Exhibit 99.2

Management’s discussion and analysis

for the quarter ended June 30, 2023

5	SECOND QUARTER MARKET UPDATE
9	OUR STRATEGY
11	CONSOLIDATED FINANCIAL RESULTS
18	OUTLOOK FOR 2023
20	LIQUIDITY AND CAPITAL RESOURCES
23	FINANCIAL RESULTS BY SEGMENT
26	OUR OPERATIONS - SECOND QUARTER UPDATES
29	QUALIFIED PERSONS
30	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, 2023 (interim financial statements). The information is based on what we knew as of August 1, 2023, and updates our first quarter and annual MD&A included in our 2022 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, 2022, 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 2023 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 ability to address environmental, social and governance risks and opportunities, and our ambition to reach net-zero greenhouse gas emissions

• the discussion under the heading Strategy in action including, the demand for nuclear fuel supplies, our expectations regarding uranium contracting and our contract portfolio, 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 our expected financial capacity to execute our strategy and self-manage risk

• the discussion of our expectations relating to our acquisition of a 49% interest in Westinghouse Electric Company (Westinghouse), including the sources and uses of financing for the acquisition, the timeline of the acquisition, including the anticipated closing thereof, and creating a powerful platform for strategic growth

• the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our expectations regarding receiving refunds and payment of disbursements from CRA, our confidence that the courts would reject any attempt by CRA to utilize the same position and arguments for tax years 2007 through 2014 or the alternate position advanced for tax years 2014 through 2016, and our belief that CRA should return the full amount of cash and security that has been paid or otherwise secured by us

• the discussion under the heading Outlook for 2023, including our production plan, expected improvement in financial performance, expected care and maintenance costs for our tier-two assets, our cash balances and the generation of cash flow, our outlook for our uranium average realized price, and other information in the table under the heading 2023 Financial Outlook, our revenue, adjusted net earnings, and cash flow sensitivity analysis, and our price sensitivity analysis for our uranium segment

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

• our expectation that our operating and investment activities for the remainder of 2023 will not be constrained by the financial-related covenants in our unsecured revolving credit facility

• our intention to update the table under the heading Purchase commitments to reflect material changes to purchase commitments and prices

• 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

• expected timing for the first shipment of our 2023 share of Inkai’s production to begin transit and the possibility of further delays in expected Inkai deliveries this year

• we have inventory, long-term purchase agreements and loan arrangements in place that we can draw upon to mitigate the risk of delay in Inkai deliveries

• the expected care and maintenance costs for our US ISR Operations and Rabbit Lake for 2023

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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% greenhouse gas (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

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

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

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

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

• disruption or delay in the transportation of our products

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

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

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

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

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

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

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

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

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

• 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

• operations are disrupted due to problems with our own or our suppliers’ or customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, 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, including due to labour disruption

• our Key Lake mill production plan is delayed or does not succeed for any reason, including due to labour disruption

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

• McClean Lake’s mill production plan is delayed or does 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

2023 SECOND QUARTER REPORT 3

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 2023 Financial Outlook

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

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

• 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 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

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

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

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

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

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

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

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

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

• our Key Lake mill production plans succeeds

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

• 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

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

• our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, climate change, natural disasters, 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

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Second quarter market update

Ongoing geopolitical events, the global focus on the climate crisis, and energy security concerns have created what we believe are transformative tailwinds for the nuclear power industry, from both a demand and supply perspective. In 2022, uranium prices reached levels not seen since 2011, driven by a tightened uranium market and growing security of supply concerns. The unrest in Kazakhstan at the outset of 2022 raised concerns about the more than 40% of global uranium supply that originates from Kazakhstan’s mines. However, it was the Russian invasion of Ukraine in February 2022 that was the most impactful event for our industry. The war continues to broadly impact our market in 2023 with parts of Ukraine, including the Zaporizhzhia Nuclear Power Plant, remaining under Russian control. We believe these developments have set in motion a geopolitical realignment in energy markets that is highlighting the increasingly important role for nuclear power not just in providing clean energy, but also providing secure and affordable energy. And, with the global nuclear industry reliant on Russian supplies for approximately 14% of uranium concentrates, 27% of conversion and 39% of enrichment, the realignment is also highlighting the security of supply risk associated with the growing primary supply gap and shrinking secondary supplies, while increasing the focus on origin of supply.

Amid the heightened supply risk caused by geopolitical developments, utilities continue to evaluate their nuclear fuel supply chains. In the second quarter of 2023, fuel buyers continued contracting to secure their long-term requirements for conversion and enrichment services and have now returned their focus to the uranium required to feed into those services, as evidenced by higher prices across the fuel cycle and long-term contracting that appears to be on track to achieve the rate required to replace what is being consumed annually (replacement-rate contracting). Therefore, we expect there will be continued competition among utilities to secure long-term contracts for uranium products and services with proven producers, operating in geopolitically attractive jurisdictions, who demonstrate strong environmental, social and governance (ESG) performance and on terms that will ensure the availability of reliable supply to satisfy demand.

Despite the increase in prices across most segments of the fuel cycle, years of underinvestment in new production capacity has shifted risk from producers to utilities. In addition to the decisions many producers, including the lowest-cost producers, have made to preserve long-term value by leaving uranium in the ground or idling capacity, there have been several unplanned supply disruptions related to the impact of the COVID-19 pandemic and associated supply chain challenges on uranium mining and processing activities. Uranium is a highly trade-dependent commodity and certain sanctions on Russia, government restrictions, and restrictions on and cancellations of some cargo insurance coverage are creating transportation and further supply chain risks for fuel supplies coming out of Central Asia. Adding to security of supply concerns is the role of commercial and state-owned entities in the uranium market, and trade policies that highlight the disconnect between where uranium is produced and where it is consumed. Nearly 80% of primary production is in the hands of state-owned enterprises, over 70% comes from countries that consume little to no uranium and nearly 90% of consumption occurs in countries that have little to no primary production. Some of the more significant developments affecting supply in the quarter and to date include:

• Sprott Physical Uranium Trust (SPUT) has purchased about 2.4 million pounds U₃O₈ thus far in 2023, bringing total purchases since inception to over 43 million pounds U₃O₈. Volatility in equity markets, has impacted whether SPUT is trading at a discount or premium to its net asset value and therefore its ability to raise funds to purchase uranium.

• In May, the US House of Representatives and Commerce Committee advanced the Prohibiting Russian Uranium Imports Act. The act would prohibit the import of Russian low-enriched uranium (LEU) into the US and includes waivers that allow importation of LEU from Russia if the US Energy Secretary determines no alternative source can be procured, or if the shipments are of national interest. These waivers would gradually reduce Russian uranium imports by 2028. In addition, the US Senate Energy and Natural Resources Committee also advanced a companion bill, the Nuclear Fuel Security Act of 2023, which has similar intent, but also directs the Department of Energy (DOE) to incentivize new LEU capacity in the US. Each piece of legislation would need to pass both chambers of Congress, and would need to be signed by President Joe Biden, before becoming law. It is widely expected that, if these bills get passed in some form, a funding element to support fuel cycle infrastructure development would be included.

2023 SECOND QUARTER REPORT 5

• On June 15, the US DOE announced awards valued at more than $56 million (US) for 68 nuclear energy projects and student innovation awards, including $47 million (US) that will go to research and development to bring collaborative teams together and advance nuclear technology and understanding. The DOE also completed the collection of feedback on two draft requests for proposals to acquire high-assay low-enriched uranium, a crucial material needed to develop and deploy advanced reactors in the United States.

• Zuri-Invest AG announced it successfully launched its Physical Uranium Actively Managed Certificate (AMC), which invests in physical uranium concentrates. The product strategy advisor is Curzon Uranium Ltd.

