EXHIBIT 99.3

Cameco Corporation

2020 Management’s Discussion and Analysis

February 10, 2021

Management’s discussion and analysis

February 10, 2021

8	2020 PERFORMANCE HIGHLIGHTS
13	MARKET OVERVIEW AND DEVELOPMENTS
18	OUR STRATEGY
25	OUR APPROACH TO ESG MATTERS
31	MEASURING OUR RESULTS
33	FINANCIAL RESULTS
62	OPERATIONS AND PROJECTS
86	MINERAL RESERVES AND RESOURCES
91	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, 2020. The information is based on what we knew as of February 9, 2021.

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 pages 3 and 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 2021 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 views on our ability to self-manage risk

• the discussion under the heading Our strategy

• our expectations for the restart of the Cigar Lake mine

• our confidence that we can add acceptable new long-term contracts to support the restart of our McArthur River/Key Lake operation

• the discussion under the heading Our approach to ESG matters, 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

• our expectations for uranium sales and deliveries

• the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including our expectations regarding the outcome of the appeal to the Supreme Court of Canada (Supreme Court) if leave to appeal is granted, our expectations regarding reassessments for other tax years, and our expectation that we will recover all or substantially all of the amounts paid or otherwise secured to date, including disbursements

• our estimate of the amount and timing of expected cash taxes and transfer pricing penalties

• the discussion under the heading Outlook for 2021, including our 2021 financial outlook, expectations for 2021 cash balances, and our price sensitivity analysis for our uranium segment

• the outlook for our uranium and fuel services segments for 2021

• 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 2021 capital requirements

• our expectations for 2021, 2022 and 2023 capital expenditures

• our expectation that in 2021 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

• 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, including lack of success in our dispute with CRA

• we are unsuccessful in our dispute with CRA and this ultimately gives rise to material tax liabilities and payment obligations that would have a material adverse effect on us

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

• the possibility that it will take longer to receive a decision if the Supreme Court agrees to hear an appeal, whether reassessed on the same or a different methodology

• we are unable to utilize letters of credit to the extent anticipated in our dispute with CRA

• 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

• 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 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

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

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

• 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

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS     3

• that the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being 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 JV Inkai and our fuel services operating sites

• our cost expectations, including production costs, operating 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 expectations about the outcome of our dispute with CRA, including that the lower court decisions will be upheld by the Supreme Court if leave is granted to appeal

• our assumptions regarding the methodology to be used by CRA in any subsequent year reassessments and our expectation that the lower court decisions will apply in principle to subsequent years not covered by the decisions that are reassessed using the same methodology

• the time it would take to receive a decision if the Supreme Court agrees to hear an appeal

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

• we are able to utilize letters of credit to the extent anticipated in our dispute with CRA

• 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 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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2020 performance highlights

In 2020, the world experienced unprecedented and challenging times due to the impact of the Coronavirus (COVID-19) pandemic. Consistent with our values, the health and safety of our workers, their families and their communities was our priority in 2020. 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 and to help slow down the spread of the virus. In addition to all of the safety protocols we put in place, we:

• suspended production at Cigar Lake, twice. The first suspension ran approximately five months from late March through the end of August. The second suspension was announced in mid-December and continues into 2021.

• suspended production at the Port Hope UF₆ conversion plant and at the Blind River refinery in April for approximately four weeks

• withdrew our 2020 outlook

• continued to pay all our employees

• set up and awarded COVID-19 Relief Funds totaling $1.25 million to support our northern Saskatchewan and Ontario communities impacted by the virus

• delivered 1,200 care packages containing essential supplies that residents of remote northern communities were having difficulty obtaining and provided significant numbers of personal protective equipment (masks, gloves and hand sanitizer) to these same communities

• provided personal protective equipment (PPE) to Port Hope and Blind River hospitals and police services in Ontario

Through all of the disruptions to our business, we continued to do what we said we would do, executing on all strategic fronts; operational, marketing and financial. Demand for our products remained strong and we delivered 30.6 million pounds of uranium to our customers. We generated $57 million in cash from operations, with higher average realized prices in our uranium and fuel services segments than in 2019. However, as a result of the precautionary production suspensions at our operations due to the COVID-19 pandemic, we produced only 5 million pounds in our uranium segment, well below our committed sales. To manage risk we purchased 11.5 million pounds more uranium than the top end of the 2020 outlook disclosed in our 2019 annual MD&A at an average annual cost of $40.41 per pound, totalling about $465 million, compared to the Cigar Lake expected life-of-mine cash operating costs of between $15 to $16 per pound. Additionally, due to the temporary suspensions we incurred $55 million more in care and maintenance costs than those we had planned for. Even while production was suspended, we kept and continued to pay all our employees. Partially off-setting these additional costs was the receipt of about $37 million under the Canada Emergency Wage Subsidy program and volatility in foreign exchange rates that resulted in foreign exchange gains.

On the contracting front, long-term contracting was delayed in 2020 due to ongoing market-access and trade policy issues and the impact of the COVID-19 pandemic on our customers’ operations. However, in our uranium segment, we were successful in adding 12.5 million pounds to our portolio of long-term uranium contracts. Market signals will take time to impact contracting in our business as we have seen with the transition in our fuel services segment. With our pipeline of uranium business continuing to grow and being larger than we have seen since 2011, we are being patient to capture as much value as possible in our contract portfolio. We continue to see off-market interest, which we believe tends to be a leading indicator of broader demand for long-term contracting. In our fuel services segment, we had a very successful year, replacing the volumes we delivered under contract and adding another 17.1 million kilograms of UF₆ to our long-term contract portfolio that reflect the price transition that began in 2017 in the conversion market, and that we expect will allow us to continue to profitably operate and consistently support the long-term fuel services needs of our customers.

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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. As of December 31, 2020, we had $943 million in cash and short-term investments and $1.0 billion in long-term debt. During the year, the impacts of the COVID-19 pandemic caused disruptions to global financial markets, and incented government stimulus packages and significant interest rate reductions. On October 21, 2020, consistent with our conservative financial management, and to take advantage of the low interest rate environment resulting from the COVID-19 pandemic, we issued debentures in the amount of $400 million, at an interest rate of 2.95% per annum and used the proceeds to redeem our outstanding $400 million debenture bearing interest of 3.75%, resetting the maturity from 2022 to 2027 and extending our maturity profile. The early redemption resulted in a cost of $24 million. Our next maturity is in 2024. In addition, we have a $1.0 billion undrawn credit facility.

We also received a unanimous decision in our favour from the Federal Court of Appeal (Court of Appeal) in our dispute with Canada Revenue Agency (CRA). The decision upholds the September 26, 2018 decision of the Tax Court of Canada (Tax Court), which was unequivocally in our favour for the 2003, 2005 and 2006 tax years and it sustains the corresponding decision on the cost award. We believe the principles in the decision apply to all tax years subsequent to 2006. CRA has made an application to the Supreme Court of Canada (Supreme Court) to seek leave to appeal the decision of the Court of Appeal. The Supreme Court will decide whether to hear the appeal or decline CRA’s request for leave. If the appeal is heard, we estimate that it could take until the second half of 2022 before a decision is rendered by the Supreme Court.

The COVID-19 pandemic has disrupted global uranium production, adding to the supply curtailments that have occurred in the industry for many years. The duration and extent of these disruptions are still not fully known. The uranium spot price increased by more than 35% following announcement of the initial supply disruptions due to the COVID-19 pandemic in March and April, reaching a high of about $34 (US) per pound in 2020. The average uranium spot price ended the year at $30.20 per pound (US) more than 20% higher than the average uranium spot price at the end of 2019.

Around the globe there is an increasing focus on electrification for various reasons. There are countries looking to install baseload power, while others are looking for a reliable replacement to fossil fuel sources, and finally, there is new demand for things such as the electrification of transportation. This is occurring at precisely the same time that countries and companies around the world are committing to net-zero carbon targets. This has led to the recognition, from a policy point of view, that nuclear will be needed in the toolbox to sustainably achieve electrification and decarbonization goals.

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. Over time, we expect this renewed focus on security of supply will provide the market signals producers need. We are taking the steps today and incurring the costs that we believe will allow us to restart our tier-one assets with more flexibility in the production rate, eliminate the care and maintenance costs incurred while our tier-one production is suspended and to benefit from the favourable life-of-mine economics our assets provide. Throughout, 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.

Financial performance

HIGHLIGHTS
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)	2020		2019		CHANGE
Revenue		1,800		1,863		(3)	%
Gross profit		106		242		(56)	%
Net earnings (loss) attributable to equity holders		(53)		74		>(100	%)
$ per common share (diluted)		(0.13)		0.19		>(100	%)
Adjusted net earnings (loss) (non-IFRS, see page 35)		(66)		41		>(100	%)
$ per common share (adjusted and diluted)		(0.17)		0.10		>(100	%)
Cash provided by operations (after working capital changes)		57		527		(89)	%

Net earnings attributable to equity holders (net earnings) and adjusted net earnings were lower in 2020 compared to 2019. See 2020 consolidated financial results beginning on page 34 for more information. Of note:

• generated $57 million in cash from operations

MANAGEMENT’S DISCUSSION AND ANALYSIS     9

• incurred $196 million in care and maintenance costs as a result of our strategic decisions, including $55 million due to the precautionary operational decisions made to deal with the risks posed by the COVID-19 pandemic

• received $37 million under the Canada Emergency Wage Subsidy program

• issued debentures in the amount of $400 million, at an interest rate of 2.95% per annum and used the proceeds to redeem our outstanding $400 million debenture bearing interest of 3.75%, resetting the maturity from 2022 to 2027 and resulting in an early redemption fee of $24 million

• received a unanimous decision in our favour from the Federal Court of Appeal in our dispute with CRA. See Transfer pricing dispute on page 39 for more information.

Our segment updates

In our uranium segment, we continue to execute our strategy. In addition, we have made a number of proactive decisions in response to the risks posed by the COVID-19 pandemic and to ensure a safe working environment for all our workers which has had an impact on our operations. Of note:

• continued the production suspension at McArthur River/Key Lake, removing 18 million pounds per year (100% basis) from the market

• suspended production at Cigar Lake, twice. The first suspension ran approximately five months from late March through the end of August. The second suspension was announced in mid-December and continues into 2021.

• annual production of 5.0 million pounds was 44% lower than in 2019, and below the outlook provided in our 2019 annual MD&A due to the impacts of the COVID-19 pandemic on our operations

• purchased 33.5 million pounds of uranium, including our spot purchases, committed purchase volumes, JV Inkai purchases and the purchase of our NUKEM subsidiary’s excess inventory

• delivered on our sales commitments of 30.6 million pounds

Production in 2020 from our fuel services segment was 12% lower than in 2019, as a result of production disruptions due to the COVID-19 pandemic. We suspended production at the Port Hope UF₆ conversion plant and at the Blind River refinery in April for approximately four weeks.

See Operations and projects beginning on page 62 for more information.

HIGHLIGHTS			2020		2019		CHANGE
Uranium	Production volume (million lbs)			5.0		9.0		(44	)%
	Sales volume (million lbs)			30.6		31.5		(3	)%
	Average realized price	($US/lb)		34.39		33.77		2	%
		($Cdn/lb)		46.14		44.85		3	%
	Revenue ($ millions)			1,412		1,414		—
	Gross profit ($ millions)			13		153		(92	)%
Fuel services	Production volume (million kgU)			11.7		13.3		(12	)%
	Sales volume (million kgU)			13.5		14.1		(4	)%
	Average realized price	($Cdn/kgU)		27.89		26.21		6	%
	Revenue ($ millions)			377		370		2	%
	Gross profit ($ millions)			96		90		7	%

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Industry prices

	2020		2019		CHANGE
Uranium ($US/lb U3O8)1
Average annual spot market price		29.96		25.64		17	%
Average annual long-term price		34.63		31.75		9	%
Fuel services ($US/kgU as UF6)1
Average annual spot market price
North America		21.94		18.27		20	%
Europe		21.09		18.12		16	%
Average annual long-term price
North America		18.27		16.73		9	%
Europe		18.18		16.63		9	%

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 2020 was approximately 92.2 million pounds U₃O₈ equivalent, compared to 64.3 million pounds U₃O₈ equivalent in 2019. The 2020 total surpassed the previous annual record of 88.7 million pounds U₃O₈ equivalent in 2018. Non-utility purchases made up a significant portion of the 2020 spot market activity. Spot market volumes were significant in the second quarter of the year due to unplanned uranium supply disruptions resulting from the COVID-19 pandemic, then slowed through the balance of 2020. At the end of 2020, the average reported spot price was $30.20 (US) per pound, up $5.27 (US) per pound from the end of 2019. During the year, the uranium spot price ranged from a high of $33.93 (US) per pound to a low of $24.63 (US) per pound, averaging $29.96 (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 fixed prices escalated over the term of the contract, and market referenced prices (spot and long-term indicators) quoted near the time of delivery. While 2020 saw resolution to a number of geopolitical issues, including recommendations from the Nuclear Fuel Working Group and the extension of the Russian Suspension Agreement, term volumes were the lowest since 2013. The volume of long-term contracting reported by UxC for 2020 was about 53 million pounds U₃O₈ equivalent, down from about 95.8 million pounds U₃O₈ equivalent in 2019. Lower volumes can be attributed in part to utilities focusing on operational safety amidst the COVID-19 pandemic. The average reported long-term price at the end of the year was $35.00 (US) per pound, up $2.50 (US) from 2019.

With continued uncertainty related to the COVID-19 pandemic and ongoing trade matters, we expect contracting in 2021 could remain largely discretionary.

While the average reported spot price for North American delivery at the end of 2020 was $21.75 (US) per kilogram uranium as UF₆ (US/kgU as UF₆), down $0.38 (US) from the end of 2019, spot UF₆ conversion prices reached record highs in both the North American and European markets during the year. Long-term UF₆ conversion prices finished 2020 at $19.00 (US/kgU as UF₆), up $0.87 (US) from the end of 2019.

MANAGEMENT’S DISCUSSION AND ANALYSIS     11

SHARES AND STOCK OPTIONS OUTSTANDING

At February 8, 2021, we had:

• 396,862,440 common shares and one Class B share outstanding

• 5,556,110 stock options outstanding, with exercise prices ranging from $11.32 to $26.81

DIVIDEND

In 2020, our board of directors declared a dividend of $0.08 per common share, which was paid December 15, 2020. The decision to declare an annual dividend by our board will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

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Market overview and developments

Growing confidence

In 2020, the COVID-19 pandemic disrupted global uranium production which added to the planned supply curtailments that have occurred in the industry for several years. The duration and extent of these disruptions are still not fully known. As a result, there was significant demand from producers – including Cameco – in the spot market to cover both the planned and unplanned reductions in primary supply. In contrast, long-term contracting was significantly reduced compared to 2019 as utilities focused on ensuring the safety of their employees and keeping their nuclear plants running to support the critical infrastructure needed throughout the pandemic. In addition, market access and trade policy issues continued to top the list of factors affecting the market in 2020. These issues created uncertainty and consumed a significant amount of time and focus from utilities during the year. The volume of uranium executed under long-term contracts was well below annual consumption levels, accelerating the inventory destocking that was already underway in the industry and adding to the growing wedge of uncovered requirement that we believe will need to be filled at a time when the availability of sufficient supply is not guaranteed. We expect a renewed focus on security of supply will provide the market signals producers need and we have growing confidence that the uranium market will undergo the same transition that is occurring in the conversion and enrichment markets.

