Exhibit 99.2

Management’s discussion and analysis

for the quarter ended March 31, 2019

4   5   7   14   17   19   22   23   24 OUR STRATEGY   FIRST QUARTER MARKET UPDATE   CONSOLIDATED FINANCIAL RESULTS   OUTLOOK FOR 2019   LIQUIDITY AND CAPITAL RESOURCES   FINANCIAL RESULTS BY SEGMENT   OUR OPERATIONS - FIRST QUARTER UPDATES   QUALIFIED PERSONS   ADDITIONAL INFORMATION

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

As you review this MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2018 and annual MD&A. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.

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

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

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

Caution about forward-looking information

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

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

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

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

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

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

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

Examples of forward-looking information in this MD&A

•  the discussion under the headings Our strategy and Strategy in action, including for uranium purchases, sales and deliveries   •  expectations for repayment of our $500 million debenture maturing in 2019   •  our expectations about 2019 and future global uranium supply, consumption, contracting volumes and demand, including the discussion under the heading First quarter market update   •  the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, including that the Tax Court of Canada (Tax Court) ruling will be upheld on appeal and our estimate of the amount and timing of cash taxes, transfer pricing penalties and disbursements award   •  the discussion under the heading Outlook for 2019, including expectations for 2019 gross profit, cash balances, and deliveries, our 2019 financial outlook, and our price sensitivity analysis for our uranium segment •  our expectations regarding 2019 cash flow, and that existing cash balances and operating cash flows will meet our anticipated 2019 capital requirements, even if we decide to retire our $500 million debenture maturing in 2019   •  production and life of mine operating cost estimates for the Cigar Lake and Inkai operations   •  our expectation that our operating and investment activities for the remainder of 2019 will not be constrained by the financial-related covenants in our unsecured revolving credit facility   •  our future plans and expectations for each of our uranium operating properties and fuel services operating sites, including production levels   •  the key highlights from our McArthur River technical report   •  our expectations related to care and maintenance costs, including incurring between $130 and $160 million in 2019   •  our planned annual 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, deliveries, 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 •  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   •  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 Cigar Lake development, mining or production plans are delayed or do not succeed for any reason   •  any difficulties in milling of Cigar Lake ore at McClean Lake mill or resuming production at Cigar Lake after the extended shutdown scheduled for the third quarter

2     CAMECO CORPORATION

•  our uranium suppliers fail to fulfil delivery commitments or our uranium purchasers fail to fulfil purchase commitments   •  we are affected by political risks   •  we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy   •  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   •  we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our dispute with CRA or with TEPCO Resources Inc. (TEPCO)   •  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 •  water quality concerns and environmental concerns result in a potential deferral of production and additional capital and operating expenses required for the Cigar Lake operation   •  JV Inkai’s development, mining or production plans are delayed or do not succeed for any reason   •  our expectations relating to care and maintenance costs prove to be inaccurate   •  we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes   •  operations are disrupted due to problems with facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts (including at our McArthur River/Key Lake operations, our Port Hope conversion facility, and Orano’s McClean Lake mill), underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

Material assumptions

•  our expectations regarding sales and purchase volumes and prices for uranium and fuel services, trade restrictions and that 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, purchase costs, operating costs, capital costs, and the success of our cost reduction strategies   •  our expectations regarding tax rates and payments, royalty rates, currency exchange rates and interest rates   •  our expectations about the outcome of our dispute with CRA, including that the Tax Court ruling will be upheld on appeal   •  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, including the assumptions upon which they are based, are reliable •  our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable   •  our understanding of the geological, hydrological and other conditions at our uranium properties   •  our Cigar Lake development, mining and production plans succeed, 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 (including at our McArthur River/Key Lake operations, our Port Hope conversion facility, and Orano’s McClean Lake mill), underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, unanticipated consequences of our cost reduction strategies or other development or operating risks

2019 FIRST QUARTER REPORT     3

Our strategy

We are a pure-play nuclear fuel supplier, focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to preserve the value of those assets and increase long-term shareholder value, and to do that with an emphasis on safety, people and the environment.

Due to the weak market conditions since 2011, we have undertaken a number of deliberate and disciplined actions: we have focused on preserving the value of our lowest cost assets, on maintaining a strong balance sheet, on protecting and extending the value of our contract portfolio and on efficiently managing the company in a low price environment.

We evaluate our strategy in the context of our market environment and continue to adjust our actions in accordance with the following marketing framework:

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

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

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

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

• And finally, in general, if we choose to source material to meet demand by purchasing it, we expect the price of that material will be more than offset by the leverage to market prices in our sales portfolio over a rolling 12-month period.

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

We believe this approach provides us with the opportunity to meet rising demand with increased production from our best margin assets, helps to mitigate risk, and will allow us to create long-term value for our shareholders. Our focus continues to be on maximizing cash flow, while maintaining our investment-grade rating so we can self-manage risk. As a result, we expect we will be in a position to retire our $500 million debenture maturing in September 2019.

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

Strategy in action

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

On the operational and financial fronts, things were relatively quiet. The suspension of production at McArthur River/Key Lake announced last July continues for an indeterminate duration. With $1.2 billion in cash and short-term investments at March 31, 2019, and the continued generation of cash from operations in 2019, our balance sheet is in good shape and we are well positioned to meet our financial obligations and self-manage risk.

The marketing facet of our strategy is where most of the activity occurred in the first quarter. In 2018, we began actively purchasing material in the spot market. This purchasing not only continues in 2019, it ramps up. In our uranium segment, we expect to take delivery of between 19 million and 21 million pounds of purchased uranium, just to meet our current 2019 sales commitments. About 60% of these volumes are expected to come from the spot market. We have already secured a portion of this material, but have not yet taken delivery of it, and we still have some purchasing activity ahead of us to meet our 2019 sales commitments. During the quarter, in our uranium segment, we took delivery of 7.2 million pounds of uranium, some drawn from the spot market, some as a result of long-term purchase commitments we had, or from JV Inkai. In addition to our purchasing activity for 2019 sales commitments, we expect to begin purchasing material this year to meet our 2020 sales commitments.

