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EXHIBIT 99.1
Cameco Corporation
2023 Annual Information Form
March 22, 2024
Cameco Corporation
2023 Annual information form
March 22, 2024
Contents
| Important information about this document |
1 | |||
| Our business |
6 | |||
| Our vision, values and strategy |
11 | |||
| Operations, projects and investments |
25 | |||
| Uranium – Tier-one operations |
26 | |||
| Uranium – Tier-two operations |
71 | |||
| Uranium – Advanced projects |
73 | |||
| Uranium – Exploration |
74 | |||
| Fuel services |
76 | |||
| Westinghouse Electric Company |
79 | |||
| Other nuclear fuel cycle investments |
86 | |||
| Mineral reserves and resources |
87 | |||
| Our ESG principles and practices |
92 | |||
| The regulatory environment |
96 | |||
| Risks that can affect our business |
107 | |||
| 1 – Operational risks |
107 | |||
| 2 – Financial risks |
114 | |||
| 3 – Governance and compliance risks |
121 | |||
| 4 – Social risks |
123 | |||
| 5 – Environmental risks |
124 | |||
| 6 – Strategic risks |
125 | |||
| Legal proceedings |
134 | |||
| Investor information |
134 | |||
| Governance |
139 | |||
| Appendix A |
144 | |||
Important information about this document
This annual information form (AIF) for the year ended December 31, 2023 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 December 31, 2023 (2023 MD&A), which is available on SEDAR+ (sedarplus.com) and on EDGAR (sec.gov) as an exhibit to our Annual Report on Form 40-F; and
• our audited consolidated financial statements for the year ended December 31, 2023 (2023 financial statements), which are also available on SEDAR+ and on EDGAR as an exhibit to our Annual Report on Form 40-F. |
Throughout this document, the terms we, us, our, the company and Cameco mean Cameco Corporation and its subsidiaries. |
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, 2023, the last day of our most recently completed financial year, and is based on what we knew as of March 15, 2024, except as otherwise stated.
Reporting currency and financial information
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 Westinghouse Electric Company 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). |
| • | It represents our current views and can change significantly. |
| • | It is based on a number of material assumptions, including those we have listed below on pages 4 and 5, which may prove to be incorrect. |
| • | Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review other parts of this document, including Risks that can affect our business starting on page 107, and our 2023 MD&A, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations. |
Forward-looking information is designed to help you understand management’s current views of our near- and longer-term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by Canadian or US securities laws.
| 2023 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 clean-air world |
| • | that 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 long-term value |
| • | 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 and that our investment in enrichment technology, if successful, will allow us to participate in the entire nuclear fuel value chain |
| • | our expectations about 2024 and future global uranium supply, consumption, contracting, demand, geopolitical issues and the market, including the discussion under the headings Market overview and developments and Building a balanced portfolio |
| • | our expectations about 2024 and future consumption of conversion services |
| • | our expectations about 2024 and future global consumption, contracting, demand, geopolitical and market issues relating to Westinghouse Electric Company’s (Westinghouse): fuel fabrication for light water reactors; reactor maintenance and other services; design, engineering, and support for the development of new reactors; and nuclear sustainability services |
| • | our expectations about when future reactors will come online |
| • | 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 exploring SMRs and other emerging opportunities within the fuel cycle |
| • | our expectations about future demand for SMRs |
| • | our expectation that the US Department of Energy (DOE) will make available a portion of its excess uranium inventory over the next two decades |
| • | 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 to deliver significant long-term business value |
| • | our ability to implement and execute our overarching low-carbon transition strategy |
| • | our expectations relating to care and maintenance costs |
| • | our expectations of executing major supply contracts |
| • | 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 commitments, and to increase value throughout these price cycles |
| • | 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 expansion capacity, and carbon reduction targets |
| • | estimates of operating and capital costs and mine life for our tier one uranium operations |
| • | our expectations regarding our licence for Crow Butte |
| • | our ability to successfully negotiate a new collective agreement for the unionized employees at McArthur River |
| • | estimated decommissioning and reclamation costs for uranium properties and fuel services operating sites |
| • | Kazatomprom’s planned production levels and timing for JV Inkai in 2024 |
| • | our mineral reserve and resource estimates |
| • | our expectations that the price of uranium, production costs, and recovery rates will allow us to operate or develop a particular site or sites |
| • | estimates of metallurgical recovery and other production parameters for each uranium property |
| • | production estimates at the McArthur River/Key Lake, Cigar Lake and Inkai operations, and the Port Hope UF6 conversion facility |
| • | our discussion of the ongoing conflict between Russia and Ukraine |
| • | our views on our ability to align our production with market opportunities and our contract portfolio |
| • | our expectation regarding opportunities to improve operational effectiveness and to reduce our impact on the environment, including through the use of digital and automation technologies |
| • | our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our confidence that the courts would reject any attempt by CRA to utilize the same or similar positions for other tax years currently in dispute and our belief that CRA should return the full amount of cash and security that has been paid or otherwise secured by us |
| • | our expectations regarding the amount of security we will need to provide to CRA in connection with the tax debts CRA considers us owing for 2017 |
| 2023 ANNUAL INFORMATION FORM | Page 2 |
| • | 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 |
| • | the discussion of our expectations relating to our recent acquisition of a 49% interest in Westinghouse, including its future prospects, our belief that Westinghouse is well-positioned for long-term growth driven by the expected increase in global demand for nuclear power, our expectation that the acquisition will be transformative and accretive to Cameco, our expectation that the investment will augment the core of our business and offer more solutions to our customers across the nuclear fuel cycle various factors and drivers for Westinghouse’s business segments, our expectation that there will be new opportunities for Westinghouse to compete for and win new business and other matters discussed under the heading Westinghouse Electric Company |
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 a competitor, trade restrictions, geopolitical issues or the impact of a pandemic |
| • | we are adversely affected by changes in currency exchange 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 |
| • | that we may not realize the expected benefits from the Westinghouse 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 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 |
| • | our uranium suppliers or purchasers fail to fulfil their commitments |
| • | our McArthur River or 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 |
| • | 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 expenses, or ultimately prove to be unsuccessful |
| • | the risk that we may become unable to pay future dividends at the expected rate |
| • | our expectations relating to care and maintenance costs prove to be inaccurate |
| • | the risk that we may not be able to refinance our debenture on terms that are as favourable as we expect, or that we may not realize our expected cash flow, or meet our expectations in reducing total debt |
| • | 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 Risks that can affect our business in this AIF and under the heading Managing the risks in our 2023 MD&A |
| 2023 ANNUAL INFORMATION FORM | Page 3 |
| • | 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 |
| • | we are adversely affected by subsurface contamination from current or legacy operations |
| • | necessary permits or approvals from government authorities cannot be obtained or maintained |
| • | we are affected by political risks, including 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 failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, 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), accident or a deterioration 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 re-licensing of existing plants, and the demand for uranium |
| • | government laws, regulations, policies, or decisions that adversely affect us, including tax and trade laws and sanctions on nuclear fuel imports |
| • | the risk that Westinghouse may not be able to meet sales commitments for any reason |
| • | the risk that Westinghouse may not achieve the expected growth or success in its business |
| • | the risk to Westinghouse’s business associated with potential production disruptions, including those related to global supply chain disruptions, global economic uncertainty, political volatility, labour relations issues, and operating risks |
| • | the risk that Westinghouse’s strategies may change, be unsuccessful, or have unanticipated consequences |
| • | the risk that Westinghouse may fail to comply with nuclear licence and quality assurance requirements at its facilities |
| • | the risk that Westinghouse may be delayed in announcing its future financial results |
| • | the risk that Westinghouse may lose protections against liability for nuclear damage, including discontinuation of global nuclear liability regimes and indemnities |
| • | the risk that increased trade barriers may adversely impact Westinghouse’s business |
| • | the risk that Westinghouse may default under its credit facilities, impacting adversely Westinghouse’s ability to fund its ongoing operations and to make distributions |
| • | the risk that liabilities at Westinghouse may exceed our estimates and the discovery of unknown or undisclosed liabilities |
| • | the risk that occupational health and safety issues may arise at Westinghouse’s operations |
| • | the risk that there may be disputes between us and Brookfield regarding our strategic partnership |
| • | the risk that we may default under the governance agreement with Brookfield, including us losing some or all of our interest in Westinghouse |
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 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 |
| • | that no major accident at a nuclear power plant will occur |
| • | the absence of new and adverse government regulations, policies or decisions |
| • | 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 |
| 2023 ANNUAL INFORMATION FORM | Page 4 |
| • | our expectations regarding spot prices and realized prices for uranium |
| • | that the construction of new nuclear power plants and the re-licensing of existing nuclear power plants will not be more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants |
| • | 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 |
| • | 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), governmental or political actions, litigation or arbitration proceedings, cyber-attacks, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, aging infrastructure or other development or operating risks |
| • | 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 |
| • | that we will be successful in our efforts to renew our operating license for Crow Butte |
| • | nuclear power and uranium demand, supply, consumption, long-term contracting, growth in the demand for and global public acceptance of nuclear energy, and prices |
| • | Westinghouse’s ability to generate cash flow and fund its approved annual operating budget and make quarterly distributions to the partners |
| • | our ability to compete for additional business opportunities so as to generate additional revenue for us as a result of the Westinghouse acquisition |
| • | Westinghouse’s production, purchases, sales, deliveries, and costs |
| • | the market conditions and other factors upon which we have based Westinghouse’s future plans and forecasts |
| • | Westinghouse’s ability to mitigate adverse consequences of delays in production and construction |
| • | the success of Westinghouse’s plans and strategies |
| • | that there will not be any significant adverse consequences to Westinghouse’s business resulting from business disruptions, including those relating to supply disruptions, economic or political uncertainty and volatility, labour relation issues, and operating risks |
| • | Westinghouse’s ability to announce future financial results when expected |
| • | Westinghouse will comply with the covenants in its credit agreements |
| • | Westinghouse will comply with nuclear license and quality assurance requirements at its facilities |
| • | Westinghouse maintaining protections against liability for nuclear damage, including continuation of global nuclear liability regimes and indemnities |
| • | that known and unknown liabilities at Westinghouse will not materially exceed our estimates |
| • | the absence of disputes between us and Brookfield regarding our strategic partnership, and that we do not default under the governance agreement with Brookfield |
| • | that we will be able to refinance our senior unsecured debentures, and assumptions regarding our expected cash flow and our ability to reduce total debt |
| 2023 ANNUAL INFORMATION FORM | Page 5 |
Our business
| Our vision is to energize a clean-air world. We have a 35-year proven track record of providing secure and reliable nuclear fuel supplies to a global customer base to generate safe, reliable, and affordable baseload carbon-free energy. Nuclear energy plants around the world use our uranium and fuel services to generate one of the cleanest sources of electricity available today.
Our operations span the nuclear fuel cycle from exploration to fuel services, which include uranium production, refining, UO2 and UF6 conversion services and CANDU fuel manufacturing for heavy water reactors. We have also further enhanced our ability to meet our customers’ growing demand for reliable and secure nuclear fuel supplies, services and technologies by investing in Westinghouse. Westinghouse’s assets are expected to augment the core of our business, providing 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. We also have made an investment in a third-generation enrichment technology, that if successful we expect will allow us to participate in the entire nuclear fuel value chain. |
Cameco Corporation 2121 – 11th Street West Saskatoon, Saskatchewan Canada S7M 1J3 Telephone: 306.956.6200
This is our head office, registered office and principal place of business.
We are publicly listed on the Toronto and New York stock exchanges, and had a total of 2,638 employees at December 31, 2023. |
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. And we are doing so 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.
Business segments
URANIUM
Our uranium production capacity is among the world’s largest. In 2023, we continued to ramp-up to our tier-one production run rate and accounted for 16% of world production. We have controlling ownership of the world’s largest high-grade mineral reserves.
Product
| • | uranium concentrates (U3O8) |
Mineral reserves and resources
Mineral reserves
| • | approximately 485 million pounds proven and probable |
Mineral resources
| • | approximately 409 million pounds measured and indicated |
| • | approximately 153 million pounds inferred |
Tier-one operations
| • | McArthur River and Key Lake, Saskatchewan |
| • | Cigar Lake, Saskatchewan |
| • | Inkai, Kazakhstan |
Tier-two operations
| • | Rabbit Lake, Saskatchewan |
| • | Smith Ranch-Highland, Wyoming |
| • | Crow Butte, Nebraska |
Advanced projects
| • | Millennium, Saskatchewan |
| • | Yeelirrie, Australia |
| • | Kintyre, Australia |
Exploration
| • | focused on North America |
| • | approximately 0.74 million hectares of land |
| 2023 ANNUAL INFORMATION FORM | Page 6 |
FUEL SERVICES
We are an integrated uranium fuel supplier, offering refining, conversion, and fuel manufacturing services.
Products
| • | uranium trioxide (UO3) |
| • | uranium hexafluoride (UF6) for light-water reactors (we have about 21% of world primary conversion capacity) |
| • | uranium dioxide (UO2) for CANDU heavy-water reactors |
| • | fuel bundles, reactor components and monitoring equipment used by CANDU heavy-water reactors |
Operations
| • | Blind River refinery, Ontario (refines uranium concentrates to UO3) |
| • | Port Hope conversion facility, Ontario (converts UO3 to UF6 or UO2) |
| • | Cameco Fuel Manufacturing Inc. (CFM), Ontario (manufactures fuel bundles and reactor components for CANDU heavy-water reactors) |
WESTINGHOUSE ELECTRIC COMPANY (Westinghouse)
In 2023, we completed the acquisition of Westinghouse, in a strategic partnership with Brookfield. We own a 49% interest.
Products
| • | Operating plant services (core business) – Provides outage and maintenance services, engineering support, instrumentation and controls equipment, plant modifications, and components and parts to nuclear reactors |
| • | Nuclear fuel (core business) – designs and manufactures nuclear fuel supplies and services for light water reactors |
| • | New build – designs, develops and procures equipment for new nuclear plant projects |
Operations
| • | Columbia, South Carolina |
(fuel fabrication)
| • | Springfields, United Kingdom |
(fuel fabrication)
| • | Västerås, Sweden |
(fuel fabrication)
For information about the financial performance of our segments for the years ended December 31, 2023 and 2022, see our 2023 MD&A as follows:
| • | uranium – page 61 |
| • | fuel services – page 62 |
| • | Westinghouse – page 63 |
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.
| 2023 ANNUAL INFORMATION FORM | Page 7 |
The nuclear fuel cycle
Our operations and investments span the nuclear fuel cycle, from exploration to fuel manufacturing.
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Mining |
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. |
| • | Underground mining is used if the ore is too deep to make open pit mining economical. Tunnels and shafts provide access to the ore. |
| • | 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 recovered. |
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Mining |
Ore from open pit and underground mines is processed to extract the uranium and package it as a powder typically referred to as uranium ore concentrates (UOC) or yellowcake (U3O8). The leftover processed rock and other solid waste (tailings) is placed in an engineered tailings facility.
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Refining |
Refining removes the impurities from the uranium concentrate and changes its chemical form to uranium trioxide (UO3).
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Conversion |
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 uranium dioxide (UO2).
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Enrichment |
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.
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Fuel manufacturing |
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.
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Generation |
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. Typical activities to ensure the safe and reliable operation of nuclear power plants include overhaul, repair and replacement of system components, testing and calibration of parts, and in-service inspections. Nuclear reactors are refueled every 18 to 24 months.
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.
| 2023 ANNUAL INFORMATION FORM | Page 8 |
Major developments
| 2021 | 2022 | 2023 | ||
| January | January | March | ||
| • 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%.
February
• We announce the Supreme Court of Canada dismissed CRA’s application for leave to appeal the June 26, 2020 decision of the Federal Court of Appeal with respect to the 2003, 2005 and 2006 tax years.
April
• We announce plans to restart production at the Cigar Lake mine.
October
• We file a notice of appeal with the Tax Court of Canada, asking it to order the reversal of 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. |
• We announce plans to transition McArthur River and Key Lake from care and maintenance to planned 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 starting in 2024.
May
• We acquire an additional 4.522% interest in Cigar Lake increasing our interest to 54.547%.
October
• We announce our plans to form a strategic partnership with Brookfield Renewable Partners L.P., together with its institutional partners (Brookfield Renewable), to acquire Westinghouse, a global provider of nuclear services, from Brookfield Renewable. Brookfield Renewable will own a 51% interest and we will own a 49% interest in Westinghouse. We are responsible to contribute approximately $2.2 billion (US) in respect of the acquisition.
• We issue 34,057,250 common shares at a price of $21.95 (US) per share for gross proceeds to us of 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.
November
• We announce that the first pounds of uranium ore from the McArthur River mine have now been milled and packaged at the Key Lake mill, marking the achievement of initial production as these facilities transition back to normal operations. |
• We sign a major supply contract to provide sufficient volumes of natural uranium hexafluoride, or UF6 (consisting of uranium and conversion services), to meet Ukraine’s full nuclear fuel needs through 2035.
• CRA has issued revised assessments for the 2007 through 2013 tax years, which resulted in a refund of $297 million, consisting of $86 million in cash and $211 million in letters of credit, which were returned in the second quarter. CRA continues to hold $483 million that we have remitted or secured based on prior reassessments CRA had issued in our longstanding tax dispute.
November
• We announce that the acquisition of Westinghouse in a strategic partnership with Brookfield Renewable closed on November 7, 2023. |
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| 2023 ANNUAL INFORMATION FORM | Page 9 |
Updated 2024 production plan for McArthur Rive/Key Lake and Cigar Lake
In February 2024, we announced our plan 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.
We also plan to begin the work necessary to extend the mine life at Cigar Lake to 2036. In addition, at McArthur River/Key Lake, we plan to undertake an evaluation of the work and investment necessary to expand production up to its annual licensed capacity of 25 million pounds (100% basis), which we expect will allow us to take advantage of this opportunity when the time is right.
Update for 2024 production at Inkai
Based on Kazatomprom (KAP)’s announcement on February 1, 2024, production in Kazakhstan is expected to remain approximately 20% below the level stipulated in subsoil use agreements, primarily due to the sulfuric acid shortage in the country and delays in development of new deposits.
Our current target for production at Inkai in 2024 is 8.3 million pounds of U3O8 (100% basis). However, this target is tentative and contingent upon receipt of sufficient quantities of sulfuric acid. In addition, the allocation of such production between JV Inkai participants is currently under discussion by Cameco and KAP.
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 |
| • | Eldorado Nuclear Limited (uranium mining, refining and conversion operations) (now Canada Eldor Inc.) |
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 Corporation Reorganization Act, as amended, and are described on pages 135 and 136.
We have made the following amendments to our articles:
| 2002 | • increased the maximum share ownership for individual non-residents to 15% from 5%
• increased the 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 as permitted by the Canada Business Corporations Act, subject to certain limitations
• eliminated the requirement for the chair of the board to be ordinarily resident in the province of Saskatchewan |
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We have one main subsidiary:
| • | Cameco Europe Ltd., a Swiss company that we have 100% ownership of through subsidiaries |
At January 1, 2024, we do not have any other subsidiary that is material, either individually or collectively.
For more information
You can find more information about Cameco on SEDAR+ (sedarplus.com), EDGAR (sec.gov) and on our website (cameco.com).
See our most recent management proxy circular for additional information, including how 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 9, 2024 annual meeting of shareholders to be available on April 5, 2024.
See our 2023 financial statements and 2023 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 greenhouse gas (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 corresponding commitment to limit global temperature rise to less than 2°C. 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, baseload 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 35 years, we have been delivering our products responsibly. Building on that strong foundation, we remain committed to our efforts to reduce our own, already low, GHG 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, 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 |
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, focused on taking advantage of the near-, medium-, and long-term growth occurring in our industry. We provide nuclear fuel and nuclear power products, services, and technologies across the fuel cycle, augmented by our investment in Westinghouse, that support the generation of clean, reliable, secure, and affordable energy. Our strategy is set within the context of what we believe is a transitioning market
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environment. Increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are driving a global focus on tripling nuclear power capacity by 2050, which is 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 contracting framework |
| • | profitably producing from our tier-one assets and aligning our production decisions in all segments of the fuel cycle with contracted demand and customer needs |
| • | being financially disciplined to allow us to: |
| • | execute our strategy |
| • | invest in new opportunities that are expected to add long-term value |
| • | self-manage risk |
| • | exploring other emerging opportunities within the nuclear power value chain, which align with our commitment to manage our business responsibly and sustainably, contribute to decarbonization, and help to provide secure and affordable energy |
We continually evaluate investment opportunities within the nuclear fuel value chain, which align well with our commitment to manage our business responsibly and sustainably, increase our contributions to decarbonization and help provide energy security. Expanding our participation in the fuel cycle is expected to complement our tier-one uranium and fuel services assets, creating new revenue opportunities, and it enhances our ability to meet the increasing needs of existing and new customers for secure, reliable nuclear fuel supplies, services and technologies.
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.
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 2023 MD&A under Capital Allocation – Focus on Value, starting on page 30.
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 2023 MD&A under Our vision, value and strategy – Strategy, starting on page 23.
Market overview and developments
A market in transition
In 2023, geopolitical uncertainty and heightened concerns about energy security and climate change continued to improve the demand and supply fundamentals for the nuclear power industry and the fuel cycle that is required to support it. Increasingly, countries and companies around the globe are recognizing the critical role nuclear power must play in providing clean and secure baseload power. This growing support has led to a rise in demand as reactors are being saved from earlier retirement, 10- and 20-year life extensions are being sought and approved for existing reactor fleets in several countries, and numerous commitments and plans are being made for the construction of new nuclear generating capacity. In addition, there is increasing interest in small modular reactors (SMR), including smaller versions of existing technology and advanced technology designs, which are expected to add to demand in the decades to come, with several projects already underway.
While demand continues to increase, future supply is not keeping pace. Heightened supply risk caused by growing geopolitical uncertainty, shrinking secondary supplies and a lack of investment in new capacity over the past decade has motivated utilities to evaluate their near-, mid-and long-term nuclear fuel supply chains. The uncertainty about where nuclear fuel supplies will come from to satisfy growing demand has led to increased long-term contracting activity and in 2023, about 160 million pounds of uranium was placed under long-term contracts by utilities. While it is the highest annual volume contracted since 2012, it remains below replacement rate and includes our contract with Ukraine, which alone accounted for about 30 million of those pounds. Prices across the nuclear fuel cycle continued to rise in 2023, with spot enrichment prices up 38%, conversion prices continuing to achieve record highs, uranium spot prices more than doubling from around $48 (US) per pound at the end
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of 2022 to $100 (US) per pound at the end of January 2024, after peaking at $106 (US) per pound earlier in the month, and the long-term price for uranium increasing about 38% over the same period. We expect there will be continued competition to secure uranium, conversion services and enrichment services under long-term contracts with proven producers and suppliers who have a diversified portfolio of assets in geopolitically attractive jurisdictions, with strong environmental, social and governance (ESG) performance, and on terms that help ensure a reliable supply is available to satisfy demand.
Durable demand growth
The benefits of nuclear energy have come clearly into focus, supporting a level of durability of demand that, 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 in energy markets that is causing countries to reexamine how they plan to address their energy needs. Net-zero carbon targets are turning global attention to a triple challenge. First, about one-third of the global population must be lifted out of energy poverty by improving access to clean and reliable baseload electricity. Second, approximately 80% of the current global electricity grids that run on carbon-emitting sources of thermal power must be replaced with a clean, reliable alternative. And finally, global power grids must grow by electrifying industries, such as private and commercial transportation, and home and industrial heating, which today are largely powered with carbon-emitting sources of thermal energy. Additionally, geopolitical uncertainty has deepened 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 and energy security goals. The growth in demand is not just long-term and in the form of new builds, but medium-term in the form of reactor life extensions, and near-term with early reactor retirement plans being deferred or cancelled and new markets continuing to emerge. And, we are seeing even more long-term momentum building with the development of SMRs, where the use case extends beyond just power generation and numerous companies and countries are pursuing projects.
Demand and energy policy highlights
| • | In September, the World Nuclear Association released its biennial Global Nuclear Fuel Report which provides scenarios for demand and supply availability across the fuel supply chain through 2040. This included a robust demand outlook showing global nuclear generating capacity increasing to 686 GWe by 2040 in the Reference Scenario, an average annual growth rate of 3.6%, compared to 2.6% in the 2021 report. This improvement was driven by improved government support, life extensions, new builds and importantly, that starting in the 2030s, the deployment of SMRs is forecasted to contribute to capacity growth. Additional key themes include assumed reductions to secondary supply and decreased availability of mobile inventories, along with the need for a growing volume of future uranium supply requiring higher incentive pricing to balance the market after 2030. |
| • | At the 28th annual Conference of Parties (COP28), the 2023 United Nations Climate Change Conference held in the United Arab Emirates, 22 countries (now 28) launched a declaration to triple nuclear energy capacity by 2050. For the first time at the conference, nuclear energy was recognized alongside other low-emissions technologies for the key role it must play in reaching global net-zero GHG emissions by 2050. In addition, the inaugural global stocktake was introduced at COP28, a process where countries and stakeholders can provide an update every five years to track the world’s progress toward the Paris Agreement targets. In 2023, the initiative concluded that more action is required, as emissions continue to rise and put 2030 targets at risk, reinforcing that in order to achieve net zero by 2050, the world needs “absolute economy-wide emission reduction targets”, which were estimated at a cost of “trillions of dollars”. |
| • | China Nuclear Energy Association published the “China Nuclear Energy Development Report 2023” in April, which highlighted China’s continuing growth. According to the report, the country is expected to lead the world in installed nuclear capacity with 110 GWe expected by 2030, rising to 150 GWe expected by 2035, and plans to build over 90% of their major nuclear power reactors domestically. Additionally, a proposal drafted by 15 Chinese national policy advisors was submitted to the government advocating for the development of new nuclear power plants at inland sites, which are now being considered following the end of a post-Fukushima moratorium on proposed inland nuclear power plants. |
| • | In Japan, Takahama unit 2 restarted in September, becoming the country’s 12th reactor to restart since Fukushima. Onagawa unit 2 and Shimane unit 2 are expected to restart in 2024. In November, the Nuclear Regulation Authority approved 20-year life extensions (beyond 40 years) for Sendai units 1 and 2; additionally, Takahama units 3 and 4 are expected to receive similar life extensions, pending generator work in 2026 and 2027. In addition, Japan enacted a bill in May allowing nuclear reactors to operate beyond the 60-year limit. |
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| • | In South Korea, Korea Hydro and Nuclear Power (KHNP) announced in September that they successfully completed fuel loading at Shin Hanul unit 2, a new 1,400 MWe APR-1400 pressurized water reactor (PWR) unit. This followed an announcement from the Ministry of Industry and Energy that Shin Hanul units 3 and 4 would be completed by the end of 2024. Additionally, to help achieve the plans set out in their 10th Basic Plan for Electricity Supply and Demand 2030, which targets more than 30% of its power supply to come from nuclear, the Ministry confirmed a review of the need for new nuclear power plants was underway. |
| • | In India, the first domestically designed 700 MWe pressurized heavy water reactor, Kakrapar unit 3, reached full operating capacity in August. Three more units of the same design are expected to come online in the next few years. The country is targeting an expansion of nuclear generating capacity to 22.5 GWe by 2031. |
| • | In February, the European Nuclear Alliance was launched. Led by France, the initiative commits 11 European countries to cooperate across the nuclear fuel supply chain, and to promote new nuclear generation projects and technologies, including the advancement of SMRs. Throughout 2023, the alliance expanded and now includes a commitment from 16 European countries that will prepare a roadmap to develop an integrated European nuclear industry and target 150 GWe of nuclear power by 2050. |
| • | In France, plans were advanced to relaunch the country’s reactor construction program: the government committed to life extensions with a proposed “industrial build” program that initially includes six new European Pressurized Reactors (EPR), as well as eight additional EPRs in the future. Électricité de France filed an application to build the first pair of 1,650 MWe EPRs with construction scheduled to begin in 2028. |
| • | In January 2024, the United Kingdom (UK) announced that they are seeking to quadruple their nuclear power output by 2050. Under the “Civil Nuclear Roadmap”, the UK will invest into developing new advanced nuclear fuel, new regulations, and a new nuclear reactor. |
| • | In June, Sweden’s parliament adopted a new energy target, changing its focus to “100% fossil-free” electricity as opposed to the previously stated focus of “100% renewable”. In August, the government announced a target to further expand the role of nuclear power and in November, announced its intention to build up to 2,500 MWe of new nuclear power capacity by 2035, and up to 10 new reactors by 2045, backed by an offer of loan guarantees. |
| • | In Belgium, the government and nuclear operator ENGIE reached an agreement following prolonged negotiations to extend the lifespans of the Doel unit 4 and Tihange unit 3 reactors by 10 years, with each now expected to operate until 2035. |
| • | In Bulgaria, the government issued its 30-year energy strategy to 2053, which envisions the construction of four new nuclear reactor units. In December, parliament approved a government proposal to inject up to 1.5 billion levs ($(US) 838 million) into the state-owned Kozloduy Nuclear Power Plant to fund the planned construction of the first of two proposed reactors using Westinghouse’s AP1000® technology. |
| • | In Poland, the government adopted a resolution committing to finance the country’s first nuclear power plant. The funds will go to Polish utility Polskie Elektrownie Jadrowe, which signed a contract with Westinghouse for multiple AP1000 reactors in February of 2023. |
| • | In the US, Vogtle unit 3 entered commercial service on July 31, after becoming the first Westinghouse AP1000 reactor in the US to successfully connect to the electrical grid. Vogtle unit 4 is expected to begin operating in the second quarter of 2024. |
| • | Throughout 2023, many US states expressed local support for nuclear: Ohio, Virginia, Kentucky, and Tennessee all began creating state-level advisory authorities to promote, research and develop nuclear power technologies, and Michigan formed a new Nuclear Caucus to support the reopening of the Palisades nuclear power plant, and also approved extending operations at the Monticello nuclear power plant through 2040. |
| • | In Canada, provincial support for nuclear increased in 2023. New Brunswick Power signed a three-year contract with Ontario Power Generation (OPG) to enhance the operational performance of the Point Lepreau nuclear power plant. In Ontario, the Minister of Energy announced support to advance the long-term planning required to explore nuclear expansion options for Bruce Power, outlining the need for nearly 18 GWe in new nuclear capacity to help the province reach its electrification and net-zero goals. Additionally, in Saskatchewan, Crown Investments Corporation provided around $479,000 to help local firms build small, advanced, and micro reactors supply chain capacity, while the Alberta government announced plans to invest around $7 million to study SMRs. |
| • | In January 2024, OPG announced plans to proceed with the refurbishment of the Pickering Nuclear Generating Station’s “B” units (units 5, 6, 7 and 8). Once the project is completed in the mid-2030s, Pickering would produce a total of 2 GWe of electricity, to help meet increasing electricity demand and fuel the province’s economic growth. |
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According to the International Atomic Energy Agency (IAEA), globally there are currently 438 operable reactors and 58 reactors under construction. Several nations are appreciating the clean energy and energy security benefits of nuclear power and have reaffirmed their commitment with plans underway to support existing reactor units and review policies to encourage more nuclear generation. 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 are therefore eligible for access to low-cost financing. In Canada, the government revised the Canada Green Bond Framework to include nuclear energy projects. In some countries where phase-out policies have been in place, policy reversals and decisions have been made to temporarily keep reactors running, with public opinion polls showing increasing support. With a number of reactor construction projects recently approved and many more planned, demand for uranium continues to improve. There is growing recognition of the role nuclear must play in providing safe, affordable, carbon-free baseload electricity to achieve a low-carbon economy, while being a reliable energy source that helps countries move away from Russian energy supply.
Supply uncertainty
Geopolitical uncertainty remained the most notable factor impacting security of supply in 2023. Driven by the Russian invasion of Ukraine, and more recently, the coup d’état in Niger, many governments and utilities are re-examining supply chains and procurement strategies that rely on nuclear fuel supplies from these jurisdictions. In addition, sanctions on Russia and Niger, government restrictions, and restrictions on and cancellations of some cargo insurance coverages continue to create transportation and supply chain risks for nuclear fuel supplies coming out of Central Asia. There are also transportation risks to material being shipped from Australia to Europe as a result of the conflict in the Middle East. Despite the recent increase in market prices, the deepening geopolitical uncertainty and years of underinvestment in new uranium and fuel cycle service capacities has shifted risk from producers to utilities.
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Supply and trade policy highlights
| • | Sprott Physical Uranium Trust (SPUT) purchased about 4 million pounds U3O8 in 2023, bringing total purchases since inception to over 45 million pounds U3O8 and increasing the total net asset value to around $(US)7 billion. Volatility in equity markets has impacted SPUT’s valuation (discount or premium to its net asset value) and therefore its ability to raise funds to purchase uranium. |
| • | In June, KAP announced plans to start production at a new uranium deposit, Inkai 3 (100% owned by KAP). KAP expects approval of a Subsoil Use Agreement (SSUA) to produce 10.4 million pounds U3O8 annually for 25 years from Inkai 3’s uranium resources of about 216 million pounds U3O8. |
| • | In September, KAP had restated its plan to increase production in 2024 to 90% of SSUAs and announced a ramp up to 100% of SSUAs in 2025, though the company also warned that geopolitical uncertainty, global supply chain issues, and inflationary pressure could create challenges. On January 12, 2024, KAP announced that it had faced challenges in completing the development required to achieve the planned 2024 production increase, and that it expected to lower its 2024 uranium production guidance due to limited availability of sulfuric acid and delays in the construction and development of new assets, including Budenovskoye 6 and 7. On February 1, 2024, KAP rescinded its 2024 target due to the shortage of sulfuric acid and construction delays in 2023, and they now plan to remain about 20% below SSUAs, expecting to produce between 55 million and 59 million pounds U3O8 in 2024 (previously 65 million to 66 million pounds U3O8). KAP also warned that if the acid, supply chain and construction issues persist throughout 2024, the company’s 2025 plan to increase production to 100% of SSUAs (79 million to 82 million pounds U3O8) may also be affected. |
| • | In April, five of the G7 countries (Canada, France, Japan, UK, and US), entered into a civil nuclear fuel security agreement that attempts to reduce Russia’s influence in the global nuclear fuel supply chain. |
| • | In December, Urenco announced its decision to expand enrichment capacity at their facility in Almelo, Netherlands, increasing capacity by 15% or approximately 750,000 separative work units (SWU), by 2027. This followed a prior announcement of plans to expand enrichment capacity at its Urenco USA site, increasing capacity there by 15% or approximately 700,000 SWU, by 2025. |
| • | In October, Orano announced a planned enrichment capacity extension project at Georges Besse 2. The project, forecasted to cost €1.7 billion, seeks to increase capacity by over 30% or approximately 2.5 million SWU, beginning in 2028. |
| • | In July, ConverDyn announced the restart of Honeywell’s Metropolis uranium conversion facility. The restart plan had been delayed by a safety equipment failure in June, resulting in a special inspection by the US Nuclear Regulatory Commission (NRC). The facility restarted production in July 2023. |
| • | In July, a coup d’état in Niger resulted in a group of military officers removing President Mohamed Bazoum and seizing power. All exports of uranium and gold to France were suspended and in September, Orano stated that it had halted uranium processing operations at the company’s majority-owned SOMAIR (Arlit) project in Niger due to logistical complications caused by international sanctions. This resulted in 2023 production dropping to 3.9 million pounds U3O8, compared to around 5.2 million pounds U3O8 in 2022. |
| • | In December, the US House of Representatives passed the Prohibiting Russian Uranium Impacts Act. The act proposes to prohibit the import of Russian low-enriched uranium (LEU) into the US but includes waivers that allow the import of LEU from Russia if the US Energy Secretary determines no alternative source can be procured, or if the shipments are of national interest. The waivers would gradually reduce and eliminate Russian uranium imports by 2028. The bill is awaiting further action after it was blocked by the US Senate on grounds unrelated to the bill itself. Separately, the US Senate Energy and Natural Resources Committee passed the Nuclear Fuel Security Act of 2023, which directs the Department of Energy to create a “Nuclear Fuel Security Program” and strengthen the US nuclear fuel supply chain, including new LEU and high-assay low-enriched uranium (HALEU) capacity, though no new funding has yet been appropriated. Finally, a Supplemental Funding Bill is progressing through Congress and includes roughly $111 billion (US) for national security measures, including a provision for $2.72 billion (US) to be allocated to a new “American Energy Independence Fund”, which would acquire non-Russian LEU and HALEU, subject to the ban on Russian imports becoming law. |
Long-term contracting creates full-cycle value for 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
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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. 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.
UxC reports that over the last five years approximately 510 million pounds U3O8 equivalent have been locked-up in the long-term market, while approximately 780 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.
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UxC estimates that cumulative uncovered requirements are about 2.2 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, geopolitical uncertainty 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 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 sales, we will compete for customer 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 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 committed sales. |
| • | As we build our portfolio of long-term contracts, we decide how to best source material to satisfy that 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. |
| • | We do not intend to build an inventory of excess uranium. Excess inventory serves to contribute to the sense that uranium is abundant and creates an overhang on the market, and it ties up working capital on our balance sheet. |
| • | Depending on the timing and volume of our production, purchase commitments, and our inventory volumes, 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 supply we expect to come from our annual production and our long-term 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 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, including future development projects, 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.
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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 generally 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 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 for uranium: 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 generally set a month or more prior to 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 established 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. Demand may come in the form of off-market negotiations or through on-market requests for proposals. 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. However, we believe our customers expect prices to rise and prefer to lock-in today’s prices, with a fixed-price mechanism.
| 2023 ANNUAL INFORMATION FORM | Page 19 |
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 adjusting our contracts in a manner that allow us to maintain our customer relationships and is mutually beneficial.
Contract portfolio status
We have executed contracts to sell approximately 205 million pounds of U3O8 with 37 customers worldwide in our uranium segment, and over 75 million kilograms as UF6 conversion with 33 customers worldwide in our fuel services segment.
Customers – U3O8:
Five largest customers account for 62% of commitments
Customers – UF6 conversion:
Five largest customers account for 64% 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 |
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| • | 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 the uranium market is in transition, driven by the growing demand for nuclear energy and the increasing recognition that it is essential to the clean-energy transition and to energy security. As the market continues to transition, we expect to continue placing our uranium under long-term contracts and 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 plan to produce 18 million pounds (100% basis) at McArthur River/Key Lake and Cigar Lake in 2024. Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain approximately 20% below the level stipulated in subsoil use agreements, primarily due to the sulfuric acid shortage in the country and delays in development of new deposits. Our current target for production at Inkai in 2024 is 8.3 million pounds U3O8 (100% basis). However, this target is tentative and contingent upon receipt of sufficient quantities of sulfuric acid. In addition, the allocation of such production between the JV Inkai participants is currently under discussion by Cameco and KAP. We also plan to begin the work necessary to extend the mine life at Cigar Lake. In addition, we plan to undertake the evaluation of the work and investment necessary to expand production at McArthur River/Key Lake up to its annual licensed capacity of 25 million pounds, which we expect will allow us to take advantage of this opportunity when the time is right.
Our production decisions will continue to be aligned with market opportunities 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 uranium production plans, we plan to produce 12,000 tonnes at our Port Hope UF6 conversion facility in 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 production plans for McArthur River/Key Lake and Cigar Lake are expected to generate strong financial performance by allowing us to source more of our committed sales from the lower cost produced pounds. 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. 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.
| 2023 ANNUAL INFORMATION FORM | Page 21 |
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 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 2023 financial results by segment – Uranium starting on page 61 of our 2023 MD&A for more information. In 2024, 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 continued efforts to ramp up to planned production at McArthur River/Key Lake.
Operating costs in our fuel services segment are mainly fixed. In 2023, labour accounted for about 56% of the total. The largest variable operating cost is for anhydrous hydrogen fluoride, followed by zirconium, 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 and operational readiness costs
In 2024, 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. Production at 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 of our share of material from Inkai, purchases under long-term contracts, purchases we make on the spot market and product loans. In 2024, we expect 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 if we are unable to source uranium as planned, and we are required to purchase uranium at prices that differ from our cost of inventory.
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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 significant 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 acquisition of a 49% interest in 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 to generate strong financial performance, 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. Current prices and contracting activity are supporting the restart of some assets, however, the market has yet to incentivise the investment in new supply necessary to meet the anticipated growth in uranium requirements.
We estimate world mine production in 2023 was about 140 million pounds U3O8, up from 129 million pounds in 2022:
| • | Over 80% of estimated world production was sourced from four countries: Kazakhstan (39%), Canada (21%), Namibia (11%) and Australia (9%). |
| • | About 80% of estimated world production was attributable to five producers. Cameco accounted for approximately 16% (22 million pounds) of estimated world production. |
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 predictable quantities. |
| • | The Russian government also holds substantial volumes of nuclear fuel inventory largely in the form of depleted uranium, but overall, their contribution to secondary supplies has reduced significantly since the end of the Highly Enriched Uranium (HEU) Agreement between the Russian and United States governments. |
| • | Utilities, mostly in Europe and some in Japan and Russia, use reprocessed uranium and plutonium from used reactor fuel. |
| • | Re-enriched depleted uranium tails and uranium from underfeeding are also generated when there is excess enrichment capacity. |
| 2023 ANNUAL INFORMATION FORM | Page 23 |
Uranium from US inventories
Historically, the US Department of Energy (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.
The DOE’s DU inventory may become 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.
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 the Prohibiting Russian Uranium Imports Act was passed by the United States House of Representatives in December 2023 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 13% of its supply of uranium concentrates, 25% of conversion supply, and 37% 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. No contracts were awarded in 2023.
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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.
Operations, projects and investments
Uranium
| Tier-one operations |
||||
| McArthur River mine/Key Lake mill |
26 | |||
| Cigar Lake |
41 | |||
| Inkai |
56 | |||
| Tier-two operations |
||||
| Rabbit Lake |
71 | |||
| US ISR Operations |
72 | |||
| Advanced projects |
||||
| Millennium |
73 | |||
| Yeelirrie |
74 | |||
| Kintyre |
74 | |||
| Exploration |
74 |
Fuel services
| Refining, conversion and fuel manufacturing |
||||
| Blind River Refinery |
77 | |||
| Port Hope Conversion Services |
77 | |||
| Cameco Fuel Manufacturing Inc. |
78 |
Westinghouse
| Core business |
82 | |||
| New build |
84 |
Other nuclear fuel cycle investments
| Global Laser Enrichment (GLE) |
86 |
| 2023 ANNUAL INFORMATION FORM | Page 25 |
Uranium production
| Cameco’s share (million lbs U3O8) |
2022 | 2023 | 2024 Plan | |||||||||
| McArthur River/Key Lake |
0.8 | 1 | 9.4 | 1 | 12.6 | 1 | ||||||
| Cigar Lake |
9.6 | 2 | 8.2 | 2 | 9.8 | 2 | ||||||
| Rabbit Lake |
— | 3 | — | 3 | — | 3 | ||||||
| US ISR Operations |
— | 3 | — | 3 | — | 3 | ||||||
|
|
|
|
|
|
|
|||||||
| Total |
10.4 | 17.6 | 22.4 | |||||||||
|
|
|
|
|
|
|
|||||||
| 1 | The McArthur River/Key Lake operations restarted production in November 2022. In 2023, production continued to ramp up and all remaining operational activities, including mine development and underground exploration were restarted. |
| 2 | At Cigar Lake, productivity in 2023 was impacted as we completed development and commissioning activities in the first quarter and achieved first production from a new mining area. We had expected to recover from these delays in the second half of the year. However, in the third quarter, we determined maintenance work was required on one of the underground circuits, which had not been planned. The additional time required to complete this work did not allow for the delayed production volumes to be recovered prior to year-end. |
| 3 | The Rabbit Lake operation remains in a state of care and maintenance, and we are no longer developing new wellfields at US ISR operations. |
Due to equity accounting, our share of production from Inkai is shown as a purchase. Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain approximately 20% below the level stipulated in subsoil use agreements, primarily due to the sulfuric acid shortage in the country and delays in development of new deposits. Our current target for production at Inkai in 2024 is 8.3 million pounds of U3O8 (100% basis). However, this target is tentative and contingent upon receipt of sufficient quantities of sulfuric acid. In addition, the allocation of such production between the JV Inkai participants is currently under discussion by Cameco and KAP. We received our share of JV Inkai’s 2023 production.
Uranium – Tier-one operations
McArthur River mine / Key Lake mill
|
2023 Production (our share)
9.4M lbs
2024 Production Outlook (our share)
12.6M lbs
Estimated Reserves (our share)
265.6M 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+ (sedarplus.com) or from EDGAR (sec.gov).
| 2023 ANNUAL INFORMATION FORM | Page 26 |
| 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 | 265.6 million pounds (proven and probable), average grade U3O8: 6.72% | |||
| Estimated resources | 4.9 million pounds (measured and indicated), average grade U3O8: 2.28% | |||
| 1.7 million pounds (inferred), average grade U3O8: 2.90% | ||||
| Licensed capacity | Mine and mill: 25.0 million pounds per year | |||
| Licence term | Through October 2043 | |||
| Total packaged production: | 2000 to 2023 | 340.0 million pounds (McArthur River/Key Lake) (100% basis) | ||
| 1983 to 2002 | 209.8 million pounds (Key Lake) (100% basis) | |||
| 2023 production | 9.4 million pounds (13.5 million pounds on 100% basis) | |||
| 2024 production outlook | 12.6 million pounds (18.0 million pounds on 100% basis) | |||
| Estimated decommissioning cost | $50.6 million – McArthur River (100% basis)1 | |||
| $276.7 million – Key Lake (100% basis)1 | ||||
All values shown, including reserves and resources, represent our share only, unless indicated.
| 1 | These amounts represent the submitted, but not yet approved, Preliminary Decommissioning Plan (PDP) and Preliminary Decommissioning Cost Estimate (PDCE) values. |
Business structure
| McArthur River is owned by a joint venture (MRJV) between two companies: |
Key Lake is owned by a joint venture between 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 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
• SMDC becomes the operator
• Active surface exploration begins
• Between 1980 and 1988 SMDC reduces its interest to 43.991% |
|
| 1988 | • Eldorado Resources Limited merges with SMDC to form Cameco
• We become the operator
• Deposit discovered by surface drilling |
|
| 1988-1992 | • Surface drilling reveals significant mineralization of potentially economic 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 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 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), increasing our interest to 83.766% • We sell half of the shares of UEM to Orano, reducing our interest to 69.805%, and increasing Orano’s to 30.195% |
|
| 2023 ANNUAL INFORMATION FORM | Page 27 |
| 1999 | • Federal authorities issue the operating licence and provincial authorities give operating approval, and mining begins in December |
|
| 2003 | • Production is temporarily suspended in April because of a water inflow
• Mining resumes in July |
|
| 2009 | • UEM distributes equally to its shareholders:
• its 27.922% interest in the McArthur River joint venture, giving us a 69.805% direct interest, and Orano a 30.195% direct interest
• its 33.333% interest in the Key Lake joint venture, giving us an 83.33% direct interest, and Orano a 16.667% direct interest |
|
| 2013 | • Federal authorities granted a 10-year renewal of the McArthur River and Key Lake operating licences |
|
| 2014 | • After a two-week labour disruption, we 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 Key Lake in 2018 |
|
| 2018 | • We announce the suspension of production at McArthur River and Key Lake for an indeterminate duration |
|
| 2022 | • We announce plans to transition McArthur River and Key Lake from care and 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 production of 18 million pounds per year (100% basis) starting in 2024
• In October 2023, the Canadian Nuclear Safety Commission (CNSC) granted 20-year renewals to the licences for both McArthur River and Key Lake. |
|
Technical report
| This description is based on the project’s technical report: McArthur River Operation, Northern Saskatchewan, Canada, dated 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., 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.