• On May 25, Kazatomprom (KAP) announced its shareholders approved a major transaction with CNNC Overseas Ltd. that involves a long-term contract for the sale and purchase of natural uranium concentrates, bringing the total contract value to over 50% of the total book value of KAP’s assets. On June 26, KAP announced plans to start production at a new uranium deposit, Inkai 3 (unrelated to JV Inkai). KAP expects approval of a Subsoil Use Agreement to produce 10.4 million pounds U₃O₈ annually for 25 years from Inkai 3’s uranium resources of 216 million pounds U₃O₈. In addition, KAP noted they plan to open a third uranium export route this year, shipping uranium via one of China’s ports.

• In July, ConverDyn announced the restart of Honeywell’s Metropolis uranium conversion facility. The restart plan had been delayed by a safety equipment failure in June, causing the US Nuclear Regulatory Commission to commence a special inspection which remains ongoing.

• On July 6, Urenco announced plans to invest and expand enrichment capacity at its Urenco USA site. Urenco expects the expansion to come online in 2025, increasing capacity by around 15% or 700,000 SWU per year.

• On May 30, Ur-Energy announced it restarted commercial production at its Lost Creek ISR uranium facility in Sweetwater County, Wyoming, which could begin to produce up to 600,000 pounds U₃O₈ annually.

• Orano and the government of Niger signed a partnership agreement to extend the operational life of their Somair open pit mine in Niger through 2040. The mine has an estimated annual capacity of 5.2 million pounds U₃O₈.

• Paladin Energy announced that the Langer Heinrich mine in Namibia is currently on track to restart production in the first quarter of 2024. The company is targeting up to 6 million pounds U₃O₈ annually during the 8-year mining phase and up to 3.3 million pounds U₃O₈ annually during the subsequent 8-year stockpile phase.

• Boss Energy announced the first wellfield is complete at its Honeymoon ISR project in South Australia and plans to restart production near the end of 2023 with annual capacity of 2.45 million pounds U₃O₈.

According to the International Atomic Energy Agency, globally, there are currently 437 operable reactors and 57 reactors under construction. Many nations that have deployed nuclear power are appreciating its clean energy and energy security benefits, reaffirming their commitment and developing plans to support existing reactor units while reviewing and developing policies to encourage more nuclear capacity. Several non-nuclear countries have also emerged as candidates for new nuclear capacity. In the European Union (EU), specific nuclear energy projects have been identified for inclusion under its sustainable financing taxonomy and are therefore eligible for access to low-cost financing. In some countries where phase-out policies were previously in place, there have been policy reversals and potential reactor life extensions with public opinion polls showing growing support. With a number of reactor construction projects recently approved and many more planned, demand for uranium fuel continues to improve. Some of the more significant developments in the quarter and to date affecting current and future demand includes:

• China Nuclear Energy Association published the “China Nuclear Energy Development Report 2023” in late April, which highlighted China’s continuing growth. The country is expected to lead the world in installed nuclear capacity with 110 GWe by 2030, rising to 150 GWe by 2035, with plans to build over 90% of their major nuclear power reactors domestically. Additionally, a proposal drafted by 15 national policy advisors has been submitted to the government advocating for the development of new nuclear power plants at inland sites, which are now being considered following the end of a post-Fukushima moratorium on proposed inland nuclear power plants. In addition, in June, the Shanghai Institute of Applied Physics of the Chinese Academy of Sciences was granted an operating permit for China’s first thorium molten salt reactor demonstration plant.

• Japan’s Nuclear Regulation Authority (NRA) has given approval to Kansai to restart the Takahama 1 and 2 reactors in mid-July and mid-September, subject to the approval of the Fukui Prefecture Governor. Following the 2022 restart of Mihama 3, these units will become Japan’s second and third reactors to operate beyond their original 40-year operating licence. In addition to the approval of Takahama 1 and 2, 10 reactors have been restarted with an additional five units receiving preliminary approval from the NRA, for a total of 17 reactors.

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• On June 12, South Korea’s Ministry of Trade, Industry and Energy approved plans outlining an expedited construction schedule for Shin Hanul 3 and 4, which aims to reduce the total schedule by approximately 19 months and targets completion as early as 2032/2033. Additionally in July, it was announced that the country’s energy minister is considering possible construction of a new nuclear plant.

• Taiwanese presidential candidate Hou Yu-ih continues to reiterate his support for reactivating Taiwan’s first nuclear plant to ensure a stable power supply.

• In Pakistan, China National Nuclear Corporation signed an agreement in June to build the country’s seventh nuclear reactor.

• In June, Belgium’s federal government and French-owned utility Engie Energy International agreed to extend the operating life of Doel 4 and Tihange 3 for 10 years.

• In the Netherlands, the government allocated over $350 million (US) for energy and climate initiatives to fund additional nuclear development including plans for two new large-scale reactors and a development plan for small modular reactors (SMR).

• On June 20, Sweden’s parliament adopted a new energy target, changing its focus to “100% fossil-free” electricity, from “100% renewable”. This will enable progress with their plans to build new nuclear power plants.

• Although all German reactors were phased out in April, due to France’s insistence, Germany will likely be forced to compensate French and other EU Nuclear Alliance members’ nuclear power plants for their baseload, carbon-free energy supplies under the EU Green Deal.

• France moved forward with President Emmanuel Macron’s plans to relaunch the country’s reactor construction program as Electricité de France (EDF) filed an application to build the first pair of 1,650 MWe EPR2 nuclear power plants. After completing the final acquisition requirements in June, the government also completed the full nationalization of EDF to enhance the utility’s ability to deliver on new nuclear projects.

• In May, the International Energy Agency released its “Finland 2023 Energy Policy Review” which emphasized the importance of nuclear and recommended updating the Nuclear Energy Act, the key law regulating nuclear power in Finland. Additionally, Fortum is leading a two-year feasibility study that will look at SMR applications.

• On May 30, Poland’s government adopted a resolution committing to finance the country’s first nuclear power plant. These funds will go to Polish utility Polskie Elektrownie Jadrowe, which signed a contract with Westinghouse for multiple AP1000 PWRs in February. Additionally in May, OSGE (an Orlen and Synthos Green Energy joint venture) released a list of seven possible locations for the construction of SMRs in Poland.

• Egypt began construction by pouring the first concrete on the third of four Russian built VVER 1200 reactors at the El-Dabaa Power Plant, as the government looks to accelerate the project.

• On June 30, the state-owned Nuclear Power Corp. of India Limited (NPCIL) began commercial operations of Kakrapar 3, the country’s first indigenously developed 700 MWe pressurized heavy water reactor (PHWR). Kakrapar 4 remains under construction while two other units, Rajasthan 7 and 8, are nearing completion. The government is targeting to build ten 700 MWe PHWR’s in the next decade.

• In Canada, the Ontario Minister of Energy announced support to advance the long-term planning required to explore nuclear expansion options for Bruce Power. In its Pathways to Decarbonization report, Ontario’s Independent Electricity System Operator outlined the need for nearly 18 GWe in new nuclear capacity to help the province reach its electrification and net-zero goals. On July 7, Ontario’s provincial government also announced their cooperation in potentially planning, licensing, and building three GE-Hitachi Nuclear Energy BWRX-300 SMRs at Ontario Power Generation’s Darlington site, in addition to the single BWRX-300 for which site preparation is already underway.

• In May, Michigan’s state government formed a new Nuclear Caucus to help support the reopening of the Palisades nuclear power plant. This development was followed by the inclusion of funding for restarting the unit in their next budget.

• In recent months, Ohio, Virginia, Kentucky, and Tennessee all began creating state-level advisory authorities to promote, develop and research nuclear power technologies.

• On March 1, Dow and X-Energy announced their entry into a joint development agreement to demonstrate the first grid-scale advanced nuclear reactor for an industrial site in North America. In May, they announced that they selected Dow’s UCC Seadrift Operations manufacturing site in Texas for the SMR project. They have begun preparing the construction permit application to the US Nuclear Regulatory Commission and aim for construction work to begin in 2026.

