.2

Management’s discussion and analysis

for the quarter ended September 30, 2026

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 September 30, 2026 (interim financial statements). The information is based on what we knew as of and through October 29, 2026, and updates our first quarter, second quarter and annual MD&A included in our 2025 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, 2025, 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, the company and Cameco mean Cameco Corporation and its subsidiaries unless otherwise indicated.

Caution about forward-looking information

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

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

Examples of forward-looking information in this MD&A

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Material Risks

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Material Assumptions

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Third quarter market update

Geopolitical uncertainty, tension in the fossil fuel supply chain, and heightened concerns about energy security, national security, and climate security continue to improve the demand fundamentals for the nuclear power industry, while highlighting the importance of secure and diversified long-term nuclear fuel cycle supplies to support its growth.

In the third quarter of 2026, the average reported long-term uranium price increased to US$96.50, approaching its highest level since 2011 (in 2026 constant dollars), while the uranium spot price ended the quarter at US$89.63. Over the past several years, fuel buyers have continued to focus on securing their long-term requirements for conversion and enrichment services amid uncertain market access and global trade policies, which resulted in higher prices across the fuel cycle. The focus on downstream services delayed a meaningful return to the procurement of the uranium required to feed into those services. However, a similar focus on security of supply is now moving upstream to uranium, evidenced by public requests for proposals from utilities and traditional demand entering the market, alongside inbound requests for direct long-term off-market negotiations. Additionally, several non-utility, non-traditional potential customers in energy intensive sectors and hard-to-abate industries are recognizing the growing long-term nuclear fuel supply deficit and have begun proactively engaging with nuclear fuel providers to better understand procurement practices. As these organizations evaluate nuclear technologies to support their energy needs, they could emerge as a new source of demand in the nuclear fuel market, adding further pressure on future uranium supply.

Some of the more significant developments affecting supply since our second quarter MD&A include:

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According to the IAEA, there are currently 438 operable reactors with 417 operating today, and 78 reactors under construction globally. Demand-related developments continue to suggest growing support for the nuclear industry, with 39 countries now pledging to triple their nuclear power capacity by 2050. Many nations are reaffirming their commitment to existing nuclear and/or reversing policies to phase out nuclear energy. Non-nuclear countries are emerging as candidates for new nuclear capacity, improvements are being made in global sustainable financing policies to include nuclear energy, and opinion polls indicate improving public support. With reactor capacities being increased (uprates), reactors being saved from early retirement, life extensions to existing reactors being sought and approved, and new reactor construction projects underway with many more planned, demand for nuclear fuel continues to improve in the near-, medium- and long-term.

The more significant developments affecting current and future demand since our second quarter MD&A include:

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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 above and under the heading Caution about forward-looking information beginning on page 2.

Industry prices at quarter end

Note: the industry does not publish UO₂ prices.

On the spot market, where purchases call for delivery within one year, the volume reported by UxC for the third quarter of 2026 was about 9 million pounds U₃O₈ equivalent, compared to 15 million pounds U₃O₈ equivalent over the same period in 2025. As of September 30, 2026, the average reported spot price was US$89.63 per pound U₃O₈ equivalent, up US$4.63 per pound from the previous quarter and up US$7.00 per pound over the past 12 months.

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 (spot and long-term indicators) determined near the time of delivery, which often include floor prices and ceiling prices that are escalated to time of delivery. The volume of long-term contracting reported by UxC, through the first nine months to September 30, 2026, totaled about 42 million pounds U₃O₈ equivalent, down slightly from about 45 million pounds U₃O₈ equivalent reported over the same period in 2025. Although customers have continued to focus on securing downstream fuel-cycle services amid global macroeconomic and geopolitical uncertainty, concerns about security-of-supply have increasingly driven attention upstream to uranium with requests for proposals from utilities, several with responses due before year-end, renewed traditional demand, and growing interest in direct, long-term, off-market negotiations.

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The average reported long-term price at the end of the quarter was US$96.50 per pound U₃O₈ equivalent, up US$1.00 per pound from the previous quarter and up US$13.50 per pound over the past 12 months.