4     CAMECO CORPORATION

In late March, we saw some motivated selling from a number of market participants. It seems these players had built up a uranium position in anticipation of short-term demand in the market, and misread the timing of that demand. When the demand didn’t materialize on the timelines expected, they began to sell material into a very illiquid spot market, which drew a few other sellers into the market as well. Once the market had found a floor, we issued a request for proposal for 1 million pounds. Despite price signals to the contrary, we found there was not enough material available to meet our specifications.

While we need to buy material, we are not the buyer of last resort in this market. Our strategy dictates that if we see this type of behavior, we will step back from our purchasing activity and let the market find its own floor. We always aim to buy uranium as cheaply as possible in order to maximize our gross profit.

For example, we are hearing that one of the Japanese utilities is looking to sell a modest amount of its inventory, less than 150,000 pounds per year for the next several years. While the volumes are small, and we have not seen a broader shift in Japanese utility behavior, we believe this selling could have an impact on market sentiment. Our response will be the same as in the first quarter, we will wait for the material to come to the market. We may purchase this material, but will do so at the lowest price possible.

In the quarter, we also saw the interest in long-term contracting start to pick up. With the decreasing primary supply as a result of curtailments, and the competition for supply in the spot market from producers and financial players, we are beginning to have off-market conversations with some of our best and largest customers about what it takes to support the operation of our tier-one assets longer term.

These customers recognize the risk overreliance on finite sources of supply poses to security of supply longer term and want first-mover advantage. In light of the market access and trade policy issues affecting our market, they are increasingly looking for stable, commercial suppliers with long-lived, tier-one assets. As a result of this activity, our average annual delivery volume over the next five years has increased to 21 million pounds (previously 20 million). See Expected realized uranium price sensitivity under various price assumptions on page 16.

The terms of our recent contracting activity remain consistent with our overall portfolio goals. However, not surprisingly, for nearer-term deliveries, there is not much leverage to higher prices because it is still a buyer’s market. While price is a very important factor, we also take into account who the customer is, the volume being contracted, duration, product form, and regional diversification. Overall, our total portfolio of sales commitments have increased by about 25 million pounds. Including our 2019 deliveries, we now have commitments to sell approximately 150 million pounds of uranium (previously 125 million) in our uranium segment. With delivery generally not starting for two to three years after we sign a long-term agreement, the bulk of those commitments occur after 2023.

First quarter market update

During the first quarter and to-date in April, much of the uranium market was consumed with the US Department of Commerce (DOC) Section 232 trade investigation. There was some weakness in the uranium spot price, largely the result of financial year-end and quarter-end motivated spot selling by some market participants. And, we are beginning to see interest in long-term contracting pick up. See Strategy in action on page 4.

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

Starting with market access and trade policy issues, in the US, which has the largest fleet of nuclear reactors in the world, the DOC has completed its 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. On April 14, 2019, it issued a confidential report to the President of the United States containing its findings and recommendation. The President has up to 90 days from that date to decide whether to concur with the DOC findings and what actions, if any, will be taken.

In addition, there is growing recognition of the role nuclear power must play in ensuring safe, reliable and affordable electricity while tackling climate change and air quality issues. As a result, a number of countries and organizations are coming out with positive policy messages.

For example, in the US, a bipartisan group of senators reintroduced legislation, Bill 903, the Nuclear Energy Leadership Act (NELA) to boost US nuclear energy innovation and ensure advanced reactors can provide safe, affordable, and reliable electricity. In addition, the US Secretary of Energy, Rick Perry announced a $3.7 billion loan guarantee to support the completion of the only two reactors under construction in the US, calling it the ‘Real Green New Deal’.

2019 FIRST QUARTER REPORT     5

On March 19, 2019, the President of Kazakhstan, Nursultan Nazarbayev, announced he was stepping down immediately, and the speaker of the Senate, Kassym-Zhomart Tokayev, assumed the presidency. A snap election has been called for June 9, 2019. With almost 45% of world supply coming out of Kazakhstan, the leadership transition will be watched closely.

In China, the fastest growing nuclear energy market in the world, construction approvals for two new reactor complexes implementing domestic Chinese Hualong One reactor technology were announced, the first new build approved in over three years. CNNC Chairman, Yu Jianfeng, indicated that China expects to be able to build six to eight new reactors each year, if the project approval process returns to normal, which would allow it to meet its 2030 target.

Financial interest in physical uranium continues from both existing funds and potential new entrants. Recently, Yellow Cake Plc, the London listed uranium fund, announced that it has agreed to purchase more than 1 million pounds of uranium from Kazatomprom, partially exercising the option under its framework agreement. While this is positive from a demand point of view in the near term, it is important not to lose sight of this material. 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. Combined with the significant idle tier-one production and expansion capability, as well as the idle tier-two production and expansion capabilities, capacity that can come back to the market relatively quickly, new supply poses a significant risk to the uranium market recovery. Today, we believe even the promise of new supply could create a headwind and put downward pressure on uranium prices.

Longer term, uranium demand is backed by steady reactor growth with more than 50 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 primary supply, some mines approaching the end of their reserve life, the overreliance on finite secondary supplies, and growing uncovered requirements are expected to generate increasing pressure for fuel buyers to return to long-term contracting.

As annual production adjusts, finite sources of supply are exhausted, 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. There will be a need to eventually contract for replacement volumes to fill these uncovered requirements at prices that will incentivize reliable, long-term supply. This contracting 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, demand and prices, 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.

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Industry prices at quarter end

	MAR 31		DEC 31		SEP 30		JUN 30		MAR 31		DEC 31
	2019		2018		2018		2018		2018		2017
Uranium ($US/lb U3O8)1
Average spot market price		25.33		27.75		27.50		22.65		21.05		23.75
Average long-term price		32.00		32.00		31.75		29.00		29.00		31.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		14.75		13.50		13.08		9.03		6.68		5.80
Europe		14.75		13.88		13.50		9.38		6.93		6.13
Average long-term price
North America		15.50		16.00		15.75		14.25		12.25		13.00
Europe		15.50		16.25		16.00		14.25		12.25		13.00

Note: the industry does not publish UO₂ prices.

