Exhibit 99.2

Management’s discussion and analysis

for the quarter ended June 30, 2018

5 SECOND QUARTER MARKET UPDATE

7 CONSOLIDATED FINANCIAL RESULTS

14 OUTLOOK FOR 2018

16 LIQUIDITY AND CAPITAL RESOURCES

19 FINANCIAL RESULTS BY SEGMENT

22 OUR OPERATIONS - SECOND QUARTER UPDATES

23 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 June 30, 2018 (interim financial statements). The information is based on what we knew as of July 25, 2018 and updates our first 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 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 Second 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 expected 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 uranium deliveries for the remainder of 2018

• the discussion under the heading Additional outlook tied to the extended shutdown of McArthur River/Key Lake

• 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

• our plans regarding consideration of the payment of a dividend

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

• 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 or with Tokyo Electric Power Company Holdings, Inc. (TEPCO)

• we are unsuccessful in our dispute with CRA and this results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision

• 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

2    CAMECO CORPORATION

• any difficulties in milling of Cigar Lake ore at McClean Lake mill, including water treatment or resuming production after the extended Cigar Lake shutdown scheduled for the third quarter

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

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

• we are affected by 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

• government laws, regulations, policies, or decisions that adversely affect us, including tax and trade laws

• the outcome of the investigation initiated by the US Department of Commerce under Section 232 of the Trade Expansion Act

• 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 disputes with CRA and with TEPCO

• 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, including the resumption of production after the end of the extended shutdown scheduled for the third quarter

• 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 SECOND 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.

In light of today’s oversupplied market and the lingering uncertainty as to how long the weak market conditions will persist, we are focused on preserving the value of our lowest cost assets, on maintaining a strong balance sheet, on protecting and extending the value of our contract portfolio and on efficiently managing the company in a low price environment. We have undertaken a number of deliberate and disciplined actions. We have reduced supply, resisted selling into a weak spot market, restructured our global marketing organization, streamlined our operations and reduced costs.

We believe this approach provides us with the opportunity to meet rising demand with increased production from our best margin assets, and helps to mitigate risk during a prolonged period of uncertainty.

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

Strategy in action

In response to market conditions, we have made the necessary decision to extend the suspension of production at our McArthur River/Key Lake operation, removing 18 million pounds of uranium per year from the market for an indeterminate duration. Our joint venture partner, Orano, has agreed to extend the suspension.

This action will result in the permanent layoff of approximately 550 site employees, including those currently on temporary layoff since January of this year.

A reduced workforce of approximately 200 employees will remain at the McArthur River and Key Lake sites to keep the facilities in a state of safe care and maintenance. We expect our share of the costs to maintain both sites to range between $5 million and $6 million per month once all the permanent layoffs take effect.

In addition, to further decrease costs, the workforce at our corporate office will be reduced by approximately 150 positions including employees and vacancies.

As a result of the permanent layoffs at site and the associated workforce reduction at our corporate office, we will incur about $40 million to $45 million in severance costs in the third quarter. For more information on how these costs will impact 2018, see Outlook for 2018 on page 14.

We have also agreed to extend repayment under the agreement to provide our partner, Orano, with up to 5.4 million pounds of uranium concentrates. Orano is now obligated to repay us, in kind, with uranium concentrates no later than December 31, 2023 (previously December 31, 2021).

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. Until we can commit our tier-one pounds under long-term contracts that provide an acceptable rate of return on these assets for our owners, we do not plan to restart McArthur River and Key Lake.

• 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.

4    CAMECO CORPORATION

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

Ultimately, we believe continuing to use this framework 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.

Second quarter market update

There were several significant announcements in the uranium market during the second quarter and to-date in July. On the supply side, Paladin announced that it was putting its Langer Heinrich mine on care and maintenance, Kazatomprom announced that it would reduce 2018 planned production from about 60 million pounds to about 56 million pounds, and we announced our decision to extend the suspension of production at McArthur River/Key Lake.

In addition, there has been increased financial interest in physical uranium, including the initial public offering for a new uranium fund called Yellow Cake. The fund has purchased about 8 million pounds of uranium from Kazatomprom, sequestering it in an investment vehicle, with the option to purchase up to $100 million in additional material annually over the next nine years.

On the demand side, in Japan, there were two additional reactor restarts, bringing the total restarted to nine, including one that is currently not operating. The Japanese government also approved a new basic energy plan confirming that nuclear power will play a significant role in its energy strategy. In China, the first AP1000 and EPR reactors were connected to the grid, and fuel loading was approved and has begun on a second AP1000 nuclear power plant. We believe the startup and regulatory approval of this new generation of reactors will clear the path for additional new build projects in that country. In South Korea, the government announced plans for the early retirement of one of its nuclear reactors and cancelled plans for four new units. In the US, a petition was filed under Section 202 of the Federal Power Act. This petition could result in assistance for struggling nuclear and coal plants as a matter of national security. And, the US Department of Commerce initiated an investigation under section 232 of the Trade Expansion Act to determine whether the quantity and circumstances of foreign uranium imports into the US threaten to impair national security.

