EX-3 4 d196778dex3.htm EX-3

Management’s discussion and analysis

February 9, 2022

8 |  | 2021 PERFORMANCE HIGHLIGHTS
13 |  | MARKET OVERVIEW AND DEVELOPMENTS
19 |  | OUR STRATEGY
27 |  | OUR ESG PRINCIPLES AND PRACTICES
30 |  | MEASURING OUR RESULTS
31 |  | FINANCIAL RESULTS
57 |  | OPERATIONS AND PROJECTS
82 |  | MINERAL RESERVES AND RESOURCES
87 |  | ADDITIONAL INFORMATION

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2021. The information is based on what we knew as of February 8, 2022.

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

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

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

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

Caution about forward-looking information

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

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

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

• |  | It represents our current views and can change significantly.

• |  | It is based on a number of material assumptions, including those we have listed on page 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 on page 3. We recommend you also review our most recent annual information form, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

• |  | Forward-looking information is designed to help you understand management’s current views of our near- and longer-term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

Examples of forward-looking information in this MD&A

• |  | our view that we have the strengths to take advantage of the world’s rising demand for safe, reliable, affordable and carbon-free energy

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

• |  | our expectations about 2022 and future global uranium supply, consumption, contracting, demand and the market including the discussion under the heading Market overview and developments

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

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

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

• |  | the discussion under the heading Our strategy

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

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

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

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

• |  | our intentions regarding our 2022 annual dividend payment

• |  | the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our expectations regarding receiving refunds and payment of disbursements from CRA, our confidence that the courts would reject any attempt by CRA to utilize the same or similar positions for other tax years currently in dispute, 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 2022, including expected business resiliency, expectations for 2022 average unit cost of sales, average purchase price per pound, deliveries and production, 2022 financial outlook, our revenue, expectations for 2022 cash balances, adjusted net earnings and cash flow sensitivity, and our price sensitivity analysis for our uranium segment

• |  | the discussion under the heading Liquidity and capital resources, including expected liquidity to meet our 2022 obligations and our expectations for our uranium contract portfolio to provide a solid revenue stream

• |  | the outlook for our uranium and fuel services segments for 2022

• |  | our expectation that the uranium contract portfolio we have built will continue to provide a solid revenue stream

• |  | our expectation that our cash balances and operating cash flows will meet our anticipated 2022 capital requirements

• |  | our expectations for future capital expenditures

• |  | our expectation that in 2022 we will be able to comply with all the covenants in our unsecured revolving credit facility

• |  | life of mine operating cost estimates for the Cigar Lake and Inkai operations

• |  | future plans and expectations for uranium properties, advanced uranium projects, and fuel services operating sites, including production levels and suspension of production at certain properties

• |  | our expectations related to care and maintenance costs and operational readiness costs

• |  | our mineral reserve and resource estimates

• |  | our decommissioning estimates

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Material risks

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

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

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

• |  | our strategies may change, be unsuccessful or have unanticipated consequences

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• |  | operations are disrupted due to problems with our own or our suppliers’ or customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, unanticipated consequences of our cost reduction strategies, or other development and operating risks

• |  | we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, outbreak of illness (such as a pandemic like COVID-19), accident or a deterioration in political support for, or demand for, nuclear energy

• |  | we may be unable to successfully manage the current environment resulting from the COVID-19 pandemic and its related operational, safety, marketing, or financial risks successfully, including the risk of significant disruptions to our operations, workforce, required supply or services, and ability to produce, transport, and deliver uranium

• |  | a major accident at a nuclear power plant

• |  | we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium

• |  | government laws, regulations, policies or decisions that adversely affect us, including tax and trade laws and sanctions on nuclear fuel imports

• |  | our uranium suppliers or purchasers fail to fulfil their commitments

• |  | our McArthur River development, mining or production plans are delayed or do not succeed for any reason

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

• |  | the McClean Lake’s mill production plan is delayed or does not succeed for any reason

• |  | water quality and environmental concerns could result in a potential deferral of production and additional capital and operating expenses required for the Cigar Lake operation

• |  | JV Inkai’s development, mining or production plans are delayed or do not succeed for any reason

• |  | we may be unsuccessful in pursuing innovation or implementing advanced technologies, including the risk that the commercialization and deployment of SMRs may incur unanticipated delays or expenses, or ultimately prove to be unsuccessful

• |  | our expectations relating to care and maintenance costs or operational readiness costs prove to be inaccurate

• |  | the risk that we may become unable to pay our 2022 annual dividend at the expected rate

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 3

• |  | the regulatory, environmental and operational risks that generally apply to all our operations and advanced uranium projects that are discussed under the heading Managing the risks beginning on page 58

• |  | the risks relating to our tier-one uranium operations discussed under the heading McArthur River mine/Key Lake mill – Managing Our Risks beginning on page 65, under the heading Cigar Lake – Managing Our Risks beginning on page 69, and under the heading Inkai – Managing Our Risks beginning on page 72

Material assumptions

• |  | our expectations regarding sales and purchase volumes and prices for uranium and fuel services, trade restrictions, 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 and the demand for and supply of uranium

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

• |  | the assumptions discussed under the heading 2022 Financial Outlook

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

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

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

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

• |  | our cost expectations, including production costs, operating costs, operational readiness costs, capital costs, and the success of our cost reduction strategies

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

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

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

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

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

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

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

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

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

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

• |  | JV Inkai’s development, mining and production plans succeed

• |  | the ability of JV Inkai to pay dividends

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

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

• |  | our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, outbreak of illness (such as a pandemic like COVID-19), governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, unanticipated consequences of our cost reduction strategies, or other development or operating risks

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MANAGEMENT’S DISCUSSION AND ANALYSIS 5

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MANAGEMENT’S DISCUSSION AND ANALYSIS 7

2021 performance highlights

Despite additional disruptions to our business in 2021, we continued to do what we said we would do, protecting the health and safety of our employees and executing on all strategic fronts; operational, marketing and financial. In our uranium segment, since the beginning of 2021, and including the volumes reported in our third quarter MD&A, we have been successful in adding 70 million pounds to our portfolio of long-term uranium contracts, bringing the total volumes added since 2016 to about 185 million pounds. Nevertheless, we maintain leverage to higher prices with significant unencumbered future productive capacity and a large and growing pipeline of uranium business under discussion. We are being strategically patient in our discussions to capture as much value as possible in our contract portfolio. In addition to the off-market contracting interest, there has been a re-emergence of on-market requests for proposals from utilities looking to secure their future requirements.

In 2021, we were operating at about 75% below the productive capacity (100% basis) due to our planned supply discipline in our uranium segment and the unplanned production suspension at Cigar Lake. Productive capacity includes licensed capacity at Cigar Lake and McArthur River/Key Lake, and it includes planned production volumes at Rabbit Lake and our US operations prior to curtailment in 2016. We proactively suspended production at Cigar Lake for a second time for about four months starting in December 2020 due to the increased risks posed by the Coronavirus (COVID-19) pandemic at the time. As well, through our investment in Inkai, we were impacted by the 20% supply reduction enacted by Kazatomprom (KAP) across all uranium mines in Kazakhstan.

In addition to the proactive suspension of production at Cigar Lake, the COVID-19 safety protocols and measures we put in place in 2020, and following the precautions and restrictions enacted by all levels of government where we operate we proactively implemented additional measures and made a number of decisions to ensure a continued safe working environment for all our workers, in 2021, we:

• |  | introduced a requirement that all employees, contractors and visitors be vaccinated across all our operations and offices

• |  | developed a hybrid work model for employees working from home that balances time in the office and remote working in accordance with business needs

The proactive decisions we have made, and continue to make, to protect our workers and to help slow down the spread of the COVID-19 virus are consistent with our values. Even while production was suspended, we kept and continued to pay all our employees. The health and safety of our workers, their families and their communities continues to be the priority in all our plans, which will align with the guidance of the relevant health authorities where we operate.

We delivered over 24 million pounds of uranium to our customers in alignment with our contract portfolio and profitable opportunities in the market. We generated $458 million in cash from operations, with higher average realized prices in our fuel services segment than in 2020. However, as a result of the unplanned precautionary production suspension at Cigar Lake due to the COVID-19 pandemic, we incurred $40 million in care and maintenance costs for the operation and produced only 6.1 million pounds in our uranium segment, well below our committed sales. To manage risk we purchased 11.1 million pounds at a unit cost significantly higher than the average production costs at Cigar Lake for 2021 and 2020. See 2021 financial results by segment – Uranium starting on page 49 for more information. Partially offsetting these additional costs was the receipt of about $21 million under the Canada Emergency Wage Subsidy program and volatility in foreign exchange rates that resulted in foreign exchange gains.

Thanks to the disciplined execution of our strategy, our balance sheet is strong, and we expect it will enable us to see out our strategy as well as self-manage risk, including from global macro-economic uncertainty and volatility. As of December 31, 2021, we had $1.3 billion in cash and cash equivalents and short-term investments with only $996 million in long-term debt. In addition, we have a $1.0 billion undrawn credit facility.

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In our transfer pricing dispute with Canada Revenue Agency (CRA), the Supreme Court of Canada (Supreme Court) dismissed CRA’s application for leave to appeal the decision of the Federal Court of Appeal (Court of Appeal). As a result, 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 or similar positions and arguments for the other tax years currently in dispute (2007 through 2014) and believe CRA should return the $777 million in cash and letters of credit we have been required to pay or otherwise secure for those years. As such, we have filed a notice of appeal with the Tax Court of Canada (Tax Court), however timing of any further payments is uncertain. See Transfer pricing dispute on page 37 for more information.

In 2021, the benefits of nuclear energy came clearly into focus with a durability that we believe has not previously been seen. This durability is being driven by the accountability for achieving the net-zero carbon targets being set by countries and companies around the world. There is increasing recognition that nuclear power, with its clean emissions profile, reliable and secure baseload characteristics and low, levelized cost has a key role to play in achieving decarbonization goals. This is leading to both traditional and non-traditional demand growth for nuclear power and resulting in increased demand for uranium.

This increase in demand is occurring at a time when there is increasing uncertainty about uranium supply. The COVID-19 pandemic continued to disrupt global uranium production and introduced new risks including disruptions to global supply chains and rising costs for some products and services, adding to the supply curtailments that have occurred in the uranium industry for many years. The duration and extent of these disruptions are still not fully known. And, with the entrance of the Sprott Asset Management LP (Sprott) Physical Uranium Trust additional significant demand for spot material has impacted uranium prices. The uranium spot price increased significantly following the initial purchase activity in August, reaching a nine-year high of about $50 (US) per pound. The average uranium spot price ended the year at $42.05 per pound (US) nearly 40% higher than the average uranium spot price at the end of 2020. The thinning of material available in the spot market and the resulting higher spot prices have also pressured long-term prices with an increase in on-market requests for proposals (RFPs) and off-market negotiations. The long-term price was up 22% this year, ending the year at $42.75 per pound (US).

In the current environment, we believe the risk to uranium supply is greater than the risk to uranium demand and expect it will create a renewed focus on ensuring availability of long-term supply to fuel nuclear reactors. With the improvements in the market and the new long-term contracts we have put in place, it is time for us to proceed with the next phase of our supply discipline strategy, which also includes a planned supply reduction at Cigar Lake. Starting in 2024, we plan for our share of production to be about 45% below our productive capacity. In addition, at Inkai we will continue to follow the 20% reduction until the end of 2023 as announced by KAP. This will remain our production plan until we see further improvements in the uranium market and have made further progress in securing the appropriate homes for our unencumbered, in-ground inventory under long-term contracts, once again demonstrating that we are a responsible supplier of uranium fuel. See Our strategy starting on page 19 for more information.

We expect the investments we are making in digital and automation technologies will allow us to operate our assets with more flexibility. This is key to our ability to continue to align our production decisions with our contract portfolio commitments and opportunities. With a solid base of contracts to underpin our productive capacity, we will begin the process of preparing the McArthur River mine and Key Lake mill for production to allow us to achieve our 2024 production plan. This plan will significantly improve our financial performance by allowing us to source more of our committed sales from lower-cost produced pounds and we will no longer be required to expense care and maintenance costs directly to cost of sales. However, until we achieve a reasonable production rate, we expect to incur between $15 million to $17 million per month in operational readiness costs, which will be expensed directly to cost of sales. Operational readiness costs include all of the costs associated with care and maintenance in addition to the costs to complete critical projects, perform maintenance readiness checks, and recruit and train sufficient mine and mill personnel before beginning operations. Throughout, we will continue to focus on delivering our products safely and responsibly and addressing the environmental, social and governance (ESG) risks and opportunities that we believe will make our business sustainable and will build long-term value.

MANAGEMENT’S DISCUSSION AND ANALYSIS 9

Financial performance

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2021 |  |  | 2020 |  |  | CHANGE |
Revenue |  |  | 1,475 |  |  |  | 1,800 |  |  |  | (18 | )%
Gross profit |  |  | 2 |  |  |  | 106 |  |  |  | (98 | )%
Net loss attributable to equity holders |  |  | (103 | ) |  |  | (53 | ) |  |  | (94 | )%
$ per common share (diluted) |  |  | (0.26 | ) |  |  | (0.13 | ) |  |  | (92 | )%
Adjusted net loss (non-IFRS, see page 33) |  |  | (98 | ) |  |  | (66 | ) |  |  | (48 | )%
$ per common share (adjusted and diluted) |  |  | (0.25 | ) |  |  | (0.17 | ) |  |  | (47 | )%
Cash provided by operations |  |  | 458 |  |  |  | 57 |  |  |  | >100 | %

Net loss attributable to equity holders (net loss) and adjusted net loss were greater in 2021 compared to 2020. See 2021 consolidated financial results beginning on page 32 for more information. Of note:

• |  | generated $458 million in cash from operations

• |  | incurred $210 million in care and maintenance costs as a result of our strategic decisions, including $40 million due to the precautionary suspension at Cigar Lake in 2021 to deal with the risks posed by the COVID-19 pandemic

• |  | received $21 million under the Canada Emergency Wage Subsidy program

• |  | recorded $27 million in the first quarter as a reduction to administration costs to reflect the amounts owing to us for legal fees and disbursements for costs as awarded in our dispute with CRA. See Transfer pricing dispute on page 37 for more information

• |  | filed notice of appeal to the Tax Court in our dispute with CRA to have $777 million in cash and letters of credit returned. See Transfer pricing dispute on page 37 for more information.

Our segment updates

In our uranium segment, we continued to execute our strategy to preserve our tier-one assets and to ensure a safe working environment for all our workers, which impacted our operations. Of note in 2021:

• |  | continued the production suspensions at McArthur River/Key Lake, Rabbit Lake and US ISR operations, keeping about 23 million pounds (100% basis) out of the market

• |  | resumed production at the Cigar Lake mine at the end of April following the second suspension that commenced in December 2020 as a precaution due to the COVID-19 pandemic

• |  | annual production at Cigar Lake of 6.1 million pounds (our share) was 33% below licensed capacity due to the impacts of the precautionary four-month suspension

• |  | purchased 11.1 million pounds of uranium, including our spot purchases, committed purchase volumes and JV Inkai purchases

• |  | delivered on our sales commitments of over 24 million pounds in alignment with our contract portfolio and profitable market opportunities and added 30 million pounds in long-term contracts to our portfolio. Since the beginning of 2022, we have added another 40 million pounds, bringing the total added since the beginning of 2021 to 70 million pounds.

Production in 2021 from our fuel services segment was 3% higher than in 2020, as a result of production suspensions in 2020 due to the COVID-19 pandemic. Planned production was impacted by hydrogen supply issues in 2021. The hydrogen supply constraint was resolved in the fourth quarter, however supply chain disruption remains a risk generally.

Additionally, we increased our interest in Global Laser Enrichment LLC (GLE) from 24% to 49% and signed a number of non-binding arrangements to explore several areas of cooperation to advance the commercialization and deployment of small modular reactors (SMRs) in Canada and around the world. This furthers our commitment to responsibly and sustainably manage our business and increase our contributions to global climate change solutions by exploring other emerging and non-traditional opportunities within the fuel cycle.

See Operations and projects beginning on page 57 for more information.

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HIGHLIGHTS |  |  |  |  |  | 2021 |  |  | 2020 |  |  | CHANGE |
Uranium |  | Production volume (million lbs) |  |  |  |  | 6.1 |  |  |  | 5.0 |  |  |  | 22 | %
|  | Sales volume (million lbs) |  |  |  |  | 24.3 |  |  |  | 30.7 |  |  |  | (21 | )%
|  | Average realized price1 |  | ($US/lb) |  |  | 34.53 |  |  |  | 34.39 |  |  |  | — |
|  |  |  | ($Cdn/lb) |  |  | 43.34 |  |  |  | 46.13 |  |  |  | (6 | )%
|  | Revenue ($ millions) |  |  |  |  | 1,055 |  |  |  | 1,416 |  |  |  | (25 | )%
|  | Gross profit (loss) ($ millions) |  |  |  |  | (108 | ) |  |  | 18 |  |  |  | (700 | )%
Fuel services |  | Production volume (million kgU) |  |  |  |  | 12.1 |  |  |  | 11.7 |  |  |  | 3 | %
|  | Sales volume (million kgU) |  |  |  |  | 13.6 |  |  |  | 13.5 |  |  |  | 1 | %
|  | Average realized price 2 |  | ($Cdn/kgU) |  |  | 29.72 |  |  |  | 27.89 |  |  |  | 7 | %
|  | Revenue ($ millions) |  |  |  |  | 404 |  |  |  | 377 |  |  |  | 7 | %
|  | Gross profit ($ millions) |  |  |  |  | 118 |  |  |  | 96 |  |  |  | 23 | %

1 | Uranium average realized price is calculated as the revenue from sales of uranium concentrate, transportation and storage fees divided by the volume of uranium concentrates sold.

2 | Fuel services average realized price is calculated as revenue from the sale of conversion and fabrication services, including fuel bundles and reactor components, transportation and storage fees divided by the volumes sold.

Industry prices

|  | 2021 |  |  | 2020 |  |  | CHANGE |
Uranium ($US/lb U3O8)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  | 35.28 |  |  |  | 29.96 |  |  |  | 18 | %
Average annual long-term price |  |  | 36.81 |  |  |  | 34.63 |  |  |  | 6 | %
Fuel services ($US/kgU as UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 19.41 |  |  |  | 21.94 |  |  |  | (12 | )%
Europe |  |  | 18.99 |  |  |  | 21.09 |  |  |  | (10 | )%
Average annual long-term price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 18.42 |  |  |  | 18.27 |  |  |  | 1 | %
Europe |  |  | 18.42 |  |  |  | 18.18 |  |  |  | 1 | %
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 2021 was the highest annual total ever of approximately 102 million pounds U3O8 equivalent, compared to 95 million pounds U3O8 equivalent in 2020. Spot market volumes were significant in the second half of the year due to unplanned uranium demand from Sprott, which contributed to the thinning of spot uranium supply. Total spot purchases by producers, junior uranium companies and financial funds was approximately 50 million pounds U3O8 equivalent. At the end of 2021, the average reported spot price was $42.05 (US) per pound, up $11.85 (US) per pound from the end of 2020. During the year, the uranium spot price ranged from a month-end high of $45.75 (US) per pound to a low of $27.98 (US) per pound, averaging $35.28 (US) for the year.

Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including base-escalated (fixed prices escalated over the term of the contract), and market referenced prices (spot and long-term indicators) quoted near the time of delivery. The volume of long-term contracting reported by UxC for 2021 was about 70 million pounds U3O8 equivalent, up from about 57 million pounds U3O8 equivalent in 2020. Higher volumes can be attributed in part to utilities turning their attention to securing their long-term needs as demand from financial funds further thinned the spot market and eliminated the ability for utilities to rely on carry trade activity. The average reported long-term price at the end of the year was $42.75 (US) per pound, up $7.75 (US) from 2020. During the year, the uranium long-term price ranged from a month-end high of $43.00 (US) per pound to a low of $33.50 (US) per pound, averaging $36.81 (US) for the year.

MANAGEMENT’S DISCUSSION AND ANALYSIS 11

Following the record highs for conversion prices in both the North American and European markets in 2020, the average reported spot price for North American delivery at the end of 2021 was $16.10 (US) per kilogram uranium as UF6 (US/kgU as UF6), down $5.65 (US) from the end of 2020. Long-term UF6 conversion prices finished 2021 at $18.00 (US/kgU as UF6), down $1.00 (US) from the end of 2020.

URANIUM (US$/lb U3O8) AND CONVERSION (US$/kgU UF6) PRICES

Source: Average of prices reported from TradeTech and UxC

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Market overview and developments

A market in transition

In 2021, there was a significant improvement in uranium prices and market sentiment. Spot uranium prices for the year were up nearly 40%, reaching their highest level in nine years. The uranium available in the spot market thinned driven by record spot market purchases primarily by the Sprott Physical Uranium Trust, which has purchased approximately 26 million pounds since its inception in 2021, but also including other financial funds, producers and junior uranium companies who have indicated that the long-term fundamentals point to growing demand and supply uncertainty. The thinning of material available in the spot market and rising spot uranium prices motivated some utilities to return to the term market both with on-market RFPs as well as continued off-market contracting. As a result, the long-term price increased by 22%, ending the year at $42.75 (US) per pound. Despite an increase in contracting in the long-term market, the volume of uranium executed under long-term contracts remained well below annual consumption levels, continuing the inventory destocking that was already underway in the industry and adding to the growing wedge of uncovered requirements that we believe will need to be filled at a time when the availability of sufficient supply is not guaranteed. With a renewed focus on security of supply we believe we are in the early stages of a market transition, with utilities turning to proven producers and assets to meet their uncovered requirements.

Durable demand growth

The benefits of nuclear energy came clearly into focus with a durability we believe has not been previously seen, driven by the accountability created by the net-zero carbon targets being set by countries and companies around the world. These targets are turning attention to a triple challenge. First, is to lift one-third of the global population out of energy poverty by growing clean and reliable baseload electricity. Second, is to replace 85% of the current global electricity grids that run on carbon-emitting sources of thermal power with a clean, reliable alternative. And finally, is to grow global power grids by electrifying industries, such as private and commercial transportation, home, and industrial heating, largely powered with carbon-emitting sources of thermal energy today. Additionally, the energy crisis experienced in some parts of the world has amplified concerns about energy security and highlighted the role of energy policy in balancing three main objectives: providing a clean emissions profile; providing a reliable and secure baseload profile; and providing an affordable levelized cost profile. Too much focus on one objective, has left some jurisdictions struggling with power shortages and spiking energy prices. There is increasing recognition that nuclear power, with its clean emissions profile, reliable and secure baseload characteristics and low, levelized cost has a key role to play in achieving decarbonization goals.