2023 SECOND QUARTER REPORT 7

• In June, Constellation and Microsoft announced their energy matching agreement, transforming their 2022 collaboration to develop energy matching technology into reality. This agreement will harness the environmental attributes of nuclear to put the data centre in Boydton, Virginia “very close” to the goal of 100% carbon-free operation; the facility is expected to receive up to 35% in environmental attributes from nuclear power, complementing the wind and solar purchases. The exact performance of the program will be monitored via Constellation’s hourly carbon-free energy matching platform.

• On June 28, Brookfield Properties announced that their entire US office portfolio (70 million square feet) will be powered by zero emissions electricity by 2026. More than 65% of its office space will transition to zero emissions electricity by 2024. The office spaces will be powered by hydropower, solar, wind and nuclear power, procuring 600 GWh of clean electricity, reducing GHG emissions by 260,000 tonnes of CO₂e annually (the equivalent of avoiding burning 300 million pounds of coal).

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 2023		MAR 31 2023		DEC 31 2022		SEP 30 2022		JUN 30 2022		MAR 31 2022
Uranium ($US/lb U3O8)1
Average spot market price		56.10		50.48		47.68		48.38		49.75		58.20
Average long-term price		56.00		53.00		52.00		51.00		51.50		49.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		40.75		39.75		40.00		38.00		32.75		26.63
Europe		40.75		39.75		40.00		38.00		32.75		26.63
Average long-term price
North America		30.75		27.88		27.25		26.75		26.25		22.50
Europe		30.50		27.88		27.50		27.00		26.50		22.50
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 2023 was over 12 million pounds U₃O₈ equivalent, compared to 13 million pounds U₃O₈ equivalent contracted in the second quarter of 2022. As of June 30, 2023, the average reported spot price was $56.10 (US) per pound, an increase of $5.62 (US) per pound from the previous quarter.

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 determined near the time of delivery. Long-term contracting reported by UxC for the first six months of 2023 totaled about 117 million pounds U₃O₈ equivalent, up from about 70 million pounds U₃O₈ equivalent reported over the same period in 2022. Based on this rate of contracting, industry long-term contracting volumes in 2023 are expected to exceed those in each of the last 10 years, a strong indication that a new long-term contracting cycle is underway. The average reported long-term price at the end of the quarter was $56.00 (US) per pound U₃O₈ equivalent, an increase of $3.00 (US) per pound from the previous quarter.

With the increased demand for conversion services, pricing in both North America and Europe continues to be strong. As of the end of the second quarter, the average reported spot price reached a record high of $40.75 (US) per kilogram uranium (kgU) as UF₆, up $1.00 (US) from the previous quarter. Long-term UF₆ conversion prices for North America finished the quarter at $30.75 (US) per kgU, up $2.87 (US) from the previous quarter.

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Our strategy

We are a pure-play investment in the growing demand for nuclear energy. We are focused on providing nuclear fuel products and services across the fuel cycle to support the generation of clean, reliable, secure and affordable energy, and we are focused on taking advantage of the long-term growth we see coming in our industry. Our strategy is set within the context of what we believe is a transitioning market environment, where increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are expected to durably strengthen the long-term fundamentals for nuclear power and the uranium and fuel services needed to run the reactors. Nuclear energy must be a significant component of 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 will help avoid some of the worst consequences of climate change.

Our strategy is to capture full-cycle value by:

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

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

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

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

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

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 emissions by 2050 or sooner. Our uranium and fuel services are used around the world in the generation of safe, carbon-free, affordable, base-load nuclear power.

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

You can read more about our strategy in our 2022 annual MD&A and our approach to ESG in our 2022 ESG report.

2023 SECOND QUARTER REPORT 9

Strategy in action

In the current environment, we believe the risk to uranium supply is greater than the risk to uranium demand and expect it will create a renewed focus on ensuring availability of long-term supply to fuel nuclear reactors. With the improvements in the market, the new long-term contracts we have put in place, and a pipeline of contracting discussions, we plan to produce 33 million pounds (20.3 million pounds our share) of uranium in 2023 and starting in 2024, 36 million pounds (22.4 million pounds our share). At Inkai, production will continue to follow the 20% reduction planned by Kazatomprom until the end of 2023. In addition to our uranium production plans, our Port Hope UF₆ conversion facility is working to increase annual production to 12,000 tonnes of UF₆ by 2024, in order to satisfy our book of long-term business and demand for conversion services, at a time when conversion prices are at historic highs. We continue to have the ability to expand production from our existing assets, however some additional investment would be required. If we took advantage of all tier-one expansion opportunities, our annual share of tier-one uranium supply could be about 32 million pounds (including our share of production from McArthur River/Key Lake and Cigar Lake, and Inkai purchases). However, we will continue to responsibly manage our supply in accordance with our contract portfolio and our customers’ needs.

With the heightened supply risk caused by geopolitical uncertainty, utilities are evaluating their nuclear fuel supply chains. Our utility customers’ nuclear power plants continue to be part of the critical infrastructure needed to guarantee the availability of 24-hour electricity to run essential services. Our customers are going to need nuclear fuel to allow them to continue to provide carbon-free baseload electricity. As a reliable, commercial supplier, with nuclear fuel assets in geopolitically stable jurisdictions, we are focused on working with our customers to secure long-term commitments that will underpin the long-term operation of our productive capacity, while helping de-risk their nuclear fuel supply chains.

We are also focused on adding new markets to our global commercial portfolio. We are successfully competing for business in countries seeking to enhance their energy security, while affirming their commitment to carbon-free nuclear power in achieving their climate goals.

In recent years, the volumes we have placed under long-term agreements has exceeded our annual delivery volumes. With our contracting success, we are heavily committed under long-term contracts. As of June 30, 2023, we had commitments requiring delivery of an average of 28 million pounds per year from 2023 through 2027, an increase from an average of 26 million pounds per year at the end of March due to the inclusion of volumes under contracts previously accepted that are now finalized. Commitment levels in 2023 through 2025 are higher than the average and in 2026 and 2027 lower than the average. We also have contracts in our uranium and fuel services segments that have deliveries spanning more than a decade, and in our uranium segment, many of our contracts benefit from market-related pricing mechanisms. In addition, we have a large and growing pipeline of business under discussion, which we expect will help further build our long-term portfolio. With more than 118 million pounds of long-term contracting industry wide so far this year, we believe there is clear evidence that the broader uranium market is moving toward replacement-rate contracting reflecting security of supply concerns. This is the type of contracting necessary to promote the price discovery already seen in the enrichment and conversion markets and that will incentivize investments in the supply necessary to satisfy the growing long-term requirements. Therefore, we remain selective in committing our unencumbered, in-ground uranium inventory and UF₆ conversion capacity under long-term contracts to help maintain additional exposure to future improvements in the market. With a new long-term contracting cycle now clearly underway, we are no longer highlighting commercially sensitive contracting activity on a quarterly basis and will only be disclosing total contracted volumes with our annual results.

We continue to meet our sales commitments through a combination of production, inventory and purchases. In the first six months of 2023, we produced 8.8 million pounds of uranium (our share) and purchased 4.2 million pounds. The average unit cost of our purchases was $68.17 per pound ($50.16 per pound (US)). See Financial results by segment – Uranium starting on page 23 for more information.

Thanks to the disciplined execution of our strategy, our balance sheet is strong. As of June 30, 2023, we had $2.5 billion in cash and cash equivalents, and short-term investments, and $1.0 billion in total debt. We also have a $1.0 billion undrawn credit facility. Our current cash balance and short-term investments are in excess of our normal working capital requirements and are expected to be deployed to help finance the proposed acquisition of Westinghouse. See Proposed acquisition of Westinghouse on page 29.