The conclusions, projections and estimates included in this description are subject to 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+ (sedarplus.com) or from EDGAR (sec.gov). |
For information about uranium sales see pages 19 to 21, environmental matters see Our ESG principles and practices and The regulatory environment starting on pages 92 and 96, and taxes see page 104.
For a description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see page 103.
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 starting at page 121, Social risks starting at page 123 and Environmental risks starting at page 124. |
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.
| 2023 ANNUAL INFORMATION FORM | Page 28 |
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 2034. 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, totaling 87,747 hectares, adjoining the mineral lease and surrounding the deposit. The mineral claims are in good standing until 2025, 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 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 92.
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.
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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 rocks |
| • | fracture controlled and vein like mineralization that occurs in the sandstone away from the unconformity and 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.
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).
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 340 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. There are currently two active mining zones (Zone 2 and 4), one with development significantly advanced (Zone 1), and one in the early stages of development (Zone 4 South).
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 3.5 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 103.9 million pounds of mineral reserves secured behind freeze walls, and it will be the main source of production for the next several years. Raisebore and blasthole stope mining will be used to recover the mineral reserves.
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Zone 1 is the next planned mine area to be brought into production. Freeze hole drilling was completed in 2023 and brine distribution construction work has resumed. A small section of the planned freeze wall is currently actively freezing. Once brine distribution construction is complete and an active freeze wall has been established, drill and extraction chamber development will need to be completed prior to the start of production. 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 in Zone 1.
Zone 4 South is in the early development stages. Access development for the freeze drifts has resumed on the lower levels and freeze drilling began at the end of 2023 on the upper freeze drifts which were established prior to the 2018 shutdown.
Permits
We need three key permits to operate the McArthur River mine:
| • | Uranium Mine Operating Licence – renewed in 2023 and expires in October 2043 (from the CNSC); |
| • | Approval to Operate Pollutant Control Facilities – renewed in 2022 and expires on June 30, 2028 (from 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 the Saskatchewan Watershed Authority) |
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 ventilation shafts |
| • | 1.6-kilometre gravel airstrip and air terminal |
| • | waste rock stockpiles |
| • | water containment ponds and treatment plant |
| • | a freshwater pump house |
| • | a powerhouse |
| • | electrical substations |
| • | backup electrical generators |
| • | a warehouse |
| • | freeze plants |
| • | a concrete batch plant |
| • | an administration and maintenance shop building |
| • | a permanent residence and recreation facilities |
| • | an ore slurry load out facility |
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.
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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.
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.
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 backfill) |
| • | low-grade mineralization temporarily stored on lined pads until trucked to Key Lake |
| • | waste with acid-generating potential – temporarily stored on lined pads – for concrete aggregate |
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:
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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 (0.45 million pounds our share) and in 2023, we produced 14.8 million pounds (10.3 million pounds our share). We plan to produce 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:
| Total mine production | • 2,135,000 tonnes of ore
• 374 million pounds of U3O8, based on current unmined mineral reserves
• Average grade of 7.95%
• 170 to 390 tonnes per day, varying with ore grade (18 million pound annual mine rate) |
Note: Broken and in-circuit ore inventory (previously mined material) is not included in the mine production plan total. Current broken inventory consists of 5.2 million pounds at McArthur River and 1.0 million pounds at Key Lake.
Key Lake Mill
No milling took place from 2019 through 2021. In 2022, we packaged 1.1 million pounds (0.8 million pounds our share) and in 2023, we packaged 13.5 million pounds (9.4 million pounds our share).
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 | • 3,393,000 tonnes of mill feed including blend and recycle material
• Average feed grade of 5.14%
• 380 million 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.
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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 no longer expense monthly operational readiness costs.
Production ramp-up activities continued in 2023. Total packaged production from McArthur River and Key Lake in 2023 was 13.5 million pounds (9.4 million pounds our share), slightly less than the announced September 3, 2023, forecast of 14 million pounds (9.8 million pounds our share).
All required mining and milling activities have now resumed at McArthur and Key Lake and the sites are expected to operate at a normal 18 million pound annual production rate in 2024, however, several operational risks remain including 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, reagents and equipment that carry with them the risks of not achieving our production plans.
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.
In 2024, we plan to undertake an evaluation of the work and investment necessary to expand production up to its annual licensed capacity, which we expect will allow us to take advantage of this opportunity when the time is right. We will continue to plan our production to align with our contract portfolio and market opportunities, demonstrating that we continue to be a responsible supplier of uranium fuel.
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 October 2023 and expires in October 2043 (from the CNSC); and |
| • | Approval to Operate Pollutant Control Facilities – renewed in 2021 and expires on November 30, 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.
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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 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 28 for more information), we made the following changes to the agreement:
| • | the fees and expenses related to Orano’s pro-rata share of ore 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 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 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 |
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.
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 sulfate 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 when the site is closed. |
| • | two contain low-grade mineralized material. These are used to lower the grade of McArthur River ore before it enters the milling circuit. |
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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 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 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 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 and decommissioning.
Operating and capital costs
The following is a summary of the operating and capital cost estimates for the life of mine, stated in constant 2023 dollars and reflecting a forecast life-of-mine mill production of 377 million pounds U3O8 packaged.
| Operating Costs ($Cdn million) |
Total (2024 – 2044) |
|||
| McArthur River Mining |
||||
| Site administration |
$ | 1,037.0 | ||
| Mining costs |
1,933.4 | |||
| Process |
224.4 | |||
| Corporate overhead |
222.6 | |||
|
|
|
|||
| Total mining costs |
$ | 3,364.4 | ||
|
|
|
|||
| Key Lake Milling |
||||
| Administration |
$ | 891.1 | ||
| Milling costs |
1,818.0 | |||
| Corporate overhead |
165.8 | |||
|
|
|
|||
| Total milling costs |
$ | 2,874.9 | ||
|
|
|
|||
| Total operating costs |
$ | 6,293.3 | ||
|
|
|
|||
| Total operating cost per pound U3O8 |
$ | 16.70 | ||
|
|
|
|||
Note: Presented as total cost to the McArthur River Joint Venture.
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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 (2024 – 2044) |
|||
| McArthur River Mine Development |
$ | 477.6 | ||
| McArthur River Mine Capital |
||||
| Freeze infrastructure |
$ | 123.4 | ||
| Water management |
11.7 | |||
| Concrete Batching and Delivery |
27.7 | |||
| Other mine capital |
351.4 | |||
|
|
|
|||
| Total mine capital |
$ | 514.2 | ||
|
|
|
|||
| Key Lake Mill Sustaining |
||||
|
|
|
|||
| Total mill capital |
$ | 244.1 | ||
|
|
|
|||
| Total capital costs |
$ | 1,193.9 | ||
|
|
|
|||
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, and minor support infrastructure. |
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 $2.97 billion for its share of the current McArthur River mineral reserves. Using the total capital invested to December 31, 2018, along with the operating and capital estimates for the remainder of the mineral reserves, the pre-tax internal rate of return (IRR) was estimated to be 11.6%.
The analysis was from the point of view of Cameco, which owns 69.805% of the MRJV, and incorporated a projection of Cameco’s sales revenue from its proportionate share of the related production, less its share of related operating and capital costs of the MRJV, as well as royalties and surcharges that will be payable on the sale of concentrates.
For the purpose of the economic analysis, the projected impact of income taxes was excluded due to the nature of the required calculations. McArthur River operates as an unincorporated joint venture and is, therefore, not subject to direct income taxation at the joint venture level. It is not practical to allocate a resulting income tax cost to Cameco’s portion of the McArthur River operation, as Cameco’s tax expense is a function of several variables, most of which are independent of its investment in McArthur River.
| 2023 ANNUAL INFORMATION FORM | Page 37 |
| Economic Analysis ($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 Ibs U3O8) |
— | 2,78.8 | 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 Ibs U3O8) |
12,567 | 12,630 | 12,618 | 12,602 | 12,591 | 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 | 33.5 | 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 cash flow |
$ | 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 NAV (8%) to January 1, 2019 |
$ | 2,973.3 | ||||||||||||||||||||||||||||||||||||||||||||||
| Pre-tax IRR (%) |
11.6 | % | ||||||||||||||||||||||||||||||||||||||||||||||
Notes:
| 1. | Production volume does not include recycled product received from the Blind River Refinery and the Port Hope Conversion Facility. |
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 2024, 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.
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.
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.
| 2023 ANNUAL INFORMATION FORM | Page 38 |
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 1,280 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
Underground exploration at McArthur River resumed in June 2023 with the resumption of infill drilling of Zone B. Infill drilling of Zone B will continue in 2024.
Sampling, analysis and data verification
Surface samples
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.
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 Müller 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 downhole 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 0.5 metre 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 radiometric values from a hand-held device |
| 2023 ANNUAL INFORMATION FORM | Page 39 |
| • | 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-resistant 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 80% passing at less than 2 mm and splitting out a 100 – 200 g sub-sample using a riffle splitter. The sub-sample is pulverized to 90% at less than 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. We also include a pulp repeat and 1 split sample repeat with every group. Samples that fail quality controls are re-analyzed.
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:
| • | surveyed drillhole collar coordinates and downhole deviations are entered into the database and visually validated and compared to the planned location of the holes |
| • | comparison of the information in the database against the original data, including paper logs, assay certificates and original probing data files as required |
| • | validation of core logging information in plan and section views, and review of logs against photographs of the core |
| • | checking for data entry errors such as overlapping intervals and out of range values |
| • | radiometric probes undergo annual servicing and re-calibration as well as additional checks including control probing to ensure precision and accuracy of the probes. Servicing and re-calibration of the probes were performed to support 2023 drilling activities. |
| • | validating uranium grades comparing radiometric probing, core radioactivity measurements and chemical assay results. New measurement data collected in 2023 was reviewed. No issues were observed. |
No mineral resource estimation work was performed in 2023. Remaining quality control and data verification activities described above will be performed prior to the next resource estimate update.
| 2023 ANNUAL INFORMATION FORM | Page 40 |
Since the start of commercial production, we have regularly compared information collected from production activities, such as freeze holes, 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 on a quarterly basis 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, sampling 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 the actual mine production with the expected production supports this opinion.
Mineral reserve and resource estimates
Please see page 87 for our mineral reserve and resource estimates for McArthur River.
Uranium – Tier-one operations
Cigar Lake
|
2023 Production (our share)
8.2M lbs
2024 Production Outlook (our share)
9.8M lbs
Estimated Reserves (our share)
113.8M lbs
Estimated Mine Life
2036 |
Cigar Lake is the world’s highest grade uranium mine. 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 22, 2024 (effective December 31, 2023) that can be downloaded from SEDAR+ (sedarplus.com) or from EDGAR (sec.gov).
| 2023 ANNUAL INFORMATION FORM | Page 41 |
| Location | Saskatchewan, Canada | |
| Ownership | 54.547% | |
| Mine type | Underground | |
| Mining method | Jet boring system | |
| End product | Uranium concentrate | |
| Certification | ISO 14001 certified | |
| Estimated reserves | 113.8 million pounds (proven and probable), average grade U3O8: 17.03% | |
| Estimated resources | 14.7 million pounds (measured and indicated), average grade U3O8: 5.32% | |
|
10.9 million pounds (inferred), average grade U3O8: 5.55% |
||
| 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 2023 | 138.4 million pounds (100% basis) | |
| 2023 production | 8.2 million pounds (15.1 million pounds on 100% basis) | |
| 2024 production outlook | 9.8 million pounds (18.0 million pounds on 100% basis) | |
| Estimated decommissioning cost | $73.8 million (100% basis)1 | |
All values shown, including reserves and resources, represent our share only, unless otherwise indicated.
| 1 | This amount represents the submitted, but not yet approved, PDP and PDCE value. |
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% |
History
| 1976 | • Canadian Kelvin Resources and Asamera Oil Corporation form an exploration joint 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 Lake |
|
| 1981 | • Deposit discovered by surface drilling – it was delineated by a surface drilling program between 1982 and 1986 |
|
| 1985 | • Reorganization of the Waterbury Lake joint venture – Cigar Lake Mining Corporation becomes the operator of the Cigar Lake lands and a predecessor to Orano becomes the operator of the remaining Waterbury Lake lands
• SMDC has a 50.75% interest |
|
| 1987-1992 | • Test mining, including sinking shaft 1 to 500 metres and lateral development 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 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 June |
|
| 2002 | • Joint venture is reorganized, new joint venture agreement is signed, Rabbit 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
• CNSC issues a construction licence |
|
| 2023 ANNUAL INFORMATION FORM | Page 42 |
| 2005 | • Development begins in January |
|
| 2006 | • Two water inflow incidents delay development: |
|
| • in April, shaft 2 floods |
||
| • in October, underground development areas flood |
||
| • In November, we begin work to remediate the underground development areas |
||
| 2008 | • Remediation interrupted by another inflow in August, preventing the mine from being dewatered |
|
| 2009 | • Remediation of shaft 2 completed in May |
|
| • We seal the 2008 inflow in October |
||
| 2010 | • We finish dewatering the underground development areas in February, establish safe access to the 480 metre level, the main working level of the mine, and backfill the 465 metre level |
|
| • We substantially complete clean-up, inspection, assessment 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 from underground and from the surface |
|
| • We resume the sinking of shaft 2 and early in 2012 achieve breakthrough to the 480 metre level, establishing a second means of egress for the mine |
||
| • We receive regulatory approval of our mine plan and begin work on our Seru Bay project |
||
| • Agreements are signed by the 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 |
|
| • We assemble the first JBS unit underground and move it to a production tunnel where we commence preliminary commissioning |
||
| 2013 | • CNSC issues an eight-year operating licence |
|
| • We begin jet boring in ore |
||
| 2014 | • First Cigar Lake ore shipped to McClean Lake mill |
|
| • McClean Lake mill starts producing uranium concentrate from Cigar Lake ore |
||
| 2015 | • We declared commercial production in May |
|
| 2016 | • We updated the CNSC on our commissioning activities to satisfy a condition in our federal licence |
|
| 2020 | • In March, production is temporarily suspended as a precautionary measure due to the COVID-19 pandemic |
|
| • In September, production resumes |
||
| • In December, production is temporarily suspended as a precautionary measure due to the COVID-19 pandemic |
||
| 2021 | • In April, we announce plans to restart production |
|
| • 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 13.5 million pounds per year (100% basis), 25% below its annual licensed capacity |
|
| • In May, we acquire an additional 4.522 percentage interest in Cigar Lake, increasing our interest to 54.547% |
||
| 2023 | • We updated our production plans for Cigar Lake to maintain production of 18 million pounds per year (100% basis) in 2024 |
|
| 2023 ANNUAL INFORMATION FORM | Page 43 |
Technical report
| This description is based on the project’s technical report: Cigar Lake Operation, Northern Saskatchewan, Canada, dated March 22, 2024 (effective December 31, 2023) 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 supervision of Biman Bharadwaj, P. Eng., Scott Bishop, P. Eng., Alain D. Renaud, P. Geo., and Lloyd Rowson, P. Eng. The following description has been prepared under the supervision of the above qualified persons within the meaning of NI 43-101. They are not independent of us.
The conclusions, projections and estimates included in this description are subject to 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 project. You can download a copy from SEDAR+ (sedarplus.com) or from EDGAR (sec.gov). |
For information about uranium sales see pages 19 to 21, environmental matters see Our ESG principles and practices and The regulatory environment starting on pages 92 and 96, and taxes see page 104.
For a description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see page 103.
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 starting at page 121, Social risks starting at page 123 and Environmental risks starting at page 124. |
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. Since that time, mine operation has achieved full nameplate capacity.
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.
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 715 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 on November 30, 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 totaling 95,293 hectares, adjoining the mineral lease and surrounding the site. The mineral claims are in good standing until 2037 or later.
| 2023 ANNUAL INFORMATION FORM | Page 44 |
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 principles and practices at page 92.
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 by its flat-lying geometry, size, the intensity of its alternation process, the high degree of associated hydrothermal clay alteration and the presence of massive, extremely rich, high-grade uranium mineralization.
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 15.7 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 (CL Main) is approximately 670 metres long by 100 metres wide and the western part (CLEXT) is approximately 1,280 metres long by 75 metres wide.
The deposit has two distinct styles of mineralization:
| • | high-grade mineralization at or proximal to the unconformity which includes all of the mineral resources and mineral reserves |
| • | low-grade, fracture controlled, vein-like mineralization which is located either higher up in the sandstone or in the basement rock mass |
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, arsenic and rare earth elements, but in non-economic concentrations. Higher concentrations of these elements are associated with massive pitchblende or massive sections of arseno-sulfides.
Deposit type
Cigar Lake is an unconformity-related 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, development, and production activities.
| 2023 ANNUAL INFORMATION FORM | Page 45 |
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 CL Main ore body.
Permits
Please see page 51 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 |
| • | access road joining the provincial highway and McClean Lake |
| • | site roads and site grading |
| • | airstrip and terminal |
| • | employee residence and construction camp |
| • | Shaft No. 1 and No. 2 surface facilities |
| • | freeze plants and brine distribution equipment |
| • | surface freeze pads |
| • | water supply, storage and distribution for industrial water, potable water and fire suppression |
| • | propane, diesel and gasoline storage and distribution |
| • | electrical power substation and distribution |
| • | compressed air supply and distribution |
| • | mine water storage ponds and water treatment |
| • | sewage collection and treatment |
| • | surface and underground pumping system installation |
| • | surface runoff containment infrastructure |
| • | waste rock stockpiles and aggregate processing infrastructure |
| • | garbage disposal landfill |
| • | administration, maintenance and warehousing facilities |
| • | ore load out facility |
| • | concrete batch plant |
| • | Seru Bay treated water effluent pipeline |
| • | 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 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.
Artificial ground freezing (AGF)
The current method of mining the Cigar Lake orebody uses progressive block freezing of portions of the mineralized zone and adjacent host rock. Freezing the orebody reduces the risk of potential inflow of groundwater and release of radon gas into the workplace, while increasing cavity stability and standup time during mining. The freezing strategy is to bulk freeze the ore zone
and the surrounding area prior to start of mining in a given area. Frozen cavity criteria are applied to each cavity prior to mining to ensure it meets the minimum standard prior to excavation.
| 2023 ANNUAL INFORMATION FORM | Page 46 |
This AGF system freezes the deposit and surrounding rock to between -5°C and -25°C in two to four years, depending on freeze pipe geometry and ground properties such as water content and thermal conductivity.
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 the frozen ore; |
| • | collecting the ore and water mixture (slurry) from the cavity and pumping it to a storage sump, allowing it to settle; |
| • | using a clamshell, transporting the ore from the storage sump to an underground comminution and processing circuit; |
| • | 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. Two additional scooptrams, plus some smaller ancillary equipment, will be added to the current equipment fleet to meet the production and development 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 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.
| 2023 ANNUAL INFORMATION FORM | Page 47 |
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 is processed at two locations:
Comminution is conducted underground at Cigar Lake, while leaching, purification and final yellowcake production and packaging occurs at the McClean Lake mill. The ore is trucked as a finely ground slurry from Cigar Lake to the McLean Lake mill in purpose-built containers identical to those used to transport McArthur River ore slurry to the Key Lake mill.
Recovery and metallurgical testing
Extensive metallurgical test work was performed on core samples of Cigar Lake ore from 1992 to 1999 in France at Orano’s CIME test centre. Samples used for the metallurgical test work during this period may not have been representative of the deposit as a whole. Additional test work completed by Orano 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 safety related modifications being implemented in the leaching circuit. Leaching modifications began in 2013 and were completed in 2014, with mill start-up in September 2014.
The results of this test work program provided the process design criteria for the additions and modifications required at the McClean Lake mill for processing Cigar Lake ore. Since 2014, the McClean Lake mill has processed on a daily basis a range of ore grades, at times in excess of 28% U. Additional testing was completed by Orano in 2018 and 2019 on samples from CLEXT. The test work, combined with ongoing optimization and operating experience at the McClean Lake mill, confirmed that no modifications would be required to the mill circuits to process CLEXT ore. Tailings neutralization and aging tests also completed during this period verified that the current operating practices at the McClean Lake mill will produce tailings that are stable over the long-term.
Based on the test results and past mill performance, an overall uranium recovery of 98.8% for CL Main and 98.5% for CLEXT is expected for the remainder of the mine life.
Specific ore induced risks include:
| • | Elevated arsenic concentration in the mill feed may result in increased leaching circuit solution temperatures. This could result in a reduction in mill feed rates and additional capital and operating expense to modify the leaching process. |
| • | Hydrogen evolution rates in leaching may exceed the design capacity of the hydrogen gas control system resulting in reduced leach feed rates. Additional capital expense may be required to increase the capacity of the hydrogen gas control system. |
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.
| 2023 ANNUAL INFORMATION FORM | Page 48 |
Waste rock
The waste rock piles are separated into three categories:
| • | clean waste – will remain on the mine site for use as aggregate for roads, concrete backfill and future site 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 | • 205.9 million pounds of U3O8, based on current mineral reserves and an overall milling recovery of 98.8% for CL Main and 98.5% for CLEXT
• Full annual production of 18 million pounds of U3O8 |
|
| Total mine production | • 554,500 tonnes of ore |
|
| Average annual mine production | • 115 to 160 tonnes per day during peak production, depending on ore grade |
|
| Average mill feed grade | • 17.0% U3O8 |
|
Total packaged production from Cigar Lake in 2023 was 15.1 million pounds U3O8 (8.2 million pounds our share) compared to 18.0 million pounds U3O8 (9.8 million pounds our share) in 2022. In 2022, we were successful in catching up on development work that had been deferred from 2021. In 2023, productivity was impacted as we completed development and commissioning activities in the first quarter and achieved first production from a new mining area. We had expected to recover from these delays in the second half of the year. However, in the third quarter, we determined maintenance work was required on one of the underground circuits, which had not been planned. The additional time required to complete this work did not allow for the delayed production volumes to be recovered prior to year-end.
In 2024, we expect to produce at the licensed rate of 18 million pounds (100% basis) per year.
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 2024 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.
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 waste management 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.
| 2023 ANNUAL INFORMATION FORM | Page 49 |
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 2023. We completed our second production crosscut in the western portion of the CL Main in preparation for ore mining starting in the second quarter of 2024.
During 2023, we:
| • | executed planned 21-day annual maintenance activities in September |
| • | executed production activities from four production tunnels in the CL Main part of the orebody and one, for the first time, from the CLEXT part of the orebody |
| • | in alignment with our long-term production planning, brought two new panels online |
| • | continued underground header construction activities and expanded our ground freezing program to ensure continued frozen ore inventory |
| • | completed our freeze hole drilling program in the second quarter |
In 2024, we plan to:
| • | continue production activities focused on bringing one new production panel online |
| • | complete construction and commissioning of freeze distribution infrastructure expansion in support of future production |
| • | continue underground mine development on two new production tunnels as well as expand ventilation and access drifts in alignment with the long-term mine plan |
| • | commission the surface backfill batch plant to support ongoing operations |
| • | execute an underground geotechnical drilling program |
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.
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. This optimization included periodic raising of a bentonite amended liner, the most recent of which was completed in 2023.
| 2023 ANNUAL INFORMATION FORM | Page 50 |
In 2022, Orano received regulatory approval for the expansion of the JEB TMF.
The expansion will be achieved by the continued construction of an engineered embankment and placement of a bentonite amended liner. Following the staged expansion, the TMF is expected to have capacity to receive tailings from processing all of Cigar Lake’s current mineral reserves.
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 extended to January 31, 2024 and then renewed in 2024 and the current approval now expires in 2030. The Saskatchewan Watershed Authority water rights licence was obtained in 1988 and was amended in 2023 and now expires in 2028.
The current Cigar Lake LCH authorizes an annual production rate up to 18 million pounds per year. The CNSC licence and LCH for the McClean Lake operation, issued by the CNSC in 2017, authorizes the production of up to 24 million pounds U3O8 annually. The licence and LCH were amended in 2022 to authorize the expansion of the JEB TMF.
Approvals, issued by the SMOE pursuant to the Saskatchewan Environmental Assessment Act, for Cigar Lake are based on estimated annual production rates of 18 million pounds U3O8 for CL Main and 6 million pounds U3O8 for CLEXT. As such, it is anticipated that the planned annual production rate of 18 million pounds U3O8 for CLEXT represents a change to the approved development that will require Ministerial Approval. Cameco plans to submit the information required to obtain this approval in 2025.
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.
Operating and capital costs
The following is a summary of the Cigar Lake operating and capital cost estimates for the remaining life of mine, stated in constant 2023 dollars and reflecting a forecast life-of-mine mill production of 205.9 million pounds.
| 2023 ANNUAL INFORMATION FORM | Page 51 |
| Operating Costs ($Cdn million) |
Total (2024 – 2036) |
|||
| Cigar Lake Mining |
||||
| Site administration |
$ | 665.5 | ||
| Mining costs |
1,016.5 | |||
| Process |
359.8 | |||
| Corporate overhead |
163.0 | |||
|
|
|
|||
| Total mining costs |
$ | 2,204.8 | ||
|
|
|
|||
| McClean Lake Milling |
||||
| Administration |
$ | 623.8 | ||
| Milling costs |
1,109.1 | |||
| Corporate overhead |
102.8 | |||
| Toll milling |
196.1 | |||
|
|
|
|||
| Total milling costs |
$ | 2,031.8 | ||
|
|
|
|||
| Total operating costs |
$ | 4,236.6 | ||
|
|
|
|||
| Total operating cost per pound U3O8 |
$ | 20.58 | ||
|
|
|
|||
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 (2024 – 2036) |
|||
| Cigar Lake Mine Development |
$ | 378.7 | ||
| Cigar Lake Mine Capital |
||||
| Production tunnel outfitting Ground freezing system |
$
|
138.5 129.9 |
|
|
| Other mine capital |
319.9 | |||
|
|
|
|||
| Total mine capital |
$ | 588.3 | ||
|
|
|
|||
| Tailings Expansion |
$ | 52.6 | ||
| Other mill capital |
227.7 | |||
|
|
|
|||
| Total mill capital |
$ | 280.3 | ||
|
|
|
|||
| Total capital costs |
$ | 1,247.3 | ||
|
|
|
|||
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 2024, 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.
| 2023 ANNUAL INFORMATION FORM | Page 52 |
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 CL Main area of the deposit to identify major structures within the sandstone column. In 2015, Cameco conducted a geotechnical drill program consisting of nine surface diamond holes (drilled to a vertical depth of 525 metres) over the western portion of the CL Main area of the deposit. Downhole cross-well seismic was done within these boreholes to image major fault structures and geotechnical characteristics of this portion of the deposit.
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 drilling campaigns were conducted by Cameco after 2007 which targeted a broad range of technical objectives, including geotechnical, geophysical, delineation and ground freezing. Since 2012, diamond drilling managed by Cameco has mainly focused on underground geotechnical and surface ground freezing programs on CL Main along with continued delineation drilling on CLEXT. Drill depths for surface delineation holes range from approximately 460 to 550 metres.
Delineation drilling in the CL Main zone was originally completed at a nominal drillhole fence spacing of 25 to 50 metres (east-west), with holes at 20 to 25 metres (north-south) spacing on the fences. Since then, the entire portion of the CL Main deposit has had surface freezeholes installed at a nominal 7 x 7 metre pattern.
The CLEXT zone was historically drilled at a nominal drillhole fence spacing of 200 metres, with holes at 20 metre spacing on the fences. Subsequent drill programs occurring between 2011 and 2023 have since reduced the drillhole spacing down to approximately 15 x 15 metres in local areas of the deposit.
Drilling results have been used to delineate and interpret the 3-dimensional geometry of the mineralized areas, the lithostructural settings, the geotechnical conditions, and to estimate the distribution and content of uranium and other elements.
Surface freeze hole drilling over the CL Main zone, ongoing since 2012, has been completed. Drilling results obtained between September 2022 and end of 2023, representing 98 additional freeze holes and six new delineation holes, are reflected in the CL Main mineral resource and reserve estimates.
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. A total of 519 underground geotechnical holes have been completed on CL Main. In addition, 24 geotechnical holes have been completed with respect to the CLEXT.
At one time, freeze holes were drilled from underground into the deposit for the purpose of freezing the ground prior to mining. No underground freeze holes have been drilled since 2006. None of them are currently used for freezing or for mineral resource and reserve estimation purposes.
| 2023 ANNUAL INFORMATION FORM | Page 53 |
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 Müller 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 in CL Main, while for CLEXT, all core has been assayed. In these cases, the core depth is validated by comparing the downhole 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 was done to reduce the potential for sampling bias, given the high-grade nature and variability of the grades of the mineralization, and to minimize human exposure to gamma radiation and radon gas during the sampling process.
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 0.5 metre 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 radiometric values from a hand-held device |
| • | bagging and sealing, with sample tags inside bags and sample numbers on the bags |
| • | 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-resistant 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 80% passing at less than two millimetres and splitting out a 100-to-200-gram sub-sample using a riffle splitter. The sub-sample is pulverized to 90% at less than 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-millilitre 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.
| 2023 ANNUAL INFORMATION FORM | Page 54 |
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. We also include a pulp repeat and one 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 and geochemical 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 verification measures taken on the data collected at Cigar Lake are as follows:
| • | surveyed drillhole collar coordinates and downhole deviations are entered into the database and visually validated and compared to the planned location of the holes. Most results were within acceptable tolerances. Holes that exceeded the thresholds were reviewed resulting in two holes being adjusted. |
| • | comparison of the information in the database against the original data, including paper logs, assay certificates and original probing data files as required. Approximately 5% of holes in the resource estimate updates were compared against the assay certificates with no discrepancies observed. We have observed no discrepancies of note since implementation of the centralized geological data management system. |
| • | validation of core logging information in plan and section views, and review of logs against photographs of the core. Core logging information was reviewed during geological modelling. No issues were observed. |
| • | checking for data entry errors such as overlapping intervals and out of range values. No issues of note were observed in 2023. |
| • | radiometric probes undergo annual servicing and re-calibration as well as 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. |
| • | validating uranium grades comparing radiometric probing, core radioactivity measurements and chemical assay results. A review of the correlation to convert corrected probe count rates into equivalent % U3O8 grades was completed in 2023. Following this review, an adjustment to the correlation was applied to address a slight U3O8 overestimation bias. |
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. Results from the resulting investigation completed in 2023 identified a local issue with the model. We do not expect further impact.
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, sampling 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 the actual mine production with the expected production supports this opinion.
Mineral reserve and resource estimates
Please see page 87 for our mineral reserve and resource estimates for Cigar Lake.
| 2023 ANNUAL INFORMATION FORM | Page 55 |
Uranium – Tier-one operations
Inkai
|
2023 Production (100% basis)
8.3M lbs
2024 Production Outlook (100% basis)
8.3M lbs
(See Production – 2024 Production on page 63)
Estimated Reserves (our share)
104.7M 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+ (sedarplus.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 | 104.7 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 2023 | 89.3 million pounds (100% basis) | |
| 2023 production | 8.3 million pounds (100% basis)1 | |
| 2024 production outlook | 8.3 million pounds (100% basis)1 See Production – 2024 Production on page 63 |
|
| Estimated decommissioning cost (100% basis) | $33.6 million (US) (100% basis) | |
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 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% |
| 2023 ANNUAL INFORMATION FORM | Page 56 |
History
| 1976-78 | • Deposit is discovered |
|
| • Exploration drilling continues until 1996 |
||
| 1979 | • Regional and local hydrogeology studies begin |
|
| • Borehole tests characterize 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 recovers 92,900 pounds of uranium |
|
| 1993 | • First Kazakhstan estimates of uranium resources for block 1 |
|
| 1996 | • First Kazakhstan estimates of uranium resources for block 2 |
|
| • Kazakhstan regulators 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 |
|
| • We acquire all of Uranerzbergbau-GmbH’s interest in JV Inkai, increasing our interest to 66 2/3% |
||
| • We agree to transfer a 6 2/3% interest to KAP, reducing our holdings to a 60% interest |
||
| 1999 | • JV Inkai receives a mining licence for block 1 and an exploration with 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 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 begins |
|
| 2006 | • Complete pilot leach test at block 2 |
|
| • Exploration-delineation drilling initiated at block 3 |
||
| 2007 | • Sign Amendment No.1 to the resource use contract, extending the exploration period at blocks 2 and 3 |
|
| 2008 | • Commission front half of the main processing plant in the fourth quarter, and begin processing solution from block 1 |
|
| 2009 | • Sign Amendment No. 2 to the resource use contract, which approves the 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 |
|
| • Commission the main processing plant, and started commissioning the first satellite plant |
||
| 2010 | • Receive regulatory approval for commissioning of the main processing plant |
|
| • File a notice of potential commercial discovery at block 3 |
||
| • Receive approval in principle for the extension of block 3 exploration for a five-year appraisal 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 |
|
| • Sign Amendment No. 3 to 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) |
||
| • Sign a memorandum of 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 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 uranium refining rather than uranium conversion |
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| • Start construction of a test leach facility at block 3 |
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| 2013 | • Sign Amendment No. 4 to the resource use contract, which provides government approval to increase annual production from blocks 1 and 2 to 5.2 million pounds (100% basis) |
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| 2015 | • At block 3, construction of the test leach facility is completed and the pilot leach test initiated |
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| 2016 | • Sign an agreement with KAP and JV Inkai to restructure and enhance JV Inkai, subject to closing, increasing KAP’s holdings to a 60% interest and reducing our holdings to a 40% interest |
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| • Sign Amendment No. 5 to the resource use contract, which extends the exploration period for block 3 to July 2018 |
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| 2017 | • In December, close the agreement with KAP and JV Inkai to restructure and enhance JV Inkai. Under the agreement, effective January 1, 2018, our ownership interest dropped to 40% and we will equity account for our investment. |
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| • Sign Amendment No. 6 to the resource use contract, which grants JV Inkai the right to produce 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
| This description is based on the project’s technical report: Inkai Operation, South Kazakhstan Oblast, Republic of Kazakhstan, dated January 25, 2018 (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 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. 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.
The conclusions, projections and estimates included in this description are subject to 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 project. You can download a copy from SEDAR+ (sedarplus.com) or from EDGAR (sec.gov). |
For information about environmental matters, see Our ESG principles and practices and The regulatory environment starting on pages 92 and 96.
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 104.
For a description of risks that might affect access, title or the right or ability to perform work on the property, see Strategic risks – Foreign investments and operations and Kazakhstan at pages 129 and 130, Operational risks – Permitting and licensing at page 113, Governance and compliance risks starting at page 121, Social risks starting at page 123, and Environmental risks starting at page 124. |
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.
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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.
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 63 for more information.
JV Inkai must give preference to local businesses. See Kazakhstan government and legislation – local content on page 66 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.
Geological setting
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.
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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.
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 term |
| • | “Licence for transportation of radioactive substances within the territory of the Republic of 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 64.
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.
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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 addition of a dining room for 150 people |
| • | construction of a 24-kilometre asphalt paved road connecting the camp to the three processing facilities |
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 sulfuric 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 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 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 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 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 69 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 |
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| • | 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 2023 slightly exceeded our target of 85%.
Production
Total production
Based on current mineral reserves and resource use contract term, we expect Inkai to produce a total of 216 million pounds U3O8 (100% basis, recovered after processing) over the life of the mine from January 2024 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 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 restructuring, were to 2024 and 2030) |
| • | our ownership interest in JV Inkai is 40% and KAP’s ownership interest is 60%. However, during production 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 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 |
| • | 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 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.
2023 Production
Total 2023 production from Inkai was 8.3 million pounds (100% basis). In 2023, Inkai experienced a number of operational issues related to interruptions in reagent delivery and wellfield drilling.
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The first shipment, containing approximately two thirds of our share of JV Inkai’s 2023 production arrived in the fourth quarter of 2023. The second shipment with the rest of our share of 2023 production arrived in early 2024. We continue to work closely with JV Inkai and our joint venture partner, KAP, to receive our share of production via the Trans-Caspian International Transport Route, which does not rely on Russian rail lines or ports.
Based on an adjustment to the production purchase entitlement under the 2016 implementation agreement, for 2023 we were entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s planned 2023 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 2023, timing was impacted by shipping delays.
2024 Production
Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain approximately 20% below the level stipulated in subsoil use agreements, primarily due to the sulfuric acid shortage in the country and delays in development of new deposits.
Our current target for production at Inkai in 2024 is 8.3 million pounds of U3O8 (100% basis). However, this target is tentative and contingent upon receipt of sufficient quantities of sulfuric acid. In addition, the allocation of such production between the JV Inkai participants is currently under discussion by Cameco and KAP.
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 2023, we received dividend payments from JV Inkai totaling $79 million (US), net of withholdings. 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 |
| • | 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 2 and 3 for two years. |
| • | In 2009, Amendment No. 2 to the resource use contract was signed, adopting the 2009 Tax Code, implementing 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 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. |
| • | In 2013, Amendment No. 4 to the resource use contract was signed to increase annual production from blocks 1 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 3 to July 13, 2018. |
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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.
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 annually, or when there is a significant change at the operation that could affect decommissioning estimates. The preliminary decommissioning estimate is $33.6 million (US).
Groundwater is not actively restored post-mining in Kazakhstan. See page 101 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 and Subsoil 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 dated June 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 with respect to the following transfers related to strategic subsoil areas: (i) transfers of a subsoil use right related to a strategic subsoil area, (ii) transfers (direct or indirect) of an ownership interest in a subsoil use, and (iii) initial public offering of shares and other securities in a subsoil user at an organized securities market, as such ownership interests, shares, or securities constitute 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.
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Local content
The subsoil code imposes local content requirements for works, services and employees.
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. As per the transitional provisions of the subsoil code, the mechanism of the decommissioning fund was preserved for old resource use contracts.
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.
| 2023 ANNUAL INFORMATION FORM | Page 66 |
Currency control regulations
Under the Law of the Republic of Kazakhstan “On Currency Regulation and Currency Control” No. 167-VI dated July 2, 2018, as amended (the Currency Control Law), the Kazakhstan Government – based on a joint recommendation from the National Bank of Kazakhstan (the NBK) and another competent state authority – Is entitled to introduce a “special currency regime” if: (a) there is a serious threat to the stability of the country’s balance of payments, the local foreign exchange market, or the economic security of the Republic of Kazakhstan; and (b) such situation (such threat) cannot be resolved by other measures of economic policy. A “special currency regime” is defined as a special regime for conducting currency transactions, which provides for a set of regulatory measures: (a) aimed at creating conditions for eliminating threats to the economic security, and the stability of the financial system, of Kazakhstan, and (b) allowing the introduction of the additional currency control restrictions on the conduct of residents and non-residents of Kazakhstan. Currency control restrictions, which could be imposed under the special currency regime, shall be temporary measures with non-discriminatory nature. These restrictions shall be cancelled as soon as the circumstances that caused their establishment are eliminated.
The restrictions, which may be introduced under the special currency regime, include:
| • | the requirement to place for a specified period a deposit (without payment of interest) in the amount determined as a percentage of the value of a designated currency transaction with a Kazakh bank or the NBK; |
| • | the requirement to obtain a special permit from the NBK to conduct a currency transaction; |
| • | the requirement for the mandatory sale of foreign currency received by a resident of Kazakhstan; and/or |
| • | restrictions on the use of accounts with foreign banks, as well as settling for residents of Kazakhstan a timing to return foreign currency earnings, as well as limits on volume, amount and currency of settlement on currency transactions |
The Kazakhstan Government – based on a joint recommendation from the NBK and other competent state authorities – may introduce other temporary currency control measures.
Under the Currency Control Law, the requirements of the special currency regime cannot restrict:
| • | fulfillment by residents of Kazakhstan of their obligations to non-residents that arose as a result of the fulfillment by non-residents of their obligations under currency transactions before the introduction of the special currency regime; and |
| • | transfer abroad by non-residents of their dividends, remuneration and other income received on deposits and securities |
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 2023 dollars and reflecting a forecast life-of-mine production of 216 million pounds U3O8 and a 367 Kazakhstan Tenge to 1 Cdn dollar exchange rate assumption.
| Operating Costs ($Cdn million) |
Total (2024 – 2045) |
|||
| Site administration |
$ | 519.3 | ||
| Processing costs |
382.4 | |||
| Mining costs |
950.3 | |||
| Corporate overhead |
830.3 | |||
|
|
|
|||
| Total operating costs |
$ | 2,682.3 | ||
|
|
|
|||
| Average cost per pound U3O8 |
$ | 12.42 | ||
|
|
|
|||
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.
| 2023 ANNUAL INFORMATION FORM | Page 67 |
| Capital Costs ($Cdn million) |
Total (2024 – 2045) |
|||
| Total wellfield development |
$ | 994.9 | ||
| Construction and maintenance capital |
70.4 | |||
| Sustaining capital |
86.9 | |||
|
|
|
|||
| Total capital costs |
$ | 1,152.2 | ||
|
|
|
|||
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 totaling $8.9 billion. Using the total capital invested, along with the operating and capital cost estimates for the remainder of mineral reserves, the after tax IRR is estimated to be 27.1%. Payback for JV Inkai, including all actual costs was achieved in 2015, on an undiscounted, after tax basis. All future capital expenditures are forecasted to be covered by operating cash flow.
Annual Cash Flows – 100% JV Inkai basis
| Annual cash flows ($Cdn M) |
2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | |||||||||||||||||||||||||||||||||||||||
| Production volume (000’s lbs U3O8) |
6,896 | 8,351 | 10,406 | 1 | 10,399 | 1 | 10,399 | 1 | 10,293 | 1 | 9,305 | 1 | 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 | Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain approximately 20% below the level stipulated in subsoil use agreements, primarily due to the sulfuric acid shortage in the country and delays in development of new deposits. Our current target for production at Inkai in 2024 is 8.3 million pounds of U3O8 (100% basis). However, this target is tentative and contingent upon receipt of sufficient quantities of sulfuric acid. In addition, the allocation of such production between the JV Inkai participants is currently under discussion by Cameco and KAP. 2021 production was 9.0 million pounds, 2022 production was 8.3 million pounds and 2023 production was also 8.3 million pounds. |
| 2023 ANNUAL INFORMATION FORM | Page 68 |
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 2024 to coincide with the ramp up of production in 2025.
The current forecast production is now 216 million pounds U3O8 for the remaining term of the resource use contract, ending mid-2045. Operating costs are expected to increase by approximately 59% as compared to the 2022 AIF and increase by approximately 30% 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 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 114 and Strategic risks – Foreign investments and operations and Kazakhstan on page 129 and page 130).
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 2024, 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 drillholes 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.
| 2023 ANNUAL INFORMATION FORM | Page 69 |
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.
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 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 metres. Sample intervals are also differentiated by barren or low permeability material. |
| • | The drillholes are nearly vertical and the mineralized horizons are almost horizontal, so the mineralized intercepts represent the true thickness of the mineralization. |
| • | JV Inkai surveys the drillholes, logging radiometric, electrical (spontaneous potential and resistivity), caliper and deviation data. |
| • | Sampling is done on half of the core. The average core sample length is 0.4 metre. |
| • | The split core is tested for grainsize and carbonate content. |
| • | Core recovery is considered acceptable given the unconsolidated state of the mineralized material. |
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 subdivided by one or three times quartering until the final representative weight of samples and duplicates is reached (0.2 kg). |
| • | The laboratory tests for uranium and radium were performed by the Central Analytical Laboratory of JSC 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. |
| • | The uranium content was determined by using the X-ray fluorescence spectrum analysis. The radium content was determined from the gamma-X-ray spectrum analysis. |
Quality control and data verification
| • | The sampling reproducibility for the uranium and radium assays was determined by two methods: (1) having the 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 tolerances. |
| • | Internal laboratory control of the uranium and the radium grade determination is performed by comparing the 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. |
| • | External (inter-laboratory) controls for the uranium and radium assays were carried out at the VIMS laboratory in 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. |
| 2023 ANNUAL INFORMATION FORM | Page 70 |
| • | All of the drillhole information in use at Inkai is regularly provided to Cameco. The current database has been 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. |
| • | Our geoscientists, including qualified persons as such term is defined in NI 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 representative and reliable. |
| • | We confirmed the correlation between radioactive readings and calculated radium grades. |
| • | We carried out data verification processes that validated the mineral resource and reserve estimates. Our 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 inconsistencies in the data used or verified nor any failures to adequately verity the data. |
| • | All drilling, logging, core drilling, and subsequent core splitting and assaying, were completed under the direction of various geological expeditions of the USSR Ministry of Geology and later under the supervision of JSC Volkovgeology. |
| • | Based on numerous quality assurance and quality controls applied by JSC Volkovgeology, including internal checks and inter-laboratory checks, the repeatability of the results for uranium and radium confirmed the accuracy required and no significant systematic deviations were found. |
| • | Sampling and analysis procedures have been examined by an independent consultant and found to be detailed and thorough. |
| • | The findings are supported by results of the leach tests and wellfield drilling results on the MA Area. |
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 87 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, 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.
| 2023 ANNUAL INFORMATION FORM | Page 71 |
| 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 2038 | |
| Total production: 1975 to 2023 | 202.2 million pounds | |
| 2023 production | 0 million pounds | |
| 2024 production outlook | 0 million pounds | |
| Estimated decommissioning cost | $294.8 million1 | |
| 1 | This amount represents the submitted, but not yet approved, PDP and PDCE value. |
Production suspension
The facilities remained in a safe state of care and maintenance throughout 2023.
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 $28 million and $32 million annually.
In October 2023, the CNSC granted a 15-year renewal of the operating licence for Rabbit Lake, extending the licence term to October 2038.
Future production
We do not expect any production from Rabbit Lake in 2024.
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, respectively. 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.
| 2023 ANNUAL INFORMATION FORM | Page 72 |
| 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 2023 | 33.0 million pounds | |||
| 2023 production | 0 million pounds | |||
| 2024 production outlook | 0 million pounds | |||
| Estimated decommissioning cost | Smith Ranch-Highland: $239 million (US), including North Butte | |||
| Crow Butte: $62 million (US) | ||||
| 1 | Including Highland mill. |
Production and 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 $12.5 million (US) and $14.5 million (US) for 2024.
The current operating licence for Crow Butte expires in October 2024. Efforts are underway for re-licensing with the NRC.
Future production
We do not expect any production in 2024.
Uranium – Advanced projects
Our advanced projects are part of our project pipeline and these resources are supportive of growth beyond our existing suite of tier-one and tier-two assets. We plan to advance them at a pace aligned with market opportunities.
| 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 through geophysical surveys and surface drilling work between 2000 and 2013.
| 2023 ANNUAL INFORMATION FORM | Page 73 |
| 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.