Demand and energy policy highlights

• |  | On behalf of the Sprott Physical Uranium Trust, Sprott issued an At-The-Market (ATM) program allowing it to sell discretionary shares and use the proceeds to purchase U3O8. The initial limit was for up to $300 million (US), and on September 9th, Sprott increased the ATM program limit to $1.3 billion (US) followed by another increase to $3.5 billion (US) on November 23. As of February 7th, the fund had raised over $1.1 billion (US) and purchased approximately 26 million pounds U3O8. In addition to its listing on the Toronto Stock Exchange, Sprott is obligated to seek a US listing for the trust.

• |  | In March, Yellow Cake PLC (YCA) raised $100 million (US) to exercise their option with KAP to purchase approximately 3.5 million pounds of U3O8 as well as an additional purchase of 440,000 pounds U3O8. Subsequently, YCA agreed to purchase an additional 2 million pounds U3O8 from KAP. In October, YCA then raised approximately $150 million (US) and used the proceeds to fund the purchase of 2 million pounds U3O8 from Curzon Uranium Limited and purchased an additional 1 million pounds U3O8 from KAP. The net impact of other transactions in 2021 resulted in YCA acquiring an additional 0.6 million pounds U3O8.

• |  | On October 18th, KAP announced their 48.5% initial investment into a privately-held physical uranium fund for $50 million (US). The fund has a projected second stage of development to raise up to an additional $500 million (US), through either a public or private offering.

• |  | Many countries, states, and utilities announced net-zero carbon targets in 2020 and 2021. Notable countries include China, Japan, South Korea, United States (US), Canada, and France. While most of these targets are further out in the future, many of the plans include an important role for nuclear.

MANAGEMENT’S DISCUSSION AND ANALYSIS 13

• |  | The International Atomic Energy Agency (IAEA) increased its projections for nuclear out to 2050 for the first time since the Fukushima events in 2011. This includes nuclear generating capacity doubling to 792 GWe, from 393 GWe in 2020, which represents a 10% rise over the prior forecast.

• |  | The 2021 World Nuclear Association Nuclear Fuel Report was released in September and includes numerous positive developments for the industry. It highlights the prospects for nuclear growth and linkages to countries now targeting net-zero carbon emissions. Improved growth in China makes the most notable impact to higher demand projections post 2030. On the supply side, uranium production through 2025 declined significantly relative to the previous report in 2019, demonstrating the growing need for more production out in time.

• |  | China’s 14th five-year plan and related policy documents covering the 2021 to 2025 period were published in March as part of their plan to be carbon neutral by 2060. Nuclear received increased attention in the plan relative to the prior version. The key objective stated was China targeting 70 GWe operating and 50 GWe under construction through 2025. Additionally, China’s Nuclear Energy Association (CNEA) stated that by 2030, China could reach up to 120 GWe in operation.

• |  | In Japan, Kansai’s Mihama 3 restarted after over ten years and represents the first Japanese reactor in service over forty years to be restarted. In October, Fumio Kishida of the Liberal Democratic Party, was confirmed as Japan’s 100th Prime Minister. He has stated support for Japan’s energy policy which is targeting 20% to 22% nuclear by 2030 as part of its plan for carbon neutrality by 2050.

• |  | Russia’s nuclear generation reached historic records in 2021 as Leningrad II-2 became the latest operating reactor. In addition, Rosatom announced plans to build about 15 new 1,200 MWe Gen 3+ reactors by 2035, with most units being built at existing sites where units that were built in the 1970s are to be decommissioned.

• |  | In the European Union (EU), on February 2nd, the European Commission approved in principle a Complementary Climate Delegated Act (CDA), which includes specific nuclear and gas energy activities in the list of economic activities covered by the EU Taxonomy. This defines certain nuclear energy projects as green and sustainable for access to low-cost financing. The nuclear-related activities included are all advanced Generation IV nuclear technology with no expiry date, new Generation III+ nuclear reactors until 2045, and lifetime extension to existing nuclear reactors until 2040, while comprehensive nuclear safety and waste management requirements apply to all. The CDA now goes to the European Parliament and Council for debate.

• |  | The Netherlands has recently elected a new government which has promised to build two new nuclear power reactors and become climate neutral by 2050.

• |  | In France, President Emmanuel Macron announced planned new reactors, for the first time in decades, to meet its 2050 carbon neutral goal. Additionally, Électricité de France submitted a final plan to construct six EPR-2 reactors, with the vendor yet to be finalized and also announced that 32 900 MWe reactors were approved for expanded life spans from 40 years to 50 years.

• |  | In the United Kingdom (UK), Prime Minster Boris Johnson confirmed plans for all UK electricity to come from low-carbon sources including nuclear and renewables by 2035.

• |  | Germany closed three reactors at the end of 2021 and remains scheduled to close the last three operating reactors at the end of 2022.

• |  | In the US, Exelon’s Byron and Dresden plants in Illinois were saved from early closure with the signing of the Climate and Equitable Jobs Act. This comprehensive energy bill included nearly $700 million (US) in new state subsidies over the next five years.

• |  | US President Biden signed the $1.2 trillion bipartisan infrastructure bill that includes $6 billion to support at-risk nuclear plants and support for the US Department of Energy (DOE) with advanced reactors by 2030.

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

• |  | In South Korea, there will be federal elections in March of 2022. The leading presidential candidate, Yoon Seok-youl of the Peoples Power Party is pro nuclear and wants to end the nuclear phase-out. In addition, in January 2022, the current government announced plans to revise its green taxonomy and consider SMRs as eligible for state funding, reversing its stance to drop nuclear projects.

• |  | During September and October Cameco announced signing several non-binding arrangements to evaluate and explore possible opportunities to partner on the development and deployment of SMR and advanced reactor technologies and evaluate opportunities to supply uranium, fuel services and other services.

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According to the International Atomic Energy Agency there are currently 439 reactors operating globally and 52 reactors under construction. Several nations are appreciating the clean energy benefits of nuclear power. They have reaffirmed their commitment to it and are developing plans to support existing reactor units and are reviewing their policies to encourage more nuclear capacity. Several other non-nuclear countries have emerged as candidates for new nuclear capacity. In the EU, specific nuclear energy projects have been identified for inclusion under its sustainable financing taxonomy and therefore eligible for access to low-cost financing. Even in countries with phase-out policies, there is growing debate about the role of nuclear power, with public opinion polls showing growing support for it. The growth in demand is not just in the form of new builds, it is medium-term demand in the form of reactor life extensions, and it is near-term growth as early reactor retirements are prevented. And we are seeing momentum building for non-traditional commercial uses of nuclear power around the world such as development of small modular reactors and advanced reactors, with numerous companies and countries pursuing projects.

CURRENTLY UNDER CONSTRUCTION

WORLD OPERABLE REACTOR COUNT

MANAGEMENT’S DISCUSSION AND ANALYSIS 15

Supply uncertainty

Low uranium prices, government-driven trade policies, and the COVID-19 pandemic have had an impact on the security of supply in our industry. Despite the recent increase in uranium prices, years of underinvestment in new 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, there have been a number of unplanned supply disruptions related to the impact of the COVID-19 pandemic and associated supply chain challenges on uranium mining and processing activities. In addition, according to industry transport experts, there is a risk of transport disruptions for Class 7 nuclear material. Uranium is a highly trade-dependent commodity. 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. Over 80% of primary production is in the hands of state-owned enterprises, after taking into account the cuts to primary production that have occurred over the last several years. Furthermore, nearly 90% of primary production comes from countries that consume little-to-no uranium, and nearly 90% of uranium consumption occurs in countries that have little-to-no primary production. As a result, government-driven trade policies can be particularly disruptive for the uranium market.

Supply and trade policy highlights

• |  | In early January 2022, Kazakhstan saw the most significant political instability since it became independent in 1991. The events resulted in a state of emergency being declared across the country. With the assistance of the Collective Security Treaty Organization (CSTO), the government restored the order and in the second half of January, the state of emergency was gradually lifted and withdrawal of CSTO forces from Kazakhstan was completed. KAP reported that its operations have been unaffected by these events.

• |  | In its 2021 fourth quarter operations and trading update, KAP confirmed its intent to maintain production levels at 20% below those stipulated in its Sub Soil Use Agreements through 2023. For 2022, production is expected to be between 54.6 million pounds and 57.2 million pounds U3O8 (100% basis). It also noted that wellfield development, procurement and supply chain challenges, including inflationary pressure on production materials and reagents, are expected to continue throughout 2022. In addition, it indicated its costs could be impacted by potential changes to the tax code in Kazakhstan and by possible local social funding requests.

• |  | On November 19th, KAP announced the approval of a plan to develop JV Budenovskoye LLP. The plan is for production at Budenovskoye Blocks 6 and 7 of up to 6.5 million pounds U3O8 (100% basis) no earlier than 2024, ramping up to 15.6 million pounds U3O8 (100% basis) no earlier than 2026. It is owned 51% by KAP and 49% by Stepnogorsk Mining and Chemical Plant LLP. KAP confirmed that the anticipated ramp up production from 2024-2026 is fully committed for supplying Russia under an offtake contract.

• |  | China General Nuclear Power Group acquired a 49% stake in Ortalyk LLP. This KAP subsidiary holds the Central Mynkuduk in situ recovery (ISR) mine with a capacity of about 5.2 million pounds U3O8 (100% basis) and the planned Zhalpak ISR mine with capacity of about 2 million pounds U3O8 (100% basis).

• |  | Unplanned production disruptions at the Cigar Lake mine and the McClean Lake mill as a precaution due to the COVID-19 pandemic resulted in production for the year being about 6 million pounds (100% basis) below annual licensed capacity. The Cigar Lake mine restarted in mid-April. On July 1 production at the mine was again temporarily suspended as a precaution due to the proximity of a forest fire, but with the risk subsided and all infrastructure intact, operations resumed a short time after.

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

• |  | Supply from the Ranger mine ceased in January, as planned, after 40 years in operation. Ranger had been milling about 4 million pounds U3O8 per year in recent years.

• |  | Orano’s Cominak mine shut in March 2021, as expected, due to depletion of reserves. The mine had been producing about 3 million pounds U3O8 per year in recent years.

• |  | In August, the US DOE published a Request for Information to inform the establishment and procurement strategy of a Strategic Uranium Reserve program. The $75 Million (US) appropriated for the program for 2021 was rolled into 2022.

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LONG-TERM CONTRACTING CREATES FULL-CYCLE VALUE FOR PROVEN PRODUCTIVE ASSETS

Global population is on the rise, and there is a growing focus on electrification and decarbonization. With the world’s need for safe, clean, reliable baseload energy, it is becoming increasingly clear that nuclear power will be an essential part of the clean-energy transition. We remain confident in the future of the nuclear industry. Demand is increasing in the near, medium, and long term with reactor restarts, cancellation of early reactor retirement decisions, life extensions, construction of new reactors, and a growing focus on non-traditional uses of nuclear power.

Like other commodities, the demand for uranium is cyclical. However, unlike other commodities, uranium is not traded in meaningful quantities on a commodity exchange. The uranium market is principally based on bilaterally negotiated long-term contracts covering the annual run-rate requirements of nuclear power plants, with a small spot market to serve discretionary demand. History demonstrates that in general, when prices are rising and high, uranium is perceived as scarce, and a lot of contracting activity takes place with proven and reliable suppliers. The higher prices discovered during this contracting cycle drive investment in higher-cost sources of production, which due to lengthy development timelines, tend to miss the contracting cycle and ramp up after demand has already been captured by proven producers. The new uncommitted supply exposed to the small, discretionary spot market becomes value destructive. The downward pressure on price creates the perception that uranium is abundant, potentially resulting in a failure of long-term price signals. When prices are declining and low, like we have seen over the past number of years, there is no perceived urgency to contract, and contracting activity and investment in new supply drops off. After years of low prices, and a lack of investment in supply, and as the uncommitted material available in the spot market begins to thin, as we are seeing currently, security-of-supply tends to overtake price concerns. Utilities re-enter the long-term contracting market to ensure they have a reliable future supply of uranium to run their reactors.

URANIUM CONTRACTING VOLUMES AND PRICE HISTORY

Source: UxC estimates

UxC reports that over the last five years approximately 400 million pounds U3O8 equivalent have been locked-up in the long-term market, while approximately 810 million pounds U3O8 equivalent have been consumed in reactors. We remain confident that utilities have a growing gap to fill.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 17

UTILITY UNCOVERED REQUIREMENTS

(2021 - 2035)

Source: UxC estimates - December 31, 2021

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

UxC estimates that cumulative uncovered requirements are about 1.4 billion pounds to the end of 2035. With the lack of investment over the past decade due to low uranium prices, there is growing uncertainty about where uranium will come from to satisfy growing demand. In fact, utilities have started to secure supply under long-term contracts, which has resulted in a 22% increase in the long-term price of uranium over the past year.

As utilities’ uncovered requirements continue to grow, primary and secondary supplies decline, and as continued demand for uranium from producers and other intermediaries leads to a thinning of the material available in the spot market, we expect there will be increased competition to secure uranium under long-term contracts on terms that will ensure the availability of reliable primary supply to meet growing demand.

Supply has become less certain as a result of low prices, production curtailments, lack of investment, end of reserve life, unplanned production disruptions, supply chain challenges, shrinking secondary supplies and trade policy issues. As a result, we believe we are starting to see a market transition that is shifting risk from the suppliers to the users of uranium fuel. We will continue to take the actions we believe are necessary to position the company for long-term success. Therefore, we will continue to align our production decisions with market signals and our contract portfolio. We will undertake contracting activity which is intended to ensure we have adequate protection under our contract portfolio, while maintaining exposure to the rewards that come from having uncommitted, low-cost supply to place into a strengthening market.

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Our strategy

We are a pure-play nuclear fuel investment, focused on providing nuclear fuel products across the fuel cycle, on providing a clean source of energy, and 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, and a growing focus on electrification and decarbonization are expected to durably strengthen the long-term fundamentals for our industry. Nuclear energy must be a central part of the solution to the world’s shift to a low-carbon, climate resilient economy. It is an option that can provide the power needed, not only reliably, but also safely and affordably, and in a way that will help avoid some of the worst consequences of climate change.

Our strategy is to capture full-cycle value by:

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

• |  | profitably producing from our tier-one assets and aligning our production decisions with our contract portfolio and market signals

• |  | being financially disciplined to allow us to self-manage risk

• |  | exploring other emerging and non-traditional opportunities within the fuel cycle, which align with our commitment to responsibly and sustainably manage our business and increase our contributions to global climate change solutions

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

URANIUM

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

We are focused on protecting and extending the value of our contract portfolio, on aligning our production decisions with our contract portfolio and market opportunities thereby preserving the value of our lowest cost assets, on maintaining a strong balance sheet, and on efficiently managing the company. We have undertaken a number of deliberate and disciplined actions, including a focus on digitization and automation to allow us to operate our assets with more flexibility. In 2021, these actions resulted in:

• |  | generation of $458 million in cash from operations

• |  | a year-end balance of $1.3 billion in cash and cash equivalents and short-term investments on our balance sheet

• |  | 70 million pounds of uranium added to our long-term contract portfolio since the beginning of 2021

• |  | a more flexible asset base that allows us to continue to align our production with market conditions and our contract portfolio

FUEL SERVICES

Our fuel services division is a source of profit and supports our uranium segment while allowing us to vertically integrate across the fuel cycle.

We are focused on securing new long-term contracts that will allow us to continue to profitably produce and consistently support the long-term needs of our customers.

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

Our focus will continue to be on maintaining and optimizing the profitability of this segment of our business.

OTHER FUEL CYCLE INVESTMENTS

We continue to explore other opportunities within the nuclear fuel cycle. In particular, we are interested in the second largest value driver of the fuel cycle, enrichment. Having operational control of uranium production, conversion, and enrichment facilities would offer operational synergies that could enhance profit margins.

MANAGEMENT’S DISCUSSION AND ANALYSIS 19

In January 2021, we increased our interest in Global Laser Enrichment LLC (GLE) from 24% to 49%. We are the commercial lead for the project and have an option to attain a majority interest of up to 75% ownership. GLE is testing a third-generation enrichment technology that, if successful, will use lasers to:

• |  | re-enrich depleted uranium tails left over as a by-product, aiding in the responsible clean-up of enrichment facilities no longer in operation

• |  | produce high-assay low-enriched uranium (HALEU), the primary fuel stock for the majority of small modular reactors and advanced reactor designs proceeding through development

• |  | produce low-enriched uranium for the world’s existing and future fleet of large-scale light-water reactors

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

Building a balanced portfolio

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

Contracting decisions need to consider the uranium market structure, the nature of our competitors, and the current market environment. The vast majority of run-rate fuel requirements are procured under long-term contracts. The spot market is thinly-traded where utilities pick-up small, discretionary volumes. This market structure is reflective of the baseload nature of nuclear power and the relatively small proportion of the overall operating costs the fuel represents compared to other sources of baseload electricity. Additionally, about half of the fuel supply is not sensitive to market prices and is typically supplied by diversified mining companies that produce uranium as a by-product or state-owned entities with production volume strategies or ambitions to serve state nuclear power ambitions with low-cost fuel supplies. We evaluate our strategy in the context of our market environment and continue to adjust our actions in accordance with our contracting framework:

• |  | First, we will not produce from our tier-one assets to sell into an oversupplied spot market. We will not produce from these assets unless we can deliver our tier-one pounds under long-term contracts that provide an acceptable rate of return.

• |  | Second, we do not intend to build an inventory of excess uranium. Excess inventory serves to contribute to the sense that uranium is abundant and creates an overhang on the market, and it ties up working capital on our balance sheet.

• |  | Third, in addition to our committed sales, we will capture end-user demand in the market where we think we can obtain value. We will take advantage of opportunities the market provides, where it makes sense from an economic, logistical and strategic point of view. Those opportunities may come in the form of spot, mid-term or long-term demand, and will be additive to our current committed sales.

• |  | Fourth, once we capture demand, we will decide how to best source material to satisfy that demand. Depending on the timing and volume of our production, purchase commitments, and our inventory volumes, this means we may be active buyers in the market in order to meet our demand obligations.

• |  | And finally, in general, if we choose to source material to meet demand by purchasing it, we expect the price of that material will be more than offset by the leverage to market prices in our sales portfolio over the long-term.

In addition to this framework, our contracting decisions always factor in who the customer is, our desire for regional diversification, the product form, and logistical factors.

Ultimately, our goal is to protect and extend the value of our contract portfolio on terms that recognize the value of our assets and pricing mechanisms that provide adequate protection when prices go down and allow us to benefit when prices rise. We believe using this framework will allow us to create long-term value. Our focus will continue to be on ensuring we have the financial capacity to execute on our strategy and self-manage risk.

LONG-TERM CONTRACTING

Uranium is not traded in meaningful quantities on a commodity exchange. Utilities have historically bought the majority of their uranium and fuel services products under long-term contracts that are bilaterally negotiated with suppliers, and they have met the rest of their needs on the spot market. We sell uranium and fuel services directly to nuclear utilities around the world as uranium concentrates, UO2 and UF6, conversion services, or fuel fabrication. We have a solid portfolio of long-term sales contracts that reflect the long-term, trusting relationships we have with our customers.

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

We deliver large volumes of uranium every year, therefore our net earnings and operating cash flows are affected by changes in the uranium price. Market prices are influenced by the fundamentals of supply and demand, market access and trade policy issues, geopolitical events, disruptions in planned supply and demand, and other market factors.

The objectives of our contracting strategy are to:

• |  | maximize realized price while providing some certainty for our future earnings and cash flow

• |  | focus on meeting the nuclear industry’s growing annual uncovered requirements with our tier-one production

• |  | establish and grow market share with strategic customers

We have a portfolio of long-term contracts that have a mix of base-escalated pricing and market-related pricing mechanisms, including provisions to protect us when the market price is declining and allow us to benefit when market prices go up. This is a balanced and flexible approach that allows us to adapt to market conditions, put a floor on our average realized price and deliver the best value over the long term.

This approach has allowed us to realize prices higher than the market prices during periods of weak uranium demand, and we expect it will enable us to realize increases linked to higher market prices in the future.

Base-escalated (fixed prices escalated over the term of the contract) contracts for uranium: typically use a pricing mechanism based on a term-price indicator at the time the contract is accepted and escalated over the term of the contract.

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

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

OPTIMIZING OUR CONTRACT PORTFOLIO

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

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

With respect to our existing contracts, at times we may also look for opportunities to optimize the value of our portfolio. In cases where a customer is seeking relief under an existing contract due to a challenging policy, operating, or economic environment, or we deem the customer’s long-term demand to be at risk, we may consider options that are beneficial to us and allow us to maintain our customer relationships.

CONTRACT PORTFOLIO STATUS

We have commitments to sell over 160 million pounds of U3O8 with 34 customers worldwide in our uranium segment, and over 48 million kilograms as UF6 conversion with 30 customers worldwide in our fuel services segment.

MANAGEMENT’S DISCUSSION AND ANALYSIS 21

Customers – U3O8:

Five largest customers account for 59% of commitments

COMMITTED U3O8 SALES BY REGION

Customers – UF6 conversion:

Five largest customers account for 52% of commitments

COMMITTED UF6 SALES BY REGION

MANAGING OUR CONTRACT COMMITMENTS

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

• |  | our existing production

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

• |  | our inventory in excess of our working requirements

• |  | product loans

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

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

• |  | our production volumes

• |  | purchases under existing and/or new arrangements

• |  | discretionary use of inventories

• |  | market opportunities

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Our supply discipline

As spot is not the fundamental market, true value is captured under a long-term contract portfolio and is measured over the full commodity cycle. Therefore, we align our uranium production decisions with our contract commitments and market opportunities to avoid creating an oversupply in a thinly-traded spot market or building an excess inventory. In accordance with market conditions, and to mitigate risk, we evaluate the optimal mix of our production, inventory and purchases in order to satisfy our contractual commitments and in order to return the best value possible over the entire commodity cycle. During a prolonged period of uncertainty, this could mean leaving our uranium in the ground. As a result, since 2016, we have left almost 115 million pounds of uranium in the ground (100% basis) through our supply curtailment activities. We have purchased more than 55 million pounds in the spot market and in 2018 we drew down our inventory by almost 20 million pounds. That totals about 190 million pounds (100% basis) of uranium that we have pulled out of the market.

Today we believe we are in the early stages of a uranium market transition, driven by the growing demand for nuclear energy and the increasingly undeniable conclusion that it must be an essential part of the clean-energy transition. As the market continues to transition, we expect to continue to place our uranium under long-term contracts and to meet rising demand with production from our best margin operations. We will continue to adjust our actions based on market signals and our contract portfolio with the intent of being able to self-manage risk, and to capture long-term value.