Supply is not guaranteed

Low uranium prices, government-driven trade policies, and the COVID-19 pandemic continued to have an impact on the security of supply in our industry. 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 on uranium mining and processing activities. Uranium is a highly trade-dependent commodity, and 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. About 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, about 80% 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. Some of the more significant supply and trade policy developments in 2020 and to-date are:

• Unplanned production disruptions at various production facilities due to the COVID-19 pandemic, including at the Cigar Lake mine and the McClean Lake mill, and across all uranium mines in Kazakhstan resulted in 2020 global uranium production being down about 15% compared to 2019 and led to an increase in spot market purchases by producers. Production in 2020 represented the lowest annual production since 2008, accounting for only 77% of reactor requirements.

• Kazatomprom (KAP) reaffirmed its intention to maintain its aggregate production reduction of 20% compared to planned levels under subsoil use contracts in 2021, with no additional production planned to replace the volumes lost in 2020 resulting from measures taken to combat COVID-19. It also announced its plan to extend the 20% reduction through 2022. KAP said full implementation of its decision would remove up to 14.3 million pounds U₃O₈ from 2022 expected global primary supply.

• During the year, KAP offered a secondary placement of its shares, increasing publicly-traded share capital from 15% to 18.8%.

• China General Nuclear Power Group is expected to acquire 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 per year and the planned Zhalpak ISR mine with expected capacity of 1.95 million pounds U₃O₈ per year, subject to obtaining regulatory and government approvals.

• In December, the US Congress approved an omnibus spending bill for fiscal 2021, which will provide nearly $1.5 billion (US) in spending for nuclear programs. Notably it includes initial funding of $75 million (US) for the creation of a national uranium reserve. This funding, which was a primary recommendation in a strategy report released in April by the US Nuclear Fuel Working Group, opens the door for the US government to purchase domestically produced uranium and UF₆ to guard against potential commercial and national security risks as a result of the country’s near-total reliance on foreign imports.

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• The American Nuclear Infrastructure Act, a bipartisan U.S. Senate bill, was approved in December, though full review is not expected until the next US Congress in 2021. The bill addresses national security, economic, and climate change elements related to the nuclear sector.

• An amendment to the Russian Suspension Agreement (RSA) was signed that extends the agreement from January 1, 2021 through December 31, 2040 and provides a clear set of rules around access to the US nuclear energy sector by Russian nuclear fuel suppliers. Since 1992, the importation of Russian uranium products in the US has been subject to a quota under the US-Russia Agreement Suspending the Antidumping Investigation on Uranium from the Russian Federation (the Russian Suspension Agreement). The amendment reduces the average overall quota and introduces caps, which will reduce the amount of Russian uranium, conversion and enrichment supplied to the US over the long-term. The amendment also includes important new provisions to ensure that all Russian origin uranium must be counted against the quota even if it is imported after further processing in other countries.

• BHP indicated that the economics for its expansion plans at the Olympic Dam mine (ODM) were challenging, and that it has decided not to proceed with the expansion at this time. ODM currently produces approximately 8 million pounds U₃O₈ per year and the expansion was projected to increase its annual uranium production up to as much as 14 million pounds.

• Energy Resources of Australia Ltd. announced on January 8, 2021 that processing operations have officially been discontinued at the Ranger uranium mine in the Northern Territory of Australia. The mine had averaged about 4 million pounds U₃O₈ in recent years and this shutdown concludes over 35 years of production.

• The board of directors of Orano’s Cominak mine announced that the mine will shut down in March 2021 due to depletion of reserves. The mine had been producing about 3 million pounds U₃O₈ in recent years.

Demand has recovered and is growing

The demand gap left by forced and premature nuclear reactor shutdowns since March of 2011 was filled in 2018. According to the International Atomic Energy Agency there are currently 443 reactors operating globally and 52 reactors under construction. With a number of reactor construction projects recently approved, and many more planned, the demand for uranium is growing. This growth is largely occurring in Asia and the Middle East. Some of this growth is tempered by early reactor retirements, plans for reduced reliance on nuclear, or phase-out policies in other regions. In addition, the COVID-19 pandemic is expected to have a negative impact on global energy demand in the near term. For 2020, the International Energy Agency (IEA) expects global electricity demand to fall by 5% over 2019 with nuclear declining by 2.5% due to lower demand and delays for planned maintenance and construction of several projects. However, there is growing focus on electrification and an increasing recognition of the role nuclear power must play in providing safe, reliable, affordable carbon-free baseload electricity and achieving a low-carbon economy. Momentum is also building for non-traditional commercial uses of nuclear power such as development of small modular reactors and advanced reactors, with numerous companies and countries pursuing projects. With the ongoing challenges posed by the COVID-19 pandemic, many governments will continue to rely on nuclear plants as part of the critical infrastructure needed to guarantee the availability of 24-hour power. Some of the more significant demand developments in 2020 and to-date are:

• Many countries, US states, and utilities announced net-zero carbon targets in 2020. While most of these targets are further out in the future, many of the plans include an important role for nuclear. For example, a study suggests that for China to achieve its net-zero target by 2060, will require a 382% increase in nuclear power from 2025 levels.

• In the US, President Biden’s campaign included positive statements about the need to maintain the existing nuclear power fleet and to build advanced reactors as part of an overall shift to non-emitting carbon power sources.

• Exelon announced plans to close its Byron and Dresden nuclear plants in Illinois in 2021, pointing to economics challenged by declining energy prices and market rules.

• Energy Harbor is facing challenges as a state law providing subsidies to its two nuclear plants in Ohio, Davis Besse and Perry, is now in question due to a lobbying and bribery scandal.

• In China, one new reactor began commercial operations in 2020 and two new reactor construction starts were recorded. A fourth power company, China Huaneng Group, was licensed to operate nuclear reactors in China.

• China’s 14^th Five-Year Plan and related policy documents covering the 2021-2025 period is ongoing, and publication of the plan is expected in March 2021.

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• In Japan, many of the nine restarted reactors were off-line for a period of time for maintenance outages and antiterrorism upgrades. However, Kyushu’s Genkai 3 and Sendai 1 and 2, and Kansai’s Ohi 4 have restarted and are operating after meeting the new standards. Following the completion of upgrades and local approvals, three additional units are expected to restart in 2021, including Kansai’s Takahama 1 and 2, and Mihama 3.

• Japan’s Prime Minister, Yoshihide Suga, announced that the country aims to become carbon neutral by 2050. Regarding nuclear, he indicated Japan will continue to develop its nuclear energy supply with “maximum priority on safety”. Japan’s current energy plan calls for 20% to 22% nuclear by 2030.

• In France, President Macron stated in December that nuclear will remain a pillar of the French energy mix for decades to come and pressed for preparatory studies on new next-generation EPR reactors to be wrapped up in the coming months.

• Two countries had their first nuclear power plants connected to the grid in 2020: United Arab Emirates with Barakah 1, and Belarus with Ostrovets 1. These are the first two countries to begin new nuclear power production since 2013.

• In Eastern Europe, important steps were made to advance nuclear power in several countries including Hungary, Poland, Bulgaria, Romania, Ukraine and Slovenia.

• Belgium confirmed its 2025 nuclear phase-out policy, but left the door open for two to three reactors to stay online longer.

• The Netherlands announced they will begin a process that considers building up to 10 nuclear power plants.

• India’s first domestically designed 700 MWe pressurized heavy water reactor was launched at Kakrapar, an important milestone for the country. Three more units of this design are expected to come online in the next few years.

• In South Korea, according to current government plans, no new nuclear power plants will be built in the country, except those already under construction. Existing nuclear power facilities will continue to operate but will not be granted operating extensions.

MANAGEMENT’S DISCUSSION AND ANALYSIS     15

OPPORTUNITIES FOR THOSE WHO CAN WAIT

UxC reports that over the last five years only approximately 390 million pounds U₃O₈ equivalent have been locked-up in the long-term market, while approximately 815 million pounds U₃O₈ equivalent have been consumed in reactors. We remain confident that utilities have a growing gap to fill.

Like other commodities, the uranium industry is cyclical. History demonstrates that in general, when prices are rising and high, uranium is perceived as scarce, and a lot of contracting activity takes place. The heavy contracting that takes place during price runs, drives investment in higher-cost sources of production. Once that production is in the market, it tends to stay in the market longer than is economically rational, creating the perception that uranium is abundant and always will be, and prices decline. 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 investment in supply, as has been the case since 2011, security of supply tends to overtake price concerns at some point, and utilities re-enter the long-term market to ensure they have the reliable supply of uranium they need to run their reactors.

We believe the current backlog of long-term contracting presents a substantial opportunity for commercially motivated suppliers like us that can weather the low-price part of the cycle. As a low-cost producer, we manage our operations with these price cycles in mind.

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In our industry, customers do not come to the market right before they need to load uranium 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. The longer the recovery of the long-term market is delayed, the less certainty there will be about the availability of future supply to fill growing demand. In fact, recent data from the US Energy Information Administration shows that utility inventories are starting to decline and are approaching levels that could put security of supply at risk. Ultimately, we expect the current market uncertainty to give way to increasing concerns about the security of future supply.

As utilities’ uncovered requirements grow, annual supply declines, demand for uranium from producers and other intermediaries increases, and with trade policy potentially restricting access to some markets, we believe the pounds available in the spot market will not be adequate to satisfy future demand. As a result, 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.

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, nuclear remains an important part of the energy mix. We remain confident in the future of the nuclear industry. With demand increasing due to restarts and new reactors, and supply becoming less certain as a result of low prices, production curtailments, lack of investment, end of reserve life, unplanned production disruptions, shrinking secondary supplies and trade policy issues, we’re continuing to expect a market transition. While the timing of a market transition remains uncertain, we will continue to take the actions we believe are necessary to position the company for long-term success. Therefore, we will undertake contracting activity which aligns with the uncertain timing of a market recovery and is intended 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 uncommitted, low-cost supply to place into a strengthening market.

MANAGEMENT’S DISCUSSION AND ANALYSIS     17

Our strategy

Our strategy is set within the context of a challenging market environment, which we expect to give way to strong long-term fundamentals driven by increasing populations, and a growing focus on electrification and decarbonization. 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.

Tier-one focus

We are a pure-play nuclear fuel investment, focused on providing a clean source of energy, and taking advantage of the long-term growth we see coming in our industry. Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to preserve the value of those assets and increase long-term value, and to do that 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. In accordance with market conditions, and to mitigate risk, we will 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. We will not produce from our tier-one assets to sell into an oversupplied spot market. During a prolonged period of uncertainty, this could mean leaving our uranium in the ground, which we began doing in 2016. As conditions improve, we expect to meet rising demand with production from our best margin operations.

We are focused on preserving the value of our lowest cost assets, on maintaining a strong balance sheet, on protecting and extending the value of our contract portfolio and on efficiently managing the company in a low-price environment. We have undertaken a number of deliberate and disciplined actions. In 2020, these actions resulted in:

• generation of $57 million in cash from operations

• issuing debentures in the amount of $400 million, bearing interest of 2.95% per annum and redeeming our outstanding $400 million debenture bearing interest of 3.75%, resetting the maturity from 2022 to 2027

• a year-end balance of $943 million in cash on our balance sheet

Consistent with our actions, our McArthur River/Key Lake operation remains on care and maintenance for an indeterminate duration, removing 18 million pounds of uranium annually from the market. In addition, due to the risks posed by the COVID-19 pandemic, we start 2021 with production at the Cigar Lake mine temporarily suspended. The restart of the Cigar Lake mine is dependent on our ability to maintain safe and stable operating protocols along with a number of other factors, including how the COVID-19 pandemic is impacting the availability of the required workforce, how cases are trending in Saskatchewan, in particular in northern communities, and the views of public health authorities. Our actions have a cost in the short term, and we must weigh these costs against the value we expect they will generate over the long term. Accordingly, we will adjust our actions based on market signals with the intent of being able to self-manage risk, and to ensure our tier-one assets are available to us in a market that values them appropriately.

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.

The UF₆ conversion market has gone through a transition that has seen the industry average North American spot price roughly quadrupled and the industry average North American term price increase by nearly 50% since the end of 2017. In this environment, with our Port Hope facility the only UF₆ plant currently operating in North America, we are focused on securing new long-term contracts that reflect today’s prices and that will allow us to continue to 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.

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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.

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 commercially enrich uranium.

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:

• create the greatest long-term value

• allow us to execute on our strategy and mitigate risk

• allow us to execute on our dividend while ensuring it is appropriately aligned with the cyclical nature of our earnings

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

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.

With the continued market uncertainty we are facing, our tier-one assets on care and maintenance and our ongoing dispute with CRA, the objective of our capital allocation is to maximize cash flow, while navigating by our investment-grade rating through close management of our balance sheet metrics.

With the metrics that inform an investment-grade rating in mind, we have taken steps to improve margin and cash flow by:

• responsibly managing our sources of supply thereby preserving the value of our tier-one assets

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

• retiring our $500 million 2019 debenture on maturity to reduce our total debt to $1 billion

• issuing debentures in the amount of $400 million, bearing interest of 2.95% per annum and redeeming our outstanding $400 million debenture bearing interest of 3.75%, resetting the maturity from 2022 to 2027

• reducing our annual dividend from $0.40 per share to $0.08 per share in 2018

• implementing an initiative intended to provide a greater focus 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 a result, we are well positioned to self-manage risk.

REINVESTMENT

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     19

We have not yet seen the market transition needed to restart our idled production capacity. Therefore, until we see that transition, our capital expenditures will be focused primarily on sustaining and capacity replacement capital and demonstrating our continued commitment to a clean environment through ongoing investment in the Vision in Motion project in Port Hope. In addition, 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 when it comes time to restart the McArthur River/Key Lake operation. Any opportunities will be rigorously assessed before an investment decision is made. If we get clarity on our CRA dispute prior to a 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 does begin to transition and higher uranium prices are beginning to flow 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 priority would be to invest in restarting our idled tier-one assets, and if warranted, turn to value-adding growth opportunities and to return excess cash 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 were 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.

Marketing framework – balanced contract portfolio

As with our corporate strategy and approach to capital allocation, the purpose of our marketing 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.

We evaluate our strategy in the context of our market environment and continue to adjust our actions in accordance with our marketing 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 will 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.

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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 maximizing cash flow, so we can 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 with suppliers and 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.

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 target a portfolio of long-term contracts that have a ratio of 40% fixed-pricing and 60% 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 and 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.

Fixed-price 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 fixed-price 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 fixed price mechanism per kgU, escalated over the term of the contract, and reflect the market at the time the contract is accepted.