10 CAMECO CORPORATION

In March, CRA issued revised reassessments for the 2007 through 2013 tax years, which resulted in a refund of $297 million of the $780 million in cash and letters of credit held by CRA at the time. The refund consisted of cash in the amount of $86 million and letters of credit in the amount of $211 million, which were returned in the second quarter. CRA continues to hold $483 million ($209 million in cash and $274 million in letters of credit) that Cameco has remitted or secured to date. See Transfer pricing dispute on page 15 for more information.

We expect to maintain the financial strength and flexibility necessary to execute our strategy by being disciplined and planning production in coordination with contracting success and market opportunities, and by taking advantage of value-added growth opportunities, while continuing to navigate by our investment grade rating to self-manage risk, including risks related to global macro-economic uncertainty and volatility.

Financial results

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

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

Consolidated financial results

	THREE MONTHS								SIX MONTHS
HIGHLIGHTS	ENDED JUNE 30								ENDED JUNE 30
($ MILLIONS EXCEPT WHERE INDICATED)	2023			2022		CHANGE			2023		2022		CHANGE
Revenue		482			558		(14	)%		1,169		956		22	%
Gross profit		110			93		18	%		277		143		94	%
Net earnings attributable to equity holders		14			84		(83	)%		133		124		7	%
$ per common share (basic)		0.03			0.21		(86	)%		0.31		0.31		—
$ per common share (diluted)		0.03			0.21		(86	)%		0.31		0.31		—
Adjusted net earnings (losses) (non-IFRS, see page 13)		(3	)		72		>(100	)%		112		89		26	%
$ per common share (adjusted and diluted)		(0.01	)		0.18		>(100	)%		0.26		0.22		18	%
Cash provided by operations (after working capital changes)		87			102		(15	)%		302		274		10	%

2023 SECOND QUARTER REPORT 11

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 13) in the second quarter and the first six months of 2023, compared to the same periods in 2022.

		THREE MONTHS						SIX MONTHS
		ENDED JUNE 30						ENDED JUNE 30
($ MILLIONS)		IFRS			ADJUSTED			IFRS			ADJUSTED
Net earnings – 2022			84			72			124			89
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		(15	)		(15	)		10			10
	Higher realized prices ($US)		22			22			36			36
	Foreign exchange impact on realized prices		24			24			56			56
	Lower (higher) costs		(13	)		(13	)		30			30
	Change – uranium		18			18			132			132
Fuel services	Impact from sales volume changes		5			5			8			8
	Higher realized prices ($Cdn)		2			2			10			10
	Higher costs		(8	)		(8	)		(15	)		(15	)
	Change – fuel services		(1	)		(1	)		3			3
Other changes
Higher administration expenditures			(33	)		(33	)		(39	)		(39	)
Higher exploration expenditures			(2	)		(2	)		(5	)		(5	)
Change in reclamation provisions			(29	)		(2	)		(47	)		(3	)
Lower earnings from equity-accounted investee			(19	)		(19	)		(6	)		(6	)
Change in gains or losses on derivatives			57			(9	)		49			(12	)
Change in foreign exchange gains or losses			(65	)		(65	)		(63	)		(63	)
Higher finance income			27			27			53			53
Bargain purchase gain on CLJV ownership interest increase			(23	)		—			(23	)		—
Change in income tax recovery or expense			4			15			(34	)		(26	)
Other			(4	)		(4	)		(11	)		(11	)
Net earnings (losses) – 2023			14			(3	)		133			112

See Financial results by segment on page 23 for more detailed discussion.

12 CAMECO CORPORATION

ADJUSTED NET EARNINGS (NON-IFRS MEASURE)

Adjusted net earnings (ANE) is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a meaningful way to compare our financial performance from period to period. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to reflect the underlying financial performance for the reporting period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is one of the targets that we measure to form the basis for a portion of annual employee and executive compensation (see Measuring our results starting on page 36 of our 2022 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 17 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 9 of our interim financial statements for more information. This amount has been excluded from our ANE measure.

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

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

The following table reconciles adjusted net earnings with net earnings for the second quarter and first six months of 2023 and compares it to the same periods in 2022.

	THREE MONTHS						SIX MONTHS
	ENDED JUNE 30						ENDED JUNE 30
($ MILLIONS)	2023			2022			2023			2022
Net earnings attributable to equity holders		14			84			133			124
Adjustments
Adjustments on derivatives		(35	)		31			(41	)		20
Adjustment to other operating expense (income)		8			(19	)		6			(38	)
Adjustment to other income (expense)		—			(23	)		—			(23	)
Income taxes on adjustments		10			(1	)		14			6
Adjusted net earnings (losses)		(3	)		72			112			89

2023 SECOND QUARTER REPORT 13

Quarterly trends

HIGHLIGHTS				2023										2022				2021
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q2			Q1		Q4			Q3			Q2		Q1		Q4		Q3
Revenue		482			687		524			389			558		398		465		361
Net earnings (losses) attributable to equity holders		14			119		(15	)		(20	)		84		40		11		(72	)
$ per common share (basic)		0.03			0.27		(0.04	)		(0.05	)		0.21		0.10		0.03		(0.18	)
$ per common share (diluted)		0.03			0.27		(0.04	)		(0.05	)		0.21		0.10		0.03		(0.18	)
Adjusted net earnings (losses) (non-IFRS, see page 13)		(3	)		115		36			10			72		17		23		(54	)
$ per common share (adjusted and diluted)		(0.01	)		0.27		0.09			0.03			0.18		0.04		0.06		(0.14	)
Cash provided by (used in) operations (after working capital changes)		87			215		77			(47	)		102		172		59		203

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

• net earnings vary from quarter to quarter due to variability in the timing of customer requirements and product purchases, and 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 13 for more information).

• cash from operations tends to fluctuate as a result of the timing of customer requirements and product purchases in our uranium and fuel services segments

• quarterly results are not necessarily a good indication of our annual results due to the variability in customer requirements and product purchases noted above

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

HIGHLIGHTS				2023												2022						2021
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Net earnings (losses) attributable to equity holders		14			119			(15	)		(20	)		84			40			11			(72	)
Adjustments
Adjustments on derivatives		(35	)		(6	)		(19	)		75			31			(11	)		5			26
Adjustment to other operating expense (income)		8			(2	)		88			(24	)		(19	)		(19	)		10			(2	)
Adjustment to other income (expense)		—			—			—			—			(23	)		—			—			—
Income taxes on adjustments		10			4			(18	)		(21	)		(1	)		7			(3	)		(6	)
Adjusted net earnings (losses) (non-IFRS, see page 13)		(3	)		115			36			10			72			17			23			(54	)

14 CAMECO CORPORATION

Corporate expenses

ADMINISTRATION

	THREE MONTHS								SIX MONTHS
	ENDED JUNE 30								ENDED JUNE 30
($ MILLIONS)	2023		2022			CHANGE			2023		2022		CHANGE
Direct administration		46		34			35	%		92		67		37	%
Stock-based compensation		11		(10	)		>100	%		29		11		>100	%
Reversal (recovery) of fees related to CRA dispute		—		—			—			—		4		(100	)%
Total administration		57		24			>100	%		121		82		48	%

Direct administration costs were $12 million higher for the second quarter of 2023 compared to the same period last year, and $25 million higher for the first six months largely due to the impacts of inflation and higher costs as a result of digital initiatives. Stock-based compensation in the first six months of 2023 was $18 million higher than 2022 due to the increase in our share price from the comparative period. See note 17 to the financial statements.

EXPLORATION AND RESEARCH & DEVELOPMENT

In the second quarter, uranium exploration expenses were $4 million, an increase of $2 million from the second quarter of 2022. Exploration expenses for the first six months of the year increased by $5 million compared to 2022, to $10 million.

