contracts for almost 12 million kgU of UF6 conversion in 2022 and have another almost 5 million kgU that have been accepted and are awaiting contract finalization.
In 2022, we operated at about 60% below the productive capacity (100% basis) in our uranium segment due to the impact of our planned supply discipline decisions, including to transition McArthur River/Key Lake back to production after five years on care and maintenance. Productive capacity includes licensed capacity at Cigar Lake of 18 million pounds (100% basis) per year and McArthur River/Key Lake of 25 million pounds (100% basis) per year, and it includes planned production volumes at Rabbit Lake and our US operations prior to curtailment in 2016. We produced 18 million pounds (100% basis) from the Cigar Lake mine and began the restart of production at our McArthur River mine and Key Lake mill, producing 1.1 million pounds (100% basis) in 2022. Through our investment in Inkai, we were impacted by the 20% supply reduction enacted by Kazatomprom (KAP) across all uranium mines in Kazakhstan and the continued supply chain challenges it has faced. Kazatomprom has the ability to flex production 20% above or below planned production levels (8.3 million to 12.5 million pounds per year). As well, delivery of our share of 2022 production from JV Inkai was delayed due to the challenges of transporting uranium via an alternate route that does not rely on Russian rail lines or ports. The first shipment, containing 2.6 million pounds of our share of Inkai’s 2022 production, arrived at a Canadian port in late December. A second shipment containing the majority of our remaining share of 2022 production is currently in transit.
We delivered over 25 million pounds of uranium and 11 million kgU in our fuel services segment to our customers in alignment with our contract portfolio and profitable opportunities in the market. We generated $305 million in cash from operations, with higher sales volumes in our uranium segment and higher average realized prices in both our uranium and fuel services segments than in 2021. With some delays in commissioning at the Key Lake mill, operational readiness costs were $169 million for the year and production from the mill was lower than originally anticipated. To meet our sales commitments and maintain a working inventory we purchased 18.3 million pounds of uranium at an average cost of $39.45 (US) per pound. While the unit cost of our purchases is significantly higher than the average production costs at Cigar Lake in 2022, the average cost was moderated by our ability to pull forward some of the long-term fixed-price purchase arrangements that were put in place in a much lower price environment. See 2022 financial results by segment – Uranium starting on page 57 for more information.
Thanks to the disciplined execution of our strategy, our balance sheet is strong, and we expect it will enable us to see out our strategy as well as self-manage risk, including from global macro-economic uncertainty and volatility. As of December 31, 2022, we had $2.3 billion in cash and cash equivalents and short-term investments with only $997 million in long-term debt. In addition, we have a $1.0 billion undrawn credit facility. The strength of our balance sheet allowed us to take advantage of two opportunities that we believe will add significant long-term value for Cameco.
In May 2022, we announced the acquisition of a greater share in the Cigar Lake mine for $107 million, increasing our ownership to 54.5% (from 50%). Cigar Lake is a proven, permitted and fully licensed tier-one mine in a safe and stable jurisdiction that we operate with the tremendous participation and support of our neighbouring Indigenous partner communities.
MANAGEMENT’S DISCUSSION AND ANALYSIS 17
In October 2022, we announced we had entered a strategic partnership with Brookfield Renewable Partners and its institutional partners (Brookfield Renewable) to acquire 100% of Westinghouse Electric Company (Westinghouse), a global provider of mission-critical and specialized technologies, products and services across most phases of the nuclear power sector. The acquisition is expected to close in the second half of 2023 and is subject to customary closing conditions and certain regulatory approvals. Once the transaction closes, Brookfield Renewable, will beneficially own a 51% interest in Westinghouse and we will beneficially own 49%. We believe bringing together our expertise in the nuclear industry with Brookfield Renewable’s expertise in clean energy positions nuclear power at the heart of the clean energy transition and creates a powerful platform for strategic growth across the nuclear sector.
The total enterprise purchase price for the acquisition is $7.875 billion (US), which includes an assumption of an estimated $3.4 billion (US) of debt which will remain with Westinghouse, and which is subject to customary purchase price adjustments. The remainder of the purchase price will be paid by approximately $4.5 billion (US) of aggregate cash contributions, our share of which will be approximately $2.2 billion (US). Following the announcement, we undertook a $650 million (US) bought deal offering of common shares, with an underwriter option to purchase additional shares. The offering closed on October 17, 2022, with gross proceeds to us of approximately $747.6 million (US), including the exercise in full of the underwriters’ option to purchase additional common shares. Net proceeds from the issuance were received in October 2022 and the US dollar cash and cash equivalents and short-term investments are included on our balance sheet. The final financing is not required until close of the acquisition and will be determined based on market conditions and the expected run rate of our business at that time. We expect a permanent financing mix of capital sources, including cash, debt and equity, designed to preserve our balance sheet and ratings strength, while maintaining healthy liquidity. See Proposed acquisition of Westinghouse beginning on page 89 for more information on the proposed acquisition.
With nuclear power’s clean emissions profile, reliable and secure baseload characteristics and low, levelized cost there was an intensified focus on preventing early reactor retirements, pursuing 10- and 20-year life extensions for the existing fleets in several countries, and the construction of new reactors, both traditional large-scale reactors and small and advanced nuclear reactors. 2022 brought further support for nuclear power as the Russian invasion of Ukraine deepened the energy crisis impacting many regions of the world and highlighted the need for energy security and affordability. Energy security concerns in regions such as Central and Eastern Europe have resulted in demand from new markets for Western nuclear fuel supplies. In addition, utilities globally are evaluating their sources of supply with a focus on origin. The increased nuclear fuel demand for Western supply of products and services, supply that established producers like we and like Westinghouse can offer, presents itself in the near, medium and long term.
Increased demand is occurring at a time when there is considerable growing uncertainty about nuclear fuel supplies. Macro uncertainty including the COVID-19 pandemic, supply chain disruptions, inflationary pressures and rapidly rising interest rates, and geopolitical unrest have accelerated this uncertainty. Low prices have led to supply concentration by origin, and a growing primary supply gap. Secondary supplies that have played a crucial role in our industry have been drawn out of the market. And, with the global nuclear industry reliant on Russian supplies for approximately 14% of uranium concentrates, 27% of conversion, and 39% of enrichment, utilities are now considering and planning for a variety of potential scenarios ranging from an abrupt end to Russian supplies to a gradual phase-out in nuclear fuel supply chains. As a result, we are seeing some utilities beginning to pivot towards procurement strategies that more carefully weigh the origin risk, and which supports producers with assets in geopolitically favourable jurisdictions.
18 CAMECO CORPORATION
In the current environment, we believe the risk to uranium supply is greater than the risk to uranium demand and expect it will create a renewed focus on ensuring availability of long-term supply to fuel nuclear reactors. With the improvements in the market, the new long-term contracts we have put in place, and a pipeline of contracting discussions, we have decided to adjust our production plan for McArthur River/Key Lake to produce 18 million pounds per year (100% basis) starting in 2024, and we plan to continue to operate Cigar Lake at 18 million pounds per year (100% basis) in 2024. At Inkai, production will continue to follow the 20% reduction planned by KAP until the end of 2023. With annual licensed capacity of 25 million pounds at McArthur River/Key Lake, we continue to have the ability to expand production from our existing assets, however some additional investment would be required. If we took advantage of all of the tier-one expansion opportunities, our annual share of tier-one supply could be about 32 million pounds. However, any decision to expand production will be dependent on further improvements in the uranium market and our ability to secure the appropriate long-term contract homes for our unencumbered, in-ground inventory, demonstrating that we continue to responsibly manage our supply in accordance with our customers’ needs. In addition to our plans to expand uranium production, at our Port Hope UF6 conversion facility we are working on increasing annual production to 12,000 tonnes by 2024 to satisfy our book of long-term business and demand for conversion services, at a time when conversion prices are at historic highs. See Our vision, values and strategy starting on page 23 for more information.
We expect the investments we have and will continue to make in digital and automation technologies will allow us to operate our assets with more flexibility. This is key to our ability to continue to align our production decisions with our contract portfolio commitments and opportunities. With a solid base of contracts to underpin our productive capacity, and a growing contracting pipeline we are beginning to return to our tier-one cost structure, which we expect will significantly improve our financial performance.
As we execute on our strategy, we will continue to focus on protecting the health and safety of our employees, delivering our products safely and responsibly and addressing the ESG risks and opportunities that we believe will make our business sustainable and will build long-term value.
Financial performance
| HIGHLIGHTS<br>DECEMBER 31 ( MILLIONS EXCEPT WHERE INDICATED) | 2021 | CHANGE | |||||
|---|---|---|---|---|---|---|---|
| Revenue | 1,868 | 1,475 | 27 | % | |||
| Gross profit | 233 | 2 | >100 | % | |||
| Net earnings (loss) attributable to equity holders | 89 | (103 | ) | >100 | % | ||
| per common share (diluted) | 0.22 | (0.26 | ) | >100 | % | ||
| Adjusted net earnings (loss) (non-IFRS, see page<br>40) | 135 | (98 | ) | >100 | % | ||
| per common share (adjusted and diluted) | 0.33 | (0.25 | ) | >100 | % | ||
| Cash provided by operations | 305 | 458 | (33 | )% |
All values are in US Dollars.
Net earnings attributable to equity holders (net earnings) and adjusted net earnings in 2022 significantly outperformed 2021 when we had a net loss for the year. See 2022 consolidated financial results beginning on page 39 for more information. Of note:
| • | generated $305 million in cash from operations |
|---|---|
| • | incurred $218 million in care and maintenance costs and operational readiness costs as a result of our<br>strategic decisions |
| --- | --- |
Our segment updates and other fuel cycle investment updates
In our uranium segment, we continued to execute our strategy to preserve our tier-one assets which impacted our operations. Of note in 2022, we:
| • | produced 18 million pounds (100% basis) at Cigar Lake and increased our ownership to 54.5%<br> |
|---|---|
| • | began the restart of production at McArthur River/Key Lake, producing 1.1 million pounds (100% basis).<br>Production was impacted by commissioning challenges at the mill. |
| --- | --- |
| • | maintained Rabbit Lake and US ISR operations on care and maintenance |
| --- | --- |
| • | purchased 18.3 million pounds of uranium, including our spot purchases, committed purchase volumes<br>(including JV Inkai purchases), and advancing some long-term purchases |
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MANAGEMENT’S DISCUSSION AND ANALYSIS 19
| • | delivered on our sales commitments of over 25 million pounds in alignment with our contract portfolio and<br>profitable market opportunities |
|---|---|
| • | added a record number of contracts with 80 million pounds added to our portfolio (58 million pounds<br>finalized and 22 million pounds accepted and awaiting contract finalization). |
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In 2022, in our fuel services segment, we:
| • | produced 13.0 million kgU, which included an annual<br>UF6 production record of over 10.6 million kgU |
|---|---|
| • | delivered 11.1 million kgU under contract |
| --- | --- |
| • | with UF6 conversion prices at historic highs, we<br>finalized contracts for 12 million kgU as UF6 and have another almost 5 million kgU as UF6 that have been accepted, awaiting<br>contract finalization. |
| --- | --- |
See Operations and projects beginning on page 66 for more information.
Other investment updates from 2022:
| • | GLE delivered the first full-scale laser system module to its facility in the US after successfully completing<br>eight months of testing in Australia |
|---|---|
| • | In October, we announced the proposed acquisition of Westinghouse |
| --- | --- |
See Global Laser Enrichment and Proposed acquisition of Westinghouse beginning on page 89 for more information.
| HIGHLIGHTS <br> <br> | 2021 | CHANGE | ||||||
|---|---|---|---|---|---|---|---|---|
| Uranium | Production volume (million lbs) | 10.4 | 6.1 | 70 | % | |||
| Sales volume (million lbs) | 25.6 | 24.3 | 5 | % | ||||
| Average realized price1 | 44.73 | 34.53 | 30 | % | ||||
| 57.85 | 43.34 | 33 | % | |||||
| Revenue ( millions) | 1,480 | 1,055 | 40 | % | ||||
| Gross profit (loss) ( millions) | 121 | (108 | ) | >100 | % | |||
| Fuel services | Production volume (million kgU) | 13.0 | 12.1 | 7 | % | |||
| Sales volume (million kgU) | 11.1 | 13.6 | (18 | )% | ||||
| Average realized price 2 | 32.92 | 29.72 | 11 | % | ||||
| Revenue ( millions) | 365 | 404 | (10 | )% | ||||
| Gross profit ( millions) | 117 | 118 | (1 | )% |
All values are in US Dollars.
| ^1^ | Uranium average realized price is calculated as the revenue from sales of uranium concentrate, transportation<br>and storage fees divided by the volume of uranium concentrates sold. |
|---|---|
| ^2^ | Fuel services average realized price is calculated as revenue from the sale of conversion and fabrication<br>services, including fuel bundles and reactor components, transportation and storage fees divided by the volumes sold. |
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Also of note,subsequent update
As announced in February 2023, we have reached agreement on commercial terms for a major supply contract to provide sufficient volumes of natural uranium hexafluoride (UF6) (consisting of uranium and conversion services) to SE NNEGC Energoatom (Energoatom) to meet Ukraine’s full nuclear fuel needs through 2035. Key commercial terms, such as pricing mechanism, volume and tenor, have been agreed to, but the contract is subject to finalization, which is anticipated in the first quarter of 2023.
The agreement will run from 2024 through 2035 and contract amounts are subject to customary volume flexibility provisions commonly contained in supply agreements. Additionally, the agreement will contain a required degree of flexibility, given present circumstances in Ukraine. The agreement will be for 100% of Energoatom’s UF6 requirements (consisting of uranium and conversion services) for the nine nuclear reactors at its Rivne, Khmelnytskyy and South Ukraine nuclear power plants for the duration of the contract. These plants have combined requirements over the contract term of approximately 15.3 million KgU as UF6 (the equivalent of about 40.1 million pounds of uranium concentrate, or U3O8).
20 CAMECO CORPORATION
The contract will also contain an option for us to supply up to 100% of the fuel requirements for the six reactors at the Zaporizhzhya nuclear power plant, currently under Russian control, should it return to Energoatom’s operation. If the option was exercised in 2024, the Zaporizhzhya plant would require roughly 10.4 million KgU as UF6 (the equivalent of approximately 27.2 million pounds of U3O8) over the contract period.
Industry prices
| 2021 | CHANGE | |||||
|---|---|---|---|---|---|---|
| Uranium (US/lb U3O8)1 | ||||||
| Average annual spot market price | 49.81 | 35.28 | 41 | % | ||
| Average annual long-term price | 49.75 | 36.81 | 35 | % | ||
| Fuel services (US/kgU as UF6)1 | ||||||
| Average annual spot market price | ||||||
| North America | 31.96 | 19.41 | 65 | % | ||
| Europe | 31.96 | 18.99 | 68 | % | ||
| Average annual long-term price | ||||||
| North America | 24.75 | 18.42 | 34 | % | ||
| Europe | 24.94 | 18.42 | 35 | % |
All values are in US Dollars.
Note: the industry does not publish UO2 prices.
| ^1^ | Average of prices reported by TradeTech and UxC, LLC (UxC) |
|---|
On the spot market, where purchases call for delivery within one year, the volume reported by UxC for 2022 dropped significantly to 61 million pounds U3O8 equivalent, compared to 2021’s record breaking 102 million pounds U3O8 equivalent. Spot market volumes were significant in 2021 due to unplanned uranium demand from the Sprott Physical Uranium Trust, which contributed to the thinning of spot uranium supply. In 2022, total spot purchases by producers, junior uranium companies and financial funds was approximately 25 million pounds U3O8 equivalent, compared to approximately 53 million pounds U3O8 equivalent in 2021; these purchases in 2022 represented over 40% of spot market purchases compared to over 50% in 2021. At the end of 2022, the average reported spot price was $47.68 (US) per pound, up $5.63 (US) per pound from the end of 2021. During the year, the uranium spot price ranged from a month-end low of $43.08 (US) per pound to a month-end high of $58.20 (US) per pound, averaging $49.81 (US) for the year.
Long-term contracts generally call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including base-escalated prices set at time of contracting and escalated over the term of the contract, and market referenced prices (spot and long-term indicators) determined near the time of delivery. The volume of long-term contracting reported by UxC for 2022 was about 113 million pounds U3O8 equivalent, up from about 72 million pounds U3O8 equivalent in 2021. Higher volumes can be attributed in part to utilities turning their attention to securing their long-term needs as demand from financial funds further thinned the spot market and, in combination with higher interest rates, greatly reduced the ability for utilities to rely on carry trade activity, as well as heightened geopolitical tensions. The average reported long-term price at the end of the year was $52.00 (US) per pound, up $9.25 (US) from 2021. During the year, the uranium long-term price steadily increased from a month-end low of $42.88 (US) per pound in January to a high of $52.00 (US) per pound in November, averaging $49.75 (US) for the year.
With the Russian invasion of Ukraine in February 2022, conversion prices in both the North American and European markets set record highs. The average reported spot price for North American delivery at the end of 2022 was $40.00 (US) per kilogram uranium as UF6 (US/kgU as UF6), up $23.90 (US) from the end of 2021. Long-term UF6 conversion prices for North American delivery finished 2022 at $27.25 (US/kgU as UF6), up $9.25 (US) from the end of 2021.
MANAGEMENT’S DISCUSSION AND ANALYSIS 21
22 CAMECO CORPORATION
Our vision, values and strategy
Our vision
Our vision – “Energizing a clean-air world” – recognizes that we have an important role to play in enabling the vast reductions in global GHG emissions required to achieve a resilient net-zero carbon economy. We support climate action that is consistent with the ambition of the Paris Agreement and the Canadian government’s commitment to the agreement to limit global temperature rise to less than 2°C and we believe that this means the world needs to reach net-zero emissions by 2050 or sooner. The uranium we produce is used around the world in the generation of safe, carbon-free, affordable, base-load nuclear power.
We believe we have the right strategy to achieve our vision and we will do so in a manner that reflects our values. For over 30 years, we have been delivering our products responsibly. Building on that strong foundation, we remain committed to our efforts to transform our own, already low, greenhouse gas footprint in our ambition to reach net-zero emissions, while identifying and addressing the ESG risks and opportunities that we believe may have a significant impact on our ability to add long-term value for our stakeholders.
Committed to our values
Our values are discussed below. They define who we are as a company and are at the core of everything we do and help to embed ESG principles and practices as we execute on our strategy in pursuit of our vision. They are:
| • | safety and environment |
|---|---|
| • | people |
| --- | --- |
| • | integrity |
| --- | --- |
| • | excellence |
| --- | --- |
SAFETY AND ENVIRONMENT
The safety of people and protection of the environment are the foundations of our work. All of us share in the responsibility of continually improving the safety of our workplace and the quality of our environment.
We are committed to keeping people safe and conducting our business with respect and care for both the local and global environment.
PEOPLE
We value the contribution of every employee and we treat people fairly by demonstrating our respect for individual dignity, creativity and cultural diversity. By being open and honest, we achieve the strong relationships we seek.
We are committed to developing and supporting a flexible, skilled, stable and diverse workforce, in an environment that:
| • | attracts and retains talented people and inspires them to be fully productive and engaged |
|---|---|
| • | encourages relationships that build the trust, credibility and support we need to grow our business<br> |
| --- | --- |
INTEGRITY
Through personal and professional integrity, we lead by example, earn trust, honour our commitments and conduct our business ethically.
We are committed to acting with integrity in every area of our business, wherever we operate.
EXCELLENCE
We pursue excellence in all that we do. Through leadership, collaboration and innovation, we strive to achieve our full potential and inspire others to reach theirs.
MANAGEMENT’S DISCUSSION AND ANALYSIS 23
Our strategy
We are a pure-play investment in the growing demand for nuclear energy. We are focused on providing nuclear fuel products and services across the fuel cycle to support the generation of clean, reliable, secure and affordable energy, and we are focused on taking advantage of the long-term growth we see coming in our industry. Our strategy is set within the context of what we believe is a transitioning market environment, where increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are expected to durably strengthen the long-term fundamentals for our industry. Nuclear energy must be a central part of the solution to the world’s shift to a low-carbon, climate resilient economy. It is an option that can provide the power needed, not only reliably, but also safely and affordably, and in a way that will help avoid some of the worst consequences of climate change.
Our strategy is to capture full-cycle value by:
| • | remaining disciplined in our contracting activity, building a balanced portfolio in accordance with our<br>contracting framework |
|---|---|
| • | profitably producing from our tier-one assets and aligning our production<br>decisions in all segments of our business with our contract portfolio and customer needs |
| --- | --- |
| • | being financially disciplined to allow us to execute on our strategy, take advantage of strategic opportunities<br>and to self-manage risk |
| --- | --- |
| • | exploring other emerging and non-traditional opportunities within the<br>fuel cycle, which align with our commitment to responsibly and sustainably manage our business, contribute to the mitigation of global climate change, and help to provide energy security and affordability |
| --- | --- |
We expect our strategy will allow us to increase long-term value, and we will execute it with an emphasis on safety, people and the environment.
URANIUM
Uranium production is central to our strategy, as it is the biggest value driver of the nuclear fuel cycle and our business. We have tier-one assets that are licensed, permitted, long-lived, and are proven reliable with capacity to expand. These tier-one assets are backed up by idle tier-two assets and what we think is the best exploration portfolio that leverages existing infrastructure.
We are focused on protecting and extending the value of our contract portfolio, on aligning our production decisions with our contract portfolio and market opportunities thereby optimizing the value of our lowest cost assets. We also prioritize maintaining a strong balance sheet, and on efficiently managing the company. We have undertaken a number of deliberate and disciplined actions, including a focus on digitization and automation to allow us to operate our assets with more flexibility.
FUEL SERVICES
Our fuel services segment is a source of profit and supports our uranium segment, providing our customers with access to refining and conversion services for both heavy-water and light-water reactors, and CANDU fuel and reactor component manufacturing for heavy-water reactors.
As in our uranium segment, we are focused on securing new long-term contracts and on aligning our production decisions with our contract portfolio that will allow us to continue to profitably produce and consistently support the long-term needs of our customers.
In addition, we are pursuing non-traditional markets for our UO2 and fuel fabrication business and have been actively securing new contracts for reactor components to support refurbishment of Canadian reactors.
OTHER NUCLEAR FUEL CYCLE INVESTMENTS
We continue to explore other opportunities across the nuclear fuel cycle. Expanding our participation in the fuel cycle is expected to complement our tier-one uranium assets and fuel services, creating new revenue opportunities and enhancing our ability to meet the increasing needs of existing and new customers for secure, reliable nuclear fuel supplies and services.
24 CAMECO CORPORATION
In particular, we are interested in the second largest value driver of the fuel cycle, enrichment, and have a 49% interest in Global Laser Enrichment LLC (GLE). GLE is the exclusive licensee of the proprietary SILEX laser enrichment technology, a third-generation uranium enrichment technology. We are the commercial lead for the GLE project with a 49% interest and starting in 2023, an option to attain a majority interest of up to 75% ownership. See Global Laser Enrichment starting on page 89 for more information.
In addition, in October 2022, we announced the planned acquisition of a 49% interest in Westinghouse, a global provider of mission-critical and specialized technologies, products and services for light-water reactors across most phases of the nuclear power sector, in a strategic partnership with Brookfield Renewable. See Proposed acquisition of Westinghouse starting on page 89 for more information on Westinghouse.
Additionally, we have signed a number of non-binding arrangements to explore several areas of cooperation to advance the commercialization and deployment of small modular reactors in Canada and around the world.
BUILDING A BALANCED PORTFOLIO
The purpose of our contracting framework is to deliver value. Our approach is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that optimizes our realized price.
Contracting decisions in all segments of our business need to consider the nuclear fuel market structure, the nature of our competitors, and the current market environment. The vast majority of run-rate fuel requirements are procured under long-term contracts. The spot market is thinly-traded where utilities buy small, discretionary volumes. This market structure is reflective of the baseload nature of nuclear power and the relatively small proportion of the overall operating costs the fuel represents compared to other sources of baseload electricity. Additionally, about half of the fuel supply typically comes from diversified mining companies that produce uranium as a by-product, or by state-owned entities with production volume strategies or ambitions to serve state nuclear power ambitions with low-cost fuel supplies. We evaluate our strategy in the context of our market environment and continue to adjust our actions in accordance with our contracting framework:
| • | First, we build a long-term contract portfolio by layering in volumes over time. In addition to our committed<br>sales, we will compete for end-user demand in the market where we think we can obtain value and, in general, as part of longer-term contracts. We will take advantage of opportunities the market provides, where<br>it makes sense from an economic, logistical, diversification 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<br>committed sales. |
|---|---|
| • | Once we have built a portfolio of long-term contracts, we decide how to best source material to satisfy that<br>demand, planning our production in accordance with our contract portfolio and other available sources of supply. We will not produce from our tier-one assets to sell into an oversupplied spot market.<br> |
| --- | --- |
| • | We do not intend to build an inventory of excess uranium. Excess inventory serves to contribute to the sense that<br>uranium is abundant and creates an overhang on the market, and it ties up working capital on our balance sheet. |
| --- | --- |
| • | Depending on the timing and volume of our production, purchase commitments, and our inventory volumes, this means<br>we may be active buyers in the market in order to meet our annual delivery commitments. Historically, prior to the supply curtailments that we began in 2016, we have generally planned our annual delivery commitments to slightly exceed the annual<br>supply we expect to come from our annual production and our purchase commitments and have therefore relied on the spot market to meet a small portion of our delivery commitments. In general, if we choose to purchase material to meet demand, we<br>expect the cost of that material will be more than offset by the volume of commitments in our sales portfolio that are exposed to market prices at the time of delivery over the long-term. |
| --- | --- |
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, our goal is to protect and extend the value of our contract portfolio on terms that recognize the value of our assets and pricing mechanisms that provide adequate protection when prices go down and exposure to rising prices. We believe using this framework will allow us to create long-term value. Our focus will continue to be on ensuring we have the financial capacity to execute on our strategy and self-manage risk.
MANAGEMENT’S DISCUSSION AND ANALYSIS 25
LONG-TERM CONTRACTING
Uranium is not traded in meaningful quantities on a commodity exchange. Utilities have historically bought the majority of their uranium and fuel services products under long-term contracts that are bilaterally negotiated with suppliers. The spot market is discretionary and typically used for one-time volumes, not to satisfy annual demand. We sell uranium and fuel products and services directly to nuclear utilities around the world as uranium concentrates, UO2 and UF6, conversion services, or fuel fabrication and reactor components for CANDU heavy water reactors. We have a solid portfolio of long-term sales contracts that reflect our reputation as a proven, reliable supplier of geographically stable supply, and the long-term relationships we have built with our customers.
In general, we are active in the market, buying and selling uranium when it is beneficial for us and in support of our long-term contract portfolio. We undertake activity in the spot and term markets prudently, looking at the prices and other business factors to decide whether it is appropriate to purchase or sell into the spot or term market. Not only is this activity a source of profit, but it also gives us insight into underlying market fundamentals.
We deliver the majority of our uranium under long-term contracts each year, some of which are tied to market-related pricing mechanisms quoted at time of delivery. Therefore, our net earnings and operating cash flows are affected by changes in the uranium price. Market prices are influenced by the fundamentals of supply and demand, market access and trade policy issues, geopolitical events, disruptions in planned supply and demand, and other market factors.