2023 project updates
We believe that we have some of the best undeveloped uranium projects in the world. However, our primary focus is on producing from our tier-one uranium assets at a pace aligned with our contract portfolio and market opportunities.
Planning for the future
2024 Planned activity
No work is planned at Millennium, Yeelirrie or Kintyre in 2024.
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.
Uranium – Exploration
Our exploration program is focused on replacing mineral reserves as they are depleted by our production, which is key to sustaining our business, meeting our commitments, and ensuring long-term growth. Our global exploration activity is adjusted annually in line with market signals and at a pace aligned with Cameco’s mining plans and sourcing needs. In recent years, we have increased exploration spending in response to the significant positive momentum in the nuclear fuel market that has provided a clear signal that more uranium production will be required in the next decade, setting the stage for a renewed exploration cycle.
| 2023 ANNUAL INFORMATION FORM | Page 74 |
Our position as one of the world’s largest uranium producers and our continued growth across the nuclear fuel cycle has been driven by decades of experience and our history of exploration, discovery and mining success. Our land position totals 740,000 hectares (1.8 million acres) that cover exploration and development prospects in Canada, Australia, Kazakhstan and the US that are among the best in the world. In northern Saskatchewan alone, we have direct interests in 650,000 hectares (1.6 million acres) that cover many of the most prospective areas of the prolific Athabasca Basin.
In northern Saskatchewan, our well-established infrastructure includes fully licensed and fully permitted uranium mills and mines in the eastern Athabasca basin, along with a supporting network of roads, airstrips and electricity supply. That infrastructure provides us with an advantage that not only underpins the potential development of our advanced exploration projects, but also supports our ongoing work to both delineate existing prospects and deposits, and to identify future undiscovered uranium potential of the region. Additionally, our decades of work to establish a positive corporate reputation by prioritizing our relationships with northern Saskatchewan Indigenous communities, confirms our long-term commitment to continually engage and provide ongoing benefits to the people that call the region home.
The uranium endowment of the Athabasca Basin, where we are involved in 39 projects (including partner-operated joint ventures), is well known and combined with the basin’s unique geological history, it creates a remarkable mining jurisdiction hosting the highest uranium grades and some of the largest uranium deposits in the world. On our projects, we have identified numerous uranium occurrences, prospects, and undeveloped deposits of variable grades and sizes that have progressed through multiple stages of evaluation. Depending on the potential deposit size, ore and ground quality, evolving mining technologies and the uranium market environment, some of these prospects are expected to become viable, economic deposits in a uranium market and price environment that supports new primary production and provides an adequate risk-adjusted return.
The combination of our large land position and proven expertise in discovering and developing world class uranium mines provides the foundation for future mill-supposed exploration projects, ranging from early to advanced stages of greenfield exploration and for brownfield opportunities to extend the lives of our existing operations.
2023 UPDATE
Brownfield exploration
Brownfield and advanced exploration activities include exploration near our existing operations and expenses for maintaining advanced projects and delineation drilling where uranium mineralization is being defined. In 2023, we spent about $4.5 million in Saskatchewan, $1 million in Australia and $1 million in the US on brownfields and advanced exploration projects. The spending in Saskatchewan was primarily focused on advancing the extension of the mine life at Cigar Lake and advanced exploration on the Dawn Lake project.
The Dawn Lake project is located approximately 45 km northwest of the Rabbit Lake operation, on the La Rocque Lake corridor which hosts several historic discoveries and deposits. In 2023, exploration drilling at Dawn Lake expanded the footprint of known uranium mineralization with mineralized intercepts in excess of 60% U3O8 over several metres. Although the deposit remains at a very early stage of exploration, the high-grade results and geological conditions observed to date are comparable to those of other mines and known deposits in the Athabasca Basin, generating interest and a focused effort to better understand its potential.
| 2023 ANNUAL INFORMATION FORM | Page 75 |
Regional exploration
Regional exploration is defined as projects that are considered greenfield. In 2023, we spent about $11 million on regional exploration programs that are comprised of target generation geophysical surveys and diamond drilling primarily in northern Saskatchewan.
PLANNING FOR THE FUTURE
We plan to continue to focus on our core projects in Saskatchewan under our long-term exploration framework. Our leadership position and industry expertise in both exploration and corporate social responsibility makes us a partner of choice and for properties and projects that meet our investment criteria, we may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements to optimize our exploration activity and spending.
Brownfield exploration
In 2024, we plan to spend about $7 million on brownfields and advanced Exploration, primarily to expand the footprint of the mineralization identified on in the La Rocque Lake corridor of the Dawn Lake project.
Regional exploration
We plan to spend about $13 million on diamond drilling and target generation geophysical surveys on our core regional projects in Saskatchewan, in 2024.
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 capture full-cycle value by supporting the growth of the uranium segment and by 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. Offering a range of products and services to customers helps us broaden our business relationships and meet customer needs.
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 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.
In 2023, fuel services produced 13.3 million kgU, 2% higher than 2022.
We plan to produce between 13.5 million and 14.5 million kgU in 2024. This includes increasing annual production at our Port Hope UF6 conversion facility to 12,000 tonnes to satisfy our book of long-term business and demand for conversion services.
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 2024 and future years.
| 2023 ANNUAL INFORMATION FORM | Page 76 |
Blind River Refinery
|
Licensed Capacity
24.0M kgU as UO3
Licence renewal in
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 conditions) | |
| Licence term | Through February 2032 | |
| Estimated decommissioning cost | $57.5 million | |
Markets
UO3 is shipped to Port Hope for conversion into either UF6 or UO2.
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 Hope Conversion Services
|
Licensed Capacity
12.5M kgU as UF6
2.8M kgU as UO2
Licence renewal in
February 2027 |
Port Hope is the only uranium conversion facility in Canada and a supplier of UO2 for Canadian-made CANDU heavy-water reactors.
| 2023 ANNUAL INFORMATION FORM | Page 77 |
| 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 | $138.2 million1 | |
| 1 | This amount is to be reviewed at the 2024 Commission hearing. |
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. Good progress was made over the past year with the removal of old buildings and structures on site, and the project will continue to be active in the year ahead.
Licensing
In February 2017, the CNSC approved a ten-year operating licence for the Port Hope conversion facility.
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
1.65M kgU as UO2 fuel pellets
Licence renewal in
February 2043 |
CFM produces fuel bundles and reactor components for CANDU reactors.
| 2023 ANNUAL INFORMATION FORM | Page 78 |
| 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 granted CFM’s request for a slight production increase to 1,650 tonnes as UO2 fuel pellets.
Labour relations
The collective agreement with unionized employees at our fuel manufacturing operations in Port Hope and Cobourg expires in June 2024. Negotiations are taking place in Q2 2024. There is a risk to the production plan if we are unable to reach an agreement and there is a labour dispute.
Westinghouse Electric Company
Westinghouse is a nuclear reactor technology original equipment manufacturer (OEM) and a leading provider of highly technical aftermarket products and services to its customer base which includes commercial nuclear power utilities and government agencies globally. Westinghouse’s history in the energy industry stretches back over a century, during which time the company became a pioneer in nuclear energy.
It is the OEM or a technology provider to about 50% of the global nuclear reactor fleet, delivering capacity of about 190,000 carbon-free Mwe.
It has three fuel fabrication facilities, one in the US, one in Sweden and one in the United Kingdom (UK). In addition, it has about 90 facilities, engineering centers, and workshops, with a presence in more than 20 countries, including major nuclear component fabrication facilities in the US and Italy.
| 2023 ANNUAL INFORMATION FORM | Page 79 |
| Corporate headquarters | Cranberry Township, Pennsylvania (United States) | |
| Ownership | 49% - equity-accounted | |
| Employees | ~ 10,000 | |
| Business activities | Operations and maintenance of installed base (core business): Designs and manufactures nuclear fuel supplies and services for light water reactors. Provides outage and maintenance services, engineering support, instrumentation and controls equipment, plant modifications, and components and parts to nuclear reactors. | |
| New build: Designs, develops and procures equipment for new nuclear plant projects. This also includes design for new small and micro reactors. | ||
| Certifications | ISO 14001 | |
| ISO 45001 | ||
| Estimated decommissioning cost | $231.1 million (US) | |
Background
On November 7, 2023, we announced the closing of the acquisition of Westinghouse in partnership with Brookfield. Brookfield beneficially owns a 51% interest in Westinghouse, and we beneficially own 49%. Bringing together Cameco’s expertise in the nuclear industry with Brookfield’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.
To finance Cameco’s 49% share of the purchase price, equaling $2.1 billion (US), we used $1.5 billion (US) of cash and drew the full amount of both $300 million (US) tranches of the term loan put in place concurrently with the execution of the acquisition agreement, and which mature two years and three years from the date of close. The $280 million (US) bridge commitment that we also secured concurrently with the acquisition agreement was not required to complete the transaction and was terminated.
The acquisition of Westinghouse was completed in the form of a limited partnership with Brookfield. The board of directors governing the limited partnership consists of six directors, three appointed by Cameco and three appointed by Brookfield. Decision-making by the board corresponds to percentage ownership interests in the limited partnership (51% Brookfield and 49% Cameco). However, decisions with respect to certain reserved matters under the partnership agreement, such as the approval of the annual budget, require the presence and support of both Cameco and Brookfield appointees to the board as long as certain ownership thresholds are met.
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We believe Westinghouse is well-positioned for long-term growth driven by the expected increase in global demand for nuclear power. As of November 7, 2023, we receive the economic benefit of our ownership in Westinghouse. We account for our proportionate interest in Westinghouse on an equity basis.
We expect this strategic acquisition will be transformative and accretive to Cameco. We are enhancing our ability to compete for more business by investing in additional nuclear fuel cycle assets that we expect will augment the core of our business and offer more solutions to our customers across the nuclear fuel cycle. Like Cameco, Westinghouse has nuclear assets that are strategic, proven, licensed and permitted, and that are in geopolitically attractive jurisdictions. We expect these assets, like ours, will participate in the growing demand profile for nuclear energy.
Cash distributions
Annually, Cameco and Brookfield (the partners) approve a budget and business plan which outline Westinghouse’s financial projections and capital allocation priorities. The determination of whether to make cash distributions to the partners will be reviewed quarterly based on the approved budgeted expenditures and capital allocation priorities, including growth investment opportunities, as well as available cash balances. However, the timing of cash distributions is expected to be aligned with the timing of Westinghouse’s cash flows, which are typically higher in the fourth quarter.
The financial information in the sections below is derived from the annual consolidated financial statements of Westinghouse, which are reported in US dollars and prepared in accordance with US GAAP. Such numbers have been updated to reflect IFRS differences to conform with Cameco’s accounting convention and are reflected on a 100% basis due to Cameco using equity accounting for its acquisition of a 49% interest in Westinghouse as of November 7, 2023.
Westinghouse debt
As at December 31, 2023, Westinghouse had the following outstanding debt:
| • | $3.5 billion (US) term loan with a maturity of August 2025 |
| • | credit facilities of $400 million (US), which had drawings of $115 million (US) and mature in June 2026 |
| • | drawn financial assurances including letters of credit of $474 million (US) and surety bonds of $262 million (US) |
Effective January 25, 2024, Westinghouse refinanced its existing debt and entered into various credit agreements, which now provide total borrowing capacity of $4.6 billion (US), comprised of:
| • | $3.5 billion (US) term loan which now matures on January 25, 2031, and has quarterly repayments of $8.75 million (US), with any remaining amounts due at maturity. The term loan is priced at the applicable term SOFR rate plus a margin that is currently 2.75% |
| • | credit facilities totaling $500 million (US), which mature in January 2029 |
| • | financial assurances including letters of credit in the amount of about $570 million (US) and surety bonds of $262 million (US) |
The credit agreements are non-recourse to Cameco, but come with certain covenants, which if breached, could result in all amounts outstanding thereunder to be immediately due and payable by Westinghouse. We expect Westinghouse to continue to comply with these covenants in 2024.
Cameco filed a Form 51-102F4 business acquisition report in respect of its acquisition of Westinghouse on January 19, 2024. The report is available on Cameco’s issuer profile on SEDAR+ at www.sedarplus.com.
Business activities
Westinghouse’s main business activities span two key stages of the life cycle of a nuclear reactor: (i) the operations and maintenance of the installed base (core business), and (ii) the design and build of new nuclear reactors.
| 2023 ANNUAL INFORMATION FORM | Page 81 |
Westinghouse’s 2023 revenue by region was as follows:
| * | EMEA means Europe, Middle East and Africa. |
Core business
Westinghouse’s core business covers two main business units: Operating plant services (OPS) and nuclear fuel.
Operating plant services
Westinghouse’s largest business unit is OPS, which accounted for approximately $2.5 billion (US) of Westinghouse’s 2023 revenue, representing about 55% of such revenue. This business unit generates revenue through four business lines:
(i) outage and maintenance services; (ii) engineering services; (iii) instrumentation and controls; and (iv) parts. Through these four business lines, Westinghouse provides services including refueling, maintenance, inspection and repair during regulation-mandated outages. Westinghouse also offers solutions to enhance the reliability, safety, lifespan, and cost-effectiveness of customer operations and supplies replacement parts and products as well as operational and technical support.
Outage and maintenance services generates revenue entirely from providing refueling, maintenance, inspection and repair services to the existing global installed reactor base and is not reliant on new plant projects. These services are provided under long-term customer relationships and demand is driven by safety related maintenance, regulatory compliance, and asset performance.
Engineering services generates stable revenue by engineering bespoke replacement components or equipment, and engineering studies to validate that changes to plant operation are within plant design safety margins, and through studies designed to establish the best course of action to improve plant performance (e.g. do nothing, repair, replace) for emergent issues. Demand for these services is driven by the long-term relationships OPS has built with its customers through prompt response to emergent business needs for customers and through providing services to recently completed nuclear units.
Instrumentation and controls generates revenue by providing advanced digital systems that include core safety and non-safety instrumentation, automation, and control systems through product development, design, assembly and testing of advanced products. This business line also provides simulation services for multiple nuclear reactor technologies.
Parts generates revenue by providing specialized manufacturing and commercial dedication capabilities to support Westinghouse’s ability to make tailored parts that are challenging to replicate. Westinghouse can offer qualified replacement parts (e.g., control rod drives) and products (safety and non-safety), as well as operational and technical support. Demand is largely driven by the need for consumables used during and between outages to maintain safe and efficient operation of nuclear power plants.
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Westinghouse’s 2023 revenue by region for OPS was as follows:
| * | EMEA means Europe, Middle East and Africa. |
Nuclear fuel
The 2023 revenue from the nuclear fuel business unit was approximately $1.4 billion (US), representing approximately 33% of Westinghouse’s total 2023 revenue.
The nuclear fuel business unit designs and fabricates highly engineered fuel assemblies that maximize power in a specific reactor. Westinghouse supplies fuel assemblies for a variety of reactor technologies, including pressurized water reactors (PWRs), boiling water reactors, advanced gas-cooled reactors and water-water energetic reactors (VVER). Although Westinghouse’s business in this space is largely focused on PWRs at this time, Westinghouse has made advancements and it is expected to continue to grow in a number of non-PWR technologies, including VVER.
The nuclear fuel business unit enjoys long-term customer relationships and has predictable demand for its products and services. To allow consistent power generation these reactors require an outage to refuel every 18 to 24 months during which one-third of the fuel assemblies are replaced.
Westinghouse’s 2023 revenue by region for nuclear fuel was as follows:
| * | EMEA means Europe, Middle East and Africa. |
| 2023 ANNUAL INFORMATION FORM | Page 83 |
New build
In addition to growth in its core business, the focus on the importance of nuclear power in providing carbon-free, secure and affordable baseload power as an essential part of the electricity grid in many countries is creating new opportunities for Westinghouse’s proven AP1000 reactor design, as well as the smaller reactor designs it has in development. Its technology and experience provide a competitive advantage as the engineering and procurement aspects of new build programs are initiated.
Westinghouse’s new build business unit covers the design, development and procurement of equipment for new plant projects. It provides large plant Gen III and AP1000 nuclear technology globally. In addition to its AP1000 reactor design, Westinghouse has submitted its pre-application Regulatory Engagement Plan with the NRC for the development of its AP300™ small modular reactor, which is based on the proven and licensed AP1000 reactor design. Its eVinci™ microreactor design was recently awarded US Department of Energy funding for a test reactor FEED (front-end engineering design) at Idaho National Lab. The AP300 small modular reactor and the eVinci microreactor are expected to offer the same carbon-free baseload benefits as larger nuclear reactor technologies, but are tailored for specific applications, including industrial, remote mining, off-grid communities, defense facilities and critical infrastructure. As with the AP1000 reactor, they are expected to have applications beyond electricity generation, including district and process heat, desalination and hydrogen production. We are optimistic about the future competitiveness of these technologies and their potential to make a meaningful contribution to Westinghouse’s long-term financial performance. However, they are presently still in the development phase.
The 2023 revenue from the new build business unit was approximately $300 million (US) representing approximately 7% of Westinghouse’s total 2023 revenue.
Westinghouse’s 2023 revenue by region for the new build business was as follows:
| * | EMEA means Europe, Middle East and Africa. |
Contracting status
Following an announcement of a successful bid, there are a number of contracts that must be signed before work commences and revenue is realized. Once contracts are signed and work begins, new build projects are expected to generate multi-year revenue streams and EBITDA for Westinghouse. In addition to the AP1000 reactors already deployed in the US and China, Poland recently signed an engineering services contract for three AP1000 reactors for its new nuclear energy program. Ukraine has also selected the AP1000 reactor for nine units and has signed an engineering services contract for the first unit, and Bulgaria has chosen the AP1000 reactor for two units at the Kozloduy nuclear site and signed a front-end engineering and design (FEED) contract. FEED contracts often precede engineering services contracts, which are required before work can begin.
Westinghouse undertakes its role in the design, development, engineering and procurement of equipment for new reactors. It does not provide construction services or assume any construction risk. This business unit has the potential to add significant long-term value during the construction phase, and then to the core of the business through reactor services and fuel supply contracts once the reactor begins commercial operation.
| 2023 ANNUAL INFORMATION FORM | Page 84 |
See the section titled New build framework starting on page 97 of Cameco’s 2023 annual MD&A for more information.
Competitive position
Demand for Westinghouse’s products and services is being driven by the increasing recognition by policy makers, industry, and general public of the critical role for nuclear energy in providing clean, secure and affordable baseload electricity.
Westinghouse has several critical-to-business suppliers with unique capabilities that are key to delivering Westinghouse’s products to its operating plant and new plant customers. It has long-standing relationships with its key suppliers, and generally has secured long-term agreements with these suppliers to solidify Westinghouse’s business relationships and security of supply. Westinghouse works closely with these suppliers to ensure that pricing and lead times from these suppliers are in line with the market expectations.
Westinghouse’s core business relies heavily on a small number of customers in 46 countries, consisting primarily of utility companies that own nuclear reactors around the globe. Westinghouse’s five largest customers accounted for nearly 30% of Westinghouse’s contracted sales.
Westinghouse’s primary competitors vary based on business unit. For OPS, the market is fragmented with several competitors globally for each business line. For nuclear fuels, Westinghouse has two primary competitors serving the same global customer base. For new build, Westinghouse has two primary competitors that offer similar services.
Business cycles
Westinghouse has a stable and predictable core business generating durable cash flows. Westinghouse’s core business is characterized by recurring and predictable revenue and cash flow streams, the majority of which are secured in advance under long-term contracts with durations that can range from three to more than ten years, depending on the product or service being provided. The 18 to 24 month outage cycle for most reactors drives some variability in its annual cash flow, which tends to be higher in the fourth quarter.
Market opportunities
Amid the ongoing demand growth and global energy security concerns, Westinghouse expects there will be new opportunities to compete for and win new business. Westinghouse’s reputation as a global leader in the nuclear industry and its position as a non-Russian alternative supplier for certified VVER fuel assemblies are expected to benefit its core business as Eastern European countries seek to develop a reliable fuel supply chain independent of Russia.
Intangible assets
Upon acquisition, the fair value of intangible assets was determined as part of the purchase price allocation. Intangible assets includes customer relationships and contracts, developed technology, the Westinghouse trade name, and product development costs.
Estimating decommissioning and environmental remediation costs
Westinghouse’s decommissioning provisions relate to the decommissioning of its fuel fabrication facilities, other licensed nuclear facilities and contaminated equipment at those locations.
Westinghouse develops conceptual decommissioning plans for its operating sites and uses them to estimate its decommissioning costs. The plans are submitted to regulators to determine the amount of financial assurance it must provide to secure its decommissioning obligations. Its plans include reclamation techniques that Westinghouse believes will generate reasonable environmental and radiological performance. Regulators give “conceptual approval” to a decommissioning plan if they believe the concept is reasonable.
The decommissioning plans are reviewed every one to five years. The cost estimates for both accounting purposes and licence applications are also reviewed. 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.
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At the end of 2023, Westinghouse had estimated total decommissioning and reclamation costs of $231.1 million (US). This is the discounted value of the obligation and is based on its current operations. Regulatory approval is required prior to beginning decommissioning. The expected timing for these costs is based on each facility’s expected operating life. The required costs for decommissioning and reclamation in each of the next five years are not expected to be material.
Westinghouse provides financial assurances using surety bonds for decommissioning liabilities to regulatory authorities, as required. It had a total of about $227 million (US) in surety bonds supporting decommissioning liabilities at the end of 2023. All of its fuel fabrication facilities have financial assurances in place in connection with the preliminary plans for decommissioning each of the sites.
In addition to these decommissioning obligations, Westinghouse has environmental remediation obligations associated with the discharge of pollutants and the disposal of waste associated with ongoing operations at its sites. At the end of 2023, Westinghouse had estimated total environmental and waste liabilities of $43.7 million (US).
Complying with regulations
Nuclear safety regulators licence Westinghouse site activities worldwide and oversee the work done with customers. Licencing requires compliance with stringent regulations, advanced training, and comprehensive programs.
Westinghouse’s US fabrication facilities are licenced by the NRC and are fully compliant with Federal Regulations. Westinghouse’s non-US fabrication facilities are compliant with regulators in their respective regions. In addition, Westinghouse voluntarily implements industry best practices and standards for safety established by the Institute for Nuclear Power Operations (INPO) and the World Association of Nuclear Operators (WANO).
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 we hold an option to attain a majority interest of 75% ownership. Silex Systems Ltd. (Silex Systems) owns the other 51% interest in GLE and is the licensor of the SILEX laser enrichment technology and the technology lead for GLE.
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, including:
| • | re-enriching depleted uranium tails leftover as a by-product of first-generation gaseous diffusion enrichment operation, repurposing legacy waste into a commercial source of uranium and conversion products to fuel nuclear reactors and aiding in the responsible clean-up of legacy tails inventories, as per GLE’s agreement with the US Department of Energy (DOE); |
| • | producing commercial low-enriched uranium (LEU) to fuel the world’s existing and future fleet of large-scale light-water reactors (and depending on market developments, SMR’s that also require LEU-based fuel) with greater efficiency and flexibility than current enrichment technologies; and |
| • | producing high-assay low-enriched uranium (HALEU), if a market for that fuel stock develops to serve a number of small modular reactor (SMR) and advanced reactor designs that might be commercially deployed and require HALEU-based fuel |
Our view is that re-enriching US government inventories of depleted uranium tails into a commercial source of uranium and conversion is GLE’s lowest-risk path to the market. This opportunity is underpinned by an agreement GLE has with the DOE to upgrade depleted uranium tails leftover from DOE’s historic enrichment operations, which may help address the growing supply gap for Western nuclear fuel supplies and services.
With the support of both Cameco and Silex Systems, GLE has accelerated its technology demonstration project activities to target an earlier delivery of the successful demonstration of Technology Readiness Level 6 (TRL-6). TRL-6 achievement will confirm large-scale system performance under relevant conditions (pilot-scale demonstration), which represents a major step up in a technology’s demonstrated readiness. Of note, GLE received the second full-scale laser system module from Silex Systems last year, which was installed in GLE’s pilot demonstration facility in the US. GLE’s efforts to bring forward planned activities and expenditures under the technology demonstration program are intended to demonstrate TRL-6 this year. Earlier TRL-6 demonstration may provide optionality for GLE to pursue government and industry support and funding related to potential commercial deployment opportunities (LEU and, potentially, HALEU) that could precede tails re-enrichment if the right conditions exist.
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Unless another commercial deployment opportunity materializes, GLE will continue its work to complete the technology demonstration project with the potential to deploy its enrichment technology at a commercial scale in Western Kentucky under its agreement with the DOE no later than 2030. GLE’s path to commercialization depends on several factors, including but not limited to the successful progression and completion of GLE’s technology demonstration and maturation program, a clear commercial use case, sound market fundamentals, clarity regarding future Russian fuel imports, the ability to secure substantial government support and funding (specifically, accelerated commercial pathways related to LEU and, potentially, HALEU are reliant on government funding) and long-term industry support.
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, 2023.
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 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 |
| • | indicated resources: we can reasonably assume geological and grade continuity to support mine planning |
| • | Inferred mineral resources are estimated using limited geological evidence and sampling information. We do 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 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.
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 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 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 $54 (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.
| 2023 ANNUAL INFORMATION FORM | Page 87 |
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
• Daley McIntyre, general manager, Key Lake, Cameco
• Alain D. Renaud, principal resource geologist, technical services, Cameco
• Biman Bharadwaj, principal metallurgist, technical services, Cameco |
• Lloyd Rowson, general manager, Cigar Lake, Cameco
• Scott Bishop, director, technical assurance & mineral reserves, technical services, Cameco
• Alain D. Renaud, principal resource geologist, technical services, Cameco
• Biman Bharadwaj, principal metallurgist, technical services, Cameco |
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| Inkai | ||
| • Sergey Ivanov, deputy general director, technical services, Cameco Kazakhstan LLP
• Alain D. Renaud, principal resource geologist, technical services, Cameco
• Scott Bishop, director, technical assurance & mineral reserves, technical services, Cameco
• Biman Bharadwaj, principal metallurgist, technical services, Cameco |
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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:
| • geological interpretation
• extraction plans
• commodity prices and currency exchange rates |
• recovery rates
• operating and capital costs |
| 2023 ANNUAL INFORMATION FORM | Page 88 |
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 107 for a discussion of the risks that can affect our business.
Please see pages 91 and 92 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 116. 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 108 |
| • | Technical challenges – see Technical challenges at Cigar Lake and McArthur River at page 109 |
Inkai mineral resource and reserve estimates
| • | Political risks – see Foreign investments and operations at page 129 and Kazakhstan at page 130 |
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, 2023 (100% – only the shaded column shows our share)
Proven and probable
(tonnes in thousands; pounds in millions)
| PROVEN | PROBABLE | TOTAL MINERAL RESERVES | OUR SHARE RESERVES |
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| PROPERTY |
MINING METHOD |
TONNES | GRADE % U3O8 |
CONTENT (LBS U3O8) |
TONNES | GRADE % U3O8 |
CONTENT (LBS U3O8) |
TONNES | GRADE % U3O8 |
CONTENT (LBS U3O8) |
CONTENT (LBS U3O8) |
METALLURGICAL RECOVERY (%) |
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| Cigar Lake |
UG | 338.1 | 18.11 | 135.0 | 217.5 | 15.36 | 73.7 | 555.6 | 17.03 | 208.6 | 113.8 | 98.7 | ||||||||||||||||||||||||||||||||||||
| Key Lake |
OP | 61.1 | 0.52 | 0.7 | — | — | — | 61.1 | 0.52 | 0.7 | 0.6 | 95.0 | ||||||||||||||||||||||||||||||||||||
| McArthur River |
UG | 2,047.3 | 7.02 | 316.8 | 520.7 | 5.55 | 63.8 | 2,568.0 | 6.72 | 380.5 | 265.6 | 99.0 | ||||||||||||||||||||||||||||||||||||
| Inkai |
ISR | 239,588.4 | 0.04 | 208.8 | 66,046.9 | 0.04 | 52.9 | 305,635.3 | 0.04 | 261.7 | 104.7 | 85.0 | ||||||||||||||||||||||||||||||||||||
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| Total |
242,035.0 | — | 661.2 | 66,785.0 | — | 190.3 | 308,820.1 | — | 851.5 | 484.7 | — | |||||||||||||||||||||||||||||||||||||
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(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 $54 (US) per pound U3O8 |
| • | are based on exchange rates of $1.00 US=$1.26 Cdn and $1.00 US=450 Kazakhstan Tenge |
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.
| 2023 ANNUAL INFORMATION FORM | Page 89 |
Changes this year
Our share of proven and probable mineral reserves increased from 469 million pounds U3O8 at the end of 2022, to 485 million pounds at the end of 2023. The change was primarily the result of:
| • | mineral resource estimate update at Cigar Lake Extension and subsequent conversion of indicated mineral resources adding 40 million pounds to probable reserves. |
partially offset by:
| • | production at Cigar Lake, Inkai and McArthur River, which removed 22 million pounds of proven and probable reserves from our mineral inventory |
The remaining changes are attributable to other adjustments based on the mineral resource and reserve estimate updates at Cigar Lake, McArthur River and Inkai.
Mineral resources
As of December 31, 2023 (100% – only the shaded columns show our share)
Measured, indicated and inferred
(tonnes in thousands; pounds in millions)
| MEASURED RESOURCES (M) | INDICATED RESOURCES (I) | OUR SHARE |
INFERRED RESOURCES | OUR SHARE |
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| 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 |
86.3 | 5.32 | 10.1 | 143.6 | 5.33 | 16.9 | 27.0 | 14.7 | 163.4 | 5.55 | 20.0 | 10.9 | ||||||||||||||||||||||||||||||||||||
| 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 |
78.7 | 2.27 | 3.9 | 60.6 | 2.30 | 3.1 | 7.0 | 4.9 | 37.2 | 2.90 | 2.4 | 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 | ||||||||||||||||||||||||||||||||||||
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| Total |
121,172.8 | — | 183.7 | 113,300.7 | — | 323.4 | 507.1 | 408.8 | 51,747.1 | — | 201.3 | 153.2 | ||||||||||||||||||||||||||||||||||||
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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 |
Changes this year
Our share of measured and indicated mineral resources decreased from 451 million pounds U3O8 at the end of 2022, to 409 million pounds U3O8 at the end of 2023. Our share of inferred mineral resources decreased from 154 million pounds U3O8 at the end of 2022, to 153 million pounds U3O8 at the end of 2023.
| 2023 ANNUAL INFORMATION FORM | Page 90 |
Key assumptions, parameters and methods
McArthur River
Key assumptions
| • | Mineral reserves assume a 99.4% planned mine recovery and have allowances for expected waste (33.6% average) and backfill (5.5% average) dilution as part of the normal mining extraction process. Mineral resources do not include such allowances. |
| • | A constant dollar average uranium price of $54 (US) per pound 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 18 million pounds. |
Key parameters
| • | Grades of U3O8 were obtained from chemical assaying of drill core or from equivalent % U3O8 grades 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 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 0.90% U3O8. |
| • | Mineral reserves are estimated based on the use of raisebore and blasthole stope mining methods in conjunction with freeze curtains. |
| • | Reasonable expectation for eventual economic extraction of the mineral resources is based on a uranium price of $62 (US) per pound U3O8, anticipated exchange rates, mining and process recoveries, production costs, royalties and mineralized area tonnage, grade, and spatial continuity considerations. |
Key methods
| • | The models were created from the geological interpretation in section views and in 3-dimensions from surface and underground drillhole information. |
| • | Mineral resources and mineral reserves were estimated using 3-dimensional 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. |
Cigar Lake
Key assumptions
| • | Mineral reserves have been estimated with an average allowance of 34% dilution at 0% U3O8 and an 86% mining recovery factor. Mineral resources do not include such allowances. |
| • | The mining rate is assumed to vary between 115 and 160 tonnes per day and a full mill production rate of approximately 18 million pounds U3O8 per year. |
| • | Areas being mined must meet specific ground freezing requirements before jet boring begins. |
| • | A constant dollar average uranium price of $54 (US) per pound U3O8 with a $1.00 (US) = $1.26 (Cdn) fixed exchange rate was used to estimate the mineral reserves. |
Key parameters
| • | Grades of U3O8 were obtained from chemical assaying of drill core or from equivalent % U3O8 grades 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 drill core and chemical assay grades. |
| • | Mineral resources have been estimated using a minimum mineralization thickness of 1.0 metre and a minimum grade of 1.0% U3O8 for the eastern part of the deposit and 0.8% U3O8 for the western portion. |
| 2023 ANNUAL INFORMATION FORM | Page 91 |
| • | Mineral reserves have been estimated on the basis of designed JBS cavities with positive economics from the estimated recovered uranium. |
| • | Reasonable expectation for eventual economic extraction of the mineral resources is based on a uranium price of $62 (US) per pound U3O8, anticipated exchange rates, mining and process recoveries, production costs, royalties and mineralized area tonnage, grade, and spatial continuity considerations. |
Key methods
| • | The geological interpretation of the orebody was done in section views and in 3-dimensions from surface drillhole information. |
| • | Mineral resources and mineral reserves were estimated using 3-dimensional 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. |
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 $54 (US) per pound U3O8, with a $1.00 US = $1.26 Cdn and 450 Kazakhstan Tenge to $1.00 US fixed exchange rate was used to estimate the mineral reserves. |
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 measurements. |
| • | Mineral resources are estimated using a minimum grade of 0.012% 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 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 $62 (US) per pound U3O8, anticipated exchange rates, mining and process recoveries, production costs, royalties and mineralized area 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 information. |
| • | Mineral resources were estimated with the GT area average method, where the estimated variable is the uranium 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. |
| • | Considerations of the rate of in situ uranium recovery, lixiviant uranium head grades, wellfield flow rates and production requirements to define the production sequence. |
| • | Geological modelling and mining software used were AtomGeo, MapInfo and Micromine. |
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.
| 2023 ANNUAL INFORMATION FORM | Page 92 |
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. Key findings from this work were actioned throughout 2022 and 2023, including the undertaking of physical and transition-related climate scenario analyses to inform our overarching climate strategy. In 2023, the IFRS published its first two sustainability standards, S1 sustainability disclosure standard and S2 climate-related disclosure via the International Sustainability Standards Board. While it is unclear when and to what extent the Canadian Securities Administrators may adopt these standards at this point, we have begun the work to better understand the requirements under these standards and how our current reporting aligns with these standards.
In July 2023, we published our 2022 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 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 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 (GHG) emissions is important and necessary in Canada and around the world. Policy makers and major industries recognize that nuclear power must be a central part of the solution to the world’s shift to a low-carbon, climate-resilient economy. Several nations have reaffirmed their commitments to nuclear power and are developing plans to support existing reactors and are reviewing their policies to encourage more nuclear capacity. There are now 28 countries that have signed on to the declaration that was launched at COP28 to triple nuclear energy capacity by 2050.
As one of the world’s largest producers of the uranium needed to fuel nuclear reactors, we believe this represents a significant opportunity for us to be part of the solution to combat climate change given 100% of our product is used to produce clean, carbon-free baseload electricity. We enable vast emissions reductions globally through nuclear power and are committed to transforming our already low operational GHG emissions footprint to achieve our ambition of having net-zero emissions while delivering significant long-term business value.
Recently, we put further support behind our commitment to climate action and our vision of energizing a clean-air world by joining Net Zero Nuclear as a corporate partner. Net Zero Nuclear is an initiative between government, industry leaders and civil society to triple global nuclear capacity to achieve carbon neutrality by 2050. We join the initiative as a Gold Partner, deepening industry support for this initiative, which was launched by the World Nuclear Association and the Emirates Nuclear Energy Corporation, with the support of the Atoms4NetZero initiative launched by the International Atomic Energy Agency at the 2023 World Nuclear Symposium in London.
In 2022, we undertook a planning process to outline our overarching Low Carbon Transition Plan. Within this plan, we set a target to reduce our combined Scope 1 and 2 GHG emissions by 30% by 2030, from 2015 levels. We also 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”. Our Low Carbon Transition Plan provides a foundation for managing our climate-related physical and transition risks, and it supports us in better aligning with the Government of Canada’s Net Zero Accountability Act and 2030 Emission Reduction Plan.
| 2023 ANNUAL INFORMATION FORM | Page 93 |
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 Plan, we have completed climate change scenario analyses to understand how projected long-term changing climate conditions could impact our employees, assets, and operations in northern Saskatchewan and Ontario, Canada. We leveraged internal subject matter expertise with help from a third-party expert to complete the assessments.
The physical risk assessment studies were undertaken to deliver initial forward-looking physical climate risk assessments and identify possible risk management and adaptation options across our mining, milling and fuel services operations. In 2024, we will focus on updating the findings from these physical climate risk assessments into our internal risk management review and developing an adaptation action plan template. The template will support the development of site-specific adaptation plans for each of our Canadian operations. We are targeting the completion of physical climate risk assessments for all our majority owned and operated facilities by the end of 2026.
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.
To support achieving our 2030 GHG emissions reduction target, we implemented a 2023 compensable target to create tailored decarbonization pathways for each operationally controlled site. The 2023 work included an evaluation of over 160 decarbonization project ideas solicited from across the organization. Project ideas were evaluated based on cost, emissions reduction potential, implementation timeline, and other co-benefits as outlined by the climate action factors recently integrated within our Capital Allocation Committee process. The site-specific decarbonization pathways also included the development of practical project implementation timelines considering life of asset plans for each operation and technological readiness of the relevant technologies. Decarbonization efforts are already underway across our five decarbonization themes: efficiency, electrification, waste to value, fuel switching and carbon economy.
Over the past few years, we have put significant effort towards efficiency, our first decarbonization theme. We have been focused on improving the visibility of energy consumption within our organization and implementing improvements to reduce energy consumption. We have already 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. In 2023, the Port Hope Closed Loop Cooling Water system was commissioned, eliminating the need to draw water from the nearby harbour. With the new closed loop system, the operation is no longer dependent on the temperature or quality of the lake water. This project has positive benefits for both the overall reliability and our environmental footprint, decreasing the energy required to change the temperature of the water and eliminating the risk of environmental releases to the lake.
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. Two projects were advanced in 2023 at our northern Saskatchewan operations: LED lighting updates to Key Lake and Ventilation-on-Demand at McArthur River. At Key Lake, we have made upgrades in lighting, updating to LED, translating to annual reductions of approximately 725,000 kWh electricity savings or 375 tonnes of CO2e. Additionally, this project improves operator comfort and safety when working in these areas. At McArthur River, the Ventilation-on-Demand project is currently underway. It includes mine ventilation upgrades to surface heater fans and underground ventilation dampers to enable a reduction in both electricity and propane consumption.
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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.
We have a five-pillar approach to develop and maintain long-term relationships and provide opportunities to those living in areas near our operations. The five-pillars include workforce development, business development, community investment, environmental stewardship, and community engagement. To strengthen relationships and shape them into mutually beneficial partnerships, we have collaboration agreements in northern Saskatchewan and Ontario that follow this approach. These agreements allow us to collaboratively determine focus areas based on a community’s unique needs, optimizing benefits to the community, providing certainty around community investment and local business opportunities.
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 and cyber 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.
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See Managing the risks, starting on page 70 of our 2023 MD&A, for a discussion of the material risks, and the specific risks discussed under each operation, advanced project, and other fuel cycle investment update in our 2023 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 107 of this AIF which includes a discussion of other material risks that could have an impact on our business. 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.
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: (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.
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. For more information on our compensation targets and our reported performance against those targets, see the Measuring our results section in our 2023 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) |
| • | 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.
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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 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 135 for more information.
Industry governance
The Nuclear Safety and Control Act (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.
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.
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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 are required to carry out surface exploration) |
| • | a crown lease with the province gives us the right to mine the minerals on the property |
| • | a surface lease with the province gives us the right to use the land for surface facilities and mine 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 The Crown 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.
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.
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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 Environmental Protection 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 64.
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 (IAA) along with changes to the Fisheries Act and introduced the Canadian Navigable Waters Act. 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. In October 2023, the Supreme Court of Canada ruled that parts of the IAA were outside the federal government’s competence and thus unconstitutional. In response, the federal government is currently reviewing this legislative framework and amendments to the IAA may be proposed in 2024, although no timeline for tabling and passing the amendments has been announced. Accordingly, we are unable to assess the implications of the amendments at this time.
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 |
| • | environmental monitoring |
| • | fire protection |
| • | operational quality assurance |
| • | organization and management systems effectiveness |
| • | transportation systems |
| • | geotechnical monitoring |
| • | training |
| • | ventilation systems |
| • | waste 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 and Ontario, Canada. We leveraged internal subject matter expertise with the assistance of a third-party expert to complete the assessments. See Our ESG principles and practices – environment starting on page 94.
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 by the Nebraska Department of Environmental Quality and the NRC. Restoration of Smith Ranch-Highland wellfields is regulated by the WDEQ.
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See page 106 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 Ecological Code, 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.
JV Inkai has environmental insurance, as required by the 2007 Ecological Code, the 2021 Ecological Code, and the resource use contract.
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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 2017, CRA has advanced an alternate reassessing position, see Reassessments, remittances 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. In October 2023, pursuant to a cost award from the courts, we received a payment of approximately $12 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 of the $780 million in cash and letters of credit we 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.
In March 2023, CRA issued revised reassessments for the 2007 through 2013 tax years, which resulted in a refund of $297 million of the $780 million in cash and letters of credit held by CRA at the time. The refund consisted of cash in the amount of $86 million and letters of credit in the amount of $211 million, which were returned in the second quarter. CRA continues to hold $483 million ($209 million in cash and $274 million in letters of credit) that we have remitted or secured to date for these tax years.
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 $5.1 billion to $3.3 billion, resulting in a reduction of $1.8 billion in income taxable in Canada compared to the previous reassessments issued to us by CRA for the 2007 through 2013 tax years.
The remaining transfer pricing adjustment of $3.3 billion for the 2007 to 2013 tax years relates to the sale of Canadian-produced uranium by our foreign subsidiary. We maintain 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 all cash and security being held.
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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 all 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, we received a reassessment for the 2015 and 2016 tax years and in late 2023, we received a reassessment for the 2017 tax year, all reflecting this alternative reassessing position. CRA did not require additional security for the tax debts they considered owing for 2014 through 2016 but did require additional letters of credit related to the tax debts they considered owing for 2017 as discussed above. We have issued letters of credit in the amount of $70 million as security for 2017. Coupled with the amounts still being held for the 2007 through 2013 tax years, CRA now holds about $553 million as security ($209 million in cash and $344 million in letters of credit).
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 2017 filing positions. On October 12, 2022, we filed an appeal with the Tax Court for the years 2014 and 2015., We filed a notice of objection in March 2023 for 2016 and recently filed a notice of objection for 2017. We are confident the courts would reject any attempt by CRA to utilize its alternate reassessing position for tax years 2014 through 2017 and believe CRA should return all cash and letters of credit being held. However, timing of any further payments is uncertain, and there can be no assurance that the courts will take this position.
We will not be in a position to determine the definitive outcome of the 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 2017.
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
| • | 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
| • | 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 |
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:
| • | Basic royalty: This royalty is calculated as 5% of gross sales of uranium, less the Saskatchewan resource credit of 0.75%. |
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| • | Profit royalty: A 10% royalty is charged on profit up to and including $28.182/kg U3O8 ($12.78/lb) and a 15% royalty is charged on profit in excess of $28.182/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. |
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 2023 was $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% beginning in 2024. Switzerland, Luxembourg, and Germany have all enacted or substantively enacted these rules.
US taxes
Our subsidiaries in Wyoming and Nebraska pay severance taxes, property taxes and Ad Valorem taxes in those states. They incurred $0.81 million (US) in taxes in 2023.
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 introduced to the 2018 Tax Code as briefly described below:
| • | Starting January 1, 2023, significant changes were introduced in relation to computation of the mineral 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 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 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% withholding tax on dividends under the Canada-Kazakhstan double taxation treaty (subject to compliance with certain requirements). |
| • | Starting January 1, 2023, the 3% limitation on deductions (for corporate income tax purposes) applies to the expenses incurred for the purchase of certain services from a non-resident related party registered in a state with favorable taxation. |
| • | Tax authorities have expanded authority to recognize a notification on high-risk violations as non-fulfilled when the tax authority disagrees with the circumstances stated in the taxpayer’s explanation. Further, tax authorities will no longer issue a decision on recognizing a notification as not fulfilled in cases when a notification is not fulfilled in accordance with the procedure and within the time limited provided by paragraph 2 of Article 96 of the 2018 Tax Code. Moreover, when a taxpayer submits an explanation to a notification on cameral control with a medium risk degree, it has the right (but is not obliged) to attach to the explanation extracts from their tax and/or accounting registers (records) and/or documents related to the specified violations confirming the accuracy of data entered in tax returns. |
| • | According to the recent amendments, subparagraph 7 of paragraph 1 of Article 118 of the 2018 Tax Code, debit operations on bank accounts of a taxpayer may be suspended only in the case of a failure to fulfil the notification on cameral control. However, the recognition by a tax authority of a notification on the elimination of violations as not fulfilled does not serve as a ground for suspension of debit transactions on bank accounts. |
| • | Apart from the above, certain changes were introduced to the VAT refund rules (i.e., changes to the formation of the report “Pyramid”, confirmation of elimination of violations, etc.). |
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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.
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 and reclamation 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 2023, 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 $1.05 billion at the end of 2023 (the present value of the $1.36 billion). Regulatory approval is required prior to beginning decommissioning. The expected timing for these costs is based on each mine or fuel service facility’s expected operating life. Our required costs for decommissioning and reclamation in each of the next five years are not expected to be material. However, we may choose to undertake progressive reclamation activities, for example, as we do at our US assets and through our Vision in Motion project at our Port Hope fuel services facilities.
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 $1.06 billion in financial assurances supporting our reclamation liabilities at the end of 2023. This amount is based on the approved preliminary decommissioning estimates and will increase to reflect the submitted preliminary decommissioning estimate amounts once they are approved. All of our North American operations have financial assurances in place in connection with our preliminary plans for decommissioning of the sites.
Please also see note 16 to our 2023 financial statements for our estimate of decommissioning and reclamation costs and related financial assurances.
Canada
Decommissioning estimates1
| (100% basis) | ||||
| McArthur River |
$ | 50.6 million | ||
| Rabbit Lake |
$ | 294.8 million | ||
| Key Lake |
$ | 276.7 million | ||
| Cigar Lake |
$ | 73.8 million | ||
| 1 | These amounts represent the submitted, but not yet approved, PDP and PDCE values. |
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.
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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.
Decommissioning estimates
| (100% basis) |
||||
| Port Hope |
$ | 138.2 million | 1 | |
| Blind River |
$ | 57.5 million | ||
| CFM |
$ | 10.8 million | ||
| 1 | This amount is to be reviewed at the 2024 Commission hearing. |
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 and the letter of credit was updated in March 2017. In 2022, as part of the required five-year update schedule, we submitted a revised preliminary decommissioning estimate for Port Hope, which has been accepted by CNSC staff and a Commission hearing is being set for 2024. The letter of credit will be revised after receiving approval from the CNSC through the Commission hearing.