With the improvements in the market and the new long-term contracts we have put in place, it is time for us to proceed with the next phase of our supply discipline strategy. Continuing with our indefinite supply discipline, starting in 2024, we plan to be operating at about 40% below productive capacity (100% basis) compared to 75% below productive capacity (100% basis) in 2021. To achieve this, we will begin preparing McArthur River/Key Lake to ensure it is operationally ready to reach our 2024 production plan. A return to production at McArthur River/Key Lake will significantly improve our financial performance by allowing us to source more of our committed sales from the lower-cost produced pounds and we will no longer be required to expense care and maintenance costs directly to cost of sales. However, until we achieve a reasonable production rate, we expect to incur between $15 million to $17 million per month in operational readiness costs, which will be expensed directly to cost of sales. This is not an end to our supply discipline. Over the course of 2022 and 2023, we will undertake all of the activities necessary to ensure we are operationally ready to achieve the 2024 production plan of 15 million pounds (100% basis) per year, 40% below the annual licensed capacity of the operation. Once we reach the planned production at McArthur River/Key Lake, starting in 2024, we plan to reduce production at Cigar Lake to 13.5 million pounds (100% basis) per year, 25% below its annual licensed capacity. Extending the mine life at Cigar Lake by aligning production with the market opportunities and our contract portfolio is consistent with our tier-one strategy and is expected to allow more time to evaluate the feasibility of extending the mine life beyond the current reserve base while continuing to supply ore to Orano’s McClean Lake mill. This will remain our production plan until we see further improvements in the uranium market and contracting progress, once again demonstrating that we are a responsible supplier of uranium fuel.

Managing our costs

PRODUCTION COSTS

In order to operate efficiently and cost-effectively, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology, and business process improvements. Like all mining companies, our uranium segment is affected by the cost of inputs such as labour and fuel.

MANAGEMENT’S DISCUSSION AND ANALYSIS 23

2021 URANIUM OPERATING COSTS BY CATEGORY

* | Production supplies include reagents, fuel and other items. Contracted services include utilities and camp costs, air charters, mining and maintenance contractors and security and ground freight.

Over the last two years the annual cash cost of production at Cigar Lake has been slightly higher than the estimated life of mine cost of between $15 and $16 per pound, as a result of the impacts of COVID-19. See 2021 financial results by segment – Uranium starting on page 49 for more information. In 2022 and 2023, our cash production costs may continue to be affected by the impacts of the COVID-19 pandemic, as well as timing and rate of production at the McArthur River/Key Lake operation. Once we achieve 2024 planned production, the average unit operating costs at Cigar Lake may increase as production declines.

Operating costs in our fuel services segment are mainly fixed. In 2021, labour accounted for about 51% of the total. The largest variable operating cost is for zirconium, followed by anhydrous hydrogen fluoride, and energy (natural gas and electricity).

We are currently undertaking a corporate-wide initiative to accelerate innovation and the adoption of advanced digital and automation technologies to improve efficiency and operational flexibility, and to further reduce cost.

For example, we are implementing energy management information systems to understand where we use energy so we can make changes to become more efficient. We have established a cross-functional working group to further study the transition opportunities and risks to our operations. This working group is analyzing the costs and benefits of various potential projects to achieve transformational reductions in emissions.

CARE AND MAINTENANCE COSTS AND OPERATIONAL READINESS COSTS

In 2022, we expect to incur between $50 million and $60 million in care and maintenance costs related to the suspension of production at our Rabbit Lake mine and mill, and our US operations. These operations are higher-cost, and with plenty of idle tier-one capacity and tier-one expansion capacity globally that can come back online relatively quickly, the restart horizon is less certain. We continue to evaluate our options in order to minimize these costs.

At the McArthur River/Key Lake operation we expect to incur between $15 million and $17 million per month in operational readiness costs which will be expensed directly to cost of sales until we achieve a reasonable production rate.

PURCHASES AND INVENTORY COSTS

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

To meet our delivery commitments, we make use of our mined production, inventories, purchases under long-term contracts, purchases we make on the spot market and product loans. In 2022, the price for the majority of our purchases will be quoted at the time of delivery.

The cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions. The cost of purchased material affects our cost of sales, which is determined by calculating the average of all of our sources of supply, including opening inventory, production, and purchases, and adding royalties, selling costs, and care and maintenance costs. If market prices exceed our cost of inventory, we expect the cost of sales may be impacted.

24 CAMECO CORPORATION

FINANCIAL IMPACT

As greater certainty returns to the uranium market, our view is that uranium prices will need to reflect the cost of bringing on new primary production to meet growing demand.

The deliberate and disciplined actions we have taken to reduce supply and streamline operations have come with near-term costs like care and maintenance costs and purchase costs higher than our production costs, but we believe the benefit over the long term will far outweigh those costs.

We believe our actions have helped position the company to self-manage risk and will reward shareholders for their continued patience and support of our strategy to build long-term value.

Capital allocation – focus on value

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

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

• |  | maintain a strong balance sheet that will allow us to execute on our strategy and mitigate risk

• |  | allow us to sustainably execute on our dividend while considering the cyclical nature of our earnings and cash flow

To deliver value, free cash flow must be productively reinvested in the business or returned to shareholders, which requires good execution and disciplined allocation. Our decisions are based on the run rate of our business, not one-time events. Cash on our balance sheet that exceeds value-adding growth opportunities and/or is not needed to self-manage risk should be returned to shareholders.

We start by determining how much cash we have to invest (investable capital), which is based on our expected cash flow from operations minus expenses we consider to be a higher priority, such as dividends and financing costs, and could include others. This investable capital can be reinvested in the company or returned to shareholders.

REINVESTMENT

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

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

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

RETURN

We believe in returning cash to shareholders but are also focused on protecting the company and rewarding those shareholders who understand and support our strategy to build long-term value. If we have excess cash and determine the best use is to return it to shareholders, we can do that through a share repurchase or dividend—an annual dividend, one-time supplemental dividend or a progressive dividend. When deciding between these options, we consider a number of factors, including the nature of the excess cash (one time or cash generated by our business operations), growth prospects for the company, and growth prospects for the industry.

Share buyback: If we are at our tier-one run rate and are generating excess cash while there were few or no growth prospects for the company or the industry, then a share buyback might make sense. However, our current view is that the long-term fundamentals for Cameco and the industry remain strong.

Dividend: The amount and type of dividend paid, annual, progressive or one-time supplemental is evaluated by our board of directors with careful consideration of our cash flow, financial position, strategy, and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

MANAGEMENT’S DISCUSSION AND ANALYSIS 25

IN ACTION

Until such time as we return to our tier-one cost structure, the objective of our capital allocation will be to ensure we have the financial capacity to execute on our strategy, while navigating by our investment-grade rating through close management of our balance sheet metrics.

In today’s transitioning uranium market environment, we are taking a cautious and prudent approach to capital allocation. We are not yet at our tier-one run-rate, and, despite rulings from the courts in our favour, our dispute with CRA continues. With the metrics that inform an investment-grade rating in mind, we have taken steps to allow us to deliver long-term value and self-manage risk by:

• |  | responsibly managing our sources of supply by aligning our production decisions with market conditions and our contract portfolio, and building a more flexible tier-one asset base

• |  | exercising strategic patience when contracting

• |  | restructuring our activities to reduce our operating, capital, and general and administrative spending

• |  | reducing our total debt and restructuring our debt maturity profile

• |  | aligning our dividend with the run-rate of our business and with consideration for the cyclical nature of our earnings and cash flow

• |  | focusing on technology and its applications to improve efficiency and reduce costs across the organization, with a particular focus on innovation and accelerating the adoption of advanced digital and automation technologies

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

If we get clarity on our CRA dispute without a continued and sustained market transition, which generates a one-time cash infusion, we may focus on the debt portion of our ratings metrics. This may mean greater emphasis on reducing the debt on our balance sheet. However, if the market continues to transition and higher uranium prices are flowing through our contract portfolio, and we are able to increase our portfolio of long-term contracts with acceptable pricing mechanisms, the earnings portion of our rating metrics are expected to improve. In that scenario, reducing debt would not be the priority. Our priorities would be to invest in ramping up and expanding production at our tier-one assets, and if warranted leveraging our existing tier-two assets and brownfield infrastructure, turning to value-adding growth opportunities including further vertical integration and returning excess cash to shareholders.

SHARES AND STOCK OPTIONS OUTSTANDING

At February 7, 2022, we had:

• |  | 398,289,260 common shares and one Class B share outstanding

• |  | 3,228,006 stock options outstanding, with exercise prices ranging from $11.32 to $26.81

DIVIDEND

In 2021, our board of directors declared a dividend of $0.08 per common share, which was paid December 15, 2021.

As a result of our deliberate actions and conservative financial management we have been and continue to be resilient. With a strong balance sheet, improving fundamentals for our business, a growing contract portfolio, and our decision to prepare McArthur River/Key Lake to be operationally ready, we have line of sight to a significant improvement in our future earnings and cash flow. Therefore, we are increasing our 2022 annual dividend by 50%.

An annual dividend of $0.12 per common share has been declared, payable on December 15, 2022 to shareholders of record on November 30, 2022. The decision to declare an annual dividend by our board is reviewed regularly and will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

26 CAMECO CORPORATION

Our ESG principles and practices: A key part of our strategy, reflecting our values

We are committed to delivering our products responsibly. We integrate environmental, social and governance (ESG) principles and practices into every aspect of our business, from our objectives and approach to compensation, to our overall corporate strategy and day-to-day operations. 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 add long-term value. We recognize the importance of integrating certain ESG factors, such as safety performance, a clean environment and supportive communities, into our executive compensation strategy as we see success in these areas as critical to the long-term success of the company.

Our 2020 ESG report, published in October of 2021, marked an evolution in our sustainability reporting. We adopted the relevant ESG performance indicators issued by the Sustainability Accounting Standards Board (SASB) and have taken the first steps towards addressing the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD), which we expect to continue to progress. The report sets out our strategy and the policies and programs we use to govern and manage ESG issues that are important to our stakeholders. In addition to SASB and TCFD, the report provides key ESG performance indicator data based on the Global Reporting Initiative’s Sustainability Framework as well as some unique corporate indicators, to measure and report our performance on environmental, social and economic impacts in the areas we believe have a significant impact on our sustainability in the long-term. This is our ESG report card to our stakeholders. You can find our report at cameco.com/about/sustainability.

Environment

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

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

Climate change: Nuclear power is part of the solution

We believe the reduction of carbon and greenhouse gas (GHG) emissions is important and necessary in Canada and around the world, and that nuclear power must be a central part of the solution to the world’s shift to a low-carbon, climate-resilient economy. As one of the world’s largest producers of the uranium needed to fuel nuclear reactors, we believe there is a significant opportunity for us to be part of the solution to combat climate change. We are a constructive partner in the battle against climate change. We enable vast emissions reductions that can be achieved through nuclear power and are committed to transforming our own low GHG emissions footprint in our ambition to reach net-zero emissions while delivering significant long-term business value.

We recognize that climate change, including shifts in temperature, precipitation and more frequent severe weather events could affect our operations in a range of possible ways. We have established a working group composed of representatives from across the organization to further study the climate-related opportunities and risks for our business. For example, this working group has conducted a preliminary analysis of the increase in operating costs that could occur at our Canadian facilities (in the short-, medium-, and long-term) as a result of increased GHG pricing and regulation. In addition, in 2022, we are undertaking a physical climate risk assessment with a third-party expert.

Social

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 27

Our response to the COVID-19 pandemic

We continue to closely monitor and adapt to the developments related to the outbreak of COVID-19. Throughout the pandemic, our priority has been to protect the health and well-being of our workers, including employees and contractors, their families, and their communities. Early in 2020, we activated our Corporate Crisis Management Plan, which includes our Pandemic Plan, and our various Local and Corporate Business Continuity Plans.

Following the precautions and restrictions enacted by all levels of government where we operate, and, considering the unique circumstances at each of our operating sites, we proactively implemented a number of measures and made a number of decisions to ensure a safe working environment for all our workers. In addition to all the safety protocols and measures put in place in 2020, in 2021 we:

• |  | suspended production at Cigar Lake for a second time for about four months starting in December 2020

• |  | introduced a requirement that all employees, contractors and visitors be vaccinated across all our operations and offices

• |  | developed a hybrid work model for employees working from home that balances time in the office and remote working in accordance with business needs

The proactive decisions we have made, and continue to make, to protect our workers and to help slow down the spread of the COVID-19 virus are necessary decisions that are consistent with our values. Even while production was suspended, we kept and continued to pay all our employees. The health and safety of our workers, their families and their communities continues to be the priority in all our plans, which will align with the guidance of the relevant health authorities where we operate.

Governance: Sound governance is the foundation for strong performance

We believe that sound governance is the foundation for strong corporate performance. Our diverse and independent board of directors plays an important role in providing oversight of the management team and providing direction for our strategy and business affairs, including the integration of ESG principles throughout the company. The board guides the company to operate as a sustainable business, to optimize financial returns while effectively managing risk, and to conduct business in a way that is transparent, independent, and ethical.

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

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

OUR VISION

Our vision – “Energizing a clean-air world” – recognizes that we have an important role to play in enabling the vast reductions in global greenhouse gas emissions required to achieve a resilient net-zero carbon economy. We support climate action that is consistent with the ambition of the Paris Agreement and the Canadian government’s commitment to the agreement to limit global temperature rise to less than 2°C and we know that this means the world needs to reach net-zero emissions by 2050 or sooner. The uranium we produce is used around the world in the generation of safe, carbon-free, affordable, base-load nuclear power. As we seek to achieve our vision, we will do so in a manner that reflects our values. We believe we have the right strategy to achieve our vision and are committed to our efforts to transform our own, already low, greenhouse gas footprint in our ambition to reach net-zero emissions, while identifying and addressing the ESG risks and opportunities that we believe may have a significant impact on our ability to add long-term value for our stakeholders.

COMMITTED TO OUR VALUES

Our values are discussed below and are at the core of everything we do and define who we are as a company. They are:

• |  | safety and environment

• |  | people

28 CAMECO CORPORATION

• |  | integrity

• |  | excellence

Safety and Environment

The safety of people and protection of the environment are the foundations of our work. All of us share in the responsibility of continually improving the safety of our workplace and the quality of our environment.

We are committed to keeping people safe and conducting our business with respect and care for both the local and global environment.

People

We value the contribution of every employee and we treat people fairly by demonstrating our respect for individual dignity, creativity and cultural diversity. By being open and honest, we achieve the strong relationships we seek.

We are committed to developing and supporting a flexible, skilled, stable and diverse workforce, in an environment that:

• |  | attracts and retains talented people and inspires them to be fully productive and engaged

• |  | encourages relationships that build the trust, credibility and support we need to grow our business

Integrity

Through personal and professional integrity, we lead by example, earn trust, honour our commitments and conduct our business ethically.

We are committed to acting with integrity in every area of our business, wherever we operate.

Excellence

We pursue excellence in all that we do. Through leadership, collaboration and innovation, we strive to achieve our full potential and inspire others to reach theirs.

Risk and Risk Management

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

Our Risk Management Program involves a broad, systematic approach to identifying, assessing, monitoring, reporting and managing the significant risks we face in our business and operations, including consideration of ESG and climate-related risks that could impact our four measures of success. The program establishes clear accountabilities for employees throughout the company to take ownership of risks specific to their area and to effectively manage those risks. The program is reviewed annually to ensure that it continues to meet our needs.

We use a common risk matrix throughout the company. Any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan is considered an enterprise risk and is brought to the attention of senior management and the board.

See Managing the risks, starting on page 58, for a discussion of the risks, that generally apply to all of our operations and advanced uranium projects, and that could have a material impact on business in the near term. We also recommend you review our most recent annual information form, which includes a discussion of other material risks that could have an impact on our business.

MANAGEMENT’S DISCUSSION AND ANALYSIS 29

Measuring our results

TARGETS AND METRICS: THE LINK BETWEEN ESG FACTORS AND EXECUTIVE PAY

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

Our targets for 2021 continue to reflect the operational strategic actions that we are taking. As such, we do not believe our financial performance (earnings and cash flow) reflects our long-term run rate performance. Despite the impact on financial results, we believe that the strategic actions we are taking will help to pave the way to stronger financial performance over time, and we will not compromise our commitment to safety, people and our environment.

2021 OBJECTIVES1 |  | TARGET |  | RESULTS
OUTSTANDING FINANCIAL PERFORMANCE
Earnings measure |  | Achieve targeted adjusted net earnings. |  | •   adjusted net earnings was below target
Cash flow measure |  | Achieve targeted cash flow from operations (before working capital changes). |  | •   cash flow from operations was slightly below target
SAFE, HEALTHY AND REWARDING WORKPLACE
Workplace safety measure |  | Strive for no injuries at all Cameco-operated sites. Maintain a long-term downward trend in combined employee and contractor total recordable injury rate while achieving targets on specified leading indicators. |  | •   a new performance record was set for the fourth year in a row. TRIR improved significantly by about 25% relative to 2020, exceeding the 2021 improvement target •   performance of the leading indicators exceeded the targets
CLEAN ENVIRONMENT
Environmental performance measures |  | Achieve divisional environmental aspect improvement targets. |  | •   performance was within the targeted range •   there were no significant environmental incidents in 2021
SUPPORTIVE COMMUNITIES
Stakeholder support measure |  | Enhance the skill set of Residents of Saskatchewan’s North for changing industrial environments |  | •   performance exceeded the target

1 | Detailed results for our 2021 corporate objectives and the related targets will be provided in our 2022 management proxy circular prior to our Annual Meeting of Shareholders on May 10, 2022.

2022 objectives

OUTSTANDING FINANCIAL PERFORMANCE
•   Achieve targeted financial measures focused on controlling costs and generating cash.
SAFE, HEALTHY AND REWARDING WORKPLACE
•   Improve workplace safety performance at all sites.
CLEAN ENVIRONMENT
•   Improve environmental performance at all sites.
SUPPORTIVE COMMUNITIES
•   Build and sustain strong stakeholder support for our activities.

30 CAMECO CORPORATION

Financial results

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

32 |  | 2021 CONSOLIDATED FINANCIAL RESULTS
41 |  | OUTLOOK FOR 2022
43 |  | LIQUIDITY AND CAPITAL RESOURCES
49 |  | 2021 FINANCIAL RESULTS BY SEGMENT
49 |  | URANIUM
51 |  | FUEL SERVICES
52 |  | FOURTH QUARTER FINANCIAL RESULTS
52 |  | CONSOLIDATED RESULTS
55 |  | URANIUM
56 |  | FUEL SERVICES

MANAGEMENT’S DISCUSSION AND ANALYSIS 31

2021 consolidated financial results

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

In the third quarter, we determined that NUKEM no longer meets the criteria for being considered a segment and concluded that it was appropriate to include NUKEM’s results with our uranium and fuel services segments. The purchase and sale of enriched uranium product and separative work units will continue to be reported in “other”. Comparative information has been adjusted. See note 28 for more information.

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2021 |  |  | 2020 |  |  | 2019 |  |  | CHANGE FROM 2020 TO 2021 |
Revenue |  |  | 1,475 |  |  |  | 1,800 |  |  |  | 1,863 |  |  |  | (18 | )%
Gross profit |  |  | 2 |  |  |  | 106 |  |  |  | 242 |  |  |  | (98 | )%
Net earnings (loss) attributable to equity holders |  |  | (103 | ) |  |  | (53 | ) |  |  | 74 |  |  |  | (94 | )%
$ per common share (basic) |  |  | (0.26 | ) |  |  | (0.13 | ) |  |  | 0.19 |  |  |  | (92 | )%
$ per common share (diluted) |  |  | (0.26 | ) |  |  | (0.13 | ) |  |  | 0.19 |  |  |  | (92 | )%
Adjusted net earnings (loss) (non-IFRS, see page 33) |  |  | (98 | ) |  |  | (66 | ) |  |  | 41 |  |  |  | (48 | )%
$ per common share (adjusted and diluted) |  |  | (0.25 | ) |  |  | (0.17 | ) |  |  | 0.10 |  |  |  | (47 | )%
Cash provided by operations |  |  | 458 |  |  |  | 57 |  |  |  | 527 |  |  |  | >100 | %

Net earnings

The following table shows what contributed to the change in net earnings in 2021 compared to 2020 and 2019.

($ MILLIONS) |  | 2021 |  |  | 2020 |  |  | 2019 |
Net earnings (losses) - previous year |  |  | (53 | ) |  |  | 74 |  |  |  | 166 |
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 |  | Lower sales volume |  |  | (4 | ) |  |  | (4 | ) |  |  | (27 | )
|  | Higher (lower) realized prices ($US) |  |  | 5 |  |  |  | 25 |  |  |  | (133 | )
|  | Foreign exchange impact on realized prices |  |  | (72 | ) |  |  | 14 |  |  |  | 35 |
|  | Lower (higher) costs |  |  | (55 | ) |  |  | (169 | ) |  |  | 9 |
|  | change – uranium |  |  | (126 | ) |  |  | (134 | ) |  |  | (116 | )
Fuel services |  | Higher (lower) sales volume |  |  | 1 |  |  |  | (4 | ) |  |  | 13 |
|  | Higher (lower) realized prices ($Cdn) |  |  | 23 |  |  |  | 21 |  |  |  | (11 | )
|  | Lower (higher) costs |  |  | (2 | ) |  |  | (10 | ) |  |  | 28 |
|  | change – fuel services |  |  | 22 |  |  |  | 7 |  |  |  | 30 |
Other changes |  |  |  |  |  |  |  |  |  |  |  |
Lower (higher) administration expenditures |  |  | 17 |  |  |  | (20 | ) |  |  | 17 |
Lower exploration expenditures |  |  | 3 |  |  |  | 3 |  |  |  | 6 |
Change in reclamation provisions |  |  | 32 |  |  |  | (21 | ) |  |  | 57 |
Change in gains or losses on derivatives |  |  | (24 | ) |  |  | 5 |  |  |  | 113 |
Change in foreign exchange gains or losses |  |  | (14 | ) |  |  | 33 |  |  |  | (45 | )
Change in earnings from equity-accounted investments |  |  | 32 |  |  |  | (9 | ) |  |  | 13 |
Redemption of Series E debentures in 2020 |  |  | 24 |  |  |  | (24 | ) |  |  | — |
Canadian Emergency Wage Subsidy |  |  | (16 | ) |  |  | 37 |  |  |  | — |
Arbitration award in 2019 related to TEPCO contract |  |  | — |  |  |  | (52 | ) |  |  | 52 |
Gain on sale of interest in Wheeler River Joint Venture in 2018 |  |  | — |  |  |  | — |  |  |  | (17 | )
Gain on restructuring of JV Inkai in 2018 |  |  | — |  |  |  | — |  |  |  | (49 | )
Gain on customer contract restructuring in 2018 |  |  | — |  |  |  | — |  |  |  | (6 | )
Sale of exploration properties in 2018 |  |  | — |  |  |  | — |  |  |  | (7 | )
Reversal of tax provision in 2018 related to CRA dispute |  |  | — |  |  |  | — |  |  |  | (61 | )
Change in income tax recovery or expense |  |  | 15 |  |  |  | 47 |  |  |  | (126 | )
Other |  |  | (15 | ) |  |  | 1 |  |  |  | 47 |
Net earnings (losses) - current year |  |  | (103 | ) |  |  | (53 | ) |  |  | 74 |

32 CAMECO CORPORATION

Non-IFRS measures

ADJUSTED NET EARNINGS

Adjusted net earnings (ANE) is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS financial measure). We use this measure as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is one of the targets that we measure to form the basis for a portion of annual employee and executive compensation (see Measuring our results starting on page 30).