The objectives of our contracting strategy are to:
| • | optimize realized price by balancing exposure to future market prices while providing some certainty for our<br>future earnings and cash flow |
|---|---|
| • | focus on meeting the nuclear industry’s growing annual uncovered requirements with our tier-one production |
| --- | --- |
| • | establish and grow market share with strategic and regionally diverse customers |
| --- | --- |
We have a portfolio of long-term contracts, each bilaterally negotiated with customers, that have a mix of base-escalated pricing and market-related pricing mechanisms, including provisions that provide exposure to rising market prices and also protect us when the market price is declining. This is a balanced and flexible approach that allows us to adapt to market conditions, put a floor on our average realized price and deliver the best value over the long term.
This approach has allowed our realized price to outperform the market during periods of weak uranium demand, and we expect it will enable us to realize increases linked to higher market prices in the future.
Base-escalated contracts foruranium (price at time of acceptance escalated over the term): use a pricing mechanism based on a term-price indicator at the time the contract is accepted and escalated to time of each delivery over the term of the contract.
Market-related contracts for uranium: are different from base-escalated contracts in that the pricing mechanism may be based on either the spot price or the long-term price, and that price is as quoted at the time of delivery rather than at the time the contract is accepted. These contracts may provide for discounts, and typically include floor prices and/or ceiling prices, which are fixed at time of contract acceptance and usually escalate over the term of the contract.
Fuel services contracts: the majority of our fuel services contracts use a base-escalated mechanism per kgU and reflect the market at the time the contract is accepted.
OPTIMIZING OUR CONTRACT PORTFOLIO
We work with our customers to optimize the value of our contract portfolio. With respect to new contracting activity, there is often a lag from when contracting discussions begin and when contracts are executed. With our large pipeline of business under negotiation in our uranium segment, and a value driven strategy, we continue to be strategically patient in considering the commercial terms we are willing to accept. We layer in contracts over time, with higher commitments in the near term and declining over time in accordance with utilities growing uncovered requirements. Much of our pending business is off-market but we are starting to see more on-market activity emerge. We remain confident that we can add acceptable new sales commitments to our portfolio of long-term contracts to underpin the ongoing operation of our productive capacity and capture long-term value.
26 CAMECO CORPORATION
Given our view that additional long-term supply will need to be incented to meet the growing demand for safe, clean, reliable, carbon-free nuclear energy, our preference today is to sign long-term contracts with market-related pricing mechanisms. Unsurprisingly, we believe our customers too expect prices to rise and prefer to lock-in today’s prices, with a fixed-price mechanism. Our goal is to balance all these factors, along with our desire for customer and regional diversification, with product form, and logistical factors to ensure we have adequate protection and will have exposure to rising market prices under our contract portfolio, while maintaining the benefits that come from having low-cost supply to deliver into a strengthening market.
With respect to our existing contracts, at times we may also look for opportunities to optimize the value of our portfolio. In cases where there is a changing policy, operating, or economic environment, we may consider options that allow us to maintain our customer relationships and are mutually beneficial.
CONTRACT PORTFOLIO STATUS
We have commitments to sell approximately 180 million pounds of U3O8 with 34 customers worldwide in our uranium segment, and over 55 million kilograms as UF6 conversion with 31 customers worldwide in our fuel services segment.
Customers – U3O8:
Five largest customers account for 56% of commitments
Customers – UF6 conversion:
Five largest customers account for 59% of commitments
MANAGEMENT’S DISCUSSION AND ANALYSIS 27
MANAGING OUR CONTRACT COMMITMENTS
We allow sales volumes to vary year-to-year depending on:
| • | the level of sales commitments in our long-term contract portfolio |
|---|---|
| • | market opportunities |
| --- | --- |
| • | our sources of supply |
| --- | --- |
To meet our delivery commitments and to mitigate risk, we have access to a number of sources of supply, which includes uranium obtained from:
| • | our productive capacity |
|---|---|
| • | purchases under our JV Inkai agreement, under long-term agreements and in the spot market |
| --- | --- |
| • | our inventory in excess of our working requirements |
| --- | --- |
| • | product loans |
| --- | --- |
OUR SUPPLY DISCIPLINE
As spot is not the fundamental market, true value is built under a long-term contract portfolio and is measured over the full commodity cycle. Therefore, we align our uranium production decisions with our contract commitments and market opportunities to avoid carrying excess inventory or having to sell into an oversupplied spot market. In accordance with market conditions, and to mitigate risk, we evaluate the optimal mix of our production, inventory and purchases in order to satisfy our contractual commitments and in order to realize the best return over the entire commodity cycle. During a prolonged period of uncertainty, this could mean leaving our uranium in the ground. For the years 2016 through 2022, we left more than 130 million pounds of uranium in the ground (100% basis) by curtailing our production. We purchased more than 60 million pounds including spot and long-term purchases and in 2018 we drew down our inventory by almost 20 million pounds. That totals over 210 million pounds (100% basis) of uranium that were not available to the market.
However, today we believe we are in the early stages of a uranium market transition, driven by the growing demand for nuclear energy and the increasingly undeniable conclusion that it is essential to the clean-energy transition and to energy security. In 2022 we secured 80 million pounds under long-term uranium contracts alone and as the market continues to transition, we expect to continue to place our uranium under long-term contracts and to meet rising demand with production from our best margin operations.
With the improvements in the market, the new long-term contracts we have put in place, and a pipeline of contracting discussions, we have decided to adjust our production plan for McArthur River/Key Lake to produce 18 million pounds (100% basis) starting in 2024, and we plan to continue to operate Cigar Lake at its licensed capacity of 18 million pounds per year (100% basis) in 2024. At Inkai, production will continue to follow the 20% reduction planned by KAP until the end of 2023.
With annual licensed capacity of 25 million pounds (100% basis) at McArthur River/Key Lake, we continue to have the ability to expand production from our existing assets, however some additional investment would be required. Any decision to expand production will be dependent on further improvements in the uranium market and our ability to secure the appropriate long-term contract homes for our unencumbered, in-ground inventory, demonstrating that we continue to responsibly manage our assets in accordance with our customers’ needs. In addition to our plans to expand uranium production, at our Port Hope UF6 conversion facility we are working on increasing production to 12,000 tonnes by 2024 to satisfy our book of long-term business for conversion services and customer demand, at a time when conversion prices are at historic highs.
Our adjusted production plans for McArthur River/Key Lake and Cigar Lake are expected to significantly improve our financial performance by allowing us to source more of our committed sales from the lower-cost produced pounds and we will no longer be required to expense care and maintenance or operational readiness costs related to McArthur River/Key Lake to cost of sales. In addition, with conversion demand elevated, we have been successful in securing long-term sales commitments that will support increased UF6 production at Port Hope, which is expected to further improve its contribution to our financial results. Over the course of 2023, we will undertake all of the activities necessary to ensure we are operationally ready to achieve the 2024 production plan. However, this is not an end to our supply discipline. We expect to continue to adjust our production in accordance with our contract portfolio. This will remain our production plan until we see further improvements in the uranium market and contracting progress, once again demonstrating that we are a responsible fuel supplier.
28 CAMECO CORPORATION
MANAGING OUR COSTS
Production costs
In order to operate efficiently and cost-effectively, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology, and business process improvements. Like all mining companies, our uranium segment is affected by the cost of inputs such as labour and fuel.
| * | Production supplies include reagents, fuel and other items. Contracted services include utilities and camp<br>costs, air charters, mining and maintenance contractors and security and ground freight. |
|---|
Over the last number of years, the annual cash cost of production reflected the operating cost of mining and milling our share of Cigar Lake as this was our only operating site. With the restart of the McArthur River/Key Lake operations the annual cost of production will reflect a combined cost of all our operating uranium assets. See 2022 financial results by segment – Uranium starting on page 57 for more information. In 2023, our cash production costs may continue to be affected by inflation, the availability of personnel with the necessary skills and experience, supply chain challenges impacting the availability of materials and reagents, and our ability to ramp up to planned production at McArthur River/Key Lake.
Operating costs in our fuel services segment are mainly fixed. In 2022, labour accounted for about 51% of the total. The largest variable operating cost is for zirconium, followed by anhydrous hydrogen fluoride, and energy (natural gas and electricity).
We continue to look to adopt innovative and advanced digital and automation technologies to improve efficiency and operational flexibility, and to further reduce cost.
Care and maintenance costs
In 2023, we expect to incur between $50 million and $60 million in care and maintenance costs related to the suspension of production at our Rabbit Lake mine and mill, and our US operations. These operations are higher-cost and a restart is less certain. We continue to evaluate our options in order to minimize these costs.
Purchases and inventory costs
Our costs are also affected by the purchases of uranium and conversion services we make under long-term contracts and on the spot market.
To meet our delivery commitments, we make use of our mined production, inventories, purchases under long-term contracts, purchases we make on the spot market and product loans. In 2023, the price for the majority of our purchases will be quoted at the time of delivery.
The cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions. The cost of purchased material affects our cost of sales, which is determined by calculating the average of all of our sources of supply, including opening inventory, production, and purchases, and adding royalties, selling costs, and care and maintenance costs. Our cost of sales could be impacted if we do not achieve our annual production plan, or we are unable to source uranium as planned, and we are required to purchase uranium at prices that differ from our cost of inventory.
MANAGEMENT’S DISCUSSION AND ANALYSIS 29
Financial impact
The growing demand for nuclear power due to its safety, clean energy, reliability, security and affordability attributes has contributed to increased demand for nuclear fuel products and services. As a result, we have seen price increases across the nuclear fuel value chain, which reflect the need for capacity increases to satisfy the projected growth.
The deliberate and disciplined actions we took to curtail production and streamline operations over the past decade came with near-term costs like care and maintenance costs, operational readiness costs, and purchase costs higher than our production costs. However, we considered these costs as investments in our future.
Today, thanks to our investments, and with our continued ability to secure new long-term sales commitments we believe we are well-positioned for growth. Our core growth is expected to come from our existing tier-one mining and fuel services assets. We do not have to build new capacity to pursue new opportunities. We have sufficient productive capacity to expand, a position we have not enjoyed in previous price cycles.
And, with the planned joint acquisition of Westinghouse, we expect to be able to expand our growth profile by extending our reach in the nuclear fuel cycle at a time when there are tremendous tailwinds for the nuclear power industry. We are extending our reach with an investment in assets, that like ours, are strategic, proven, licensed and permitted, that are located in geopolitically favourable jurisdictions, and that we expect will be able to grow from their existing footprint. These assets are also expected to provide new opportunities for our existing suite of uranium and fuel services assets.
We believe our actions and investments have helped position the company to self-manage risk and as we make the transition back to a tier-one run rate, we expect our financial performance to significantly improve, allowing us to execute on our strategy while rewarding our stakeholders for their continued patience and support of our strategy to build long-term value.
CAPITAL ALLOCATION – FOCUS ON VALUE
Delivering long-term value is a top priority. While we navigate by our investment-grade rating, we continually evaluate our investment options to ensure we allocate our capital in a way that we believe will:
| • | sustain our assets and grow our core business in a manner that we expect will create sustainable long-term value<br> |
|---|---|
| • | maintain a strong balance sheet that will allow us to execute on our strategy, take advantage of strategic<br>opportunities and self-manage risk |
| --- | --- |
| • | allow us to sustainably execute on our dividend while considering the cyclical nature of our earnings and cash<br>flow |
| --- | --- |
To deliver value, free cash flow must be productively reinvested in the business or, when appropriate, returned to shareholders, which requires good execution and disciplined allocation. Our decisions are based on the run rate of our business and other factors that we consider to be in the best interests of our stakeholders, not one-time events. Cash on our balance sheet that exceeds value-adding growth opportunities and/or is not needed to self-manage risk or for other reasons could be returned to shareholders.
We start by determining how much cash we have to invest (investable capital), which is based on our expected cash flow from operations minus expenses we consider to be a higher priority, such as dividends and financing costs, and could include others. This investable capital can be used to take advantage of new strategic opportunities in line with our corporate development objectives and long-term strategy, reinvested in the core business of the company including managing the physical and transition risks and opportunities associated with changing climate conditions, or returned to shareholders.
Reinvestment
We have a multidisciplinary capital allocation committee that evaluates possible uses of investable capital.
If a decision is made to reinvest capital in sustaining, capacity replacement, or growth, all opportunities are ranked and only those that meet the required risk-adjusted return criteria are considered for investment. We also must identify, at the corporate level, the expected impact on cash flow, earnings, and the balance sheet. All project risks must be identified, including the risks of not investing. Allocation of capital only occurs once an investment has cleared these hurdles.
This may result in some opportunities being held back in favour of higher return investments and should allow us to generate the best return on investment decisions when faced with multiple prospects, while also controlling our costs. If there are not enough good investment prospects internally or externally, this may result in residual investable capital, which we would then consider returning to shareholders.
30 CAMECO CORPORATION
Return
We believe in returning cash to shareholders under appropriate circumstances but are also focused on protecting the company and rewarding those shareholders who understand and support our strategy to build long-term value. If we have excess cash and determine the best use is to return it to shareholders, we can do that through a share repurchase or dividend—an annual dividend, one-time supplemental dividend or a progressive dividend. The decision to return capital and the type of return is evaluated by our board of directors with careful consideration of our cash flow, financial position, strategy, and other relevant factors including appropriate alignment with the cyclical nature of our earnings.
In Action
Until such time as we return to our tier-one cost structure, the objective of our capital allocation will be to ensure we have the financial capacity to execute on our strategy, including achieving production at McArthur River/Key Lake in accordance with our plan and the proposed acquisition of Westinghouse. We will continue to navigate by our investment-grade rating through close management of our balance sheet metrics, maintaining sufficient liquidity to meet our risk-mitigated working cash target and that allows us to pursue other value-adding opportunities.
As the market continues to transition, we will focus on improving operational effectiveness across our operations, including the use of digital and automation technologies with a particular goal of reducing operating costs and increasing operational flexibility. Any opportunities will be rigorously assessed by our capital allocation committee before an investment decision is made. We will invest to allow us to execute our 2024 production plan.
If we get clarity on our CRA dispute, which generates a one-time cash infusion, we may focus on the debt portion of our ratings metrics, depending on market opportunities. This may mean greater emphasis on reducing the debt on our balance sheet, including the additional debt contemplated with the proposed acquisition of Westinghouse. However, if we are able to continue increasing our portfolio of long-term contracts with acceptable pricing mechanisms, our priorities would be to invest in expanding production at our tier-one assets, and if warranted taking advantage of our existing tier-two assets and brownfield infrastructure, turning to value-adding growth opportunities including further investment in the nuclear fuel value chain and returning excess cash to shareholders.
Shares and stock options outstanding
At February 7, 2023, we had:
| • | 432,717,980 common shares and one Class B share outstanding |
|---|---|
| • | 2,854,061 stock options outstanding, with exercise prices ranging from $11.32 to $19.30 |
| --- | --- |
As announced on October 17, 2022, our $747.6 million (US) bought deal offering of common shares closed. The offering, including the exercise, in full, of the underwriters’ option to purchase additional common shares, increased our outstanding shares by 34,057,250. See Proposed acquisition of Westinghouse beginning on page 89 for more information.
Dividend
In 2022, our board of directors declared a dividend of $0.12 per common share, which was paid December 15, 2022.
The decision to declare an annual dividend by our board is reviewed regularly and will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.
MANAGEMENT’S DISCUSSION AND ANALYSIS 31
Our ESG principles and practices
A key part of our strategy, reflecting our values
We are committed to delivering our products responsibly. We integrate ESG principles and practices into every aspect of our business, from our corporate objectives and approach to compensation, to our overall corporate strategy, risk management, and day-to-day operations, and they align with our values. We seek to be transparent with our stakeholders, keeping them updated on the risks and opportunities that we believe may have a significant impact on our ability to achieve our strategic plan and add long-term value. We recognize the importance of integrating certain ESG factors, such as safety performance, a clean environment and supportive communities, into our executive compensation strategy as we see success in these areas as critical to the long-term success of the company.
Our board of directors holds the highest level of oversight for our business strategy and strategic risks, including ESG matters and climate-related risks. Oversight of ESG and climate-related reporting and disclosure has been delegated by the board to the Safety, Health and Environment (SHE) committee of the board. We also have a multi-disciplinary ESG steering committee, chaired by our senior vice-president and chief corporate officer that includes representatives from across the organization whose role is to review our ESG governance and reporting, and our current approach to sustainability, against evolving trends. Additional information about our governance of ESG matters is included in our most recent ESG report.
In an effort to continually evolve the robustness of our sustainability commitments and communications, starting in 2020, we aligned our ESG performance indicators with the ones recommended by the Sustainability Accounting Standards Board (SASB). In addition, we began addressing the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) in our ESG report. In 2022, we continued to progress our work, conducting a gap analysis to identify how we could better align to TCFD recommendations. Findings from this work identified the need to undertake scenario analysis (physical and transition) to develop a robust evidence base for our climate strategy and pursue opportunities to financially quantify identified climate-related risks and opportunities where possible. See the discussion below regarding our climate change scenario analysis for more information.
In July 2022, we published our 2021 ESG report. The report sets out our strategy and the policies and programs we use to govern and manage ESG issues that are important to our stakeholders. In addition to SASB and TCFD, the report provides key ESG performance indicator data based on the Global Reporting Initiative’s Sustainability Framework as well as some unique corporate indicators, to measure and report our performance on environmental, social and economic impacts in the areas we believe have a significant impact on our sustainability in the long-term and that are important to our stakeholders. This is our ESG report card to our stakeholders. You can find our report at cameco.com/about/sustainability.
ENVIRONMENT
We recognize and embrace our responsibility to manage our activities with care for the protection of environmental resources. Protection of the environment is one of our highest corporate priorities during all stages of our activities from exploration through development, operations, and decommissioning. Environmental stewardship is embedded in how we operate.
We are guided by our safety, health, environment and quality policy and associated programs that are designed to minimize our impact on air, land, and water and to conserve the biodiversity of surrounding ecosystems. Across our operations, we comply with strict regulations and have systems in place to monitor and mitigate our potential impacts. In addition to our own environmental monitoring, we collaborate with local communities in northern Saskatchewan around our operations to give confidence to them that traditionally harvested foods remain safe to eat, and water remains safe to drink.
32 CAMECO CORPORATION
Climate change: Nuclear power is part of the solution
We recognize the critical nature of the fight against climate change, and want our employees, customers, investors, and community partners near our operations to know we are committed to being an active and constructive partner in addressing this challenge. The reduction of carbon and greenhouse gas (GHG) emissions is important and necessary in Canada and around the world. Nuclear power must be a central part of the solution to the world’s shift to a low-carbon, climate-resilient economy. As one of the world’s largest producers of the uranium needed to fuel nuclear reactors, we believe there is a significant opportunity for us to be part of the solution to combat climate change. We enable vast emissions reductions that can be achieved through nuclear power and are committed to transforming our already low GHG emissions footprint to achieve our ambition of having net-zero emissions while delivering significant long-term business value.
In accordance with our 2022 compensable corporate objectives, we undertook a planning process to outline our overarching low-carbon transition strategy. We identified the practical and achievable actions that we expect to take to decarbonize our operations and manage climate-related risks. In doing so, we are demonstrating our alignment with the ambitions of the Paris Agreement to, “limit global temperature rise to well below 2 degrees Celsius (°C), above pre-industrial levels, and to pursue efforts to limit global temperature rise even further to 1.5°C”. By extension, we are demonstrating our alignment with the Government of Canada’s commitment to the Paris Agreement in accordance with the Net Zero Accountability Act and resulting 2030 Emissions Reduction Plan.
We recognize that climate change, including shifts in temperature, precipitation and more frequent severe weather events could affect our operations in a range of possible ways. As part of our low-carbon transition planning, we completed a climate change scenario analysis to understand how projected long-term changing climate conditions could impact our employees, assets, and operations in northern Saskatchewan. We leveraged internal subject matter expertise with help from a third-party expert to complete the assessment.
The physical risk assessment study was undertaken to deliver an initial forward-looking physical climate risk assessment across our four sites in northern Saskatchewan and identify possible risk management and adaptation options. The next steps for the northern Saskatchewan physical risk assessment are to embed the physical climate risk findings into Cameco’s internal risk processes and develop an adaptation action plan for each site in the study. We are targeting the completion of similar assessments for all our majority owned and operated facilities over the next five years. In 2023, we will focus our physical climate risk assessment efforts on our Ontario operations.
We will continue to explore climate change projections for the areas where we operate and those critical to moving supplies and products through our value chain. We will use this information to identify where our existing climate-related acute and chronic risk management practices are expected to remain sufficient in the years to come and where adaptation and other enhancements may be required.
When it comes to climate change, we have tracked and reported our GHG emissions for more than two decades. A summary of our activities to understand and mitigate the risks associated with climate change scenarios is reported to the board of directors on a regular basis in accordance with our Enterprise Risk Management program, including the mitigating controls and management actions taken to reduce these risks.
In 2022, we developed the Energy and GHG Emissions Reductions Ideas Box that allows all employees to submit ideas to support us in reducing operational emissions. The Ideas Box also provides employees the opportunity to see key details from all decarbonization projects under investigation today.
We have also enjoyed some significant success in our efforts to reduce our energy use and GHG emissions to date. For example, at our Port Hope conversion facility, we have achieved a 28% reduction to peak power demand and more than $2.1 million in annual energy savings with projects such as HVAC and compressed air system upgrades and lighting efficiency retrofits. At our northern Saskatchewan mining and milling operations, recent efforts have focused on the implementation of an Energy Management Information System (EMIS) in alignment with our larger digital transformation efforts. The EMIS improves our ability to visualize, monitor, and manage our energy use and emissions profile in real time. Ultimately, EMIS gives those operations the ability to identify where our highest impact emissions reduction opportunities exist and assurance that the actions we have taken are maintained over time.
MANAGEMENT’S DISCUSSION AND ANALYSIS 33
Beyond these projects and initiatives, we have completed work to profile our emissions, enabling the identification of multiple high impact energy efficiency and emissions reductions opportunities including lighting retrofits, building envelope improvements, heat recovery projects, and the ability to explore alternative energy sources. Through these and other innovative decarbonization actions across efficiency, electrification, waste to value, carbon economy, and fuel switching themes – we expect to achieve a 30% absolute reduction from our total Scope 1 and 2 emissions level by 2030 from our 2015 baseline as our first major milestone on the journey to achieve our ambition of being net zero. For our Scope 2 emissions (purchased power), achieving this target will largely be dependent on the success of SaskPower in decarbonizing its grid in accordance with its current plans.
SOCIAL
Our relationships with our workforce, Indigenous Peoples, and local communities are fundamental to our success. The safety and protection of our workforce and the public is our top priority in our assessment of risk and planning for safe operations and product transport. To deliver on our vision, we invest in programs to attract and retain a diverse and skilled workforce that better reflects the communities in which we operate and to increase the participation of underrepresented groups in trades and technical positions. We want to build a workforce that is dedicated to continuous improvement and shares our values.
The importance of our workers and Indigenous Peoples working and living near our operations is exemplified by our ongoing commitment to help manage the impacts of the COVID-19 pandemic on our workforce, their families and their communities.
Our response to the COVID-19 pandemic
We continue to closely monitor and adapt to the developments related to COVID-19. Throughout the pandemic, our priority has been to protect the health and well-being of our workers, including employees and contractors, their families, and their communities.
The proactive decisions we made, and our ongoing efforts to monitor and manage the risk of COVID-19, to help ensure our workers are safe are consistent with our values. The health and safety of our workers, their families and their communities continues to be the priority in all our plans, which will align with the guidance of the relevant health authorities where we operate.
GOVERNANCE
We believe that sound governance is the foundation for strong corporate performance. Our diverse and independent board of directors’ primary role is to provide strategic direction and risk oversight in order to help the company achieve its vision of “energizing a clean-air world”. The board guides the company to operate as a sustainable business, to optimize financial returns while effectively managing risk, and to conduct business in a way that is transparent, independent, and ethical.
The board has formal governance guidelines that set out our approach to governance and the board’s governance role and practices. The guidelines ensure we comply with all of the applicable governance rules and legislation in Canada and the US, conduct ourselves in the best interests of our stakeholders, and meet industry best practices. The guidelines are reviewed and updated regularly.
Our corporate governance framework includes an established and recognized management system that describes the policies, processes and procedures we use to help us fulfill all the tasks required to achieve our objectives and strategy. It sets out our vision, values, and measures of success. It speaks to our strategic planning process, leadership alignment and accountability, compliance and assessment, people and culture, process identification and work management, risk management, communications and stakeholder support, knowledge and information management, change management, problem identification and resolution, and continual improvement.
Risk and Risk Management
Our board of directors oversees management’s implementation of appropriate risk management processes and controls. We have a Risk Policy that is supported by our formal Risk Management Program.
34 CAMECO CORPORATION
Our Risk Management Program involves a broad, systematic approach to identifying, assessing, monitoring, reporting and managing the significant risks we face in our business and operations, including consideration of ESG and climate-related risks that could impact our four measures of success. The program is based on the ISO 31000 Risk Management guidelines. ISO 31000 provides guidance on risk management activities with internationally recognized practices and provides sound principles for effective management and governance of risks. Our program applies to all risks facing the company, including climate-related risks. The program establishes clear accountabilities for employees throughout the company to take ownership of risks specific to their area and to effectively manage those risks. The program is reviewed annually to ensure that it continues to meet our needs.
We use a common risk matrix throughout the company. Any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan is considered an enterprise risk and is brought to the attention of senior management and the board. We continually update our risk profile by performing regular monitoring of risks across the organization. Regular monitoring helps us to properly manage risks and identify any new risks. Detailed risk reporting is provided on a quarterly basis to senior management and the board and its committees on the status of the mitigating and/or monitoring plans for each of the enterprise risks. Management also reviews monthly updates on the company’s progress in managing these risks.
In addition to considering the other information in this MD&A, you should carefully consider the material risks discussed starting on page 4, under the heading Managing the risks, starting on page 67, and the specific risks discussed under each operation, advanced project, and other fuel cycle investment update in this document. These risks, however, are not a complete list of the potential risks our operations, advanced projects, or other investments face. There may be others we are not aware of or risks we feel are not material today that could become material in the future.
We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.
MANAGEMENT’S DISCUSSION AND ANALYSIS 35
Measuring our results
Targets and Metrics: The link between ESG factors and executive pay
Each year, we set corporate objectives that are aligned with our strategic plan. These objectives fall under our four measures of success: outstanding financial performance, safe, healthy and rewarding workplace, clean environment and supportive communities. Performance against specific targets under these objectives forms the foundation for a portion of annual employee and executive compensation. See our most recent management proxy circular for more information on how executive compensation is determined.