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 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 $62 million (US). We have provided the state of Nebraska with $62 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 $239 million (US), including North Butte. We have provided the state of Wyoming with $239 million (US) in financial assurances as security for decommissioning the property.
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Westinghouse and JV Inkai
Please see Estimating decommissioning and environmental remediation costs on page 85 for information on Westinghouse’s decommissioning obligations.
Please see Decommissioning on page 64 for information on JV Inkai’s decommissioning obligations in Kazakhstan.
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, investments, or planned operations. 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. Many of these risks, or similar risks, also apply to our JV Inkai partnership as well as our investment in Westinghouse. Such risks to JV Inkai or Westinghouse also could have a significant impact on our earnings, cash flows, or financial condition, which may result in a significant decrease in the market price of our common shares. 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 2023 MD&A.
Types of risk
| • | Operational |
| • | Financial |
| • | Governance and compliance |
| • | Environmental |
| • | Social |
| • | 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 chemicals (such as a release of UF6 or anhydrous hydrogen fluoride used in the UF6 conversion process or release of ammonia at our mining and milling operations), or a tailings facility failure |
| • | environmental incidents (including hazardous emissions from our refinery and conversion facilities) |
| • | industrial safety accidents |
| • | equipment failures |
| • | fires |
| • | transportation incidents, which may involve radioactive or other hazardous materials |
| • | transportation and delivery disruptions |
| • | labour shortages, disputes or strikes |
| • | availability of personnel with the necessary skills and experience |
| • | cyberattacks |
| • | joint venture dispute or litigation |
| • | non-compliance with legal requirements, including exceedances of applicable air or water limits or requirements |
| • | inability to obtain and renew the licences and other approvals needed to operate, restart, and to increase production at our mines, mills, and processing facilities, or to develop new mines, or for Westinghouse to operate its fuel fabrication or other facilities or undertake its other commercial activities |
| • | workforce health and safety or increased regulatory burdens resulting from a pandemic or other causes |
| • | 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) |
| • | blockades or other acts of social or political activism |
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| • | cost increases for labour, contracted or purchased materials, supplies and services |
| • | shortages of, or interruptions in the supply of, required equipment, materials, and supplies (including anhydrous hydrofluoric acid at our conversion facilities) |
| • | interruptions in the supply of electricity, water, and other utilities or other infrastructure |
| • | inability of our innovation initiatives to achieve the expected cost saving and operational flexibility objectives |
| • | 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) |
| • | unusual, unexpected or adverse mining or geological conditions |
| • | underground water inflows at our mining operations |
| • | ground movement or cave-ins at our mining operations |
| • | 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 these properties |
| • | personal injury or death |
| • | environmental damage |
| • | delays in, 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 operations |
| • | costs, expenses, or monetary losses |
| • | legal liability |
| • | 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.
JV Inkai and Westinghouse operate independently from Cameco, however may be subject to the same or similar operational risks.
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 coverage for our suspended 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.
JV Inkai and Westinghouse also buy insurance to cover losses or liabilities arising from some of the operating risks and hazards listed above, as well as other business risks. Similar risks would apply with respect to their insurance coverage as a result of uninsurable or uninsured risks or insufficient insurance coverage.
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.
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A water inflow could have a material and adverse effect on us, including:
| • | significant delays or interruptions in production or lower production |
| • | 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.
McArthur River
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 49 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.
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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.
The extended period of time the assets were on care and maintenance, the operational changes made, aging infrastructure, and commissioning issues that we have worked through at the mill caused delays to the production schedule in 2022 and 2023. 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.
JV Inkai and Westinghouse operate independently from Cameco, but have similar risks related to information technology systems.
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.
Cameco manages these facilities in accordance with Mining Association of Canada’s Towards Sustainable Mining Tailings Management Protocol, which provides a comprehensive approach across the entire life cycle of a tailings facility, from the initial planning through to closure and post-closure. Our program includes requirements for an independent tailings review board, annual reviews, and emergency preparedness to complement the robust operating, maintenance and surveillance programs for each TMF. In addition, our active tailings management facilities are in pit with no risk of dam failure. If a TMF 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.
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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.
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.
Mining at JV Inkai is done using in-situ recovery and does not have any associated tailings.
Aging facilities
Our fuel services facilities and mining and 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, JV Inkai and Westinghouse compete with other companies in the mining and nuclear industry on a global basis to attract and retain workers at all levels with appropriate skills and experience necessary to operate our mines, processing and manufacturing facilities and work at our corporate offices. We, JV Inkai and Westinghouse 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, 2023, we had 2,638 employees (including employees of our subsidiaries). This includes 770 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 June 30, 2025. |
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| • | The collective agreement with the bargaining unit employees at the McArthur River and Key Lake operations ended 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. |
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.
A lengthy work interruption could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.
Westinghouse also has unionized employees and has similar risks related to work stoppage and work interruptions.
Occupational health and safety and accident risks
Some of the tasks undertaken by our employees and contractors are inherently dangerous and have the potential to result in serious injury or death. Accordingly, our 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.
We are subject to increasingly stringent laws and regulations governing health and safety matters. Any violation of these obligations, or serious accidents involving our employees, contractors or members of the public, could expose us 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 our financial condition.
JV Inkai and Westinghouse operate independently from Cameco, but have similar risks related to occupational health and safety and accident risks at their 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 and the February 2022 Russian invasion of Ukraine has increased the risk. In 2023, planned production from our fuel services operations was impacted by hydrogen supply issues.
Presently, JV Inkai is experiencing procurement and supply chain issues, most notably, related to the availability of sulfuric acid. KAP announced on February 1, 2024, that it will only produce approximately 80% of its permitted uranium output allowed under SSUAs, instead of the previously announced 90% level, due to difficulties procuring sufficient levels of sulfuric acid and delays in development of new deposits. KAP cited increased demand for sulfuric acid by the agricultural sector for fertilizer production, as well as supply chain disruptions and geopolitical uncertainty, as factors contributing to the procurement issue. Our current target for production at Inkai in 2024 is 8.3 million pounds of U3O8 (100% basis). However, this target is tentative and contingent upon receipt of sufficient quantities of sulfuric acid. In addition, the allocation of such production between the JV Inkai participants is currently under discussion by Cameco and KAP. However, KAP has indicated that if limited availability of sulfuric acid continues through the year, its production plans for 2025 could be negatively impacted. While KAP will actively pursue alternative sources of sulfuric acid, its continued shortage in Kazakhstan could have a material and adverse effect on our earnings, cash flows, financial condition, or results of operations.
Westinghouse is exposed to similar risks related to production inputs and supplies. A shortage of, or disruption in the delivery, of any of these supplies could limit or interrupt their production or increase their production costs.
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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 in the region. We could continue to experience delays in our expected 2024 Inkai deliveries. 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.
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 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.
Intellectual property
Westinghouse has developed and owns various forms of proprietary nuclear intellectual property. To protect its intellectual property rights, Westinghouse may be required to spend significant resources to monitor and protect these rights, including through litigation. Such litigation could be costly and may result in the impairment or loss of portions of Westinghouse’s intellectual property. Furthermore, Westinghouse’s efforts to enforce its intellectual property rights may be met with defenses, counterclaims, and countersuits attacking the validity and enforceability of Westinghouse’s intellectual property rights and may result in invalidation or cancellation of such rights. The costs of protecting its intellectual property rights, as well as the impairment or cancellation of such rights, could have a material adverse effect on Westinghouse’s earnings, cash flows, financial condition, results of operations, or prospects.
In addition, companies have increasingly become subject to infringement threats from non-operating organizations (sometimes referred to as “patent trolls”) filing lawsuits for patent infringement in order to extract settlements. Westinghouse may become subject to claims for infringement and it may be required to defend itself from such claims. All of these types of matters, regardless of their merit, can be time consuming, costly to defend in litigation, divert Westinghouse’s attention and resources, damage Westinghouse’s reputation and cause Westinghouse to incur significant expenses. Westinghouse’s current exposure with respect to pending legal matters could change if determinations by judges and other finders of fact are not in accordance with Westinghouse’s evaluation of such claims. Should Westinghouse’s evaluations prove incorrect and such claims are successful, Westinghouse’s exposure could exceed expectations and have a material adverse effect on its business, financial results and financial condition.
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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.
Failure to comply with nuclear licence and quality assurance requirements at certain Westinghouse facilities could result in costs, additional regulatory oversight 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, and Sweden 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 licences.
Further, Westinghouse operates major nuclear component fabrication facilities in the United States. 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 our business, financial results, and financial condition.
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:
| • | 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 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) |
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| • | 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 uranium tails |
| • | uranium from underfeeding generated using excess enrichment capacity |
| • | sales of excess civilian and military inventories of uranium by governments and industry participants |
| • | levels of uranium production and production costs |
| • | significant production interruptions or delays in expansion plans or new mines going into production |
| • | 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 |
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 notable recovery in 2022 and 2023 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 $US/lb of U3O8 |
||||||||||||||||||||
| 2019 | 2020 | 2021 | 2022 | 2023 | ||||||||||||||||
| High |
$ | 28.90 | $ | 33.93 | $ | 45.75 | $ | 58.20 | $ | 91.00 | ||||||||||
| Low |
24.05 | 24.63 | 27.98 | 43.08 | 50.48 | |||||||||||||||
| Spot UF6 conversion values $US/kg U |
||||||||||||||||||||
| High |
$ | 22.13 | $ | 22.50 | $ | 21.75 | $ | 40.00 | $ | 46.00 | ||||||||||
| Low |
13.75 | 21.50 | 16.10 | 16.25 | 39.75 | |||||||||||||||
The next table shows the range in term prices over the last five years.
| Range of long-term uranium prices $US/lb of U3O8 |
||||||||||||||||||||
| 2019 | 2020 | 2021 | 2022 | 2023 | ||||||||||||||||
| High |
$ | 32.50 | $ | 36.00 | $ | 43.00 | $ | 52.00 | $ | 68.00 | ||||||||||
| Low |
31.00 | 32.50 | 33.50 | 42.88 | 52.50 | |||||||||||||||
| Term UF6 conversion values $US/kg U |
||||||||||||||||||||
| High |
$ | 18.13 | $ | 19.00 | $ | 19.00 | $ | 27.25 | $ | 34.25 | ||||||||||
| Low |
15.50 | 18.00 | 18.00 | 18.50 | 27.50 | |||||||||||||||
Notes:
| • | Spot and long-term uranium prices are the average of prices published monthly by UxC, LLC (UxC) and from The Nuexco Exchange Value, published by TradeTech. |
| • | Spot and term UF6 conversion values are the average of the North American prices published monthly by UxC and from The Nuexco Conversion Value, published by TradeTech. |
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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 as 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 fully realize the benefit immediately 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. As of December 31, 2023, in our uranium segment, our portfolio of long-term contracts totals approximately 205 million pounds. This includes annual average sales commitments over the next five years of about 27 million pounds per year, with commitment levels in 2024 and 2025 higher than the average and in 2026 through 2028 lower than the average. As the market improves, we expect to continue to layer in volumes capturing greater upside using market-related pricing mechanisms. 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.
JV Inkai and Westinghouse operate independently from Cameco, but may be subject to the same or similar volatility and sensitivity to uranium prices.
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.
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.
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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, JV Inkai and Westinghouse establish our operating and capital plans based on the information available 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, JV Inkai and Westinghouse 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 |
| • | Cigar Lake assume that development, mining, milling, and production plans proceed as expected |
| • | Inkai assume that development, mining, and production plans proceed as expected |
| • | Westinghouse assume that their operating and capital 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 |
| • | 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 |
| • | 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 supplies, underground floods, earthquakes, tailings dam failures, lack of tailings capacity, ground movements and cave-ins, outbreak of illness (such as a pandemic), cyber-attacks, or other difficulties |
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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 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 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. 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.
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. Westinghouse’s core business also relies heavily on a small number of customers, consisting primarily of utility companies that own nuclear reactors around the globe.
At December 31, 2023:
| • | in our uranium segment, our five largest customers account for 62% of our contracted supply of U3O8 |
| • | in our fuel services segment, our five largest UF6 conversion customers account for 64% of our contracted supply of UF6 conversion services |
| • | Westinghouse’s five largest customers accounted for nearly 30% of its contracted sales |
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We are a supplier of UO2 used by Canadian CANDU heavy water reactors. Our sales to our largest customer accounted for 45% of our UO2 sales in 2023. In addition, revenues in 2023 from our two largest customers of our uranium segment represented $260 million or approximately 17% of total segment revenues, while revenues from our two largest customers from our conversion segment represented $60 million or approximately 35% of total segment revenues.
Sales for the Bruce A and B reactors represent a substantial portion of our fuel manufacturing business.
If we or Westinghouse 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 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 |
| • | 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.
JV Inkai and Westinghouse operate independently of Cameco, but have similar risks related to counterparty and credit risk.
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 unacceptable level of credit risk |
As of December 31, 2023, 83% of our forecast revenue under contract for the period 2024 to 2026 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.
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 commodity prices and input prices.
We believe our current financial resources are sufficient to support projects planned for 2024, based on the assumption that we will refinance our $500 million debenture on or prior to its June 24, 2024 maturity. 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.
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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.
We also believe JV Inkai and Westinghouse each currently have financial resources and will generate operating cash flows sufficient to support their annual operating budget. Default by Westinghouse under its credit facilities would impact its ability to fund its ongoing operations.
Failure to realize any or all of the anticipated benefits from the acquisition of Westinghouse
Following the acquisition of Westinghouse on November 7, 2023, 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 are subject to numerous risks and uncertainties that may change at any time.
We cannot provide any assurance that the benefits we expect will be achieved on a timely basis or at all.
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 our North American facilities 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 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.
JV Inkai and Westinghouse also have decommissioning and reclamation obligations. If the actual cost or liabilities are significantly higher than current estimates, this could have a material and adverse effect on the financial condition of JV Inkai or Westinghouse.
The liabilities of Westinghouse may exceed our estimates, and there may also be unknown or undisclosed liabilities in connection with its 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. These potential liabilities could negatively impact the value of our investment in Westinghouse. 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 Westinghouse and our ability to realize the benefits thereof.
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In connection with the acquisition, the strategic partnership and the general partner 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.
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.
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 134 for 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 102 and 103. 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.
JV Inkai and Westinghouse operate independently from Cameco, but may be subject to the same or similar litigation risks.
Joint ventures and Partnerships
We participate in McArthur River, Key Lake, Cigar Lake, Inkai, Millennium, GLE, and Westinghouse through joint ventures or partnerships with third parties. Some of these joint ventures are unincorporated and some are incorporated (like JV Inkai and GLE). We have other joint ventures and may enter more in the future.
There are risks associated with joint ventures and partnerships, including:
| • | disagreement with a joint venture participant or partner about how to develop, operate or finance a project |
| • | a joint venture participant or partner not complying with a joint venture or partnership agreement |
| • | possible litigation or arbitration between joint venture participants or partners about joint venture/partnership matters |
| • | the inability to exert control over decisions related to a joint venture/partnership we do not have a controlling interest in |
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 partnership, or have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.
We do not currently control Westinghouse
We do not currently control Westinghouse. We beneficially own 49% of Westinghouse and Brookfield Renewable beneficially owns 51%. Although we will have certain governance and approval rights in connection with our ownership interest in the strategic partnership used for the acquisition, we cannot provide any assurance that Westinghouse will be operated in the same way we would operate Westinghouse if we were its sole owner.
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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 general partner of the strategic partnership, including the right to designate directors of the boards of directors of the general partner and certain material subsidiaries of the general partner and the strategic partnership, our beneficial ownership in the strategic partnership entities is 49%, whereas Brookfield Renewable beneficially owns 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.
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 strategic 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 strategic partnership and general partner. 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 strategic 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 strategic partnership. In the event that the strategic 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 strategic partnership.
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 |
| • | remedial actions that result in temporary or permanent shut-down or reduction of our operations |
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| • | requirements that we compensate communities that suffer loss or damage because of our or their activities |
| • | 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.
JV Inkai and Westinghouse operate independently of Cameco, but are subject to regulatory risks that could impact their financial condition and their operations could be subject to enforcement actions.
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.
Westinghouse operates independently of Cameco and provides their own financial reporting that is subject to similar risks.
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, investment operations 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 programs and policies, including for ESG matters, 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.
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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 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, and on June 21, 2023, the Government of Canada released the UN Declaration Act Action Plan, which includes 181 measures aimed at implementing the goals of UNDRIP from 2023 to 2028. These measures create some additional risk for future activities, which we will continue to monitor in the coming years.
5 – Environmental risks
Complex legislation and environmental, 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 facilities may be adversely affected by the real or perceived impact of our activities on the environment and human health and safety at 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.
JV Inkai and Westinghouse operate independently of Cameco, but have risks related to environment, health and safety, which could impact the operation of their facilities, their ability to secure and maintain approvals, licences and permits and could have a material and adverse effect on their earnings, cash flows, financial condition, results of operations or prospects.
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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 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.
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, like Germany and Switzerland, announced their intention to phase out nuclear power. As of April 15, 2023, Germany had shut down all of its 17 nuclear reactors. Prior to the accident in 2011 at Fukushima, Japan had 54 nuclear reactors, which represented 12% of global nuclear generating capacity. As of December 2023, Japan has restarted 12 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.
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.
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.
JV Inkai and Westinghouse operate independently from Cameco, but may be subject to similar nuclear incident risks.
Public acceptance of nuclear energy is uncertain
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.
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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 our and Westinghouse’s products and services 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 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. In the past, 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 114.
Mine concentration risk
Our main sources of uranium production are mines at Cigar Lake and McArthur River and our interest in JV Inkai.
In 2024, 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 mill is unable to mill Cigar Lake production.
In 2024, our share of planned McArthur River production is 12.6 million pounds. McArthur River production is milled at the Key Lake mill we operate. See McArthur River mine and Key Lake mill ramp up on page 110.
We own a 40% interest in JV Inkai and presently, JV Inkai is experiencing procurement and supply chain issues, most notably, related to the availability of sulfuric acid. It is also experiencing challenges related to construction delays and inflationary pressures on its production costs. Production plans for 2024 and subsequent years are uncertain and being reassessed (see 2024 Production on page 63).
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 and Westinghouse 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, Westinghouse’s or JV Inkai’s 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. Some of these sources can be considered substitutes for nuclear energy, particularly over the longer term. Sustained lower costs for these energy sources may result in lower demand for nuclear energy and consequently a reduction in demand for uranium and lower uranium prices.
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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.
JV Inkai and Westinghouse operate independently from Cameco but may be subject to similar risks related to a reduction in demand for uranium and lower uranium prices due to alternate sources of energy.
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 small.
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 and generate uranium from underfeeding.
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.
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 and obsolescence
Requirements for our products or those of Westinghouse may be affected by technological changes and innovation in nuclear reactors and other uses of uranium. These technological changes could reduce the demand for nuclear reactors and uranium, which could have a material adverse impact 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, either for us, our joint ventures or the businesses we have invested in, 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.
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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 |
| • | 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 exploration is highly speculative
Uranium exploration is highly speculative and involves many risks, and few properties that are explored are ultimately developed into producing mines.
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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.
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 access uranium from other sources, 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 GHG 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 noted in the Our ESG principles and practices section starting on page 92, in 2022 and 2023, Cameco completed a physical risk assessment study to deliver an initial forward-looking physical climate risk assessment across our sites in Northern Saskatchewan and Ontario and to identify possible risk management and adaptation options. The next steps for the northern Saskatchewan and Ontario physical risk assessments 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.
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.
JV Inkai and Westinghouse operate independently from Cameco, but may be subject to similar climate change risks.
Foreign investments and operations
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We, JV Inkai and Westinghouse 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:
| • | 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) |
| • | 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 and Westinghouse 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.
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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.
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.
One of the recent examples of the legislation that poses a risk of property confiscation is the Law on Return of Illegally Diverted Assets to the State adopted after re-election of President Tokayev. This law is aimed at confiscation of assets deemed to have been illegally acquired by persons holding a responsible public position or a managerial position in state or quasi-state companies (target persons) or by individuals/legal entities affiliated with the target persons. As the law establishes extremely broad categories of affiliated persons such as, for example, individuals and legal entities related to target persons by common commercial interests, foreign investors are potentially at risk of being declared as affiliated to target persons and their assets deemed illegally diverted and confiscated. 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 64 to 67 for a more detailed discussion of the regulatory and political environment in Kazakhstan.
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Presidential succession and instability
The first 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 experienced 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. 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.
Compliance with sanctions
It has been reported in the media that Kazakhstan’s official stance is that it is dedicated to complying with the sanctions imposed against Russia and that the government holds consultations with Western partners to prevent the imposition of secondary sanctions, has introduced restrictions on the export of certain types of goods which are intended for military purposes, and has launched an online tracking system for all goods passing through Kazakhstan’s borders.
However, since EU lawmakers adopted the 11th sanctions package that make it possible for the sanctions to be imposed on companies and individuals in third countries that are found to be helping Russia to circumvent sanctions, there is a risk of persons, banks, and companies based in Kazakhstan being subjected to secondary sanctions.
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 future earnings, cash flows, financial condition, results of operations, or prospects.
Conflict in Ukraine
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 product from JV Inkai in 2022 and 2023. We may continue to experience delays in our expected deliveries in 2024. See Uranium – Tier-one operations – Inkai and Operational risks – Transportation.
| 2023 ANNUAL INFORMATION FORM | Page 132 |
Our business has been and may continue to be impacted by the ongoing conflict between Russia and Ukraine and the related economic sanctions.
In March 2023, we signed a major supply contract with Energoatom, Ukraine’s state-owned nuclear energy utility, to supply 100% of Energoatom’s UF6 requirements, including an option 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. 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 – Major nuclear incident risk.
Governments continue to develop and implement economic sanctions in response to the conflict. For instance, the Prohibiting Russian Uranium Imports Act was passed by the United States House of Representatives in December 2023 which, if enacted, would ban imports of enriched Russian uranium to the United States. This ban would be subject to certain waivers until 2028 allowing the import of low-enriched uranium from Russia if the United States energy secretary determines there is no alternative source available or if the shipments are in the national interest. Sanctions such as these may lead to significant volatility in global uranium prices. In addition, with the United States presidential election occurring in late 2024, there remains significant uncertainty regarding future economic sanctions in the United States and how they may be altered by a potentially new administration.
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.
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 Inkai product. We will continue to monitor the potential impacts on our business as the situation develops.
Westinghouse’s comprehensive protections against liability for nuclear damage depend on the viability of global indemnities and continuation of nuclear 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, 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.
| 2023 ANNUAL INFORMATION FORM | Page 133 |
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.
Legal proceedings
We are currently involved in a dispute with CRA. See Transfer pricing dispute at page 102 for more details about this dispute.
Investor information
Share capital
Our authorized share capital consists of:
| • | first preferred shares |
| • | 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.
First preferred 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, 2023, we had 434,175,752 common shares outstanding. These were fully paid and non-assessable.
| 2023 ANNUAL INFORMATION FORM | Page 134 |
On February 29, 2024, there were 1,396,289 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 2023 and 2024, 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 |
| • | the vice-chair of the board, chief executive officer (CEO), president, chief financial officer (CFO) and 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 Limited Reorganization 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.
| 2023 ANNUAL INFORMATION FORM | Page 135 |
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.
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) |
| • | applying for continuance in another jurisdiction |
| • | enacting articles of incorporation or bylaws that have provisions that are inconsistent with the ENL Reorganization Act |
We must maintain our registered office and head office operations in Saskatchewan under the Saskatchewan Mining Development 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 S&P Global Ratings (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 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 mature on June 24, 2024 (classified as current) |
| • | $400 million of debentures issued on October 21, 2020, that have an interest rate of 2.95% per year and mature on October 21, 2027 |
| 2023 ANNUAL INFORMATION FORM | Page 136 |
We have a commercial paper program which is supported by a $1 billion unsecured revolving credit facility that matures October 1, 2027. As of December 31, 2023, there were no amounts outstanding under the commercial paper facility.
Additionally, we have approximately $800 million in term loan debt. We have drawn the full amount of the single advance $600 million (US) term loan that was put in place concurrently with the execution of the Westinghouse acquisition agreement, of which $300 million (US) matures in November 2025 and $300 million (US) matures in November 2026. In early 2024, we completed a partial repayment of $200 million (US) on the $300 million (US) tranche which matures in November 2026, leaving a principal balance of $100 million (US) on that tranche. The term loan facility requires interest rate elections on each tranche, priced at the applicable rate of:
| • | SOFR plus a credit spread adjustment of 0.10% and a margin that currently ranges from 1.7% to 1.95%, or |
| • | US base rate, plus a margin that currently ranges from 0.7% to 0.95% |
The margins are dependent on Cameco’s credit rating and as such could change over the term if the credit rating changes.
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 | ||
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, May 27, 2022 and
October 12, 2023, DBRS confirmed the rating and the outlook.
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. On March 12, 2024 S&P confirmed their BBB- rating and Stable outlook.
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 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
• represents “adequate credit quality”
• fifth highest of 10 available credit rating categories
|
||
| S&P rates commercial paper by categories ranging from a high of A-1 (high) to a low of D |
A-3 | • represents “adequate protection parameters”
• third highest of six 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.
| 2023 ANNUAL INFORMATION FORM | Page 137 |
The table below explains the credit ratings of our senior unsecured debentures in more detail:
| Rating |
Ranking |
|||
| DBRS | BBB | • middle of the BBB category |
||
| rates senior unsecured debentures by categories ranging from a high of AAA to a low of D | • represents “adequate credit quality”
• fourth highest of eight available credit rating categories |
|||
| • capacity for the payment of financial obligations is considered acceptable |
||||
| • may be vulnerable to future economic events |
||||
| S&P | BBB- | • the lower end of the BBB category |
||
| rates senior unsecured debentures by categories ranging from a high of AAA to a low of D | • exhibits “adequate protection parameters”
• fourth highest of 10 available credit rating categories |
|||
| • adverse economic conditions 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 $1,384,500 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:
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 Eighth supplemental indenture with CIBC Mellon on October 21, 2020, relating to the issue of $400 million in unsecured debentures at an interest rate of 2.95% per year and due in 2027.
We entered into the Resignation and Appointment Agreement with CIBC Mellon and BNY Trust Company of Canada on February 22, 2021, relating to resignation of CIBC Mellon as trustee and appointment of BNY as trustee under the above supplemental indentures.
See Senior unsecured debentures, above for more information about these debentures.
Resource use contract
See page 63 at Resource use contract for information about this contract.
Market for our securities
Our common shares are listed and traded on the Toronto Stock Exchange (TSX) (under the symbol CCO) and the New York Stock Exchange (under the symbol CCJ).
We have a registrar and transfer agent in Canada and the US for our common shares:
| Canada | TSX Trust Company 301 – 100 Adelaide Street West Toronto, ON M5H 4H1 |
US | Equiniti Trust Company, LLC 55 Challenger Road 2nd floor Ridgefield Park, New Jersey United States of America 07660 |
| 2023 ANNUAL INFORMATION FORM | Page 138 |
Trading activity
The table below shows the high and low closing prices and trading volume for our common shares on the TSX in 2023.
| 2023 |
High ($) | Low ($) | Volume | |||||||||
| January |
37.72 | 30.02 | 27,180,990 | |||||||||
| February |
39.80 | 35.94 | 27,336,592 | |||||||||
| March |
38.82 | 32.65 | 26,572,625 | |||||||||
| April |
37.49 | 33.27 | 18,832,797 | |||||||||
| May |
38.75 | 35.65 | 20,244,351 | |||||||||
| June |
43.94 | 38.05 | 25,178,696 | |||||||||
| July |
46.43 | 39.00 | 18,587,612 | |||||||||
| August |
50.57 | 42.12 | 22,318,028 | |||||||||
| September |
56.87 | 48.84 | 25,753,210 | |||||||||
| October |
57.62 | 48.45 | 26,390,916 | |||||||||
| November |
62.81 | 54.56 | 24,623,312 | |||||||||
| December |
63.12 | 56.54 | 26,030,946 | |||||||||
Dividend
In 2023, our board of directors declared a dividend of $0.12 per common share which was paid on December 15, 2023. 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.
| 2023 | 2022 | 2021 | ||||||||||
| Cash dividends |
$ | 0.12 | $ | 0.12 | $ | 0.08 | ||||||
| Total dividends paid (millions) |
$ | 52 | $ | 52 | $ | 32 | ||||||
Governance
Directors
| Director |
Board committees |
Principal occupation or employment |
||
| Daniel Camus Westmount, Québec, Canada Director since 2011 |
Audit and finance (Chair) Human resources and compensation |
Corporate director as of 2011 | ||
| Tammy Cook-Searson Lac La Ronge, Saskatchewan, Canada Director since 2023 |
Safety, health and environment Technical |
2005 to present – Chief of the Lac La Ronge Indian Band and President of Kitsaki Management Limited Partnership | ||
| Don Deranger Prince Albert, Saskatchewan, Canada Director since 2009 |
Nominating, corporate governance and risk Safety, health and environment Technical |
May 2013 to present – non-executive chair of the board of Points Athabasca Contracting LP, a civil, earthworks and industrial contracting company 1997 to present – Advisor to First Nations Communities |
||
| Catherine Gignac Mississauga, Ontario, Canada Director since 2014 |
A member of all board committees Nominating, corporate governance and risk (Chair) |
Corporate director as of 2011 | ||
| 2023 ANNUAL INFORMATION FORM | Page 139 |
| Director |
Board committees |
Principal occupation or employment |
||
| Tim Gitzel Saskatoon, Saskatchewan, Canada Director since 2011 |
None | July 2011 to present – President and Chief Executive Officer | ||
| Jim Gowans Surrey, British Columbia, Canada Director since 2009 |
Safety, health and environment (Chair) Audit and finance Technical |
Corporate director as of 2018 August 2019 to May 2020 – Interim president, CEO and a director of Trilogy Metals Inc. January 2016 to 2018 – President and CEO of Arizona Mining Inc., an exploration and development company |
||
| Kathryn Jackson Indialantic, Florida, USA Director since 2017 |
Human resources and compensation Nominating, corporate governance and risk Safety, health and environment Technical (Chair) |
Corporate director as of 2008 | ||
| Don Kayne Delta, British Columbia, Canada Director since 2016 |
Human resources and compensation (Chair) Safety, health and environment |
May 2011 to present – President and CEO of Canfor Corporation September 2012 to April 2022 – Chief Executive Officer of Canfor Pulp Products Incorporated, an integrated forest products company |
||
| Dominique Minière Toronto, Ontario, Canada Director since 2023 |
Human resources and compensation Safety, health and environment Technical |
Corporate director as of 2023 January 2022 to December 2022 – Executive Vice President of Ontario Power Generation September 2020 to December 2021 – Executive Vice President and Chief Strategy Officer of Ontario Power Generation March 2019 to September 2020 – Nuclear President of Ontario Power Generation |
||
| Leontine van Leeuwen-Atkins Calgary, Alberta, Canada Director since 2020 |
Audit and finance Nominating, corporate governance and risk Technical |
Corporate director as of 2019 2006 to 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 five years |
|
| Catherine Gignac Chair Mississauga, Ontario, Canada |
Assumed current position November 2023 | |
| Tim Gitzel President and Chief Executive Officer Saskatoon, Saskatchewan, Canada |
Assumed current position July 2011 | |
| Grant Isaac Executive Vice-President and Chief Financial Officer Saskatoon, Saskatchewan, Canada |
Assumed current position February 2023 July 2011 to February 1, 2023 – Senior Vice-President and Chief Financial Officer |
|
| Sean Quinn Senior Vice-President, Chief Legal Officer and Corporate Secretary Saskatoon, Saskatchewan, Canada |
Assumed current position April 2014 | |
| 2023 ANNUAL INFORMATION FORM | Page 140 |
| Officer |
Principal occupation or employment for past five years |
|
| Brian Reilly Senior Vice-President and Chief Operating Officer Saskatoon, Saskatchewan, Canada |
Assumed current position July 2017 | |
| Heidi Shockey Senior Vice-President and Deputy Chief Financial Officer Saskatoon, Saskatchewan, Canada |
Assumed current position February 2023 April 2013 to February 1, 2023 – Vice-President, Controller October 2017 to April 2020 – Vice-President, Controller and Treasurer |
|
| Alice Wong Senior Vice-President and Chief Corporate Officer 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 782,482 as at March 15, 2024. 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 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 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 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 for: |
| • | Jim Gowans was a director of Gedex Technologies Inc. (Gedex), an Ontario-based developer of airborne geological 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 |
| • | 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 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 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).
| 2023 ANNUAL INFORMATION FORM | Page 141 |
Composition of the audit and finance committee
The committee is made up of four members: Daniel Camus (chair), 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
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, MedAccess plc, located in London, UK. He is the former audit committee chair and board member of the non-governmental organization, FIND Diagnostics, located in Geneva, Switzerland and 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 served on the audit, compensation, nominating and sustainability committees of other public-traded company boards. 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 three 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.
| 2023 ANNUAL INFORMATION FORM | Page 142 |
Auditors’ fees
The table below shows the fees billed by the external auditors for services in 2023 and 2022:
| 2023 ($) |
% of total fees |
2022 ($) |
% of total fees |
|||||||||||||
| Audit fees |
||||||||||||||||
| Cameco1 |
2,436,700 | 88.7 | 2,389,200 | 82.8 | ||||||||||||
| Subsidiaries2 |
135,600 | 4.9 | 136,800 | 4.7 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total audit fees |
2,572,300 | 93.6 | 2,526,000 | 87.5 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Audit-related fees |
||||||||||||||||
| Translation services3 Pensions4 |
|
— 31,600 |
|
|
0 1.2 |
|
|
137,500 30,000 |
|
|
4.8 1.0 |
|
||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total audit-related fees |
31,600 | 1.2 | 167,500 | 5.8 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Tax fees |
||||||||||||||||
| Compliance |
5,600 | 0.2 | 5,100 | 0.2 | ||||||||||||
| Planning and advice5 |
136,100 | 5.0 | 117,700 | 4.1 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total tax fees |
141,700 | 5.2 | 122,800 | 4.3 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| All other fees Other non-audit fees6 |
— | 0 | 69,500 | 2.4 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other non-audit fees |
— | 0 | 69,500 | 2.4 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total fees |
2,745,600 | 100 | 2,885,800 | 100.0 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 1 | Includes amounts billed for the audit of Cameco’s annual consolidated financial statements and the review 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 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 2023 for translation services. |
| 4 | Includes amounts billed for the audit of Cameco’s pension plan financial statements. |
| 5 | Includes amounts billed for tax compliance and tax advisory services. |
| 6 | Other non-audit fees for 2022 includes amounts billed for Cameco’s I-4 Membership. No invoices were issued in 2023. |
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 their 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 2023 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.
| 2023 ANNUAL INFORMATION FORM | Page 143 |
The individuals who are qualified persons for the purposes of NI 43-101 are listed under Mineral reserves and resources on page 88 and under Technical report on pages 28, 44 and 58. 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.
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.
| 2023 ANNUAL INFORMATION FORM | Page 144 |
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.
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 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. |
| 2. | Consider any matter required to be communicated to the committee by the external auditors under applicable 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 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 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 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 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 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 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 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 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 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 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. |
| 8. | Review with the external auditors any audit problems or difficulties experienced by the external auditors in 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. |
| 2023 ANNUAL INFORMATION FORM | Page 145 |
| 9. | Review the results of the external auditors’ audit work including findings and recommendations, management’s response, and any resulting changes in accounting practices or policies and the impact such changes may have on the financial statements. |
| 10. | Review and discuss with management and the external auditors the audited annual financial statements and 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 periods. |
| 11. | Review and discuss with management and the external auditors all interim unaudited financial statements and 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 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 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 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 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 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 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 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 officer and controller. Review the succession plans in respect of the chief financial officer and controller. |
Internal controls
| 17. | Receive from management a statement of the corporation’s system of internal controls over accounting and financial reporting. |
| 18. | Consider and review with management, the internal auditor and the external auditors, the adequacy and effectiveness of internal controls over accounting and financial reporting within the corporation and any proposed significant changes in them. |
| 19. | Consider and discuss the scope of the internal auditors’ and external auditors’ review of the corporation’s internal controls, and obtain reports on significant findings and recommendations, together with management responses. |
| 20. | Discuss, as appropriate, with management, the external auditors and the internal auditor, any major issues as to the adequacy of the corporation’s internal controls and any special audit steps in light of material internal control deficiencies. |
| 21. | Review annually the disclosure controls and procedures, including (a) the certification timetable and 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 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 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 or other employees who have a significant role in the corporation’s internal control over financial reporting. In addition, receive confirmation from 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. |
| 2023 ANNUAL INFORMATION FORM | Page 146 |
| 22. | Review management’s annual report and the external auditors’ report on the assessment of the effectiveness of the corporation’s internal control over financial reporting. |
| 23. | Receive a report, at least annually, from the technical committee of the board on the corporation’s mineral reserves. |
External auditors
| (i) | External Auditors’ Qualifications and Selection |
| 24. | Subject to the requirements of applicable law, be solely responsible to select, retain, compensate, oversee, 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 auditors for completing an audit and audit report. |
| 25. | Instruct the external auditors that: |
| (a) | they are ultimately accountable to the board and the committee, as representatives of shareholders; and |
| (b) | they must report directly to the committee. |
| 26. | Ensure that the external auditors have direct and open communication with the committee and that the external 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. |
| 27. | Evaluate the external auditors’ qualifications, performance, and independence. As part of that evaluation: |
| (a) | at least annually, request and review a formal report by the external auditors describing: the firm’s 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 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, 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 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 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 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 with applicable law on such matters; and |
| (c) | annually review and evaluate senior members of the external audit team, including their expertise and 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.
| 28. | Review and approve the corporation’s policies for the corporation’s hiring of employees and former employees of the external auditors. Such policies shall include, at minimum, a one-year hiring “cooling off” period. |
| (ii) | Other Matters |
| 29. | Meet with the external auditors to review and approve the annual audit plan of the corporation’s financial statements prior to the annual audit being undertaken by the external auditors, including reviewing the year-to-year 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 external auditors in determining their audit scope, including major risk factors. The external auditors shall report to the committee all significant changes to the approved audit plan. |
| 2023 ANNUAL INFORMATION FORM | Page 147 |
| 30. | Review and approve the basis and amount of the external auditors’ fees with respect to the annual audit in light of all relevant matters. |
| 31. | Review and pre-approve all audit and 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 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 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 procedures for such matters. |
Internal auditor
| 32. | Review and approve the appointment or removal of the internal auditor. |
| 33. | Review and discuss with the external auditors, management, and internal auditor the responsibilities, budget and staffing of the corporation’s internal audit function. |
| 34. | Review and approve the mandate for the internal auditor and the scope of annual work planned by the internal auditor, receive summary reports of internal audit findings, management’s response thereto, and reports on any subsequent follow-up to any identified weakness. |
| 35. | Ensure that the internal auditor has direct and open communication with the committee and that the internal 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 course of internal audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management. |
| 36. | Review and discuss with the internal auditor and management the internal auditor’s ongoing assessments of the corporation’s business processes and system of internal controls. |
| 37. | Review the effectiveness of the internal audit function, including staffing, organizational structure and qualifications of the internal auditor and staff. |
Compliance
| 38. | Monitor compliance by the corporation with all payments and remittances required to be made in accordance with applicable law, where the failure to make such payments could render the directors of the corporation personally liable. |
| 39. | The receipt of regular updates from management regarding compliance with laws and regulations and the process 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 external auditors’ observations relating to such matters. |
| 40. | Establish and oversee the procedures in the code of conduct and ethics policy to address: |
| (a) | the receipt, retention and treatment of complaints received by the corporation regarding accounting, internal accounting or auditing matters; and |
| (b) | confidential, anonymous submissions by employees of concerns regarding questionable accounting and auditing 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.
| 41. | Review and recommend to the board for approval a code of conduct and ethics for employees, officers and 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 of compliance by employees pursuant to such policies and reviewing the findings of any investigations of non-compliance. Periodically review the adequacy and appropriateness of such policies and programs and make recommendations to the board thereon. |
| 2023 ANNUAL INFORMATION FORM | Page 148 |
| 42. | Monitor management’s implementation of the anti-fraud policy; and review compliance therewith by, among 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.
| 43. | Review all proposed related party transactions and situations involving a director’s, senior 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 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 meeting, the chair shall report the results of such review. |
| 44. | Monitor management of hedging, debt and credit, make recommendations to the board respecting policies for management of such risks, and review the corporation’s compliance therewith. |
| 45. | Approve the review and approval process for the expenses submitted for reimbursement by the chief executive officer. |
| 46. | Oversee management’s mitigation of material risks within the committee’s mandate and as otherwise assigned. |
| 47. | Undertake such other tasks as may be directed to it from time to time by the board. |
Financial oversight
| 48. | 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 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; and |
| (h) | matters the board may refer to the committee from time to time in connection with the corporation’s capital position. |
Organizational matters
| 49. | The procedures governing the committee shall, except as otherwise provided for herein, be those applicable to the board committees as set forth in Part 7 of the General Bylaws of the corporation. |
| 50. | The members and the chair of the committee shall be entitled to receive remuneration for acting in such capacity as the board may from time to time determine. |
| 51. | The committee shall have the resources and authority appropriate to discharge its duties and responsibilities, including the authority to: |
| (a) | select, retain, terminate, set and approve the fees and other retention terms of special or independent counsel, accountants or other experts, as it considers appropriate; and |
| 2023 ANNUAL INFORMATION FORM | Page 149 |
| (b) | obtain appropriate funding to pay, or approve the payment of, such approved fees; |
without seeking approval of the board or management.
| 52. | Any member of the committee may be removed or replaced at any time by the board and shall cease to be a member 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 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. |
| 53. | The committee shall annually review and assess the adequacy of its mandate and recommend any proposed changes to the nominating, corporate governance and risk committee for recommendation to the board for approval. |
| 54. | The committee shall participate in an annual performance evaluation, the results of which will be reviewed by the board. |
| 55. | The committee shall perform any other activities consistent with this mandate, the corporation’s governing laws and the regulations of stock exchanges, as the committee or the board considers necessary or appropriate. |
| 56. | A standing invitation will be issued to all non-executive directors to attend the financial oversight portion of each committee meeting. |
| 2023 ANNUAL INFORMATION FORM | Page 150 |
EXHIBIT 99.3
Cameco Corporation
February 8, 2024
Management’s discussion and analysis
February 8, 2024
| 10 | MARKET OVERVIEW AND DEVELOPMENTS |
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| 17 | 2023 PERFORMANCE HIGHLIGHTS |
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| 22 | OUR VISION, VALUES AND STRATEGY |
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| 32 | OUR ESG PRINCIPLES AND PRACTICES |
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| 36 | MEASURING OUR RESULTS |
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| 38 | FINANCIAL RESULTS |
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| 69 | OPERATIONS AND PROJECTS |
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| 100 | MINERAL RESERVES AND RESOURCES |
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| 105 | ADDITIONAL INFORMATION |
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2023 Management’s Discussion and Analysis 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, 2023. The information is based on what we knew as of February 7, 2024.