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

On the spot market, where purchases call for delivery within one year, the volume reported by UxC for the first quarter of 2019 was approximately 18 million pounds, compared to 14 million pounds in the first quarter of 2018. At the end of the quarter, the average reported spot price was $25.33 (US) per pound, down $2.42 (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 three months of 2019 was about 14 million pounds compared to about ten million pounds reported over the same period in 2018. 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 $32.00 (US) per pound, unchanged from last quarter.

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

Shares and stock options outstanding   At April 30, 2019, we had:   •  395,797,732 common shares and one Class B share outstanding   •  8,850,922 stock options outstanding, with exercise prices ranging from $11.32 to $26.81 Dividend   Our board of directors have planned an annual dividend of $0.08 per common share. The decision to declare an annual dividend by our board will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

Also of note:

The Australian Federal Department of Environment and Energy has granted environmental approval for the Yeelirrie uranium project, located in Western Australia.

Any decisions to advance this project will depend upon market conditions.

Financial results

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

In this MD&A, our 2019 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 began accounting for JV Inkai on an equity basis, with no restatement of prior periods.

2019 FIRST QUARTER REPORT     7

Consolidated financial results

HIGHLIGHTS	THREE MONTHS ENDED MARCH 31
($ MILLIONS EXCEPT WHERE INDICATED)	2019			2018		CHANGE
Revenue		298			439		(32	)%
Gross profit		17			68		(75	)%
Net earnings (losses) attributable to equity holders		(18	)		55		>(100	%)
$ per common share (basic)		(0.05	)		0.14		>(100	%)
$ per common share (diluted)		(0.05	)		0.14		>(100	%)
Adjusted net earnings (losses) (non-IFRS, see page 8)		(33	)		23		>(100	%)
$ per common share (adjusted and diluted)		(0.08	)		0.06		>(100	%)
Cash provided by operations (after working capital changes)		80			275		(71	)%

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 first quarter of 2019, compared to the first quarter of 2018.

		THREE MONTHS ENDED MARCH 31
($ MILLIONS)		IFRS			ADJUSTED
Net earnings – 2018			55			23
Change in gross profit by segment
(We calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A))
Uranium	Lower sales volume		(21	)		(21	)
	Lower realized prices ($US)		(66	)		(66	)
	Foreign exchange impact on realized prices		11			11
	Higher costs		(5	)		(5	)
	Change – uranium		(81	)		(81	)
Fuel services	Higher sales volume		3			3
	Higher realized prices ($Cdn)		2			2
	Lower costs		3			3
	Change – fuel services		8			8
Other changes
Higher administration expenditures			(1	)		(1	)
Lower exploration expenditures			4			4
Change in reclamation provisions			(1	)		—
Higher earnings from equity-accounted investee			11			11
Change in gains or losses on derivatives			46			1
Change in foreign exchange gains or losses			(15	)		(15	)
Gain on restructuring of JV Inkai in 2018			(49	)		—
Gain on customer contract restructuring in 2018			(6	)		(6	)
Change in income tax recovery or expense			(7	)		5
Other			18			18
Net losses – 2019			(18	)		(33	)

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

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.

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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 first quarter of 2019 and compares it to the same period in 2018.

	THREE MONTHS
	ENDED MARCH 31
($ MILLIONS)	2019			2018
Net earnings (losses) attributable to equity holders		(18	)		55
Adjustments
Adjustments on derivatives		(23	)		22
Reclamation provision adjustments		2			1
Gain on restructuring of JV Inkai		—			(49	)
Income taxes on adjustments		6			(6	)
Adjusted net earnings (losses)		(33	)		23

Every quarter we are required to update the reclamation provisions for all operations based on new cash flow estimates, discount and inflation rates. This normally results in an adjustment to an asset retirement obligation asset in addition to the provision balance. When the assets of an operation have been written off due to an impairment, as is the case with our Rabbit Lake and US ISR operations, the adjustment is recorded directly to the statement of earnings as “other operating expense (income)”. See note 8 of our interim financial statements for more information. This amount has been excluded from our adjusted net earnings measure.

Quarterly trends

HIGHLIGHTS	2019			2018									2017
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q1			Q4		Q3		Q2			Q1		Q4			Q3			Q2
Revenue		298			831		488		333			439		809			486			470
Net earnings (losses) attributable to equity holders		(18	)		160		28		(76	)		55		(62	)		(124	)		(2	)
$ per common share (basic)		(0.05	)		0.40		0.07		(0.19	)		0.14		(0.16	)		(0.31	)		(0.00	)
$ per common share (diluted)		(0.05	)		0.40		0.07		(0.19	)		0.14		(0.16	)		(0.31	)		(0.00	)
Adjusted net earnings (losses) (non-IFRS, see page 8)		(33	)		202		15		(28	)		23		181			(50	)		(44	)
$ per common share (adjusted and diluted)		(0.08	)		0.51		0.04		(0.07	)		0.06		0.46			(0.13	)		(0.11	)
Cash provided by (used in) operations (after working		80			57		278		57			275		320			154			130
capital changes)

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 69% of consolidated revenues in the first quarter of 2019

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

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

2019 FIRST QUARTER REPORT     9

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

HIGHLIGHTS	2019			2018												2017
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2
Net earnings (losses) attributable to equity holders		(18	)		160			28			(76	)		55			(62	)		(124	)		(2	)
Adjustments
Adjustments on derivatives		(23	)		47			(24	)		20			22			(2	)		(40	)		(44	)
Impairment charges		—			—			—			—			—			247			111			—
Reclamation provision adjustments		2			10			5			44			1			15			(9	)		(12	)
Gain on restructuring of JV Inkai		—			—			—			—			(49	)		—			—			—
Income taxes on adjustments		6			(15	)		6			(16	)		(6	)		(17	)		12			14
Adjusted net earnings (losses) (non-IFRS, see page 8)		(33	)		202			15			(28	)		23			181			(50	)		(44	)

Corporate expenses

ADMINISTRATION

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2019		2018		CHANGE
Direct administration		30		29		3	%
Stock-based compensation		6		6		—
Total administration		36		35		3	%

Direct administration costs were $1 million higher for the first quarter of 2019 compared to the same period last year.

EXPLORATION

In the first quarter, uranium exploration expenses were $4 million, a decrease of $4 million compared to the first quarter of 2018 due to a planned reduction in expenditures.

