EX-99.3 4 d381976dex993.htm EX-99.3

EXHIBIT 99.3

Cameco Corporation

2022 Management’s Discussion and Analysis

February 9, 2023

Management’s discussion and analysis

February 9, 2023

10 |  | MARKET OVERVIEW AND DEVELOPMENTS
17 |  | 2022 PERFORMANCE HIGHLIGHTS
23 |  | OUR VISION, VALUES AND STRATEGY
32 |  | OUR ESG PRINCIPLES AND PRACTICES
36 |  | MEASURING OUR RESULTS
38 |  | FINANCIAL RESULTS
66 |  | OPERATIONS AND PROJECTS
94 |  | MINERAL RESERVES AND RESOURCES
99 |  | ADDITIONAL INFORMATION

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2022. The information is based on what we knew as of February 8, 2023.

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

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

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

Throughout this document, the terms we, us, our, the Company and Cameco mean Cameco Corporation and its subsidiaries, unless otherwise indicated.

Caution about forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans, future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and United States (US) securities laws. We refer to them in this MD&A as forward-looking information.

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

• |  | It typically includes words and phrases about the future, such as: anticipate, believe, estimate, expect, plan, 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, reliable, affordable and carbon-free energy, and our vision to energize a clean-air world

• |  | we will continue to focus on delivering our products responsibly and addressing the environmental, social and governance (ESG) risks and opportunities that we believe will make our business sustainable and will build long-term value

• |  | our expectations about 2023 and future global uranium supply, consumption, contracting, demand, geopolitical issues and the market including the discussion under the heading Market overview and developments

• |  | our expectations for the future of the nuclear industry and the potential for new enrichment technology, including that nuclear power must be a central part of the solution to the world’s shift to a low-carbon climate-resilient economy

• |  | our efforts to participate in the commercialization and deployment of small modular reactors (SMRs) and increase our contributions to global climate change solutions by exploring SMRs and other emerging opportunities within the fuel cycle

• |  | our views on our ability to self-manage risk

• |  | the discussion under the heading Our strategy

• |  | the discussion under the heading Our response to the COVID-19 pandemic, including the priority of employee health and safety in our plans

• |  | our expectations regarding the operation of, and production levels for, the Cigar Lake mine and McArthur River/Key Lake operation and the Port Hope UF6 conversion facility

• |  | the discussion under the heading Our ESG principles and practices including our belief there is a significant opportunity for us to be part of the solution to combat climate change and that we are well positioned to deliver significant long-term business value

• |  | our expectations for uranium purchases, sales and deliveries

• |  | the anticipated timing for the finalization of the SE NNEGC Energoatom (Energoatom) supply contract, volume requirements under the contract and our expectation that Cameco will provide sufficient volumes of UF6 under it to meet Ukraine’s full nuclear fuel needs through 2035

• |  | our intentions regarding future dividend payments

• |  | the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our expectations regarding receiving refunds and payment of disbursements from CRA, our confidence that the courts would reject any attempt by CRA to utilize the same or similar positions for other tax years currently in dispute, our plan to file a notice of objection for 2016 and our belief that CRA should return the full amount of cash and security that has been paid or otherwise secured by us

• |  | the discussion under the heading Outlook for 2023, including expected business resiliency, expectations for 2023 average unit cost of sales, average purchase price per pound, deliveries and production, 2023 financial outlook, our revenue, expectations for 2023 cash balances, tax rates, adjusted net earnings and cash flow sensitivity, and our price sensitivity analysis for our uranium segment

• |  | the discussion under the heading Liquidity and capital resources, including expected liquidity to meet our 2023 obligations and our expectations for our uranium contract portfolio to provide a solid revenue stream

• |  | our expectation that the uranium contract portfolio we have built will continue to provide a solid revenue stream, and our portfolio management strategy, including our inventory strategy and the extent of our spot market purchases

• |  | our expectation that our cash balances and operating cash flows will meet our anticipated 2023 capital requirements

• |  | our expectations for future capital expenditures

• |  | our expectation that in 2023 we will be able to comply with all the covenants in our unsecured revolving credit facility

• |  | life of mine operating cost estimates for the Cigar Lake, McArthur River/Key Lake and JV Inkai operations

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• |  | 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 sources and uses of financing for the acquisition, the timeline of the acquisition, including the anticipated closing thereof, and the acquisition organizational structure, equity accounting for our investment, generation of new revenue opportunities, the potential to generate additional revenue in the year following the acquisition closing, our expectation that the acquisition will be accretive to our cash flow after closing, Westinghouse’s ability to generate cash flow to fund its approved annual operating budget and provide quarterly distributions to the partners after closing, the acquisition expanding our participation in the nuclear fuel value chain, and providing a platform for further growth, our intention in respect of not issuing additional equity to fund our portion of the purchase price for the Westinghouse acquisition and various factors and drivers for Westinghouse’s business segment

MANAGEMENT’S DISCUSSION AND ANALYSIS 3

Material risks

• |  | actual sales volumes or market prices for any of our products or services are lower than we expect, or cost of sales is higher than we expect, for any reason, including changes in market prices, loss of market share to a competitor, trade restrictions, geopolitical issues or the impact of the COVID-19 pandemic

• |  | we are adversely affected by changes in currency exchange rates, interest rates, royalty rates, tax rates, or inflation

• |  | our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms

• |  | our strategies may change, be unsuccessful or have unanticipated consequences, or we may not be able to achieve anticipated operational flexibility and efficiency

• |  | changing views of governments regarding the pursuit of carbon reduction strategies or our view may prove to be inaccurate on the role of nuclear power in pursuit of those strategies

• |  | our estimates and forecasts prove to be inaccurate, including production, purchases, deliveries, cash flow, revenue, costs, decommissioning, reclamation expenses, or receipt of future dividends from JV Inkai

• |  | the Westinghouse acquisition may be delayed or may not be completed on the terms in the acquisition agreement or at all

• |  | consummation of the Westinghouse acquisition is subject to the satisfaction of closing conditions and regulatory approvals that may not be satisfied on a timely basis or at all

• |  | that we may not realize the expected benefits from the Westinghouse acquisition

• |  | after closing the acquisition, Westinghouse fails to generate sufficient cash flow to fund its approved annual operating budget or make quarterly distributions to the partners

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

• |  | we are subject to litigation or arbitration that has an adverse outcome

• |  | that we may not receive expected refunds and payments from CRA

• |  | that the courts may accept the same, similar or different positions and arguments advanced by CRA to reach decisions that are adverse to us for other tax years

• |  | the possibility of a materially different outcome in disputes with CRA for other tax years

• |  | that CRA does not agree that the court rulings for the years that have been resolved in Cameco’s favour should apply to subsequent tax years

• |  | that CRA will not return all or substantially all of the cash and security that has been paid or otherwise secured in a timely manner, or at all

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

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

• |  | we are affected by environmental, safety and regulatory risks, including workforce health and safety or increased regulatory burdens or delays resulting from the COVID-19 pandemic or other causes

• |  | necessary permits or approvals from government authorities cannot be obtained or maintained

• |  | we are affected by political risks, including the early-2022, and any potential future, unrest in Kazakhstan

• |  | operations are disrupted due to problems with our own or our suppliers’ or customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment 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 like COVID-19), 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 become unable to pay future dividends at the expected rate

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• |  | we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes

• |  | the risks that generally apply to all our operations and advanced uranium projects that are discussed under the heading Managing the risks beginning on page 67

• |  | the risks relating to our tier-one uranium operations discussed under the heading McArthur River mine/Key Lake mill – Managing Our Risks beginning on page 73, under the heading Cigar Lake – Managing Our Risks beginning on page 76, and under the heading Inkai – Managing Our Risks beginning on page 80

• |  | risks relating to the Energoatom supply contract, including the risk that it will not be finalized within the time or on the terms expected, our ability to supply UF6 under the contract, that the option for us to supply the Zaporizhzhya nuclear power plant, if exercised, may not result in the delivery volumes expected and that the continuation or outcome of the conflict between the Ukraine and Russia may prevent Cameco from realizing its expected benefits

Material assumptions

• |  | our expectations regarding sales and purchase volumes and prices for uranium and fuel services, cost of sales, trade restrictions, inflation and that counterparties to our sales and purchase agreements will honour their commitments

• |  | our expectations for the nuclear industry, including its growth profile, market conditions, geopolitical issues and the demand for and supply of uranium

• |  | the continuing pursuit of carbon reduction strategies by governments and the role of nuclear in the pursuit of those strategies

• |  | the assumptions discussed under the heading 2023 Financial Outlook

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

• |  | the Westinghouse acquisition is closed on the anticipated timeline and on the terms of the acquisition agreement

• |  | Westinghouse’s ability to generate cash flow and fund its approved annual operating budget and make quarterly distributions to the partners after closing of the acquisition

• |  | our ability to compete for additional business opportunities so as to generate additional revenue for us in the year after closing the Westinghouse acquisition

• |  | market conditions and other factors upon which we based the Westinghouse acquisition and our related forecasts will be as expected

• |  | the success of our plans and strategies relating to the Westinghouse acquisition

• |  | that the construction of new nuclear power plants and the relicensing of existing nuclear power plants will not be more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants

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

• |  | our expected production levels for Cigar Lake, McArthur River/Key Lake, JV Inkai and our fuel services operating sites

• |  | our cost expectations, including production costs, operating costs, and capital costs

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

• |  | our entitlement to and ability to receive expected refunds and payments from CRA

• |  | in our dispute with CRA, that courts will reach consistent decisions for other tax years that are based upon similar positions and arguments

• |  | that CRA will not successfully advance different positions and arguments that may lead to different outcomes for other tax years

• |  | our expectation that we will recover all or substantially all of the amounts paid or secured in respect of the CRA dispute to date

• |  | our decommissioning and reclamation estimates, including the assumptions upon which they are based, are reliable

• |  | our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable

• |  | our understanding of the geological, hydrological and other conditions at our uranium properties

• |  | our Cigar Lake and McArthur River development, mining and production plans succeed

• |  | our Key Lake mill production plan succeeds

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

• |  | our production plans for our Port Hope UF6 conversion facility succeed

• |  | JV Inkai’s development, mining and production plans succeed, and that JV Inkai will be able to transport and deliver its production

• |  | the ability of JV Inkai to pay dividends

• |  | that care and maintenance costs will be as expected

• |  | our and our contractors’ ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals

• |  | our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, outbreak of illness (such as a pandemic like COVID-19), governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, 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

MANAGEMENT’S DISCUSSION AND ANALYSIS 5

• |  | assumptions regarding the Energoatom supply contract, including that we will reach agreement on final terms within the time and on the terms expected, delivery volumes, our ability to supply UF6 under the contract, and that we will not be prevented from realizing the expected benefits of the contract because of the continuation or outcome of the conflict between Ukraine and Russia

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MANAGEMENT’S DISCUSSION AND ANALYSIS 7

Market overview and developments

A market in transition

In 2022, geopolitical events coupled with the ongoing focus on the climate crisis created what we believe are transformative tailwinds for the nuclear power industry from both a demand and supply perspective. Uranium prices continued to rise, reaching levels not seen since 2011 driven by a tightened uranium market and growing security of supply concerns. In early-January, unrest in Kazakhstan raised concerns about the more than 40% of global uranium supply that originates from Kazakhstan. However, it was the Russian invasion of Ukraine in late-February that was the most transformative event for our industry. We believe it has set in motion a geopolitical realignment in energy markets that is highlighting the increasingly important role for nuclear power not just in providing clean energy, but also providing secure and affordable energy. And, with the global nuclear industry reliant on Russian supplies for approximately 14% of uranium concentrates, 27% of conversion and 39% of enrichment, it is highlighting the security of supply risk associated with the growing primary supply gap and shrinking secondary supplies and increasing the focus on origin of supply.

With the heightened supply risk caused by geopolitical uncertainty, utilities are evaluating their nuclear fuel supply chains. Utilities continue to be focused on ensuring they have the conversion and enrichment services they require secured under long-term contracts and are now beginning to return their focus to uranium. The uncertainty about where nuclear fuel supplies will come from to satisfy growing demand led to increased long-term contracting activity in 2022. This contracting activity resulted in a 22% increase in the long-term price of uranium over the past year, conversion prices that are at historic highs, and enrichment prices that have increased over 210% since the start of the invasion of Ukraine. Notably, utilities are now approaching replacement rate contracting for the first time in over a decade. Therefore, we expect there will be continued competition to secure uranium, conversion and enrichment services under long-term contracts with proven producers and assets in geopolitically attractive jurisdictions, with strong environmental, social and governance (ESG) performance and on terms that will ensure the availability of reliable supply to satisfy demand.

DURABLE DEMAND GROWTH

The benefits of nuclear energy have come clearly into focus with a durability we believe has not been previously seen. The durability is being driven not only by accountability for achieving the net-zero carbon targets set by countries and companies around the world, but also by a geopolitical realignment that is causing countries to reexamine how they approach their energy needs. Net-zero carbon targets are turning attention to a triple challenge. First, is to lift one-third of the global population out of energy poverty by growing clean and reliable baseload electricity. Second, is to replace 85% of the current global electricity grids that run on carbon-emitting sources of thermal power with a clean, reliable alternative. And finally, is to grow global power grids by electrifying industries, such as private and commercial transportation, home, and industrial heating, largely powered with carbon-emitting sources of thermal energy today. Additionally, the Russian invasion of Ukraine has deepened the energy crisis experienced in some parts of the world and amplified concerns about energy security, highlighting the role of energy policy in balancing three main objectives: providing a clean emissions profile; providing a reliable and secure baseload profile; and providing an affordable levelized cost profile. There is increasing recognition that nuclear power meets these objectives and has a key role to play in achieving decarbonization goals. The growth in demand is not just long-term in the form of new builds, it is medium-term demand in the form of reactor life extensions, and it is near-term growth as early reactor retirements are prevented and new markets continue to emerge. And we are seeing momentum building for non-traditional commercial uses of nuclear power around the world such as development of small modular reactors and advanced reactors, with numerous companies and countries pursuing projects.

Demand and energy policy highlights

• |  | China announced plans to accelerate new nuclear projects to combat future electricity shortages, indicating it could raise the number of new reactor construction approvals to ten or more per year. In 2022, there were ten approvals.

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• |  | In December, Japan announced a new plan to maximize nuclear power by restarting as many existing reactors as possible, prolonging the operating lives of aging reactors beyond a 60-year limit, and building new reactors. This followed an earlier pledge by Japan’s Prime Minister Kishida to have up to 17 reactors restarted by the summer of 2023. Additionally, the government set a target for nuclear to make up 20% to 22% of the country’s energy mix by the end of the decade, and under the new policy will push for the development and construction of “next-generation innovative reactors” to replace about 20 reactors now set for decommissioning.

• |  | South Korea finalized their 10th Basic Plan for Electricity Supply and Demand in January 2023. The plan aims to maintain 30% of the country’s 2030 energy mix as nuclear power, resume construction on Units 3 and 4 at the Shin Hanul nuclear plant, and sets a goal of exporting 10 nuclear power plants by 2030, as well as the development of a Korean small modular reactor (SMR). This positive news builds from the earlier 2022 announcements that included nuclear power in South Korea’s green taxonomy and reversed the previous administration’s anti-nuclear stance.

• |  | In July 2022, the European Parliament voted to keep nuclear power in the European Union’s sustainable finance taxonomy as a transitional “green” investment. The Complimentary Delegated Act from this vote was entered into application on January 1, 2023. Including nuclear power in the “transitional” category indicates that it will help mitigate climate change but cannot yet be replaced by economically and technologically feasible low-carbon alternatives.

• |  | Following the Russian invasion, numerous European countries announced their intention to reduce reliance on Russian-supplied nuclear fuel under long-term contracts. For example, on June 2nd, Ukraine’s state-owned utility, Energoatom, signed an agreement with Westinghouse to supply all its nuclear fuel and increase the number of planned AP1000 reactor new builds from five to nine. Numerous other countries have also taken steps to diversify their nuclear fuel supply.

• |  | In Sweden, a newly elected coalition majority government immediately updated the country’s energy policy to be more pro-nuclear. They cited a significant shift away from the previous focus on renewables, changing the previous goal of “100% renewable” electricity by 2040 to “100% fossil free electricity”, and have put forward legislation to allow for the construction of more reactors.

• |  | Belgium shut down its Doel-3 nuclear reactor in September, but in January announced 10-year life extensions for their two newest reactors, Doel 4 and Tihange 3. These reactors were set to close in 2025 but will now restart in November 2026 after the necessary preparation and will continue operating for 10 years.

• |  | Chancellor Olaf Scholz has ordered the life extension of Germany’s three remaining reactors until mid-April 2023, keeping them on stand-by due to energy concerns.

• |  | In November 2022, the United Kingdom (UK) announced that it would take a joint stake alongside French partner Électricité de France (EDF) in the construction of its new Sizewell C nuclear power station, replacing China General Nuclear’s 20% stake. The UK will invest £700 million in the project, which will be matched by EDF.

• |  | In France, the government and regulator are working on conditions to extend the operating lives of existing reactors and are planning an “industrial build” program with the start of construction around 2028 for the first two of six new EPR reactors and with plans for eight additional EPRs in the future. In addition, the French state is finalizing increased ownership in EDF from 84% to 100% to provide a smooth energy transition, ensure sovereignty in the face of war and firm up the company’s diminished financial situation.

• |  | In Finland, Teollisuuden Voima Oyj announced Olkiluoto 3, the 1,600 MWe EPR, resumed test electricity production in December following a few months delay with regular electricity production now scheduled to start in March 2023.

• |  | Poland confirmed its intent to build nuclear power capacity for the first time and is progressing plans with both Westinghouse for AP1000 PWR’s and Korea Hydro & Nuclear Power (KHNP) for APR 1400’s.

• |  | Egypt began construction on the first two of four Russian built VVER 1200 reactors at the El-Dabaa Power Plant as the government looks to accelerate the project. Additionally, in December, Egypt announced plans to start mining uranium in 2024 as part of the country’s rapidly developing program for peaceful use of nuclear energy.

• |  | India’s first domestically designed 700 MWe pressurized heavy water reactor at Kakrapar is now in commercial operation, an important milestone for the country. Three more units of this design are expected to come online in the next few years. The country is targeting an expansion to have 22.5 GWe operating by 2031.

MANAGEMENT’S DISCUSSION AND ANALYSIS 11

• |  | In August 2022, President Biden signed the Inflation Reduction Act of 2022 (IRA) into law. Through $369 billion (US) in tax incentives and other investments, IRA is a major federal legislative initiative enacted to address climate change. The IRA includes significant support for nuclear power with the establishment of a Production Tax Credit to support existing nuclear reactors and provides $700 million (US) to incentivize the development of domestic sources of high-assay low-enriched uranium. Additionally, in December, the International Nuclear Energy Act passed a US Senate Committee vote and is expected to be reintroduced to Congress. The bill seeks to promote engagement with partner and ally nations to develop a civil nuclear export strategy, establish financing relationships, standardize licensing frameworks, and is designed to offset the influence of Russia and China in the international nuclear market. This support comes in addition to ongoing work at various levels of the US government to eliminate US dependence on nuclear fuel imports from Russia.

• |  | In California, Governor Newsom signed a bill seeking to extend operations at the Diablo Canyon Power Plant for five years beyond its current licence, which expires in 2025.

• |  | Southern Company announced fuel loading began in October 2022 for Vogtle unit 3, the first of two 1,250 MWe AP1000’s under construction in Georgia. The company also confirmed its plans to apply to have the operating licences for its Farley and Hatch reactors extended to 80 years. This followed similar announced extensions for Tennessee Valley Authority’s Browns Ferry reactor, Xcel Energy’s Monticello reactor, and Dominion Energy’s Virgil C. Summer reactor.

• |  | Mexico’s Laguna Verde nuclear plant has been granted 30-year operating life extensions for its two units.

• |  | Ontario Power Generation (OPG) announced plans to extend the life of the Pickering nuclear power plant until at least 2026 and potentially up to 30 years. In addition, OPG signed an agreement with X-energy to examine deploying their Xe-100 SMR. Finally, OPG issued a $300 million Green Bond, a first-of-its-kind for the company and part of its commitment to be net zero by 2040. The funds are to be used to finance the refurbishment activities at its Darlington site, where life extensions to four units are in progress, as well as for maintenance of existing nuclear facilities.

• |  | In October 2022, OPG completed a significant project milestone by submitting an application for a Licence to Construct to the Canadian Nuclear Safety Commission (CNSC). This licence application is the next step in the deployment of a SMR at the Darlington site. The submission comes after the beginning of site preparation activities earlier in 2022, which was another significant milestone.

• |  | In late 2022, Bruce Power achieved a major milestone in the refurbishment of Unit 6, as project teams successfully installed the CANDU reactor’s fuel channel assembly, which puts the project on track to return to operation in 2023. Additionally, the Unit 3 refurbishment campaign is scheduled to begin in March 2023.

• |  | Sprott Physical Uranium Trust (SPUT) purchased about 17 million pounds U3O8 in 2022, bringing total purchases since inception to over 41 million pounds U3O8. The challenging equity markets in recent months have contributed to SPUT shares trading at a discount to net asset value, impacting its ability to raise funds to purchase uranium.

According to the International Atomic Energy Agency, globally there are currently 439 operable reactors and 57 reactors under construction. Several nations are appreciating the clean energy and energy security benefits of nuclear power. They have reaffirmed their commitment to it and are developing plans to support existing reactor units and are reviewing their policies to encourage more nuclear capacity. Several other non-nuclear countries have emerged as candidates for new nuclear capacity. In the EU, specific nuclear energy projects have been identified for inclusion under its sustainable financing taxonomy and therefore eligible for access to low-cost financing. Even in countries where phase-out policies were in place, there have been policy reversals and decisions to, at a minimum, temporarily keep reactors running, with public opinion polls showing growing support for it. With a number of reactor construction projects recently approved, and many more planned, the demand for uranium continues to improve. There is growing recognition of the role nuclear must play in providing safe, affordable, carbon-free baseload electricity that achieves a low-carbon economy while being a reliable energy source to help countries diversify away from Russian energy supply.

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SUPPLY UNCERTAINTY

In addition to low uranium prices, government-driven trade policies, the COVID-19 pandemic, and ongoing supply chain challenges, the most notable factor impacting security of supply in 2022 was geopolitical uncertainty. The geopolitical uncertainty, driven by the Russian invasion of Ukraine, has led many governments and utilities to re-examine supply chains and procurement strategies that are reliant on nuclear fuel supplies coming out of Russia. In addition, sanctions on Russia, government restrictions, and restrictions on and cancellations of some cargo insurance coverage are creating transportation and further supply chain risks for fuel supplies coming out of Central Asia. Despite the recent increase in uranium prices, years of underinvestment in new capacity and the deepening geopolitical uncertainty has shifted risk from producers to utilities.

Supply and trade policy highlights

• |  | In November 2022, Cameco announced that the first pounds of uranium ore from the McArthur River mine had been milled and packaged at the Key Lake mill, marking the achievement of initial production as the facilities transition back into normal operations.

• |  | In early January 2022, Kazakhstan saw the most significant political instability since it became independent in 1991. The events resulted in a state of emergency being declared across the country. Order was restored in the second half of January, and the state of emergency was gradually lifted. In November 2022, President Tokayev was re-elected for a new 7-year term.

MANAGEMENT’S DISCUSSION AND ANALYSIS 13

• |  | Kazatomprom (KAP) announced in August 2022 its plan to produce 10% below its total Subsoil Use Contracts level in 2024. This plan was expected to result in increased production in Kazakhstan of about 5 million to 8 million pounds U3O8 compared to the current 20% reduction, bringing total expected annual uranium production to about 65 million pounds in 2024. KAP stated the decision was based on its contracting progress but that it may still face significant challenges to increase above current production levels due to the state of global supply chains. In January 2023, KAP’s operational update showed lower expected production in 2023 due to wellfield development, procurement and supply chain issues, resulting in forecasted production of between 53.3 million and 55.9 million pounds, compared to between 58.5 million and 59.8 million pounds previously.

• |  | KATCO, the joint venture between Orano Mining and KAP, was granted a new mining permit for a parcel of the Muyunkum uranium deposit bringing total estimated uranium reserves to about 120 million pounds U3O8. The full production level of about 10.4 million pounds U3O8 is planned for 2026 at the earliest.

• |  | Orano announced plans to increase its enrichment production capacity by 30%, which could involve an expansion of the Georges-Besse II plant located in Tricastin. The cost of the project is estimated at $970M (US) and could increase the capacity at its Georges Besse II plant to 11 million separative work units (SWU) from 7.5 million SWU.

• |  | GLE made progress with the first full-scale laser system module, successfully completing eight months of testing in Australia. The system, which was developed by Silex Systems Ltd for deployment in GLE’s commercial pilot demonstration facility has been delivered to GLE’s facility in the US. Additionally, GLE signed letters of intent (LOI) to collaborate with two major US utilities to help diversify a portion of the US nuclear fuel supply chain, including measures to support its deployment of laser enrichment technology in the US.

• |  | In June, Boss Energy Limited (Boss) finalized their decision to develop the Honeymoon Uranium Project in South Australia. Boss intends to accelerate construction and is projecting Honeymoon will have first production in the fourth quarter of 2023, ramping up to 2.45 million pounds U3O8 production per year within three years.

• |  | ConverDyn’s parent, Honeywell, is planning for a 2023 restart of its UF6 conversion facility.

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 drive investment in higher-cost sources of production, which due to lengthy development timelines, tend to miss the contracting cycle and ramp up after demand has already been won by proven producers. The new uncommitted supply exposed to the small, discretionary spot market puts downward pressure on price and can create the perception that uranium is abundant, potentially resulting in a failure of long-term price signals. When prices are declining and low, there is no perceived urgency to contract, and contracting activity and investment in new supply dramatically decreases. After years of low prices, and a lack of investment in supply, and as the uncommitted material available in the spot market begins to thin, security-of-supply tends to overtake price concerns. Utilities typically re-enter the long-term contracting market to ensure they have a reliable future supply of uranium to run their reactors.

14 CAMECO CORPORATION

UxC reports that over the last five years approximately 430 million pounds U3O8 equivalent have been locked-up in the long-term market, while approximately 775 million pounds U3O8 equivalent have been consumed in reactors. We remain confident that utilities have a growing gap to fill.

We believe the current backlog of long-term contracting presents a substantial opportunity for proven and reliable suppliers with tier-one productive capacity and a record of honoring supply commitments. As a low-cost producer, we manage our operations to increase value throughout these price cycles.

In our industry, customers do not come to the market right before they need to load nuclear fuel into their reactors. To operate a reactor that could run for more than 60 years, natural uranium and the downstream services have to be purchased years in advance, allowing time for a number of processing steps before a finished fuel bundle arrives at the power plant. At present, we believe there is a significant amount of uranium that needs to be contracted to keep reactors running into the next decade.

UxC estimates that cumulative uncovered requirements are about 2.3 billion pounds to the end of 2040. With the lack of investment over the past decade, there is growing uncertainty about where uranium will come from to satisfy growing demand, and utilities are becoming increasingly concerned about the availability of material to meet their long-term needs. In addition, secondary supplies have diminished, and the material available in the spot market has thinned as producers and financial funds continue to purchase material. Furthermore, the Russian invasion of Ukraine in February has given rise to a geopolitical realignment in energy markets that is causing some utilities to seek nuclear fuel suppliers whose values are aligned with their own or whose origin of supply better protects them from potential interruptions, including from transportation challenges or the possible imposition of formal sanctions.