With consistent demand for western conversion services, pricing in both North America and Europe continues to be strong. At the end of the third quarter, the average reported conversion spot price for North America was US$62.00 per kilogram uranium (kgU) as UF₆, down US$2.50 from the previous quarter. The average long-term conversion price for North America finished the quarter at US$54.00 per kgU as UF₆, down US$1.50 per kgU from the previous quarter.

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Our strategy

We are a pure-play investment in the growing demand for nuclear energy, focused on taking advantage of the near-, medium- and long-term growth occurring in our industry. We provide nuclear fuel and nuclear power products, services and technologies across the fuel and reactor life cycles, augmented by our investment in Westinghouse, that support the generation of carbon-free, reliable, secure and affordable energy. Our strategy is set within the context of what we believe is a transitioning market environment. Increasing populations, a growing focus on electrification and decarbonization, and concerns about energy security and affordability are driving a global focus on tripling nuclear power capacity by 2050, which is expected to durably strengthen long-term fundamentals for our industry. Nuclear energy must be a central part of the solution to achieving energy growth and national security objectives, and helping the world shift to a low-carbon, climate resilient economy. It is an option that can provide the necessary power in a carbon-free, reliable and affordable manner.

Our strategy is to capture full-cycle value by:

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 – “Powering a secure energy future” – recognizes that we have an important role to play in achieving energy security, national security and climate security. Our uranium and fuel services are used around the world in the generation of safe, reliable, carbon-free, baseload nuclear power, which is crucial to energy security. In times of geopolitical uncertainty, a secure source of nuclear fuel is more important than ever as it also supports national security objectives. Additionally, Cameco supports climate security by enabling the generation of carbon-free nuclear power, helping to reduce greenhouse gas emissions and combat climate change. Cameco’s strategic initiatives aim to expand global nuclear capacity and support the transition to a low-carbon economy.

We believe we have the right strategy to achieve our vision, and we will do so in a manner that reflects our values. For more than 35 years, we have been committed to operating and delivering our products responsibly and profitably. We integrate sustainability principles and practices into every aspect of our business, from our corporate objectives and approach to compensation to our overall corporate strategy, risk management, and day-to-day operations, and they align with our values. We seek to be transparent with our stakeholders, keeping them updated on the risks and opportunities that we believe may have a significant impact on our ability to achieve our strategic plan and add long-term value. We recognize the importance of integrating certain sustainability factors, such as a clean environment, supportive communities and a safe, healthy and rewarding workplace, into our executive compensation strategy as we see success in these areas as critical to the long-term success of the company.

You can read more about our strategy in our 2025 annual MD&A and our approach to sustainability in our 2025 Sustainability Report.

Strategy in action

With the ongoing transition and improvements in the nuclear fuel market, our three-pillar strategy is guiding our disciplined contracting, supply and financial decisions. As a proven and reliable commercial supplier with assets in geopolitically stable jurisdictions across all segments of the nuclear fuel cycle, we continue to be selective in committing our unencumbered, in-ground uranium inventory and UF₆ conversion capacity under long-term contracts, responsibly managing our supply in accordance with our customers’ needs. With our operationally flexible and disciplined approach to supply, we continue to meet our sales commitments through the strategic management of our inventory, which can include production, purchases and

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material borrowed under product loans. To support the long-term operation of our productive capacity, our contracting is focused on maintaining exposure to future improvements in the market while retaining downside protection. Through risk-managed financial discipline, our balance sheet remains strong, and we expect to maintain the financial strength and flexibility necessary to execute on our strategy by planning production in coordination with contracting success and market opportunities.

FINANCIAL HIGHLIGHTS

Adjusted net earnings and adjusted EBITDA are non-IFRS measures. See the information starting on page 43.

OPERATIONAL HIGHLIGHTS

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MARKETING HIGHLIGHTS

2026 OUTLOOK UPDATE

ADDITIONAL HIGHLIGHTS

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Financial results

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

During the quarter, Cameco and Orano acquired TEPCO Resources Inc.’s (TEPCO) 5% participating interest in the Cigar Lake Joint Venture (CLJV). Cameco’s ownership stake in Cigar Lake now stands at 57.418%, 2.871% higher than it was prior to the transaction. Effective July 2, 2026, we have reflected our share of production and financial results at this new ownership level.