Despite an approximately 8% increase in the uranium spot price during the quarter, there has not been a lot of activity in the long-term market. The market continues to try to digest the changing market dynamics, including the developments discussed above and the implications of the review of the Russian Suspension Agreement, which imposes annual quotas on imports of Russian uranium into the US, and expires at the end of 2020.

Longer term, uranium demand is backed by steady reactor growth with 57 reactors under construction. However, 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 and uncovered requirements grow, we believe the pounds available in the spot market won’t be enough to satisfy the 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, future global uranium supply, 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.

2018 SECOND QUARTER REPORT    5

Industry prices at quarter end

	JUN 30		MAR 31		DEC 31		SEP 30		JUN 30		MAR 31
	2018		2018		2017		2017		2017		2017
Uranium ($US/lb U3O8)1
Average spot market price		22.65		21.05		23.75		20.33		20.15		23.88
Average long-term price		29.00		29.00		31.00		30.50		33.00		33.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		9.03		6.68		5.80		4.55		5.13		5.93
Europe		9.38		6.93		6.13		4.93		5.50		6.45
Average long-term price
North America		14.25		12.25		13.00		14.50		14.50		13.50
Europe		14.25		12.25		13.00		14.25		14.25		14.00

Note: the industry does not publish UO₂ prices.

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

On the spot market, where purchases call for delivery within one year, the volume reported by Ux Consulting (UxC) for the second quarter of 2018 was approximately 20 million pounds, compared to 12 million pounds in the second quarter of 2017. Total volume in the spot market year-to-date is 43 million pounds, significantly higher than in previous years. This volume includes the 8 million pounds purchased by the newly established uranium fund, Yellow Cake. At the end of the quarter, the average reported spot price was $22.65 (US) per pound, up $1.60 (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 six months of 2018 was about 16 million pounds compared to about 54 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 $29.00 (US) per pound, unchanged from last quarter.

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

Shares and stock options outstanding

At July 25, 2018, we had:

• 395,792,732 common shares and one Class B share outstanding

• 8,909,524 stock options outstanding, with exercise prices ranging from $11.32 to $39.53

Dividend

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 will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings. Accordingly, the dividend will be considered at the time of the third quarter earnings release.

6    CAMECO CORPORATION

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

	THREE MONTHS									SIX MONTHS
CONSOLIDATED HIGHLIGHTS	ENDED JUNE 30									ENDED JUNE 30
($ MILLIONS EXCEPT WHERE INDICATED)	2018			2017			CHANGE			2018			2017			CHANGE
Revenue		333			470			(29	)%		773			862			(10	)%
Gross profit		26			93			(72	)%		94			148			(36	)%
Net losses attributable to equity holders		(76	)		(2	)		>(100	%)		(22	)		(20	)		(10	)%
$ per common share (basic)		(0.19	)		(0.00	)		>(100	%)		(0.05	)		(0.05	)		—
$ per common share (diluted)		(0.19	)		(0.00	)		>(100	%)		(0.05	)		(0.05	)		—
Adjusted net losses (non-IFRS, see page 8)		(28	)		(44	)		36	%		(6	)		(73	)		92	%
$ per common share (adjusted and diluted)		(0.07	)		(0.11	)		36	%		(0.01	)		(0.18	)		94	%
Cash provided by operations (after working capital changes)		57			130			(56	)%		332			122			>100	%

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 second quarter and the first six months of 2018, compared to the same periods in 2017.

		THREE MONTHS						SIX MONTHS
		ENDED JUNE 30						ENDED JUNE 30
($ MILLIONS)		IFRS			ADJUSTED			IFRS			ADJUSTED
Net losses – 2017			(2	)		(44	)		(20	)		(73	)
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 (lower) sales volume		(11	)		(11	)		1			1
	Higher (lower) realized prices ($US)		(11	)		(11	)		62			62
	Foreign exchange impact on realized prices		(11	)		(11	)		(30	)		(30	)
	Higher costs		(31	)		(31	)		(64	)		(64	)
	Change – uranium		(64	)		(64	)		(31	)		(31	)
Fuel services	Higher (lower) sales volume		(6	)		(6	)		1			1
	Higher (lower) realized prices ($Cdn)		5			5			(9	)		(9	)
	Higher costs		(6	)		(6	)		(1	)		(1	)
	Change – fuel services		(7	)		(7	)		(9	)		(9	)
Other changes
Lower administration expenditures			13			13			18			18
Lower exploration expenditures			2			2			3			3
Change in reclamation provisions			(56	)		—			(51	)		—
Higher earnings from equity-accounted investee			3			3			4			4
Change in gains or losses on derivatives			(48	)		16			(87	)		21
Change in foreign exchange gains or losses			22			22			31			31
Gain on restructuring of JV Inkai			—			—			49			—
Gain on customer contract restructuring in 2018			—			—			6			6
Change in income tax recovery or expense			41			11			52			11
Other			20			20			13			13
Net losses – 2018			(76	)		(28	)		(22	)		(6	)

See Financial results by segment beginning on page 19 for more detailed discussion.    