MANAGEMENT’S DISCUSSION AND ANALYSIS 15

We will continue to take the actions we believe are necessary to position the company for long-term success. Therefore, we will continue to align our production decisions with our customers’ needs under our contract portfolio. We will undertake contracting activity which is intended to ensure we have adequate protection while maintaining exposure to the benefits that come from having uncommitted, low-cost supply to place into a strengthening market.

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2022 performance highlights

It was another positive year for the nuclear energy industry. Demand for nuclear power, including support for existing reactors, continues to grow, catalyzed by the increasing recognition by policy makers and major industries that nuclear energy must play an important role in achieving the objectives of providing clean, secure, reliable and affordable energy. Geopolitical unrest highlighted the importance of energy policy decisions on national security. With nuclear energy clearly back in durable growth mode, we are also back in durable growth mode. Growth that will be sought in the same manner as we approach all aspects of our business; strategic, deliberate, disciplined and responsible and with a focus on generating full-cycle value.

In our uranium segment, in 2022, we added 80 million pounds to our portfolio of long-term uranium contracts; about 58 million of which are finalized and 22 million accepted with key commercial terms, such as pricing mechanism, volume and tenor having been agreed to, but still awaiting contract finalization; and we have a large and growing pipeline of uranium business under discussion. Our focus continues to be on obtaining market-related pricing mechanisms, while also providing adequate downside protection. We continue to be strategically patient in our discussions to maximize value in our contract portfolio and to maintain exposure to higher prices with unencumbered future productive capacity. In addition, with strong demand in the UF6 conversion market, we were successful in adding long-term contracts that we expect will profitably underpin that operation for years to come. We finalized contracts for almost 12 million kgU of UF6 conversion in 2022 and have another almost 5 million kgU that have been accepted and are awaiting contract finalization.

In 2022, we operated at about 60% below the productive capacity (100% basis) in our uranium segment due to the impact of our planned supply discipline decisions, including to transition McArthur River/Key Lake back to production after five years on care and maintenance. Productive capacity includes licensed capacity at Cigar Lake of 18 million pounds (100% basis) per year and McArthur River/Key Lake of 25 million pounds (100% basis) per year, and it includes planned production volumes at Rabbit Lake and our US operations prior to curtailment in 2016. We produced 18 million pounds (100% basis) from the Cigar Lake mine and began the restart of production at our McArthur River mine and Key Lake mill, producing 1.1 million pounds (100% basis) in 2022. Through our investment in Inkai, we were impacted by the 20% supply reduction enacted by Kazatomprom (KAP) across all uranium mines in Kazakhstan and the continued supply chain challenges it has faced. Kazatomprom has the ability to flex production 20% above or below planned production levels (8.3 million to 12.5 million pounds per year). As well, delivery of our share of 2022 production from JV Inkai was delayed due to the challenges of transporting uranium via an alternate route that does not rely on Russian rail lines or ports. The first shipment, containing 2.6 million pounds of our share of Inkai’s 2022 production, arrived at a Canadian port in late December. A second shipment containing the majority of our remaining share of 2022 production is currently in transit.

We delivered over 25 million pounds of uranium and 11 million kgU in our fuel services segment to our customers in alignment with our contract portfolio and profitable opportunities in the market. We generated $305 million in cash from operations, with higher sales volumes in our uranium segment and higher average realized prices in both our uranium and fuel services segments than in 2021. With some delays in commissioning at the Key Lake mill, operational readiness costs were $169 million for the year and production from the mill was lower than originally anticipated. To meet our sales commitments and maintain a working inventory we purchased 18.3 million pounds of uranium at an average cost of $39.45 (US) per pound. While the unit cost of our purchases is significantly higher than the average production costs at Cigar Lake in 2022, the average cost was moderated by our ability to pull forward some of the long-term fixed-price purchase arrangements that were put in place in a much lower price environment. See 2022 financial results by segment – Uranium starting on page 57 for more information.

Thanks to the disciplined execution of our strategy, our balance sheet is strong, and we expect it will enable us to see out our strategy as well as self-manage risk, including from global macro-economic uncertainty and volatility. As of December 31, 2022, we had $2.3 billion in cash and cash equivalents and short-term investments with only $997 million in long-term debt. In addition, we have a $1.0 billion undrawn credit facility. The strength of our balance sheet allowed us to take advantage of two opportunities that we believe will add significant long-term value for Cameco.

In May 2022, we announced the acquisition of a greater share in the Cigar Lake mine for $107 million, increasing our ownership to 54.5% (from 50%). Cigar Lake is a proven, permitted and fully licensed tier-one mine in a safe and stable jurisdiction that we operate with the tremendous participation and support of our neighbouring Indigenous partner communities.

MANAGEMENT’S DISCUSSION AND ANALYSIS 17

In October 2022, we announced we had entered a strategic partnership with Brookfield Renewable Partners and its institutional partners (Brookfield Renewable) to acquire 100% of Westinghouse Electric Company (Westinghouse), a global provider of mission-critical and specialized technologies, products and services across most phases of the nuclear power sector. The acquisition is expected to close in the second half of 2023 and is subject to customary closing conditions and certain regulatory approvals. Once the transaction closes, Brookfield Renewable, will beneficially own a 51% interest in Westinghouse and we will beneficially own 49%. We believe bringing together our expertise in the nuclear industry with Brookfield Renewable’s expertise in clean energy positions nuclear power at the heart of the clean energy transition and creates a powerful platform for strategic growth across the nuclear sector.

The total enterprise purchase price for the acquisition is $7.875 billion (US), which includes an assumption of an estimated $3.4 billion (US) of debt which will remain with Westinghouse, and which is subject to customary purchase price adjustments. The remainder of the purchase price will be paid by approximately $4.5 billion (US) of aggregate cash contributions, our share of which will be approximately $2.2 billion (US). Following the announcement, we undertook a $650 million (US) bought deal offering of common shares, with an underwriter option to purchase additional shares. The offering closed on October 17, 2022, with gross proceeds to us of approximately $747.6 million (US), including the exercise in full of the underwriters’ option to purchase additional common shares. Net proceeds from the issuance were received in October 2022 and the US dollar cash and cash equivalents and short-term investments are included on our balance sheet. The final financing is not required until close of the acquisition and will be determined based on market conditions and the expected run rate of our business at that time. We expect a permanent financing mix of capital sources, including cash, debt and equity, designed to preserve our balance sheet and ratings strength, while maintaining healthy liquidity. See Proposed acquisition of Westinghouse beginning on page 89 for more information on the proposed acquisition.

With nuclear power’s clean emissions profile, reliable and secure baseload characteristics and low, levelized cost there was an intensified focus on preventing early reactor retirements, pursuing 10- and 20-year life extensions for the existing fleets in several countries, and the construction of new reactors, both traditional large-scale reactors and small and advanced nuclear reactors. 2022 brought further support for nuclear power as the Russian invasion of Ukraine deepened the energy crisis impacting many regions of the world and highlighted the need for energy security and affordability. Energy security concerns in regions such as Central and Eastern Europe have resulted in demand from new markets for Western nuclear fuel supplies. In addition, utilities globally are evaluating their sources of supply with a focus on origin. The increased nuclear fuel demand for Western supply of products and services, supply that established producers like we and like Westinghouse can offer, presents itself in the near, medium and long term.

Increased demand is occurring at a time when there is considerable growing uncertainty about nuclear fuel supplies. Macro uncertainty including the COVID-19 pandemic, supply chain disruptions, inflationary pressures and rapidly rising interest rates, and geopolitical unrest have accelerated this uncertainty. Low prices have led to supply concentration by origin, and a growing primary supply gap. Secondary supplies that have played a crucial role in our industry have been drawn out of the market. And, with the global nuclear industry reliant on Russian supplies for approximately 14% of uranium concentrates, 27% of conversion, and 39% of enrichment, utilities are now considering and planning for a variety of potential scenarios ranging from an abrupt end to Russian supplies to a gradual phase-out in nuclear fuel supply chains. As a result, we are seeing some utilities beginning to pivot towards procurement strategies that more carefully weigh the origin risk, and which supports producers with assets in geopolitically favourable jurisdictions.

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In the current environment, we believe the risk to uranium supply is greater than the risk to uranium demand and expect it will create a renewed focus on ensuring availability of long-term supply to fuel nuclear reactors. With the improvements in the market, the new long-term contracts we have put in place, and a pipeline of contracting discussions, we have decided to adjust our production plan for McArthur River/Key Lake to produce 18 million pounds per year (100% basis) starting in 2024, and we plan to continue to operate Cigar Lake at 18 million pounds per year (100% basis) in 2024. At Inkai, production will continue to follow the 20% reduction planned by KAP until the end of 2023. With annual licensed capacity of 25 million pounds at McArthur River/Key Lake, we continue to have the ability to expand production from our existing assets, however some additional investment would be required. If we took advantage of all of the tier-one expansion opportunities, our annual share of tier-one supply could be about 32 million pounds. However, any decision to expand production will be dependent on further improvements in the uranium market and our ability to secure the appropriate long-term contract homes for our unencumbered, in-ground inventory, demonstrating that we continue to responsibly manage our supply in accordance with our customers’ needs. In addition to our plans to expand uranium production, at our Port Hope UF6 conversion facility we are working on increasing annual production to 12,000 tonnes by 2024 to satisfy our book of long-term business and demand for conversion services, at a time when conversion prices are at historic highs. See Our vision, values and strategy starting on page 23 for more information.

We expect the investments we have and will continue to make in digital and automation technologies will allow us to operate our assets with more flexibility. This is key to our ability to continue to align our production decisions with our contract portfolio commitments and opportunities. With a solid base of contracts to underpin our productive capacity, and a growing contracting pipeline we are beginning to return to our tier-one cost structure, which we expect will significantly improve our financial performance.

As we execute on our strategy, we will continue to focus on protecting the health and safety of our employees, delivering our products safely and responsibly and addressing the ESG risks and opportunities that we believe will make our business sustainable and will build long-term value.

Financial performance

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2022 |  |  | 2021 |  |  | CHANGE |
Revenue |  |  | 1,868 |  |  |  | 1,475 |  |  |  | 27 | %
Gross profit |  |  | 233 |  |  |  | 2 |  |  |  | >100 | %
Net earnings (loss) attributable to equity holders |  |  | 89 |  |  |  | (103 | ) |  |  | >100 | %
$ per common share (diluted) |  |  | 0.22 |  |  |  | (0.26 | ) |  |  | >100 | %
Adjusted net earnings (loss) (non-IFRS, see page 40) |  |  | 135 |  |  |  | (98 | ) |  |  | >100 | %
$ per common share (adjusted and diluted) |  |  | 0.33 |  |  |  | (0.25 | ) |  |  | >100 | %
Cash provided by operations |  |  | 305 |  |  |  | 458 |  |  |  | (33 | )%

Net earnings attributable to equity holders (net earnings) and adjusted net earnings in 2022 significantly outperformed 2021 when we had a net loss for the year. See 2022 consolidated financial results beginning on page 39 for more information. Of note:

• |  | generated $305 million in cash from operations

• |  | incurred $218 million in care and maintenance costs and operational readiness costs as a result of our strategic decisions

Our segment updates and other fuel cycle investment updates

In our uranium segment, we continued to execute our strategy to preserve our tier-one assets which impacted our operations. Of note in 2022, we:

• |  | produced 18 million pounds (100% basis) at Cigar Lake and increased our ownership to 54.5%

• |  | began the restart of production at McArthur River/Key Lake, producing 1.1 million pounds (100% basis). Production was impacted by commissioning challenges at the mill.

• |  | maintained Rabbit Lake and US ISR operations on care and maintenance

• |  | purchased 18.3 million pounds of uranium, including our spot purchases, committed purchase volumes (including JV Inkai purchases), and advancing some long-term purchases

MANAGEMENT’S DISCUSSION AND ANALYSIS 19

• |  | delivered on our sales commitments of over 25 million pounds in alignment with our contract portfolio and profitable market opportunities

• |  | added a record number of contracts with 80 million pounds added to our portfolio (58 million pounds finalized and 22 million pounds accepted and awaiting contract finalization).

In 2022, in our fuel services segment, we:

• |  | produced 13.0 million kgU, which included an annual UF6 production record of over 10.6 million kgU

• |  | delivered 11.1 million kgU under contract

• |  | with UF6 conversion prices at historic highs, we finalized contracts for 12 million kgU as UF6 and have another almost 5 million kgU as UF6 that have been accepted, awaiting contract finalization.

See Operations and projects beginning on page 66 for more information.

Other investment updates from 2022:

• |  | GLE delivered the first full-scale laser system module to its facility in the US after successfully completing eight months of testing in Australia

• |  | In October, we announced the proposed acquisition of Westinghouse

See Global Laser Enrichment and Proposed acquisition of Westinghouse beginning on page 89 for more information.

HIGHLIGHTS |  |  |  | 2022 |  |  | 2021 |  |  | CHANGE |
Uranium |  | Production volume (million lbs) |  |  |  |  | 10.4 |  |  |  | 6.1 |  |  |  | 70 | %
|  | Sales volume (million lbs) |  |  |  |  | 25.6 |  |  |  | 24.3 |  |  |  | 5 | %
|  | Average realized price1 |  | ($US/lb) |  |  | 44.73 |  |  |  | 34.53 |  |  |  | 30 | %
|  |  |  | ($Cdn/lb) |  |  | 57.85 |  |  |  | 43.34 |  |  |  | 33 | %
|  | Revenue ($ millions) |  |  |  |  | 1,480 |  |  |  | 1,055 |  |  |  | 40 | %
|  | Gross profit (loss) ($ millions) |  |  |  |  | 121 |  |  |  | (108 | ) |  |  | >100 | %
Fuel services |  | Production volume (million kgU) |  |  |  |  | 13.0 |  |  |  | 12.1 |  |  |  | 7 | %
|  | Sales volume (million kgU) |  |  |  |  | 11.1 |  |  |  | 13.6 |  |  |  | (18 | )%
|  | Average realized price 2 |  | ($Cdn/kgU) |  |  | 32.92 |  |  |  | 29.72 |  |  |  | 11 | %
|  | Revenue ($ millions) |  |  |  |  | 365 |  |  |  | 404 |  |  |  | (10 | )%
|  | Gross profit ($ millions) |  |  |  |  | 117 |  |  |  | 118 |  |  |  | (1 | )%

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.

Also of note, subsequent update

As announced in February 2023, we have reached agreement on commercial terms for a major supply contract to provide sufficient volumes of natural uranium hexafluoride (UF6) (consisting of uranium and conversion services) to SE NNEGC Energoatom (Energoatom) to meet Ukraine’s full nuclear fuel needs through 2035. Key commercial terms, such as pricing mechanism, volume and tenor, have been agreed to, but the contract is subject to finalization, which is anticipated in the first quarter of 2023.

The agreement will run from 2024 through 2035 and contract amounts are subject to customary volume flexibility provisions commonly contained in supply agreements. Additionally, the agreement will contain a required degree of flexibility, given present circumstances in Ukraine. The agreement will be for 100% of Energoatom’s UF6 requirements (consisting of uranium and conversion services) for the nine nuclear reactors at its Rivne, Khmelnytskyy and South Ukraine nuclear power plants for the duration of the contract. These plants have combined requirements over the contract term of approximately 15.3 million KgU as UF6 (the equivalent of about 40.1 million pounds of uranium concentrate, or U3O8).

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The contract will also contain an option for us to supply up to 100% of the fuel requirements for the six reactors at the Zaporizhzhya nuclear power plant, currently under Russian control, should it return to Energoatom’s operation. If the option was exercised in 2024, the Zaporizhzhya plant would require roughly 10.4 million KgU as UF6 (the equivalent of approximately 27.2 million pounds of U3O8) over the contract period.

Industry prices

|  | 2022 |  |  | 2021 |  |  | CHANGE |
Uranium ($US/lb U3O8)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  | 49.81 |  |  |  | 35.28 |  |  |  | 41 | %
Average annual long-term price |  |  | 49.75 |  |  |  | 36.81 |  |  |  | 35 | %
Fuel services ($US/kgU as UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 31.96 |  |  |  | 19.41 |  |  |  | 65 | %
Europe |  |  | 31.96 |  |  |  | 18.99 |  |  |  | 68 | %
Average annual long-term price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 24.75 |  |  |  | 18.42 |  |  |  | 34 | %
Europe |  |  | 24.94 |  |  |  | 18.42 |  |  |  | 35 | %

Note: the industry does not publish UO2 prices.

1 | Average of prices reported by TradeTech and UxC, LLC (UxC)

On the spot market, where purchases call for delivery within one year, the volume reported by UxC for 2022 dropped significantly to 61 million pounds U3O8 equivalent, compared to 2021’s record breaking 102 million pounds U3O8 equivalent. Spot market volumes were significant in 2021 due to unplanned uranium demand from the Sprott Physical Uranium Trust, which contributed to the thinning of spot uranium supply. In 2022, total spot purchases by producers, junior uranium companies and financial funds was approximately 25 million pounds U3O8 equivalent, compared to approximately 53 million pounds U3O8 equivalent in 2021; these purchases in 2022 represented over 40% of spot market purchases compared to over 50% in 2021. At the end of 2022, the average reported spot price was $47.68 (US) per pound, up $5.63 (US) per pound from the end of 2021. During the year, the uranium spot price ranged from a month-end low of $43.08 (US) per pound to a month-end high of $58.20 (US) per pound, averaging $49.81 (US) for the year.

Long-term contracts generally call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including base-escalated prices set at time of contracting and escalated over the term of the contract, and market referenced prices (spot and long-term indicators) determined near the time of delivery. The volume of long-term contracting reported by UxC for 2022 was about 113 million pounds U3O8 equivalent, up from about 72 million pounds U3O8 equivalent in 2021. Higher volumes can be attributed in part to utilities turning their attention to securing their long-term needs as demand from financial funds further thinned the spot market and, in combination with higher interest rates, greatly reduced the ability for utilities to rely on carry trade activity, as well as heightened geopolitical tensions. The average reported long-term price at the end of the year was $52.00 (US) per pound, up $9.25 (US) from 2021. During the year, the uranium long-term price steadily increased from a month-end low of $42.88 (US) per pound in January to a high of $52.00 (US) per pound in November, averaging $49.75 (US) for the year.

With the Russian invasion of Ukraine in February 2022, conversion prices in both the North American and European markets set record highs. The average reported spot price for North American delivery at the end of 2022 was $40.00 (US) per kilogram uranium as UF6 (US/kgU as UF6), up $23.90 (US) from the end of 2021. Long-term UF6 conversion prices for North American delivery finished 2022 at $27.25 (US/kgU as UF6), up $9.25 (US) from the end of 2021.

MANAGEMENT’S DISCUSSION AND ANALYSIS 21

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Our vision, values and strategy

Our vision

Our vision – “Energizing a clean-air world” – recognizes that we have an important role to play in enabling the vast reductions in global GHG emissions required to achieve a resilient net-zero carbon economy. We support climate action that is consistent with the ambition of the Paris Agreement and the Canadian government’s commitment to the agreement to limit global temperature rise to less than 2°C and we believe that this means the world needs to reach net-zero emissions by 2050 or sooner. The uranium we produce is used around the world in the generation of safe, carbon-free, affordable, base-load nuclear power.

We believe we have the right strategy to achieve our vision and we will do so in a manner that reflects our values. For over 30 years, we have been delivering our products responsibly. Building on that strong foundation, we remain committed to our efforts to transform our own, already low, greenhouse gas footprint in our ambition to reach net-zero emissions, while identifying and addressing the ESG risks and opportunities that we believe may have a significant impact on our ability to add long-term value for our stakeholders.

Committed to our values

Our values are discussed below. They define who we are as a company and are at the core of everything we do and help to embed ESG principles and practices as we execute on our strategy in pursuit of our vision. They are:

• |  | safety and environment

• |  | 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 23

Our strategy

We are a pure-play investment in the growing demand for nuclear energy. We are focused on providing nuclear fuel products and services across the fuel cycle to support the generation of clean, reliable, secure and affordable energy, and we are focused on taking advantage of the long-term growth we see coming in our industry. Our strategy is set within the context of what we believe is a transitioning market environment, where increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are expected to durably strengthen the long-term fundamentals for our industry. Nuclear energy must be a central part of the solution to the world’s shift to a low-carbon, climate resilient economy. It is an option that can provide the power needed, not only reliably, but also safely and affordably, and in a way that will help avoid some of the worst consequences of climate change.

Our strategy is to capture full-cycle value by:

• |  | remaining disciplined in our contracting activity, building a balanced portfolio in accordance with our contracting framework

• |  | profitably producing from our tier-one assets and aligning our production decisions in all segments of our business with our contract portfolio and customer needs

• |  | being financially disciplined to allow us to execute on our strategy, take advantage of strategic opportunities and to self-manage risk

• |  | exploring other emerging and non-traditional opportunities within the fuel cycle, which align with our commitment to responsibly and sustainably manage our business, contribute to the mitigation of global climate change, and help to provide energy security and affordability

We expect our strategy will allow us to increase long-term value, and we will execute it with an emphasis on safety, people and the environment.

URANIUM

Uranium production is central to our strategy, as it is the biggest value driver of the nuclear fuel cycle and our business. We have tier-one assets that are licensed, permitted, long-lived, and are proven reliable with capacity to expand. These tier-one assets are backed up by idle tier-two assets and what we think is the best exploration portfolio that leverages existing infrastructure.

We are focused on protecting and extending the value of our contract portfolio, on aligning our production decisions with our contract portfolio and market opportunities thereby optimizing the value of our lowest cost assets. We also prioritize maintaining a strong balance sheet, and on efficiently managing the company. We have undertaken a number of deliberate and disciplined actions, including a focus on digitization and automation to allow us to operate our assets with more flexibility.

FUEL SERVICES

Our fuel services segment is a source of profit and supports our uranium segment, providing our customers with access to refining and conversion services for both heavy-water and light-water reactors, and CANDU fuel and reactor component manufacturing for heavy-water reactors.

As in our uranium segment, we are focused on securing new long-term contracts and on aligning our production decisions with our contract portfolio that will allow us to continue to profitably produce and consistently support the long-term needs of our customers.

In addition, we are pursuing non-traditional markets for our UO2 and fuel fabrication business and have been actively securing new contracts for reactor components to support refurbishment of Canadian reactors.

OTHER NUCLEAR FUEL CYCLE INVESTMENTS

We continue to explore other opportunities across the nuclear fuel cycle. Expanding our participation in the fuel cycle is expected to complement our tier-one uranium assets and fuel services, creating new revenue opportunities and enhancing our ability to meet the increasing needs of existing and new customers for secure, reliable nuclear fuel supplies and services.

24 CAMECO CORPORATION

In particular, we are interested in the second largest value driver of the fuel cycle, enrichment, and have a 49% interest in Global Laser Enrichment LLC (GLE). GLE is the exclusive licensee of the proprietary SILEX laser enrichment technology, a third-generation uranium enrichment technology. We are the commercial lead for the GLE project with a 49% interest and starting in 2023, an option to attain a majority interest of up to 75% ownership. See Global Laser Enrichment starting on page 89 for more information.

In addition, in October 2022, we announced the planned acquisition of a 49% interest in Westinghouse, a global provider of mission-critical and specialized technologies, products and services for light-water reactors across most phases of the nuclear power sector, in a strategic partnership with Brookfield Renewable. See Proposed acquisition of Westinghouse starting on page 89 for more information on Westinghouse.

Additionally, we have signed a number of non-binding arrangements to explore several areas of cooperation to advance the commercialization and deployment of small modular reactors in Canada and around the world.

BUILDING A BALANCED PORTFOLIO

The purpose of our contracting framework is to deliver value. Our approach is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that optimizes our realized price.

Contracting decisions in all segments of our business need to consider the nuclear fuel market structure, the nature of our competitors, and the current market environment. The vast majority of run-rate fuel requirements are procured under long-term contracts. The spot market is thinly-traded where utilities buy small, discretionary volumes. This market structure is reflective of the baseload nature of nuclear power and the relatively small proportion of the overall operating costs the fuel represents compared to other sources of baseload electricity. Additionally, about half of the fuel supply typically comes from diversified mining companies that produce uranium as a by-product, or by state-owned entities with production volume strategies or ambitions to serve state nuclear power ambitions with low-cost fuel supplies. We evaluate our strategy in the context of our market environment and continue to adjust our actions in accordance with our contracting framework:

• |  | First, we build a long-term contract portfolio by layering in volumes over time. In addition to our committed sales, we will compete for end-user demand in the market where we think we can obtain value and, in general, as part of longer-term contracts. We will take advantage of opportunities the market provides, where 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.

• |  | Once we have built a 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, this means 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 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 and pricing mechanisms that provide adequate protection when prices go down and exposure to rising prices. We believe using this framework will allow us to create long-term value. Our focus will continue to be on ensuring we have the financial capacity to execute on our strategy and self-manage risk.

MANAGEMENT’S DISCUSSION AND ANALYSIS 25

LONG-TERM CONTRACTING

Uranium is not traded in meaningful quantities on a commodity exchange. Utilities have historically bought the majority of their uranium and fuel services products under long-term contracts that are bilaterally negotiated with suppliers. The spot market is discretionary and typically used for one-time volumes, not to satisfy annual demand. We sell uranium and fuel products and services directly to nuclear utilities around the world as uranium concentrates, UO2 and UF6, conversion services, or fuel fabrication and reactor components for CANDU heavy water reactors. We have a solid portfolio of long-term sales contracts that reflect our reputation as a proven, reliable supplier of geographically stable supply, and the long-term relationships we have built with our customers.

In general, we are active in the market, buying and selling uranium when it is beneficial for us and in support of our long-term contract portfolio. We undertake activity in the spot and term markets prudently, looking at the prices and other business factors to decide whether it is appropriate to purchase or sell into the spot or term market. Not only is this activity a source of profit, but it also gives us insight into underlying market fundamentals.

We deliver the majority of our uranium under long-term contracts each year, some of which are tied to market-related pricing mechanisms quoted at time of delivery. Therefore, our net earnings and operating cash flows are affected by changes in the uranium price. Market prices are influenced by the fundamentals of supply and demand, market access and trade policy issues, geopolitical events, disruptions in planned supply and demand, and other market factors.

The objectives of our contracting strategy are to:

• |  | optimize realized price by balancing exposure to future market prices while providing some certainty for our 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 (price at time of acceptance escalated over the term): use a pricing mechanism based on a term-price indicator at the time the contract is accepted and escalated to time of each delivery over the term of the contract.

Market-related contracts for uranium: are different from base-escalated contracts in that the pricing mechanism may be based on either the spot price or the long-term price, and that price is as quoted at the time of delivery rather than at the time the contract is accepted. These contracts may provide for discounts, and typically include floor prices and/or ceiling prices, which are fixed at time of contract acceptance and usually escalate over the term of the contract.

Fuel services contracts: the majority of our fuel services contracts use a base-escalated mechanism per kgU and reflect the market at the time the contract is accepted.

OPTIMIZING OUR CONTRACT PORTFOLIO

We work with our customers to optimize the value of our contract portfolio. With respect to new contracting activity, there is often a lag from when contracting discussions begin and when contracts are executed. With our large pipeline of business under negotiation in our uranium segment, and a value driven strategy, we continue to be strategically patient in considering the commercial terms we are willing to accept. We layer in contracts over time, with higher commitments in the near term and declining over time in accordance with utilities growing uncovered requirements. Much of our pending business is off-market but we are starting to see more on-market activity emerge. We remain confident that we can add acceptable new sales commitments to our portfolio of long-term contracts to underpin the ongoing operation of our productive capacity and capture long-term value.