Consolidated financial results

Quarterly trends

Key things to note:

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The following table compares the net earnings and adjusted net earnings (loss) for the third quarter to the previous seven quarters.

Corporate expenses

ADMINISTRATION

Direct administration costs were $17 million higher for the third quarter of 2026 compared to the same period last year, and $34 million higher for the first nine months. Direct administration costs were higher due to increased labour costs, strategic initiatives, technology investments and renovations to our corporate office. Share-based compensation was $23 million lower for the third quarter of 2026 compared to the same period last year due to the decrease in our share price during this period compared to an increase in the same period last year. Share-based compensation in the first nine months of 2026 was $3 million higher than in the same period in 2025 primarily driven by performance metrics increasing the share-based compensation awards in 2026.

EXPLORATION AND RESEARCH & DEVELOPMENT

In the third quarter, uranium exploration expenses were $12 million, an increase of $4 million from the third quarter of 2025. In line with the annual outlook provided for 2026, exploration expenses for the first nine months of the year increased by $6 million compared to 2025, to $28 million.

As planned, research and development expenses in the third quarter of the year were $13 million, $3 million higher than the third quarter of 2025, and $36 million for the first nine months of the year, $12 million higher compared to the same period in 2025 due to the timing of expenditures. These expenses mainly relate to our investment in Global Laser Enrichment, LLC.

INCOME TAXES

We recorded an income tax expense of $12 million in the third quarter of 2026, compared to an expense of $16 million in the third quarter of 2025, and for the first nine months of 2026, we recorded an expense of $65 million compared to an expense of $140 million in 2025.

Income tax expense to the end of the third quarter in 2026 has been lower compared to the same period last year primarily as a result of lower earnings in Canada. Equity-accounted investees are included in both Canadian and foreign earnings net of tax paid in the jurisdictions in which they operate. Foreign earnings include losses in some jurisdictions for which no future tax benefit has been recognized.

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TRANSFER PRICING DISPUTE

Background

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

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

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

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

Refund and cost award

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

Reassessments, remittances and next steps

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

In March 2023, CRA issued revised reassessments for the 2007 through 2013 tax years, which resulted in a refund of $297 million of the $780 million in cash and letters of credit held by CRA at the time. The refund consisted of cash in the amount of $86 million and letters of credit in the amount of $211 million, which were returned in the second quarter.

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

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

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

In 2020, CRA advanced an alternate reassessing position for the 2014 tax year in the event the basis for its original reassessment, noted above, is unsuccessful. Subsequent to this, we received a reassessment for the 2015, 2016 and 2017 tax years, all reflecting this alternative reassessing position. While CRA did not require additional security for the tax debts they considered owing for 2014 through 2016, CRA did require additional letters of credit related to the tax debts they considered owing for 2017. To date, Cameco has remitted $559 million ($209 million in cash and $350 million in letters of credit) which continues to be held as security related to the reassessments. Further, as a result of these reassessments CRA has drawn down the tax pools available to us and we were required to remit cash tax totaling $346 million for the 2024, 2025 and 2026 taxation years. The new basis of reassessment is inconsistent with the methodology CRA has pursued for prior years and we are disputing it separately. Our view is that this alternate methodology will not result in a materially different outcome from our 2014 to 2017 filing positions. We filed appeals with the Tax Court for each year from 2014 through 2017.

In 2024, we received a reassessment for the 2018 tax year and in 2025, we received a reassessment for the 2019 tax year. Both reassessments relate to contracts other than those discussed above. CRA has advanced another alternate reassessing position for the 2018 and 2019 tax years. We filed a notice of objection for each of 2018 and 2019.

Cameco is challenging the 2019 reassessment separately and apart from the litigation and objections otherwise described herein. In its audit findings for 2019, CRA concluded there should be an upward pricing adjustment of $52 million under certain intercompany agreements and a downward pricing adjustment of about $57 million under other intercompany agreements. The downward adjustment would have entirely offset the increase to taxable income as per the CRA’s reassessment if made. The Minister of National Revenue decided, however, not to make the downward adjustment based on CRA administrative policy. Cameco has objected to this decision and has filed a request for judicial review with the Federal Court to contest it. The outcome of Cameco’s objection and the request for judicial review are not known at this time.