2018 SECOND QUARTER REPORT    7

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 second quarter and first six months of 2018 and compares it to the same periods in 2017.

	THREE MONTHS						SIX MONTHS
	ENDED JUNE 30						ENDED JUNE 30
($ MILLIONS)	2018			2017			2018			2017
Net losses attributable to equity holders		(76	)		(2	)		(22	)		(20	)
Adjustments
Adjustments on derivatives		20			(44	)		42			(66	)
Reclamation provision adjustments		44			(12	)		45			(6	)
Gain on restructuring of JV Inkai		—			—			(49	)		—
Income taxes on adjustments		(16	)		14			(22	)		19
Adjusted net losses		(28	)		(44	)		(6	)		(73	)

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)”. In the second quarter, our estimate for Rabbit Lake decommissioning costs increased due to a scheduled revision to its preliminary decommissioning plan that was submitted to the relevant regulatory authorities. See note 9 of our interim financial statements for more information. This amount has been excluded from our adjusted net earnings measure.

Quarterly trends

HIGHLIGHTS	2018					2017												2016
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q2			Q1		Q4			Q3			Q2			Q1			Q4			Q3
Revenue		333			439		809			486			470			393			887			670
Net earnings (losses) attributable to equity holders		(76	)		55		(62	)		(124	)		(2	)		(18	)		(144	)		142
$ per common share (basic)		(0.19	)		0.14		(0.16	)		(0.31	)		(0.00	)		(0.05	)		(0.36	)		0.36
$ per common share (diluted)		(0.19	)		0.14		(0.16	)		(0.31	)		(0.00	)		(0.05	)		(0.36	)		0.36
Adjusted net earnings (losses) (non-IFRS, see page 8)		(28	)		23		181			(50	)		(44	)		(29	)		90			118
$ per common share (adjusted and diluted)		(0.07	)		0.06		0.46			(0.13	)		(0.11	)		(0.07	)		0.23			0.30
Cash provided by (used in) operations (after working capital changes)		57			275		320			154			130			(8	)		255			385

8    CAMECO CORPORATION

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 71% of consolidated revenues in the second 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

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

HIGHLIGHTS	2018						2017												2016
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Net earnings (losses) attributable to equity holders		(76	)		55			(62	)		(124	)		(2	)		(18	)		(144	)		142
Adjustments
Adjustments on derivatives		20			22			(2	)		(40	)		(44	)		(22	)		23			(27	)
Impairment charges		—			—			247			111			—			—			238			—
Reclamation provision adjustments		44			1			15			(9	)		(12	)		6			(28	)		(6	)
Gain on restructuring of JV Inkai		—			(49	)		—			—			—			—			—			—
Income taxes on adjustments		(16	)		(6	)		(17	)		12			14			5			1			9
Adjusted net earnings (losses) (non-IFRS, see page 8)		(28	)		23			181			(50	)		(44	)		(29	)		90			118

Corporate expenses

ADMINISTRATION

	THREE MONTHS							SIX MONTHS
	ENDED JUNE 30							ENDED JUNE 30
($ MILLIONS)	2018		2017		CHANGE			2018		2017		CHANGE
Direct administration		26		43		(40	)%		55		77		(29	)%
Stock-based compensation		5		1		400	%		11		7		57	%
Total administration		31		44		(30	)%		66		84		(21	)%

Direct administration costs were $17 million lower for the second quarter of 2018 compared to the same period last year, and $22 million lower for the first six 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 six months was higher due to the 27% increase in our share price compared to the same period in 2017.

EXPLORATION

In the second quarter, uranium exploration expenses were $4 million, a decrease of $2 million compared to the second quarter of 2017. Exploration expenses for the first six months of the year decreased by $3 million compared to 2017, to $13 million, due to a planned reduction in expenditures.

2018 SECOND QUARTER REPORT    9

INCOME TAXES

We recorded an income tax recovery of $12 million in the second quarter of 2018, compared to an expense of $29 million in the second quarter of 2017.

On an adjusted basis, we recorded an income tax expense of $4 million this quarter compared to an expense of $15 million in the second quarter of 2017, primarily due to a change in the Saskatchewan corporate tax rate in 2017 which caused a decrease in our deferred tax asset, resulting in an expense of $24 million. In addition, the change in reporting for JV Inkai also contributes to the difference. In 2018, we recorded earnings of $3 million in Canada compared to earnings of $4 million in 2017, while we recorded losses of $27 million in foreign jurisdictions compared to losses of $33 million last year.

In the first six months of 2018, we recorded an income tax recovery of $19 million compared to an expense of $33 million in 2017.

