Exhibit 99.2

Management’s discussion and analysis

for the quarter ended September 30, 2018

5 THIRD QUARTER MARKET UPDATE

7 CONSOLIDATED FINANCIAL RESULTS

15 OUTLOOK FOR 2018

17 LIQUIDITY AND CAPITAL RESOURCES

20 FINANCIAL RESULTS BY SEGMENT

23 OUR OPERATIONS - THIRD QUARTER UPDATES

24 QUALIFIED PERSONS

24 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, 2018 (interim financial statements). The information is based on what we knew as of November 1, 2018 and updates our first quarter, second quarter and annual MD&A included in our 2017 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, 2017 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   •  our expectations about 2018 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 our estimate of the amount and timing of cash taxes and transfer pricing penalties   •  our 2018 consolidated outlook and the outlook for our uranium and fuel services segments for 2018   •  our expectations for our average realized uranium price for 2018 and the fourth quarter of 2018.   •  our expectations for 2019 uranium purchases •  our expectations for uranium deliveries for the remainder of 2018   •  our price sensitivity analysis for our uranium segment   •  our expectations regarding 2018 cash flow, and that existing cash balances and operating cash flows will meet our anticipated 2018 capital requirements   •  our expectation that our operating and investment activities for the remainder of 2018 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

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 are unsuccessful or have unanticipated consequences   •  our estimates of production, purchases, cash flow, costs, decommissioning, reclamation expenses, or our tax expense prove to be inaccurate   •  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   •  any difficulties in milling of Cigar Lake ore at McClean Lake mill, including water treatment   •  JV Inkai’s development, mining or production plans are delayed or do not succeed for any reason •  our Cigar Lake development, mining or production plans are delayed or do not succeed for any reason   •  we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our dispute with CRA   •  we are unsuccessful in our dispute with CRA and this results in significantly higher cash taxes, interest charges and penalties that could have a material adverse effect on us   •  we are unable to utilize letters of credit to the extent anticipated in our dispute with CRA   •  there are defects in, or challenges to, title to our properties   •  our mineral reserve and resource estimates are not reliable, or there are 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

2     CAMECO CORPORATION

•  the outcome of the investigation initiated by the US Department of Commerce (DOC) under Section 232 of the Trade Expansion Act, which may result in the US imposing tariffs or quotas on uranium imports   •  our expectations relating to care and maintenance costs prove to be inaccurate   •  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   •  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 •  our uranium suppliers fail to fulfil delivery commitments or our uranium purchasers fail to fulfil purchase commitments   •  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, 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 the 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, and purchase costs   •  the success of our plans and strategies   •  the agreement of our partners with our plans and strategies   •  our expectations regarding tax rates and payments, royalty rates, currency exchange rates and interest rates   •  our expectations about the outcome of dispute with CRA   •  the outcome of the investigation initiated by the DOC under Section 232 of the Trade Expansion Act does not result in the US imposing tariffs or quotas on uranium imports   •  we are able to utilize letters of credit to the extent anticipated in our dispute with CRA   •  our decommissioning and reclamation expenses •  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, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, or other development or operating risks

2018 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 an oversupplied market and the resulting weak market conditions 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, as always, our focus will continue to be on maximizing cash flow, while maintaining our investment-grade rating so we can self-manage risk, including being in a position to retire our 2019 debt maturity when it comes due.

You can read more about our strategy in our 2017 annual MD&A.

Strategy in action

In July 2018, we announced the extended shutdown of McArthur River/Key Lake, which resulted in the permanent layoff of approximately 520 site employees. As a result of the layoffs, we incurred $27 million in severance costs, which were expensed directly to cost of sales in the third quarter, see Financial results by segment – Uranium starting on page 20.

In addition, as a further cost cutting measure, we announced a reduction in the corporate office workforce of approximately 150 positions, resulting in severance costs of $13 million being expensed as part of our administrative costs for the quarter, see Corporate expenses – Administration on page 10.

In conjunction with the production suspension at McArthur River/Key Lake, we have drawn down our inventory by 17.2 million pounds since the beginning of the year, freeing up significant working capital. In addition, we have begun the necessary purchasing to meet our delivery commitments in 2018 and 2019. Since the end of July, we have secured 2.9 million pounds. For further information, see Outlook for 2018 on page 15.

Although we have been actively purchasing material, it is too early to determine if any trends are emerging. However, in general, the volume of material on offer has not been surprising, and appears to be decreasing. In terms of pricing, we have seen some offers with aggressive discounting and others with premium pricing, however, the pricing range appears to be tightening.

4     CAMECO CORPORATION

We have also been successful in securing long-term purchase arrangements for more than 7 million pounds of uranium concentrates for future delivery through 2028. The deliveries are heavily weighted to the years 2025 through 2028. As previously reported, we have long-term sales commitments to deliver about 150 million pounds of uranium concentrates. Securing this material today, provides us with added flexibility in making future sourcing decisions to fulfil our delivery commitments, without the need to build inventory. These arrangements also allow us to defer capital investment decisions and still meet future demand. Further, securing material today for future delivery allows us to lock in pounds at today’s low uranium prices, and with price escalation based on today’s low interest rates. Since we are not required to pay until we take delivery, we do not tie up cash on our balance sheet. In addition, we believe it removes these pounds from the spot market. Finally, these arrangements help mitigate risk. We believe we can advance delivery under these contracts if we are unable to find the pounds we need, or are unable to find the pounds we need at a reasonable price, to meet our delivery commitments while McArthur River/Key Lake production is suspended.

To the end of the third quarter, under the agreement with our partner, Orano, we have delivered 4.1 million pounds of uranium concentrates, out of a total of up to 5.4 million pounds. Orano is obligated to repay us, in kind, with uranium concentrates no later than December 31, 2023.

Third quarter market update

The uranium market is showing a marked improvement compared to a year ago and relative to the first half of the year. There have been significant production cuts, reductions in producer inventories, and an increase in demand for uranium in the spot market from producers and financial players. These actions have helped remove excess material from the spot market and have put pressure on uranium prices. The current spot price is up about 23% compared to the end of June, and is almost 40% higher compared to the end of October last year. Whereas, the long-term price is up about 9% compared to the end of June, and is about 6% higher compared to a year ago.