Our targets for 2022 continue to reflect the operational strategic actions that we have taken. While we saw a significant improvement in our financial performance (earnings and cash flow) as our tier-one production increases and our average realized price reflects the improving market, our results still do not reflect our expected long-term run rate performance. As our long-term contract portfolio continues to grow and our tier-one production continues to ramp up, we believe that the strategic actions we have taken have helped to pave the way to stronger financial performance over time. Additionally, we will not compromise our commitment to safety, people and our environment.
| 2022<br>OBJECTIVES^1^ | TARGET | RESULTS |
|---|---|---|
| OUTSTANDING FINANCIAL PERFORMANCE | ||
| Earnings measure | Achieve targeted adjusted net earnings. | • adjusted net earnings was above the target |
| Cash flow measure | Achieve targeted cash flow from operations (before working capital changes). | • cash flow from operations was above the target |
| SAFE, HEALTHY AND REWARDING WORKPLACE | ||
| Workplace safety measure | Strive for no injuries at all Cameco-operated sites. Maintain a long-term downward trend in combined employee and contractor total recordable injury rate while achieving targets on specified leading indicators. | • we did not achieve our target for TRIR<br><br><br><br> <br>• performance of the<br>leading indicators was within the target range |
| CLEAN ENVIRONMENT | ||
| Environmental performance measures | Achieve divisional environmental aspect improvement targets.<br> <br><br><br><br>Complete initial planning to outline our overarching low-carbon transition strategy | • performance on divisional environmental targets was below the targeted<br>range<br> <br><br> <br>• Completed<br>initial planning and identified the practical and achievable actions that we expect to take to reduce carbon emissions at our operations and manage climate-related risks |
| SUPPORTIVE COMMUNITIES | ||
| Stakeholder support measure | Enhance the skill set of Residents of Saskatchewan’s North (RSN) for changing industrial environments | • a RSN work placement program was developed and implemented with 50%<br>female participation with support from external agencies, achieving results above the target |
| ^1^ | Detailed results for our 2022 corporate objectives and the related targets will be provided in our 2023<br>management proxy circular prior to our Annual Meeting of Shareholders on May 10, 2023. | |
| --- | --- |
36 CAMECO CORPORATION
2023 objectives
OUTSTANDING FINANCIAL PERFORMANCE
| • | Achieve targeted financial measures. |
|---|
SAFE, HEALTHY AND REWARDING WORKPLACE
| • | Improve workplace safety performance at all sites. |
|---|
CLEAN ENVIRONMENT
| • | Improve environmental performance at all sites. |
|---|
SUPPORTIVE COMMUNITIES
| • | Build and sustain strong stakeholder support for our activities. |
|---|
MANAGEMENT’S DISCUSSION AND ANALYSIS 37
Financial results
This section of our MD&A discusses our performance, financial condition and outlook for the future.
| 39 | 2022 CONSOLIDATED FINANCIAL RESULTS |
|---|---|
| 48 | OUTLOOK FOR 2023 |
| 50 | LIQUIDITY AND CAPITAL RESOURCES |
| 57 | 2022 FINANCIAL RESULTS BY SEGMENT |
| 57 | URANIUM |
| 59 | FUEL SERVICES |
| 60 | FOURTH QUARTER FINANCIAL RESULTS |
| 60 | CONSOLIDATED RESULTS |
| 63 | URANIUM |
| 64 | FUEL SERVICES |
38 CAMECO CORPORATION
2022 consolidated financial results
In the second quarter of 2022, we along with Orano acquired Idemitsu Canada Resources Ltd.’s 7.875% participating interest in the Cigar Lake Joint Venture. Our ownership stake in Cigar Lake now stands at 54.547%, 4.522 percentage points higher than it was prior to the transaction. Effective May 19, 2022, we have reflected our share or production and financial results based on this new ownership stake.
| HIGHLIGHTS | CHANGE FROM | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| DECEMBER 31 ( MILLIONS EXCEPT WHERE INDICATED) | 2021 | 2020 | 2021 TO 2022 | |||||||
| Revenue | 1,868 | 1,475 | 1,800 | 27 | % | |||||
| Gross profit | 233 | 2 | 106 | >100 | % | |||||
| Net earnings (loss) attributable to equity holders | 89 | (103 | ) | (53 | ) | >100 | % | |||
| per common share (basic) | 0.22 | (0.26 | ) | (0.13 | ) | >100 | % | |||
| per common share (diluted) | 0.22 | (0.26 | ) | (0.13 | ) | >100 | % | |||
| Adjusted net earnings (loss) (non-IFRS, see page<br>40) | 135 | (98 | ) | (66 | ) | >100 | % | |||
| per common share (adjusted and diluted) | 0.33 | (0.25 | ) | (0.17 | ) | >100 | % | |||
| Cash provided by operations | 305 | 458 | 57 | (33 | )% |
All values are in US Dollars.
Net earnings
The following table shows what contributed to the change in net earnings in 2022 compared to 2021 and 2020.
| ( MILLIONS) | 2021 | 2020 | ||||||
|---|---|---|---|---|---|---|---|---|
| Net earnings (losses) - previous year | (103 | ) | **** | (53 | ) | **** | 74 | **** |
| Change in gross profit by segment | ||||||||
| (we calculate gross profit by deducting from revenue the cost of products and<br>services sold, and depreciation and amortization (D&A), net of hedging benefits) | ||||||||
| Uranium | (6 | ) | (4 | ) | (4 | ) | ||
| 328 | 5 | 25 | ||||||
| 44 | (72 | ) | 14 | |||||
| (137 | ) | (55 | ) | (169 | ) | |||
| 229 | (126 | ) | (134 | ) | ||||
| Fuel services | (21 | ) | 1 | (4 | ) | |||
| 33 | 23 | 21 | ||||||
| (13 | ) | (2 | ) | (10 | ) | |||
| (1 | ) | 22 | 7 | |||||
| Other changes | ||||||||
| Lower (higher) administration expenditures | (44 | ) | 17 | (20 | ) | |||
| Lower (higher) exploration expenditures | (3 | ) | 3 | 3 | ||||
| Change in reclamation provisions | (31 | ) | 32 | (21 | ) | |||
| Change in gains or losses on derivatives | (86 | ) | (24 | ) | 5 | |||
| Change in foreign exchange gains or losses | 74 | (14 | ) | 33 | ||||
| Change in earnings from equity-accounted investments | 26 | 32 | (9 | ) | ||||
| Redemption of Series E debentures in 2020 | — | 24 | (24 | ) | ||||
| Canadian Emergency Wage Subsidy | (21 | ) | (16 | ) | 37 | |||
| Arbitration award in 2019 related to TEPCO contract | — | — | (52 | ) | ||||
| Bargain purchase gain on CLJV ownership interest increase | 23 | — | — | |||||
| Higher (lower) finance income | 30 | (4 | ) | (19 | ) | |||
| Change in income tax recovery or expense | 3 | 15 | 47 | |||||
| Other | (7 | ) | (11 | ) | 20 | |||
| Net earnings (losses) - current year | 89 | **** | **** | (103 | ) | **** | (53 | ) |
All values are in US Dollars.
MANAGEMENT’S DISCUSSION AND ANALYSIS 39
Non-IFRS measures
ADJUSTED NET EARNINGS
Adjusted net earnings (ANE) is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS financial measure). We use this measure as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting 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 one of the targets that we measure to form the basis for a portion of annual employee and executive compensation (see Measuringour results starting on page 36).
In calculating ANE we adjust for derivatives. We do not use hedge accounting under IFRS and, therefore, we are required to report gains and losses on all hedging activity, both for contracts that close in the period and those that remain outstanding at the end of the period. For the contracts that remain outstanding, we must treat them as though they were settled at the end of the reporting period (mark-to-market). However, we do not believe the gains and losses that we are required to report under IFRS appropriately reflect the intent of our hedging activities, so we make adjustments in calculating our ANE to better reflect the impact of our hedging program in the applicable reporting period. See Foreign exchange starting on page 46 for more information.
We also adjust for changes to our reclamation provisions that flow directly through earnings. 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 our asset retirement obligation 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)”. See note 16 of our annual financial statements for more information. This amount has been excluded from our ANE measure.
The bargain purchase gain that was recognized when we acquired our pro-rata share of Idemitsu Canada Resources Ltd.’s 7.875% participating interest in the Cigar Lake Joint Venture has also been removed in calculating ANE since it is non-cash, non-operating and outside of the normal course of our business. The gain was recorded in the statement of earnings as part of “other income (expense)”.
Adjusted net earnings is a non-IFRS financial measure 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.
40 CAMECO CORPORATION
To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2022, 2021 and 2020.
| ($ MILLIONS) | 2022 | 2021 | 2020 | ||||||
|---|---|---|---|---|---|---|---|---|---|
| Net earnings (loss) attributable to equity holders | **** | 89 | **** | (103 | ) | (53 | ) | ||
| Adjustments | |||||||||
| Adjustments on derivatives | **** | 76 | **** | 13 | (45 | ) | |||
| Adjustments on other operating expense (income) | **** | 26 | **** | (8 | ) | 24 | |||
| Adjustment to other income | **** | (23 | ) | — | — | ||||
| Income taxes on adjustments | **** | (33 | ) | — | 8 | ||||
| Adjusted net earnings (loss) | **** | 135 | **** | (98 | ) | (66 | ) |
The following table shows what contributed to the change in adjusted net earnings (non-IFRS measure, see above) in 2022 compared to the same period in 2021 and 2020.
| ( MILLIONS) | 2021 | 2020 | ||||||
|---|---|---|---|---|---|---|---|---|
| Adjusted net earnings (losses) - previous year | (98 | ) | **** | (66 | ) | **** | 41 | **** |
| Change in gross profit by segment | ||||||||
| (we calculate gross profit by deducting from revenue the cost of products and<br>services sold, and depreciation and amortization (D&A), net of hedging benefits) | ||||||||
| Uranium | (6 | ) | (4 | ) | (4 | ) | ||
| 328 | 5 | 25 | ||||||
| 44 | (72 | ) | 14 | |||||
| (137 | ) | (55 | ) | (169 | ) | |||
| 229 | (126 | ) | (134 | ) | ||||
| Fuel services | (21 | ) | 1 | (4 | ) | |||
| 33 | 23 | 21 | ||||||
| (13 | ) | (2 | ) | (10 | ) | |||
| (1 | ) | 22 | 7 | |||||
| Other changes | ||||||||
| Lower (higher) administration expenditures | (44 | ) | 17 | (20 | ) | |||
| Lower (higher) exploration expenditures | (3 | ) | 3 | 3 | ||||
| Change in reclamation provisions | 3 | — | — | |||||
| Change in gains or losses on derivatives | (23 | ) | 34 | 9 | ||||
| Change in foreign exchange gains or losses | 74 | (14 | ) | 33 | ||||
| Change in earnings from equity-accounted investments | 26 | 32 | (9 | ) | ||||
| Redemption of Series E debentures in 2020 | — | 24 | (24 | ) | ||||
| Canadian Emergency Wage Subsidy | (21 | ) | (16 | ) | 37 | |||
| Arbitration award in 2019 related to TEPCO contract | — | — | (52 | ) | ||||
| Higher (lower) finance income | 30 | (4 | ) | (19 | ) | |||
| Change in income tax recovery or expense | (30 | ) | 7 | 42 | ||||
| Other | (7 | ) | (11 | ) | 20 | |||
| Adjusted net earnings (losses) - current year | 135 | **** | **** | (98 | ) | **** | (66 | ) |
All values are in US Dollars.
Average realized prices
| CHANGE FROM | |||||||
|---|---|---|---|---|---|---|---|
| 2021 | 2020 | 2021 TO 2022 | |||||
| Uranium^1^ | US/lb | 44.73 | 34.53 | 34.39 | 30% | ||
| Cdn/lb | 57.85 | 43.34 | 46.13 | 33% | |||
| Fuel services | Cdn/kgU | 32.92 | 29.72 | 27.89 | 11% |
All values are in US Dollars.
| ^1^ | Average realized foreign exchange rate ($US/$Cdn): 2022 – 1.29, 2021 – 1.26 and 2020 – 1.34.<br> |
|---|
MANAGEMENT’S DISCUSSION AND ANALYSIS 41
Revenue
The following table shows what contributed to the change in revenue for 2022.
| ( MILLIONS) | |
|---|---|
| Revenue – 2021 | **** |
| Uranium | |
| Higher sales volume | |
| Higher realized prices (Cdn) | |
| Fuel services | |
| Lower sales volume | ) |
| Higher realized prices (Cdn) | |
| Other | |
| Revenue – 2022 | **** |
All values are in US Dollars.
See 2022 Financial results by segment on page 57 for more detailed discussion.
THREE-YEAR TREND
In 2021, revenue decreased by 18% compared to 2020 due to a decrease in sales volume in the uranium segment and a decrease in the Canadian dollar average realized price. In our fuel services segment, revenue increased by 10% as a result of the increase in average realized price and sales volume.
In 2022, revenue increased by 27% compared to 2021 due to an increase in the average realized price and sales volume in the uranium segment. In our fuel services segment, revenue decreased by 10% as a result of a decrease in sales volume partially offset by an increase in average realized price. See notes 18 and 29 in our annual financial statements for more information.
SALES DELIVERY OUTLOOK FOR 2023
For 2023 we have committed sales volumes in our uranium segment of between 29 and 31 million pounds. In general, we are active in the market, buying and selling uranium when it is beneficial for us and in support of our long-term contract portfolio.
In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly. We expect the quarterly distribution of uranium deliveries in 2023 to be more heavily weighted to the first and fourth quarters as shown below. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.
42 CAMECO CORPORATION
Corporate expenses
ADMINISTRATION
| ($ MILLIONS) | 2022 | 2021 | CHANGE | |||||
|---|---|---|---|---|---|---|---|---|
| Direct administration^1^ | **** | 143 | 111 | 29 | % | |||
| Stock-based compensation^1^ | **** | 25 | 44 | (43 | )% | |||
| Reversal (recovery) of fees related to CRA dispute | **** | 4 | (27 | ) | 115 | % | ||
| Total administration | **** | 172 | 128 | 34 | % | |||
| ^1^ | Direct administration and stock-based compensation are supplementary financial measures. They are components of<br>administration expense as shown on the statement of earnings and calculated according to IFRS. | |||||||
| --- | --- |
Direct administration costs in 2022 were $32 million higher than in 2021 largely due to costs related to digital initiatives. Increased activities associated with the restart of operations at McArthur River and Key Lake, increased business travel and work associated with other business activities also resulted in increased costs.
We recorded $25 million in stock-based compensation expenses in 2022, $19 million lower compared to 2021 due primarily to a reduction in the expense related to the executive performance share units as a result of a change in assumptions for vesting criteria. See note 25 to the financial statements.
In 2021, we recorded $27 million as a reduction to administration costs to reflect the amounts owing to us for the recovery of costs as was awarded to us on the successful outcome in our transfer pricing dispute with Canada Revenue Agency (CRA). In 2022, we adjusted this amount by $4 million to reflect the actual recovery for costs. See Transfer pricing dispute on page 44 for more information.
Administration outlook for 2023
We expect direct administration costs to be between $160 million to $170 million.
EXPLORATION
Our 2022 exploration activities were focused primarily on Canada. Our spending increased from $8 million in 2021 to $11 million in 2022 reflects higher planned expenditures.
Exploration outlook for 2023
We expect exploration expenses to be about $18 million in 2023. The focus for 2023 will be on our core projects in Saskatchewan.
FINANCE COSTS
Finance costs were $86 million, an increase from $77 million in 2021 due to higher costs related to the unwinding of the discount on our reclamation provisions. See note 20 to the financial statements.
FINANCE INCOME
Finance income was $37 million compared to $7 million in 2021 mainly due to higher interest rates and higher balances for cash and cash equivalents and short-term investments in 2022.
GAINS AND LOSSES ON DERIVATIVES
In 2022, we recorded $73 million in losses on our derivatives compared to $13 million in gains in 2021. The increased losses reflect a weaker Canadian dollar compared to the US dollar in 2022 compared to 2021. See Foreign exchange on page 46 and note 27 to the financial statements.
INCOME TAXES
We recorded an income tax recovery of $4 million in 2022 compared to a recovery of $1 million in 2021 as a result of an income tax recovery in Canada that was offset by an expense in foreign jurisdictions. Equity accounted investees are included in Canadian earnings net of tax paid in the jurisdiction in which they operate. Foreign earnings include losses in some jurisdictions for which no future tax benefit has been recognized.
In 2022, we recorded earnings of $100 million in Canada compared to earnings of $59 million in 2021, while in foreign jurisdictions, we recorded a loss of $15 million compared to a loss of $162 million in 2021.
MANAGEMENT’S DISCUSSION AND ANALYSIS 43
| ($ MILLIONS) | 2022 | 2021 | ||||
|---|---|---|---|---|---|---|
| Net earnings (loss) before income taxes | ||||||
| Canada | **** | 100 | **** | 59 | ||
| Foreign | **** | (15 | ) | (162 | ) | |
| Total net earnings (loss) before income taxes | **** | 85 | **** | (103 | ) | |
| Income tax expense (recovery) | ||||||
| Canada | **** | (8 | ) | (2 | ) | |
| Foreign | **** | 4 | **** | 1 | ||
| Total income tax recovery | **** | (4 | ) | (1 | ) | |
| Effective tax rate | **** | (5 | )% | 1 | % |
TRANSFER PRICING DISPUTE
Background
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.
For the years 2003 to 2014, CRA shifted Cameco Europe Limited’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. In addition, for 2014 to 2016, CRA has advanced an alternate reassessing position, see Reassessments, remittance and next steps below for more information.
In September 2018, the Tax Court of Canada (Tax Court) ruled that our marketing and trading structure involving foreign subsidiaries, as well as the related transfer pricing methodology used for certain intercompany uranium sales and purchasing agreements, were in full compliance with Canadian law for the tax years in question (2003, 2005 and 2006). On June 26, 2020 the Federal Court of Appeal (Court of Appeal) upheld the Tax Court’s decision.
On February 18, 2021, the Supreme Court of Canada (Supreme Court) dismissed CRA’s application for leave to appeal the June 26, 2020 decision of the Court of Appeal. The dismissal means that the dispute for the 2003, 2005 and 2006 tax years is fully and finally resolved in our favour. Although not technically binding, there is nothing in the reasoning of the lower court decisions that should result in a different outcome for the 2007 through 2014 tax years, which were reassessed on the same basis.
Refund and cost award
The Minister of National Revenue issued new reassessments for the 2003 through 2006 tax years in accordance with the decision and in July 2021, refunded the tax paid for those years. Pursuant to a cost award from the courts, we are expecting a payment of approximately $13 million for disbursements which is in addition to the $10 million we received from CRA in April 2021 as reimbursement for legal fees.
Reassessments, remittances and next steps
The Canadian income tax rules include provisions that generally 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. While we have received a refund for the amounts remitted for the 2003 through 2006 reassessments as noted above, CRA continues to hold $778 million ($295 million in cash and $483 million in letters of credit) we paid or secured for the years 2007 through 2013. For the 2014 and 2015 reassessments, CRA did not require additional security to secure the tax debts they considered owing. We have requested the same treatment with respect to the 2016 reassessment.
Following the Supreme Court’s dismissal of CRA’s application for leave to appeal, we wrote to CRA requesting reversal of CRA’s transfer pricing adjustments for 2007 through 2013 and the return of our $778 million in cash and letters of credit. Given the strength of the court decisions received, our request was made on the basis that the Tax Court would reject any attempt by CRA to defend its reassessments for the 2007 through 2013 tax years applying the same or similar positions already denied for previous years. Due to a lack of significant progress in response to our request, in October 2021, we filed a notice of appeal with the Tax Court for the years 2007 through 2013. We are asking the Tax Court to order the reversal of the CRA’s transfer pricing adjustment for those years and the return of our cash and letters of credit, with costs.
44 CAMECO CORPORATION
In 2020, CRA advanced an alternate reassessing position for the 2014 tax year in the event the basis for its original reassessment, noted above, is unsuccessful. Subsequent to this, in 2021, we received a reassessment for the 2015 tax year and in late 2022, we received a reassessment for the 2016 tax year, both using this alternative reassessing position. The new basis of reassessment is inconsistent with the methodology CRA has pursued for prior years and we are disputing it separately. Our view is that this alternate methodology will not result in a materially different outcome from our 2014 to 2016 filing positions. On October 12, 2022, we filed an appeal with the Tax Court for the years 2014 and 2015, and plan to file a notice of objection for 2016.
We will not be in a position to determine the definitive outcome of this dispute for any tax year other than 2003 through 2006 until such time as all reassessments have been issued advancing CRA’s arguments and final resolution is reached for that tax year. CRA may also advance alternative reassessment methodologies for years other than 2003 through 2006, such as the alternative reassessing position advanced for 2014 through 2016.
Caution about forward-looking information relating to our CRA tax dispute
This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.
Assumptions
| • | our entitlement and ability to receive the expected refunds and payments from CRA |
|---|---|
| • | the courts will reach consistent decisions for subsequent tax years that are based on similar positions and arguments |
| --- | --- |
| • | CRA will not successfully advance different positions and arguments that may lead to a different outcome for other tax years |
| --- | --- |
Material risks that could cause actual results to differ materially
| • | we will not receive the expected refunds and payments from CRA |
|---|---|
| • | the possibility the courts may accept the same, similar or different positions and arguments advanced by CRA to reach decisions that are adverse to us for other tax years |
| --- | --- |
| • | the possibility that we will not be successful in eliminating all double taxation |
| --- | --- |
| • | the possibility that CRA does not agree that the court decisions for the years that have been resolved in Cameco’s favour should apply to subsequent tax years |
| --- | --- |
| • | the possibility CRA will not return all or substantially all of the cash and security that has been paid or otherwise secured by Cameco in a timely manner, or at all |
| --- | --- |
| • | the possibility of a materially different outcome in disputes for other tax years |
| --- | --- |
| • | an unfavourable determination of the officer of the Tax Court of the amount of our disbursements award |
| --- | --- |
Tax outlook for 2023
Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. Since 2017, our global marketing organization has been mainly consolidated in Canada in order to achieve efficiencies, resulting in more income earned in Canada. In addition, equity accounted investees are included in Canadian earnings net of tax paid in the jurisdiction in which they operate. We continue to expect our consolidated tax rate will trend toward the Canadian statutory rate in the longer term.
The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and differences between accounting earnings and income for tax purposes. In addition, the Organization for Economic Co-operation and Development has proposed the introduction of rules that would impose a global minimum tax rate of 15%. The European Union has unanimously agreed to implement these rules and impose them into each country’s national law by the end of 2023, and we expect Canada to follow suit. If these tax laws are enacted or substantively enacted in any jurisdiction in which we operate, we may be subject to a minimum rate of 15% in that jurisdiction.
MANAGEMENT’S DISCUSSION AND ANALYSIS 45
FOREIGN EXCHANGE
The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments.
We sell the majority of our uranium and fuel services products under long-term sales contracts, which are routinely denominated in US dollars. Our product purchases are 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 risk management policy is based on a 60-month period and permits us to hedge 35% to 100% of our expected net exposure in the first 12-month period. Our normal practice is to layer in hedge contracts over a three- to four-year period with the hedge percentage being highest in the first 12 months and decreasing hedge percentages in subsequent years. The portion of our net exposure that remains unhedged is subject to prevailing market exchange rates for the period. Therefore, our results are affected by the movements in the exchange rate on our hedge portfolio (explained below), and on the unhedged portion of our net exposure. A weakening Canadian dollar would have a positive effect on the unhedged exposure, and a strengthening Canadian dollar would have a negative effect.
Impact of hedging on IFRS earnings
We do not use hedge accounting under IFRS and, therefore, we are required to report gains and losses on all hedging activity, both for contracts that close in the period and those that remain outstanding at the end of the period. For the contracts that remain outstanding, we must treat them as though they were settled at the end of the reporting period (mark-to-market).
However, we do not believe the gains and losses that we are required to report under IFRS appropriately reflect the intent of our hedging activities, so we make adjustments in calculating our ANE to better reflect the impact 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 2023 and future years and we will recognize the gains or 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 or 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 40.
The table below provides a summary of our hedge portfolio at December 31, 2022. You can use this information to estimate the expected gains or losses on derivatives for 2023 on an ANE basis. However, due to the uncertainty around timing of closing of the proposed Westinghouse acquisition, we have not included the associated debt financing and cash outflows as part of the net US exposure for 2023, however our current USD cash position (which includes the equity issuance proceeds) is included. Additionally, if we add contracts to the portfolio that are designated for use in 2023 or if there are changes in the US/Cdn exchange rates in the year, those expected gains or losses could change.
46 CAMECO CORPORATION
Hedge portfolio summary
| DECEMBER 31, 2022 | AFTER | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ( MILLIONS) | 2023 | 2023 | TOTAL | |||||||
| US dollar forward contracts | ) | 330 | 710 | 1,040 | ||||||
| Average contract rate 1 | ) | 1.29 | 1.31 | 1.30 | ||||||
| US dollar option contracts | ) | 60 | 10 | 70 | ||||||
| Average contract rate range1 | ) | 1.32 to 1.36 | 1.20 to 1.24 | 1.30 to 1.34 | ||||||
| Total US dollar hedge contracts | ) | **** | 390 | **** | **** | 720 | **** | **** | 1,110 | **** |
| Average hedge rate range | ) | **** | 1.29 to 1.30 | **** | **** | 1.31 | **** | **** | 1.30 | **** |
| Hedge ratio2,3 | **** | 21 | % | **** | 13 | % | **** | 19 | % |
All values are in US Dollars.
| ^1^ | The average contract rate is the weighted average of the rates stipulated in the outstanding contracts.<br> |
|---|---|
| ^2^ | Hedge ratio is calculated by dividing the amount (in foreign currency) of outstanding derivative contracts by<br>estimated future net exposures. |
| --- | --- |
| ^3^ | Due to the uncertainty around timing of closing of the proposed Westinghouse acquisition, our hedge ratio is<br>below our minimum as we have not included the financing or closing costs as part of the net US exposure. |
| --- | --- |
At December 31, 2022:
| • | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.36 (Cdn), up from $1.00 (US) for<br>$1.26 (Cdn) at December 31, 2021. The exchange rate averaged $1.00 (US) for $1.30 (Cdn) over the year. |
|---|---|
| • | The mark-to-market position on<br>all foreign exchange contracts was a $48 million loss compared to a $28 million gain at December 31, 2021. The mark-to-market position is a component of<br>gain on derivatives as shown on the statement of earnings and calculated in accordance with IFRS. |
| --- | --- |
We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2022, all of our hedging counterparties had a Standard & Poor’s (S&P) credit rating of A or better.
For information on the impact of foreign exchange on our intercompany balances, see note 27 to the financial statements.
MANAGEMENT’S DISCUSSION AND ANALYSIS 47
Outlook for 2023
Our outlook for 2023 is beginning to reflect the transition of our cost structure back to a tier-one run rate, as we plan our production to satisfy the growing long-term commitments under our contract portfolio. With our plan to produce 18 million pounds per year (100% basis) at Cigar Lake, 18 million pounds per year (100% basis) at McArthur River/Key Lake beginning in 2024, and increase UF6 production at our Port Hope conversion facility, we expect to see continued improvement in our financial performance.
From a cash perspective, we expect to generate strong cash flows. The amount of cash generated will be dependent on the timing and volume of production and the timing and magnitude of our purchasing activity. Therefore, our cash balances may fluctuate throughout the year.
As in prior years, we will incur care and maintenance costs for the ongoing curtailment of our tier-two assets, which are expected to be between $50 million and $60 million.
2022 outlook compared to actual
Our actual results were largely in-line with the outlook provided in our third quarter MD&A. In 2022 we announced the restart of McArthur River/Key Lake. Throughout 2022, the operations transitioned to production. Based on the restart schedule, we set a production target for up to 1.4 million pounds (our share) for McArthur River/Key Lake. We achieved 0.8 million pounds (our share) production at McArthur River/Key Lake as we worked through some normal commissioning issues at the mill. At Cigar Lake, we achieved 9.6 million pounds production (our share), in line with expectations.
As a result of the lower production from McArthur River/Key Lake and deferral and uncertainty related to the timing of receipt of our deliveries from JV Inkai, additional purchases were made.