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Given our view that additional long-term supply will need to be incented to meet the growing demand for safe, clean, reliable, carbon-free nuclear energy, our preference today is to sign long-term contracts with market-related pricing mechanisms. Unsurprisingly, we believe our customers too expect prices to rise and prefer to lock-in today’s prices, with a fixed-price mechanism. Our goal is to balance all these factors, along with our desire for customer and regional diversification, with product form, and logistical factors to ensure we have adequate protection and will have exposure to rising market prices under our contract portfolio, while maintaining the benefits that come from having low-cost supply to deliver into a strengthening market.

With respect to our existing contracts, at times we may also look for opportunities to optimize the value of our portfolio. In cases where there is a changing policy, operating, or economic environment, we may consider options that allow us to maintain our customer relationships and are mutually beneficial.

CONTRACT PORTFOLIO STATUS

We have commitments to sell approximately 180 million pounds of U3O8 with 34 customers worldwide in our uranium segment, and over 55 million kilograms as UF6 conversion with 31 customers worldwide in our fuel services segment.

Customers – U3O8:

Five largest customers account for 56% of commitments

Customers – UF6 conversion:

Five largest customers account for 59% of commitments

MANAGEMENT’S DISCUSSION AND ANALYSIS 27

MANAGING OUR CONTRACT COMMITMENTS

We allow sales volumes to vary year-to-year depending on:

• |  | the level of sales commitments in our long-term contract portfolio

• |  | market opportunities

• |  | our sources of supply

To meet our delivery commitments and to mitigate risk, we have access to a number of sources of supply, which includes uranium obtained from:

• |  | our productive capacity

• |  | purchases under our JV Inkai agreement, under long-term agreements and in the spot market

• |  | our inventory in excess of our working requirements

• |  | product loans

OUR SUPPLY DISCIPLINE

As spot is not the fundamental market, true value is built under a long-term contract portfolio and is measured over the full commodity cycle. Therefore, we align our uranium production decisions with our contract commitments and market opportunities to avoid carrying excess inventory or having to sell into an oversupplied spot market. In accordance with market conditions, and to mitigate risk, we evaluate the optimal mix of our production, inventory and purchases in order to satisfy our contractual commitments and in order to realize the best return over the entire commodity cycle. During a prolonged period of uncertainty, this could mean leaving our uranium in the ground. For the years 2016 through 2022, we left more than 130 million pounds of uranium in the ground (100% basis) by curtailing our production. We purchased more than 60 million pounds including spot and long-term purchases and in 2018 we drew down our inventory by almost 20 million pounds. That totals over 210 million pounds (100% basis) of uranium that were not available to the market.

However, today we believe we are in the early stages of a uranium market transition, driven by the growing demand for nuclear energy and the increasingly undeniable conclusion that it is essential to the clean-energy transition and to energy security. In 2022 we secured 80 million pounds under long-term uranium contracts alone and as the market continues to transition, we expect to continue to place our uranium under long-term contracts and to meet rising demand with production from our best margin operations.

With the improvements in the market, the new long-term contracts we have put in place, and a pipeline of contracting discussions, we have decided to adjust our production plan for McArthur River/Key Lake to produce 18 million pounds (100% basis) starting in 2024, and we plan to continue to operate Cigar Lake at its licensed capacity of 18 million pounds per year (100% basis) in 2024. At Inkai, production will continue to follow the 20% reduction planned by KAP until the end of 2023.

With annual licensed capacity of 25 million pounds (100% basis) at McArthur River/Key Lake, we continue to have the ability to expand production from our existing assets, however some additional investment would be required. Any decision to expand production will be dependent on further improvements in the uranium market and our ability to secure the appropriate long-term contract homes for our unencumbered, in-ground inventory, demonstrating that we continue to responsibly manage our assets in accordance with our customers’ needs. In addition to our plans to expand uranium production, at our Port Hope UF6 conversion facility we are working on increasing production to 12,000 tonnes by 2024 to satisfy our book of long-term business for conversion services and customer demand, at a time when conversion prices are at historic highs.

Our adjusted production plans for McArthur River/Key Lake and Cigar Lake are expected to significantly improve our financial performance by allowing us to source more of our committed sales from the lower-cost produced pounds and we will no longer be required to expense care and maintenance or operational readiness costs related to McArthur River/Key Lake to cost of sales. In addition, with conversion demand elevated, we have been successful in securing long-term sales commitments that will support increased UF6 production at Port Hope, which is expected to further improve its contribution to our financial results. Over the course of 2023, we will undertake all of the activities necessary to ensure we are operationally ready to achieve the 2024 production plan. However, this is not an end to our supply discipline. We expect to continue to adjust our production in accordance with our contract portfolio. This will remain our production plan until we see further improvements in the uranium market and contracting progress, once again demonstrating that we are a responsible fuel supplier.

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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 2022 financial results by segment – Uranium starting on page 57 for more information. In 2023, our cash production costs may continue to be affected by inflation, the availability of personnel with the necessary skills and experience, supply chain challenges impacting the availability of materials and reagents, and our ability to ramp up to planned production at McArthur River/Key Lake.

Operating costs in our fuel services segment are mainly fixed. In 2022, labour accounted for about 51% of the total. The largest variable operating cost is for zirconium, followed by anhydrous hydrogen fluoride, and energy (natural gas and electricity).

We continue to look to adopt innovative and advanced digital and automation technologies to improve efficiency and operational flexibility, and to further reduce cost.

Care and maintenance costs

In 2023, we expect to incur between $50 million and $60 million in care and maintenance costs related to the suspension of production at our Rabbit Lake mine and mill, and our US operations. These operations are higher-cost and a restart is less certain. We continue to evaluate our options in order to minimize these costs.

Purchases and inventory costs

Our costs are also affected by the purchases of uranium and conversion services we make under long-term contracts and on the spot market.

To meet our delivery commitments, we make use of our mined production, inventories, purchases under long-term contracts, purchases we make on the spot market and product loans. In 2023, the price for the majority of our purchases will be quoted at the time of delivery.

The cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions. The cost of purchased material affects our cost of sales, which is determined by calculating the average of all of our sources of supply, including opening inventory, production, and purchases, and adding royalties, selling costs, and care and maintenance costs. Our cost of sales could be impacted if we do not achieve our annual production plan, or we are unable to source uranium as planned, and we are required to purchase uranium at prices that differ from our cost of inventory.

MANAGEMENT’S DISCUSSION AND ANALYSIS 29

Financial impact

The growing demand for nuclear power due to its safety, clean energy, reliability, security and affordability attributes has contributed to increased demand for nuclear fuel products and services. As a result, we have seen price increases across the nuclear fuel value chain, which reflect the need for capacity increases to satisfy the projected growth.

The deliberate and disciplined actions we took to curtail production and streamline operations over the past decade came with near-term costs like care and maintenance costs, operational readiness costs, and purchase costs higher than our production costs. However, we considered these costs as investments in our future.

Today, thanks to our investments, and with our continued ability to secure new long-term sales commitments we believe we are well-positioned for growth. Our core growth is expected to come from our existing tier-one mining and fuel services assets. We do not have to build new capacity to pursue new opportunities. We have sufficient productive capacity to expand, a position we have not enjoyed in previous price cycles.

And, with the planned joint acquisition of Westinghouse, we expect to be able to expand our growth profile by extending our reach in the nuclear fuel cycle at a time when there are tremendous tailwinds for the nuclear power industry. We are extending our reach with an investment in assets, that like ours, are strategic, proven, licensed and permitted, that are located in geopolitically favourable jurisdictions, and that we expect will be able to grow from their existing footprint. These assets are also expected to provide new opportunities for our existing suite of uranium and fuel services assets.

We believe our actions and investments have helped position the company to self-manage risk and as we make the transition back to a tier-one run rate, we expect our financial performance to significantly improve, allowing us to execute on our strategy while rewarding our stakeholders for their continued patience and support of our strategy to build long-term value.

CAPITAL ALLOCATION – FOCUS ON VALUE

Delivering long-term value is a top priority. While we navigate by our investment-grade rating, we continually evaluate our investment options to ensure we allocate our capital in a way that we believe will:

• |  | sustain our assets and grow our core business in a manner that we expect will create sustainable long-term value

• |  | 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 or, when appropriate, returned to shareholders, which requires good execution and disciplined allocation. Our decisions are based on the run rate of our business and other factors that we consider to be in the best interests of our stakeholders, not one-time events. Cash on our balance sheet that exceeds value-adding growth opportunities and/or is not needed to self-manage risk or for other reasons could be returned to shareholders.

We start by determining how much cash we have to invest (investable capital), which is based on our expected cash flow from operations minus expenses we consider to be a higher priority, such as dividends and financing costs, and could include others. This investable capital can be used to take advantage of new strategic opportunities in line with our corporate development objectives and long-term strategy, reinvested in the core business of the company including managing the physical and transition risks and opportunities associated with changing climate conditions, or returned to shareholders.

Reinvestment

We have a multidisciplinary capital allocation committee that evaluates possible uses of investable capital.

If a decision is made to reinvest capital in sustaining, capacity replacement, or growth, all opportunities are ranked and only those that meet the required risk-adjusted return criteria are considered for investment. We also must identify, at the corporate level, the expected impact on cash flow, earnings, and the balance sheet. All project risks must be identified, including the risks of not investing. Allocation of capital only occurs once an investment has cleared these hurdles.

This may result in some opportunities being held back in favour of higher return investments and should allow us to generate the best return on investment decisions when faced with multiple prospects, while also controlling our costs. If there are not enough good investment prospects internally or externally, this may result in residual investable capital, which we would then consider returning to shareholders.

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Return

We believe in returning cash to shareholders under appropriate circumstances but are also focused on protecting the company and rewarding those shareholders who understand and support our strategy to build long-term value. If we have excess cash and determine the best use is to return it to shareholders, we can do that through a share repurchase or dividend—an annual dividend, one-time supplemental dividend or a progressive dividend. The decision to return capital and the type of return is evaluated by our board of directors with careful consideration of our cash flow, financial position, strategy, and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

In Action

Until such time as we return to our tier-one cost structure, the objective of our capital allocation will be to ensure we have the financial capacity to execute on our strategy, including achieving production at McArthur River/Key Lake in accordance with our plan and the proposed acquisition of Westinghouse. We will continue to navigate by our investment-grade rating through close management of our balance sheet metrics, maintaining sufficient liquidity to meet our risk-mitigated working cash target and that allows us to pursue other value-adding opportunities.

As the market continues to transition, we will focus on improving operational effectiveness across our operations, including the use of digital and automation technologies with a particular goal of reducing operating costs and increasing operational flexibility. Any opportunities will be rigorously assessed by our capital allocation committee before an investment decision is made. We will invest to allow us to execute our 2024 production plan.

If we get clarity on our CRA dispute, which generates a one-time cash infusion, we may focus on the debt portion of our ratings metrics, depending on market opportunities. This may mean greater emphasis on reducing the debt on our balance sheet, including the additional debt contemplated with the proposed acquisition of Westinghouse. However, if we are able to continue increasing our portfolio of long-term contracts with acceptable pricing mechanisms, our priorities would be to invest in expanding production at our tier-one assets, and if warranted taking advantage of our existing tier-two assets and brownfield infrastructure, turning to value-adding growth opportunities including further investment in the nuclear fuel value chain and returning excess cash to shareholders.

Shares and stock options outstanding

At February 7, 2023, we had:

• |  | 432,717,980 common shares and one Class B share outstanding

• |  | 2,854,061 stock options outstanding, with exercise prices ranging from $11.32 to $19.30

As announced on October 17, 2022, our $747.6 million (US) bought deal offering of common shares closed. The offering, including the exercise, in full, of the underwriters’ option to purchase additional common shares, increased our outstanding shares by 34,057,250. See Proposed acquisition of Westinghouse beginning on page 89 for more information.

Dividend

In 2022, our board of directors declared a dividend of $0.12 per common share, which was paid December 15, 2022.

The decision to declare an annual dividend by our board is reviewed regularly and will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

MANAGEMENT’S DISCUSSION AND ANALYSIS 31

Our ESG principles and practices

A key part of our strategy, reflecting our values

We are committed to delivering our products responsibly. We integrate ESG principles and practices into every aspect of our business, from our corporate objectives and approach to compensation, to our overall corporate strategy, risk management, and day-to-day operations, and they align with our values. We seek to be transparent with our stakeholders, keeping them updated on the risks and opportunities that we believe may have a significant impact on our ability to achieve our strategic plan and add long-term value. We recognize the importance of integrating certain ESG factors, such as safety performance, a clean environment and supportive communities, into our executive compensation strategy as we see success in these areas as critical to the long-term success of the company.

Our board of directors holds the highest level of oversight for our business strategy and strategic risks, including ESG matters and climate-related risks. Oversight of ESG and climate-related reporting and disclosure has been delegated by the board to the Safety, Health and Environment (SHE) committee of the board. We also have a multi-disciplinary ESG steering committee, chaired by our senior vice-president and chief corporate officer that includes representatives from across the organization whose role is to review our ESG governance and reporting, and our current approach to sustainability, against evolving trends. Additional information about our governance of ESG matters is included in our most recent ESG report.

In an effort to continually evolve the robustness of our sustainability commitments and communications, starting in 2020, we aligned our ESG performance indicators with the ones recommended by the Sustainability Accounting Standards Board (SASB). In addition, we began addressing the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) in our ESG report. In 2022, we continued to progress our work, conducting a gap analysis to identify how we could better align to TCFD recommendations. Findings from this work identified the need to undertake scenario analysis (physical and transition) to develop a robust evidence base for our climate strategy and pursue opportunities to financially quantify identified climate-related risks and opportunities where possible. See the discussion below regarding our climate change scenario analysis for more information.

In July 2022, we published our 2021 ESG report. The report sets out our strategy and the policies and programs we use to govern and manage ESG issues that are important to our stakeholders. In addition to SASB and TCFD, the report provides key ESG performance indicator data based on the Global Reporting Initiative’s Sustainability Framework as well as some unique corporate indicators, to measure and report our performance on environmental, social and economic impacts in the areas we believe have a significant impact on our sustainability in the long-term and that are important to our stakeholders. This is our ESG report card to our stakeholders. You can find our report at cameco.com/about/sustainability.

ENVIRONMENT

We recognize and embrace our responsibility to manage our activities with care for the protection of environmental resources. Protection of the environment is one of our highest corporate priorities during all stages of our activities from exploration through development, operations, and decommissioning. Environmental stewardship is embedded in how we operate.

We are guided by our safety, health, environment and quality policy and associated programs that are designed to minimize our impact on air, land, and water and to conserve the biodiversity of surrounding ecosystems. Across our operations, we comply with strict regulations and have systems in place to monitor and mitigate our potential impacts. In addition to our own environmental monitoring, we collaborate with local communities in northern Saskatchewan around our operations to give confidence to them that traditionally harvested foods remain safe to eat, and water remains safe to drink.

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Climate change: Nuclear power is part of the solution

We recognize the critical nature of the fight against climate change, and want our employees, customers, investors, and community partners near our operations to know we are committed to being an active and constructive partner in addressing this challenge. The reduction of carbon and greenhouse gas (GHG) emissions is important and necessary in Canada and around the world. Nuclear power must be a central part of the solution to the world’s shift to a low-carbon, climate-resilient economy. As one of the world’s largest producers of the uranium needed to fuel nuclear reactors, we believe there is a significant opportunity for us to be part of the solution to combat climate change. We enable vast emissions reductions that can be achieved through nuclear power and are committed to transforming our already low GHG emissions footprint to achieve our ambition of having net-zero emissions while delivering significant long-term business value.

In accordance with our 2022 compensable corporate objectives, we undertook a planning process to outline our overarching low-carbon transition strategy. We identified the practical and achievable actions that we expect to take to decarbonize our operations and manage climate-related risks. In doing so, we are demonstrating our alignment with the ambitions of the Paris Agreement to, “limit global temperature rise to well below 2 degrees Celsius (°C), above pre-industrial levels, and to pursue efforts to limit global temperature rise even further to 1.5°C”. By extension, we are demonstrating our alignment with the Government of Canada’s commitment to the Paris Agreement in accordance with the Net Zero Accountability Act and resulting 2030 Emissions Reduction Plan.

We recognize that climate change, including shifts in temperature, precipitation and more frequent severe weather events could affect our operations in a range of possible ways. As part of our low-carbon transition planning, we completed a climate change scenario analysis to understand how projected long-term changing climate conditions could impact our employees, assets, and operations in northern Saskatchewan. We leveraged internal subject matter expertise with help from a third-party expert to complete the assessment.

The physical risk assessment study was undertaken to deliver an initial forward-looking physical climate risk assessment across our four sites in northern Saskatchewan and identify possible risk management and adaptation options. The next steps for the northern Saskatchewan physical risk assessment are to embed the physical climate risk findings into Cameco’s internal risk processes and develop an adaptation action plan for each site in the study. We are targeting the completion of similar assessments for all our majority owned and operated facilities over the next five years. In 2023, we will focus our physical climate risk assessment efforts on our Ontario operations.

We will continue to explore climate change projections for the areas where we operate and those critical to moving supplies and products through our value chain. We will use this information to identify where our existing climate-related acute and chronic risk management practices are expected to remain sufficient in the years to come and where adaptation and other enhancements may be required.

When it comes to climate change, we have tracked and reported our GHG emissions for more than two decades. A summary of our activities to understand and mitigate the risks associated with climate change scenarios is reported to the board of directors on a regular basis in accordance with our Enterprise Risk Management program, including the mitigating controls and management actions taken to reduce these risks.

In 2022, we developed the Energy and GHG Emissions Reductions Ideas Box that allows all employees to submit ideas to support us in reducing operational emissions. The Ideas Box also provides employees the opportunity to see key details from all decarbonization projects under investigation today.

We have also enjoyed some significant success in our efforts to reduce our energy use and GHG emissions to date. For example, at our Port Hope conversion facility, we have achieved a 28% reduction to peak power demand and more than $2.1 million in annual energy savings with projects such as HVAC and compressed air system upgrades and lighting efficiency retrofits. At our northern Saskatchewan mining and milling operations, recent efforts have focused on the implementation of an Energy Management Information System (EMIS) in alignment with our larger digital transformation efforts. The EMIS improves our ability to visualize, monitor, and manage our energy use and emissions profile in real time. Ultimately, EMIS gives those operations the ability to identify where our highest impact emissions reduction opportunities exist and assurance that the actions we have taken are maintained over time.

MANAGEMENT’S DISCUSSION AND ANALYSIS 33

Beyond these projects and initiatives, we have completed work to profile our emissions, enabling the identification of multiple high impact energy efficiency and emissions reductions opportunities including lighting retrofits, building envelope improvements, heat recovery projects, and the ability to explore alternative energy sources. Through these and other innovative decarbonization actions across efficiency, electrification, waste to value, carbon economy, and fuel switching themes – we expect to achieve a 30% absolute reduction from our total Scope 1 and 2 emissions level by 2030 from our 2015 baseline as our first major milestone on the journey to achieve our ambition of being net zero. For our Scope 2 emissions (purchased power), achieving this target will largely be dependent on the success of SaskPower in decarbonizing its grid in accordance with its current plans.

SOCIAL

Our relationships with our workforce, Indigenous Peoples, and local communities are fundamental to our success. The safety and protection of our workforce and the public is our top priority in our assessment of risk and planning for safe operations and product transport. To deliver on our vision, we invest in programs to attract and retain a diverse and skilled workforce that better reflects the communities in which we operate and to increase the participation of underrepresented groups in trades and technical positions. We want to build a workforce that is dedicated to continuous improvement and shares our values.

The importance of our workers and Indigenous Peoples working and living near our operations is exemplified by our ongoing commitment to help manage the impacts of the COVID-19 pandemic on our workforce, their families and their communities.

Our response to the COVID-19 pandemic

We continue to closely monitor and adapt to the developments related to COVID-19. Throughout the pandemic, our priority has been to protect the health and well-being of our workers, including employees and contractors, their families, and their communities.

The proactive decisions we made, and our ongoing efforts to monitor and manage the risk of COVID-19, to help ensure our workers are safe are consistent with our values. The health and safety of our workers, their families and their communities continues to be the priority in all our plans, which will align with the guidance of the relevant health authorities where we operate.

GOVERNANCE

We believe that sound governance is the foundation for strong corporate performance. Our diverse and independent board of directors’ primary role is to provide strategic direction and risk oversight in order to help the company achieve its vision of “energizing a clean-air world”. The board guides the company to operate as a sustainable business, to optimize financial returns while effectively managing risk, and to conduct business in a way that is transparent, independent, and ethical.

The board has formal governance guidelines that set out our approach to governance and the board’s governance role and practices. The guidelines ensure we comply with all of the applicable governance rules and legislation in Canada and the US, conduct ourselves in the best interests of our stakeholders, and meet industry best practices. The guidelines are reviewed and updated regularly.

Our corporate governance framework includes an established and recognized management system that describes the policies, processes and procedures we use to help us fulfill all the tasks required to achieve our objectives and strategy. It sets out our vision, values, and measures of success. It speaks to our strategic planning process, leadership alignment and accountability, compliance and assessment, people and culture, process identification and work management, risk management, communications and stakeholder support, knowledge and information management, change management, problem identification and resolution, and continual improvement.

Risk and Risk Management

Our board of directors oversees management’s implementation of appropriate risk management processes and controls. We have a Risk Policy that is supported by our formal Risk Management Program.

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Our Risk Management Program involves a broad, systematic approach to identifying, assessing, monitoring, reporting and managing the significant risks we face in our business and operations, including consideration of ESG and climate-related risks that could impact our four measures of success. The program is based on the ISO 31000 Risk Management guidelines. ISO 31000 provides guidance on risk management activities with internationally recognized practices and provides sound principles for effective management and governance of risks. Our program applies to all risks facing the company, including climate-related risks. The program establishes clear accountabilities for employees throughout the company to take ownership of risks specific to their area and to effectively manage those risks. The program is reviewed annually to ensure that it continues to meet our needs.

We use a common risk matrix throughout the company. Any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan is considered an enterprise risk and is brought to the attention of senior management and the board. We continually update our risk profile by performing regular monitoring of risks across the organization. Regular monitoring helps us to properly manage risks and identify any new risks. Detailed risk reporting is provided on a quarterly basis to senior management and the board and its committees on the status of the mitigating and/or monitoring plans for each of the enterprise risks. Management also reviews monthly updates on the company’s progress in managing these risks.

In addition to considering the other information in this MD&A, you should carefully consider the material risks discussed starting on page 4, under the heading Managing the risks, starting on page 67, and the specific risks discussed under each operation, advanced project, and other fuel cycle investment update in this document. These risks, however, are not a complete list of the potential risks our operations, advanced projects, or other investments face. There may be others we are not aware of or risks we feel are not material today that could become material in the future.

We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.

MANAGEMENT’S DISCUSSION AND ANALYSIS 35

Measuring our results

Targets and Metrics: The link between ESG factors and executive pay

Each year, we set corporate objectives that are aligned with our strategic plan. These objectives fall under our four measures of success: outstanding financial performance, safe, healthy and rewarding workplace, clean environment and supportive communities. Performance against specific targets under these objectives forms the foundation for a portion of annual employee and executive compensation. See our most recent management proxy circular for more information on how executive compensation is determined.

Our targets for 2022 continue to reflect the operational strategic actions that we have taken. While we saw a significant improvement in our financial performance (earnings and cash flow) as our tier-one production increases and our average realized price reflects the improving market, our results still do not reflect our expected long-term run rate performance. As our long-term contract portfolio continues to grow and our tier-one production continues to ramp up, we believe that the strategic actions we have taken have helped to pave the way to stronger financial performance over time. Additionally, we will not compromise our commitment to safety, people and our environment.

2022 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 above the target
SAFE, HEALTHY AND REWARDING WORKPLACE
Workplace safety measure |  | Strive for no injuries at all Cameco-operated sites. Maintain a long-term downward trend in combined employee and contractor total recordable injury rate while achieving targets on specified leading indicators. |  | •   we did not achieve our target for TRIR •   performance of the leading indicators was within the target range
CLEAN ENVIRONMENT
Environmental performance measures |  | Achieve divisional environmental aspect improvement targets. Complete initial planning to outline our overarching low-carbon transition strategy |  | •   performance on divisional environmental targets was below the targeted range •   Completed initial planning and identified the practical and achievable actions that we expect to take to reduce carbon emissions at our operations and manage climate-related risks
SUPPORTIVE COMMUNITIES
Stakeholder support measure |  | Enhance the skill set of Residents of Saskatchewan’s North (RSN) for changing industrial environments |  | •   a RSN work placement program was developed and implemented with 50% female participation with support from external agencies, achieving results above the target

1 | Detailed results for our 2022 corporate objectives and the related targets will be provided in our 2023 management proxy circular prior to our Annual Meeting of Shareholders on May 10, 2023.

36 CAMECO CORPORATION

2023 objectives

OUTSTANDING FINANCIAL PERFORMANCE

| • |  | Achieve targeted financial measures.

SAFE, HEALTHY AND REWARDING WORKPLACE

| • |  | Improve workplace safety performance at all sites.

CLEAN ENVIRONMENT

| • |  | Improve environmental performance at all sites.

SUPPORTIVE COMMUNITIES

| • |  | Build and sustain strong stakeholder support for our activities.

MANAGEMENT’S DISCUSSION AND ANALYSIS 37

Financial results

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

39 |  | 2022 CONSOLIDATED FINANCIAL RESULTS
48 |  | OUTLOOK FOR 2023
50 |  | LIQUIDITY AND CAPITAL RESOURCES
57 |  | 2022 FINANCIAL RESULTS BY SEGMENT
57 |  | URANIUM
59 |  | FUEL SERVICES
60 |  | FOURTH QUARTER FINANCIAL RESULTS
60 |  | CONSOLIDATED RESULTS
63 |  | URANIUM
64 |  | FUEL SERVICES

38 CAMECO CORPORATION

2022 consolidated financial results

In the second quarter of 2022, we along with Orano acquired Idemitsu Canada Resources Ltd.’s 7.875% participating interest in the Cigar Lake Joint Venture. Our ownership stake in Cigar Lake now stands at 54.547%, 4.522 percentage points higher than it was prior to the transaction. Effective May 19, 2022, we have reflected our share or production and financial results based on this new ownership stake.

HIGHLIGHTS |  |  |  |  |  |  |  | CHANGE FROM |
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2022 |  |  | 2021 |  |  | 2020 |  |  | 2021 TO 2022 |
Revenue |  |  | 1,868 |  |  |  | 1,475 |  |  |  | 1,800 |  |  |  | 27 | %
Gross profit |  |  | 233 |  |  |  | 2 |  |  |  | 106 |  |  |  | >100 | %
Net earnings (loss) attributable to equity holders |  |  | 89 |  |  |  | (103 | ) |  |  | (53 | ) |  |  | >100 | %
$ per common share (basic) |  |  | 0.22 |  |  |  | (0.26 | ) |  |  | (0.13 | ) |  |  | >100 | %
$ per common share (diluted) |  |  | 0.22 |  |  |  | (0.26 | ) |  |  | (0.13 | ) |  |  | >100 | %
Adjusted net earnings (loss) (non-IFRS, see page 40) |  |  | 135 |  |  |  | (98 | ) |  |  | (66 | ) |  |  | >100 | %
$ per common share (adjusted and diluted) |  |  | 0.33 |  |  |  | (0.25 | ) |  |  | (0.17 | ) |  |  | >100 | %
Cash provided by operations |  |  | 305 |  |  |  | 458 |  |  |  | 57 |  |  |  | (33 | )%

Net earnings

The following table shows what contributed to the change in net earnings in 2022 compared to 2021 and 2020.

