Exhibit 99.2

Management’s discussion and analysis

for the quarter ended June 30, 2024

6	SECOND QUARTER MARKET UPDATE
9	OUR STRATEGY
12	CONSOLIDATED FINANCIAL RESULTS
16	OUTLOOK FOR 2024
21	LIQUIDITY AND CAPITAL RESOURCES
23	FINANCIAL RESULTS BY SEGMENT
27	OUR OPERATIONS - SECOND QUARTER UPDATES
29	QUALIFIED PERSONS
29	NON-IFRS MEASURES
35	ADDITIONAL INFORMATION

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited condensed consolidated interim financial statements and notes for the quarter ended June 30, 2024 (interim financial statements). The information is based on what we knew as of July 30, 2024, and updates our first quarter and annual MD&A included in our 2023 annual report.

As you review this MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2023, and annual MD&A. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR+ at sedarplus.ca or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.

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

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

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

Caution about forward-looking information

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

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

• It typically includes words and phrases about the future, such as: anticipate, believe, estimate, expect, plan, will, intend, goal, target, forecast, project, strategy and outlook (see examples below).

• It represents our current views and can change significantly.

• It is based on a number of material assumptions, including those we have listed starting on page 4, which may prove to be incorrect.

• Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review our most recent annual information form and annual MD&A, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

• Forward-looking information is designed to help you understand management’s current views of our near-term 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 expectations regarding 2024 and future uranium supply, demand, contracting, geopolitical issues, and the market including the discussion under the heading Second quarter market update

• the discussion under the heading Our strategy, including the role of nuclear energy in the world’s shift to a low-carbon, climate-resilient economy, our expectation that our strategy will allow us to increase long-term value, our intention to execute our strategy with an emphasis on safety, people and the environment, our belief that we have the right strategy to achieve our vision and will do so in a manner that reflects our values, our target to reduce our combined Scope 1 and Scope 2 greenhouse (GHG) emissions by 30% by 2030, from our 2015 baseline, our ability to address risks and opportunities that we believe may have a significant impact on our ability to operate sustainably and add long-term value for our stakeholders, our ambition to reach net-zero GHG emissions and our expected financial capacity to execute our strategy, invest in new opportunities and self-manage risk

• the discussion under the heading Strategy in action, including expected Westinghouse segment performance, our expectations regarding uranium contracting, our contract portfolio and market conditions, our plans for production at McArthur River/Key Lake, Cigar Lake, and the Port Hope UF₆ conversion facility, our expectations regarding production levels at JV Inkai and cash dividend entitlements and timing

• the discussion of our expectations following the completion of our acquisition of a 49% interest in Westinghouse Electric Company (Westinghouse) including our ability to create a powerful platform for strategic growth, and the variability of the impact of Westinghouse on our quarterly results due to its customer requirements, delivery and outage schedules

• the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, our confidence that the courts would reject any attempt by CRA to utilize the same position and arguments for tax years 2007 through 2014 or the alternate position advanced for tax years 2014 through 2017, 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 2024, including our production plan, our planned production levels, expected care and maintenance costs for our tier-two assets, our cost of sales in our fuel services segment, our outlook for our uranium average realized price, and other information in the table under the heading 2024 Financial Outlook, our revenue, adjusted net earnings, and cash flow sensitivity analysis, our price sensitivity analysis for our uranium segment, our expected share of adjusted EBITDA from our equity investment in Westinghouse, and its expected adjusted EBITDA growth rate in 2024 and over the next five years

• the discussion under the heading Liquidity and capital resources, including our available alternatives to fund future capital requirements, our expectations regarding cash flow generation in 2024, our expectation that our cash balances and operating cash flows will meet our capital requirements during 2024

• our expectation that our operating and investment activities for the remainder of 2024 will not be constrained by the covenants in our credit agreements, including the financial covenants

• our intention to update the table under the heading Expected realized uranium price sensitivity under various spot price assumption at June 30, 2024 each quarter to reflect deliveries made and changes to our contract portfolio

• our future plans and expectations for each of our uranium operating properties and fuel services operating sites, including production levels and our expected cash cost of production at McArthur River/Key Lake and Cigar Lake

• our expectations regarding future JV Inkai production levels and dividend payments, including its ability to transport shipments of our share of Inkai’s production using the Trans-Caspian International Transport Route, which does not rely on Russian rail lines or ports, the possibility of further delays in expected Inkai deliveries and our evaluation of the implications of announced tax law changes in Kazakhstan including our preliminary analysis of their impact on Inkai’s production costs and conclusions that indicate production costs in Kazakhstan would be similar to northern Saskatchewan operations

2 CAMECO CORPORATION

• our ability to draw upon long-term purchase agreements and loan arrangements to mitigate the risks of a production shortfall or delays in Inkai deliveries

• the expected care and maintenance costs for our US ISR operations and Rabbit Lake for 2024

• our intention to file a new base shelf-prospectus, our expectation that we will continue to navigate by our investment-grade credit rating, and our intention to prioritize repayment of the remaining $300 million (US) outstanding in floating-rate term loan debt used to finance the Westinghouse acquisition

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, or geopolitical issues

• 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 that our view on the role of nuclear power in pursuit of those strategies may prove to be inaccurate

• risks relating to the development and use of new technology or lack of appropriate technology needed to achieve our 30% GHG emissions reduction target or advance our ambition to reach net-zero GHG emissions

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

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

• that Westinghouse fails to generate sufficient cash flow to fund its approved annual operating budget or make distributions to the partners

• the risk that we and Westinghouse may not be able to meet sales commitments for any reason

• the risk that Westinghouse may not achieve the expected growth in its business

• the risk to Westinghouse’s business associated with potential production disruptions, including those related to global supply chain disruptions, global economic uncertainty, political volatility, labour relations issues, and operating risks

• the risk that Westinghouse may not be able to implement its business objectives in a manner consistent with its or our environmental, social, governance and other values

• the risk that Westinghouse’s strategies may change, be unsuccessful, or have unanticipated consequences

• the risk that Westinghouse may be unsuccessful in respect of its new business

• the risk that Westinghouse may fail to comply with nuclear licence and quality assurance requirements at its facilities

• the risk that Westinghouse may lose protections against liability for nuclear damage, including discontinuation of global nuclear liability regimes and indemnities

• the risk that increased trade barriers may adversely impact Westinghouse’s business

• the risk that Westinghouse may default under its credit facilities, impacting adversely Westinghouse’s ability to fund its ongoing operations and to make distributions

• the risk that liabilities at Westinghouse may exceed our estimates and the discovery of unknown or undisclosed liabilities

• the risk that occupational health and safety issues may arise at Westinghouse’s operations

• the risk that there may be disputes between us and Brookfield regarding our strategic partnership

• the risk that we may default under the governance agreement with Brookfield, including us losing some or all of our interest in Westinghouse

• the risk that we are unable to enforce our legal rights under our agreements, permits or licences

• disruption or delay in the transportation of our products

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

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

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

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

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

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

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

• we are affected by environmental, safety and regulatory risks, including workforce health and safety or increased regulatory burdens or delays

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

• we are affected by political risks, including unrest in Kazakhstan, and geopolitical events, including the Russian invasion of Ukraine

2024 SECOND QUARTER REPORT 3

• operations are disrupted due to problems with our own or our joint venture partners’, 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, fires, 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 war, terrorism, cyber-attacks, 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 exports and 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 Key Lake mill production plan is delayed or does not succeed for any reason

• our Cigar Lake development, mining or production plans are delayed or do not succeed for any reason

• 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

• our production plan for our Port Hope UF₆ conversion facility is delayed or does not succeed for any reason, including due to the availability of production supplies

• our expectations relating to care and maintenance costs prove to be inaccurate

• we are affected by 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

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 availability or development of technologies needed to achieve our 30% GHG emissions reduction target or advance our net-zero GHG emission ambition

• the assumptions discussed under the heading 2024 Financial Outlook, including the assumptions used to prepare the outlook table and assumptions relating to growth in Westinghouse adjusted EBITDA

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

• 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 adversely affected 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

• plans to transport our products succeed, including the shipment of our share of JV Inkai production to our Blind River refinery

• our ability to mitigate adverse consequences of production shortfalls or delays in the shipment of our share of JV Inkai production to our Blind River refinery

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

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

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

• our Key Lake mill production plans succeed

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

• the ability of JV Inkai to pay dividends

• our production plan for our Port Hope UF₆ conversion facility succeeds

• that care and maintenance costs will be as expected

4 CAMECO CORPORATION

• 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

• neither our operations, nor those of our joint venture partners, suppliers or customers, are significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, climate change, natural disasters, aging infrastructure, forest or other fires, outbreak of illness (such as a pandemic like COVID-19), governmental, political or regulatory actions, litigation or arbitration proceedings, cyber-attacks, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, health and safety issues, underground floods, increased loadings into the environment, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, improper air emission or treated water releases, transportation disruptions or accidents, aging infrastructure, or other development or operating risks

• Westinghouse’s ability to generate cash flow and fund its approved annual operating budget and make distributions to the partners

• our ability to compete for additional business opportunities so as to generate additional revenue for us as a result of the Westinghouse acquisition

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

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

• Westinghouse’s production, purchases, sales, deliveries, and costs

• the assumptions and discussion set out under the heading Outlook

• the market conditions and other factors upon which we have based Westinghouse’s future plans and forecasts

• Westinghouse’s ability to mitigate adverse consequences of delays in production and construction

• the success of Westinghouse’s plans and strategies

• the absence of new and adverse government regulations, policies or decisions

• that there will not be any significant adverse consequences to Westinghouse’s business resulting from business disruptions, including those relating to supply disruptions, economic or political uncertainty and volatility, labour relation issues, and operating risks

• Westinghouse will comply with the covenants in its credit agreement

• Westinghouse will comply with nuclear licence and quality assurance requirements at its facilities

• Westinghouse maintaining protections against liability for nuclear damage, including continuation of global nuclear liability regimes and indemnities

• that known and unknown liabilities at Westinghouse will not materially exceed our estimates

2024 SECOND QUARTER REPORT 5

Second quarter market update

Ongoing geopolitical events, energy security concerns, and the global focus on the climate crisis amid rising low-carbon energy demand have created what we believe are transformative tailwinds for the nuclear power industry, from both a demand and supply perspective. With many countries looking to reindustrialize and nationalize sourcing capabilities, at COP28 in 2023, global leaders, heads of state and industry leaders acknowledged that it is not possible to achieve net-zero carbon emissions (net-zero) without nuclear power and pledged to triple generating capacity by 2050. In addition, there is increasing demand for reliable, uninterrupted power supplies to underpin large, energy-intensive industries, with recognition from within those sectors that baseload nuclear power is on the critical path for achieving the anticipated transformations with secure and carbon-free sources. Alongside that recognition is an understanding that a sufficient supply of nuclear fuel and fuel cycle services are essential to realizing a tripling of nuclear power.

In the second quarter of 2024, the long-term uranium price increased to its highest level since 2012 (in 2024 constant dollars), while the uranium spot price fell slightly compared to the first quarter and remained range-bound between $80 (US) and $90 (US), much higher than the first half of 2023. Over the past two years, fuel buyers continued to secure their long-term requirements for conversion and enrichment services, and they have returned their focus to the procurement of the uranium required to feed into those services. The increased contracting has resulted in higher prices across the fuel cycle, an increasing volume of requests for proposals from utilities entering the market alongside inbound requests for direct off-market negotiations, and sustained volumes of long-term contracting reported.

Some of the more significant developments affecting supply in the quarter and to date include:

• Sprott Physical Uranium Trust (SPUT) has purchased nearly 2 million pounds U₃O₈ year-to-date in 2024, bringing total purchases since inception to nearly 47 million pounds U₃O₈. Volatility in the equity markets has impacted SPUT’s valuation, with the discount or premium to its net asset value impacting its ability to raise funds to purchase uranium.