INCOME TAXES

We recorded an income tax expense of $0.5 million in the first quarter of 2019, compared to a recovery of $7 million in the first quarter of 2018.

On an adjusted basis, we recorded an income tax recovery of $6 million this quarter compared to a recovery of $1 million in the first quarter of 2018. In 2019, we recorded losses of $4 million in Canada compared to losses of $42 million in 2018, while we recorded losses of $35 million in foreign jurisdictions compared to earnings of $64 million last year.

	THREE MONTHS
	ENDED MARCH 31
($ MILLIONS)	2019			2018
Pre-tax adjusted earnings1
Canada		(4	)		(42	)
Foreign		(35	)		64
Total pre-tax adjusted earnings		(39	)		22
Adjusted income taxes1
Canada		(2	)		(5	)
Foreign		(4	)		4
Adjusted income tax recovery		(6	)		(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, 2018, the Tax Court of Canada (Tax Court) ruled unequivocally in our favour in our case with the Canada Revenue Agency (CRA) for the 2003, 2005 and 2006 tax years.

10     CAMECO CORPORATION

The Tax Court ruled that our marketing and trading structure involving foreign subsidiaries and the related transfer pricing methodology used for certain intercompany uranium purchase and sale agreements were in full compliance with Canadian laws for the three tax years in question. While the decision applies only to the three tax years under dispute, we believe there is nothing in the decision that would warrant a materially different outcome for subsequent tax years.

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

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

Appeals process

On October 25, 2018, CRA filed a notice of appeal with the Federal Court of Appeal. In its notice of appeal, CRA dropped the sham argument, but is appealing the Tax Court’s interpretation and application of the transfer pricing provisions in section 247 of the Income Tax Act. 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, which are due at the end of May.

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

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

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

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

Potential exposure based on CRA appeal

Since 2008, CRA has disputed our marketing and trading structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements. To date, we have received notices of reassessment for our 2003 through 2012 tax years. While the Tax Court has ruled unequivocally in our favour for the 2003, 2005 and 2006 tax years, and we believe there is nothing in the decision that would warrant a materially different outcome on appeal, or for subsequent tax years we will continue to report on the potential exposure as we expect it will continue to tie up our financial capacity until the dispute is finally resolved for all years.

For the years 2003 to 2012, CRA has shifted Cameco Europe Limited’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2011, transfer pricing penalties. We understand CRA is currently considering whether to impose a transfer pricing penalty for 2012. Taxes of approximately $321 million for the 2003 to 2018 years have already been paid to date in a jurisdiction outside Canada. If CRA is successful on appeal, we will consider our options under bilateral international tax treaties to limit double taxation of this income. There is a risk that we will not be successful in eliminating all potential double taxation. The income adjustments claimed by CRA in its reassessments are represented by the amounts described below.

2019 FIRST QUARTER REPORT     11

The Canadian income tax rules include provisions that require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions, we have paid or secured the amounts shown in the table below. Of these amounts, we expect to receive refunds totaling approximately $5.5 million plus interest based on the ruling of the Tax Court. The timing of the refund may be delayed pending the outcome of the appeal.

YEAR PAID ($ MILLIONS)	CASH TAXES		INTEREST AND INSTALMENT PENALTIES		TRANSFER PRICING PENALTIES		TOTAL		CASH REMITTANCE		SECURED BY LC
Prior to 2014		1		22		36		59		59		—
2014		106		47		—		153		153		—
2015		202		71		79		352		20		332
2016		51		38		31		120		32		88
2017		—		1		39		40		39		1
2018		17		40		—		57		—		57
2019		—		2		—		2		—		2
Total		377		221		185		783		303		480

While we expect the Tax Court’s decision to be upheld on appeal and believe the decision should apply in principle to subsequent years, until such time as all appeals are exhausted, and a resolution is reached for all tax years in question, we will not be in a position to determine the definitive outcome of this dispute. We expect any further actions regarding the tax years 2007 through 2012 will be suspended until the three years covered under the decision are finally resolved, with the exception of the transfer pricing penalty noted above. The tax years 2013 and beyond have not yet been reassessed, and it is uncertain what approach CRA will take on audit. Despite the fact that we believe there is no basis to do so, and it is not our view of the likely outcome, CRA may continue to reassess us using the methodology it used to reassess the 2003 through 2012 tax years. In that scenario, and including the $4.9 billion already reassessed, we would expect to receive notices of reassessment for a total of approximately $8.7 billion of additional income taxable in Canada for the years 2003 through 2018, which would result in a related tax expense of approximately $2.6 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2011. In that case, we estimate that cash taxes and transfer pricing penalties claimed by CRA for these years would be between $1.95 billion and $2.15 billion. In addition, CRA may seek to apply interest and instalment penalties that would be material to us. While in dispute, we would be required to remit or otherwise provide security for 50% of the cash taxes and transfer pricing penalties (between $970 million and $1.07 billion), plus related interest and instalment penalties assessed, which would be material to us. We have already paid or secured $562 million in cash taxes and transfer pricing penalties and $221 million in interest and instalment penalties.

Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. CRA has to date disallowed the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This does not impact the anticipated income tax expense for a particular year, but does impact the timing of any required security or payment. As noted above, for amounts reassessed after 2014, as an alternative to remitting cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. We believe we will be able to continue to provide security in the form of letters of credit to satisfy these requirements. The amounts summarized in the table below reflect actual amounts paid or secured from 2003 through 2018 along with estimated post-2018 amounts if CRA were to continue to reassess based on the scenario outlined above, and include the expected timing adjustment for the inability to use any loss carry-backs starting with the 2008 tax year. The amounts have not been adjusted to reflect the refund of approximately $5.5 million plus interest we expect to receive based on the ruling of the Tax Court. The timing of such refund may be delayed pending the outcome of the appeal. We plan to update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2018.

12     CAMECO CORPORATION

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

¹ These amounts do not include interest and instalment penalties, which totaled approximately $221 million to March 31, 2019.