($ MILLIONS) |  | 2022 |  |  | 2021 |  |  | 2020 |
Net earnings (losses) - previous year |  |  | (103 | ) |  |  | (53 | ) |  |  | 74 |
Change in gross profit by segment |  |  |  |  |  |  |  |  |  |  |  |
(we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |
Uranium |  | Impact from sales volume changes |  |  | (6 | ) |  |  | (4 | ) |  |  | (4 | )
|  | Higher realized prices ($US) |  |  | 328 |  |  |  | 5 |  |  |  | 25 |
|  | Foreign exchange impact on realized prices |  |  | 44 |  |  |  | (72 | ) |  |  | 14 |
|  | Higher costs |  |  | (137 | ) |  |  | (55 | ) |  |  | (169 | )
|  | change – uranium |  |  | 229 |  |  |  | (126 | ) |  |  | (134 | )
Fuel services |  | Impact from sales volume changes |  |  | (21 | ) |  |  | 1 |  |  |  | (4 | )
|  | Higher realized prices ($Cdn) |  |  | 33 |  |  |  | 23 |  |  |  | 21 |
|  | Higher costs |  |  | (13 | ) |  |  | (2 | ) |  |  | (10 | )
|  | change – fuel services |  |  | (1 | ) |  |  | 22 |  |  |  | 7 |
Other changes |  |  |  |  |  |  |  |  |  |  |  |
Lower (higher) administration expenditures |  |  | (44 | ) |  |  | 17 |  |  |  | (20 | )
Lower (higher) exploration expenditures |  |  | (3 | ) |  |  | 3 |  |  |  | 3 |
Change in reclamation provisions |  |  | (31 | ) |  |  | 32 |  |  |  | (21 | )
Change in gains or losses on derivatives |  |  | (86 | ) |  |  | (24 | ) |  |  | 5 |
Change in foreign exchange gains or losses |  |  | 74 |  |  |  | (14 | ) |  |  | 33 |
Change in earnings from equity-accounted investments |  |  | 26 |  |  |  | 32 |  |  |  | (9 | )
Redemption of Series E debentures in 2020 |  |  | — |  |  |  | 24 |  |  |  | (24 | )
Canadian Emergency Wage Subsidy |  |  | (21 | ) |  |  | (16 | ) |  |  | 37 |
Arbitration award in 2019 related to TEPCO contract |  |  | — |  |  |  | — |  |  |  | (52 | )
Bargain purchase gain on CLJV ownership interest increase |  |  | 23 |  |  |  | — |  |  |  | — |
Higher (lower) finance income |  |  | 30 |  |  |  | (4 | ) |  |  | (19 | )
Change in income tax recovery or expense |  |  | 3 |  |  |  | 15 |  |  |  | 47 |
Other |  |  | (7 | ) |  |  | (11 | ) |  |  | 20 |
Net earnings (losses) - current year |  |  | 89 |  |  |  | (103 | ) |  |  | (53 | )

MANAGEMENT’S DISCUSSION AND ANALYSIS 39

Non-IFRS measures

ADJUSTED NET EARNINGS

Adjusted net earnings (ANE) is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS financial measure). We use this measure as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is one of the targets that we measure to form the basis for a portion of annual employee and executive compensation (see 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 46 for more information.

We also adjust for changes to our reclamation provisions that flow directly through earnings. Every quarter we are required to update the reclamation provisions for all operations based on new cash flow estimates, discount and inflation rates. This normally results in an adjustment to our asset retirement obligation in addition to the provision balance. When the assets of an operation have been written off due to an impairment, as is the case with our Rabbit Lake and US ISR operations, the adjustment is recorded directly to the statement of earnings as “other operating expense (income)”. See note 16 of our annual financial statements for more information. This amount has been excluded from our ANE measure.

The bargain purchase gain that was recognized when we acquired our pro-rata share of Idemitsu Canada Resources Ltd.’s 7.875% participating interest in the Cigar Lake Joint Venture has also been removed in calculating ANE since it is non-cash, non-operating and outside of the normal course of our business. The gain was recorded in the statement of earnings as part of “other income (expense)”.

Adjusted net earnings is a non-IFRS financial measure and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

40 CAMECO CORPORATION

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2022, 2021 and 2020.

($ MILLIONS) |  | 2022 |  |  | 2021 |  |  | 2020 |
Net earnings (loss) attributable to equity holders |  |  | 89 |  |  |  | (103 | ) |  |  | (53 | )
Adjustments |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | 76 |  |  |  | 13 |  |  |  | (45 | )
Adjustments on other operating expense (income) |  |  | 26 |  |  |  | (8 | ) |  |  | 24 |
Adjustment to other income |  |  | (23 | ) |  |  | — |  |  |  | — |
Income taxes on adjustments |  |  | (33 | ) |  |  | — |  |  |  | 8 |
Adjusted net earnings (loss) |  |  | 135 |  |  |  | (98 | ) |  |  | (66 | )

The following table shows what contributed to the change in adjusted net earnings (non-IFRS measure, see above) in 2022 compared to the same period in 2021 and 2020.

($ MILLIONS) |  |  |  | 2022 |  |  | 2021 |  |  | 2020 |
Adjusted net earnings (losses) - previous year |  |  | (98 | ) |  |  | (66 | ) |  |  | 41 |
Change in gross profit by segment |  |  |  |  |  |  |  |  |  |  |  |
(we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |
Uranium |  | Impact from sales volume changes |  |  | (6 | ) |  |  | (4 | ) |  |  | (4 | )
|  | Higher realized prices ($US) |  |  | 328 |  |  |  | 5 |  |  |  | 25 |
|  | Foreign exchange impact on realized prices |  |  | 44 |  |  |  | (72 | ) |  |  | 14 |
|  | Higher costs |  |  | (137 | ) |  |  | (55 | ) |  |  | (169 | )
|  | change – uranium |  |  | 229 |  |  |  | (126 | ) |  |  | (134 | )
Fuel services |  | Impact from sales volume changes |  |  | (21 | ) |  |  | 1 |  |  |  | (4 | )
|  | Higher realized prices ($Cdn) |  |  | 33 |  |  |  | 23 |  |  |  | 21 |
|  | Higher costs |  |  | (13 | ) |  |  | (2 | ) |  |  | (10 | )
|  | change – fuel services |  |  | (1 | ) |  |  | 22 |  |  |  | 7 |
Other changes |  |  |  |  |  |  |  |  |  |  |  |
Lower (higher) administration expenditures |  |  | (44 | ) |  |  | 17 |  |  |  | (20 | )
Lower (higher) exploration expenditures |  |  | (3 | ) |  |  | 3 |  |  |  | 3 |
Change in reclamation provisions |  |  | 3 |  |  |  | — |  |  |  | — |
Change in gains or losses on derivatives |  |  | (23 | ) |  |  | 34 |  |  |  | 9 |
Change in foreign exchange gains or losses |  |  | 74 |  |  |  | (14 | ) |  |  | 33 |
Change in earnings from equity-accounted investments |  |  | 26 |  |  |  | 32 |  |  |  | (9 | )
Redemption of Series E debentures in 2020 |  |  | — |  |  |  | 24 |  |  |  | (24 | )
Canadian Emergency Wage Subsidy |  |  | (21 | ) |  |  | (16 | ) |  |  | 37 |
Arbitration award in 2019 related to TEPCO contract |  |  | — |  |  |  | — |  |  |  | (52 | )
Higher (lower) finance income |  |  | 30 |  |  |  | (4 | ) |  |  | (19 | )
Change in income tax recovery or expense |  |  | (30 | ) |  |  | 7 |  |  |  | 42 |
Other |  |  | (7 | ) |  |  | (11 | ) |  |  | 20 |
Adjusted net earnings (losses) - current year |  |  | 135 |  |  |  | (98 | ) |  |  | (66 | )

Average realized prices

|  |  |  |  |  |  |  |  |  |  |  |  | CHANGE FROM
|  | 2022 |  |  | 2021 |  |  | 2020 |  |  | 2021 TO 2022
Uranium1 |  | $US/lb |  |  | 44.73 |  |  |  | 34.53 |  |  |  | 34.39 |  |  | 30%
|  | $Cdn/lb |  |  | 57.85 |  |  |  | 43.34 |  |  |  | 46.13 |  |  | 33%
Fuel services |  | $Cdn/kgU |  |  | 32.92 |  |  |  | 29.72 |  |  |  | 27.89 |  |  | 11%

1 | Average realized foreign exchange rate ($US/$Cdn): 2022 – 1.29, 2021 – 1.26 and 2020 – 1.34.

MANAGEMENT’S DISCUSSION AND ANALYSIS 41

Revenue

The following table shows what contributed to the change in revenue for 2022.

($ MILLIONS) |  |  |
Revenue – 2021 |  |  | 1,475 |
Uranium |  |  |  |
Higher sales volume |  |  | 53 |
Higher realized prices ($Cdn) |  |  | 372 |
Fuel services |  |  |  |
Lower sales volume |  |  | (72 | )
Higher realized prices ($Cdn) |  |  | 33 |
Other |  |  | 7 |
Revenue – 2022 |  |  | 1,868 |

See 2022 Financial results by segment on page 57 for more detailed discussion.

THREE-YEAR TREND

In 2021, revenue decreased by 18% compared to 2020 due to a decrease in sales volume in the uranium segment and a decrease in the Canadian dollar average realized price. In our fuel services segment, revenue increased by 10% as a result of the increase in average realized price and sales volume.

In 2022, revenue increased by 27% compared to 2021 due to an increase in the average realized price and sales volume in the uranium segment. In our fuel services segment, revenue decreased by 10% as a result of a decrease in sales volume partially offset by an increase in average realized price. See notes 18 and 29 in our annual financial statements for more information.

SALES DELIVERY OUTLOOK FOR 2023

For 2023 we have committed sales volumes in our uranium segment of between 29 and 31 million pounds. In general, we are active in the market, buying and selling uranium when it is beneficial for us and in support of our long-term contract portfolio.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly. We expect the quarterly distribution of uranium deliveries in 2023 to be more heavily weighted to the first and fourth quarters as shown below. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.

42 CAMECO CORPORATION

Corporate expenses

ADMINISTRATION

($ MILLIONS) |  | 2022 |  |  | 2021 |  |  | CHANGE |
Direct administration1 |  |  | 143 |  |  |  | 111 |  |  |  | 29 | %
Stock-based compensation1 |  |  | 25 |  |  |  | 44 |  |  |  | (43 | )%
Reversal (recovery) of fees related to CRA dispute |  |  | 4 |  |  |  | (27 | ) |  |  | 115 | %
Total administration |  |  | 172 |  |  |  | 128 |  |  |  | 34 | %

1 | Direct administration and stock-based compensation are supplementary financial measures. They are components of administration expense as shown on the statement of earnings and calculated according to IFRS.

Direct administration costs in 2022 were $32 million higher than in 2021 largely due to costs related to digital initiatives. Increased activities associated with the restart of operations at McArthur River and Key Lake, increased business travel and work associated with other business activities also resulted in increased costs.

We recorded $25 million in stock-based compensation expenses in 2022, $19 million lower compared to 2021 due primarily to a reduction in the expense related to the executive performance share units as a result of a change in assumptions for vesting criteria. See note 25 to the financial statements.

In 2021, we recorded $27 million as a reduction to administration costs to reflect the amounts owing to us for the recovery of costs as was awarded to us on the successful outcome in our transfer pricing dispute with Canada Revenue Agency (CRA). In 2022, we adjusted this amount by $4 million to reflect the actual recovery for costs. See Transfer pricing dispute on page 44 for more information.

Administration outlook for 2023

We expect direct administration costs to be between $160 million to $170 million.

EXPLORATION

Our 2022 exploration activities were focused primarily on Canada. Our spending increased from $8 million in 2021 to $11 million in 2022 reflects higher planned expenditures.

Exploration outlook for 2023

We expect exploration expenses to be about $18 million in 2023. The focus for 2023 will be on our core projects in Saskatchewan.

FINANCE COSTS

Finance costs were $86 million, an increase from $77 million in 2021 due to higher costs related to the unwinding of the discount on our reclamation provisions. See note 20 to the financial statements.

FINANCE INCOME

Finance income was $37 million compared to $7 million in 2021 mainly due to higher interest rates and higher balances for cash and cash equivalents and short-term investments in 2022.

GAINS AND LOSSES ON DERIVATIVES

In 2022, we recorded $73 million in losses on our derivatives compared to $13 million in gains in 2021. The increased losses reflect a weaker Canadian dollar compared to the US dollar in 2022 compared to 2021. See Foreign exchange on page 46 and note 27 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $4 million in 2022 compared to a recovery of $1 million in 2021 as a result of an income tax recovery in Canada that was offset by an expense in foreign jurisdictions. Equity accounted investees are included in Canadian earnings net of tax paid in the jurisdiction in which they operate. Foreign earnings include losses in some jurisdictions for which no future tax benefit has been recognized.

In 2022, we recorded earnings of $100 million in Canada compared to earnings of $59 million in 2021, while in foreign jurisdictions, we recorded a loss of $15 million compared to a loss of $162 million in 2021.

MANAGEMENT’S DISCUSSION AND ANALYSIS 43

($ MILLIONS) |  | 2022 |  |  | 2021 |
Net earnings (loss) before income taxes |  |  |  |  |  |  |  |
Canada |  |  | 100 |  |  |  | 59 |
Foreign |  |  | (15 | ) |  |  | (162 | )
Total net earnings (loss) before income taxes |  |  | 85 |  |  |  | (103 | )
Income tax expense (recovery) |  |  |  |  |  |  |  |
Canada |  |  | (8 | ) |  |  | (2 | )
Foreign |  |  | 4 |  |  |  | 1 |
Total income tax recovery |  |  | (4 | ) |  |  | (1 | )
Effective tax rate |  |  | (5 | )% |  |  | 1 | %

TRANSFER PRICING DISPUTE

Background

Since 2008, CRA has disputed our marketing and trading structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements.

For the years 2003 to 2014, CRA shifted Cameco Europe Limited’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2011, transfer pricing penalties. In addition, for 2014 to 2016, CRA has advanced an alternate reassessing position, see Reassessments, remittance and next steps below for more information.

In September 2018, the Tax Court of Canada (Tax Court) ruled that our marketing and trading structure involving foreign subsidiaries, as well as the related transfer pricing methodology used for certain intercompany uranium sales and purchasing agreements, were in full compliance with Canadian law for the tax years in question (2003, 2005 and 2006). On June 26, 2020 the Federal Court of Appeal (Court of Appeal) upheld the Tax Court’s decision.

On February 18, 2021, the Supreme Court of Canada (Supreme Court) dismissed CRA’s application for leave to appeal the June 26, 2020 decision of the Court of Appeal. The dismissal means that the dispute for the 2003, 2005 and 2006 tax years is fully and finally resolved in our favour. Although not technically binding, there is nothing in the reasoning of the lower court decisions that should result in a different outcome for the 2007 through 2014 tax years, which were reassessed on the same basis.

Refund and cost award

The Minister of National Revenue issued new reassessments for the 2003 through 2006 tax years in accordance with the decision and in July 2021, refunded the tax paid for those years. Pursuant to a cost award from the courts, we are expecting a payment of approximately $13 million for disbursements which is in addition to the $10 million we received from CRA in April 2021 as reimbursement for legal fees.

Reassessments, remittances and next steps

The Canadian income tax rules include provisions that generally require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. While we have received a refund for the amounts remitted for the 2003 through 2006 reassessments as noted above, CRA continues to hold $778 million ($295 million in cash and $483 million in letters of credit) we paid or secured for the years 2007 through 2013. For the 2014 and 2015 reassessments, CRA did not require additional security to secure the tax debts they considered owing. We have requested the same treatment with respect to the 2016 reassessment.

Following the Supreme Court’s dismissal of CRA’s application for leave to appeal, we wrote to CRA requesting reversal of CRA’s transfer pricing adjustments for 2007 through 2013 and the return of our $778 million in cash and letters of credit. Given the strength of the court decisions received, our request was made on the basis that the Tax Court would reject any attempt by CRA to defend its reassessments for the 2007 through 2013 tax years applying the same or similar positions already denied for previous years. Due to a lack of significant progress in response to our request, in October 2021, we filed a notice of appeal with the Tax Court for the years 2007 through 2013. We are asking the Tax Court to order the reversal of the CRA’s transfer pricing adjustment for those years and the return of our cash and letters of credit, with costs.

44 CAMECO CORPORATION

In 2020, CRA advanced an alternate reassessing position for the 2014 tax year in the event the basis for its original reassessment, noted above, is unsuccessful. Subsequent to this, in 2021, we received a reassessment for the 2015 tax year and in late 2022, we received a reassessment for the 2016 tax year, both using this alternative reassessing position. The new basis of reassessment is inconsistent with the methodology CRA has pursued for prior years and we are disputing it separately. Our view is that this alternate methodology will not result in a materially different outcome from our 2014 to 2016 filing positions. On October 12, 2022, we filed an appeal with the Tax Court for the years 2014 and 2015, and plan to file a notice of objection for 2016.

We will not be in a position to determine the definitive outcome of this dispute for any tax year other than 2003 through 2006 until such time as all reassessments have been issued advancing CRA’s arguments and final resolution is reached for that tax year. CRA may also advance alternative reassessment methodologies for years other than 2003 through 2006, such as the alternative reassessing position advanced for 2014 through 2016.

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

This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

Assumptions

| • |  | our entitlement and ability to receive the expected refunds and payments from CRA

| • |  | the courts will reach consistent decisions for subsequent tax years that are based on similar positions and arguments

| • |  | CRA will not successfully advance different positions and arguments that may lead to a different outcome for other tax years

Material risks that could cause actual results to differ materially

| • |  | we will not receive the expected refunds and payments from CRA

| • |  | the possibility the courts may accept the same, similar or different positions and arguments advanced by CRA to reach decisions that are adverse to us for other tax years

| • |  | the possibility that we will not be successful in eliminating all double taxation

| • |  | the possibility that CRA does not agree that the court decisions for the years that have been resolved in Cameco’s favour should apply to subsequent tax years

| • |  | the possibility CRA will not return all or substantially all of the cash and security that has been paid or otherwise secured by Cameco in a timely manner, or at all

| • |  | the possibility of a materially different outcome in disputes for other tax years

| • |  | an unfavourable determination of the officer of the Tax Court of the amount of our disbursements award

Tax outlook for 2023

Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. Since 2017, our global marketing organization has been mainly consolidated in Canada in order to achieve efficiencies, resulting in more income earned in Canada. In addition, equity accounted investees are included in Canadian earnings net of tax paid in the jurisdiction in which they operate. We continue to expect our consolidated tax rate will trend toward the Canadian statutory rate in the longer term.

The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and differences between accounting earnings and income for tax purposes. In addition, the Organization for Economic Co-operation and Development has proposed the introduction of rules that would impose a global minimum tax rate of 15%. The European Union has unanimously agreed to implement these rules and impose them into each country’s national law by the end of 2023, and we expect Canada to follow suit. If these tax laws are enacted or substantively enacted in any jurisdiction in which we operate, we may be subject to a minimum rate of 15% in that jurisdiction.

MANAGEMENT’S DISCUSSION AND ANALYSIS 45

FOREIGN EXCHANGE

The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments.

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

Our risk management policy is based on a 60-month period and permits us to hedge 35% to 100% of our expected net exposure in the first 12-month period. Our normal practice is to layer in hedge contracts over a three- to four-year period with the hedge percentage being highest in the first 12 months and decreasing hedge percentages in subsequent years. The portion of our net exposure that remains unhedged is subject to prevailing market exchange rates for the period. Therefore, our results are affected by the movements in the exchange rate on our hedge portfolio (explained below), and on the unhedged portion of our net exposure. A weakening Canadian dollar would have a positive effect on the unhedged exposure, and a strengthening Canadian dollar would have a negative effect.

Impact of hedging on IFRS earnings

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

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

Impact of hedging on ANE

We designate contracts for use in particular periods, based on our expected net exposure in that period. Hedge contracts are layered in over time based on this expected net exposure. The result is that our current hedge portfolio is made up of a number of contracts which are currently designated to net exposures we expect in 2023 and future years and we will recognize the gains or losses in ANE in those periods.

For the purposes of ANE, gains and losses on derivatives are reported based on the difference between the effective hedge rate of the contracts designated for use in the particular period and the exchange rate at the time of settlement. This results in an adjustment to current period IFRS earnings to effectively remove reported gains or losses on derivatives that arise from contracts put in place for use in future periods. The effective hedge rate will lag the market in periods of rapid currency movement. See Non-IFRS measures on page 40.

The table below provides a summary of our hedge portfolio at December 31, 2022. You can use this information to estimate the expected gains or losses on derivatives for 2023 on an ANE basis. However, due to the uncertainty around timing of closing of the proposed Westinghouse acquisition, we have not included the associated debt financing and cash outflows as part of the net US exposure for 2023, however our current USD cash position (which includes the equity issuance proceeds) is included. Additionally, if we add contracts to the portfolio that are designated for use in 2023 or if there are changes in the US/Cdn exchange rates in the year, those expected gains or losses could change.

46 CAMECO CORPORATION

Hedge portfolio summary

DECEMBER 31, 2022 |  |  |  |  |  |  |  | AFTER |  |  |  |
($ MILLIONS) |  |  |  |  | 2023 |  |  | 2023 |  |  | TOTAL |
US dollar forward contracts |  |  | ($ millions | ) |  |  | 330 |  |  |  | 710 |  |  |  | 1,040 |
Average contract rate 1 |  |  | (US/Cdn dollar | ) |  |  | 1.29 |  |  |  | 1.31 |  |  |  | 1.30 |
US dollar option contracts |  |  | ($ millions | ) |  |  | 60 |  |  |  | 10 |  |  |  | 70 |
Average contract rate range1 |  |  | (US/Cdn dollar | ) |  |  | 1.32 to 1.36 |  |  |  | 1.20 to 1.24 |  |  |  | 1.30 to 1.34 |
Total US dollar hedge contracts |  |  | ($ millions | ) |  |  | 390 |  |  |  | 720 |  |  |  | 1,110 |
Average hedge rate range |  |  | (US/Cdn dollar | ) |  |  | 1.29 to 1.30 |  |  |  | 1.31 |  |  |  | 1.30 |
Hedge ratio2,3 |  |  |  |  |  |  | 21 | % |  |  | 13 | % |  |  | 19 | %

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.

3 | Due to the uncertainty around timing of closing of the proposed Westinghouse acquisition, our hedge ratio is below our minimum as we have not included the financing or closing costs as part of the net US exposure.

At December 31, 2022:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.36 (Cdn), up from $1.00 (US) for $1.26 (Cdn) at December 31, 2021. The exchange rate averaged $1.00 (US) for $1.30 (Cdn) over the year.

• |  | The mark-to-market position on all foreign exchange contracts was a $48 million loss compared to a $28 million gain at December 31, 2021. The mark-to-market position is a component of gain on derivatives as shown on the statement of earnings and calculated in accordance with IFRS.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2022, all of our hedging counterparties had a Standard & Poor’s (S&P) credit rating of A or better.

For information on the impact of foreign exchange on our intercompany balances, see note 27 to the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 47

Outlook for 2023

Our outlook for 2023 is beginning to reflect the transition of our cost structure back to a tier-one run rate, as we plan our production to satisfy the growing long-term commitments under our contract portfolio. With our plan to produce 18 million pounds per year (100% basis) at Cigar Lake, 18 million pounds per year (100% basis) at McArthur River/Key Lake beginning in 2024, and increase UF6 production at our Port Hope conversion facility, we expect to see continued improvement in our financial performance.

From a cash perspective, we expect to generate strong cash flows. The amount of cash generated will be dependent on the timing and volume of production and the timing and magnitude of our purchasing activity. Therefore, our cash balances may fluctuate throughout the year.

As in prior years, we will incur care and maintenance costs for the ongoing curtailment of our tier-two assets, which are expected to be between $50 million and $60 million.

2022 outlook compared to actual

Our actual results were largely in-line with the outlook provided in our third quarter MD&A. In 2022 we announced the restart of McArthur River/Key Lake. Throughout 2022, the operations transitioned to production. Based on the restart schedule, we set a production target for up to 1.4 million pounds (our share) for McArthur River/Key Lake. We achieved 0.8 million pounds (our share) production at McArthur River/Key Lake as we worked through some normal commissioning issues at the mill. At Cigar Lake, we achieved 9.6 million pounds production (our share), in line with expectations.

As a result of the lower production from McArthur River/Key Lake and deferral and uncertainty related to the timing of receipt of our deliveries from JV Inkai, additional purchases were made.

Capital expenditures for 2022 were $143 million, lower than our outlook of $150 to $175 million, as a result of the deferral of project work to 2023.

See 2022 Financial results by segment on page 57 for details.

2023 Financial outlook

|  | CONSOLIDATED |  |  | URANIUM |  |  | FUEL SERVICES |
Production (owned and operated properties) |  |  | — |  |  |  | 20.3 million lbs |  |  |  | 13 to 14 million kgU |
Purchases |  |  | — |  |  |  | 9 to 11 million lbs |  |  |  | — |
Sales/delivery volume |  |  | — |  |  |  | 29 to 31 million lbs |  |  |  | 11.5 to 12.5 million kgU |
Revenue |  |  | $2,120 to 2,270 million |  |  |  | $1,730 to 1,820 million |  |  |  | $390-420 million |
Average realized price |  |  | — |  |  |  | $58.90/lb |  |  |  | — |
Average unit cost of sales (including D&A) |  |  | — |  |  |  | $46.00-47.00/lb | 1 |  |  | $23.50-24.50/kgU | 2
Direct administration costs |  |  | $160-170 million |  |  |  | — |  |  |  | — |
Exploration costs |  |  | — |  |  |  | $18 million |  |  |  | — |
Capital expenditures |  |  | $150-175 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.

We do not provide an outlook for the items in the table that are marked with a dash.

The following assumptions were used to prepare the outlook in the table above:

| • |  | Production – we achieve 20.3 million pounds of production (our share) in our uranium segment. If we do not achieve 20.3 million pounds, the outlook for the uranium segment could vary.

48 CAMECO CORPORATION

| • |  | Purchases – are based on the volumes we currently have commitments to acquire under contract in 2023, including our JV Inkai purchases, and it includes additional volumes we are required to purchase in order to meet the sales/delivery commitments we have under contract in 2023 and maintain a working inventory. It does not include any purchases that we may make as a result of the impact of any delays or disruptions to production for any reason, including disruptions caused by supply chain or transportation issues, or other challenges.

| • |  | Our 2023 outlook for sales/delivery volume does not include sales between our uranium and fuel services segments.

| • |  | Sales/delivery volume is based on the volumes we currently have commitments to deliver under contract in 2023.

| • |  | Uranium revenue and average realized price are based on a uranium spot price of $47.75 (US) per pound (the UxC spot price on December 26, 2022), a long-term price indicator of $51.00 (US) per pound (the UxC long-term indicator on December 26, 2022) and an exchange rate of $1.00 (US) for $1.30 (Cdn)

| • |  | Uranium average unit cost of sales (including D&A) is based on the expected unit cost of sales for produced material, the planned purchases noted in the outlook at an anticipated average purchase price of about $56.20 (Cdn) per pound and includes care and maintenance costs of between $50 million and $60 million. We expect overall unit cost of sales could vary if there are changes in production and purchase volumes or the mix between spot and long-term purchases, uranium spot prices, and/or care and maintenance costs in 2023.