We will not be in a position to determine the definitive outcome of the dispute for any tax year other than 2003 through 2006 until such time as all reassessments have been issued advancing CRA’s arguments and final resolution is reached for that tax year. CRA may also advance alternative reassessment methodologies for years other than 2003 through 2006, such as the alternative reassessing position advanced for 2014 through 2017, or the new reassessing position advanced for 2018 and 2019.

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 above and under the heading Caution about forward-looking information beginning on page 2.

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FOREIGN EXCHANGE

The exchange rate between the Canadian dollar and US dollar affects the financial results of our business.

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 dollar exposure (e.g. total US dollar sales and distributions received 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, and in particular, 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 impact of our hedging program in the applicable reporting period.

Impact of hedging on ANE

We designate contracts for use in particular periods, based on our expected net exposure in that period. Hedge contracts are layered in over time based on this expected net exposure. The result is that our current hedge portfolio is made up of a number of contracts, which are currently designated to net exposures we expect in 2026 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 or significant currency movement. See Non-IFRS measures on page 43.

For more information, see our 2025 annual MD&A.

At September 30, 2026:

Outlook for 2026

Our outlook for 2026 reflects our plan to produce between 17.5 million and 18 million pounds (100% basis) at Cigar Lake, between 14 million and 14.5 million pounds (100% basis) at McArthur River/Key Lake, and 13 million to 14 million kgU in our fuel services segment, as well as continued work to extend the mine life at Cigar Lake. See Our operations – Uranium 2026 Q3 Updates on page 32 for more information

In 2026, we expect strong financial performance, including strong cash flow generation. Our financial performance and the amount of cash generated will be dependent on sourcing the material required to meet our deliveries as planned, including achieving our production plans.

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 $62 million and $67 million.

We have increased our outlook for direct administration costs to between $260 million and $280 million (previously $245 million to $260 million) as a result of increased spend on strategic initiatives related to non-recurring expenses.

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As we approach the end of the year, we have greater certainty in our expected uranium production and timing of uranium deliveries, and we have therefore narrowed our consolidated uranium production guidance to between 19.5 million and 20.5 million pounds (previously 19.5 million to 21.5 million pounds), and our sales/delivery volume guidance in our uranium segment to between 29.5 million and 30.5 million pounds (previously 29 million to 32 million pounds).

We have also adjusted our guidance for average unit cost of sales to $67.00 to $70.00/lb (previously $63.00 to $67.50/lb) to reflect the narrowed production guidance and the effect of inflation on production costs.

We decreased our estimate for capital spending to between $440 million and 490 million (previously between $490 million and $540 million), primarily due to the timing of certain mine development activities at our northern operations and the deferral of scheduled work at our fuel services operations into the following years.

2026 FINANCIAL OUTLOOK

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

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

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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 19.

In 2026 we continue to expect our share of adjusted EBITDA from our equity investment in Westinghouse to be between US$370 million and US$430 million. Certain line-items within the table have been adjusted to align with internal Westinghouse reporting. Integration and transformation costs (previously restructuring costs) are intended to modernize or redesign significant business processes, systems or organizational structures, non-recurring expenses are associated with establishing the framework to facilitate funding under the American Nuclear Supply Chain Loans (ANSCL), while other expenses include expenses associated with the long-term incentive plan and non-operating expenditures.

Note: the ranges for 2026 outlook for EBITDA and adjusted EBITDA are not determined using the high and low estimates of the ranges provided for each of the detailed reconciling line items.

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The outlook for adjusted EBITDA from Westinghouse’s core business for 2026 assumes that the work is fulfilled on the timelines, expected scope based on current orders received, and additional work is undertaken based on past trends. The expected margins are aligned with the historic margins of about 20%, with the variability expected to come from product mix compared to previous years.

In addition, Westinghouse’s adjusted EBITDA outlook is based on both signed and expected contracts in its new build business and assumes that Westinghouse enters into definitive agreements relating to the deployment of new AP1000 reactors in the US, and that work advances on at least one project during the year. Delays in finalizing the definitive agreements with the US Government and establishing a commitment from an approved partner may impact Westinghouse’s adjusted EBITDA outlook.