The market continues to try to digest the changing industry dynamics, including the developments discussed above and below.

In the US, which has the largest fleet of nuclear reactors in the world, the investigation launched by the DOC on July 18, 2018 under section 232 of the Trade Expansion Act continues. The investigation is to determine whether the quantity and circumstances of foreign uranium imports into the US threaten to impair national security. The investigation could take up to 270 days to complete. A report will then be provided to the President of the United States containing the DOC’s findings and recommendations, if warranted. The President then has up to 90 days to decide whether to concur with the DOC findings and what actions, if any, will be taken in response. The deadline for public comments was September 25. The Ad Hoc Utilities Group, an organization comprised of US nuclear power generators, issued a statement urging the federal government to avoid taking any action on levying tariffs or quotas.

On October, 22, 2018, Kazatomprom announced its intent to proceed with an initial public offering on the Astana International Exchange and the London Stock Exchange for securities representing up to 25% of its issued share capital. In its announcement, it states, “The Group has substantially changed its strategic approach to being a market-centric operator, as opposed to production-led operator.”

In Japan, the court injunction that caused the shutdown of Shikoku’s Ikata 3 reactor last year was successfully overturned, allowing that reactor to restart, which will bring the total number of reactors operating to nine. In China, five reactor units have been connected to the grid so far in 2018, and four additional units are projected to be connected to the grid by the end of the year. In Russia, unit 4 of the Rostov nuclear power plant entered commercial operation, four months ahead of schedule. In addition, Russia and India have agreed to work together on a project to build six nuclear units at a new site in India.

Despite the improvements in the uranium market during the quarter, we believe there is still a need for some caution. There has not been a return of long-term contracting in meaningful quantities, and prices are still not where they need to be to restart the significant idled production capacity that exists, let alone incentivize investment in value-adding growth opportunities. In fact, before the market turns to growth and the addition of new production capacity, the material held by financial players needs to be considered. Over time, as the financial interests meet investment targets, we believe some of the material currently sequestered in these funds will make its way back into the market, potentially temporarily over supplying the spot market and putting downward pressure on prices.

2018 THIRD QUARTER REPORT    5

Longer term, uranium demand is backed by steady reactor growth with 55 reactors under construction. While under construction, these reactors are not yet consuming uranium. Therefore, there has not yet been a corresponding increase in uranium consumption.

With each new reactor, comes the long-term need for a safe and reliable source of uranium. And while the availability of pounds in the spot market has helped to satisfy the needs of utilities in the near term, the continued risk of production curtailments, financially distressed producers, lack of investment in new primary supply, some mines approaching the end of their reserve life, declining secondary supplies, and growing uncovered requirements are expected to generate increasing pressure for fuel buyers to return to long-term contracting.

As annual supply adjusts, demand for uranium from producers and financial players increases, and uncovered requirements grow, we believe the pounds available in the spot market won’t be enough to satisfy long-term demand. The need to eventually contract for replacement volumes to fill these uncovered requirements will create opportunities for producers that can weather today’s low prices and provide a recovering market with uncommitted uranium from long-lived, tier-one assets.

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, reactor growth, pressure for long-term contracting and utilities’ uncovered requirements is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2.

Industry prices at quarter end

	SEP 30 2018		JUN 30 2018		MAR 31 2018		DEC 31 2017		SEP 30 2017		JUN 30 2017
Uranium ($US/lb U3O8)1
Average spot market price		27.50		22.65		21.05		23.75		20.33		20.15
Average long-term price		31.75		29.00		29.00		31.00		30.50		33.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		13.08		9.03		6.68		5.80		4.55		5.13
Europe		13.50		9.38		6.93		6.13		4.93		5.50
Average long-term price
North America		15.75		14.25		12.25		13.00		14.50		14.50
Europe		16.00		14.25		12.25		13.00		14.25		14.25

Note: the industry does not publish UO₂ prices.

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

On the spot market, where purchases call for delivery within one year, the volume reported by UxC for the third quarter of 2018 was approximately 27 million pounds, compared to 12 million pounds in the third quarter of 2017. Total volume in the spot market year-to-date is 70 million pounds, significantly higher than in previous years. At the end of the quarter, the average reported spot price was $27.50 (US) per pound, up $4.85 (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 (spot and long-term indicators) quoted near the time of delivery. The volume of long-term contracting reported by UxC for the first nine months of 2018 was about 58 million pounds compared to about 63 million pounds reported over the same period in 2017. Volumes continue to be less than the quantities consumed, and remain largely discretionary due to currently high inventory levels. The average reported long-term price at the end of the quarter was $31.75 (US) per pound, up $2.75 (US) from last quarter.

Spot UF₆ conversion prices increased in both the North American and European markets, as did long-term UF₆ conversion prices.

6     CAMECO CORPORATION

Shares and stock options outstanding   At October 31, 2018, we had:   •  395,792,732 common shares and one Class B share outstanding   •  8,972,563 stock options outstanding, with exercise prices ranging from $11.32 to $39.53 Dividend   For 2018, an annual dividend of $0.08 per common share has been declared, payable on December 14, 2018, to shareholders of record on November 30, 2018. In 2017, our board of directors reduced the planned dividend to $0.08 per common share to be paid annually. The decision to declare a 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.

Also of note:

During the quarter it was announced that we had entered into an agreement to sell our interest in the Wheeler River Joint Venture. The deal closed on October 26, 2018. We will report a gain on the transaction in our fourth quarter financial results.

Financial results

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

In this MD&A, our 2018 financial outlook and other disclosures relating to our contract portfolio are presented on a basis which excludes the agreement with TEPCO, which is under dispute. See our annual MD&A for more information.