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

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

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

Assumptions   •  CRA will reassess us for the years 2013 through 2018 using a similar methodology as for the years 2003 through 2012, and the reassessments will be issued on the basis we expect   •  we will be able to apply elective deductions and utilize letters of credit to the extent anticipated   •  CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years 2007 through 2011) in addition to interest charges and instalment penalties   •  we will be substantially successful in our dispute with CRA, including any appeals of the Tax Court’s decision or any decisions regarding other tax years, and we will not incur any significant tax liability resulting from the outcome of the dispute or other costs, potentially including costs associated with a negotiated resolution with CRA   •  the successful outcome and timing of the determination of our disbursements award Material risks that could cause actual results to differ materially   •  CRA reassesses us for years 2013 through 2018 using a different methodology than for years 2003 through 2012, or we are unable to utilize elective deductions or letters of credit to the extent anticipated, resulting in the required cash payments or security provided to CRA pending the outcome of the dispute being higher than expected   •  the time lag for the reassessments for each year is different than we currently expect   •  we are unsuccessful in an appeal of the Tax Court’s decision or any decisions of the Tax Court for subsequent years, or appeals of those decisions, and the outcome of our dispute with CRA, potentially including costs associated with a negotiated resolution with CRA, results in significant costs, cash taxes, interest charges and penalties which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows   •  cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing   •  we are unable to effectively eliminate any double taxation   •  an unfavourable determination of the officer of the Tax Court or delays in making a determination of the amount of our disbursements award

FOREIGN EXCHANGE

The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments. See Revenue, adjusted net earnings, and cash flow sensitivity analysis on page 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.

2019 FIRST QUARTER REPORT     13

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

For the purposes of ANE, gains and losses on derivatives are reported based on the difference between the effective hedge rate of the contracts designated for use in the particular period and the exchange rate at the time of settlement. This results in an adjustment to current period IFRS earnings to effectively remove reported gains and losses on derivatives that arise from contracts put in place for use in future periods. The effective hedge rate will lag the market in periods of rapid currency movement. See Non-IFRS measures on page 8.

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

At March 31, 2019:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.33 (Cdn), down from $1.00 (US) for $1.36 (Cdn) at December 31, 2018. The exchange rate averaged $1.00 (US) for $1.33 (Cdn) over the quarter.

• The mark-to-market position on all foreign exchange contracts was a $30 million loss compared to a $53 million loss at December 31, 2018.

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

Outlook for 2019

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

Our outlook for 2019 reflects the expenditures necessary to help us achieve our strategy. We have made significant progress in reducing our administration, exploration and operating costs, as well as our capital expenditures. We have also made a number of strategic decisions that come with significant costs in the near term, costs we factored into our decisions. As a result, and based on what we know today, from a gross profit point of view, 2019 is expected to be a weaker year for us. The changing pricing terms under our existing contract portfolio and the proportion of purchased material compared to produced material making up our uranium supply are expected to adversely impact our revenue and cost of sales in 2019 relative to 2018. In addition, our outlook for the average unit cost of sales in 2019 continues to be impacted by care and maintenance costs, which, although lower than in 2018, are expected to be between $130 million and $160 million. Despite the impact on our expected results, we continue to believe these are the right decisions to create long-term shareholder value.

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

We report our results and outlook based on a calendar-year view, at a point in time. However, under our marketing framework, we plan on a rolling 12-month basis, which means our sales, inventory and purchases are all variables. Therefore, in accordance with market opportunities and as the year unfolds, we expect our actual sales, purchases and inventory will vary from what we are reporting in the 2019 Financial Outlook table. Also, in 2019, there is a greater risk of production variability due to the expiry of Orano’s collective agreement with unionized employees at the McClean Lake mill on May 31, 2019.

14     CAMECO CORPORATION

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

• the results of the investigation under the Section 232 Trade Expansion Act in the US, and the impact, if any, on the uranium market and uranium prices

• a potential award for damages from the TEPCO arbitration panel

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

Our outlook for average realized price and unit cost of sales have changed as a result of the change in the uranium spot price. The average realized price for our uranium segment is now expected to be $44.20 per pound (previously $46.10 per pound) while our average unit cost of sales is expected to range between $39.50 and $41.50 per pound (previously between $41.00 and $43.00 per pound). In addition, we now anticipate an average purchase price of $34.80 per pound for both our committed and required purchases (previously $36.70 per pound as stated on page 48 of our 2018 annual report).

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales/delivery volumes and revenue can vary significantly. We are on track for our uranium sales/delivery targets in 2019, with deliveries weighed to the second half of the year.

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

2019 FINANCIAL OUTLOOK

	CONSOLIDATED			URANIUM			FUEL SERVICES
EXPECTED CONTRIBUTION TO GROSS PROFIT		100	%		66	%		34	%
Production (owned and operated properties)		—			9.0 million lbs			12 to 13 million kgU
Purchases		—			19 to 21 million lbs			—
Sales/delivery volume		—			28 to 30 million lbs			11 to 12 million kgU
Revenue	$	1,650-1,800 million		$	1,290-1,380 million		$	280-310 million
Average realized price		—		$	44.20/lb			—
Average unit cost of sales (including D&A)		—		$	39.50-41.50/lb		$	20.20-21.20/kgU
Direct administration costs	$	110-120 million			—			—
Exploration costs		—		$	13 million			—
Expected loss on derivatives - ANE basis	$	5-15 million			—			—
Tax expense - ANE basis	$	0-10 million			—			—
Capital expenditures	$	95 million			—			—

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

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

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

• Sales/delivery volume is based on the volumes we currently have commitments to deliver under contract in 2019.

• Uranium revenue and average realized price are based on a uranium spot price of $25.33 (US) per pound (the UxC spot price as of March 25, 2019), a long-term price indicator of $32.00 (US) per pound (the UxC long-term indicator on March 25, 2019) and an exchange rate of $1.00 (US) for $1.30 (Cdn).

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

2019 FIRST QUARTER REPORT     15

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

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

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

In addition, the 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. For more information on how changes in the exchange rate or uranium prices can impact our outlook see Revenue, adjusted net earnings, and cash flow sensitivity analysis below, and Foreign exchange on page 13.