Capital expenditures for 2022 were $143 million, lower than our outlook of $150 to $175 million, as a result of the deferral of project work to 2023.
See 2022 Financial results by segment on page 57 for details.
2023 Financial outlook
| CONSOLIDATED | FUEL SERVICES | ||||
|---|---|---|---|---|---|
| Production (owned and operated properties) | — | 20.3 million lbs | 13 to 14 million kgU | ||
| Purchases | — | 9 to 11 million lbs | — | ||
| Sales/delivery volume | — | 29 to 31 million lbs | 11.5 to 12.5 million kgU | ||
| Revenue | 2,120 to 2,270 million | 1,730 to 1,820 million | 390-420 million | ||
| Average realized price | — | 58.90/lb | — | ||
| Average unit cost of sales (including D&A) | — | 46.00-47.00/lb | 23.50-24.50/kgU | ||
| Direct administration costs | 160-170 million | — | — | ||
| Exploration costs | — | 18 million | — | ||
| Capital expenditures | 150-175 million | — | — |
All values are in US Dollars.
| ^1^ | Uranium average unit cost of sales is calculated as the cash and<br>non-cash costs of the product sold, royalties, care and maintenance and selling costs, divided by the volume of uranium concentrates sold. |
|---|---|
| ^2^ | Fuel services average unit cost of sales is calculated as the cash and<br>non-cash costs of the product sold, transportation and weighing and sampling costs, as well as care and maintenance costs, divided by the volume of products sold. |
| --- | --- |
We do not provide an outlook for the items in the table that are marked with a dash.
The following assumptions were used to prepare the outlook in the table above:
| • | Production – we achieve 20.3 million pounds of production (our share) in our uranium segment. If we do<br>not achieve 20.3 million pounds, the outlook for the uranium segment could vary. |
|---|
48 CAMECO CORPORATION
| • | Purchases – are based on the volumes we currently have commitments to acquire under contract in 2023,<br>including our JV Inkai purchases, and it includes additional volumes we are required to purchase in order to meet the sales/delivery commitments we have under contract in 2023 and maintain a working inventory. It does not include any purchases that<br>we may make as a result of the impact of any delays or disruptions to production for any reason, including disruptions caused by supply chain or transportation issues, or other challenges. |
|---|---|
| • | Our 2023 outlook for sales/delivery volume does not include sales between our uranium and fuel services segments.<br> |
| --- | --- |
| • | Sales/delivery volume is based on the volumes we currently have commitments to deliver under contract in 2023.<br> |
| --- | --- |
| • | Uranium revenue and average realized price are based on a uranium spot price of $47.75 (US) per pound (the UxC<br>spot price on December 26, 2022), a long-term price indicator of $51.00 (US) per pound (the UxC long-term indicator on December 26, 2022) and an exchange rate of $1.00 (US) for $1.30 (Cdn) |
| --- | --- |
| • | Uranium average unit cost of sales (including D&A) is based on the expected unit cost of sales for produced<br>material, the planned purchases noted in the outlook at an anticipated average purchase price of about $56.20 (Cdn) per pound and includes care and maintenance costs of between $50 million and $60 million. We expect overall unit cost of<br>sales could vary if there are changes in production and purchase volumes or the mix between spot and long-term purchases, uranium spot prices, and/or care and maintenance costs in 2023. |
| --- | --- |
Our 2023 financial outlook is presented on the basis of equity accounting for our minority ownership interest in JV Inkai. Under equity accounting, our share of the profits earned by JV Inkai on the sale of its production will be included in “income from equity-accounted investees” on our consolidated statement of earnings. Our share of production will be purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures. Please see Inkai Planning for the future on pages 79 and 80 for more details.
The following table shows how changes in the exchange rate or uranium prices can impact our outlook. We currently are holding excess USD, largely from the proceeds of the October 2022 share issuance, to partially finance the proposed acquisition of Westinghouse, as such our adjusted net earnings will have a higher sensitivity to exchange rate movements. For more details on the impact of exchange rates, also see Foreign exchange on page 46.
| FOR 2023 ($ MILLIONS) | CHANGE | ANE | CASH FLOW | ||||||
| Uranium spot and long-term<br>price^1^ | 5(US)/lb increase | 63 | 41 | 8 | |||||
| 5(US)/lb decrease | (77 | ) | (51 | ) | (21 | ) | |||
| Value of Canadian dollar vs US dollar | One cent decrease in CAD | 15 | 14 | 7 | |||||
| One cent increase in CAD | (15 | ) | (14 | ) | (7 | ) |
All values are in US Dollars.
| ^1^ | Assuming change both UxC spot price $47.75 (US) per pound on December 26, 2022 and the UxC long-term price<br>indicator $51.00 (US) per pound on December 26, 2022. |
|---|
Price sensitivity analysis: uranium segment
As discussed under the Long-term contracting section on page 26, our portfolio of long-term contracts includes a mix of base-escalated and market-related contracts. Each contract is bilaterally negotiated with the customer and is subject to terms of confidentiality. Therefore, to help understand how the pricing under our current portfolio of commitments is expected to react at various spot prices at December 31, 2022, we have constructed the table below.
The table is based on the pricing terms under the long-term commitments in our contract portfolio that have been finalized as at December 31, 2022, it does not include the contracts that have been accepted but are still subject to contract finalization. Based on the terms and volumes under those commitments, the table is designed to indicate how our average realized price will react under various spot price assumptions at a point in time. At year-end, the annual average sales commitments under our contract portfolio at December 31, 2022 are 21 million pounds per year, with commitment levels in 2023 through 2025 higher than the average and in 2026 and 2027 lower than the average. As the market improves, we expect to continue to layer in volumes capturing greater upside using market-related pricing mechanisms. In this table, we do not consider the impact on our average realized price of volumes under negotiation and those not yet finalized under contract. In other words, the prices shown in the table would only be realized if the contract portfolio remained exactly as it was on December 31, 2022, using the following assumptions:
| • | The uranium price remains fixed at a given spot level for each annual period shown |
|---|
MANAGEMENT’S DISCUSSION AND ANALYSIS 49
| • | Deliveries based on commitments under finalized contracts include best estimates of the expected deliveries under<br>contract terms |
|---|---|
| • | To reflect escalation mechanisms contained in existing contracts, the long-term US inflation rate of 2% is used,<br>for modeling purposes only |
| --- | --- |
It is important to note, that the 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. We intend to update this table each quarter in our MD&A to reflect deliveries made and 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 at December 31, 2022
| (rounded to the nearest 1.00) | ||||||
|---|---|---|---|---|---|---|
| SPOT PRICES | ||||||
| (US/lb U3O8) | 40 | 60 | 80 | 100 | 120 | 140 |
| 2023 | ||||||
| 2024 | ||||||
| 2025 | ||||||
| 2026 | ||||||
| 2027 |
All values are in US Dollars.
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 in order to execute our strategy and to allow us to self-manage risk. 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. In addition, due to the deliberate cost reduction measures we have implemented, we have continued to have positive cash from operations which has added to our cash balance. And with the proceeds from the October share issuance, which are expected to help finance the proposed acquisition of Westinghouse, we have significant cash balances.
As announced on October 11, 2022, we have entered into a strategic partnership with Brookfield Renewable and its institutional partners to acquire Westinghouse. Permanent financing is expected to be a mix of capital sources (cash, debt and equity), designed to preserve the company’s balance sheet and ratings strength while maintaining our liquidity. Closing is anticipated in the second half of 2023. Please see Proposed acquisition of Westinghouse starting on page 89 for further details.
Following the announcement, we undertook a $650 million (US) bought deal offering of common shares, with an underwriter option to purchase additional shares. The offering closed on October 17, 2022 with gross proceeds to us of approximately $747.6 million (US), including the exercise in full of the underwriters’ option to purchase additional common shares. Concurrently with the execution of the acquisition agreement, we secured commitments for a $1 billion (US) bridge loan facility and $600 million (US) in term loans. As of the closing of the bought deal offering, the bridge loan facility was reduced to $280 million (US) by the net proceeds received from the offering. The facilities will remain undrawn until closing of the acquisition. The bridge facility, if funded, will mature 364 days after the acquisition closing date, and the term loans consisting of two tranches $300 million (US) each, are expected to mature two years and three years after the acquisition closing.
At the end of 2022, we had cash and cash equivalents and short-term investments of $2.3 billion, while our total debt amounted to $997 million. Our cash balances are expected to be largely utilized for the close of the proposed acquisition of Westinghouse. Depending on the timing of the close, expected in the second half of 2023, cash balances could be lower or higher than expected.
50 CAMECO CORPORATION
We have large, creditworthy customers that continue to need our nuclear fuel products and services even during weak economic conditions, and we expect the contract portfolio we have built to continue to provide a solid revenue stream. In our uranium segment, from 2023 through 2027, we have commitments to deliver an average of 21 million pounds per year, with commitment levels in 2023 through 2025 higher than the average and in 2026 and 2027 lower than the average.
We expect increased production at McArthur River/Key Lake will be positive for cash flow. It will allow us to source more of our committed sales from lower-cost produced pounds and we will no longer be required to expense operational readiness costs directly to cost of sales. However, cash flow from operations for 2023 will be dependent on the timing and volume of production and the timing and magnitude of our purchasing activity.
We expect our cash balances and operating cash flows to meet our capital requirements during 2023. Depending on the timing of the close of the Westinghouse transaction, and the final financing mix of capital sources, cash balances could be lower or higher than expected.
With the Supreme Court’s dismissal of CRA’s application for leave, the dispute of the 2003 through 2006 tax years are fully and finally resolved in our favour. Furthermore, we are confident the courts would reject any attempt by CRA to utilize the same or similar positions and arguments for the other tax years currently in dispute (2007 through 2014) and believe CRA should return the $778 million in cash and letters of credit we have been required to pay or otherwise secure. As such, we have filed notice of appeal to the Tax Court however, timing of any further payments is uncertain. See page 44 for more information.
Financial condition
| 2021 | |||||
|---|---|---|---|---|---|
| Cash position ( millions) | |||||
| (cash and cash equivalents and short-term investments) | 2,282 | **** | 1332 | ||
| Cash provided by operations ( millions) | |||||
| (net cash flow generated by our operating activities after changes in working capital) | 305 | **** | 458 | ||
| Cash provided by operations/net<br>debt1 | |||||
| (net debt is total consolidated debt, less cash position) | -24 | % | -136 | % | |
| Net debt/total<br>capitalization1 | |||||
| (total capitalization is net debt and equity) | -28 | % | -7 | % |
All values are in US Dollars.
| ^1^ | As at December 31, 2022, Cameco was negative net debt due to our large cash position.<br> |
|---|
Credit ratings
The credit ratings assigned by external ratings agencies are important as they impact our ability to raise capital at competitive pricing to support our business operations and execute our strategy.
Third-party ratings for our commercial paper and senior debt as of February 8, 2023:
| SECURITY | DBRS | S&P | ||||
|---|---|---|---|---|---|---|
| Commercial paper | R-2 (middle) | A-3 | ||||
| Senior unsecured debentures | BBB | BBB- | ||||
| Rating trend / rating outlook | Stable | ^1^ | Stable | ^2^ | ||
| ^1^ | On May 28, 2020, DBRS changed Cameco’s rating trend to stable. On May 26, 2021 and May 27,<br>2022, DBRS confirmed the rating and outlook. Currently our rating is under review following the announcement of the proposed acquisition of Westinghouse | |||||
| --- | --- | |||||
| ^2^ | On February 16, 2022, S&P revised Cameco’s rating outlook to stable and affirmed the rating.<br> | |||||
| --- | --- |
The rating agencies may revise or withdraw these ratings if they believe circumstances warrant. The rating trend/outlook represents the rating agency’s assessment of the likelihood and direction that the rating could change in the future.
A change in our credit ratings could affect our cost of funding and our access to capital through the capital markets.
MANAGEMENT’S DISCUSSION AND ANALYSIS 51
Liquidity
| ($ MILLIONS) | 2022 | 2021 | ||||
|---|---|---|---|---|---|---|
| Cash and cash equivalents and short-term investments at beginning of year | **** | 1,332 | **** | 943 | ||
| Cash from operations | **** | 305 | **** | 458 | ||
| Investment activities | ||||||
| Additions to property, plant and equipment and acquisitions | **** | (245 | ) | (99 | ) | |
| Other investing activities | **** | 8 | **** | 79 | ||
| Financing activities | ||||||
| Interest paid | **** | (39 | ) | (39 | ) | |
| Issue of shares | **** | 963 | **** | 27 | ||
| Dividends | **** | (52 | ) | (32 | ) | |
| Other financing activities | **** | (3 | ) | (3 | ) | |
| Exchange rate on changes on foreign currency cash balances | **** | 13 | **** | (2 | ) | |
| Cash and cash equivalents and short-term investments at end of year | **** | 2,282 | **** | 1,332 |
CASH FROM OPERATIONS
Cash from operations was lower than in 2021 due largely to an increase in working capital requirements which was the result of increased purchasing activity. Purchases in 2022 were 18.3 million pounds compared to 11.1 million pounds in 2021. Not including working capital requirements, our operating cash flows in the year were up $253 million. See note 24 to the financial statements.
INVESTING ACTIVITIES
Cash used in investing includes acquisitions and capital spending.
Capital spending
We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development. We have a capital allocation process to approve our capital spend. See Capital Allocation beginning on page 30 for more information.
| CAMECO’S SHARE ($ MILLIONS) | 2022 ACTUAL | 2023 PLAN | ||
|---|---|---|---|---|
| Sustaining capital | ||||
| Uranium | 62 | **** | 55-60 | |
| Fuel services | 39 | **** | 40-45 | |
| Other | 2 | **** | 5-10 | |
| Total sustaining capital | 103 | **** | 100-115 | |
| Capacity replacement capital | ||||
| Uranium | 40 | **** | 40-50 | |
| Fuel services | — | **** | — | |
| Total capacity replacement capital | **** | 40 | **** | 40-50 |
| Growth capital | ||||
| Uranium | — | **** | 0-5 | |
| Fuel services | — | **** | 5-10 | |
| Total growth capital | **** | — | **** | 5-15 |
| Total sustaining, capital and growth | **** | 143 | **** | 150-175 |
52 CAMECO CORPORATION
Outlook for investing activities
| CAMECO’S SHARE ($ MILLIONS) | 2023 PLAN | 2024 PLAN | 2025 PLAN | |||
|---|---|---|---|---|---|---|
| Total uranium & fuel services | **** | 150-175 | **** | 150-200 | **** | 100-150 |
| Sustaining capital | 105-115 | 120-140 | 70-90 | |||
| Capacity replacement capital | 40-50 | 25-45 | 25-45 | |||
| Growth capital | 5-10 | 5-15 | 5-15 |
Our 2023, 2024 and 2025 capital spending estimates assume that in 2024, we begin producing 18 million pounds (100% basis) per year at McArthur River/Key Lake, continue producing 18 million pounds (100% basis) per year at Cigar Lake, and increase annual production at our UF6 conversion facility to 12,000 tonnes per year.
Our estimate for capital spending in 2023 has been increased to between $150 million and $175 million (previously between $100 million and $150 million) due to the capital required to meet production targets and the rescheduling of some expenditures planned in 2022 to 2023.
Capital expenditures for JV Inkai are expected to be covered by JV Inkai cash flows in 2023 and are included in our overall equity investment.
Major capital expenditures in 2023 include:
| • | Fuel services – capital required to increase production at our UF6 conversion facility and continued work on our Vision in Motion project |
|---|---|
| • | Cigar Lake – underground development and necessary ground freezing infrastructure to meet production targets<br> |
| --- | --- |
| • | McArthur River/Key Lake – capital required to produce 18 million pounds per year (100% basis) starting<br>in 2024 |
| --- | --- |
| • | Our investment in digital and automation technologies |
| --- | --- |
This information regarding currently expected capital expenditures for future periods is forward-looking information and is based upon the assumptions and subject to the material risks discussed on pages 4 to 6. Our actual capital expenditures for future periods may be significantly different.
FINANCINGACTIVITIES
Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance.
Long-term contractual obligations
| 2024 AND | 2026 AND | 2028 AND | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| DECEMBER 31 ($ MILLIONS) | 2023 | 2025 | 2027 | BEYOND | TOTAL | |||||
| Long-term debt | — | 500 | 400 | 100 | 1,000 | |||||
| Interest on long-term debt | 38 | 44 | 34 | 76 | 192 | |||||
| Provision for reclamation | 47 | 69 | 95 | 1,145 | 1,356 | |||||
| Provision for waste disposal | 2 | 4 | 3 | — | 9 | |||||
| Other liabilities | 29 | 36 | 6 | 64 | 135 | |||||
| Capital commitments | 57 | — | — | — | 57 | |||||
| Total | **** | 173 | **** | 653 | **** | 538 | **** | 1,385 | **** | 2,749 |
We have contractual capital commitments of approximately $57 million at December 31, 2022. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfil the contracts.
We have sufficient borrowing capacity with available unsecured lines of credit totalling about $2.7 billion, which include the following:
| • | A $1.0 billion unsecured revolving credit facility that matures October 1, 2026. Each calendar year,<br>upon mutual agreement, the facility can be extended for an additional year. We may increase the revolving credit facility above $1.0 billion, by increments of no less than $50 million, up to a total of $1.25 billion. The facility<br>ranks equally with all of our other senior debt. At December 31, 2022, there were no amounts outstanding under this facility. |
|---|
MANAGEMENT’S DISCUSSION AND ANALYSIS 53
| • | At December 31, 2022, we had approximately $1.6 billion outstanding in financial assurances provided by<br>various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, for our obligations relating to the CRA dispute, and as overdraft protection.<br> |
|---|
In total we have $1.0 billion in senior unsecured debentures outstanding:
| • | $500 million bearing interest at 4.19% per year, maturing on June 24, 2024 |
|---|---|
| • | $400 million bearing interest at 2.95% per year, maturing on October 21, 2027 |
| --- | --- |
| • | $100 million bearing interest at 5.09% per year, maturing on November 14, 2042 |
| --- | --- |
We have secured $600 million (US) in term loan facilities and $280 million (US) under a bridge loan facility to help finance the proposed acquisition of Westinghouse. The debt facilities will remain undrawn until closing of the acquisition. The bridge facility, if funded, will mature 364 days after the acquisition closing date, and the term loans consisting of two tranches of $300 million (US) each, are expected to mature two years and three years after the acquisition closes. Please see Proposed acquisition of Westinghouse on page 89 for more information. These facilities have not been included in the long-term contractual obligation table due to the uncertainty around timing of the close of the acquisition and how much will be funded under these facilities when it closes.
Debt covenants
Our revolving credit facility includes the following financial covenants:
| • | our funded debt to tangible net worth ratio must be 1:1 or less |
|---|---|
| • | other customary covenants and events of default |
| --- | --- |
Funded debt is total consolidated debt less non-recourse debt, $100 million in letters of credit, cash and cash equivalents and short-term investments.
Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2022, we complied with all covenants, and we expect to continue to comply in 2023.
OFF-BALANCE SHEET ARRANGEMENTS
We had three kinds of off-balance sheet arrangements at the end of 2022:
| • | purchase commitments |
|---|---|
| • | financial assurances |
| --- | --- |
| • | other arrangements |
| --- | --- |
Purchase commitments
We make purchases under long-term contracts where it is beneficial for us to do so and to support our long-term contract portfolio. The following table is based on our purchase commitments in our uranium and fuel services segments at December 31, 2022^2^ but does not include purchases of our share of Inkai production. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.
| 2024 AND | 2026 AND | 2028<br>AND | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| DECEMBER 31, 2022 ($ MILLIONS) | 2023 | 2025 | 2027 | BEYOND | TOTAL | |||||
| Purchase commitments^1,2^ | 232 | 98 | 154 | 17 | 501 | |||||
| ^1^ | Denominated in US dollars and Japanese yen, converted from US dollars to Canadian dollars at the rate of 1.30<br>and from Japanese yen to Canadian dollars at the rate of $0.01. | |||||||||
| --- | --- | |||||||||
| ^2^ | These amounts have been adjusted for any additional purchase commitments that we have entered into since<br>December 31, 2022 but does not include deliveries taken under contract since December 31, 2022. | |||||||||
| --- | --- |
We have commitments of $501 million (Cdn) for the following:
| • | approximately 9.2 million pounds of U3O8 equivalent from 2023 to 2028 |
|---|---|
| • | approximately 0.4 million kgU as UF6 in conversion<br>services from 2023 to 2024 |
| --- | --- |
54 CAMECO CORPORATION
| • | about 0.6 million Separative Work Units (SWU) of enrichment services to meet existing forward sales<br>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
We use standby letters of credit and surety bonds mainly to provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities
Once we have permanently stopped mining and processing activities at an operating site, we are required to decommission the site to the satisfaction of the regulators. We have developed preliminary decommissioning plans for our operating sites and use them to estimate our decommissioning costs. Regulators review and accept our preliminary decommissioning plans on a regular basis. As the site approaches or goes into decommissioning, regulators review the detailed decommissioning plans. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.
We have submitted updates to all Saskatchewan operations’ Preliminary Decommissioning Plan (PDP) and Preliminary Decommissioning Cost Estimate (PDCE) documents in accordance with the five-year timeline specified in the regulations. Upon acceptance of the PDP and PDCE documents by the Saskatchewan Ministry of Environment and Canadian Nuclear Safety Commission (CNSC) staff, a formal Commission proceeding will be required for final approval of the PDP and PDCE by the Commission. All Saskatchewan mining operations have received the necessary approvals for the current PDP and PDCE and all required financial assurances are in place.
The PDP and PDCE for the Blind River refinery were revised in 2020. The CNSC approved the PDCE in February 2022 and the financial assurance was updated in March 2022. The Cameco Fuel Manufacturing PDP and PDCE were revised in 2021, and the revised PDCE was approved by the Commission in February 2022 and the financial assurance was updated in March 2022. The PDP and PDCE for the Port Hope conversion facility were revised in 2022 and submitted to CNSC staff in September 2022 and are currently under review by CNSC staff. Once accepted by staff, the PDCE will be considered by the Commission, after which the financial assurance will be updated.
For Smith Ranch-Highland, the 2022 surety was approved and the credit instruments are being reviewed by the State of Wyoming. For Crow Butte, the 2022 annual update was submitted to the federal Nuclear Regulatory Commission and Nebraska Department of Environmental Quality in September 2022. This most recent surety has been approved by the state and is still waiting for approval from the NRC.
At the end of 2022, our estimate of total decommissioning and reclamation costs was $1.36 billion. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $1.06 billion at the end of 2022 (the present value of the $1.36 billion). Regulatory approval is required prior to beginning decommissioning. Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, and none of our assets have approval for decommissioning, our expected costs for decommissioning and reclamation for the next five years are not material.
We had a total of about $1.04 billion in financial assurances supporting our reclamation liabilities at the end of 2022. All of our North American operations have financial assurances in place in connection with our preliminary plans for decommissioning of the sites.
We are also providing letters of credit until the CRA dispute is resolved.
Our financial assurances renew automatically on an annual basis, unless otherwise advised by the issuing institution. At December 31, 2022 our financial assurances totaled $1.6 billion, the same as at December 31, 2021.
Other arrangements
We have arranged for standby product loan facilities with various counterparties. The arrangements allow us to borrow up to 2.4 million kgU of UF6 conversion services and 2.8 million pounds of U3O8 over the period 2020 to 2026 with repayment in kind up to December 31, 2026. Under the loan facilities, standby fees of up to 1% are payable based on the market value of the facilities and interest is payable on the market value of any amounts drawn at rates ranging from 0.5% to 2.0%. At December 31, 2022, we have 1.0 million kgU of UF6 conversion services and 630,000 pounds of U3O8 drawn on the loans.
MANAGEMENT’S DISCUSSION AND ANALYSIS 55
BALANCE SHEET
| DECEMBER 31, | CHANGE | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) | 2022 | 2021 | 2020 | 2021 TO 2022 | |||||
| Inventory | **** | 665 | 410 | 680 | 62 | % | |||
| Total assets | **** | 8,633 | 7,518 | 7,581 | 15 | % | |||
| Total non-current liabilities | **** | 2,236 | 2,258 | 2,318 | (1 | )% | |||
| Dividends per common share | **** | 0.12 | 0.08 | 0.08 | 50 | % |
Total product inventories increased by 62% to $665 million this year as production and purchases were higher than sales during the year. At December 31, 2022, our average cost for uranium was $43.45 per pound, up from $38.30 per pound at December 31, 2021. As of December 31, 2022, we held an inventory of 12 million pounds of U3O8 equivalent (excluding broken ore).
At the end of 2022, our total assets amounted to $8.6 billion, an increase of 15% compared to 2021, due mainly to an increase in investment balances resulting from the October 2022 issuance of common shares in preparation for the closing of the Westinghouse transaction as well as higher inventories. In 2021, the total asset balance decreased by $0.1 billion compared to 2020, due mainly to lower inventories which was largely offset by an increase in cash and investment balances.
56 CAMECO CORPORATION
2022 financial results by segment
Uranium
| HIGHLIGHTS | 2022 | 2021 | CHANGE | ||||||
|---|---|---|---|---|---|---|---|---|---|
| Production volume (million lbs) | **** | 10.4 | 6.1 | 70 | % | ||||
| Sales volume (million lbs) | **** | 25.6 | 24.3 | 5 | % | ||||
| Average spot price | ) | **** | 49.81 | 35.28 | 41 | % | |||
| Average long-term price | ) | **** | 49.75 | 36.81 | 35 | % | |||
| Average realized price | ) | **** | 44.73 | 34.53 | 30 | % | |||
| ) | **** | 57.85 | 43.34 | 33 | % | ||||
| Average unit cost of sales (including D&A) | ) | **** | 53.13 | 47.80 | 11 | % | |||
| Revenue ( millions) | **** | 1,480 | 1,055 | 40 | % | ||||
| Gross profit (loss) ( millions) | **** | 121 | (108 | ) | >100 | % | |||
| Gross profit (loss) (%) | **** | 8 | (10 | ) | >100 | % |
All values are in US Dollars.
Production volumes in 2022 increased by 70% compared to 2021. See Uranium – production overview on page 69 for more information.
Uranium revenues this year were up 40% compared to 2021 due to an increase in sales volumes of 5% and an increase of 33% in the Canadian dollar average realized price due to an increase in the spot price. While the spot price for uranium averaged $49.81 (US) per pound in 2022, an increase of 41% compared to the 2021 average of $35.28 (US) per pound, the US dollar average realized price only increased by 30% due to the impact of fixed price contracts on the portfolio.
Total cost of sales (including D&A) increased by 17% ($1.36 billion compared to $1.16 billion in 2021) due to an increase in sales volume of 5% and an 11% increase in unit cost of sales. Unit cost of sales is higher than in the same period in 2021 due to the higher cost of purchased material and the higher operational readiness costs at McArthur River/Key Lake operations. This was offset by the impact of care and maintenance costs at Cigar Lake in 2021 due to the temporary suspension of operations due to COVID-19.
The net effect was a $229 million increase in gross profit for the year.