Westinghouse expects growth in the new build business based on agreements that have been signed and announcements where AP1000 technology has been selected. As decisions on the projects are made, we expect the projects will proceed on the timelines and revenue pattern noted under the AP1000 contracting framework, although variations to this general framework will occur depending on the customer and a number of other factors and assumptions. See New Build starting on page 102 in our annual MD&A for more details.

The outlook for Westinghouse capital expenditures is strategically focused on modernizing and reinforcing long-term reliability of its operations. Growth capital has been prioritized to support AP1000 readiness, operational stability and advanced fuel designs.

Westinghouse 2026 capital spending outlook

Westinghouse future capital spending

Westinghouse plans to continue to invest sustaining capital to modernize and reinforce the long-term reliability of its operations, which has historically been approximately US$0.2 billion to US$0.3 billion per year on a steady-state basis. In addition, capital will be required for fuel fabrication expansion initiatives, including planned construction of LEU+ fuel capabilities at Westinghouse’s Columbia Fuel Fabrication Facility, which are estimated to require approximately US$400 million to US$4 50 million (based on our 49% ownership) between 2027 and 2030. These investments are expected to support existing fuel customers while expanding Westinghouse’s fuel fabrication capabilities required to support future AP1000 reactor deployments.

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

This discussion of our expectations for Westinghouse’s future earnings and adjusted EBITDA and our share thereof is forward-looking information that is based upon the assumptions and subject to the material risks discussed above and under the heading Caution about forward-looking information beginning on page 2. Actual results and events may be significantly different from what we currently expect.

IMPACT OF CONFLICT IN MIDDLE EAST

Ongoing geopolitical conflict in the Middle East has disrupted key global trade routes, reducing availability of certain commodities from the region and driving up global costs. Our operations do not directly rely on materials being sourced from or transiting the Middle East region and we expect to maintain reliable access to the commodities we require. However, we are experiencing some cost increases. At this time, we do not anticipate the cost increases will have a material impact on our 2026 financial results. We will continue to monitor conditions and manage our supply chain to mitigate potential risks.

POTENTIAL TARIFF IMPACT

While we currently do not anticipate the direct impact of US tariffs to be material on our 2026 financial results, there continues to be uncertainty around the exact details of how broader tariffs may be applied to uranium products and whether any tariff refund mechanisms are available.

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REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

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

As a result, if the uranium spot price increased by US$5 per pound, we expect revenue would increase by $6 million, while ANE would decrease by $7 million and cash flow would decrease by $17 million. From a cash flow perspective, the sensitivity does not adequately capture the impact of JV Inkai purchases, which straddle two annual fiscal reporting periods in light of when dividends are declared and paid by JV Inkai. The cash flow sensitivity includes the cash outflow for the 4.2 million pounds of uranium assumed to be purchased from JV Inkai in 2026 at a 5% discount to the spot price but does not account for an associated increase in the cash dividend expected, which will be tied to our agreed to 2026 production purchase entitlement and is expected to be received in 2027. JV Inkai distributes excess cash as dividends to its owners, net of working capital requirements. In the case of a US$5 per pound increase in uranium prices, the JV Inkai purchases are responsible for about a $21 million decrease in cash flow, and we expect the impact of these purchases on the 2026 cash flow will be partially offset by dividends once declared and paid in 2027.

If the uranium spot price decreased by US$5 per pound, we expect revenue to decrease by $11 million, ANE to increase by $4 million, and cash flow to increase by $14 million. From a cash flow perspective, the impact of the noted decrease in uranium price on the assumed purchase of uranium from JV Inkai is expected to have the opposite impact from that described above for the noted uranium price increase.

Changes in the uranium spot price will impact the sensitivity analysis of ANE and cash flow differently, depending on the terms of the contracts within our contract portfolio, the inclusion of our share of earnings from our equity-accounted investment in JV Inkai in the reporting period, the rate of inventory turnover, and income taxes.

