Exhibit 99.2

Management’s discussion and analysis

for the quarter ended September 30, 2019

4   5   8   15   18   20   23   24   24 OUR STRATEGY   THIRD QUARTER MARKET UPDATE   CONSOLIDATED FINANCIAL RESULTS   OUTLOOK FOR 2019   LIQUIDITY AND CAPITAL RESOURCES   FINANCIAL RESULTS BY SEGMENT   OUR OPERATIONS - THIRD QUARTER UPDATES   QUALIFIED PERSONS   ADDITIONAL INFORMATION

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited condensed consolidated interim financial statements and notes for the quarter ended September 30, 2019 (interim financial statements). The information is based on what we knew as of October 31, 2019 and updates our first quarter, second quarter and annual MD&A included in our 2018 annual report.

As you review this MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2018 and annual MD&A. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at 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 and Cameco mean Cameco Corporation and its subsidiaries unless otherwise indicated.

Caution about forward-looking information

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

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

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

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

• It is based on a number of material assumptions, including those we have listed on page 3, which may prove to be incorrect.

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

• Forward-looking information is designed to help you understand management’s current views of our near 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

•  the discussion under the headings Our strategy and Strategy in action, including for uranium purchases, sales, deliveries, and prices, our ability to self-manage risk, and our tax risk   •  our expectations about 2019 and future global uranium supply, consumption, contracting volumes and demand, including the discussion under the heading Third quarter market update   •  the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including that the Tax Court of Canada (Tax Court) ruling will be upheld on appeal and our estimate of the amount and timing of cash taxes, transfer pricing penalties and disbursements award   •  the discussion under the heading Outlook for 2019, including expectations for 2019 gross profit, cash balances, revenue, and deliveries, our 2019 financial outlook, our revenue, adjusted net earnings, and cash flow sensitivity analysis, and our price sensitivity analysis for our uranium segment •  our expectations regarding 2019 cash flow, and that existing cash balances and operating cash flows will meet our 2019 capital requirements   •  production and life of mine operating cost estimates for the Cigar Lake and Inkai operations   •  our expectation that our operating and investment activities for the remainder of 2019 will not be constrained by the financial-related covenants in our unsecured revolving credit facility   •  our future plans and expectations for each of our uranium operating properties and fuel services operating sites, including production levels   •  our expectations related to care and maintenance costs, including incurring between $130 and $160 million in 2019

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 or trade restrictions   •  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 necessary supplies are not available, or not available on commercially reasonable terms   •  our strategies may change, be unsuccessful or have unanticipated consequences   •  our estimates and forecasts prove to be inaccurate, including production, purchases, deliveries, cash flow, revenue, costs, decommissioning, reclamation expenses, or our tax expense   •  we are unable to enforce our legal rights under our existing agreements, permits or licences   •  the necessary permits or approvals from government authorities are not obtained or maintained •  there are defects in, or challenges to, title to our properties   •  our mineral reserve and resource estimates are not reliable, or there are challenging or unexpected geological, hydrological or mining conditions   •  we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays   •  government laws, regulations, policies, or decisions that adversely affect us, including tax and trade laws   •  our Cigar Lake development, mining or production plans are delayed or do not succeed for any reason   •  any difficulties in milling of Cigar Lake ore at McClean Lake mill   •  water quality concerns and environmental concerns 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

2     CAMECO CORPORATION

•  our uranium suppliers fail to fulfil delivery commitments or our uranium purchasers fail to fulfil purchase commitments   •  we are affected by political risks   •  we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy   •  a major accident at a nuclear power plant   •  we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium   •  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 results in significantly higher cash taxes, interest charges and penalties that could have a material adverse effect on us   •  our expectations relating to care and maintenance costs prove to be inaccurate   •  we are unable to utilize letters of credit to the extent anticipated in our dispute with CRA   •  we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes   •  operations are disrupted due to problems with 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 (including at Orano’s McClean Lake mill), underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, 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 regarding the demand for and supply of uranium   •  our expectations regarding spot prices and realized prices for uranium, and other factors discussed under the heading Price sensitivity analysis: uranium segment   •  that the construction of new nuclear power plants and the relicensing of existing nuclear power plants will not be more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants   •  our ability to continue to supply our products and services in the expected quantities and at the expected times   •  our expected production levels for uranium and conversion services   •  our cost expectations, including production costs, purchase costs, operating costs, capital costs, and the success of our cost reduction strategies   •  our expectations regarding tax rates and payments, royalty rates, currency exchange rates and interest rates   •  our expectations about the outcome of our dispute with CRA, including that the Tax Court ruling will be upheld on appeal   •  we are able to utilize letters of credit to the extent anticipated in our dispute with CRA   •  our decommissioning and reclamation expenses, 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   •  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   •  operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, 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 (including at Orano’s McClean Lake mill), 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

2019 THIRD QUARTER REPORT     3

Our strategy

We are a pure-play nuclear fuel supplier, 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 shareholder value, and to do that with an emphasis on safety, people and the environment.

Due to the weak market conditions since 2011, we have undertaken a number of deliberate and disciplined actions: we have 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 evaluate our strategy in the context of our market environment and continue to adjust our actions in accordance with the following 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 commit our tier-one pounds under long-term contracts that provide an acceptable rate of return for our owners.

• Second, we do not intend to build up 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 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 a rolling 12-month period.

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.

We believe this approach provides us with the opportunity to meet rising demand with increased production from our best margin assets, helps to mitigate risk, and will allow us to create long-term value for our shareholders. And, if the market transition takes longer than expected, we believe it positions us to meet the delivery commitments under our contract portfolio, generate cash flow, and preserve our tier-one assets. Our focus continues to be on maximizing cash flow, while maintaining our investment-grade rating so we can self-manage risk.

You can read more about our strategy in our 2018 annual MD&A.

Strategy in action

During the third quarter of 2019, we continued to execute on all three facets of our strategy, operational, marketing, and financial.

On the operational front, as planned, production continues to be well below our sales commitments. With the fourth quarter expected to be our largest delivery quarter this year we have begun to purchase some of the material we need to meet our commitments. In addition, with McArthur River/Key Lake still on care and maintenance we will need to purchase material to meet our 2020 sales commitments. Therefore, we expect to make significant purchases of material on the spot market. However, we are being discretionary. The activity we have seen has largely been churn in the market, the same material changing hands many times. Today, there has been a lack of fundamental demand in the spot market. This lack of demand is primarily the delay of purchasing decisions caused by uncertainty due to the changing market dynamics, including ongoing market access and trade policy issues. If there are sellers that want to sell material into a market that lacks fundamental demand, we will plan our purchasing activity to pick up material as cheaply as possible with the intent of maximizing our gross profit.

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Ultimately, whether it is in the fourth quarter or thereafter, we have more spot market purchasing ahead of us than we have undertaken since putting McArthur River/Key Lake on care and maintenance. We will responsibly manage our supply to meet our sales commitments, which means along with our sales volumes, our production, purchases and inventory are all variables. Our goal is to buy material as cheaply as possible. If we think uranium will be cheaper tomorrow, we may choose to delay some of our purchases and temporarily draw on our working inventory. However, if we think the cheaper pounds are available today, we may advance our purchasing activity and temporarily build inventory to ensure we have the material where we need it, when we need it, and in the right form. The quantum of purchasing we have to do does not change, just the potential timing.