The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures, see below). These costs do not include care and maintenance costs, operational readiness costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
| ($CDN/LB) | 2022 | 2021 | CHANGE | ||||
|---|---|---|---|---|---|---|---|
| Produced | |||||||
| Cash cost | **** | 19.24 | 16.00 | 20 | % | ||
| Non-cash cost | **** | 15.72 | 17.17 | (8 | )% | ||
| Total production cost ^1^ | **** | 34.96 | 33.17 | 5 | % | ||
| Quantity produced (million lbs)^1^ | **** | 10.4 | 6.1 | 70 | % | ||
| Purchased | |||||||
| Cash cost^1^ | **** | 51.36 | 42.30 | 21 | % | ||
| Quantity purchased (million lbs)^1^ | **** | 18.3 | 11.1 | 65 | % | ||
| Totals | |||||||
| Produced and purchased costs | **** | 45.42 | 39.06 | 16 | % | ||
| Quantities produced and purchased (million lbs) | **** | 28.7 | 17.2 | 67 | % | ||
| ^1^ | Due to equity accounting for JV Inkai, our share of production is shown as a purchase at the time of delivery.<br>JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. In 2022 we purchased 3.3 million pounds at a purchase price per pound of $62.78 ($47.33 (US)) (2021 – 5.2 million pounds at a<br>purchase price per pound of $45.31 ($36.03 (US))). | ||||||
| --- | --- |
MANAGEMENT’S DISCUSSION AND ANALYSIS 57
The average cash cost of production was 20% higher compared to 2021. Cash cost was higher due to inflationary pressures, labour shortages and supply chain challenges. In addition, with the restart of McArthur River/Key Lake operations the cash cost of production will reflect a combined cost of all our operating uranium assets going forward.
In 2023, with McArthur River/Key Lake ramping up production, and the impact of inflationary pressures, the availability of personnel with the necessary skills and experience, and supply chain challenges on the availability of materials and reagents, our average annual unit cash cost of production is expected to be higher than the average unit life of mine operating costs reflected in our most recent annual information form: approximately $16 per pound at McArthur River/Key Lake; approximately $18 per pound at Cigar Lake.
We also expect the Inkai unit cash cost of production in 2023 to be higher than the average unit life of mine operating costs reflected in our most recent annual information form (between $8 and $9 per pound) due to the current supply chain challenges and inflationary pressures experienced in Kazakhstan. The benefit of the estimated life-of-mine operating cost for JV Inkai’s production is expected to be reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investee”. The current geopolitical and economic uncertainty could continue to impact JV Inkai’s operating costs.
Our purchases in 2022, totaled about $940 million, representing an average annual cost of $51.36 per pound, about $16.00 per pound higher than our total unit production cost for the year. Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. The average cost of purchased material in Canadian dollar terms increased by 21% this year compared to 2021. The average cash cost of purchased material was $51.36 (Cdn), or $39.45 (US) per pound, compared to $42.30 (Cdn), or $33.73 (US) per pound in the same period in 2021.
Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.
These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.
To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the years ended 2022 and 2021 as reported in our financial statements.
58 CAMECO CORPORATION
CASH AND TOTAL COST PER POUND RECONCILIATION
| ($ MILLIONS) | 2022 | 2021 | ||||
|---|---|---|---|---|---|---|
| Cost of product sold | **** | 1,223.6 | **** | 1,028.8 | ||
| Add / (subtract) | ||||||
| Royalties | **** | (23.4 | ) | (15.2 | ) | |
| Other selling costs | **** | (5.9 | ) | (4.6 | ) | |
| Care and maintenance and operational readiness costs | **** | (178.5 | ) | (156.7 | ) | |
| Change in inventories | **** | 124.2 | **** | (285.2 | ) | |
| Cash operating costs (a) | **** | 1,140.0 | **** | 567.1 | ||
| Add / (subtract) | ||||||
| Depreciation and amortization | **** | 135.8 | **** | 134.6 | ||
| Care and maintenance and operational readiness costs | **** | (39.9 | ) | (52.9 | ) | |
| Change in inventories | **** | 67.6 | **** | 23.0 | ||
| Total operating costs (b) | **** | 1,303.5 | **** | 671.8 | ||
| Uranium produced & purchased (million lbs) (c) | **** | 28.7 | **** | 17.2 | ||
| Cash costs per pound (a ÷ c) | **** | 39.72 | **** | 32.97 | ||
| Total costs per pound (b ÷ c) | **** | 45.42 | **** | 39.06 |
ROYALTIES
We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:
| • | Basic royalty: calculated as 5% of gross sales of uranium, less the Saskatchewan resource credit of 0.75%.<br> |
|---|---|
| • | Profit royalty: a 10% royalty is charged on profit up to and including $26.268/kg U3O8 ($11.91/lb) and a 15% royalty is charged on profit in excess of $26.268/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.<br> |
| --- | --- |
As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.
Fuel services
| (includes results for UF6, UO2, UO3 and fuel fabrication)<br>HIGHLIGHTS | 2022 | 2021 | CHANGE | ||||||
|---|---|---|---|---|---|---|---|---|---|
| Production volume (million kgU) | **** | 13.0 | 12.1 | 7 | % | ||||
| Sales volume (million kgU) | **** | 11.1 | 13.6 | (18 | )% | ||||
| Average realized price | Cdn/kgU | ) | **** | 32.92 | 29.72 | 11 | % | ||
| Average unit cost of sales (including D&A) | Cdn/kgU | ) | **** | 22.39 | 21.02 | 7 | % | ||
| Revenue ( millions) | **** | 365 | 404 | (10 | )% | ||||
| Gross profit ( millions) | **** | 117 | 118 | (1 | )% | ||||
| Gross profit (%) | **** | 32 | 29 | 10 | % |
All values are in US Dollars.
Total revenue decreased by 10% from 2021 due to an 18% decrease in sales volume partially offset by an 11% increase in the realized price. The increase in realized price was mainly the result of increased prices due to market conditions.
Total cost of products and services sold (including D&A) decreased 13% ($248 million compared to $286 million in 2021), due to the 18% decrease in sales volume partially offset by a 7% increase in average unit cost of sales compared to 2021 due to higher input costs.
The net effect was a $1 million decrease in gross profit.
MANAGEMENT’S DISCUSSION AND ANALYSIS 59
Fourth quarter financial results
Consolidated results
| HIGHLIGHTS | |||||||
| ( MILLIONS EXCEPT WHERE INDICATED) | 2021 | CHANGE | |||||
| Revenue | 524 | **** | 465 | 13 | % | ||
| Gross profit | 65 | **** | 56 | 16 | % | ||
| Net earnings (loss) attributable to equity holders | (15 | ) | 11 | >100 | % | ||
| per common share (basic) | (0.04 | ) | 0.03 | >100 | % | ||
| per common share (diluted) | (0.04 | ) | 0.03 | >100 | % | ||
| Adjusted net earnings (non-IFRS, see page 40) | 36 | **** | 23 | 57 | % | ||
| per common share (adjusted and diluted) | 0.09 | **** | 0.06 | 50 | % | ||
| Cash provided by operations | 77 | **** | 59 | 31 | % |
All values are in US Dollars.
NET EARNINGS
The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 40) in the fourth quarter of 2022 compared to the same period in 2021.
| ( MILLIONS) | Adjusted | ||||
|---|---|---|---|---|---|
| Net earnings - 2021 | 11 | **** | **** | 23 | **** |
| Change in gross profit by segment | |||||
| (we calculate gross profit by deducting from revenue the cost of products and<br>services sold, and depreciation and amortization (D&A), net of hedging benefits) | |||||
| Uranium | 1 | 1 | |||
| 29 | 29 | ||||
| 25 | 25 | ||||
| (41 | ) | (41 | ) | ||
| 14 | 14 | ||||
| Fuel services | (10 | ) | (10 | ) | |
| 4 | 4 | ||||
| 1 | 1 | ||||
| (5 | ) | (5 | ) | ||
| Other changes | |||||
| Lower administration expenditures | 8 | 8 | |||
| Change in reclamation provisions | (78 | ) | — | ||
| Change in gains or losses on derivatives | 12 | (12 | ) | ||
| Change in foreign exchange gains or losses | 6 | 6 | |||
| Change in earnings from equity-accounted investments | (19 | ) | (19 | ) | |
| Higher finance income | 21 | 21 | |||
| Change in income tax recovery or expense | 13 | (2 | ) | ||
| Other | 2 | 2 | |||
| Net earnings (losses) - 2022 | (15 | ) | **** | 36 | **** |
All values are in US Dollars.
ADJUSTED NET EARNINGS
We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 40 for more information. The following table reconciles adjusted net earnings with our net earnings.
60 CAMECO CORPORATION
| THREE MONTHS ENDED | ||||||
|---|---|---|---|---|---|---|
| DECEMBER 31 | ||||||
| ($ MILLIONS) | 2022 | 2021 | ||||
| Net earnings (loss) attributable to equity holders | **** | (15 | ) | 11 | ||
| Adjustments | ||||||
| Adjustments on derivatives | **** | (19 | ) | 5 | ||
| Adjustments on other operating expense (income) | **** | 88 | **** | 10 | ||
| Income taxes on adjustments | **** | (18 | ) | (3 | ) | |
| Adjusted net earnings | **** | 36 | **** | 23 |
ADMINISTRATION
| THREE MONTHS ENDED | ||||||||
|---|---|---|---|---|---|---|---|---|
| DECEMBER 31 | ||||||||
| ($ MILLIONS) | 2022 | 2021 | CHANGE | |||||
| Direct administration | **** | 37 | **** | 28 | 32 | % | ||
| Stock-based compensation | **** | (8 | ) | 9 | (189 | )% | ||
| Total administration | **** | 29 | **** | 37 | (22 | )% |
Direct administration costs were $37 million in the quarter, $9 million higher than the same period last year. Stock-based compensation expenses were $17 million lower from the fourth quarter of 2021 because of a large decrease in share price in the current quarter compared to a very small increase in the same period last year. In addition, the impact of the share price changes was offset by a change in assumptions for vesting criteria related to the executive performance share units. In the current quarter this was a recovery while in 2021 it was an expense.
Quarterly trends
| HIGHLIGHTS | 2021 | |||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ( MILLIONS EXCEPT PER SHARE AMOUNTS) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||
| Revenue | 524 | **** | 389 | 558 | 398 | **** | 465 | 361 | 359 | 290 | ||||||||||
| Net earnings (loss) attributable to equity holders | (15 | ) | (20 | ) | 84 | 40 | **** | 11 | (72 | ) | (37 | ) | (5 | ) | ||||||
| per common share (basic) | (0.04 | ) | (0.05 | ) | 0.21 | 0.10 | **** | 0.03 | (0.18 | ) | (0.09 | ) | (0.01 | ) | ||||||
| per common share (diluted) | (0.04 | ) | (0.05 | ) | 0.21 | 0.10 | **** | 0.03 | (0.18 | ) | (0.09 | ) | (0.01 | ) | ||||||
| Adjusted net earnings (loss) (non-IFRS, see page<br>40) | 36 | **** | 10 | 72 | 17 | **** | 23 | (54 | ) | (38 | ) | (29 | ) | |||||||
| per common share (adjusted and diluted) | 0.09 | **** | 0.03 | 0.18 | 0.04 | **** | 0.06 | (0.14 | ) | (0.10 | ) | (0.07 | ) | |||||||
| Cash provided by (used in) operations (after working capital changes) | 77 | **** | (47 | ) | 102 | 172 | **** | 59 | 203 | 152 | 45 |
All values are in US Dollars.
Key things to note:
| • | The timing of customer requirements, which tends to vary from quarter to quarter, drives revenue in the uranium<br>and fuel services segments. |
|---|---|
| • | Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to<br>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 40 for more information). |
| --- | --- |
| • | Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our<br>uranium and fuel services segments. |
| --- | --- |
| • | Quarterly results are not necessarily a good indication of annual results due to the variability in customer<br>requirements noted above. |
| --- | --- |
MANAGEMENT’S DISCUSSION AND ANALYSIS 61
The table that follows presents the differences between net earnings and adjusted net earnings for the previous seven quarters.
| HIGHLIGHTS | 2022 | 2021 | ||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
| Net earnings (loss) attributable to equity holders | **** | (15 | ) | (20 | ) | 84 | 40 | **** | 11 | **** | (72 | ) | (37 | ) | (5 | ) | ||||||||
| Adjustments | ||||||||||||||||||||||||
| Adjustments on derivatives | **** | (19 | ) | 75 | 31 | (11 | ) | **** | 5 | **** | 26 | (9 | ) | (9 | ) | |||||||||
| Adjustments on other operating expense (income) | **** | 88 | **** | (24 | ) | (19 | ) | (19 | ) | **** | 10 | **** | (2 | ) | 6 | (22 | ) | |||||||
| Adjustment to other income | **** | — | **** | — | (23 | ) | — | **** | — | **** | — | — | — | |||||||||||
| Income taxes on adjustments | **** | (18 | ) | (21 | ) | (1 | ) | 7 | **** | (3 | ) | (6 | ) | 2 | 7 | |||||||||
| Adjusted net earnings (losses) (non-IFRS, see page40) | **** | 36 | **** | 10 | 72 | 17 | **** | 23 | **** | (54 | ) | (38 | ) | (29 | ) |
62 CAMECO CORPORATION
Fourth quarter financial results by segment
Uranium
| THREE MONTHS ENDED | ||||||||
|---|---|---|---|---|---|---|---|---|
| DECEMBER 31 | ||||||||
| HIGHLIGHTS | 2022 | 2021 | CHANGE | |||||
| Production volume (million lbs) | **** | 3.7 | 2.8 | 32 | % | |||
| Sales volume (million lbs) | **** | 6.9 | 6.5 | 6 | % | |||
| Average spot price | ) | **** | 49.94 | 44.33 | 13 | % | ||
| Average long-term price | ) | **** | 51.67 | 42.92 | 20 | % | ||
| Average realized price | ) | **** | 43.05 | 39.65 | 9 | % | ||
| ) | **** | 57.87 | 49.94 | 16 | % | |||
| Average unit cost of sales (including D&A) | ) | **** | 54.37 | 48.35 | 12 | % | ||
| Revenue ( millions) | **** | 397 | 323 | 23 | % | |||
| Gross profit ( millions) | **** | 24 | 10 | >100 | % | |||
| Gross profit (%) | **** | 6 | 3 | 100 | % |
All values are in US Dollars.
Production volumes this quarter increased by 32% compared to the fourth quarter of 2021. See Uranium – productionoverview on page 69 for more information.
Uranium revenues were up 23% due to a 6% increase in sales volume and a 16% increase in the Canadian dollar average realized price which was a result of an increase in the average spot price for uranium. While the average US dollar spot price for uranium increased by 13% compared to the same period in 2021, the US dollar average realized price only increased by 9% as a result of lower prices on fixed-price contracts. In addition, the Canadian dollar was weaker compared to the same period last year, $1.00 (US) for $1.34 (Cdn) compared to $1.00 (US) for $1.26 (Cdn) in the fourth quarter of 2021.
Total cost of sales (including D&A) increased by 19% ($373 million compared to $313 million in 2021). This was primarily the result of the 6% increase in sales volume as well as the increase of 12% in the average unit cost of sales which was due to the higher cost of purchased material.
The net effect was a $14 million increase in gross profit for the quarter.
The following table shows the costs of produced and purchased uranium incurred in the reporting periods. These costs do not include care and maintenance costs, operational readiness costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
| THREE MONTHS ENDED | |||||||
|---|---|---|---|---|---|---|---|
| DECEMBER 31 | |||||||
| ($/LB) | 2022 | 2021 | CHANGE | ||||
| Produced | |||||||
| Cash cost | **** | 19.50 | 13.67 | 43 | % | ||
| Non-cash cost | **** | 13.76 | 17.10 | (20 | )% | ||
| Total production cost ^1^ | **** | 33.26 | 30.77 | 8 | % | ||
| Quantity produced (million lbs)^1^ | **** | 3.7 | 2.8 | 32 | % | ||
| Purchased | |||||||
| Cash cost^1^ | **** | 57.02 | 52.73 | 8 | % | ||
| Quantity purchased (million lbs)^1^ | **** | 5.8 | 3.3 | 76 | % | ||
| Totals | |||||||
| Produced and purchased costs | **** | 47.77 | 42.65 | 12 | % | ||
| Quantities produced and purchased (million lbs) | **** | 9.5 | 6.1 | 56 | % | ||
| ^1^ | Due to equity accounting for JV Inkai, our share of production will be shown as a purchase at the time of<br>delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. During the quarter, we purchased 2.6 million pounds at a purchase price per pound of $61.27 ($45.60 (US)) (Q4 2021 –<br>2.2 million pounds at a purchase price per pound of $52.69 ($41.79 (US))). | ||||||
| --- | --- |
MANAGEMENT’S DISCUSSION AND ANALYSIS 63
The average cash cost of production for the fourth quarter was 47% higher compared to the same period in the prior year. Cash cost was higher due to the effect of supply chain challenges and inflationary pressures, as well as the decreased production rate for Cigar Lake compared to 2021. Effective May 19, our ownership stake and share of production from Cigar Lake stands at 54.547%, compared to 50.025% in 2021. In addition, the unit production costs for the fourth quarter of 2022 include production costs from McArthur River/Key Lake operations as they ramp up production.
Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the fourth quarter, the average cash cost of purchased material was $57.02 (Cdn) per pound, or $42.18 (US) per pound in US dollar terms, compared to $52.73 (Cdn) per pound, or $41.87 (US) per pound in the fourth quarter of 2021.
Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. See page 57 for more information.
To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2022 and 2021.
CASH AND TOTAL COST PER POUND RECONCILIATION
| THREE MONTHS ENDED | ||||||
|---|---|---|---|---|---|---|
| DECEMBER 31 | ||||||
| ($ MILLIONS) | 2022 | 2021 | ||||
| Cost of product sold | **** | 355.1 | **** | 278.9 | ||
| Add / (subtract) | ||||||
| Royalties | **** | (2.1 | ) | (5.0 | ) | |
| Other selling costs | **** | (2.0 | ) | (1.6 | ) | |
| Care and maintenance and operational readiness costs | **** | (35.5 | ) | (36.8 | ) | |
| Change in inventories | **** | 87.4 | **** | (23.2 | ) | |
| Cash operating costs (a) | **** | 402.9 | **** | 212.3 | ||
| Depreciation and amortization | **** | 18.2 | **** | 34.2 | ||
| Care and maintenance and operational readiness costs | **** | (7.5 | ) | (10.1 | ) | |
| Change in inventories | **** | 40.2 | **** | 23.8 | ||
| Total operating costs (b) | **** | 453.8 | **** | 260.2 | ||
| Uranium produced & purchased (million lbs) (c) | **** | 9.5 | **** | 6.1 | ||
| Cash costs per pound (a ÷ c) | **** | 42.41 | **** | 34.80 | ||
| Total costs per pound (b ÷ c) | **** | 47.77 | **** | 42.65 |
Fuel services
(includes results for UF6, UO2, UO3 and fuel fabrication)
| THREE MONTHS ENDED | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| DECEMBER 31 | |||||||||
| HIGHLIGHTS | 2022 | 2021 | CHANGE | ||||||
| Production volume (million kgU) | **** | 3.7 | 3.1 | 19 | % | ||||
| Sales volume (million kgU) | **** | 3.8 | 4.9 | (22 | )% | ||||
| Average realized price | Cdn/kgU | ) | **** | 30.11 | 28.80 | 5 | % | ||
| Average unit cost of sales (including D&A) | Cdn/kgU | ) | **** | 19.33 | 19.45 | (1 | )% | ||
| Revenue ( millions) | **** | 115 | 140 | (18 | )% | ||||
| Gross profit ( millions) | **** | 41 | 46 | (11 | )% | ||||
| Gross profit (%) | **** | 36 | 33 | 9 | % |
All values are in US Dollars.
Total revenue decreased by 18% due to a 22% decrease in sales volumes which was partially offset by a 5% increase in average realized price. The increase in average realized price was mainly the result of the mix of products sold, as well as contracts that were entered into in an improved price environment.
64 CAMECO CORPORATION
Total cost of sales (including D&A) decreased by 22% to $74 million compared to the fourth quarter of 2021 due to the 22% decrease in sales volumes and a decrease of 1% in the average unit cost of sales.
The net effect was a $5 million decrease in gross profit.
MANAGEMENT’S DISCUSSION AND ANALYSIS 65
Operations, projects and other fuel cycle investments
This section of our MD&A is an overview of the mining, milling and processing facilities we operate or have an interest in, our curtailed operations and our advanced uranium projects, what we accomplished this year, our plans for the future and how we manage risk. It also includes an overview of our other investments in the nuclear fuel cycle, and our approach to corporate development.
| 67 | MANAGING THE RISKS |
|---|---|
| 69 | URANIUM – PRODUCTION OVERVIEW |
| 69 | PRODUCTION OUTLOOK |
| 70 | URANIUM – TIER-ONE OPERATIONS |
| 70 | MCARTHUR RIVER MINE / KEY LAKE MILL **** |
| 74 | CIGAR LAKE |
| 78 | INKAI |
| 81 | URANIUM – TIER-TWO OPERATIONS |
| 81 | RABBIT LAKE |
| 82 | US ISR **** |
| 83 | URANIUM – ADVANCED PROJECTS |
| 83 | MILLENNIUM |
| 83 | YEELIRRIE |
| 83 | KINTYRE |
| 85 | URANIUM – EXPLORATION |
| 86 | FUEL SERVICES |
| 86 | BLIND RIVER REFINERY |
| 87 | PORT HOPE CONVERSION SERVICES |
| 87 | CAMECO FUEL MANUFACTURING INC. (CFM) |
| 89 | OTHER NUCLEAR FUEL CYCLE INVESTMENTS |
| 89 | GLOBAL LASER ENRICHMENT (GLE) |
| 89 | PROPOSED ACQUISITION OF WESTINGHOUSE |
| 93 | CORPORATE DEVELOPMENT |
66 CAMECO CORPORATION
Managing the risks
The nature of our business means we face many kinds of potential risks and hazards – some that relate to the nuclear energy industry in general, safety, health and environmental risks associated with any mining and chemical processing company and others that apply to specific properties, operations, planned operations or investments. Our uranium and fuel services segments also face unique risks associated with radiation. These risks could have a significant impact on our business, earnings, cash flows, financial condition, results of operations or prospects, which may result in a significant decrease in the market price of our common shares.
Risks and hazards generally applicable to the mining, milling and processing facilities we operate, and advanced projects include:
| • | catastrophic accidents resulting in large-scale releases of hazardous chemicals, or a tailings facility failure, which could pose a significant risk to the environment, and to employee and public safety |
|---|---|
| • | industrial safety accidents |
| --- | --- |
| • | transportation incidents |
| --- | --- |
| • | labour shortages, disputes or strikes |
| --- | --- |
| • | cost increases for labour, contracted or purchased materials, supplies and services |
| --- | --- |
| • | shortages of, or interruptions in the supply of, required materials, supplies and equipment |
| --- | --- |
| • | transportation and delivery disruptions |
| --- | --- |
| • | interruptions in the supply of electricity, water, and other utilities or infrastructure |
| --- | --- |
| • | inability of our innovation initiatives to achieve the expected cost saving and operational flexibility objectives |
| --- | --- |
| • | equipment failures |
| --- | --- |
| • | cyberattacks |
| --- | --- |
| • | joint venture disputes or litigation |
| --- | --- |
| • | non-compliance with legal requirements, including exceedances of applicable air or water limits |
| --- | --- |
| • | subsurface contamination from current or legacy operations |
| --- | --- |
| • | inability to obtain and renew the licences and other approvals needed to restart, operate, and to increase production at our mines, mills, and processing facilities, or to develop new mines |
| --- | --- |
| • | increased workforce health and safety risks or increased regulatory burdens resulting from the COVID-19 pandemic or other causes |
| --- | --- |
| • | fires |
| --- | --- |
| • | blockades or other acts of social or political activism |
| --- | --- |
| • | uncertain impact of changing regulations or policy leading to higher annual operating costs, including GHG pricing and regulations (e.g., carbon pricing, the Canadian Clean Fuel Standard) |
| --- | --- |
| • | natural phenomena, such as forest fires, floods and earthquakes as well as shifts in temperature, precipitation, and the impact of more frequent severe weather conditions on our operations as a result of climate change |
| --- | --- |
| • | outbreak of illness (such as a pandemic like COVID-19) |
| --- | --- |
| • | unusual, unexpected or adverse mining or geological conditions |
| --- | --- |
| • | underground water inflows at our mining operations |
| --- | --- |
| • | ground movement or cave-ins at our mining operations |
| --- | --- |
We have a Risk Policy that is supported by our formal Risk Management Program.
Our Risk Management Program involves a broad, systematic approach to identifying, assessing, monitoring, reporting and managing the significant risks we face in our business and operations, including consideration of ESG and climate-related risks that could impact our four measures of success. For more information about our risk management program see the Risk and Risk Management section in this MD&A, as well as our most recent ESG Report at cameco.com.
We have insurance to cover some of these risks and hazards, but not all of them, and not to the full amount of losses or liabilities that could potentially arise.
MANAGEMENT’S DISCUSSION AND ANALYSIS 67
In addition to considering the other information in this MD&A and the risks noted above, you should carefully consider the material risks discussed starting on page 4, and the specific risks discussed under the update for each operation, advanced project, and other nuclear fuel cycle investment in this section. These risks, however, are not a complete list of the potential risks our operations, advanced projects, or other investments face. There may be others we are not aware of or risks we feel are not material today that could become material in the future.
We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.
68 CAMECO CORPORATION
Uranium – production overview
Production in our uranium segment in the fourth quarter was 3.7 million pounds, 32% higher compared to the same period in 2021, while production for the year was 10.4 million pounds, 70% higher than in 2021. Cigar Lake production was higher in 2022 as production was impacted in 2021 by the proactive four-month suspension related to the COVID-19 pandemic. The McArthur River/Key Lake operations transitioned to production in 2022, producing 1.1 million pounds (100% basis) during the year. The Rabbit Lake operation remained in a safe and sustainable state of care and maintenance, and we are no longer developing new wellfields at Crow Butte and Smith Ranch-Highland. See Uranium – Tier-one operations starting on page 70 and Uranium – Tier-twooperations beginning on page 81 for more information.
Uranium production
| CAMECO SHARE | THREE MONTHS ENDED<br>DECEMBER 31 | YEAR ENDED<br>DECEMBER 31 | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (MILLION LBS) | 2022 | 2021 | 2022 | 2021 | 2022 PLAN^1^ | 2023 PLAN | ||||||
| Cigar Lake | **** | 2.9 | 2.8 | **** | 9.6 | 6.1 | 9.5 | 9.8 | ||||
| McArthur River/Key Lake | **** | 0.8 | — | **** | 0.8 | — | up to 1.4 | 10.5 | ||||
| Total | **** | 3.7 | 2.8 | **** | 10.4 | 6.1 | up to 10.9 | 20.3 | ||||
| ^1^ | Cigar Lake was successful in catching up on development work that had been deferred from 2021, and the<br>production target was updated to 9.5 million pounds (our share) in our 2022 second quarter MD&A. The increase also reflected our increase in ownership at Cigar Lake. A production target of up to 1.4 million pounds (our share) from<br>McArthur River/Key Lake was provided in our 2022 second quarter MD&A due to commissioning delays at the mill. | |||||||||||
| --- | --- |
PRODUCTION OUTLOOK
We remain 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 includes a focus, in our uranium segment, on protecting and extending the value of our contract portfolio, on aligning our production decisions with our contract portfolio and market opportunities thereby preserving the value of our lowest cost assets in order to increase long-term value, and to do that with an emphasis on safety, people and the environment.
