EX-99.2 3 d553910dex992.htm EX-99.2

EX-99.2

Exhibit 99.2

Management’s discussion and analysis

for the quarter ended March 31, 2018

4 FIRST QUARTER MARKET UPDATE

7 CONSOLIDATED FINANCIAL RESULTS

14 OUTLOOK FOR 2018

16 LIQUIDITY AND CAPITAL RESOURCES

17 FINANCIAL RESULTS BY SEGMENT

20 OUR OPERATIONS - FIRST QUARTER UPDATES

21 QUALIFIED PERSONS

21 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, 2018 (interim financial statements). The information is based on what we knew as of April 26, 2018 and updates our 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, 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 heading Our strategy

• our expectations about 2018 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 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 quarterly uranium deliveries and quarterly average realized prices for the remainder of 2018

• our price sensitivity analysis for our uranium segment

• our expectations regarding 2018 cash flow, and that existing cash balances and operating cash flows will meet our anticipated 2018 capital requirements

• our expectation that our operating and investment activities for the remainder of 2018 will not be constrained by the financial-related covenants in our unsecured revolving credit facility

• our future plans and expectations for each of our uranium operating properties and fuel services operating sites, including production levels

• our expectations related to care and maintenance costs

• our plans regarding consideration of the payment of a dividend

• the expected date for repayment of the product provided to Orano

• the impact of our transition to equity accounting on reporting of our share of JV Inkai’s production

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 our cost reduction strategies are unsuccessful, or necessary supplies are not available, or not available on commercially reasonable terms

• 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

• 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

• the necessary permits or approvals from government authorities are not obtained or maintained

• our McArthur River and/or 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 after the extended Cigar Lake shutdown scheduled for the third quarter

• any difficulties in resuming McArthur River production after the end of the production suspension including as a result of failure to reach a new collective agreement

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

• 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 (including at Cameco Fuel Manufacturing Inc. (CFM)), underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, unanticipated consequences of our cost reduction strategies, or other development and operating risks

Material assumptions

• our expectations regarding sales and purchase volumes and prices for uranium and fuel services, trade restrictions and that 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 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 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 McArthur River development, mining and production plans succeed, including the resumption of production after the end of the production suspension

• 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 CFM), 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

2018 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.

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.

In accordance with market conditions, and to mitigate risk, we evaluate the optimal mix of our production, inventory and purchases in order to satisfy our contractual commitments and in order to return the best value possible. We have temporarily suspended production at our McArthur River/Key Lake operation, which we expect will remove 18 million pounds of uranium from the market in 2018. And, in addition to our purchase commitments, we intend to be active buyers in the spot market. This activity may mean we give up some margin at times, however, we believe it will provide us with the supply flexibility we need to meet our sales commitments and will allow us to preserve the value of our tier-one assets.

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.

First quarter market update

There were several notable announcements in the uranium market in the first quarter. On the supply side, the US Department of Energy suspended excess uranium sales for the remainder of 2018, with the possibility of an extension. Demand news was mixed. China confirmed construction on another six to eight units will commence this year, and India and the Middle East added to their plans for nuclear with additional construction targets. In addition, Japan reactor restarts continued to progress during the quarter. There are now seven reactors that have restarted in Japan, including one that is not currently operating. However, the positive news this quarter was tempered by potential reactor closures announced in the US and a phase out announced in Belgium.

As a result, and despite previous supply curtailment announcements, the market was at a stand-still in the first quarter of 2018. Prices remained low, as the market continues to digest the changing market dynamics, including the implications of possible US trade action under section 232 of the Trade Expansion Act and review of the Russian Suspension Agreement. Further uncertainty was raised in April, with Russia considering a ban on uranium supplied to the US as retaliation to US imposed sanctions.

Longer term, uranium demand is backed by steady reactor growth with 55 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.