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 www.sedarplus.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 is 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, 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 incorrect. |
| • | Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks 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 to differ significantly from our current expectations. |
| • | Forward-looking information is designed to help you understand management’s current views of our near- and longer-term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws. |
Examples of forward-looking information in this MD&A
| • | our view that we have the strengths to take advantage of the world’s rising demand for safe, clean, secure, reliable, affordable and carbon-free energy, and our vision to energize a clean-air world |
| • | that 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 long-term value |
| • | our expectations about when future reactors will come online |
| • | our expectations about 2024 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 and that our investment in enrichment technology, if successful, will allow us to participate in the entire nuclear fuel value chain |
| • | 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 within the fuel cycle |
| • | our expectations about future demand for SMRs |
| • | our views on our ability to self-manage risk |
| • | the discussion under the heading Our business |
| • | the discussion under the heading Our strategy |
| • | our expectations regarding the effect of supply scarcity on our long-term contract portfolio |
| • | 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 facility, as well as our exploration activities at these and other sites |
| • | our expectations regarding the future average unit cost of production at McArthur River/Key Lake and at Cigar Lake |
| • | our expectation regarding the timing of filing a new technical report for Cigar Lake |
| • | our expectations regarding our licences for McArthur River, Key Lake and Crow Butte |
| • | Kazatomprom’s planned production levels and timing for JV Inkai |
| • | 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 to deliver significant long-term business value |
| • | our expectations for uranium purchases, sales and deliveries |
| • | our intentions regarding future dividend payments |
| • | the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our confidence that 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 2017 and our belief that CRA should return the full amount of cash and security that has been paid or otherwise secured by us |
| • | our expectations regarding the amount of security we will need to provide to CRA in connection with the tax debts CRA considers us owing for 2017 |
| • | the discussion of our future plans for Cigar Lake and McArthur River/Key Lake under the heading 2023 performance highlights |
| • | our views on our ability to align our production with market opportunities and our contract portfolio |
| • | our expectation regarding opportunities to improve operational effectiveness and to reduce our impact on the environment, including through the use of digital and automation technologies |
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| • | the discussion under the heading Outlook for 2024, including expected business resiliency, expectations for 2024 average unit cost of sales, average purchase price per pound, deliveries and production, 2024 financial outlook, our revenue, expectations for 2024 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 2024 obligations and our expectations regarding how the ratings agencies will consider our investment in Westinghouse in their analysis |
| • | 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 market purchases |
| • | our expectation that our cash balances and operating cash flows will meet our anticipated 2024 capital requirements |
| • | our expectations for our and Westinghouse’s future capital expenditures and sources of funds |
| • | our expectation that in 2024 we will be able to comply with all the covenants in our credit agreements |
| • | our expectation that Westinghouse will continue to comply with the covenants in its credit agreements |
| • | life of mine operating cost estimates for the Cigar Lake, McArthur River/Key Lake and JV Inkai operations |
| • | our 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 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 acquisition expanding our participation in the nuclear fuel value chain, and providing a platform for further growth, and various factors and drivers for Westinghouse’s business segment |
| • | our expectation that the acquisition will enhance our participation in the nuclear fuel cycle |
| • | our expectation that the Westinghouse acquisition will be accretive to us and augment the core of our business |
| • | our expectation of Westinghouse being well positioned to participate in the growing demand profile for nuclear energy |
| • | our plans to update our physical climate risk assessments, incorporate these findings into our internal risk management review and developing an adaptation action plan template and our expectations regarding the timing for implementation of these plans |
| • | our expectations regarding our research and development expenses for 2024 |
| • | our expectations regarding the timing of the Canadian Nuclear Safety Commission’s review of our preliminary decommissioning cost estimate for the Port Hope conversion facility |
| • | our expectations regarding which extraction methods we will use in the future |
| • | our expectation that Westinghouse’s durable and growing business will allow Westinghouse to self-fund its approved annual operating budget, maintain its existing capacity to service its annual financial obligations from de-risked cash flows, and pay annual distributions to its owners |
| • | our 2024 outlook for Westinghouse’s Adjusted EBITDA, capital expenditures and revenue |
| • | our expectation that strategic initiatives, including the development of the AP300™ small modular reactor and the eVinci™ microreactor, will provide new business opportunities for Westinghouse that will make a meaningful contribution to Westinghouse’s long-term financial performance |
| • | our expectation for Westinghouse projects generating multi-year revenue streams and EBITDA for Westinghouse |
| • | our expectation that the timing of cash distributions from Westinghouse will be aligned with the timing of Westinghouse’s cash flows |
| • | our expectation that Westinghouse’s new opportunities will allow Westinghouse to compete for and win new business |
| • | our expectation that Westinghouse’s reputation and position will benefit its core business as Eastern European countries seek to develop a reliable fuel supply chain |
| • | our expectations regarding the growth of Westinghouse’s Adjusted EBITDA over the next five years |
| • | our estimates in respect of the framework for the timing of revenue flows and profitability of contracts under a new build project |
| • | our expectation with respect to the development of its AP300 small modular reactor and eVinci microreactor |
| • | our expectation on Westinghouse being well-positioned for future growth |
| • | our expectation around the refinancing of our senior unsecured debentures, our expected cash flow and our plan to reduce total debt, with a focus on the floating rate term loan |
| • | our expectations regarding when Global Laser Enrichment’s technology will be deployed at a commercial scale |
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 a competitor, trade restrictions, geopolitical issues or the impact of a 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 |
| • | that we may not realize the expected benefits from the Westinghouse 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 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 a pandemic or other causes |
| • | we are adversely affected by subsurface contamination from current or legacy operations |
| • | necessary permits or approvals from government authorities cannot be obtained or maintained |
| • | we are affected by political risks, including 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 failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, 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), accident or a deterioration 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 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 expenses, or ultimately prove to be unsuccessful |
| • | our expectations relating to care and maintenance costs prove to be inaccurate |
| • | the risk that we may not be able to refinance our debenture on terms that are as favourable as we expect, or that we may not realize our expected cash flow, or meet our expectations in reducing total debt |
| • | the risk that we may become unable to pay future dividends at the expected rate |
| • | 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 70 |
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| • | 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 75, under the heading Cigar Lake – Managing Our Risks beginning on page 79, and under the heading Inkai – Managing Our Risks beginning on page 83 |
| • | unexpected changes in uranium supply, demand, long-term contracting, and prices |
| • | changes in consumer demand for nuclear power and uranium as a result of changing societal views and objectives regarding nuclear power, electrification and decarbonization |
| • | the risk that our views regarding nuclear power, its growth profile, and benefits may prove to be incorrect |
| • | the risk that we and Westinghouse may not be able to meet sales commitments for any reason |
| • | the risk that Westinghouse may not achieve the expected growth in its business |
| • | the risk to Westinghouse’s business associated with potential production disruptions, including those related to global supply chain disruptions, global economic uncertainty, political volatility, labour relations issues, and operating risks |
| • | the risk that Westinghouse may not be able to implement its business objectives in a manner consistent with its or our environmental, social, governance and other values |
| • | the risk that Westinghouse’s strategies may change, be unsuccessful, or have unanticipated consequences |
| • | the risk that Westinghouse may be unsuccessful in respect of its new business |
| • | the risk that Westinghouse may be delayed in announcing its future financial results |
| • | the risk that Westinghouse may fail to comply with nuclear license and quality assurance requirements at its facilities |
| • | the risk that Westinghouse may lose protections against liability for nuclear damage, including discontinuation of global nuclear liability regimes and indemnities |
| • | the risk that increased trade barriers may adversely impact Westinghouse’s business |
| • | the risk that Westinghouse may default under its credit facilities, impacting adversely Westinghouse’s ability to fund its ongoing operations and to make distributions |
| • | the risk that liabilities at Westinghouse may exceed our estimates and the discovery of unknown or undisclosed liabilities |
| • | the risk that occupational health and safety issues may arise at Westinghouse’s operations |
| • | the risk that there may be disputes between us and Brookfield regarding our strategic partnership |
| • | the risk that we may default under the governance agreement with Brookfield, including us losing some or all of our interest in Westinghouse |
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 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 2024 Financial Outlook |
| • | our expectations regarding spot prices and realized prices for uranium, and other factors discussed under the heading Price sensitivity analysis: uranium segment |
| • | Westinghouse’s ability to generate cash flow and fund its approved annual operating budget and make quarterly distributions to the partners |
| • | our ability to compete for additional business opportunities so as to generate additional revenue for us as a result of 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 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 |
MANAGEMENT’S DISCUSSION AND ANALYSIS 5
| • | 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 |
| • | that we will be successful in our efforts to renew our operating license for Crow Butte |
| • | that we will be able to refinance our senior unsecured debentures, and assumptions regarding our expected cash flow and our ability to reduce total debt |
| • | 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), governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, aging infrastructure or other development or operating risks |
| • | that no major accident at a nuclear power plant will occur |
| • | nuclear power and uranium demand, supply, consumption, long-term contracting, growth in the demand for and global public acceptance of nuclear energy, and prices |
| • | Westinghouse’s production, purchases, sales, deliveries, and costs |
| • | the assumptions and discussion set out under the heading Westinghouse Electric Company – Future Prospects |
| • | the market conditions and other factors upon which we have based Westinghouse’s future plans and forecasts |
| • | Westinghouse’s ability to mitigate adverse consequences of delays in production and construction |
| • | the success of Westinghouse’s plans and strategies |
| • | the absence of new and adverse government regulations, policies or decisions |
| • | that there will not be any significant adverse consequences to Westinghouse’s business resulting from business disruptions, including those relating to supply disruptions, economic or political uncertainty and volatility, labour relation issues, and operating risks |
| • | Westinghouse’s ability to announce future financial results when expected |
| • | Westinghouse will comply with the covenants in its credit agreements |
| • | Westinghouse will comply with nuclear license and quality assurance requirements at its facilities |
| • | Westinghouse maintaining protections against liability for nuclear damage, including continuation of global nuclear liability regimes and indemnities |
| • | that known and unknown liabilities at Westinghouse will not materially exceed our estimates |
| • | the absence of disputes between us and Brookfield regarding our strategic partnership, and that we do not default under the governance agreement with Brookfield |
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MANAGEMENT’S DISCUSSION AND ANALYSIS 9
Market overview and developments
A market in transition
In 2023, geopolitical uncertainty and heightened concerns about energy security and climate change continued to improve the demand and supply fundamentals for the nuclear power industry and the fuel cycle that is required to support it. Increasingly, countries and companies around the globe are recognizing the critical role nuclear power must play in providing clean and secure baseload power. This growing support has led to a rise in demand as reactors are being saved from earlier retirement, 10- and 20-year life extensions are being sought and approved for existing reactor fleets in several countries, and numerous commitments and plans are being made for the construction of new nuclear generating capacity. In addition, there is increasing interest in small modular reactors (SMR), including smaller versions of existing technology and advanced technology designs, which are expected to add to demand in the decades to come, with several projects already underway.
While demand continues to increase, future supply is not keeping pace. Heightened supply risk caused by growing geopolitical uncertainty, shrinking secondary supplies and a lack of investment in new capacity over the past decade has motivated utilities to evaluate their near-, mid- and long-term nuclear fuel supply chains. The uncertainty about where nuclear fuel supplies will come from to satisfy growing demand has led to increased long-term contracting activity and in 2023, about 160 million pounds of uranium was placed under long-term contracts by utilities. While it is the highest annual volume contracted since 2012, it remains below replacement rate and includes our contract with Ukraine, which alone accounted for about 30 million of those pounds. Prices across the nuclear fuel cycle continued to rise in 2023, with spot enrichment prices up 38%, conversion prices continuing to achieve record highs, uranium spot prices more than doubling from around $48 (US) per pound at the end of 2022 to $100 (US) per pound at the end of January 2024, after peaking at $106 (US) per pound earlier in the month, and the long-term price for uranium increasing about 38% over the same period. We expect there will be continued competition to secure uranium, conversion services and enrichment services under long-term contracts with proven producers and suppliers who have a diversified portfolio of assets in geopolitically attractive jurisdictions, with strong environmental, social and governance (ESG) performance, and on terms that help ensure a reliable supply is available to satisfy demand.
DURABLE DEMAND GROWTH
The benefits of nuclear energy have come clearly into focus, supporting a level of durability that, 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 in energy markets that is causing countries to reexamine how they plan to address their energy needs. Net-zero carbon targets are turning global attention to a triple challenge. First, about one-third of the global population must be lifted out of energy poverty by improving access to clean and reliable baseload electricity. Second, approximately 80% of the current global electricity grids that run on carbon-emitting sources of thermal power must be replaced with a clean, reliable alternative. And finally, global power grids must grow by electrifying industries, such as private and commercial transportation, and home and industrial heating, which today are largely powered with carbon-emitting sources of thermal energy. Additionally, geopolitical uncertainty has deepened 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 and energy security goals. The growth in demand is not just long-term and in the form of new builds, but medium-term in the form of reactor life extensions, and near-term with early reactor retirement plans being deferred or cancelled and new markets continuing to emerge. And, we are seeing even more long-term momentum building with the development of SMRs, where the use case extends beyond just power generation and numerous companies and countries are pursuing projects.
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Demand and energy policy highlights
| • | In September, the World Nuclear Association released its biennial Global Nuclear Fuel Report which provides scenarios for demand and supply availability across the fuel supply chain through 2040. This included a robust demand outlook showing global nuclear generating capacity increasing to 686 GWe by 2040 in the Reference Scenario, an average annual growth rate of 3.6%, compared to 2.6% in the 2021 report. This improvement was driven by improved government support, life extensions, new builds and importantly, that starting in the 2030s, the deployment of SMRs is forecasted to contribute to capacity growth. Additional key themes include assumed reductions to secondary supply and decreased availability of mobile inventories, along with the need for a growing volume of future uranium supply requiring higher incentive pricing to balance the market after 2030. |
| • | At the 28th annual Conference of Parties (COP28), the 2023 United Nations Climate Change Conference held in the United Arab Emirates, 22 countries (now 28) launched a declaration to triple nuclear energy capacity by 2050. For the first time at the conference, nuclear energy was recognized alongside other low-emissions technologies for the key role it must play in reaching global net-zero greenhouse gas emissions by 2050. In addition, the inaugural global stocktake was introduced at COP28, a process where countries and stakeholders can provide an update every five years to track the world’s progress toward the Paris Agreement targets. In 2023, the initiative concluded that more action is required, as emissions continue to rise and put 2030 targets at risk, reinforcing that in order to achieve net zero by 2050, the world needs “absolute economy-wide emission reduction targets”, which were estimated at a cost of “trillions of dollars”. |
| • | China Nuclear Energy Association published the “China Nuclear Energy Development Report 2023” in April, which highlighted China’s continuing growth. According to the report, the country is expected to lead the world in installed nuclear capacity with 110 GWe expected by 2030, rising to 150 GWe expected by 2035, and plans to build over 90% of their major nuclear power reactors domestically. Additionally, a proposal drafted by 15 Chinese national policy advisors was submitted to the government advocating for the development of new nuclear power plants at inland sites, which are now being considered following the end of a post-Fukushima moratorium on proposed inland nuclear power plants. |
| • | In Japan, Takahama unit 2 restarted in September, becoming the country’s 12th reactor to restart since Fukushima. Onagawa unit 2 and Shimane unit 2 are expected to restart in 2024. In November, the Nuclear Regulation Authority approved 20-year life extensions (beyond 40 years) for Sendai units 1 and 2; additionally, Takahama units 3 and 4 are expected to receive similar life extensions, pending generator work in 2026 and 2027. In addition, Japan enacted a bill in May allowing nuclear reactors to operate beyond the 60-year limit. |
| • | In South Korea, Korea Hydro and Nuclear Power (KHNP) announced in September that they successfully completed fuel loading at Shin Hanul unit 2, a new 1,400 MWe APR-1400 pressurized water reactor (PWR) unit. This followed an announcement from the Ministry of Industry and Energy that Shin Hanul units 3 and 4 would be completed by the end of 2024. Additionally, to help achieve the plans set out in their 10th Basic Plan for Electricity Supply and Demand 2030, which targets more than 30% of its power supply to come from nuclear, the Ministry confirmed a review of the need for new nuclear power plants was underway. |
| • | In India, the first domestically designed 700 MWe pressurized heavy water reactor, Kakrapar unit 3, reached full operating capacity in August. Three more units of the same design are expected to come online in the next few years. The country is targeting an expansion of nuclear generating capacity to 22.5 GWe by 2031. |
| • | In February, the European Nuclear Alliance was launched. Led by France, the initiative commits 11 European countries to cooperate across the nuclear fuel supply chain, and to promote new nuclear generation projects and technologies, including the advancement of SMRs. Throughout 2023, the alliance expanded and now includes a commitment from 16 European countries that will prepare a roadmap to develop an integrated European nuclear industry and target 150 GWe of nuclear power by 2050. |
| • | In France, plans were advanced to relaunch the country’s reactor construction program: the government committed to life extensions with a proposed “industrial build” program that initially includes six new European Pressurized Reactors (EPR), as well as eight additional EPRs in the future. Électricité de France filed an application to build the first pair of 1,650 MWe EPRs with construction scheduled to begin in 2028. |
| • | In January 2024, the United Kingdom (UK) announced that they are seeking to quadruple their nuclear power output by 2050. Under the “Civil Nuclear Roadmap”, the UK will invest into developing new advanced nuclear fuel, new regulations, and a new nuclear reactor. |
MANAGEMENT’S DISCUSSION AND ANALYSIS 11
| • | In June, Sweden’s parliament adopted a new energy target, changing its focus to “100% fossil-free” electricity as opposed to the previously stated focus of “100% renewable”. In August, the government announced a target to further expand the role of nuclear power and in November, announced its intention to build up to 2,500 MWe of new nuclear power capacity by 2035, and up to 10 new reactors by 2045, backed by an offer of loan guarantees. |
| • | In Belgium, the government and nuclear operator ENGIE reached an agreement following prolonged negotiations to extend the lifespans of the Doel unit 4 and Tihange unit 3 reactors by 10 years, with each now expected to operate until 2035. |
| • | In Bulgaria, the government issued its 30-year energy strategy to 2053, which envisions the construction of four new nuclear reactor units. In December, parliament approved a government proposal to inject up to 1.5 billion levs ($838 million (US)) into the state-owned Kozloduy Nuclear Power Plant to fund the planned construction of the first of two proposed reactors using Westinghouse’s AP1000® technology. |
| • | In Poland, the government adopted a resolution committing to finance the country’s first nuclear power plant. The funds will go to Polish utility Polskie Elektrownie Jadrowe, which signed a contract with Westinghouse for multiple AP1000 reactors in February of 2023. |
| • | In the US, Vogtle unit 3 entered commercial service on July 31, after becoming the first Westinghouse AP1000 reactor in the US to successfully connect to the electrical grid. Vogtle unit 4 is expected to begin operating in the second quarter of 2024. |
| • | Throughout 2023, many US states expressed local support for nuclear: Ohio, Virginia, Kentucky, and Tennessee all began creating state-level advisory authorities to promote, research and develop nuclear power technologies, and Michigan formed a new Nuclear Caucus to support the reopening of the Palisades nuclear power plant, and also approved extending operations at the Monticello nuclear power plant through 2040. |
| • | In Canada, provincial support for nuclear increased in 2023. New Brunswick Power signed a three-year contract with Ontario Power Generation (OPG) to enhance the operational performance of the Point Lepreau nuclear power plant. In Ontario, the Minister of Energy announced support to advance the long-term planning required to explore nuclear expansion options for Bruce Power, outlining the need for nearly 18 GWe in new nuclear capacity to help the province reach its electrification and net-zero goals. Additionally, in Saskatchewan, Crown Investments Corporation provided around $479,000 to help local firms build small, advanced, and micro reactors supply chain capacity, while the Alberta government announced plans to invest around $7 million to study SMRs. |
| • | In January 2024, OPG announced plans to proceed with the refurbishment of the Pickering Nuclear Generating Station’s “B” units (units 5, 6, 7 and 8). Once the project is completed in the mid-2030s, Pickering would produce a total of 2 GWe of electricity, to help meet increasing electricity demand and fuel the province’s economic growth. |
According to the International Atomic Energy Agency (IAEA), globally there are currently 438 operable reactors and 58 reactors under construction. Several nations are appreciating the clean energy and energy security benefits of nuclear power and have reaffirmed their commitment with plans underway to support existing reactor units and review policies to encourage more nuclear generation. 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 are therefore eligible for access to low-cost financing. In Canada, the government revised the Canada Green Bond Framework to include nuclear energy projects. In some countries where phase-out policies have been in place, policy reversals and decisions have been made to temporarily keep reactors running, with public opinion polls showing increasing support. With a number of reactor construction projects recently approved and many more planned, demand for uranium continues to improve. There is growing recognition of the role nuclear must play in providing safe, affordable, carbon-free baseload electricity to achieve a low-carbon economy, while being a reliable energy source that helps countries move away from Russian energy supply.
12 CAMECO CORPORATION
SUPPLY UNCERTAINTY
Geopolitical uncertainty remained the most notable factor impacting security of supply in 2023. Driven by the Russian invasion of Ukraine, and more recently, the coup d’état in Niger, many governments and utilities are re-examining supply chains and procurement strategies that rely on nuclear fuel supplies from these jurisdictions. In addition, sanctions on Russia and Niger, government restrictions, and restrictions on and cancellations of some cargo insurance coverages continue to create transportation and supply chain risks for nuclear fuel supplies coming out of Central Asia. There are also transportation risks to material being shipped from Australia to Europe as a result of the conflict in the Middle East. Despite the recent increase in market prices, the deepening geopolitical uncertainty and years of underinvestment in new uranium and fuel cycle service capacities has shifted risk from producers to utilities.
Supply and trade policy highlights
| • | Sprott Physical Uranium Trust (SPUT) purchased about 4 million pounds U3O8 in 2023, bringing total purchases since inception to over 45 million pounds U3O8 and increasing the total net asset value to around $7 billion (US). Volatility in equity markets has impacted SPUT’s valuation (discount or premium to its net asset value) and therefore its ability to raise funds to purchase uranium. |
| • | In June, Kazatomprom (KAP) announced plans to start production at a new uranium deposit, Inkai 3 (100% owned by KAP). KAP expects approval of a Subsoil Use Agreement (SSUA) to produce 10.4 million pounds U3O8 annually for 25 years from Inkai 3’s uranium resources of about 216 million pounds U3O8. |
MANAGEMENT’S DISCUSSION AND ANALYSIS 13
| • | In September, KAP had restated its plan to increase production in 2024 to 90% of SSUAs and announced a ramp up to 100% of SSUAs in 2025, though the company also warned that geopolitical uncertainty, global supply chain issues, and inflationary pressure could create challenges. On January 12, 2024, KAP announced that it had faced challenges in completing the development required to achieve the planned 2024 production increase, and that it expected to lower its 2024 uranium production guidance due to limited availability of sulfuric acid and delays in the construction and development of new assets, including Budenovskoye 6 and 7. On February 1, 2024, KAP rescinded its 2024 target due to the shortage of sulfuric acid and construction delays in 2023, and they now plan to remain about 20% below SSUAs, expecting to produce between 55 million and 59 million pounds U3O8 in 2024 (previously 65 million to 66 million pounds U3O8). KAP also warned that if the acid, supply chain and construction issues persist throughout 2024, the company’s 2025 plan to increase production to 100% of SSUAs (79 million to 82 million pounds U3O8) may also be affected. |
| • | In April, five of the G7 countries (Canada, France, Japan, UK, and US), entered into a civil nuclear fuel security agreement that attempts to reduce Russia’s influence in the global nuclear fuel supply chain. |
| • | In December, Urenco announced its decision to expand enrichment capacity at their facility in Almelo, Netherlands, increasing capacity by 15% or approximately 750,000 separative work units (SWU), by 2027. This followed a prior announcement of plans to expand enrichment capacity at its Urenco USA site, increasing capacity there by 15% or approximately 700,000 SWU, by 2025. |
| • | In October, Orano announced a planned enrichment capacity extension project at Georges Besse 2. The project, forecasted to cost €1.7 billion, seeks to increase capacity by over 30% or approximately 2.5 million SWU, beginning in 2028. |
| • | In July, ConverDyn announced the restart of Honeywell’s Metropolis uranium conversion facility. The restart plan had been delayed by a safety equipment failure in June, resulting in a special inspection by the US Nuclear Regulatory Commission. The facility restarted production in July 2023. |
| • | In July, a coup d’état in Niger resulted in a group of military officers removing President Mohamed Bazoum and seizing power. All exports of uranium and gold to France were suspended and in September, Orano stated that it had halted uranium processing operations at the company’s majority-owned SOMAIR (Arlit) project in Niger due to logistical complications caused by international sanctions. This resulted in 2023 production dropping to 3.9 million pounds U3O8, compared to around 5.2 million pounds U3O8 in 2022. |
| • | In December, the US House of Representatives passed the Prohibiting Russian Uranium Impacts Act. The act proposes to prohibit the import of Russian low-enriched uranium (LEU) into the US, but includes waivers that allow the import of LEU from Russia if the US Energy Secretary determines no alternative source can be procured, or if the shipments are of national interest. The waivers would gradually reduce and eliminate Russian uranium imports by 2028. The bill is awaiting further action after it was blocked by the US Senate on grounds unrelated to the bill itself. Separately, the US Senate Energy and Natural Resources Committee passed the Nuclear Fuel Security Act of 2023, which directs the Department of Energy to create a “Nuclear Fuel Security Program” and strengthen the US nuclear fuel supply chain, including new LEU and high-assay low-enriched uranium (HALEU) capacity, though no new funding has yet been appropriated. Finally, a Supplemental Funding Bill is progressing through Congress and includes roughly $111 billion (US) for national security measures, including a provision for $2.72 billion (US) to be allocated to a new “American Energy Independence Fund”, which would acquire non-Russian LEU and HALEU, subject to the ban on Russian imports becoming law. |
Long-term contracting creates full-cycle value for 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. 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 510 million pounds U3O8 equivalent have been locked-up in the long-term market, while approximately 780 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 2.2 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, geopolitical uncertainty 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
2023 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. We recently announced our commitment to the Net Zero Nuclear initiative, which is calling for collaboration among government, industry leaders and civil society to triple global nuclear capacity to achieve carbon neutrality by 2050. We believe nuclear energy is back in durable growth mode, and we too are back in durable growth mode. This growth 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, our portfolio of long-term contracts totals approximately 205 million pounds representing only about 20% of our current reserve and resource base, providing us with plenty of exposure to improving demand from our customers as they look to secure their long-term needs. We continue to 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 new long-term contracts that bring our total contracted volumes to over 75 million kgU of UF6 that will underpin that operation for years to come.
At McArthur River/Key Lake, we produced 13.5 million pounds (100% basis) of packaged uranium concentrate (14.8 million pounds at the mine, 13.5 million pounds of which were packaged at the mill), slightly below our most recent estimate of 14 million pounds (100% basis). At Cigar Lake, we produced 15.1 million pounds (100% basis) of packaged uranium, which is in line with our most recent estimate of up to 16.3 million pounds (100% basis). Any pounds we did not produce in 2023 remain available to us and, with increasing supply pressures, have potentially become more valuable when delivered in the future.
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. As well, delivery of our share of 2023 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 approximately two thirds of our share of Inkai’s 2023 production, arrived in the fourth quarter. The second shipment with the remainder of our share of 2023 production has arrived at a Canadian port.
Cameco has 35 years of experience in this market, and we have designed our strategy of full-cycle value capture to be resilient. Given the nature of our contracts, we have good visibility into when and where we need to deliver material, and we have put in place a number of tools that allow us to self-manage risk.
We have built a strong reputation as a proven and reliable supplier with a diversified production portfolio, that provides us with the flexibility to work with our customers to ensure they maintain access to our reliable supplies to satisfy their ongoing fuel requirements. In addition to our production, we can source material from market purchases today, and while these purchases would be more expensive than our production, our strategy positions us to benefit from added demand for nuclear fuel supplies and services. We have exposure to higher prices under the market-related contracts in our long-term portfolio and a pipeline of contracting discussions underway, which we expect will also benefit from the increased focus on securing access to scarce supplies and generate long-term value for Cameco. Also, we do not have to buy every pound in the spot market. We can source from inventory, to be replaced by production or purchases later. Further, we have the ability to pull forward long-term purchase arrangements that we put in place in a much lower-price environment, and with licensed storage facilities, we have secured the ability to borrow product under the terms of some of our storage agreements.
Global production shortfalls and transportation challenges in 2023 further highlighted the growing security of supply risk at a time when we believe the demand outlook is stronger and more durable than ever, with 28 countries around the world committing to triple nuclear power capacity by 2050. In this environment, uncertainty about where nuclear fuel supplies will come from to satisfy growing demand continues to drive long-term contracting as risk shifts from producers to utilities.
We delivered 32 million pounds of uranium and 12 million kgU in our fuel services segment to our customers in alignment with our contract portfolio and profitable opportunities in the market. We generated $688 million in cash from operations, with higher sales volumes and higher average realized prices in both our uranium and fuel services segments than in 2022.
MANAGEMENT’S DISCUSSION AND ANALYSIS 17
To meet our sales commitments and maintain a working inventory we purchased 11.3 million pounds of uranium at an average cost of $59.42 (US) per pound. While the unit cost of our purchases is significantly higher than the average production costs at McArthur River/Key Lake and Cigar Lake in 2023, we benefit from higher prices under the market-related portion of our long-term contract portfolio and higher prices benefit the pounds we have under negotiation. See 2023 financial results by segment – Uranium starting on page 61 for more information.
Thanks to our disciplined strategy, our balance sheet is strong, and we expect it will enable us to continue executing our strategy as well as to self-manage risk, including from global macro-economic uncertainty and volatility. As of December 31, 2023, we had $567 million in cash and cash equivalents with $1.8 billion in total debt. In addition, we have a $1.0 billion undrawn credit facility.
On November 7, 2023, we announced the closing of the acquisition of Westinghouse Electric Company (Westinghouse) in a strategic partnership with Brookfield Asset Management alongside its publicly listed affiliate Brookfield Renewable Partners (Brookfield) and institutional partners. Cameco now owns a 49% interest and Brookfield owns the remaining 51% in Westinghouse. We believe bringing together our expertise in the nuclear industry with Brookfield’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. See Westinghouse Electric Company beginning on page 94 for more information.
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 and to help meet our sales commitments, we plan to produce 18 million pounds (100% basis) at each of McArthur River/Key Lake and Cigar Lake in 2024. Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain 20% below the level stipulated in subsoil use agreements, similar to in 2023, primarily due to the sulfuric acid shortage in the country. We are still in discussions with JV Inkai and KAP to determine how this may impact production at Inkai in 2024 and thereafter and therefore our corresponding purchase obligation. We also plan to begin the work necessary to extend the mine life at Cigar Lake to 2036, subject to approval of Orano’s board, which we expect will be granted in the first quarter of 2024. In addition, at McArthur River/Key Lake, we plan to undertake an evaluation of the work and investment necessary to expand production up to its annual licensed capacity of 25 million pounds (100% basis), which we expect will allow us to take advantage of this opportunity when the time is right. See Uranium – Tier-one operations starting on page 73 for more information.
If we took advantage of all of the tier-one expansion opportunities available to us, our annual share of tier-one supply could be about 32 million pounds. However, we will continue to align our production with our contract portfolio and market opportunities, demonstrating that we continue to responsibly manage our supply in accordance with our customers’ needs.
In addition to our uranium production, at our Port Hope UF6 conversion facility we plan to produce 12,000 tonnes in 2024 to satisfy our book of long-term business and demand for conversion services, at a time when conversion prices are at historic highs.
We will continue to look for opportunities to improve operational effectiveness, to improve our safety performance and reduce our impact on the environment, including through the use of digital and automation technologies to allow us to operate our assets with more flexibility and efficiency. 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 plan to return to our tier-one cost structure, which we expect will generate strong 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.
18 CAMECO CORPORATION
Financial performance
| HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |
2023 | 2022 | CHANGE | |||||||||
| Revenue |
2,588 | 1,868 | 39 | % | ||||||||
| Gross profit |
562 | 233 | >100 | % | ||||||||
| Net earnings attributable to equity holders |
361 | 89 | >100 | % | ||||||||
| $ per common share (diluted) |
0.83 | 0.22 | >100 | % | ||||||||
| Adjusted net earnings (non-IFRS, see page 41) |
339 | 135 | >100 | % | ||||||||
| $ per common share (adjusted and diluted) |
0.78 | 0.33 | >100 | % | ||||||||
| Adjusted EBITDA (non-IFRS, see page 41) |
831 | 431 | 93 | % | ||||||||
| Cash provided by operations |
688 | 305 | >100 | % | ||||||||
Net earnings attributable to equity holders (net earnings) and adjusted net earnings in 2023 significantly outperformed 2022. See 2023 consolidated financial results beginning on page 39 for more information. Of note:
| • | generated $688 million in cash from operations |
| • | received refund of $297 million from CRA, consisting of cash in the amount of $86 million and letters of credit in the amount of $211 million. Also, received $12 million from CRA for disbursements related to the September 2018 Tax Court decision and cost award. See Transfer pricing dispute on page 46 for more information. |
| • | received a cash dividend of $79 million (US), net of withholdings, from JV Inkai |
| • | completed acquisition of 49% interest in Westinghouse for a $2.1 billion (US) purchase price. To finance the acquisition, we used $1.5 billion (US) of cash and drew the full amount of both $300 million (US) tranches of the term loan put in place concurrently with the execution of the acquisition agreement. See Westinghouse Electric Company starting on page 94 for more information. |
| • | incurred $51 million in care and maintenance costs compared to $218 million in care and maintenance and operational readiness costs in 2022 |
Our segment updates and other fuel cycle investment updates
In our uranium segment, we continued to execute our strategy, further ramping up our tier-one assets which had a positive impact on our operations. Of note in 2023, we:
| • | delivered 32 million pounds in alignment with the commitments under our contract portfolio and profitable market opportunities |
| • | produced 15.1 million pounds (100% basis) at Cigar Lake. Production was impacted by delays associated with the first production from a new mining zone and some unplanned maintenance work. |
| • | produced 13.5 million pounds (100% basis) at McArthur River/Key Lake. Production was impacted by challenges related to length of time the facility was in care and maintenance, the operational changes that were implemented throughout the mill, aging infrastructure, availability of personnel with the necessary skills and experience, and the impact of supply chain challenges on the availability of materials and reagents. |
| • | purchased 11.3 million pounds of uranium, including our spot purchases and committed purchase volumes (including JV Inkai purchases) |
| • | signed major supply agreement to meet Ukraine’s full nuclear fuel needs through 2035 |
| • | received 20-year licence renewals from the Canadian Nuclear Safety Commission (CNSC) for McArthur River, Key Lake and a 15-year licence renewal for Rabbit Lake |
| • | maintained Rabbit Lake and US ISR operations on care and maintenance |
In 2023, in our fuel services segment, we:
| • | delivered 12.0 million kgU under contract |
| • | produced 13.3 million kgU |
| • | received a 20-year licence renewal from the CNSC for Cameco Fuel Manufacturing (CFM). The licence renewal also grants CFM’s request for a slight production increase to 1,650 tonnes as UO2 fuel pellets. |
| • | commissioned a Closed Loop Cooling Water system at the Port Hope conversion facility, which is expected to provide environmental and operational improvements |
MANAGEMENT’S DISCUSSION AND ANALYSIS 19
See Operations and projects beginning on page 69 for more information.
| HIGHLIGHTS |
2023 | 2022 | CHANGE | |||||||||||||
| Uranium |
Production volume (million lbs) |
17.6 | 10.4 | 69 | % | |||||||||||
| Sales volume (million lbs) |
32.0 | 25.6 | 25 | % | ||||||||||||
| Average realized price1 |
($US/lb) |
49.76 | 44.73 | 11 | % | |||||||||||
| ($Cdn/lb) |
67.31 | 57.85 | 16 | % | ||||||||||||
| Revenue ($ millions) |
2,152 | 1,480 | 45 | % | ||||||||||||
| Gross profit ($ millions) |
444 | 121 | >100 | % | ||||||||||||
| Net earnings attributable to equity holders |
606 | 200 | >100 | % | ||||||||||||
| Adjusted EBITDA (non-IFRS, see page 41) |
835 | 380 | >100 | % | ||||||||||||
| Fuel services | Production volume (million kgU) |
13.3 | 13.0 | 2 | % | |||||||||||
| Sales volume (million kgU) |
12.0 | 11.1 | 8 | % | ||||||||||||
| Average realized price 2 |
($Cdn/kgU) | 35.61 | 32.92 | 8 | % | |||||||||||
| Revenue ($ millions) |
426 | 365 | 17 | % | ||||||||||||
| Gross profit ($ millions) |
124 | 117 | 6 | % | ||||||||||||
| Net earnings attributable to equity holders |
129 | 120 | 8 | % | ||||||||||||
| Adjusted EBITDA (non-IFRS, see page 41) |
164 | 153 | 7 | % | ||||||||||||
| Westinghouse |
Revenue |
521 | — | — | ||||||||||||
| (our share) |
Net loss attributable to equity holders |
(24 | ) | — | — | |||||||||||
| Adjusted EBITDA (non-IFRS, see page 41) |
101 | — | — | |||||||||||||
| 1 | Uranium average realized price is calculated as the revenue from sales of uranium concentrate, transportation 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 services, including fuel bundles and reactor components, transportation and storage fees divided by the volumes sold. |
Industry prices
| 2023 | 2022 | CHANGE | ||||||||||
| Uranium ($US/lb U3O8)1 |
||||||||||||
| Average annual spot market price |
62.51 | 49.81 | 25 | % | ||||||||
| Average annual long-term price |
58.20 | 49.75 | 17 | % | ||||||||
| Fuel services ($US/kgU as UF6)1 |
||||||||||||
| Average annual spot market price |
||||||||||||
| North America |
41.23 | 31.96 | 29 | % | ||||||||
| Europe |
41.23 | 31.96 | 29 | % | ||||||||
| Average annual long-term price |
||||||||||||
| North America |
30.55 | 24.75 | 23 | % | ||||||||
| Europe |
30.55 | 24.94 | 22 | % | ||||||||
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 2023 decreased to 55 million pounds U3O8 equivalent, compared to 62 million pounds U3O8 equivalent in 2022. In 2023, total spot purchases by producers, junior uranium companies, financial funds and intermediaries was approximately 42 million pounds U3O8 equivalent, compared to approximately 53 million pounds U3O8 equivalent in 2022; in 2023, these purchases represented over 75% of spot market purchases compared to over 85% in 2022. At the end of 2023, the average reported spot price was $91.00 (US) per pound, up $43.33 (US) per pound from the end of 2022. During the year, the uranium spot price ranged from a month-end low of $50.48 (US) per pound to a month-end high of $91.00 (US) per pound, averaging $62.51 (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, which also often include floor prices and ceiling prices that are also escalated to time of delivery.
20 CAMECO CORPORATION
The volume of long-term contracting reported by UxC for 2023 was about 160 million pounds U3O8 equivalent, up from about 125 million pounds U3O8 equivalent in 2022, including two contracts that combined totaled over 60 million pounds. Higher volumes can largely be attributed to utilities turning their attention to securing their long-term fuel needs to support the durable growth in demand for nuclear power and in light of the growing uncertainty of supply driven by heightened geopolitical tensions, and ongoing production challenges. The average reported long-term price at the end of the year was $68.00 (US) per pound, up $16.00 (US) from the end of 2022. During the year, the uranium long-term price steadily increased from a month-end low of $52.50 (US) per pound in January to a high of $68.00 (US) per pound in December, averaging $58.20 (US) for the year.
Since the Russian invasion of Ukraine in February 2022, conversion prices in both the North American and European markets have continued to increase. At the end of 2023, the average reported spot price for North American delivery reached a record high of $46.00 (US) per kilogram uranium as UF6 (US/kgU as UF6), up $6.00 (US) from the end of 2022. Long-term UF6 conversion prices for North American delivery finished 2023 at $34.25 (US/kgU as UF6), up $7.00 (US) from the end of 2022.
MANAGEMENT’S DISCUSSION AND ANALYSIS 21
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 corresponding commitment to limit global temperature rise to less than 2°C. 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 35 years, we have been delivering our products responsibly. Building on that strong foundation, we remain committed to our efforts to reduce 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, 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 |
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.
22 CAMECO CORPORATION
Our strategy
We are a pure-play investment in the growing demand for nuclear energy, focused on taking advantage of the near-, medium-, and long-term growth occurring in our industry. We provide nuclear fuel and nuclear power products, services, and technologies across the fuel cycle, augmented by our investment in Westinghouse, that support the generation of clean, reliable, secure, and affordable energy. Our strategy is set within the context of what we believe is a transitioning market environment. Increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are driving a global focus on tripling nuclear power capacity by 2050, which is 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 contracting framework |
| • | profitably producing from our tier-one assets and aligning our production decisions in all segments of the fuel cycle with contracted demand and customer needs |
| • | being financially disciplined to allow us to: |
| • | execute our strategy |
| • | invest in new opportunities that are expected to add long-term value |
| • | to self-manage risk |
| • | exploring other emerging opportunities within the nuclear power value chain, which align with our commitment to manage our business responsibly and sustainably, contribute to decarbonization, and help to provide secure and affordable energy |
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 of mineral reserves and resources that in some cases can leverage our existing infrastructure. Currently, we believe that we have ample productive capacity with the ability to expand as the demand for nuclear energy and nuclear fuel grows.
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 operational effectiveness to allow us to operate our assets more efficiently and with more flexibility.
FUEL SERVICES
Our fuel services segment supports our strategy to capture full-cycle value by 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.
WESTINGHOUSE
In 2023, we completed the acquisition of 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. We own a 49% interest in Westinghouse.
MANAGEMENT’S DISCUSSION AND ANALYSIS 23
We are enhancing our ability to compete for more business by investing in additional nuclear fuel cycle assets that we expect will augment the core of our business and offer more solutions to our customers across the nuclear fuel cycle. Like Cameco, Westinghouse has nuclear assets that are strategic, proven, licensed and permitted, and that are in geopolitically attractive jurisdictions. We expect these assets, like ours, will participate in the growing demand profile for nuclear energy.
Westinghouse has a stable and predictable core business generating durable cash flows. Like Cameco, Westinghouse has a long-term contract portfolio, which we believe positions it well to compete for growing demand for new nuclear reactors and reactor services, as well as the fuel supplies and services needed to keep the global reactor fleet operating safely and reliably. This strong base of business also helps protect Westinghouse from macro-economic headwinds as utility customers run their critical nuclear power plants. Its durable and growing business is expected to allow Westinghouse to self-fund its approved annual operating budget, to service its annual financial obligations from de-risked cash flows, and to pay annual distributions to its owners. See Westinghouse starting on page 94 for more information.
OTHER NUCLEAR FUEL CYCLE INVESTMENTS
We continually evaluate investment opportunities within the nuclear fuel value chain, which align well with our commitment to manage our business responsibly and sustainably, increase our contributions to decarbonization and help provide energy security. Expanding our participation in the fuel cycle is expected to complement our tier-one uranium and fuel services assets, creating new revenue opportunities, and it enhances our ability to meet the increasing needs of existing and new customers for secure, reliable nuclear fuel supplies, services and technologies.
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 an option to attain a majority interest of up to 75% ownership. See Global Laser Enrichment starting on page 99 for more information.
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.
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 Capital Allocation – Focus on Value, starting on page 30.
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 sales, we will compete for customer 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 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 committed sales. |
| • | As we build our portfolio of long-term contracts, we decide how to best source material to satisfy that 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. |
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| • | We do not intend to build an inventory of excess uranium. Excess inventory serves to contribute to the sense that uranium is abundant and creates an overhang on the market, and it ties up working capital on our balance sheet. |
| • | Depending on the timing and volume of our production, purchase commitments, and our inventory volumes, 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 supply we expect to come from our annual production and our long-term 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 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, including future development projects, 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.
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 generally 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 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 for uranium: 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS 25
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 generally set a month or more prior to 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 established 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. Demand may come in the form of off-market negotiations or through on-market requests for proposals. 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. However, we believe our customers 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 adjusting our contracts in a manner that allow us to maintain our customer relationships and is mutually beneficial.
CONTRACT PORTFOLIO STATUS
We have executed contracts to sell approximately 205 million pounds of U3O8 with 37 customers worldwide in our uranium segment, and over 75 million kilograms as UF6 conversion with 33 customers worldwide in our fuel services segment.
Customers – U3O8:
Five largest customers account for 62% of commitments
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Customers – UF6 conversion:
Five largest customers account for 64% 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 |
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 the uranium market is in transition, driven by the growing demand for nuclear energy and the increasing recognition that it is essential to the clean-energy transition and to energy security. As the market continues to transition, we expect to continue placing our uranium under long-term contracts and meet rising demand with production from our best margin operations.
MANAGEMENT’S DISCUSSION AND ANALYSIS 27
With the improvements in the market, the new long-term contracts we have put in place, and a pipeline of contracting discussions, we plan to produce 18 million pounds (100% basis) at McArthur River/Key Lake and Cigar Lake in 2024. Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain 20% below the level stipulated in subsoil use agreements, similar to in 2023, primarily due to the sulfuric acid shortage in the country. We are still in discussions with JV Inkai and KAP to determine how this may impact production at Inkai in 2024 and thereafter and therefore our corresponding purchase obligation. We also plan to begin the work necessary to extend the mine life at Cigar Lake subject to approval of Orano’s board. In addition, we plan to undertake the evaluation of the work and investment necessary to expand production at McArthur River/Key Lake up to its annual licensed capacity of 25 million pounds, which we expect will allow us to take advantage of this opportunity when the time is right.
Our production decisions will continue to be aligned with market opportunities 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 uranium production plans, we plan to produce 12,000 tonnes at our Port Hope UF6 conversion facility in 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 production plans for McArthur River/Key Lake and Cigar Lake are expected to generate strong financial performance by allowing us to source more of our committed sales from the lower-cost produced pounds. 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. 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.
| * | Production supplies include reagents, fuel and other items. Contracted services include utilities and camp costs, air charters, mining and maintenance contractors and security and ground freight. |
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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 2023 financial results by segment – Uranium starting on page 61 for more information. In 2024, 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 continued efforts to ramp up to planned production at McArthur River/Key Lake.
Operating costs in our fuel services segment are mainly fixed. In 2023, labour accounted for about 56% of the total. The largest variable operating cost is for anhydrous hydrogen fluoride, followed by zirconium, 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 2024, 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. Production at 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 of our share of material from Inkai, purchases under long-term contracts, purchases we make on the spot market and product loans. In 2024, we expect 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 if 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 significant 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 acquisition of a 49% interest in 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 to generate strong financial performance, 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS 29
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 |
| • | maintain a strong balance sheet that will allow us to execute on our strategy, take advantage of strategic opportunities and self-manage risk |
| • | allow us to sustainably execute on our dividend while considering the cyclical nature of our earnings and cash flow |
To deliver value, free cash flow must be productively reinvested in the business. We start by determining how much cash we have to invest (investable capital). Investable capital takes into account, our expected cash flow from operations, including the expected cash distributions from JV Inkai and our Westinghouse investment, minus the cash required to satisfy our financing costs, for working capital purposes, and the other uses of cash we consider to be higher priority, such as dividends. This investable capital can be reinvested in the core business of the company, including to manage the physical and transition risks and opportunities associated with changing climate conditions, or to take advantage of new opportunities in line with our long-term strategy. If after consideration of investment opportunities there is excess investable capital available, it can be considered for debt reduction, or shareholder returns.
Reinvestment
We have a multidisciplinary capital allocation committee that evaluates all sustaining, capacity replacement, or growth investment opportunities.
These opportunities are ranked using return criteria that includes both financial and non-financial metrics, with a current priority focus on five main value drivers:
| • | cost reduction |
| • | emission reduction |
| • | operational flexibility |
| • | improving safety performance |
| • | enabling digital technology |
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 and meeting ESG objectives, including achieving the 30% reduction in our GHG emissions by 2030 compared to 2015 levels.
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 regularly 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. For example, in 2022, the board increased the dividend by 50% to reflect the expected improvement in our financial performance as we began the transition to our tier-one run rate.
In Action
The current objective of our capital allocation will be to ensure we have the financial capacity to execute on our 2024 production plan and to return to our tier-one cost structure. In addition, we expect to allocate the capital necessary to allow us to begin work on extending the mine life at Cigar Lake and to undertake evaluation of the work and investment required to expand production at McArthur River/Key Lake up to its licensed capacity of 25 million pounds per year (100% basis).
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We will maintain our focus on improving operational effectiveness across the company through for example, the use of digital and automation technologies. The particular goals of this work being to reduce operating costs, increase operational flexibility, improve our safety performance and reduce our impact on the environment, including the reduction of our GHG emissions.
Over the coming months, we will look for an opportunity to refinance the $500 million senior unsecured debenture maturing on June 24, 2024, prior to maturity or as it comes due. Ultimately our decision will be made with consideration for our cash generation, the interest rate environment and other capital allocation considerations. In addition, we have initiated a partial repayment of $200 million (US) on the $600 million (US) floating-rate term loan that was used to finance the acquisition of Westinghouse. The prepayment will be applied to the $300 million (US) tranche which matures in November 2026. See Liquidity and capital resources – Financing Activities starting on page 54 for more information about the term loan.
We will continue to navigate by our investment-grade rating through close management of our balance sheet metrics, maintaining sufficient liquidity, including a minimum cash balance for working capital requirements and that would allow us to pursue other value-adding opportunities. If the market transition continues as expected, our priorities might include consideration of:
| • | the opportunities available to add value with our licensed and permitted tier-two assets and brownfield infrastructure |
| • | further value-adding opportunities in the nuclear fuel value chain |
| • | the return of excess cash to shareholders |
Any opportunities will be rigorously assessed by our capital allocation committee before an investment decision is made.
Shares and stock options outstanding
At February 6, 2024, we had:
| • | 434,175,752 common shares and one Class B share outstanding |
| • | 1,396,289 stock options outstanding, with exercise prices ranging from $11.32 to $16.38 |
Dividend
In 2023, our board of directors declared a dividend of $0.12 per common share, which was paid December 15, 2023. See the section titled Return on page 30 for more information regarding the factors the board considers in deciding to declare an annual dividend.
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. Key findings from this work were actioned throughout 2022 and 2023, including the undertaking of physical and transition-related climate scenario analyses to inform our overarching climate strategy. In 2023, the IFRS published its first two sustainability standards, S1 sustainability disclosure standard and S2 climate-related disclosure via the International Sustainability Standards Board. While it is unclear when and to what extent the Canadian Securities Administrators may adopt these standards at this point, we have begun the work to better understand the requirements under these standards and how our current reporting aligns with these standards.
In July 2023, we published our 2022 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 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 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. Policy makers and major industries recognize that nuclear power must be a central part of the solution to the world’s shift to a low-carbon, climate-resilient economy. Several nations have reaffirmed their commitments to nuclear power and are developing plans to support existing reactors and are reviewing their policies to encourage more nuclear capacity. There are now 28 countries that have signed on to the declaration that was launched at COP28 to triple nuclear energy capacity by 2050.