On an adjusted basis, we recorded an income tax expense of $3 million for the first six months compared to an expense of $14 million in 2017 due to 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 $38 million in Canada compared to earnings of $3 million in 2017, while we recorded earnings of $36 million in foreign jurisdictions compared to losses of $62 million last year.

	THREE MONTHS						SIX MONTHS
	ENDED JUNE 30						ENDED JUNE 30
($ MILLIONS)	2018			2017			2018			2017
Pre-tax adjusted earnings1
Canada		3			4			(38	)		3
Foreign		(27	)		(33	)		36			(62	)
Total pre-tax adjusted earnings		(24	)		(29	)		(2	)		(59	)
Adjusted income taxes1
Canada		2			20			(4	)		19
Foreign		2			(5	)		7			(5	)
Adjusted income tax expense		4			15			3			14

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

We have been reporting on our transfer pricing dispute with CRA since 2008, when it originated.

Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing dispute we have.

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of cases like ours. However, tax authorities generally test two things:

• the governance (structure) of the corporate entities involved in the transactions

• the price at which goods and services are sold by one member of a corporate group to another

We have a global customer base and we established a marketing and trading structure involving foreign subsidiaries, including Cameco Europe Limited (CEL), which entered into various intercompany arrangements, including purchase and sale agreements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s-length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts entered into between arm’s-length parties at that time.

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 expect that CRA will seek to impose a transfer pricing penalty for 2012. Taxes of approximately $321 million for the 2003 – 2017 years have already been paid to date in a jurisdiction outside Canada, and we are considering 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 expected income adjustments under our CRA tax dispute are represented by the amounts claimed by CRA and are described below.

10    CAMECO CORPORATION

CRA dispute

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 received notices of reassessment for our 2003 through 2012 tax returns. We have recorded a cumulative tax provision of $61 million, where an argument could be made that, based on our methodology, our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through June 30, 2018. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

For the years 2003 through 2012, CRA issued notices of reassessment for approximately $4.9 billion of additional income for

Canadian tax purposes, which would result in a related tax expense of about $1.2 billion. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2011 in the amount of $371 million. 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 remitted a net amount of $303 million in cash. In addition, we have provided $478 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed after 2014. The amounts paid or secured are shown in the table below.

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

Using the methodology we believe CRA will continue to apply, and including the $4.9 billion already reassessed, we 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 for these years would be between $1.95 billion and $2.15 billion. In addition, we estimate there would be interest and instalment penalties applied 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 secured $562 million in cash taxes and transfer pricing penalties and $219 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 decided to disallow 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. We plan to update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2017.

2018 SECOND QUARTER REPORT    11

$ 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 June 30, 2018.

In light of our view of the likely outcome of the case 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 of Canada. 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 2017. The largest expenditures were incurred in 2016 and 2017 during trial preparation and court proceedings. If the decision of the Tax Court is appealed, additional costs will be incurred.

The trial for the 2003, 2005 and 2006 tax years concluded on September 13, 2017 and we expect to receive a Tax Court decision within the next nine months. Once the decision is issued, the rules that apply to our case permit either party to appeal the Tax Court decision to the Federal Court of 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. An appeal of a Tax Court decision to the Federal Court of Appeal must be filed within 30 days after the issuance of a Tax Court decision (excluding the months of July and August). 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 Tax Court decision, we anticipate that it would take about two years from the date the Tax Court decision is issued to receive a decision from the Federal Court of Appeal. If a further appeal is pursued, 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.

The total tax amount reassessed for the 2003, 2005 and 2006 tax years was $11 million, and we remitted 50% of such amount at the time the reassessments were issued. In certain circumstances, including where neither party pursues an appeal of the Tax Court decision, CRA would issue revised reassessments for the 2003, 2005 and 2006 tax years that comply with the Tax Court decision. Following those reassessments, the corresponding tax payments or refunds, as applicable, plus interest, would be made or received, as applicable, within a reasonable period. Where one or more appeals are pursued by either party, reassessments might not be issued until after the decision on the final appeal is received. If the Tax Court decision results in an aggregate tax amount in excess of what we have already remitted, and we pursue an appeal of that decision, we may be required to remit or secure additional cash tax amounts not exceeding the remaining unpaid portion of the original $11 million (plus interest) while that appeal is underway. Where the Tax Court decision results in a refund of the remitted portion of the original $11 million (with interest), we may not receive that refund until and unless the Tax Court decision is confirmed after the final appeal.

Once the Tax Court has delivered a decision for the 2003, 2005 and 2006 tax years we will consider how the decision relates to other years in issue (being 2004 and years subsequent to 2006). While the decision would not be legally binding for any year other than the trial years, we expect the ultimate decision for the trial years to be an important factor in resolving the dispute for the other years in issue.

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.

12    CAMECO CORPORATION

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 and the cumulative tax provision of $61 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

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 and the outcome of our dispute with CRA results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision of $61 million, 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 all 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 15 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.