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 39 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 15 of our annual financial statements for more information. This amount has been excluded from our ANE measure.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 33

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2021, 2020 and 2019.

($ MILLIONS) |  | 2021 |  |  | 2020 |  |  | 2019 |
Net earnings (loss) attributable to equity holders |  |  | (103 | ) |  |  | (53 | ) |  |  | 74 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | 13 |  |  |  | (45 | ) |  |  | (49 | )
Adjustments on other operating expense (income) |  |  | (8 | ) |  |  | 24 |  |  |  | 3 |
Income taxes on adjustments |  |  | — |  |  |  | 8 |  |  |  | 13 |
Adjusted net earnings (loss) |  |  | (98 | ) |  |  | (66 | ) |  |  | 41 |

The following table shows what contributed to the change in adjusted net earnings (non-IFRS measure, see above) in 2021 compared to the same period in 2020 and 2019.

($ MILLIONS) |  | 2021 |  |  | 2020 |  |  | 2019 |
Adjusted net earnings (losses) - previous year |  |  | (66 | ) |  |  | 41 |  |  |  | 211 |
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 |  | Lower sales volume |  |  | (4 | ) |  |  | (4 | ) |  |  | (27 | )
|  | Higher (lower) realized prices ($US) |  |  | 5 |  |  |  | 25 |  |  |  | (133 | )
|  | Foreign exchange impact on realized prices |  |  | (72 | ) |  |  | 14 |  |  |  | 35 |
|  | Lower (higher) costs |  |  | (55 | ) |  |  | (169 | ) |  |  | 9 |
|  | change – uranium |  |  | (126 | ) |  |  | (134 | ) |  |  | (116 | )
Fuel services |  | Higher (lower) sales volume |  |  | 1 |  |  |  | (4 | ) |  |  | 13 |
|  | Higher (lower) realized prices ($Cdn) |  |  | 23 |  |  |  | 21 |  |  |  | (11 | )
|  | Lower (higher) costs |  |  | (2 | ) |  |  | (10 | ) |  |  | 28 |
|  | change – fuel services |  |  | 22 |  |  |  | 7 |  |  |  | 30 |
Other changes |  |  |  |  |  |  |  |  |  |  |  |
Lower (higher) administration expenditures |  |  | 17 |  |  |  | (20 | ) |  |  | 17 |
Lower (higher) exploration expenditures |  |  | 3 |  |  |  | 3 |  |  |  | 6 |
Change in gains or losses on derivatives |  |  | 34 |  |  |  | 9 |  |  |  | (1 | )
Change in foreign exchange gains or losses |  |  | (14 | ) |  |  | 33 |  |  |  | (45 | )
Change in earnings from equity-accounted investments |  |  | 32 |  |  |  | (9 | ) |  |  | 13 |
Redemption of Series E debentures in 2020 |  |  | 24 |  |  |  | (24 | ) |  |  | — |
Canadian Emergency Wage Subsidy |  |  | (16 | ) |  |  | 37 |  |  |  | — |
Arbitration award in 2019 related to TEPCO contract |  |  | — |  |  |  | (52 | ) |  |  | 52 |
Gain on sale of interest in Wheeler River Joint Venture in 2018 |  |  | — |  |  |  | — |  |  |  | (17 | )
Gain on customer contract restructuring in 2018 |  |  | — |  |  |  | — |  |  |  | (6 | )
Sale of exploration properties in 2018 |  |  | — |  |  |  | — |  |  |  | (7 | )
Reversal of tax provision in 2018 related to CRA dispute |  |  | — |  |  |  | — |  |  |  | (61 | )
Change in income tax recovery or expense |  |  | 7 |  |  |  | 42 |  |  |  | (82 | )
Other |  |  | (15 | ) |  |  | 1 |  |  |  | 47 |
Adjusted net earnings (losses) - current year |  |  | (98 | ) |  |  | (66 | ) |  |  | 41 |

Average realized prices

|  |  |  | 2021 |  |  | 2020 |  |  | 2019 |  |  | CHANGE FROM 2020 TO 2021 |
Uranium1 |  | $US/lb |  |  | 34.53 |  |  |  | 34.39 |  |  |  | 33.77 |  |  |  | — |
|  | $Cdn/lb |  |  | 43.34 |  |  |  | 46.13 |  |  |  | 44.85 |  |  |  | (6 | )%
Fuel services |  | $Cdn/kgU |  |  | 29.72 |  |  |  | 27.89 |  |  |  | 26.21 |  |  |  | 7 | %

1 | Average realized foreign exchange rate ($US/$Cdn): 2021 – 1.26, 2020 – 1.34 and 2019 – 1.33.

34 CAMECO CORPORATION

Revenue

The following table shows what contributed to the change in revenue for 2021.

($ MILLIONS) |  |  |
Revenue – 2020 |  |  | 1,800 |
Uranium |  |  |  |
Lower sales volume |  |  | (293 | )
Lower realized prices ($Cdn) |  |  | (68 | )
Fuel services |  |  |  |
Higher sales volume |  |  | 2 |
Higher realized prices ($Cdn) |  |  | 25 |
Other |  |  | 9 |
Revenue – 2021 |  |  | 1,475 |

See 2021 Financial results by segment on page 49 for more detailed discussion.

THREE-YEAR TREND

In 2020, revenue decreased by 3% compared to 2019 due to a decrease in sales volume in the uranium segment that was partially offset by an increase in the Canadian dollar average realized price. In our fuel services segment, revenue increased by 2% as a result of the increase in average realized price partially offset by a decrease in sales volume.

In 2021, revenue decreased by 18% compared to 2020 due to a decrease in sales volume in the uranium segment and a decrease in the Canadian dollar average realized price. In our fuel services segment, revenue increased by 10% as a result of the increase in average realized price and sales volume. See notes 17 and 28 in our annual financial statements for more information.

SALES DELIVERY OUTLOOK FOR 2022

For 2022 we have committed sales volumes in our uranium segment of between 23 to 25 million pounds. We will continue to be active buying and selling uranium in the spot market if it makes sense for us.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly. We expect the quarterly distribution of uranium deliveries in 2022 to be fairly evenly distributed as shown below. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.

ANNUAL DELIVERY VOLUME DISTRIBUTION BY QUARTER

Source: Cameco reports and estimates

MANAGEMENT’S DISCUSSION AND ANALYSIS 35

Corporate expenses

ADMINISTRATION

($ MILLIONS) |  | 2021 |  |  | 2020 |  |  | CHANGE |
Direct administration1 |  |  | 111 |  |  |  | 113 |  |  |  | (2 | )%
Stock-based compensation1 |  |  | 44 |  |  |  | 32 |  |  |  | 38 | %
Recovery of fees related to CRA dispute |  |  | (27 | ) |  |  | — |  |  |  | n/a |
Total administration |  |  | 128 |  |  |  | 145 |  |  |  | (12 | )%

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

Direct administration costs in 2021 decreased by $2 million from 2020. As a result of the Supreme Court’s dismissal of CRA’s application for leave to appeal the June 26, 2020 decision of the Court of Appeal, we recorded $27 million as a reduction to administration costs to reflect the amounts owing to us for legal fees and disbursements for costs as was awarded to us by the Tax Court and nominal cost awards related to the Court of Appeal hearing and Supreme Court application.

We recorded $44 million in stock-based compensation expenses in 2021, $12 million higher compared to 2020 due to the increase in our share price. See note 24 to the financial statements.

Administration outlook for 2022

We expect direct administration costs to be between $125 million to $135 million.

EXPLORATION

Our 2021 exploration activities were focused primarily on Canada. Our spending decreased from $11 million in 2020 to $8 million in 2021 due to lower planned expenditures.

Exploration outlook for 2022

We expect exploration expenses to be about $11 million in 2022. The focus for 2022 will be on our core projects in Saskatchewan.

FINANCE COSTS

Finance costs were $77 million, a decrease from $96 million in 2020 due to the cost associated with the early redemption of our Series E debentures in 2020. See note 19 to the financial statements.

FINANCE INCOME

Finance income was $7 million compared to $11 million in 2020 mainly due to lower interest rates.

GAINS AND LOSSES ON DERIVATIVES

In 2021, we recorded $13 million in gains on our derivatives compared to $37 million in gains in 2020. The decrease reflects the strength in the Canadian dollar compared to the US dollar at the end of 2021 compared to 2020. See Foreign exchange on page 39 and note 26 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $1 million in 2021 compared to an expense of $14 million in 2020. The increase in recovery was primarily due to a change in the distribution of earnings among jurisdictions compared to 2020.

In 2021, we recorded earnings of $59 million in Canada compared to earnings of $73 million in 2020, while in foreign jurisdictions, we recorded a loss of $162 million compared to a loss of $112 million in 2020. Differences between accounting income and income for tax purposes resulted in lower taxes recorded in Canada.

36 CAMECO CORPORATION

($ MILLIONS) |  | 2021 |  |  | 2020 |
Net earnings (loss) before income taxes |  |  |  |  |  |  |  |
Canada |  |  | 59 |  |  |  | 73 |
Foreign |  |  | (162 | ) |  |  | (112 | )
Total net loss before income taxes |  |  | (103 | ) |  |  | (39 | )
Income tax expense (recovery) |  |  |  |  |  |  |  |
Canada |  |  | (2 | ) |  |  | 9 |
Foreign |  |  | 1 |  |  |  | 5 |
Total income tax expense (recovery) |  |  | (1 | ) |  |  | 14 |
Effective tax rate |  |  | 1 | % |  |  | (36 | )%

TRANSFER PRICING DISPUTE

Background

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

For the years 2003 to 2014, CRA shifted Cameco Europe Limited’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2011, transfer pricing penalties. In addition, for 2014 and 2015, CRA has advanced an alternate reassessing position, see Reassessments, remittance and next steps below for more information.

In September 2018, the 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 Court of Appeal upheld the Tax Court’s decision.

Supreme Court of Canada decision

On February 18, 2021, the 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 total tax reassessed for the three tax years was $11 million, and we remitted 50%. The Minister of National Revenue has issued new reassessments for the 2003 through 2006 tax years in accordance with the decision and in July we received payments totaling $9 million, representing the refund of the $5.5 million we remitted plus interest.

On April 20, 2021, we received $10 million from CRA, which includes payment of the legal fees awarded by the Tax Court as well as the cost awards related to the Court of Appeal and Supreme Court decisions.

In addition to the cost award for legal fees, in 2019, the Tax Court awarded us an amount for disbursements of up to $17 million. The actual amount of the award for disbursements will be determined by an officer of the Tax Court. We expect to recover all, or substantially all, of the $17 million in disbursements.

We anticipate further direction on our award for disbursements from the Tax Court in the first quarter of this year.

Reassessments, remittances and next steps

The Canadian income tax rules include provisions that generally require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. While we have received a refund for the amounts remitted for the 2003 through 2006 reassessments as noted above, CRA continues to hold $777 million ($295 million in cash and $482 million in letters of credit) we paid or secured for the years 2007 through 2013. For the 2014 and 2015 reassessments, CRA did not require additional security to secure the tax debts they considered owing.

MANAGEMENT’S DISCUSSION AND ANALYSIS 37

Following the Supreme Court’s dismissal of CRA’s application for leave to appeal, we wrote to CRA requesting reversal of CRA’s transfer pricing adjustments for 2007 through 2013 and the return of our $777 million in cash and letters of credit. Given the strength of the court decisions received, our request was made on the basis that the Tax Court would reject any attempt by CRA to defend its reassessments for the 2007 through 2013 tax years applying the same or similar positions already denied for previous years. Due to a lack of significant progress in response to our request, in October 2021, we filed a notice of appeal with the Tax Court for the years 2007 through 2013. We are asking the Tax Court to order the reversal of the CRA’s transfer pricing adjustment for those years and the return of our cash and letters of credit, with costs.

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. In late 2021, we received a reassessment for the 2015 tax year 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 or 2015 filing positions.

We will not be in a position to determine the definitive outcome of this dispute for any tax year other than 2003 through 2006 until such time as all reassessments have been issued advancing CRA’s arguments and final resolution is reached for that tax year. CRA may also advance alternative reassessment methodologies for years other than 2003 through 2006, such as the alternative reassessing position advanced for 2014 and 2015.

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

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

Assumptions

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

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

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

Material risks that could cause actual results to differ materially

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

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

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

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

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

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

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

Tax outlook for 2022

Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. We have a global customer base and we have established a marketing and trading structure involving foreign subsidiaries, which entered into various intercompany purchase and sale arrangements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s-length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts between arm’s-length parties entered into at that time. In 2017, we changed our global marketing organization to consolidate our international activities in Canada in order to achieve efficiencies. The existing purchase and sale arrangements will continue to be in place until they expire. As the existing contracts expire, we anticipate that more income will be earned in Canada.

38 CAMECO CORPORATION

We continue to expect our consolidated tax rate will trend toward the Canadian statutory rate in the longer term. The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and the market conditions at the time transactions occur under both our intercompany and third-party purchase and sale arrangements.

FOREIGN EXCHANGE

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

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

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

Impact of hedging on IFRS earnings

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

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

Impact of hedging on ANE

We designate contracts for use in particular periods, based on our expected net exposure in that period. Hedge contracts are layered in over time based on this expected net exposure. The result is that our current hedge portfolio is made up of a number of contracts which are currently designated to net exposures we expect in 2022 and future years and we will recognize the gains or losses in ANE in those periods.

For the purposes of ANE, gains and losses on derivatives are reported based on the difference between the effective hedge rate of the contracts designated for use in the particular period and the exchange rate at the time of settlement. This results in an adjustment to current period IFRS earnings to effectively remove reported gains or losses on derivatives that arise from contracts put in place for use in future periods. The effective hedge rate will lag the market in periods of rapid currency movement. See Non-IFRS measures on page 33.

The table below provides a summary of our hedge portfolio at December 31, 2021. You can use this information to estimate the expected gains or losses on derivatives for 2022 on an ANE basis. However, if we add contracts to the portfolio that are designated for use in 2022 or if there are changes in the US/Cdn exchange rates in the year, those expected gains or losses could change.

MANAGEMENT’S DISCUSSION AND ANALYSIS 39

HEDGE PORTFOLIO SUMMARY

DECEMBER 31, 2021 ($ MILLIONS) |  |  |  | 2022 |  |  | AFTER 2022 |  |  | TOTAL |
US dollar forward contracts |  | ($ millions) |  |  | 210 |  |  |  | 330 |  |  |  | 540 |
Average contract rate 1 |  | (US/Cdn dollar) |  |  | 1.34 |  |  |  | 1.28 |  |  |  | 1.30 |
US dollar option contracts |  | ($ millions) |  |  | 120 |  |  |  | 70 |  |  |  | 190 |
Average contract rate range1 |  | (US/Cdn dollar) |  |  | 1.32 to 1.36 |  |  |  | 1.30 to 1.34 |  |  |  | 1.31 to 1.36 |
Total US dollar hedge contracts |  | ($ millions) |  |  | 330 |  |  |  | 400 |  |  |  | 730 |
Average hedge rate range |  | (US/Cdn dollar) |  |  | 1.33 to 1.35 |  |  |  | 1.28 to 1.30 |  |  |  | 1.31 to 1.33 |
Hedge ratio2 |  |  |  |  | 51 | % |  |  | 9 | % |  |  | 14 | %

1 | The average contract rate is the weighted average of the rates stipulated in the outstanding contracts.

2 | Hedge ratio is calculated by dividing the amount (in foreign currency) of outstanding derivative contracts by estimated future net exposures.

At December 31, 2021:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.26 (Cdn), down from $1.00 (US) for $1.27 (Cdn) at December 31, 2020. The exchange rate averaged $1.00 (US) for $1.25 (Cdn) over the year.

• |  | The mark-to-market position on all foreign exchange contracts was a $28 million gain compared to a $41 million gain at December 31, 2020. The mark-to-market position is a component of gain on derivatives as shown on the statement of earnings and calculated in accordance with IFRS.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2021, all of our hedging counterparties had a Standard & Poor’s (S&P) credit rating of A or better.

For information on the impact of foreign exchange on our intercompany balances, see note 26 to the financial statements.

40 CAMECO CORPORATION

Outlook for 2022

Our outlook for 2022 reflects the expenditures necessary to help us achieve our strategy, including the ramp-up to planned production of 15 million pounds per year (100% basis) at McArthur River/Key Lake by 2024. As in prior years, we will incur care and maintenance costs for the ongoing outage at our tier-two assets, which are expected to be between $50 million and $60 million. We also expect to incur between $15 million and $17 million per month at McArthur River/Key Lake in operational readiness costs which will be expensed directly to cost of sales until we achieve a reasonable production rate.

The production outlook reflects the expected impact of the delays and deferrals to development work at Cigar Lake in 2021 and the ongoing pandemic and supply chain challenges we are currently experiencing at all our operations. We will work to mitigate and minimize any disruptions to our operations.

We expect our business to remain resilient. From a cash perspective, we expect to continue to maintain a significant cash balance. We expect to continue to generate cash from operations. The amount of cash generated will be dependent on the timing and volume of production at McArthur River, and the extent to which COVID-related disruptions including supply chain challenges impact our operations and the resulting magnitude of our purchasing activity. Therefore, our cash balances may fluctuate throughout the year.

See 2021 Financial results by segment on page 49 for details.

2021 outlook compared to actual

Our actual results were largely in-line with the outlook provided in our third quarter MD&A. In 2021 we started the year with Cigar Lake suspended due to the uncertainty created by the COVID-19 pandemic. Based on the restart of the Cigar Lake mine in April, we set a production target for Cigar Lake of up to 6 million pounds (our share). We achieved 6.1 million pounds production at Cigar Lake in 2021.

Capital expenditures for 2021 were $99 million, lower than our outlook of $130 to $155 million, as a result of the deferral of project work to 2022.

2022 FINANCIAL OUTLOOK

|  | CONSOLIDATED |  | URANIUM |  | FUEL SERVICES
Production (owned and operated properties) |  | — |  | up to 11 million lbs |  | 12.5 to 13.5 million kgU
Purchases |  | — |  | 11 to 13 million lbs |  | —
Sales/delivery volume |  | — |  | 23 to 25 million lbs |  | 10.5 to 11.5 million kgU
Revenue |  | $1,500 to 1,650 million |  | $1,150 to 1,240 million |  | $340-370 million
Average realized price |  | — |  | $50.90/lb |  | —
Average unit cost of sales (including D&A) |  | — |  | $50.00-51.00/lb 1 |  | $21.50-22.50/kgU 2
Direct administration costs |  | $125-135 million |  | — |  | —
Exploration costs |  | — |  | $11 million |  | —
Capital expenditures |  | $150-175 million |  | — |  | —

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

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

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

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

• |  | Production – we achieve 11 million pounds of production (our share) in our uranium segment. If we do not achieve 11 million pounds, the outlook for the uranium segment could vary.

MANAGEMENT’S DISCUSSION AND ANALYSIS 41

• |  | Purchases – are based on the volumes we currently have commitments to acquire under contract in 2022, 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 2022 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 the COVID-19 pandemic and related supply chain challenges.

• |  | Our 2022 outlook for sales/delivery volume does not include sales between our uranium and fuel services segments.

• |  | Sales/delivery volume is based on the volumes we currently have commitments to deliver under contract in 2022.

• |  | Uranium revenue and average realized price are based on a uranium spot price of $42.10 (US) per pound (the UxC spot price as of December 31, 2021), a long-term price indicator of $40.50 (US) per pound (the UxC long-term indicator on December 31, 2021) and an exchange rate of $1.00 (US) for $1.27 (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 $48.80 (Cdn) per pound and includes care and maintenance costs of between $50 million and $60 million, and operational readiness costs at McArthur River and Key Lake operations of between $15 million and $17 million per month until a reasonable level of production is achieved. We expect overall unit cost of sales could vary if there are changes in production and purchase volumes, uranium spot prices, care and maintenance costs and/or operational readiness costs in 2022.

Our 2022 financial outlook is presented on the basis of equity accounting for our minority ownership interest in JV Inkai. Under equity accounting, our share of the profits earned by JV Inkai on the sale of its production will be included in “income from equity-accounted investees” on our consolidated statement of earnings. Our share of production will be purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures. Please see Inkai Planning for the future on pages 71 and 72 for more details.

The following table shows how changes in the exchange rate or uranium prices can impact our outlook. For more details on the impact of exchange rates, also see Foreign exchange on page 39.

|  |  |  | IMPACT ON: |
FOR 2022 ($ MILLIONS) |  | CHANGE |  | REVENUE |  |  | ANE |  |  | CASH FLOW |
Uranium spot and long-term price1 |  | $5(US)/lb increase |  |  | 68 |  |  |  | 29 |  |  |  | 16 |
| $5(US)/lb decrease |  |  | (76 | ) |  |  | (35 | ) |  |  | (24 | )
Value of Canadian dollar vs US dollar |  | One cent decrease in CAD |  |  | 11 |  |  |  | 4 |  |  |  | 3 |
| One cent increase in CAD |  |  | (11 | ) |  |  | (4 | ) |  |  | (3 | )

1 | Assuming change both UxC spot price ($42.10 (US) per pound on December 27, 2021) and the UxC long-term price indicator ($40.50 (US) per pound on December 27, 2021).

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

As discussed under the Long-term contracting section on page 20, our portfolio of long-term contracts includes a mix of base-escalated and market-related contracts. Each contract is bilaterally negotiated with the customer and is subject to terms of confidentiality. Therefore, to help understand how the pricing under our current portfolio of commitments is expected to react at various spot prices at December 31, 2021, we have constructed the table below.