MANAGEMENT’S DISCUSSION AND ANALYSIS     21

OPTIMIZING OUR CONTRACT PORTFOLIO

We work with our customers to optimize the value of our contract portfolio. With respect to new contracting activity, as we have seen in our fuel services segment, there is often a lag from when contracting discussions begin and when contracts are executed. With our pipeline of business under negotiation in our uranium segment being larger than we have seen since 2011, and a value driven strategy, we are being strategically patient in considering the commercial terms we are willing to accept. Much of our pending business is off-market and, in the past, off-market activity has been a leading indicator of a contracting cycle. We remain confident that we can add acceptable new sales commitments to our portfolio of long-term contracts to support the restart of our McArthur River/Key Lake operation. 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 low prices, with a fixed-price mechanism. Our goal is to balance all these factors, along with our desire for 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 113 million pounds of U₃O₈ with 32 customers worldwide in our uranium segment, and over 53 million kilograms as UF₆ conversion with 31 customers worldwide in our fuel services segment. The annual average sales commitments over the next five years in our uranium segment is around 16 million pounds, with commitment levels in 2021 and 2022 higher than in 2023 through 2025.

Customers – U₃O₈:

Five largest customers account for 60% of commitments

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Customers – UF₆ conversion:

Five largest customers account for 54% of commitments

MANAGING OUR CONTRACT COMMITMENTS

To meet our delivery commitments, we use our uranium 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 existing inventory

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

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

Given the current market dynamics and the risks posed by the COVID-19 pandemic, we start 2021 with all our uranium mining operations on care and maintenance. We expect to restart Cigar Lake, but the timing and the production rate will be dependent on how the COVID-19 pandemic is impacting the availability of the required workforce at Cigar Lake, how cases are trending in Saskatchewan, in particular in northern communities, and the views of public health authorities. In general, while McArthur River and Key Lake are shut down, our annual cost of production is expected to reflect the estimated life-of-mine operating cost, between $15 and $16 per pound, of mining and milling our share of Cigar Lake mineral reserves. However, our cash production costs in 2021 may be impacted by the timing of the restart and the production rate of Cigar Lake.

Operating costs in our fuel services segment are mainly fixed. In 2020, 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).

CARE AND MAINTENANCE COSTS

In 2021, we expect to incur between $150 million and $170 million in care and maintenance costs related to the suspension of production at our McArthur River/Key Lake mine and mill, Rabbit Lake mine and mill, and US operations. The largest proportion of these costs will be incurred at McArthur River/Key Lake. In addition, we expect to incur care and maintenance costs of between $8 million to $10 million per month while production at Cigar Lake is suspended due to the risks posed by the COVID-19 pandemic.

As noted above, the restart of Cigar Lake is dependent on the risks posed by the COVID-19 pandemic. At McArthur River/Key Lake, the restart of the mine and mill is a commercial decision that will be based on our ability to commit our share of production from this operation under acceptable long-term contracts and to benefit from the favourable life-of-mine economics it provides. Therefore, while on care and maintenance we are focused on improving operational effectiveness, including the use of digital and automation technologies. Our goal is to streamline our processes and leverage digital and automation technologies to reduce our future operating costs and increase the degree of operating flexibility we have when we restart this tier-one asset and eliminate the costs associated with care and maintenance. As a result, care and maintenance costs are expected to be higher for McArthur River/Key Lake compared to Rabbit Lake and in the US. Upon its restart, care and maintenance costs at McArthur River/Key Lake will be eliminated. Our Rabbit Lake and US operations are higher-cost, and with plenty of idle tier-one capacity and tier-one expansion capacity globally that can come back on line relatively quickly, the restart horizon is less certain.

While Rabbit Lake and our US operations are in standby, we will continue to evaluate our options in order to minimize costs.

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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, and purchases we make on the spot market. In 2021, 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.

FINANCIAL IMPACT

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

We have taken a number of deliberate and disciplined actions to reduce supply and streamline operations. Some of these actions come with a cost in the near term, 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 will help shield the company from the nearer term risks we face and will reward shareholders for their continued patience and support of our strategy to build long-term value.

Our approach to ESG matters

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. 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 identifying and addressing the environmental, social and governance (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 at the core of everything we do and define who we are as a company.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     25

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.

SUSTAINABILITY: A KEY PART OF OUR STRATEGY, REFLECTING OUR VALUES

We are committed to delivering our products responsibly. This is why we integrate sustainability principles and practices into all stages of our activities, from exploration to decommissioning. We factor them into every aspect of our business, from our objectives and approach to compensation, to our overall corporate strategy and day-to-day operations. We adopt established and recognized management system frameworks to guide our integrated approach, which is embedded within ethical business practices and our robust and transparent governance framework. 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 have a sustainability policy that describes our commitments in this regard. We encourage you to review our sustainability policy at cameco.com/about/governance/policies-programs.

Environment

We employ an integrated management system that applies to all phases and aspects of our business. The system is governed by our integrated Safety, Health, Environment and Quality (SHEQ) policy, which recognizes that the safety and health of our workers and the public, protection of the environment, and quality of our processes are the highest priority during all stages of our operations. The policy is supported by multiple corporate SHEQ management programs. We maintain ISO 14001 certification of our environmental management program at a corporate level. We encourage you to review our SHEQ policy at cameco.com/about/governance/policies-programs.

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 and that we are well positioned to deliver significant long-term business value, while actively working to reduce our emission profile.

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There is growing recognition of the role nuclear power must play in ensuring safe, reliable and affordable carbon-free electricity generation. This recognition from key global agencies, such as the United Nations Economic Commission for Europe, the United Nations Intergovernmental Panel on Climate Change, and the Union of Concerned Scientists is important because it acknowledges that nuclear power is needed to credibly achieve commitments under the Paris Agreement or transition to a net-zero carbon future. Indeed, in 2019, for the first time in nearly two decades, the International Energy Agency released a report on nuclear energy in the hopes of bringing it back into the global energy debate. The report highlighted that a steep decline in nuclear power would threaten energy security and climate change goals and result in four billion tonnes of additional carbon emissions by 2040.

The nuclear industry recognizes the scale and immediacy of the challenge outlined in the Paris Agreement, and the important role that all low-carbon and carbon-free energy sources have to play. Led by the World Nuclear Association, the nuclear industry has a program and vision for the future of electricity supply called “Harmony”. The Harmony program sets a target for nuclear power to provide 25% of electricity by 2050 to help avoid the worst consequences of climate change. As members of the World Nuclear Association, and through participation in other industry organizations we fully support and are advocates of this initiative.

Uranium is, in our view, the world’s most significant zero emission fuel. Uranium’s heat value is thousands to tens of thousands of times greater than any other available fuel meaning that a tiny amount of uranium can generate a huge amount of emission-free electricity as nuclear power. The uranium we supply plays a significant role in contributing to GHG mitigation efforts in Canada and abroad. Within Canada, this uranium fuel provides greater than 30% of the province of Ontario’s power every year, avoiding more than 5,000,000 tonnes of carbon dioxide from being emitted into the atmosphere. It enables the province of Ontario to maintain the massive carbon reduction that was fully realized in 2014 when the proportion of electricity produced by nuclear power was increased in that province. Considering only the domestic emissions avoided resulting from the use of nuclear power in Ontario, we could claim to be one of Canada’s first net-zero carbon companies.

We have tracked and reported GHG emissions for more than two decades before it was a regulatory requirement to do so. In the past few years, the emissions of our Canadian operations have become regulated through Canadian output-based performance standard programs. These programs are intended to ensure business competitiveness and prevent carbon leakage. As an organization, we continue to be focused on improving energy management and the visibility of energy consumption within our organization, with the overall goal of improving the energy intensity of our operations to create business value.

Social

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. Our Pandemic Plan and Local and Corporate Business Continuity Plans continue to be in effect across our global operations.

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. We:

• asked employees at corporate office to work remotely from home

• asked that all meetings be conducted by phone or videoconference where possible

• suspended all business travel

• restricted non-essential contractors, visitors and deliveries at all locations

• put in place screening protocols for access to our facilities that align with the guidance of government and public health authorities

• implemented a number of additional protective measures in the workplace, including increased sanitization, physical barriers and physical distancing as well as enhancing use of personal protective equipment

• suspended work on the VIM project in Port Hope

MANAGEMENT’S DISCUSSION AND ANALYSIS     27

• suspended production at Cigar Lake in late March through August – production was suspended again in December and currently remains suspended

• suspended production, at the Port Hope UF₆ conversion facility and at the Blind River refinery in April for about four weeks

• set up and awarded COVID-19 Relief Funds totaling $1.25 million to support our northern Saskatchewan and Ontario communities impacted by the virus

• donated significant volumes of personal protective equipment, including masks, gloves, hand sanitizer, respirators and cartridges, respirator wipes, and safety eyewear

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. We continue to actively monitor the pandemic, and our screening and safety measures will remain in place for the foreseeable future. We will continue to work closely with the relevant health authorities to ensure our protocols align with their guidance.

Safety

The safety and health of our workers and the public is the highest priority during all stages of our activities.

We employ an integrated management system that applies to all phases and aspects of our business. The system is governed by our integrated SHEQ policy and is supported by multiple corporate SHEQ management programs.

Our operations have a strong safety record. We employ systematic programs to identify, evaluate and mitigate risks and engage all workers and managers in development of a strong safety culture. These programs follow the international OHSAS 18001 model and have delivered increasingly noteworthy and recognized safety performance.

Inclusion and Diversity

We have made a formal commitment to inclusion and diversity that is communicated company-wide through our value statements. We understand the value of a diverse workforce and we embrace, encourage and support workplace inclusion and diversity. Members of a diverse workplace bring new ideas, perspective, experiences and expertise to the company. Our diversity vision is to create a work environment where inclusion is the goal, and a diverse and representative workforce is our measure of success. We have a people policy that describes our commitment to developing and supporting a flexible, skilled, stable and diverse workforce, and acting to eliminate racism wherever it exists. The policy is supported by multiple corporate human resource programs, standards and practices. We encourage you to review this policy at cameco.com/about/governance/policies-programs.

We want a culture where each of our workers feel welcome, valued and an integral part of the team and we recognize that in order to successfully progress towards this culture, we must engage members of the workforce throughout the journey. In 2021, this work will be championed through the establishment of an Inclusion and Diversity committee. Members of the committee will be drawn from across the organization and will help us engage the workforce through open and respectful communication, will advocate, lead and support change and provide awareness and understanding of the benefits of inclusion and diversity. The committee will report to the President and CEO, and the Senior Vice-President and Chief Corporate Officer.

Diversity is an important element of executive and board leadership. We have commitments in our diversity and inclusion plan to ensure leadership is at the forefront of our diversity agenda. We strive for a complement of female officers that, at a minimum, reflect the proportion of women in our workforce. We expect that our long-term diversity and inclusion plan will result in more women being identified and prepared for senior level positions within the company. Our board has a diversity policy that was put in place to ensure that the members of the board have the necessary range of perspectives, experience and expertise required to achieve our objectives. The board has also set specific diversity objectives (which they currently meet or exceed) for gender diversity as well as the inclusion of Indigenous directors on the board.

For more information about diversity and inclusion at Cameco, see our most recent management proxy circular.

Stakeholder relations

The long-term sustainability of our business is dependent upon our ability to effectively build relationships with, work with, and add value for our stakeholders.

28     CAMECO CORPORATION

From community liaison groups and industry associations, to registered charities, regulators, customers, suppliers, contractors, the investment community and our employees, we recognize the value of maintaining many long-term relationships that help us succeed together. All are important but none more so than the relationships we hold with our workers and Indigenous people working and living near our operations.

Informed by best practices, we set standards for the ways we meaningfully engage with and are involved with our stakeholders to ensure we fulfil our obligations to them.

We strive to earn the support of the communities in which we operate, which is one of our key measures of success. We identify opportunities and initiatives that support and respect these communities and their cultures.

We recognize the substantial value in developing and maintaining long-term mutually beneficial relationships with Indigenous communities located within or near our operations and other activities.

Over more than 30 years of operation in Saskatchewan and Ontario and partnerships in northern Saskatchewan and northern Ontario, we have developed a comprehensive strategy that applies to all our operations globally and is aimed at ensuring the support of the communities with whom we work. We achieve success at our sites when we involve, train, and engage local people. This global strategy is flexible and is implemented locally to reflect the needs of the Indigenous and other local communities. The bulk of the strategy has evolved from the commercial benefits we see from building and maintaining strong support among local communities wherever we operate and focuses on five key areas:

• Workforce development: designed to deliver programming that aims to build educational and skills capacity in local communities.

• Business development: designed to promote involvement of locally-owned businesses in contracting opportunities at our operations, to provide additional jobs, revenue streams and capacity building at the local community level.

• Community engagement: designed with the objective to ensure that we secure support for our operations from local communities and satisfy the obligations placed on us by regulators and laws.

• Community investment: designed to help local communities with much-needed funding for community programming and infrastructure for initiatives focused on youth, education and literacy, health and wellness, and community development.

• Environmental stewardship: designed to support our overall environmental programming and give communities a voice in both the formal environmental assessment regulatory process, as well as ongoing monitoring activities.

Wherever we operate, it is our goal to ensure local people are aware of and understand our activities and have opportunities to provide input. Engaging communities and keeping them informed throughout all phases of our operations is a priority for us. We set standards for the measures that we will conform to in maintaining ongoing and meaningful engagement within the communities where we operate.

Ethics and Business Integrity

We have a reputation for maintaining the highest standards of ethical behaviour, which has helped us to grow into the global business we are today. Our Code of Conduct and Ethics guides us in ethical conduct as we fulfil our roles, and our Supplier Code of Conduct and Ethics sets out our expectations for suppliers to ensure a sustainable and ethical supply chain. Our Global Anti-Corruption Program also guides employees to ensure that the integrity of our relationships is maintained. You can access our Code of Conduct and Ethics and Supplier Code of Conduct and Ethics at cameco.com/about/sustainability/our-approach-to-esg-reporting/governance.

Governance: Sound governance is the foundation for strong performance

We believe that sound governance is the foundation for strong corporate performance. Our board of directors is responsible for overseeing management, and our strategy and business affairs, including the integration of ESG principles throughout the company. The board’s goal is to ensure we operate as a sustainable business, optimizing financial returns while effectively managing risk.

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 governance rules and legislation in Canada and the United States that are applicable, conduct ourselves in the best interests of our stakeholders, and meet industry best practices. The guidelines are reviewed and updated regularly.

MANAGEMENT’S DISCUSSION AND ANALYSIS     29

Risk and Risk Management

We have a mature enterprise risk management (ERM) framework that consists of processes and controls to ensure risks are being appropriately managed and mitigated.

Decisions to accept, mitigate, or transfer identified risks guide management’s plans in our strategic planning and budgeting process. Employees throughout the company take ownership of the risks specific to their area and are responsible for developing and implementing the controls to manage and re-assess risk, including ESG risks.

Our risk policy sets out a broad, systematic approach to identifying, assessing, reporting and managing the significant risks, including ESG risks, we face in our business and operations. The policy is reviewed annually to ensure that it continues to meet our needs.