2018 SECOND QUARTER REPORT    13

At June 30, 2018:

• 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 $1.29 (Cdn) at March 31, 2018. The exchange rate averaged $1.00 (US) for $1.29 (Cdn) over the quarter.

• The mark-to-market position on all foreign exchange contracts was a $27 million loss compared to a $1 million gain at March 31, 2018.

For information on the impact of foreign exchange on our intercompany balances, see note 18 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 15, and Foreign exchange on page 13. 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 delivery volumes, revenue, average realized price, and average unit cost of sales (including D&A); capital expenditures; the expected contribution of our uranium and fuel services segments to gross profit; and cash flow 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 19 for details.

2018 FINANCIAL OUTLOOK

	CONSOLIDATED		URANIUM			FUEL SERVICES
EXPECTED CONTRIBUTION TO GROSS PROFIT	100%		81%			19%
Production (owned and operated properties)		—		9.2 million lbs			9 to 10 million kgU
Purchases		—		8 to 9 million lbs	1		—
Sales/delivery volume2		—		34 to 35 million lbs	3		11 to 12 million kgU
Revenue2	$	1,890-2,140 million	$	1,550-1,640 million	4	$	280-310 million
Average realized price3		—	$	46.10/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	$	0-10 million		—			—
Tax recovery - ANE basis7	$	40-50 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. It does not include the 3 million to 4 million pounds of intersegment committed purchases we have, or the 2 million to 4 million pounds of uranium we expect we may need to purchase to meet our 2018 delivery commitments, and 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 $22.55 (US) per pound (the Ux spot price as of June 25, 2018), a long-term price indicator of $30.00 (US) per pound (the Ux long-term indicator on June 25, 2018) and an exchange rate of $1.00 (US) for $1.25 (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 or severance costs associated with our announced corporate office workforce reduction.

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.

14    CAMECO CORPORATION

We now expect our annual uranium sales volume to be 34 million to 35 million pounds (previously 32 million to 33 million pounds) as a result of additional sales commitments made during the quarter. Sales revenue for the uranium segment will also be affected and is now expected to be $1,550 million to $1,640 million (previously $1,460 million to $1,550 million), resulting in consolidated revenue of $1,890 million to $2,140 million (previously $1,800 million to $1,930 million).

Average realized price for our uranium segment is now expected to be $46.10 per pound (previously $46.30 per pound) as a result of entering additional sales commitments for delivery in 2018 at prices lower than the previous average realized price outlook provided. In addition, average unit cost of sales is now expected to be $40.00 per pound to $42.00 per pound (previously $38.00 per pound to $40.00 per pound) due to the severance costs associated with the continued suspension of production at McArthur River and Key Lake.

As a result of the changes to the uranium average realized price and average unit cost of sales, we now expect the contribution to gross profit to be 81% from the uranium segment and 19% from the fuel services segment (previously 85% and 15% respectively).

We now expect capital expenditures to be $80 million (previously $90 million) mainly as a result of the optimization of the Cigar Lake development plan, which results in a reduction in expenditures this year.

Cash from operations for 2018 is now expected 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 8 million and 9 million pounds, the estimate also includes expected purchases of 2 million to 4 million pounds.

Direct administration costs remain unchanged, however, we expect an increase in our overall administration costs of about $10 million due to the severance costs associated with the workforce reduction at corporate office. These costs will be expensed in the third quarter.

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, with deliveries weighted to the second half of the year.

Additional outlook tied to the extended shutdown of McArthur River/Key Lake

To meet our delivery commitments in 2018, and taking into account the Orano loan of up to 5.4 million pounds, we expect we will need to purchase 2 million to 4 million pounds of uranium this year in addition to the purchase commitments outlined in the 2018 Financial Outlook table. This will achieve our inventory reduction plan, assuming we target four and a half months of forward sales in inventory.

In the absence of an extended shutdown, that would be the extent of our required purchases this year. However, considering the extended production suspension, and our willingness to capture demand in the market, we may undertake additional purchasing activity if the opportunity or need arises.

Looking at 2019, in our uranium segment, we expect to produce 9 million pounds, we have commitments to purchase between 5 million and 6 million pounds, and have sales commitments to deliver between 25 million and 27 million pounds. To meet our 2019 delivery commitments and maintain our target inventory, we expect we will need to purchase an additional 9 million to 11 million pounds. The timing of purchases may be impacted by the timing of deliveries and opportunities in the market.

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		37			24			30
	$5(US)/lb decrease		(37	)		(24	)		(30	)
Value of Canadian dollar vs US dollar	One cent decrease in CAD		9			3			3
	One cent increase in CAD		(9	)		(3	)		(3	)

¹  Assuming change in both UxC spot price ($22.55 (US) per pound on June 25, 2018) and the UxC long-term price indicator ($30.00 (US) per pound on June 25, 2018)

2018 SECOND QUARTER REPORT    15

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 June 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 June 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		43		56		66		75		83		89
2020		31		41		54		64		73		80		86
2021		28		41		55		65		74		83		90
2022		27		41		55		66		75		84		92

The table illustrates the mix of long-term contracts in our June 30, 2018 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to June 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 23 million pounds per year, with commitment levels of between 34 million and 35 million pounds in 2018 and 25 million to 27 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 June 30, 2018, we had cash and short-term investments of $837 million, 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. Over the next five years, we have commitments to deliver an average of 23 million pounds per year, with commitments levels in 2018 of 34 million to 35 million pounds and 25 million to 27 million pounds in 2019. Commitments for 2020 through 2022 are lower.