Despite the spot market underperforming our expectations to date, we are pleased by the performance of the term market. The interest in long-term contracting and our off-market conversations with some of our best and largest customers continues. We have not seen the current level of prospective business in our pipeline since before 2011. With the 25 million pounds of long-term contracting disclosed in our first quarter MD&A and some of the prospective business noted, we expect to more than replace the volumes delivered under our contract portfolio this year alone, while maintaining leverage to higher future uranium prices. These customers are asking what it takes to support the operation of our tier-one assets longer term. They recognize that, from a security of supply perspective, diversification is important, and in some cases their risk management departments require it. They want access to long-lived, tier-one productive capacity from commercial suppliers who have a proven operating track record. Increasingly, many customers are also required to ensure their suppliers adhere to more stringent environmental, social, and governance performance standards. In addition, in light of the market access and trade policy issues affecting our market, they recognize the potential for trade policy distortions to regionalize supply, and ultimately, along with low prices, make the availability of future supply less certain and less predictable.

We were also active on the financial aspect of our strategy in the third quarter. We retired one-third, $500 million, of our outstanding debt. In addition, we extended the maturity date of our revolving credit facility to November 2023, while also reducing it by $250 million. We do not have a history of drawing on the excess capacity and, with the strength of our balance sheet, we don’t anticipate needing it. Therefore, it does not make sense to pay to maintain excess capacity on our revolving credit facility. With $864 million in cash and short-term investments on our balance sheet as a result of the strategic actions we have taken, our balance sheet is strong. Our ability to self-manage risk has improved substantially. Additionally, we believe the risk related to our tax case with Canada Revenue Agency (CRA) has diminished based on the unequivocal ruling we received from the Tax Court of Canada (Tax Court) in September 2018, and we believe that decision will be upheld on appeal.

Third quarter market update

Economic realities and government-driven trade policies continue to have an impact on the security of supply in our industry. Not only does it not make sense to invest in future primary supply, even the lowest-cost producers are deciding to preserve long-term value by leaving uranium in the ground. Adding to security of supply concerns today is the role of commercial and state-owned entities in the uranium market, and the disconnect between where uranium is produced and where it is consumed. Nearly 80% of primary production is in the hands of state-owned enterprises, after taking into account the cuts to primary production that have occurred over the last several years. Furthermore, almost 90% of primary production comes from countries that consume little-to-no uranium, and 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 developments during the quarter and to date are:

• In the US, which has the largest fleet of nuclear reactors in the world, the US Nuclear Fuel Working Group (NFWG) was established to further analyze the state of nuclear fuel production in the US. This action followed the determination by the President of the United States under Section 232 of the Trade Expansion Act that imports of foreign uranium do not constitute a national security threat, and that new restrictions on imports were not required. The NFWG was expected to provide its report to the President on October 10, 2019, however, the deadline has been extended by 30 days.

• There is increasing concern regarding expanded sanctions on Iran that could extend to countries providing nuclear fuel products and services to Iran, and therefore disrupt Russian nuclear fuel imports into the US. Compounding this concern is the continued uncertainty regarding Russian sanctions and whether existing quotas on imports of Russian uranium into the US, under the Russian Suspension Agreement, will be extended or amended prior to its expiry in 2020.

• Trade tensions with China continue. On August 14, 2019, the US issued sanctions that involved China General Nuclear Power Group and three of its subsidiaries, effectively banning US companies from supplying these groups with specific nuclear-related commercial or dual-use goods.

2019 THIRD QUARTER REPORT     5

• Kazatomprom (KAP) announced that, given current market conditions, it intends to extend its current production limits (20% reduction from planned production volumes) across all its production assets through 2021. Combined with reductions from prior years, KAP indicated its cutbacks are equivalent to stopping all production in Kazakhstan for about one year. In addition, during the quarter KAP offered a secondary placement of its shares, increasing its publicly-traded share capital from 15% to 18.8%.

• Energy Resources of Australia Ltd. reconfirmed that the Ranger uranium mine in the Northern Territory of Australia will be shut down in January 2021.

• 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 collective bargaining process continues following the May 2019 expiration of the contract with unionized employees at Orano’s McClean Lake mill, which poses a risk to 2020 production plans at Cigar Lake if an agreement cannot be reached and there is a work stoppage.

The demand gap left by forced and premature nuclear reactor shut-downs since March of 2011 has been filled. With four new reactors beginning commercial operation so far in 2019, about 50 reactors under construction, a number of reactor construction projects recently approved, and many more planned, demand 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. However, there is growing recognition of the role nuclear power must play in providing safe, reliable and affordable low-carbon baseload electricity and achieving a carbon-neutral future. Some of the more significant demand developments during the quarter and to date are:

• The World Nuclear Association’s 2019 Nuclear Fuel Report shows demand is forecast to be higher in all scenarios examined over the period 2019 through 2040. In addition, the report shows that under all demand scenarios, the industry needs to at least double projected primary uranium production, by 2040, which will require the appropriate market signals to ensure current levels of production continue, the return of idled production capacity, completion of projects under development, and development of currently planned and prospective projects.

• In May 2019, the International Energy Agency released its first nuclear report in 20 years, “Nuclear Power in a Clean Energy System”. The report highlights that a steep decline in nuclear power would threaten energy security and climate change goals and result in billions of tonnes of additional carbon emissions by 2040.

• In October 2019, the International Atomic Energy Agency (IAEA) held its first ever conference recognizing the critical role for nuclear power in combating climate change, “International Conference on Climate Change and the Role of Nuclear Power”. The IAEA advocates that it will be difficult to achieve the goal of reducing greenhouse gas emissions without a significant increase in nuclear power.

• Duke Energy announced it is seeking to renew the operating licences for the 11 reactors it operates in North and South Carolina for an additional 20 years to support carbon reduction plans. The first of these reactors will reach the end of its current operating licence in the early 2030’s.

• Three Mile Island nuclear power plant was retired from service by Exelon after 45 years of operation in Pennsylvania.

• In Ohio, a bill was passed providing funding to support the ongoing operation of the Perry and Davis-Besse nuclear power plants, similar to incentives enacted by other states including Illinois, New Jersey, New York, Connecticut, and pending legislation in Pennsylvania.

• There were reports that Kyushu Electric Power Co. in Japan expects to temporarily close its currently operating Sendai units next year to complete the implementation of the antiterrorism measures required by the nuclear regulators. The two units are expected to shut down in May of 2020 and restart in December 2020 and January of 2021.

• Brazil announced the possible construction of six more nuclear reactors by 2050, in addition to completion of Angra unit 3, which is currently under construction. Brazil also plans to restart domestic uranium mining in 2019 for the first time in five years, and is open to private sector investment.