In 2023, we are planning production of 20.3 million pounds (our share).
Due to equity accounting, our share of production from Inkai is shown as a purchase. We expect total production from Inkai to be 8.3 million pounds (100% basis) in 2023. An adjustment to the production purchase entitlement allows us to purchase 4.2 million pounds in 2023. In addition, we expect to purchase the remaining share of our 2022 production entitlement, the majority of which is currently in transit.
MANAGEMENT’S DISCUSSION AND ANALYSIS 69
Uranium – Tier-one operations
McArthur River mine / Key Lake mill
| 2022 Production (our share) |
|---|
| 0.8M lbs |
| 2023 Production Outlook (our share) |
| 10.5M lbs |
| Estimated Reserves (our share) |
| 275.0M lbs |
| Estimated Mine Life |
| 2044 |
McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the world’s largest uranium mill. Ore grades at the McArthur River mine are 100 times the world average. We are the operator of both the mine and mill.
McArthur River is considered a material uranium property for us. There is a technical report dated March 29, 2019 (effective December 31, 2018) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).
| Location | Saskatchewan, Canada | |
|---|---|---|
| Ownership | McArthur River – 69.805% | |
| Key Lake – 83.33% | ||
| Mine type | Underground | |
| Mining methods | Blasthole stoping and raiseboring | |
| End product | Uranium concentrate | |
| Certification | ISO 14001 certified | |
| Estimated reserves | 275.0 million pounds (proven and probable), average grade U3O8: 6.70% | |
| Estimated resources | 4.7 million pounds (measured and indicated), average grade U3O8: 2.23% | |
| 1.7 million pounds (inferred), average grade U3O8: 2.89% | ||
| Licensed capacity | Mine and mill: 25.0 million pounds per year | |
| Licence term | Through October, 2023 | |
| Total packaged production: | 2000 to 2022 | 326.5 million pounds (McArthur River/Key Lake) (100% basis) |
| 1983 to 2002 | 209.8 million pounds (Key Lake) (100% basis) | |
| 2022 production | 0.8 million pounds (1.1 million pounds on 100% basis) | |
| 2023 production outlook | 10.5 million pounds (15.0 million pounds on 100% basis) | |
| Estimated decommissioning cost | $42 million – McArthur River (100% basis) | |
| $223 million – Key Lake (100% basis) |
All values shown, including reserves and resources, represent our share only, unless indicated.
70 CAMECO CORPORATION
BACKGROUND
Mine description
The mineral reserves at McArthur River are contained within seven zones: Zones 1, 2, 3, 4, 4 South, A and B. Prior to care and maintenance, there were two active mining zones and one where development was significantly advanced.
Zone 2 has been actively mined since production began in 1999. The ore zone was initially divided into three freeze panels. As the freeze wall was expanded, the inner connecting freeze walls were decommissioned in order to recover the inaccessible uranium around the active freeze pipes. Mining of zone 2 is almost complete. About 4.7 million pounds of mineral reserves remain and we expect to recover them using a combination of raisebore and blasthole stope mining.
Zone 4 has been actively mined since 2010. The zone was divided into four freeze panels, and like in zone 2, as the freeze wall was expanded, the inner connecting freeze walls were decommissioned. Zone 4 has 116.6 million pounds of mineral reserves secured behind freeze walls and it will be the main source of production for the next several years. Raisebore mining and blasthole stoping will be used to recover the mineral reserves.
Zone 1 is the next planned mine area to be brought into production. Freezehole drilling was 90% complete and brine distribution construction was approximately 10% complete when work was suspended in 2018 as part of the production suspension. Work remaining before production can begin includes completion of the freezehole drilling, brine distribution construction, ground freezing and drill and extraction chamber development. Work is expected to resume in zone 1 in 2024. Once complete, an additional 48.0 million pounds of mineral reserves will be secured behind freeze walls. Blasthole stope mining is currently planned as the main extraction method.
We have successfully extracted over 325 million pounds (100% basis) since we began mining in 1999.
Mining methods and techniques
All the mineralized areas discovered to date at McArthur River are in, or partially in, water-bearing ground with significant pressure at mining depths.
There are three approved mining methods at McArthur River: raisebore mining, blasthole stope mining and boxhole mining. However, only raisebore and blasthole stope mining remain in use. Before we begin mining an area, we freeze the ground around it by circulating chilled brine through freezeholes to form an impermeable freeze barrier.
Blasthole stoping
Blasthole stoping began in 2011 and was the main extraction method prior to our production suspension. It is planned in areas where blastholes can be accurately drilled and small stable stopes excavated without jeopardizing the freeze wall integrity. The use of this method has allowed the site to improve operating costs by increasing overall extraction efficiency by reducing underground development, concrete consumption, mineralized waste generation and improving extraction cycle time.
Raisebore mining
Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River, and it has been used since mining began in 1999. This method is favourable for mining the weaker rock mass areas of the deposit, and is suitable for massive high-grade zones where there is access both above and below the ore zone.
Initial processing
McArthur River produces two product streams, high grade slurry and low-grade mineralized rock. Both product streams are shipped to Key Lake mill to produce uranium ore concentrate.
The high-grade material is ground and thickened into a slurry underground and then pumped to surface. The material is then thickened and blended for grade control and shipped to Key Lake in slurry totes using haul trucks.
The low-grade mineralized material is hoisted to surface and shipped as a dry product to Key Lake using covered haul trucks. Once at Key Lake, the material is ground, thickened and blended with the high-grade slurry to a nominal 5% U3O8 mill feed grade. It is then processed into uranium ore concentrate and packaged in drums for further processing offsite.
MANAGEMENT’S DISCUSSION AND ANALYSIS 71
Tailings capacity
Based on the current licence conditions, tailings capacity at Key Lake is sufficient to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.
Licensed annual production capacity
The McArthur River mine and Key Lake mill are both licensed to produce up to 25 million pounds (100% basis) per year. To achieve annual production at the licensed capacity, additional investment will be required.
2022 UPDATE
Production
The McArthur River and Key Lake operation was in a state of safe care and maintenance from 2018 through 2021 due to weak market conditions. Through most of 2022, we undertook the necessary operational readiness activities prior to restarting production. In November 2022, we announced that the first pounds of uranium ore from the McArthur River mine had been milled and packaged at the Key Lake mill, marking the achievement of initial production as these facilities transition back into normal operations.
Total packaged production from McArthur River and Key Lake in 2022 was 1.1 million pounds (0.8 million pounds our share) as the mine and mill resumed production.
Operational readiness activities consisted of recruitment, training, infrastructure upgrades and commissioning as well as reactivation of mobile equipment previously stored for care and maintenance. Operational activities included mine dewatering, water treatment, freeze wall maintenance, and environmental monitoring.
In 2022, production forecasts were revised as we worked through normal commissioning issues to integrate the existing and new assets with upgraded operational technology which caused some delays to schedule at the mill. During the year we expensed operational readiness costs of approximately $169 million directly to cost of sales. With the restart of production, in 2023 we will no longer expense monthly operational readiness costs.
Exploration
There was no exploration activity in 2022, as we focused on the restart of production.
PLANNING FOR THE FUTURE
Production
We plan to produce 15 million pounds (100% basis) in 2023 and 18 million pounds (100% basis) in 2024.
With the improvement in the uranium market and the success we have had in securing new long-term contracts, we have updated our 2024 production plan to achieve 18 million pounds (100% basis) per year starting in 2024. This will remain our production plan until we see further improvements in the uranium market and contracting progress, demonstrating that we continue to be a responsible supplier of uranium fuel.
Innovation
In 2020, we began a program to advance the assessment of innovation opportunities at the McArthur River mine and Key Lake mill. We established a team of internal experts who have been tasked with assessing, designing and implementing opportunities to improve operating efficiency. We continue to advance the projects that meet our investment criteria.
72 CAMECO CORPORATION
MANAGING OUR RISKS
The McArthur River deposit presents unique challenges that are not typical of traditional hard or soft rock mines. These challenges are the result of mining in or near high pressure ground water in challenging ground conditions with significant radiation concerns due to the high-grade uranium. We take significant steps and precautions to reduce the risks. Mine designs and mining methods are selected based on their ability to mitigate hydrological, radiological and geotechnical risks. Operational experience gained since the start of production has resulted in a significant reduction in risk. However, there is no guarantee that our efforts to mitigate risk will be successful.
In addition to the risks listed on pages 67 to 68, in 2023 we are focused on the management of the following risks:
Mine and mill ramp up
With the extended period of time the assets were on care and maintenance, the operational changes made, and commissioning issues that we have worked through at the mill, which caused delays to the production schedule in 2022, there is continued uncertainty regarding the timing of a successful ramp up to planned production and the associated costs. In addition, inflation, the availability of personnel with the necessary skills and experience, and the potential impact of supply chain challenges on the availability of materials and reagents carry with them the risks of not achieving our production plans, production delays and increased costs.
Labour relations
The collective agreement with the United Steelworkers local 8914 expired in December 2022. As in the past negotiations, work continues under the terms of the expired collective agreement while negotiations to reach a new agreement proceeded. There is a risk to the production plan if we are unable to reach an agreement and there is a labour dispute.
Licensing risk
The current operating licence from the CNSC for both Key Lake and McArthur River expire in October 2023. The relicensing process is under way for both sites, and we expect a decision from the CNSC later in 2023. We do not expect any interruption or significant risks from this process.
Water inflow risk
All the mineralized areas discovered to date at McArthur River are in, or partially in, water-bearing ground with significant pressure at mining depths. This high-pressure water source is isolated from active development and production areas in order to reduce the inherent risk of an inflow. McArthur River relies on pressure grouting and ground freezing, and sufficient pumping, water treatment and above ground storage capacity to mitigate the risks of the high-pressure ground water.
McArthur River has not experienced a significant disruption to its mining or development activities resulting from a water inflow since 2008. The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.
MANAGEMENT’S DISCUSSION AND ANALYSIS 73
Uranium – Tier-one operations
Cigar Lake
| 2022 Production (our share) |
|---|
| 9.6M lbs |
| 2023 Production Outlook (our share) |
| 9.8M lbs |
| Estimated Reserves (our share) |
| 84.4M lbs |
| Estimated Mine Life |
| 2031 |
Cigar Lake is the world’s highest grade uranium mine, with grades that are 100 times the world average. We are a 54.5% owner and the mine operator. Cigar Lake uranium is milled at Orano’s McClean Lake mill.
Cigar Lake is considered a material uranium property for us. There is a technical report dated March 29, 2016 (effective December 31, 2015) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).
| Location | Saskatchewan, Canada |
|---|---|
| Ownership | 54.547% |
| Mine type | Underground |
| Mining method | Jet boring system |
| End product | Uranium concentrate |
| Certification | ISO 14001 certified |
| Estimated reserves | 84.4 million pounds (proven and probable), average grade U3O8: 17.21% |
| Estimated resources | 57.5 million pounds (measured and indicated), average grade U3O8: 13.19% |
| 12.0 million pounds (inferred), average grade U3O8: 5.62% | |
| Licensed capacity | 18.0 million pounds per year (our share 9.8 million pounds per year*)* |
| Licence term | Through June, 2031 |
| Total packaged production: 2014 to 2022 | 123 million pounds (100% basis) |
| 2022 production | 9.6 million pounds (18.0 million pounds on 100% basis) |
| 2023 production outlook | 9.8 million pounds (18.0 million pounds on 100% basis) |
| Estimated decommissioning cost | $62 million (100% basis) |
| All values shown, including reserves and resources,<br>represent our share only, unless otherwise indicated. |
BACKGROUND
Minedescription
Cigar Lake’s geological setting is similar to McArthur River’s. However, unlike McArthur River, the Cigar Lake deposit has the shape of a flat- to cigar-shaped lens.
Mine development is carried out in the basement rocks below the ore horizon. New mine development is required throughout the mine life to gain access to the ore above.
Mining method
At Cigar Lake, the permeable sandstone which overlays the deposit and basement rocks, contains large volumes of water at significant pressure. Before we begin mining, we freeze the ore zone and surrounding ground in the area to be mined to meet certain specifications. We use a jet boring mining method to extract the ore.
74 CAMECO CORPORATION
Jet boring system (JBS) mining
As a result of the unique geological conditions at Cigar Lake, we are unable to utilize traditional mining methods that require access above the ore, which necessitated the development of a non-entry mining method specifically adapted for this deposit. After many years of test mining, we selected jet boring, and it has been used since mining began in 2014. This method involves:
| • | drilling a pilot hole into the frozen orebody, inserting a high pressure water jet and cutting a cavity out of<br>the frozen ore |
|---|---|
| • | collecting the ore and water mixture (slurry) from the cavity and pumping it to a storage sump, allowing it to<br>settle |
| --- | --- |
| • | using a clamshell, transporting the ore from the storage sump to an underground grinding and processing circuit<br> |
| --- | --- |
| • | once mining is complete, filling each cavity in the orebody with concrete |
| --- | --- |
| • | starting the process again with the next cavity. |
| --- | --- |
We have divided the orebody into production panels and at least three production panels need to be frozen at one time to achieve the annual production rate. One JBS machine is located below each frozen panel. Three JBS machines are currently in operation. Two machines actively mine at any given time while the third is moving, setting up, or undergoing maintenance.
We have successfully extracted approximately 123 million pounds (100% basis) since we began mining in 2014.
Initial processing
We carry out initial processing of the extracted ore at Cigar Lake before shipping it to McClean Lake. To accomplish this, we:
| • | grind the ore and mix it with water to form a slurry in our underground circuit |
|---|---|
| • | pump the slurry 500 metres to the surface and store it in one of two ore slurry holding tanks, where it is<br>blended and thickened to remove excess water |
| --- | --- |
| • | the final slurry, at an average grade of approximately 15%<br>U3O8, is pumped into transport truck containers and shipped to McClean Lake mill on a<br>69-kilometre all-weather road |
| --- | --- |
Water from this process, including water from underground operations, is treated on the surface. Any excess treated water is released into the environment.
Milling
All of Cigar Lake’s ore slurry is being processed at the McClean Lake mill, operated by Orano. Given the McClean Lake mill’s capacity, it is able to:
| • | process up to 18 million pounds U3O8 per year |
|---|---|
| • | process and package all of Cigar Lake’s current mineral reserves |
| --- | --- |
Licensing annual production capacity
The Cigar Lake mine is licensed to produce up to 18 million pounds (100% basis) per year. Orano’s McClean Lake mill is licensed to produce 24 million pounds annually.
2022 UPDATE
As announced in May, we along with Orano acquired Idemitsu Canada Resources Ltd.’s 7.875% participating interest in the Cigar Lake Joint Venture. Our ownership stake in Cigar Lake now stands at 54.547%, 4.522 percentage points higher than it was prior to the transaction.
Production
Total packaged production from Cigar Lake in 2022 was 18 million pounds U3O8 (9.6 million pounds our share) compared to 12.2 million pounds U3O8 (6.1 million pounds our share) in 2021. 2021 production was impacted by suspensions, which were a precautionary measure due to the COVID-19 pandemic. In 2022, we were successful in catching up on development work that had been deferred from 2021. Our share of production for 2022 has been updated to reflect the ownership increase effective May 19, 2022.
During the year, we:
| • | executed planned 21-day annual maintenance activities in July<br> |
|---|---|
| • | executed production activities from four production tunnels in the eastern part of the orebody<br> |
| --- | --- |
MANAGEMENT’S DISCUSSION AND ANALYSIS 75
| • | in alignment with our long-term production planning, brought one new panel online as another production panel was<br>depleted |
|---|---|
| • | continued underground header construction activities and expanded our ground freezing program to ensure continued<br>frozen ore inventory |
| --- | --- |
Underground development
Underground mine development continued in 2022. We completed the first production crosscut in the western portion of the orebody in preparation for ore mining starting in the second quarter of 2023.
PLANNING FOR THE FUTURE
Production
In 2023, we expect to produce 18 million pounds (100% basis) at Cigar Lake; our share is approximately 9.8 million pounds.
In 2023, we plan to:
| • | continue production activities focused on bringing two new production panels online |
|---|---|
| • | complete surface freeze drilling and complete construction and commissioning of freeze distribution<br>infrastructure expansion in support of future production |
| --- | --- |
| • | continue underground mine development on two new production tunnels as well as expand ventilation and access<br>drifts in alignment with the long-term mine plan |
| --- | --- |
| • | continue upgrades to process water handling circuits and the surface backfill batch plant to support ongoing<br>operations |
| --- | --- |
| • | execute a surface delineation drilling program and underground geotechnical drilling program<br> |
| --- | --- |
Consistent with our strategy to align our production decisions with our contract portfolio and market opportunities, we have updated our 2024 production plan. We expect to maintain production at the licensed rate of 18 million pounds (100% basis) per year based on our contracting success and the improved outlook for the uranium market compared to our previous plan of 13.5 million pounds (100% basis) per year in 2024.
MANAGING OUR RISKS
The Cigar Lake deposit presents unique challenges that are not typical of traditional hard or soft rock mines. These challenges are the result of mining in or near high-pressure ground water in challenging ground conditions with significant radiation concerns due to the high-grade uranium and elements of concern in the orebody with respect to water quality. We take significant steps and precautions to reduce the risks. Mine designs and the mining method are selected based on their ability to mitigate hydrological, radiological, and geotechnical risks. Operational experience gained since the start of production has resulted in a significant reduction in risk. However, there is no guarantee that our efforts to mitigate risk will be successful.
In addition to the risks listed on pages 67 to 68, in 2023 we are focused on the management of the following risks:
Inflation, labour shortages, and supply chain challenges
Inflation, the availability of personnel with the necessary skills and experience, and the impact of supply chain challenges on the availability of materials and reagents carry with them the risk of not achieving our production plans, production delays and increased costs in 2023 and future years.
Transition to new mining areas
In order to successfully achieve the planned production schedule, we must continue to successfully transition into new mining areas, which includes mine development and investment in critical support infrastructure. If development work is delayed for any reason, including availability of storage capacity for waste rock, our ability to meet our future production plans may be impacted.
Water inflow risk
The sandstone that overlays the Cigar Lake deposit and basement rocks is water-bearing with significant pressure at mining depths. This high-pressure water source is isolated from active development and production areas in order to reduce the inherent risk of an inflow. Cigar Lake relies on ground freezing and sufficient pumping, water treatment and above ground storage capacity to mitigate the risks of the high-pressure ground water.
76 CAMECO CORPORATION
Cigar Lake has not experienced a significant disruption resulting from a water inflow since 2008. The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.
MANAGEMENT’S DISCUSSION AND ANALYSIS 77
Uranium – Tier-one operations
Inkai
| 2022 Production (100% basis) |
|---|
| 8.3M lbs |
| 2023 Production Outlook (100% basis) |
| 8.3M lbs |
| Estimated Reserves (our share) |
| 108.7M lbs |
| Estimated Mine Life |
| 2045 (based on licence term) **** |
Inkai is a very significant uranium deposit, located in Kazakhstan. The operator is JV Inkai limited liability partnership, which we jointly own (40%)^1^ with Kazatomprom (60%).
Inkai is considered a material uranium property for us. There is a technical report dated January 25, 2018 (effective January 1, 2018) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).
| Location | South Kazakhstan | ||
|---|---|---|---|
| Ownership | 40%^1^ | ||
| Mine type | In situ recovery (ISR) | ||
| End product | Uranium concentrate | ||
| Certifications | BSI OHSAS 18001 | ||
| ISO 14001 certified | |||
| Estimated reserves | 108.7 million pounds (proven and probable), average grade U3O8: 0.04% | ||
| Estimated resources | 35.6 million pounds (measured and indicated), average grade U3O8: 0.03% | ||
| 9.6 million pounds (inferred), average grade U3O8: 0.03% | |||
| Licensed capacity (wellfields) | 10.4 million pounds per year (our share 4.2 million pounds per year*)^1^ | ||
| Licence term | Through July 2045 | ||
| Total packaged production: 2009 to 2022 | 81 million pounds (100% basis) | ||
| 2022 production | 8.3 million pounds (100% basis)^1^ | ||
| 2023 production outlook | 8.3 million pounds (100% basis)*^1^ | ||
| Estimated decommissioning cost (100% basis) | $20 million (US) (100% basis) (this estimate is currently under review) |
All values shown, including reserves and resources, represent our share only, unless indicated.
| ^1^ | Our ownership interest in the joint venture is 40% and we equity account for our investment. As such, our share<br>of production is shown as a purchase. |
|---|
78 CAMECO CORPORATION
BACKGROUND
Mine description
The Inkai uranium deposit is a roll-front type orebody within permeable sandstones. The more porous and permeable units host several stacked and relatively continuous, sinuous “roll-fronts” of low-grade uranium forming a regional system. Superimposed over this regional system are several uranium projects and active mines.
Inkai’s mineralization ranges in depths from about 260 metres to 530 metres. The deposit has a surface projection of about 40 kilometres in length, and the width ranges from 40 to 1600 metres. The deposit has hydrogeological and mineralization conditions favourable for use of in-situ recovery (ISR) technology.
Mining and milling method
JV Inkai uses conventional, well-established, and very efficient ISR technology, developed after extensive test work and operational experience. The process involves five major steps:
| • | leach the uranium in-situ by circulating an acid-based solution through<br>the host formation |
|---|---|
| • | recover it from solution with ion exchange resin (takes place at both main and satellite processing plants)<br> |
| --- | --- |
| • | precipitate the uranium with hydrogen peroxide |
| --- | --- |
| • | thicken, dewater, and dry it |
| --- | --- |
| • | package the uranium peroxide product in drums |
| --- | --- |
Production
Total 2022 production from Inkai was 8.3 million pounds (100% basis) as planned, a decrease of 7% from 2021. In 2022, Inkai experienced a number of operational issues related to interruptions in reagent delivery and wellfield drilling. While the issues have been partially mitigated, their impact on production and inflationary pressure on production supplies pose a risk to JV Inkai’s 2023 production volume and its costs.
The first shipment of our share of JV Inkai’s 2022 production via the Trans-Caspian route arrived at a Canadian port in December 2022. This was the first shipment of our share of finished product from JV Inkai that did not rely on Russian rail lines or ports. However, the geopolitical situation continues to cause transportation risks in the region. Our 2022 share of earnings from this equity-accounted investee were impacted due to the timing of delivery of our share of 2022 production.
Production purchase entitlements
Under the terms of a restructuring agreement signed with our partner Kazatomprom in 2016, our ownership interest in JV Inkai is 40% and Kazatomprom’s share is 60%. However, during production rampup to the licensed limit of 10.4 million pounds, we are entitled to purchase 57.5% of the first 5.2 million pounds of annual production, and as annual production increases over 5.2 million pounds, we are entitled to purchase 22.5% of such incremental production, to the maximum annual share of 4.2 million pounds. Once the rampup to 10.4 million pounds annually is complete, we will be entitled to purchase 40% of such annual production, matching our ownership interest.
Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement, for 2022 we were entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s 2022 production of 8.3 million pounds. Timing of our JV Inkai purchases will fluctuate during the quarters and may not match production, and, in particular, in 2022, timing was impacted by shipping delays. Total purchases in 2022 were 3.3 million pounds, of which 2.6 million pounds were related to our 2022 entitlement. In 2023, we expect to purchase our remaining 2022 entitlement once it is delivered to our Blind River refinery. A second shipment containing the majority of the remaining 2022 production is currently in transit.
Cash distribution
Excess cash, net of working capital requirements, will be distributed to the partners as dividends. In 2022, we received dividend payments from JV Inkai totaling $92.4 million (US). Our share of dividends follows our production purchase entitlements as described above.
MANAGEMENT’S DISCUSSION AND ANALYSIS 79
PLANNING FOR THE FUTURE
Production
Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement described above, we are entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s planned 2023 production of 8.3 million pounds.
Our share of production is purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures.
In August 2022, Kazatomprom announced its plan to produce 10% below the planned volumes under its Subsoil Use Contracts in 2024.
MANAGING OUR RISKS
In addition to the risks listed on pages 67 to 68, JV Inkai also manages the following risks:
2023 production forecast
Presently, JV Inkai is experiencing wellfield development, procurement and supply chain issues, and inflationary pressures on its production materials and reagents. Achievement of its 2023 production forecast requires it to successfully manage these risks. If there is a significant disruption to JV Inkai’s operations for any reason, it may not achieve its production plans, there may be a delay in production, and it may experience increased costs to produce uranium. In addition, JV Inkai’s costs could be impacted by potential changes to the tax code in Kazakhstan and by possible increased financial contributions to social and other state causes, although these risks cannot be quantified or estimated at this time.
Transportation
The geopolitical situation continues to cause transportation risks in the region. We could continue to experience delays in our expected Inkai deliveries from 2022 and for 2023. To mitigate this risk, we have inventory, long-term purchase agreements and loan arrangements in place we can draw on. Depending on when we receive shipments of our share of Inkai’s production, our share of earnings from this equity-accounted investee and the timing of the receipt of our share of dividends from the joint venture may be impacted.
Political
Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our investment in JV Inkai is subject to the greater risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal and fiscal instability. Kazakhstan laws and regulations are complex and still developing and their application can be difficult to predict. The other owner of JV Inkai is Kazatomprom, an entity majority owned by the government of Kazakhstan. We have entered into agreements with JV Inkai and Kazatomprom intended to mitigate political risk. This risk includes the imposition of governmental laws or policies that could restrict or hinder JV Inkai paying us dividends, or selling us our share of JV Inkai production, or that impose discriminatory taxes or currency controls on these transactions. The restructuring of JV Inkai, which took effect January 1, 2018, was undertaken with the objective to better align the interests of Cameco and Kazatomprom and includes a governance framework that provides for protection for us as a minority owner of JV Inkai.
In early January 2022, Kazakhstan saw the most significant political instability since it became independent in 1991. The events resulted in a state of emergency being declared across the country. Order was restored in the second half of January, and the state of emergency was gradually lifted. In November 2022, President Tokayev was re-elected for a new 7-year term.
For more details on this risk, please see our most recent annual information form under the heading political risks.
JV Inkai manages risks listed on pages 67 to 68.
80 CAMECO CORPORATION
Uranium – Tier-two operations
Rabbit Lake
Located in Saskatchewan, Canada, our 100% owned Rabbit Lake operation opened in 1975, and has the second largest uranium mill in the world. Due to market conditions, we suspended production at Rabbit Lake during the second quarter of 2016.
| Location | Saskatchewan, Canada |
|---|---|
| Ownership | 100% |
| End product | Uranium concentrates |
| ISO certification | ISO 14001 certified |
| Mine type | Underground |
| Estimated reserves | — |
| Estimated resources | 38.6 million pounds (indicated), average grade U3O8: 0.95% |
| 33.7 million pounds (inferred), average grade U3O8: 0.62% | |
| Mining methods | Vertical blasthole stoping |
| Licensed capacity | Mill: maximum 16.9 million pounds per year; currently 11 million |
| Licence term | Through October, 2023 |
| Total production: 1975 to 2022 | 202.2 million pounds |
| 2022 production | 0 million pounds |
| 2023 production outlook | 0 million pounds |
| Estimated decommissioning cost | $213 million |
PRODUCTION SUSPENSION
The facilities remained in a state of safe and sustainable care and maintenance throughout 2022.
While in standby, we continue to evaluate our options in order to minimize care and maintenance costs. We expect care and maintenance costs to range between $27 million and $32 million annually.