• The United States Prohibiting Russian Uranium Imports Act (H.R. 1042) was signed by President Biden in May 2024, following passage by the US House of Representatives and by unanimous vote in the US Senate. The bill will prohibit the import of Russian low-enriched uranium (LEU) into the US beginning 90 days after enactment and is set to expire in 2040. The Act contains a Department of Energy (DOE) waiver process through which utilities, until 2028, can enter a public process to apply for an exception to the import ban in situations concerning energy and national security. Additionally, the US DOE issued a $3.4 billion (US) request for proposals to purchase LEU to incentivize investment in the US fuel cycle in support of commercial domestic capacity in the event of a disruption in the market.

• In July, the government of the Republic of Kazakhstan introduced amendments to its Tax Code and the Mineral Extraction Tax (MET) rate on uranium production. The MET rate will increase from 6% in 2024, to 9% in 2025, with a further increase in 2026 of up to 18% under a progressive tax regime based on annual production volumes. An additional MET of up to 2.5% will also be applied beginning in 2026, based on a progressive system linked to published uranium market prices. The MET is incurred and paid by the mining entities, impacting both Kazatomprom (KAP) and its joint ventures and subsidiaries.

• In Niger, Orano reported that its 63% owned Somair mine is facing financial difficulties due to its inability to export uranium since the July 2023 military coup in the country. Without a resolution, Orano indicated that they may need to implement measures to stop all activity on the site, putting future production at risk. In June, Orano also reported that the Nigerien government revoked their operating permit for their undeveloped Imouraren deposit in Niger, which contains proven and probable reserves of about 446 million pounds U₃O₈. Orano holds a 67% share, Sopamin holds 23%, while the Republic of Niger holds 10%. Furthermore, subsequent to the end of the quarter, GoviEx Uranium Inc. was informed by the Nigerien government that the company’s rights over the perimeter of the Madaouela mining permit, which has estimated life of mine production of 51 million pounds U₃O₈, had been revoked. The government has not yet clarified its plans for the Imouraren or Madaouela deposits.

• In June, Paladin Energy and Fission Uranium Corporation announced that they have entered into a definitive agreement, whereby Paladin will acquire 100% of the issued and outstanding shares of Fission. The transaction is targeted to close in September 2024.

• In April, Boss Energy announced that it produced the first drum of uranium from its restarted Honeymoon in situ recovery project in South Australia, which has a production capacity of 2.45 million pounds U₃O₈ per year.

6 CAMECO CORPORATION

• In June, enCore Energy announced the successful startup of production at its Alta Mesa Uranium Central Processing Plant and wellfield in South Texas. The project operates under a joint venture with Boss Energy Ltd. and has a total annual capacity of 1.5 million pounds U₃O₈.

• In June, Terrafame reported that it started recovering natural uranium at its industrial site in Sotkamo, Finland. After the planned start-up phase, the uranium recovery plant is expected to ramp up to 520,000 pounds U₃O₈ per year by 2026.

According to the International Atomic Energy Agency (IAEA), globally, there are currently 441 operable reactors and 59 reactors under construction. Demand-related developments continue to evidence growing support for the nuclear industry, with over 30 countries pledging to triple nuclear power capacity by 2050. Nations are reaffirming their commitment to existing nuclear and/or reversing policies to phase out nuclear, non-nuclear countries are emerging as candidates for new nuclear capacity, improvements are being made in global sustainable financing policies to include nuclear energy, and opinion polls indicate improving public support. With several reactors being saved from early retirement, life-extensions to existing reactors being sought and approved, and new build construction projects underway and many more planned, demand for uranium fuel continues to improve in the near-, medium- and long-term.

The more significant developments in the quarter affecting current and future demand include:

• In Japan, the Nuclear Regulation Authority approved Kansai Electric Power Company’s Ohi units 3 and 4 to operate for an additional 10 years, increasing the operating lives from 30 years to 40 years. The approval marks the first time the Japanese regulator has approved a long-term management plan utilizing funding through the Green Transformation Law to meet net-zero emissions by 2050.

• In South Korea, the government announced plans to build four more 1.4 GWe APR1400 reactors, which will bring the total Korean reactor count to 30, including the completion of two delayed plants, Shin-Hanul units 3 and 4, and two units already under construction at the Saeul nuclear plant.

• SE NNEGC Energoatom (Energoatom) saw first concrete poured for the construction of Khmelnitski units 5 and 6. The new reactors will be the first Westinghouse Electric Company (Westinghouse) designed AP1000^® pressurized water reactors (PWR) built in Ukraine.

• In Poland, the government approved a plan to build a small modular reactor (SMR) based on the Rolls-Royce design, known as the UK SMR.

• In June, following a lengthy legal battle with Rio de Janeiro’s Court of Justice, Brazilian utility Electronuclear successfully appealed the government-ordered suspension of construction activity at Angra unit 3, a 1,350 MWe PWR reactor that will now be allowed to continue construction.

• In the US, Southern Company announced that Vogtle unit 4, a Westinghouse AP1000^® reactor, began commercial operation, following the start-up of unit 3 in 2023. At the announcement event, US Secretary of Energy Jennifer Granholm stated that to reach net-zero by 2050, the US will have to at least triple its current nuclear capacity, adding 200 more gigawatts of nuclear generation capacity.

• In July, The Nuclear Company, a fleet-scale nuclear development firm, announced plans to build a series of nuclear power plants across the US. The start-up’s fleet-scale model integrates “proven, licensed technology and a design-once, build-many approach,” and plans to focus on sites which have already had some level of Nuclear Regulatory Commission (NRC) licensing for its initial 6-GWe reactor fleet, which could begin power generation by the mid-2030s.

• In June, the US DOE announced they will be financing $900 million (US) towards the deployment of light-water SMR’s, with $800 million (US) earmarked for two of the “first-mover teams”, which can include utilities, SMR producers, vendors, and other end-users. The DOE is looking for entities that are committed to deploying advanced reactors and that have well-established plans for additional builds. In addition, President Biden signed bipartisan legislation into law known as the Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy (ADVANCE) Act. This builds on prior legislation to develop a modernized approach to licensing new reactor technologies, which is expected to speed up the process and cut fees companies must pay to do so. It also requires the NRC to commission a report which considers ways to shorten and simplify the environmental review process.

• The California government approved a $400 million (US) loan to keep Pacific Gas & Electric’s (PG&E) two-unit Diablo Canyon plant operating until 2030. PG&E has filed a licence renewal application to extend the units’ operation for 20 years, until the mid-2040’s.

• Energy Northwest confirmed plans to build 12 X-energy SMR’s in central Washington, which would generate a total of up to 960 MWe.

2024 SECOND QUARTER REPORT 7

• In June, SaskPower, Westinghouse, and Cameco signed a memorandum of understanding to evaluate Saskatchewan’s clean energy needs, with discussions and cooperation between the three entities on AP1000^® reactor and AP300^™ small modular reactor technology. The province of Saskatchewan will be evaluating its infrastructure suitability for a nuclear fuel supply chain and reactor installation.

• Westinghouse opened a new nuclear engineering hub in Kitchener, Ontario, where approximately 50 engineers will work on designing future nuclear reactors for deployment in Canada and across the global reactor market.

Caution about forward-looking information relating to the nuclear industry

This discussion of our expectations for the nuclear industry, including its growth profile, uranium supply and demand, and reactor growth is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2.

Industry prices at quarter end

	JUN 30 2024		MAR 31 2024		DEC 31 2023		SEP 30 2023		JUN 30 2023		MAR 31 2023
Uranium ($US/lb U3O8)1
Average spot market price		84.25		87.75		91.00		71.58		56.10		50.48
Average long-term price		79.50		77.50		68.00		61.50		56.00		53.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		60.00		58.00		46.00		40.88		40.75		39.75
Europe		60.00		58.00		46.00		40.88		40.75		39.75
Average long-term price
North America		38.00		35.50		34.25		31.50		30.75		27.88
Europe		38.00		35.50		34.25		31.50		30.50		27.88
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 the second quarter of 2024 was nearly 13 million pounds U₃O₈ equivalent, similar to the second quarter of 2023. Total spot purchases for the first six months of 2024 were 22 million pounds U₃O₈ equivalent, compared to 29 million pounds U₃O₈ equivalent over the same period in 2023. As of June 30, 2024, the average reported spot price was $84.25 (US) per pound U₃O₈ equivalent, a decrease of $3.50 (US) per pound from the previous quarter due to very small volumes of uncommitted supply entering the near-term market.

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-related prices, which reference spot and/or long-term indicators, and are generally set a month or more prior to delivery, typically including floor prices and ceiling prices that are also escalated to time of delivery. Long-term contracting reported by UxC for the first six months of 2024 totaled about 32 million pounds U₃O₈ equivalent, down from about 117 million pounds U₃O₈ equivalent reported over the same period in 2023. The contracting volume in the first half of 2023 was much higher due to significant non-US utilities diversifying away from Russian supply, including our contracts with Ukraine and Bulgaria, which alone, accounted for about 46 million pounds U₃O₈. The modest level reported to date in 2024 can be attributed in part to US utilities awaiting clarity on the impact of Russian sanctions, the Russian uranium import ban, and clarity around the US waiver process, although requests for proposals from utilities are continuing alongside requests for direct off-market negotiations.

The average reported long-term price at the end of the quarter was $79.50 (US) per pound U₃O₈ equivalent, an increase of $2.00 (US) per pound from the previous quarter, and the highest reported long-term price since 2012 (in 2024 constant dollars).

With increased demand for western conversion services, pricing in both North America and Europe continues to be strong. At the end of the second quarter, the average reported spot price for conversion reached a record high of $60.00 (US) per kilogram uranium (kgU) as UF₆, up $2.00 (US) from the previous quarter. Long-term UF₆ conversion prices for North America and Europe finished the quarter at $38.00 (US) per kgU, up $2.50 (US) from the previous quarter.

8 CAMECO CORPORATION

Our strategy

We are a pure-play investment in the growing demand for nuclear energy, focused on taking advantage of the near-, medium- and long-term growth occurring in our industry. We provide nuclear fuel and nuclear power products, services and technologies across the fuel cycle, augmented by our investment in Westinghouse, that supports the generation of carbon-free, reliable, secure and affordable energy. Our strategy is set within the context of what we believe is a transitioning market environment. Increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are driving a global focus on tripling nuclear power capacity by 2050, which is expected to durably strengthen 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 necessary power in a reliable, safe, and affordable manner, and in a way that is expected to 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

• invest in new opportunities that are expected to add long-term value

• self-manage risk

• exploring other emerging opportunities within the nuclear power value chain that align with our commitment to manage our business responsibly and sustainably, contribute to decarbonization, and help to provide secure and affordable energy

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

Our vision – “Energizing a clean-air world” – recognizes that we have an important role to play in enabling the vast reductions in global greenhouse gas (GHG) emissions required to achieve a resilient net-zero carbon economy. We support climate action that is consistent with the ambitions of the Paris Agreement and the Canadian government’s commitment to the agreement, which seeks to limit global temperature rise to less than 2° Celsius, a target that climate scientists believe will require the world to reach net-zero by 2050 or sooner. Our uranium and fuel services are used around the world in the generation of safe, reliable, zero-carbon, 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 35 years, we have been operating and delivering our products responsibly. Building on that strong foundation, we have set a target to reduce our combined Scope 1 and Scope 2 GHG emissions by 30% by 2030, from our 2015 baseline, as our first major milestone in our ambition of being net-zero. In 2023, we targeted to refine the calculations to quantify our Scope 3 emissions to further understand our value chain GHG emissions. We successfully met this target, and for the first time, in our 2023 Sustainability Report, we have disclosed our estimated Scope 3 emissions value and quantification method. We remain committed to our efforts to transform our own, already low, greenhouse gas footprint, and we continue to identify and address the risks and opportunities that we believe may have a significant impact on our ability to operate sustainably and add long-term value for our stakeholders.