The table is based on the pricing terms under the long-term commitments in our contract portfolio that have been fully executed as at December 31, 2021. Based on the terms and volumes under those commitments, the table is designed to indicate how our average realized price will react under various spot price assumptions at a point in time. At year-end, the annual average sales commitments under our contract portfolio at December 31, 2021 are 18 million pounds per year, with commitment levels in 2022, 2023 and 2024 higher than the average and in 2025 and 2026 lower than the average. As the market improves, we expect to continue to layer in volumes capturing greater upside using market-related pricing mechanisms. In this table, we do not consider the impact on our average realized price of volumes under negotiation and those not yet committed under contract. In other words, the prices shown in the table would only be realized if the contract portfolio remained exactly as it was on December 31, 2021, using the following assumptions:

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

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

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

42 CAMECO CORPORATION

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

Expected realized uranium price sensitivity under various spot price assumptions at December 31, 2021

(rounded to the nearest $1.00) SPOT PRICES ($US/lb U3O8) |  | $20 |  |  | $40 |  |  | $60 |  |  | $80 |  |  | $100 |  |  | $120 |  |  | $140 |
2022 |  |  | 29 |  |  |  | 39 |  |  |  | 48 |  |  |  | 55 |  |  |  | 59 |  |  |  | 62 |  |  |  | 65 |
2023 |  |  | 28 |  |  |  | 39 |  |  |  | 50 |  |  |  | 57 |  |  |  | 61 |  |  |  | 63 |  |  |  | 66 |
2024 |  |  | 30 |  |  |  | 39 |  |  |  | 49 |  |  |  | 54 |  |  |  | 57 |  |  |  | 58 |  |  |  | 58 |
2025 |  |  | 31 |  |  |  | 40 |  |  |  | 52 |  |  |  | 60 |  |  |  | 64 |  |  |  | 66 |  |  |  | 68 |
2026 |  |  | 33 |  |  |  | 40 |  |  |  | 53 |  |  |  | 61 |  |  |  | 66 |  |  |  | 71 |  |  |  | 74 |

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 and as a result, we have significant cash balances.

At the end of 2021, we had cash and cash equivalents and short-term investments of $1.3 billion, while our total debt amounted to $996 million.

We have large, creditworthy customers that continue to need uranium even during weak economic conditions, and we expect the uranium contract portfolio we have built to continue to provide a solid revenue stream. From 2022 through 2026, we have commitments to deliver an average of 18 million pounds per year, with commitment levels in 2022, 2023 and 2024 higher than in 2025 and 2026.

The health and safety of our employees, their families and their communities is our priority as the COVID-19 pandemic continues to bring uncertainty and could have an impact on both the sources and uses of liquidity.

We expect a return to production at McArthur River/Key Lake will be positive for cash flow. It will allow us to source more of our committed sales from lower-cost produced pounds and we will no longer be required to expense care and maintenance costs directly to cost of sales. Until we achieve a reasonable production rate, we expect to incur between $15 million to $17 million per month in operational readiness costs, which will be expensed directly to cost of sales. Therefore, cash flow from operations for 2022 will be dependent on the timing and volume of McArthur River/Key Lake production, the timing and volume of Cigar Lake production and the timing and magnitude of our purchasing activity, as a result cash balances may fluctuate throughout the year. However, we expect our cash balances and operating cash flows to meet our capital requirements during 2022.

With the Supreme Court’s dismissal of CRA’s application for leave, the dispute of the 2003 through 2006 tax years are fully and finally resolved in our favour. Furthermore, we are confident the courts would reject any attempt by CRA to utilize the same or similar positions and arguments for the other tax years currently in dispute (2007 through 2014) and believe CRA should return the $777 million in cash and letters of credit we have been required to pay or otherwise secure. As such, we have filed notice of appeal to the Tax Court however, timing of any further payments is uncertain. See page 37 for more information.

MANAGEMENT’S DISCUSSION AND ANALYSIS 43

FINANCIAL CONDITION

|  | 2021 |  |  | 2020 |
Cash position ($ millions) |  |  |  |  |  |  |  |
(cash and cash equivalents and short-term investments) |  |  | 1,332 |  |  |  | 943 |
Cash provided by operations ($ millions) |  |  |  |  |  |  |  |
(net cash flow generated by our operating activities after changes in working capital) |  |  | 458 |  |  |  | 57 |
Cash provided by operations/net debt 1 |  |  |  |  |  |  |  |
(net debt is total consolidated debt, less cash position) |  |  | -136 | % |  |  | 109 | %
Net debt/total capitalization 1 |  |  |  |  |  |  |  |
(total capitalization is net debt and equity) |  |  | -7 | % |  |  | 1 | %

1 | As at December 31, 2021, Cameco was negative net debt due to our strong cash position.

CREDIT RATINGS

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

Third-party ratings for our commercial paper and senior debt as of February 8, 2022:

SECURITY |  | DBRS |  | S&P |
Commercial paper |  | R-2 (middle) |  |  | A-3 |
Senior unsecured debentures |  | BBB |  |  | BBB- |
Rating trend / rating outlook |  | Stable1 |  |  | Negative | 2

1 | On May 28, 2020, DBRS changed Cameco’s rating trend to stable. On June 3, 2021, DBRS confirmed the rating and outlook.

2 | On March 11, 2020, S&P changed Cameco’s rating outlook to negative. On March 12, 2021, S&P affirmed the rating and outlook.

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

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

Liquidity

($ MILLIONS) |  | 2021 |  |  | 2020 |
Cash and cash equivalents at beginning of year |  |  | 943 |  |  |  | 1,062 |
Cash from operations |  |  | 458 |  |  |  | 57 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment and acquisitions |  |  | (99 | ) |  |  | (77 | )
Other investing activities |  |  | 79 |  |  |  | 1 |
Financing activities |  |  |  |  |  |  |  |
Change in debt |  |  | — |  |  |  | (2 | )
Interest paid |  |  | (39 | ) |  |  | (66 | )
Other financing activities |  |  | (3 | ) |  |  | (3 | )
Issue of shares |  |  | 27 |  |  |  | 5 |
Dividends |  |  | (32 | ) |  |  | (32 | )
Exchange rate on changes on foreign currency cash balances |  |  | (2 | ) |  |  | (2 | )
Cash and cash equivalents and short-term investments at end of year |  |  | 1,332 |  |  |  | 943 |

CASH FROM OPERATIONS

Cash from operations was higher than in 2020 due largely to the purchasing activity that was a result of the Cigar Lake production suspension and higher sales commitments in 2020. Purchases in 2021 were 11.1 million pounds compared to 36.2 million pounds in 2020. Not including working capital requirements, our operating cash flows in the year were down $79 million. See note 23 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

44 CAMECO CORPORATION

Capital spending

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

Capital expenditures for 2021 were $99 million, lower than our outlook of $130 million to $155 million, as a result of the deferral of project work to 2022.

Outlook for investing activities

CAMECO’S SHARE ($ MILLIONS) |  | 2022 PLAN |  |  | 2023 PLAN |  |  | 2024 PLAN |
Total uranium & fuel services |  |  | 150-175 |  |  |  | 100-150 |  |  |  | 100-150 |
Sustaining capital |  |  | 110-125 |  |  |  | 75-105 |  |  |  | 75-105 |
Capacity replacement capital |  |  | 40-50 |  |  |  | 25-45 |  |  |  | 25-45 |
Growth capital |  |  | — |  |  |  | — |  |  |  | — |

Our 2022, 2023 and 2024 capital spending estimates assume that we engage in operational readiness activities at McArthur River/Key Lake to reach our 2024 production plan and are able to mitigate the risks posed by the COVID-19 pandemic and supply chain disruptions at all our operations.

Our estimate for capital spending in 2022 has been increased to between $150 million and $175 million (previously between $50 million and $100 million) due to the capital required for operational readiness activities and the rescheduling of some expenditures planned in 2021 to 2022.

Capital expenditures for JV Inkai are expected to be covered by JV Inkai cash flows in 2022 and are included in our overall equity investment.

Major sustaining and capacity replacement expenditures in 2022 include:

• |  | Fuel services – continued work on our Vision in Motion project

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

• |  | McArthur River/Key Lake – capital required for operational readiness to reach the 2024 planned production of 15 million pounds per year (100% basis)

• |  | Our investment in digital and automation technologies

This information regarding currently expected capital expenditures for future periods is forward-looking information and is based upon the assumptions and subject to the material risks discussed on pages 3 and 4. Our actual capital expenditures for future periods may be significantly different.

FINANCING ACTIVITIES

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 45

Long-term contractual obligations

DECEMBER 31 ($ MILLIONS) |  | 2022 |  |  | 2023 AND 2024 |  |  | 2025 AND 2026 |  |  | 2027 AND BEYOND |  |  | TOTAL |
Long-term debt |  |  | — |  |  |  | 500 |  |  |  | — |  |  |  | 500 |  |  |  | 1,000 |
Interest on long-term debt |  |  | 38 |  |  |  | 65 |  |  |  | 34 |  |  |  | 93 |  |  |  | 230 |
Provision for reclamation |  |  | 45 |  |  |  | 66 |  |  |  | 71 |  |  |  | 918 |  |  |  | 1,100 |
Provision for waste disposal |  |  | 1 |  |  |  | 4 |  |  |  | 3 |  |  |  | — |  |  |  | 8 |
Other liabilities |  |  | 4 |  |  |  | 8 |  |  |  | 2 |  |  |  | 85 |  |  |  | 99 |
Capital commitments |  |  | 53 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 53 |
Total |  |  | 141 |  |  |  | 643 |  |  |  | 110 |  |  |  | 1,596 |  |  |  | 2,490 |

We have contractual capital commitments of approximately $53 million at December 31, 2021. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfil the contracts.

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

• |  | A $1.0 billion unsecured revolving credit facility that matures October 1, 2025. Each calendar year, upon mutual agreement, the facility can be extended for an additional year. We may increase the revolving credit facility above $1.0 billion, by increments of no less than $50 million, up to a total of $1.25 billion. The facility ranks equally with all of our other senior debt. At December 31, 2021, there were no amounts outstanding under this facility and we do not expect to need to draw on this facility in 2022.

• |  | At December 31, 2021, we had approximately $1.6 billion outstanding in financial assurances provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, for our obligations relating to the CRA dispute, and as overdraft protection.

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

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

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

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

Debt covenants

Our revolving credit facility includes the following financial covenants:

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

• |  | other customary covenants and events of default

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

Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2021, we complied with all covenants, and we expect to continue to comply in 2022.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at the end of 2021:

• |  | purchase commitments

• |  | financial assurances

• |  | other arrangements

46 CAMECO CORPORATION

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 December 31, 20212 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.

DECEMBER 31, 2021 ($ MILLIONS) |  | 2022 |  |  | 2023 AND 2024 |  |  | 2025 AND 2026 |  |  | 2027 AND BEYOND |  |  | TOTAL |
Purchase commitments1,2 |  |  | 224 |  |  |  | 207 |  |  |  | 258 |  |  |  | 175 |  |  |  | 864 |

1 | Denominated in US dollars and Japanese yen, converted from US dollars to Canadian dollars at the rate of 1.27 and from Japanese yen to Canadian dollars at the rate of $0.01.

2 | These amounts have been adjusted for any additional purchase commitments that we have entered into since December 31, 2021 but does not include deliveries taken under contract since December 31, 2021.

We have commitments of $864 million (Cdn) for the following:

• |  | approximately 19 million pounds of U3O8 equivalent from 2022 to 2028

• |  | approximately 0.8 million kgU as UF6 in conversion services from 2022 to 2024

• |  | about 0.9 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

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

Financial assurances

We use standby letters of credit and surety bonds mainly to provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities as well as for our obligations relating to the CRA dispute. We are required to provide financial assurances to various regulatory agencies until decommissioning and reclamation activities are complete. We are also providing letters of credit until the CRA dispute is resolved. Our financial assurances renew automatically on an annual basis, unless otherwise advised by the issuing institution. At December 31, 2021 our financial assurances totaled $1.6 billion, the same as at December 31, 2020.

Other arrangements

We have arranged for standby product loan facilities with various counterparties. The arrangements allow us to borrow up to 2.0 million kgU of UF6 conversion services and 2.6 million pounds of U3O8 over the period 2020 to 2023 with repayment in kind up to December 31, 2023. 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 1.6%. At December 31, 2021, we have 1.1 million kgU of UF6 conversion services drawn on the loans.

BALANCE SHEET

DECEMBER 31, ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | 2021 |  |  | 2020 |  |  | 2019 |  |  | CHANGE 2020 TO 2021 |
Inventory |  |  | 410 |  |  |  | 680 |  |  |  | 321 |  |  |  | (40 | )%
Total assets |  |  | 7,518 |  |  |  | 7,581 |  |  |  | 7,427 |  |  |  | (1 | )%
Total non-current liabilities |  |  | 2,258 |  |  |  | 2,318 |  |  |  | 2,155 |  |  |  | (3 | )%
Dividends per common share |  |  | 0.08 |  |  |  | 0.08 |  |  |  | 0.08 |  |  |  | — |

Total product inventories decreased by 40% to $410 million this year as sales were higher than production and purchases during the year. At December 31, 2021, our average cost for uranium was $38.30 per pound, up from $38.01 per pound at December 31, 2020. As of December 31, 2021, we held an inventory of 8 million pounds of U3O8 equivalent (excluding broken ore).

MANAGEMENT’S DISCUSSION AND ANALYSIS 47

At the end of 2021, our total assets amounted to $7.5 billion, a decrease of 1% compared to 2020, due mainly to lower inventories which were largely offset by an increase in cash and investment balances. In 2020, the total asset balance increased by $0.2 billion compared to 2019, due mainly to higher inventories.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation, accrued pension and post-retirement benefit liability, deferred sales and financial derivatives.

48 CAMECO CORPORATION

2021 financial results by segment

Uranium

HIGHLIGHTS |  |  |  | 2021 |  |  | 2020 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  | 6.1 |  |  |  | 5.0 |  |  |  | 22 | %
Sales volume (million lbs) |  |  |  |  | 24.3 |  |  |  | 30.7 |  |  |  | (21 | )%
Average spot price |  | ($US/lb) |  |  | 35.28 |  |  |  | 29.96 |  |  |  | 18 | %
Average long-term price |  | ($US/lb) |  |  | 36.81 |  |  |  | 34.63 |  |  |  | 6 | %
Average realized price |  | ($US/lb) |  |  | 34.53 |  |  |  | 34.39 |  |  |  | — |
|  | ($Cdn/lb) |  |  | 43.34 |  |  |  | 46.13 |  |  |  | (6 | )%
Average unit cost of sales (including D&A) |  | ($Cdn/lb) |  |  | 47.80 |  |  |  | 45.53 |  |  |  | 5 | %
Revenue ($ millions) |  |  |  |  | 1,055 |  |  |  | 1,416 |  |  |  | (25 | )%
Gross profit (loss) ($ millions) |  |  |  |  | (108 | ) |  |  | 18 |  |  |  | (700 | )%
Gross profit (loss) (%) |  |  |  |  | (10 | ) |  |  | 1 |  |  |  | (1100 | )%

Production volumes in 2021 increased by 22% compared to 2020. See Uranium – production overview on page 61 for more information.

Uranium revenues this year were down 25% compared to 2020 due to a decrease in sales volumes of 21% and a decrease of 6% in the Canadian dollar average realized price. Although the spot price for uranium averaged $35.28 (US) per pound in 2021, an increase of 18% compared to the 2020 average price of $29.96 (US) per pound, the average realized price was 6% lower compared to the same period in 2020 primarily due to the strengthening of the Canadian dollar compared to 2020.

Total cost of sales (including D&A) decreased by 17% ($1.16 billion compared to $1.40 billion in 2020) due to a decrease in sales volume of 21% partially offset by a 5% increase in unit cost of sales. Unit cost of sales is higher than in the same period in 2020 due to the higher cost of purchased material and the higher unit cost impact of fixed care and maintenance costs resulting from lower sales volumes.

The net effect was a $126 million decrease in gross profit for the year.

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

($CDN/LB) |  | 2021 |  |  | 2020 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 16.17 |  |  |  | 16.24 |  |  |  | — |
Non-cash cost |  |  | 17.18 |  |  |  | 15.10 |  |  |  | 14 | %
Total production cost 1 |  |  | 33.35 |  |  |  | 31.34 |  |  |  | 6 | %
Quantity produced (million lbs)1 |  |  | 6.1 |  |  |  | 5.0 |  |  |  | 22 | %
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost1 |  |  | 42.30 |  |  |  | 39.66 |  |  |  | 7 | %
Quantity purchased (million lbs)1 |  |  | 11.1 |  |  |  | 36.2 |  |  |  | (69 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 39.13 |  |  |  | 38.65 |  |  |  | 1 | %
Quantities produced and purchased (million lbs) |  |  | 17.2 |  |  |  | 41.2 |  |  |  | (58 | )%

1 | Due to equity accounting for JV Inkai, our share of production is shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. In 2021 we purchased 5.2 million pounds at a purchase price per pound of $45.31 ($36.03 (US)) (2020 – 4.0 million pounds at a purchase price per pound of $36.63 ($27.66 (US))).

Over the last two years the annual cash cost of production has averaged $16.21 per pound at Cigar Lake, slightly higher than the estimated life of mine cost of between $15 and $16 per pound, as a result of the impacts of COVID-19. In 2022 and 2023, our cash production costs may continue to be affected by the impacts of the COVID-19 pandemic, as well as timing and rate of production at the McArthur River/Key Lake operation. Once we achieve the 2024 planned production, the average unit operating costs at Cigar Lake may increase as production declines.

MANAGEMENT’S DISCUSSION AND ANALYSIS 49

The benefit of the estimated life-of-mine operating cost for Inkai’s production of between $6 and $7 per pound, is expected to be reflected in the line item on our statement of earnings called “share of earnings from equity-accounted investee”.

Our purchases in 2021, totaled about $470 million, representing an average annual cost of $42.30 per pound, about $9.90 per pound higher than the average production cost at Cigar Like for 2021 and 2020. Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the year, the average cash cost of purchased material was $42.30 (Cdn), or $33.73 (US) per pound, compared to $39.66 (Cdn), or $29.17 (US) per pound in the same period in 2020.

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

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

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the years ended 2021 and 2020 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS) |  | 2021 |  |  | 2020 |
Cost of product sold |  |  | 1,028.8 |  |  |  | 1,243.3 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (15.2 | ) |  |  | (15.5 | )
Other selling costs |  |  | (4.6 | ) |  |  | (12.1 | )
Care and maintenance and severance costs |  |  | (156.7 | ) |  |  | (138.5 | )
Change in inventories |  |  | (284.1 | ) |  |  | 439.7 |
Cash operating costs (a) |  |  | 568.2 |  |  |  | 1,516.9 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 134.6 |  |  |  | 154.6 |
Care and maintenance costs |  |  | (52.9 | ) |  |  | (57.5 | )
Change in inventories |  |  | 23.1 |  |  |  | (21.6 | )
Total operating costs (b) |  |  | 673.0 |  |  |  | 1,592.4 |
Uranium produced & purchased (million lbs) (c) |  |  | 17.2 |  |  |  | 41.2 |
Cash costs per pound (a ÷ c) |  |  | 33.03 |  |  |  | 36.82 |
Total costs per pound (b ÷ c) |  |  | 39.13 |  |  |  | 38.65 |

ROYALTIES

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

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

• |  | Profit royalty: a 10% royalty is charged on profit up to and including $24.38/kg U3O8 ($11.06/lb) and a 15% royalty is charged on profit in excess of $24.38/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.

As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.

URANIUM SEGMENT OUTLOOK

Based on the contracts we have in place, and not including sales between our segments, we expect to deliver between 23 million and 25 million pounds of U3O8 in 2022.

50 CAMECO CORPORATION

In addition, we expect to purchase between 11 million and 13 million pounds in 2022 to meet our sales commitments and maintain a working inventory. This includes our spot market purchases and other purchase commitments, including from JV Inkai.

Fuel services

(includes results for UF6, UO2, UO3 and fuel fabrication) HIGHLIGHTS |  |  |  | 2021 |  |  | 2020 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  | 12.1 |  |  |  | 11.7 |  |  |  | 3 | %
Sales volume (million kgU) |  |  |  |  | 13.6 |  |  |  | 13.5 |  |  |  | 1 | %
Average realized price |  | ($Cdn/kgU) |  |  | 29.72 |  |  |  | 27.89 |  |  |  | 7 | %
Average unit cost of sales (including D&A) |  | ($Cdn/kgU) |  |  | 21.02 |  |  |  | 20.76 |  |  |  | 1 | %
Revenue ($ millions) |  |  |  |  | 404 |  |  |  | 377 |  |  |  | 7 | %
Gross profit ($ millions) |  |  |  |  | 118 |  |  |  | 96 |  |  |  | 23 | %
Gross profit (%) |  |  |  |  | 29 |  |  |  | 25 |  |  |  | 16 | %

Total revenue increased by 7% from 2020 due to a 7% increase in the realized price and a 1% increase in sales volume. The increase in realized price was mainly the result of contracts that were entered into in an improved price environment.

Total cost of products and services sold (including D&A) increased 2% ($286 million compared to $281 million in 2020), due to the 1% increase in sales volume and a 1% increase in average unit cost of sales compared to 2020 due to higher input costs.

The net effect was a $22 million increase in gross profit.

FUEL SERVICES SEGMENT OUTLOOK

In 2022, we plan to produce 12.5 million to 13.5 million kgU, and we expect sales volumes, not including intersegment sales, to be 10.5 million to 11.5 million kgU. Overall revenue is expected to be between $340 million and $370 million, slightly lower than 2021 due to lower committed sales volumes. We expect the average unit cost of sales (including D&A) to be between $21.50/kgU and $22.50/kgU.

MANAGEMENT’S DISCUSSION AND ANALYSIS 51

Fourth quarter financial results

Consolidated results

HIGHLIGHTS |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($ MILLIONS EXCEPT WHERE INDICATED) |  | 2021 |  |  | 2020 |  |  | CHANGE |
Revenue |  |  | 465 |  |  |  | 550 |  |  |  | (15 | )%
Gross profit |  |  | 56 |  |  |  | 109 |  |  |  | (49 | )%
Net earnings attributable to equity holders |  |  | 11 |  |  |  | 80 |  |  |  | (86 | )%
$ per common share (basic) |  |  | 0.03 |  |  |  | 0.20 |  |  |  | (85 | )%
$ per common share (diluted) |  |  | 0.03 |  |  |  | 0.20 |  |  |  | (85 | )%
Adjusted net earnings (non-IFRS, see page 33) |  |  | 23 |  |  |  | 48 |  |  |  | (52 | )%
$ per common share (adjusted and diluted) |  |  | 0.06 |  |  |  | 0.12 |  |  |  | (50 | )%
Cash provided by operations |  |  | 59 |  |  |  | 257 |  |  |  | (77 | )%

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 33) in the fourth quarter of 2021 compared to the same period in 2020.