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

		IMPACT ON:
FOR 2019 ($ MILLIONS)	CHANGE	REVENUE			ANE			CASH FLOW
Uranium spot and term price1	$5(US)/lb increase		69			18			15
	$5(US)/lb decrease		(59	)		(11	)		(5	)
Value of Canadian dollar vs US dollar	One cent decrease in CAD		10			4			3
	One cent increase in CAD		(10	)		(4	)		(3	)

¹  Assuming change in both UxC spot price ($25.33 (US) per pound on March 25, 2019) and the UxC long-term price indicator ($32.00 (US) per pound on March 25, 2019)

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 March 31, 2019 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on March 31, 2019 and none of the assumptions we list below change.

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

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

SPOT PRICES ($US/lb U3O8)	$20		$40		$60		$80		$100		$120		$140
2020		30		40		53		63		72		79		86
2021		27		40		53		62		66		71		75
2022		28		40		54		63		67		71		74
2023		29		41		54		64		69		72		76

The table illustrates the mix of long-term contracts in our March 31, 2019 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to March 31, 2019, 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.

16     CAMECO CORPORATION

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 21 million pounds per year, with commitment levels in 2019 and 2020 higher than in 2021 through 2023.   •  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 20% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table will be higher.

Liquidity and capital resources

Our financial objective is to ensure we have the cash and debt capacity to fund our operating activities, investments and other financial obligations. As of March 31, 2019, we had cash and short-term investments of $1.2 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 2019 through 2023, we have commitments to deliver an average of 21 million pounds per year, with commitment levels in 2019 and 2020 higher than in 2021 through 2023.

In the currently weak uranium price environment, our focus is on preserving the value of our tier-one assets and reducing our operating, capital and general and administrative spending. We have a number of alternatives to fund future capital requirements, including using our operating cash flow, drawing on our existing credit facilities, entering new credit facilities, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. In addition, due to the deliberate cost reduction measures implemented over the past five years, the reduction in our dividend, and the drawdown of inventory in 2018 as a result of the suspension of production at our McArthur River/Key Lake operation, we have significant cash balances. We will continue to generate cash from operations however, it will not be as robust as in 2018 given the weaker expected results, and without the release of working capital associated with the inventory drawdown we had in 2018. We expect our cash balances and operating cash flows to meet our capital requirements during 2019, even if we decide to retire our $500 million debenture maturing in 2019.

We received a favourable ruling in our case with CRA for the 2003, 2005 and 2006 tax years. We expect the ruling to be upheld on appeal, and we believe the ruling should apply in principle to subsequent tax years. However, until such time as all appeals are exhausted, and a resolution is reached for all tax years in question, in accordance with Canadian income tax rules we may be required to remit or otherwise secure 50% of any cash taxes plus related interest and penalties CRA may continue to reassess, even though we believe there is no basis for them to do so. See page 10 for more information. In the above scenario, the table on page 13 provides the amount and timing of the cash taxes and transfer pricing penalties paid or secured to date. In addition, it provides an estimate of the amounts we would potentially have to pay or secure upfront if CRA continues to reassess us using the same methodology it reassessed the 2003 to 2012 tax years. The timing of these amounts is uncertain.

CASH FROM/USED IN OPERATIONS

Cash provided by operations was $195 million lower this quarter than in the first quarter of 2018 mainly due to an increase in working capital requirements, which provided $105 million less in 2019 than in 2018. Not including working capital requirements, our operating cash flows this quarter were lower by $90 million.

2019 FIRST QUARTER REPORT     17

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 March 31, 2019, unchanged from December 31, 2018. At March 31, 2019, we had approximately $1.6 billion outstanding in financial assurances, unchanged from December 31, 2018. At March 31, 2019, we had no short-term debt outstanding on our $1.25 billion unsecured revolving credit facility, unchanged from December 31, 2018.

Long-term contractual obligations

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

Debt covenants

We are bound by certain covenants in our unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at March 31, 2019, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2019 to be constrained by them.

OFF-BALANCE SHEET ARRANGEMENTS

We had two kinds of off-balance sheet arrangements at March 31, 2019:

• purchase commitments

• financial assurances

Purchase commitments

We make purchases under long-term contracts where it is beneficial for us to do so and in order to support our long-term contract portfolio. The following table is based on our purchase commitments in our uranium and fuel services segments, as well as commitments previously contracted by NUKEM, at March 31, 2019² but does not include purchases of our share of Inkai production. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

MARCH 31 ($ MILLIONS)	2019		2020 AND 2021		2022 AND 2023		2024 AND BEYOND		TOTAL
Purchase commitments1,2		229		207		133		329		898

¹  Denominated in US dollars and Japanese yen, as of March 31, 2019 converted from US dollars to Canadian dollars at the rate of $1.30 and from Japanese yen to Canadian dollars at the rate of $0.01.

²  These amounts have been adjusted for any additional purchase commitments that we have entered into since March 31, 2019, but does not include deliveries taken under contract since March 31, 2019.

Our purchase commitments of about $898 million include the following:

• approximately 21 million pounds of U₃O₈ equivalent from 2019 to 2028

• approximately 0.1 million kgU as UF₆ in conversion services in 2019

• about 0.1 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions. For more information on our purchasing activity, see Strategy in action starting on page 4.

Financial assurances

At March 31, 2019, our financial assurances totalled $1.6 billion, unchanged from December 31, 2018.

18     CAMECO CORPORATION

BALANCE SHEET

($ MILLIONS)	MAR 31, 2019		DEC 31, 2018		CHANGE
Cash, cash equivalents and short-term investments		1,221		1,103		11	%
Total debt		1,496		1,496		—
Inventory		638		468		36	%

Total cash, cash equivalents and short-term investments at March 31, 2019 were $1.2 billion, or 11% higher than at December 31, 2018, primarily due to cash from operations of $80 million, a decrease in long-term receivables of $66 million, partially offset by capital expenditures of $10 million, and interest payments of $15 million. Net debt at March 31, 2019 was $275 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 first quarter of 2019 we received distributions of $50 million (US), which were made as loan and interest repayments. As of March 31, 2019, the outstanding principal balance of the loan was $42 million (US).

Total product inventories increased to $638 million. Inventories temporarily increased as sales were lower than production and purchases in the first three months of the year. We expect our quarterly distribution of uranium deliveries in 2019 to be weighted to the second half of the year. The average cost for uranium has increased to $34.20 per pound compared to $33.05 per pound at December 31, 2018. As of March 31, 2019, we held an inventory of 12.5 million pounds of U₃O₈ equivalent in our uranium segment (excluding broken ore).