4    CAMECO CORPORATION

Industry prices at quarter end

		MAR 31 2018				DEC 31 2017				SEP 30 2017				JUN 30 2017				MAR 31 2017				DEC 31 2016
Uranium ($US/lb U3O8)1
Average spot market price			21.05				23.75				20.33				20.15				23.88				20.25
Average long-term price			29.00				31.00				30.50				33.00				33.00				30.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America			6.68				5.80				4.55				5.13				5.93				5.93
Europe			6.93				6.13				4.93				5.50				6.45				6.45
Average long-term price
North America			12.25				13.00				14.50				14.50				13.50				12.50
Europe			12.25				13.00				14.25				14.25				14.00				13.00

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 first quarter of 2018 was approximately 13.5 million pounds, compared to ten million pounds in the first quarter of 2017. At the end of the quarter, the average reported spot price was $21.05 (US) per pound, down $2.70 (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 2018 was over ten million pounds compared to 28 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, down $2.00 (US) from last quarter.

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

Shares and stock options outstanding

At April 26, 2018, we had:

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

• 9,091,982 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.

Also of note:

JV INKAI RESTRUCTURING GAIN

As outlined in the previously disclosed implementation agreement dated May 27, 2016, the restructuring of JV Inkai with Kazatomprom and JV Inkai closed and took effect on January 1, 2018. Our ownership interest in JV Inkai is now 40% and Kazatomprom’s is 60%. As a result of the restructuring we have recognized a gain on the change in ownership interests of $49 million. The gain was lower than originally reported in our annual MD&A (which was approximately $66 million) due to the finalization of the treatment of certain intercompany balances. See note 6 for more information.

PORTFOLIO OPTIMIZATION

As part of our ongoing efforts to optimize our contract portfolio and convert uncertain future value into certain present value, we restructured an agreement with one of our utility customers. The restructuring advanced the majority of contract deliveries into the first quarter of 2018 and displaced a small amount of future uranium and conversion deliveries, resulting in a gain of $6 million being recognized.

2018 FIRST QUARTER REPORT    5

PRODUCT ARRANGEMENT

As a result of the decision to temporarily suspend production at the McArthur River mine, we have entered into an agreement with our joint venture partner Orano to provide them up to 5.4 million pounds of uranium concentrate through 2018. The product is deliverable in 12 equal monthly instalments of 450,000 pounds. Orano is not obligated to take delivery but must provide 30 days’ notice prior to the upcoming delivery date if they do not wish to take that delivery. Orano is obligated to repay us in kind with uranium concentrate no later than December 31, 2021. At March 31, 2018, we had provided 1.35 million pounds under this agreement. See note 5 for more information.

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.

In addition, NUKEM is no longer a reportable segment and as such will be included in our consolidated results and in our “other” category in our segmented note. Please see note 18 for more information.

Consolidated financial results

		THREE MONTHS
HIGHLIGHTS		ENDED MARCH 31
($ MILLIONS EXCEPT WHERE INDICATED)		2018				2017				CHANGE
Revenue			439				393				12	%
Gross profit			68				55				24	%
Net earnings (losses) attributable to equity holders			55				(18	)			>100	%
$ per common share (basic)			0.14				(0.05	)			>100	%
$ per common share (diluted)			0.14				(0.05	)			>100	%
Adjusted net earnings (losses) (non-IFRS, see page 8)			23				(29	)			>100	%
$ per common share (adjusted and diluted)			0.06				(0.07	)			>100	%
Cash provided by (used in) operations (after working capital changes)			275				(8	)			>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 first quarter of 2018, compared to the first quarter of 2017.

				THREE MONTHS
				ENDED MARCH 31
($ MILLIONS)				IFRS				ADJUSTED
Net losses – 2017					(18	)			(29	)
Change in gross profit by segment
(We calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)
Uranium		Higher sales volume			7				7
		Higher realized prices ($US)			78				78
		Foreign exchange impact on realized prices			(21	)			(21	)
		Higher costs			(31	)			(31	)
		Change – uranium			33				33
Fuel services		Higher sales volume			7				7
		Lower realized prices ($Cdn)			(16	)			(16	)
		Lower costs			7				7
		Change – fuel services			(2	)			(2	)
Other changes
Lower administration expenditures					6				6
Lower exploration expenditures					2				2
Change in reclamation provisions					5				—
Higher earnings from equity-accounted investee					1				1
Change in gains or losses on derivatives					(40	)			4
Change in foreign exchange gains or losses					9				9
Gain on restructuring of JV Inkai					49				—
Gain on customer contract restructuring in 2018					6				6
Change in income tax recovery or expense					11				—
Other					(7	)			(7	)
Net earnings – 2018					55				23

See Financial results by segment beginning on page 17 for more detailed discussion.