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

Consolidated financial results

CONSOLIDATED HIGHLIGHTS	THREE MONTHS ENDED SEPTEMBER 30									NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS EXCEPT WHERE INDICATED)	2018			2017			CHANGE			2018		2017			CHANGE
Revenue		488			486			—			1,260		1,348			(7	)%
Gross profit (loss)		(6	)		51			>(100	%)		89		199			(55	)%
Net earnings (losses) attributable to equity holders		28			(124	)		>100	%		6		(143	)		>100	%
$ per common share (basic)		0.07			(0.31	)		>100	%		0.02		(0.36	)		>100	%
$ per common share (diluted)		0.07			(0.31	)		>100	%		0.02		(0.36	)		>100	%
Adjusted net earnings (losses) (non-IFRS, see page 8)		15			(50	)		>100	%		9		(122	)		>100	%
$ per common share (adjusted and diluted)		0.04			(0.13	)		>100	%		0.02		(0.31	)		>100	%
Cash provided by operations (after working capital changes)		278			154			81	%		610		276			>100	%

2018 THIRD QUARTER REPORT    7

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 8) in the third quarter and the first nine months of 2018, compared to the same periods in 2017.

		THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)		IFRS			ADJUSTED			IFRS			ADJUSTED
Net losses – 2017			(124	)		(50	)		(143	)		(122	)
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	Higher sales volume		8			8			13			13
	Higher (lower) realized prices ($US)		(30	)		(30	)		27			27
	Foreign exchange impact on realized prices		7			7			(22	)		(22	)
	Higher costs		(45	)		(45	)		(109	)		(109	)
	Change – uranium		(60	)		(60	)		(91	)		(91	)
Fuel services	Lower sales volume		—			—			(2	)		(2	)
	Higher (lower) realized prices ($Cdn)		4			4			(3	)		(3	)
	Higher costs		(3	)		(3	)		(3	)		(3	)
	Change – fuel services		1			1			(8	)		(8	)
Other changes
Lower administration expenditures			1			1			19			19
Lower impairment charges			111			—			111			—
Lower exploration expenditures			3			3			7			7
Change in reclamation provisions			(14	)		—			(65	)		—
Higher earnings from equity-accounted investee			2			2			6			6
Change in gains or losses on derivatives			—			16			(86	)		38
Change in foreign exchange gains or losses			15			15			46			46
Gain on restructuring of JV Inkai in 2018			—			—			49			—
Gain on customer contract restructuring in 2018			—			—			6			6
Reversal of tax provision related to CRA dispute			61			61			61			61
Change in income tax recovery or expense			23			17			76			29
Other			9			9			18			18
Net earnings – 2018			28			15			6			9

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

ADJUSTED NET EARNINGS (NON-IFRS MEASURE)

Adjusted net earnings are 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 are 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 are 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.

8     CAMECO CORPORATION

The following table reconciles adjusted net earnings with net earnings for the third quarter and first nine months of 2018 and compares it to the same periods in 2017.

	THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2018			2017			2018			2017
Net earnings (losses) attributable to equity holders		28			(124	)		6			(143	)
Adjustments
Adjustments on derivatives		(24	)		(40	)		18			(106	)
Impairment charges		—			111			—			111
Reclamation provision adjustments		5			(9	)		50			(15	)
Gain on restructuring of JV Inkai		—			—			(49	)		—
Income taxes on adjustments		6			12			(16	)		31
Adjusted net earnings (losses)		15			(50	)		9			(122	)

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

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2018							2017												2016
	Q3		Q2			Q1		Q4			Q3			Q2			Q1			Q4
Revenue		488		333			439		809			486			470			393			887
Net earnings (losses) attributable to equity holders		28		(76	)		55		(62	)		(124	)		(2	)		(18	)		(144	)
$ per common share (basic)		0.07		(0.19	)		0.14		(0.16	)		(0.31	)		(0.00	)		(0.05	)		(0.36	)
$ per common share (diluted)		0.07		(0.19	)		0.14		(0.16	)		(0.31	)		(0.00	)		(0.05	)		(0.36	)
Adjusted net earnings (losses) (non-IFRS, see page 8)		15		(28	)		23		181			(50	)		(44	)		(29	)		90
$ per common share (adjusted and diluted)		0.04		(0.07	)		0.06		0.46			(0.13	)		(0.11	)		(0.07	)		0.23
Cash provided by (used in) operations (after working capital changes)		278		57			275		320			154			130			(8	)		255

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 86% of consolidated revenues in the third quarter of 2018

• 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 8 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

2018 THIRD QUARTER REPORT    9

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

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2018									2017												2016
	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Net earnings (losses) attributable to equity holders		28			(76	)		55			(62	)		(124	)		(2	)		(18	)		(144	)
Adjustments
Adjustments on derivatives		(24	)		20			22			(2	)		(40	)		(44	)		(22	)		23
Impairment charges		—			—			—			247			111			—			—			238
Reclamation provision adjustments		5			44			1			15			(9	)		(12	)		6			(28	)
Gain on restructuring of JV Inkai		—			—			(49	)		—			—			—			—			—
Income taxes on adjustments		6			(16	)		(6	)		(17	)		12			14			5			1
Adjusted net earnings (losses) (non-IFRS, see page 8)		15			(28	)		23			181			(50	)		(44	)		(29	)		90

Corporate expenses

ADMINISTRATION

	THREE MONTHS ENDED SEPTEMBER 30							NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2018		2017		CHANGE			2018		2017		CHANGE
Direct administration		23		38		(39	)%		79		116		(32	)%
Severance costs		13		—		—			13		—		—
Stock-based compensation		3		2		50	%		14		9		56	%
Total administration		39		40		(3	)%		106		125		(15	)%

Direct administration costs were $15 million lower for the third quarter of 2018 compared to the same period last year, and $37 million lower for the first nine months due mainly to changes to our global marketing structure, lower costs related to our CRA litigation and our continued actions to reduce costs.

Stock-based compensation in the first nine months was higher due to the 22% increase in our share price compared to the same period in 2017.