You can read more about our strategy in our 2023 annual MD&A and our approach to sustainability in our 2023 Sustainability Report.

Strategy in action

With the ongoing transition and improvements in the nuclear fuel market, our three-pillar strategy is guiding our disciplined contracting, supply and financial decisions.

In the second quarter, results were as expected with net earnings of $36 million, adjusted net earnings of $62 million, and adjusted EBITDA of $337 million. Both net earnings and adjusted EBITDA were up by over 100% compared to the same period in 2023 largely due to strong performance in our core uranium segment, with higher sales volumes, which was in line with the delivery pattern and outlook disclosed in our annual MD&A, which has not changed, and an increase of 15% in the

2024 SECOND QUARTER REPORT 9

Canadian dollar average realized price. During the first half of the year, net earnings of $29 million were lower, while adjusted net earnings of $118 million, and adjusted EBITDA of $681 million were each higher than in 2023 and in line with our 2024 outlook, which has not changed. See Financial results by segment – Uranium on page 23 for more information.

The outlook for Westinghouse is unchanged, and we believe, on track. As indicated in our 2023 annual MD&A and reiterated in our 2024 first quarter MD&A, Westinghouse is expected to generate a net loss of between $170 million and $230 million in 2024 due to the impact of the purchase accounting, which requires the revaluation of Westinghouse’s inventory and other assets at the time of acquisition, and the expensing of certain non-operating acquisition-related transition costs. As expected, results for the second quarter improved over the first quarter with a net loss of $47 million, bringing the year-to-date net loss to $170 million for the first six months. Due to normal variability in the timing of its customer requirements, and delivery and outage schedules, we expect to see stronger performance from the Westinghouse segment in the second half of the year, with higher expected cash flows in the fourth quarter. We do not believe the impact of the revaluation of Westinghouse’s inventory and assets, or the non-operating acquisition-related transition costs reflect its underlying performance for the reporting period, therefore, we use adjusted EBITDA as a performance measure for Westinghouse, which was $121 million for the second quarter and $197 million for the first six months. We continue to expect adjusted EBITDA of between $445 million and $510 million for the year in the Westinghouse segment. See Our outlook for 2024 starting on page 16 and Our earnings from Westinghouse, starting on page 26 for more information. Adjusted net earnings and adjusted EBITDA are non-IFRS measures, see the information starting on page 29.

We continue to responsibly manage our supply in accordance with our customers’ needs. As a proven and reliable commercial supplier with assets in geopolitically stable jurisdictions across all segments of the nuclear fuel cycle, we are being selective in committing our unencumbered, in-ground uranium inventory and UF₆ conversion capacity under long term contracts. To support the long-term operation of our productive capacity, our contracting is focused on maintaining exposure to future improvements in the market while retaining downside protection. In our uranium segment, over the next five years, we have contracts in place for average annual deliveries of 29 million pounds of U₃O₈ per year, with commitments higher than the average in 2024 and 2025, and lower than the average in 2026 through 2028. We also have contracts in both our uranium and fuel services segments that have deliveries spanning more than a decade. In our uranium segment, many of those contracts incorporate market-related pricing mechanisms that are expected to benefit from the improving market conditions.

To advance our strategy in step with the positive market momentum and long-term contracts we have put in place, we remain on track to produce 36 million pounds (22.4 million pounds our share) of uranium in 2024. At Joint Venture Inkai (JV Inkai), the tentative production target for 2024 continues to be 8.3 million pounds (100% basis), remaining 20% below the operation’s subsoil use agreement level, and is contingent upon receipt of sufficient volumes of sulfuric acid. Our allocation of the planned production from JV Inkai remains under discussion. At Port Hope, we now expect annual UF₆ production of 11,000 to 11,500 tonnes in 2024 (previously 12,000 tonnes), due to a temporary operational issue that was resolved. We are continuing work to achieve an ongoing production rate that will supply 12,000 tonnes per year, in order to satisfy our book of long-term commitments and demand for conversion services. Our annual 2024 production expectation for fuel services, which includes UF₆ conversion, UO₂, and heavy water reactor fuel bundles, remains between 13.5 million and 14.5 million kgU of combined fuel services products.

With our operationally flexible and disciplined approach to supply, we continue to meet our sales commitments through a combination of production, inventory, product loans and purchases. In the second quarter, we produced 7.1 million pounds of uranium (our share), and we purchased 1.7 million pounds (purchased at an average unit cost of $109.11 per pound ($80.27 (US) per pound)). See Financial results by segment – Uranium starting on page 23 for more information. Our purchases to date in 2024 include our remaining share of JV Inkai’s 2023 production, which was delivered to our Blind River refinery in February with a cost per pound of $129.96 ($96.88 (US)). The cash dividend associated with the sale of pounds from Inkai in 2024 is expected to be received in 2025, once declared and paid by JV Inkai. See Revenue, adjusted net earnings, and cash flow sensitivity analysis in the Outlook for 2024 section starting on page 16. After delivering 6.2 million pounds in the second quarter, our uranium inventory was 13.4 million pounds on June 30, 2024, with an average inventory cost of $46.49 per pound.

10 CAMECO CORPORATION

We expect to maintain the financial strength and flexibility necessary to execute our strategy by planning production in coordination with contracting success and market opportunities. As previously disclosed, work is underway to extend the mine life at Cigar Lake to 2036 and, in-line with our supply discipline and future sourcing requirements of our contract portfolio, we continue to evaluate the required work and investment necessary to advance to a future decision for increasing production at McArthur River/Key Lake from 18 million pounds (100% basis) to its licensed annual capacity of 25 million pounds (100% basis).

Thanks to our risk-managed financial discipline, our balance sheet remains strong. Consistent with the conservative financial management we have demonstrated and our 2024 capital allocation priorities, in May 2024, we refinanced $500 million through a senior unsecured debenture issuance and used the proceeds to retire the $500 million senior unsecured debentures that were due June 24, 2024. As of June 30, 2024, after the refinance and a second quarter repayment of another $100 million (US) on the floating-rate term loan used to finance the Westinghouse acquisition, we had $362 million in cash and cash equivalents, and $1.4 billion in total debt and a $1.0 billion undrawn credit facility.

We plan to continue to prioritize repayment of the remaining $300 million (US) outstanding floating-rate term loan debt that is due in November 2025. We will continue to navigate by our investment-grade rating through close management of our balance sheet metrics, maintaining sufficient liquidity and cash to pursue value-adding opportunities while self-managing risk, including from global macro-economic and geopolitical uncertainty and volatility.

2024 SECOND QUARTER REPORT 11

Financial results

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

In the fourth quarter of 2023, we announced the closing of the acquisition of a 49% interest in Westinghouse. Effective November 7, 2023, we began equity accounting for this investment. Our share of Westinghouse’s earnings has been reflected in our financial results from that date.

Consolidated financial results

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED JUNE 30								SIX MONTHS ENDED JUNE 30
	2024		2023			CHANGE			2024		2023		CHANGE
Revenue		598		482			24	%		1,232		1,169		5	%
Gross profit		175		110			59	%		362		277		31	%
Net earnings attributable to equity holders		36		14			>100	%		29		133		(78	)%
$ per common share (basic)		0.08		0.03			>100	%		0.07		0.31		(77	)%
$ per common share (diluted)		0.08		0.03			>100	%		0.07		0.31		(77	)%
Adjusted net earnings (losses) (ANE) (non-IFRS, see page 29)		62		(3	)		>100	%		118		112		5	%
$ per common share (adjusted and diluted)		0.14		(0.01	)		>100	%		0.27		0.26		4	%
Adjusted EBITDA (non-IFRS, see page 29)		337		54			>100	%		681		278		>100	%
Cash provided by operations (after working capital changes)		260		87			>100	%		323		302		7	%

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)			2024										2023					2022
	Q2		Q1			Q4		Q3		Q2			Q1		Q4			Q3
Revenue		598		634			844		575		482			687		524			389
Net earnings (losses) attributable to equity holders		36		(7	)		80		148		14			119		(15	)		(20	)
$ per common share (basic)		0.08		(0.02	)		0.18		0.34		0.03			0.27		(0.04	)		(0.05	)
$ per common share (diluted)		0.08		(0.02	)		0.18		0.34		0.03			0.27		(0.04	)		(0.05	)
Adjusted net earnings (losses) (non-IFRS, see page 29)		62		56			90		137		(3	)		115		36			10
$ per common share (adjusted and diluted)		0.14		0.13			0.21		0.32		(0.01	)		0.27		0.09			0.03
Cash provided by (used in) operations (after working capital changes)		260		63			201		185		87			215		77			(47	)

Key things to note:

• The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments, meaning quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements.

• Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 29 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.

• Our quarterly results are impacted by variability in the timing of Westinghouse’s customer requirements and deliveries as well as outage schedules. The first quarter is typically weaker, with stronger expected performance in the second half of the year, and higher expected cash flows in the fourth quarter. In addition, the revaluation of Westinghouse’s inventory and other assets upon acquisition and the non-operating acquisition-related transition costs can have a significant impact on Westinghouse’s quarterly results. See Our earnings from Westinghouse, starting on page 26 for more information.

12 CAMECO CORPORATION

The following table compares the net earnings and adjusted net earnings for the second quarter to the previous seven quarters.

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)				2024												2023						2022
	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Net earnings (losses) attributable to equity holders		36			(7	)		80			148			14			119			(15	)		(20	)
Adjustments
Adjustments on derivatives		14			33			(59	)		41			(35	)		(6	)		(19	)		75
Inventory purchase accounting (net of tax)1		12			38			20			—			—			—			—			—
Acquisition-related transition costs (net of tax)1		5			14			—			—			—			—			—			—
Adjustment to other operating expense (income)		(2	)		(15	)		40			(48	)		8			(2	)		88			(24	)
Income taxes on adjustments		(3	)		(7	)		9			(4	)		10			4			(18	)		(21	)
Adjusted net earnings (losses) (non-IFRS, see page 29)		62			56			90			137			(3	)		115			36			10

¹ These adjustments relate to our investment in Westinghouse

Corporate expenses

ADMINISTRATION

	THREE MONTHS ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
($ MILLIONS)	2024		2023		CHANGE			2024		2023		CHANGE
Direct administration		52		46		13	%		104		92		13	%
Stock-based compensation		14		11		27	%		22		29		(24	)%
Total administration		66		57		16	%		126		121		4	%

Direct administration costs were $6 million higher for the second quarter of 2024 compared to the same period last year, and $12 million higher for the first six months mainly due to the impacts of inflation and higher payments under Collaboration Agreements tied to production volumes. Stock-based compensation in the first six months of 2024 was $7 million lower than 2023 due to both the grant and vesting of a lower number of share-based awards compared to the same period last year. See note 18 to the financial statements.

EXPLORATION AND RESEARCH & DEVELOPMENT

In the second quarter, uranium exploration expenses were $3 million, a decrease of $1 million from the second quarter of 2023. Exploration expenses for the first six months of the year were unchanged compared to 2023, at $10 million.

We also had research and development expenditures in the second quarter of $8 million, an increase of $3 million from the second quarter of 2023. Research and development expenses for the first six months of the year increased by $8 million compared to 2023, to $17 million. These expenses are related to our investment in Global Laser Enrichment, LLC.

INCOME TAXES

We recorded an income tax expense of $18 million in the second quarter of 2024, compared to an expense of $23 million in the second quarter of 2023.

In the first six months of 2024, we recorded an expense of $49 million compared to an expense of $59 million in 2023.