2018 FIRST 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 NUKEM purchase price inventory recovery, 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 first quarter of 2018 and compares it to the same period in 2017.

		THREE MONTHS
		ENDED MARCH 31
($ MILLIONS)		2018				2017
Net earnings (losses) attributable to equity holders			55				(18	)
Adjustments
Adjustments on derivatives			22				(22	)
Reclamation provision adjustments			1				6
Gain on restructuring of JV Inkai			(49	)			—
Income taxes on adjustments			(6	)			5
Adjusted net earnings (losses)			23				(29	)

Quarterly trends

HIGHLIGHTS		2018				2017																2016
($ MILLIONS EXCEPT PER SHARE AMOUNTS)		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
Revenue			439				809				486				470				393				887				670				466
Net earnings (losses) attributable to equity holders			55				(62	)			(124	)			(2	)			(18	)			(144	)			142				(137	)
$ per common share (basic)			0.14				(0.16	)			(0.31	)			(0.00	)			(0.05	)			(0.36	)			0.36				(0.35	)
$ per common share (diluted)			0.14				(0.16	)			(0.31	)			(0.00	)			(0.05	)			(0.36	)			0.36				(0.35	)
Adjusted net earnings (losses) (non-IFRS, see page 8)			23				181				(50	)			(44	)			(29	)			90				118				(57	)
$ per common share (adjusted and diluted)			0.06				0.46				(0.13	)			(0.11	)			(0.07	)			0.23				0.30				(0.14	)
Cash provided by (used in) operations (after working capital changes)			275				320				154				130				(8	)			255				385				(51	)

Key things to note:

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

8    CAMECO CORPORATION

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

HIGHLIGHTS		2018				2017																2016
($ MILLIONS EXCEPT PER SHARE AMOUNTS)		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
Net earnings (losses) attributable to equity holders			55				(62	)			(124	)			(2	)			(18	)			(144	)			142				(137	)
Adjustments
Adjustments on derivatives			22				(2	)			(40	)			(44	)			(22	)			23				(27	)			(10	)
NUKEM purchase price inventory recovery			—				—				—				—				—				—				—				(6	)
Impairment charges			—				247				111				—				—				238				—				124
Reclamation provision adjustments			1				15				(9	)			(12	)			6				(28	)			(6	)			—
Gain on restructuring of JV Inkai			(49	)			—				—				—				—				—				—				—
Income taxes on adjustments			(6	)			(17	)			12				14				5				1				9				(28	)
Adjusted net earnings (losses) (non-IFRS, see page 8)			23				181				(50	)			(44	)			(29	)			90				118				(57	)

Corporate expenses

ADMINISTRATION

		THREE MONTHS
		ENDED MARCH 31
($ MILLIONS)		2018				2017				CHANGE
Direct administration			29				35				(17	)%
Stock-based compensation			6				6				—
Total administration			35				41				(15	)%

Direct administration costs were $6 million lower for the first quarter of 2018 compared to the same period last year due mainly to changes to our global marketing structure and other cost reductions.

EXPLORATION

In the first quarter, uranium exploration expenses were $8 million, a decrease of $2 million compared to the first quarter of 2017 due to a planned reduction in expenditures.

INCOME TAXES

We recorded an income tax recovery of $7 million in the first quarter of 2018, compared to an expense of $4 million in the first quarter of 2017.