16    CAMECO CORPORATION

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 planned 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 have an ongoing transfer pricing dispute with CRA. See page 10 for more information. Until this dispute is resolved, we expect to pay cash or provide security in the form of letters of credit for future amounts owing to the Government of Canada for 50% of the cash taxes payable and the related interest and penalties. We have provided an estimate of the amount and timing of the expected cash taxes and transfer pricing penalties paid, secured or owing in the table on page 12.

CASH FROM/USED IN OPERATIONS

Cash provided by operations was $73 million lower this quarter than in the second quarter of 2017. Contributing to this change was lower gross profits in both our uranium and fuel services segments. In addition, there was an increase in working capital requirements, which required $29 million more in 2018 than in 2017. Not including working capital requirements, our operating cash flows this quarter were lower by $44 million.

Cash provided by operations was $210 million higher in the first six 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 decrease in inventory compared to an increase in 2017 as well as changes in other working capital items. Working capital required $171 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 six months were higher by $39 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 June 30, 2018, unchanged from March 31, 2018. At June 30, 2018, we had approximately $1.6 billion outstanding in financial assurances, up from $1.5 billion at December 31, 2017. At June 30, 2018, we had no short-term debt outstanding on our $1.25 billion unsecured revolving credit facility, unchanged from December 31, 2017. This facility matures November 1, 2021.

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 June 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 June 30, 2018:

• purchase commitments

• financial assurances

• other arrangements

2018 SECOND QUARTER REPORT    17

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 July 17, 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.

JULY 17 ($ MILLIONS)	2018		2019 AND 2020		2021 AND 2022		2023 AND BEYOND		TOTAL
Purchase commitments1		408		249		178		132		967

¹  Denominated in US dollars, converted to Canadian dollars as of June 30, 2018 at the rate of $1.32.

As of July 25, 2018, we had commitments of about $967 million 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.

Financial assurances

At June 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 June 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)	JUN 30, 2018		DEC 31, 2017		CHANGE
Cash, cash equivalents and short-term investments		837		592		41	%
Total debt		1,495		1,494		—
Inventory		838		950		(12	)%

Total cash, cash equivalents and short-term investments at June 30, 2018 were $837 million, or 41% higher than at December 31, 2017, primarily due to cash from operations of $332 million, partially offset by capital expenditures of $30 million, 2017 dividend payments of $40 million, and interest payments of $35 million. Net debt at June 30, 2018 was $658 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 second quarter of 2018 we received distributions of $4.2 million (US), totaling $13.3 million (US) year-to-date, which were made as loan and interest repayments, and as of June 30, 2018, the outstanding principal balance of the loan was $106 million (US).

Total product inventories decreased to $838 million. Inventories decreased as sales were higher than production and purchases in the first six months of the year. In addition, the product provided to Orano contributed to the decrease. The average cost for uranium has increased to $31.50 per pound compared to $30.72 per pound at December 31, 2017. As of June 30, 2018, we held an inventory of 19.3 million pounds of U₃O₈ equivalent in our uranium segment (excluding broken ore).

18    CAMECO CORPORATION

Financial results by segment

Uranium

		THREE MONTHS ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
HIGHLIGHTS		2018		2017		CHANGE			2018		2017		CHANGE
Production volume (million lbs)			2.9		7.1		(59	)%		5.3		13.8		(62	)%
Sales volume (million lbs)1			5.3		6.1		(13	)%		11.9		11.8		1	%
Average spot price	($US/lb)		22.13		20.79		6	%		21.78		22.29		(2	)%
Average long-term price	($US/lb)		29.00		32.83		(12	)%		29.25		32.83		(11	)%
Average realized price	($US/lb)		34.93		36.51		(4	)%		39.38		35.50		11	%
	($Cdn/lb)		44.91		49.11		(9	)%		50.04		47.36		6	%
Average unit cost of sales (including D&A)	($Cdn/lb)		41.12		35.29		17	%		41.84		36.47		15	%
Revenue ($ millions)1			237		298		(20	)%		596		558		7	%
Gross profit ($ millions)			20		84		(76	)%		98		128		(23	)%
Gross profit (%)			8		28		(71	)%		16		23		(30	)%

¹  There were no significant intersegment transactions in the periods shown.

SECOND QUARTER

Production volumes this quarter were 59% lower compared to the second 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 Q2 updates starting on page 22 for more information.