See Managing the risks, starting on page 63, for a discussion of the risks, including ESG 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.

The board is responsible for overseeing management’s implementation of appropriate risk management processes and controls. Time is dedicated at board and committee meetings to risk identification, management, and reporting. In consultation with the board, management works on enhancing its enterprise risk oversight practices, processes and controls. While the board oversees the company’s strategic risks, including ESG/climate-related risks, it also allocates oversight of other top-tier risks to specific board committees. Set out below is an overview of the responsibilities allocated to specific board committees.

Audit and finance – supports the board in fulfilling its oversight responsibilities regarding the integrity of our accounting and financial reporting, the adequacy and effectiveness of our internal controls and disclosure controls, legal, regulatory (excluding safety, health and the environment) and ethical compliance, the independence and performance of our external and internal auditors, oversight of specific material risks, and prevention and detection of fraudulent activities and financial oversight.

Human resources and compensation – supports the board in fulfilling its oversight responsibilities regarding human resource policies, employee and labour relations matters, executive compensation, executive succession and development, pension plan governance, as well as oversight of cyber-security risk.

Nominating, corporate governance and risk – supports the board in fulfilling its oversight responsibilities by developing and recommending a set of corporate governance principles, identifying and recommending qualified individuals as members of the board and its committees, assessing the effectiveness of the board and committees, and overseeing the risk program.

Reserves oversight – supports the board in fulfilling its oversight responsibilities regarding estimating and disclosing mineral reserves and resources.

Safety, health and environment – supports the board in fulfilling its oversight responsibilities regarding safety, health, environmental and climate-related matters, and supportive communities.

More information about our shareholder commitment, our governance principles, how our board operates, its responsibilities, and the profiles of each of our directors can be found in our most recent management proxy circular and on our website at cameco.com/about/board-of-directors.

HOW WE ARE DOING

Given the evolving nature of the ESG landscape, we have established a multi-disciplinary working group to review our current approach to sustainability and ESG governance and reporting. We are planning to issue a ESG report later in 2021 that reflects Sustainability Accounting Standards Board (SASB) and Task Force on Climate-Related Financial Disclosures (TCFD) principles. The working group is chaired by our Senior Vice-President and Chief Corporate Officer and has been reporting to our board and its committees.

30     CAMECO CORPORATION

Since 2012, we have reported on globally recognized key indicators that measure our environmental, social, governance and financial impacts in the areas that we believe may have a significant impact on our ability to add long-term value for our stakeholders. We have used the Global Reporting Initiative’s Sustainability Framework (GRI), in addition to some corporate indicators that are unique to the company to measure and report our performance. This is our report card to our stakeholders. You can find our most recent performance results at cameco.com/about/sustainability.

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

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. For more information on our compensable targets and our reported performance against those targets see the Measuring our results section that follows and our most recent management proxy circular.

Measuring our results

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.

2020 OBJECTIVES1	TARGET	RESULTS
OUTSTANDING FINANCIAL PERFORMANCE
Earnings measure	Achieve targeted adjusted net earnings.	•   adjusted net earnings was below target largely due to the costs associated with the proactive measures taken to protect the health and safety of our workforce from the risks posed by the COVID-19 pandemic
Cash flow measure	Achieve cash flow from operations (after working capital changes).	•   cash flow from operations was below target largely due to the costs associated with the proactive measures taken to protect the health and safety of our workforce from the risks posed by the COVID-19 pandemic
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 injury frequency and severity, and radiation doses.	•   best safety performance in the history of the company, however TRIR did not meet the 2020 improvement target •   completion of corrective actions and job task observations was within the targeted range •   average radiation doses remained low and stable
CLEAN ENVIRONMENT
Environmental performance measures	Achieve divisional environmental aspect improvement targets.	•   performance was within the targeted range •   there were no significant environmental incidents in 2020
SUPPORTIVE COMMUNITIES
Stakeholder support measure	Develop the skill set of residents of Saskatchewan’s north in conjunction with our initiative to accelerate the adoption of advanced digital and automation technologies at our northern Saskatchewan operations.	•   Performance was above target

¹  Detailed results for our 2020 corporate objectives and the related targets will be provided in our 2021 management proxy circular prior to our Annual Meeting of Shareholders on May 6, 2021.

MANAGEMENT’S DISCUSSION AND ANALYSIS     31

2021 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.

32     CAMECO CORPORATION

Financial results

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

34	2020 CONSOLIDATED FINANCIAL RESULTS
45	OUTLOOK FOR 2021
47	LIQUIDITY AND CAPITAL RESOURCES
53	2020 FINANCIAL RESULTS BY SEGMENT
53	URANIUM
55	FUEL SERVICES
56	FOURTH QUARTER FINANCIAL RESULTS
56	CONSOLIDATED RESULTS
59	URANIUM
61	FUEL SERVICES

MANAGEMENT’S DISCUSSION AND ANALYSIS     33

2020 consolidated financial results

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

As of January 1, 2018, due to restructuring and a change in our ownership interest, we began accounting for JV Inkai on an equity basis, with no restatement of prior periods.

HIGHLIGHTS								CHANGE FROM
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)	2020			2019		2018		2019 TO 2020
Revenue		1,800			1,863		2,092		(3	)%
Gross profit		106			242		296		(56	)%
Net earnings (loss) attributable to equity holders		(53	)		74		166		>100	%
$ per common share (basic)		(0.13	)		0.19		0.42		>100	%
$ per common share (diluted)		(0.13	)		0.19		0.42		>100	%
Adjusted net earnings (loss) (non-IFRS, see page 35)		(66	)		41		211		>100	%
$ per common share (adjusted and diluted)		(0.17	)		0.10		0.53		>100	%
Cash provided by operations (after working capital changes)		57			527		668		(89	)%

Net earnings

The following table shows what contributed to the change in net earnings in 2020 compared to 2019 and 2018.

($ MILLIONS)		2020			2019			2018
Net earnings (losses) - previous year			74			166			(205	)
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	Higher (lower) sales volume		(4	)		(27	)		18
	Higher (lower) realized prices ($US)		25			(133	)		40
	Foreign exchange impact on realized prices		14			35			1
	Lower (higher) costs		(175	)		10			(186	)
	change – uranium		(140	)		(115	)		(127	)
Fuel services	Higher (lower) sales volume		(4	)		13			1
	Higher (lower) realized prices ($Cdn)		21			(11	)		(5	)
	Lower (higher) costs		(11	)		29			(1	)
	change – fuel services		6			31			(5	)
Other changes
Lower (higher) administration expenditures			(20	)		17			21
Lower impairment charges			—			—			358
Lower exploration expenditures			3			6			10
Change in reclamation provisions			(21	)		57			(60	)
Change in gains or losses on derivatives			5			113			(137	)
Change in foreign exchange gains or losses			33			(45	)		49
Change in earnings from equity-accounted investments			(9	)		13			32
Redemption of Series E debentures in 2020			(24	)		—			—
Canadian Emergency Wage Subsidy in 2020			37			—			—
Arbitration award in 2019 related to TEPCO contract			(52	)		52			—
Gain on sale of interest in Wheeler River Joint Venture in 2018			—			(17	)		17
Gain on restructuring of JV Inkai in 2018			—			(49	)		49
Gain on customer contract restructuring in 2018			—			(6	)		6
Sale of exploration properties in 2018			—			(7	)		7
Reversal of tax provision in 2018 related to CRA dispute			—			(61	)		61
Change in income tax recovery or expense			47			(126	)		62
Other			8			45			28
Net earnings (losses) - current year			(53	)		74			166

34     CAMECO CORPORATION

Non-IFRS measures

ADJUSTED NET EARNINGS

Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to 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 our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period and is adjusted for reclamation provisions for our Rabbit Lake and US operations, which have been impaired, the gain on restructuring of JV Inkai, and income taxes on adjustments.

Adjusted net earnings is non-standard supplemental information 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.

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2020, 2019 and 2018.

($ MILLIONS)	2020			2019			2018
Net earnings (loss) attributable to equity holders		(53	)		74			166
Adjustments
Adjustments on derivatives		(45	)		(49	)		65
Reclamation provision adjustments		24			3			60
Gain on restructuring of JV Inkai		—			—			(49	)
Income taxes on adjustments		8			13			(31	)
Adjusted net earnings (loss)		(66	)		41			211

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 adjusted net earnings measure.

MANAGEMENT’S DISCUSSION AND ANALYSIS     35

The following table shows what contributed to the change in adjusted net earnings (non-IFRS measure, see above) in 2020 compared to the same period in 2019 and 2018.

($ MILLIONS)		2020			2019			2018
Adjusted net earnings - previous year			41			211			59
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	Higher (lower) sales volume		(4	)		(27	)		18
	Higher (lower) realized prices ($US)		25			(133	)		40
	Foreign exchange impact on realized prices		14			35			1
	Lower (higher) costs		(175	)		10			(186	)
	change – uranium		(140	)		(115	)		(127	)
Fuel services	Higher (lower) sales volume		(4	)		13			1
	Higher (lower) realized prices ($Cdn)		21			(11	)		(5	)
	Lower (higher) costs		(11	)		29			(1	)
	change – fuel services		6			31			(5	)
Other changes
Lower (higher) administration expenditures			(20	)		17			21
Lower (higher) exploration expenditures			3			6			10
Change in gains or losses on derivatives			9			(1	)		36
Change in foreign exchange gains or losses			33			(45	)		49
Change in earnings from equity-accounted investments			(9	)		13			32
Redemption of Series E debentures in 2020			(24	)		—			—
Canadian Emergency Wage Subsidy in 2020			37			—			—
Arbitration award in 2019 related to TEPCO contract			(52	)		52			—
Gain on sale of interest in Wheeler River Joint Venture in 2018			—			(17	)		17
Gain on customer contract restructuring in 2018			—			(6	)		6
Sale of exploration properties in 2018			—			(7	)		7
Reversal of tax provision in 2018 related to CRA dispute			—			(61	)		61
Change in income tax recovery or expense			42			(82	)		17
Other			8			45			28
Adjusted net earnings (losses) - current year			(66	)		41			211

Average realized prices

								CHANGE FROM
		2020		2019		2018		2019 TO 2020
Uranium1	$US/lb		34.39		33.77		37.01		2	%
	$Cdn/lb		46.14		44.85		47.96		3	%
Fuel services	$Cdn/kgU		27.89		26.21		26.78		6	%

¹  Average realized foreign exchange rate ($US/$Cdn): 2020 – 1.34, 2019 – 1.33 and 2018 – 1.30.

36     CAMECO CORPORATION

Revenue

The following table shows what contributed to the change in revenue for 2020.

($ MILLIONS)
Revenue – 2019	1,863
Uranium
Lower sales volume	(42	)
Higher realized prices ($Cdn)	40
Fuel services
Lower sales volume	(16	)
Higher realized prices ($Cdn)	23
Other	(68	)
Revenue – 2020	1,800

See 2020 Financial results by segment on page 53 for more detailed discussion.

THREE-YEAR TREND

In 2019, revenue decreased by 11% compared to 2018 due to a decrease in sales volume in the uranium segment and a decrease in the Canadian dollar average realized price despite an increase in the uranium spot price. This decrease in the uranium segment was partially offset by an increase in sales volumes in our fuel services segment.

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 addition, our subsidiary NUKEM had a decrease in sales volume. See notes 17 and 28 in our annual financial statements for more information.

SALES DELIVERY OUTLOOK FOR 2021

For 2021 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 2021 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     37

Corporate expenses    

ADMINISTRATION    

($ MILLIONS)	2020		2019		CHANGE
Direct administration		113		114		(1	)%
Stock-based compensation		32		11		191	%
Total administration		145		125		16	%

Direct administration costs in 2020 were $1 million lower than 2019.

We recorded $32 million in stock-based compensation expenses in 2020 under our stock option, restricted share unit, deferred share unit, performance share unit and phantom stock option plans, $21 million higher than in 2019 due to the increase in our share price compared to the same period in 2019. See note 24 to the financial statements.

Administration outlook for 2021

We expect direct administration costs to be between $110 million to $120 million, similar to 2020.

EXPLORATION

Our 2020 exploration activities were focused primarily on Canada. Our spending decreased from $14 million in 2019 to $11 million in 2020 due to a reduction in expenditures as a result of restrictions related to the COVID-19 pandemic.

Exploration outlook for 2021

We expect exploration expenses to be about $9 million in 2021. The focus for 2021 will be on our core projects in Saskatchewan.

FINANCE COSTS

Finance costs were $96 million, a decrease from $99 million in 2019 due to a reduction in our outstanding debt during 2019, as we retired our Series D debentures debenture that matured in September of that year and lower accretion expense as a result of decreases in both reclamation estimates and discount rates. These decreases were partially offset by the cost associated with the early redemption of our Series E debentures. See note 19 to the financial statements.

FINANCE INCOME

Finance income was $11 million compared to $30 million in 2019 mainly due to lower interest rates during 2020. In addition, during 2019 our loan to JV Inkai was fully repaid, decreasing the amount of interest received in the current year.

GAINS AND LOSSES ON DERIVATIVES

In 2020, we recorded $37 million in gains on our derivatives compared to $32 million in gains in 2019. The increase reflects the strength in the Canadian dollar compared to the US dollar at the end of 2020 compared to 2019. See Foreign exchange on page 43 and note 26 to the financial statements.

INCOME TAXES

We recorded an income tax expense of $14 million in 2020 compared to an expense of $61 million in 2019. The decrease in expense was primarily due to a change in the distribution of earnings among jurisdictions compared to 2019.

In 2020, we recorded earnings of $73 million in Canada compared to earnings of $229 million in 2019, while in foreign jurisdictions, we recorded a loss of $112 million compared to a loss of $94 million in 2019. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate.

On an adjusted earnings basis, we recognized a tax expense of $6 million in 2020 compared to an expense of $48 million in 2019. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

38     CAMECO CORPORATION

($ MILLIONS)	2020			2019
Pre-tax adjusted earnings1
Canada		52			183
Foreign		(112	)		(94	)
Total pre-tax adjusted earnings		(60	)		89
Adjusted income taxes1
Canada		1			55
Foreign		5			(7	)
Adjusted income tax expense		6			48

¹  Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures. Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measures on page 35).

TRANSFER PRICING DISPUTE

Federal Court of Appeal decision

On June 26, 2020, the Court of Appeal decided unanimously in our favour in our dispute with CRA. The decision upholds the September 26, 2018 decision of the Tax Court of Canada (Tax Court), which was unequivocally in our favour for the 2003, 2005 and 2006 tax years and it sustains the corresponding decision on the cost award. We also believe the principles in the decision apply to all tax years subsequent to 2006.

The Court of Appeal decision is further confirmation that our marketing and trading structure involving foreign subsidiaries and the related transfer pricing methodology used for certain intercompany uranium purchase and sale agreements were in full compliance with Canadian laws for the three years in question.

The total tax reassessed for the three tax years was $11 million, and we remitted 50%. Therefore, we expect to receive refunds totaling about $5.5 million plus interest. The matter has been referred to the Minister of National Revenue in order to issue new reassessments for the 2003, 2005 and 2006 tax years in accordance with the decision.