EXPLORATION

In the third quarter, uranium exploration expenses were $5 million, a decrease of $3 million compared to the third quarter of 2017. Exploration expenses for the first nine months of the year decreased by $7 million compared to 2017, to $17 million, due to a planned reduction in expenditures.

INCOME TAXES

We recorded an income tax recovery of $87 million in the third quarter of 2018, compared to a recovery of $3 million in the third quarter of 2017.

On an adjusted basis, we recorded an income tax recovery of $93 million this quarter compared to a recovery of $15 million in the third quarter of 2017, primarily due to the reversal of the provision related to our CRA dispute in the amount of $61 million (see Tax Court of Canada decision starting on page 11 for more details). In addition, the change in reporting for JV Inkai also contributes to the difference. In 2018, we recorded losses of $121 million in Canada compared to losses of $31 million in 2017, while we recorded earnings of $43 million in foreign jurisdictions compared to losses of $34 million last year.

In the first nine months of 2018, we recorded an income tax recovery of $106 million compared to an expense of $31 million in 2017.

On an adjusted basis, we recorded an income tax recovery of $90 million for the first nine months compared to a recovery of $1 million in 2017 due primarily to the reversal of the provision related to our dispute with the CRA. Other factors include the change in the Saskatchewan corporate tax rate in 2017, as well as a change in the distribution of earnings among jurisdictions in 2018 which includes the change in accounting for JV Inkai. In 2018, we recorded losses of $157 million in Canada compared to losses of $27 million in 2017, while we recorded earnings of $76 million in foreign jurisdictions compared to losses of $95 million last year.

10     CAMECO CORPORATION

	THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2018			2017			2018			2017
Pre-tax adjusted earnings1
Canada		(121	)		(31	)		(157	)		(27	)
Foreign		43			(34	)		76			(95	)
Total pre-tax adjusted earnings		(78	)		(65	)		(81	)		(122	)
Adjusted income taxes1
Canada		(96	)		(9	)		(100	)		10
Foreign		3			(6	)		10			(11	)
Adjusted income tax recovery		(93	)		(15	)		(90	)		(1	)

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 8).

TRANSFER PRICING DISPUTE

Tax Court of Canada decision

On September 26, 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 a refund of 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 below.

In accordance with the ruling, we will be making an application to the Tax Court to recover substantial costs incurred over the course of this case. The actual cost award will be at the discretion of the Tax Court.

In addition, given the clear and decisive ruling in our favour, and the endorsement by the Tax Court of our transfer pricing methodology, we have reversed the provision on our balance sheet of $61 million.

Appeals process

On October 25, 2018, CRA filed a notice of appeal with the Federal Court of Appeal. In its notice of appeal, CRA is not appealing the Tax Court’s finding that sham was not present, but is appealing the Tax Court’s interpretation and application of the transfer pricing provisions in section 247 of the Income Tax Act. We will not have more specific information on how and why the CRA believes the Tax Court was wrong in its interpretation of the transfer pricing provisions until we are in receipt of the CRA’s complete written submissions.

We anticipate that it will take about two years to receive a decision from the Federal Court of Appeal. We believe there is nothing in the 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 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.

2018 THIRD QUARTER REPORT    11

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 CEL’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 2017 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. We expect to receive a refund of approximately $5.5 million plus interest of the amounts noted in the table below based on the ruling of the Tax Court. The timing of the refund may be delayed pending the outcome of the appeal.

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
Total		377		219		185		781		303		478

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, not much may change for some time. 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 reassessed the 2003 through 2012 tax years with. In that scenario, and including the $4.9 billion already reassessed, we would expect to receive notices of reassessment for a total of approximately $8.4 billion of additional income taxable in Canada for the years 2003 through 2017, which would result in a related tax expense of approximately $2.5 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2011. As a result, 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 $219 million in interest and instalment penalties.

12     CAMECO CORPORATION

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 estimated amounts summarized in the table below reflect actual amounts paid or secured and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2017, 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 2017.

$ MILLIONS	2003-2017		2018-2019		2020-2023		TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period
Cash payments		226		65 - 90		120 - 145		410 - 460
Secured by letters of credit		319		10 - 35		230 - 255		560 - 610
Total paid1		545		75 - 125		350 - 400		970 - 1070

¹ These amounts do not include interest and instalment penalties, which totaled approximately $219 million to September 30, 2018.

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 $781 million already paid or otherwise secured to date.

We have spent a total of about $57 million disputing the CRA reassessments and presenting our appeal in the Tax Court. This amount includes legal fees, expert witness fees, consultant fees, filing expenses, and other costs related to the case, from the time we started specifically tracking such costs in 2009, through 2018. The largest expenditures were incurred in 2016 and 2017 during trial preparation and Tax Court proceedings. Despite the appeal, in accordance with the ruling, we will be making an application to the Tax Court to recover substantial costs incurred over the course of this case. The actual cost award will be at the discretion of the Tax Court. 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.

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.

2018 THIRD QUARTER REPORT    13

Assumptions   •  CRA will reassess us for the years 2013 through 2017 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 Material risks that could cause actual results to differ materially   •  CRA reassesses us for years 2013 through 2017 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

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 16 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 8).

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.

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 2018 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 8.

For more information, see our 2017 annual MD&A.

14     CAMECO CORPORATION

At September 30, 2018:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.29 (Cdn), down from $1.00 (US) for $1.32 (Cdn) at June 30, 2018. The exchange rate averaged $1.00 (US) for $1.31 (Cdn) over the quarter.

• The mark-to-market position on all foreign exchange contracts was a $4 million loss compared to a $27 million loss at June 30, 2018.

For information on the impact of foreign exchange on our intercompany balances, see note 19 to the financial statements.

Outlook for 2018

Our outlook for 2018 reflects the expenditures necessary to help us achieve our strategy and is based on the assumptions found below the table, including a given uranium spot price, uranium term price, and foreign exchange rate. 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 on page 16, and Foreign exchange on page 14. Our 2018 financial outlook, and other disclosures relating to our contract portfolio, have been presented on a basis that excludes our contract with TEPCO, which is under dispute.