On an adjusted basis, we recorded an income tax recovery of $1 million this quarter compared to a recovery of $1 million in the first quarter of 2017. In 2018, we recorded losses of $42 million in Canada compared to losses of $1 million in 2017, while we recorded earnings of $64 million in foreign jurisdictions compared to losses of $29 million last year.

		THREE MONTHS
		ENDED MARCH 31
($ MILLIONS)		2018				2017
Pre-tax adjusted earnings1
Canada			(42	)			(1	)
Foreign			64				(29	)
Total pre-tax adjusted earnings			22				(30	)
Adjusted income taxes1
Canada			(5	)			(1	)
Foreign			4				—
Adjusted income tax recovery			(1	)			(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).

2018 FIRST QUARTER REPORT    9

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.

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 March 31, 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

10    CAMECO CORPORATION

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 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.

$ 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 March 31, 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 have been 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 12 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.

2018 FIRST QUARTER REPORT    11

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.

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, 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.

12    CAMECO CORPORATION

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 period of rapid currency movement. See Non-IFRS measures on page 8.

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

At March 31, 2018:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.29 (Cdn), up from $1.00 (US) for $1.25 (Cdn) at December 31, 2017. The exchange rate averaged $1.00 (US) for $1.26 (Cdn) over the quarter.

• The mark-to-market position on all foreign exchange contracts was a $1 million gain compared to a $34 million gain at December 31, 2017.

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

2018 FIRST QUARTER REPORT    13

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 12. 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 uranium production 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 17 for details.

2018 FINANCIAL OUTLOOK

		CONSOLIDATED				URANIUM				FUEL SERVICES
EXPECTED CONTRIBUTION TO GROSS PROFIT		100%				85%				15%
Production (owned and operated properties)			—				9.2 million lbs				9 to 10 million kgU
Purchases			—				8 to 9 million lbs	1			—
Sales/delivery volume2			—				32 to 33 million lbs	3			11 to 12 million kgU
Revenue 2		$	1,800-1,930 million			$	1,460-1,550 million	4		$	280-310 million
Average realized price3			—			$	46.30/lb	4			—
Average unit cost of sales (including D&A)			—			$	38.00-40.00/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		$	90 million				—				—

¹  Based on the volumes we currently have commitments to acquire under contract in 2018. This includes our JV Inkai purchases.

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 $21.10 (US) per pound (the Ux spot price as of March 26, 2018), a long-term price indicator of $30.00 (US) per pound (the Ux long-term indicator on March 26, 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. See page 9 for more information.

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.

We now expect our annual uranium production to be 9.2 million lbs (previously 9.1 million lbs) as a result of slightly higher than anticipated production during the curtailment of existing wellfields at the US ISR Operations.

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, we expect cash flow in 2018 to be similar to 2017.

14    CAMECO CORPORATION

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.

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			47				28				37
		$5(US)/lb decrease			(47	)			(27	)			(36	)
Value of Canadian dollar vs US dollar		One cent decrease in CAD			10				3				3
		One cent increase in CAD			(10	)			(3	)			(3	)

¹  Assuming change in both UxC spot price ($21.10 (US) per pound on March 26, 2018) and the UxC long-term price indicator ($30.00 (US) per pound on March 26, 2018)

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, 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 March 31, 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				65				74				81				87
2020			30				41				55				64				73				81				87
2021			27				41				55				66				75				84				92
2022			26				41				56				66				75				85				94

The table illustrates the mix of long-term contracts in our March 31, 2018 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to March 31, 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 22 million pounds per year, with commitment levels in 2018 through 2020 higher than in 2021 and 2022

• excludes sales between our uranium, fuel services and NUKEM 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.

2018 FIRST QUARTER REPORT    15

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 2018, we had cash and short-term investments of $813 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 22 million pounds per year, with commitments levels in 2018 through 2020 higher than in 2021 and 2022.

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 temporary 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 will 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 11.