Financial results by segment

Uranium

		THREE MONTHS ENDED MARCH 31
HIGHLIGHTS		2019			2018		CHANGE
Production volume (million lbs)			2.4			2.4		—
Sales volume (million lbs)			4.8			6.6		(27	)%
Average spot price	($US/lb)		27.41			21.43		28	%
Average long-term price	($US/lb)		32.00			29.50		8	%
Average realized price	($US/lb)		32.05			42.92		(25	)%
	($Cdn/lb)		42.80			54.13		(21	)%
Average unit cost of sales (including D&A)	($Cdn/lb)		43.44			42.41		2	%
Revenue ($ millions)			207			359		(42	)%
Gross profit (loss) ($ millions)			(3	)		78		(104	)%
Gross profit (loss) (%)			(1	)		22		(105	)%

FIRST QUARTER

Production volumes this quarter were unchanged compared to the first quarter of 2018. See Uranium 2019 Q1 updates starting on page 22 for more information.

Uranium revenues this quarter were down 42% compared to 2018 due to a decrease in sales volumes of 27% and a decrease of 21% in the Canadian dollar average realized price. Sales volumes declined compared to the same period last year due to the restructuring of an agreement with one of our utility customers last year which advanced the majority of deliveries under that contract into the first quarter of 2018. While the average spot price for uranium increased by 28% compared to the same period in 2018, our average realized price decreased due to high-priced deliveries being advanced into the first quarter last year.

Total cost of sales (including D&A) decreased by 25% ($210 million compared to $281 million in 2018) as a result of a 27% decrease in sales volume partially offset by a unit cost of sales that was 2% higher than the same period last year. The increase in the unit cost of sales was due mainly to the cost of our purchases having increased from the first quarter in 2018.

The net effect was an $81 million decrease in gross profit for the quarter.

Equity earnings from investee, JV Inkai, were $12 million in the first quarter compared to $1 million in same period last year.

2019 FIRST QUARTER REPORT     19

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 MARCH 31
($CDN/LB)	2019		2018		CHANGE
Produced
Cash cost		14.43		18.30		(21	)%
Non-cash cost		15.89		17.27		(8	)%
Total production cost 1		30.32		35.57		(15	)%
Quantity produced (million lbs)1		2.4		2.4		—
Purchased
Cash cost1		37.03		36.55		1	%
Quantity purchased (million lbs)1		7.2		1.7		324	%
Totals
Produced and purchased costs		35.35		35.98		(2	)%
Quantities produced and purchased (million lbs)		9.6		4.1		134	%

¹  Our share of Inkai production was 0.8 million pounds for the quarter. Due to equity accounting, our share of production is shown as a purchase at the time of delivery. JV Inkai purchases will fluctuate during the quarters and timing of purchases will not match production. In the first quarter we purchased 0.5 million pounds at a purchase price per pound of $36.84 ($27.39 (US)).

The average cash cost of production this quarter was 21% lower than the comparable period in 2018 due to production coming only from Cigar Lake this quarter while last year in the same period there was a small amount of higher-cost production from the suspended McArthur River and US operations. While McArthur River and Key Lake are shut down, our cash cost of production is expected to be reflective of the estimated life-of-mine operating cost, between $15 and $16 per pound, of mining and milling our share of Cigar Lake mineral reserves.

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

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. The average cash cost of purchased material in US dollar terms was $27.77 (US) per pound this quarter, compared to $28.93 (US) per pound in the first quarter of 2018. In addition, in the first quarter of 2019, the exchange rate on purchases averaged $1.00 (US) for $1.33 (Cdn), compared to $1.00 (US) for $1.26 (Cdn) in the first quarter of 2018. As a result, the average cash cost of purchased material in Canadian dollar terms increased by 1% this quarter compared to the same period 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 first quarter of 2019 and 2018.

20     CAMECO CORPORATION

Cash and total cost per pound reconciliation
	THREE MONTHS
	ENDED MARCH 31
($ MILLIONS)	2019			2018
Cost of product sold		181.2			231.7
Add / (subtract)
Royalties		(3.0	)		(12.2	)
Care and maintenance costs		(28.2	)		(41.9	)
Other selling costs		(3.0	)		(4.3	)
Change in inventories		154.2			(67.2	)
Cash operating costs (a)		301.2			106.1
Add / (subtract)
Depreciation and amortization		28.9			49.6
Care and maintenance costs		(11.1	)		(6.9	)
Change in inventories		20.4			(1.3	)
Total operating costs (b)		339.4			147.5
Uranium produced & purchased (million lbs) (c)		9.6			4.1
Cash costs per pound (a ÷ c)		31.38			25.88
Total costs per pound (b ÷ c)		35.35			35.98

Fuel services
(includes results for UF6, UO2 and fuel fabrication)
		THREE MONTHS
		ENDED MARCH 31
HIGHLIGHTS		2019		2018		CHANGE
Production volume (million kgU)			3.8		3.9		(3	)%
Sales volume (million kgU)			3.0		2.4		25	%
Average realized price	($Cdn/kgU)		27.26		26.60		2	%
Average unit cost of sales (including D&A)	($Cdn/kgU)		20.55		21.56		(5	)%
Revenue ($ millions)			83		64		30	%
Gross profit ($ millions)			20		12		67	%
Gross profit (%)			24		19		26	%

FIRST QUARTER

Total revenue for the first quarter of 2019 increased to $83 million from $64 million for the same period last year. This was primarily due to a 25% increase in sales volumes as well as a 2% increase in average realized price compared to 2018. 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 fuel bundles.

The total cost of products and services sold (including D&A) increased 19% ($62 million compared to $52 million in 2018) due to the 25% increase in sales volume, partially offset by a 5% decrease in the average unit cost of sales due to lower costs for UF₆.