FUTURE PRODUCTION
We do not expect any production from Rabbit Lake in 2023.
MANAGING OUR RISKS
The current operating licence from the CNSC for Rabbit Lake expires in October 2023. The relicensing process is under way, and we expect a decision from the CNSC later in 2023.
We also manage the risks listed on pages 67 to 68.
MANAGEMENT’S DISCUSSION AND ANALYSIS 81
US ISR Operations
Located in Nebraska and Wyoming in the US, the Crow Butte and Smith Ranch-Highland (including the North Butte satellite) operations began production in 1991 and 1975. Each operation has its own processing facility. Due to market conditions, we curtailed production and deferred all wellfield development at these operations during the second quarter of 2016.
| Ownership | 100% | |
|---|---|---|
| End product | Uranium concentrates | |
| ISO certification | ISO 14001 certified | |
| Estimated reserves | Smith Ranch-Highland: | — |
| North Butte-Brown Ranch: | — | |
| Crow Butte: | — | |
| Estimated resources | Smith Ranch-Highland: | 24.9 million pounds (measured and indicated), average grade U3O8: 0.06% |
| 7.7 million pounds (inferred), average grade U3O8: 0.05% | ||
| North Butte-Brown Ranch: | 9.4 million pounds (measured and indicated), average grade U3O8: 0.07% | |
| 0.4 million pounds (inferred), average grade U3O8: 0.06% | ||
| Crow Butte: | 13.9 million pounds (measured and indicated), average grade U3O8: 0.25% | |
| 1.8 million pounds (inferred), average grade U3O8: 0.16% | ||
| Mining methods | In situ recovery (ISR) | |
| Licensed capacity | Smith Ranch-Highland:^1^ | Wellfields: 3 million pounds per year; processing plants: 5.5 million pounds per year |
| Crow Butte: | Processing plants and wellfields: 2 million pounds per year | |
| Licence term | Smith Ranch-Highland: | Through September, 2028 |
| Crow Butte: | Through October, 2024 | |
| Total production: 2002 to 2022 | 33.0 million pounds | |
| 2022 production | 0 million pounds | |
| 2023 production outlook | 0 million pounds | |
| Estimated decommissioning cost | Smith Ranch-Highland: $219 million (US), including North Butte | |
| Crow Butte: $56 million (US) | ||
| ^1^ | Including Highland mill | |
| --- | --- |
PRODUCTION CURTAILMENT
As a result of our 2016 decision, commercial production at the US operations ceased in 2018. We expect ongoing cash and non-cash care and maintenance costs to range between $12 million (US) and $14 million (US) for 2023.
FUTURE PRODUCTION
We do not expect any production in 2023.
MANAGING OUR RISKS
We manage the risks listed on pages 67 to 68.
82 CAMECO CORPORATION
Uranium – advanced projects
Work on our advanced projects has been scaled back and will continue at a pace aligned with market signals.
Millennium
| Location | Saskatchewan, Canada |
|---|---|
| Ownership | 69.9% |
| End product | Uranium concentrates |
| Potential mine type | Underground |
| Estimated resources (our share) | 53.0 million pounds (indicated), average grade U3O8: 2.39%<br> <br><br> <br>20.2 million pounds<br>(inferred), average grade U3O8: 3.19% |
BACKGROUND
The Millennium deposit was discovered in 2000 and was delineated through geophysical surveys and surface drilling work between 2000 and 2013.
Yeelirrie
| Location | Western Australia |
|---|---|
| Ownership | 100% |
| End product | Uranium concentrates |
| Potential mine type | Open pit |
| Estimated resources | 128.1 million pounds (measured and indicated), average grade U3O8: 0.15% |
BACKGROUND
The deposit was discovered in 1972 and is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.
Kintyre
| Location | Western Australia |
|---|---|
| Ownership | 100% |
| End product | Uranium concentrates |
| Potential mine type | Open pit |
| Estimated resources | 53.5 million pounds (indicated), average grade U3O8: 0.62%<br> <br><br> <br>6.0 million pounds<br>(inferred), average grade U3O8: 0.53% |
BACKGROUND
The Kintyre deposit was discovered in 1985 and is amenable to open pit mining techniques.
2022 PROJECT UPDATES
We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment our primary focus is on producing from our tier-one uranium assets at a pace aligned with our contract portfolio and market opportunities. We continue to await a signal from our customers that additional production is needed prior to making any new development decisions.
PLANNING FOR THE FUTURE
2023 Planned activity
No work is planned at Millennium, Yeelirrie or Kintyre.
Further progress towards a development decision on any of these projects is not expected until the market fully transitions and supply is incented by prices that reflect production economics.
MANAGEMENT’S DISCUSSION AND ANALYSIS 83
MANAGING THE RISKS
Project approval
The approval received for Kintyre from the prior state government required substantial commencement of the project by March 2020, being within five years of the grant of the approval, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future, we can apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Kintyre project, provided we have all other required regulatory approvals.
The approval for the Yeelirrie project, received from the prior state government, required substantial commencement of the project by January 2022, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future, we can again apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Yeelirrie project, provided we have all other required regulatory approvals. Approval for the Yeelirrie project at the federal level was granted in 2019 and extends until 2043.
For all of our advanced projects, we manage the risks listed on pages 67 to 68.
84 CAMECO CORPORATION
Uranium – exploration
Our exploration program is directed at replacing mineral reserves as they are depleted by our production and is key to sustaining our business. We are focused on exploration near our existing operations where we have established infrastructure and capacity to expand. Globally, we have land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia and the US. Our land holdings total about 0.78 million hectares (1.9 million acres). In northern Saskatchewan alone, we have direct interests in about 0.68 million hectares (1.7 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin.
2022 UPDATE
Brownfield exploration
Brownfield exploration is uranium exploration near our existing operations and includes expenses for advanced exploration on the evaluation of projects where uranium mineralization is being defined.
In 2022, we spent about $2 million on brownfields and advanced uranium projects in Saskatchewan and Australia. At the US operations we spent $1 million.
Regional exploration
We spent about $8 million on regional exploration programs (including support costs), primarily in Saskatchewan’s Athabasca Basin.
PLANNING FOR THEFUTURE
We will maintain an active uranium exploration program and continue to focus on our core projects in Saskatchewan under our long-term exploration strategy. Long-term, we look for properties that meet our investment criteria. We may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our industry expertise in both exploration and corporate social responsibility make us a partner of choice.
MANAGEMENT’S DISCUSSION AND ANALYSIS 85
Fuel services
Refining, conversion and fuel manufacturing
We have about 21% of world UF6 primary conversion capacity and are a supplier of natural UO2. Our focus is on cost-competitiveness and operational efficiency, as well as increasing our production of UF6 in line with our contract portfolio and market opportunities.
Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and meet customer needs.
Blind River Refinery
| Licensed Capacity<br> <br><br><br><br>24.0M kgU as UO3<br> <br><br><br><br>Licence renewal in<br> <br><br><br><br>February 2032 |
|---|
Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO3.
| Location | Ontario, Canada |
|---|---|
| Ownership | 100% |
| End product | UO3 |
| ISO certification | ISO 14001 certified |
| Licensed capacity | 18.0 million kgU as UO3 per year, approved to 24.0 million subject to the completion of certain equipment upgrades (advancement depends on market<br>conditions) |
| Licence term | Through February 2032 |
| Estimated decommissioning cost | $58 million |
86 CAMECO CORPORATION
Port Hope Conversion Services
| Licensed Capacity<br> <br><br><br><br>12.5M kgU as UF6<br> <br><br><br><br>2.8M kgU as UO2<br> <br><br><br><br>Licence renewal in<br> <br><br><br><br>February 2027 |
|---|
Port Hope is the only uranium conversion facility in Canada and a supplier of UO2 for Canadian-made CANDU heavy-water reactors.
| Location | Ontario, Canada |
|---|---|
| Ownership | 100% |
| End product | UF6, UO2 |
| ISO certification | ISO 14001 certified |
| Licensed capacity | 12.5 million kgU as UF6 per year |
| 2.8 million kgU as UO2 per year | |
| Licence term | Through February 2027 |
| Estimated decommissioning cost | $129 million |
Cameco Fuel Manufacturing Inc. (CFM)
| Licensed Capacity<br> <br><br><br><br>1.65M kgU as UO2 fuel pellets<br><br><br><br> <br>Licence renewal in<br><br><br><br> <br>February 2043 |
|---|
CFM produces fuel bundles and reactor components for CANDU heavy-water reactors.
| Location | Ontario**,** Canada |
|---|---|
| Ownership | 100% |
| End product | CANDU fuel bundles and components |
| ISO certification | ISO 9001 certified, ISO 14001 certified |
| Licensed capacity | 1.65 million kgU as UO2 fuel pellets |
| Licence term | Through February 2043 |
| Estimated decommissioning cost | $10.8 million |
MANAGEMENT’S DISCUSSION AND ANALYSIS 87
2022 UPDATE
Production
Fuel services produced 13.0 million kgU, 7% higher than 2021 due to an increase in demand in 2022.
Port Hope conversion facility cleanup and modernization (Vision in Motion)
Vision in Motion is a unique opportunity that demonstrates our continued commitment to a clean environment. It has been made possible by the opening of a long-term waste management facility by the Government of Canada’s Port Hope Area Initiative project. There is a limited opportunity during the life of this project to engage in clean-up and renewal activities that address legacy waste at the Port Hope Conversion facility inherited from historic operations. Progress was made over the past year to facilitate the removal of some old buildings and structures, which will be the focus in the year ahead.
PLANNING FOR THE FUTURE
Production
We plan to produce between 13 million and 14 million kgU in 2023. In addition, at our Port Hope UF6 conversion facility we are working on increasing annual production to 12,000 tonnes in 2024 to satisfy our book of long-term business and demand for conversion services.
Also, in conjunction with our initiative intended to provide a greater focus on technology and its applications to improve efficiency and reduce costs across the organization, we will continue to look for opportunities to improve operational effectiveness, including the use of digital and automation technologies.
Licensing
In January 2023, the CNSC granted a 20-year renewal to the licence for CFM. The licence renewal also grants CFM’s request for a slight production increase to 1,650 tonnes as UO2 fuel pellets.
MANAGING OUR RISKS
We take significant steps and precautions to reduce risk. However, there is no guarantee that our efforts to mitigate risk will be successful.
In addition to the risks listed on pages 67 to 68, in 2023 we are focused on the management of the following risk:
Production plans
Inflation, the availability of personnel with the necessary skills and experience, aging infrastructure, and the potential impact of supply chain challenges on the availability of materials and reagents carry the risk of not achieving our production plans, production delays, and increased costs in 2023 and future years.
88 CAMECO CORPORATION
Other Nuclear Fuel Cycle Investments
Global Laser Enrichment
Global Laser Enrichment LLC (GLE) is the exclusive licensee of the proprietary Separation of Isotopes by Laser Excitation (SILEX) laser enrichment technology, a third-generation uranium enrichment technology. We are the commercial lead for the GLE project with a 49% interest and starting in February 2023, an option to attain a majority interest of up to 75% ownership.
Subject to completion of the technology development program, and its progression through to commercialization, GLE has the potential to offer a variety of advantages to the global nuclear energy sector over the long-term, which include:
| • | re-enriching depleted uranium tails leftover as a by-product of previous-generation enrichment technologies, repurposing legacy waste into a commercial source of uranium and conversion products to fuel nuclear reactors and aiding in the responsible clean-up of enrichment facilities no longer in operation, as per GLE’s agreement with the U.S. Department of Energy |
|---|---|
| • | producing commercial low-enriched uranium (LEU) fuel for the world’s<br>existing and future fleet of large-scale light-water reactors with greater efficiency and flexibility than current enrichment technologies |
| --- | --- |
| • | producing high-assay low-enriched uranium (HALEU), the primary fuel stock<br>for the majority of small modular reactor (SMR) and advanced reactor designs that are proceeding through the development stage and continuing toward commercial readiness |
| --- | --- |
In 2022, GLE made progress with the first full-scale laser system module, successfully completing eight months of testing in Australia, and the system was delivered to GLE’s commercial pilot demonstration facility in the US. In addition, GLE signed letters of intent to collaborate with two major US utilities to help diversify the US nuclear fuel supply chain, including measures to support its deployment of laser enrichment technology in the US.
The development timeline for GLE will be dependent on several factors, including market fundamentals, securing government funding, support for HALEU availability in the US and GLE’s ability to secure long-term contracts to underpin the deployment of a commercial facility.
MANAGING OUR RISKS
GLE is subject to the risks relating to the nuclear industry discussed under the heading Caution about forward-looking information beginning on page 2.
Proposed acquisition ofWestinghouse
As announced on October 11, 2022, we entered into a strategic partnership with Brookfield Renewable and its institutional partners to acquire Westinghouse Electric Company (Westinghouse), a global provider of mission-critical and specialized technologies, products and services across most phases of the nuclear power sector. Brookfield Renewable will beneficially own a 51% interest in Westinghouse and Cameco will beneficially own 49%. Bringing together Cameco’s expertise in the nuclear industry with Brookfield Renewable’s expertise in clean energy positions nuclear power at the heart of the energy transition and creates a powerful platform for strategic growth across the nuclear sector.
Westinghouse’s history in the energy industry stretches back over a century, during which time the company became a pioneer in nuclear energy.
Westinghouse is organized in three business segments:
| • | Operating Plant Services: Long-term contracting for the manufacturing and<br>installation of fuel assemblies and other ancillary equipment across multiple light water reactor technologies. Westinghouse provides recurring services for outages and maintenance, engineering solutions, and replacement components and parts.<br> |
|---|---|
| • | Energy Systems: Designing, engineering and supporting the development of new nuclear reactors.<br> |
| --- | --- |
| • | Environmental Services: Services to government and commercial customers that support nuclear sustainability,<br>environmental stewardship and remediation. |
| --- | --- |
MANAGEMENT’S DISCUSSION AND ANALYSIS 89
The largest business segment is Operating Plant Services, which accounted for approximately $2.7 billion (US) or about 81% of Westinghouse’s total 2021 revenue of approximately $3.3 billion (US). This segment is built on long-term customer relationships. These customers seek solutions to ensure their reactors operate efficiently and reliably and therefore results in predictable revenue streams.
The acquisition of Westinghouse will be through a strategic partnership with Brookfield Renewable in the form of a limited partnership that will allow each of us to further participate in and support the growing momentum for nuclear energy. The board of directors of the general partner of the limited partnership will consist of six directors, three appointed by Cameco and three appointed by Brookfield Renewable. Decision-making by the board of the general partnership will correspond to percentage ownership interests in the limited partnership (51% Brookfield Renewable and 49% Cameco). There are a number of significant decisions that require the presence and support of both Cameco and Brookfield Renewable appointees to the board as long as certain ownership thresholds are met. These “reserved” matters will include decisions such as the approval of the annual budget, entering into material contracts, the making of significant investments, entering into new lines of business and related-party transactions. We expect to account for our share of the investment using the equity method.
We expect the acquisition to:
| • | expand our participation in the nuclear fuel value chain. The acquisition is expected to complement our<br>high-quality, tier-one uranium assets and fuel services, including CANDU fuel manufacturing for heavy water reactors with Westinghouse’s global nuclear fuel and plant services platform for light water<br>reactors, which we expect will augment and expand our ability to meet the growing demand for nuclear fuel supplies and services that are reliable and secure; |
|---|---|
| • | be accretive to our cash flow after the closing, and prior to considering new revenue opportunities and to<br>complement our existing business. Based on Westinghouse’s strong long-term customer relationships, the service type model of the Operating Plant Services segment and resulting reliable revenue streams we expect it to generate stable cash flow,<br>to fund its approved annual operating budget and provide quarterly distributions to the partners after the closing; |
| --- | --- |
| • | create new revenue opportunities for us by expanding our ability to satisfy existing and new customer needs. In<br>addition to Westinghouse’s contribution to our financial results, the acquisition is expected to result in up to $50 million in additional revenue for Cameco in the year following the closing of the transaction and to result in additional<br>revenue opportunities for us in the future from new customers and existing customers seeking a fully fabricated fuel supply option; and |
| --- | --- |
| • | maintain our strong balance sheet through a disciplined funding strategy designed to enhance our financial<br>strength. At the same time, we expect to continue to execute on our strategy and provide a platform for further growth, expanding our reach in an industry that has historically performed well during varying macroeconomic environments due to the<br>baseload nature of nuclear power and its strong customer base. |
| --- | --- |
MANAGING OUR RISKS
The proposed acquisition of a beneficial ownership interest in Westinghouse is subject to the risks that are discussed under the heading Caution aboutforward-looking information beginning on page 2. For a further description of the material risks relating to the acquisition, please refer to Risk Factors — Risks Related to the Acquisition in our October 12, 2022, prospectus supplement filed with the U.S. Securities and Exchange Commission and Canadian securities administrators. It is available at www.sec.gov and www.sedar.com.
WESTINGHOUSE NON-GAAP MEASURES
When we announced the proposed acquisition, we had derived the following summary financial information from Westinghouse’s annual and interim consolidated financial statements, which are reported in US dollars and prepared in accordance with US generally accepted accounting principles (GAAP). Since the transaction has not closed and ownership has not transferred, we are unable to update this information. The Westinghouse financial information is not predictive of actual future results. Additionally, the financial information for Westinghouse does not take into account any circumstances or geopolitical or other events occurring after the date it was prepared. We will evaluate the appropriate and required disclosures when the acquisition closes, assuming all regulatory and other approvals are received.
90 CAMECO CORPORATION
Adjusted EBITDA, adjusted free cash flow, adjusted EBITDA margin and adjusted free cash flow margin are measures that do not have a standardized meaning or a consistent basis of calculation under GAAP (non-GAAP measure). These measures are used by Cameco and other users, including our lenders and investors, to assess Westinghouse’s results of operations from a management perspective without regard to its capital structure. We believe that these measures are useful to management, lenders, and investors in assessing the underlying performance of Westinghouse’s ongoing operations and its ability to generate cash flows to fund its cash requirements.
Westinghouse’s adjusted EBITDA is defined as its net income, adjusted for the impact of certain expenses, costs, charges or benefits incurred in such period which are either not indicative of underlying business performance or that impact the ability to assess the operating performance of its business. Westinghouse may realize similar gains or incur similar expenditures in the future. The other measures are defined in the table below.
Adjusted EBITDA, adjusted free cash flow, adjusted EBITDA margin and adjusted free cash flow margin are specified financial measures and should not be considered in isolation or as a substitute for financial information prepared according to GAAP. 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.
The following financial information of Westinghouse was prepared by us at the time of the announced acquisition and was derived from (i) Westinghouse’s annual consolidated financial statements as at and for the years ended December 31, 2019, 2020 and 2021 and (ii) Westinghouse’s interim consolidated financial statements as at and for the six-months ended June 30, 2021 and 2022 which are reported in US dollars and prepared in accordance with US GAAP. The following table provides a reconciliation of Westinghouse’s net income to adjusted EBITDA, adjusted free cash flow, adjusted EBITDA margin and adjusted free cash flow margin for the years ended December 31, 2019, 2020 and 2021 and for the twelve-month period ended June 30, 2022:
| ($US MILLIONS) | LTM ENDED<br>JUNE 30, 2022 | 2021 | 2020 | 2019 | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Net income | **** | 559 | **** | 126 | **** | 42 | **** | 26 | ||||
| Depreciation and amortization | **** | 299 | **** | 303 | **** | 289 | **** | 284 | ||||
| Interest costs (net, including accretion) | **** | 183 | **** | 186 | **** | 221 | **** | 243 | ||||
| Income tax (recovery) | **** | (433 | ) | (17 | ) | **** | 15 | **** | (6 | ) | ||
| Restructuring and acquisition related expenses | **** | 89 | **** | 67 | **** | 70 | **** | 97 | ||||
| Gain (loss) on disposal of fixed assets | **** | (1 | ) | 7 | **** | 5 | **** | (9 | ) | |||
| Non-operating income | **** | (1 | ) | — | **** | (3 | ) | (36 | ) | |||
| Impact of derivative instruments | **** | 12 | **** | 2 | **** | (20 | ) | — | ||||
| Other non-operating items | **** | (7 | ) | 21 | **** | 28 | **** | 13 | ||||
| Adjusted EBITDA | **** | 701 | **** | 695 | **** | 646 | **** | 613 | ||||
| Capital expenditures | **** | 145 | **** | 154 | **** | 133 | **** | 138 | ||||
| Revenue | **** | 3,273 | **** | 3,286 | **** | 3,275 | **** | 3,350 | ||||
| Adjusted free cash flow (adjusted EBITDA - capital expenditures) | **** | 556 | **** | 541 | **** | 513 | **** | 475 | ||||
| Adjusted EBITDA margin (adjusted EBITDA/revenue) | **** | 21 | % | 21 | % | **** | 20 | % | 18 | % | ||
| Adjusted free cash flow margin (adjusted free cash flow/adjustedEBITDA) | **** | 79 | % | 78 | % | **** | 79 | % | 78 | % |
Calculations may not compute due to rounding
The total enterprise purchase price for the acquisition is $7.875 billion (US), which includes an assumption of an estimated $3.4 billion (US) of debt which will remain with Westinghouse, and which is subject to customary purchase price adjustments. The remainder of the purchase price will be paid by approximately $4.5 billion (US) of aggregate cash contributions, our share of which will be approximately $2.2 billion (US).
MANAGEMENT’S DISCUSSION AND ANALYSIS 91
Concurrently with the execution of the acquisition agreement, we secured commitments that provide for a $1 billion (US) bridge loan facility and $600 million (US) in term loans. Following the announcement, we undertook a $650 million (US) bought deal offering of common shares, with an underwriter option to purchase additional shares. The offering closed on October 17, 2022, providing us with gross proceeds of approximately $747.6 million (US) including the underwriters’ exercise of the option to purchase additional shares in full. With the proceeds from the closing of the offering and based on current uncertainty in the global macroeconomic environment and the success we are having in adding new long-term business, at this time, we do not intend to issue additional equity to fund our portion of the purchase price for the Westinghouse acquisition. As of the closing of the bought deal offering, the bridge loan facility was reduced to $280 million (US). The debt facilities will remain undrawn until closing of the acquisition. The bridge facility, if funded, will mature 364 days after the acquisition closing date, and the term loans consisting of two tranches of $300 million (US) each, are expected to mature two years and three years after the acquisition closes.
The acquisition is expected to close in the second half of 2023 and continues to be subject to customary closing conditions and certain regulatory approvals. The final financing is not required until close of the acquisition and will be determined based on market conditions and the expected run rate of our business at that time. We expect a permanent financing mix of capital sources, including cash, debt and equity, designed to preserve our balance sheet and ratings strength, while maintaining healthy liquidity.
Caution about forward-looking information relating to the Westinghouse acquisition
This discussion of our expectations for the Westinghouse acquisition, including sources and uses of financing for the acquisition, timeline for the acquisition, including anticipated closing date, expected benefits, and our intention in respect of not issuing additional equity to fund our portion of the purchase price for the Westinghouse acquisition is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headings Caution about forward-looking information beginning on page 2, and in our October 18, 2022 material change report. The material change report is available at www.sedar.com and www.sec.gov. Actual results and events may be significantly different from what we currently expect.
92 CAMECO CORPORATION
Corporate development
Investment program
Currently, with our extensive portfolio of mineral reserves and resources and our belief that we have ample productive capacity with the ability to expand as the demand for nuclear energy and nuclear fuels grows, our focus is on navigating by our investment-grade rating and returning to our tier-one run rate while aligning our tier-one production with our delivery commitments and market opportunities. We expect that these assets will allow us to meet rising uranium demand with increased production from our best margin operations and will help to mitigate risk in the event of prolonged uncertainty.
Additionally, we are exploring opportunities across the fuel cycle, which align well with our commitment to responsibly and sustainably manage our business and increase our contributions to global climate change solutions. These opportunities include investments such as our recently announced plans to acquire a 49% interest in Westinghouse Electric Company, as well as emerging opportunities such as our investment in Global Laser Enrichment LLC. It also includes the non-binding arrangements we have signed to explore several areas of cooperation to advance the commercialization and deployment of small modular reactors in Canada and around the world.
We continually evaluate investment opportunities within the nuclear fuel cycle that could add to our future supply options, support our customer’s needs, and complement and enhance our business in the nuclear industry. We will make an investment decision when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our stakeholders in a fundamentally stronger position. As such, an investment opportunity is never assessed in isolation. Investments must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described under Our vision, values and strategy, starting on page 23.
MANAGEMENT’S DISCUSSION AND ANALYSIS 93
Mineral reserves and resources
Our mineral reserves and resources are the foundation of our company and fundamental to our success.
We have interests in a number of uranium properties. The tables in this section show the estimates of the proven and probable mineral reserves, and measured, indicated, and inferred mineral resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River/Key Lake, Cigar Lake and Inkai. Mineral reserves and resources are all reported as of December 31, 2022.
We estimate and disclose mineral reserves and resources in five categories, using the definition standards adopted by the Canadian Institute of Mining, Metallurgy and Petroleum Council, and in accordance with National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), developed by the Canadian Securities Administrators. You can find out more about these categories at www.cim.org.
About mineral resources
Mineral resources do not have to demonstrate economic viability but have reasonable prospects for eventual economic extraction. They fall into three categories: measured, indicated and inferred. Our reported mineral resources are exclusive of mineral reserves.
| • | measured and indicated mineral resources can be estimated with sufficient confidence to allow the<br>appropriate application of technical, economic, marketing, legal, environmental, social and governmental factors to support evaluation of the economic viability of the deposit |
|---|---|
| • | measured resources: we can confirm both geological and grade continuity to support detailed mine planning<br> |
| --- | --- |
| • | indicated resources: we can reasonably assume geological and grade continuity to support mine planning<br> |
| --- | --- |
| • | inferred mineral resources are estimated using limited geological evidence and sampling information. We do<br>not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource, but it is reasonably<br>expected that the majority of inferred mineral resources could be upgraded to indicated mineral resources with continued exploration. |
| --- | --- |
Our share of uranium in the following mineral resource tables is based on our respective ownership interests. Reported mineral resources have not demonstrated economic viability.
About mineral reserves
Mineral reserves are the economically mineable part of measured and/or indicated mineral resources demonstrated by at least a preliminary feasibility study. The reference point at which mineral reserves are defined is the point where the ore is delivered to the processing plant, except for ISR operations where the reference point is where the mineralization occurs under the existing or planned wellfield patterns. Mineral reserves fall into two categories:
| • | proven reserves: the economically mineable part of a measured resource for which at least a preliminary<br>feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified with a high degree of confidence |
|---|---|
| • | probable reserves: the economically mineable part of a measured and/or indicated resource for which at<br>least a preliminary feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified with a degree of confidence lower than that applying to proven reserves |
| --- | --- |
For properties where we are the operator, we use current geological models, an average uranium price of $53 (US) per pound U3O8, and current or projected operating costs and mine plans to report our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate. For properties in which Cameco has an interest but is not the operator, we will take reasonable steps to ensure that the reserve and resource estimates that we report are reliable.
Our share of uranium in the mineral reserves table below is based on our respective ownership interests.