Caution about forward-looking information relating to the nuclear industry

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

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Industry prices at quarter end

	SEP 30		JUN 30		MAR 31		DEC 31		SEP 30		JUN 30
	2019		2019		2019		2018		2018		2018
Uranium ($US/lb U3O8)1
Average spot market price		25.68		24.60		25.33		27.75		27.50		22.65
Average long-term price		31.50		31.50		32.00		32.00		31.75		29.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		20.25		18.25		14.75		13.50		13.08		9.03
Europe		20.00		18.00		14.75		13.88		13.50		9.38
Average long-term price
North America		17.88		16.38		15.50		16.00		15.75		14.25
Europe		17.50		16.38		15.50		16.25		16.00		14.25

Note: the industry does not publish UO₂ prices.

¹  Average of prices reported by TradeTech and UxC LLC (UxC)

On the spot market, where purchases call for delivery within one year, the volume reported by UxC for the third quarter of 2019 was over 13 million pounds, compared to 35 million pounds in the third quarter of 2018. The total volume in the spot market year-to-date is over 43 million pounds, which is lower than the same period last year. The majority of the activity in the spot market has been churn, the same material changing hands many times. There has been a lack of fundamental demand primarily caused by the delay of purchasing decisions. Uncertainty due to changing market dynamics, including ongoing market access and trade policy issues continued to keep some utilities on the sidelines. At the end of the quarter, the average reported spot price was $25.68 (US) per pound, up $1.08 (US) from the previous quarter.

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 quoted near the time of delivery. The volume of long-term contracting reported by UxC for the first nine months of 2019 was about 68 million pounds compared to about 58 million pounds reported over the same period in 2018. While higher than the same period last year, newly contracted volumes continued to be less than the quantities consumed. Uncertainty regarding the future of some reactor fleets and complacency due to low uranium prices continued to impact contracting volumes. The average reported long-term price at the end of the quarter was $31.50 (US) per pound, unchanged from last quarter.

Both spot and long-term UF₆ conversion prices increased in the North American and European markets.

Shares and stock options outstanding   At October 30, 2019, we had:   •  395,797,732 common shares and one Class B share outstanding   •  8,722,384 stock options outstanding, with exercise prices ranging from $11.32 to $26.81 Dividend   An annual dividend of $0.08 per common share has been declared, payable on December 13, 2019, to shareholders of record on November 29, 2019. The decision to declare an annual dividend by our board is based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

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.

2019 THIRD QUARTER REPORT     7

Consolidated financial results

CONSOLIDATED HIGHLIGHTS	THREE MONTHS ENDED SEPTEMBER 30									NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS EXCEPT WHERE INDICATED)	2019			2018			CHANGE			2019			2018		CHANGE
Revenue		303			488			(38	)%		988			1,260		(22	)%
Gross profit (loss)		(2	)		(6	)		67	%		57			89		(36	)%
Net earnings (losses) attributable to equity holders		(13	)		28			>(100	%)		(54	)		6		>(100	%)
$ per common share (basic)		(0.03	)		0.07			>(100	%)		(0.14	)		0.02		>(100	%)
$ per common share (diluted)		(0.03	)		0.07			>(100	%)		(0.14	)		0.02		>(100	%)
Adjusted net earnings (losses) (non-IFRS, see page 9)		(2	)		15			>(100	%)		(53	)		9		>(100	%)
$ per common share (adjusted and diluted)		(0.01	)		0.04			>(100	%)		(0.13	)		0.02		>(100	%)
Cash provided by operations (after working capital changes)		232			278			(17	)%		253			610		(59	)%

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 9) in the third quarter and the first nine months of 2019, compared to the same periods in 2018.

		THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)		IFRS			ADJUSTED			IFRS			ADJUSTED
Net earnings – 2018			28			15			6			9
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))
Uranium	Lower sales volume		4			4			(19	)		(19	)
	Higher (lower) realized prices ($US)		6			6			(68	)		(68	)
	Foreign exchange impact on realized prices		3			3			27			27
	Higher costs		(7	)		(7	)		(11	)		(11	)
	Change – uranium		6			6			(71	)		(71	)
Fuel services	Higher (lower) sales volume		(1	)		(1	)		7			7
	Higher (lower) realized prices ($Cdn)		4			4			(16	)		(16	)
	Lower (higher) costs		(3	)		(3	)		19			19
	Change – fuel services		—			—			10			10
Other changes
Lower administration expenditures			15			15			16			16
Lower exploration expenditures			2			2			6			6
Change in reclamation provisions			2			—			21			—
Higher earnings from equity-accounted investee			—			—			20			20
Change in gains or losses on derivatives			(37	)		(4	)		49			—
Change in foreign exchange gains or losses			14			14			(20	)		(20	)
Arbitration award in 2019 related to TEPCO contract			52			52			52			52
Gain on restructuring of JV Inkai in 2018			—			—			(49	)		—
Gain on customer contract restructuring in 2018			—			—			(6	)		(6	)
Reversal of tax provision in 2018 related to CRA dispute			(61	)		(61	)		(61	)		(61	)
Change in income tax recovery or expense			(36	)		(43	)		(57	)		(38	)
Other			2			2			30			30
Net losses – 2019			(13	)		(2	)		(54	)		(53	)

See Financial results by segment beginning on page 20 for more detailed discussion.

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ADJUSTED NET EARNINGS (NON-IFRS MEASURE)

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 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 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 has also been adjusted for impairment charges, reclamation provisions for our Rabbit Lake and US operations, which had 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.

The following table reconciles adjusted net earnings with net earnings for the third quarter and first nine months of 2019 and compares it to the same periods in 2018.

	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2019			2018			2019			2018
Net earnings (losses) attributable to equity holders		(13	)		28			(54	)		6
Adjustments
Adjustments on derivatives		9			(24	)		(31	)		18
Reclamation provision adjustments		3			5			29			50
Gain on restructuring of JV Inkai		—			—			—			(49	)
Income taxes on adjustments		(1	)		6			3			(16	)
Adjusted net earnings (losses)		(2	)		15			(53	)		9

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 8 of our interim financial statements for more information. This amount has been excluded from our adjusted net earnings measure.

Quarterly trends

HIGHLIGHTS	2019									2018									2017
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q3			Q2			Q1			Q4		Q3		Q2			Q1		Q4
Revenue		303			388			298			831		488		333			439		809
Net earnings (losses) attributable to equity holders		(13	)		(23	)		(18	)		160		28		(76	)		55		(62	)
$ per common share (basic)		(0.03	)		(0.06	)		(0.05	)		0.40		0.07		(0.19	)		0.14		(0.16	)
$ per common share (diluted)		(0.03	)		(0.06	)		(0.05	)		0.40		0.07		(0.19	)		0.14		(0.16	)
Adjusted net earnings (losses) (non-IFRS, see page 9)		(2	)		(18	)		(33	)		202		15		(28	)		23		181
$ per common share (adjusted and diluted)		(0.01	)		(0.04	)		(0.08	)		0.51		0.04		(0.07	)		0.06		0.46
Cash provided by (used in) operations (after working capital changes)		232			(59	)		80			57		278		57			275		320

2019 THIRD QUARTER REPORT     9

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 82% of consolidated revenues in the third quarter of 2019

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

• 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 9 for more information).