As one of the world’s largest producers of the uranium needed to fuel nuclear reactors, we believe this represents a significant opportunity for us to be part of the solution to combat climate change given 100% of our product is used to produce clean, carbon-free base-load electricity. We enable vast emissions reductions globally through nuclear power and are committed to transforming our already low operational GHG emissions footprint to achieve our ambition of having net-zero emissions while delivering significant long-term business value. In the 35 years we have been in business, we have sold over 954 million pounds of product for nuclear power generation. By reducing the need for fossil-fuel based electricity, this has avoided up to 16 billion tonnes of CO2e emissions, equivalent to removing all gas-powered vehicles in the world from operation for 3.5 years.
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Recently, we put further support behind our commitment to climate action and our vision of energizing a clean-air world by joining Net Zero Nuclear as a corporate partner. Net Zero Nuclear is an initiative between government, industry leaders and civil society to triple global nuclear capacity to achieve carbon neutrality by 2050. We join the initiative as a Gold Partner, deepening industry support for this initiative, which was launched by the World Nuclear Association and the Emirates Nuclear Energy Corporation, with the support of the Atoms4NetZero initiative launched by the International Atomic Energy Agency at the 2023 World Nuclear Symposium in London.
In 2022, we undertook a planning process to outline our overarching Low Carbon Transition Plan. Within this plan, we set a target to reduce our Scope 1 and 2 GHG emissions by 30% by 2030, from 2015 levels. We also 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”. Our Low Carbon Transition Plan provides a foundation for managing our climate-related physical and transition risks, and it supports us in better aligning with the Government of Canada’s Net Zero Accountability Act and 2030 Emission 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 Plan, we have completed climate change scenario analyses to understand how projected long-term changing climate conditions could impact our employees, assets, and operations in northern Saskatchewan and Ontario, Canada. We leveraged internal subject matter expertise with help from a third-party expert to complete the assessments.
The physical risk assessment studies were undertaken to deliver initial forward-looking physical climate risk assessments and identify possible risk management and adaptation options across our mining, milling and fuel services operations. In 2024, we will focus on updating the findings from these physical climate risk assessments into our internal risk management review and developing an adaptation action plan template. The template will support the development of site-specific adaptation plans for each of our Canadian operations. We are targeting the completion of physical climate risk assessments for all our majority owned and operated facilities by the end of 2026.
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.
To support achieving our 2030 GHG emissions reduction target, we implemented a 2023 compensable target to create tailored decarbonization pathways for each operationally controlled site. The 2023 work included an evaluation of over 160 decarbonization project ideas solicited from across the organization. Project ideas were evaluated based on cost, emissions reduction potential, implementation timeline, and other co-benefits as outlined by the climate action factors recently integrated within our Capital Allocation Committee process. The site-specific decarbonization pathways also included the development of practical project implementation timelines considering life of asset plans for each operation and technological readiness of the relevant technologies. Decarbonization efforts are already underway across our five decarbonization themes: efficiency, electrification, waste to value, fuel switching and carbon economy.
MANAGEMENT’S DISCUSSION AND ANALYSIS 33
Over the past few years, we have put significant effort towards efficiency, our first decarbonization theme. We have been focused on improving the visibility of energy consumption within our organization and implementing improvements to reduce energy consumption. We have already 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. In 2023, the Port Hope Closed Loop Cooling Water system was commissioned, eliminating the need to draw water from the nearby harbour. With the new closed loop system, the operation is no longer dependent on the temperature or quality of the lake water. This project has positive benefits for both the overall reliability and our environmental footprint, decreasing the energy required to change the temperature of the water and eliminating the risk of environmental releases to the lake.
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. Two projects were advanced in 2023 at our northern Saskatchewan operations: LED lighting updates to Key Lake and Ventilation-on-Demand at McArthur River. At Key Lake, we have made upgrades in lighting, updating to LED, translating to annual reductions of approximately 725,000 kWh electricity savings or 375 tonnes of CO2e. Additionally, this project improves operator comfort and safety when working in these areas. At McArthur River, the Ventilation-on-Demand project is currently underway. It includes mine ventilation upgrades to surface heater fans and underground ventilation dampers to enable a reduction in both electricity and propane consumption.
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.
We have a five-pillar approach to develop and maintain long-term relationships and provide opportunities to those living in areas near our operations. The five-pillars include workforce development, business development, community investment, environmental stewardship, and community engagement. To strengthen relationships and shape them into mutually beneficial partnerships, we have collaboration agreements in northern Saskatchewan and Ontario that follow this approach. These agreements allow us to collaboratively determine focus areas based on a community’s unique needs, optimizing benefits to the community, providing certainty around community investment and local business opportunities.
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.
34 CAMECO CORPORATION
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 and cyber 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 70, 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.
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.
| 2023 OBJECTIVES1 |
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 below 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
• performance of the leading indicators was above the target range |
||
| CLEAN ENVIRONMENT | ||||
| Environmental performance measures | Achieve corporate environmental targets.
Develop tailored decarbonization pathways for operationally controlled sites. |
• performance on corporate environmental targets was within the target range
• Completed decarbonization pathways for all operationally controlled sites |
||
| SUPPORTIVE COMMUNITIES | ||||
| Stakeholder support measure | Enhance the skill set of Residents of Saskatchewan’s North (RSN) for changing industrial environments | • RSN skill enhancement was above the target |
||
| 1 | Detailed results for our 2023 corporate objectives and the related targets will be provided in our 2024 management proxy circular prior to our Annual Meeting of Shareholders on May 9, 2024. |
36 CAMECO CORPORATION
2024 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 and continue to execute on our Low Carbon Transition Plan. |
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 |
2023 CONSOLIDATED FINANCIAL RESULTS |
|
| 51 |
OUTLOOK FOR 2024 |
|
| 54 |
LIQUIDITY AND CAPITAL RESOURCES |
|
| 61 |
2023 FINANCIAL RESULTS BY SEGMENT |
|
| 61 |
URANIUM |
|
| 62 |
FUEL SERVICES |
|
| 63 |
WESTINGHOUSE |
|
| 64 |
FOURTH QUARTER FINANCIAL RESULTS |
|
| 64 |
CONSOLIDATED RESULTS |
|
| 67 |
URANIUM |
|
| 68 |
FUEL SERVICES |
38 CAMECO CORPORATION
2023 consolidated financial results
During the fourth quarter, we announced the closing of the acquisition of a 49% interest in Westinghouse. Effective November 7, 2023, we began equity accounting for this investment. Our share of Westinghouse’s earnings has been reflected in our financial results from that date.
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 of production and financial results based on this new ownership stake.
| HIGHLIGHTS | CHANGE FROM | |||||||||||||||
| DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |
2023 | 2022 | 2021 | 2022 TO 2023 | ||||||||||||
| Revenue |
2,588 | 1,868 | 1,475 | 39 | % | |||||||||||
| Gross profit |
562 | 233 | 2 | >100 | % | |||||||||||
| Net earnings (loss) attributable to equity holders |
361 | 89 | (103 | ) | >100 | % | ||||||||||
| $ per common share (basic) |
0.83 | 0.22 | (0.26 | ) | >100 | % | ||||||||||
| $ per common share (diluted) |
0.83 | 0.22 | (0.26 | ) | >100 | % | ||||||||||
| Adjusted net earnings (loss) (non-IFRS, see page 41) |
339 | 135 | (98 | ) | >100 | % | ||||||||||
| $ per common share (adjusted and diluted) |
0.78 | 0.33 | (0.25 | ) | >100 | % | ||||||||||
| Adjusted EBITDA (non-IFRS, see page 41) |
831 | 431 | 194 | 93 | % | |||||||||||
| Cash provided by operations |
688 | 305 | 458 | >100 | % | |||||||||||
Net earnings
The following table shows what contributed to the change in net earnings in 2023 compared to 2022 and 2021.
| ($ MILLIONS) |
2023 | 2022 | 2021 | |||||||||||
| Net earnings (losses) - previous year |
89 | (103 | ) | (53 | ) | |||||||||
|
|
|
|
|
|
|
|||||||||
| Change in gross profit by segment |
||||||||||||||
| (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |
|
|||||||||||||
| Uranium |
Impact from sales volume changes |
30 | (6 | ) | (4 | ) | ||||||||
| Higher realized prices ($US) |
208 | 328 | 5 | |||||||||||
| Foreign exchange impact on realized prices |
95 | 44 | (72 | ) | ||||||||||
| Higher costs |
(9 | ) | (137 | ) | (55 | ) | ||||||||
|
|
|
|
|
|
|
|||||||||
| change – uranium |
324 | 229 | (126 | ) | ||||||||||
|
|
|
|
|
|
|
|||||||||
| Fuel services |
Impact from sales volume changes |
9 | (21 | ) | 1 | |||||||||
| Higher realized prices ($Cdn) |
32 | 33 | 23 | |||||||||||
| Higher costs |
(34 | ) | (13 | ) | (2 | ) | ||||||||
|
|
|
|
|
|
|
|||||||||
| change – fuel services |
7 | (1 | ) | 22 | ||||||||||
|
|
|
|
|
|
|
|||||||||
| Other changes |
||||||||||||||
| Lower (higher) administration expenditures |
(74 | ) | (44 | ) | 17 | |||||||||
| Lower (higher) exploration expenditures |
(7 | ) | (3 | ) | 3 | |||||||||
| Change in reclamation provisions |
31 | (31 | ) | 32 | ||||||||||
| Change in gains or losses on derivatives |
111 | (86 | ) | (24 | ) | |||||||||
| Change in foreign exchange gains or losses |
(58 | ) | 74 | (14 | ) | |||||||||
| Change in earnings from equity-accounted investments |
60 | 26 | 32 | |||||||||||
| Redemption of Series E debentures in 2020 |
— | — | 24 | |||||||||||
| Canadian Emergency Wage Subsidy |
— | (21 | ) | (16 | ) | |||||||||
| Bargain purchase gain on CLJV ownership interest increase |
(23 | ) | 23 | — | ||||||||||
| Higher (lower) finance income |
75 | 30 | (4 | ) | ||||||||||
| Higher finance costs |
(30 | ) | (9 | ) | (5 | ) | ||||||||
| Change in income tax recovery or expense |
(130 | ) | 3 | 15 | ||||||||||
| Other |
(14 | ) | 2 | (6 | ) | |||||||||
|
|
|
|
|
|
|
|||||||||
| Net earnings (losses) - current year |
361 | 89 | (103 | ) | ||||||||||
|
|
|
|
|
|
|
|||||||||
MANAGEMENT’S DISCUSSION AND ANALYSIS 39
Average realized prices
| CHANGE FROM | ||||||||||||||||||||
| 2023 | 2022 | 2021 | 2022 TO 2023 | |||||||||||||||||
| Uranium1 |
$ | US/lb | 49.76 | 44.73 | 34.53 | 11 | % | |||||||||||||
| $ | Cdn/lb | 67.31 | 57.85 | 43.34 | 16 | % | ||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| Fuel services |
$ | Cdn/kgU | 35.61 | 32.92 | 29.72 | 8 | % | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
| 1 | Average realized foreign exchange rate ($US/$Cdn): 2023 – 1.35, 2022 – 1.29 and 2021 – 1.26. |
Revenue
The following table shows what contributed to the change in revenue for 2023.
| ($ MILLIONS) |
||||
| Revenue – 2022 |
1,868 | |||
|
|
|
|||
| Uranium |
||||
| Higher sales volume |
370 | |||
| Higher realized prices ($Cdn) |
303 | |||
|
|
|
|||
| Fuel services |
||||
| Higher sales volume |
28 | |||
| Higher realized prices ($Cdn) |
32 | |||
|
|
|
|||
| Other |
(13 | ) | ||
|
|
|
|||
| Revenue – 2023 |
2,588 | |||
|
|
|
|||
See 2023 Financial results by segment on page 61 for more detailed discussion.
THREE-YEAR TREND
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.
In 2023, revenue increased by 39% compared to 2022 due to a 45% increase in the uranium segment and a 17% increase in our fuel services segment. Both segments saw increases in the average realized price and sales volume. See notes 18 and 29 in our annual financial statements for more information.
SALES DELIVERY OUTLOOK FOR 2024
For 2024 we have committed sales volumes in our uranium segment of between 32 and 34 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.
40 CAMECO CORPORATION
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 2024 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.
Non-IFRS measures
The non-IFRS measures referenced in this document are supplemental measures, which are used as indicators of our financial performance. Management believes that these non-IFRS measures provide useful supplemental information to investors, securities analysts, lenders and other interested parties in assessing our operational performance and our ability to generate cash flows to meet our cash requirements. These measures are not recognized measures under IFRS, do not have standardized meanings, and are therefore unlikely to be comparable to similarly-titled measures presented by other companies. Accordingly, these measures should not be considered in isolation or as a substitute for the financial information reported under IFRS. The following are the non-IFRS measures used in this document.
ADJUSTED NET EARNINGS
Adjusted net earnings (ANE) is our net earnings attributable to equity holders, adjusted for non-operating or non-cash items such as gains and losses on derivatives, adjustments to reclamation provisions flowing through other operating expenses, and bargain purchase gains, that we believe do not reflect the underlying financial performance for the reporting period. Other items may also be adjusted from time to time. We adjust this measure for certain of the items that our equity-accounted investees make in arriving at other non-IFRS measures. 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 Measuring our 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 49 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 asset in addition to the provision balance. When the assets of an operation have been written off due to an impairment, as is the case with our Rabbit Lake and US ISR operations, the adjustment is recorded directly to the statement of earnings as “other operating expense (income)”. See note 16 of our annual financial statements for more information. This amount has been excluded from our ANE measure.
MANAGEMENT’S DISCUSSION AND ANALYSIS 41
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)”.
As a result of the change in ownership of Westinghouse when they were acquired by Cameco and Brookfield, their inventories at the acquisition date were revalued based on the market price at that date. As these quantities are sold, their cost of products and services sold reflect these market values, regardless of Westinghouse’s historic costs. Since this adjustment is non-cash, outside of the normal course of business and only occurred due to the change in ownership, it has been excluded from our ANE measure.
To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2023, 2022 and 2021.
| ($ MILLIONS) |
2023 | 2022 | 2021 | |||||||||
| Net earnings (loss) attributable to equity holders |
361 | 89 | (103 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Adjustments |
||||||||||||
| Adjustments on derivatives |
(59 | ) | 76 | 13 | ||||||||
| Adjustments to earnings from equity-investees |
20 | — | — | |||||||||
| Adjustments on other operating expense (income) |
(2 | ) | 26 | (8 | ) | |||||||
| Adjustment to other income |
— | (23 | ) | — | ||||||||
| Income taxes on adjustments |
19 | (33 | ) | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Adjusted net earnings (loss) |
339 | 135 | (98 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
The following table shows what contributed to the change in adjusted net earnings (non-IFRS measure, see above) in 2023 compared to the same period in 2022 and 2021.
42 CAMECO CORPORATION
| ($ MILLIONS) |
2023 | 2022 | 2021 | |||||||||||
| Adjusted net earnings (losses) - previous year |
135 | (98 | ) | (66 | ) | |||||||||
|
|
|
|
|
|
|
|||||||||
| Change in gross profit by segment |
||||||||||||||
| (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |
|
|||||||||||||
| Uranium |
Impact from sales volume changes |
30 | (6 | ) | (4 | ) | ||||||||
| Higher realized prices ($US) |
208 | 328 | 5 | |||||||||||
| Foreign exchange impact on realized prices |
95 | 44 | (72 | ) | ||||||||||
| Higher costs |
(9 | ) | (137 | ) | (55 | ) | ||||||||
|
|
|
|
|
|
|
|||||||||
| change – uranium |
324 | 229 | (126 | ) | ||||||||||
|
|
|
|
|
|
|
|||||||||
| Fuel services |
Impact from sales volume changes |
9 | (21 | ) | 1 | |||||||||
| Higher realized prices ($Cdn) |
32 | 33 | 23 | |||||||||||
| Higher costs |
(34 | ) | (13 | ) | (2 | ) | ||||||||
|
|
|
|
|
|
|
|||||||||
| change – fuel services |
7 | (1 | ) | 22 | ||||||||||
|
|
|
|
|
|
|
|||||||||
| Other changes |
||||||||||||||
| Lower (higher) administration expenditures |
(74 | ) | (44 | ) | 17 | |||||||||
| Lower (higher) exploration expenditures |
(7 | ) | (3 | ) | 3 | |||||||||
| Change in reclamation provisions |
3 | 3 | — | |||||||||||
| Change in gains or losses on derivatives |
(24 | ) | (23 | ) | 34 | |||||||||
| Change in foreign exchange gains or losses |
(58 | ) | 74 | (14 | ) | |||||||||
| Change in earnings from equity-accounted investments |
80 | 26 | 32 | |||||||||||
| Redemption of Series E debentures in 2020 |
— | — | 24 | |||||||||||
| Canadian Emergency Wage Subsidy |
— | (21 | ) | (16 | ) | |||||||||
| Higher (lower) finance income |
75 | 30 | (4 | ) | ||||||||||
| Higher finance costs |
(30 | ) | (9 | ) | (5 | ) | ||||||||
| Change in income tax recovery or expense |
(78 | ) | (30 | ) | 7 | |||||||||
| Other |
(14 | ) | 2 | (6 | ) | |||||||||
|
|
|
|
|
|
|
|||||||||
| Adjusted net earnings (losses) - current year |
339 | 135 | (98 | ) | ||||||||||
|
|
|
|
|
|
|
|||||||||
EBITDA
EBITDA is defined as net earnings attributable to equity holders, adjusted for the costs related to the impact of the company’s capital and tax structure including depreciation and amortization, finance income, finance costs (including accretion) and income taxes.
ADJUSTED EBITDA
Adjusted EBITDA is defined as EBITDA, as further-adjusted for the impact of certain costs or benefits incurred in the period which are either not indicative of the underlying business performance or that impact the ability to assess the operating performance of the business. These adjustments include the amounts noted in the adjusted net earnings definition.
In calculating adjusted EBITDA, we also adjust for items included in the results of our equity-accounted investees. These items are reported as part of marketing, administrative and general expenses within the investee financial information and are not representative of the underlying operations. These include gain/loss on undesignated hedges, transaction costs related to acquisitions and gain/loss on disposition of a business.
We also adjust for the unwinding of the effect of purchase accounting on the sale of inventories which is included in our share of earnings from equity-accounted investee and recorded in the cost of products and services sold in the investee information (see note 12 to the financial statements).
The company may realize similar gains or incur similar expenditures in the future.
ADJUSTED FREE CASH FLOW
Adjusted free cash flow is defined as adjusted EBITDA less capital expenditures for the period.
ADJUSTED EBITDA MARGIN
Adjusted EBITDA margin is defined as adjusted EBITDA divided by revenue for the appropriate period.
MANAGEMENT’S DISCUSSION AND ANALYSIS 43
EBITDA, adjusted EBITDA, adjusted free cash flow, and adjusted EBITDA margin are measures which allow us and other users to assess results of operations from a management perspective without regard for our capital structure. To facilitate a better understanding of these measures, the table below reconciles earnings before income taxes with EBITDA and adjusted EBITDA for the years ended 2023 and 2022.
For the year ended December 31, 2023:
| FUEL | ||||||||||||||||||||
| ($ MILLIONS) |
URANIUM1 | SERVICES | WESTINGHOUSE | OTHER | TOTAL | |||||||||||||||
| Net earnings (loss) attributable to equity holders |
606 | 129 | (24 | ) | (350 | ) | 361 | |||||||||||||
| Depreciation and amortization |
175 | 35 | — | 10 | 220 | |||||||||||||||
| Finance income |
— | — | — | (112 | ) | (112 | ) | |||||||||||||
| Finance costs |
— | — | — | 116 | 116 | |||||||||||||||
| Income taxes |
(7 | ) | 126 | 119 | ||||||||||||||||
| Net adjustments on equity investees2 |
56 | — | 89 | — | 145 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| EBITDA |
837 | 164 | 58 | (210 | ) | 849 | ||||||||||||||
| Loss on derivatives |
— | — | — | (59 | ) | (59 | ) | |||||||||||||
| Other operating expense (income) |
(2 | ) | — | — | — | (2 | ) | |||||||||||||
| Other income |
— | — | — | — | — | |||||||||||||||
| Adjustments on equity investees3 |
— | — | 43 | — | 43 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Adjusted EBITDA |
835 | 164 | 101 | (269 | ) | 831 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 1 | JV Inkai EBITDA of $235 million is included in the uranium segment. See JV Inkai Non-IFRS measures on page 83. |
| 2 | Includes depreciation and amortization, finance income and finance costs of equity-accounted investees (see note 12 to the financial statements). |
| 3 | For detail of adjustments, see Our 2023 Earnings from Westinghouse on page 63. |
For the year ended December 31, 2022:
| FUEL | ||||||||||||||||
| ($ MILLIONS) |
URANIUM1 | SERVICES | OTHER | TOTAL | ||||||||||||
| Net earnings (loss) attributable to equity holders |
200 | 120 | (231 | ) | 89 | |||||||||||
| Depreciation and amortization |
136 | 33 | 8 | 177 | ||||||||||||
| Finance income |
— | — | (37 | ) | (37 | ) | ||||||||||
| Finance costs |
— | — | 86 | 86 | ||||||||||||
| Income taxes |
— | — | (4 | ) | (4 | ) | ||||||||||
| Net adjustments on equity investees2 |
41 | — | — | 41 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| EBITDA |
377 | 153 | (178 | ) | 352 | |||||||||||
| Loss on derivatives |
— | — | 76 | 76 | ||||||||||||
| Other operating expense (income) |
26 | — | — | 26 | ||||||||||||
| Other income |
(23 | ) | — | — | (23 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted EBITDA |
380 | 153 | (102 | ) | 431 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 1 | JV Inkai EBITDA of $135 million is included in the uranium segment. See JV Inkai Non-IFRS measures on page 83. |
| 2 | Includes depreciation and amortization, finance income and finance costs of equity-accounted investees (see note 12 to the financial statements). |
CASH COST PER POUND, NON-CASH COST PER POUND AND TOTAL COST PER POUND FOR PRODUCED AND PURCHASED URANIUM
Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium are non-IFRS measures. We use these measures in our assessment of the performance of our uranium business. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS.
44 CAMECO CORPORATION
To facilitate a better understanding of these measures, the table below reconciles these measures to cost of product sold and depreciation and amortization for the fourth quarter and years ended 2023 and 2022.
| THREE MONTHS | YEAR ENDED | |||||||||||||||
| ENDED DECEMBER 31 | DECEMBER 31 | |||||||||||||||
| ($ MILLIONS) |
2023 | 2022 | 2023 | 2022 | ||||||||||||
| Cost of product sold |
573.3 | 355.1 | 1,532.3 | 1,223.6 | ||||||||||||
| Add / (subtract) |
||||||||||||||||
| Royalties |
(10.6 | ) | (2.1 | ) | (71.7 | ) | (23.4 | ) | ||||||||
| Other selling costs |
(3.8 | ) | (2.0 | ) | (10.9 | ) | (5.9 | ) | ||||||||
| Care and maintenance and operational readiness costs |
(11.6 | ) | (35.5 | ) | (46.7 | ) | (178.5 | ) | ||||||||
| Change in inventories |
139.1 | 87.4 | (63.0 | ) | 124.2 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash operating costs (a) |
686.4 | 402.9 | 1,340.0 | 1,140.0 | ||||||||||||
| Add / (subtract) |
||||||||||||||||
| Depreciation and amortization |
31.6 | 18.2 | 175.5 | 135.8 | ||||||||||||
| Care and maintenance and operational readiness costs |
(0.5 | ) | (7.5 | ) | (3.9 | ) | (39.9 | ) | ||||||||
| Change in inventories |
31.3 | 40.2 | 32.6 | 67.6 | ||||||||||||
|
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|
|||||||||
| Total operating costs (b) |
748.8 | 453.8 | 1,544.2 | 1,303.5 | ||||||||||||
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| Uranium produced & purchased (million lbs) (c) |
12.0 | 9.5 | 28.9 | 28.7 | ||||||||||||
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|
|||||||||
| Cash costs per pound (a ÷ c) |
57.20 | 42.41 | 46.37 | 39.72 | ||||||||||||
| Total costs per pound (b ÷ c) |
62.40 | 47.77 | 53.43 | 45.42 | ||||||||||||
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Corporate expenses
ADMINISTRATION
| ($ MILLIONS) |
2023 | 2022 | CHANGE | |||||||||
| Direct administration1 |
186 | 143 | 30 | % | ||||||||
| Stock-based compensation1 |
60 | 25 | 140 | % | ||||||||
| Reversal (recovery) of fees related to CRA dispute |
— | 4 | (100 | )% | ||||||||
|
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|
|
|
|||||||
| Total administration |
246 | 172 | 43 | % | ||||||||
|
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|
|
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| 1 | Direct administration and stock-based compensation are supplementary financial measures. They are components of administration expense as shown on the statement of earnings and calculated according to IFRS. |
Direct administration costs in 2023 were $43 million higher than in 2022 largely due to the impacts of inflation, higher costs as a result of digital initiatives, and the restart at McArthur River/Key Lake.
We recorded $60 million in stock-based compensation expenses in 2023, $35 million higher compared to 2022 due to the increase in our share price from the comparative period. See note 25 to the financial statements.
Administration outlook for 2024
We expect direct administration costs to be between $190 million to $200 million.
EXPLORATION AND RESEARCH & DEVELOPMENT
Our 2023 exploration activities were focused primarily on Canada. Our spending increased from $11 million in 2022 to $18 million in 2023 and reflects higher planned expenditures.
We also had research and development expenditures in 2023 of $21 million compared to $12 million in 2022. These expenses are related to our investment in Global Laser Enrichment LLC (GLE). See Global Laser Enrichment on page 99.
Exploration and research & development outlook for 2024
We expect exploration expenses to be about $20 million in 2024. The focus for 2024 will be on our core projects in Saskatchewan. We expect research and development expenses to be about $37 million in 2024, primarily related to our investment in GLE. See Global Laser Enrichment on page 99.
MANAGEMENT’S DISCUSSION AND ANALYSIS 45
FINANCE COSTS
Finance costs were $116 million, an increase from $86 million in 2022 due to interest and standby fees on the facilities put in place to finance the acquisition of Westinghouse as well as 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 $112 million compared to $37 million in 2022 mainly due to higher interest rates and a higher short-term investments balance throughout 2023 due to the proceeds from the October 2022 share issuance that were used to partially finance the Westinghouse acquisition.
GAINS AND LOSSES ON DERIVATIVES
In 2023, we recorded $38 million in gains on our derivatives compared to $73 million in losses in 2022. The gains reflect a stronger Canadian dollar compared to the US dollar in 2023 compared to 2022. See Foreign exchange on page 49 and note 27 to the financial statements.
INCOME TAXES
We recorded an income tax expense of $126 million in 2023 compared to a recovery of $4 million in 2022 primarily as a result of higher earnings in Canada. Equity-accounted investees are included in both Canadian and foreign earnings net of tax paid in the jurisdictions in which they operate. Foreign earnings include losses in some jurisdictions for which no future tax benefit has been recognized.
In 2023, we recorded earnings of $562 million in Canada compared to earnings of $100 million in 2022, while in foreign jurisdictions, we recorded a loss of $75 million compared to a loss of $15 million in 2022.
| ($ MILLIONS) |
2023 | 2022 | ||||||
| Net earnings (loss) before income taxes |
||||||||
| Canada |
562 | 100 | ||||||
| Foreign |
(75 | ) | (15 | ) | ||||
|
|
|
|
|
|||||
| Total net earnings before income taxes |
487 | 85 | ||||||
|
|
|
|
|
|||||
| Income tax expense (recovery) |
||||||||
| Canada |
131 | (8 | ) | |||||
| Foreign |
(5 | ) | 4 | |||||
|
|
|
|
|
|||||
| Total income tax expense (recovery) |
126 | (4 | ) | |||||
|
|
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|
|
|||||
| Effective tax rate |
26 | % | (5 | )% | ||||
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TRANSFER PRICING DISPUTE
Background
Since 2008, Canada Revenue Agency (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 2017, CRA has advanced an alternate reassessing position, see Reassessments, remittances 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.
46 CAMECO CORPORATION
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. In October 2023, pursuant to a cost award from the courts, we received a payment of approximately $12 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 of the $780 million in cash and letters of credit we 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.
In March 2023, CRA issued revised reassessments for the 2007 through 2013 tax years, which resulted in a refund of $297 million of the $780 million in cash and letters of credit held by CRA at the time. The refund consisted of cash in the amount of $86 million and letters of credit in the amount of $211 million, which were returned in the second quarter. CRA continues to hold $483 million ($209 million in cash and $274 million in letters of credit) that we have remitted or secured to date.
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 $5.1 billion to $3.3 billion, resulting in a reduction of $1.8 billion in income taxable in Canada compared to the previous reassessments issued to us by CRA for the 2007 through 2013 tax years.
The remaining transfer pricing adjustment of $3.3 billion for the 2007 to 2013 tax years relates to the sale of Canadian-produced uranium by our foreign subsidiary. We maintain 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 all 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 all 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, we received a reassessment for the 2015 and 2016 tax years and in late 2023, we received a reassessment for the 2017 tax year, all reflecting this alternative reassessing position. CRA did not require additional security for the tax debts they considered owing for 2014 through 2016 but do require additional letters of credit related to the tax debts they considered owing for 2017 as discussed above, which we expect will be about $70 million.
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 2017 filing positions. On October 12, 2022, we filed an appeal with the Tax Court for the years 2014 and 2015, and in March 2023, filed a notice of objection for 2016. We plan to file a notice of objection for 2017.
MANAGEMENT’S DISCUSSION AND ANALYSIS 47
We will not be in a position to determine the definitive outcome of the 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 2017.
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
| • | 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
| • | 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 |
Tax outlook for 2024
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 and foreign 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% beginning in 2024. Switzerland, Luxembourg, and Germany have all enacted or substantively enacted these rules.
48 CAMECO CORPORATION
FOREIGN EXCHANGE
The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments.
We sell the majority of our uranium and fuel services products under long-term sales contracts, which are routinely denominated in US dollars. While our product purchases are denominated in US dollars, our production costs are largely denominated in Canadian dollars. To provide cash flow predictability, we hedge a portion of our net US/Cdn exposure (e.g. total US dollar sales less US dollar expenditures and product purchases) to manage shorter term exchange rate volatility. Our results are therefore affected by the movements in the exchange rate on our hedge portfolio, and on the unhedged portion of our net exposure.
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 2024 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 41.
The table below provides a summary of our hedge portfolio at December 31, 2023. You can use this information to estimate the expected gains or losses on derivatives for 2024 on an ANE basis. Additionally, if we add contracts to the portfolio that are designated for use in 2024 or if there are changes in the US/Cdn exchange rates in the year, those expected gains or losses could change.
MANAGEMENT’S DISCUSSION AND ANALYSIS 49
Hedge portfolio summary
| DECEMBER 31, 2023 | AFTER | |||||||||||||||
| ($ MILLIONS) |
2024 | 2024 | TOTAL | |||||||||||||
| US dollar forward contracts |
($ millions | ) | 690 | 870 | 1,560 | |||||||||||
| Average contract rate 1 |
(US/Cdn dollar | ) | 1.32 | 1.34 | 1.33 | |||||||||||
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| US dollar option contracts |
($ millions | ) | 10 | — | 10 | |||||||||||
| Average contract rate range1 |
(US/Cdn dollar | ) | 1.20 to 1.24 | — | 1.20 to 1.24 | |||||||||||
|
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| Total US dollar hedge contracts |
($ millions | ) | 700 | 870 | 1,570 | |||||||||||
| Average hedge rate |
(US/Cdn dollar | ) | 1.32 | 1.34 | 1.33 | |||||||||||
| Hedge ratio2 |
52 | % | 19 | % | 22 | % | ||||||||||
| 1 | The average contract rate is the weighted average of the rates stipulated in the outstanding contracts. |
| 2 | Hedge ratio is calculated by dividing the amount (in foreign currency) of outstanding derivative contracts by estimated future net exposures. |
At December 31, 2023:
| • | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.32 (Cdn), down from $1.00 (US) for $1.36 (Cdn) at December 31, 2022. The exchange rate averaged $1.00 (US) for $1.35 (Cdn) over the year. |
| • | The mark-to-market position on all foreign exchange contracts was a $12 million gain compared to a $48 million loss at December 31, 2022. The mark-to-market position is a component of 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, 2023, 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.
50 CAMECO CORPORATION
Outlook for 2024
Our outlook for 2024 reflects the continued 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 (100% basis) at each of Cigar Lake and McArthur River/Key Lake, and to produce 12,000 tonnes UF6 at our Port Hope conversion facility, we expect strong financial performance, including cash flow generation.
Our financial performance and the amount of cash generated will be dependent on sourcing the material required to meet our deliveries as planned, including achieving our production plans. 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.
2023 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 2023, the operations continued to ramp up production. We set a production target of 20.3 million pounds (our share) at the beginning of 2023. In September, we revised this to up to 18.7 million pounds (our share), and we achieved 17.6 million pounds (our share), consisting of 9.4 million pounds (our share) of production at McArthur River/Key Lake and 8.2 million pounds of production (our share) at Cigar Lake, both slightly below our forecast. See Uranium – Tier-one production on page 73 for more information.
At the end of the third quarter, average realized price was expected to be $65.50 per pound. This was based on a uranium spot price of $70.00 (US) per pound (the UxC spot price as of September 25, 2023) and a long-term price indicator of $61.00 (US) per pound (the UxC long-term indicator on September 25, 2023). The spot price averaged $82.21 (US) per pound during the fourth quarter, and as a result, the actual average realized price was $67.31 per pound, resulting in revenue slightly above the forecasted range for the uranium segment.
See 2023 Financial results by segment on page 61 for details.
2024 Financial outlook
| CONSOLIDATED | URANIUM | FUEL SERVICES | WESTINGHOUSE | |||||||||||||
| Production (owned and operated properties) |
— | 22.4 million lbs | 13.5 to 14.5 million kgU | — | ||||||||||||
| Market purchases |
— | up to 2 million lbs | — | — | ||||||||||||
| Committed purchases (including Inkai purchase volumes) |
— | 9 million lbs | — | — | ||||||||||||
| Sales/delivery volume |
— | 32 to 34 million lbs | 12 to 13 million kgU | — | ||||||||||||
| Revenue |
$ | 2,850 to 3,000 million | $ | 2,410 to 2,530 million | $ | 430-460 million | — | |||||||||
| Average realized price |
— | $ | 74.70/lb | — | — | |||||||||||
| Average unit cost of sales (including D&A) |
— | $ | 57.00-60.00/lb | 1 | $ | 24.50-25.50/kgU | 2 | — | ||||||||
| Direct administration costs |
$ | 190-200 million | — | — | — | |||||||||||
| Exploration costs |
— | $ | 20 million | — | — | |||||||||||
| Capital expenditures |
$ | 215-250 million | — | — | — | |||||||||||
| Adjusted EBITDA (non-IFRS measure see page 41) |
— | — | — | $ | 445-510 million | |||||||||||
| 1 | Uranium average unit cost of sales is calculated as the cash and 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 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. |
MANAGEMENT’S DISCUSSION AND ANALYSIS 51
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 22.4 million pounds of production (our share) in our uranium segment. If we do not achieve 22.4 million pounds, the consolidated revenue outlook and outlook for the uranium segment could vary. |
| • | Market purchases – reflect the market purchases we plan to make in 2024. Market purchases may vary if planned production varies. In addition, if we decide to increase our working inventory from current levels our market purchases could be higher. Our market purchases could also be lower if, instead of making market purchases, we choose to source the required volumes by temporarily reducing inventory levels, by pulling forward long-term purchase commitments, or by drawing on loan arrangements we have in place. |
| • | Committed purchases – are based on the 4.7 million pounds we currently have commitments to acquire under contract in 2024 and our JV Inkai purchases, which we have assumed will be equivalent to our 2023 purchase volume of 4.2 million pounds. If Inkai production and/or deliveries vary, committed purchases may vary and we may have to rely on our other sources of supply described above. We equity account for our minority ownership interest in JV Inkai. We record our share of its production as a purchase. However, this does not reflect our share of the economic benefit. Our share of the economic benefit is based on the difference between our purchase price and JV Inkai’s lower production cost and is reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investees”. As a result, increases in the spot price increase our cost of purchases from JV Inkai and also our “share of earnings from equity-accounted investees”. The benefit is realized, through receipt of a cash dividend, when declared and paid by JV Inkai. |
| • | Our 2024 outlook for sales/delivery volume does not include sales between our uranium and fuel services segments. |
| • | Sales/delivery volume is based on the volumes we currently have commitments to deliver under contract in 2024. |
| • | Uranium revenue and average realized price are based on a uranium spot price of $91.00 (US) per pound (the UxC spot price on December 25, 2023), a long-term price indicator of $68.00 (US) per pound (the UxC long-term indicator on December 25, 2023) 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 material, the planned market purchases and committed purchases noted in the outlook at an anticipated average purchase price of about $100 (Cdn) per pound and includes care and maintenance costs of between $50 million and $60 million. We expect overall unit cost of sales could vary if there are changes in production and market or committed purchase volumes or the mix of supply sources used to meet our contract deliveries, uranium spot prices, and/or care and maintenance costs in 2023. |
| • | The Adjusted EBITDA outlook for Westinghouse is based on the assumptions listed in the section titled, Westinghouse – Future Prospects starting on page 94. |
| • | Westinghouse and JV Inkai are accounted for using the equity method for our share. Under equity accounting Westinghouse and JV Inkai capital expenditures are not presented within our consolidated financial statements and are therefore not included in our outlook for capital expenditures. |
The following table shows how changes in the exchange rate or uranium prices can impact our outlook.
| IMPACT ON: | ||||||||||||||
| FOR 2024 ($ MILLIONS) |
CHANGE |
REVENUE | ANE | CASH FLOW | ||||||||||
| Uranium spot and long-term price1 |
$5(US)/lb increase | 9 | (21 | ) | (49 | ) | ||||||||
| $5(US)/lb decrease | (22 | ) | 12 | 37 | ||||||||||
| Value of Canadian dollar vs US dollar |
One cent decrease in CAD | 22 | 7 | 5 | ||||||||||
| One cent increase in CAD | (22 | ) | (7 | ) | (5 | ) | ||||||||
| 1 | Assuming change both UxC spot price $91.00 (US) per pound on December 25, 2023 and the UxC long-term price indicator $68.00 (US) per pound on December 25, 2023. |
We have sensitivity to the uranium price through both our sales and purchase commitments. However, at the current price levels many of the market-related sales contracts we are delivering into in 2024 are subject to ceiling prices and therefore are generally less sensitive than our purchase commitments.
This sensitivity assumes that 2 million pounds of purchases are sourced from the market. To the extent that our market purchases vary, our sensitivity of ANE and cash flow to changes in the spot and long-term prices may be impacted. In the case of decreased market purchasing, our sensitivity would be reduced. In the case of increased market purchasing, our sensitivity would be greater.
52 CAMECO CORPORATION
Price sensitivity analysis: uranium segment
As discussed under the Long-term contracting section on page 25, our average realized price is based on pricing terms established in our portfolio of long-term contracts, which includes a mix of base-escalated and market-related contracts that are layered in over time. Each confidential contract is bilaterally negotiated with the customer and delivery generally does not begin until two years or more after signing.
| • | Base-escalated contracts will reflect market conditions and pricing at the time each contract was finalized, with escalation factors applied based on when the material is delivered. |
| • | Market-related contracts reference a pricing mechanism that may be based on either the spot price or the long-term price, and that price is generally set a month or more prior to delivery, subject to specific terms unique to each contract, such as floors and ceilings set relative to market pricing at time of negotiation and typically escalated to time of delivery. |
As a result of these contracting dynamics, changes to our average realized price will generally lag changes in market prices in both rising and falling price conditions. The magnitude and direction of the deviation can vary based on the degree of market price volatility between the time the contract price is set, and the time the product is delivered.
To help understand how the pricing under our current portfolio of commitments is expected to react at various spot prices at December 31, 2023, we have constructed the table that follows.
The table is based on the volumes and pricing terms under the long-term commitments in our contract portfolio that have been finalized as at December 31, 2023. The table does not include volumes and pricing terms in contracts under negotiation or those that have been accepted but are still subject to contract finalization. Based on the terms and volumes under contracts that have been finalized, the table is designed to indicate how our average realized price would react under various spot price assumptions at a point in time. 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, 2023, using the following assumptions:
| • | The uranium price remains fixed at a given spot level for each annual period shown |
| • | Deliveries based on commitments under finalized contracts include best estimates of the expected deliveries and flexibility under contract terms |
| • | To reflect escalation mechanisms contained in existing contracts, the long-term US inflation rate target of 2% is used, 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, 2023
| (rounded to the nearest $1.00) | ||||||||||||||||||||||||||||
| SPOT PRICES | ||||||||||||||||||||||||||||
| ($US/lb U3O8) |
$20 | $40 | $60 | $80 | $100 | $120 | $140 | |||||||||||||||||||||
| 2024 |
38 | 43 | 52 | 56 | 58 | 59 | 59 | |||||||||||||||||||||
| 2025 |
38 | 43 | 54 | 61 | 64 | 65 | 66 | |||||||||||||||||||||
| 2026 |
41 | 43 | 56 | 66 | 69 | 70 | 71 | |||||||||||||||||||||
| 2027 |
41 | 44 | 57 | 68 | 71 | 73 | 74 | |||||||||||||||||||||
| 2028 |
44 | 46 | 57 | 69 | 72 | 74 | 76 | |||||||||||||||||||||
As of December 31, 2023, we had commitments requiring delivery of an average of about 27 million pounds per year from 2024 through 2028, with commitment levels in 2024 and 2025 higher than the average and in 2026 through 2028 lower than the average, reflecting our disciplined approach to contracting. As the market improves, we expect to continue to layer in volumes capturing greater upside using market-related pricing mechanisms.
MANAGEMENT’S DISCUSSION AND ANALYSIS 53
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 regularly consider our financing options so we can take advantage of favourable market conditions when they arise. In addition, with improving prices under our long-term contract portfolio and the plan to return to our tier one cost structure, we expect to continue to see strong earnings and cash flow generation in 2024.
To finance our 49% share of the purchase price of Westinghouse, on November 7, 2023, we used $1.5 billion (US) of cash and drew the full amount of both $300 million (US) tranches of the term loan. See Westinghouse on page 94 for more information. At the end of 2023, we had cash and cash equivalents of $567 million, while our total debt amounted to $1.8 billion. Our cash balances and investments are held in government securities or with banks that are party to our lending facilities. We have a risk management policy that we follow to manage our exposure to banking counterparties, which limits the amount and tenor of cash or investments based on counterparty credit rating. Our investment decisions prioritize security and liquidity and consider concentration amongst our banking partners. The majority of our cash balances are with Schedule I Canadian banks.
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 2024 through 2028, we have commitments to deliver an average of 27 million pounds per year, with commitment levels in 2024 and 2025 higher than the average and in 2026 through 2028 lower than the average.
We expect the increased production from our tier one assets will continue to generate strong cash flows. It will allow us to source more of our committed sales from lower-cost produced pounds. However, cash flow from operations for 2024 will be dependent on our ability to source the material required to meet our deliveries as planned, including achieving our production plans.
We expect our cash balances and operating cash flows to meet our capital requirements during 2024, based on the assumption that we will refinance our $500 million debenture on or prior to its June 2024 maturity. With our expected strong cash flow generation, and in conjunction with our capital allocation priorities, we plan to reduce total debt, with a focus on the floating rate term loan. See below for more information on Investing Activities, Financing Activities and Off-Balance Sheet Arrangements and our Capital Allocation section on page 30 for more information.
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 position and arguments for tax years 2007 through 2014, or its alternate reassessing position for tax years 2014 through 2017 and believe CRA should return all cash and letters of credit (to date, $483 million for 2007 through 2014) being held. However, timing of any further payments is uncertain, and there can be no assurance that the courts will take this position. Additionally, we expect to provide approximately $70 million in letters of credit to secure the tax debts CRA considers owing for 2017. See page 46 for more information.
54 CAMECO CORPORATION
Financial condition
| 2023 | 2022 | |||||||
| Cash position ($ millions) |
||||||||
| (cash and cash equivalents and short-term investments) |
567 | 2,282 | ||||||
|
|
|
|
|
|||||
| Cash provided by operations ($ millions) |
||||||||
| (net cash flow generated by our operating activities after changes in working capital) |
688 | 305 | ||||||
|
|
|
|
|
|||||
| Cash provided by operations/net debt1 |
||||||||
| (net debt is total consolidated debt, less cash position) |
57 | % | -24 | % | ||||
|
|
|
|
|
|||||
| Net debt/total capitalization1 |
||||||||
| (total capitalization is net debt and equity) |
17 | % | -28 | % | ||||
|
|
|
|
|
|||||
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 7, 2024:
| 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 October 12, 2023, DBRS confirmed the rating and outlook. |
| 2 | On February 16, 2022, S&P revised Cameco’s rating outlook to stable and affirmed the rating. |
Although we are required to equity account for our investment in Westinghouse, we expect the ratings agencies will proportionately consolidate it in their rating analysis. There was no change to our credit ratings upon close of the acquisition.
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.
Liquidity
| ($ MILLIONS) |
2023 | 2022 | ||||||
| Cash and cash equivalents and short-term investments at beginning of year |
2,282 | 1,332 | ||||||
|
|
|
|
|
|||||
| Cash from operations |
688 | 305 | ||||||
|
|
|
|
|
|||||
| Investment activities |
||||||||
| Additions to property, plant and equipment and acquisitions |
(3,183 | ) | (245 | ) | ||||
| Other investing activities |
— | 8 | ||||||
|
|
|
|
|
|||||
| Financing activities |
||||||||
| Change in debt |
817 | — | ||||||
| Interest paid |
(41 | ) | (39 | ) | ||||
| Issue of shares |
28 | 963 | ||||||
| Dividends |
(52 | ) | (52 | ) | ||||
| Other financing activities |
(3 | ) | (3 | ) | ||||
|
|
|
|
|
|||||
| Exchange rate on changes on foreign currency cash balances |
31 | 13 | ||||||
|
|
|
|
|
|||||
| Cash and cash equivalents and short-term investments at end of year |
567 | 2,282 | ||||||
|
|
|
|
|
|||||
CASH FROM OPERATIONS
Cash from operations in 2023 was higher than in 2022 due to higher earnings, the $86 million cash refund from CRA, higher interest received due to higher cash and investment balances, and lower working capital requirements. Purchases in 2023 were 11.3 million pounds compared to 18.3 million pounds in 2022. Not including working capital requirements, our operating cash flows in the year were up $330 million. See note 24 to the financial statements.
MANAGEMENT’S DISCUSSION AND ANALYSIS 55
INVESTING ACTIVITIES
Cash used in investing includes acquisitions and capital spending.