Uranium revenues this quarter were down 20% compared to 2017 due to a decrease of 9% in the Canadian dollar average realized price and a decrease in sales volumes of 13%. While the average spot price for uranium increased by 6% compared to the same period in 2017, our average realized price decreased due to lower prices on fixed price contracts and the strengthening of the Canadian dollar compared to the same period in the prior year.

Total cost of sales (including D&A) increased by 1% ($217 million compared to $214 million in 2017) as a result of unit cost of sales that was 17% higher than the same period last year offset by a 13% decrease 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 and the cessation of production at our US ISR operations. The cost of our purchases have decreased from the second quarter in 2017.

The net effect was a $64 million decrease in gross profit for the quarter.

Equity earnings from investee, JV Inkai, were $4 million in the second quarter.

FIRST SIX MONTHS

Production volumes for the first six months of the year were 62% 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 Q2 updates starting on page 22 for more information.

Uranium revenues increased 7% compared to the first six months of 2017 due to a 6% increase in the Canadian dollar average realized price and a 1% increase in sales volumes. The increase in sales volume was due to the restructuring of an agreement with one of our utility customers. The restructuring advanced the majority of contract deliveries into the first quarter of 2018.

Our Canadian dollar realized prices for the first six months of 2018 were higher than 2017, primarily as a result of higher prices on fixed price contracts.

Total cost of sales (including D&A) increased by 16% ($499 million compared to $430 million in 2017) mainly due to a 15% increase in the unit cost of sales and a 1% increase in sales volume for the first six months. The increase in the unit cost of sales compared to last year was mainly due to increased costs associated with the temporary 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 $30 million decrease in gross profit for the first six months.

2018 SECOND QUARTER REPORT    19

Equity earnings from investee, JV Inkai, were $5 million for the first six 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.

	THREE MONTHS ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
($CDN/LB)	2018		2017		CHANGE			2018		2017		CHANGE
Produced
Cash cost		10.78		13.53		(20	)%		14.14		14.02		1	%
Non-cash cost		15.96		10.59		51	%		16.55		10.47		58	%
Total production cost 1		26.74		24.12		11	%		30.69		24.49		25	%
Quantity produced (million lbs)1		2.9		7.1		(59	)%		5.3		13.8		(62	)%
Purchased
Cash cost1		29.64		37.34		(21	)%		32.73		40.36		(19	)%
Quantity purchased (million lbs)1		2.2		0.7		214	%		3.9		2.5		56	%
Totals
Produced and purchased costs		27.99		25.31		11	%		31.55		26.92		17	%
Quantities produced and purchased (million lbs)		5.1		7.8		(35	)%		9.2		16.3		(44	)%

¹  Our share of Inkai production was 0.7 million pounds for Q2, 2018 (1.4 million pounds for the first six 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 second quarter we purchased 856,000 pounds at a purchase price per pound of $27.52 ($21.46 (US)) (870,000 pounds in the first six months of 2018 at $27.54 ($21.47 (US))).

The average cash cost of production was 20% lower for the quarter compared to 2017 due to higher production at Cigar Lake. In addition, with the cessation of higher cost production at our US operations in the first quarter, any costs associated with the operation are considered care and maintenance and expensed directly to cost of sales as incurred. For the first six months, the average cash cost of production was 1% higher than in in 2017 due to lower production from McArthur River/Key Lake as the operations moved into care and maintenance.

The other item affecting this table was the change to equity accounting for our interest in JV Inkai.

The change 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”.

As a result, 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.

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the second quarter, the average cash cost of purchased material was $29.64 (Cdn) per pound, or $23.07 (US) per pound in US dollar terms, compared to $27.82 (US) per pound in the second quarter of 2017. For the first six months, the average cash cost of purchased material was $32.73 (Cdn), or $25.69 (US) per pound, compared to $30.40 (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 21% this quarter and by 19% for the six 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.

20    CAMECO CORPORATION

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 second quarter and the first six months of 2018 and 2017.

Cash and total cost per pound reconciliation

	THREE MONTHS ENDED JUNE 30						SIX MONTHS ENDED JUNE 30
($ MILLIONS)	2018			2017			2018			2017
Cost of product sold		156.4			158.9			388.1			340.9
Add / (subtract)
Royalties		(9.5	)		(13.0	)		(21.8	)		(23.2	)
Care and maintenance costs		(34.6	)		(10.4	)		(76.5	)		(20.8	)
Other selling costs		(1.2	)		(2.2	)		(5.5	)		(2.9	)
Change in inventories		(14.6	)		(11.1	)		(81.7	)		0.4
Cash operating costs (a)		96.5			122.2			202.6			294.4
Add / (subtract)
Depreciation and amortization		48.8			55.5			91.5			89.0
Care and maintenance costs		12.0			—			19.0			—
Change in inventories		(14.5	)		19.7			(22.8	)		55.4
Total operating costs (b)		142.8			197.4			290.3			438.8
Uranium produced & purchased (million lbs) (c)		5.1			7.8			9.2			16.3
Cash costs per pound (a ÷ c)		18.92			15.67			22.02			18.06
Total costs per pound (b ÷ c)		27.99			25.31			31.55			26.92