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

2019 FIRST QUARTER REPORT     21

Our operations

Uranium – production overview

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

URANIUM PRODUCTION
	THREE MONTHS
	ENDED MARCH 31
OUR SHARE (MILLION LBS)	2019		2018		CHANGE			2019 PLAN
McArthur River/Key Lake		—		0.1		(100	)%		—
Cigar Lake		2.4		2.2		9	%		9.0
US ISR		—		0.1		(100	)%		—
Total		2.4		2.4		—			9.0

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

Uranium 2019 Q1 updates

PRODUCTION UPDATE

McArthur River/Key Lake

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

In the first quarter, we filed a technical report for the McArthur River operation under Canadian Securities Administrators’ National Instrument 43-101, which reflects a significant improvement in economics since the last report in 2012, and highlights the value this asset is expected to create when it comes back into operation. Key highlights of the report include:

• increase in mineral reserve estimate at December 31, 2018 of 9.1% compared to December 31, 2017

• estimated mine life of 23 years based on a production rate of 18 million pounds U₃O₈ per year upon production restart

• estimated capital cost for the McArthur River and Key Lake operations of $658 (our share) million compared to $2.5 billion (our share) in the 2012 technical report

• estimated average operating costs per pound of $14.97 per pound U₃O₈ over the mine life ($19.23 per pound in the 2012 technical report)

• estimated capital expenditures in year of restart of approximately $8 million at McArthur River and $30 million at Key Lake will be required to replace equipment and return processing circuits to their full production capabilities

• estimated to take a minimum of nine months to complete critical projects, maintenance readiness checks, and sufficient recruitment and training before mine and mill will restart

• assumes in year one, work to restart operations commences on January 1 with approximately 4 million pounds of production in that year, and assumes in years two through 21, 18 million pounds of annual production, with rampdown of production in years 22 and 23

• estimated cash operating and capital costs to maintain both operations during the production suspension shutdown of between $6 million and $7 million per month (our share)

Caution about forward-looking information relating to the McArthur River technical report

This discussion of the key highlights of the McArthur River technical report is forward-looking information, and actual results could vary significantly. Material risks that could lead to different results include: the risk that our expectations regarding the value of this asset prove incorrect; mineral reserves are lower than estimated; actual mine life is shorter than expected; anticipated production rates cannot be achieved; required capital costs and operating costs are higher than expected, either during the shutdown or after operation resumes; and that it takes longer than expected to restart the mine and mill. In presenting this forward-looking information, we have made material assumptions, including assumptions about the value of this asset; mineral reserves; mine life; production rates; capital and operating costs; and the timing requirements for resuming operation. Other material risks and assumptions are identified in sections 24.4 and 24.5 of the technical report, elsewhere in this MD&A and in our annual MD&A and annual information form.

22     CAMECO CORPORATION

The collective bargaining agreement between Cameco and the United Steelworkers Local 8914 expired December 31, 2017. Following the requirements of the Canada Labour Code, as of May 4, 2019, either party could be in a position to effect a work stoppage (strike or lockout). There are approximately 100 unionized employees working at Key Lake and McArthur River.

Cigar Lake

Total production from Cigar Lake was 9% higher in the first quarter compared to the same period last year. Production remains on track to meet our forecast for the year.

The collective agreement between Orano and unionized employees at the McClean Lake mill expires on May 31, 2019. There is a risk to the production plan if Orano is unable to reach an agreement and there is a labour dispute.

Inkai

Production on a 100% basis was 2 million pounds for the quarter. Production is tracking higher than the comparable period in 2018 due to an increase in planned production in 2019. Due to the transition to equity accounting in 2018, our share of production will be shown as a purchase at a discount to the spot price and included in inventory at this value at the time of delivery. Our share of the profits earned by JV Inkai on the sale of its production will be included in “share of earnings from equity-accounted investee” on our consolidated statement of earnings.

TIER-TWO CURTAILED OPERATIONS

US ISR Operations

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

Rabbit Lake

Rabbit Lake continues in a safe state of care and maintenance. As a result, there was no production in the first quarter of 2019. 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.

Fuel services 2019 Q1 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 3.8 million kgU in the first quarter, 3% lower than the same period last year due to the timing of scheduled production.

The collective agreement with unionized employees at our conversion facility in Port Hope expires on June 30, 2019. There is a risk to our production plans if we are unable to reach an agreement and there is a labour disruption.

Qualified persons

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

  MCARTHUR RIVER/KEY LAKE   •  Linda Bray, principal metallurgist, technical services, Cameco   •  Greg Murdock, general manager, McArthur River/Key Lake, Cameco   •  Alain D. Renaud, lead geologist, technical services, Cameco CIGAR LAKE   •  Lloyd Rowson, general manager, Rabbit Lake/Cigar Lake, Cameco   INKAI •  Dr. Darryl Clark, consultant geologist

2019 FIRST 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 March 31, 2019, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of March 31, 2019, the CEO and CFO concluded that:

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

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

During the first quarter, we implemented a new marketing system resulting in a material change in internal controls over financial reporting. The new system provides for contract administration, including the processing and recording of delivery obligations as well as revenue forecasting and reporting. The implementation process included extensive involvement by key end users and management and incorporated user acceptance testing, change management procedures, data migration strategies and a parallel run period where users validated the new system. Post-implementation reviews and testing were conducted by management to ensure that internal controls surrounding the implementation process are properly designed to prevent material financial statement errors.

There have been no other changes in our internal control over financial reporting during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

New standards and interpretations

The following new standard was required to be applied for our accounting periods beginning on or after January 1, 2019. This standard did not have a material impact on the interim financial statements.

• IFRS 16, Leases, eliminates the dual model for lessees, which distinguishes between on-balance sheet finance leases and off-balance sheet operating leases. Instead, there is a single, on-balance sheet accounting model that is similar to current finance lease accounting. We adopted IFRS 16 using the modified retrospective approach which does not require comparative information to be restated.

• IFRIC 23, Uncertainty over Income Tax Treatments, provides guidance on the accounting for current and deferred tax liabilities and assets in circumstances in which there is uncertainty over income tax treatments. The adoption of the standard did not have a material impact on the financial statements.

A number of new standards, interpretations and amendments to existing standards are not yet effective for the year ended December 31, 2019, and have not been applied in preparing these interim financial statements. Please refer to our 2018 annual MD&A for a brief description of each accounting pronouncement.

24     CAMECO CORPORATION