CASH FROM/USED IN OPERATIONS

Cash provided by operations was $283 million higher this quarter than in the first quarter of 2017. Contributing to this change was a higher gross profit in our uranium segment and a decrease in income taxes paid. In addition, there was a decrease in working capital requirements, which provided $199 million more in 2018 than in 2017. Not including working capital requirements, our operating cash flows this quarter were higher by $84 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 March 31, 2018, up from $2.9 billion at December 31, 2017. At March 31, 2018, we had approximately $1.6 billion outstanding in financial assurances, up from $1.5 billion at December 31, 2017. At March 31, 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 March 31, 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 March 31, 2018:

• purchase commitments

• financial assurances

• other arrangements

Financial assurances

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

16    CAMECO CORPORATION

Other arrangements

We continue to use factoring and other third party arrangements to manage short-term cash flow fluctuations. You can read more about these arrangements in our 2017 annual MD&A.

BALANCE SHEET

($ MILLIONS)		MAR 31, 2018				DEC 31, 2017				CHANGE
Cash and cash equivalents			813				592				37	%
Total debt			1,495				1,494				—
Inventory			870				950				(8	)%

Total cash and cash equivalents at March 31, 2018 were $813 million, or 37% higher than at December 31, 2017, primarily due to cash from operations of $275 million, partially offset by capital expenditures of $15 million, 2017 dividend payments of $40 million, and interest payments of $14 million. Net debt at March 31, 2018 was $682 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 2018 we received distributions of $9.1 million (US), which was made as a loan repayment, and as of March 31, 2018, the outstanding principal balance of the loan was $109 million (US).

Total product inventories decreased to $870 million. Inventories decreased as sales were higher than production and purchases in the first three months of the year. In addition, the product provided to Orano contributed to the decrease. The average cost for uranium has increased to $32.11 per pound compared to $30.72 per pound at December 31, 2017. As of March 31, 2018, we held an inventory of 21 million pounds of U₃O₈ equivalent in our uranium segment (excluding broken ore).

Financial results by segment

Uranium

				THREE MONTHS
				ENDED MARCH 31
HIGHLIGHTS				2018				2017				CHANGE
Production volume (million lbs)					2.4				6.7				(64)%
Sales volume (million lbs)1					6.6				5.7				16%
Average spot price		($US/lb)			21.43				23.79				(10)%
Average long-term price		($US/lb)			29.50				32.83				(10)%
Average realized price		($US/lb)			42.92				34.43				25%
		($Cdn/lb)			54.13				45.51				19%
Average unit cost of sales (including D&A)		($Cdn/lb)			42.41				37.72				12%
Revenue ($ millions)1					359				260				38%
Gross profit ($ millions)					78				44				77%
Gross profit (%)					22				17				29%

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

FIRST QUARTER

Production volumes this quarter were 64% lower compared to the first quarter of 2017, mainly due to lower production from McArthur River/Key Lake as the operations moved into care and maintenance and a change in reporting for JV Inkai. See Uranium 2018 Q1 updates starting on page 20 for more information.

Uranium revenues this quarter were up 38% compared to 2017 due to an increase of 19% in the Canadian dollar average realized price and increase in sales volumes of 16%. While the average spot price for uranium declined by 10% compared to the same period in 2017, our average realized price increased due to higher prices on fixed price contracts. The increase in sales volume in the quarter 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.

Total cost of sales (including D&A) increased by 30% ($281 million compared to $216 million in 2017) as a result of unit cost of sales that was 12% higher than the same period last year and a 16% increase in sales volume. The increase in the unit cost of sales was due mainly to increased costs associated with the temporary suspension of production at our McArthur River/Key Lake operation. The cost of our purchases have decreased from the first quarter in 2017.

2018 FIRST QUARTER REPORT    17

The net effect was a $34 million increase in gross profit for the quarter.

Equity earnings from investee, JV Inkai, were $1 million in the first quarter.