We also had research and development expenditures in the second quarter of $5 million, an increase of $2 million from the second quarter of 2022. Research and development expenses for the first six months of the year increased by $3 million compared to 2022, to $9 million. The expenses were mainly related to our investment in Global Laser Enrichment, LLC.

INCOME TAXES

We recorded an income tax expense of $23 million in the second quarter of 2023, compared to an expense of $27 million in the second quarter of 2022.

In the first six months of 2023, we recorded an expense of $59 million compared to an expense of $25 million in 2022.

	THREE MONTHS						SIX MONTHS
	ENDED JUNE 30						ENDED JUNE 30
($ MILLIONS)	2023			2022			2023			2022
Net earnings before income taxes
Canada		62			134			211			165
Foreign		(25	)		(23	)		(19	)		(16	)
Total net earnings before income taxes		37			111			192			149
Income tax expense
Canada		21			25			54			22
Foreign		2			2			5			3
Total income tax expense		23			27			59			25

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 2016, CRA has advanced an alternate reassessing position, see Reassessments, remittances and next steps below for more information.

2023 SECOND QUARTER REPORT 15

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

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

Refund and cost award

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

Reassessments, remittances and next steps

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

In March, CRA issued revised reassessments for the 2007 through 2013 tax years, which resulted in a refund of $297 million of the $780 million in cash and letters of credit held by CRA at the time. The refund consisted of cash in the amount of $86 million and letters of credit in the amount of $211 million, which were returned in the second quarter. CRA continues to hold $483 million ($209 million in cash and $274 million in letters of credit) that Cameco has remitted or secured to date.

The series of court decisions that were completely and unequivocally in our favour for the 2003, 2005 and 2006 tax years, determined that the income earned by our foreign subsidiary from the sale of non-Canadian produced uranium was not taxable in Canada. In accordance with these decisions, CRA issued reassessments reducing the proposed transfer pricing adjustment from $5.1 billion to $3.3 billion, resulting in a reduction of $1.8 billion in income taxable in Canada compared to the previous reassessments issued to us by CRA for the 2007 through 2013 tax years.

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

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

In 2020, CRA advanced an alternate reassessing position for the 2014 tax year in the event the basis for its original reassessment, noted above, is unsuccessful. Subsequent to this, in 2021, we received a reassessment for the 2015 tax year and in late 2022, we received a reassessment for the 2016 tax year, both using this alternative reassessing position. The new basis of reassessment is inconsistent with the methodology CRA has pursued for prior years and we are disputing it separately. Our view is that this alternate methodology will not result in a materially different outcome from our 2014 to 2016 filing positions. On October 12, 2022, we filed an appeal with the Tax Court for the years 2014 and 2015, and in March 2023, filed a notice of objection for 2016. CRA did not require additional security for the tax debts they considered owing for 2014, 2015 and 2016.

16 CAMECO CORPORATION

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

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

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

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).

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

Impact of hedging on ANE

We designate contracts for use in particular periods, based on our expected net exposure in that period. Hedge contracts are layered in over time based on this expected net exposure. The result is that our current hedge portfolio is made up of a number of contracts which are currently designated to net exposures we expect in 2023 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 13.

For more information, see our 2022 annual MD&A.

At June 30, 2023:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.32 (Cdn), down from $1.00 (US) for $1.35 (Cdn) at March 31, 2023. The exchange rate averaged $1.00 (US) for $1.34 (Cdn) over the quarter.

• The mark-to-market position on all foreign exchange contracts was a $7 million loss compared to a $43 million loss at March 31, 2023.

For information on the impact of foreign exchange on our intercompany balances, see note 18 to the financial statements.

2023 SECOND QUARTER REPORT 17

Outlook for 2023

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

From a cash perspective, we expect to generate strong cash flows. However, cash balances will be dependent on the timing and volume of production, the timing and magnitude of our purchasing activity and the timing of the close of the Westinghouse acquisition.

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.

As a result of additional market opportunities, we now expect to deliver between 31 million and 33 million pounds of uranium this year (previously between 29 million and 31 million). Due to the additional deliveries and the recent movement in the uranium spot price, we have updated our outlook for the anticipated uranium average realized price to $63.80 per pound (previously $61.70 per pound). With the updates to sales volume and price, we now expect uranium revenue to be between $1,990 million and $2,080 million (previously $1,830 million to $1,920 million) and expected consolidated revenue to between $2,380 million and $2,530 million (previously $2,220 million to $2,370 million).

With the additional deliveries in 2023 and to maintain a working inventory, we expect to purchase between 11 million to 13 million pounds in the uranium segment this year (previously between 9 million and 11 million pounds). The average unit cost of sales in our uranium segment is now expected to be between $49.00 and $51.00 per pound (previously $47.00 to $48.00 per pound) due to the expected increase in our purchasing activity and the impact of the uranium spot price.

Our outlook for direct administration costs is now between $180 million and $190 million (previously between $160 million and $170 million) due to additional costs associated with work on various business opportunities.

2023 FINANCIAL OUTLOOK

	CONSOLIDATED		URANIUM			FUEL SERVICES
Production (owned and operated properties)		—		20.3 million lbs			13 to 14 million kgU
Purchases		—		11 to 13 million lbs			—
Sales/delivery volume		—		31 to 33 million lbs			11.5 to 12.5 million kgU
Revenue	$	2,380-2,530 million	$	1,990-2,080 million		$	390-420 million
Average realized price		—	$	63.80/lb			—
Average unit cost of sales (including D&A)		—	$	49.00-51.00/lb	1	$	23.50-24.50/kgU	2
Direct administration costs	$	180-190 million		—			—
Exploration costs		—	$	18 million			—
Capital expenditures	$	150-175 million		—			—

¹  Uranium average unit cost of sales is calculated as the cash and non-cash costs of the product sold, care and maintenance and selling costs, divided by the volume of uranium concentrates sold.

²  Fuel services average unit cost of sales is calculated as the cash and non-cash costs of the product sold, transportation and weighing and sampling costs, divided by the volume of products sold.

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

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

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

18 CAMECO CORPORATION

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

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

• Sales/delivery volume is based on the volumes already delivered this year and the remaining commitments we have to deliver under contract in 2023.

• Uranium revenue and average realized price are based on a uranium spot price of $56.20 (US) per pound (the UxC spot price as of June 26, 2023), a long-term price indicator of $56.00 (US) per pound (the UxC long-term indicator on June 26, 2023) and an exchange rate of $1.00 (US) for $1.33 (Cdn).

• Uranium average unit cost of sales (including D&A) is based on the expected unit cost of sales for produced material, the planned purchases noted in the outlook at an anticipated average purchase price of about $68.90 (Cdn) per pound (previously $62.40 (Cdn) per pound) and includes care and maintenance costs of between $50 million and $60 million. We expect overall unit cost of sales could vary if there are changes in production and purchase volumes or the mix between spot and long-term purchases, uranium spot prices, and/or care and maintenance costs in 2023.

• Direct administration costs do not include stock-based compensation expenses or fees related to the CRA dispute. See page 15 for more information.

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

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 17.

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVIY ANALYSIS

FOR 2023 ($ MILLIONS)		IMPACT ON:
	CHANGE	REVENUE			ANE			CASH FLOW
Uranium spot and term price1	$5(US)/lb increase		19			2			(22	)
	$5(US)/lb decrease		(25	)		(6	)		16
Value of Canadian dollar vs US dollar	One cent decrease in CAD		9			10			2
	One cent increase in CAD		(9	)		(10	)		(2	)

¹ Assuming change in both UxC spot price ($56.20 (US) per pound on June 26, 2023) and the UxC long-term price indicator ($56.00 (US) per pound on June 26, 2023)

We have sensitivity to the uranium price through both our sales and purchase commitments. However, for the remainder of the year our sales commitments are less sensitive to an increase in the uranium price than a decrease, while our purchase commitments are equally sensitive to an increase or decrease.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

As discussed under Long-term contracting on page 26 of our 2022 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 market price that can be set several months 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.