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

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

HIGHLIGHTS	2019									2018												2017
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Net earnings (losses) attributable to equity holders		(13	)		(23	)		(18	)		160			28			(76	)		55			(62	)
Adjustments
Adjustments on derivatives		9			(17	)		(23	)		47			(24	)		20			22			(2	)
Impairment charges		—			—			—			—			—			—			—			247
Reclamation provision adjustments		3			24			2			10			5			44			1			15
Gain on restructuring of JV Inkai		—			—			—			—			—			—			(49	)		—
Income taxes on adjustments		(1	)		(2	)		6			(15	)		6			(16	)		(6	)		(17	)
Adjusted net earnings (losses) (non-IFRS, see page 9)		(2	)		(18	)		(33	)		202			15			(28	)		23			181

Corporate expenses

ADMINISTRATION

	THREE MONTHS ENDED SEPTEMBER 30							NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2019		2018		CHANGE			2019		2018		CHANGE
Direct administration		22		23		(4	)%		80		79		1	%
Severance costs		—		13		(100	)%		1		13		(92	)%
Stock-based compensation		2		3		(33	)%		9		14		(36	)%
Total administration		24		39		(38	)%		90		106		(15	)%

Direct administration costs were $1 million lower for the third quarter of 2019 compared to the same period last year, and $1 million higher for the first nine months.

Stock-based compensation in the first nine months was lower due primarily to the decrease in our share price during the period compared to 2018.

EXPLORATION

In the third quarter, uranium exploration expenses were $3 million, a decrease of $2 million compared to the third quarter of 2018. Exploration expenses for the first nine months of the year decreased by $6 million compared to 2018, to $11 million, due to a planned reduction in expenditures.

INCOME TAXES

We recorded an income tax expense of $10 million in the third quarter of 2019, compared to a recovery of $87 million in the third quarter of 2018.

10     CAMECO CORPORATION

On an adjusted basis, we recorded an income tax expense of $11 million this quarter compared to a recovery of $93 million in the third quarter of 2018. In 2018, we recorded a reversal of the provision related to our CRA dispute in the amount of $61 million as a result of the clear and decisive ruling in our favour. In 2019, we recorded earnings of $56 million in Canada compared to losses of $121 million in 2018, while we recorded losses of $47 million in foreign jurisdictions compared to earnings of $43 million last year.

In the first nine months of 2019, we recorded an income tax expense of $12 million compared to a recovery of $106 million in 2018.

On an adjusted basis, we recorded an income tax expense of $9 million for the first nine months compared to a recovery of $90 million in 2018. In 2019, we recorded earnings of $62 million in Canada compared to losses of $157 million in 2018, while we recorded losses of $106 million in foreign jurisdictions compared to earnings of $76 million last year.

	THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2019			2018			2019			2018
Pre-tax adjusted earnings1
Canada		56			(121	)		62			(157	)
Foreign		(47	)		43			(106	)		76
Total pre-tax adjusted earnings		9			(78	)		(44	)		(81	)
Adjusted income taxes1
Canada		14			(96	)		15			(100	)
Foreign		(3	)		3			(6	)		10
Adjusted income tax expense (recovery)		11			(93	)		9			(90	)

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 measure on page 9).

TRANSFER PRICING DISPUTE

Tax Court of Canada decision

On September 26, 2018, the Tax Court of Canada (Tax Court) ruled unequivocally in our favour in our case with the Canada Revenue Agency (CRA) for the 2003, 2005 and 2006 tax years.

The Tax Court ruled 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 tax years in question. While the decision applies only to the three tax years under dispute, we believe there is nothing in the decision that would warrant a materially different outcome for subsequent tax years.

The Tax Court has referred the matter back to the Minister of National Revenue in order to issue new reassessments for the 2003, 2005 and 2006 tax years in accordance with the Tax Court’s decision. The total tax amount reassessed for those tax years was $11 million, and we remitted 50%. Therefore, we expect to receive refunds totaling about $5.5 million plus interest. The timing for the revised reassessments along with refunds plus interest may be delayed pending the outcome of the appeal. For further information regarding the appeal, see Appeals process.

On April 30, 2019, we announced the decision of the Tax Court in our application to recover costs in the amount of about $38 million ($20.5 million for legal fees and $17.9 million in disbursements), which were incurred over the course of this case. The Tax Court awarded $10.25 million in legal fees incurred, plus an amount for disbursements, which is yet to be determined. The amount of the award for disbursements will be determined by an officer of the Tax Court, which we expect will happen before the end of the year. We are optimistic we will recover all, or substantially all, of the $17.9 million in disbursements. Timing of any payments under the cost award is uncertain. The CRA has asked for the cost award to be overturned should it be successful in the appeals process.

2019 THIRD QUARTER REPORT     11

Appeals process

On October 25, 2018, CRA filed a notice of appeal with the Federal Court of Appeal. In its notice of appeal, CRA dropped the sham argument, but is appealing the Tax Court’s interpretation and application of the transfer pricing provisions in section 247 of the Income Tax Act. CRA filed its written submissions with the Federal Court of Appeal on May 31, 2019. In its written submission, CRA repeated its trial argument that the transactions should be recharacterized because arm’s length persons would not have entered into the various agreements that underpin the marketing and trading structure. CRA’s alternate argument is that the terms (focused on pricing) of these agreements would have been significantly different if these agreements had been made between arm’s length persons. CRA argues that either approach should result in the disputed reassessments being upheld in their totality.

We anticipate that it will take about two years from the start of the appeal process to receive a decision from the Federal Court of Appeal. We believe there is nothing in the Tax Court’s decision that would warrant a materially different outcome on appeal.

The decision of the Federal Court of Appeal can be appealed to the Supreme Court of Canada, but only if the Supreme Court of Canada agrees to hear the appeal. The request to appeal a decision of the Federal Court of Appeal to the Supreme Court of Canada must be made within 60 days of issuance of a Federal Court of Appeal decision.

In the event that either party appeals the Federal Court of Appeal decision, it would likely take about two years from the date the Federal Court of Appeal decision is issued to receive a decision from the Supreme Court of Canada should that court hear the appeal.

We expect to incur additional costs during the appeal process, 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 2012 tax years. While the Tax Court has ruled unequivocally in our favour for the 2003, 2005 and 2006 tax years, and we believe there is nothing in the decision that would warrant a materially different outcome on appeal, or for subsequent tax years, we will continue to report on the potential exposure as we expect it will continue to tie up our financial capacity until the dispute is finally resolved for all years.

For the years 2003 to 2012, 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. We understand CRA is currently considering whether to impose a transfer pricing penalty for 2012. Taxes of approximately $321 million for the 2003 to 2018 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 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. 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 based on the ruling of the Tax Court. The timing of the refund may be delayed pending the outcome of the appeal.