2024 SECOND QUARTER REPORT 13

	THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS)	2024			2023			2024			2023
Net earnings before income taxes
Canada		90			62			231			211
Foreign		(36	)		(25	)		(153	)		(19	)
Total net earnings before income taxes		54			37			78			192
Income tax expense
Canada		13			21			44			54
Foreign		5			2			5			5
Total income tax expense		18			23			49			59

TRANSFER PRICING DISPUTE

Background

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

For the years 2003 to 2014, CRA shifted Cameco Europe Limited’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2011, transfer pricing penalties. In addition, for 2014 to 2017, CRA has advanced an alternate reassessing position. See Reassessments, remittances and next steps below for more information.

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

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

Refund and cost award

The Minister of National Revenue issued new reassessments for the 2003 through 2006 tax years in accordance with the decision and, in July 2021, refunded the tax paid for those years. In October 2023, pursuant to a cost award from the courts, we received a payment of approximately $12 million for disbursements, which is in addition to the $10 million we received from CRA in April 2021 as reimbursement for legal fees.

Reassessments, remittances and next steps

The Canadian income tax rules include provisions that generally require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. Following the Supreme Court’s dismissal of CRA’s application for leave to appeal, we wrote to CRA requesting reversal of CRA’s transfer pricing adjustments for 2007 through 2013 and the return of the $780 million in cash and letters of credit we had paid or provided for those years. Given the strength of the court decisions received, our request was made on the basis that the Tax Court would reject any attempt by CRA to defend its reassessments for the 2007 through 2013 tax years applying the same or similar positions already denied for previous years.

14 CAMECO CORPORATION

The series of court decisions that were completely and unequivocally in our favour for the 2003, 2005 and 2006 tax years determined that the income earned by our foreign subsidiary from the sale of non-Canadian produced uranium was not taxable in Canada. In accordance with these decisions, CRA issued reassessments reducing the proposed transfer pricing adjustment from $5.1 billion to $3.3 billion, resulting in a reduction of $1.8 billion in income taxable in Canada compared to the previous reassessments issued to us by CRA for the 2007 through 2013 tax years. In March 2023, CRA issued revised reassessments for the 2007 through 2013 tax years, which resulted in a refund of $297 million of the $780 million in cash and letters of credit held by the CRA at that time. The refund consisted of cash in the amount of $86 million and letters of credit in the amount of $211 million.

The remaining transfer pricing adjustment of $3.3 billion for the 2007 to 2013 tax years relates to the sale of Canadian-produced uranium by our foreign subsidiary. Cameco maintains that the clear and decisive court decisions described above apply, and that CRA should fully reverse the remaining transfer pricing adjustments for these years and return the cash and security being held.

In October 2021, due to a lack of significant progress on our points of contention, we filed a notice of appeal with the Tax Court for the years 2007 through 2013. We have asked the Tax Court to order the complete reversal of CRA’s transfer pricing adjustment for those years and the return of the remainder of our cash and letters of credit being held, with costs.

In 2020, CRA advanced an alternate reassessing position for the 2014 tax year in the event the basis for its original reassessment, noted above, is unsuccessful. Subsequent to this, we received reassessments for the 2015, 2016 and 2017 tax years, all reflecting this alternative reassessing position. CRA holds about $555 million as security (approximately $209 million in cash and $346 million in letters of credit) related to the 2007 through 2017 tax years.

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 alternative methodology will not result in a materially different outcome from our 2014 to 2017 filing positions.

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 2017.

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

This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2.

FOREIGN EXCHANGE

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

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

Impact of hedging on IFRS earnings

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

2024 SECOND QUARTER REPORT 15

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

Impact of hedging on ANE

We designate contracts for use in particular periods, based on our expected net exposure in that period. Hedge contracts are layered in over time based on this expected net exposure. The result is that our current hedge portfolio is made up of a number of contracts which are currently designated to net exposures we expect in 2024 and future years, and we will recognize the gains and losses in ANE in those periods.

For the purposes of ANE, gains and losses on derivatives are reported based on the difference between the effective hedge rate of the contracts designated for use in the particular period and the exchange rate at the time of settlement. This results in an adjustment to current period IFRS earnings to effectively remove reported gains and losses on derivatives that arise from contracts put in place for use in future periods. The effective hedge rate will lag the market in periods of rapid currency movement. See Non-IFRS measures on page 29.

For more information, see our 2023 annual MD&A.

At June 30, 2024:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.37 (Cdn), up from $1.00 (US) for $1.35 (Cdn) at March 31, 2024. The exchange rate averaged $1.00 (US) for $1.37 (Cdn) over the quarter.

• The mark-to-market position on all foreign exchange contracts was a $35 million loss compared to a $21 million loss at March 31, 2024.

For information on the impact of foreign exchange on our intercompany balances, see note 19 to the financial statements.

Outlook for 2024

Our outlook for 2024 reflects the continued transition of our cost structure back to a tier-one run rate, as we plan our production to satisfy the growing long-term commitments under our contract portfolio. With our plan to produce 18 million pounds (100% basis) at each of Cigar Lake and McArthur River/Key Lake, and to produce between 11,000 and 11,500 tonnes UF₆ (previously 12,000 tonnes UF₆) at our Port Hope conversion facility, we expect strong cash flow generation.

Our financial performance and the amount of cash generated will be dependent on sourcing the material required to meet our deliveries as planned, including achieving our production plans. Therefore, our cash balances may fluctuate throughout the year.

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

The average unit cost of sales in our fuel services segment is now expected to be between $25.50 and $26.50 per kgU (previously $24.50 to $25.50 per kgU) due to the lower production expectations for UF₆ at our Port Hope conversion facility.

16 CAMECO CORPORATION

2024 FINANCIAL OUTLOOK

	CONSOLIDATED		URANIUM			FUEL SERVICES			WESTINGHOUSE
Production (owned and operated properties)		—		22.4 million lbs			13.5 to 14.5 million kgU			—
Market purchases		—		up to 2 million lbs			—			—
Committed purchases (including Inkai purchase volumes)		—		9 million lbs			—			—
Sales/delivery volume		—		32 to 34 million lbs			12 to 13 million kgU			—
Revenue	$	2,850-3,000 million	$	2,410-2,530 million		$	430-460 million			—
Average realized price		—	$	74.70/lb	1		—			—
Average unit cost of sales (including D&A)		—	$	57.00-60.00/lb	2	$	25.50-26.50/kgU	3		—
Direct administration costs	$	190-200 million		—			—			—
Exploration costs		—	$	20 million			—			—
Research and development	$	37 million		—			—			—
Capital expenditures	$	215-250 million		—			—			—
Adjusted EBITDA (non-IFRS, see page 29)		—		—			—		$	445-510 million

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  Uranium average unit cost of sales is calculated as the cash and non-cash costs of the product sold, care and maintenance and selling costs, divided by the volume of uranium concentrates sold.

³  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, divided by the volume of products sold.

We are not providing 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:

• Market purchases – reflect the market purchases we have made to date or expect to make in 2024. Market purchases may vary if planned production varies. In addition, if we decide to increase our working inventory from current levels our market purchases could be higher.

• Committed purchases—are based on the 4.7 million pounds of commitments we have made to date or agreed to acquire under contracts signed prior to 2024 and our JV Inkai purchases, which we have assumed will be equivalent to our 2023 purchase volume of 4.2 million pounds, including the 1.1 million purchased to date. If Inkai production and/or deliveries vary, committed purchases may vary and we may choose to make additional market purchases, temporarily reduce our inventory levels, pull forward long-term purchase commitments, or draw on loan arrangements we have in place. We equity account for our minority ownership interest in JV Inkai. We record our share of its production as a purchase. However, this does not reflect our share of the economic benefit. Our share of the economic benefit is based on the difference between our purchase price and JV Inkai’s lower production cost and is reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investees”. As a result, increases in the spot price increase our cost of purchases from JV Inkai and also our “share of earnings from equity accounted investees”. The benefit is realized, through receipt of a cash dividend, when declared and paid by JV Inkai.

• Our 2024 outlook for sales/delivery volume does not include sales between our uranium and fuel services segments.

• Sales/delivery volume is based on the volumes we currently have delivered and our remaining commitments to deliver under contract in 2024.

• Uranium revenue and average realized price are calculated based on the terms contained in the base-escalated and market-related contracts under which we have deliveries in 2024. For market-related contracts not yet priced and for delivery in 2024, subject to any floors or ceilings, we used a uranium spot price of $83.50 (US) per pound (the UxC spot price as of June 24, 2024), a long-term price indicator of $79.00 (US) per pound (the UxC long-term indicator on June 24, 2024) and an exchange rate of $1.00 (US) for $1.30 (Cdn).

2024 SECOND QUARTER REPORT 17

• Uranium average unit cost of sales (including D&A) is based on the expected unit cost of sales for produced material and the market purchases and committed purchases made to date and the planned volume remaining noted in the outlook at an anticipated average purchase price of about $95 (Cdn) per pound (previously $100 (Cdn) per pound) and includes care and maintenance costs of between $50 million and $60 million. We expect overall unit cost of sales could vary if there are changes in production and market or committed purchase volumes or the mix of supply sources used to meet our contract deliveries, uranium spot prices, and/or care and maintenance costs in 2024.

• Direct administration costs do not include stock-based compensation expenses. See page 13 for more information.

• The adjusted EBITDA outlook for Westinghouse is based on the assumptions listed later in this section.

• Westinghouse and JV Inkai are accounted for using the equity method for our share. Under equity accounting, Westinghouse and JV Inkai capital expenditures are not presented within our consolidated financial statements and are therefore not included in our outlook for capital expenditures.

For more information on how changes in the exchange rate or uranium prices can impact our outlook see Revenue, adjusted net earnings, and cash flow sensitivity analysis below, and Foreign exchange on page 15.

In 2024 we expect our share of adjusted EBITDA from our equity investment in Westinghouse to be between $445 million and $510 million. Over the next five years, we expect its adjusted EBITDA will grow at a compound annual growth rate of 6% to 10%.

CAMECO SHARE (49%)	2024 OUTLOOK
Net earnings (loss)		(170-230	)
Depreciation and amortization		335-385
Finance income		(2-3	)
Finance costs		175-205
Income tax expense (recovery)		(40-50	)
EBITDA (non-IFRS, see page 29)		320-380
Inventory purchase accounting		65-70
Acquisition-related transition costs		25-30
Other expenses		55-65
Adjusted EBITDA (non-IFRS, see page 29)		445-510

Note: the ranges for 2024 outlook for EBITDA and adjusted EBITDA are not determined using the high and low estimates of the ranges provided for each of the detailed reconciling line items.

The outlook has been revised to reflect the expected additional impacts of purchase accounting on income tax recovery (previously $10 million to $30 million expense, respectively). The range for other expenses has also been increased slightly due to additional non-operating charges and integration and restructuring costs (previously $40 million to $50 million, respectively). The outlook for net income and adjusted EBITDA remains unchanged.

The outlook for adjusted EBITDA for 2024 and its growth rate over the next five years are based on the following assumptions:

• An exchange rate of $1.00 (US) for $1.30 (Cdn)

• A compound annual growth rate in revenue from its core business of 4% to 6%, which is slightly higher than the anticipated average growth rate of the nuclear industry based on the World Nuclear Association’s Reference Case. In addition to orders for PWR reactor fuel and services, this includes orders for VVER and BWR fuel and services. The outlook assumes that work is fulfilled on the timelines and scope expected based on current orders received, and additional work is undertaken based on past trends. The expected margins on this work are aligned with the historic margins of 16% to 19%, with variability expected to come from product mix compared to previous years.

• Growth from new AP1000 reactor projects is based on agreements that have been signed and announcements where the AP1000 technology has been selected, including Poland, Bulgaria and Ukraine. It is assumed that work on announced agreements and announced selections to be done by Westinghouse would proceed on the timelines and revenue pattern noted under the New Build Framework in our 2023 annual MD&A. The growth only assumes Westinghouse undertakes the engineering and procurement work required prior to a new reactor project breaking ground, which is a small component of the overall potential. A delay in project timelines or cancellation of announced projects would result in a growth rate near the bottom of the range.