In addition, on April 30, 2019, the Tax Court awarded us $10.25 million for legal fees incurred, plus an amount for disbursement of up to $17.9 million. The amount of the award for disbursements will be determined by an officer of the Tax Court. We are optimistic we will recover all, or substantially all, of the $17.9 million in disbursements. In addition, we will be receiving a nominal cost award related to the Court of Appeal hearing.

The timing of any payments as a result of the Court of Appeal decision is uncertain.

Appeal process

On October 30, 2020, we received notice that CRA made an application to the Supreme Court to seek leave to appeal the decision of the Court of Appeal. The Supreme Court will decide whether to hear the appeal or decline CRA’s request for leave. If the appeal is heard, we estimate that it could take until the second half of 2022 before a decision is rendered by the Supreme Court.

We remain confident in our position, and that we would succeed on appeal, if leave to appeal is granted. If leave to appeal is not granted, then the dispute over the three tax years in question is fully and finally resolved in our favour.

We expect to incur additional costs if leave to appeal is granted by the Supreme Court, and in connection with potential reassessments of subsequent years. There could also be costs incurred if a negotiated resolution with CRA is sought or achieved.

Potential exposure based on CRA appeal

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. To date, we have received notices of reassessment for our 2003 through 2014 tax years. Both the Court of Appeal and the Tax Court have ruled unequivocally in our favour for the 2003, 2005 and 2006 tax years, and we believe there is nothing in the lower court decisions that would warrant a materially different outcome if the Supreme Court decides to hear the appeal. Although not technically binding, there is nothing in the reasoning of the lower court decisions that should result in a different outcome for those subsequent tax years. However, we expect these disputes with CRA may continue to tie up our financial capacity until the dispute is finally resolved for all years.

MANAGEMENT’S DISCUSSION AND ANALYSIS     39

For the years 2003 to 2014, CRA has 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. CRA has advised that it has deferred consideration of whether to impose a transfer pricing penalty for 2012 through 2014. Taxes of approximately $326 million for the 2003 to 2020 years have already been paid to date in a jurisdiction outside Canada. If CRA is successful on appeal, we will consider our options under bilateral international tax treaties to limit double taxation of this income. There is a risk that we will not be successful in eliminating all potential double taxation. The income adjustments claimed by CRA in its reassessments are represented by the amounts described below.

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. We received the 2014 reassessment late in 2020. CRA has advised that security remitted to date is sufficient to secure the tax debts they consider owing and as such, no further security is required at this time. To date, under these provisions, after applying elective deductions, we have paid or secured the amounts shown in the table below. Of these amounts, we expect to receive refunds totaling approximately $5.5 million plus interest for the years 2003, 2005 and 2006. The timing of the refund may be delayed pending the outcome of the decision of the Supreme Court to hear the appeal.

			INTEREST		TRANSFER
			AND INSTALMENT		PRICING				CASH		SECURED BY
YEAR PAID ($ MILLIONS)	CASH TAXES		PENALTIES		PENALTIES		TOTAL		REMITTANCE		LC
Prior to 2014		1		22		36		59		59		—
2014		106		47		—		153		153		—
2015		202		71		79		352		20		332
2016		51		38		31		120		32		88
2017		—		1		39		40		39		1
2018		17		40		—		57		—		57
2019		—		2		—		2		—		2
2020		—		2		—		2		—		2
Total		377		223		185		785		303		482

If leave to appeal is granted by the Supreme Court, we expect the prior court decisions to be upheld and believe they should also apply in principle to subsequent years. We expect any further actions regarding the tax years 2007 through 2014 will be suspended until the three years covered under the decision are finally resolved. For 2014, CRA has recently reassessed us on the same basis as previous tax years, but has also proposed an alternative reassessing position that, if applied, would result in a less adverse, albeit still material, adjustment to our income taxable in Canada. This proposed new basis of reassessment is inconsistent with the methodology CRA has pursued for prior years and is being assessed. Our initial view is that this alternative methodology will not result in a materially different outcome for 2014. Until such time as all appeals are exhausted and a resolution is reached for each of the tax years in question, we will not be in a position to determine the definitive outcome of this dispute for that tax year.

Despite the fact that we believe there is no basis to do so, and it is not our view of the likely outcome, CRA may continue to reassess us using the methodology it used to reassess the 2003 through 2014 tax years. In that scenario, and including the $6.6 billion already reassessed, we would expect to receive notices of reassessment for a total of up to approximately $8.7 billion of additional income taxable in Canada for the years 2003 through 2020, which would result in a related tax expense of up to approximately $2.6 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2011. In that case, we estimate that cash taxes and transfer pricing penalties claimed by CRA for these years would be between $1.95 billion and $2.15 billion. In addition, CRA may seek to apply interest and instalment penalties that would be material to us. While in dispute, we may be required to remit or otherwise provide security for 50% of the cash taxes and transfer pricing penalties (between $970 million and $1.07 billion), plus related interest and instalment penalties assessed, which would be material to us. However, as noted previously, CRA has informed us that no further security is required for the tax debts it considers owing at this time. We have already paid or secured $562 million in cash taxes and transfer pricing penalties and $223 million in interest and instalment penalties. CRA may also advance alternative reassessment methodologies for years other than 2003, 2005 and 2006, such as the alternative reassessing position advanced for 2014.

40     CAMECO CORPORATION

Under the Canadian federal and provincial tax rules, any amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. CRA has to date disallowed the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This does not impact the anticipated income tax expense for a particular year but does impact the timing of any required security or payment. As noted above, for amounts reassessed after 2014, as an alternative to remitting cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. If required, we believe we will be able to continue to provide security in the form of letters of credit to satisfy these requirements. The amounts summarized in the table below reflect actual amounts paid or secured from 2003 through 2020 along with estimated post-2020 amounts if CRA were to continue to reassess based on the scenario outlined above and include the expected timing adjustment for the inability to use any loss carry-backs starting with the 2008 tax year. The amounts have not been adjusted to reflect the refund of approximately $5.5 million plus interest we expect to receive based on the ruling of the Tax Court. The timing of such refund may be delayed pending the outcome of the application for leave to appeal. We plan to update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2020.

$ MILLIONS	2003-2020		Post-2020		TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or potentially owing in the period
Cash payments		226		185 -  235		410 - 460
Secured by letters of credit		336		225 - 275		560 - 610
Total paid or potentially owing1		562		410 - 510		970 - 1070

¹ These amounts do not include interest and instalment penalties, which totaled approximately $223 million to December 31, 2020.

Based on the Court of Appeal and Tax Court decisions as described above and our view of the likely outcome if the Supreme Court decides to hear the appeal, and the dispute for subsequent years, we expect to recover all or substantially all of the $785 million already paid or otherwise secured to date.

MANAGEMENT’S DISCUSSION AND ANALYSIS     41

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

• CRA will reassess us for the years 2015 through 2020 using an expected methodology, and the reassessments will be issued on the basis we expect

• we will be able to apply elective deductions and utilize letters of credit to the extent anticipated

• CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years 2007 through 2011) in addition to interest charges and instalment penalties

• we will be substantially successful in our dispute with CRA, including any appeals of the Court of Appeal’s decision or any decisions regarding other tax years, and we will not incur any significant tax liability resulting from the outcome of the dispute or other costs, potentially including costs associated with a negotiated resolution with CRA

• a favourable determination by the officer of the Tax Court of the amount of our disbursements award

• the time it would take to receive a decision if the Supreme Court agrees to hear an appeal

• the principles in the lower court decisions should apply to all subsequent tax years

Material risks that could cause actual results to differ materially

• CRA reassesses us for years 2015 through 2020 using a different methodology than expected, or we are unable to utilize elective deductions or letters of credit to the extent anticipated, resulting in the required cash payments or security provided to CRA pending the outcome of the dispute being higher than expected

• the time lag for the reassessments for each year is different than we currently expect

• if heard by the Supreme Court, we may be unsuccessful in an appeal of the Court of Appeal’s decision which could result in us owing the full amounts that were originally claimed against us by CRA for the 2003, 2005 and 2006 tax years and losing our entitlement to cost awards, and could ultimately result in a negotiated settlement or an adverse determination against us for the other tax years for which we have been reassessed under the same methodology or a different methodology, giving rise to material tax liabilities and payment obligations which would have a material adverse effect on us

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

• cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing

• we are unable to effectively eliminate all double taxation

• the risk that for some reason we may be unable to recover all or substantially all of the amounts we have paid or otherwise secured to date, or payment of the full amount of cost awards

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

Tax outlook for 2021

Given the ongoing uncertainty about the impact of the COVID-19 pandemic on production at the Cigar Lake mine, and on production at the Inkai operation, we do not have enough certainty to provide tax outlook.

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.

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.

42     CAMECO CORPORATION

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 2021 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 35.

The table below provides a summary of our hedge portfolio at December 31, 2020. You can use this information to estimate the expected gains or losses on derivatives for 2021 on an ANE basis. However, if we add contracts to the portfolio that are designated for use in 2021 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     43

HEDGE PORTFOLIO SUMMARY

DECEMBER 31, 2020					AFTER
($ MILLIONS)		2021			2021			TOTAL
US dollar forward contracts	($ millions)		190			220			410
Average contract rate 1	(US/Cdn dollar)		1.33			1.35			1.34
US dollar option contracts	($ millions)		125			160			285
Average contract rate range1	(US/Cdn dollar)		1.30 to 1.34			1.33 to 1.37			1.32 to 1.36
Total US dollar hedge contracts	($ millions)		315			380			695
Effective hedge rate range2	(US/Cdn dollar)		1.32 to 1.33			1.34 to 1.36			1.33 to 1.35
Hedge ratio3			41	%		9	%		14	%

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

²  The effective hedge rate is the exchange rate on the original hedge contract at the time it was established and designated for use. Therefore, the effective hedge rate range shown reflects an average of contract exchange rates at the time of designation.

³  Hedge ratio is calculated by dividing the amount (in foreign currency) of outstanding derivative contracts by estimated future net exposures.

At December 31, 2020:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.27 (Cdn), down from $1.00 (US) for $1.30 (Cdn) at December 31, 2019. The exchange rate averaged $1.00 (US) for $1.34 (Cdn) over the year.

• The mark-to-market position on all foreign exchange contracts was a $41 million gain compared to a $4 million loss at December 31, 2019.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2020, 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.

44     CAMECO CORPORATION

Outlook for 2021

Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals, in order to preserve the value of those assets and increase long-term value, and to do that with a focus on safety, people and the environment.

Our outlook for 2021 reflects the expenditures necessary to help us achieve our strategy. We have made significant progress in reducing our administration, exploration and operating costs, as well as our capital expenditures. We have also made a number of strategic decisions that come with significant costs in the near term, costs we factored into our decisions. As in prior years, care and maintenance costs for the ongoing outage of McArthur River and Key Lake operations and our tier-two assets are expected to be between $150 million and $170 million. Despite the impact on our expected results, we continue to believe these are the right decisions to create long-term value. In addition, we expect to incur care and maintenance costs of between $8 million to $10 million per month while production at Cigar Lake is suspended due to the risks posed by the COVID-19 pandemic.

Given the ongoing uncertainty about the impact of the COVID-19 pandemic on production at the Cigar Lake mine, and on production at the Inkai operation, we do not have enough certainty to provide full outlook information for the uranium segment.

We expect our business to be resilient. We have provided outlook for our sales commitments, which we do not expect to be materially impacted by the disruptions to our business as a result of the COVID-19 pandemic. We expect, given the current production disruptions at Cigar Lake, that we will continue to purchase material on the spot market to meet our delivery commitments and maintain our desired level of inventory. Combined with additional care and maintenance costs associated with the temporary closure of Cigar Lake, we expect these items will again negatively impact our uranium gross margin. The exact magnitude of this impact is uncertain and will be dependent on the length of the temporary closure and our ability to safely return to production.

From a cash perspective, we expect to continue to maintain a significant cash balance. We expect to continue to generate cash from operations however, the amount of cash generated will be dependent on the timing and magnitude of our purchasing activity and therefore, cash balances may fluctuate throughout the year.

See 2020 Financial results by segment on page 53 for details.

2020 outlook compared to actual

In April of 2020 we withdrew our outlook due to the uncertainty created by the COVID-19 pandemic. Based on the restart of the Cigar Lake mine in September after the first production suspension, in the second quarter we set a production target for Cigar Lake of up to 5.3 million pounds (our share). We achieved 5.0 million pounds prior to a second suspension of production at Cigar Lake. The second suspension was a result of the workforce uncertainty caused by the COVID-19 pandemic.

Our results were in-line with the updated production outlook we provided for fuel services in the second quarter MD&A.

MANAGEMENT’S DISCUSSION AND ANALYSIS     45

2021 FINANCIAL OUTLOOK    

	CONSOLIDATED		URANIUM		FUEL SERVICES
Production (owned and operated properties)		—		—		12.5 to 13.5 million kgU
Purchases		—		8 to 10 million lbs		—
Sales/delivery volume		—		23 to 25 million lbs		12 to 13 million kgU
Revenue		—		—	$	360-390 million
Average unit cost of sales (including D&A)		—		—	$	20.50-21.50/kgU
Direct administration costs	$	110-120 million		—		—
Exploration costs		—	$	9 million		—
Expected gain on derivatives - ANE basis	$	5-15 million		—		—
Capital expenditures	$	130-155 million		—		—

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:

• Purchases – are based on the volumes we currently have commitments to acquire under contract in 2021, including our JV Inkai purchases, in order to meet the sales/delivery commitments we have under contract in 2021 and maintain a working inventory. It does not include any purchasing required as a result of the impact of the pandemic on our production rate at Cigar Lake.

• Our 2021 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 2021.

• Direct administration costs do not include stock-based compensation expenses. See page 38 for more information.

Our 2021 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 77 and 78 for more details.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following 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. It is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2020 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2020, and none of the assumptions we list below change.

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.

46     CAMECO CORPORATION

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

SPOT PRICES
($US/lb U3O8)	$20		$40		$60		$80		$100		$120		$140
2021		28		38		49		56		62		66		70
2022		27		39		52		60		64		68		71
2023		28		40		53		62		66		70		73
2024		30		41		52		60		63		64		66
2025		30		41		55		64		69		72		75

The table illustrates the mix of long-term contracts in our December 31, 2020 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to December 31, 2020.

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices.

Our portfolio is affected by more than just the spot price. We made the following assumptions (which are not forecasts) to create the table:

Sales

• sales volumes on average of 16 million pounds per year, with commitment levels in 2021 and 2022 higher than in 2023 through 2025

• excludes sales between our segments

Deliveries

• deliveries include best estimates of requirements contracts and contracts with volume flex provisions

Annual inflation

• is 2% in the US

Prices

• the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 20% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table may be higher.

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 implemented over the past five years, we have continued to have positive cash from operations and as a result, we have significant cash balances.

At the end of 2020, we had cash and short-term investments of $943 million, while our total debt amounted to $1.0 billion.