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

A one cent increase or decrease in the value of the US dollar compared to the Canadian dollar would respectively increase or decrease expected revenue by $8 million, while the impacts on ANE and cash flow would not be significant. The majority of our sales are denominated in US dollars, resulting in sensitivity to foreign exchange rates. Revenue will be recognized at the prevailing foreign exchange rate at the time of the sale. ANE and cash flow are less sensitive to foreign exchange rates as we have layered in foreign exchange hedges to provide cash flow certainty. Currently, for 2026, we have US$1.45 billion hedged at an average rate of 1.37 USDCAD, meaning for ANE and cash flow purposes that this portion of our net exposure to the US dollar will realize a rate of 1.37 USDCAD instead of prevailing rates. See Foreign exchange starting on page 44 in our annual MD&A for more details.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

As discussed under Long-term contracting on page 25 of our 2025 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.

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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 September 30, 2026, 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 of September 30, 2026. 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 September 30, 2026, using the following assumptions:

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 September 30, 2026

As of September 30, 2026, we had commitments requiring delivery of an average of about 28 million pounds per year from 2026 through 2030, with commitment levels in 2026 through 2028 being higher than the average, and in 2029 and 2030, lower than the average, reflecting our disciplined approach to contracting. As the market improves, we expect to continue layering in volumes that capture greater upside using market-related pricing mechanisms.

Liquidity and capital resources

Our financial objective is to ensure we have the cash and access to capital to fund our operating activities, investments and other financial obligations in order to execute our strategy, take advantage of opportunities and self-manage risk. We regularly consider our financing options so we can take advantage of favourable market conditions when they arise. 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 financing, including by conducting a registered offering of securities using our base shelf prospectus or utilizing our at-the-market equity program.

In July 2026, we closed our transaction to purchase (jointly with Orano) TEPCO’s ownership share of Cigar Lake, including making the associated closing payments. As of September 30, 2026, we had cash and cash equivalents of $860 million, while our total debt amounted to approximately $1.0 billion. We have a risk management policy to manage our cash balances and investments, which are largely held in government securities or with banks that are party to our lending facilities. In addition, we have a $1.0 billion revolving credit facility, which remains undrawn.

24 CAMECO CORPORATION

We have large, creditworthy customers that continue to need our nuclear fuel products and services even during weak economic conditions, and we expect the contract portfolio we have built will continue to provide a solid revenue stream. In our uranium segment, from 2026 through 2030, we have commitments to deliver an average of about 28 million pounds per year, with commitment levels higher than the average in 2026 through 2028 and lower than the average in 2029 and 2030.

We expect the low-cost production from our tier-one assets will continue to generate strong cash flows, which we expect will meet our capital requirements during 2026. However, cash flow from operations for 2026 will be dependent on our ability to source the material required to meet our deliveries as planned, including achieving our production plans.

With the Supreme Court’s dismissal of CRA’s application for leave, the dispute of the 2003 through 2006 tax years is fully and finally resolved in our favour. Furthermore, we are confident the courts would reject any attempt by CRA to utilize the same position and arguments for tax years 2007 through 2014, or its alternate reassessing position for tax years 2014 through 2017, or its new alternative reassessing position for 2018 and 2019 and believe CRA should return all cash and letters of credit (to date, $559 million) being held. However, timing of any further payments is uncertain, and there can be no assurance that the courts will take this position. See Transfer pricing dispute starting on page 17 for more information.

CASH FROM OPERATIONS

Cash provided by operations was $153 million lower this quarter than in the third quarter of 2025 due primarily to higher income taxes paid and higher working capital requirements.

Cash provided by operations was $619 million lower in the first nine months of 2026 compared to the same period in 2025 due primarily to lower earnings, higher income taxes paid and higher working capital requirements partially offset by higher dividends received.

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We believe we have sufficient borrowing capacity with unsecured lines of credit of about $2.9 billion at September 30, 2026, unchanged from June 30, 2026. Credit facility size may vary based on current requirements or expected changes in financial assurance requirements during the year. At September 30, 2026, we had approximately $1.6 billion outstanding in financial assurances, which was unchanged from June 30, 2026.

We have extended the maturity date of our $1.0 billion unsecured revolving credit facility from October 1, 2029 to October 1, 2030. The facility allows us to request increases above $1.0 billion in increments of no less than $50 million, up to a total of $1.25 billion. At September 30, 2026, we had no short-term debt outstanding on our $1.0 billion unsecured revolving credit facility, which is unchanged from December 31, 2025.