Our 2023 financial outlook is presented on the basis of equity accounting for our minority ownership interest in JV Inkai. Under equity accounting, our share of the profits earned by JV Inkai on the sale of its production will be included in “income from equity-accounted investees” on our consolidated statement of earnings. Our share of production will be purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures. Please see Inkai Planning for the future on pages 79 and 80 for more details.

The following table shows how changes in the exchange rate or uranium prices can impact our outlook. We currently are holding excess USD, largely from the proceeds of the October 2022 share issuance, to partially finance the proposed acquisition of Westinghouse, as such our adjusted net earnings will have a higher sensitivity to exchange rate movements. For more details on the impact of exchange rates, also see Foreign exchange on page 46.

|  |  |  | IMPACT ON: |
FOR 2023 ($ MILLIONS) |  | CHANGE |  | REVENUE |  |  | ANE |  |  | CASH FLOW |
Uranium spot and long-term price1 |  | $5(US)/lb increase |  |  | 63 |  |  |  | 41 |  |  |  | 8 |
| $5(US)/lb decrease |  |  | (77 | ) |  |  | (51 | ) |  |  | (21 | )
Value of Canadian dollar vs US dollar |  | One cent decrease in CAD |  |  | 15 |  |  |  | 14 |  |  |  | 7 |
| One cent increase in CAD |  |  | (15 | ) |  |  | (14 | ) |  |  | (7 | )

1 | Assuming change both UxC spot price $47.75 (US) per pound on December 26, 2022 and the UxC long-term price indicator $51.00 (US) per pound on December 26, 2022.

Price sensitivity analysis: uranium segment

As discussed under the Long-term contracting section on page 26, our portfolio of long-term contracts includes a mix of base-escalated and market-related contracts. Each contract is bilaterally negotiated with the customer and is subject to terms of confidentiality. Therefore, to help understand how the pricing under our current portfolio of commitments is expected to react at various spot prices at December 31, 2022, we have constructed the table below.

The table is based on the pricing terms under the long-term commitments in our contract portfolio that have been finalized as at December 31, 2022, it does not include the contracts that have been accepted but are still subject to contract finalization. Based on the terms and volumes under those commitments, the table is designed to indicate how our average realized price will react under various spot price assumptions at a point in time. At year-end, the annual average sales commitments under our contract portfolio at December 31, 2022 are 21 million pounds per year, with commitment levels in 2023 through 2025 higher than the average and in 2026 and 2027 lower than the average. As the market improves, we expect to continue to layer in volumes capturing greater upside using market-related pricing mechanisms. In this table, we do not consider the impact on our average realized price of volumes under negotiation and those not yet finalized under contract. In other words, the prices shown in the table would only be realized if the contract portfolio remained exactly as it was on December 31, 2022, using the following assumptions:

| • |  | The uranium price remains fixed at a given spot level for each annual period shown

MANAGEMENT’S DISCUSSION AND ANALYSIS 49

| • |  | Deliveries based on commitments under finalized contracts include best estimates of the expected deliveries under contract terms

| • |  | To reflect escalation mechanisms contained in existing contracts, the long-term US inflation rate 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, 2022

(rounded to the nearest $1.00) |
SPOT PRICES |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
($US/lb U3O8) |  | $20 |  |  | $40 |  |  | $60 |  |  | $80 |  |  | $100 |  |  | $120 |  |  | $140 |
2023 |  |  | 35 |  |  |  | 41 |  |  |  | 49 |  |  |  | 53 |  |  |  | 56 |  |  |  | 58 |  |  |  | 59 |
2024 |  |  | 33 |  |  |  | 40 |  |  |  | 49 |  |  |  | 54 |  |  |  | 57 |  |  |  | 58 |  |  |  | 59 |
2025 |  |  | 35 |  |  |  | 42 |  |  |  | 52 |  |  |  | 58 |  |  |  | 61 |  |  |  | 63 |  |  |  | 64 |
2026 |  |  | 36 |  |  |  | 42 |  |  |  | 54 |  |  |  | 62 |  |  |  | 66 |  |  |  | 70 |  |  |  | 73 |
2027 |  |  | 37 |  |  |  | 43 |  |  |  | 55 |  |  |  | 65 |  |  |  | 70 |  |  |  | 73 |  |  |  | 76 |

Liquidity and capital resources

Our financial objective is to ensure we have the cash and debt capacity to fund our operating activities, investments and other financial obligations in order to execute our strategy and to allow us to self-manage risk. We have a number of alternatives to fund future capital requirements, including using our operating cash flow, drawing on our existing credit facilities, entering new credit facilities, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. In addition, due to the deliberate cost reduction measures we have implemented, we have continued to have positive cash from operations which has added to our cash balance. And with the proceeds from the October share issuance, which are expected to help finance the proposed acquisition of Westinghouse, we have significant cash balances.

As announced on October 11, 2022, we have entered into a strategic partnership with Brookfield Renewable and its institutional partners to acquire Westinghouse. Permanent financing is expected to be a mix of capital sources (cash, debt and equity), designed to preserve the company’s balance sheet and ratings strength while maintaining our liquidity. Closing is anticipated in the second half of 2023. Please see Proposed acquisition of Westinghouse starting on page 89 for further details.

Following the announcement, we undertook a $650 million (US) bought deal offering of common shares, with an underwriter option to purchase additional shares. The offering closed on October 17, 2022 with gross proceeds to us of approximately $747.6 million (US), including the exercise in full of the underwriters’ option to purchase additional common shares. Concurrently with the execution of the acquisition agreement, we secured commitments for a $1 billion (US) bridge loan facility and $600 million (US) in term loans. As of the closing of the bought deal offering, the bridge loan facility was reduced to $280 million (US) by the net proceeds received from the offering. The facilities will remain undrawn until closing of the acquisition. The bridge facility, if funded, will mature 364 days after the acquisition closing date, and the term loans consisting of two tranches $300 million (US) each, are expected to mature two years and three years after the acquisition closing.

At the end of 2022, we had cash and cash equivalents and short-term investments of $2.3 billion, while our total debt amounted to $997 million. Our cash balances are expected to be largely utilized for the close of the proposed acquisition of Westinghouse. Depending on the timing of the close, expected in the second half of 2023, cash balances could be lower or higher than expected.

50 CAMECO CORPORATION

We have large, creditworthy customers that continue to need our nuclear fuel products and services even during weak economic conditions, and we expect the contract portfolio we have built to continue to provide a solid revenue stream. In our uranium segment, from 2023 through 2027, we have commitments to deliver an average of 21 million pounds per year, with commitment levels in 2023 through 2025 higher than the average and in 2026 and 2027 lower than the average.

We expect increased production at McArthur River/Key Lake will be positive for cash flow. It will allow us to source more of our committed sales from lower-cost produced pounds and we will no longer be required to expense operational readiness costs directly to cost of sales. However, cash flow from operations for 2023 will be dependent on the timing and volume of production and the timing and magnitude of our purchasing activity.

We expect our cash balances and operating cash flows to meet our capital requirements during 2023. Depending on the timing of the close of the Westinghouse transaction, and the final financing mix of capital sources, cash balances could be lower or higher than expected.

With the Supreme Court’s dismissal of CRA’s application for leave, the dispute of the 2003 through 2006 tax years are fully and finally resolved in our favour. Furthermore, we are confident the courts would reject any attempt by CRA to utilize the same or similar positions and arguments for the other tax years currently in dispute (2007 through 2014) and believe CRA should return the $778 million in cash and letters of credit we have been required to pay or otherwise secure. As such, we have filed notice of appeal to the Tax Court however, timing of any further payments is uncertain. See page 44 for more information.

Financial condition

|  | 2022 |  |  | 2021 |
Cash position ($ millions) |  |  |  |  |  |  |  |
(cash and cash equivalents and short-term investments) |  |  | 2,282 |  |  |  | 1332 |
Cash provided by operations ($ millions) |  |  |  |  |  |  |  |
(net cash flow generated by our operating activities after changes in working capital) |  |  | 305 |  |  |  | 458 |
Cash provided by operations/net debt1 |  |  |  |  |  |  |  |
(net debt is total consolidated debt, less cash position) |  |  | -24 | % |  |  | -136 | %
Net debt/total capitalization1 |  |  |  |  |  |  |  |
(total capitalization is net debt and equity) |  |  | -28 | % |  |  | -7 | %

1 | As at December 31, 2022, Cameco was negative net debt due to our large cash position.

Credit ratings

The credit ratings assigned by external ratings agencies are important as they impact our ability to raise capital at competitive pricing to support our business operations and execute our strategy.

Third-party ratings for our commercial paper and senior debt as of February 8, 2023:

SECURITY |  | DBRS |  |  | S&P |
Commercial paper |  |  | R-2 (middle) |  |  |  | A-3 |
Senior unsecured debentures |  |  | BBB |  |  |  | BBB- |
Rating trend / rating outlook |  |  | Stable | 1 |  |  | Stable | 2

1 | On May 28, 2020, DBRS changed Cameco’s rating trend to stable. On May 26, 2021 and May 27, 2022, DBRS confirmed the rating and outlook. Currently our rating is under review following the announcement of the proposed acquisition of Westinghouse

2 | On February 16, 2022, S&P revised Cameco’s rating outlook to stable and affirmed the rating.

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant. The rating trend/outlook represents the rating agency’s assessment of the likelihood and direction that the rating could change in the future.

A change in our credit ratings could affect our cost of funding and our access to capital through the capital markets.

MANAGEMENT’S DISCUSSION AND ANALYSIS 51

Liquidity

($ MILLIONS) |  | 2022 |  |  | 2021 |
Cash and cash equivalents and short-term investments at beginning of year |  |  | 1,332 |  |  |  | 943 |
Cash from operations |  |  | 305 |  |  |  | 458 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment and acquisitions |  |  | (245 | ) |  |  | (99 | )
Other investing activities |  |  | 8 |  |  |  | 79 |
Financing activities |  |  |  |  |  |  |  |
Interest paid |  |  | (39 | ) |  |  | (39 | )
Issue of shares |  |  | 963 |  |  |  | 27 |
Dividends |  |  | (52 | ) |  |  | (32 | )
Other financing activities |  |  | (3 | ) |  |  | (3 | )
Exchange rate on changes on foreign currency cash balances |  |  | 13 |  |  |  | (2 | )
Cash and cash equivalents and short-term investments at end of year |  |  | 2,282 |  |  |  | 1,332 |

CASH FROM OPERATIONS

Cash from operations was lower than in 2021 due largely to an increase in working capital requirements which was the result of increased purchasing activity. Purchases in 2022 were 18.3 million pounds compared to 11.1 million pounds in 2021. Not including working capital requirements, our operating cash flows in the year were up $253 million. See note 24 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

Capital spending

We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development. We have a capital allocation process to approve our capital spend. See Capital Allocation beginning on page 30 for more information.

CAMECO’S SHARE ($ MILLIONS) |  | 2022 ACTUAL |  |  | 2023 PLAN |
Sustaining capital |  |  |  |  |  |  |  |
Uranium |  |  | 62 |  |  |  | 55-60 |
Fuel services |  |  | 39 |  |  |  | 40-45 |
Other |  |  | 2 |  |  |  | 5-10 |
Total sustaining capital |  |  | 103 |  |  |  | 100-115 |
Capacity replacement capital |  |  |  |  |  |  |  |
Uranium |  |  | 40 |  |  |  | 40-50 |
Fuel services |  |  | — |  |  |  | — |
Total capacity replacement capital |  |  | 40 |  |  |  | 40-50 |
Growth capital |  |  |  |  |  |  |  |
Uranium |  |  | — |  |  |  | 0-5 |
Fuel services |  |  | — |  |  |  | 5-10 |
Total growth capital |  |  | — |  |  |  | 5-15 |
Total sustaining, capital and growth |  |  | 143 |  |  |  | 150-175 |

52 CAMECO CORPORATION

Outlook for investing activities

CAMECO’S SHARE ($ MILLIONS) |  | 2023 PLAN |  |  | 2024 PLAN |  |  | 2025 PLAN |
Total uranium & fuel services |  |  | 150-175 |  |  |  | 150-200 |  |  |  | 100-150 |
Sustaining capital |  |  | 105-115 |  |  |  | 120-140 |  |  |  | 70-90 |
Capacity replacement capital |  |  | 40-50 |  |  |  | 25-45 |  |  |  | 25-45 |
Growth capital |  |  | 5-10 |  |  |  | 5-15 |  |  |  | 5-15 |

Our 2023, 2024 and 2025 capital spending estimates assume that in 2024, we begin producing 18 million pounds (100% basis) per year at McArthur River/Key Lake, continue producing 18 million pounds (100% basis) per year at Cigar Lake, and increase annual production at our UF6 conversion facility to 12,000 tonnes per year.

Our estimate for capital spending in 2023 has been increased to between $150 million and $175 million (previously between $100 million and $150 million) due to the capital required to meet production targets and the rescheduling of some expenditures planned in 2022 to 2023.

Capital expenditures for JV Inkai are expected to be covered by JV Inkai cash flows in 2023 and are included in our overall equity investment.

Major capital expenditures in 2023 include:

| • |  | Fuel services – capital required to increase production at our UF6 conversion facility and continued work on our Vision in Motion project

| • |  | Cigar Lake – underground development and necessary ground freezing infrastructure to meet production targets

| • |  | McArthur River/Key Lake – capital required to produce 18 million pounds per year (100% basis) starting in 2024

| • |  | Our investment in digital and automation technologies

This information regarding currently expected capital expenditures for future periods is forward-looking information and is based upon the assumptions and subject to the material risks discussed on pages 4 to 6. Our actual capital expenditures for future periods may be significantly different.

FINANCING ACTIVITIES

Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance.

Long-term contractual obligations

|  |  |  |  | 2024 AND |  |  | 2026 AND |  |  | 2028 AND |  |  |  |
DECEMBER 31 ($ MILLIONS) |  | 2023 |  |  | 2025 |  |  | 2027 |  |  | BEYOND |  |  | TOTAL |
Long-term debt |  |  | — |  |  |  | 500 |  |  |  | 400 |  |  |  | 100 |  |  |  | 1,000 |
Interest on long-term debt |  |  | 38 |  |  |  | 44 |  |  |  | 34 |  |  |  | 76 |  |  |  | 192 |
Provision for reclamation |  |  | 47 |  |  |  | 69 |  |  |  | 95 |  |  |  | 1,145 |  |  |  | 1,356 |
Provision for waste disposal |  |  | 2 |  |  |  | 4 |  |  |  | 3 |  |  |  | — |  |  |  | 9 |
Other liabilities |  |  | 29 |  |  |  | 36 |  |  |  | 6 |  |  |  | 64 |  |  |  | 135 |
Capital commitments |  |  | 57 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 57 |
Total |  |  | 173 |  |  |  | 653 |  |  |  | 538 |  |  |  | 1,385 |  |  |  | 2,749 |

We have contractual capital commitments of approximately $57 million at December 31, 2022. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfil the contracts.

We have sufficient borrowing capacity with available unsecured lines of credit totalling about $2.7 billion, which include the following:

| • |  | A $1.0 billion unsecured revolving credit facility that matures October 1, 2026. Each calendar year, 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, 2022, there were no amounts outstanding under this facility.

MANAGEMENT’S DISCUSSION AND ANALYSIS 53

| • |  | At December 31, 2022, we had approximately $1.6 billion outstanding in financial assurances provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, for our obligations relating to the CRA dispute, and as overdraft protection.

In total we have $1.0 billion in senior unsecured debentures outstanding:

| • |  | $500 million bearing interest at 4.19% per year, maturing on June 24, 2024

| • |  | $400 million bearing interest at 2.95% per year, maturing on October 21, 2027

| • |  | $100 million bearing interest at 5.09% per year, maturing on November 14, 2042

We have secured $600 million (US) in term loan facilities and $280 million (US) under a bridge loan facility to help finance the proposed acquisition of Westinghouse. The debt facilities will remain undrawn until closing of the acquisition. The bridge facility, if funded, will mature 364 days after the acquisition closing date, and the term loans consisting of two tranches of $300 million (US) each, are expected to mature two years and three years after the acquisition closes. Please see Proposed acquisition of Westinghouse on page 89 for more information. These facilities have not been included in the long-term contractual obligation table due to the uncertainty around timing of the close of the acquisition and how much will be funded under these facilities when it closes.

Debt covenants

Our revolving credit facility includes the following financial covenants:

| • |  | our funded debt to tangible net worth ratio must be 1:1 or less

| • |  | other customary covenants and events of default

Funded debt is total consolidated debt less non-recourse debt, $100 million in letters of credit, cash and cash equivalents and short-term investments.

Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2022, we complied with all covenants, and we expect to continue to comply in 2023.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at the end of 2022:

| • |  | purchase commitments

| • |  | financial assurances

| • |  | other arrangements

Purchase commitments

We make purchases under long-term contracts where it is beneficial for us to do so and to support our long-term contract portfolio. The following table is based on our purchase commitments in our uranium and fuel services segments at December 31, 20222 but does not include purchases of our share of Inkai production. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

|  |  |  |  | 2024 AND |  |  | 2026 AND |  |  | 2028 AND |  |  |  |
DECEMBER 31, 2022 ($ MILLIONS) |  | 2023 |  |  | 2025 |  |  | 2027 |  |  | BEYOND |  |  | TOTAL |
Purchase commitments1,2 |  |  | 232 |  |  |  | 98 |  |  |  | 154 |  |  |  | 17 |  |  |  | 501 |

1 | Denominated in US dollars and Japanese yen, converted from US dollars to Canadian dollars at the rate of 1.30 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, 2022 but does not include deliveries taken under contract since December 31, 2022.

We have commitments of $501 million (Cdn) for the following:

| • |  | approximately 9.2 million pounds of U3O8 equivalent from 2023 to 2028

| • |  | approximately 0.4 million kgU as UF6 in conversion services from 2023 to 2024

54 CAMECO CORPORATION

| • |  | about 0.6 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.

We have submitted updates to all Saskatchewan operations’ Preliminary Decommissioning Plan (PDP) and Preliminary Decommissioning Cost Estimate (PDCE) documents in accordance with the five-year timeline specified in the regulations. Upon acceptance of the PDP and PDCE documents by the Saskatchewan Ministry of Environment and Canadian Nuclear Safety Commission (CNSC) staff, a formal Commission proceeding will be required for final approval of the PDP and PDCE by the Commission. All Saskatchewan mining operations have received the necessary approvals for the current PDP and PDCE and all required financial assurances are in place.

The PDP and PDCE for the Blind River refinery were revised in 2020. The CNSC approved the PDCE in February 2022 and the financial assurance was updated in March 2022. The Cameco Fuel Manufacturing PDP and PDCE were revised in 2021, and the revised PDCE was approved by the Commission in February 2022 and the financial assurance was updated in March 2022. The PDP and PDCE for the Port Hope conversion facility were revised in 2022 and submitted to CNSC staff in September 2022 and are currently under review by CNSC staff. Once accepted by staff, the PDCE will be considered by the Commission, after which the financial assurance will be updated.

For Smith Ranch-Highland, the 2022 surety was approved and the credit instruments are being reviewed by the State of Wyoming. For Crow Butte, the 2022 annual update was submitted to the federal Nuclear Regulatory Commission and Nebraska Department of Environmental Quality in September 2022. This most recent surety has been approved by the state and is still waiting for approval from the NRC.

At the end of 2022, our estimate of total decommissioning and reclamation costs was $1.36 billion. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $1.06 billion at the end of 2022 (the present value of the $1.36 billion). Regulatory approval is required prior to beginning decommissioning. Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, and none of our assets have approval for decommissioning, our expected costs for decommissioning and reclamation for the next five years are not material.

We had a total of about $1.04 billion in financial assurances supporting our reclamation liabilities at the end of 2022. All of our North American operations have financial assurances in place in connection with our preliminary plans for decommissioning of the sites.

We are also providing letters of credit until the CRA dispute is resolved.

Our financial assurances renew automatically on an annual basis, unless otherwise advised by the issuing institution. At December 31, 2022 our financial assurances totaled $1.6 billion, the same as at December 31, 2021.

Other arrangements

We have arranged for standby product loan facilities with various counterparties. The arrangements allow us to borrow up to 2.4 million kgU of UF6 conversion services and 2.8 million pounds of U3O8 over the period 2020 to 2026 with repayment in kind up to December 31, 2026. Under the loan facilities, standby fees of up to 1% are payable based on the market value of the facilities and interest is payable on the market value of any amounts drawn at rates ranging from 0.5% to 2.0%. At December 31, 2022, we have 1.0 million kgU of UF6 conversion services and 630,000 pounds of U3O8 drawn on the loans.

MANAGEMENT’S DISCUSSION AND ANALYSIS 55

BALANCE SHEET

DECEMBER 31, |  |  |  |  |  |  |  |  |  |  | CHANGE |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | 2022 |  |  | 2021 |  |  | 2020 |  |  | 2021 TO 2022 |
Inventory |  |  | 665 |  |  |  | 410 |  |  |  | 680 |  |  |  | 62 | %
Total assets |  |  | 8,633 |  |  |  | 7,518 |  |  |  | 7,581 |  |  |  | 15 | %
Total non-current liabilities |  |  | 2,236 |  |  |  | 2,258 |  |  |  | 2,318 |  |  |  | (1 | )%
Dividends per common share |  |  | 0.12 |  |  |  | 0.08 |  |  |  | 0.08 |  |  |  | 50 | %

Total product inventories increased by 62% to $665 million this year as production and purchases were higher than sales during the year. At December 31, 2022, our average cost for uranium was $43.45 per pound, up from $38.30 per pound at December 31, 2021. As of December 31, 2022, we held an inventory of 12 million pounds of U3O8 equivalent (excluding broken ore).

At the end of 2022, our total assets amounted to $8.6 billion, an increase of 15% compared to 2021, due mainly to an increase in investment balances resulting from the October 2022 issuance of common shares in preparation for the closing of the Westinghouse transaction as well as higher inventories. In 2021, the total asset balance decreased by $0.1 billion compared to 2020, due mainly to lower inventories which was largely offset by an increase in cash and investment balances.

56 CAMECO CORPORATION

2022 financial results by segment

Uranium

HIGHLIGHTS |  |  |  |  | 2022 |  |  | 2021 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  |  |  | 10.4 |  |  |  | 6.1 |  |  |  | 70 | %
Sales volume (million lbs) |  |  |  |  |  |  | 25.6 |  |  |  | 24.3 |  |  |  | 5 | %
Average spot price |  |  | ($US/lb | ) |  |  | 49.81 |  |  |  | 35.28 |  |  |  | 41 | %
Average long-term price |  |  | ($US/lb | ) |  |  | 49.75 |  |  |  | 36.81 |  |  |  | 35 | %
Average realized price |  |  | ($US/lb | ) |  |  | 44.73 |  |  |  | 34.53 |  |  |  | 30 | %
|  |  | ($Cdn/lb | ) |  |  | 57.85 |  |  |  | 43.34 |  |  |  | 33 | %
Average unit cost of sales (including D&A) |  |  | ($Cdn/lb | ) |  |  | 53.13 |  |  |  | 47.80 |  |  |  | 11 | %
Revenue ($ millions) |  |  |  |  |  |  | 1,480 |  |  |  | 1,055 |  |  |  | 40 | %
Gross profit (loss) ($ millions) |  |  |  |  |  |  | 121 |  |  |  | (108 | ) |  |  | >100 | %
Gross profit (loss) (%) |  |  |  |  |  |  | 8 |  |  |  | (10 | ) |  |  | >100 | %

Production volumes in 2022 increased by 70% compared to 2021. See Uranium – production overview on page 69 for more information.

Uranium revenues this year were up 40% compared to 2021 due to an increase in sales volumes of 5% and an increase of 33% in the Canadian dollar average realized price due to an increase in the spot price. While the spot price for uranium averaged $49.81 (US) per pound in 2022, an increase of 41% compared to the 2021 average of $35.28 (US) per pound, the US dollar average realized price only increased by 30% due to the impact of fixed price contracts on the portfolio.

Total cost of sales (including D&A) increased by 17% ($1.36 billion compared to $1.16 billion in 2021) due to an increase in sales volume of 5% and an 11% increase in unit cost of sales. Unit cost of sales is higher than in the same period in 2021 due to the higher cost of purchased material and the higher operational readiness costs at McArthur River/Key Lake operations. This was offset by the impact of care and maintenance costs at Cigar Lake in 2021 due to the temporary suspension of operations due to COVID-19.

The net effect was a $229 million increase in gross profit for the year.

The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures, see below). These costs do not include care and maintenance costs, operational readiness costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

($CDN/LB) |  | 2022 |  |  | 2021 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 19.24 |  |  |  | 16.00 |  |  |  | 20 | %
Non-cash cost |  |  | 15.72 |  |  |  | 17.17 |  |  |  | (8 | )%
Total production cost 1 |  |  | 34.96 |  |  |  | 33.17 |  |  |  | 5 | %
Quantity produced (million lbs)1 |  |  | 10.4 |  |  |  | 6.1 |  |  |  | 70 | %
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost1 |  |  | 51.36 |  |  |  | 42.30 |  |  |  | 21 | %
Quantity purchased (million lbs)1 |  |  | 18.3 |  |  |  | 11.1 |  |  |  | 65 | %
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 45.42 |  |  |  | 39.06 |  |  |  | 16 | %
Quantities produced and purchased (million lbs) |  |  | 28.7 |  |  |  | 17.2 |  |  |  | 67 | %

1 | Due to equity accounting for JV Inkai, our share of production is shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. In 2022 we purchased 3.3 million pounds at a purchase price per pound of $62.78 ($47.33 (US)) (2021 – 5.2 million pounds at a purchase price per pound of $45.31 ($36.03 (US))).

MANAGEMENT’S DISCUSSION AND ANALYSIS 57

The average cash cost of production was 20% higher compared to 2021. Cash cost was higher due to inflationary pressures, labour shortages and supply chain challenges. In addition, with the restart of McArthur River/Key Lake operations the cash cost of production will reflect a combined cost of all our operating uranium assets going forward.

In 2023, with McArthur River/Key Lake ramping up production, and the impact of inflationary pressures, the availability of personnel with the necessary skills and experience, and supply chain challenges on the availability of materials and reagents, our average annual unit cash cost of production is expected to be higher than the average unit life of mine operating costs reflected in our most recent annual information form: approximately $16 per pound at McArthur River/Key Lake; approximately $18 per pound at Cigar Lake.

We also expect the Inkai unit cash cost of production in 2023 to be higher than the average unit life of mine operating costs reflected in our most recent annual information form (between $8 and $9 per pound) due to the current supply chain challenges and inflationary pressures experienced in Kazakhstan. The benefit of the estimated life-of-mine operating cost for JV Inkai’s production is expected to be reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investee”. The current geopolitical and economic uncertainty could continue to impact JV Inkai’s operating costs.

Our purchases in 2022, totaled about $940 million, representing an average annual cost of $51.36 per pound, about $16.00 per pound higher than our total unit production cost for the year. Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. The average cost of purchased material in Canadian dollar terms increased by 21% this year compared to 2021. The average cash cost of purchased material was $51.36 (Cdn), or $39.45 (US) per pound, compared to $42.30 (Cdn), or $33.73 (US) per pound in the same period in 2021.

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.

These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the years ended 2022 and 2021 as reported in our financial statements.