($ MILLIONS) |  | IFRS |  |  | Adjusted |
Net earnings (losses) - 2020 |  |  | 80 |  |  |  | 48 |
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 |  | Lower sales volume |  |  | (20 | ) |  |  | (20 | )
|  | Higher realized prices ($US) |  |  | 10 |  |  |  | 10 |
|  | Foreign exchange impact on realized prices |  |  | (13 | ) |  |  | (13 | )
|  | Higher costs |  |  | (47 | ) |  |  | (47 | )
|  | change – uranium |  |  | (70 | ) |  |  | (70 | )
Fuel services |  | Higher sales volume |  |  | 4 |  |  |  | 4 |
|  | Higher realized prices ($Cdn) |  |  | 11 |  |  |  | 11 |
|  | change – fuel services |  |  | 15 |  |  |  | 15 |
Other changes |  |  |  |  |  |  |  |

Lower administration expenditures |  |  | 8 |  |  |  | 8 |
Lower exploration expenditures |  |  | 1 |  |  |  | 1 |
Change in reclamation provisions |  |  | (10 | ) |  |  | — |
Change in gains or losses on derivatives |  |  | (35 | ) |  |  | 13 |
Change in foreign exchange gains or losses |  |  | 7 |  |  |  | 7 |
Change in earnings from equity-accounted investments |  |  | 16 |  |  |  | 16 |
Redemption of Series E debentures in 2020 |  |  | 24 |  |  |  | 24 |
Canadian Emergency Wage Subsidy |  |  | (37 | ) |  |  | (37 | )
Change in income tax recovery or expense |  |  | 19 |  |  |  | 5 |
Other |  |  | (7 | ) |  |  | (7 | )
Net earnings - 2021 |  |  | 11 |  |  |  | 23 |

ADJUSTED NET EARNINGS

We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 33 for more information. The following table reconciles adjusted net earnings with our net earnings.

52 CAMECO CORPORATION

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2021 |  |  | 2020 |
Net earnings attributable to equity holders |  |  | 11 |  |  |  | 80 |
Adjustments |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | 5 |  |  |  | (43 | )
Adjustments on other operating expense (income) |  |  | 10 |  |  |  | — |
Income taxes on adjustments |  |  | (3 | ) |  |  | 11 |
Adjusted net earnings |  |  | 23 |  |  |  | 48 |

ADMINISTRATION

|  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($ MILLIONS) |  | 2021 |  |  | 2020 |  |  | CHANGE |
Direct administration |  |  | 28 |  |  |  | 31 |  |  |  | (10 | )%
Stock-based compensation |  |  | 9 |  |  |  | 14 |  |  |  | (36 | )%
Total administration |  |  | 37 |  |  |  | 45 |  |  |  | (18 | )%

Direct administration costs were $28 million in the quarter, $3 million lower than the same period last year. Stock-based compensation expenses were $5 million lower from the fourth quarter of 2020. See note 24 to the financial statements.

Quarterly trends

HIGHLIGHTS |  | 2021 |  |  | 2020 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 465 |  |  |  | 361 |  |  |  | 359 |  |  |  | 290 |  |  |  | 550 |  |  |  | 379 |  |  |  | 525 |  |  |  | 346 |
Net earnings (loss) attributable to equity holders |  |  | 11 |  |  |  | (72 | ) |  |  | (37 | ) |  |  | (5 | ) |  |  | 80 |  |  |  | (61 | ) |  |  | (53 | ) |  |  | (19 | )
$ per common share (basic) |  |  | 0.03 |  |  |  | (0.18 | ) |  |  | (0.09 | ) |  |  | (0.01 | ) |  |  | 0.20 |  |  |  | (0.15 | ) |  |  | (0.13 | ) |  |  | (0.05 | )
$ per common share (diluted) |  |  | 0.03 |  |  |  | (0.18 | ) |  |  | (0.09 | ) |  |  | (0.01 | ) |  |  | 0.20 |  |  |  | (0.15 | ) |  |  | (0.13 | ) |  |  | (0.05 | )
Adjusted net earnings (loss) (non-IFRS, see page 33) |  |  | 23 |  |  |  | (54 | ) |  |  | (38 | ) |  |  | (29 | ) |  |  | 48 |  |  |  | (78 | ) |  |  | (65 | ) |  |  | 29 |
$ per common share (adjusted and diluted) |  |  | 0.06 |  |  |  | (0.14 | ) |  |  | (0.10 | ) |  |  | (0.07 | ) |  |  | 0.12 |  |  |  | (0.20 | ) |  |  | (0.16 | ) |  |  | 0.07 |
Cash provided by (used in) operations (after working capital changes) |  |  | 59 |  |  |  | 203 |  |  |  | 152 |  |  |  | 45 |  |  |  | 257 |  |  |  | (66 | ) |  |  | (316 | ) |  |  | 182 |

Key things to note:

• |  | The timing of customer requirements, which tends to vary from quarter to quarter, drives revenue in the uranium and fuel services segments.

• |  | Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 33 for more information).

• |  | Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 53

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

HIGHLIGHTS |  | 2021 |  |  | 2020 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Net earnings (loss) attributable to equity holders |  |  | 11 |  |  |  | (72 | ) |  |  | (37 | ) |  |  | (5 | ) |  |  | 80 |  |  |  | (61 | ) |  |  | (53 | ) |  |  | (19 | )
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | 5 |  |  |  | 26 |  |  |  | (9 | ) |  |  | (9 | ) |  |  | (43 | ) |  |  | (31 | ) |  |  | (41 | ) |  |  | 70 |
Adjustments on other operating expense (income) |  |  | 10 |  |  |  | (2 | ) |  |  | 6 |  |  |  | (22 | ) |  |  | — |  |  |  | 7 |  |  |  | 23 |  |  |  | (6 | )
Income taxes on adjustments |  |  | (3 | ) |  |  | (6 | ) |  |  | 2 |  |  |  | 7 |  |  |  | 11 |  |  |  | 7 |  |  |  | 6 |  |  |  | (16 | )
Adjusted net earnings (losses) (non-IFRS, see page 33) |  |  | 23 |  |  |  | (54 | ) |  |  | (38 | ) |  |  | (29 | ) |  |  | 48 |  |  |  | (78 | ) |  |  | (65 | ) |  |  | 29 |

54 CAMECO CORPORATION

Fourth quarter financial results by segment

Uranium

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  | 2021 |  |  | 2020 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  | 2.8 |  |  |  | 2.8 |  |  |  | — |
Sales volume (million lbs) |  |  |  |  | 6.5 |  |  |  | 8.6 |  |  |  | (24 | )%
Average spot price |  | ($US/lb) |  |  | 44.33 |  |  |  | 29.86 |  |  |  | 48 | %
Average long-term price |  | ($US/lb) |  |  | 42.92 |  |  |  | 35.00 |  |  |  | 23 | %
Average realized price |  | ($US/lb) |  |  | 39.65 |  |  |  | 38.43 |  |  |  | 3 | %
|  | ($Cdn/lb) |  |  | 49.94 |  |  |  | 50.40 |  |  |  | (1 | )%
Average unit cost of sales (including D&A) |  | ($Cdn/lb) |  |  | 48.35 |  |  |  | 41.09 |  |  |  | 18 | %
Revenue ($ millions) |  |  |  |  | 323 |  |  |  | 436 |  |  |  | (26 | )%
Gross profit ($ millions) |  |  |  |  | 10 |  |  |  | 80 |  |  |  | (88 | )%
Gross profit (%) |  |  |  |  | 3 |  |  |  | 18 |  |  |  | (83 | )%

Production volumes this quarter were unchanged from the fourth quarter of 2020. See Uranium – production overview on page 61 for more information.

Uranium revenues were down 26% due to a 24% decrease in sales volume and a 1% decrease in the Canadian dollar average realized price. While the average spot price for uranium increased by 48% compared to the same period in 2020, our average realized price decreased by 1% as a result of lower prices on fixed-price contracts and the lagging effect of changes in spot price on market related prices. In addition, the Canadian dollar was stronger compared to the same period last year, $1.00 (US) for $1.26 (Cdn) compared to $1.00 (US) for $1.31 (Cdn) in the fourth quarter of 2020.

Total cost of sales (including D&A) decreased by 12% ($313 million compared to $355 million in 2020). This was primarily the result of the 24% decrease in sales volume as the average unit cost of sales increased by 18% due to the higher cost of purchased material and higher care and maintenance costs.

The net effect was a $70 million decrease in gross profit for the quarter.

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

|  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($/LB) |  | 2021 |  |  | 2020 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 14.01 |  |  |  | 13.48 |  |  |  | 4 | %
Non-cash cost |  |  | 17.10 |  |  |  | 14.62 |  |  |  | 17 | %
Total production cost 1 |  |  | 31.11 |  |  |  | 28.10 |  |  |  | 11 | %
Quantity produced (million lbs)1 |  |  | 2.8 |  |  |  | 2.8 |  |  |  | — |
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost1 |  |  | 52.73 |  |  |  | 38.24 |  |  |  | 38 | %
Quantity purchased (million lbs)1 |  |  | 3.3 |  |  |  | 5.7 |  |  |  | (42 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 42.81 |  |  |  | 34.90 |  |  |  | 23 | %
Quantities produced and purchased (million lbs) |  |  | 6.1 |  |  |  | 8.5 |  |  |  | (28 | )%

1 | Due to equity accounting for JV Inkai, our share of production will be shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. During the quarter, we purchased 2.2 million pounds at a purchase price per pound of $52.69 ($41.79 (US)) (Q4 2020 – 2.7 million pounds at a purchase price per pound of $37.14 ($28.17 (US))).

MANAGEMENT’S DISCUSSION AND ANALYSIS 55

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the fourth quarter, the average cash cost of purchased material was $52.73 (Cdn) per pound, or $41.87 (US) per pound in US dollar terms, compared to $38.24 (Cdn) per pound, or $29.21 (US) per pound in the fourth quarter of 2020.

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. See page 49 for more information.

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2021 and 2020.

CASH AND TOTAL COST PER POUND RECONCILIATION

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2021 |  |  | 2020 |
Cost of product sold |  |  | 278.9 |  |  |  | 296.6 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (5.0 | ) |  |  | (7.8 | )
Other selling costs |  |  | (1.6 | ) |  |  | (1.3 | )
Care and maintenance and severance costs |  |  | (36.8 | ) |  |  | (29.5 | )
Change in inventories |  |  | (22.3 | ) |  |  | (2.5 | )
Cash operating costs (a) |  |  | 213.2 |  |  |  | 255.5 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 34.2 |  |  |  | 58.6 |
Care and maintenance costs |  |  | (10.1 | ) |  |  | (11.4 | )
Change in inventories |  |  | 23.8 |  |  |  | (6.1 | )
Total operating costs (b) |  |  | 261.1 |  |  |  | 296.6 |
Uranium produced & purchased (million lbs) (c) |  |  | 6.1 |  |  |  | 8.5 |
Cash costs per pound (a ÷ c) |  |  | 34.95 |  |  |  | 30.06 |
Total costs per pound (b ÷ c) |  |  | 42.81 |  |  |  | 34.90 |

Fuel services

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
(includes results for UF6, UO2, UO3 and fuel fabrication) HIGHLIGHTS |  |  |  | 2021 |  |  | 2020 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  | 3.1 |  |  |  | 3.3 |  |  |  | (6 | )%
Sales volume (million kgU) |  |  |  |  | 4.9 |  |  |  | 4.4 |  |  |  | 11 | %
Average realized price |  | ($Cdn/kgU) |  |  | 28.80 |  |  |  | 26.29 |  |  |  | 10 | %
Average unit cost of sales (including D&A) |  | ($Cdn/kgU) |  |  | 19.45 |  |  |  | 19.12 |  |  |  | 2 | %
Revenue ($ millions) |  |  |  |  | 140 |  |  |  | 115 |  |  |  | 22 | %
Gross profit ($ millions) |  |  |  |  | 46 |  |  |  | 32 |  |  |  | 44 | %
Gross profit (%) |  |  |  |  | 33 |  |  |  | 28 |  |  |  | 18 | %

Total revenue increased by 22% due to an 11% increase in sales volumes and a 10% increase in average realized price. The increase in average realized price was mainly the result of contracts that were entered into in an improved price environment.

Total cost of sales (including D&A) increased by 14% to $95 million compared to the fourth quarter of 2020 due to the 11% increase in sales volumes and an increase of 2% in the average unit cost of sales, due to higher input costs.

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

56 CAMECO CORPORATION

Operations and projects

This section of our MD&A is an overview of the mining properties we operate or have an interest in, our curtailed operations and our projects, what we accomplished this year, our plans for the future and how we manage risk.

58 |  | MANAGING THE RISKS
61 |  | URANIUM – PRODUCTION OVERVIEW
61 |  | PRODUCTION OUTLOOK
62 |  | URANIUM – TIER-ONE OPERATIONS
62 |  | MCARTHUR RIVER MINE / KEY LAKE MILL
66 |  | CIGAR LAKE
70 |  | INKAI
73 |  | URANIUM – TIER-TWO OPERATIONS
73 |  | RABBIT LAKE
74 |  | US ISR
75 |  | URANIUM – ADVANCED PROJECTS
75 |  | MILLENNIUM
75 |  | YEELIRRIE
75 |  | KINTYRE
77 |  | URANIUM – EXPLORATION
78 |  | FUEL SERVICES
78 |  | BLIND RIVER REFINERY
79 |  | PORT HOPE CONVERSION SERVICES
79 |  | CAMECO FUEL MANUFACTURING INC. (CFM)
81 |  | CORPORATE DEVELOPMENT

MANAGEMENT’S DISCUSSION AND ANALYSIS 57

Managing the risks

The nature of our operations means we face many potential risks and hazards that could have a significant impact on our business.

Below we list the risks that generally apply to all of our operations and advanced projects. We also talk about how we manage specific risks in each operation or project update. These risks could have a material impact on our business in the near term. These risks, however, are not a complete list of the potential risks our operations and advanced projects face. There may be others we are not aware of or risks we feel are not material today that could become material in the future.

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

Regulatory risks

A significant part of our economic value depends on our ability to:

• |  | obtain and renew the licences and other approvals we need to restart, operate, to increase production at our mines and to develop new mines. If we do not receive the regulatory approvals we need, or do not receive them at the right time, then we may have to delay, modify or cancel a project, which could increase our costs and delay or prevent us from generating revenue from the project. Regulatory review, including the review of environmental matters, is a long and complex process.

• |  | comply with the conditions in these licences and approvals. Our right to continue operating facilities, restart operations, increase production at our mines and develop new mines depends on our compliance with these conditions.

• |  | comply with the extensive and complex laws and regulations that govern our activities. Environmental legislation imposes strict standards and controls on almost every aspect of our operations and projects, and is not only introducing new requirements, but also becoming more stringent. For example:

| • |  | we must complete the environmental assessment process before we can begin developing a new mine or, in some cases, make significant changes to our operations

| • |  | we may need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an extensive review of supporting technical information. The complexity of this process can be further compounded when regulatory approvals are required from multiple agencies.

| • |  | the federal government has introduced an Impact Assessment Act as well as a Canadian Navigable Waters Act along with significant revisions to the federal Fisheries Act. This legislation could impact the scope, timeliness and cost of approvals for projects and the revisions could impact existing operations.

| • |  | Federal requirements stemming from the Species at Risk Act are introducing significant uncertainty into the management of activities in northern Saskatchewan. One specific example includes the amended national recovery strategy for woodland caribou, which contains strategic directions that have the potential to impact economic and social development in northern Saskatchewan. As a requirement of this document, the province of Saskatchewan is responsible for developing range plans that outline population and habitat protection measures for activities conducted in northern Saskatchewan. Mitigation requirements, and other measures, could have an impact on Saskatchewan operations and advanced projects in northern Saskatchewan.

| • |  | A number of government or governmental bodies have introduced or are contemplating regulatory changes in response to the potential impacts of climate change. While we have a relatively small carbon footprint, our Canadian facilities could experience higher annual operating costs due to changes in GHG pricing and regulations, such as carbon pricing, the Canadian Clean Fuel Standard, and/or other policy changes.

We use significant management and financial resources to manage our regulatory risks.

Environmental risks

We have the safety, health and environmental risks associated with any mining and chemical processing company. Our uranium and fuel services segments also face unique risks associated with radiation.

58 CAMECO CORPORATION

Laws to protect the environment are becoming more stringent for members of the nuclear energy industry, including mining, milling and processing facilities, and have inter-jurisdictional aspects (both federal and provincial/state regimes are applicable). Once we have permanently stopped mining and processing activities at an operating site, we are required to decommission the site to the satisfaction of the regulators. We have developed preliminary decommissioning plans for our operating sites and use them to estimate our decommissioning costs. Regulators review and accept our preliminary decommissioning plans on a regular basis. As the site approaches or goes into decommissioning, regulators review the detailed decommissioning plans. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.

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

At the end of 2021, our estimate of total decommissioning and reclamation costs was $1.11 billion. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $1.14 billion at the end of 2021 (the present value of the $1.11 billion). Regulatory approval is required prior to beginning decommissioning. Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, and none of our assets have approval for decommissioning, our expected costs for decommissioning and reclamation for the next five years are not material.

We provide financial assurances for decommissioning and reclamation such as letters of credit or surety bonds to regulatory authorities, as required. We had a total of about $1.01 billion in financial assurances supporting our reclamation liabilities at the end of 2021. All of our North American operations have financial assurances in place in connection with our preliminary plans for decommissioning of the sites.

Some of the sites we own or operate have been under ongoing investigation and/or remediation and planning as a result of historic soil and groundwater conditions.

We use significant management and financial resources to manage our environmental risks.

We manage environmental risks through our safety, health, environment and quality (SHEQ) management system. Our chief executive officer is responsible for ensuring that our SHEQ management system is implemented. Our board’s safety, health and environment committee also oversees how we manage our SHEQ risks, including the use of our enterprise risk management program.

A key cornerstone of our SHEQ management system is the continual improvement of process and physical infrastructure supporting the management system. Proposed projects are evaluated and, if beneficial, included in our site’s life of asset plan. Noteworthy projects expected to reduce SHEQ risks that were advanced in 2021 included:

• |  | The Vision in Motion project at the Port Hope conversion facility

• |  | the program to advance the assessment of innovation opportunities at the McArthur River mine and Key Lake mill

• |  | energy management improvements at our Saskatchewan operations

• |  | progressive decommissioning activities at our in-situ recovery operations in the United States

• |  | containment system upgrades at our operations.

Most of these projects are multi-year projects that are expected to continue into 2022 and beyond.

MANAGEMENT’S DISCUSSION AND ANALYSIS 59

Operational risks

Other risks and hazards generally applicable to our operations and advanced projects include:

• |  | environmental damage

• |  | industrial and transportation accidents

• |  | labour shortages, disputes or strikes

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

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

• |  | transportation and delivery disruptions

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

• |  | equipment failures

• |  | cyberattacks

• |  | joint venture disputes or litigation

• |  | non-compliance with laws and licences

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

• |  | uncertain environment resulting from the COVID-19 pandemic and its related operational and safety risks

• |  | catastrophic accidents

• |  | fires

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

• |  | climate change or natural phenomena, such as inclement weather conditions, forest fires, floods and earthquakes

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

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

• |  | underground floods

• |  | ground movement or cave-ins

• |  | tailings pipeline or dam failures

• |  | technological failure of mining methods

• |  | unanticipated consequences of our cost reduction strategies

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

60 CAMECO CORPORATION

Uranium – production overview

Production in our uranium segment in the fourth quarter was 2.8 million pounds, no change compared to the same period in 2020, while production for the year was 6.1 million pounds, 22% higher than in 2020. The McArthur River/Key Lake and Rabbit Lake operations remained in a safe and sustainable state of care and maintenance, and we are no longer developing new wellfields at Crow Butte and Smith Ranch-Highland. See Uranium – Tier-one operations starting on page 62 and Uranium – Tier-two operations beginning on page 73 for more information.

Uranium production

CAMECO SHARE |  | THREE MONTHS ENDED DECEMBER 31 |  |  | YEAR ENDED DECEMBER 31 |  |  |  |  |  |  |
(MILLION LBS) |  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |  |  | 2021 PLAN1 |  |  | 2022 PLAN |
Cigar Lake |  |  | 2.8 |  |  |  | 2.8 |  |  |  | 6.1 |  |  |  | 5.0 |  |  |  | up to 6.0 |  |  |  | 7.5 | 2
McArthur River/Key Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | up to 3.5 | 3
Total |  |  | 2.8 |  |  |  | 2.8 |  |  |  | 6.1 |  |  |  | 5.0 |  |  |  | up to 6.0 |  |  |  | up to 11.0 |

1 | A production target was not set in 2021 until after production at Cigar Lake resumed following the proactive four-month COVID-19-related suspension that started in December of 2020. A production target of up to 6.0 million pounds (our share) was provided in our 2021 second quarter MD&A.

2 | At Cigar Lake, we expect production of 15 million pounds (100% basis) in 2022 due to the delays and deferrals to development work experienced in 2021 related to the suspension of production noted above and the ongoing pandemic and supply chain challenges impacting the availability of construction materials, equipment and labour.

3 | Over the course of 2022 and 2023, we will undertake all the activities necessary to ramp up to the 2024 planned production of 15 million pounds per year (100% basis) at McArthur River/Key Lake. As a result, in 2022, we could produce up to 5 million pounds (100% basis).

Production outlook

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

Given the transition we are seeing in the uranium market, we plan to:

• |  | begin the work necessary at McArthur River/Key Lake to achieve our 2024 production plan, matching our production level to our sales commitments and market opportunities

• |  | focus on technology and its applications to improve efficiency, reduce costs and improve operational effectiveness across our operations, including the use of digital and automation technologies

We expect our share of production to be up to 11 million pounds in 2022 and we will work to minimize the impact of any COVID-19 pandemic disruptions and supply chain challenges on the availability of materials, reagents and labour.

We expect total production from Inkai to be 8.3 million pounds in 2022 on a 100% basis, assuming no production disruptions due to the COVID-19 pandemic, civil unrest, supply chain issues or other causes. Due to equity accounting, our share of production is shown as a purchase. An adjustment to the production purchase entitlement allows us to purchase 4.2 million pounds in 2022.

MANAGEMENT’S DISCUSSION AND ANALYSIS 61

Uranium – Tier-one operations

McArthur River mine / Key Lake mill

|  | 2021 Production (our share)
| 0.0M lbs
| 2022 Production Outlook (our share)
| up to 3.5M lbs
| Estimated Reserves (our share)
| 275.0M lbs
| Estimated Mine Life
| 2048

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

In 2018, a decision was made to suspend production and place the mine and mill in care and maintenance. With the improvement in the uranium market and the success we have had in securing new long-term contracts, it is time to proceed with the next phase of our supply discipline decisions. Therefore, continuing to align our production with market conditions and our contract portfolio, our plan is to produce 15 million pounds (100% basis) per year by 2024 at McArthur River/Key Lake, 40% below its licensed capacity. This will remain our production plan until we see further improvements in the uranium market and contracting progress, demonstrating that we continue to be a responsible supplier of uranium fuel.