94 CAMECO CORPORATION
Changes this year
Our share of proven and probable mineral reserves increased from 464 million pounds U3O8 at the end of 2021, to 469 million pounds at the end of 2022. The change was primarily the result of:
| • | a mineral resource and reserve estimate update at Cigar Lake which added 9 million pounds to proven and<br>probable reserves based on ongoing surface freeze drilling results. |
|---|---|
| • | increased ownership stake at Cigar Lake which added 7 million pounds |
| --- | --- |
partially offset by:
| • | production at Cigar Lake, Inkai and McArthur River, which removed 14 million pounds from our mineral<br>inventory |
|---|
The remaining changes are attributable to other adjustments based on the mineral resource and reserve estimate updates at Cigar Lake and McArthur River.
Our share of measured and indicated mineral resources increased from 447 million pounds U3O8 at the end of 2021, to 451 million pounds at the end of 2022. Our share of inferred mineral resources remains unchanged at 154 million pounds U3O8.
MANAGEMENT’S DISCUSSION AND ANALYSIS 95
Qualified persons
The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:
MCARTHUR RIVER/KEY LAKE
| • | Greg Murdock, general manager, McArthur River, Cameco |
|---|---|
| • | Daley McIntyre, general manager, Key Lake, Cameco |
| --- | --- |
| • | Alain D. Renaud, principal resource geologist, technical services, Cameco |
| --- | --- |
| • | Biman Bharadwaj, principal metallurgist, technical services, Cameco |
| --- | --- |
CIGAR LAKE
| • | Lloyd Rowson, general manager, Cigar Lake, Cameco |
|---|---|
| • | Scott Bishop, director, technical services, Cameco |
| --- | --- |
| • | Alain D. Renaud, principal resource geologist, technical services, Cameco |
| --- | --- |
| • | Biman Bharadwaj, principal metallurgist, technical services, Cameco |
| --- | --- |
INKAI
| • | Alain D. Renaud, principal resource geologist, technical services, Cameco |
|---|---|
| • | Scott Bishop, director, technical services, Cameco |
| --- | --- |
| • | Biman Bharadwaj, principal metallurgist, technical services, Cameco |
| --- | --- |
| • | Sergey Ivanov, deputy director general, technical services, Cameco Kazakhstan LLP |
| --- | --- |
Important information about mineralreserve and resource estimates
Although we have carefully prepared and verified the mineral reserve and resource figures in this document, the figures are estimates, based in part on forward-looking information.
Estimates are based on knowledge, mining experience, analysis of drilling results, the quality of available data and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions, including:
| • | geological interpretation |
|---|---|
| • | extraction plans |
| --- | --- |
| • | commodity prices and currency exchange rates |
| --- | --- |
| • | recovery rates |
| --- | --- |
| • | operating and capital costs |
| --- | --- |
There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 2 for information about forward-looking information.
Please see our mineral reserves and resources section of our most recent annual information form for the specific assumptions, parameters and methods used for McArthur River, Inkai and Cigar Lake mineral reserve and resource estimates.
Importantinformation for US investors
We present information about mineralization, mineral reserves and resources as required by National Instrument 43-101 – Standards of Disclosure for Mineral Projects of the Canadian Securities Administrators (NI 43-101), in accordance with applicable Canadian securities laws. As a foreign private issuer filing reports with the US Securities and Exchange Commission (SEC) under the Multijurisdictional Disclosure System, we are not required to comply with the SEC’s disclosure requirements relating to mining properties. Investors in the United States should be aware that the disclosure requirements of NI 43-101 are different from those under applicable SEC rules, and the information that we present concerning mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for mining companies.
96 CAMECO CORPORATION
Mineral reserves
As of December 31, 2022 (100% – only the shaded column shows our share)
PROVEN AND PROBABLE
(tonnes in thousands; pounds in millions)
| OUR | |||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| SHARE | |||||||||||||||||||||||
| PROVEN | PROBABLE | TOTAL MINERAL RESERVES | RESERVES | ||||||||||||||||||||
| MINING | GRADE | CONTENT | GRADE | CONTENT | GRADE | CONTENT | CONTENT | METALLURGICAL | |||||||||||||||
| PROPERTY | METHOD | TONNES | % U3O8 | (LBS U3O8) | TONNES | % U3O8 | (LBS U3O8) | TONNES | % U3O8 | (LBS U3O8) | (LBS U3O8) | RECOVERY (%) | |||||||||||
| Cigar Lake | UG | 308.9 | 16.25 | 110.7 | 99.1 | 20.19 | 44.1 | 408.0 | 17.21 | 154.8 | **** | 84.4 | 98.8 | ||||||||||
| Key Lake | OP | 61.1 | 0.52 | 0.7 | — | — | — | 61.1 | 0.52 | 0.7 | **** | 0.6 | 95 | ||||||||||
| McArthur River | UG | 2,138.3 | 7.00 | 329.9 | 530.7 | 5.47 | 64.0 | 2,669.0 | 6.70 | 394.0 | **** | 275.0 | 99 | ||||||||||
| Inkai | ISR | 253,647.2 | 0.04 | 218.3 | 71,803.1 | 0.03 | 53.5 | 325,450.3 | 0.04 | 271.8 | **** | 108.7 | 85 | ||||||||||
| Total | **** | 256,155.6 | **** | — | **** | 659.7 | **** | 72,432.9 | **** | — | **** | 161.6 | **** | 328,588.5 | **** | — | **** | 821.3 | **** | 468.8 | **** | — |
(UG – underground, OP – open pit, ISR – in situ recovery)
Note that the estimates in the above table:
| • | use a constant dollar average uranium price of approximately $53 (US) per pound U3O8 |
|---|---|
| • | are based on exchange rates of $1.00 US=$1.26 Cdn and $1.00 US=490 Kazakhstan Tenge |
| --- | --- |
Our estimate of mineral reserves and mineral resources may be positively or negatively affected by the occurrence of one or more of the material risks discussed under the heading Caution about forward-looking information beginning on page 2, as well as certain property-specific risks. See Uranium – Tier-one operations starting on page 70.
Metallurgical recovery
We report mineral reserves as the quantity of contained ore supporting our mining plans and provide an estimate of the metallurgical recovery for each uranium property. The estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process is obtained by multiplying the quantity of contained metal (content) by the planned metallurgical recovery percentage. The content and our share of uranium in the table above are before accounting for estimated metallurgical recovery.
2022 CONSOLIDATED FINANCIAL STATEMENTS AND NOTES 97
Mineral resources
As of December 31, 2022 (100% – only the shaded columns show our share)
MEASURED, INDICATED AND INFERRED
(tonnes in thousands; pounds in millions)
| OUR<br>SHARE | OUR<br>SHARE | ||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| MEASURED RESOURCES (M) | INDICATED RESOURCES (I) | INFERRED RESOURCES | |||||||||||||||||||||||
| TOTAL M+I | TOTAL M+I | INFERRED | |||||||||||||||||||||||
| GRADE | CONTENT | GRADE | CONTENT | CONTENT | CONTENT | GRADE | CONTENT | CONTENT | |||||||||||||||||
| PROPERTY | TONNES | % U3O8 | (LBS U3O8) | TONNES | % U3O8 | (LBS U3O8) | (LBS U3O8) | (LBS U3O8) | TONNES | % U3O8 | (LBS U3O8) | (LBS U3O8) | |||||||||||||
| Cigar Lake | 48.0 | 6.06 | 6.4 | 314.1 | 14.28 | 98.9 | 105.3 | 57.5 | 178.2 | 5.62 | 22.1 | 12.0 | |||||||||||||
| Fox Lake | — | — | — | — | — | — | — | — | 386.7 | 7.99 | 68.1 | 53.3 | |||||||||||||
| Kintyre | — | — | — | 3,897.7 | 0.62 | 53.5 | 53.5 | 53.5 | 517.1 | 0.53 | 6.0 | 6.0 | |||||||||||||
| McArthur River | 74.9 | 2.23 | 3.7 | 63.0 | 2.23 | 3.1 | 6.8 | 4.7 | 38.9 | 2.89 | 2.5 | 1.7 | |||||||||||||
| Millennium | — | — | — | 1,442.6 | 2.39 | 75.9 | 75.9 | 53.0 | 412.4 | 3.19 | 29.0 | 20.2 | |||||||||||||
| Rabbit Lake | — | — | — | 1,836.5 | 0.95 | 38.6 | 38.6 | 38.6 | 2,460.9 | 0.62 | 33.7 | 33.7 | |||||||||||||
| Tamarack | — | — | — | 183.8 | 4.42 | 17.9 | 17.9 | 10.3 | 45.6 | 1.02 | 1.0 | 0.6 | |||||||||||||
| Yeelirrie | 27,172.9 | 0.16 | 95.9 | 12,178.3 | 0.12 | 32.2 | 128.1 | 128.1 | — | — | — | — | |||||||||||||
| Crow Butte | 1,558.1 | 0.19 | 6.6 | 939.3 | 0.35 | 7.3 | 13.9 | 13.9 | 531.4 | 0.16 | 1.8 | 1.8 | |||||||||||||
| Gas Hills - Peach | 687.2 | 0.11 | 1.7 | 3,626.1 | 0.15 | 11.6 | 13.3 | 13.3 | 3,307.5 | 0.08 | 6.0 | 6.0 | |||||||||||||
| Inkai | 87,192.7 | 0.03 | 56.1 | 65,236.0 | 0.02 | 32.9 | 89.1 | 35.6 | 36,165.2 | 0.03 | 23.9 | 9.6 | |||||||||||||
| North Butte - Brown Ranch | 604.2 | 0.08 | 1.1 | 5,530.3 | 0.07 | 8.4 | 9.4 | 9.4 | 294.5 | 0.06 | 0.4 | 0.4 | |||||||||||||
| Ruby Ranch | — | — | — | 2,215.3 | 0.08 | 4.1 | 4.1 | 4.1 | 56.2 | 0.13 | 0.2 | 0.2 | |||||||||||||
| Shirley Basin | 89.2 | 0.15 | 0.3 | 1,638.2 | 0.11 | 4.1 | 4.4 | 4.4 | 508.0 | 0.10 | 1.1 | 1.1 | |||||||||||||
| Smith Ranch - Highland | 3,703.5 | 0.10 | 7.9 | 14,372.3 | 0.05 | 17.0 | 24.9 | 24.9 | 6,861.0 | 0.05 | 7.7 | 7.7 | |||||||||||||
| Total | **** | 121,130.7 | **** | — | **** | 179.7 | **** | 113,473.7 | **** | — | **** | 405.5 | **** | 585.2 | **** | 451.4 | **** | 51,763.7 | **** | — | **** | 203.5 | **** | 154.4 |
Note that mineral resources:
| • | do not include amounts that have been identified as mineral reserves |
|---|---|
| • | do not have demonstrated economic viability |
| --- | --- |
| • | totals may not add due to rounding |
| --- | --- |
98 CAMECO CORPORATION
Additional information
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.
We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements. These estimates affect all of our segments, unless otherwise noted.
Decommissioning and reclamation
In our uranium and fuel services segments, we are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position. See note 16 to the financial statements.
Carryingvalue of assets
We depreciate property, plant and equipment primarily using the unit-of-production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.
We assess the carrying values of property, plant and equipment, intangibles and investments in associates and joint ventures every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital, our ability to economically recover mineral reserves and the impact of geopolitical events. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.
In performing impairment assessments of long-lived assets, assets that cannot be assessed individually are grouped together into the smallest group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Management is required to exercise judgment in identifying these cash generating units.
Taxes
When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation of deferred tax assets, changes in tax laws and our expectations for future results.
We base our estimates of deferred income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record deferred income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses, future market conditions, production levels and intercompany sales. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.
Controls and procedures
We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2022, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.
2022 CONSOLIDATED FINANCIAL STATEMENTS AND NOTES 99
Management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that, while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2022.
There have been no changes in our internal control over financial reporting during the year that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
New standards adopted
A number of amendments to existing standards became effective January 1, 2022, but they did not have an effect on our financial statements.
A number of amendments to existing standards are not yet effective for the year ended December 31, 2022, and have not been applied in preparing these consolidated financial statements. We do not intend to early adopt any of the amendments and do not expect them to have a material impact on our financial statements.
100 CAMECO CORPORATION
EX-99.4
EXHIBIT 99.4
For fiscal years ended December 31, 2022 and December 31, 2021, KPMG LLP and its affiliates billed Cameco Corporation and its subsidiaries the following fees:
| 2022() | % oftotal fees | 2021() | % oftotal fees | |||
|---|---|---|---|---|---|---|
| Audit fees | ||||||
| Cameco^1^ | 82.8 | 83.8 | ||||
| Subsidiaries^2^ | 4.7 | 6.6 | ||||
| Total audit fees | 87.5 | 90.4 | ||||
| Audit-related fees | ||||||
| Translation services^3^ | 4.8 | — | ||||
| Pensions | 1.0 | 1.3 | ||||
| Total audit-related fees | 5.8 | 1.3 | ||||
| Tax fees | ||||||
| Compliance | 0.2 | 0.7 | ||||
| Planning and advice^4^ | 4.1 | 7.6 | ||||
| Total tax fees | 4.3 | 8.3 | ||||
| All other fees | ||||||
| Other non-audit fees^5^ | 2.4 | — | ||||
| Total other non-audit fees | 2.4 | — | ||||
| Total fees | **** | 100.0 | **** | 100.0 |
All values are in US Dollars.
| ^1^ | Includes amounts billed for the audit of Cameco’s annual consolidated financial statements and the review<br>of interim financial statements. |
|---|---|
| ^2^ | Includes amounts billed for the audit of Cameco’s subsidiary financial statements. |
| --- | --- |
| ^3^ | Translation services for 2022 relate to the French translation of the 2021 annual financial statements and<br>management’s discussion and analysis, 2022 Q2 interim financial statements and management’s discussion and analysis, and certain sections of the September 2022 base shelf prospectus. No invoices were issued in 2021 for translation<br>services. |
| --- | --- |
| ^4^ | Includes amounts billed for transfer pricing advisory. |
| --- | --- |
| ^5^ | Includes amounts billed for Cameco’s I-4 Membership.<br> |
| --- | --- |
Pre-Approval Policies and Procedures
As part of Cameco Corporation’s corporate governance practices, under its committee charter, the audit committee is required to pre-approve the audit and non-audit services performed by the external auditors. The audit committee pre-approves the audit and non-audit services up to a maximum specified level of fees. If fees relating to audit and non-audit services are expected to exceed this level or if a type of audit or non-audit service is to be performed that previously has not been pre-approved, then separate pre-approval by Cameco Corporation’s audit committee or audit committee chair, or in the absence of the audit committee chair, the chair of the board, is required. All pre-approvals granted pursuant to the delegated authority must be presented by the member(s) who granted the pre-approvals to the full audit committee at its next meeting. The audit committee has adopted a written policy to provide procedures to implement the foregoing principles.****For each of the years ended December 31, 2022 and 2021, none of Cameco Corporation’s Audit-Related Fees, Tax Fees or All Other Fees made use of the de minimis exception to pre-approval provisions contained in paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X promulgated by the U.S. Securities and Exchange Commission.
EX-99.5
EXHIBIT 99.5
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Cameco Corporation
We consent to the use of:
| • | our report dated February 8, 2023 on the consolidated financial statements of Cameco Corporation (the<br>“Entity”) which comprise the consolidated statements of financial position as of December 31, 2022 and 2021, the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the years<br>in the two-year period ended December 31, 2022 and the related notes (collectively the “consolidated financial statements”), and |
|---|---|
| • | our report dated February 8, 2023 on the effectiveness of the Entity’s internal control over financial<br>reporting as of December 31, 2022 |
| --- | --- |
each of which is included in the Annual Report on Form 40-F of the Entity for the fiscal year ended December 31, 2022.
We also consent to the incorporation by reference of such reports in the Registration Statements (File Nos. 333-11736, 333-06180, 333-139165, and 333-196422) on Form S-8 and on Form F-10 (File No. 333-267625) of the Entity.
/s/ KPMG LLP
Chartered Professional Accountants
March 29, 2023
Saskatoon, Canada
EX-99.6
EXHIBIT 99.6
CERTIFICATION PURSUANT TO RULE 13a-14(a) OR 15d-14(a)
OF THE U.S. SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Tim Gitzel, certify that:
| 1. | I have reviewed this Annual Report on Form 40-F of Cameco Corporation;<br> |
|---|---|
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a<br>material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| --- | --- |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report,<br>fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
| --- | --- |
| 4. | The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure<br>controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
| --- | --- |
| a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be<br>designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being<br>prepared; |
| --- | --- |
| b) | designed such internal control over financial reporting, or caused such internal control over financial<br>reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting<br>principles; |
| --- | --- |
| c) | evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| --- | --- |
| d) | disclosed in this report any change in the issuer’s internal control over financial reporting that<br>occurred during the period covered by the Annual Report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and |
| --- | --- |
| 5. | The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of<br>internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
| --- | --- |
| a) | all significant deficiencies and material weaknesses in the design or operation of internal control over<br>financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and |
| --- | --- |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in<br>the issuer’s internal control over financial reporting. |
| --- | --- |
Date: March 29, 2023
| /s/ Tim Gitzel | |
|---|---|
| Name: | Tim Gitzel |
| Title: | President and Chief Executive Officer<br>(Principal Executive Officer) |
EX-99.7
EXHIBIT 99.7
CERTIFICATION PURSUANT TO RULE 13a-14(a) OR 15d-14(a)
OF THE U.S. SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Grant Isaac, certify that:
| 1. | I have reviewed this Annual Report on Form 40-F of Cameco Corporation;<br> |
|---|---|
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a<br>material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| --- | --- |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report,<br>fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
| --- | --- |
| 4. | The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure<br>controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
| --- | --- |
| a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be<br>designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being<br>prepared; |
| --- | --- |
| b) | designed such internal control over financial reporting, or caused such internal control over financial<br>reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting<br>principles; |
| --- | --- |
| c) | evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| --- | --- |
| d) | disclosed in this report any change in the issuer’s internal control over financial reporting that<br>occurred during the period covered by the Annual Report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and |
| --- | --- |
| 5. | The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of<br>internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
| --- | --- |
| a) | all significant deficiencies and material weaknesses in the design or operation of internal control over<br>financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and |
| --- | --- |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in<br>the issuer’s internal control over financial reporting. |
| --- | --- |
Date: March 29, 2023
| /s/ Grant Isaac | |
|---|---|
| Name: | Grant Isaac |
| Title: | Executive Vice-President and Chief Financial Officer (Principal Financial Officer) |
EX-99.8
EXHIBIT 99.8
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Cameco Corporation (the “Company”) on Form 40-F for the year ended December 31, 2022, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Tim Gitzel, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
| 1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act<br>of 1934; and |
|---|---|
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and<br>results of operations of the Company. |
| --- | --- |
| By: | /s/ Tim Gitzel |
| --- | --- |
| Name: Tim Gitzel | |
| Title: President and Chief Executive Officer |
March 29, 2023
EX-99.9
EXHIBIT 99.9
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Cameco Corporation (the “Company”) on Form 40-F for the year ended December 31, 2022, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Grant Isaac, Executive Vice-President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
| 1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act<br>of 1934; and |
|---|---|
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and<br>results of operations of the Company. |
| --- | --- |
| By: | /s/ Grant Isaac |
| --- | --- |
| Name: Grant Isaac | |
| Title: Executive Vice-President and<br><br><br>Chief Financial Officer |
March 29, 2023
EX-99.10
EXHIBIT 99.10
CONSENT OF EXPERT
Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.
I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:
| (a) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and other nuclear fuel cycle investments – Cigar Lake”, “Operations, projects and other nuclear fuel<br>cycle investments – Uranium – Tier-one operations – Inkai”, “Mineral reserves and resources” and “Governance – Interest of experts” in the Corporation’s Annual<br>Information Form for the year ended December 31, 2022 dated March 29, 2023 for the McArthur River mine/Key Lake mill, Cigar Lake and Inkai operations; and |
|---|---|
| (b) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one<br>operations – Cigar Lake”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Inkai”, and “Mineral reserves and<br>resources” in Management’s Discussion and Analysis for the year ended December 31, 2022 dated February 9, 2023 for the McArthur River mine/Key Lake mill, Cigar Lake and Inkai operations, |
| --- | --- |
(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.
I also hereby consent to the incorporation by reference of such Technical Information in the Registration Statements on Form S-8 (File Nos. 333-11736, 333-06180 and 333-139165) for the Cameco Corporation Stock Option Plan, the Registration Statement on Form S-8 (File No. 333-196422) for the Cameco Corporation Employee Share Ownership Plan and the Registration Statement on Form F-10 (File No. 333-267625).
Sincerely,
| /s/ Alain D. Renaud | |
|---|---|
| Name: | Alain D. Renaud, P. Geo. |
| Title: | Principal Resource Geologist, Technical<br>Services, Cameco Corporation |
Date: March 29, 2023
EX-99.11
EXHIBIT 99.11
CONSENT OF EXPERT
Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.
I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:
| (a) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one<br>operations – Cigar Lake”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Inkai”, “Mineral reserves and resources”<br>and “Governance – Interest of experts” in the Corporation’s Annual Information Form for the year ended December 31, 2022 dated March 29, 2023 for the McArthur River mine/Key Lake mill, Cigar Lake and Inkai operations;<br>and |
|---|---|
| (b) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one<br>operations – Cigar Lake”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Inkai”, and “Mineral reserves and<br>resources” in Management’s Discussion and Analysis for the year ended December 31, 2022 dated February 9, 2023 for the McArthur River mine/Key Lake mill, Cigar Lake and Inkai operations, |
| --- | --- |
(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.
I also hereby consent to the incorporation by reference of such Technical Information in the Registration Statements on Form S-8 (File Nos. 333-11736, 333-06180 and 333-139165) for the Cameco Corporation Stock Option Plan, the Registration Statement on Form S-8 (File No. 333-196422) for the Cameco Corporation Employee Share Ownership Plan and the Registration Statement on Form F-10 (File No. 333-267625).
Sincerely,
| /s/ Biman Bharadwaj | |
|---|---|
| Name: | Biman Bharadwaj, P. Eng. |
| Title: | Principal Metallurgist, Technical Services, Cameco Corporation |
Date: March 29, 2023
EX-99.12
EXHIBIT 99.12
CONSENT OF EXPERT
Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.
I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:
| (a) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Cigar Lake”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Inkai”,<br>“Mineral reserves and resources” and “Governance – Interest of experts” in the Corporation’s Annual Information Form for the year ended December 31, 2022 dated March 29, 2023 for the Cigar Lake and Inkai<br>operations; and |
|---|---|
| (b) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Cigar Lake”, “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Inkai”,<br>and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2022 dated February 9, 2023 for the Cigar Lake and Inkai operations, |
| --- | --- |
(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.
I also hereby consent to the incorporation by reference of such Technical Information in the Registration Statements on Form S-8 (File Nos. 333-11736, 333-06180 and 333-139165) for the Cameco Corporation Stock Option Plan, the Registration Statement on Form S-8 (File No. 333-196422) for the Cameco Corporation Employee Share Ownership Plan and the Registration Statement on Form F-10 (File No. 333-267625).
Sincerely,
| /s/ Scott Bishop | |
|---|---|
| Name: | Scott Bishop, P. Eng. |
| Title: | Director, Technical Services, Cameco Corporation |
Date: March 29, 2023
EX-99.13
EXHIBIT 99.13
CONSENT OF EXPERT
Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.
I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:
| (a) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Cigar Lake”, “Mineral reserves and resources” and “Governance – Interest of experts” in the Corporation’s Annual Information Form for the year ended<br>December 31, 2022 dated March 29, 2023 for the Cigar Lake operation; and |
|---|---|
| (b) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Cigar Lake” and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2023 dated February 9, 2023 for the<br>Cigar Lake operation, |
| --- | --- |
(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.
I also hereby consent to the incorporation by reference of such Technical Information in the Registration Statements on Form S-8 (File Nos. 333-11736, 333-06180 and 333-139165) for the Cameco Corporation Stock Option Plan, the Registration Statement on Form S-8 (File No. 333-196422) for the Cameco Corporation Employee Share Ownership Plan and the Registration Statement on Form F-10 (File No. 333-267625).
Sincerely,
| /s/ Lloyd Rowson | |
|---|---|
| Name: | Lloyd Rowson, P. Eng. |
| Title: | General Manager, Cigar Lake, Cameco Corporation |
Date: March 29, 2023
EX-99.14
EXHIBIT 99.14
CONSENT OF EXPERT
Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.
I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:
| (a) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Mineral reserves and resources” and “Governance – Interest of experts” in the Corporation’s Annual Information Form<br>for the year ended December 31, 2022 dated March 29, 2023 for the McArthur River mine; and |
|---|---|
| (b) | under the headings “Operations and projects – Uranium –<br>Tier-one operations – McArthur River mine/Key Lake mill” and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2022 dated<br>February 9, 2023 for the McArthur River mine, |
| --- | --- |
(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.
I also hereby consent to the incorporation by reference of such Technical Information in the Registration Statements on Form S-8 (File Nos. 333-11736, 333-06180 and 333-139165) for the Cameco Corporation Stock Option Plan, the Registration Statement on Form S-8 (File No. 333-196422) for the Cameco Corporation Employee Share Ownership Plan and the Registration Statement on Form F-10 (File No. 333-267625).
Sincerely,
| /s/ Gregory M. Murdock | |
|---|---|
| Name: | Gregory M. Murdock, P. Eng. |
| Title: | General Manager, McArthur River, Cameco Corporation |
Date: March 29, 2023
EX-99.15
EXHIBIT 99.15
CONSENT OF EXPERT
Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.
I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:
| (a) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Inkai”, “Mineral reserves and resources” and “Governance – Interest of experts” in the Corporation’s Annual Information Form for the year ended<br>December 31, 2022 dated March 29, 2023 for the Inkai operation; and |
|---|---|
| (b) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – Inkai”, and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2022 dated February 9, 2023 for the Inkai<br>operation, |
| --- | --- |
(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.
I also hereby consent to the incorporation by reference of such Technical Information in the Registration Statements on Form S-8 (File Nos. 333-11736, 333-06180 and 333-139165) for the Cameco Corporation Stock Option Plan, the Registration Statement on Form S-8 (File No. 333-196422) for the Cameco Corporation Employee Share Ownership Plan and the Registration Statement on Form F-10 (File No. 333-267625).
Sincerely,
| /s/ Sergey Ivanov | |
|---|---|
| Name: | Sergey Ivanov, P. Geo. |
| Title: | Deputy Director General, Technical Services, Cameco Kazakhstan LLP |
Date: March 29, 2023
EX-99.16
EXHIBIT 99.16
CONSENT OF EXPERT
Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.
I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:
| (a) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Mineral reserves and resources” and “Governance – Interest of experts” in the Corporation’s Annual Information Form<br>for the year ended December 31, 2022 dated March 29, 2023 for the Key Lake mill; and |
|---|---|
| (b) | under the headings “Operations, projects and other nuclear fuel cycle investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill” and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2022 dated<br>February 9, 2023 for the Key Lake mill, |
| --- | --- |
(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.
I also hereby consent to the incorporation by reference of such Technical Information in the Registration Statements on Form S-8 (File Nos. 333-11736, 333-06180 and 333-139165) for the Cameco Corporation Stock Option Plan, the Registration Statement on Form S-8 (File No. 333-196422) for the Cameco Corporation Employee Share Ownership Plan and the Registration Statement on Form F-10 (File No. 333-267625).
Sincerely,
| /s/ Daley McIntyre | |
|---|---|
| Name: | Daley McIntyre, P. Eng. |
| Title: | General Manager, Key Lake, Cameco Corporation |
Date: March 29, 2023