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 2021 through 2025, we have commitments to deliver an average of 16 million pounds per year, with commitment levels in 2021 and 2022 higher than in 2023 through 2025.

Strategically our focus is on preserving the value of our tier-one assets and reducing our operating, capital and general and administrative spending. In the current environment, the health and safety of our employees, their families and their communities is our priority as the COVID-19 pandemic continues to bring uncertainty. In 2020, we took measures to enhance our health and safety protocols as well we proactively suspended production. As a result of these measures, and a negative trend in the pandemic in Saskatchewan in December, currently production at our Cigar Lake mine is temporarily suspended. See Operations and projects beginning on page 62 for more information. Cash flow from operations will be dependent on how long production at Cigar Lake remains suspended and the timing and magnitude of our purchasing activity, therefore cash balances may fluctuate throughout the year. However, we expect our cash balances and operating cash flows to meet our capital requirements during 2021.

MANAGEMENT’S DISCUSSION AND ANALYSIS     47

We have now received two favourable rulings in our case with CRA for the 2003, 2005 and 2006 tax years. We continue to believe the rulings should apply in principle to subsequent tax years. However, CRA has submitted a request to seek leave to appeal to the Supreme Court. The Supreme Court will decide whether to hear the appeal or decline CRA’s request for leave. If the appeal is heard, we estimate that it could take until the second half of 2022 before a decision is rendered. Until we know whether an appeal to the Supreme Court will be heard, and a resolution is reached for all tax years in question, in accordance with Canadian income tax rules we may be required to remit or otherwise secure 50% of any cash taxes plus related interest and penalties CRA may continue to reassess, even though we believe there is no basis for them to do so. See page 39 for more information. In the above scenario, the table on page 41 provides the amount and timing of the cash taxes and transfer pricing penalties paid or secured to date. In addition, it provides an estimate of the amounts we may potentially have to pay or secure upfront if CRA continues to reassess us using the same methodology it reassessed the 2003 to 2014 tax years. The timing of these amounts is uncertain.

FINANCIAL CONDITION

	2020			2019
Cash position ($ millions)		943			1,062
(cash and cash equivalents and short-term investments)
Cash provided by operations ($ millions)		57			527
(net cash flow generated by our operating activities after changes in working capital)
Cash provided by operations/net debt1		109	%		n/a
(net debt is total consolidated debt, less cash position)
Net debt/total capitalization1		1	%		n/a
(total capitalization is net debt and equity)

¹  As at December 31, 2019, Cameco’s net debt was negligible 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 9, 2021:

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

¹  On May 28, 2020, DBRS changed Cameco’s rating outlook to stable.

²  On March 11, 2020 S&P changed Cameco’s rating outlook to negative.

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.

48     CAMECO CORPORATION

Liquidity

($ MILLIONS)	2020			2019
Cash and cash equivalents at beginning of year		1,062			1,103
Cash from operations		57			527
Investment activities
Additions to property, plant and equipment and acquisitions		(77	)		(75	)
Other investing activities		1			121
Financing activities
Change in debt		(2	)		(500	)
Interest paid		(66	)		(72	)
Other financing activities		(3	)		(3	)
Issue of shares		5			—
Dividends		(32	)		(32	)
Exchange rate on changes on foreign currency cash balances		(2	)		(7	)
Cash and cash equivalents and short-term investments at end of year		943			1,062

CASH FROM OPERATIONS

Cash from operations was 89% lower than in 2019 due largely to the additional purchase activity and care and maintenance costs related to the unplanned suspensions of production due to the COVID-19 pandemic. Working capital provided $289 million less in 2020. Not including working capital requirements, our operating cash flows in the year were down $181 million. See note 23 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

Capital spending

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

Outlook for investing activities

CAMECO’S SHARE ($ MILLIONS)	2021 PLAN		2022 PLAN		2023 PLAN
Total uranium & fuel services		130-155		100-150		100-150
Sustaining capital		105-120		85-110		90-115
Capacity replacement capital		25-35		15-40		10-35
Growth capital		—		—		—

As a result of the uncertain impact of the COVID-19 pandemic on our operations, we are unable to more accurately provide an outlook by operation for capital spending. As a result, the ranges above represent our best estimate of total capital spend for 2021 and may be affected by the timing and length of temporary shutdowns at our operations.

We have assumed that the impact of the COVID-19 pandemic on our operations will be reduced for 2022 and 2023. Our 2021, 2022 and 2023 capital spending estimates also assume that market conditions remain such that McArthur River and Key Lake remain in care and maintenance. We expect total 2021 capital expenditures for uranium and fuel services to be between 70% and 100% higher than in 2020 due to the ongoing investment in the initiative intended to provide a greater focus on technology and its applications to improve efficiency and reduce costs including the use digital and automation technologies and the rescheduling of some expenditures planned in 2020 to 2021.

Our estimate for capital spending in 2022 has been increased to between $100 million and $150 million (previously between $50 million and $100 million) due to our continued investment in digital and automation technologies, along with the timing of expenditures on our Vision in Motion project.    

Capital expenditures for JV Inkai are expected to be covered by JV Inkai cash flows in 2021 and are included in our overall equity investment.

MANAGEMENT’S DISCUSSION AND ANALYSIS     49

Major sustaining and capacity replacement expenditures in 2021 include:

• Fuel services – continuation of work on our Vision in Motion project

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

• 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.

Long-term contractual obligations

			2022 AND		2024 AND		2026 AND
DECEMBER 31 ($ MILLIONS)	2021		2023		2025		BEYOND		TOTAL
Long-term debt		—		—		500		500		1,000
Interest on long-term debt		38		76		44		110		268
Provision for reclamation		41		64		74		951		1,130
Provision for waste disposal		2		3		2		1		8
Other liabilities		7		9		3		86		105
Capital commitments		47		—		—		—		47
Total		135		152		623		1,648		2,558

We have contractual capital commitments of approximately $47 million at December 31, 2020. 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 November 1, 2023. Each year on the anniversary date, and 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, 2020, there were no amounts outstanding under this facility and we do not expect to draw on this facility in 2021.

• At December 31, 2020, 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

On October 21, 2020, we issued debentures in the amount of $400 million, at an interest rate of 2.95% per annum and the proceeds were used to redeem our outstanding $400 million debenture bearing interest of 3.75%, resetting the maturity from 2022 to 2027 and resulting in an early redemption fee of $24 million.

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

50     CAMECO CORPORATION

Funded debt is total consolidated debt less non-recourse debt, $100 million in letters of credit, cash 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, 2020, we complied with all covenants, and we expect to continue to comply in 2021.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at the end of 2020:

• purchase commitments

• financial assurances

• other arrangements

Purchase commitments

We make purchases under long-term contracts where it is beneficial for us to do so and in order to support our long-term contract portfolio. The following table is based on our purchase commitments in our uranium and fuel services segments, as well as commitments previously contracted by our subsidiary NUKEM, at December 31, 2020² 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.

			2022 AND		2024 AND		2026 AND
DECEMBER 31, 2020 ($ MILLIONS)	2021		2023		2025		BEYOND		TOTAL
Purchase commitments1,2		217		156		130		411		914

¹ Denominated in US dollars and Japanese yen, converted from US dollars to Canadian dollars at the rate of 1.30 and from Japanese yen to Canadian dollars at the rate of $0.01.

² These amounts have been adjusted for any additional purchase commitments that we have entered into since December 31, 2020 but does not include deliveries taken under contract since December 31, 2020.

We have commitments of $914 million (Cdn) for the following:

• approximately 20 million pounds of U₃O₈ equivalent from 2021 to 2028

• about 0.1 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, 2020 our financial assurances totaled $1.6 billion, up from $1.5 billion at December 31, 2019. The increase in 2020 was mainly due to some short-term requirements.

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 2.0%. During the year, we drew 0.5 million kgU of UF₆ conversion services and 1.2 million pounds of U₃O₈ on the loans. At December 31, 2020, only the conversion services loan was outstanding.

MANAGEMENT’S DISCUSSION AND ANALYSIS     51

BALANCE SHEET

DECEMBER 31, 2020							CHANGE
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2020		2019		2018		2019 TO 2020
Inventory		680		321		468		112	%
Total assets		7,581		7,427		8,019		2	%
Long-term financial liabilities		2,253		2,099		2,102		7	%
Dividends per common share		0.08		0.08		0.08		—

Total product inventories increased by 112% to $680 million this year due to lower sales volumes than the quantities produced and purchased during the year. There has been an increase in purchased inventory due to production suspensions. At December 31, 2020, our average cost for uranium was $38.09 per pound, up from $33.41 per pound at December 31, 2019. As of December 31, 2020, we held an inventory of 15.3 million pounds of U₃O₈ equivalent (excluding broken ore).

At the end of 2020, our total assets amounted to $7.6 billion, an increase of $0.2 billion compared to 2019, due mainly to higher inventories. In 2019, the total asset balance decreased by $0.6 billion compared to 2018, due to a decrease in cash and investment balances resulting from the repayment of long-term debt, offset by strong cash flow from operations. In addition, lower inventories, the repayment of our loan to JV Inkai and ongoing depreciation on our property, plant and equipment impacted our total assets.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation, deferred sales and financial derivatives.

52     CAMECO CORPORATION

2020 financial results by segment

Uranium

HIGHLIGHTS				2020		2019		CHANGE
Production volume (million lbs)					5.0		9.0		(44	)%
Sales volume (million lbs)					30.6		31.5		(3	)%
Average spot price	($	US/lb	)		29.96		25.64		17	%
Average long-term price	($	US/lb	)		34.63		31.75		9	%
Average realized price	($	US/lb	)		34.39		33.77		2	%
	($	Cdn/lb	)		46.14		44.85		3	%
Average unit cost of sales (including D&A)	($	Cdn/lb	)		45.71		39.99		14	%
Revenue ($ millions)					1,412		1,414		—
Gross profit ($ millions)					13		153		(92	)%
Gross profit (%)					1		11		(91	)%

Production volumes in 2020 decreased by 44% compared to 2019. See Uranium – production overview on page 66 for more information.

Uranium revenues this year were unchanged compared to 2019 due to a decrease in sales volumes of 3% offset by an increase of 3% in the Canadian dollar average realized price. Although the spot price for uranium averaged $29.96 (US) per pound in 2020, an increase of 17% compared to the 2019 average price of $25.64 (US) per pound, the average realized price was only 3% higher compared to the same period in 2019 primarily due to lower prices on fixed-price contracts and less sensitivity to price changes due to floor prices in the market-related contracts delivered into in 2019.

Total cost of sales (including D&A) increased by 11% ($1.40 billion compared to $1.26 billion in 2019) due to a 14% increase in unit cost of sales partially offset by a decrease in sales volume of 3%. Unit cost of sales is higher than in the same period in 2019 due to the higher cost of purchased material and additional care and maintenance costs of $46 million resulting from our proactive decision to suspend production at the Cigar Lake mine in response to the threat posed by the COVID-19 pandemic.

The net effect was a $140 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)	2020		2019		CHANGE
Produced
Cash cost		16.24		15.70		3	%
Non-cash cost		15.10		16.09		(6	)%
Total production cost 1		31.34		31.79		(1	)%
Quantity produced (million lbs)1		5.0		9.0		(44	)%
Purchased
Cash cost1		40.41		35.26		15	%
Quantity purchased (million lbs)1		33.5		19.0		76	%
Totals
Produced and purchased costs		39.23		34.14		15	%
Quantities produced and purchased (million lbs)		38.5		28.0		38	%

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 2020 we purchased 4.0 million pounds at a purchase price per pound of $36.63 ($27.66 (US)) (2019 - 3.5 million pounds at a purchase price per pound of $32.43 ($24.37 (US))).

MANAGEMENT’S DISCUSSION AND ANALYSIS     53

The average cash cost of production was 3% higher in the year than in 2019 as a result of lower production. Due to the impacts of the COVID-19 pandemic and the suspension of production at Cigar Lake, our cost of production was higher than in 2019. While McArthur River and Key Lake are shut down, our annual cost of production is expected to reflect the estimated life-of-mine operating cost, between $15 and $16 per pound, of mining and milling our share of Cigar Lake mineral reserves. However, our cash production costs in 2021 may be impacted by the timing of the restart and the production rate of Cigar Lake and may fluctuate from quarter to quarter.

The benefit of the estimated life-of-mine operating cost for Inkai’s production of between $8 and $9 per pound, is expected to be reflected in the line item on our statement of earnings called “share of earnings from equity-accounted investee”.

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 $40.41 (Cdn), or $29.69 (US) per pound, compared to $35.26 (Cdn), or $26.49 (US) per pound in the same period in 2019.

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 2020 and 2019 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS)	2020			2019
Cost of product sold		1,244.0			1,041.9
Add / (subtract)
Royalties		(15.5	)		(32.5	)
Other selling costs		(12.1	)		(10.5	)
Care and maintenance and severance costs		(138.5	)		(109.5	)
Change in inventories		357.0			(78.2	)
Cash operating costs (a)		1,434.9			811.2
Add / (subtract)
Depreciation and amortization		154.6			218.8
Care and maintenance costs		(57.5	)		(44.4	)
Change in inventories		(21.6	)		(29.6	)
Total operating costs (b)		1,510.4			956.0
Uranium produced & purchased (million lbs) (c)		38.5			28.0
Cash costs per pound (a ÷ c)		37.27			28.97
Total costs per pound (b ÷ c)		39.23			34.14

54     CAMECO CORPORATION

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 $24.22/kg U₃O₈ ($10.99/lb) and a 15% royalty is charged on profit in excess of $24.22/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

In mid-December 2020, we announced a second suspension of production at Cigar Lake as a result of the impacts of the COVID-19 pandemic. This suspension continues into 2021 and due to the uncertainty this creates we are unable to provide a full outlook for the uranium segment.

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 2021.

In addition, we expect to purchase between 8 million and 10 million pounds in 2021 to meet our sales commitments and maintain a working inventory. This includes our spot market purchases and other purchase commitments, including from JV Inkai, but It does not include any purchasing required as a result of the impact of the pandemic on our production rate at Cigar Lake.

Fuel services

(includes results for UF6, UO2, UO3 and fuel fabrication)
HIGHLIGHTS				2020		2019		CHANGE
Production volume (million kgU)					11.7		13.3		(12	)%
Sales volume (million kgU)					13.5		14.1		(4	)%
Average realized price	($	Cdn/kgU	)		27.89		26.21		6	%
Average unit cost of sales (including D&A)	($	Cdn/kgU	)		20.76		19.84		5	%
Revenue ($ millions)					377		370		2	%
Gross profit ($ millions)					96		90		7	%
Gross profit (%)					25		24		4	%

Total revenue increased by 2% from 2019 due to a 6% increase in the realized price that was partially offset by a 4% decrease in sales volume. The increase in realized price was mainly the result of increased prices on the sale of UF₆ due to market conditions.