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

Location |  | Saskatchewan, Canada
Ownership |  |  |  | McArthur River – 69.805% Key Lake – 83.33%
Mine type |  | Underground
Mining methods |  |  |  | Primary: blasthole stoping Secondary: raiseboring
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 275.0 million pounds (proven and probable), average grade U3O8: 6.58%
Estimated resources |  | 6.3 million pounds (measured and indicated), average grade U3O8: 2.46% 1.8 million pounds (inferred), average grade U3O8: 2.85%
Licensed capacity |  | Mine and mill: 25.0 million pounds per year
Licence term |  | Through October, 2023
Total packaged production: |  | 2000 to 2021 1983 to 2002 |  | 325.4 million pounds (McArthur River/Key Lake) (100% basis) 209.8 million pounds (Key Lake) (100% basis)
2021 production |  | 0.0 million pounds (0.0 million pounds on 100% basis)
2022 production outlook |  | up to 3.5 million pounds (5.0 million pounds on 100% basis)
Estimated decommissioning cost |  | $42 million – McArthur River (100% basis) $223 million – Key Lake (100% basis)

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

62 CAMECO CORPORATION

BACKGROUND

Mine description

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

Zone 2 has been actively mined since production began in 1999. The ore zone was initially divided into three freeze panels. As the freeze wall was expanded, the inner connecting freeze walls were decommissioned in order to recover the inaccessible uranium around the active freeze pipes. Mining of zone 2 is almost complete. About 4.8 million pounds of mineral reserves remain and we expect to recover them using a combination of raisebore and blasthole stope mining.

Zone 4 has been actively mined since 2010. The zone was divided into four freeze panels, and like in zone 2, as the freeze wall was expanded, the inner connecting freeze walls were decommissioned. Zone 4 has 117.5 million pounds of mineral reserves secured behind freeze walls and it will be the main source of production when mine production restarts. Raisebore mining and blasthole stoping will be used to recover the mineral reserves.

Zone 1 is the next planned mine area to be brought into production. Freezehole drilling was 90% complete and brine distribution construction was approximately 10% complete when work was suspended in 2018 as part of the production suspension. Work remaining before production can begin includes completion of the freezehole drilling, brine distribution construction, ground freezing and drill and extraction chamber development. Once complete, an additional 47.5 million pounds of mineral reserves will be secured behind freeze walls. Blasthole stope mining is currently planned as the main extraction method.

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

Mining methods and techniques

The McArthur River deposit presents unique challenges that are not typical of traditional hard or soft rock mines. These challenges are the result of mining in or near high pressure ground water in challenging ground conditions with significant radiation concerns due to the high-grade uranium ore. Therefore, mine designs and mining methods are selected based on their ability to mitigate hydrological, radiological and geotechnical risks.

There are three approved mining methods at McArthur River: raisebore mining, blasthole stope mining and boxhole mining. However, only raisebore and blasthole stope mining remain in use. In addition, we use ground freezing to mine the McArthur River deposit.

Ground freezing

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

Chilled brine is circulated through freeze holes to form an impermeable freeze barrier around the area being mined. This prevents water from entering the mine, and helps stabilize weak rock formations.

Blasthole stoping

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

Raisebore mining

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 63

Initial processing

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

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

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

Tailings capacity

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

Licensed annual production capacity

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

2021 UPDATE

Production suspension

The facilities remained in a state of safe and sustainable care and maintenance throughout 2021.

Care and maintenance activities included mine dewatering, water treatment, freeze wall maintenance, and environmental monitoring. In addition, preservation maintenance and monitoring of the critical facilities continued. These activities were performed to ensure that the McArthur River and Key Lake operations are available to return to production in a timely manner.

Exploration

As a result of the production suspension, there was no exploration activity in 2021.

PLANNING FOR THE FUTURE

Production

Over the course of 2022 and 2023, we will undertake all the activities necessary to ramp up to the planned annual production of 15 million pounds (100% basis) by 2024. As a result, in 2022, we could produce up to 5 million pounds (100% basis). This plan will significantly improve our financial performance by allowing us to source more of our committed sales from lower-cost produced pounds and we will no longer be required to expense care and maintenance costs directly to cost of sales. However, until we achieve a reasonable production rate, we expect to incur between $15 million to $17 million per month in operational readiness costs, which will be expensed directly to cost of sales. There is a potential for the COVID-19 pandemic and related supply chain challenges to impact the availability of materials, reagents and labour, which could not only impact 2022 production but could also introduce risk to production in 2023.

Innovation

In 2020, we began a program to advance the assessment of innovation opportunities at the McArthur River mine and Key Lake mill. We established a team of internal experts who have been tasked with assessing, designing and implementing opportunities to improve operating efficiency. During the year, the team advanced a portfolio of projects focused on improvement of the mine and mill through application of automation, digitization and optimization. In 2021, the projects that met our investment criteria were advanced to implementation.

64 CAMECO CORPORATION

Optimizing production

The technical report dated March of 2019 is based on production of 18 million pounds (100% basis) per year, however, we plan to align production with our contract portfolio and market signals once operations resume. Our current plan is to achieve production of 15 million pounds (100% basis) per year by 2024. We expect that this paced approach will allow us to extract maximum value from the operation.

MANAGING OUR RISKS

Production at McArthur River/Key Lake poses many challenges. These challenges include control of groundwater, weak rock formations, radiation protection, water inflow, mine area transitioning, regulatory approvals, surface and underground fires and other mining related challenges. Operational experience gained since the start of production has resulted in a significant reduction in risk.

Mine and mill operational readiness

The operational changes we have made, including the suspension of production in 2018 and the accompanying workforce reduction, carry with them the risks of a delay in achieving operational readiness and resuming production.

With the extended period of time the assets were on care and maintenance, there is increased uncertainty regarding the timing of a successful rampup to planned production and the associated costs.

Labour relations

The collective agreement with the United Steelworkers local 8914 expires in December 2022. We plan to begin contract negotiations prior to the expiration of the current agreement. There is a risk to the ramp up to planned production if we are unable to reach agreement and there is a labour dispute.

Water inflow risk

Water inflows pose a significant risk to mine production. In 2003, a water inflow resulted in a three-month suspension of production. We also had a small water inflow in 2008 that did not impact production but did cause significant development delays.

The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.

We take significant steps and precautions to reduce the risk of inflows, but there is no guarantee that these will be successful. In the event that an inflow does occur, we believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow.

We also manage the risks listed on pages 58 to 60.

MANAGEMENT’S DISCUSSION AND ANALYSIS 65

Uranium – Tier-one operations

Cigar Lake

|  | 2021 Production (our share)
| 6.1M lbs
| 2022 Production Outlook (our share)
| 7.5M lbs
| Estimated Reserves (our share)
| 76.2M lbs
| Estimated Mine Life
| 2032

Cigar Lake is the world’s highest grade uranium mine, with grades that are 100 times the world average. We are a 50% owner and the mine operator. Cigar Lake uranium is milled at Orano’s (previously AREVA) McClean Lake mill.

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

Location |  | Saskatchewan, Canada
Ownership |  | 50.025%
Mine type |  | Underground
Mining method |  | Jet boring system
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 76.2 million pounds (proven and probable), average grade U3O8: 15.41%
Estimated resources |  | 51.9 million pounds (measured and indicated), average grade U3O8: 13.83%
| 11.5 million pounds (inferred), average grade U3O8: 5.58%
Licensed capacity |  | 18.0 million pounds per year (our share 9.0 million pounds per year)
Licence term |  | Through June, 2031
Total packaged production: 2014 to 2021 |  | 105 million pounds (100% basis)
2021 production |  | 6.1 million pounds (12.2 million pounds on 100% basis)
2022 production outlook |  | 7.5 million pounds (15.0 million pounds on 100% basis)
Estimated decommissioning cost |  | $62 million (100% basis)

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

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows in 2006 and 2008. The underground workings were successfully remediated and secured in 2011 and, in October 2014 the McClean Lake mill produced the first uranium concentrate from ore mined at the Cigar Lake operation. Commercial production was declared in May 2015.

66 CAMECO CORPORATION

Mine description

Cigar Lake’s geological setting is similar to McArthur River’s: the permeable sandstone, which overlays the deposit and basement rocks, contains large volumes of water at significant pressure. However, unlike McArthur River, the Cigar Lake deposit has the shape of a flat- to cigar-shaped lens. As a result of these challenging geological conditions, we are unable to utilize traditional mining methods that require access above the ore, necessitating the development of a non-entry mining method specifically adapted for this deposit: the Jet Boring System (JBS).

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

Mining method

Bulk ground freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, and to prevent water from entering the mine, help stabilize weak rock formations, and meet our production schedule, we freeze the ground from surface. The ore zone and surrounding ground in the area to be mined must meet specific ground freezing requirements before we begin jet boring.

Jet boring system (JBS) mining

After many years of test mining, we selected jet boring, a non-entry mining method, which we have developed and adapted specifically for this deposit. This method involves:

• |  | drilling a pilot hole into the frozen orebody, inserting a high pressure water jet and cutting a cavity out of the frozen ore

• |  | collecting the ore and water mixture (slurry) from the cavity and pumping it to storage (sump storage), allowing it to settle

• |  | using a clamshell, transporting the ore from sump storage to an underground grinding and processing circuit

• |  | once mining is complete, filling each cavity in the orebody with concrete

• |  | starting the process again with the next cavity

We have divided the orebody into production panels and at least three production panels need to be frozen at one time to achieve the annual production rate. One JBS machine is located below each frozen panel. Three JBS machines are currently in operation. Two machines actively mine at any given time while the third is moving, setting up, or undergoing maintenance.

Initial processing

We carry out initial processing of the extracted ore at Cigar Lake:

• |  | the underground circuit grinds the ore and mixes it with water to form a slurry

• |  | the slurry is pumped 500 metres to the surface and stored in one of two ore slurry holding tanks

• |  | it is blended and thickened, removing excess water

• |  | the final slurry, at an average grade of approximately 15% U3O8, is pumped into transport truck containers and shipped to McClean Lake mill on a 69 kilometre all-weather road

Water from this process, including water from underground operations, is treated on the surface. Any excess treated water is released into the environment.

MANAGEMENT’S DISCUSSION AND ANALYSIS 67

Milling

All of Cigar Lake’s ore slurry is being processed at the McClean Lake mill, operated by Orano. Given the McClean Lake mill’s capacity, it is able to:

• |  | process up to 18 million pounds U3O8 per year

• |  | process and package all of Cigar Lake’s current mineral reserves

Licensing annual production capacity

The Cigar Lake mine is licensed to produce up to 18 million pounds (100% basis) per year. Orano’s McClean Lake mill is licensed to produce 24 million pounds annually.

2021 UPDATE

Production

Total packaged production from Cigar Lake in 2021 was 12.2 million pounds U3O8 (6.1 million pounds our share) compared to 10 million pounds U3O8 (5.0 million pounds our share) in 2020. Production was impacted by suspensions in the second and third quarters of 2020 as a precautionary measure due to COVID-19. In December 2020, we safely suspended production at the Cigar Lake mine a second time as a precaution. The mine remained suspended through the first quarter of 2021 until its restart in mid-April. On July 1, all non-essential personnel from the Cigar Lake mine were evacuated and production was temporarily suspended as a precaution due to the proximity of a forest fire. With the risk subsided and all infrastructure intact, the workforce returned on July 4 and production resumed in the first week of July.

During the year, we:

• |  | executed planned ten-day annual maintenance activities in September

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

• |  | in alignment with our long-term production plans, we substantially completed optimizations of the underground water handling system and header expansions, and expanded our ground freezing program to ensure continued frozen ore inventory

Underground development

Underground mine development continued in 2021. A new production cross cut was completed in 2021 as well as development work in the western portion of the orebody. However, as a result of the suspension in production, we have also experienced delays and deferrals in project work, including lower capital expenditures, which have introduced risk to production in 2022. Furthermore, the potential for supply chain impacts on construction materials, equipment and labour remains uncertain and could further exacerbate production risk in 2022 and future years.

PLANNING FOR THE FUTURE

Production

At Cigar Lake, due to delays and deferrals to development work caused by the proactive COVID-19-related four-month suspension of production in 2021 and the ongoing pandemic and supply chain challenges impacting the availability of construction materials, equipment and labour, we expect production of 15 million pounds (100% basis) in 2022. We will work to minimize the impacts of these disruptions.

In 2022, we plan to:

• |  | continue production activities focused on bringing one new production panel online and closing out a completed one

• |  | continue surface freeze drilling and complete construction and commissioning of freeze distribution infrastructure expansion in support of future production

• |  | continue underground mine development on two new production tunnels as well as expand ventilation and access drifts in alignment with the long-term mine plan

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

68 CAMECO CORPORATION

Optimizing production

Consistent with our strategy and the improving market conditions, we are proceeding with the next phase of our supply discipline decisions. Continuing to align our production with the market conditions and our contract portfolio, starting in 2024, we will target production from Cigar Lake that is 25% below the licensed capacity, or 13.5 million pounds (100% basis) per year. Extending the mine life at Cigar Lake by aligning production with the market opportunities and our contract portfolio is consistent with our tier-one strategy and is expected to allow more time to evaluate the feasibility of extending the mine life beyond the current reserve base while continuing to supply ore to Orano’s McClean Lake mill. This will remain our production plan until we see further improvements in the uranium market and contracting progress, demonstrating that we continue to be a responsible supplier of uranium fuel.

MANAGING OUR RISKS

Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, chemical ore characteristics, performance of the water treatment system, water inflow, regulatory approvals, surface and underground fires and other mining-related challenges. To reduce this risk, we are applying our operational experience and the lessons we have learned about water inflows at McArthur River and Cigar Lake.

Transition to new mining areas

In order to successfully achieve the planned production schedule, we must continue to successfully transition into new mining areas, which includes mine development and investment in critical support infrastructure.

Ground freezing

To manage our risks and meet our production schedule, the areas being mined must meet specific ground freezing requirements before we begin jet boring. We have identified greater variation of the freeze rates of different geological formations encountered in the mine, based on information obtained through surface freeze drilling. As a mitigation measure, we have increased the site freeze capacity to facilitate the mining of ore cavities as planned.

Environmental performance

The Cigar Lake orebody contains elements of concern with respect to the water quality and the receiving environment. The distribution of elements such as arsenic, molybdenum, selenium and others is non-uniform throughout the orebody, and this can present challenges in attaining and maintaining the required effluent concentrations.

There have been ongoing efforts to optimize the current water treatment process and water handling systems to ensure acceptable environmental performance, which is expected to avoid the need for additional capital upgrades and potential deferral of production.

Water inflow risk

A significant risk to development and production is from water inflows. The 2006 and 2008 water inflows were significant setbacks.

The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant delay or disruption in Cigar Lake production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

• |  | Bulk freezing: Two of the primary challenges in mining the deposit are control of groundwater and ground support. Bulk freezing reduces but does not completely eliminate the risk of water inflows.

• |  | Mine development: We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk and apply extensive additional technical and operating controls for all higher risk development.

• |  | Pumping capacity and treatment limits: We have pumping capacity to meet our standard for this operation of at least one and a half times the estimated maximum inflow.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum inflow.

We also manage the risks listed on pages 58 to 60.

MANAGEMENT’S DISCUSSION AND ANALYSIS 69

Uranium – Tier-one operations

Inkai

|  | 2021 Production (100% basis)
| 9.0M lbs
| 2022 Production Outlook (100% basis)
| 8.3M lbs
| Estimated Reserves (our share)
| 112.5M lbs
| Estimated Mine Life
| 2045 (based on licence term)

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

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

Location |  | South Kazakhstan
Ownership |  | 40%1
Mine type |  | In situ recovery (ISR)
End product |  | Uranium concentrate
Certifications |  | BSI OHSAS 18001 ISO 14001 certified
Estimated reserves |  | 112.5 million pounds (proven and probable), average grade U3O8: 0.04%
Estimated resources |  | 35.6 million pounds (measured and indicated), average grade U3O8: 0.03% 9.6 million pounds (inferred), average grade U3O8: 0.03%
Licensed capacity (wellfields) |  | 10.4 million pounds per year (our share 4.2 million pounds per year)1
Licence term |  | Through July 2045
Total packaged production: 2009 to 2021 |  | 73 million pounds (100% basis)
2021 production |  | 9.0 million pounds (100% basis)1
2022 production outlook |  | 8.3 million pounds (100% basis)1
Estimated decommissioning cost (100% basis) |  | $20 million (US) (100% basis) (this estimate is currently under review)

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

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

70 CAMECO CORPORATION

BACKGROUND

Mine description

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

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

Mining and milling method

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

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

• |  | recover it from solution with ion exchange resin (takes place at both main and satellite processing plants)

• |  | precipitate the uranium with hydrogen peroxide

• |  | thicken, dewater, and dry it

• |  | package the uranium peroxide product in drums

Production

Total 2021 production from Inkai was 9.0 million pounds (100% basis), an increase of 28% from 2020. The increase in production is due to the impact of the reduction in operational activities introduced to manage the risks posed by the COVID-19 pandemic in 2020.

Production purchase entitlements

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

Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement, in 2021 we were entitled to purchase 5.3 million pounds, or 59.4% of JV Inkai’s 2021 production of 9.0 million pounds.

Cash distribution

Excess cash, net of working capital requirements, will be distributed to the partners as dividends. In 2021, we received dividend payments from JV Inkai totaling $40 million (US). Our share of dividends follows our production purchase entitlements as described above.

PLANNING FOR THE FUTURE

Production

On July 2, 2021, Kazatomprom announced that it plans to maintain 2023 production at a similar level to 2022, which is expected to be 20% lower than the planned volumes under its Subsoil Use Contracts.

Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement described above, we are entitled to purchase 4.2 million pounds, or 50% of JV Inkai’s planned 2022 production of 8.3 million pounds, assuming no production disruptions due to the COVID-19 pandemic, supply chain disruptions, civil unrest or other causes.

MANAGEMENT’S DISCUSSION AND ANALYSIS 71

Presently, JV Inkai is experiencing wellfield development, procurement and supply chain issues, including inflationary pressure on production materials and reagents, which are expected to continue and could pose a risk to JV Inkai’s 2022 production volume, impacting its costs. In addition, JV Inkai’s costs could be impacted by potential changes to the tax code in Kazakhstan and by possible increased financial contributions to social and other state causes, although these risks cannot be quantified or estimated at this time.

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

MANAGING OUR RISKS

2022 production forecast risk

Achievement of JV Inkai’s 2022 production forecast requires it to successfully manage its operating and other risks including the current uncertain environment resulting from civil unrest and from the COVID-19 pandemic, including the risk of significant disruption to JV Inkai’s operations, workforce, required supplies or services, and its ability to produce uranium.

Political risk

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

In early January 2022, Kazakhstan saw the most significant political instability since it became independent in 1991. The events resulted in a state of emergency being declared across the country. With the assistance of the Collective Security Treaty Organization (CSTO), the government restored the order and in the second half of January, the state of emergency was gradually lifted and withdrawal of CSTO forces from Kazakhstan was completed. The early outcome of those events was a number of political and economic reforms declared by the government. While the exact impact of those reforms is unclear at this time, they could potentially impact JV Inkai’s operations and costs.

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

JV Inkai manages risks listed on pages 58 to 60.

72 CAMECO CORPORATION

Uranium – Tier-two operations

Rabbit Lake

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

Location |  | Saskatchewan, Canada
Ownership |  | 100%
End product |  | Uranium concentrates
ISO certification |  | ISO 14001 certified
Mine type |  | Underground
Estimated reserves |  | -
Estimated resources |  | 38.6 million pounds (indicated), average grade U3O8: 0.95%
|  | 33.7 million pounds (inferred), average grade U3O8: 0.62%
Mining methods |  | Vertical blasthole stoping
Licensed capacity |  | Mill: maximum 16.9 million pounds per year; currently 11 million
Licence term |  | Through October, 2023
Total production: 1975 to 2021 |  | 202.2 million pounds
2021 production |  | 0 million pounds
2022 production outlook |  | 0 million pounds
Estimated decommissioning cost |  | $213 million

PRODUCTION SUSPENSION

The facilities remained in a state of safe and sustainable care and maintenance throughout 2021.

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

MANAGING OUR RISKS

We also manage the risks listed on pages 58 to 60.

MANAGEMENT’S DISCUSSION AND ANALYSIS 73

US ISR Operations

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

Ownership |  |  |  | 100%
End product |  |  |  | Uranium concentrates
ISO certification |  |  |  | ISO 14001 certified
Estimated reserves |  | Smith Ranch-Highland: |  | -
|  | North Butte-Brown Ranch: |  | -
|  | Crow Butte: |  | -
Estimated resources |  | Smith Ranch-Highland: |  | 24.9 million pounds (measured and indicated), average grade U3O8: 0.06%
|  |  |  | 7.7 million pounds (inferred), average grade U3O8: 0.05%
|  | North Butte-Brown Ranch: |  | 9.5 million pounds (measured and indicated), average grade U3O8: 0.07%
|  |  |  | 0.4 million pounds (inferred), average grade U3O8: 0.07%
|  | Crow Butte: |  | 13.9 million pounds (measured and indicated), average grade U3O8: 0.25%
|  |  |  | 1.8 million pounds (inferred), average grade U3O8: 0.16%
Mining methods |  |  |  | In situ recovery (ISR)
Licensed capacity |  | Smith Ranch-Highland:1 |  | Wellfields: 3 million pounds per year; processing plants: 5.5 million pounds per year
|  | Crow Butte: |  | Processing plants and wellfields: 2 million pounds per year
Licence term |  | Smith Ranch-Highland: |  | Through September, 2028
|  | Crow Butte: |  | Through October, 2024
Total production: 2002 to 2021 |  | 33.0 million pounds
2021 production |  |  |  | 0 million pounds
2022 production outlook |  |  |  | 0 million pounds
Estimated decommissioning cost |  | Smith Ranch-Highland: $219 million (US), including North Butte
|  | Crow Butte: $56 million (US)

1 | Including Highland mill

PRODUCTION CURTAILMENT

As a result of our 2016 decision, production at the US operations ceased in 2018. We expect ongoing cash and non-cash care and maintenance costs to range between $17 million (US) and $19 million (US) for 2022.

FUTURE PRODUCTION

We do not expect any production in 2022.

MANAGING OUR RISKS

We manage the risks listed on pages 58 to 60.