Capital spending
We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development. We have a capital allocation process to approve our capital spend. See Capital Allocation beginning on page 30 for more information.
| CAMECO’S SHARE ($ MILLIONS) |
2023 ACTUAL | 2024 PLAN | ||||||
| Sustaining capital |
||||||||
| Uranium |
49 | 80-85 | ||||||
| Fuel services |
39 | 60-65 | ||||||
| Other |
6 | 5-10 | ||||||
|
|
|
|
|
|||||
| Total sustaining capital |
94 | 145-160 | ||||||
|
|
|
|
|
|||||
| Capacity replacement capital |
||||||||
| Uranium |
56 | 50-60 | ||||||
| Fuel services |
— | — | ||||||
|
|
|
|
|
|||||
| Total capacity replacement capital |
56 | 50-60 | ||||||
|
|
|
|
|
|||||
| Growth capital |
||||||||
| Uranium |
1 | 15-20 | ||||||
| Fuel services |
3 | 5-10 | ||||||
|
|
|
|
|
|||||
| Total growth capital |
4 | 20-30 | ||||||
|
|
|
|
|
|||||
| Total sustaining, capital and growth |
154 | 215-250 | ||||||
|
|
|
|
|
|||||
Outlook for investing activities
| CAMECO’S SHARE ($ MILLIONS) |
2024 PLAN | 2025 PLAN | 2026 PLAN | |||||||||
| Total uranium & fuel services |
215-250 | 200-250 | 200-250 | |||||||||
|
|
|
|
|
|
|
|||||||
| Sustaining capital |
145-160 | 120-140 | 110-130 | |||||||||
| Capacity replacement capital |
50-60 | 30-50 | 30-50 | |||||||||
| Growth capital |
20-30 | 50-60 | 60-70 | |||||||||
Our 2024, 2025 and 2026 capital spending estimates assume that we produce 18 million pounds (100% basis) per year at McArthur River/Key Lake and at Cigar Lake and produce 12,000 tonnes per year at our UF6 conversion facility. If our production plans change, then our capital spending estimates may change.
Our estimate for capital spending in 2024 has been increased to between $215 million and $250 million (previously between $150 million and $200 million) due to the capital required to meet production targets sustainably and reliably, commencement of work on the Cigar Lake extension and the rescheduling of some expenditures planned in 2023 to 2024.
Our estimate for capital spending in 2025 has been increased to between $200 million and $250 million (previously between $100 million and $150 million) due to the rescheduling of expenditures and work on the Cigar Lake extension.
Capital expenditures for JV Inkai are expected to be covered by JV Inkai cash flows in 2024 and Westinghouse capital expenditures are expected to be covered by Westinghouse cash flows, both are included in our overall equity investment.
Major capital expenditures in 2024 include:
| • | Investments required to refresh aging infrastructure to help ensure reliable and sustainable production at all our operations as planned |
| • | Fuel services – continued work on our Vision in Motion project |
| • | Cigar Lake – begin work on the Cigar Lake extension. See Cigar Lake starting on page 77. |
56 CAMECO CORPORATION
This information regarding currently expected capital expenditures for future periods is forward-looking information and is based upon the assumptions and subject to the material risks discussed on pages 4 to 6. Our actual capital expenditures for future periods may be significantly different.
FINANCING ACTIVITIES
Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance.
Contractual obligations
| 2025 AND | 2027 AND | 2029 AND | ||||||||||||||||||
| DECEMBER 31 ($ MILLIONS) |
2024 | 2026 | 2028 | BEYOND | TOTAL | |||||||||||||||
| Debt |
500 | 795 | 400 | 100 | 1,795 | |||||||||||||||
| Interest on debt |
85 | 121 | 22 | 71 | 299 | |||||||||||||||
| Provision for reclamation |
36 | 131 | 105 | 1,084 | 1,356 | |||||||||||||||
| Provision for waste disposal |
3 | 5 | 2 | — | 10 | |||||||||||||||
| Other liabilities |
18 | 12 | 5 | 77 | 112 | |||||||||||||||
| Capital commitments |
61 | — | — | — | 61 | |||||||||||||||
| Unconditional product purchase obligations |
341 | 170 | 18 | — | 529 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
1,044 | 1,234 | 552 | 1,332 | 4,162 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 1 | Debt and interest on debt is calculated assuming that all debt is held to maturity and as such does not incorporate the expected reduction in 2024 of the term loan outstanding, or any other reductions, and the associated impact on interest payments. |
We have contractual capital commitments of approximately $61 million at December 31, 2023. 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, 2027. Each calendar year, 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 ranks equally with all of our other senior debt. At December 31, 2023, there were no amounts outstanding under this facility. |
| • | Financial assurance facilities with various financial institutions and insurers of approximately $1.7 billion. At December 31, 2023, we had approximately $1.4 billion outstanding on these facilities. 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. |
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 (classified as current) |
| • | $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 |
Additionally, we have approximately $800 million in term loan debt. We have drawn the full amount of the single advance
$600 million (US) term loan that was put in place concurrently with the execution of the Westinghouse acquisition agreement, of which $300 million (US) matures in November 2025 and $300 million (US) matures in November 2026. We have initiated a partial repayment of $200 million (US) on the $300 million (US) tranche which matures in November 2026. The term loan facility requires interest rate elections on each tranche, priced at the applicable rate of:
| • | Term Secured Overnight Financing Rate (SOFR) plus a credit spread adjustment of 0.10% and a margin that currently ranges from 1.7% to 1.95%, or |
| • | US base rate, plus a margin that currently ranges from 0.7% to 0.95% |
The margins are dependent on the company’s credit rating and as such could change over the term if the credit rating changes.
MANAGEMENT’S DISCUSSION AND ANALYSIS 57
The $280 million (US) bridge commitment that we also secured concurrently with the acquisition agreement was not required to complete the transaction and was terminated.
Debt covenants
Our credit agreements include 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, $100 million in letters of credit, cash and cash equivalents and short-term investments.
Not complying with any of these covenants could result in accelerated payment and termination of our credit agreements. At December 31, 2023, we complied with all covenants, and we expect to continue to comply in 2024.
OFF-BALANCE SHEET ARRANGEMENTS
We had three kinds of off-balance sheet arrangements at the end of 2023:
| • | purchase commitments |
| • | financial assurances |
| • | other arrangements |
Purchase commitments
We make purchases under long-term contracts where it is beneficial for us to do so and to support our long-term contract portfolio. The following table is based on our purchase commitments in our uranium and fuel services segments at December 31, 20232, but does not include purchases of our share of Inkai production. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.
| 2025 AND | 2027 AND | 2029 AND | ||||||||||||||||||
| DECEMBER 31, 2023 ($ MILLIONS) |
2024 | 2026 | 2028 | BEYOND | TOTAL | |||||||||||||||
| Purchase commitments1,2 |
341 | 170 | 18 | — | 529 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 1 | Denominated in US dollars and Japanese yen, converted from US dollars to Canadian dollars at the rate of 1.30 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 December 31, 2023, but does not include deliveries taken under contract since December 31, 2023. |
We have commitments of $529 million (Cdn) for the following:
| • | approximately 8.4 million pounds of U3O8 equivalent from 2024 to 2028 |
| • | approximately 0.3 million kgU as UF6 in conversion services in 2024 |
| • | about 0.4 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier |
The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions.
Financial assurances
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.
58 CAMECO CORPORATION
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. A decision on the PDCE is expected by the Commission in April 2024, after which the financial assurance will be updated.
For Smith Ranch-Highland, the 2023 surety was approved and the credit instruments are being reviewed by the State of Wyoming. For Crow Butte, the 2023 annual update was submitted to the federal Nuclear Regulatory Commission and Nebraska Department of Environmental Quality in September 2023.
At the end of 2023, 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 $1.05 billion at the end of 2023 (the present value of the $1.36 billion). Regulatory approval is required prior to beginning decommissioning. The expected timing for these costs in based on each mine or fuel service facility’s expected operating life. Our required costs for decommissioning and reclamation in each of the next five years are not expected to be material. However, we may choose to undertake progressive reclamation activities, for example, as we do at our US assets and through our Vision in Motion project at our Port Hope fuel services facilities.
We had a total of about $1.06 billion in financial assurances supporting our reclamation liabilities at the end of 2023. 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, 2023 our financial assurances totaled $1.4 billion, down from $1.6 billion at December 31, 2022, largely due to the return of letters of credit in the amount of $211 million from CRA. See Transfer pricing dispute on page 46.
Other arrangements
We have arranged for standby product loan facilities with various counterparties. The arrangements allow us to borrow up to 2.0 million kgU of UF6 conversion services and 3.5 million pounds of U3O8 over the period 2020 to 2026 with repayment in kind up to December 31, 2026. Under the loan facilities, standby fees of up to 1% are payable based on the market value of the facilities and interest is payable on the market value of any amounts drawn at rates ranging from 0.5% to 2.0%. At December 31, 2023, we have 1.8 million kgU of UF6 conversion services and 2.8 million pounds of U3O8 drawn on the loans.
BALANCE SHEET
| DECEMBER 31, | CHANGE | |||||||||||||||
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |
2023 | 2022 | 2021 | 2022 TO 2023 | ||||||||||||
| Inventory |
692 | 665 | 410 | 4 | % | |||||||||||
| Total assets |
9,934 | 8,633 | 7,518 | 15 | % | |||||||||||
| Total non-current liabilities |
2,651 | 2,236 | 2,318 | 19 | % | |||||||||||
| Dividends per common share |
0.12 | 0.12 | 0.08 | — | ||||||||||||
Total product inventories increased by 4% to $692 million this year due to the higher cost of purchased material. At December 31, 2023, our average cost for uranium was $49.62 per pound, up from $43.45 per pound at December 31, 2022. As of December 31, 2023, we held an inventory of 10.3 million pounds of U3O8 equivalent (excluding broken ore).
MANAGEMENT’S DISCUSSION AND ANALYSIS 59
At the end of 2023, our total assets amounted to $9.9 billion, an increase of 15% compared to 2022, due mainly to the addition of Westinghouse as an equity-accounted investee, partially offset by the decrease in cash and cash equivalents and short-term investments used to fund the acquisition. In 2022, the total asset balance increased by $1.1 billion compared to 2021, due mainly to an increase in investment balances resulting from the October 2022 issuance of common shares in preparation for the closing of the Westinghouse transaction as well as higher inventories.
60 CAMECO CORPORATION
2023 financial results by segment
Uranium
| HIGHLIGHTS |
2023 | 2022 | CHANGE | |||||||||||||
| Production volume (million lbs) |
17.6 | 10.4 | 69 | % | ||||||||||||
|
|
|
|
|
|
|
|||||||||||
| Sales volume (million lbs) |
32.0 | 25.6 | 25 | % | ||||||||||||
|
|
|
|
|
|
|
|||||||||||
| Average spot price |
($US/lb | ) | 62.51 | 49.81 | 25 | % | ||||||||||
| Average long-term price |
($US/lb | ) | 58.20 | 49.75 | 17 | % | ||||||||||
| Average realized price |
($US/lb | ) | 49.76 | 44.73 | 11 | % | ||||||||||
| ($Cdn/lb | ) | 67.31 | 57.85 | 16 | % | |||||||||||
|
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|||||||||||
| Average unit cost of sales (including D&A) |
($Cdn/lb | ) | 53.41 | 53.13 | 1 | % | ||||||||||
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|||||||||||
| Revenue ($ millions) |
2,152 | 1,480 | 45 | % | ||||||||||||
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|||||||||||
| Gross profit ($ millions) |
444 | 121 | >100 | % | ||||||||||||
|
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|||||||||||
| Gross profit (%) |
21 | 8 | >100 | % | ||||||||||||
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|||||||||||
| Net earnings attributable to equity holders |
606 | 200 | >100 | % | ||||||||||||
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|||||||||||
| Adjusted EBITDA (non-IFRS, see page 41)1 |
835 | 380 | >100 | % | ||||||||||||
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|||||||||||
| 1 | Includes JV Inkai EBITDA of $235 million in 2023 and $135 million in 2022. See JV Inkai Non-IFRS measures on page 83. |
Production volumes in 2023 increased by 69% compared to 2022. See Uranium – production overview on page 72 for more information.
Uranium revenues this year were up 45% compared to 2022 due to an increase in sales volumes of 25% and an increase of 16% in the Canadian dollar average realized price due to the impact of the increase in average US dollar spot price on market-related contracts as well as the weakening of the Canadian dollar. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 53.
Total cost of sales (including D&A) increased by 26% ($1.71 billion compared to $1.36 billion in 2022) due primarily to an increase in sales volume of 25% as well as a 1% increase in unit cost of sales. Unit cost of sales is slightly higher than in the same period in 2022 due to the higher cost of purchased material in 2023 compared to the same period in 2022 mostly offset by higher operational readiness costs at McArthur River/Key Lake operations in 2022.
The net effect was a $323 million increase in gross profit for the year.
The following table shows the costs of produced and purchased uranium incurred in the reporting periods (see Non-IFRS measures starting on page 41). These costs do not include care and maintenance costs, operational readiness costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
| ($CDN/LB) |
2023 | 2022 | CHANGE | |||||||||
| Produced |
||||||||||||
| Cash cost |
24.12 | 19.24 | 25 | % | ||||||||
| Non-cash cost |
11.60 | 15.72 | (26 | )% | ||||||||
|
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|||||||
| Total production cost 1 |
35.72 | 34.96 | 2 | % | ||||||||
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|||||||
| Quantity produced (million lbs)1 |
17.6 | 10.4 | 69 | % | ||||||||
|
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|
|||||||
| Purchased |
||||||||||||
| Cash cost1 |
81.02 | 51.36 | 58 | % | ||||||||
|
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|
|||||||
| Quantity purchased (million lbs)1 |
11.3 | 18.3 | (38 | )% | ||||||||
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|||||||
| Totals |
||||||||||||
| Produced and purchased costs |
53.43 | 45.42 | 18 | % | ||||||||
|
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|||||||
| Quantities produced and purchased (million lbs) |
28.9 | 28.7 | 1 | % | ||||||||
|
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|||||||
| 1 | Due to equity accounting for JV Inkai, our share of production is shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. In 2023 we purchased 4.2 million pounds at a purchase price per pound of $92.72 ($67.69 (US)) (2022 – 3.3 million pounds at a purchase price per pound of $62.78 ($47.33 (US))). |
MANAGEMENT’S DISCUSSION AND ANALYSIS 61
The average cash cost of production was 25% higher compared to 2022, due to lower production at Cigar Lake in 2023 as well as well as inflationary pressures and the ongoing ramp up of production at McArthur/Key Lake.
In 2024, we expect the average unit cost of production at McArthur River/Key Lake to continue to be higher than the average unit life of mine operating costs reflected in our most recent annual information form as we complete the ramp up of production and continue work to realize the benefits from the operational improvements that have been made. The average unit production cost at Cigar Lake is expected to trend down with higher planned production. The estimated average unit life of mine operating costs reflected in our most recent annual information form are $16 per pound at McArthur River/Key Lake and $18 per pound at Cigar Lake.
We equity account for our share of JV Inkai. As a result, we record our share of its production as a purchase, which under Kazakhstan’s pricing regulations, requires we purchase the material at a price equal to the uranium spot price, less a 5% discount. However, this does not reflect the economic benefit to Cameco. Our share of the economic benefit is based on the difference between our purchase price and JV Inkai’s lower production cost and is reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investees.” This benefit is realized through receipt of a cash dividend, when declared and paid by JV Inkai. Excess cash, net of working capital requirements is distributed to the partners as dividends. 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.
Our purchases in 2023, totaled about $916 million, representing an average annual cost of $81.02 per pound, about $45.00 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 58% this year compared to 2022. The average cash cost of purchased material was $81.02 (Cdn), or $59.42 (US) per pound, compared to $51.36 (Cdn), or $39.45 (US) per pound in the same period in 2022.
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%. |
| • | Profit royalty: a 10% royalty is charged on profit up to and including $28.182/kg U3O8 ($12.78/lb) and a 15% royalty is charged on profit in excess of $28.182/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer. |
As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.
Fuel services
| (includes results for UF6, UO2, UO3 and fuel fabrication) HIGHLIGHTS |
2023 | 2022 | CHANGE | |||||||||||||
| Production volume (million kgU) |
13.3 | 13.0 | 2 | % | ||||||||||||
| Sales volume (million kgU) |
12.0 | 11.1 | 8 | % | ||||||||||||
| Average realized price |
($ | Cdn/kgU | ) | 35.61 | 32.92 | 8 | % | |||||||||
| Average unit cost of sales (including D&A) |
($ | Cdn/kgU | ) | 25.23 | 22.39 | 13 | % | |||||||||
| Revenue ($ millions) |
426 | 365 | 17 | % | ||||||||||||
| Gross profit ($ millions) |
124 | 117 | 6 | % | ||||||||||||
| Gross profit (%) |
29 | 32 | (9 | )% | ||||||||||||
| Net earnings attributable to equity holders |
129 | 120 | 8 | % | ||||||||||||
| Adjusted EBITDA (non-IFRS, see page 41) |
164 | 153 | 7 | % | ||||||||||||
Total revenue increased by 17% from 2022 due to an 8% increase in sales volume and an 8% 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) increased 21% ($301 million compared to $248 million in 2022), due to the 8% increase in sales volume as well as a 13% increase in average unit cost of sales compared to 2022 due to higher input costs.
62 CAMECO CORPORATION
The net effect was a $7 million increase in gross profit.
Westinghouse
OUR 2023 EARNINGS FROM WESTINGHOUSE
On November 7, 2023, we announced the closing of the acquisition of Westinghouse in a strategic partnership with Brookfield. Cameco now owns a 49% interest and Brookfield owns the remaining 51%. Under the equity method of accounting, beginning on November 7, 2023, we have included our share of Westinghouse’s earnings in our financial results.
| ($ MILLIONS) |
100% | 49% | ||||||
| Net loss1 |
(49 | ) | (24 | ) | ||||
| Depreciation and amortization |
124 | 61 | ||||||
| Finance income |
(4 | ) | (2 | ) | ||||
| Finance costs |
61 | 30 | ||||||
| Income tax expense (recovery) |
(14 | ) | (7 | ) | ||||
|
|
|
|
|
|||||
| EBITDA2 |
118 | 58 | ||||||
| Adjustments on cost of products and services sold3 |
55 | 27 | ||||||
| Adjustments on marketing, administrative and general |
34 | 16 | ||||||
|
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|
|||||
| Adjusted EBITDA2 |
207 | 101 | ||||||
| Capital expenditures |
87 | 42 | ||||||
|
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|
|||||
| Adjusted free cash flow2 |
120 | 59 | ||||||
|
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|
|||||
| Revenue |
1,063 | 521 | ||||||
|
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|
|||||
| Adjusted EBITDA margin2 |
19 | % | 19 | % | ||||
|
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|||||
| 1 | This table includes results for the period beginning on the date of acquisition until the end of 2023. Comparative figures are not available. See Westinghouse Non-IFRS measures starting on page 95 for full year results for both 2023 and 2022 prepared in accordance with US GAAP. |
| 2 | Non-IFRS measures, see page 41 |
| 3 | Net earnings for 2023 were impacted by purchase price accounting. Inventories acquired were assigned values based on the market price at the date of the acquisition. As these quantities are sold, cost of products and services sold reflects these market values, regardless of Westinghouse’s historic costs. |
MANAGEMENT’S DISCUSSION AND ANALYSIS 63
Fourth quarter financial results
Consolidated results
| THREE MONTHS ENDED | ||||||||||||
| HIGHLIGHTS | DECEMBER 31 | |||||||||||
| ($ MILLIONS EXCEPT WHERE INDICATED) |
2023 | 2022 | CHANGE | |||||||||
| Revenue |
844 | 524 | 61 | % | ||||||||
| Gross profit |
133 | 65 | >100 | % | ||||||||
| Net earnings (loss) attributable to equity holders |
80 | (15 | ) | >100 | % | |||||||
| $ per common share (basic) |
0.18 | (0.04 | ) | >100 | % | |||||||
| $ per common share (diluted) |
0.18 | (0.04 | ) | >100 | % | |||||||
| Adjusted net earnings (non-IFRS, see page 41) |
90 | 36 | >100 | % | ||||||||
| $ per common share (adjusted and diluted) |
0.21 | 0.09 | >100 | % | ||||||||
| Cash provided by operations |
201 | 77 | >100 | % | ||||||||
NET EARNINGS
The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 41) in the fourth quarter of 2023 compared to the same period in 2022.
| ($ MILLIONS) |
IFRS | Adjusted | ||||||||
| Net earnings (losses) - 2022 |
(15 | ) | 36 | |||||||
|
|
|
|
|
|||||||
| Change in gross profit by segment |
||||||||||
| (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |
|
|||||||||
| Uranium |
Impact from sales volume changes |
10 | 10 | |||||||
| Higher realized prices ($US) |
122 | 122 | ||||||||
| Foreign exchange impact on realized prices |
13 | 13 | ||||||||
| Higher costs |
(73 | ) | (73 | ) | ||||||
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|||||||
| change – uranium |
72 | 72 | ||||||||
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|||||||
| Fuel services |
Impact from sales volume changes |
4 | 4 | |||||||
| Higher realized prices ($Cdn) |
8 | 8 | ||||||||
| Higher costs |
(14 | ) | (14 | ) | ||||||
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|||||||
| change – fuel services |
(2 | ) | (2 | ) | ||||||
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|||||||
| Other changes |
||||||||||
| Higher administration expenditures |
(30 | ) | (30 | ) | ||||||
| Higher exploration expenditures |
(1 | ) | (1 | ) | ||||||
| Change in reclamation provisions |
41 | (7 | ) | |||||||
| Change in gains or losses on derivatives |
36 | (4 | ) | |||||||
| Change in foreign exchange gains or losses |
2 | 2 | ||||||||
| Change in earnings from equity-accounted investments |
39 | 59 | ||||||||
| Lower finance income |
(3 | ) | (3 | ) | ||||||
| Higher finance costs |
(24 | ) | (24 | ) | ||||||
| Change in income tax recovery or expense |
(32 | ) | (5 | ) | ||||||
| Other |
(3 | ) | (3 | ) | ||||||
|
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| Net earnings - 2023 |
80 | 90 | ||||||||
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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 41 for more information. The following table reconciles adjusted net earnings with our net earnings.
64 CAMECO CORPORATION
| THREE MONTHS ENDED | ||||||||
| DECEMBER 31 | ||||||||
| ($ MILLIONS) |
2023 | 2022 | ||||||
| Net earnings (loss) attributable to equity holders |
80 | (15 | ) | |||||
|
|
|
|
|
|||||
| Adjustments |
||||||||
| Adjustments on derivatives |
(59 | ) | (19 | ) | ||||
| Adjustments to earnings from equity-investees |
20 | — | ||||||
| Adjustments on other operating expense (income) |
40 | 88 | ||||||
| Income taxes on adjustments |
9 | (18 | ) | |||||
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| Adjusted net earnings |
90 | 36 | ||||||
|
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ADMINISTRATION
| THREE MONTHS ENDED | ||||||||||||
| DECEMBER 31 | ||||||||||||
| ($ MILLIONS) |
2023 | 2022 | CHANGE | |||||||||
| Direct administration |
48 | 37 | 30 | % | ||||||||
| Stock-based compensation |
11 | (8 | ) | 238 | % | |||||||
| Total administration |
59 | 29 | 103 | % | ||||||||
Direct administration costs were $48 million in the quarter, $11 million higher than the same period last year. We recorded $11 million in stock-based compensation expenses in the fourth quarter of 2023, $19 million higher compared to 2022 due to the increase in our share price compared to the same period last year.
Quarterly trends
| HIGHLIGHTS | 2023 | 2022 | ||||||||||||||||||||||||||||||
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||||||||||
| Revenue |
844 | 575 | 482 | 687 | 524 | 389 | 558 | 398 | ||||||||||||||||||||||||
| Net earnings (loss) attributable to equity holders |
80 | 148 | 14 | 119 | (15 | ) | (20 | ) | 84 | 40 | ||||||||||||||||||||||
| $ per common share (basic) |
0.18 | 0.34 | 0.03 | 0.27 | (0.04 | ) | (0.05 | ) | 0.21 | 0.10 | ||||||||||||||||||||||
| $ per common share (diluted) |
0.18 | 0.34 | 0.03 | 0.27 | (0.04 | ) | (0.05 | ) | 0.21 | 0.10 | ||||||||||||||||||||||
| Adjusted net earnings (loss) (non-IFRS, see page 41) |
90 | 137 | (3 | ) | 115 | 36 | 10 | 72 | 17 | |||||||||||||||||||||||
| $ per common share (adjusted and diluted) |
0.21 | 0.32 | (0.01 | ) | 0.27 | 0.09 | 0.03 | 0.18 | 0.04 | |||||||||||||||||||||||
| Cash provided by (used in) operations (after working capital changes) |
201 | 185 | 87 | 215 | 77 | (47 | ) | 102 | 172 | |||||||||||||||||||||||
Key things to note:
| • | The timing of customer requirements, which tends to vary from quarter to quarter, drives revenue in the uranium and fuel services segments, meaning quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements. |
| • | Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 41 for more information). |
| • | Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments. |
MANAGEMENT’S DISCUSSION AND ANALYSIS 65
The table that follows presents the differences between net earnings and adjusted net earnings for the previous seven quarters.
| HIGHLIGHTS | 2023 | 2022 | ||||||||||||||||||||||||||||||
| ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||||||||||
| Net earnings (loss) attributable to equity holders |
80 | 148 | 14 | 119 | (15 | ) | (20 | ) | 84 | 40 | ||||||||||||||||||||||
| Adjustments |
||||||||||||||||||||||||||||||||
| Adjustments on derivatives |
(59 | ) | 41 | (35 | ) | (6 | ) | (19 | ) | 75 | 31 | (11 | ) | |||||||||||||||||||
| Adjustments to earnings from equity-investees |
20 | — | — | — | — | — | — | — | ||||||||||||||||||||||||
| Adjustments on other operating expense (income) |
40 | (48 | ) | 8 | (2 | ) | 88 | (24 | ) | (19 | ) | (19 | ) | |||||||||||||||||||
| Adjustment to other income |
— | — | — | — | — | — | (23 | ) | — | |||||||||||||||||||||||
| Income taxes on adjustments |
9 | (4 | ) | 10 | 4 | (18 | ) | (21 | ) | (1 | ) | 7 | ||||||||||||||||||||
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| Adjusted net earnings (losses) (non-IFRS, see page 41) |
90 | 137 | (3 | ) | 115 | 36 | 10 | 72 | 17 | |||||||||||||||||||||||
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66 CAMECO CORPORATION
Fourth quarter financial results by segment
Uranium
| THREE MONTHS ENDED | ||||||||||||||||
| DECEMBER 31 | ||||||||||||||||
| HIGHLIGHTS |
2023 | 2022 | CHANGE | |||||||||||||
| Production volume (million lbs) |
5.7 | 3.7 | 54 | % | ||||||||||||
|
|
|
|
|
|
|
|||||||||||
| Sales volume (million lbs) |
9.8 | 6.9 | 42 | % | ||||||||||||
|
|
|
|
|
|
|
|||||||||||
| Average spot price |
($US/lb | ) | 82.21 | 49.94 | 65 | % | ||||||||||
| Average long-term price |
($US/lb | ) | 66.00 | 51.67 | 28 | % | ||||||||||
| Average realized price |
($US/lb | ) | 52.35 | 43.05 | 22 | % | ||||||||||
| ($Cdn/lb | ) | 71.65 | 57.87 | 24 | % | |||||||||||
|
|
|
|
|
|
|
|||||||||||
| Average unit cost of sales (including D&A) |
($Cdn/lb | ) | 61.90 | 54.37 | 14 | % | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Revenue ($ millions) |
700 | 397 | 76 | % | ||||||||||||
|
|
|
|
|
|
|
|||||||||||
| Gross profit ($ millions) |
96 | 24 | >100 | % | ||||||||||||
|
|
|
|
|
|
|
|||||||||||
| Gross profit (%) |
14 | 6 | >100 | % | ||||||||||||
|
|
|
|
|
|
|
|||||||||||
Production volumes this quarter increased by 54% compared to the fourth quarter of 2022. See Uranium – production overview on page 72 for more information.
Uranium revenues were up 76% due to a 42% increase in sales volume due to the timing of sales, which were in line with the delivery pattern disclosed in our 2022 annual MD&A, and a 24% increase in the Canadian dollar average realized price. While the average US dollar spot price for uranium increased by 65% compared to the same period in 2022, the Canadian dollar average realized price increased by 24% due to the timing of market changes on our contract portfolio. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 53.
Total cost of sales (including D&A) increased by 62% ($605 million compared to $373 million in 2022). This was primarily the result of the 42% increase in sales volume as well as an increase of 14% in the average unit cost of sales which was due to the higher cost of purchased material.
The net effect was a $72 million increase in gross profit for the quarter.
The following table shows the costs of produced and purchased uranium incurred in the reporting periods (see Non-IFRS measures starting on page 41). These costs do not include care and maintenance costs, operational readiness costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
| THREE MONTHS ENDED | ||||||||||||
| DECEMBER 31 | ||||||||||||
| ($/LB) |
2023 | 2022 | CHANGE | |||||||||
| Produced |
||||||||||||
| Cash cost |
21.07 | 19.50 | 8 | % | ||||||||
| Non-cash cost |
10.95 | 13.76 | (20 | )% | ||||||||
|
|
|
|
|
|
|
|||||||
| Total production cost 1 |
32.02 | 33.26 | (4 | )% | ||||||||
|
|
|
|
|
|
|
|||||||
| Quantity produced (million lbs)1 |
5.7 | 3.7 | 54 | % | ||||||||
|
|
|
|
|
|
|
|||||||
| Purchased |
||||||||||||
| Cash cost1 |
89.89 | 57.02 | 58 | % | ||||||||
|
|
|
|
|
|
|
|||||||
| Quantity purchased (million lbs)1 |
6.3 | 5.8 | 9 | % | ||||||||
|
|
|
|
|
|
|
|||||||
| Totals |
||||||||||||
| Produced and purchased costs |
62.40 | 47.77 | 31 | % | ||||||||
|
|
|
|
|
|
|
|||||||
| Quantities produced and purchased (million lbs) |
12.0 | 9.5 | 26 | % | ||||||||
|
|
|
|
|
|
|
|||||||
| 1 | Due to equity accounting for JV Inkai, our share of production will be shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. During the quarter we purchased 2.8 million pounds at a purchase price per pound of $105.74 ($77.13 (US)) (Q4 2022 – 2.6 million pounds at a purchase price per pound of $61.27 ($45.60 (US))). |
MANAGEMENT’S DISCUSSION AND ANALYSIS 67
The average cash cost of production for the fourth quarter was 8% 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.
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 $89.89 (Cdn) per pound, or $65.67 (US) per pound in US dollar terms, compared to $57.02 (Cdn) per pound, or $42.18 (US) per pound in the fourth quarter of 2022.
Fuel services
(includes results for UF6, UO2, UO3 and fuel fabrication)
| THREE MONTHS ENDED | ||||||||||||||||
| DECEMBER 31 | ||||||||||||||||
| HIGHLIGHTS |
2023 | 2022 | CHANGE | |||||||||||||
| Production volume (million kgU) |
3.7 | 3.7 | — | |||||||||||||
| Sales volume (million kgU) |
4.2 | 3.8 | 11 | % | ||||||||||||
| Average realized price |
($ | Cdn/kgU | ) | 32.19 | 30.11 | 7 | % | |||||||||
| Average unit cost of sales (including D&A) |
($ | Cdn/kgU | ) | 22.69 | 19.33 | 17 | % | |||||||||
| Revenue ($ millions) |
134 | 115 | 17 | % | ||||||||||||
| Gross profit ($ millions) |
40 | 41 | (2 | )% | ||||||||||||
| Gross profit (%) |
30 | 36 | (17 | )% | ||||||||||||
Total revenue increased by 17% due to an 11% increase in sales volumes and a 7% increase in average realized price. The increase in average realized price was mainly the result of increased prices for UF6 due to market conditions.
Total cost of sales (including D&A) increased by 28% to $95 million compared to the fourth quarter of 2022 due to the 11% increase in sales volumes and an increase of 17% in the average unit cost of sales. Unit cost of sales increased mainly as a result of higher input costs.
The net effect was a $1 million decrease in gross profit.
68 CAMECO CORPORATION
Operations, projects and 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, our advanced uranium projects and our exploration activities, what we accomplished this year, our plans for the future and how we manage risk. It also includes an overview of our investments in Westinghouse and GLE.
| 70 |
MANAGING THE RISKS |
|
| 72 |
URANIUM – PRODUCTION OVERVIEW |
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| 72 |
PRODUCTION OUTLOOK |
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| 73 |
URANIUM – TIER-ONE OPERATIONS |
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| 73 |
MCARTHUR RIVER MINE / KEY LAKE MILL |
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| 77 |
CIGAR LAKE |
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| 81 |
INKAI |
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| 85 |
URANIUM – TIER-TWO OPERATIONS |
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| 85 |
RABBIT LAKE |
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| 86 |
US ISR |
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| 87 |
URANIUM – ADVANCED PROJECTS |
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| 87 |
MILLENNIUM |
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| 87 |
YEELIRRIE |
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| 87 |
KINTYRE |
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| 89 |
URANIUM – EXPLORATION |
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| 91 |
FUEL SERVICES |
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| 91 |
BLIND RIVER REFINERY |
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| 92 |
PORT HOPE CONVERSION SERVICES |
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| 92 |
CAMECO FUEL MANUFACTURING INC. (CFM) |
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| 94 |
WESTINGHOUSE ELECTRIC COMPANY |
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| 99 |
OTHER NUCLEAR FUEL CYCLE INVESTMENTS |
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| 99 |
GLOBAL LASER ENRICHMENT (GLE) |
|
MANAGEMENT’S DISCUSSION AND ANALYSIS 69
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, Westinghouse or other fuel cycle investments. Our uranium and fuel services and Westinghouse 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 |
| • | industrial safety accidents |
| • | transportation incidents, which may involve radioactive or other hazardous materials |
| • | labour shortages, disputes or strikes |
| • | availability of personnel with the necessary skills and experience |
| • | 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, processing facilities, to develop new mines, or for Westinghouse to operate its fuel fabrication or other facilities or undertake its other commercial activities |
| • | increased workforce health and safety risks or increased regulatory burdens resulting from a 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 communicable illness (such as a pandemic) |
| • | unusual, unexpected or adverse mining or geological conditions |
| • | underground water inflows at our mining operations |
| • | ground movement or cave-ins at our mining operations |
Risks and hazards generally applicable to Westinghouse and our ownership interest in Westinghouse include:
| • | failure to realize any or all of the anticipated benefits from the acquisition |
| • | Westinghouse’s failure to generate sufficient cash flow to fund its approved annual operating budget or make quarterly distributions to us and Brookfield |
| • | Westinghouse’s failure to comply with nuclear licence and quality assurance requirements at its facilities |
| • | Westinghouse’s loss of protections against liability for nuclear damage, including discontinuation of global nuclear liability regimes and indemnities |
| • | adverse public perception of nuclear energy |
70 CAMECO CORPORATION
| • | adverse public reaction to an unforeseen nuclear incident resulting in a lessening of demand for nuclear generators |
| • | threat of increased trade barriers adversely impacting Westinghouse’s business |
| • | our inability to control Westinghouse |
| • | liabilities at Westinghouse exceeding our estimates and the discovery of unknown or undisclosed liabilities |
| • | default by Westinghouse under its credit facilities impacting adversely Westinghouse’s ability to fund its ongoing operations |
| • | occupational health and safety issues arising at Westinghouse’s operations |
| • | disputes between us and Brookfield regarding our strategic partnership |
| • | Cameco defaulting under the governance agreement with Brookfield, including us losing some or all of our interest in Westinghouse |
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.
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, Westinghouse, and GLE 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 most recent annual information form, which includes a discussion of other material risks that could have an impact on our business.
MANAGEMENT’S DISCUSSION AND ANALYSIS 71
Uranium – production overview
Our share of production in our uranium segment in the fourth quarter was 5.7 million pounds, 54% higher compared to the same period in 2022, while production for the year was 17.6 million pounds, 69% higher than in 2022. In 2022, there was no production from McArthur River and Key Lake until the fourth quarter. Total production in 2023 was 1.1 million pounds below the revised production plan we announced in September.
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 73 and Uranium – Tier-two operations beginning on page 85 for more information.
Uranium production
| CAMECO SHARE | THREE MONTHS ENDED DECEMBER 31 |
YEAR ENDED DECEMBER 31 |
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| (MILLION LBS) |
2023 | 2022 | 2023 | 2022 | 2023 PLAN1 | 2024 PLAN | ||||||||||||||||||
| Cigar Lake |
2.6 | 2.9 | 8.2 | 9.6 | 8.9 | 9.8 | ||||||||||||||||||
| McArthur River/Key Lake |
3.1 | 0.8 | 9.4 | 0.8 | up to 9.8 | 12.6 | ||||||||||||||||||
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| Total |
5.7 | 3.7 | 17.6 | 10.4 | up to 18.7 | 22.4 | ||||||||||||||||||
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| 1 | During the third quarter, we updated our Cigar Lake production forecast to up to 16.3 million pounds (100% basis) in 2023 (previously 18 million pounds). |
| 2 | During the third quarter, we updated our McArthur River/Key Lake production forecast to 14 million pounds (100% basis) in 2023 (previously 15 million pounds). |
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 in order to increase long-term value, and to do that with an emphasis on safety, people and the environment.
In 2024, we are planning production of 22.4 million pounds (our share).
Due to equity accounting, our share of production from Inkai is shown as a purchase. Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain 20% below the level stipulated in subsoil use agreements, similar to in 2023, primarily due to the sulfuric acid shortage in the country. We are still in discussions with JV Inkai and KAP to determine how this may impact production at Inkai in 2024 and thereafter and therefore our corresponding purchase obligation. We expect to purchase the remaining share of our 2023 production entitlement, which has arrived at a Canadian port.
72 CAMECO CORPORATION
Uranium – Tier-one operations
McArthur River mine / Key Lake mill
|
2023 Production (our share) | |
| 9.4M lbs | ||
| 2024 Production Outlook (our share) | ||
| 12.6M lbs | ||
| Estimated Reserves (our share) | ||
| 265.6M 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+ (www.sedarplus.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 | 265.6 million pounds (proven and probable), average grade U3O8: 6.72% | |||
| Estimated resources | 4.9 million pounds (measured and indicated), average grade U3O8: 2.28% | |||
| 1.7 million pounds (inferred), average grade U3O8: 2.90% | ||||
| Licensed capacity | Mine and mill: 25.0 million pounds per year | |||
| Licence term | Through October 2043 | |||
| Total packaged production: | 2000 to 2023 | 340.0 million pounds (McArthur River/Key Lake) (100% basis) | ||
| 1983 to 2002 | 209.8 million pounds (Key Lake) (100% basis) | |||
| 2023 production | 9.4 million pounds (13.5 million pounds on 100% basis) | |||
| 2024 production outlook | 12.6 million pounds (18.0 million pounds on 100% basis) | |||
| Estimated decommissioning cost | $50.6 million – McArthur River (100% basis) | |||
| $276.7 million – Key Lake (100% basis) | ||||
All values shown, including reserves and resources, represent our share only, unless indicated.
MANAGEMENT’S DISCUSSION AND ANALYSIS 73
BACKGROUND
Mine description
The mineral reserves at McArthur River are contained within seven zones: zones 1, 2, 3, 4, 4 South, A and B. There are currently two active mining zones (zone 2 and 4), one with development significantly advanced (zone 1), and one in the early stages of development (zone 4 South).
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 3.5 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 103.9 million pounds of mineral reserves secured behind freeze walls, and it will be the main source of production for the next several years. Raisebore and blasthole stope mining will be used to recover the mineral reserves.
Zone 1 is the next planned mine area to be brought into production. Freeze hole drilling was completed in 2023 and brine distribution construction work has resumed. A small section of the planned freeze wall is currently actively freezing. Once brine distribution construction is complete and an active freeze wall has been established, drill and extraction chamber development will need to be completed prior to the start of production. 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 in zone 1.
Zone 4 South is in the early development stages. Access development for the freeze drifts has resumed on the lower levels and freeze drilling began at the end of 2023 on the upper freeze drifts which were established prior to the 2018 shutdown.
We have successfully extracted over 340 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 freeze holes to form an impermeable frozen barrier.
Blasthole stope mining
Blasthole stope mining began in 2011 and is the main extraction method planned for future production. 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.
74 CAMECO CORPORATION
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.
2023 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. The operation began transitioning back to production through the first three quarters of 2022, with no packaged pounds until the fourth quarter of 2022. Production ramp-up activities continued in 2023.
Total packaged production from McArthur River and Key Lake in 2023 was 13.5 million pounds (9.4 million pounds our share), slightly less than the announced September 3, 2023, forecast of 14 million pounds (9.8 million pounds our share).
The McArthur River mine continued to operate well and achieved its planned mine production for the year. Any ore from McArthur River that was not immediately processed at Key Lake is stored in inventory for future milling. All required mine activities have now resumed at McArthur and the site is now considered to be back in normal mine operations.
At the Key Lake mill, the extended period of time the mill was on care and maintenance, the operational changes made, aging infrastructure, the availability of personnel with the necessary skills and experience, and the impact of supply chain challenges on the availability of materials and reagents combined to impact production in 2023.
Licensing
In October 2023, the Canadian Nuclear Safety Commission (CNSC) granted 20-year renewals to the licences for both McArthur River and Key Lake. The renewed licences are expected to allow McArthur River and Key Lake to operate until October 2043.
Exploration
Underground exploration at McArthur River resumed in June 2023 with the resumption of infill drilling of zone B. Infill drilling of zone B will continue in 2024.
PLANNING FOR THE FUTURE
Production
We plan to produce 18 million pounds (100% basis) in 2024. Over the last three months, the mill has been running at a rate that, when annualized, would allow this operation to achieve its 2024 planned production. In 2024, we plan to undertake an evaluation of the work and investment necessary to expand production up to its annual licensed capacity, which we expect will allow us to take advantage of this opportunity when the time is right. We will continue to plan our production to align with our contract portfolio and market opportunities, demonstrating that we continue to be a responsible supplier of uranium fuel.
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.
MANAGEMENT’S DISCUSSION AND ANALYSIS 75
In addition to the risks listed on pages 70 to 71, in 2024 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, aging infrastructure, and commissioning issues that we have worked through at the mill, which caused delays to the production schedule in 2022 and 2023, there is continued uncertainty regarding the timing of a successful ramp up to planned 2024 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, and we are in negotiations to reach a new agreement. As in the past, work continues under the terms of the expired collective agreement while negotiations proceed. There is a risk to the production plan if we are unable to reach an agreement and there is a labour disruption.
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 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.
76 CAMECO CORPORATION
Uranium – Tier-one operations
Cigar Lake
|
2023 Production (our share)
|
|
| 8.2M lbs | ||
| 2024 Production Outlook (our share) | ||
| 9.8M lbs | ||
| Estimated Reserves (our share) | ||
| 113.8M lbs | ||
| Estimated Mine Life | ||
| 2036 |
Cigar Lake is the world’s highest grade uranium mine. 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+ (www.sedarplus.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 | 113.8 million pounds (proven and probable), average grade U3O8: 17.03% | |
| Estimated resources | 14.7 million pounds (measured and indicated), average grade U3O8: 5.32% | |
|
10.9 million pounds (inferred), average grade U3O8: 5.55% |
||
| 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 2023 | 138.4 million pounds (100% basis) | |
| 2023 production | 8.2 million pounds (15.1 million pounds on 100% basis) | |
| 2024 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.
BACKGROUND
Mine description
Cigar Lake’s geological setting is similar to McArthur River’s. However, unlike McArthur River, the Cigar Lake deposit is horizontally oriented.
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. We use a jet boring system to mine the ore.
MANAGEMENT’S DISCUSSION AND ANALYSIS 77
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 the frozen ore |
| • | collecting the ore and water mixture (slurry) from the cavity and pumping it to a storage sump, allowing it to settle |
| • | using a clamshell, transporting the ore from the storage sump to an underground grinding and processing circuit |
| • | 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 138.4 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 blended and thickened to remove excess water |
| • | the final slurry, at an average grade of approximately 17% U3O8, is pumped into transport truck containers and shipped to McClean Lake mill on a 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.
2023 UPDATE
Production
Total packaged production from Cigar Lake in 2023 was 15.1 million pounds U3O8 (8.2 million pounds our share) compared to 18.0 million pounds U3O8 (9.8 million pounds our share) in 2022.
Productivity was impacted as we completed development and commissioning activities in the first quarter and achieved first production from a new mining area. We had expected to recover from these delays in the second half of the year. However, in the third quarter, we determined maintenance work was required on one of the underground circuits, which had not been planned. The additional time required to complete this work did not allow for the delayed production volumes to be recovered prior to year-end.
During the year, we:
| • | executed planned 21-day annual maintenance activities in September |
| • | executed production activities from four production tunnels in the eastern part of the orebody and one, for the first time, from the western part of the orebody |
78 CAMECO CORPORATION
| • | in alignment with our long-term production planning, brought two new panels online |
| • | continued underground header construction activities and expanded our ground freezing program to ensure continued frozen ore inventory |
| • | completed our freeze hole drilling program in the second quarter |
Underground development
Underground mine development continued in 2023. We completed our second production crosscut in the western portion of the orebody in preparation for ore mining starting in the second quarter of 2024.
PLANNING FOR THE FUTURE
Production
In 2024, we expect to produce 18 million pounds (100% basis) at Cigar Lake; our share is approximately 9.8 million pounds.
In 2024, we plan to:
| • | continue production activities focused on bringing one new production panel online |
| • | complete construction and commissioning of freeze distribution infrastructure expansion in support of future production |
| • | continue underground mine development on two new production tunnels as well as expand ventilation and access drifts in alignment with the long-term mine plan |
| • | commission the surface backfill batch plant to support ongoing operations |
| • | execute an underground geotechnical drilling program |
CIGAR LAKE EXTENSION
Completion of a prefeasibility study of the indicated resources contained in the Cigar Lake extension orebody (referred to as Phase 2 in the technical report filed in 2016), demonstrated the economic feasibility of extracting those resources, allowing us to convert 73.4 million pounds (100% basis) (40 million pounds our share), to probable reserves and extending the estimated mine life to 2036. Based on our analyses, we expect our share of the up-front capital cost to complete the mine development and other capacity replacement projects necessary to access these reserves to be between $250 million and $300 million. We expect the average life of mine unit cash operating costs for Cigar Lake production to increase to between $19 per pound and $20 per pound (previously $18.13 per pound) and our share of annual production to be between 9.5 million pounds and 10.0 million pounds.
A new NI 43-101 technical report for Cigar Lake is in the process of being finalized and is expected to be filed under Cameco’s profile on SEDAR+ within 45 days of this release. More detailed descriptions of the scientific and technical information on which the mineral reserves and mine plan are based will be included in the relevant sections of the technical report. Once filed, the new technical report will supersede and replace the current technical report titled “Cigar Lake Operation, Northern Saskatchewan, Canada” dated March 29, 2016, with an effective date of December 31, 2015. A copy is available on SEDAR+ (www.sedarplus.com), on EDGAR (www.sec.gov/edgar.shtml), and on Cameco’s website (www.cameco.com/media/media-library).