Our outlook for consolidated revenue; uranium purchase and delivery volumes, revenue, and average realized price; fuel services production; the expected loss on derivatives and tax recovery; and the expected contribution of our uranium and fuel services segments to gross profit has changed. We do not provide an outlook for the items in the table that are marked with a dash.

See 2018 Financial results by segment on page 20 for details.

2018 FINANCIAL OUTLOOK

	CONSOLIDATED		URANIUM			FUEL SERVICES
EXPECTED CONTRIBUTION TO GROSS PROFIT	100%		82%			18%
Production (owned and operated properties)		—		9.2 million lbs			10 to 11 million kgU
Purchases		—		11 to 12 million lbs	1		—
Sales/delivery volume2		—		35 to 36 million lbs	3		11 to 12 million kgU
Revenue 2	$	1,990-2,190 million	$	1,630-1,720 million	4	$	280-310 million
Average realized price3		—	$	47.80/lb	4		—
Average unit cost of sales (including D&A)		—	$	40.00-42.00/lb	5	$	21.60-22.60/kgU
Direct administration costs6	$	120-130 million		—			—
Exploration costs		—	$	20 million			—
Expected loss on derivatives - ANE basis4	$	10-20 million		—			—
Tax recovery - ANE basis7	$	80-90 million		—			—
Capital expenditures8	$	80 million		—			—

¹  Based on the volumes we currently have commitments to acquire under contract in 2018. This includes our JV Inkai purchases and the 2.9 million pounds of additional purchases we have secured since July. It does not include the 3 million to 4 million pounds of intersegment committed purchases we have, or the additional 1 million to 3 million pounds of uranium we expect we may still need to purchase to maintain our desired inventory level, taking into account the Orano loan.

²  Our 2018 outlook for sales volume and revenue does not include sales between our segments.

³  Based on the volumes we currently have commitments to deliver under contract in 2018.

⁴  Based on a uranium spot price of $27.35 (US) per pound (the Ux spot price as of September 24, 2018), a long-term price indicator of $31.50 (US) per pound (the Ux long-term indicator on September 24, 2018) and an exchange rate of $1.00 (US) for $1.30 (Cdn).

⁵  Based on the expected unit cost of sales for produced material and committed long-term purchases including our JV Inkai purchases. If we make discretionary purchases in 2018, then we expect the overall unit cost of sales may be affected.

⁶  Direct administration costs do not include stock-based compensation expenses.

⁷  Our outlook for the tax recovery 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 recovery may be affected.

⁸  Our share of JV Inkai capital spending for 2018 is not included as it is reflected on the basis of equity accounting for our minority ownership interest. JV Inkai cash flows are expected to cover capital expenditures in 2018.

2018 THIRD QUARTER REPORT    15

Due to additional demand we have captured in the market, our 2018 committed delivery volumes have increased to between 35 million and 36 million pounds (previously 34 million to 35 million pounds), and our 2019 sales commitments have increased to between 27 million and 29 million pounds (previously 25 million to 27 million pounds).

In 2018, the average realized price for our uranium segment is now expected to be $47.80 per pound (previously $46.10 per pound) as a result of the increased spot price and weakening of the Canadian dollar. Our Canadian dollar average realized price for the first nine months of 2018 was $45.08 per pound. To achieve the expected annual average realized price requires an average realized price greater than $50 per pound in the fourth quarter.

As a result of the changes to 2018 delivery volumes and the expected average realized price, we now expect revenue in our uranium segment to be $1,630 million to $1,720 million (previously $1,550 million to $1,640 million), resulting in consolidated revenue of $1,990 million to $2,190 million (previously $1,890 million to $2,140 million).

We now have committed purchase volumes of 11 million to 12 million pounds (previously 8 million to 9 million pounds) for 2018. As a result of the extended shutdown of McArthur River/Key Lake, we secured an additional 2.9 million pounds of purchase commitments. Our purchase commitments for 2019 are unchanged at 5 million to 6 million pounds.

With increased delivery commitments in 2018 and 2019, in addition to our committed purchases and the material we have already secured in the spot market, we expect we may still need to purchase an additional 1 million to 3 million pounds in 2018, and between 10 million and 12 million pounds (previously 9 million to 11 million pounds) in 2019, to meet our delivery commitments and maintain our desired inventory.

Fuel services production is now expected to be 10 million to 11 million kgU (previously 9 million to 10 million kgU) as a result of an expected increase in UF₆ production given the increase in demand that we have been seeing in the market.

As a result of the changes to the uranium average realized price and sales volumes, we now expect the contribution to gross profit to be 82% from the uranium segment and 18% from the fuel services segment (previously 81% and 19% respectively).

Including severance costs of $13 million, direct administration costs continue to be $120 million to $130 million as a result of further anticipated savings from the corporate office restructuring.

We now expect a loss on derivatives of $10 million to $20 million (previously $0 million to $10 million) due to the weakening of the Canadian dollar.

Our tax recovery on an adjusted net earnings basis is now expected to be $80 million to $90 million (previously $40 million to $50 million) primarily due to the reversal of the provision related to our CRA dispute, partially offset by changes in our outlook noted above.

We continue to expect cash from operations for 2018 to be between 20% and 30% higher than the $596 million reported in 2017. This estimate is based on the outlook provided in the table and the assumptions for uranium prices and foreign exchange rates used in and listed below the table. In addition to our purchase commitments of between 11 million and 12 million pounds, the estimate also includes expected purchases of 1 million to 3 million pounds.

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 2018 and, therefore expect to deliver between 12.5 million and 13.5 million pounds in the fourth quarter.