18 CAMECO CORPORATION

• Estimates and assumptions, including development timelines for both announced and potential reactor builds are subject to government and regulatory approval, as well as risks related to the current macro-economic environment, and may differ significantly from those assumed.

• It is also expected that investments in new technologies, including eVinci^™ microreactor and AP300^™ small modular reactor, will be made in accordance with the current business plan and are expected to contribute to adjusted EBITDA largely outside the five-year time frame.

Caution about forward-looking information relating to our future earnings and adjusted EBITDA form Westinghouse

This discussion of our expectations for Westinghouse’s future earnings and adjusted EBITDA and our share thereof 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. Actual results and events may be significantly different from what we currently expect.

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

We have sensitivity to the uranium price through both our sales and purchase commitments. However, at the current price levels many of the market-related sales contracts we have delivered into or are delivering into this year are subject to ceiling prices and therefore are generally less sensitive than our purchase commitments.

As a result, if the uranium spot price increased by $5 (US) per pound, we expect revenue would increase by $15 million, while ANE would increase by $1 million and cash flow would decrease by $21 million. From a cash flow perspective, the sensitivity does not adequately capture the impact of JV Inkai purchases, which straddle two fiscal reporting periods due to when dividends are declared and paid by JV Inkai. The cash flow sensitivity includes the cash outflow for the remaining 3.0 million pounds of uranium assumed to be purchased from JV Inkai in 2024 at a 5% discount to the spot price, but does not account for an associated increase in the cash dividend expected, which will be tied to our agreed to 2024 production purchase entitlement and is expected to be received in 2025. JV Inkai distributes excess cash as dividends to its owners, net of working capital requirements. In the case of a $5 (US) per pound increase in uranium prices, the JV Inkai purchases are responsible for about $19 million of the noted expected decrease in cash flow and we expect the impact of these purchases on the 2024 cash flow will be partially offset by dividends once declared and paid in 2025.

If the uranium spot price decreased by $5 (US) per pound, we expect revenue to decrease by $15 million, ANE to decrease by $1 million, and cash flow to increase by $21 million. From a cash flow perspective, the impact of the noted decrease in uranium price on the assumed purchase of uranium from JV Inkai is expected to have the opposite impact from that described above for the noted uranium price increase.

In the case of a $5 (US) increase or decrease in the uranium spot price, the sensitivity for ANE compared to the sensitivity for cash flow is less due to the impact on our net earnings from the inclusion of our share of earnings from our equity-accounted investment in JV Inkai in the reporting period, the rate of inventory turnover, and income taxes.

The following assumptions were used to prepare the revenue, ANE and cash flow sensitivity analysis above:

• 2 million pounds of purchases are sourced from the market, including those pounds purchased to date.

• Total JV Inkai purchases for the year are equivalent to our 2023 purchase volume of 4.2 million pounds, of which 3.0 million pounds remain for 2024.

• For market-related contracts not yet priced and for delivery in 2024, subject to any floors or ceilings, we used a uranium spot price of $83.50 (US) per pound (the UxC spot price as of June 24, 2024), a long-term price indicator of $79.00 (US) per pound (the UxC long-term indicator on June 24, 2024) and an exchange rate of $1.00 (US) for $1.30 (Cdn).

To the extent that our market purchases or Inkai purchases vary, the sensitivity of our ANE and cash flow to changes in the spot and long-term prices may be impacted. In the case of decreased market or Inkai purchases, our sensitivity would be reduced. In the case of increased market or Inkai purchases, our sensitivity would be greater.

A one cent increase or decrease in the value of the Canadian dollar compared to the US dollar would respectively increase or decrease expected revenue by $13 million, ANE by $6 million and cash flow by $4 million.

2024 SECOND QUARTER REPORT 19

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

As discussed under Long-term contracting on page 25 of our 2023 annual MD&A, our average realized price is based on pricing terms established in our portfolio of long-term contracts, which includes a mix of base-escalated and market-related contracts that are layered in over time. Each confidential contract is bilaterally negotiated with the customer, and delivery generally does not begin until two years or more after signing.

• Base-escalated contracts will reflect market conditions and pricing at the time each contract was finalized, with escalation factors applied based on when the material is delivered.

• Market-related contracts reference a pricing mechanism that may be based on the spot price and/or the long-term price, and that price is generally set a month or more prior to delivery, subject to specific terms unique to each contract such as floors and ceilings set relative to market pricing at time of negotiation and typically escalated to time of delivery.

As a result of these contracting dynamics, changes to our average realized price will generally lag changes in market prices in both rising and falling price conditions. The magnitude and direction of the deviation can vary based on the degree of market price volatility between the time the contract price is set, and the time the product is delivered.

To help understand how the pricing under our current portfolio of commitments is expected to react at various spot prices at June 30, 2024, we have constructed the table that follows.

The table is based on the volumes and pricing terms under the long-term commitments in our contract portfolio that have been finalized as at June 30, 2024. The table does not include volumes and pricing terms in contracts under negotiation or those that have been accepted but are still subject to contract finalization. Based on the terms and volumes under contracts that have been finalized, the table is designed to indicate how our average realized price would react under various spot price assumptions at a point in time. In other words, the prices shown in the table would only be realized if the contract portfolio remained exactly as it was on June 30, 2024, using the following assumptions:

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

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

• To reflect escalation mechanisms contained in existing contracts the long-term US inflation rate target of 2% is used, for modeling purposes only.

It is important to note that the table is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table. We intend to update this table each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio. As a result, we expect the table to change from quarter to quarter.

Expected realized uranium price sensitivity under various spot price assumptions at June 30, 2024

(rounded to the nearest $1.00)
SPOT PRICES
($US/lb U3O8)	$	20	$	40	$	60	$	80	$	100	$	120	$	140
2024		49		52		55		57		58		59		59
2025		39		44		54		61		64		65		65
2026		42		44		56		67		69		70		72
2027		43		45		57		69		73		74		76
2028		46		49		58		70		75		77		78

As of June 30, 2024, we had commitments requiring delivery of an average of about 29 million pounds per year (previously an average of about 28 million pounds per year) from 2024 through 2028, with commitment levels in 2024 and 2025 being higher than the average, and in 2026 through 2028, lower than the average. As the market continues to improve, we expect to continue layering in volumes that capture greater future upside using market-related pricing mechanisms.

20 CAMECO CORPORATION

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 and the tools we have available so we can take advantage of favourable market conditions when they arise. To help provide this flexibility, we plan to file a new base shelf prospectus when the current base shelf prospectus expires in October 2024. We may also consider other financial tools to provide added flexibility. In addition, with improving prices under our long-term contract portfolio, our plan to return to a tier-one cost structure in our uranium segment, and an expected increase in our UF₆ conversion production, we expect to see strong cash flow generation in 2024.

As of June 30, 2024, we had cash and cash equivalents of $362 million, while our total debt amounted to approximately $1.4 billion. We also have a $1.0 billion undrawn credit facility.

Our cash balances and investments are held in government securities or with banks that are party to our lending facilities. We have a risk management policy that we follow to manage our exposure to banking counterparties, which limits amount and tenor of cash or investments based on counterparty credit rating. Our investment decisions prioritize security and liquidity and consider concentration amongst our banking partners. The majority of our cash balances are with Schedule I Canadian banks.

We continue to navigate by our investment-grade rating, which has been affirmed by both S&P and DBRS following our acquisition of Westinghouse (S&P rating of BBB- and DBRS rating of BBB). On May 24, 2024, we issued debentures in the amount of $500 million, at an interest rate of 4.94% per annum, the Series I senior unsecured debentures mature on May 24, 2031. The proceeds from the issuance were used to retire our outstanding $500 million Series G debentures bearing interest of 4.19% at maturity on June 24. Additionally, during the quarter, we made a partial prepayment of $100 million (US) on our floating-rate term loan. We plan to continue to prioritize repayment of the remaining $300 million (US) outstanding in floating-rate term loan debt used to finance the acquisition of Westinghouse while balancing our liquidity and cash position.

We expect our cash balances and operating cash flows to meet our capital requirements during 2024. However, cash flow from operations for 2024 will be dependent on our ability to source the material required to meet our deliveries as planned, including achieving our production plans.

We 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 will continue to provide a solid revenue stream. In our uranium segment, from 2024 through 2028, we have commitments to deliver an average of about 29 million pounds per year, with commitment levels in 2024 and 2025 higher than the average and in 2026 through 2028 lower than the average.

With the Supreme Court’s dismissal of CRA’s application for leave, the dispute for the 2003 through 2006 tax years is fully and finally resolved in our favour. Furthermore, we are confident the courts would reject any attempt by CRA to utilize the same position and arguments for tax years 2007 through 2014, or its alternate reassessing position for tax years 2014 through 2017 and believe CRA should return the $555 million in cash and letters of credit we have been required to pay or otherwise secure. However, timing of any further payments is uncertain. See Transfer pricing dispute starting on page 14 for more information.

CASH FROM/USED IN OPERATIONS

Cash provided by operations was $173 million higher this quarter than in the second quarter of 2023 due to higher gross profits in the uranium segment, a higher dividend payment from JV Inkai in 2024 and a decrease in working capital requirements which required $78 million less in 2024 than in 2023. Cash from operations in the quarter compared to the prior year also reflects higher interest received in 2023 due to higher cash and investment balances being held in the second quarter of 2023 in anticipation of closing the Westinghouse acquisition. Additionally, in the second quarter of 2023 we received an $86 million cash refund from CRA.

Cash provided by operations was $21 million higher in the first six months of 2024 compared to the same period in 2023 due to the same factors that impacted the quarter except for working capital requirements, which required $23 million more in 2024 than in 2023. See note 17 of our interim financial statements for more information.

2024 SECOND QUARTER REPORT 21

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.7 billion at June 30, 2024, unchanged from March 31, 2024. At June 30, 2024, we had approximately $1.5 billion outstanding in financial assurances, down from $1.6 billion at March 31, 2024 due to some changes to short-term requirements during the quarter.

At June 30, 2024, we had no short-term debt outstanding on our $1.0 billion unsecured revolving credit facility, unchanged from December 31, 2023. Our revolving credit facility matures October 1, 2027.

Additionally, after making partial prepayments of $300 million (US) in 2024, $300 million (US) remains outstanding on the term loan debt incurred in connection with the execution of the Westinghouse acquisition agreement. The remaining principal of $300 million (US) matures in November 2025.

Long-term contractual obligations

On May 24, 2024, we issued debentures in the amount of $500 million, at an interest rate of 4.94% per annum, the Series I senior unsecured debentures mature on May 24, 2031. The proceeds from the issuance were used to retire our outstanding $500 million Series G debentures bearing interest of 4.19% at maturity on June 24. Additionally, since December 31, 2023, we have repaid the full $300 million (US) of term loan debt that was set to mature in November 2026. There have been no other material changes to our long-term contractual obligations. Please see our 2023 annual MD&A for more information.

Debt covenants

As at June 30, 2024, we complied with all covenants in our credit agreements, including the financial covenants. The financial covenants place restrictions on total debt, including guarantees and other financial assurances. We do not expect our operating and investment activities for the remainder of 2024 to be constrained by these covenants.

SHARES AND STOCK OPTIONS OUTSTANDING

At July 29, 2024, we had:

• 435,180,572 common shares and one Class B share outstanding

• 391,469 stock options outstanding, with exercise prices ranging from $11.32 to $15.27

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at June 30, 2024:

• purchase commitments

• financial assurances

• other arrangements

Purchase commitments

There have been no material changes to our purchase commitments since December 31, 2023. Please see our annual MD&A for more information.