2023 SECOND QUARTER REPORT 19

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, 2023, we have constructed the table that follows.

The table is based on the volumes and pricing terms under the long-term commitments in our contract portfolio that have been finalized as at June 30, 2023. The table does not include volumes and pricing terms in contracts under negotiation or those that have been accepted but are still subject to contract finalization. Based on the terms and volumes under contracts that have been finalized, the table is designed to indicate how our average realized price would react under various spot price assumptions at a point in time. In other words, the prices shown in the table would only be realized if the contract portfolio remained exactly as it was on June 30, 2023, using the following assumptions:

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

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

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

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

Expected realized uranium price sensitivity under various spot price assumptions at June 30, 2023

(rounded to the nearest $1.00)
SPOT PRICES
($US/lb U3O8)	$20		$40		$60		$80		$100		$120		$140
2023		43		45		48		49		51		52		53
2024		34		40		51		56		58		60		61
2025		37		43		54		61		65		67		68
2026		40		43		56		65		69		71		73
2027		41		44		56		68		72		74		76

As of June 30, 2023, we had commitments requiring delivery of an average of 28 million pounds per year from 2023 through 2027, with commitment levels in 2023 through 2025 higher than the average and in 2026 and 2027 lower than the average. As the market improves, we expect to continue to layer in volumes capturing greater upside using market-related pricing mechanisms.

Liquidity and capital resources

Our financial objective is to ensure we have the cash and debt capacity to fund our operating activities, investments and other financial obligations in order to execute our strategy and to allow us to self-manage risk. We have a number of alternatives to fund future capital requirements, including using our operating cash flow, drawing on our existing credit facilities, entering new credit facilities, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. In addition, due to the deliberate cost reduction measures we have implemented, we have continued to have positive cash from operations, which has added to our cash balance. With the net proceeds from the October 2022 share issuance, which are expected to help finance the proposed acquisition of Westinghouse, we had significant cash balances again at the end of the second quarter.

20 CAMECO CORPORATION

As of June 30, 2023, we had cash and cash equivalents and short-term investments of $2.5 billion, while our total debt amounted to $1.0 billion. Our cash balances include the April 12, 2023 cash refund of $86 million related to the receipt of revised reassessments from CRA for the 2007 through 2013 tax years and the $79 million (US) dividend we received from JV Inkai on April 26, 2023. 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 and short-term investments are with Schedule I Canadian banks.

As announced on October 11, 2022, we have entered into a strategic partnership with Brookfield Renewable and its institutional partners to acquire Westinghouse. Permanent financing is expected to be a mix of capital sources (cash, debt and equity), designed to preserve the company’s balance sheet and ratings strength while maintaining our liquidity. Please see Liquidity and capital resources starting on page 50 of our annual MD&A for more information.

We expect our cash balances, operating cash flows, and the credit facilities put in place to support the close of the Westinghouse transaction, to meet our 2023 capital requirements. Depending on timing, we may have more or less cash than expected at closing and could temporarily draw on our revolving credit facility for short-term working capital purposes.

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 2023 through 2027, we have commitments to deliver an average of 28 million pounds per year, with commitment levels in 2023 through 2025 higher than the average and in 2026 and 2027, lower than the average.

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

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 2016 and believe CRA should return the remaining $483 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 15 for more information.

CASH FROM/USED IN OPERATIONS

Cash provided by operations was $15 million lower this quarter than in the second quarter of 2022 due to lower earnings and an increase in working capital requirements, which required $58 million more in 2023 than in 2022. Partially offsetting the lower earnings and increased working capital requirements was the cash refund of $86 million related to the revised reassessments from CRA for the 2007 through 2013 tax years as well as a higher dividend payment from JV Inkai and higher interest received due to higher cash and investment balances.

Cash provided by operations was $28 million higher in the first six months of 2023 than for the same period in 2022 due to higher earnings, the $86 million cash refund from CRA, the higher dividend payment from JV Inkai and higher interest received due to higher cash and investment balances. These factors were partially offset by an increase in working capital requirements, which required $152 million more in 2023 than in 2022. See note 16 of our interim financial statements for more information.

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, 2023, down from $2.8 billion at March 31, 2023. At June 30, 2023, we had approximately $1.4 billion outstanding in financial assurances, down from $1.6 billion at March 31, 2023, due largely to the return of letters of credit from CRA.

At June 30, 2023, we had no short-term debt outstanding on our $1.0 billion unsecured revolving credit facility, unchanged from December 31, 2022. This facility matures October 1, 2026.

2023 SECOND QUARTER REPORT 21

Long-term contractual obligations

Since December 31, 2022, we have reclassified our Series G debentures to current since they mature on June 24, 2024. There have been no other material changes to our long-term contractual obligations. Please see our 2022 annual MD&A for more information.

Debt covenants

We are bound by certain covenants in our unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at June 30, 2023, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2023 to be constrained by them.

SHARES AND STOCK OPTIONS OUTSTANDING

At July 30, 2023, we had:

• 433,308,237 common shares and one Class B share outstanding

• 2,263,804 stock options outstanding, with exercise prices ranging from $11.32 to $16.38

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at June 30, 2023:

• purchase commitments

• financial assurances

• other arrangements

Purchase commitments

We make purchases under long-term contracts where it is beneficial for us to do so and in order to support our long-term contract portfolio. The following table is based on our purchase commitments in our uranium and fuel services segments at June 30, 2023,² but does not include purchases of our share of Inkai production. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

			2024 AND		2026 AND		2028 AND
JUNE 30 ($ MILLIONS)	2023		2025		2027		BEYOND		TOTAL
Purchase commitments1,2		267		102		158		17		544

¹  Denominated in US dollars and Japanese yen, converted from US dollars to Canadian dollars at the rate of 1.33 and from Japanese yen to Canadian dollars at the rate of $0.01.

²  These amounts have been adjusted for any additional purchase commitments that we have entered into since June 30, 2023, but does not include deliveries taken under contract since June 30, 2023.

We have commitments of $544 million (Cdn) for the following:

• approximately 9.3 million pounds of U₃O₈ equivalent from 2023 to 2028

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

• about 0.6 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions.

Financial assurances

At June 30, 2023, our financial assurances totaled $1.4 billion, down from $1.6 billion at March 31, 2023 due largely to the return of letters of credit in the amount of $211 million from CRA. See Transfer pricing dispute on page 15.

22 CAMECO CORPORATION

Other arrangement

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 2.8 million pounds of U₃O₈ over the period 2020 to 2026 with repayment in kind up to December 31, 2026. Under the loan facilities, standby fees of up to 1% are payable based on the market value of the facilities and interest is payable on the market value of any amounts drawn at rates ranging from 0.5% to 2.0%. At June 30, 2023, we have 1.8 million kgU of UF₆ conversion services and 2.1 million pounds of U₃O₈ drawn on the loans.

BALANCE SHEET

($ MILLIONS)	JUN 30, 2023		DEC 31, 2022		CHANGE
Cash, cash equivalents and short-term investments		2,473		2,282		8	%
Total debt		997		997		—
Inventory		633		665		(5	)%

Total cash, cash equivalents and short-term investments at June 30, 2023 were $2.5 billion, or 8% higher than at December 31, 2022, due to strong earnings, the receipt of the $86 million refund from CRA, the receipt of $79 million (US) of dividend payments from JV Inkai as well as $61 million of interest received during the first six months of the year. Net debt at June 30, 2023, was negative $1.5 billion.