12     CAMECO CORPORATION

YEAR PAID ($ MILLIONS)	CASH TAXES		INTEREST AND INSTALMENT PENALTIES		TRANSFER PRICING PENALTIES		TOTAL		CASH REMITTANCE		SECURED BY 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
Total		377		221		185		783		303		480

While we expect the Tax Court’s decision to be upheld on appeal and believe the decision should apply in principle to subsequent years, until such time as all appeals are exhausted, and a resolution is reached for all tax years in question, we will not be in a position to determine the definitive outcome of this dispute. We expect any further actions regarding the tax years 2007 through 2012 will be suspended until the three years covered under the decision are finally resolved, with the exception of the transfer pricing penalty noted above. The tax years 2013 and beyond have not yet been reassessed, and it is uncertain what approach CRA will take on audit. 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 2012 tax years. In that scenario, and including the $4.9 billion already reassessed, we would expect to receive notices of reassessment for a total of approximately $8.7 billion of additional income taxable in Canada for the years 2003 through 2018, which would result in a related tax expense of 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 would 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. We have already paid or secured $562 million in cash taxes and transfer pricing penalties and $221 million in interest and instalment penalties.

Under the Canadian federal and provincial tax rules, the 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. 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 2018 along with estimated post-2018 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 appeal. We plan to update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2018.

$ MILLIONS	2003-2018		Post-2018		TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period
Cash payments		226		185 - 235		410 - 460
Secured by letters of credit		336		225 - 275		560 - 610
Total paid1		562		410 - 510		970 - 1070

¹ These amounts do not include interest and instalment penalties, which totaled approximately $221 million to September 30, 2019.

2019 THIRD QUARTER REPORT     13

In light of our view of the likely outcome of the appeal, and the dispute for subsequent years, based on the Tax Court’s decision as described above, we expect to recover the amounts remitted, including the $783 million already paid or otherwise secured to date.

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 2013 through 2018 using a similar methodology as for the years 2003 through 2012, 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 Tax Court’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   •  the successful outcome and timing of the determination of our disbursements award Material risks that could cause actual results to differ materially   •  CRA reassesses us for years 2013 through 2018 using a different methodology than for years 2003 through 2012, 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   •  we are unsuccessful in an appeal of the Tax Court’s decision or any decisions of the Tax Court for subsequent years, or appeals of those decisions, and the outcome of our dispute with CRA, potentially including costs associated with a negotiated resolution with CRA, results in significant costs, cash taxes, interest charges and penalties which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows   •  cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing   •  we are unable to effectively eliminate any double taxation   •  an unfavourable determination of the officer of the Tax Court or delays in making a determination of the amount of our disbursements award

FOREIGN EXCHANGE

The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments. See Revenue, adjusted net earnings, and cash flow sensitivity analysis on page 17 for more information on how a change in the exchange rate will impact our revenue, cash flow, and adjusted net earnings (ANE) (see Non-IFRS measures on page 9).

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

Impact of hedging on IFRS earnings

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

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

14     CAMECO CORPORATION

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 2019 and future years, and we will recognize the gains and losses in ANE in those periods.

For the purposes of ANE, gains and losses on derivatives are reported based on the difference between the effective hedge rate of the contracts designated for use in the particular period and the exchange rate at the time of settlement. This results in an adjustment to current period IFRS earnings to effectively remove reported gains and losses on derivatives that arise from contracts put in place for use in future periods. The effective hedge rate will lag the market in periods of rapid currency movement. See Non-IFRS measures on page 9.

For more information, see our 2018 annual MD&A.

At September 30, 2019:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.32 (Cdn), up from $1.00 (US) for $1.31 (Cdn) at June 30, 2019. The exchange rate averaged $1.00 (US) for $1.32 (Cdn) over the quarter.

• The mark-to-market position on all foreign exchange contracts was a $22 million loss compared to a $13 million loss at June 30, 2019.

For information on the impact of foreign exchange on our intercompany balances, see note 17 to the financial statements.

Outlook for 2019

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 shareholder value, and to do that with a focus on safety, people and the environment.

Our outlook for 2019 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 a result, and based on what we know today, from a gross profit point of view, 2019 is expected to be a weaker year for us. The changing pricing terms under our existing contract portfolio and the proportion of purchased material compared to produced material making up our uranium supply are expected to adversely impact our revenue and cost of sales in 2019 relative to 2018. In addition, our outlook for the average unit cost of sales in 2019 continues to be impacted by care and maintenance costs, which, although lower than in 2018, are expected to be between $130 million and $160 million. Despite the impact on our expected results, we continue to believe these are the right decisions to create long-term shareholder value.

In contrast, from a cash perspective, we expect to continue to maintain a significant cash balance, even after retiring our $500 million debenture in September 2019. We expect to continue to generate cash from operations in this difficult time, however, it will not be as robust as in 2018 given the weaker outlook provided, and without the release of working capital associated with the inventory drawdown we had in 2018.

We report our results and outlook based on a calendar-year view, at a point in time. However, under our marketing framework, we plan on a rolling 12-month basis, which means our sales, inventory and purchases are all variables. Therefore, in accordance with market opportunities and as the year unfolds, we expect our actual sales, purchases and inventory will vary from what we are reporting in the 2019 Financial Outlook table.

In addition, there are a number of moving pieces both internally and externally, that could have an impact on the market and on our results, and it is important to keep them in mind. Some of the remaining items are:

• the impact, if any, on the uranium market and uranium prices from market access or trade policy issues, including the report from the United States Nuclear Fuel Working Group

• whether CRA issues a transfer pricing penalty for the 2012 tax year and/or continues to reassess us for years subsequent to 2012

Our outlook has changed for consolidated, uranium, and fuel services revenue as a result of additional sales commitments in the fuel services segment and a higher anticipated average realized price in the uranium segment.

2019 THIRD QUARTER REPORT     15

Uranium revenue is now expected to be between $1,340 million and $1,430 million (previously $1,320 million to $1,410 million) and the anticipated average realized price increased to $44.70 per pound (previously $44.20 per pound), due to a slightly higher spot price and a more favorable US dollar exchange rate. We expect the average realized price in the fourth quarter will exceed $47 per pound to achieve the expected annual average realized price.

Fuel services deliveries are now expected to be between 14 million and 15 million kgU (previously 13 million to 14 million kgU), increasing the outlook for fuel services revenue to between $350 million and $380 million (previously $330 million to $360 million).

As a result of the items mentioned above, the consolidated revenue is now expected to be between $1,770 million and $1,920 million (previously between $1,730 million and $1,880 million).

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales/delivery volumes and revenue can vary significantly. We are on track for our uranium sales/delivery targets in 2019, with the fourth quarter expected to have the largest delivery volume this year.