Financial assurances

At June 30, 2024, our financial assurances totaled $1.5 billion, down from $1.6 billion at March 31, 2024, due to some changes of short-term requirements during this quarter.

Other arrangements

We have arranged for standby product loan facilities with various counterparties. The arrangements allow us to borrow up to 2.0 million kgU of UF₆ conversion services and 6.7 million pounds of U₃O₈ over the period 2020 to 2027 with repayment in kind up to December 31, 2027. Under the loan facilities, standby fees of up to 1.5% 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 3.0%. At June 30, 2024, we have 1.8 million kgU of UF₆ conversion services and 2.8 million pounds of U₃O₈ drawn on the loans.

22 CAMECO CORPORATION

BALANCE SHEET

($ MILLIONS)	JUN 30, 2024		DEC 31, 2023		CHANGE
Cash and cash equivalents		362		567		(36	)%
Total debt		1,403		1,784		(21	)%
Inventory		838		692		21	%

Total cash and cash equivalents at June 30, 2024, were $362 million, or 36% lower than at December 31, 2023, due mainly to $300 million (US) in pre-payments on the floating-rate term loan during the year partially offset by the receipt of $129 million (US) of dividend payments from JV Inkai. Net debt at June 30, 2024, was $1.0 billion.

Total product inventories are $838 million compared to $692 million at the end of 2023. Inventories increased due to sales being lower than production and purchases in the first six months of the year. The average cost for uranium has decreased to $46.49 per pound compared to $49.62 per pound at December 31, 2023. As of June 30, 2024, we held an inventory of 13.4 million pounds of U₃O₈ equivalent (excluding broken ore) (December 31, 2023 - 10.3 million pounds). Inventory varies from quarter to quarter depending on the timing of production, purchases and sales deliveries in the year.

Financial results by segment

Uranium

		THREE MONTHS					SIX MONTHS
		ENDED JUNE 30					ENDED JUNE 30
HIGHLIGHTS		2024		2023		CHANGE	2024		2023		CHANGE
Production volume (million lbs)			7.1		4.4	61%		12.9		8.8		47	%
Sales volume (million lbs)			6.2		5.5	13%		13.5		15.2		(11	)%
Average spot price	($US/lb)		87.88		54.53	61%		91.10		52.60		73	%
Average long-term price	($US/lb)		78.50		54.83	43%		76.67		53.83		42	%
Average realized price
	($US/lb)		56.43		49.41	14%		57.04		46.81		22	%
	($Cdn/lb)		76.93		67.05	15%		77.15		63.17		22	%
Average unit cost of sales (including D&A)	($Cdn/lb)		53.86		53.93	—		54.01		49.37		9	%
Revenue			481		369	30%		1,042		963		8	%
Gross profit			144		72	100%		313		208		50	%
Gross profit (%)			30		20	50%		30		22		36	%
Net earnings attributable to equity holders			192		68	>100%		445		256		74	%
Adjusted EBITDA ($ millions) (non-IFRS, see page 29)			248		118	>100%		550		378		46	%

SECOND QUARTER

Production during the quarter was 7.1 million pounds, 61% higher than the second quarter of 2023. See Uranium 2024 Q2 updates starting on page 27 for more information.

Uranium revenues this quarter were up 30% compared to 2023 due to a 13% increase in sales volume due to the timing of sales, which were in line with the delivery pattern disclosed in our annual MD&A, and an increase of 15% in the Canadian dollar average realized price. The average realized price increased as a result of the impact of spot price changes on market-related contracts. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 20.

Total cost of sales (including D&A) increased by 13% ($336 million compared to $297 million in 2023) due to a 13% increase in sales volume. Unit cost of sales was unchanged from the same period last year.

The net effect was a $72 million increase in gross profit for the quarter.

Equity earnings from investee, JV Inkai, were $48 million in the second quarter compared to $8 million in the same period last year.

FIRST SIX MONTHS

Production volumes for the first six months of the year were 47% higher than in the previous year. See Uranium 2024 Q2 updates starting on page 27 for more information.

2024 SECOND QUARTER REPORT 23

Uranium revenues increased 8% compared to the first six months of 2023 despite an 11% decrease in sales volumes, due to an increase of 22% in the Canadian dollar average realized price, which was a result of the impact of the increase in the average US dollar spot price on market-related contracts. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 20.

Total cost of sales (including D&A) decreased by 3% ($729 million compared to $755 million in 2023) primarily as a result of an 11% decrease in sales volume partially offset by a unit cost of sales that was 9% higher than the same period last year. Unit cost of sales was higher in 2024 due to the higher cost of purchased material in 2024 compared to the same period in 2023.

The net effect was a $105 million increase in gross profit for the first six months.

Equity earnings from investee, JV Inkai, were $125 million in the first six months of 2024 compared to $64 million in the same period last year.

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

	THREE MONTHS							SIX MONTHS
	ENDED JUNE 30							ENDED JUNE 30
($CDN/LB)	2024		2023		CHANGE			2024		2023		CHANGE
Produced
Cash cost		16.96		23.35		(27	)%		18.11		23.24		(22	)%
Non-cash cost		9.10		12.82		(29	)%		9.41		11.81		(20	)%
Total production cost 1		26.06		36.17		(28	)%		27.52		35.05		(21	)%
Quantity produced (million lbs)1		7.1		4.4		61	%		12.9		8.8		47	%
Purchased
Cash cost		109.11		68.31		60	%		96.25		68.17		41	%
Quantity purchased (million lbs)1		1.7		3.8		(55	)%		4.4		4.2		5	%
Totals
Produced and purchased costs		42.10		51.06		(18	)%		45.00		45.75		(2	)%
Quantities produced and purchased (million lbs)		8.8		8.2		7	%		17.3		13.0		33	%

¹  Due to equity accounting, our share of production from JV Inkai is shown as a purchase at the time of delivery. These purchases will fluctuate during the quarters and timing of purchases will not match production. There were no purchases during the quarter. In the first six months of 2024, we purchased 1.1 million pounds at a purchase price per pound of $129.96 ($96.88 (US)).

The average cash cost of production was 27% lower for the quarter compared to the same period in 2023. For the first six months, the average cash cost of production was 22% lower than in the same period in 2023.

In 2024, we expect the average unit cost of production at McArthur River/Key Lake to continue to be higher than the average unit life of mine operating costs reflected in our most recent annual information form as we complete the ramp up of production and continue work to realize the benefits from the operational improvements that have been made. The estimated average unit life of mine operating costs reflected in our most recent annual information form are $16.70 per pound at McArthur River/Key Lake and $20.58 per pound at Cigar Lake.

Our purchases in the second quarter of 2024 totaled about $185 million, representing an average cost of $109.11 per pound, about $83.00 per pound higher than our total unit production cost for the quarter. Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the second quarter, the average cash cost of purchased material was $109.11 (Cdn) per pound, or $80.27 (US) per pound, compared to $68.31 (Cdn) per pound, or $50.23 (US) per pound in the second quarter of 2023. As a result, the average cash cost per pound of purchased material in Canadian dollar terms increased by 60% this quarter compared to the same period last year.

For the first six months of the year, purchases totaled about $424 million, representing an average cost of $96.25 per pound, about $69.00 per pound higher than our total unit production cost for the same period last year. The average cash cost of purchased material for the six-month period was $96.25 (Cdn), or $71.32 (US) per pound, compared to $68.17 (Cdn), or $50.16 (US) per pound in the same period in 2023. As a result, the average cash cost per pound of purchased material in Canadian dollar terms increased by 41% for the six months compared to the same period last year.

24 CAMECO CORPORATION

We equity account for our share of JV Inkai. As a result, we record our share of its production as a purchase, which under Kazakhstan’s pricing regulations, requires we purchase the material at a price equal to the uranium spot price, less a 5% discount. Our share of the economic benefit is reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investee” and is based on the difference between our purchase price and JV Inkai’s lower production cost (estimated average unit life of mine operating cash cost of $12.42 per pound, prior to the implementation of the amended MET provisions). 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.

JV Inkai contribution to uranium segment

In the second quarter, included in net earnings attributable to equity holders for the uranium segment is $48 million of equity earnings and included in EBITDA is $54 million of EBITDA from JV Inkai, compared to $8 million and $18 million respectively in the same period last year.

For the first six months of the year, $125 million is included in net earnings attributable to equity holders and $159 million is included in EBITDA from JV Inkai, compared to $64 million and $80 million respectively in the same period last year.

The increase in JV Inkai’s equity earnings and EBITDA was largely driven by the higher uranium prices in the first quarter and six months of 2024 compared to the same periods in 2023, partially offset by increased costs. In April, we received a cash dividend of $129 million (US), net of withholdings, based on JV Inkai’s 2023 financial performance. From a cash flow perspective, we expect to realize the benefit from JV Inkai’s 2024 financial performance in 2025, once the dividend for 2024 is declared and paid.

The following table reconciles our share of earnings from JV Inkai to EBITDA:

	THREE MONTHS							SIX MONTHS
	ENDED JUNE 30							ENDED JUNE 30
($ MILLIONS)	2024		2023		CHANGE			2024		2023		CHANGE
Share of earnings from equity-accounted investee		48		8		>100	%		125		64		95	%
Depreciation and amortization		2		3		(33	)%		10		5		100	%
Income tax expense		4		7		(43	)%		24		11		>100	%
EBITDA (non-IFRS, see page 29) attributable to JV Inkai		54		18		>100	%		159		80		99	%

Fuel services

(includes results for UF6, UO2, UO3 and fuel fabrication)
		THREE MONTHS							SIX MONTHS
		ENDED JUNE 30							ENDED JUNE 30
HIGHLIGHTS		2024		2023		CHANGE			2024		2023		CHANGE
Production volume (million kgU)			2.9		3.4		(15	)%		6.7		7.6		(12	)%
Sales volume (million kgU)			2.9		3.2		(9	)%		4.4		5.6		(21	)%
Average realized price	($Cdn/kgU)		39.98		35.63		12	%		42.80		36.51		17	%
Average unit cost of sales (including D&A)	($Cdn/kgU)		29.05		23.38		24	%		31.35		24.14		30	%
Revenue			118		113		4	%		190		206		(8	)%
Net earnings attributable to equity holders			33		39		(15	)%		53		70		(24	)%
Adjusted EBITDA ($ millions) (non-IFRS, see page 29)			42		48		(13	)%		67		86		(22	)%
Adjusted EBITDA margin (%) (non-IFRS, see page 29)			36		42		(14	)%		35		42		(17	)%

SECOND QUARTER

Total revenue for the second quarter of 2024 increased by 4% from $113 million in the same period last year to $118 million. This was due primarily to a 12% increase in average realized price compared to 2023 partially offset by a 9% decrease in sales volumes. Average realized price increased mainly due to constructive market conditions and increased prices for UF₆.

The total cost of products and services sold (including D&A) increased 16% ($86 million compared to $74 million in 2023) due to an increase of 24% in the average unit cost of sales, which was partially offset by the 9% decrease in sales volume. Unit cost of sales increased mainly due to lower production volumes which was a result of operational issues in the first half of the year which have now been resolved.

2024 SECOND QUARTER REPORT 25

The net effect was a $6 million decrease in net earnings.

FIRST SIX MONTHS

In the first six months of the year, total revenue decreased 8% to $190 million from $206 million for the same period last year due to a 21% decrease in sales volumes, partially offset by a 17% increase in average realized price. The increase in average realized price was mainly the result of increased prices due to constructive market conditions.

The total cost of products and services sold (including D&A) increased 2% ($139 million compared to $136 million in 2023) due to a 30% increase in the average unit cost of sales partially offset by a 21% decrease in sales volume. Average unit cost of sales was higher as a result of increased input costs as well as the lower production volume.

The net effect was a $17 million decrease in net earnings.