58 CAMECO CORPORATION

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS) |  | 2022 |  |  | 2021 |
Cost of product sold |  |  | 1,223.6 |  |  |  | 1,028.8 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (23.4 | ) |  |  | (15.2 | )
Other selling costs |  |  | (5.9 | ) |  |  | (4.6 | )
Care and maintenance and operational readiness costs |  |  | (178.5 | ) |  |  | (156.7 | )
Change in inventories |  |  | 124.2 |  |  |  | (285.2 | )
Cash operating costs (a) |  |  | 1,140.0 |  |  |  | 567.1 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 135.8 |  |  |  | 134.6 |
Care and maintenance and operational readiness costs |  |  | (39.9 | ) |  |  | (52.9 | )
Change in inventories |  |  | 67.6 |  |  |  | 23.0 |
Total operating costs (b) |  |  | 1,303.5 |  |  |  | 671.8 |
Uranium produced & purchased (million lbs) (c) |  |  | 28.7 |  |  |  | 17.2 |
Cash costs per pound (a ÷ c) |  |  | 39.72 |  |  |  | 32.97 |
Total costs per pound (b ÷ c) |  |  | 45.42 |  |  |  | 39.06 |

ROYALTIES

We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:

| • |  | Basic royalty: calculated as 5% of gross sales of uranium, less the Saskatchewan resource credit of 0.75%.

| • |  | Profit royalty: a 10% royalty is charged on profit up to and including $26.268/kg U3O8 ($11.91/lb) and a 15% royalty is charged on profit in excess of $26.268/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.

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 |  |  |  |  | 2022 |  |  | 2021 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  |  |  | 13.0 |  |  |  | 12.1 |  |  |  | 7 | %
Sales volume (million kgU) |  |  |  |  |  |  | 11.1 |  |  |  | 13.6 |  |  |  | (18 | )%
Average realized price |  | ($ | Cdn/kgU | ) |  |  | 32.92 |  |  |  | 29.72 |  |  |  | 11 | %
Average unit cost of sales (including D&A) |  | ($ | Cdn/kgU | ) |  |  | 22.39 |  |  |  | 21.02 |  |  |  | 7 | %
Revenue ($ millions) |  |  |  |  |  |  | 365 |  |  |  | 404 |  |  |  | (10 | )%
Gross profit ($ millions) |  |  |  |  |  |  | 117 |  |  |  | 118 |  |  |  | (1 | )%
Gross profit (%) |  |  |  |  |  |  | 32 |  |  |  | 29 |  |  |  | 10 | %

Total revenue decreased by 10% from 2021 due to an 18% decrease in sales volume partially offset by an 11% increase in the realized price. The increase in realized price was mainly the result of increased prices due to market conditions.

Total cost of products and services sold (including D&A) decreased 13% ($248 million compared to $286 million in 2021), due to the 18% decrease in sales volume partially offset by a 7% increase in average unit cost of sales compared to 2021 due to higher input costs.

The net effect was a $1 million decrease in gross profit.

MANAGEMENT’S DISCUSSION AND ANALYSIS 59

Fourth quarter financial results

Consolidated results

|  | THREE MONTHS ENDED |  |  |  |
HIGHLIGHTS |  | DECEMBER 31 |  |  |  |
($ MILLIONS EXCEPT WHERE INDICATED) |  | 2022 |  |  | 2021 |  |  | CHANGE |
Revenue |  |  | 524 |  |  |  | 465 |  |  |  | 13 | %
Gross profit |  |  | 65 |  |  |  | 56 |  |  |  | 16 | %
Net earnings (loss) attributable to equity holders |  |  | (15 | ) |  |  | 11 |  |  |  | >100 | %
$ per common share (basic) |  |  | (0.04 | ) |  |  | 0.03 |  |  |  | >100 | %
$ per common share (diluted) |  |  | (0.04 | ) |  |  | 0.03 |  |  |  | >100 | %
Adjusted net earnings (non-IFRS, see page 40) |  |  | 36 |  |  |  | 23 |  |  |  | 57 | %
$ per common share (adjusted and diluted) |  |  | 0.09 |  |  |  | 0.06 |  |  |  | 50 | %
Cash provided by operations |  |  | 77 |  |  |  | 59 |  |  |  | 31 | %

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 40) in the fourth quarter of 2022 compared to the same period in 2021.

($ MILLIONS) |  | IFRS |  |  | Adjusted |
Net earnings - 2021 |  |  | 11 |  |  |  | 23 |
Change in gross profit by segment |  |  |  |  |  |  |  |
(we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |
Uranium |  | Impact from sales volume changes |  |  | 1 |  |  |  | 1 |
|  | Higher realized prices ($US) |  |  | 29 |  |  |  | 29 |
|  | Foreign exchange impact on realized prices |  |  | 25 |  |  |  | 25 |
|  | Higher costs |  |  | (41 | ) |  |  | (41 | )
|  | change – uranium |  |  | 14 |  |  |  | 14 |
Fuel services |  | Impact from sales volume changes |  |  | (10 | ) |  |  | (10 | )
|  | Higher realized prices ($Cdn) |  |  | 4 |  |  |  | 4 |
|  | Lower costs |  |  | 1 |  |  |  | 1 |
|  | change – fuel services |  |  | (5 | ) |  |  | (5 | )
Other changes |  |  |  |  |  |  |  |
Lower administration expenditures |  |  | 8 |  |  |  | 8 |
Change in reclamation provisions |  |  | (78 | ) |  |  | — |
Change in gains or losses on derivatives |  |  | 12 |  |  |  | (12 | )
Change in foreign exchange gains or losses |  |  | 6 |  |  |  | 6 |
Change in earnings from equity-accounted investments |  |  | (19 | ) |  |  | (19 | )
Higher finance income |  |  | 21 |  |  |  | 21 |
Change in income tax recovery or expense |  |  | 13 |  |  |  | (2 | )
Other |  |  | 2 |  |  |  | 2 |
Net earnings (losses) - 2022 |  |  | (15 | ) |  |  | 36 |

ADJUSTED NET EARNINGS

We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 40 for more information. The following table reconciles adjusted net earnings with our net earnings.

60 CAMECO CORPORATION

|  | THREE MONTHS ENDED |
|  | DECEMBER 31 |
($ MILLIONS) |  | 2022 |  |  | 2021 |
Net earnings (loss) attributable to equity holders |  |  | (15 | ) |  |  | 11 |
Adjustments |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | (19 | ) |  |  | 5 |
Adjustments on other operating expense (income) |  |  | 88 |  |  |  | 10 |
Income taxes on adjustments |  |  | (18 | ) |  |  | (3 | )
Adjusted net earnings |  |  | 36 |  |  |  | 23 |

ADMINISTRATION

|  | THREE MONTHS ENDED |  |  |  |
|  | DECEMBER 31 |  |  |  |
($ MILLIONS) |  | 2022 |  |  | 2021 |  |  | CHANGE |
Direct administration |  |  | 37 |  |  |  | 28 |  |  |  | 32 | %
Stock-based compensation |  |  | (8 | ) |  |  | 9 |  |  |  | (189 | )%
Total administration |  |  | 29 |  |  |  | 37 |  |  |  | (22 | )%

Direct administration costs were $37 million in the quarter, $9 million higher than the same period last year. Stock-based compensation expenses were $17 million lower from the fourth quarter of 2021 because of a large decrease in share price in the current quarter compared to a very small increase in the same period last year. In addition, the impact of the share price changes was offset by a change in assumptions for vesting criteria related to the executive performance share units. In the current quarter this was a recovery while in 2021 it was an expense.

Quarterly trends

HIGHLIGHTS |  | 2022 |  |  | 2021 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 524 |  |  |  | 389 |  |  |  | 558 |  |  |  | 398 |  |  |  | 465 |  |  |  | 361 |  |  |  | 359 |  |  |  | 290 |
Net earnings (loss) attributable to equity holders |  |  | (15 | ) |  |  | (20 | ) |  |  | 84 |  |  |  | 40 |  |  |  | 11 |  |  |  | (72 | ) |  |  | (37 | ) |  |  | (5 | )
$ per common share (basic) |  |  | (0.04 | ) |  |  | (0.05 | ) |  |  | 0.21 |  |  |  | 0.10 |  |  |  | 0.03 |  |  |  | (0.18 | ) |  |  | (0.09 | ) |  |  | (0.01 | )
$ per common share (diluted) |  |  | (0.04 | ) |  |  | (0.05 | ) |  |  | 0.21 |  |  |  | 0.10 |  |  |  | 0.03 |  |  |  | (0.18 | ) |  |  | (0.09 | ) |  |  | (0.01 | )
Adjusted net earnings (loss) (non-IFRS, see page 40) |  |  | 36 |  |  |  | 10 |  |  |  | 72 |  |  |  | 17 |  |  |  | 23 |  |  |  | (54 | ) |  |  | (38 | ) |  |  | (29 | )
$ per common share (adjusted and diluted) |  |  | 0.09 |  |  |  | 0.03 |  |  |  | 0.18 |  |  |  | 0.04 |  |  |  | 0.06 |  |  |  | (0.14 | ) |  |  | (0.10 | ) |  |  | (0.07 | )
Cash provided by (used in) operations (after working capital changes) |  |  | 77 |  |  |  | (47 | ) |  |  | 102 |  |  |  | 172 |  |  |  | 59 |  |  |  | 203 |  |  |  | 152 |  |  |  | 45 |

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.

| • |  | 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 40 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.

| • |  | Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

MANAGEMENT’S DISCUSSION AND ANALYSIS 61

The table that follows presents the differences between net earnings and adjusted net earnings for the previous seven quarters.

HIGHLIGHTS |  | 2022 |  |  | 2021 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Net earnings (loss) attributable to equity holders |  |  | (15 | ) |  |  | (20 | ) |  |  | 84 |  |  |  | 40 |  |  |  | 11 |  |  |  | (72 | ) |  |  | (37 | ) |  |  | (5 | )
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | (19 | ) |  |  | 75 |  |  |  | 31 |  |  |  | (11 | ) |  |  | 5 |  |  |  | 26 |  |  |  | (9 | ) |  |  | (9 | )
Adjustments on other operating expense (income) |  |  | 88 |  |  |  | (24 | ) |  |  | (19 | ) |  |  | (19 | ) |  |  | 10 |  |  |  | (2 | ) |  |  | 6 |  |  |  | (22 | )
Adjustment to other income |  |  | — |  |  |  | — |  |  |  | (23 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Income taxes on adjustments |  |  | (18 | ) |  |  | (21 | ) |  |  | (1 | ) |  |  | 7 |  |  |  | (3 | ) |  |  | (6 | ) |  |  | 2 |  |  |  | 7 |
Adjusted net earnings (losses) (non-IFRS, see page 40) |  |  | 36 |  |  |  | 10 |  |  |  | 72 |  |  |  | 17 |  |  |  | 23 |  |  |  | (54 | ) |  |  | (38 | ) |  |  | (29 | )

62 CAMECO CORPORATION

Fourth quarter financial results by segment

Uranium

|  |  |  |  | THREE MONTHS ENDED |  |  |  |
|  |  |  |  | DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  |  | 2022 |  |  | 2021 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  |  |  | 3.7 |  |  |  | 2.8 |  |  |  | 32 | %
Sales volume (million lbs) |  |  |  |  |  |  | 6.9 |  |  |  | 6.5 |  |  |  | 6 | %
Average spot price |  |  | ($US/lb | ) |  |  | 49.94 |  |  |  | 44.33 |  |  |  | 13 | %
Average long-term price |  |  | ($US/lb | ) |  |  | 51.67 |  |  |  | 42.92 |  |  |  | 20 | %
Average realized price |  |  | ($US/lb | ) |  |  | 43.05 |  |  |  | 39.65 |  |  |  | 9 | %
|  |  | ($Cdn/lb | ) |  |  | 57.87 |  |  |  | 49.94 |  |  |  | 16 | %
Average unit cost of sales (including D&A) |  |  | ($Cdn/lb | ) |  |  | 54.37 |  |  |  | 48.35 |  |  |  | 12 | %
Revenue ($ millions) |  |  |  |  |  |  | 397 |  |  |  | 323 |  |  |  | 23 | %
Gross profit ($ millions) |  |  |  |  |  |  | 24 |  |  |  | 10 |  |  |  | >100 | %
Gross profit (%) |  |  |  |  |  |  | 6 |  |  |  | 3 |  |  |  | 100 | %

Production volumes this quarter increased by 32% compared to the fourth quarter of 2021. See Uranium – production overview on page 69 for more information.

Uranium revenues were up 23% due to a 6% increase in sales volume and a 16% increase in the Canadian dollar average realized price which was a result of an increase in the average spot price for uranium. While the average US dollar spot price for uranium increased by 13% compared to the same period in 2021, the US dollar average realized price only increased by 9% as a result of lower prices on fixed-price contracts. In addition, the Canadian dollar was weaker compared to the same period last year, $1.00 (US) for $1.34 (Cdn) compared to $1.00 (US) for $1.26 (Cdn) in the fourth quarter of 2021.

Total cost of sales (including D&A) increased by 19% ($373 million compared to $313 million in 2021). This was primarily the result of the 6% increase in sales volume as well as the increase of 12% in the average unit cost of sales which was due to the higher cost of purchased material.

The net effect was a $14 million increase in gross profit for the quarter.

The following table shows the costs of produced and purchased uranium incurred in the reporting periods. These costs do not include care and maintenance costs, operational readiness costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

|  | THREE MONTHS ENDED |  |  |  |
|  | DECEMBER 31 |  |  |  |
($/LB) |  | 2022 |  |  | 2021 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 19.50 |  |  |  | 13.67 |  |  |  | 43 | %
Non-cash cost |  |  | 13.76 |  |  |  | 17.10 |  |  |  | (20 | )%
Total production cost 1 |  |  | 33.26 |  |  |  | 30.77 |  |  |  | 8 | %
Quantity produced (million lbs)1 |  |  | 3.7 |  |  |  | 2.8 |  |  |  | 32 | %
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost1 |  |  | 57.02 |  |  |  | 52.73 |  |  |  | 8 | %
Quantity purchased (million lbs)1 |  |  | 5.8 |  |  |  | 3.3 |  |  |  | 76 | %
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 47.77 |  |  |  | 42.65 |  |  |  | 12 | %
Quantities produced and purchased (million lbs) |  |  | 9.5 |  |  |  | 6.1 |  |  |  | 56 | %

1 | Due to equity accounting for JV Inkai, our share of production will be shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. During the quarter, we purchased 2.6 million pounds at a purchase price per pound of $61.27 ($45.60 (US)) (Q4 2021 – 2.2 million pounds at a purchase price per pound of $52.69 ($41.79 (US))).

MANAGEMENT’S DISCUSSION AND ANALYSIS 63

The average cash cost of production for the fourth quarter was 47% higher compared to the same period in the prior year. Cash cost was higher due to the effect of supply chain challenges and inflationary pressures, as well as the decreased production rate for Cigar Lake compared to 2021. Effective May 19, our ownership stake and share of production from Cigar Lake stands at 54.547%, compared to 50.025% in 2021. In addition, the unit production costs for the fourth quarter of 2022 include production costs from McArthur River/Key Lake operations as they ramp up production.

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the fourth quarter, the average cash cost of purchased material was $57.02 (Cdn) per pound, or $42.18 (US) per pound in US dollar terms, compared to $52.73 (Cdn) per pound, or $41.87 (US) per pound in the fourth quarter of 2021.

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. See page 57 for more information.

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2022 and 2021.

CASH AND TOTAL COST PER POUND RECONCILIATION

|  | THREE MONTHS ENDED |
|  | DECEMBER 31 |
($ MILLIONS) |  | 2022 |  |  | 2021 |
Cost of product sold |  |  | 355.1 |  |  |  | 278.9 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (2.1 | ) |  |  | (5.0 | )
Other selling costs |  |  | (2.0 | ) |  |  | (1.6 | )
Care and maintenance and operational readiness costs |  |  | (35.5 | ) |  |  | (36.8 | )
Change in inventories |  |  | 87.4 |  |  |  | (23.2 | )
Cash operating costs (a) |  |  | 402.9 |  |  |  | 212.3 |
Depreciation and amortization |  |  | 18.2 |  |  |  | 34.2 |
Care and maintenance and operational readiness costs |  |  | (7.5 | ) |  |  | (10.1 | )
Change in inventories |  |  | 40.2 |  |  |  | 23.8 |
Total operating costs (b) |  |  | 453.8 |  |  |  | 260.2 |
Uranium produced & purchased (million lbs) (c) |  |  | 9.5 |  |  |  | 6.1 |
Cash costs per pound (a ÷ c) |  |  | 42.41 |  |  |  | 34.80 |
Total costs per pound (b ÷ c) |  |  | 47.77 |  |  |  | 42.65 |

Fuel services

(includes results for UF6, UO2, UO3 and fuel fabrication)

|  |  |  |  | THREE MONTHS ENDED |  |  |  |
|  |  |  |  | DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  |  | 2022 |  |  | 2021 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  |  |  | 3.7 |  |  |  | 3.1 |  |  |  | 19 | %
Sales volume (million kgU) |  |  |  |  |  |  | 3.8 |  |  |  | 4.9 |  |  |  | (22 | )%
Average realized price |  | ($ | Cdn/kgU | ) |  |  | 30.11 |  |  |  | 28.80 |  |  |  | 5 | %
Average unit cost of sales (including D&A) |  | ($ | Cdn/kgU | ) |  |  | 19.33 |  |  |  | 19.45 |  |  |  | (1 | )%
Revenue ($ millions) |  |  |  |  |  |  | 115 |  |  |  | 140 |  |  |  | (18 | )%
Gross profit ($ millions) |  |  |  |  |  |  | 41 |  |  |  | 46 |  |  |  | (11 | )%
Gross profit (%) |  |  |  |  |  |  | 36 |  |  |  | 33 |  |  |  | 9 | %

Total revenue decreased by 18% due to a 22% decrease in sales volumes which was partially offset by a 5% increase in average realized price. The increase in average realized price was mainly the result of the mix of products sold, as well as contracts that were entered into in an improved price environment.

64 CAMECO CORPORATION

Total cost of sales (including D&A) decreased by 22% to $74 million compared to the fourth quarter of 2021 due to the 22% decrease in sales volumes and a decrease of 1% in the average unit cost of sales.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 65

Operations, projects and other fuel cycle investments

This section of our MD&A is an overview of the mining, milling and processing facilities we operate or have an interest in, our curtailed operations and our advanced uranium projects, what we accomplished this year, our plans for the future and how we manage risk. It also includes an overview of our other investments in the nuclear fuel cycle, and our approach to corporate development.

67 |  | MANAGING THE RISKS
69 |  | URANIUM – PRODUCTION OVERVIEW
69 |  | PRODUCTION OUTLOOK
70 |  | URANIUM – TIER-ONE OPERATIONS
70 |  | MCARTHUR RIVER MINE / KEY LAKE MILL
74 |  | CIGAR LAKE
78 |  | INKAI
81 |  | URANIUM – TIER-TWO OPERATIONS
81 |  | RABBIT LAKE
82 |  | US ISR
83 |  | URANIUM – ADVANCED PROJECTS
83 |  | MILLENNIUM
83 |  | YEELIRRIE
83 |  | KINTYRE
85 |  | URANIUM – EXPLORATION
86 |  | FUEL SERVICES
86 |  | BLIND RIVER REFINERY
87 |  | PORT HOPE CONVERSION SERVICES
87 |  | CAMECO FUEL MANUFACTURING INC. (CFM)
89 |  | OTHER NUCLEAR FUEL CYCLE INVESTMENTS
89 |  | GLOBAL LASER ENRICHMENT (GLE)
89 |  | PROPOSED ACQUISITION OF WESTINGHOUSE
93 |  | CORPORATE DEVELOPMENT

66 CAMECO CORPORATION

Managing the risks

The nature of our business means we face many kinds of potential risks and hazards – some that relate to the nuclear energy industry in general, safety, health and environmental risks associated with any mining and chemical processing company and others that apply to specific properties, operations, planned operations or investments. Our uranium and fuel services segments also face unique risks associated with radiation. These risks could have a significant impact on our business, earnings, cash flows, financial condition, results of operations or prospects, which may result in a significant decrease in the market price of our common shares.

Risks and hazards generally applicable to the mining, milling and processing facilities we operate, and advanced projects include:

• |  | catastrophic accidents resulting in large-scale releases of hazardous chemicals, or a tailings facility failure, which could pose a significant risk to the environment, and to employee and public safety

• |  | industrial safety accidents

• |  | transportation incidents

• |  | labour shortages, disputes or strikes

• |  | cost increases for labour, contracted or purchased materials, supplies and services

• |  | shortages of, or interruptions in the supply of, required materials, supplies and equipment

• |  | transportation and delivery disruptions

• |  | interruptions in the supply of electricity, water, and other utilities or infrastructure

• |  | inability of our innovation initiatives to achieve the expected cost saving and operational flexibility objectives

• |  | equipment failures

• |  | cyberattacks

• |  | joint venture disputes or litigation

• |  | non-compliance with legal requirements, including exceedances of applicable air or water limits

• |  | subsurface contamination from current or legacy operations

• |  | inability to obtain and renew the licences and other approvals needed to restart, operate, and to increase production at our mines, mills, and processing facilities, or to develop new mines

• |  | increased workforce health and safety risks or increased regulatory burdens resulting from the COVID-19 pandemic or other causes

• |  | fires

• |  | blockades or other acts of social or political activism

• |  | uncertain impact of changing regulations or policy leading to higher annual operating costs, including GHG pricing and regulations (e.g., carbon pricing, the Canadian Clean Fuel Standard)

• |  | natural phenomena, such as forest fires, floods and earthquakes as well as shifts in temperature, precipitation, and the impact of more frequent severe weather conditions on our operations as a result of climate change

• |  | outbreak of illness (such as a pandemic like COVID-19)

• |  | unusual, unexpected or adverse mining or geological conditions

• |  | underground water inflows at our mining operations

• |  | ground movement or cave-ins at our mining operations

We have a Risk Policy that is supported by our formal Risk Management Program.

Our Risk Management Program involves a broad, systematic approach to identifying, assessing, monitoring, reporting and managing the significant risks we face in our business and operations, including consideration of ESG and climate-related risks that could impact our four measures of success. For more information about our risk management program see the Risk and Risk Management section in this MD&A, as well as our most recent ESG Report at cameco.com.

We have insurance to cover some of these risks and hazards, but not all of them, and not to the full amount of losses or liabilities that could potentially arise.

MANAGEMENT’S DISCUSSION AND ANALYSIS 67

In addition to considering the other information in this MD&A and the risks noted above, you should carefully consider the material risks discussed starting on page 4, and the specific risks discussed under the update for each operation, advanced project, and other nuclear fuel cycle investment in this section. These risks, however, are not a complete list of the potential risks our operations, advanced projects, or other investments face. There may be others we are not aware of or risks we feel are not material today that could become material in the future.

We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.

68 CAMECO CORPORATION

Uranium – production overview

Production in our uranium segment in the fourth quarter was 3.7 million pounds, 32% higher compared to the same period in 2021, while production for the year was 10.4 million pounds, 70% higher than in 2021. Cigar Lake production was higher in 2022 as production was impacted in 2021 by the proactive four-month suspension related to the COVID-19 pandemic. The McArthur River/Key Lake operations transitioned to production in 2022, producing 1.1 million pounds (100% basis) during the year. The Rabbit Lake operation remained in a safe and sustainable state of care and maintenance, and we are no longer developing new wellfields at Crow Butte and Smith Ranch-Highland. See Uranium – Tier-one operations starting on page 70 and Uranium – Tier-two operations beginning on page 81 for more information.

Uranium production

CAMECO SHARE |  | THREE MONTHS ENDED DECEMBER 31 |  |  | YEAR ENDED DECEMBER 31 |  |  |  |  |  |  |
(MILLION LBS) |  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |  |  | 2022 PLAN1 |  |  | 2023 PLAN |
Cigar Lake |  |  | 2.9 |  |  |  | 2.8 |  |  |  | 9.6 |  |  |  | 6.1 |  |  |  | 9.5 |  |  |  | 9.8 |
McArthur River/Key Lake |  |  | 0.8 |  |  |  | — |  |  |  | 0.8 |  |  |  | — |  |  |  | up to 1.4 |  |  |  | 10.5 |
Total |  |  | 3.7 |  |  |  | 2.8 |  |  |  | 10.4 |  |  |  | 6.1 |  |  |  | up to 10.9 |  |  |  | 20.3 |

1 | Cigar Lake was successful in catching up on development work that had been deferred from 2021, and the production target was updated to 9.5 million pounds (our share) in our 2022 second quarter MD&A. The increase also reflected our increase in ownership at Cigar Lake. A production target of up to 1.4 million pounds (our share) from McArthur River/Key Lake was provided in our 2022 second quarter MD&A due to commissioning delays at the mill.

PRODUCTION OUTLOOK

We remain focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. Our strategy includes a focus, in our uranium segment, on protecting and extending the value of our contract portfolio, on aligning our production decisions with our contract portfolio and market opportunities thereby preserving the value of our lowest cost assets in order to increase long-term value, and to do that with an emphasis on safety, people and the environment.

In 2023, we are planning production of 20.3 million pounds (our share).

Due to equity accounting, our share of production from Inkai is shown as a purchase. We expect total production from Inkai to be 8.3 million pounds (100% basis) in 2023. An adjustment to the production purchase entitlement allows us to purchase 4.2 million pounds in 2023. In addition, we expect to purchase the remaining share of our 2022 production entitlement, the majority of which is currently in transit.

MANAGEMENT’S DISCUSSION AND ANALYSIS 69

Uranium – Tier-one operations

McArthur River mine / Key Lake mill

|  | 2022 Production (our share)
| 0.8M lbs
| 2023 Production Outlook (our share)
| 10.5M lbs
| Estimated Reserves (our share)
| 275.0M lbs
| Estimated Mine Life
| 2044

McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the world’s largest uranium mill. Ore grades at the McArthur River mine are 100 times the world average. We are the operator of both the mine and mill.

McArthur River is considered a material uranium property for us. There is a technical report dated March 29, 2019 (effective December 31, 2018) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).

Location |  | Saskatchewan, Canada
Ownership |  |  |  | McArthur River – 69.805%
|  | Key Lake – 83.33%
Mine type |  |  |  | Underground
Mining methods |  | Blasthole stoping and raiseboring
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 275.0 million pounds (proven and probable), average grade U3O8: 6.70%
Estimated resources |  | 4.7 million pounds (measured and indicated), average grade U3O8: 2.23%
|  | 1.7 million pounds (inferred), average grade U3O8: 2.89%
Licensed capacity |  |  |  | Mine and mill: 25.0 million pounds per year
Licence term |  | Through October, 2023
Total packaged production: |  | 2000 to 2022 |  | 326.5 million pounds (McArthur River/Key Lake) (100% basis)
|  | 1983 to 2002 |  | 209.8 million pounds (Key Lake) (100% basis)
2022 production |  | 0.8 million pounds (1.1 million pounds on 100% basis)
2023 production outlook |  | 10.5 million pounds (15.0 million pounds on 100% basis)
Estimated decommissioning cost |  | $42 million – McArthur River (100% basis)
|  | $223 million – Key Lake (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

70 CAMECO CORPORATION

BACKGROUND

Mine description

The mineral reserves at McArthur River are contained within seven zones: Zones 1, 2, 3, 4, 4 South, A and B. Prior to care and maintenance, there were two active mining zones and one where development was significantly advanced.

Zone 2 has been actively mined since production began in 1999. The ore zone was initially divided into three freeze panels. As the freeze wall was expanded, the inner connecting freeze walls were decommissioned in order to recover the inaccessible uranium around the active freeze pipes. Mining of zone 2 is almost complete. About 4.7 million pounds of mineral reserves remain and we expect to recover them using a combination of raisebore and blasthole stope mining.