Total cost of products and services sold (including D&A) remained relatively unchanged ($281 million compared to $280 million in 2019), due to the 4% decrease in sales volume being offset by a 5% increase in average unit cost of sales compared to 2019. The unit cost of sales was impacted by lower production volumes and the $9 million in care and maintenance costs incurred as a result of our proactive decision to suspend production for four weeks at the Blind River refinery and Port Hope UF₆ conversion plant in response to the threat posed by the COVID-19 pandemic.

The net effect was a $6 million increase in gross profit.

FUEL SERVICES SEGMENT OUTLOOK

In 2021, we plan to produce 12.5 million to 13.5 million kgU, and we expect sales volumes, not including intersegment sales, to be 12 million to 13 million kgU. Overall revenue is expected to be between $360 million and $390 million, slightly lower than 2020 due to lower committed sales volumes. We expect the average unit cost of sales (including D&A) to be between $20.50/kgU and $21.50/kgU.

MANAGEMENT’S DISCUSSION AND ANALYSIS     55

Fourth quarter financial results

Consolidated results

	THREE MONTHS ENDED
HIGHLIGHTS	DECEMBER 31
($ MILLIONS EXCEPT WHERE INDICATED)	2020		2019		CHANGE
Revenue		550		874		(37	)%
Gross profit		109		184		(41	)%
Net earnings attributable to equity holders		80		128		(38	)%
$ per common share (basic)		0.20		0.32		(38	)%
$ per common share (diluted)		0.20		0.32		(38	)%
Adjusted net earnings (non-IFRS, see page 35)		48		94		(49	)%
$ per common share (adjusted and diluted)		0.12		0.24		(50	)%
Cash provided by operations (after working capital changes)		257		274		(6	)%

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 35) in the fourth quarter of 2020 compared to the same period in 2019.

($ MILLIONS)		IFRS			ADJUSTED
Net earnings - 2019			128			94
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		(52	)		(52	)
	Higher realized prices ($US)		29			29
	Foreign exchange impact on realized prices		(4	)		(4	)
	Higher costs		(33	)		(33	)
	change – uranium		(60	)		(60	)
Fuel services	Lower sales volume		(14	)		(14	)
	Higher realized prices ($Cdn)		7			7
	Higher costs		(8	)		(8	)
	change – fuel services		(15	)		(15	)
Other changes
Higher administration expenditures			(11	)		(11	)
Higher exploration expenditures			(1	)		(1	)
Change in reclamation provisions			(26	)		—
Change in gains or losses on derivatives			28			3
Change in foreign exchange gains or losses			6			6
Redemption of Series E debentures in 2020			(24	)		(24	)
Canadian Emergency Wage Subsidy in 2020			37			37
Change in income tax recovery or expense			22			23
Other			(4	)		(4	)
Net earnings - 2020			80			48

56     CAMECO CORPORATION

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 35 for more information. The following table reconciles adjusted net earnings with our net earnings.

	THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)	2020			2019
Net earnings attributable to equity holders		80			128
Adjustments
Adjustments on derivatives		(43	)		(18	)
Reclamation provision adjustments		—			(26	)
Income taxes on adjustments		11			10
Adjusted net earnings		48			94

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 adjusted net earnings measure.

ADMINISTRATION

	THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)	2020		2019		CHANGE
Direct administration		31		32		(3	)%
Stock-based compensation		14		2		600	%
Total administration		45		34		32	%

Direct administration costs were $31 million in the quarter, $1 million lower than the same period last year. Stock-based compensation expenses were $12 million higher from the fourth quarter of 2019 due to the increase in our share price compared to the same period in 2019. See note 24 to the financial statements.

Quarterly trends

HIGHLIGHTS	2020											2019
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q4		Q3			Q2			Q1			Q4		Q3			Q2			Q1
Revenue		550		379			525			346			874		303			388			298
Net earnings (loss) attributable to equity holders		80		(61	)		(53	)		(19	)		128		(13	)		(23	)		(18	)
$ per common share (basic)		0.20		(0.15	)		(0.13	)		(0.05	)		0.32		(0.03	)		(0.06	)		(0.05	)
$ per common share (diluted)		0.20		(0.15	)		(0.13	)		(0.05	)		0.32		(0.03	)		(0.06	)		(0.05	)
Adjusted net earnings (loss) (non-IFRS, see page 35)		48		(78	)		(65	)		29			94		(2	)		(18	)		(33	)
$ per common share (adjusted and diluted)		0.12		(0.20	)		(0.16	)		0.07			0.24		(0.01	)		(0.04	)		(0.08	)
Cash provided by (used in) operations (after working capital changes)		257		(66	)		(316	)		182			274		232			(59	)		80

Key things to note:

• Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 79% of consolidated revenues in the fourth quarter of 2020 and 76% of consolidated revenues in the fourth quarter of 2019.

• 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 35 for more information).

MANAGEMENT’S DISCUSSION AND ANALYSIS     57

• 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.

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

HIGHLIGHTS	2020												2019
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Net earnings (loss) attributable to equity holders		80			(61	)		(53	)		(19	)		128			(13	)		(23	)		(18	)
Adjustments
Adjustments on derivatives		(43	)		(31	)		(41	)		70			(18	)		9			(17	)		(23	)
Reclamation provision adjustments		—			7			23			(6	)		(26	)		3			24			2
Income taxes on adjustments		11			7			6			(16	)		10			(1	)		(2	)		6
Adjusted net earnings (losses) (non-IFRS, see page 35)		48			(78	)		(65	)		29			94			(2	)		(18	)		(33	)

58     CAMECO CORPORATION

Fourth quarter financial results by segment    

Uranium

		THREE MONTHS ENDED
		DECEMBER 31
HIGHLIGHTS		2020		2019		CHANGE
Production volume (million lbs)			2.8		2.7		4	%
Sales volume (million lbs)			8.6		14.0		(39	)%
Average spot price	($US/lb)		29.86		25.08		19	%
Average long-term price	($US/lb)		35.00		32.17		9	%
Average realized price	($US/lb)		38.43		35.92		7	%
	($Cdn/lb)		50.40		47.50		6	%
Average unit cost of sales (including D&A)	($Cdn/lb)		41.57		37.80		10	%
Revenue ($ millions)			436		666		(35	)%
Gross profit ($ millions)			76		136		(44	)%
Gross profit (%)			17		20		(15	)%

Production volumes this quarter were 4% higher compared to the fourth quarter of 2019. See Uranium – production overview on page 66 for more information.

Uranium revenues were down 35% due mainly to a 39% decrease in sales volume slightly offset by a 6% increase in the Canadian dollar average realized price. While the average spot price for uranium increased by 19% compared to the same period in 2019, our average realized price only increased by 6% as a result of lower prices on fixed-price contracts and less sensitivity to price changes due to floor prices in the market-related contracts delivered into. In addition, the Canadian dollar was slightly stronger compared to the same period last year, $1.00 (US) for $1.31 (Cdn) compared to $1.00 (US) for $1.32 (Cdn) in the fourth quarter of 2019.

Total cost of sales (including D&A) decreased by 33% ($348 million compared to $519 million in 2019). This was primarily the result of the 39% decrease in sales volume as the average unit cost of sales increased by 10% due to the higher cost of purchased material.

The net effect was a $60 million decrease in gross profit for the quarter. While the increase in the uranium price compared to 2019 has had a positive effect on our average realized price, the increase has also impacted the cost of our spot market purchases.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS     59

	THREE MONTHS ENDED
	DECEMBER 31
($CDN/LB)	2020		2019		CHANGE
Produced
Cash cost		13.48		17.21		(22	)%
Non-cash cost		14.62		15.54		(6	)%
Total production cost 1		28.10		32.75		(14	)%
Quantity produced (million lbs)1		2.8		2.7		4	%
Purchased
Cash cost1		37.63		34.17		10	%
Quantity purchased (million lbs)1		7.3		4.3		70	%
Totals
Produced and purchased costs		34.99		33.62		4	%
Quantities produced and purchased (million lbs)		10.1		7.0		44	%

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 2.7 million pounds at a purchase price per pound of $37.14 ($28.17 (US)) (Q4 2019 - 1.4 million pounds at a purchase price per pound of $32.18 ($24.40 (US))).

The average cash cost of production was 22% lower for the quarter than in the comparable period in 2019 due to the timing of costs in 2019. While McArthur River and Key Lake are shut down, our annual cost of production is expected to reflect the estimated life-of-mine operating cost, between $15 and $16 per pound, of mining and milling our share of Cigar Lake mineral reserves, but it may fluctuate from quarter to quarter.

The benefit of the estimated life-of-mine operating cost for Inkai’s production of between $8 and $9 per pound, is expected to be reflected in the line item on our statement of earnings called “share of earnings from equity-accounted investee”.

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 $37.63 (Cdn) per pound, or $28.58 (US) per pound in US dollar terms, compared to $34.17 (Cdn) per pound, or $25.87 (US) per pound in the fourth quarter of 2019.

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 fourth quarters of 2020 and 2019.

60     CAMECO CORPORATION

CASH AND TOTAL COST PER POUND RECONCILIATION

	THREE MONTHS ENDED
	DECEMBER 31
($ MILLIONS)	2020			2019
Cost of product sold		300.8			442.8
Add / (subtract)
Royalties		(7.8	)		(14.3	)
Other selling costs		(1.3	)		(4.4	)
Care and maintenance and severance costs		(29.5	)		(29.7	)
Change in inventories		50.2			(201.0	)
Cash operating costs (a)		312.4			193.4
Add / (subtract)
Depreciation and amortization		58.6			87.4
Care and maintenance costs		(11.4	)		(11.5	)
Change in inventories		(6.2	)		(33.9	)
Total operating costs (b)		353.4			235.4
Uranium produced & purchased (million lbs) (c)		10.1			7.0
Cash costs per pound (a ÷ c)		30.93			27.63
Total costs per pound (b ÷ c)		34.99			33.63

Fuel services

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

		THREE MONTHS ENDED
		DECEMBER 31
HIGHLIGHTS		2020		2019		CHANGE
Production volume (million kgU)			3.3		4.0		(18	)%
Sales volume (million kgU)			4.4		6.2		(29	)%
Average realized price	($Cdn/kgU)		26.29		24.61		7	%
Average unit cost of sales (including D&A)	($Cdn/kgU)		19.12		17.11		12	%
Revenue ($ millions)			115		152		(24	)%
Gross profit ($ millions)			32		47		(32	)%
Gross profit (%)			28		31		(10	)%

Total revenue decreased by 24% due to a 29% decrease in sales volumes partially offset by a 7% increase in average realized price. The increase in average realized price was due primarily to increased prices on the sale of UF₆ due to market conditions.

Total cost of sales (including D&A) decreased by 22% to $83 million compared to the fourth quarter of 2019 due to the 29% decrease in sales volumes partially offset by an increase of 12% in the average unit cost of sales, due to the mix of product sold.

The net effect was a $15 million decrease in gross profit.

MANAGEMENT’S DISCUSSION AND ANALYSIS     61

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.

63	MANAGING THE RISKS
66	URANIUM – PRODUCTION OVERVIEW
66	PRODUCTION OUTLOOK
67	URANIUM – TIER-ONE OPERATIONS
67	MCARTHUR RIVER MINE / KEY LAKE MILL
71	CIGAR LAKE
76	INKAI
79	URANIUM – TIER-TWO OPERATIONS
79	RABBIT LAKE
80	US ISR
81	URANIUM – ADVANCED PROJECTS
81	MILLENNIUM
81	YEELIRRIE
81	KINTYRE
82	URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
83	FUEL SERVICES
83	BLIND RIVER REFINERY
84	PORT HOPE CONVERSION SERVICES
84	CAMECO FUEL MANUFACTURING INC. (CFM)

62     CAMECO CORPORATION

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. Our risk policy and program involves a broad, systematic approach to identifying, assessing, reporting and managing the significant risks we face in our business and operations, including ESG risks. The policy establishes clear accountabilities for enterprise risk management. We use a common risk matrix throughout the company and consider any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan as an enterprise risk. However, there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause. We recommend you read our most recent management proxy circular for more information about our risk oversight.

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 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, 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 make any significant change 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 recently introduced a new Impact Assessment Act as well as a Canadian Navigable Waters Act along with significant revisions to the federal Fisheries Act. This new legislation will impact the scope, timeliness and cost of approvals for projects and the revisions could impact existing operations.

• Environment and Climate Change Canada (ECCC) has published an amended national recovery strategy for woodland caribou that has the potential to impact economic and social development in northern Saskatchewan. Research completed in northern Saskatchewan has resulted in a report indicating the range in which our northern Saskatchewan operations are located, hosts a secure and self-sustaining population of woodland caribou, perhaps one of the most secure boreal caribou populations in Canada. The population status was incorporated by ECCC into the amended national recovery strategy; however, potential habitat protection measures could still have an impact on our Saskatchewan operations and advanced projects.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     63

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. We have received the required approvals for the revised PDP and our letters of credit have been updated for McArthur River, Cigar Lake and Key Lake. The revised PDP for Rabbit Lake is still under review by CNSC staff.

At the end of 2020, our estimate of total decommissioning and reclamation costs was $1.14 billion. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $1.20 billion at the end of 2020 (the present value of the $1.14 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 $1.02 billion in financial assurances supporting our reclamation liabilities at the end of 2020. 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 2020 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 on historical components of our Rabbit Lake and Key Lake operations as well as at our in-situ recovery operations in the United States

• containment system upgrades and remediation of the groundwater issue discovered in 2018 at our Key Lake operation.

Most of these projects are multi-year projects that are expected to continue into 2021 and beyond.

64     CAMECO CORPORATION

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

• natural phenomena, such as inclement weather conditions, 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     65

Uranium – production overview

Production in our uranium segment in the fourth quarter was 2.8 million pounds, 4% higher compared to the same period in 2019, while production for the year was 5.0 million pounds, 44% lower than in 2019. The McArthur River/Key Lake and Rabbit Lake operations are 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 67 and Uranium – Tier-two operations beginning on page 79 for more information.

Uranium production

	THREE MONTHS ENDED				YEAR ENDED
CAMECO SHARE	DECEMBER 31				DECEMBER 31
(MILLION LBS)	2020		2019		2020		2019		2020 TARGET1
Cigar Lake		2.8		2.7		5.0		9.0		up to 5.3
Total		2.8		2.7		5.0		9.0		up to 5.3

¹  In April 2020 we withdrew our production outlook for the Cigar Lake mine due to the first precautionary suspension of production to manage the risks posed by the COVID-19 pandemic. With the restart of the mine in September after the first production suspension, a production target of up to 5.3 million pounds (our share) was set.

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 is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to preserve the value of those assets and increase long-term value, and to do that with an emphasis on safety, people and the environment.

Given the uncertainty due to the COVID-19 pandemic and to mitigate risk, we plan to:

• prioritize the health and safety of our workers, their families and communities

• return Cigar Lake to production when it is safe to do so after the second production suspension

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

• 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 total production from Inkai to be 8.3 million pounds in 2021 on a 100% basis, assuming no production disruptions due to the COVID-19 pandemic 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 4.9 million pounds in 2021.