Westinghouse

OUR EARNINGS FROM WESTINGHOUSE

On November 7, 2023, we announced the closing of the acquisition of Westinghouse in a strategic partnership with Brookfield. Cameco now owns a 49% interest and Brookfield owns the remaining 51%. Under the equity method of accounting, beginning on November 7, 2023, we have included our share of Westinghouse’s earnings in our financial results.

	THREE MONTHS							SIX MONTHS
	ENDED JUNE 30							ENDED JUNE 30
($ MILLIONS)	2024			20231		CHANGE		2024			20231		CHANGE
Net loss		(47	)		—		—		(170	)		—		—
Depreciation and amortization		89			—		—		173			—		—
Finance income		(1	)		—		—		(3	)		—		—
Finance costs		54			—		—		118			—		—
Income tax recovery		(11	)		—		—		(48	)		—		—
EBITDA2		84			—		—		70			—		—
Inventory purchase accounting		16			—		—		66			—		—
Acquisition-related transition costs		6			—		—		25			—		—
Other expenses		15			—		—		36			—		—
Adjusted EBITDA2		121			—		—		197			—		—
Capital expenditures		32			—		—		65			—		—
Adjusted free cash flow2		89			—		—		132			—		—
Revenue		670			—		—		1,325			—		—
Adjusted EBITDA margin2		18	%		—		—		15	%		—		—

¹  2023 results are presented for comparative purposes only. Cameco did not acquire its interest in Westinghouse until November 7, 2023.

²  Non-IFRS measures, see page 29.

In line with the expected variability in Westinghouse’s quarterly performance, second quarter results improved over the first quarter with a reported net loss of $47 million (our share), resulting in a net loss of $170 million (our share) for the six months ended June 30, 2024 primarily related to the impact of purchase accounting, which required the revaluation of its inventories based on market prices at time of acquisition and the expensing of some other non-operating acquisition-related transition costs. As the acquired inventory is sold, Westinghouse’s cost of products and services sold will reflect these higher market values, regardless of its historic costs. The impact of the revaluation of inventory and the other non-operating acquisition-related transition costs are largely isolated to 2024 and therefore are expected to have little impact in future years. However, Westinghouse’s quarterly results will continue to be impacted by amortization of the intangible assets that arose as a result of the fair values assigned to Westinghouse’s net assets at the time of acquisition. We use adjusted EBITDA as a performance measure as the impact of the revaluation of Westinghouse’s inventory and assets and the non-operating acquisition-related transition costs do not reflect the underlying performance for the reporting period. We believe Westinghouse remains on track to achieve its 2024 outlook.

26 CAMECO CORPORATION

We do not believe Westinghouse’s quarterly results are necessarily a good indication of annual results due to variability in timing of customer requirements and delivery and outage schedules. The first quarter is typically weaker, with stronger expected performance in the second half of the year, and higher expected cash flows in the fourth quarter.

Our operations

Uranium – production overview

We produced 7.1 million pounds of U₃O₈ (our share) in the second quarter and 12.9 million pounds production (our share) in the first six months of 2024, compared to 4.4 million pounds and 8.8 million pounds in the same periods of 2023. In 2023, the Key Lake mill had not yet achieved an 18 million pound per year run rate, and at Cigar Lake, productivity was impacted by a transition to a new mining area.

We continue to evaluate the optimal mix of production, inventory and purchases in order to retain the flexibility to deliver long-term value.

URANIUM PRODUCTION

	THREE MONTHS							SIX MONTHS
	ENDED JUNE 30							ENDED JUNE 30
OUR SHARE (MILLION LBS)	2024		2023		CHANGE			2024		2023		CHANGE			2024 PLAN
Cigar Lake		2.9		2.1		38	%		5.1		4.2		21	%		9.8
McArthur River/Key Lake		4.2		2.3		83	%		7.8		4.6		70	%		12.6
Total		7.1		4.4		61	%		12.9		8.8		47	%		22.4

Inflation, the availability of personnel with the necessary skills and experience, aging infrastructure, and the impact of supply chain challenges on the availability of materials and reagents carry with them the risk that we do not achieve our production plans and/or, experience production delays and increased costs.

The annual maintenance shutdowns at Cigar Lake and at McArthur River and Key Lake are currently planned for the third quarter of 2024, which is similar timing to previous years.

Uranium 2024 Q2 updates

PRODUCTION UPDATE

McArthur River/Key Lake

In the second quarter of 2024, total packaged production from McArthur River and Key Lake was 6.2 million pounds (4.2 million pounds our share) compared to 3.3 million pounds (2.3 million pounds our share) in the second quarter of 2023. Our share of production was higher in the second quarter of 2024 compared to 2023 with the mill having achieved its planned production run rate. Our share of production in the first six months of 2024 was 7.8 million pounds compared to 4.6 million pounds in 2023 for the same reason.

We continue to expect production of 18 million pounds (12.6 million pounds our share) in 2024.

The collective agreement with the United Steelworkers Local 8914 expired in December 2022 and a new three-year contract was approved by union membership in July 2024. The new collective agreement expires in December 2025.

Cigar Lake

Total packaged production from Cigar Lake was 5.3 million pounds (2.9 million pounds our share) in the second quarter of 2024 compared to 3.8 million pounds (2.1 million pounds our share) in the second quarter of 2023, when quarterly production was lower while transitioning to a new mining area. Our share of production in the first six months of 2024 was 5.1 million pounds compared to 4.2 million pounds in the same period in 2023 for the same reason.

We continue to expect 18.0 million pounds (9.8 million pounds our share) in 2024.

2024 SECOND QUARTER REPORT 27

Inkai

Production on a 100% basis was 1.9 million pounds for the quarter, and 3.5 million pounds for the first six months of this year, compared to 2.4 million pounds and 4.3 million pounds in the same periods last year. The lower production for the quarter and the first half of the year is attributed to challenges with acid supply in the early part of the year.

Due to equity accounting, our share of production is shown as a purchase at a 5% discount to the spot price and included in inventory at this value at the time of delivery. Our share of the profits earned by JV Inkai on the sale of its production to the JV partners is included in “share of earnings from equity-accounted investee” on our consolidated statement of earnings. Excess cash, net of working capital requirements, is distributed to the partners as dividends once declared.

JV Inkai continues to experience procurement and supply chain issues, most notably, related to the stability of sulfuric acid deliveries. JV Inkai’s current production target for 2024 is 8.3 million pounds of U₃O₈ (100% basis). However, this target is tentative and contingent upon receipt of sufficient volumes of sulfuric acid. Our allocation of the planned production from JV Inkai remains under discussion, which is now further complicated by taxation changes that are expected to take effect beginning in 2025.

In addition to the issue of availability of sulfuric acid, achievement of JV Inkai’s 2024 production target requires it to successfully manage several other ongoing risks, including other procurement and supply chain issues, transportation challenges, construction delays and inflationary pressures on its production costs.

The geopolitical situation continues to cause transportation risks in the region. We continue to work closely with JV Inkai and our joint venture partner, Kazatomprom, to receive our share of production via the Trans-Caspian International Transport Route, which does not rely on Russian rail lines or ports. We could experience further delays to our expected Inkai deliveries this year if transportation using this shipping route takes longer than anticipated.

To mitigate the risk of production shortfalls or transportation delays, we have inventory, long-term purchase agreements and loan arrangements in place we can draw on.

Depending on cost inflation impacts, actual production volumes and when we receive shipments of our share of Inkai’s 2024 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.

Subsequent to the end of the quarter, our JV partner, Kazatomprom, issued a news release indicating that at the end of June, the government of the Republic of Kazakhstan introduced amendments to the country’s Tax Code, including significant increases to the MET rate paid by mining entities on uranium production, beginning in 2025. We are evaluating the new MET and if it remains as currently formulated, preliminary conclusions indicate that production costs in Kazakhstan would be similar to northern Saskatchewan operations, depending on the assumptions used for uranium price, production profile, and exchange rate.

TIER-TWO CURTAILED OPERATIONS

US ISR Operations

As a result of our 2016 curtailment decision, commercial production has ceased. As production is suspended, we expect ongoing cash and non-cash care and maintenance costs to range between $12.5 million (US) and $14.5 million (US) for 2024.

Rabbit Lake

Rabbit Lake remains in a safe state of care and maintenance following the suspension of production in 2016. We continue to evaluate opportunities to minimize care and maintenance costs while maintaining critical infrastructure and processes. We expect care and maintenance costs to range between $29 million and $33 million for 2024.

28 CAMECO CORPORATION

Fuel services 2024 Q2 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 2.9 million kgU in the second quarter of 2024, 15% lower than the second quarter last year primarily due to temporary operational issues in one of the processing circuits at the UF₆ plant, which have been resolved. Production in the first six months of 2024 was 6.7 million kgU, down 12% compared to the same period last year, also related to the temporary operational issues in the first half of 2024.

Our fuel services segment includes the combined production of UO₂, UF₆, and heavy water reactor fuel bundles. Although fuel services outlook and production results are typically not broken down by individual product line, we previously indicated we were targeting production of 12,000 tonnes per year at the Port Hope UF₆ conversion facility. While our annual production expectation for fuel services remains between 13.5 million and 14.5 million kgU of combined fuel services products in 2024, we now expect the conversion component of that guidance to be between 11,000 and 11,500 tonnes of UF₆.

We are continuing our work at Port Hope to achieve an ongoing production rate that will supply 12,000 tonnes per year in order to satisfy our book of long-term commitments and demand for conversion services. Inflation, the availability of personnel with the necessary skills and experience, aging infrastructure, and the impact of supply chain challenges on the availability of materials and reagents carry with them the risk that we do not achieve our production plans and/or experience production delays and increased costs.

A new collective agreement with unionized employees at our Cameco Fuel Manufacturing operations was reached in June 2024 for a three-year term, expiring in June 2027.

Qualified persons

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

MCARTHUR RIVER/KEY LAKE   •  Greg Murdock, general manager, McArthur River, Cameco   •  Daley McIntyre, general manager, Key Lake, Cameco   CIGAR LAKE   •  Kirk Lamont, general manager, Cigar Lake, Cameco INKAI   •  Sergey Ivanov, deputy general director, technical services, Cameco Kazakhstan LLP

Non-IFRS measures

The non-IFRS measures referenced in this document are supplemental measures, which are used as indicators of our financial performance. Management believes that these non-IFRS measures provide useful supplemental information to investors, securities analysts, lenders and other interested parties in assessing our operational performance and our ability to generate cash flows to meet our cash requirements. These measures are not recognized measures under IFRS, do not have standardized meanings, and are therefore unlikely to be comparable to similarly titled measures presented by other companies. Accordingly, these measures should not be considered in isolation or as a substitute for the financial information reported under IFRS. The following are the non-IFRS measures used in this document.

2024 SECOND QUARTER REPORT 29

ADJUSTED NET EARNINGS

Adjusted net earnings is our net earnings attributable to equity holders, adjusted for non-operating or non-cash items such as gains and losses on derivatives, adjustments to reclamation provisions flowing through other operating expenses, and bargain purchase gains, that we believe do not reflect the underlying financial performance for the reporting period. Other items may also be adjusted from time to time. We adjust this measure for certain of the items that our equity-accounted investees make in arriving at other non-IFRS measures. Adjusted net earnings is one of the targets that we measure to form the basis for a portion of annual employee and executive compensation (see Measuring our results starting on page 36 of our 2023 annual report).

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 15 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 an asset retirement obligation asset in addition to the provision balance. When the assets of an operation have been written off due to an impairment, as is the case with our Rabbit Lake and US ISR operations, the adjustment is recorded directly to the statement of earnings as “other operating expense (income)”. See note 10 of our interim financial statements for more information. This amount has been excluded from our ANE measure.