Zone 4 has been actively mined since 2010. The zone was divided into four freeze panels, and like in zone 2, as the freeze wall was expanded, the inner connecting freeze walls were decommissioned. Zone 4 has 116.6 million pounds of mineral reserves secured behind freeze walls and it will be the main source of production for the next several years. Raisebore mining and blasthole stoping will be used to recover the mineral reserves.

Zone 1 is the next planned mine area to be brought into production. Freezehole drilling was 90% complete and brine distribution construction was approximately 10% complete when work was suspended in 2018 as part of the production suspension. Work remaining before production can begin includes completion of the freezehole drilling, brine distribution construction, ground freezing and drill and extraction chamber development. Work is expected to resume in zone 1 in 2024. Once complete, an additional 48.0 million pounds of mineral reserves will be secured behind freeze walls. Blasthole stope mining is currently planned as the main extraction method.

We have successfully extracted over 325 million pounds (100% basis) since we began mining in 1999.

Mining methods and techniques

All the mineralized areas discovered to date at McArthur River are in, or partially in, water-bearing ground with significant pressure at mining depths.

There are three approved mining methods at McArthur River: raisebore mining, blasthole stope mining and boxhole mining. However, only raisebore and blasthole stope mining remain in use. Before we begin mining an area, we freeze the ground around it by circulating chilled brine through freezeholes to form an impermeable freeze barrier.

Blasthole stoping

Blasthole stoping began in 2011 and was the main extraction method prior to our production suspension. It is planned in areas where blastholes can be accurately drilled and small stable stopes excavated without jeopardizing the freeze wall integrity. The use of this method has allowed the site to improve operating costs by increasing overall extraction efficiency by reducing underground development, concrete consumption, mineralized waste generation and improving extraction cycle time.

Raisebore mining

Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River, and it has been used since mining began in 1999. This method is favourable for mining the weaker rock mass areas of the deposit, and is suitable for massive high-grade zones where there is access both above and below the ore zone.

Initial processing

McArthur River produces two product streams, high grade slurry and low-grade mineralized rock. Both product streams are shipped to Key Lake mill to produce uranium ore concentrate.

The high-grade material is ground and thickened into a slurry underground and then pumped to surface. The material is then thickened and blended for grade control and shipped to Key Lake in slurry totes using haul trucks.

The low-grade mineralized material is hoisted to surface and shipped as a dry product to Key Lake using covered haul trucks. Once at Key Lake, the material is ground, thickened and blended with the high-grade slurry to a nominal 5% U3O8 mill feed grade. It is then processed into uranium ore concentrate and packaged in drums for further processing offsite.

MANAGEMENT’S DISCUSSION AND ANALYSIS 71

Tailings capacity

Based on the current licence conditions, tailings capacity at Key Lake is sufficient to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Licensed annual production capacity

The McArthur River mine and Key Lake mill are both licensed to produce up to 25 million pounds (100% basis) per year. To achieve annual production at the licensed capacity, additional investment will be required.

2022 UPDATE

Production

The McArthur River and Key Lake operation was in a state of safe care and maintenance from 2018 through 2021 due to weak market conditions. Through most of 2022, we undertook the necessary operational readiness activities prior to restarting production. In November 2022, we announced that the first pounds of uranium ore from the McArthur River mine had been milled and packaged at the Key Lake mill, marking the achievement of initial production as these facilities transition back into normal operations.

Total packaged production from McArthur River and Key Lake in 2022 was 1.1 million pounds (0.8 million pounds our share) as the mine and mill resumed production.

Operational readiness activities consisted of recruitment, training, infrastructure upgrades and commissioning as well as reactivation of mobile equipment previously stored for care and maintenance. Operational activities included mine dewatering, water treatment, freeze wall maintenance, and environmental monitoring.

In 2022, production forecasts were revised as we worked through normal commissioning issues to integrate the existing and new assets with upgraded operational technology which caused some delays to schedule at the mill. During the year we expensed operational readiness costs of approximately $169 million directly to cost of sales. With the restart of production, in 2023 we will no longer expense monthly operational readiness costs.

Exploration

There was no exploration activity in 2022, as we focused on the restart of production.

PLANNING FOR THE FUTURE

Production

We plan to produce 15 million pounds (100% basis) in 2023 and 18 million pounds (100% basis) in 2024.

With the improvement in the uranium market and the success we have had in securing new long-term contracts, we have updated our 2024 production plan to achieve 18 million pounds (100% basis) per year starting in 2024. This will remain our production plan until we see further improvements in the uranium market and contracting progress, demonstrating that we continue to be a responsible supplier of uranium fuel.

Innovation

In 2020, we began a program to advance the assessment of innovation opportunities at the McArthur River mine and Key Lake mill. We established a team of internal experts who have been tasked with assessing, designing and implementing opportunities to improve operating efficiency. We continue to advance the projects that meet our investment criteria.

72 CAMECO CORPORATION

MANAGING OUR RISKS

The McArthur River deposit presents unique challenges that are not typical of traditional hard or soft rock mines. These challenges are the result of mining in or near high pressure ground water in challenging ground conditions with significant radiation concerns due to the high-grade uranium. We take significant steps and precautions to reduce the risks. Mine designs and mining methods are selected based on their ability to mitigate hydrological, radiological and geotechnical risks. Operational experience gained since the start of production has resulted in a significant reduction in risk. However, there is no guarantee that our efforts to mitigate risk will be successful.

In addition to the risks listed on pages 67 to 68, in 2023 we are focused on the management of the following risks:

Mine and mill ramp up

With the extended period of time the assets were on care and maintenance, the operational changes made, and commissioning issues that we have worked through at the mill, which caused delays to the production schedule in 2022, there is continued uncertainty regarding the timing of a successful ramp up to planned production and the associated costs. In addition, inflation, the availability of personnel with the necessary skills and experience, and the potential impact of supply chain challenges on the availability of materials and reagents carry with them the risks of not achieving our production plans, production delays and increased costs.

Labour relations

The collective agreement with the United Steelworkers local 8914 expired in December 2022. As in the past negotiations, work continues under the terms of the expired collective agreement while negotiations to reach a new agreement proceeded. There is a risk to the production plan if we are unable to reach an agreement and there is a labour dispute.

Licensing risk

The current operating licence from the CNSC for both Key Lake and McArthur River expire in October 2023. The relicensing process is under way for both sites, and we expect a decision from the CNSC later in 2023. We do not expect any interruption or significant risks from this process.

Water inflow risk

All the mineralized areas discovered to date at McArthur River are in, or partially in, water-bearing ground with significant pressure at mining depths. This high-pressure water source is isolated from active development and production areas in order to reduce the inherent risk of an inflow. McArthur River relies on pressure grouting and ground freezing, and sufficient pumping, water treatment and above ground storage capacity to mitigate the risks of the high-pressure ground water.

McArthur River has not experienced a significant disruption to its mining or development activities resulting from a water inflow since 2008. The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.

MANAGEMENT’S DISCUSSION AND ANALYSIS 73

Uranium – Tier-one operations

Cigar Lake

|  | 2022 Production (our share)
| 9.6M lbs
| 2023 Production Outlook (our share)
| 9.8M lbs
| Estimated Reserves (our share)
| 84.4M lbs
| Estimated Mine Life
| 2031

Cigar Lake is the world’s highest grade uranium mine, with grades that are 100 times the world average. We are a 54.5% owner and the mine operator. Cigar Lake uranium is milled at Orano’s McClean Lake mill.

Cigar Lake is considered a material uranium property for us. There is a technical report dated March 29, 2016 (effective December 31, 2015) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).

Location |  | Saskatchewan, Canada
Ownership |  | 54.547%
Mine type |  | Underground
Mining method |  | Jet boring system
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 84.4 million pounds (proven and probable), average grade U3O8: 17.21%
Estimated resources |  | 57.5 million pounds (measured and indicated), average grade U3O8: 13.19%
| 12.0 million pounds (inferred), average grade U3O8: 5.62%
Licensed capacity |  | 18.0 million pounds per year (our share 9.8 million pounds per year)
Licence term |  | Through June, 2031
Total packaged production: 2014 to 2022 |  | 123 million pounds (100% basis)
2022 production |  | 9.6 million pounds (18.0 million pounds on 100% basis)
2023 production outlook |  | 9.8 million pounds (18.0 million pounds on 100% basis)
Estimated decommissioning cost |  | $62 million (100% basis)
All values shown, including reserves and resources, 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 has the shape of a flat- to cigar-shaped lens.

Mine development is carried out in the basement rocks below the ore horizon. New mine development is required throughout the mine life to gain access to the ore above.

Mining method

At Cigar Lake, the permeable sandstone which overlays the deposit and basement rocks, contains large volumes of water at significant pressure. Before we begin mining, we freeze the ore zone and surrounding ground in the area to be mined to meet certain specifications. We use a jet boring mining method to extract the ore.

74 CAMECO CORPORATION

Jet boring system (JBS) mining

As a result of the unique geological conditions at Cigar Lake, we are unable to utilize traditional mining methods that require access above the ore, which necessitated the development of a non-entry mining method specifically adapted for this deposit. After many years of test mining, we selected jet boring, and it has been used since mining began in 2014. This method involves:

• |  | drilling a pilot hole into the frozen orebody, inserting a high pressure water jet and cutting a cavity out of 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 123 million pounds (100% basis) since we began mining in 2014.

Initial processing

We carry out initial processing of the extracted ore at Cigar Lake before shipping it to McClean Lake. To accomplish this, we:

• |  | grind the ore and mix it with water to form a slurry in our underground circuit

• |  | pump the slurry 500 metres to the surface and store it in one of two ore slurry holding tanks, where it is blended and thickened to remove excess water

• |  | the final slurry, at an average grade of approximately 15% 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.

2022 UPDATE

As announced in May, we along with Orano acquired Idemitsu Canada Resources Ltd.’s 7.875% participating interest in the Cigar Lake Joint Venture. Our ownership stake in Cigar Lake now stands at 54.547%, 4.522 percentage points higher than it was prior to the transaction.

Production

Total packaged production from Cigar Lake in 2022 was 18 million pounds U3O8 (9.6 million pounds our share) compared to 12.2 million pounds U3O8 (6.1 million pounds our share) in 2021. 2021 production was impacted by suspensions, which were a precautionary measure due to the COVID-19 pandemic. In 2022, we were successful in catching up on development work that had been deferred from 2021. Our share of production for 2022 has been updated to reflect the ownership increase effective May 19, 2022.

During the year, we:

• |  | executed planned 21-day annual maintenance activities in July

• |  | executed production activities from four production tunnels in the eastern part of the orebody

MANAGEMENT’S DISCUSSION AND ANALYSIS 75

• |  | in alignment with our long-term production planning, brought one new panel online as another production panel was depleted

• |  | continued underground header construction activities and expanded our ground freezing program to ensure continued frozen ore inventory

Underground development

Underground mine development continued in 2022. We completed the first production crosscut in the western portion of the orebody in preparation for ore mining starting in the second quarter of 2023.

PLANNING FOR THE FUTURE

Production

In 2023, we expect to produce 18 million pounds (100% basis) at Cigar Lake; our share is approximately 9.8 million pounds.

In 2023, we plan to:

• |  | continue production activities focused on bringing two new production panels online

• |  | complete surface freeze drilling and complete construction and commissioning of freeze distribution 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

• |  | continue upgrades to process water handling circuits and the surface backfill batch plant to support ongoing operations

• |  | execute a surface delineation drilling program and underground geotechnical drilling program

Consistent with our strategy to align our production decisions with our contract portfolio and market opportunities, we have updated our 2024 production plan. We expect to maintain production at the licensed rate of 18 million pounds (100% basis) per year based on our contracting success and the improved outlook for the uranium market compared to our previous plan of 13.5 million pounds (100% basis) per year in 2024.

MANAGING OUR RISKS

The Cigar Lake deposit presents unique challenges that are not typical of traditional hard or soft rock mines. These challenges are the result of mining in or near high-pressure ground water in challenging ground conditions with significant radiation concerns due to the high-grade uranium and elements of concern in the orebody with respect to water quality. We take significant steps and precautions to reduce the risks. Mine designs and the mining method are selected based on their ability to mitigate hydrological, radiological, and geotechnical risks. Operational experience gained since the start of production has resulted in a significant reduction in risk. However, there is no guarantee that our efforts to mitigate risk will be successful.

In addition to the risks listed on pages 67 to 68, in 2023 we are focused on the management of the following risks:

Inflation, labour shortages, and supply chain challenges

Inflation, the availability of personnel with the necessary skills and experience, and the impact of supply chain challenges on the availability of materials and reagents carry with them the risk of not achieving our production plans, production delays and increased costs in 2023 and future years.

Transition to new mining areas

In order to successfully achieve the planned production schedule, we must continue to successfully transition into new mining areas, which includes mine development and investment in critical support infrastructure. If development work is delayed for any reason, including availability of storage capacity for waste rock, our ability to meet our future production plans may be impacted.

Water inflow risk

The sandstone that overlays the Cigar Lake deposit and basement rocks is water-bearing with significant pressure at mining depths. This high-pressure water source is isolated from active development and production areas in order to reduce the inherent risk of an inflow. Cigar Lake relies on ground freezing and sufficient pumping, water treatment and above ground storage capacity to mitigate the risks of the high-pressure ground water.

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Cigar Lake has not experienced a significant disruption resulting from a water inflow since 2008. The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.

MANAGEMENT’S DISCUSSION AND ANALYSIS 77

Uranium – Tier-one operations

Inkai

|  | 2022 Production (100% basis)
| 8.3M lbs
| 2023 Production Outlook (100% basis)
| 8.3M lbs
| Estimated Reserves (our share)
| 108.7M lbs
| Estimated Mine Life
| 2045 (based on licence term)

Inkai is a very significant uranium deposit, located in Kazakhstan. The operator is JV Inkai limited liability partnership, which we jointly own (40%)1 with Kazatomprom (60%).

Inkai is considered a material uranium property for us. There is a technical report dated January 25, 2018 (effective January 1, 2018) that can be downloaded from SEDAR (sedar.com) or from EDGAR (sec.gov).

Location |  | South Kazakhstan
Ownership |  | 40%1
Mine type |  | In situ recovery (ISR)
End product |  | Uranium concentrate
Certifications |  | BSI OHSAS 18001
|  | ISO 14001 certified
Estimated reserves |  | 108.7 million pounds (proven and probable), average grade U3O8: 0.04%
Estimated resources |  | 35.6 million pounds (measured and indicated), average grade U3O8: 0.03%
|  | 9.6 million pounds (inferred), average grade U3O8: 0.03%
Licensed capacity (wellfields) |  | 10.4 million pounds per year (our share 4.2 million pounds per year)1
Licence term |  | Through July 2045
Total packaged production: 2009 to 2022 |  | 81 million pounds (100% basis)
2022 production |  | 8.3 million pounds (100% basis)1
2023 production outlook |  | 8.3 million pounds (100% basis)1
Estimated decommissioning cost (100% basis) |  | $20 million (US) (100% basis) (this estimate is currently under review)

All values shown, including reserves and resources, represent our share only, unless indicated.

1 | Our ownership interest in the joint venture is 40% and we equity account for our investment. As such, our share of production is shown as a purchase.

78 CAMECO CORPORATION

BACKGROUND

Mine description

The Inkai uranium deposit is a roll-front type orebody within permeable sandstones. The more porous and permeable units host several stacked and relatively continuous, sinuous “roll-fronts” of low-grade uranium forming a regional system. Superimposed over this regional system are several uranium projects and active mines.

Inkai’s mineralization ranges in depths from about 260 metres to 530 metres. The deposit has a surface projection of about 40 kilometres in length, and the width ranges from 40 to 1600 metres. The deposit has hydrogeological and mineralization conditions favourable for use of in-situ recovery (ISR) technology.

Mining and milling method

JV Inkai uses conventional, well-established, and very efficient ISR technology, developed after extensive test work and operational experience. The process involves five major steps:

• |  | leach the uranium in-situ by circulating an acid-based solution through 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

Total 2022 production from Inkai was 8.3 million pounds (100% basis) as planned, a decrease of 7% from 2021. In 2022, Inkai experienced a number of operational issues related to interruptions in reagent delivery and wellfield drilling. While the issues have been partially mitigated, their impact on production and inflationary pressure on production supplies pose a risk to JV Inkai’s 2023 production volume and its costs.

The first shipment of our share of JV Inkai’s 2022 production via the Trans-Caspian route arrived at a Canadian port in December 2022. This was the first shipment of our share of finished product from JV Inkai that did not rely on Russian rail lines or ports. However, the geopolitical situation continues to cause transportation risks in the region. Our 2022 share of earnings from this equity-accounted investee were impacted due to the timing of delivery of our share of 2022 production.

Production purchase entitlements

Under the terms of a restructuring agreement signed with our partner Kazatomprom in 2016, our ownership interest in JV Inkai is 40% and Kazatomprom’s share is 60%. However, during production rampup to the licensed limit of 10.4 million pounds, we are entitled to purchase 57.5% of the first 5.2 million pounds of annual production, and as annual production increases over 5.2 million pounds, we are entitled to purchase 22.5% of such incremental production, to the maximum annual share of 4.2 million pounds. Once the rampup to 10.4 million pounds annually is complete, we will be entitled to purchase 40% of such annual production, matching our ownership interest.

Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement, for 2022 we were entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s 2022 production of 8.3 million pounds. Timing of our JV Inkai purchases will fluctuate during the quarters and may not match production, and, in particular, in 2022, timing was impacted by shipping delays. Total purchases in 2022 were 3.3 million pounds, of which 2.6 million pounds were related to our 2022 entitlement. In 2023, we expect to purchase our remaining 2022 entitlement once it is delivered to our Blind River refinery. A second shipment containing the majority of the remaining 2022 production is currently in transit.

Cash distribution

Excess cash, net of working capital requirements, will be distributed to the partners as dividends. In 2022, we received dividend payments from JV Inkai totaling $92.4 million (US). Our share of dividends follows our production purchase entitlements as described above.

MANAGEMENT’S DISCUSSION AND ANALYSIS 79

PLANNING FOR THE FUTURE

Production

Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement described above, we are entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s planned 2023 production of 8.3 million pounds.

Our share of production is purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures.

In August 2022, Kazatomprom announced its plan to produce 10% below the planned volumes under its Subsoil Use Contracts in 2024.

MANAGING OUR RISKS

In addition to the risks listed on pages 67 to 68, JV Inkai also manages the following risks:

2023 production forecast

Presently, JV Inkai is experiencing wellfield development, procurement and supply chain issues, and inflationary pressures on its production materials and reagents. Achievement of its 2023 production forecast requires it to successfully manage these risks. If there is a significant disruption to JV Inkai’s operations for any reason, it may not achieve its production plans, there may be a delay in production, and it may experience increased costs to produce uranium. In addition, JV Inkai’s costs could be impacted by potential changes to the tax code in Kazakhstan and by possible increased financial contributions to social and other state causes, although these risks cannot be quantified or estimated at this time.

Transportation

The geopolitical situation continues to cause transportation risks in the region. We could continue to experience delays in our expected Inkai deliveries from 2022 and for 2023. To mitigate this risk, we have inventory, long-term purchase agreements and loan arrangements in place we can draw on. Depending on when we receive shipments of our share of Inkai’s production, our share of earnings from this equity-accounted investee and the timing of the receipt of our share of dividends from the joint venture may be impacted.

Political

Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our investment in JV Inkai is subject to the greater risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal and fiscal instability. Kazakhstan laws and regulations are complex and still developing and their application can be difficult to predict. The other owner of JV Inkai is Kazatomprom, an entity majority owned by the government of Kazakhstan. We have entered into agreements with JV Inkai and Kazatomprom intended to mitigate political risk. This risk includes the imposition of governmental laws or policies that could restrict or hinder JV Inkai paying us dividends, or selling us our share of JV Inkai production, or that impose discriminatory taxes or currency controls on these transactions. The restructuring of JV Inkai, which took effect January 1, 2018, was undertaken with the objective to better align the interests of Cameco and Kazatomprom and includes a governance framework that provides for protection for us as a minority owner of JV Inkai.

In early January 2022, Kazakhstan saw the most significant political instability since it became independent in 1991. The events resulted in a state of emergency being declared across the country. Order was restored in the second half of January, and the state of emergency was gradually lifted. In November 2022, President Tokayev was re-elected for a new 7-year term.

For more details on this risk, please see our most recent annual information form under the heading political risks.

JV Inkai manages risks listed on pages 67 to 68.

80 CAMECO CORPORATION

Uranium – Tier-two operations

Rabbit Lake

Located in Saskatchewan, Canada, our 100% owned Rabbit Lake operation opened in 1975, and has the second largest uranium mill in the world. Due to market conditions, we suspended production at Rabbit Lake during the second quarter of 2016.

Location |  | Saskatchewan, Canada
Ownership |  | 100%
End product |  | Uranium concentrates
ISO certification |  | ISO 14001 certified
Mine type |  | Underground
Estimated reserves |  | —
Estimated resources |  | 38.6 million pounds (indicated), average grade U3O8: 0.95%
|  | 33.7 million pounds (inferred), average grade U3O8: 0.62%
Mining methods |  | Vertical blasthole stoping
Licensed capacity |  | Mill: maximum 16.9 million pounds per year; currently 11 million
Licence term |  | Through October, 2023
Total production: 1975 to 2022 |  | 202.2 million pounds
2022 production |  | 0 million pounds
2023 production outlook |  | 0 million pounds
Estimated decommissioning cost |  | $213 million

PRODUCTION SUSPENSION

The facilities remained in a state of safe and sustainable care and maintenance throughout 2022.

While in standby, we continue to evaluate our options in order to minimize care and maintenance costs. We expect care and maintenance costs to range between $27 million and $32 million annually.

FUTURE PRODUCTION

We do not expect any production from Rabbit Lake in 2023.

MANAGING OUR RISKS

The current operating licence from the CNSC for Rabbit Lake expires in October 2023. The relicensing process is under way, and we expect a decision from the CNSC later in 2023.

We also manage the risks listed on pages 67 to 68.

MANAGEMENT’S DISCUSSION AND ANALYSIS 81

US ISR Operations

Located in Nebraska and Wyoming in the US, the Crow Butte and Smith Ranch-Highland (including the North Butte satellite) operations began production in 1991 and 1975. Each operation has its own processing facility. Due to market conditions, we curtailed production and deferred all wellfield development at these operations during the second quarter of 2016.

Ownership |  |  |  | 100%
End product |  |  |  | Uranium concentrates
ISO certification |  |  |  | ISO 14001 certified
Estimated reserves |  | Smith Ranch-Highland: |  | —
|  | North Butte-Brown Ranch: |  | —
|  | Crow Butte: |  | —
Estimated resources |  | Smith Ranch-Highland: |  | 24.9 million pounds (measured and indicated), average grade U3O8: 0.06%
|  |  |  | 7.7 million pounds (inferred), average grade U3O8: 0.05%
|  | North Butte-Brown Ranch: |  | 9.4 million pounds (measured and indicated), average grade U3O8: 0.07%
|  |  |  | 0.4 million pounds (inferred), average grade U3O8: 0.06%
|  | Crow Butte: |  | 13.9 million pounds (measured and indicated), average grade U3O8: 0.25%
|  |  |  | 1.8 million pounds (inferred), average grade U3O8: 0.16%
Mining methods |  |  |  | In situ recovery (ISR)
Licensed capacity |  | Smith Ranch-Highland:1 |  | Wellfields: 3 million pounds per year; processing plants: 5.5 million pounds per year
|  | Crow Butte: |  | Processing plants and wellfields: 2 million pounds per year
Licence term |  | Smith Ranch-Highland: |  | Through September, 2028
|  | Crow Butte: |  | Through October, 2024
Total production: 2002 to 2022 |  | 33.0 million pounds
2022 production |  |  |  | 0 million pounds
2023 production outlook |  |  |  | 0 million pounds
Estimated decommissioning cost |  | Smith Ranch-Highland: $219 million (US), including North Butte
|  | Crow Butte: $56 million (US)

1 | Including Highland mill

PRODUCTION CURTAILMENT

As a result of our 2016 decision, commercial production at the US operations ceased in 2018. We expect ongoing cash and non-cash care and maintenance costs to range between $12 million (US) and $14 million (US) for 2023.

FUTURE PRODUCTION

We do not expect any production in 2023.

MANAGING OUR RISKS

We manage the risks listed on pages 67 to 68.

82 CAMECO CORPORATION

Uranium – advanced projects

Work on our advanced projects has been scaled back and will continue at a pace aligned with market signals.

Millennium

Location |  | Saskatchewan, Canada
Ownership |  | 69.9%
End product |  | Uranium concentrates
Potential mine type |  | Underground
Estimated resources (our share) |  | 53.0 million pounds (indicated), average grade U3O8: 2.39% 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.

2022 PROJECT UPDATES

We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment our primary focus is on producing from our tier-one uranium assets at a pace aligned with our contract portfolio and market opportunities. We continue to await a signal from our customers that additional production is needed prior to making any new development decisions.

PLANNING FOR THE FUTURE

2023 Planned activity

No work is planned at Millennium, Yeelirrie or Kintyre.

Further progress towards a development decision on any of these projects is not expected until the market fully transitions and supply is incented by prices that reflect production economics.

MANAGEMENT’S DISCUSSION AND ANALYSIS 83

MANAGING THE RISKS

Project approval

The approval received for Kintyre from the prior state government required substantial commencement of the project by March 2020, being within five years of the grant of the approval, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future, we can apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Kintyre project, provided we have all other required regulatory approvals.

The approval for the Yeelirrie project, received from the prior state government, required substantial commencement of the project by January 2022, and this was not achieved. The current government declined to grant us an extension to achieve it. In the future, we can again apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Yeelirrie project, provided we have all other required regulatory approvals. Approval for the Yeelirrie project at the federal level was granted in 2019 and extends until 2043.

For all of our advanced projects, we manage the risks listed on pages 67 to 68.

84 CAMECO CORPORATION

Uranium – exploration

Our exploration program is directed at replacing mineral reserves as they are depleted by our production and is key to sustaining our business. We are focused on exploration near our existing operations where we have established infrastructure and capacity to expand. Globally, we have land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia and the US. Our land holdings total about 0.78 million hectares (1.9 million acres). In northern Saskatchewan alone, we have direct interests in about 0.68 million hectares (1.7 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin.

2022 UPDATE

Brownfield exploration

Brownfield exploration is uranium exploration near our existing operations and includes expenses for advanced exploration on the evaluation of projects where uranium mineralization is being defined.

In 2022, we spent about $2 million on brownfields and advanced uranium projects in Saskatchewan and Australia. At the US operations we spent $1 million.

Regional exploration

We spent about $8 million on regional exploration programs (including support costs), primarily in Saskatchewan’s Athabasca Basin.

PLANNING FOR THE FUTURE

We will maintain an active uranium exploration program and continue to focus on our core projects in Saskatchewan under our long-term exploration strategy. Long-term, we look for properties that meet our investment criteria. We may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our industry expertise in both exploration and corporate social responsibility make us a partner of choice.

MANAGEMENT’S DISCUSSION AND ANALYSIS 85

Fuel services

Refining, conversion and fuel manufacturing

We have about 21% of world UF6 primary conversion capacity and are a supplier of natural UO2. Our focus is on cost-competitiveness and operational efficiency, as well as increasing our production of UF6 in line with our contract portfolio and market opportunities.

Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and meet customer needs.

Blind River Refinery

|  | Licensed Capacity 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

86 CAMECO CORPORATION

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 87

2022 UPDATE

Production

Fuel services produced 13.0 million kgU, 7% higher than 2021 due to an increase in demand in 2022.