Long-term contractual obligations

Since June 30, 2026, there have been no material changes to our long-term contractual obligations. Please see our 2025 annual MD&A for more information.

Debt covenants

As at September 30, 2026, we complied with all covenants in our credit agreement, including the financial covenants. The financial covenants in our credit agreement place restrictions on total debt, including guarantees and other financial assurances. We do not expect our operating and investment activities for the remainder of 2026 to be constrained by these covenants.

DIVIDEND

Our board of directors declared a 2026 annual dividend of $0.24 per common share, payable on December 15, 2026, to shareholders of record on November 30, 2026. The dividend is equal to the 2026 target dividend under the dividend growth plan announced in 2024 to double the annual dividend. The decision to declare an annual dividend is reviewed regularly by our board in the context of our cash flow, financial position, strategy and other relevant factors, including appropriate alignment with the cyclical nature of our earnings.

SHARES AND STOCK OPTIONS OUTSTANDING

At October 28, 2026, we had:

2026 THIRD QUARTER REPORT 25

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at September 30, 2026:

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 September 30, 2026,² but does not include purchases of our share of JV 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.

We have purchase commitments of $232 million (previously $259 million at December 31, 2025) for the following:

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

Financial assurances

At September 30, 2026, our financial assurances totaled $1.6 billion, which is unchanged from June 30, 2026.

Other arrangements

We have arranged for standby product loan facilities with various counterparties to provide flexibility to supplement our inventory from time-to-time. We record the loans at our weighted average cost of inventory, which we believe is the best estimate of the cost to settle the obligation. The arrangements allow us to borrow up to 7.9 million pounds of U₃O₈ and 2.7 million kgU of UF₆ conversion services until 2032 with repayment in-kind up to March 31, 2032 (see note 9 to the financial statements). Under the loan facilities, standby fees of up to 2.1% 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 2.2%. At September 30, 2026, we have 4.0 million pounds of U₃O₈ and 1.2 million kgU of UF₆ conversion services drawn on the loans.

BALANCE SHEET

Total cash and cash equivalents at September 30, 2026 were $860 million, or 29% lower than at December 31, 2025, mainly due to higher working capital requirements, income taxes paid and the acquisition of the additional ownership stake in Cigar Lake. Net debt at September 30, 2026, was approximately $137 million.

26 CAMECO CORPORATION

Total product inventories are $829 million compared to $844 million at the end of 2025. The average inventory cost for uranium has decreased to $58.37 per pound compared to $61.85 per pound at December 31, 2025. As of September 30, 2026, we held an inventory of 8.5 million pounds of U₃O₈ equivalent (excluding broken ore) (December 31, 2025—9.7 million pounds). Total product inventory value and inventory volume varies from quarter to quarter depending on the inventory cost and the timing of production, purchases and sales deliveries in the year.

Financial results by segment

Uranium

THIRD QUARTER

Production during the quarter was 3.5 million pounds, 20% lower compared to the third quarter of 2025. See Our Operations starting on page 32 for more information.

Uranium revenues this quarter were down 1% compared to 2025 due to an 8% decrease in sales volumes, resulting from normal quarterly variations in deliveries and our lower planned 2026 sales delivery volumes, reflecting our contracting discipline. Customers choose when in the year to receive deliveries and as a result, our quarterly delivery patterns and, therefore, our quarterly sales volumes and revenue can vary significantly. This was partially offset by an increase of 8% in the Canadian dollar average realized price which increased due to the impact of market-priced contracts on the portfolio. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 23.

Total cost of sales (including D&A) increased by 12% ($407 million compared to $365 million in 2025) due to an increase of 21% in the average unit cost of sales, partially offset by an 8% decrease in sales volume. The average unit cost of sales increased due to higher purchase and production costs compared to the third quarter of 2025. See table below and Uranium production on page 32.

The net effect was a $47 million decrease in gross profit for the quarter.

FIRST NINE MONTHS

Production volumes for the first nine months of the year were 9% lower than in the previous year. See Our Operations starting on page 32 for more information.