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

FOR 2018 ($ MILLIONS)		IMPACT ON:
	CHANGE	REVENUE			ANE			CASH FLOW
Uranium spot and term price1	$5(US)/lb increase		15			11			15
	$5(US)/lb decrease		(6	)		(4	)		(6	)
Value of Canadian dollar vs US dollar	One cent decrease in CAD		6			2			1
	One cent increase in CAD		(6	)		(2	)		(1	)

¹  Assuming change in both UxC spot price ($27.35 (US) per pound on September 24, 2018) and the UxC long-term price indicator ($31.50 (US) per pound on September 24, 2018)

16     CAMECO CORPORATION

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, 2018 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, 2018 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
2019		32		42		54		64		73		81		87
2020		30		41		55		65		74		82		88
2021		27		41		55		66		74		82		88
2022		28		41		55		66		74		81		87

The table illustrates the mix of long-term contracts in our September 30, 2018 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to September 30, 2018, and it excludes our contract under dispute with TEPCO.

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.

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 24 million pounds per year, with commitment levels of between 35 million and 36 million pounds in 2018 and 27 million to 29 million pounds in 2019. Commitments for 2020 through 2022 are lower.

• excludes sales between our segments

• excludes the contract under dispute with TEPCO

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 21% 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, 2018, we had cash and short-term investments of $1.1 billion, while our total debt amounted to $1.5 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 2018 through 2022, we have commitments to deliver an average of 24 million pounds per year, with commitments levels in 2018 of 35 million to 36 million pounds and 27 million to 29 million pounds in 2019. Commitments for 2020 through 2022 are lower.

2018 THIRD QUARTER REPORT    17

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. Due to the deliberate cost reduction measures implemented over the past five years, the reduction in our 2018 dividend, and the drawdown of inventory in 2018 as a result of the suspension of production at our McArthur River/Key Lake operation, we expect to generate significant cash flow in 2018. Therefore, we expect our cash balances and operating cash flows to meet our capital requirements during 2018, and help position us to self-manage risk.

We received a favorable 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. 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 timing and 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 with, even though we believe there is no basis for them to do so.

CASH FROM/USED IN OPERATIONS

Cash provided by operations was $124 million higher this quarter than in the third quarter of 2017 mainly due to a decrease in working capital requirements, which provided $130 million more in 2018 than in 2017. Not including working capital requirements, our operating cash flows this quarter were lower by $6 million.

Cash provided by operations was $334 million higher in the first nine months of 2018 than for the same period in 2017 due largely to a decrease in working capital requirements. This was a result of a larger decrease in inventory compared to in 2017 as well as changes in other working capital items. Working capital required $302 million less in 2018. In addition, while we had lower gross profits in our operating segments, income taxes paid decreased and cost reduction measures resulted in a lower use of cash. Not including working capital requirements, our operating cash flows in the first nine months were higher by $32 million.

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $3.0 billion at September 30, 2018, unchanged from June 30, 2018. At September 30, 2018, we had approximately $1.6 billion outstanding in financial assurances, up from $1.5 billion at December 31, 2017. At September 30, 2018, we had no short-term debt outstanding on our $1.25 billion unsecured revolving credit facility, unchanged from December 31, 2017. During the quarter, we extended the maturity date of the facility from November 1, 2021 to November 1, 2022.

Long-term contractual obligations

Since December 31, 2017, there have been no material changes to our long-term contractual obligations. Please see our 2017 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, 2018, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2018 to be constrained by them.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at September 30, 2018:

• purchase commitments

• financial assurances

• other arrangements

18     CAMECO CORPORATION

Purchase commitments

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, 2018. 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.

			2019 AND		2021 AND		2023 AND
SEPTEMBER 30 ($ MILLIONS)	2018		2020		2022		BEYOND		TOTAL
Purchase commitments1,2		269		337		173		286		1,065

¹  Denominated in US dollars and Japanese yen, as of September 30, 2018 converted from US dollars to Canadian dollars at the rate of $1.29 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, 2018, but does not include deliveries taken under contract since September 30, 2018.

As of September 30, 2018, we had commitments of about $1.1 billion for the following:

• approximately 25 million pounds of U₃O₈ equivalent from 2018 to 2028

• approximately 1 million kgU as UF₆ in conversion services in 2018 and 2019

• about 0.2 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. For more information on our purchasing activity, see Strategy in action starting on page 4.

Financial assurances

At September 30, 2018, our financial assurances totalled $1.6 billion, up from $1.5 billion at December 31, 2017.

Other arrangements

We continue to have factoring arrangements available to us to manage short-term cash flow fluctuations. At September 30, 2018 we did not have any balances outstanding under these arrangements. You can read more about these arrangements in our 2017 annual MD&A.

BALANCE SHEET

($ MILLIONS)	SEP 30, 2018		DEC 31, 2017		CHANGE
Cash, cash equivalents and short-term investments		1,095		592		85	%
Total debt		1,495		1,494		—
Inventory		545		950		(43	)%

Total cash, cash equivalents and short-term investments at September 30, 2018 were $1.1 billion, or 85% higher than at December 31, 2017, primarily due to cash from operations of $610 million, partially offset by capital expenditures of $45 million, 2017 dividend payments of $40 million, and interest payments of $49 million. Net debt at September 30, 2018 was $400 million.

Under the restructuring agreement for JV Inkai, the partners have agreed that JV Inkai will distribute excess cash, after capital expenditures, as priority repayment of our loan. We have an outstanding loan for Inkai’s work on block 3 prior to the restructuring. In the third quarter of 2018 we received distributions of $10 million (US), totaling $23 million (US) year-to-date, which were made as loan and interest repayments. As of September 30, 2018, the outstanding principal balance of the loan was $97 million (US).

Total product inventories decreased to $545 million. Inventories decreased as sales were higher than production and purchases in the first nine months of the year. In addition, the product provided to Orano contributed to the decrease. The average cost for uranium has increased to $31.81 per pound compared to $30.72 per pound at December 31, 2017. As of September 30, 2018, we held an inventory of 9.5 million pounds of U₃O₈ equivalent in our uranium segment (excluding broken ore).