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

2019 FINANCIAL OUTLOOK

	CONSOLIDATED			URANIUM			FUEL SERVICES
EXPECTED CONTRIBUTION TO GROSS PROFIT		100	%		62	%		38	%
Production (owned and operated properties)		—			9.0 million lbs			12 to 13 million kgU
Purchases		—			21 to 23 million lbs			—
Sales/delivery volume		—			30 to 32 million lbs			14 to 15 million kgU
Revenue	$	1,770-1,920 million		$	1,340-1,430 million		$	350-380 million
Average realized price		—		$	44.70/lb			—
Average unit cost of sales (including D&A)		—		$	39.50-41.50/lb		$	19.40-20.40/kgU
Direct administration costs	$	110-120 million			—			—
Exploration costs		—		$	13 million			—
Expected loss on derivatives - ANE basis	$	5-15 million			—			—
Tax expense - ANE basis	$	30-40 million			—			—
Capital expenditures	$	95 million			—			—

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

• Purchases – are based on the volumes we have already taken delivery of this year, those we currently have commitments to acquire under contract in 2019, including our JV Inkai purchases and the purchase of NUKEM’s excess inventory, and it includes the additional volumes we are required to purchase in order to meet the sales/delivery commitments we have under contract in 2019 and maintain our normal working inventory.

• Our 2019 outlook for sales/delivery volume and revenue does not include sales between our uranium and fuel services segments.

• Sales/delivery volume is based on the volumes already delivered this year and the remaining commitments we have to deliver under contract in 2019.

• Uranium revenue and average realized price are based on a uranium spot price of $25.65 (US) per pound (the UxC spot price as of September 30, 2019), a long-term price indicator of $32.00 (US) per pound (the UxC long-term indicator on September 30, 2019) and an exchange rate of $1.00 (US) for $1.32 (Cdn).

• Uranium average unit cost of sales (including D&A) is based on the expected unit cost of sales for produced material and expected purchases noted in the outlook. If purchase volumes vary in 2019, then we expect the overall unit cost of sales may be affected.

• Direct administration costs do not include stock-based compensation expenses. See page 10 for more information.

16     CAMECO CORPORATION

• Our outlook for the tax expense is based on adjusted net earnings and the other assumptions listed in the table. The outlook does not include our share of taxes on JV Inkai profits as the income from JV Inkai is net of taxes. If other assumptions change then the expected expense may be affected.

Our 2019 financial outlook is presented on the basis of equity accounting for our minority ownership interest in JV Inkai. Under equity accounting, our share of the profits earned by JV Inkai on the sale of its production will be included in “income from equity-accounted investees” on our consolidated statement of earnings. Our share of production will be purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures.

For more information on how changes in the exchange rate or uranium prices can impact our outlook see Revenue, adjusted net earnings, and cash flow sensitivity analysis below, and Foreign exchange on page 14.

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

FOR 2019 ($ MILLIONS)		IMPACT ON:
	CHANGE	REVENUE			ANE			CASH FLOW
Uranium spot and term price1	$5(US)/lb increase		9			(4	)		(18	)
	$5(US)/lb decrease		(7	)		5			19
Value of Canadian dollar vs US dollar	One cent decrease in CAD		6			3			3
	One cent increase in CAD		(6	)		(3	)		(3	)

¹  Assuming change in both UxC spot price ($25.65 (US) per pound on September 30, 2019) and the UxC long-term price indicator ($32.00 (US) per pound on September 30, 2019)

In the fourth quarter, our adjusted net earnings and cash flow is expected to move in the opposite direction from price. Cash inflows from revenue are expected to be relatively less sensitive to an increase in the spot price than cash outflows from purchases. The volume of remaining spot purchases, based on our outlook, is higher than the volume of planned deliveries that are tied to market prices in the fourth quarter.

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 September 30, 2019 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 September 30, 2019 and none of the assumptions we list below change.

We intend to update this table each quarter in our MD&A to reflect changes to our contract portfolio. As a result, we expect the table to change from quarter to quarter.

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

SPOT PRICES ($US/lb U3O8)	$20		$40		$60		$80		$100		$120		$140
2020		30		40		53		63		72		79		86
2021		27		40		53		60		65		69		73
2022		27		40		54		62		65		68		71
2023		28		41		54		62		66		69		72

The table illustrates the mix of long-term contracts in our September 30, 2019 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to September 30, 2019.

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 higher prices or have high floor prices will yield prices that are higher than current market prices.

2019 THIRD QUARTER REPORT     17

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 22 million pounds per year, with commitment levels in 2019 and 2020 higher than in 2021 through 2023.   •  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 will 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. As of September 30, 2019, we had cash and short-term investments of $864 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 2019 through 2023, we have commitments to deliver an average of 22 million pounds per year, with commitment levels in 2019 and 2020 higher than in 2021 through 2023.

In the currently weak uranium price environment, our focus is on preserving the value of our tier-one assets and reducing our operating, capital and general and administrative spending. 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, the reduction in our dividend, and the drawdown of inventory in 2018 as a result of the suspension of production at our McArthur River/Key Lake operation, we have significant cash balances. We will continue to generate cash from operations however, it will not be as robust as in 2018 given the weaker expected results, and without the release of working capital associated with the inventory drawdown we had in 2018. We expect our cash balances and operating cash flows to meet our 2019 capital requirements.

We received a favourable ruling in our case with CRA for the 2003, 2005 and 2006 tax years. We expect the ruling to be upheld on appeal, and we believe the ruling should apply in principle to subsequent tax years. However, until such time as all appeals are exhausted, 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 11 for more information. In the above scenario, the table on page 13 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 would potentially have to pay or secure upfront if CRA continues to reassess us using the same methodology it reassessed the 2003 to 2012 tax years. The timing of these amounts is uncertain.

CASH FROM/USED IN OPERATIONS

Cash provided by operations was $46 million lower this quarter than in the third quarter of 2018 mainly due to an increase in working capital requirements.

Cash provided by operations was $357 million lower in the first nine months of 2019 than for the same period in 2018 due largely to the drawdown of inventory in 2018 in accordance with our strategy. See note 15 of our interim financial statements for more information.

18     CAMECO CORPORATION

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.7 billion at September 30, 2019, down from $3.0 billion at June 30, 2019. At September 30, 2019, we had approximately $1.5 billion outstanding in financial assurances, down from $1.6 billion at December 31, 2018.

At September 30, 2019, we had no short-term debt outstanding on our unsecured revolving credit facility, unchanged from December 31, 2018. During the quarter we extended the maturity date of the facility from November 1, 2022 to November 1, 2023. In addition, we decreased the facility to $1.0 billion from $1.25 billion. The credit facility allows us to request increases above $1.0 billion, in increments of no less than $50 million, up to a total of $1.25 billion.

Long-term contractual obligations

Since December 31, 2018, there have been no material changes to our long-term contractual obligations. Please see our 2018 annual MD&A for more information.

Debt covenants

We are bound by certain covenants in our unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at September 30, 2019, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2019 to be constrained by them.

OFF-BALANCE SHEET ARRANGEMENTS

We had two kinds of off-balance sheet arrangements at September 30, 2019:

• purchase commitments

• financial assurances

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 NUKEM, at September 30, 2019² 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.