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)		2018				2017				CHANGE
Produced
Cash cost			18.30				14.54				26	%
Non-cash cost			17.27				10.34				67	%
Total production cost 1			35.57				24.88				43	%
Quantity produced (million lbs)1			2.4				6.7				(64	)%
Purchased
Cash cost1			36.55				41.47				(12	)%
Quantity purchased (million lbs)1			1.7				1.8				(6	)%
Totals
Produced and purchased costs			35.98				28.39				27	%
Quantities produced and purchased (million lbs)			4.1				8.5				(52	)%

¹  Our share of Inkai production was 0.7 million pounds for the quarter. 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 first quarter we purchased 14,080 pounds at a purchase price per pound of $28.49 ($22.31 (US)).

The average cash cost of production this quarter was 26% higher than the comparable period in 2017, primarily due to lower production from McArthur River/Key Lake as the operations moved into care and maintenance.

The other item affecting this table in the quarter 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. The average cash cost of purchased material in US dollar terms was $28.93 (US) per pound this quarter, compared to $31.34 (US) per pound in the first quarter of 2017. In addition, in the first quarter of 2018, the exchange rate on purchases averaged $1.00 (US) for $1.26 (Cdn), compared to $1.00 (US) for $1.32 (Cdn) in the first quarter of 2017. As a result, the average cash cost of purchased material in Canadian dollar terms decreased by 12% 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.

18    CAMECO CORPORATION

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 2018 and 2017.

Cash and total cost per pound reconciliation

		THREE MONTHS
		ENDED MARCH 31
($ MILLIONS)		2018				2017
Cost of product sold			231.7				182.1
Add / (subtract)
Royalties			(12.2	)			(10.2	)
Care and maintenance costs			(41.9	)			(10.4	)
Other selling costs			(4.3	)			(0.7	)
Change in inventories			(67.2	)			11.2
Cash operating costs (a)			106.1				172.0
Add / (subtract)
Depreciation and amortization			42.7				33.5
Care and maintenance costs			6.9				—
Change in inventories			(8.2	)			35.8
Total operating costs (b)			147.5				241.3
Uranium produced & purchased (million lbs) (c)			4.1				8.5
Cash costs per pound (a ÷ c)			25.88				20.24
Total costs per pound (b ÷ c)			35.98				28.39

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

						THREE MONTHS
						ENDED MARCH 31
HIGHLIGHTS						2018				2017				CHANGE
Production volume (million kgU)							3.9				2.6				50	%
Sales volume (million kgU)1							2.4				1.6				50	%
Average realized price		($	Cdn/kgU	)			26.60				33.22				(20	)%
Average unit cost of sales (including D&A)		($	Cdn/kgU	)			21.56				24.67				(13	)%
Revenue ($ millions)1							64				54				19	%
Gross profit ($ millions)							12				14				(14	)%
Gross profit (%)							19				26				(27	)%

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

FIRST QUARTER

Total revenue for the first quarter of 2018 increased to $64 million from $54 million for the same period last year. This was primarily due to a 50% increase in sales volumes partially offset by a 20% decrease in average realized price compared to 2017. The increase in sales volume in the quarter 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. Average realized price decreased mainly due to the mix of product sold, as well as a decrease in the average realized price for UF₆.

The total cost of products and services sold (including D&A) increased 30% ($52 million compared to $40 million in 2017) due to the 50% increase in sales volume, partially offset by a 13% decrease in the average unit cost of sales.

The net effect was a $2 million decrease in gross profit.

2018 FIRST QUARTER REPORT    19

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 64% lower than the first quarter of 2017 due to the production suspension at McArthur River and Key Lake and a change in reporting for JV Inkai. We continue to evaluate the optimal mix of production, inventory and purchases in order to retain the flexibility to deliver long-term value. See below for more information.

URANIUM PRODUCTION

		THREE MONTHS
		ENDED MARCH 31
OUR SHARE (MILLION LBS)		2018				2017				CHANGE				2018 PLAN
McArthur River/Key Lake			0.1				3.6				(97	)%			0.1
Cigar Lake			2.2				2.3				(4	)%			9.0
Inkai1			—				0.7				(100	)%			—
US ISR			0.1				0.1				—				0.1
Total			2.4				6.7				(64	)%			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 Q1 updates

PRODUCTION UPDATE

McArthur River/Key Lake

Production was 97% lower for the first quarter compared to the same period in 2017 as a result of the planned production suspension beginning in February. Due to continued uranium price weakness, and in accordance with our announcement at the end of 2017, we have temporarily suspended production. During January 2018, activities at the mine and mill were focused on putting the operation into a state of safe care and maintenance. As a result of the suspension, and the time required to restart the mine and mill, we do not expect any additional production from the operation in 2018.