2018 THIRD QUARTER REPORT    19

Financial results by segment

Uranium

				THREE MONTHS								NINE MONTHS
				ENDED SEPTEMBER 30								ENDED SEPTEMBER 30
HIGHLIGHTS				2018			2017		CHANGE			2018		2017		CHANGE
Production volume (million lbs)					1.5			3.1		(52	)%		6.8		16.9		(60	)%
Sales volume (million lbs)					10.6			9.2		15	%		22.5		21.0		7	%
Average spot price	($	US/lb	)		26.53			20.22		31	%		23.36		21.60		8	%
Average long-term price	($	US/lb	)		31.50			31.33		1	%		30.00		32.33		(7	)%
Average realized price	($	US/lb	)		30.18			32.42		(7	)%		35.05		34.15		3	%
	($	Cdn/lb	)		39.49			41.66		(5	)%		45.08		44.86		—
Average unit cost of sales (including D&A)	($	Cdn/lb	)		40.36			36.12		12	%		41.14		36.32		13	%
Revenue ($ millions)					418			385		9	%		1,014		943		8	%
Gross profit (loss) ($ millions)					(9	)		51		(118	)%		89		179		(50	)%
Gross profit (loss) (%)					(2	)		13		(115	)%		9		19		(53	)%

THIRD QUARTER

Production volumes this quarter were 52% lower compared to the third quarter of 2017, mainly due to a lack of production from the suspended McArthur River/Key Lake operations and a change in reporting for JV Inkai. See Uranium 2018 Q3 updates starting on page 23 for more information.

Uranium revenues this quarter were up 9% compared to 2017 due to an increase in sales volumes of 15% partially offset by a decrease of 5% in the Canadian dollar average realized price. While the average spot price for uranium increased by 31% compared to the same period in 2017, our average realized price decreased due to the mix of market-related and fixed price contracts.

Total cost of sales (including D&A) increased by 28% ($427 million compared to $334 million in 2017) as a result of unit cost of sales that was 12% higher than the same period last year and a 15% increase in sales volume. The increase in the unit cost of sales was due mainly to increased costs associated with the temporary suspension of production at our McArthur River/Key Lake operation. The cost of our purchases have decreased from the third quarter in 2017.

The net effect was a $60 million decrease in gross profit for the quarter.

Equity earnings from investee, JV Inkai, were $2 million in the third quarter.

FIRST NINE MONTHS

Production volumes for the first nine months of the year were 60% lower than in the previous year mainly due to planned lower production from McArthur River/Key Lake as the operation moved into care and maintenance in the first quarter and a change in reporting for JV Inkai. See Uranium 2018 Q3 updates starting on page 23 for more information.

Uranium revenues increased 8% compared to the first nine months of 2017 due to a 7% increase in sales volumes.

Total cost of sales (including D&A) increased by 21% ($926 million compared to $764 million in 2017) mainly due to a 13% increase in the unit cost of sales and a 7% increase in sales volume for the first nine months. The increase in the unit cost of sales compared to last year was mainly due to increased costs associated with the suspension of production at our McArthur River/Key Lake and US ISR operations. The cost of our purchases have decreased from the same period in 2017.

The net effect was a $90 million decrease in gross profit for the first nine months.

Equity earnings from investee, JV Inkai, were $6 million for the first nine months.

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.

20     CAMECO CORPORATION

	THREE MONTHS							NINE MONTHS
	ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
($CDN/LB)	2018		2017		CHANGE			2018		2017		CHANGE
Produced
Cash cost		19.96		24.40		(18	)%		15.45		15.90		(3	)%
Non-cash cost		14.99		16.33		(8	)%		16.20		11.53		41	%
Total production cost 1		34.95		40.73		(14	)%		31.65		27.43		15	%
Quantity produced (million lbs)1		1.5		3.1		(52	)%		6.8		16.9		(60	)%
Purchased
Cash cost1		35.10		36.83		(5	)%		33.74		39.75		(15	)%
Quantity purchased (million lbs)1		2.9		0.5		480	%		6.8		3.0		127	%
Totals
Produced and purchased costs		35.05		40.19		(13	)%		32.70		29.29		12	%
Quantities produced and purchased (million lbs)		4.4		3.6		22	%		13.6		19.9		(32	)%

¹  Our share of Inkai production was 0.6 million pounds for Q3, 2018 (1.9 million pounds for the first nine months of 2018). Due to the transition 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 0.5 million pounds at a purchase price per pound of $28.55 ($21.75 (US)) (1.4 million pounds in the first nine months of 2018 at $27.90 ($21.57 (US))).

The change to equity accounting for our interest in JV Inkai removes the impact of our share of Inkai’s low cash cost of production from the mix. Those pounds now are reflected as a purchase at a discount to the spot price in this table. The benefit of the estimated $9.55 per pound life-of-mine operating cost is expected to be reflected in the line item on our statement of earnings called “share of earnings from equity-accounted investee”.

The average cash cost of production was 18% lower for the quarter compared to 2017. While McArthur River and Key Lake are shut down, our cash cost of production is expected to be reflective of the estimated $15.42 per pound life-of-mine operating cost of mining and milling our share of Cigar Lake pounds. 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 2017 due to McArthur River/Key Lake and our US ISR operations moving into care and maintenance.

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 $35.10 (Cdn) per pound, or $26.81 (US) per pound in US dollar terms, compared to $29.20 (US) per pound in the third quarter of 2017. For the first nine months, the average cash cost of purchased material was $33.74 (Cdn), or $26.17 (US) per pound, compared to $30.19 (US) per pound in the same period in 2017. As a result, the average cash cost of purchased material in Canadian dollar terms decreased by 5% this quarter and by 15% for the nine months compared to the same periods last year.

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

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

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the third quarter and the first nine months of 2018 and 2017.