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

				THREE MONTHS ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
HIGHLIGHTS				2018		2017		CHANGE			2018		2017		CHANGE
Production volume (million kgU)					2.3		2.2		5	%		6.2		4.8		29	%
Sales volume (million kgU)1					2.1		2.7		(22	)%		4.5		4.3		5	%
Average realized price	($	Cdn/kgU	)		32.63		30.46		7	%		29.40		31.50		(7	)%
Average unit cost of sales (including D&A)	($	Cdn/kgU	)		24.30		21.44		13	%		22.83		22.66		1	%
Revenue ($ millions)1					68		82		(17	)%		133		137		(3	)%
Gross profit ($ millions)					17		24		(29	)%		30		38		(21	)%
Gross profit (%)					25		29		(14	)%		23		28		(18	)%

¹  There were no significant intersegment transactions in the periods shown.

SECOND QUARTER

Total revenue for the second quarter of 2018 decreased to $68 million from $82 million for the same period last year. This was primarily due to a 22% 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 UO₂ and fabrication.

The total cost of products and services sold (including D&A) decreased 12% ($51 million compared to $58 million in 2017) due to the 22% decrease in sales volume, partially offset by a 13% increase in the average unit cost of sales.

The net effect was a $7 million decrease in gross profit.

2018 SECOND QUARTER REPORT    21

FIRST SIX MONTHS

In the first six months of the year, total revenue decreased by 3% due to a 7% decrease in realized price, partially offset by a 5% increase in sales volumes. The decrease in realized price was the result of decreased prices on the sale of UF₆, and the mix of products sold.

The total cost of products and services sold (including D&A) increased 5% ($103 million compared to $98 million in 2017) due to the 5% increase in sales volume and a 1% increase in the average unit cost of sales.

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

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 59% lower than the second 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 ENDED JUNE 30							SIX MONTHS ENDED JUNE 30
OUR SHARE (MILLION LBS)	2018		2017		CHANGE			2018		2017		CHANGE			2018 PLAN
McArthur River/Key Lake		—		3.6		(100	)%		0.1		7.2		(99	)%		0.1
Cigar Lake		2.9		2.5		16	%		5.1		4.8		6	%		9.0
Inkai1		—		0.8		(100	)%		—		1.5		(100	)%		—
US ISR		—		0.2		(100	)%		0.1		0.3		(67	)%		0.1
Total		2.9		7.1		(59	)%		5.3		13.8		(62	)%		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 Q2 updates

PRODUCTION UPDATE

McArthur River/Key Lake

There was no production in the second quarter as a result of the planned 10-month production suspension that began in February.

Due to continued weakness in the uranium market, we have made the decision to extend the suspension for an indeterminate duration. This action will result in the permanent layoff of approximately 550 employees, including those currently on temporary layoff.

A reduced workforce of approximately 200 employees will remain at the operations to keep the facilities in a state of safe care and maintenance.

We will incur about $30 million to $35 million in severance costs in the third quarter as a result of the permanent layoffs. Our share of the cost to maintain both operations during the suspension is expected to range between $5 million and $6 million per month (previously $6.5 million to $7.5 million per month) once the permanent layoffs take effect.

Cigar Lake

Total packaged production from Cigar Lake was 16% higher in the second quarter and 6% higher for the first six months compared to the same periods last year. Production is expected to be lower in the third quarter as the site enters an extended summer shutdown period starting in July, which is expected to increase quarterly unit production costs. Production is expected to restart at the end of August and remains on track to meet forecast for the year.

22    CAMECO CORPORATION

Inkai

Production on a 100% basis was 1.8 million pounds for the quarter and 3.5 million pounds for the first six 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.

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 second quarter. We have now effectively ceased production, which is expected to result in production of less than 100,000 pounds for the year. As long as production is suspended, we expect care and maintenance costs to range between $18 million (US) and $22 million (US) annually for the first few years.

Rabbit Lake

The Rabbit Lake operation is in a safe state of care and maintenance; there was no production in the second quarter of 2018. We are continually weighing the value of maintaining the operation in standby, against the cost of doing so. However, as long as production is suspended, we expect care and maintenance costs to range between $35 million and $40 million annually for the first few years.

Fuel services 2018 Q2 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 2.3 million kgU in the second quarter, 5% higher than the same period last year due to the timing of scheduled production.

Labour relations

Approximately 90 unionized employees at CFM’s operations in Ontario accepted a new collective agreement. The employees, represented by the United Steelworkers Local 14193, agreed to a three-year contract. The previous contract expired May 30, 2018.

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

• Brian Reilly, senior vice-president and chief operating officer, Cameco

2018 SECOND QUARTER REPORT    23

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 June 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.

Based upon that evaluation and as of June 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 June 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

24    CAMECO CORPORATION