Port Hope conversion facility cleanup and modernization (Vision in Motion)

Vision in Motion is a unique opportunity that demonstrates our continued commitment to a clean environment. It has been made possible by the opening of a long-term waste management facility by the Government of Canada’s Port Hope Area Initiative project. There is a limited opportunity during the life of this project to engage in clean-up and renewal activities that address legacy waste at the Port Hope Conversion facility inherited from historic operations. Progress was made over the past year to facilitate the removal of some old buildings and structures, which will be the focus in the year ahead.

PLANNING FOR THE FUTURE

Production

We plan to produce between 13 million and 14 million kgU in 2023. In addition, at our Port Hope UF6 conversion facility we are working on increasing annual production to 12,000 tonnes in 2024 to satisfy our book of long-term business and demand for conversion services.

Also, in conjunction with our initiative intended to provide a greater focus on technology and its applications to improve efficiency and reduce costs across the organization, we will continue to look for opportunities to improve operational effectiveness, including the use of digital and automation technologies.

Licensing

In January 2023, the CNSC granted a 20-year renewal to the licence for CFM. The licence renewal also grants CFM’s request for a slight production increase to 1,650 tonnes as UO2 fuel pellets.

MANAGING OUR RISKS

We take significant steps and precautions to reduce risk. However, there is no guarantee that our efforts to mitigate risk will be successful.

In addition to the risks listed on pages 67 to 68, in 2023 we are focused on the management of the following risk:

Production plans

Inflation, the availability of personnel with the necessary skills and experience, aging infrastructure, and the potential impact of supply chain challenges on the availability of materials and reagents carry the risk of not achieving our production plans, production delays, and increased costs in 2023 and future years.

88 CAMECO CORPORATION

Other Nuclear Fuel Cycle Investments

Global Laser Enrichment

Global Laser Enrichment LLC (GLE) is the exclusive licensee of the proprietary Separation of Isotopes by Laser Excitation (SILEX) laser enrichment technology, a third-generation uranium enrichment technology. We are the commercial lead for the GLE project with a 49% interest and starting in February 2023, an option to attain a majority interest of up to 75% ownership.

Subject to completion of the technology development program, and its progression through to commercialization, GLE has the potential to offer a variety of advantages to the global nuclear energy sector over the long-term, which include:

• |  | re-enriching depleted uranium tails leftover as a by-product of previous-generation enrichment technologies, repurposing legacy waste into a commercial source of uranium and conversion products to fuel nuclear reactors and aiding in the responsible clean-up of enrichment facilities no longer in operation, as per GLE’s agreement with the U.S. Department of Energy

• |  | producing commercial low-enriched uranium (LEU) fuel for the world’s existing and future fleet of large-scale light-water reactors with greater efficiency and flexibility than current enrichment technologies

• |  | producing high-assay low-enriched uranium (HALEU), the primary fuel stock for the majority of small modular reactor (SMR) and advanced reactor designs that are proceeding through the development stage and continuing toward commercial readiness

In 2022, GLE made progress with the first full-scale laser system module, successfully completing eight months of testing in Australia, and the system was delivered to GLE’s commercial pilot demonstration facility in the US. In addition, GLE signed letters of intent to collaborate with two major US utilities to help diversify the US nuclear fuel supply chain, including measures to support its deployment of laser enrichment technology in the US.

The development timeline for GLE will be dependent on several factors, including market fundamentals, securing government funding, support for HALEU availability in the US and GLE’s ability to secure long-term contracts to underpin the deployment of a commercial facility.

MANAGING OUR RISKS

GLE is subject to the risks relating to the nuclear industry discussed under the heading Caution about forward-looking information beginning on page 2.

Proposed acquisition of Westinghouse

As announced on October 11, 2022, we entered into a strategic partnership with Brookfield Renewable and its institutional partners to acquire Westinghouse Electric Company (Westinghouse), a global provider of mission-critical and specialized technologies, products and services across most phases of the nuclear power sector. Brookfield Renewable will beneficially own a 51% interest in Westinghouse and Cameco will beneficially own 49%. Bringing together Cameco’s expertise in the nuclear industry with Brookfield Renewable’s expertise in clean energy positions nuclear power at the heart of the energy transition and creates a powerful platform for strategic growth across the nuclear sector.

Westinghouse’s history in the energy industry stretches back over a century, during which time the company became a pioneer in nuclear energy.

Westinghouse is organized in three business segments:

• |  | Operating Plant Services: Long-term contracting for the manufacturing and installation of fuel assemblies and other ancillary equipment across multiple light water reactor technologies. Westinghouse provides recurring services for outages and maintenance, engineering solutions, and replacement components and parts.

• |  | Energy Systems: Designing, engineering and supporting the development of new nuclear reactors.

• |  | Environmental Services: Services to government and commercial customers that support nuclear sustainability, environmental stewardship and remediation.

MANAGEMENT’S DISCUSSION AND ANALYSIS 89

The largest business segment is Operating Plant Services, which accounted for approximately $2.7 billion (US) or about 81% of Westinghouse’s total 2021 revenue of approximately $3.3 billion (US). This segment is built on long-term customer relationships. These customers seek solutions to ensure their reactors operate efficiently and reliably and therefore results in predictable revenue streams.

The acquisition of Westinghouse will be through a strategic partnership with Brookfield Renewable in the form of a limited partnership that will allow each of us to further participate in and support the growing momentum for nuclear energy. The board of directors of the general partner of the limited partnership will consist of six directors, three appointed by Cameco and three appointed by Brookfield Renewable. Decision-making by the board of the general partnership will correspond to percentage ownership interests in the limited partnership (51% Brookfield Renewable and 49% Cameco). There are a number of significant decisions that require the presence and support of both Cameco and Brookfield Renewable appointees to the board as long as certain ownership thresholds are met. These “reserved” matters will include decisions such as the approval of the annual budget, entering into material contracts, the making of significant investments, entering into new lines of business and related-party transactions. We expect to account for our share of the investment using the equity method.

We expect the acquisition to:

• |  | expand our participation in the nuclear fuel value chain. The acquisition is expected to complement our high-quality, tier-one uranium assets and fuel services, including CANDU fuel manufacturing for heavy water reactors with Westinghouse’s global nuclear fuel and plant services platform for light water reactors, which we expect will augment and expand our ability to meet the growing demand for nuclear fuel supplies and services that are reliable and secure;

• |  | be accretive to our cash flow after the closing, and prior to considering new revenue opportunities and to complement our existing business. Based on Westinghouse’s strong long-term customer relationships, the service type model of the Operating Plant Services segment and resulting reliable revenue streams we expect it to generate stable cash flow, to fund its approved annual operating budget and provide quarterly distributions to the partners after the closing;

• |  | create new revenue opportunities for us by expanding our ability to satisfy existing and new customer needs. In addition to Westinghouse’s contribution to our financial results, the acquisition is expected to result in up to $50 million in additional revenue for Cameco in the year following the closing of the transaction and to result in additional revenue opportunities for us in the future from new customers and existing customers seeking a fully fabricated fuel supply option; and

• |  | maintain our strong balance sheet through a disciplined funding strategy designed to enhance our financial strength. At the same time, we expect to continue to execute on our strategy and provide a platform for further growth, expanding our reach in an industry that has historically performed well during varying macroeconomic environments due to the baseload nature of nuclear power and its strong customer base.

MANAGING OUR RISKS

The proposed acquisition of a beneficial ownership interest in Westinghouse is subject to the risks that are discussed under the heading Caution about forward-looking information beginning on page 2. For a further description of the material risks relating to the acquisition, please refer to Risk Factors — Risks Related to the Acquisition in our October 12, 2022, prospectus supplement filed with the U.S. Securities and Exchange Commission and Canadian securities administrators. It is available at www.sec.gov and www.sedar.com.

WESTINGHOUSE NON-GAAP MEASURES

When we announced the proposed acquisition, we had derived the following summary financial information from Westinghouse’s annual and interim consolidated financial statements, which are reported in US dollars and prepared in accordance with US generally accepted accounting principles (GAAP). Since the transaction has not closed and ownership has not transferred, we are unable to update this information. The Westinghouse financial information is not predictive of actual future results. Additionally, the financial information for Westinghouse does not take into account any circumstances or geopolitical or other events occurring after the date it was prepared. We will evaluate the appropriate and required disclosures when the acquisition closes, assuming all regulatory and other approvals are received.

90 CAMECO CORPORATION

Adjusted EBITDA, adjusted free cash flow, adjusted EBITDA margin and adjusted free cash flow margin are measures that do not have a standardized meaning or a consistent basis of calculation under GAAP (non-GAAP measure). These measures are used by Cameco and other users, including our lenders and investors, to assess Westinghouse’s results of operations from a management perspective without regard to its capital structure. We believe that these measures are useful to management, lenders, and investors in assessing the underlying performance of Westinghouse’s ongoing operations and its ability to generate cash flows to fund its cash requirements.

Westinghouse’s adjusted EBITDA is defined as its net income, adjusted for the impact of certain expenses, costs, charges or benefits incurred in such period which are either not indicative of underlying business performance or that impact the ability to assess the operating performance of its business. Westinghouse may realize similar gains or incur similar expenditures in the future. The other measures are defined in the table below.

Adjusted EBITDA, adjusted free cash flow, adjusted EBITDA margin and adjusted free cash flow margin are specified financial measures and should not be considered in isolation or as a substitute for financial information prepared according to GAAP. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

The following financial information of Westinghouse was prepared by us at the time of the announced acquisition and was derived from (i) Westinghouse’s annual consolidated financial statements as at and for the years ended December 31, 2019, 2020 and 2021 and (ii) Westinghouse’s interim consolidated financial statements as at and for the six-months ended June 30, 2021 and 2022 which are reported in US dollars and prepared in accordance with US GAAP. The following table provides a reconciliation of Westinghouse’s net income to adjusted EBITDA, adjusted free cash flow, adjusted EBITDA margin and adjusted free cash flow margin for the years ended December 31, 2019, 2020 and 2021 and for the twelve-month period ended June 30, 2022:

($US MILLIONS) |  | LTM ENDED JUNE 30, 2022 |  |  | 2021 |  |  | 2020 |  |  | 2019 |
Net income |  |  | 559 |  |  |  | 126 |  |  |  | 42 |  |  |  | 26 |
Depreciation and amortization |  |  | 299 |  |  |  | 303 |  |  |  | 289 |  |  |  | 284 |
Interest costs (net, including accretion) |  |  | 183 |  |  |  | 186 |  |  |  | 221 |  |  |  | 243 |
Income tax (recovery) |  |  | (433 | ) |  |  | (17 | ) |  |  | 15 |  |  |  | (6 | )
Restructuring and acquisition related expenses |  |  | 89 |  |  |  | 67 |  |  |  | 70 |  |  |  | 97 |
Gain (loss) on disposal of fixed assets |  |  | (1 | ) |  |  | 7 |  |  |  | 5 |  |  |  | (9 | )
Non-operating income |  |  | (1 | ) |  |  | — |  |  |  | (3 | ) |  |  | (36 | )
Impact of derivative instruments |  |  | 12 |  |  |  | 2 |  |  |  | (20 | ) |  |  | — |
Other non-operating items |  |  | (7 | ) |  |  | 21 |  |  |  | 28 |  |  |  | 13 |
Adjusted EBITDA |  |  | 701 |  |  |  | 695 |  |  |  | 646 |  |  |  | 613 |
Capital expenditures |  |  | 145 |  |  |  | 154 |  |  |  | 133 |  |  |  | 138 |
Revenue |  |  | 3,273 |  |  |  | 3,286 |  |  |  | 3,275 |  |  |  | 3,350 |
Adjusted free cash flow (adjusted EBITDA - capital expenditures) |  |  | 556 |  |  |  | 541 |  |  |  | 513 |  |  |  | 475 |
Adjusted EBITDA margin (adjusted EBITDA/revenue) |  |  | 21 | % |  |  | 21 | % |  |  | 20 | % |  |  | 18 | %
Adjusted free cash flow margin (adjusted free cash flow/adjusted EBITDA) |  |  | 79 | % |  |  | 78 | % |  |  | 79 | % |  |  | 78 | %

Calculations may not compute due to rounding

The total enterprise purchase price for the acquisition is $7.875 billion (US), which includes an assumption of an estimated $3.4 billion (US) of debt which will remain with Westinghouse, and which is subject to customary purchase price adjustments. The remainder of the purchase price will be paid by approximately $4.5 billion (US) of aggregate cash contributions, our share of which will be approximately $2.2 billion (US).

MANAGEMENT’S DISCUSSION AND ANALYSIS 91

Concurrently with the execution of the acquisition agreement, we secured commitments that provide for a $1 billion (US) bridge loan facility and $600 million (US) in term loans. Following the announcement, we undertook a $650 million (US) bought deal offering of common shares, with an underwriter option to purchase additional shares. The offering closed on October 17, 2022, providing us with gross proceeds of approximately $747.6 million (US) including the underwriters’ exercise of the option to purchase additional shares in full. With the proceeds from the closing of the offering and based on current uncertainty in the global macroeconomic environment and the success we are having in adding new long-term business, at this time, we do not intend to issue additional equity to fund our portion of the purchase price for the Westinghouse acquisition. As of the closing of the bought deal offering, the bridge loan facility was reduced to $280 million (US). The debt facilities will remain undrawn until closing of the acquisition. The bridge facility, if funded, will mature 364 days after the acquisition closing date, and the term loans consisting of two tranches of $300 million (US) each, are expected to mature two years and three years after the acquisition closes.

The acquisition is expected to close in the second half of 2023 and continues to be subject to customary closing conditions and certain regulatory approvals. The final financing is not required until close of the acquisition and will be determined based on market conditions and the expected run rate of our business at that time. We expect a permanent financing mix of capital sources, including cash, debt and equity, designed to preserve our balance sheet and ratings strength, while maintaining healthy liquidity.

Caution about forward-looking information relating to the Westinghouse acquisition

This discussion of our expectations for the Westinghouse acquisition, including sources and uses of financing for the acquisition, timeline for the acquisition, including anticipated closing date, expected benefits, and our intention in respect of not issuing additional equity to fund our portion of the purchase price for the Westinghouse acquisition is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headings Caution about forward-looking information beginning on page 2, and in our October 18, 2022 material change report. The material change report is available at www.sedar.com and www.sec.gov. Actual results and events may be significantly different from what we currently expect.

92 CAMECO CORPORATION

Corporate development

Investment program

Currently, with our extensive portfolio of mineral reserves and resources and our belief that we have ample productive capacity with the ability to expand as the demand for nuclear energy and nuclear fuels grows, our focus is on navigating by our investment-grade rating and returning to our tier-one run rate while aligning our tier-one production with our delivery commitments and market opportunities. We expect that these assets will allow us to meet rising uranium demand with increased production from our best margin operations and will help to mitigate risk in the event of prolonged uncertainty.

Additionally, we are exploring opportunities across the fuel cycle, which align well with our commitment to responsibly and sustainably manage our business and increase our contributions to global climate change solutions. These opportunities include investments such as our recently announced plans to acquire a 49% interest in Westinghouse Electric Company, as well as emerging opportunities such as our investment in Global Laser Enrichment LLC. It also includes the non-binding arrangements we have signed to explore several areas of cooperation to advance the commercialization and deployment of small modular reactors in Canada and around the world.

We continually evaluate investment opportunities within the nuclear fuel cycle that could add to our future supply options, support our customer’s needs, and complement and enhance our business in the nuclear industry. We will make an investment decision when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our stakeholders in a fundamentally stronger position. As such, an investment opportunity is never assessed in isolation. Investments must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described under Our vision, values and strategy, starting on page 23.

MANAGEMENT’S DISCUSSION AND ANALYSIS 93

Mineral reserves and resources

Our mineral reserves and resources are the foundation of our company and fundamental to our success.

We have interests in a number of uranium properties. The tables in this section show the estimates of the proven and probable mineral reserves, and measured, indicated, and inferred mineral resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River/Key Lake, Cigar Lake and Inkai. Mineral reserves and resources are all reported as of December 31, 2022.

We estimate and disclose mineral reserves and resources in five categories, using the definition standards adopted by the Canadian Institute of Mining, Metallurgy and Petroleum Council, and in accordance with National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), developed by the Canadian Securities Administrators. You can find out more about these categories at www.cim.org.

About mineral resources

Mineral resources do not have to demonstrate economic viability but have reasonable prospects for eventual economic extraction. They fall into three categories: measured, indicated and inferred. Our reported mineral resources are exclusive of mineral reserves.

• |  | measured and indicated mineral resources can be estimated with sufficient confidence to allow the 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 $53 (US) per pound U3O8, and current or projected operating costs and mine plans to report our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate. For properties in which Cameco has an interest but is not the operator, we will take reasonable steps to ensure that the reserve and resource estimates that we report are reliable.

Our share of uranium in the mineral reserves table below is based on our respective ownership interests.

94 CAMECO CORPORATION

Changes this year

Our share of proven and probable mineral reserves increased from 464 million pounds U3O8 at the end of 2021, to 469 million pounds at the end of 2022. The change was primarily the result of:

• |  | a mineral resource and reserve estimate update at Cigar Lake which added 9 million pounds to proven and probable reserves based on ongoing surface freeze drilling results.

• |  | increased ownership stake at Cigar Lake which added 7 million pounds

partially offset by:

• |  | production at Cigar Lake, Inkai and McArthur River, which removed 14 million pounds from our mineral inventory

The remaining changes are attributable to other adjustments based on the mineral resource and reserve estimate updates at Cigar Lake and McArthur River.

Our share of measured and indicated mineral resources increased from 447 million pounds U3O8 at the end of 2021, to 451 million pounds at the end of 2022. Our share of inferred mineral resources remains unchanged at 154 million pounds U3O8.

MANAGEMENT’S DISCUSSION AND ANALYSIS 95

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:

MCARTHUR RIVER/KEY LAKE

• |  | Greg Murdock, general manager, McArthur River, Cameco

• |  | Daley McIntyre, general manager, Key Lake, Cameco

• |  | Alain D. Renaud, principal resource geologist, technical services, Cameco

• |  | Biman Bharadwaj, principal metallurgist, technical services, Cameco

CIGAR LAKE

• |  | Lloyd Rowson, general manager, Cigar Lake, Cameco

• |  | Scott Bishop, director, technical services, Cameco

• |  | Alain D. Renaud, principal resource geologist, technical services, Cameco

• |  | Biman Bharadwaj, principal metallurgist, technical services, Cameco

INKAI

• |  | Alain D. Renaud, principal resource geologist, technical services, Cameco

• |  | Scott Bishop, director, technical services, Cameco

• |  | Biman Bharadwaj, principal metallurgist, technical services, Cameco

• |  | Sergey Ivanov, deputy director general, technical services, Cameco Kazakhstan LLP

Important information about 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.

96 CAMECO CORPORATION

Mineral reserves

As of December 31, 2022 (100% – only the shaded column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | OUR |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | SHARE |  |  |  |
|  |  |  | PROVEN |  |  | PROBABLE |  |  | TOTAL MINERAL RESERVES |  |  | RESERVES |  |  |  |
|  | MINING |  |  |  |  | GRADE |  |  | CONTENT |  |  |  |  |  | GRADE |  |  | CONTENT |  |  |  |  |  | GRADE |  |  | CONTENT |  |  | CONTENT |  |  | METALLURGICAL |
PROPERTY |  | METHOD |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | (LBS U3O8) |  |  | RECOVERY (%) |
Cigar Lake |  | UG |  |  | 308.9 |  |  |  | 16.25 |  |  |  | 110.7 |  |  |  | 99.1 |  |  |  | 20.19 |  |  |  | 44.1 |  |  |  | 408.0 |  |  |  | 17.21 |  |  |  | 154.8 |  |  |  | 84.4 |  |  |  | 98.8 |
Key Lake |  | OP |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 95 |
McArthur River |  | UG |  |  | 2,138.3 |  |  |  | 7.00 |  |  |  | 329.9 |  |  |  | 530.7 |  |  |  | 5.47 |  |  |  | 64.0 |  |  |  | 2,669.0 |  |  |  | 6.70 |  |  |  | 394.0 |  |  |  | 275.0 |  |  |  | 99 |
Inkai |  | ISR |  |  | 253,647.2 |  |  |  | 0.04 |  |  |  | 218.3 |  |  |  | 71,803.1 |  |  |  | 0.03 |  |  |  | 53.5 |  |  |  | 325,450.3 |  |  |  | 0.04 |  |  |  | 271.8 |  |  |  | 108.7 |  |  |  | 85 |
Total |  |  |  |  | 256,155.6 |  |  |  | — |  |  |  | 659.7 |  |  |  | 72,432.9 |  |  |  | — |  |  |  | 161.6 |  |  |  | 328,588.5 |  |  |  | — |  |  |  | 821.3 |  |  |  | 468.8 |  |  |  | — |

(UG – underground, OP – open pit, ISR – in situ recovery)

Note that the estimates in the above table:

| • |  | use a constant dollar average uranium price of approximately $53 (US) per pound U3O8

| • |  | are based on exchange rates of $1.00 US=$1.26 Cdn and $1.00 US=490 Kazakhstan Tenge

Our estimate of mineral reserves and mineral resources may be positively or negatively affected by the occurrence of one or more of the material risks discussed under the heading Caution about forward-looking information beginning on page 2, as well as certain property-specific risks. See Uranium – Tier-one operations starting on page 70.

Metallurgical recovery

We report mineral reserves as the quantity of contained ore supporting our mining plans and provide an estimate of the metallurgical recovery for each uranium property. The estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process is obtained by multiplying the quantity of contained metal (content) by the planned metallurgical recovery percentage. The content and our share of uranium in the table above are before accounting for estimated metallurgical recovery.

2022 CONSOLIDATED FINANCIAL STATEMENTS AND NOTES 97

Mineral resources

As of December 31, 2022 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | OUR 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 |  |  | 48.0 |  |  |  | 6.06 |  |  |  | 6.4 |  |  |  | 314.1 |  |  |  | 14.28 |  |  |  | 98.9 |  |  |  | 105.3 |  |  |  | 57.5 |  |  |  | 178.2 |  |  |  | 5.62 |  |  |  | 22.1 |  |  |  | 12.0 |
Fox Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 386.7 |  |  |  | 7.99 |  |  |  | 68.1 |  |  |  | 53.3 |
Kintyre |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,897.7 |  |  |  | 0.62 |  |  |  | 53.5 |  |  |  | 53.5 |  |  |  | 53.5 |  |  |  | 517.1 |  |  |  | 0.53 |  |  |  | 6.0 |  |  |  | 6.0 |
McArthur River |  |  | 74.9 |  |  |  | 2.23 |  |  |  | 3.7 |  |  |  | 63.0 |  |  |  | 2.23 |  |  |  | 3.1 |  |  |  | 6.8 |  |  |  | 4.7 |  |  |  | 38.9 |  |  |  | 2.89 |  |  |  | 2.5 |  |  |  | 1.7 |
Millennium |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,442.6 |  |  |  | 2.39 |  |  |  | 75.9 |  |  |  | 75.9 |  |  |  | 53.0 |  |  |  | 412.4 |  |  |  | 3.19 |  |  |  | 29.0 |  |  |  | 20.2 |
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,836.5 |  |  |  | 0.95 |  |  |  | 38.6 |  |  |  | 38.6 |  |  |  | 38.6 |  |  |  | 2,460.9 |  |  |  | 0.62 |  |  |  | 33.7 |  |  |  | 33.7 |
Tamarack |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 17.9 |  |  |  | 10.3 |  |  |  | 45.6 |  |  |  | 1.02 |  |  |  | 1.0 |  |  |  | 0.6 |
Yeelirrie |  |  | 27,172.9 |  |  |  | 0.16 |  |  |  | 95.9 |  |  |  | 12,178.3 |  |  |  | 0.12 |  |  |  | 32.2 |  |  |  | 128.1 |  |  |  | 128.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Crow Butte |  |  | 1,558.1 |  |  |  | 0.19 |  |  |  | 6.6 |  |  |  | 939.3 |  |  |  | 0.35 |  |  |  | 7.3 |  |  |  | 13.9 |  |  |  | 13.9 |  |  |  | 531.4 |  |  |  | 0.16 |  |  |  | 1.8 |  |  |  | 1.8 |
Gas Hills - Peach |  |  | 687.2 |  |  |  | 0.11 |  |  |  | 1.7 |  |  |  | 3,626.1 |  |  |  | 0.15 |  |  |  | 11.6 |  |  |  | 13.3 |  |  |  | 13.3 |  |  |  | 3,307.5 |  |  |  | 0.08 |  |  |  | 6.0 |  |  |  | 6.0 |
Inkai |  |  | 87,192.7 |  |  |  | 0.03 |  |  |  | 56.1 |  |  |  | 65,236.0 |  |  |  | 0.02 |  |  |  | 32.9 |  |  |  | 89.1 |  |  |  | 35.6 |  |  |  | 36,165.2 |  |  |  | 0.03 |  |  |  | 23.9 |  |  |  | 9.6 |
North Butte - Brown Ranch |  |  | 604.2 |  |  |  | 0.08 |  |  |  | 1.1 |  |  |  | 5,530.3 |  |  |  | 0.07 |  |  |  | 8.4 |  |  |  | 9.4 |  |  |  | 9.4 |  |  |  | 294.5 |  |  |  | 0.06 |  |  |  | 0.4 |  |  |  | 0.4 |
Ruby Ranch |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 56.2 |  |  |  | 0.13 |  |  |  | 0.2 |  |  |  | 0.2 |
Shirley Basin |  |  | 89.2 |  |  |  | 0.15 |  |  |  | 0.3 |  |  |  | 1,638.2 |  |  |  | 0.11 |  |  |  | 4.1 |  |  |  | 4.4 |  |  |  | 4.4 |  |  |  | 508.0 |  |  |  | 0.10 |  |  |  | 1.1 |  |  |  | 1.1 |
Smith Ranch - Highland |  |  | 3,703.5 |  |  |  | 0.10 |  |  |  | 7.9 |  |  |  | 14,372.3 |  |  |  | 0.05 |  |  |  | 17.0 |  |  |  | 24.9 |  |  |  | 24.9 |  |  |  | 6,861.0 |  |  |  | 0.05 |  |  |  | 7.7 |  |  |  | 7.7 |
Total |  |  | 121,130.7 |  |  |  | — |  |  |  | 179.7 |  |  |  | 113,473.7 |  |  |  | — |  |  |  | 405.5 |  |  |  | 585.2 |  |  |  | 451.4 |  |  |  | 51,763.7 |  |  |  | — |  |  |  | 203.5 |  |  |  | 154.4 |

Note that mineral resources:

| • |  | do not include amounts that have been identified as mineral reserves

| • |  | do not have demonstrated economic viability

| • |  | totals may not add due to rounding

98 CAMECO CORPORATION

Additional information

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

We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements. These estimates affect all of our segments, unless otherwise noted.

Decommissioning and reclamation

In our uranium and fuel services segments, we are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position. See note 16 to the financial statements.

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, 2022, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

2022 CONSOLIDATED FINANCIAL STATEMENTS AND NOTES 99

Management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that, while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2022.

There have been no changes in our internal control over financial reporting during the year that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

New standards adopted

A number of amendments to existing standards became effective January 1, 2022, but they did not have an effect on our financial statements.

A number of amendments to existing standards are not yet effective for the year ended December 31, 2022, and have not been applied in preparing these consolidated financial statements. We do not intend to early adopt any of the amendments and do not expect them to have a material impact on our financial statements.

100 CAMECO CORPORATION