Uranium revenues increased 2% compared to the first nine months of 2025 due to an increase of 9% in the Canadian dollar average realized price, partially offset by a 6% decrease in sales volume. While the average US dollar spot price for uranium increased by 22% compared to the same period in 2025, the US dollar average realized price increased by only 10%, reflecting the impact of ceiling prices on market-priced contracts, which limited the average realized price. The Canadian dollar average realized price increased by only 9% due to a stronger Canadian dollar compared to 2025. For more information on the impact of spot price changes on average realized price, see Price sensitivity analysis: uranium segment on page 23.

2026 THIRD QUARTER REPORT 27

Total cost of sales (including D&A) increased by 7% ($1,361 million compared to $1,269 million in 2025) primarily as a result of a 14% increase in the average unit cost of sales, partially offset by a 6% decrease in sales volume compared to the same period last year. The average unit cost of sales increased due to higher purchased quantities and production costs. See table below and Uranium production on page 32.

The net effect was a $51 million decrease in gross profit for the first nine months.

The table below shows the costs of produced and purchased uranium incurred in the reporting periods (see non-IFRS measures starting on page 43). These costs do not include care and maintenance costs, maintenance and operational outage costs, selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

The average cash cost of production was 62% higher for the quarter compared to the same period in 2025. For the first nine months, the average cash cost of production was 22% higher than in the same period in 2025. The increase was due to the impact of fixed costs on lower production as well as the effects of inflation. Production costs have increased as a result of inflationary impacts on labor costs, commodity prices, and production supplies. Increased project work to maintain aging infrastructure has also contributed to higher costs.

The estimated average unit life of mine operating costs reflected in our most recent annual information form are $21.72 per pound at McArthur River/Key Lake and $23.94 per pound at Cigar Lake. We expect that the estimated life of mine operating cost for McArthur River/Key Lake will be revised following the release of an updated NI 43-101 technical report. See Our operations - Uranium 2026 Q3 Updates starting on page 32.

Our purchases in the third quarter of 2026 totaled about $151 million, representing an average cash cost of $83.78 per pound, about $26.00 per pound higher than our total unit production cost for the quarter. Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the third quarter, the average cash cost of purchased material was $83.78 per pound, or US$60.15 per pound, compared to $82.51 per pound, or US$60.13 per pound in the third quarter of 2025. As a result, the average cash cost per pound of purchased material in Canadian dollar terms increased by 2% this quarter compared to the same period last year.

For the first nine months of the year, purchases totaled about $438 million, representing an average cost of $89.29 per pound, about $47.00 per pound higher than our total unit production cost for the year. The average cash cost of purchased material for the nine-month period was $89.29, or US$64.72 per pound, compared to $94.04, or US$67.17 per pound in the same period in 2025. As a result, the average cash cost per pound of purchased material in Canadian dollar terms decreased by 5% for the nine months compared to the same period last year.

28 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 that we purchase the material at a price equal to the uranium spot price, less a 5% discount. Our share of the economic benefit is reflected in the line item on our statement of earnings called, “share of earnings from equity-accounted investee” and is based on the difference between our purchase price and JV Inkai’s lower production cost (estimated average unit life of mine operating cash cost of $12.94 per pound). If there is a significant disruption to JV Inkai’s operations for any reason, it may not achieve its production plans, there may be a delay in production, and it may experience increased costs to produce uranium.

JV Inkai contribution to uranium segment

In the third quarter, $23 million is included in net earnings attributable to equity holders and $29 million is included in adjusted EBITDA from JV Inkai, compared to $16 million and $19 million respectively in the same period last year.

For the first nine months of the year, $153 million is included in net earnings attributable to equity holders and $187 million is included in adjusted EBITDA from JV Inkai, compared to $114 million and $133 million respectively in the same period last year.

The increase in JV Inkai’s equity earnings and adjusted EBITDA in the third quarter of 2026 was largely driven by the timing of sales and higher uranium prices, partially offset by increased costs. The increase in JV Inkai’s equity earnings and adjusted EBITDA for the first nine months of the year was also driven by the timing of sales and higher uranium prices, partially offset by increased costs compared to the prior year. In April, we received a cash dividend of US$124 million, net of withholdings, based on JV Inkai’s 2025 financial performance. From a cash flow perspective, we expect to realize the benefit from JV Inkai’s 2026 financial performance in 2027, once the dividend for 2026 is declared and paid.

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

Fuel services

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