The bargain purchase gain that was recognized in the second quarter of 2022 when we acquired our pro-rata share of Idemitsu Canada Resources Ltd.’s 7.875% participating interest in the Cigar Lake Joint Venture has also been removed in calculating ANE since it is non-cash, non-operating and outside of the normal course of our business. The gain was recorded in the statement of earnings as part of “other income (expense)”.

As a result of the change in ownership of Westinghouse when it was acquired by Cameco and Brookfield, Westinghouse’s inventories at the acquisition date were revalued based on the market price at that date. As these quantities are sold, Westinghouse’s cost of products and services sold reflect these market values, regardless of their historic costs. Our share of these costs are included in earnings from equity-accounted investees and recorded in cost of products and services sold in the investee information (see note 7 to the financial statements). Since this expense is non-cash, outside of the normal course of business and only occurred due to the change in ownership, we have excluded our share from our ANE measure.

Westinghouse has also expensed some non-operating acquisition-related transition costs that the acquiring parties agreed to pay for, which resulted in a reduction in the purchase price paid. Our share of these costs are included in earnings from equity-accounted investees and recorded in other expenses in the investee information (see note 7 to the financial statements). Since this expense is outside of the normal course of business and only occurred due to the change in ownership, we have excluded our share from our ANE measure.

30 CAMECO CORPORATION

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the second quarter and first six months of 2024 and compares it to the same periods in 2023.

	THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS)	2024			2023			2024			2023
Net earnings attributable to equity holders		36			14			29			133
Adjustments
Adjustments on derivatives		14			(35	)		47			(41	)
Inventory purchase accounting (net of tax)		12			—			50			—
Acquisition-related transition costs (net of tax)		5			—			19			—
Adjustment to other operating expense (income)		(2	)		8			(17	)		6
Income taxes on adjustments		(3	)		10			(10	)		14
Adjusted net earnings (losses)		62			(3	)		118			112

The following table shows what contributed to the change in adjusted net earnings in the second quarter and first six months of 2024 compared to the same period in 2023.

		THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS)		IFRS			ADJUSTED			IFRS			ADJUSTED
Net earnings (losses) - 2023		14			(3)			133			112
Change in gross profit by segment (We calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)
Uranium	Impact from sales volume changes		10			10			(24	)		(24	)
	Higher realized prices ($US)		60			60			186			186
	Foreign exchange impact on realized prices		2			2			3			3
	Lower (higher) costs		1			1			(61	)		(61	)
	Change – uranium		73			73			104			104
Fuel services	Impact from sales volume changes		(3	)		(3	)		(15	)		(15	)
	Higher realized prices ($Cdn)		13			13			28			28
	Higher costs		(17	)		(17	)		(32	)		(32	)
	Change – fuel services		(7	)		(7	)		(19	)		(19	)
Other changes
Higher administration expenditures			(9	)		(9	)		(5	)		(5	)
Higher exploration and research and development expenditures			(2	)		(2	)		(8	)		(8	)
Change in reclamation provisions			11			1			26			3
Higher (lower) earnings from equity-accounted investees			(7	)		10			(109	)		(40	)
Change in gains or losses on derivatives			(48	)		1			(91	)		(3	)
Change in foreign exchange gains or losses			49			49			68			68
Lower finance income			(23	)		(23	)		(45	)		(45	)
Higher finance costs			(20	)		(20	)		(36	)		(36	)
Change in income tax recovery or expense			5			(8	)		10			(14	)
Other			—			—			1			1
Net earnings - 2024			36			62			29			118

EBITDA

EBITDA is defined as net earnings attributable to equity holders, adjusted for the costs related to the impact of the company’s capital and tax structure including depreciation and amortization, finance income, finance costs (including accretion) and income taxes. Included in EBITDA is our share of equity-accounted investees.

ADJUSTED EBITDA

Adjusted EBITDA is defined as EBITDA, as further adjusted for the impact of certain costs or benefits incurred in the period which are either not indicative of the underlying business performance or that impact the ability to assess the operating performance of the business. These adjustments include the amounts noted in the ANE definition.

2024 SECOND QUARTER REPORT 31

In calculating adjusted EBITDA, we also adjust for items included in the results of our equity-accounted investees that are not adjustments to arrive at our ANE measure. These items are reported as part of other expenses within the investee financial information and are not representative of the underlying operations. These primarily include transaction, integration and restructuring costs related to acquisitions.

The company may realize similar gains or incur similar expenditures in the future.

ADJUSTED FREE CASH FLOW

Adjusted free cash flow is defined as adjusted EBITDA less capital expenditures for the period.

ADJUSTED EBITDA MARGIN

Adjusted EBITDA margin is defined as adjusted EBITDA divided by revenue for the appropriate period.

EBITDA, adjusted EBITDA, adjusted free cash flow, and adjusted EBITDA margin are non-IFRS measures which allow us and other users to assess results of operations from a management perspective without regard for our capital structure. To facilitate a better understanding of these measures, the tables below reconcile earnings before income taxes with EBITDA and adjusted EBITDA for the first quarter of 2024 and 2023.

For the quarter ended June 30, 2024:

				FUEL
($ MILLIONS)	URANIUM1			SERVICES		WESTINGHOUSE			OTHER			TOTAL
Net earnings (loss) attributable to equity holders		192			33		(47	)		(142	)		36
Depreciation and amortization		52			9		—			1			62
Finance income		—			—		—			(8	)		(8	)
Finance costs		—			—		—			43			43
Income taxes		—			—		—			18			18
		244			42		(47	)		(88	)		151
Adjustments on equity investees
Depreciation and amortization		2			—		89			—
Finance income		—			—		(1	)		—
Finance expense		—			—		54			—
Income taxes		4			—		(11	)		—
Net adjustments on equity investees		6			—		131			—			137
EBITDA		250			42		84			(88	)		288
Gain on derivatives		—			—		—			14			14
Other operating income		(2	)		—		—			—			(2	)
		(2	)		—		—			14			12
Adjustments on equity investees
Inventory purchase accounting		—			—		16			—
Acquisition-related transition costs		—			—		6			—
Other expenses		—			—		15			—
Net adjustments on equity investees		—			—		37			—			37
Adjusted EBITDA		248			42		121			(74	)		337

¹  JV Inkai EBITDA of $54 million is included in the uranium segment. See Financial results by segment - Uranium for reconciliation.

32 CAMECO CORPORATION

For the quarter ended June 30, 2023:

			FUEL
($ MILLIONS)	URANIUM1		SERVICES		OTHER			TOTAL
Net earnings (loss) attributable to equity holders		68		39		(93	)		14
Depreciation and amortization		32		9		1			42
Finance income		—		—		(31	)		(31	)
Finance costs		—		—		23			23
Income taxes		—		—		23			23
		100		48		(77	)		71
Adjustments on equity investees
Depreciation and amortization		3		—		—
Income taxes		7		—		—
Net adjustments on equity investees		10		—		—			10
EBITDA		110		48		(77	)		81
Loss on derivatives		—		—		(35	)		(35	)
Other operating expense		8		—		—			8
Adjusted EBITDA		118		48		(112	)		54

¹  JV Inkai EBITDA of $18 million is included in the uranium segment. See Financial results by segment - Uranium for reconciliation.

For the six months ended June 30, 2024:

				FUEL
($ MILLIONS)	URANIUM1			SERVICES		WESTINGHOUSE			OTHER			TOTAL
Net earnings (loss) attributable to equity holders		445			53		(170	)		(299	)		29
Depreciation and amortization		88			14		—			2			104
Finance income		—			—		—			(14	)		(14	)
Finance costs		—			—		—			82			82
Income taxes		—			—		—			49			49
		533			67		(170	)		(180	)		250
Adjustments on equity investees
Depreciation and amortization		10			—		173			—
Finance income		—			—		(3	)		—
Finance expense		—			—		118			—
Income taxes		24			—		(48	)		—
Net adjustments on equity investees		34			—		240			—			274
EBITDA		567			67		70			(180	)		524
Gain on derivatives		—			—		—			47			47
Other operating income		(17	)		—		—			—			(17	)
		(17	)		—		—			47			30
Adjustments on equity investees
Inventory purchase accounting		—			—		66			—
Acquisition-related transition costs		—			—		25			—
Other expenses		—			—		36			—
Net adjustments on equity investees		—			—		127			—			127
Adjusted EBITDA		550			67		197			(133	)		681

¹  JV Inkai EBITDA of $159 million is included in the uranium segment. See Financial results by segment - Uranium for reconciliation.

2024 SECOND QUARTER REPORT 33

For the six months ended June 30, 2023:

($ MILLIONS)	URANIUM1		FUEL SERVICES		OTHER			TOTAL
Net earnings (loss) attributable to equity holders		256		70		(193	)		133
Depreciation and amortization		100		16		2			118
Finance income		—		—		(59	)		(59	)
Finance costs		—		—		46			46
Income taxes		—		—		59			59
		356		86		(145	)		297
Adjustments on equity investees
Depreciation and amortization		5		—		—
Income taxes		11		—		—
Net adjustments on equity investees		16		—		—			16
EBITDA		372		86		(145	)		313
Loss on derivatives		—		—		(41	)		(41	)
Other operating expense		6		—		—			6
Adjusted EBITDA		378		86		(186	)		278

¹  JV Inkai EBITDA of $80 million is included in the uranium segment. See Financial results by segment - Uranium for reconciliation.

CASH COST PER POUND, NON-CASH COST PER POUND AND TOTAL COST PER POUND FOR PRODUCED AND PURCHASED URANIUM

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium are non-IFRS measures. We use these measures in our assessment of the performance of our uranium business. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS.

To facilitate a better understanding of these measures, the table below reconciles these measures to cost of product sold and depreciation and amortization for the second quarter and first six months of 2024 and 2023.

	THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS)	2024			2023			2024			2023
Cost of product sold		284.7			264.5			640.5			654.5
Add / (subtract)
Royalties		(32.2	)		(14.1	)		(50.0	)		(38.8	)
Care and maintenance costs		(11.7	)		(11.1	)		(23.8	)		(23.1	)
Other selling costs		(4.5	)		(1.4	)		(9.4	)		(4.1	)
Change in inventories		69.6			124.4			99.8			(97.7	)
Cash operating costs (a)		305.9			362.3			657.1			490.8
Add / (subtract)
Depreciation and amortization		51.5			32.2			88.2			100.1
Care and maintenance costs		(0.2	)		(1.0	)		(0.4	)		(2.5	)
Change in inventories		13.3			25.2			33.6			6.3
Total operating costs (b)		370.5			418.7			778.5			594.7
Uranium produced & purchased (million lbs) (c)		8.8			8.2			17.3			13.0
Cash costs per pound (a ÷ c)		34.76			44.18			37.98			37.75
Total costs per pound (b ÷ c)		42.10			51.06			45.00			45.75

34 CAMECO CORPORATION

Additional information

Critical accounting estimates

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

Purchase prices related to business combinations and asset acquisitions are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires us to make assumptions, estimates and judgments regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation impacts our reported assets and liabilities, future net earnings due to the impact on future depreciation and amortization expense and impairment tests.

Controls and procedures

As of June 30, 2024, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of June 30, 2024, the CEO and CFO concluded that:

• the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required; and

• such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

In April 2024, we implemented SAP S/4 HANA, an enterprise resource planning (ERP) system, across the entire organization. As a result of this implementation, we modified certain existing internal controls and implemented new controls and procedures. The implementation process included extensive involvement by key end users and required significant pre-implementation planning, design, and testing. We continue to evaluate and monitor our internal controls and believe we are taking the necessary steps to maintain appropriate internal controls over financial reporting during this period of change. This includes performing additional verifications and analysis to ensure data integrity.

There have been no other changes in our internal control over financial reporting during the quarter ended June 30, 2024, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

2024 SECOND QUARTER REPORT 35