SEPTEMBER 30 ($ MILLIONS)	2019		2020 AND 2021		2022 AND 2023		2024 AND BEYOND		TOTAL
Purchase commitments1,2		48		244		135		317		744

¹  Denominated in US dollars and Japanese yen, as of September 30, 2019 converted from US dollars to Canadian dollars at the rate of $1.32 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 September 30, 2019, but does not include deliveries taken under contract since September 30, 2019.

Our purchase commitments of about $744 million include the following:

• approximately 16 million pounds of U₃O₈ equivalent from 2019 to 2028

• approximately 0.4 million kgU as UF₆ in conversion services from 2019 to 2020

• 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

At September 30, 2019, our financial assurances totaled $1.5 billion, down from $1.6 billion at December 31, 2018.

2019 THIRD QUARTER REPORT     19

BALANCE SHEET

($ MILLIONS)	SEP 30, 2019		DEC 31, 2018		CHANGE
Cash, cash equivalents and short-term investments		864		1,103		(22	)%
Total debt		997		1,496		(33	)%
Inventory		529		468		13	%

Total cash, cash equivalents and short-term investments at September 30, 2019 were $864 million, or 22% lower than at December 31, 2018 largely due to the retirement of our series D debenture in September 2019. Net debt at September 30, 2019 was $133 million.

We had an outstanding loan for JV Inkai’s work on block 3 prior to the restructuring. Under the restructuring agreement for JV Inkai, the partners agreed that JV Inkai would distribute excess cash, after capital expenditures, as priority repayment of our loan. In the third quarter of 2019 we received distributions of $42.2 million (US), which repaid the loan in full.

Total product inventories are $529 million compared to $468 million at the end of 2018. Inventories increased as sales were lower than production and purchases in the first nine months of the year. The average cost for uranium has increased to $33.88 per pound compared to $33.05 per pound at December 31, 2018. As of September 30, 2019, we held an inventory of 7.9 million pounds of U₃O₈ equivalent in our uranium segment (excluding broken ore). Inventory varies from quarter to quarter depending on the timing of production, purchases and sales deliveries in the year.

Financial results by segment

Uranium

		THREE MONTHS ENDED SEPTEMBER 30									NINE MONTHS ENDED SEPTEMBER 30
HIGHLIGHTS		2019			2018			CHANGE			2019		2018		CHANGE
Production volume (million lbs)			1.4			1.5			(7	)%		6.3		6.8		(7	)%
Sales volume (million lbs)			6.1			10.6			(42	)%		17.5		22.5		(22	)%
Average spot price	($US/lb)		25.45			26.53			(4	)%		25.83		23.36		11	%
Average long-term price	($US/lb)		31.33			31.50			(1	)%		31.61		30.00		5	%
Average realized price	($US/lb)		30.94			30.18			3	%		32.05		35.05		(9	)%
	($Cdn/lb)		40.91			39.49			4	%		42.72		45.08		(5	)%
Average unit cost of sales (including D&A)	($Cdn/lb)		41.42			40.36			3	%		41.74		41.14		1	%
Revenue ($ millions)			248			418			(41	)%		748		1,014		(26	)%
Gross profit (loss) ($ millions)			(3	)		(9	)		(67	)%		17		89		(81	)%
Gross profit (loss) (%)			(1	)		(2	)		(50	)%		2		9		(78	)%

THIRD QUARTER

Production volumes this quarter were 7% lower compared to the third quarter of 2018. See Uranium 2019 Q3 updates starting on page 23 for more information.

Uranium revenues this quarter were down 41% compared to 2018 due to a decrease in sales volumes of 42% partially offset by an increase of 4% in the Canadian dollar average realized price. While the average spot price for uranium decreased by 4% compared to the same period in 2018, our average realized price was 4% higher primarily as a result of protection from floor prices in the market-related contracts delivered into.

Total cost of sales (including D&A) decreased by 41% ($251 million compared to $427 million in 2018) as a result of a 42% decrease in sales volume partially offset by a unit cost of sales that was 3% higher than the same period last year.

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

Equity earnings from investee, JV Inkai, were $1 million in the third quarter compared to $2 million in same period last year.

FIRST NINE MONTHS

Production volumes for the first nine months of the year were 7% lower than in the previous year. See Uranium 2019 Q3 updates starting on page 23 for more information.

20     CAMECO CORPORATION

Uranium revenues decreased 26% compared to the first nine months of 2018 due to a 22% decrease in sales volumes and a decrease of 5% in the Canadian dollar average realized price. While the average spot price for uranium increased by 11% compared to the same period in 2018, the average realized price for the first nine months was lower compared to the same period in 2018 due to a lower proportion of sales from higher priced fixed price contracts compared to 2018 partially offset by the weakening of the Canadian dollar compared to the prior year.

Total cost of sales (including D&A) decreased by 21% ($731 million compared to $926 million in 2018) mainly due to a 22% decrease in sales volume for the first nine months.

The net effect was a $72 million decrease in gross profit for the first nine months.

Equity earnings from investee, JV Inkai, were $25 million for the first nine months compared to $6 million for the same period last year.

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

	THREE MONTHS ENDED SEPTEMBER 30							NINE MONTHS ENDED SEPTEMBER 30
($CDN/LB)	2019		2018		CHANGE			2019		2018		CHANGE
Produced
Cash cost		20.38		19.96		2	%		15.05		15.45		(3	)%
Non-cash cost		20.99		14.99		40	%		16.33		16.20		1	%
Total production cost 1		41.37		34.95		18	%		31.38		31.65		(1	)%
Quantity produced (million lbs)1		1.4		1.5		(7	)%		6.3		6.8		(7	)%
Purchased
Cash cost1		31.92		35.10		(9	)%		35.58		33.74		5	%
Quantity purchased (million lbs)1		1.9		2.9		(34	)%		14.6		6.8		115	%
Totals
Produced and purchased costs		35.93		35.05		3	%		34.31		32.70		5	%
Quantities produced and purchased (million lbs)		3.3		4.4		(25	)%		20.9		13.6		54	%

¹  Our share of Inkai production was 0.9 million pounds for Q3, 2019 (2.4 million pounds for the first nine months of 2019). Due to equity accounting, 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. In the third quarter we purchased 0.7 million pounds at a purchase price per pound of $31.81 ($23.97 (US)) (2.1 million pounds in the first nine months of 2019 at $32.59 ($24.36 (US))).

The average cash cost of production was 2% higher for the quarter compared to 2018. While McArthur River and Key Lake are shut down, our cash cost of production is expected to be reflective of the estimated life-of-mine operating cost, between $15 and $16 per pound, of mining and milling our share of Cigar Lake mineral reserves. Unit non-cash cost in the quarter was impacted by the planned shutdown at Cigar Lake for maintenance and vacation. For the first nine months, the average cash cost of production was 3% lower than in in 2018.

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 third quarter, the average cash cost of purchased material was $31.92 (Cdn) per pound, or $24.15 (US) per pound in US dollar terms, compared to $26.81 (US) per pound in the third quarter of 2018. For the first nine months, the average cash cost of purchased material was $35.58 (Cdn), or $26.67 (US) per pound, compared to $26.17 (US) per pound in the same period in 2018. As a result, the average cash cost of purchased material in Canadian dollar terms decreased by 9% this quarter and increased by 5% for the nine months compared to the same periods last year.