Our share of the cost to maintain both operations during the suspension is expected to range between $6.5 million and $7.5 million per month.

The collective agreement with the United Steelworkers local 8914 expired in December 2017, and the collective bargaining process has begun. There is a risk to the restart of operations after the production suspension if we are unable to reach agreement and there is a labour dispute.

Cigar Lake

Total packaged production from Cigar Lake was 4% lower in the first quarter compared to the same period last year. Lower production in the quarter was largely due to challenging ground conditions and processing circuit issues which have been resolved. We expect to meet our planned production for the year.

Inkai

Production on a 100% basis was 1.8 million pounds for the quarter. Production was higher in the first quarter 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

Total production was nominal for the quarter similar to the same period in 2017, as a result of the decision to curtail production and defer all wellfield development at our US operations. We have now effectively ceased production, which is expected to result in production of less than 100,000 pounds for the year.

20    CAMECO CORPORATION

Rabbit Lake

The Rabbit Lake operation is in a safe state of care and maintenance; there was no production in the first 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 Q1 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 3.9 million kgU in the first quarter, 54% higher than the same period last year due to the timing of scheduled production.

Labour relations

The current collective bargaining agreement for our unionized employees at the CFM facility expires June 1, 2018. We expect that the collective bargaining process will begin in the second quarter.

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		INKAI
•  Les Yesnik, general manager, McArthur River/Key Lake, Cameco •  Greg Murdock, manager, operations, McArthur River, Cameco CIGAR LAKE •  Jeremy Breker, general manager, Rabbit Lake/Cigar Lake, Cameco		•  Darryl Clark, president, Cameco Kazakhstan LLP

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, 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 March 31, 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

2018 FIRST QUARTER REPORT    21

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New standards and interpretations

The following new standards and amendments to existing standards were required to be applied for our accounting periods beginning on or after January 1, 2018, unless otherwise noted. These standards did not have a material impact on the interim financial statements.

• IFRS 15 Revenue from Contracts with Customers, clarifies the principles for recognizing revenue from contracts with customers. We adopted IFRS 15 using the cumulative effect method without practical expedients which does not require comparative financial statements to be restated. As the adoption of the new standard did not have a material impact on our existing revenue recognition practices, there was no cumulative effect on net earnings at January 1, 2018 that would have required restatement. The new standard did result in additional disclosures. See note 10 for more information.

• IFRS 9 Financial Instruments, includes revised guidance on the classification and measurement of financial assets. While it largely retains the existing requirements in IAS 39 for the classification and measurement of financial liabilities, it eliminates the previous categories for financial assets of held to maturity, loans and receivables and available for sale. Upon adoption, we reclassified financial assets from loans and receivable to amortized cost and equity securities from available for sale to fair value through other comprehensive income (FVOCI). In addition, accounts receivable that may be subject to factoring arrangements are now classified as either FVOCI or fair value through profit or loss depending on the terms of the arrangement. There was no impact on the measurement of any of these instruments. The new standard also includes a new expected credit loss model for calculating impairment on financial assets. Due to risk management practices that we have in place, this change did not have a material impact on the consolidated financial statements. IFRS 9 also introduces new hedge accounting requirements. Since we do not apply hedge accounting, there was no impact on the interim financial statements. See note 17 for more information.

A number of new standards, interpretations and amendments to existing standards are not yet effective for the year ended December 31, 2018, and have not been applied in preparing these interim financial statements. Please refer to our 2017 annual MD&A for a brief description of each accounting pronouncement.

22    CAMECO CORPORATION