Total product inventories are $633 million compared to $665 million at the end of 2022. Inventories decreased due to sales being higher than production and purchases in the first six months of the year. The average cost for uranium has increased to $45.26 per pound compared to $43.45 per pound at December 31, 2022. As of June 30, 2023, we held an inventory of 10.6 million pounds of U₃O₈ equivalent (excluding broken ore) (December 31, 2022 – 12.4 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 ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
HIGHLIGHTS			2023		2022		CHANGE			2023		2022		CHANGE
Production volume (million lbs)				4.4		2.8		57	%		8.8		4.7		87	%
Sales volume (million lbs)				5.5		7.6		(28	)%		15.2		13.5		13	%
Average spot price	($US/lb	)		54.53		50.17		9	%		52.60		50.09		5	%
Average long-term price	($US/lb	)		54.83		50.75		8	%		53.83		48.00		12	%
Average realized price
	($US/lb	)		49.41		46.30		7	%		46.81		44.97		4	%
	($Cdn/lb	)		67.05		58.74		14	%		63.17		57.14		11	%
Average unit cost of sales (including D&A)	($Cdn/lb	)		53.93		51.68		4	%		49.37		51.34		(4	)%
Revenue ($ millions)				368		447		(18	)%		963		770		25	%
Gross profit ($ millions)				72		54		33	%		210		78		>100	%
Gross profit (%)				20		12		67	%		22		10		>100	%

SECOND QUARTER

Production during the quarter was 4.4 million pounds, 57% higher than the second quarter of 2022. See Uranium 2023 Q2 updates starting on page 27 for more information.

Uranium revenues this quarter were down 18% compared to 2022 due to a 28% decrease in sales volume due to the timing of sales, which were in line with the delivery pattern disclosed in our annual MD&A, partially offset by an increase of 14% in the Canadian dollar average realized price. While the US dollar average realized price increased by 7%, the Canadian dollar average realized price increased by 14% as a result of a weakening of the Canadian dollar. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 19.

2023 SECOND QUARTER REPORT 23

Total cost of sales (including D&A) decreased by 25% ($296 million compared to $393 million in 2022) due to a 28% decrease in sales volume which was slightly offset by a unit cost of sales that was 4% higher than the same period last year. Unit cost of sales was higher in 2023 due primarily to the higher cost of purchased material compared to 2022, offset by a decrease in operational readiness costs at McArthur River and Key Lake operations.

The net effect was an $18 million increase in gross profit for the quarter.

Equity earnings from investee, JV Inkai, were $8 million in the second quarter compared to $27 million in same period last year.

FIRST SIX MONTHS

Production volumes for the first six months of the year were 87% higher than in the previous year. See Uranium 2023 Q2 updates starting on page 27 for more information.

Uranium revenues increased 25% compared to the first six months of 2022 due to a 13% increase in sales volumes and an increase of 11% in the Canadian dollar average realized price as a result of the impact of the increase in the average US dollar spot price on market-related contracts as well as the weakening of the Canadian dollar. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 19.

Total cost of sales (including D&A) increased by 9% ($752 million compared to $692 million in 2022) primarily as a result of a 13% increase in sales volume partially offset by a unit cost of sales that was 4% lower than the same period last year. Unit cost of sales was lower in 2023 due to higher operational readiness costs at McArthur River and Key Lake operations in 2022 slightly offset by the higher cost of purchased material in 2023 compared to the same period in 2022.

The net effect was a $132 million increase in gross profit for the first six months.

Equity earnings from investee, JV Inkai, were $64 million for the first six months compared to $70 million for 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 ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
($CDN/LB)	2023		2022		CHANGE			2023		2022		CHANGE
Produced
Cash cost		23.35		15.58		50	%		23.24		17.85		30	%
Non-cash cost		12.82		14.57		(12	)%		11.81		16.46		(28	)%
Total production cost 1		36.17		30.15		20	%		35.05		34.31		2	%
Quantity produced (million lbs)1		4.4		2.8		57	%		8.8		4.7		87	%
Purchased
Cash cost		68.31		48.76		40	%		68.17		50.17		36	%
Quantity purchased (million lbs)1		3.8		5.5		(31	)%		4.2		7.8		(46	)%
Totals
Produced and purchased costs		51.06		42.48		20	%		45.75		44.21		3	%
Quantities produced and purchased (million lbs)		8.2		8.3		(1	)%		13.0		12.5		4	%

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. In the second quarter, we purchased 1.4 million pounds of material produced in 2022 at a purchase price per pound of $66.51 ($48.69 (US)) (1.4 million pounds in the first six months of 2023 at $66.51 ($48.69 (US))).

The average cash cost of production was 50% higher for the quarter compared to the same period in 2022. For the first six months, the average cash cost of production was 30% higher than in the same period in 2022. In 2023, with McArthur River/Key Lake ramping up production, inflationary pressure, the availability of personnel with the necessary skills and experience and supply chain challenges with the availability of materials and reagents, our annual cash cost of production is expected to be higher than the average life of mine operating costs noted in our most recent annual information form: approximately $16 per pound at McArthur River/Key Lake and approximately $18 per pound at Cigar Lake.

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. However, this does not reflect the economic benefit to Cameco. Our share of the economic benefit is based on the difference between our purchase price and JV Inkai’s lower production cost and is reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investee.” This benefit is realized through payment of a cash dividend by JV Inkai. Excess, cash, net of working capital requirements is distributed to the partners as dividends. If there is a significant disruption to JV Inkai’s operations for any reason, it may not achieve its production plans, there may be a delay in production, and it may experience increased costs to produce uranium.

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 $68.31 (Cdn) per pound, or $50.23 (US) per pound, compared to $48.76 (Cdn) per pound, or $38.38 (US) per pound in the second quarter of 2022. For the first six months, the average cash cost of purchased material was $68.17 (Cdn), or $50.16 (US) per pound, compared to $50.17 (Cdn), or $39.47 (US) per pound in the same period in 2022. As a result, the average cash cost of purchased material in Canadian dollar terms increased by 40% this quarter and increased by 36% for the six months compared to the same periods last year.

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

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

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the second quarter and the first six months of 2023 and 2022.

Cash and total cost per pound reconciliation

	THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS)	2023			2022			2023			2022
Cost of product sold		264.5			343.9			654.5			610.8
Add / (subtract)
Royalties		(14.1	)		(9.7	)		(38.8	)		(14.9	)
Care and maintenance and operational readiness costs		(11.1	)		(47.0	)		(23.1	)		(89.3	)
Other selling costs		(1.4	)		(1.1	)		(4.1	)		(3.4	)
Change in inventories		124.4			25.7			(97.7	)		(28.0	)
Cash operating costs (a)		362.3			311.8			490.8			475.2
Add / (subtract)
Depreciation and amortization		31.8			49.6			97.8			80.8
Care and maintenance and operational readiness costs		(1.0	)		(10.6	)		(2.5	)		(22.5	)
Change in inventories		25.6			1.8			8.6			19.1
Total operating costs (b)		418.7			352.6			594.7			552.6
Uranium produced & purchased (million lbs) (c)		8.2			8.3			13.0			12.5
Cash costs per pound (a ÷ c)		44.18			37.57			37.75			38.02
Total costs per pound (b ÷ c)		51.06			42.48			45.75			44.21

2023 SECOND QUARTER REPORT 25

Fuel services

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

		THREE MONTHS ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
HIGHLIGHTS		2023		2022		CHANGE			2023		2022		CHANGE
Production volume (million kgU)			3.4		3.7		(8	)%		7.6		7.8		(3	)%
Sales volume (million kgU)			3.2		2.8		14	%		5.6		5.0		12	%
Average realized price	($Cdn/kgU)		35.63		35.09		2	%		36.51		34.83		5	%
Average unit cost of sales (including D&A)	($Cdn/kgU)		23.38		20.75		13	%		24.14		21.55		12	%
Revenue ($ millions)			113		99		14	%		206		175		18	%
Gross profit ($ millions)			39		40		(3	)%		70		67		4	%
Gross profit (%)			35		40		(13	)%		34		38		(11	)%

SECOND QUARTER

Total revenue for the second quarter of 2023 increased by 14% from $99 million in the same period last year to $113 million. This was due primarily to a 14% increase in sales volumes.