66     CAMECO CORPORATION

Uranium – Tier-one operations

McArthur River mine / Key Lake mill

2020 Production (our share)   0.0M lbs   2021 Production Outlook (our share)   0.0M lbs   Estimated Reserves (our share)   273.6M lbs   Estimated Mine Life¹   23 years

¹  Estimated mine life based on the production schedule presented in the National Instrument 43-101 Technical Report dated March 29, 2019.

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, which means it can produce more than 18 million pounds per year by mining only 200 to 400 tonnes of ore per day. 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, which will continue for an indeterminate duration. The restart of the mine and mill is a commercial decision that will be based on our ability to commit our share of production from this operation under acceptable long-term contracts and to benefit from the favourable life-of-mine economics it provides.

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		273.6 million pounds (proven and probable), average grade U3O8: 6.89%
Estimated resources		7.2 million pounds (measured and indicated), average grade U3O8: 2.45%
		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 2020	325.4 million pounds (McArthur River/Key Lake) (100% basis)
	1983 to 2002	209.8 million pounds (Key Lake) (100% basis)
2020 production		0.0 million pounds (0.0 million pounds on 100% basis)
2021 production outlook		0.0 million pounds (0.0 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     67

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 46.6 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.

68     CAMECO CORPORATION

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.

2020 UPDATE

Production suspension

The facilities remained in a state of safe and sustainable care and maintenance throughout 2020.

Approximately 185 Cameco employees remain employed at the McArthur River and Key Lake sites. Care and maintenance activities include mine dewatering, water treatment, freeze wall maintenance, and environmental monitoring. In addition, preservation maintenance and monitoring of the critical facilities continues. Our objective is that the McArthur River and Key Lake operations are available to return to production in a timely manner once a decision is made to end the production suspension.

Exploration

As a result of the production suspension, there was no exploration activity in 2020.

PLANNING FOR THE FUTURE

Production

Due to continued uranium price weakness, we have suspended production for an indeterminate duration. The restart of the mine and mill is a commercial decision that will be based on our ability to commit our share of production from this operation under acceptable long-term contracts and to benefit from the favourable life-of-mine economics it provides. As a result of the suspension, and the time required to restart the mine and mill, we do not expect the operation to produce any uranium in 2021. Our share of the cash and non-cash costs to maintain both operations during the suspension is expected to range between $8 million and $10 million per month.

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 43 projects focused on improvement of the mine and mill through application of automation, digitization and optimization. The initial assessment of the majority of the projects was completed, which will allow us to complete the pre-feasibility work and to define the business case. We expect projects that meet our investment criteria will be advanced to implementation in 2021.

MANAGEMENT’S DISCUSSION AND ANALYSIS     69

Optimizing production

The technical report dated March of 2019 is based on a production rate of 18 million pounds (100% basis) per year, however, once a restart decision is made, we plan to optimize the production rate to respond to market signals. We expect that this paced approach will allow us to extract maximum value from the operation as the market transitions.

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 restart

The operational changes we have made, including the suspension of production in 2018 for an indeterminate duration and the accompanying workforce reduction, carry with them the risks of a delay in restarting operations and subsequent production disruption.

There is increased uncertainty regarding the timing of a successful restart of the operations and the associated costs the longer the mine and mill are on care and maintenance.

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 63 to 65.

70     CAMECO CORPORATION

Uranium – Tier-one operations

Cigar Lake

2020 Production (our share)   5.0M lbs   2021 Production Outlook (our share)   Production temporarily suspended   Estimated Reserves (our share)   82.8M lbs   Estimated Mine Life   2029

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	82.8 million pounds (proven and probable), average grade U3O8: 15.92%
Estimated resources	52.4 million pounds (measured and indicated), average grade U3O8: 13.88%
	11.4 million pounds (inferred), average grade U3O8: 5.55%
Licensed capacity	18.0 million pounds per year (our share 9.0 million pounds per year)
Licence term	Through June, 2021
Total packaged production: 2014 to 2020	93.0 million pounds (100% basis)
2020 production	5.0 million pounds (10.1 million pounds on 100% basis)
2021 production outlook	Production temporarily suspended
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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     71

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 full annual production rate of 18 million pounds. 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 16% U₃O₈, is pumped into transport truck containers and shipped to McClean Lake mill on a 69 kilometre all-weather road

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

Milling

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

• operate at Cigar Lake’s targeted annual production level of 18 million pounds U₃O₈

• 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.

The CNSC licence is set to expire in June 2021. The CNSC has set an April date for the licence renewal hearing and it will be held virtually. At this time, we have submitted all of the relevant supporting program documents and we, along with the CNSC, are preparing the Commission Member Documents that the CNSC will review as part of this proceeding. The CNSC has yet to finalize intervener funding for this hearing.

2020 UPDATE

Production

Total packaged production from Cigar Lake was 10.1 million pounds U₃O₈; our share was 5.0 million pounds. Production was temporarily suspended twice in 2020 due to precautionary measures taken with the increasing risks posed by the COVID-19 pandemic.

An initial suspension was announced in March 2020 with the operations moving to care and maintenance in April. In September we safely restarted the Cigar Lake mine. As planned, it took about two weeks to achieve initial production once the mine was restarted.

As announced in December 2020, production at the Cigar Lake mine was temporarily suspended again as a precautionary measure with a negative trend in the pandemic in Saskatchewan which created increased uncertainty for the continuous operation of the mine due to access to qualified operational personnel.

During the year, we:

• substantially completed the extension of the underground electrical distribution system and commenced the extension of the underground piping infrastructure to support mining the west portion of the orebody

• executed planned annual maintenance activities during the first two weeks of September, prior to the safe restart of production following the five-month precautionary suspension of production due to the COVID-19 pandemic

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

• expanded our ground freezing program ensuring continued frozen ore inventory growth in alignment with our long-term production plans

• completed a project looking at alternative mining methods that have potential to be utilized as alternatives to the underground jet boring system at Cigar Lake

MANAGEMENT’S DISCUSSION AND ANALYSIS     73

Underground development

In alignment with our production plans, underground mine development continued in 2020 between January to March and September to December. Development included focus on two new production panels in the eastern portion of the orebody along with initial access development towards the western portion. Development of the two production panels in the east were completed in 2020. Development in the western portion of the orebody is planned for 2021, along with further development in the eastern portion of the orebody to ensure new production panels are available in alignment with long-term production plans.

PLANNING FOR THE FUTURE

Production

Our production and development plans for 2021 are uncertain as the Cigar Lake mine remains suspended and a restart of the operation and the production rate will be dependent on our ability to maintain safe and stable operating protocols along with a number of other factors, including how the COVID-19 pandemic is impacting the availability of the required workforce, how cases are trending in Saskatchewan, in particular in northern communities, and the views of the public health authorities.

As a result of the suspensions in production, we have also experienced delays and deferrals in project work, including lower capital expenditures, which introduces potential risk to the production rate in 2022.

While Cigar Lake is on care and maintenance, we expect to incur costs of between $8 million and $10 million per month, which will be expensed directly to cost of sales. We may also incur additional costs related to the purchase of uranium, which comes at a higher cost than our production.

In 2021, we plan to:

• 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

• substantially complete the expansion of the underground piping and infrastructure towards new production panels required to sustain production

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.

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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 63 to 65.

MANAGEMENT’S DISCUSSION AND ANALYSIS     75

Uranium – Tier-one operations

Inkai

2020 Production (100% basis)   7.0M lbs   2021 Production Outlook (100% basis)   8.3M lbs   Estimated Reserves (our share)   97.5M 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	97.5 million pounds (proven and probable), average grade U3O8: 0.03%
Estimated resources	12.8 million pounds (measured and indicated), average grade U3O8: 0.03%
	30 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 2020	64.5 million pounds (100% basis)
2020 production	7.0 million pounds (100% basis)1
2021 production outlook	8.3 million pounds (100% basis)1
Estimated decommissioning cost (100% basis)	$11 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.

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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 2020 production from Inkai was 7.0 million pounds (100% basis), a decrease of 16% from 2019. The decrease in production is due to the impact of the reduction in operational activities introduced to manage the risks posed by the COVID-19 pandemic.

On April 7, 2020, Kazatomprom announced a reduction to operational activities across all uranium mines in Kazakhstan for an expected period of three months due to the risks posed by the COVID-19 pandemic. It indicated that its decision would result in a lower level of wellfield development activity and, as a result, an estimated reduction of up to 17.5% in total planned uranium production in Kazakhstan in 2020. On July 6, 2020, Kazatomprom announced a one-month extension of the period of reduced operational activities with the impact on its revised production plan for 2020 expected to be immaterial. In August 2020, the previously reduced operational activities, including wellfield development resumed at JV Inkai.

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.

Cash distribution

Excess cash, net of working capital requirements, will be distributed to the partners as dividends. In 2020, we received dividend payments from JV Inkai totaling $40.6 million (US). Our share of dividends follows our production purchase entitlements as described above.

PLANNING FOR THE FUTURE

Production

Based on an adjustment to the production purchase entitlement under the 2016 JV Inkai restructuring agreement described above, we are entitled to purchase 4.9 million pounds, or 59.4% of JV Inkai’s planned 2021 production of 8.3 million pounds, assuming no production disruptions due to the COVID-19 pandemic or other causes. 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     77

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

2021 production forecast risk

Achievement of JV Inkai’s 2021 production forecast requires it to successfully manage its operating and other risks including the current uncertain environment resulting from the COVID-19 pandemic and its related operational risks, 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. We believe the political risk related to our investment in JV Inkai is manageable.

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

JV Inkai manages risks listed on pages 63 to 65.

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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 2020	202.2 million pounds
2020 production	0 million pounds
2021 production outlook	0 million pounds
Estimated decommissioning cost1	$213 million

¹  This updated estimate is currently under regulatory review.

PRODUCTION SUSPENSION

The facilities remained in a state of safe and sustainable care and maintenance throughout 2020.

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 63 to 65.

MANAGEMENT’S DISCUSSION AND ANALYSIS     79

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 2020		33.0 million pounds
2020 production		0 million pounds
2021 production outlook		0 million pounds
Estimated decommissioning cost		Smith Ranch-Highland: $219 million (US), including North Butte
		Crow Butte: $52 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 2021.

FUTURE PRODUCTION

We do not expect any production in 2021.

MANAGING OUR RISKS

We manage the risks listed on pages 63 to 65.

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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.

2020 PROJECT UPDATES

We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment our primary focus is on preserving the value of our tier-one uranium assets. 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

2021 Planned activity

No work is planned at Millennium, Yeelirrie or Kintyre. Further progress towards a development decision is not expected until market conditions improve.

MANAGING THE RISKS

For all of our advanced projects, we manage the risks listed on pages 63 to 65.

MANAGEMENT’S DISCUSSION AND ANALYSIS     81

Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral reserves as they are depleted by our production and is key to sustaining our business. However, during this period of weak uranium prices, and as we 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 0.8 million hectares (2.0 million acres). In northern Saskatchewan alone, we have direct interests in about 0.7 million hectares (1.8 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin.

2020 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 2020, we spent about $4 million on brownfields and advanced uranium projects in Saskatchewan and Australia. At the US operations we spent $1 million.

Regional exploration

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

PLANNING FOR THE FUTURE

We will 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.

INVESTMENT PROGRAM

Currently, given the conditions in the uranium market, our extensive portfolio of reserves and resources and our belief that we have ample idle production capacity, our focus is on navigating by our investment-grade rating and preserving the value of our tier-one assets. 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.

However, 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 in the strategy section, starting on page 18.

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Fuel services

Refining, conversion and fuel manufacturing

We have about 24% 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	$58 million

MANAGEMENT’S DISCUSSION AND ANALYSIS     83

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

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2020 UPDATE

Production

Fuel services produced 11.7 million kgU, 12% lower than 2019. This was a result of the temporary suspension of production in April resulting from the precautionary measures taken for the COVID-19 pandemic.

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 was progress earlier in the year, work on the Vision in Motion project in 2020 was suspended due to 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 2021, 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

2021 production forecast risk

Achievement of our 2021 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, including the risk of significant disruption to our fuel services operations, workforce, required supplies or services, and our ability to produce product.

Labour relations

The current collective bargaining agreement with the unionized employees at CFM expires on June 1, 2021. 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 is underway for both sites and will continue throughout 2021. We do not expect any interruption or significant risks from this process.

We also manage the risks listed on pages 63 to 65.

MANAGEMENT’S DISCUSSION AND ANALYSIS     85

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, 2020.

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

We use current geological models, an average uranium price of $45 (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.

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

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Changes this year

Our share of proven and probable mineral reserves decreased from 461 million pounds U₃O₈ at the end of 2019, to 455 million pounds at the end of 2020. The change was primarily the result of:

• production at Cigar Lake and Inkai, which removed 8.3 million pounds from our mineral inventory

• application of a revised mining recovery factor at Cigar Lake from 90% to 86% which removed 3.8 million pounds of proven and probable reserves

partially offset by:

• a mineral resource and reserve estimate update at Cigar Lake, which added 7.4 million pounds of proven and probable reserves

Our share of measured and indicated mineral resources slightly increased from 424 million pounds U₃O₈ at the end of 2019, to 426 million pounds at the end of 2020. Our share of inferred mineral resources is 174 million pounds U₃O₈, a slight decrease of 1 million pounds from the end of 2019. The variance in mineral resources was primarily the result of the Cigar Lake mineral resource estimate update and minor mineral resource estimation work at McArthur River.

MANAGEMENT’S DISCUSSION AND ANALYSIS     87

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

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.

88     CAMECO CORPORATION

Mineral reserves

As of December 31, 2020 (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		268.7		17.53		103.8		203.2		13.78		61.7		471.9		15.92		165.6		82.8		98.5
Key Lake		OP		61.1		0.52		0.7		—		—		—		61.1		0.52		0.7		0.6		99
McArthur River		UG		2,041.0		7.12		320.2		540.0		6.02		71.7		2,581.0		6.89		391.9		273.6		99
Inkai		ISR		202,780.4		0.03		156.0		149,442.2		0.03		87.8		352,222.7		0.03		243.8		97.5		85
Total				205,151.3		—		580.7		150,185.4		—		221.2		355,336.7		—		802.0		454.5		—

(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 $45 (US) per pound U₃O₈

• are based on exchange rates of $1.00 US=$1.26 Cdn and 460 Kazakhstan Tenge to $1.00 Cdn

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 67.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS     89

Mineral resources

As of December 31, 2020 (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		32.9		7.61		5.5		309.4		14.55		99.3		104.8		52.4		186.3		5.55		22.8		11.4
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		97.8		2.57		5.5		92.4		2.32		4.7		10.3		7.2		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		6.7		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		36,680.9		0.03		21.3		21,132.2		0.02		10.7		32.0		12.8		116,394.6		0.03		75.0		30.0
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		3,710.6		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		70,650.9		—		146.0		69,394.6		—		385.2		531.2		426.1		132,003.2		—		255.4		174.3

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

90     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, 2020, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

MANAGEMENT’S DISCUSSION AND ANALYSIS     91

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, 2020.

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, 2020 but they did not have an effect on the Company’s financial statements.

92     CAMECO CORPORATION