74 CAMECO CORPORATION

Uranium – advanced projects

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

Millennium

Location |  | Saskatchewan, Canada
Ownership |  | 69.9%
End product |  | Uranium concentrates
Potential mine type |  | Underground
Estimated resources (our share) |  | 53.0 million pounds (indicated), average grade U3O8: 2.39% 20.2 million pounds (inferred), average grade U3O8: 3.19%

BACKGROUND

The Millennium deposit was discovered in 2000, and was delineated through geophysical survey and surface drilling work between 2000 and 2013.

Yeelirrie

Location |  | Western Australia
Ownership |  | 100%
End product |  | Uranium concentrates
Potential mine type |  | Open pit
Estimated resources |  | 128.1 million pounds (measured and indicated), average grade U3O8: 0.15%

BACKGROUND

The deposit was discovered in 1972 and is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.

Kintyre

Location |  | Western Australia
Ownership |  | 100%
End product |  | Uranium concentrates
Potential mine type |  | Open pit
Estimated resources |  | 53.5 million pounds (indicated), average grade U3O8: 0.62% 6.0 million pounds (inferred), average grade U3O8: 0.53%

BACKGROUND

The Kintyre deposit was discovered in 1985 and is amenable to open pit mining techniques.

2021 PROJECT UPDATES

We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment these assets are not required to meet near-term demand. We continue to await a signal from the market that additional production is needed prior to making any new development decisions.

PLANNING FOR THE FUTURE

2022 Planned activity

No work is planned at Millennium, Yeelirrie or Kintyre.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 75

MANAGING THE RISKS

Project approval

The approval for the Yeelirrie project, received from the prior state government, required substantial commencement of the project by January 2022 unless an extension is granted by the state government. The Minister for Environment; Climate Action for the state government has indicated that it will not consider our request for an extension at this time. In the future we can again apply for an extension of time to achieve substantial commencement of the project. If granted by a future government we could commence the Yeelirrie project, provided we have all other required regulatory approvals. Approval for the Yeelirrie project at the federal level was granted in 2019 and extends until 2043.

For all of our advanced projects, we manage the risks listed on pages 58 to 60.

76 CAMECO CORPORATION

Uranium – exploration

Our exploration program is directed at replacing mineral reserves as they are depleted by our production and is key to sustaining our business. However, as we are preserving our tier-one assets and have ample idled production capacity, we have reduced our spending to focus only on exploration near our existing operations where we have established infrastructure and capacity to expand. Globally, we have land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia and the US. Our land holdings total about 0.85 million hectares (2.1 million acres). In northern Saskatchewan alone, we have direct interests in about 0.75 million hectares (1.9 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin.

EXPLORATION AND EVALUATION SPENDING

2021 UPDATE

Brownfield exploration

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

In 2021, we spent about $3 million on brownfields and advanced uranium projects in Saskatchewan and Australia. At the US operations we spent $1 million.

Regional exploration

We spent about $4 million on regional exploration programs (including support costs), primarily in Saskatchewan’s Athabasca Basin.

PLANNING FOR THE FUTURE

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 77

Fuel services

Refining, conversion and fuel manufacturing

We have about 21% of world UF6 primary conversion capacity and are a supplier of natural UO2. Our focus is on cost-competitiveness and operational efficiency.

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

Blind River Refinery

|  | Licensed Capacity 24.0M kgU as UO3 Licence renewal in February, 2022

Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO3.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | UO3
ISO certification |  | ISO 14001 certified
Licensed capacity |  | 18.0 million kgU as UO3 per year, approved to 24.0 million subject to the completion of certain equipment upgrades (advancement depends on market conditions)
Licence term |  | Through February, 2022
Estimated decommissioning cost |  | $48 million

78 CAMECO CORPORATION

Port Hope Conversion Services

|  | Licensed Capacity 12.5M kgU as UF6 2.8M kgU as UO2 Licence renewal in February, 2027

Port Hope is the only uranium conversion facility in Canada and a supplier of UO2 for Canadian-made CANDU reactors.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | UF6, UO2
ISO certification |  | ISO 14001 certified
Licensed capacity |  | 12.5 million kgU as UF6 per year
|  | 2.8 million kgU as UO2 per year
Licence term |  | Through February, 2027
Estimated decommissioning cost |  | $129 million

Cameco Fuel Manufacturing Inc. (CFM)

|  | Licensed Capacity 1.2M kgU as UO2 fuel pellets Licence renewal in February, 2022

CFM produces fuel bundles and reactor components for CANDU reactors.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | CANDU fuel bundles and components
ISO certification |  | ISO 9001 certified, ISO 14001 certified
Licensed capacity |  | 1.2 million kgU as UO2 fuel pellets
Licence term |  | Through February, 2022
Estimated decommissioning cost |  | $21 million

MANAGEMENT’S DISCUSSION AND ANALYSIS 79

2021 UPDATE

Production

Fuel services produced 12.1 million kgU, 3% higher than 2020 due to production suspensions in 2020 as a precaution due to the COVID-19 pandemic. Planned production was impacted by hydrogen supply issues in 2021. The hydrogen supply constraint was resolved in the fourth quarter, however supply chain disruption remains a risk generally.

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

Vision in Motion is a unique opportunity that demonstrates our continued commitment to a clean environment. It has been made possible by the opening of a long-term waste management facility by the government of Canada’s Port Hope Area Initiative project. There is a limited opportunity during the life of this project to engage in clean-up and renewal activities that address legacy waste at the Port Hope Conversion facility inherited from historic operations. While there were some targeted activities throughout the year, significant progress on the Vision in Motion project was limited due to the COVID-19 pandemic and actions taken by the Ontario government to limit all non-essential construction activity.

PLANNING FOR THE FUTURE

Production

We plan to produce between 12.5 million and 13.5 million kgU in 2022, assuming no production disruptions due to the COVID-19 pandemic or other causes.

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

MANAGING OUR RISKS

2022 production forecast risk

Achievement of our 2022 forecast for fuel services production requires us to successfully manage our operating and other risks, including the current uncertain environment resulting from the COVID-19 pandemic and its related operational risks, such as the risk of significant disruption to our workforce, required supplies or services, and our ability to produce product.

Labour relations

The current collective bargaining agreement with the unionized employees at Port Hope Conversion Facility expires on July 1, 2022. There is a risk to our production if we are unable to reach an agreement and there is a labour disruption.

Licensing

The current operating licence from the CNSC for both the Blind River refinery and CFM expire in February 2022. The relicensing process for both sites took place in the fourth quarter of 2021 and a decision from the CNSC is expected in early 2022. We do not expect any interruption or significant risks from this process.

We also manage the risks listed on pages 58 to 60.

80 CAMECO CORPORATION

Corporate development

INVESTMENT PROGRAM

Currently, with our extensive portfolio of reserves and resources and our belief that we have ample idle production capacity for a market that is transitioning, our focus is on navigating by our investment-grade rating and continuing to preserve the value of our tier-one assets by aligning our tier-one production with our delivery commitments and market opportunities. We expect that these assets will allow us to meet rising uranium demand with increased production from our best margin operations and will help to mitigate risk in the event of prolonged uncertainty.

Additionally, we are exploring other emerging and non-traditional opportunities within the fuel cycle, which align well with our commitment to responsibly and sustainably manage our business and increase our contributions to global climate change solutions, such as our investment in Global Laser Enrichment LLC and the non-binding arrangements we signed to explore several areas of cooperation to advance the commercialization and deployment of small modular reactors in Canada and around the world.

We continually evaluate investment opportunities within the nuclear fuel cycle that could add to our future supply options, support our sales activities, and complement and enhance our business in the nuclear industry. We will make an investment decision when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our shareholders in a fundamentally stronger position. As such, an investment opportunity is never assessed in isolation. Investments must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described under Our strategy, starting on page 19.

MANAGEMENT’S DISCUSSION AND ANALYSIS 81

Mineral reserves and resources

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

We have interests in a number of uranium properties. The tables in this section show the estimates of the proven and probable mineral reserves, and measured, indicated, and inferred mineral resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River/Key Lake, Cigar Lake and Inkai. Mineral reserves and resources are all reported as of December 31, 2021.

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

About mineral resources

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

• |  | Measured and indicated mineral resources can be estimated with sufficient confidence to allow the appropriate application of technical, economic, marketing, legal, environmental, social and governmental factors to support evaluation of the economic viability of the deposit.

• |  | measured resources: we can confirm both geological and grade continuity to support detailed mine planning

• |  | indicated resources: we can reasonably assume geological and grade continuity to support mine planning

• |  | Inferred mineral resources are estimated using limited geological evidence and sampling information. We do not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource, but it is reasonably expected that the majority of inferred mineral resources could be upgraded to indicated mineral resources with continued exploration.

Our share of uranium in the following mineral resource tables is based on our respective ownership interests. Reported mineral resources have not demonstrated economic viability.

About mineral reserves

Mineral reserves are the economically mineable part of measured and/or indicated mineral resources demonstrated by at least a preliminary feasibility study. The reference point at which mineral reserves are defined is the point where the ore is delivered to the processing plant, except for ISR operations where the reference point is where the mineralization occurs under the existing or planned wellfield patterns. Mineral reserves fall into two categories:

• |  | proven reserves: the economically mineable part of a measured resource for which at least a preliminary feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified with a high degree of confidence

• |  | probable reserves: the economically mineable part of a measured and/or indicated resource for which at least a preliminary feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified with a degree of confidence lower than that applying to proven reserves

For properties where we are the operator, we use current geological models, an average uranium price of $50 (US) per pound U3O8, and current or projected operating costs and mine plans to report our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate. For properties in which Cameco has an interest but is not the operator, we will take reasonable steps to ensure that the reserve and resource estimates that we report are reliable.

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

82 CAMECO CORPORATION

PROVEN AND PROBABLE (P&P) RESERVES, MEASURED AND INDICATED (M&I)

RESOURCES, INFERRED RESOURCES (SHOWING CHANGE FROM 2020)

at December 31, 2021

Changes this year

Our share of proven and probable mineral reserves increased from 455 million pounds U3O8 at the end of 2020, to 464 million pounds at the end of 2021. The change was primarily the result of:

• |  | a mineral resource and reserve estimate update at Inkai which added 19.0 million pounds to proven and probable reserves based on the infill drilling program completed in the Sat-1 area in 2018-2019. This update also resulted in increased confidence and consequent upgrading to the underlying mineral resource categories.

partially offset by:

• |  | production at Cigar Lake and Inkai, which removed 10.5 million pounds from our mineral inventory

The remaining changes are attributable to mineral resource and reserve estimate updates at Cigar Lake and McArthur River.

Our share of measured and indicated mineral resources increased from 426 million pounds U3O8 at the end of 2020, to 447 million pounds at the end of 2021. Our share of inferred mineral resources is 154 million pounds U3O8, a decrease of 20 million pounds from the end of 2020. The variance in mineral resources was primarily the result of the Inkai mineral resource estimate update.

MANAGEMENT’S DISCUSSION AND ANALYSIS 83

Qualified persons

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

MCARTHUR RIVER/KEY LAKE

• |  | Greg Murdock, general manager, McArthur River/Key Lake, Cameco

• |  | Alain D. Renaud, chief geologist, technical services, Cameco

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

CIGAR LAKE

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

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

• |  | Alain D. Renaud, chief geologist, technical services, Cameco

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

INKAI

• |  | Alain D. Renaud, chief geologist, technical services, Cameco

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

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

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

Important information about mineral reserve and resource estimates

Although we have carefully prepared and verified the mineral reserve and resource figures in this document, the figures are estimates, based in part on forward-looking information.

Estimates are based on knowledge, mining experience, analysis of drilling results, the quality of available data and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions, including:

• |  | geological interpretation

• |  | extraction plans

• |  | commodity prices and currency exchange rates

• |  | recovery rates

• |  | operating and capital costs

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 2 for information about forward-looking information.

Please see our mineral reserves and resources section of our most recent annual information form for the specific assumptions, parameters and methods used for McArthur River, Inkai and Cigar Lake mineral reserve and resource estimates.

Important information for US investors

We present information about mineralization, mineral reserves and resources as required by National Instrument 43-101 – Standards of Disclosure for Mineral Projects of the Canadian Securities Administrators (NI 43-101), in accordance with applicable Canadian securities laws. As a foreign private issuer filing reports with the US Securities and Exchange Commission (SEC) under the Multijurisdictional Disclosure System, we are not required to comply with the SEC’s disclosure requirements relating to mining properties. Investors in the United States should be aware that the disclosure requirements of NI 43-101 are different from those under applicable SEC rules, and the information that we present concerning mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for mining companies.

84 CAMECO CORPORATION

Mineral reserves

As of December 31, 2021 (100% – only the shaded column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | OUR |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | SHARE |  |  |  |
|  |  |  | PROVEN |  |  | PROBABLE |  |  | TOTAL MINERAL RESERVES |  |  | RESERVES |  |  |  |
|  | MINING |  |  |  |  | GRADE |  |  | CONTENT |  |  |  |  |  | GRADE |  |  | CONTENT |  |  |  |  |  | GRADE |  |  | CONTENT |  |  | CONTENT |  |  | METALLURGICAL |
PROPERTY |  | METHOD |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | (LBS U3O8) |  |  | RECOVERY (%) |
Cigar Lake |  | UG |  |  | 271.0 |  |  |  | 15.90 |  |  |  | 95.0 |  |  |  | 177.5 |  |  |  | 14.67 |  |  |  | 57.4 |  |  |  | 448.5 |  |  |  | 15.41 |  |  |  | 152.4 |  |  |  | 76.2 |  |  |  | 98.5 |
Key Lake |  | OP |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 95 |
McArthur River |  | UG |  |  | 2,139.6 |  |  |  | 6.97 |  |  |  | 328.9 |  |  |  | 575.1 |  |  |  | 5.13 |  |  |  | 65.1 |  |  |  | 2,714.7 |  |  |  | 6.58 |  |  |  | 393.9 |  |  |  | 275.0 |  |  |  | 99 |
Inkai |  | ISR |  |  | 264,001.7 |  |  |  | 0.04 |  |  |  | 226.9 |  |  |  | 80,459.5 |  |  |  | 0.03 |  |  |  | 54.3 |  |  |  | 344,461.2 |  |  |  | 0.04 |  |  |  | 281.2 |  |  |  | 112.5 |  |  |  | 85 |
Total |  |  |  |  | 266,473.4 |  |  |  | — |  |  |  | 651.5 |  |  |  | 81,212.1 |  |  |  | — |  |  |  | 176.8 |  |  |  | 347,685.5 |  |  |  | — |  |  |  | 828.2 |  |  |  | 464.3 |  |  |  | — |

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

Note that the estimates in the above table:

| • |  | use a constant dollar average uranium price of approximately $50 (US) per pound U3O8 except Inkai, where an average uranium price of approximately $35 (US) per pound U3O8 was used by JV Inkai

| • |  | are based on exchange rates of $1.00 US=$1.25 Cdn and $1.00 US=425 Kazakhstan Tenge

Our estimate of mineral reserves and mineral resources may be positively or negatively affected by the occurrence of one or more of the material risks discussed under the heading Caution about forward-looking information beginning on page 2, as well as certain property-specific risks. See Uranium – Tier-one operations starting on page 62.

Metallurgical recovery

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

2021 CONSOLIDATED FINANCIAL STATEMENTS AND NOTES 85

Mineral resources

As of December 31, 2021 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | OUR SHARE |  |  |  |  |  |  |  |  |  |  |  | OUR SHARE |
|  | MEASURED RESOURCES (M) |  |  | INDICATED RESOURCES (I) |  |  |  |  |  | INFERRED RESOURCES |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | TOTAL M+I |  |  | TOTAL M+I |  |  |  |  |  |  |  |  |  |  |  | INFERRED |
|  |  |  |  | GRADE |  |  | CONTENT |  |  |  |  |  | GRADE |  |  | CONTENT |  |  | CONTENT |  |  | CONTENT |  |  |  |  |  | GRADE |  |  | CONTENT |  |  | CONTENT |
PROPERTY |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | (LBS U3O8) |  |  | (LBS U3O8) |  |  | TONNES |  |  | % U3O8 |  |  | (LBS U3O8) |  |  | (LBS U3O8) |
Cigar Lake |  |  | 26.8 |  |  |  | 7.55 |  |  |  | 4.5 |  |  |  | 313.3 |  |  |  | 14.37 |  |  |  | 99.3 |  |  |  | 103.7 |  |  |  | 51.9 |  |  |  | 186.4 |  |  |  | 5.58 |  |  |  | 22.9 |  |  |  | 11.5 |
Fox Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 386.7 |  |  |  | 7.99 |  |  |  | 68.1 |  |  |  | 53.3 |
Kintyre |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,897.7 |  |  |  | 0.62 |  |  |  | 53.5 |  |  |  | 53.5 |  |  |  | 53.5 |  |  |  | 517.1 |  |  |  | 0.53 |  |  |  | 6.0 |  |  |  | 6.0 |
McArthur River |  |  | 91.7 |  |  |  | 2.63 |  |  |  | 5.3 |  |  |  | 74.5 |  |  |  | 2.26 |  |  |  | 3.7 |  |  |  | 9.0 |  |  |  | 6.3 |  |  |  | 41.0 |  |  |  | 2.85 |  |  |  | 2.6 |  |  |  | 1.8 |
Millennium |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,442.6 |  |  |  | 2.39 |  |  |  | 75.9 |  |  |  | 75.9 |  |  |  | 53.0 |  |  |  | 412.4 |  |  |  | 3.19 |  |  |  | 29.0 |  |  |  | 20.2 |
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,836.5 |  |  |  | 0.95 |  |  |  | 38.6 |  |  |  | 38.6 |  |  |  | 38.6 |  |  |  | 2,460.9 |  |  |  | 0.62 |  |  |  | 33.7 |  |  |  | 33.7 |
Tamarack |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 17.9 |  |  |  | 10.3 |  |  |  | 45.6 |  |  |  | 1.02 |  |  |  | 1.0 |  |  |  | 0.6 |
Yeelirrie |  |  | 27,172.9 |  |  |  | 0.16 |  |  |  | 95.9 |  |  |  | 12,178.3 |  |  |  | 0.12 |  |  |  | 32.2 |  |  |  | 128.1 |  |  |  | 128.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Crow Butte |  |  | 1,558.1 |  |  |  | 0.19 |  |  |  | 6.6 |  |  |  | 939.3 |  |  |  | 0.35 |  |  |  | 7.3 |  |  |  | 13.9 |  |  |  | 13.9 |  |  |  | 531.4 |  |  |  | 0.16 |  |  |  | 1.8 |  |  |  | 1.8 |
Gas Hills - Peach |  |  | 687.2 |  |  |  | 0.11 |  |  |  | 1.7 |  |  |  | 3,626.1 |  |  |  | 0.15 |  |  |  | 11.6 |  |  |  | 13.3 |  |  |  | 13.3 |  |  |  | 3,307.5 |  |  |  | 0.08 |  |  |  | 6.0 |  |  |  | 6.0 |
Inkai |  |  | 87,192.7 |  |  |  | 0.03 |  |  |  | 56.1 |  |  |  | 65,236.0 |  |  |  | 0.02 |  |  |  | 32.9 |  |  |  | 89.1 |  |  |  | 35.6 |  |  |  | 36,165.2 |  |  |  | 0.03 |  |  |  | 23.9 |  |  |  | 9.6 |
North Butte - Brown Ranch |  |  | 621.3 |  |  |  | 0.08 |  |  |  | 1.1 |  |  |  | 5,530.3 |  |  |  | 0.07 |  |  |  | 8.4 |  |  |  | 9.5 |  |  |  | 9.5 |  |  |  | 294.5 |  |  |  | 0.07 |  |  |  | 0.4 |  |  |  | 0.4 |
Ruby Ranch |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 56.2 |  |  |  | 0.14 |  |  |  | 0.2 |  |  |  | 0.2 |
Shirley Basin |  |  | 89.2 |  |  |  | 0.16 |  |  |  | 0.3 |  |  |  | 1,638.2 |  |  |  | 0.11 |  |  |  | 4.1 |  |  |  | 4.4 |  |  |  | 4.4 |  |  |  | 508.0 |  |  |  | 0.10 |  |  |  | 1.1 |  |  |  | 1.1 |
Smith Ranch - Highland |  |  | 3,703.5 |  |  |  | 0.10 |  |  |  | 7.9 |  |  |  | 14,372.3 |  |  |  | 0.05 |  |  |  | 17.0 |  |  |  | 24.9 |  |  |  | 24.9 |  |  |  | 6,861.0 |  |  |  | 0.05 |  |  |  | 7.7 |  |  |  | 7.7 |
Total |  |  | 121,143.4 |  |  |  | — |  |  |  | 179.4 |  |  |  | 113,484.3 |  |  |  | — |  |  |  | 406.4 |  |  |  | 585.9 |  |  |  | 447.4 |  |  |  | 51,774.0 |  |  |  | — |  |  |  | 204.5 |  |  |  | 153.9 |

Note that mineral resources:

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

| • |  | do not have demonstrated economic viability

| • |  | totals may not add due to rounding

86 CAMECO CORPORATION

Additional information

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

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

Decommissioning and reclamation

In our uranium and fuel services segments, we are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position. See note 15 to the financial statements.

Property, plant and equipment

We depreciate property, plant and equipment primarily using the unit-of-production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.

We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.

In performing impairment assessments of long-lived assets, assets that cannot be assessed individually are grouped together into the smallest group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Management is required to exercise judgment in identifying these cash generating units.

Taxes

When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation of deferred tax assets, changes in tax laws and our expectations for future results.

We base our estimates of deferred income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record deferred income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses, future market conditions, production levels and intercompany sales. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2021, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

2021 CONSOLIDATED FINANCIAL STATEMENTS AND NOTES 87

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

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2021.

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

New standards adopted

A number of amendments to existing standards became effective January 1, 2021 but they did not have an effect on the Company’s financial statements.

The following amendment to an existing standard is not yet effective for the year ended December 31, 2021 and has not been applied in preparing these consolidated financial statements. Cameco does not intend to early adopt the amendment.

In May 2021, the International Accounting Standards Board issued Deferred Tax related to Assets and Liabilities arising from a Single Transaction, which amended IAS 12, Income Taxes (IAS 12). The amendments are effective for periods beginning on or after January 1, 2023, with early adoption permitted. The amendments narrowed the scope of the recognition exemption in paragraphs 15 and 24 of IAS 12 (recognition exemption) so that it no longer applies to transactions that, on initial recognition, give rise to equal taxable and deductible temporary differences, such as leases and decommissioning liabilities. Cameco does not expect adoption of the standard to have a material impact on the financial statements.

88 CAMECO CORPORATION