2019 THIRD QUARTER REPORT     21

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 third quarter and the first nine months of 2019 and 2018.

Cash and total cost per pound reconciliation
	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2019			2018			2019			2018
Cost of product sold		192.6			341.6			598.9			729.7
Add / (subtract)
Royalties		(8.7	)		(14.7	)		(18.2	)		(36.5	)
Care and maintenance costs		(24.3	)		(53.2	)		(79.8	)		(129.7	)
Other selling costs		(1.6	)		(3.1	)		(6.1	)		(8.6	)
Change in inventories		(68.8	)		(138.9	)		119.5			(220.4	)
Cash operating costs (a)		89.2			131.7			614.3			334.5
Add / (subtract)
Depreciation and amortization		58.1			85.6			131.6			196.1
Care and maintenance costs		(9.7	)		(11.8	)		(32.9	)		(30.8	)
Change in inventories		(19.0	)		(51.3	)		4.2			(55.1	)
Total operating costs (b)		118.6			154.2			717.2			444.7
Uranium produced & purchased (million lbs) (c)		3.3			4.4			20.9			13.6
Cash costs per pound (a ÷ c)		27.03			29.93			29.39			24.60
Total costs per pound (b ÷ c)		35.93			35.05			34.31			32.70

Fuel services
(includes results for UF6, UO2, UO3 and fuel fabrication)
				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2019		2018		CHANGE			2019		2018		CHANGE
Production volume (million kgU)					1.7		0.8		113	%		9.3		7.0		33	%
Sales volume (million kgU)					1.8		2.1		(14	)%		8.0		6.6		21	%
Average realized price	($	Cdn/kgU	)		31.56		29.20		8	%		27.46		29.25		(6	)%
Average unit cost of sales (including D&A)	($	Cdn/kgU	)		29.29		27.12		8	%		21.96		24.11		(9	)%
Revenue ($ millions)					56		61		(8	)%		219		194		13	%
Gross profit ($ millions)					4		4		—			44		34		29	%
Gross profit (%)					7		7		—			20		18		11	%

THIRD QUARTER

Total revenue for the third quarter of 2019 decreased to $56 million from $61 million for the same period last year. This was primarily due to a 14% decrease in sales volumes partially offset by an 8% increase in average realized price compared to 2018. Average realized price increased mainly due to the mix of product sold.

22     CAMECO CORPORATION

The total cost of products and services sold (including D&A) decreased 7% ($52 million compared to $56 million in 2018) due to the 14% decrease in sales volume, partially offset by an 8% increase in the average unit cost of sales due to the mix of product sold.

Gross profit remained unchanged at $4 million.

FIRST NINE MONTHS

In the first nine months of the year, total revenue increased by 13% due to a 21% increase in sales volumes partially offset by a 6% decrease in realized price. The decrease in realized price was mainly the result of decreased prices on the sale of UF_6.

The total cost of products and services sold (including D&A) increased 9% ($175 million compared to $160 million in 2018) due to the 21% increase in sales volume, partially offset by a 9% decrease in the average unit cost of sales due to lower costs for UF₆ as a result of higher production.

The net effect was a $10 million increase in gross profit.

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 7% lower than the third quarter of 2018. See table below for more information. We continue to evaluate the optimal mix of production, inventory and purchases in order to retain the flexibility to deliver long-term value.

URANIUM PRODUCTION
	THREE MONTHS							NINE MONTHS
	ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
OUR SHARE (MILLION LBS)	2019		2018		CHANGE			2019		2018		CHANGE			2019 PLAN
McArthur River/Key Lake		—		—		—			—		0.1		(100	)%		—
Cigar Lake		1.4		1.5		(7	)%		6.3		6.6		(5	)%		9.0
US ISR		—		—		—			—		0.1		(100	)%		—
Total		1.4		1.5		(7	)%		6.3		6.8		(7	)%		9.0

¹  We expect total production from Inkai to be 8.3 million pounds in 2019 on a 100% basis. Due to equity accounting, our share of production is shown as a purchase. Please see below for more information.

Uranium 2019 Q3 updates

PRODUCTION UPDATE

McArthur River/Key Lake

There was no production in the third quarter as a result of the planned production suspension that began in February 2018 and continues for an indeterminate duration due to continued weakness in the uranium market.

Our share of the cash and non-cash costs to maintain both operations during the suspension is expected to range between $7 million and $9 million per month.

Cigar Lake

Total production from Cigar Lake was 7% lower in the third quarter compared to the same period last year. Production remains on track to meet our forecast for the year.

The collective agreement between Orano and unionized employees at the McClean Lake mill expired on May 31, 2019. On October 15, 2019, the parties applied for conciliation, after a tentative agreement was not ratified by unionized employees. The conciliation period will run for 60 days and, if an agreement is not reached, can be extended by mutual consent. If not extended, there is a 21 day cooling-off period prior to either party acquiring the legal right to undertake a work stoppage. Work continues under the terms of the expired collective agreement during conciliation. If Orano is unable to reach an agreement and there is a work stoppage, there is a risk to production plans for 2020.

2019 THIRD QUARTER REPORT     23

Inkai

Production on a 100% basis was 2.3 million pounds for the quarter and 6 million pounds for the first nine months of the year. Production is tracking higher than the comparable period in 2018 due to an increase in planned production in 2019. Due to the transition to equity accounting in 2018, our share of production will be shown as a purchase at a discount to the spot price and included in inventory at this value at the time of delivery. Our share of the profits earned by JV Inkai on the sale of its production will be included in “share of earnings from equity-accounted investee” on our consolidated statement of earnings.

TIER-TWO CURTAILED OPERATIONS

US ISR Operations

As a result of our 2016 curtailment decision, commercial production has ceased. As long as production is suspended, we expect ongoing cash and non-cash care and maintenance costs to range between $11 million (US) and $13 million (US) annually.

Rabbit Lake

Rabbit Lake continues in a safe state of care and maintenance. As a result, there was no production in the third quarter of 2019. While in standby, we continue to evaluate our options at Rabbit Lake in order to minimize care and maintenance costs. We expect ongoing care and maintenance costs to range between $30 million and $35 million annually.

Fuel services 2019 Q3 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 1.7 million kgU in the third quarter, 113% higher than the same period last year due to the timing of scheduled production and the planned increase in production for 2019.

Qualified persons

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

MCARTHUR RIVER/KEY LAKE   •  Greg Murdock, general manager, McArthur River/Key Lake, Cameco   CIGAR LAKE   •  Lloyd Rowson, general manager, Cigar Lake, Cameco INKAI   •  Scott Bishop, director, technical services, Cameco

Additional information

Critical accounting estimates

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

24     CAMECO CORPORATION

Controls and procedures

As of September 30, 2019, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of September 30, 2019, the CEO and CFO concluded that:

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

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

There have been no changes in our internal control over financial reporting during the quarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

2019 THIRD QUARTER REPORT     25