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 70 to 71, 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 2024 and future years.
MANAGEMENT’S DISCUSSION AND ANALYSIS 79
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, and deployment of the jet boring method in new areas. If development or infrastructure construction work is delayed for any reason, including availability of storage capacity for waste rock, or if the performance of our jet boring method is materially different than previously mined areas, 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.
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.
80 CAMECO CORPORATION
Uranium – Tier-one operations
Inkai
|
2023 Production (100% basis) | |
| 8.3M lbs | ||
| 2024 Production Outlook (100% basis) | ||
| See Planning for the future – Production on page 83 | ||
| Estimated Reserves (our share) | ||
| 104.7M 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 (KAP) (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+ (www.sedarplus.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 | 104.7 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 2023 | 89.3 million pounds (100% basis) | |
| 2023 production | 8.3 million pounds (100% basis)1 | |
| 2024 production outlook | See Planning for the future – Production on page 831 | |
| 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 of production is shown as a purchase. |
MANAGEMENT’S DISCUSSION AND ANALYSIS 81
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 the host formation |
| • | recover it from solution with ion exchange resin (takes place at both main and satellite processing plants) |
| • | precipitate the uranium with hydrogen peroxide |
| • | thicken, dewater, and dry it |
| • | package the uranium peroxide product in drums |
Production
Through our investment in Inkai, production continued to be impacted by the 20% supply reduction enacted by KAP across all uranium mines in Kazakhstan and the continued supply chain challenges it has faced. KAP has the ability to flex production 20% above or below planned production levels (8.3 million to 12.5 million pounds per year). Total 2023 production from Inkai was 8.3 million pounds (100% basis), the same as in 2022. In 2023, Inkai experienced a number of operational issues related to interruptions in reagent delivery and wellfield drilling.
The first shipment, containing approximately two thirds of our share of Inkai’s 2023 production, arrived in the fourth quarter. The second shipment with the remainder of our share of 2023 production has arrived at a Canadian port. We continue to work closely with JV Inkai and our joint venture partner, KAP, to receive our share of production via the Trans-Caspian International Transport Route, which does not rely on Russian rail lines or ports.
Production purchase entitlements
Under the terms of a restructuring agreement signed with our partner KAP in 2016, our ownership interest in JV Inkai is 40% and KAP’s share is 60%. However, during production 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 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 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.
Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement, for 2023 we were entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s planned 2023 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 2023, timing was impacted by shipping delays. Total purchases in 2023 were 4.2 million pounds, of which 2.8 million pounds were related to our 2023 entitlement.
Cash distribution
Excess cash, net of working capital requirements, will be distributed to the partners as dividends. In 2023, we received a cash dividend from JV Inkai of $79 million (US), net of withholdings. Our share of dividends follows our production purchase entitlements as described above.
82 CAMECO CORPORATION
JV INKAI NON-IFRS MEASURE
EBITDA is a supplemental measure which is used by us and other users to assess results of operations for JV Inkai from a management perspective without regard to its capital structure. We believe that this measure is useful to management, lenders, investors, security analysts and other interested parties in assessing the underlying performance of JV Inkai’s ongoing operations and its ability to generate cash flows to fund its cash requirements. See Non-IFRS Measures starting on page 41.
| CAMECO SHARE | ||||||||||||
| ($ MILLIONS) |
2023 | 2022 | CHANGE | |||||||||
| Share of earnings from equity-investee |
179 | 94 | 90 | % | ||||||||
| Depreciation and amortization |
14 | 10 | 40 | % | ||||||||
| Finance costs |
— | 1 | (100 | )% | ||||||||
| Income tax expense (recovery) |
42 | 30 | 40 | % | ||||||||
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| EBITDA |
235 | 135 | 74 | % | ||||||||
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PLANNING FOR THE FUTURE
Production
Based on KAP’s announcement on February 1, 2024, production in Kazakhstan is expected to remain 20% below the level stipulated in subsoil use agreements, similar to in 2023, primarily due to the sulfuric acid shortage in the country. We are still in discussions with JV Inkai and KAP to determine how this may impact production at Inkai in 2024 and thereafter and therefore our corresponding purchase obligation.
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.
MANAGING OUR RISKS
In addition to the risks listed on pages 70 to 71, JV Inkai also manages the following risks:
Production forecast
Presently, JV Inkai is experiencing procurement and supply chain issues, most notably, related to the availability of sulfuric acid. It is also experiencing challenges related to construction delays and inflationary pressures on its production costs. Production plans for 2024 and subsequent years are uncertain and being reassessed. A significant disruption to JV Inkai’s previous production plans for 2024 and subsequent years could result in penalties and further escalation of production costs. 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.
Depending on production levels at Inkai and the outcome of our discussions related thereto with JV Inkai and KAP, our share of production and earnings from this equity-accounted investee and the amount and timing of our dividends from the joint venture may be impacted.
Transportation
The geopolitical situation continues to cause transportation risks in the region. We could continue to experience delays in our expected Inkai deliveries from 2023 and for 2024. 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS 83
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.
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 70 to 71.
84 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 2038 | |
| Total production: 1975 to 2023 | 202.2 million pounds | |
| 2023 production | 0 million pounds | |
| 2024 production outlook | 0 million pounds | |
| Estimated decommissioning cost | $213 million | |
OPERATING STATUS
The site remained in a safe state of care and maintenance throughout 2023.
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 $28 million and $32 million annually.
Licensing
In October 2023, the CNSC granted a 15-year renewal of the operating licence for Rabbit Lake, extending the licence term to October 2038.
FUTURE PRODUCTION
We do not expect any production from Rabbit Lake in 2024.
MANAGING OUR RISKS
We manage the risks listed on pages 70 to 71.
MANAGEMENT’S DISCUSSION AND ANALYSIS 85
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, respectively. 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 2023 | 33.0 million pounds | |||
| 2023 production | 0 million pounds | |||
| 2024 production outlook | 0 million pounds | |||
| Estimated decommissioning cost | Smith Ranch-Highland: $239 million (US), including North Butte | |||
| Crow Butte: $62 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 $12.5 million (US) and $14.5 million (US) for 2024.
FUTURE PRODUCTION
We do not expect any production in 2024.
MANAGING OUR RISKS
The current operating licence for Crow Butte expires in October 2024. Efforts are underway for re-licensing with the Nuclear Regulatory Commission.
We also manage the risks listed on pages 70 to 71.
86 CAMECO CORPORATION
Uranium – advanced projects
Our advanced projects are part of our project pipeline and these resources are supportive of growth beyond our existing suite of tier-one and tier-two assets. We plan to advance them at a pace aligned with market opportunities.
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 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%
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.
2023 PROJECT UPDATES
We believe that we have some of the best undeveloped uranium projects in the world. However, our primary focus is on producing from our tier-one uranium assets at a pace aligned with our contract portfolio and market opportunities.
PLANNING FOR THE FUTURE
2024 Planned activity
No work is planned at Millennium, Yeelirrie or Kintyre in 2024.
MANAGEMENT’S DISCUSSION AND ANALYSIS 87
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 70 to 71.
88 CAMECO CORPORATION
Uranium – exploration
Our exploration program is focused on replacing mineral reserves as they are depleted by our production, which is key to sustaining our business, meeting our commitments, and ensuring long-term growth. Our global exploration activity is adjusted annually in line with market signals and at a pace aligned with Cameco’s mining plans and sourcing needs. In recent years, we have increased exploration spending in response to the significant, positive momentum in the nuclear fuel market that has provided a clear signal that more uranium production will be required in the next decade, setting the stage for a renewed exploration cycle.
Our position as one of the world’s largest uranium producers and our continued growth across the nuclear fuel cycle has been driven by decades of experience and our history of exploration, discovery and mining success. Our land position totals 740,000 hectares (1.8 million acres) that cover exploration and development prospects in Canada, Australia, Kazakhstan and the US that are among the best in the world. In northern Saskatchewan alone, we have direct interests in 650,000 hectares (1.6 million acres) that cover many of the most prospective areas of the prolific Athabasca Basin.
In northern Saskatchewan, our well-established infrastructure includes fully licensed and fully permitted uranium mills and mines in the eastern Athabasca basin, along with a supporting network of roads, airstrips and electricity supply. That infrastructure provides us with an advantage that not only underpins the potential development of our advanced exploration projects, but also supports our ongoing work to both delineate existing prospects and deposits, and to identify future undiscovered uranium potential of the region. Additionally, our decades of work to establish a positive corporate reputation by prioritizing our relationships with northern Saskatchewan Indigenous communities, confirms our long-term commitment to continually engage and provide ongoing benefits to the people that call the region home.
The uranium endowment of the Athabasca Basin, where we are involved in 39 projects (including partner-operated joint ventures), is well known and combined with the basin’s unique geological history, it creates a remarkable mining jurisdiction hosting the highest uranium grades and some of the largest uranium deposits in the world. On our projects, we have identified numerous uranium occurrences, prospects, and undeveloped deposits of variable grades and sizes that have progressed through multiple stages of evaluation. Depending on the potential deposit size, ore and ground quality, evolving mining technologies and the uranium market environment, some of these prospects are expected to become viable, economic deposits in a uranium market and price environment that supports new primary production and provides an adequate risk-adjusted return.
MANAGEMENT’S DISCUSSION AND ANALYSIS 89
The combination of our large land position and proven expertise in discovering and developing world class uranium mines provides the foundation for future mill-supported exploration projects, ranging from early to advanced stages of greenfield exploration and for brownfield opportunities to extend the lives of our existing operations.
2023 UPDATE
Brownfield and advanced exploration
Brownfield and advanced exploration activities include exploration near our existing operations and expenses for maintaining advanced projects and delineation drilling where uranium mineralization is being defined. In 2023, we spent about $4.5 million in Saskatchewan, $1 million in Australia and $1 million in the US on brownfields and advanced exploration projects. The spending in Saskatchewan was primarily focused on advancing the extension of the mine life at Cigar Lake and advanced exploration on the Dawn Lake project.
The Dawn Lake project is located approximately 45 km northwest of the Rabbit Lake operation, on the La Rocque Lake corridor which hosts several historic discoveries and deposits. In 2023, exploration drilling at Dawn Lake expanded the footprint of known uranium mineralization with mineralized intercepts in excess of 60% U3O8 over several metres. Although the deposit remains at a very early stage of exploration, the high-grade results and geological conditions observed to date are comparable to those of other mines and known deposits in the Athabasca Basin, generating interest and a focused effort to better understand its potential.
Regional exploration
Regional exploration is defined as projects that are considered greenfield. In 2023, we spent about $11 million on regional exploration programs that are comprised of target generation geophysical surveys and diamond drilling primarily in northern Saskatchewan.
PLANNING FOR THE FUTURE
We plan to continue to focus on our core projects in Saskatchewan under our long-term exploration framework. Our leadership position and industry expertise in both exploration and corporate social responsibility makes us a partner of choice and for properties and projects that meet our investment criteria, we may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements to optimize our exploration activity and spending.
Brownfields and Advanced Exploration
In 2024, we plan to spend about $7 million on brownfields and advanced Exploration, primarily to expand the footprint of the mineralization identified on in the La Rocque Lake corridor of the Dawn Lake project.
Regional Exploration
We plan to spend about $13 million on diamond drilling and target generation geophysical surveys on our core regional projects in Saskatchewan, in 2024.
90 CAMECO CORPORATION
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
24.0M kgU as UO3
Licence renewal in
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 conditions) | |
| Licence term | Through February 2032 | |
| Estimated decommissioning cost | $58 million | |
MANAGEMENT’S DISCUSSION AND ANALYSIS 91
Port Hope Conversion Services
|
Licensed Capacity
12.5M kgU as UF6
2.8M kgU as UO2
Licence renewal in
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
1.65M kgU as UO2 fuel pellets
Licence renewal in
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 | |
92 CAMECO CORPORATION
2023 UPDATE
Production
Fuel services produced 13.3 million kgU in 2023, 2% higher than 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. Good progress was made over the past year with the removal of old buildings and structures on site, and the project will continue to be active in the year ahead.
PLANNING FOR THE FUTURE
Production
We plan to produce between 13.5 million and 14.5 million kgU in 2024. This includes increasing annual production at our Port Hope UF6 conversion facility to 12,000 tonnes to satisfy our book of long-term business and demand for conversion services.
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 70 to 71, in 2024 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 2024 and future years.
Labour relations
The collective agreement with unionized employees at our fuel manufacturing operations in Port Hope and Cobourg expires in June 2024. During past negotiations, work has continued 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS 93
Westinghouse Electric Company
Westinghouse is a nuclear reactor technology original equipment manufacturer (OEM) and a leading provider of highly technical aftermarket products and services to commercial nuclear power utilities and government agencies globally. Westinghouse’s history in the energy industry stretches back over a century, during which time the company became a pioneer in nuclear energy.
| • | It is the OEM or a technology provider to about 50% of the global nuclear reactor fleet, delivering capacity of about 190,000 carbon-free MWe. |
| • | It has three fuel fabrication facilities, one in the US, one in Sweden and one in the United Kingdom. |
| • | In addition, it has about 90 facilities, engineering centers, and workshops, with a presence in more than 20 countries. |
The company has strong recurring and predictable revenue and cash flow profiles due to the critical and non-discretionary nature of its products and services to the operation of nuclear power plants around the world.
Like Cameco, Westinghouse enables carbon-free baseload and dispatchable energy that is needed to support the energy transition and we believe is therefore well-positioned for long-term growth.
| Corporate headquarters | Cranberry Township, Pennsylvania (United States) | |
| Ownership | 49% - equity-accounted | |
| Business activities | Operations and maintenance of installed base (core business): Designs and manufactures nuclear fuel supplies and services for light water reactors. Provides outage and maintenance services, engineering support, instrumentation and controls equipment, plant modifications, and components and parts to nuclear reactors. | |
| New build: Designs, develops and procures equipment for new nuclear plants. | ||
| Certifications | ISO 14001 | |
| ISO 45001 | ||
BACKGROUND
On November 7, 2023, we announced the closing of the acquisition of Westinghouse in partnership with Brookfield. Brookfield beneficially owns a 51% interest in Westinghouse, and we beneficially own 49%. Bringing together Cameco’s expertise in the nuclear industry with Brookfield’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.
The total enterprise value at time of close was $7.9 billion (US) and was adjusted for working capital balances at that time, resulting in a final enterprise value of $8.2 billion (US). At time of close, Westinghouse had $3.8 billion (US) in outstanding debt commitments, for which it maintains responsibility, and which reduced the equity cost of the acquisition.
To finance Cameco’s 49% share of the purchase price, equaling $2.1 billion (US), we used $1.5 billion (US) of cash and drew the full amount of both $300 million (US) tranches of the term loan put in place concurrently with the execution of the acquisition agreement, and which mature two years and three years from the date of close. The $280 million (US) bridge commitment that we also secured concurrently with the acquisition agreement was not required to complete the transaction and was terminated.
The acquisition of Westinghouse was completed in the form of a limited partnership with Brookfield. The board of directors governing the limited partnership consists of six directors, three appointed by Cameco and three appointed by Brookfield. Decision-making by the board corresponds to percentage ownership interests in the limited partnership (51% Brookfield and 49% Cameco). However, decisions with respect to certain reserved matters under the partnership agreement, such as the approval of the annual budget, require the presence and support of both Cameco and Brookfield appointees to the board as long as certain ownership thresholds are met.
We believe Westinghouse is well-positioned for long-term growth driven by the expected increase in global demand for nuclear power. As of November 7, 2023, we receive the economic benefit of our ownership in Westinghouse. We account for our proportionate interest in Westinghouse on an equity basis.
94 CAMECO CORPORATION
We expect this strategic acquisition will be transformative and accretive to Cameco. We are enhancing our ability to compete for more business by investing in additional nuclear fuel cycle assets that we expect will augment the core of our business and offer more solutions to our customers across the nuclear fuel cycle. Like Cameco, Westinghouse has nuclear assets that are strategic, proven, licensed and permitted, and that are in geopolitically attractive jurisdictions. We expect these assets, like ours, will participate in the growing demand profile for nuclear energy.
Cash distributions
Annually, we and Brookfield (the partners) approve a budget and business plan which outline Westinghouse’s financial projections and capital allocation priorities. The determination of whether to make cash distributions to the partners will be reviewed quarterly based on the approved budgeted expenditures and capital allocation priorities, including growth investment opportunities, as well as available cash balances. However, the timing of cash distributions is expected to be aligned with the timing of Westinghouse’s cash flows, which are typically higher in the fourth quarter.
Westinghouse debt
As at December 31, 2023, Westinghouse had the following outstanding debt:
| • | $3.5 billion (US) term loan with a maturity of August 2025 |
| • | credit facilities of $400 million (US), which had drawings of $115 million (US) and mature in June 2026 |
| • | drawn financial assurances including letters of credit of $474 million (US) and surety bonds of $262 million (US) |
Effective January 25, 2024, Westinghouse refinanced its existing debt and entered into various credit agreements which now provide total borrowing capacity of $4.6 billion (US), comprised of:
| • | $3.5 billion (US) term loan which now matures on January 25, 2031, and has quarterly repayments of $8.75 million (US), with any remaining amounts due at maturity. The term loan is priced at the applicable term SOFR rate plus a margin that is currently 2.75%. |
| • | credit facilities totaling $500 million (US), which mature in January 2029 |
| • | financial assurances including letters of credit in the amount of about $570 million (US) and surety bonds of $262 million (US) |
The credit agreements are non-recourse to Cameco, but come with certain covenants, which if breached, could result in all amounts outstanding thereunder to be immediately due and payable by Westinghouse. We expect Westinghouse to continue to comply with these covenants in 2024.
WESTINGHOUSE NON-IFRS MEASURES
EBITDA, adjusted EBITDA and adjusted free cash flow and adjusted EBITDA margin are supplemental measures which are used by us and other users, including our lenders and investors, to assess the results of operations for Westinghouse from a management perspective without regard to its capital structure. We believe that these measures are useful to management, lenders and investors in assessing the underlying performance of Westinghouse’s ongoing operations and its ability to generate cash flows to fund its cash requirements. See Non-IFRS measures starting on page 41.
The financial information in the table below is provided to allow comparison to, and is in line with the outlook provided in our November 7, 2023, news release. It is derived from the consolidated financial statements of Westinghouse, which are reported in US dollars and prepared in accordance with US GAAP, and does not reflect Cameco’s ownership share.
MANAGEMENT’S DISCUSSION AND ANALYSIS 95
| ($US MILLIONS – US GAAP) |
2023 | 2022 | ||||||
| Net earnings (loss) |
(155 | ) | 440 | |||||
| Depreciation and amortization |
348 | 371 | ||||||
| Finance income |
(11 | ) | (2 | ) | ||||
| Finance costs |
296 | 202 | ||||||
| Income tax expense (recovery) |
4 | (392 | ) | |||||
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| EBITDA |
482 | 619 | ||||||
| Other expenses (income) |
22 | (5 | ) | |||||
| (Gain) loss on disposal of fixed assets |
6 | (4 | ) | |||||
| Purchase accounting unwind |
40 | — | ||||||
| Restructuring and acquisition-related costs |
159 | 92 | ||||||
| Gain on disposition of businesses |
(14 | ) | — | |||||
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| Adjusted EBITDA |
695 | 702 | ||||||
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| Capital expenditures |
200 | 165 | ||||||
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| Adjusted free cash flow |
495 | 537 | ||||||
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| Revenue |
4,281 | 3,784 | ||||||
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| Adjusted EBITDA margin |
16 | % | 19 | % | ||||
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FUTURE PROSPECTS
Amid the ongoing demand growth and global energy security concerns, we expect there will be new opportunities for Westinghouse to compete for and win new business. Westinghouse’s reputation as a global leader in the nuclear industry and its position as the only fully European supplier for certified VVER fuel assemblies are expected to benefit its core business as Eastern European countries seek to develop a reliable fuel supply chain independent of Russia.
In addition to growth in its core business, the focus on the importance of nuclear power in providing carbon-free, secure and affordable baseload power as an essential part of the electricity grid in many countries is creating new opportunities for Westinghouse’s proven AP1000 reactor design, as well as the smaller reactor designs it has in development. Its technology and experience provide a competitive advantage as the engineering and procurement aspects of new build programs are initiated.
The following financial outlook is reported in Canadian dollars and prepared in accordance with IFRS and reflects Cameco’s 49% ownership share.
In 2024, we expect our share of Adjusted EBITDA from our equity investment in Westinghouse to be between $445 million and $510 million. Over the next five years, we expect its Adjusted EBITDA will grow at a compound annual growth rate of 6% to 10%. Adjusted EBITDA is a non-IFRS measure (see Non-IFRS Measures starting on page 41).
| CAMECO SHARE (49%) ($Cdn MILLIONS - IFRS) |
2024 OUTLOOK | |||
| Net earnings (loss) |
(170-230 | ) | ||
| Depreciation and amortization |
335-385 | |||
| Finance income |
(2-3 | ) | ||
| Finance costs |
140-170 | |||
| Income tax expense (recovery) |
10-30 | |||
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| EBITDA |
320-380 | |||
| Adjustments on cost of products and services sold |
55-60 | |||
| Adjustments on marketing, administrative and general |
50-65 | |||
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| Adjusted EBITDA |
445-510 | |||
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The outlook for Adjusted EBITDA for 2024 and its growth over the next five years are based on the following assumptions:
| • | An exchange rate of $1.00 (US) for $1.30 (Cdn) |
96 CAMECO CORPORATION
| • | A compound annual growth rate in revenue from its core business of 4% to 6%, which is slightly higher than the anticipated average growth rate of the nuclear industry based on the World Nuclear Association’s Reference Case. In addition to orders for PWR reactor fuel and services, this includes orders for VVER and BWR fuel and services. The outlook assumes that work is fulfilled on the timelines and scope expected based on current orders received, and additional work is undertaken based on past trends. The expected margins on this work are aligned with the historic margins of 16% to 19%, with variability expected to come from product mix compared to in previous years. |
| • | Growth from new AP1000 reactor projects is based on agreements that have been signed and announcements where the AP1000 technology has been selected, including Poland, Bulgaria and Ukraine. It is assumed that work on announced agreements and announced selections to be done by Westinghouse would proceed on the timelines and revenue pattern noted under the New Build Framework. The growth only assumes Westinghouse undertakes the Engineering and Procurement work required prior to a new reactor project breaking ground, which is a small component of the overall potential. A delay in project timelines or cancellation of announced projects would result in a growth rate near the bottom of the range. |
| • | Estimates and assumptions, including development timelines for both announced and potential reactor builds are subject to government and regulatory approval, as well as risks related to the current macro-economic environment, and may differ significantly from those assumed. |
| • | It is also expected that investments in new technologies, including eVinci™ microreactor and AP300™ small modular reactor, will be made in accordance with the current business plan and are expected to contribute to Adjusted EBITDA largely outside the 5-year time frame. |
New Build
New Build framework
Westinghouse undertakes its role in the design, development, engineering and procurement of equipment for new reactors. It does not provide construction services or assume any construction risk. This segment has the potential to add significant long-term value during the construction phase, and then to the core of the business through reactor services and fuel supply contracts once the reactor begins commercial operation.
Following an announcement of a successful bid, there are a number of contracts that must be signed before work commences and revenue is realized. The chart below is an illustrative framework and the assumptions used for the expected timing of revenue flows and profitability as these large, one-time decisions by utilities to construct new nuclear power plants using Westinghouse’s proven AP1000 reactor design are made.
Assumptions and estimates:
| • | Cost to construct new AP1000 reactor in the US based on an MIT (Massachusetts Institute of Technology) study: $6 billion to $8 billion (US), although it can vary significantly depending on in-country labour and construction productivity rates. There is a measured and noticeable scale effect where multiple reactors have been built – for example, in China, where four AP1000 reactors are in operation and six more are under construction, and the US, where two were built and one is in operation. |
| • | Engineering and procurement work: 25% to 40% of total plant cost, depending on the scope of the project – excluding China, where Westinghouse scope is typically less than 10% of the total project cost. |
| • | EBITDA margin for new build activity is expected to be aligned with the overall core business, although it can vary between 10% to 20%. |
MANAGEMENT’S DISCUSSION AND ANALYSIS 97
Illustrative framework of Westinghouse revenue flow for reactor new build project
Other growth opportunities
In addition to its AP1000 reactor design, Westinghouse has submitted its pre-application Regulatory Engagement Plan with the US Nuclear Regulatory Commission for the development of its AP300 small modular reactor, which is based on the proven and licensed AP1000 reactor design. Its eVinci microreactor design was recently awarded US Department of Energy funding for a test reactor FEED (front-end engineering design) at Idaho National Lab. The AP300 small modular reactor and the eVinci microreactor are expected to offer the same carbon-free baseload benefits as larger nuclear reactor technologies, but are tailored for specific applications, including industrial, remote mining, off-grid communities, defense facilities and critical infrastructure. As with the AP1000 reactor, they are expected to have applications beyond electricity generation, including district and process heat, desalination and hydrogen production. We are optimistic about the future competitiveness of these technologies and their potential to make a meaningful contribution to Westinghouse’s long-term financial performance. However, they are presently still in the development phase.
Caution about forward-looking information relating to Westinghouse
This discussion of our expectations relating to the future prospects of Westinghouse is subject to the assumptions and risks that are discussed under the heading Caution about forward-looking information beginning on page 2 and may be subject to the risks listed under the heading Managing the risks, starting on page 70, which include:
Assumptions
| • | the market conditions and other factors upon which we have based Westinghouse’s future plans and forecasts |
| • | Westinghouse’s ability to mitigate adverse consequences of delays in production and construction, and the success of its plans and strategies |
| • | the absence of new and adverse government regulations, policies or decisions, and that Westinghouse will comply with nuclear licence and quality assurance requirements at its facilities |
| • | that there will not be any significant adverse consequences to Westinghouse’s business resulting from business disruptions, including those relating to supply disruptions, economic or political uncertainty and volatility, labour relation issues, and operating risks |
Material risks that could cause actual results to differ materially
| • | the risk that Westinghouse may not be able to meet sales commitments for any reason |
| • | the risk that Westinghouse may not achieve the expected growth or success in its business |
| • | the risk to Westinghouse’s business associated with potential production disruptions, including those related to global supply chain disruptions, global economic uncertainty, political volatility, labour relations issues, and operating risks |
| • | the risk that Westinghouse’s strategies may change, be unsuccessful, or have unanticipated consequences |
| • | the risk that Westinghouse may fail to comply with nuclear licence and quality assurance requirements at its facilities |
We also recommend that you review our most recent AIF, which discusses other material risks that could have an impact on Westinghouse’s performance. Actual outcomes may vary significantly.
98 CAMECO CORPORATION
Other Nuclear Fuel Cycle Investments
Global Laser Enrichment
Global Laser Enrichment LLC (GLE) is the exclusive worldwide licensee of the proprietary Separation of Isotopes by Laser EXcitation (SILEX) laser uranium enrichment technology, a third-generation enrichment technology. Cameco is the commercial lead for the GLE project with a 49% interest and we hold an option to attain a majority interest of 75%. Silex Systems Ltd. (Silex Systems) owns the other 51% interest in GLE and is the licensor of the SILEX laser enrichment technology and the technology lead for GLE.
Subject to completion of the technology demonstration program and its progression through to commercialization, GLE has the potential to offer a variety of advantages to the global nuclear energy sector, including:
| • | re-enriching depleted uranium tails leftover as a by-product of first-generation gaseous diffusion enrichment operation, repurposing legacy waste into a commercial source of uranium and conversion products to fuel nuclear reactors and aiding in the responsible clean-up of legacy tails inventories, as per GLE’s agreement with the US Department of Energy (DOE); |
| • | producing commercial low-enriched uranium (LEU) to fuel the world’s existing and future fleet of large-scale light-water reactors (and depending on market developments, SMR’s that also require LEU-based fuel) with greater efficiency and flexibility than current enrichment technologies; and |
| • | producing high-assay low-enriched uranium (HALEU), if a market for that fuel stock develops to serve a number of small modular reactor (SMR) and advanced reactor designs that might be commercially deployed and require HALEU-based fuel. |
Our view is that re-enriching US government inventories of depleted uranium tails into a commercial source of uranium and conversion is GLE’s lowest-risk path to the market. This opportunity is underpinned by an agreement GLE has with the DOE to upgrade depleted uranium tails leftover from DOE’s historic enrichment operations, which may help address the growing supply gap for Western nuclear fuel supplies and services.
With the support of both Cameco and Silex Systems, GLE has accelerated its technology demonstration project activities to target an earlier delivery of the successful demonstration of Technology Readiness Level 6 (TRL-6). TRL-6 achievement will confirm large-scale system performance under relevant conditions (pilot-scale demonstration), which represents a major step up in a technology’s demonstrated readiness. Of note, GLE received the second full-scale laser system module from Silex Systems last year, which was installed in GLE’s pilot demonstration facility in the US. GLE’s efforts to bring forward planned activities and expenditures under the technology demonstration program are intended to demonstrate TRL-6 this year. Earlier TRL-6 demonstration may provide optionality for GLE to pursue government and industry support and funding related to potential commercial deployment opportunities (LEU and, potentially, HALEU) that could precede tails re-enrichment if the right conditions exist.
Unless another commercial deployment opportunity materializes, GLE will continue its work to complete the technology demonstration project with the potential to deploy its enrichment technology at a commercial scale in Western Kentucky under its agreement with the DOE no later than 2030. GLE’s path to commercialization depends on several factors, including but not limited to the successful progression and completion of GLE’s technology demonstration and maturation program, a clear commercial use case, sound market fundamentals, clarity regarding future Russian fuel imports, the ability to secure substantial government support and funding (specifically, accelerated commercial pathways related to LEU and, potentially, HALEU are reliant on government funding) and long-term industry support.
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.
MANAGEMENT’S DISCUSSION AND ANALYSIS 99
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, 2023.
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 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 |
| • | indicated resources: we can reasonably assume geological and grade continuity to support mine planning |
| • | inferred mineral resources are estimated using limited geological evidence and sampling information. We do 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 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 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 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 $54 (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 we have an interest but are not the operator, we will take reasonable steps to ensure that the reserve and resource estimates that we report are reliable.
100 CAMECO CORPORATION
Our share of uranium in the mineral reserves table below is based on our respective ownership interests.
Changes this year
Our share of proven and probable mineral reserves increased from 469 million pounds U3O8 at the end of 2022, to 485 million pounds at the end of 2023. The change was primarily the result of:
| • | mineral resource estimate update at Cigar Lake Extension and subsequent conversion of indicated mineral resources adding 40 million pounds to probable reserves. |
partially offset by:
| • | production at Cigar Lake, Inkai and McArthur River, which removed 22 million pounds of proven and probable reserves from our mineral inventory |
The remaining changes are attributable to other adjustments based on the mineral resource and reserve estimate updates at Cigar Lake, McArthur River and Inkai.
Our share of measured and indicated mineral resources decreased from 451 million pounds U3O8 at the end of 2022, to 409 million pounds at the end of 2023. Our share of inferred mineral resources decreased from 154 million pounds U3O8 to 153 million pounds.
MANAGEMENT’S DISCUSSION AND ANALYSIS 101
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 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 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.
Important information 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.
102 CAMECO CORPORATION
Mineral reserves
As of December 31, 2023 (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 | 338.1 | 18.11 | 135.0 | 217.5 | 15.36 | 73.7 | 555.6 | 17.03 | 208.6 | 113.8 | 98.7 | ||||||||||||||||||||||||||||||||||
| Key Lake |
OP | 61.1 | 0.52 | 0.7 | — | — | — | 61.1 | 0.52 | 0.7 | 0.6 | 95.0 | ||||||||||||||||||||||||||||||||||
| McArthur River |
UG | 2,047.3 | 7.02 | 316.8 | 520.7 | 5.55 | 63.8 | 2,568.0 | 6.72 | 380.5 | 265.6 | 99.0 | ||||||||||||||||||||||||||||||||||
| Inkai |
ISR | 239,588.4 | 0.04 | 208.8 | 66,046.9 | 0.04 | 52.9 | 305,635.3 | 0.04 | 261.7 | 104.7 | 85.0 | ||||||||||||||||||||||||||||||||||
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| Total |
242,035.0 | — | 661.2 | 66,785.0 | — | 190.3 | 308,820.1 | — | 851.5 | 484.7 | — | |||||||||||||||||||||||||||||||||||
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(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 $54 (US) per pound U3O8 |
| • | are based on exchange rates of $1.00 US=$1.26 Cdn and $1.00 US=450 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 73.
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.
MANAGEMENT’S DISCUSSION AND ANALYSIS 103
Mineral resources
As of December 31, 2023 (100% – only the shaded columns show our share)
MEASURED, INDICATED AND INFERRED
(tonnes in thousands; pounds in millions)
| OUR SHARE |
OUR 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 |
86.3 | 5.32 | 10.1 | 143.6 | 5.33 | 16.9 | 27.0 | 14.7 | 163.4 | 5.55 | 20.0 | 10.9 | ||||||||||||||||||||||||||||||||||||
| 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 |
78.7 | 2.27 | 3.9 | 60.6 | 2.30 | 3.1 | 7.0 | 4.9 | 37.2 | 2.90 | 2.4 | 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 | ||||||||||||||||||||||||||||||||||||
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| Total |
121,172.8 | — | 183.7 | 113,300.7 | — | 323.4 | 507.1 | 408.8 | 51,747.1 | — | 201.3 | 153.2 | ||||||||||||||||||||||||||||||||||||
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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 |
104 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.
Carrying value 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, 2023, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.
MANAGEMENT’S DISCUSSION AND ANALYSIS 105
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, 2023.
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, 2023, 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, 2023, 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.
106 CAMECO CORPORATION
EXHIBIT 99.4
For fiscal years ended December 31, 2023 and December 31, 2022, KPMG LLP and its affiliates billed Cameco Corporation and its subsidiaries the following fees:
| 2023 ($) |
% of total fees |
2022 ($) |
% of total fees |
|||||||||||||
| Audit fees |
||||||||||||||||
| Cameco1 |
2,436,700 | 88.7 | 2,389,200 | 82.8 | ||||||||||||
| Subsidiaries2 |
135,600 | 4.9 | 136,800 | 4.7 | ||||||||||||
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|||||||||
| Total audit fees |
2,572,300 | 93.6 | 2,526,000 | 87.5 | ||||||||||||
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|
|
|||||||||
| Audit-related fees |
||||||||||||||||
| Translation services3 |
— | 0 | 137,500 | 4.8 | ||||||||||||
| Pensions4 |
31,600 | 1.2 | 30,000 | 1.0 | ||||||||||||
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|
|
|||||||||
| Total audit-related fees |
31,600 | 1.2 | 167,500 | 5.8 | ||||||||||||
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| Tax fees |
||||||||||||||||
| Compliance |
5,600 | 0.2 | 5,100 | 0.2 | ||||||||||||
| Planning and advice5 |
136,100 | 5.0 | 117,700 | 4.1 | ||||||||||||
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| Total tax fees |
141,700 | 5.2 | 122,800 | 4.3 | ||||||||||||
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| All other fees |
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| Other non-audit fees6 |
— | 0 | 69,500 | 2.4 | ||||||||||||
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| Total other non-audit fees |
— | 0 | 69,500 | 2.4 | ||||||||||||
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| Total fees |
2,745,600 | 100.0 | 2,885,800 | 100.0 | ||||||||||||
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| 1 | Includes amounts billed for the audit of Cameco’s annual consolidated financial statements and the review 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 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 2023 for translation services. |
| 4 | Includes amounts billed for the audit of Cameco’s pension plan financial statements. |
| 5 | Includes amounts billed for tax compliance and tax advisory services. |
| 6 | Other non-audit fees for 2022 includes amounts billed for Cameco’s I-4 Membership. No invoices were issued in 2023. |
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, 2023 and 2022, 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.
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 7, 2024 on the consolidated financial statements of Cameco Corporation (the “Entity”) which comprise the consolidated statements of financial position as of December 31, 2023 and 2022, the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the years then ended, and the related notes (collectively the “consolidated financial statements”), and |
| • | our report dated February 7, 2024 on the effectiveness of the Entity’s internal control over financial reporting as of December 31, 2023 |
each of which is included in the Annual Report on Form 40-F of the Entity for the fiscal year ended December 31, 2023.
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 22, 2024
Saskatoon, Canada
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; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a 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, 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 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 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 prepared; |
| b) | designed such internal control over financial reporting, or caused such internal control over financial 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 principles; |
| c) | evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this 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 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 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 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 the issuer’s internal control over financial reporting. |
Date: March 22, 2024
| /s/ Tim Gitzel |
| Name: Tim Gitzel |
| Title: President and Chief Executive Officer (Principal Executive Officer) |
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; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a 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, 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 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 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 prepared; |
| b) | designed such internal control over financial reporting, or caused such internal control over financial 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 principles; |
| c) | evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this 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 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 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 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 the issuer’s internal control over financial reporting. |
| Date: March 22, 2024 | /s/ Grant Isaac |
|||||
| Name: | Grant Isaac | |||||
| Title: | Executive Vice-President and | |||||
| Chief Financial Officer | ||||||
| (Principal Financial Officer) | ||||||
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, 2023, 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 of 1934; and |
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
| By: | /s/ Tim Gitzel |
|
| Name: Tim Gitzel | ||
| Title: President and Chief Executive Officer |
March 22, 2024
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, 2023, 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 of 1934; and |
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
| By: | /s/ Grant Isaac |
|
| Name: Grant Isaac | ||
| Title: Executive Vice-President and | ||
| Chief Financial Officer |
March 22, 2024
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 investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and investments – Cigar Lake”, “Operations, projects and 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 December 31, 2023 dated March 22, 2024 for the McArthur River mine/Key Lake mill, Cigar Lake and Inkai operations; and |
| (b) | under the headings “Operations, projects and investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and investments – Uranium – Tier-one operations – Cigar Lake”, “Operations, projects and investments – Uranium – Tier-one operations – Inkai”, and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2023 dated February 8, 2024 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 Services, Cameco Corporation
Date: March 22, 2024
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 investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and investments – Uranium – Tier-one operations – Cigar Lake”, “Operations, projects and 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 December 31, 2023 dated March 22, 2024 for the McArthur River mine/Key Lake mill, Cigar Lake and Inkai operations; and |
| (b) | under the headings “Operations, projects and investments – Uranium – Tier-one operations – McArthur River mine/Key Lake mill”, “Operations, projects and investments – Uranium – Tier-one operations – Cigar Lake”, “Operations, projects and investments – Uranium – Tier-one operations – Inkai”, and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2023 dated February 8, 2024 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 22, 2024
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 investments – Uranium – Tier-one operations – Cigar Lake”, “Operations, projects and 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 December 31, 2023 dated March 22, 2024 for the Cigar Lake and Inkai operations; and |
| (b) | under the headings “Operations, projects and investments – Uranium – Tier-one operations – Cigar Lake”, “Operations, projects and investments – Uranium – Tier-one operations – Inkai”, and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2023 dated February 8, 2024 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 Assurance & Mineral Reserves, Technical Services, Cameco Corporation
Date: March 22, 2024
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 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 December 31, 2023 dated March 22, 2024 for the Cigar Lake operation; and |
| (b) | under the headings “Operations, projects and 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 8, 2024 for the 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 22, 2024
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 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 for the year ended December 31, 2023 dated March 22, 2024 for the McArthur River mine; and |
| (b) | under the headings “Operations, projects and 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, 2023 dated February 8, 2024 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 22, 2024
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 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 December 31, 2023 dated March 22, 2024 for the Inkai operation; and |
| (b) | under the headings “Operations, projects and investments – Uranium – Tier-one operations – Inkai”, and “Mineral reserves and resources” in Management’s Discussion and Analysis for the year ended December 31, 2023 dated February 8, 2024 for the Inkai 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 22, 2024
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 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 for the year ended December 31, 2023 dated March 22, 2024 for the Key Lake mill; and |
| (b) | under the headings “Operations, projects and 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, 2023 dated February 8, 2024 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 22, 2024
EXHIBIT 99.18
EXECUTIVE INCENTIVE COMPENSATION RECOUPMENT POLICY
(SEC AND NYSE)
Purpose
This Executive Incentive Compensation Recoupment Policy (SEC and NYSE) has been adopted by
Cameco Corporation (Cameco) to enhance its alignment with good compensation governance practices, to comply with requirements set forth by the U.S. Securities and Exchange Commission and the New York Stock Exchange, and to assist Cameco to manage its compensation related risk.
Definitions
In this Policy the following capitalized terms have the meanings set out below:
| 1. | “Applicable Rules” means any laws, regulations and rules of any stock exchange applicable to Cameco, including the listing standards of the New York Stock Exchange. |
| 2. | “Board” means the board of directors of Cameco. |
| 3. | “Cameco” means Cameco Corporation. |
| 4. | “Effective Date” means October 2, 2023. |
| 5. | “Executives” means any officer appointed by the Board from time to time and includes former officer appointees and any individual who is, or was during the Look-Back Period, an executive officer of Cameco within the meaning of Rule 10D-1(d) under the U.S. Securities Exchange Act of 1934. “Executive” means any one of the Executives. |
| 6. | “Human Resources and Compensation Committee” means the human resources and compensation committee of the Board. |
| 7. | “Incentive Compensation” means that portion of an Executive’s compensation that is granted, earned or vested based wholly or in part on stock price, total shareholder return or the attainment of (i) financial goals that are determined and presented in accordance with the accounting principles used in preparing Cameco’s financial statements, and (ii) any other measures that are derived from such measures. |
| 8. | “Look-Back Period” means, with respect to any given Restatement, the three completed fiscal years preceding the date Cameco is required to prepare such Restatement. |
| 9. | “Overcompensation Amount” means the portion of an Executive’s Incentive Compensation relating to the Look-Back Period which is in excess of the Incentive Compensation that the Executive would have received for such period if the Incentive Compensation had been computed in accordance with the results as restated under the Restatement, calculated without regard to any taxes paid. For Incentive Compensation based on stock price or total shareholder return, where the amount to be recovered is not subject to mathematical recalculation directly from information in the Restatement, |
| the amount to be recovered shall be based on a reasonable estimate of the effect of the Restatement on the stock price or total shareholder return, as applicable, and Cameco shall retain documentation of the determination of such estimate and provide such documentation to the New York Stock Exchange if so required by the Applicable Rules. Incentive Compensation is deemed received during the fiscal year during which the applicable financial reporting measure, stock price and/or total shareholder return measure, upon which the payment is based, is achieved, even if the grant or payment occurs after the end of such period. |
| 10. | “Policy” means this Executive Incentive Compensation Recoupment Policy (SEC and NYSE). |
| 11. | “Restatement” means an accounting restatement due to Cameco’s material non-compliance with any applicable financial reporting requirement under securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that corrects an error that is not material to the previously issued financial statements but would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period. Changes to financial statements that do not constitute a Restatement include retroactive: (i) application of a change from one International Financial Reporting Standards (IFRS) accounting principle to another IFRS accounting principle; (ii) revisions to reportable segment information due to a change in internal organization; (iii) reclassification due to a discontinued operation; (iv) application of a change in reporting entity, such as from a reorganization of entities under common control; (v) adjustments to provisional amounts in connection with a prior business combination; and (vi) revisions for stock splits, reverse stock splits, stock dividends, or other changes in capital structure. |
Application
This Policy applies to all Incentive Compensation received by a current or former Executive on or after the Effective Date.
Right to Recoup Incentive Compensation
In the event that:
| a) | Cameco makes a Restatement; and |
| b) | the Executive received an Overcompensation Amount, |
the Board shall, on the recommendation of the Human Resources and Compensation Committee, subject to Applicable Rules, determine and recover the Overcompensation Amount from the Executive as follows:
| (i) | to the extent that the Overcompensation Amount has been paid, transferred or otherwise made available to the Executive, require, by written demand, the Executive to reimburse Cameco for such Overcompensation Amount (which, in the case of options or share appreciation rights received by the Executive during the Look-Back Period which have been exercised by the Executive, means the amount, by which the fair market value of a common share of Cameco on the date of exercise or settlement exceeded the exercise price for the option or share appreciation right); |
| (ii) | to the extent that the Overcompensation Amount has not been paid, transferred or otherwise made available to the Executive by Cameco, cancel, or require the Executive to forfeit, the receipt or payment of such Overcompensation Amount; and |
| (iii) | to the extent the Overcompensation Amount is not immediately recovered upon demand from the Executive, whether by reimbursement, forfeiture and/or cancellation, deduct the Overcompensation Amount, or any unrecovered portion thereof, from salary, wages and/or any other Incentive Compensation whether or not referable to the Look-Back Period owing, awarded or payable by Cameco to the Executive or withhold, forfeit and/or cancel any Incentive Compensation to compensate for the Overcompensation Amount or any unrecovered portion thereof, and to bring any other actions against the Executive which they may deem necessary or advisable to recover the Overcompensation Amount or any unrecovered portion thereof. |
Notwithstanding the foregoing, the Board may determine that repayment of an Overcompensation Amount (or a portion thereof) is not required only where it determines that recovery would be impracticable and one of the following circumstances exists: (i) the direct expense paid to a third party to assist in enforcing this Policy would exceed the amount to be recovered, provided Cameco has (A) made a reasonable attempt to recover such Incentive Compensation, (B) documented such reasonable attempt and (C) provided such documentation to the New York Stock Exchange; (ii) recovery would violate Canadian law where the law was adopted prior to November 28, 2022, provided Cameco has (A) obtained an opinion of Canadian counsel acceptable to the New York Stock Exchange that recovery would result in such violation and (B) provided such opinion to the New York Stock Exchange; or (iii) recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of Cameco, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and the regulations thereunder.
This Policy will be enforced and appropriate exhibit filings will be made in accordance with the Applicable Rules. Recoupment of Overcompensation Amounts under this Policy will be initiated by Cameco at the direction of the Board on the recommendation of the Human Resources and Compensation Committee, and all amounts recoverable or payable hereunder shall be paid to Cameco or as directed by the Board.
This Policy is in addition to any other action or remedy available to Cameco against the Executive under Applicable Rules, including termination of employment for cause.
No Fault Application, No Indemnification
Recovery of erroneously received compensation under this Policy is on a “no fault” basis, meaning that it will occur regardless of whether the Executive engaged in misconduct or was otherwise directly or indirectly responsible, in whole or in part, for the Restatement. No Executive may be indemnified by Cameco, or any of its affiliates, from losses arising from the application of this Policy.
General
Subject to applicable law, this Policy may be terminated at any time by the Board.
In the event of any conflict or inconsistency between this Policy and any other policies, plans or other materials of Cameco, this Policy will govern.
Nothing in this Policy is intended to limit or otherwise preclude recovery under the Company’s existing Executive Incentive Compensation Recoupment Policy, as such policy may be amended from time to time.
Policy Governance
Policy Sponsor: The human resources and compensation committee
Approved by: The Cameco Corporation Board of Directors
Date approved: November 22, 2023
Date last reviewed: Not applicable
Responsibility for document management: Corporate Secretary