The total cost of products and services sold (including D&A) increased 25% ($74 million compared to $59 million in 2022) due to the 14% increase in sales volume as well as an increase of 13% in the average unit cost of sales. Unit cost of sales increased mainly as a result of higher input costs.

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

FIRST SIX MONTHS

In the first six months of the year, total revenue increased 18% to $206 million from $175 million for the same period last year due to a 12% increase in sales volumes and a 5% increase in realized price. The increase in average realized price was mainly the result of increased prices due to market conditions.

The total cost of products and services sold (including D&A) increased 26% ($136 million compared to $108 million in 2022) due to the 12% increase in sales volume and a 12% increase in the average unit cost of sales due to higher input costs.

The net effect was a $3 million increase in gross profit.

Our operations

Uranium – production overview

Production volumes reflect our increased ownership interest in Cigar Lake of 54.547% as of May 19, 2022 (previously 50.025%).

We had 4.4 million pounds of production (our share) in the second quarter and 8.8 million pounds production (our share) in the first six months of 2023, compared to 2.8 million pounds and 4.7 million pounds in the same periods of 2022. In 2022, there was no production from McArthur River and Key Lake until the fourth quarter of 2022.

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

URANIUM PRODUCTION

	THREE MONTHS ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
OUR SHARE (MILLION LBS)	2023		2022		CHANGE			2023		2022		CHANGE			2023 PLAN
Cigar Lake		2.1		2.8		(25	)%		4.2		4.7		(11	)%		9.8
McArthur River/Key Lake		2.3		—		—			4.6		—		—			10.5
Total		4.4		2.8		57	%		8.8		4.7		87	%		20.3

26 CAMECO CORPORATION

Inflation, the availability of personnel with the necessary skills and experience, and the impact of supply chain challenges on the availability of materials and reagents carry with them the risk that we do not achieve our production plans and/or, experience production delays and increased costs. Additionally, with the extended period of time the McArthur River/Key Lake assets were on care and maintenance, the operational changes that have been made, and commissioning issues that we worked through at the mill in 2022, there is continued uncertainty regarding the timing of a successful ramp up to planned production and the associated costs.

Uranium 2023 Q2 updates

PRODUCTION UPDATE

McArthur River/Key Lake

The McArthur River and Key Lake operation was in a state of safe care and maintenance from 2018 through 2021 due to weak market conditions. The operation began transitioning back to production through the first three quarters of 2022, with no packaged pounds until the fourth quarter. Production ramp-up activities continue in 2023.

In the second quarter of 2023, total packaged production from McArthur River and Key Lake was 3.3 million pounds (2.3 million pounds our share). Our share of production in the first six months of 2023 was 4.6 million pounds.

We continue to expect production of 15 million pounds (10.5 million pounds our share) in 2023 and 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 negotiations to reach a new agreement have begun. As in the past, work continues under the terms of the expired collective agreement while negotiations proceed. There is a risk to the production plan if we are unable to reach an agreement and there is a labour disruption.

The current operating licences from the Canadian Nuclear Safety Commission (CNSC) for both McArthur River and Key Lake expire in October 2023. A licensing hearing was held by the CNSC in June 2023, and we expect its decision later in 2023. We do not expect any disruption to operations or significant risks from this process.

Cigar Lake

Total packaged production from Cigar Lake was 3.8 million pounds (2.1 million pounds our share) compared to 5.4 million pounds (2.8 million pounds our share) in the second quarter of 2022. Our share of production in the first six months of 2023 was 4.2 million pounds compared to 4.7 million pounds in the first six months of 2022. During the quarter we completed development and commissioning activities and achieved first production from a new mining area, which impacted productivity. As we disclosed in our annual MD&A, our mine plan included the start of mining activities from the western portion of the orebody in the second quarter of this year. Historically, all mining has been done in the eastern portion of the orebody.

In 2023 and 2024, we expect to produce 18.0 million pounds (9.8 million pounds our share) at Cigar Lake.

Inkai

Production on a 100% basis was 2.4 million pounds for the quarter and 4.3 million pounds for the first six months of the year, compared to 1.8 million pounds and 3.6 million pounds in the same periods last year.

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

Due to equity accounting, our share of production is shown as a purchase at a discount to the spot price and included in inventory at this value at the time of delivery. Our share of the profits earned by JV Inkai on the sale of its production 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.

Achievement of JV Inkai’s 2023 production forecast requires it to continue to successfully manage several ongoing risks, including the potential impact of procurement and supply chain issues, and inflationary pressures on its production materials and reagents. 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.

2023 SECOND QUARTER REPORT 27

The geopolitical situation continues to cause transportation risks in the region. In 2022, we experienced transportation delays for our share of Inkai’s production. In April, the second shipment containing 1.3 million pounds, representing the majority of our share of Inkai’s remaining 2022 production, arrived at a Canadian port. The first shipment of our share of Inkai’s 2023 production, which has been delayed, is expected to begin transit in the third quarter. 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 delays, we have inventory, long-term purchase agreements and loan arrangements in place we can draw on. Depending on when we receive shipments of our share of Inkai’s production, our share of earnings from this equity-accounted investee and the timing of the receipt of our share of dividends from the joint venture may be impacted.

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 million (US) and $14 million (US) for 2023.

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 and expect these costs to range between $27 million and $32 million for 2023.

The current operating licence from the CNSC for Rabbit Lake expires in October 2023. A licensing hearing was held by the CNSC in June 2023, and we expect its decision later in 2023.

Fuel services 2023 Q2 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 3.4 million kgU in the second quarter, 8% lower than the second quarter last year, and 7.6 million kgU in the first six months, which was 3% lower than the same period last year. The lower second quarter and year-to-date production compared to 2022 was primarily due to availability and timing of delivery of hydrogen from our supplier.

In our fuel services segment, which includes the production of UO₂, UF₆ and heavy water reactor fuel bundles, we expect to produce between 13 million and 14 million kgU of combined fuel services products in 2023 (outlook and production results are not disclosed by individual product line). Limited access to hydrogen supply during the first half of the year is not expected to impact total annual production.

In addition, at our Port Hope UF₆ conversion facility we are working on increasing annual production to 12,000 tonnes in 2024 to satisfy our book of long-term commitments and demand for conversion services.

28 CAMECO CORPORATION

Proposed acquisition of Westinghouse

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

The acquisition is expected to close later this year and is subject to customary closing conditions and certain regulatory approvals. The final financing, our share of which will be approximately $2.2 billion (US), will be determined based on our cash balance, future expected cash flow generation, and market conditions at the time of close. We expect a permanent financing mix of capital sources, including cash, debt and equity, designed to preserve our balance sheet and ratings strength, while maintaining healthy liquidity. See our annual MD&A for more information.

Caution about forward-looking information relating to the Westinghouse acquisition

This discussion of our expectations for the Westinghouse acquisition, including sources and uses of financing for the acquisition, timeline for the acquisition, including anticipated closing date, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headings Caution about forward-looking information beginning on page 2, and in our October 18, 2022, material change report. The material change report is available at www.sedarplus.ca and www.sec.gov. Actual results and events may be significantly different from what we currently expect.

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   •  Lloyd Rowson, general manager, Cigar Lake,
Cameco INKAI   •  Sergey Ivanov, deputy general director, technical services, Cameco Kazakhstan LLP

2023 SECOND QUARTER REPORT 29

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, 2023, 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, 2023, the CEO and CFO concluded that:

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

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

There have been no changes in our internal control over financial reporting during the quarter ended June 30, 2023, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

30 CAMECO CORPORATION