2018 THIRD QUARTER REPORT    21

Cash and total cost per pound reconciliation

	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2018			2017			2018			2017
Cost of product sold		341.6			250.5			729.7			591.4
Add / (subtract)
Royalties		(14.7	)		(23.0	)		(36.5	)		(46.2	)
Care and maintenance costs		(53.2	)		(8.0	)		(129.7	)		(28.9	)
Other selling costs		(3.1	)		(2.8	)		(8.6	)		(5.7	)
Change in inventories		(138.9	)		(122.6	)		(220.4	)		(122.6	)
Cash operating costs (a)		131.7			94.1			334.5			388.0
Add / (subtract)
Depreciation and amortization		73.8			83.2			165.3			172.2
Care and maintenance costs		11.8			—			30.8			—
Change in inventories		(63.1	)		(32.6	)		(85.9	)		22.6
Total operating costs (b)		154.2			144.7			444.7			582.8
Uranium produced & purchased (million lbs) (c)		4.4			3.6			13.6			19.9
Cash costs per pound (a ÷ c)		29.93			26.14			24.60			19.50
Total costs per pound (b ÷ c)		35.05			40.19			32.70			29.29

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2018		2017		CHANGE			2018		2017		CHANGE
Production volume (million kgU)					0.8		0.6		33	%		7.0		5.4		30	%
Sales volume (million kgU)					2.1		2.5		(16	)%		6.6		6.9		(4	)%
Average realized price	($	Cdn/kgU	)		29.20		27.27		7	%		29.25		29.94		(2	)%
Average unit cost of sales (including D&A)	($	Cdn/kgU	)		27.12		25.84		5	%		24.11		23.83		1	%
Revenue ($ millions)					61		69		(12	)%		194		206		(6	)%
Gross profit ($ millions)					4		4		—			34		42		(19	)%
Gross profit (%)					7		6		17	%		18		20		(10	)%

THIRD QUARTER

Total revenue for the third quarter of 2018 decreased to $61 million from $69 million for the same period last year. This was primarily due to a 16% decrease in sales volumes partially offset by a 7% increase in average realized price compared to 2017. Average realized price increased mainly due to the mix of product sold, as well as an increase in the average realized price for UF₆ and UO₂.

The total cost of products and services sold (including D&A) decreased 14% ($56 million compared to $65 million in 2017) due to the 16% decrease in sales volume, partially offset by a 5% increase in the average unit cost of sales due to higher costs for UF₆.

Gross profit remained unchanged at $4 million.

FIRST NINE MONTHS

In the first nine months of the year, total revenue decreased by 6% due to a 4% decrease in sales volumes and a 2% decrease in realized price. The decrease in realized price was the result of decreased prices on the sale of UF₆.

The total cost of products and services sold (including D&A) decreased 2% ($160 million compared to $164 million in 2017) due to the 4% decrease in sales volume, partially offset by a 1% increase in the average unit cost of sales due to higher costs for UF₆.

22     CAMECO CORPORATION

The net effect was an $8 million decrease in gross profit.

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 52% lower than the third quarter of 2017 due to the production suspension at McArthur River and Key Lake and a change in reporting for JV Inkai. 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)	2018		2017		CHANGE			2018		2017		CHANGE			2018 PLAN
McArthur River/Key Lake		—		0.6		(100	)%		0.1		7.8		(99	)%		0.1
Cigar Lake		1.5		1.7		(12	)%		6.6		6.5		2	%		9.0
Inkai1		—		0.8		(100	)%		—		2.3		(100	)%		—
US ISR		—		—		—			0.1		0.3		(67	)%		0.1
Total		1.5		3.1		(52	)%		6.8		16.9		(60	)%		9.2

¹  We expect total production from Inkai to be 6.9 million pounds in 2018 on a 100% basis. Due to the transition to equity accounting, our share of production will be shown as a purchase. Please see below for more information.

Uranium 2018 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 and continues for an indeterminate duration, as announced on July 25, 2018, due to continued weakness in the uranium market.

The production suspension resulted in the permanent layoff of approximately 520 employees, including those currently on temporary layoff. A reduced workforce of approximately 200 employees remains at the operations to keep the facilities in a state of safe care and maintenance.

We incurred approximately $27 million in severance costs in the third quarter as a result of the permanent layoffs. 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 (previously between $5 million and $6 million because non-cash costs were not included) once the permanent layoffs take effect.

Cigar Lake

Total packaged production from Cigar Lake was 12% lower in the third quarter and 2% higher for the first nine months compared to the same periods last year. Packaged production was lower in the third quarter due primarily to the planned summer shutdown for maintenance and vacation. The shutdown went as planned with the mine and mill returning to full production at the end of August. Production remains on track to meet forecast for the year.

Inkai

Production on a 100% basis was 1.5 million pounds for the quarter and 4.8 million pounds for the first nine months of the year. Production is tracking higher than the comparable period in 2017 due to increased planned production in 2018 above 2017 production levels. Due to the transition to equity accounting, 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.

2018 THIRD QUARTER REPORT    23

TIER-TWO CURTAILED OPERATIONS

US ISR Operations

As a result of the decision to curtail production and defer all wellfield development at our US operations, there was no production in the third quarter. We have now effectively ceased production, which is expected to result in production of about 100,000 pounds for the year. 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 for the first few years (previously $18 million (US) and $22 million (US) which reflected care and maintenance costs prior to full cessation of production).

On September 30, the Nuclear Regulatory Commission approved a 10-year renewal of the operating licence for Smith Ranch-Highland. The licence is valid until September 30, 2028.

Rabbit Lake

The Rabbit Lake operation is in a safe state of care and maintenance; there was no production in the third quarter of 2018. While in standby, we continue to evaluate our options at Rabbit Lake in order to minimize care and maintenance costs. We now expect ongoing care and maintenance costs to range between $30 million and $35 million annually (previously $35 million to $40 million) due to actions being taken to minimize costs.

Fuel services 2018 Q3 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 0.8 million kgU in the third quarter, 33% higher than the same period last year due to the timing of scheduled production.

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, manager, operations, McArthur River, Cameco   CIGAR LAKE   •  Jeremy Breker, general manager, Rabbit Lake/Cigar Lake, Cameco INKAI   •  Dr. Darryl Clark, consultant geologist

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.

Controls and procedures

As of September 30, 2018, 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.

24     CAMECO CORPORATION

Based upon that evaluation and as of September 30, 2018, 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 has been no change in our internal control over financial reporting during the quarter ended September 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

2018 THIRD QUARTER REPORT    25